Edgar Filing: SOUTHERN Co GAS

Document




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

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended June 30, 2016



Commission File Number 1-14174

SOUTHERN COMPANY GAS
Ten Peachtree Place NE, Atlanta, Georgia 30309
404-584-4000

Georgia	58-2210952
(State of incorporation)	(I.R.S. Employer Identification No.)


Southern Company Gas (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Southern Company Gas has submitted electronically and posted on its corporate website every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months.

Southern Company Gas is a large accelerated filer and is not a shell company.

The number of shares of Southern Company Gas' common stock, Par Value $0.01 Per Share, outstanding as of July 25, 2016, was 100, all of which were held by The Southern Company.

Southern Company Gas

Quarterly Report on Form 10-Q

For the Quarter Ended June 30, 2016

TABLE OF CONTENTS



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

1.	Condensed Consolidated Financial Statements (Unaudited)	4
	Condensed Consolidated Balance Sheets - Assets	4
	Condensed Consolidated Balance Sheets - Liabilities, Contingently Redeemable Noncontrolling Interest and Equity	5
	Condensed Consolidated Statements of Income	6
	Condensed Consolidated Statements of Comprehensive Income	7
	Condensed Consolidated Statements of Equity	8
	Condensed Consolidated Statements of Cash Flows	9
	Notes to Condensed Consolidated Financial Statements (Unaudited)	10
	Note 1 - Organization and Basis of Presentation	10
	Note 2 - Merger with Southern Company	10
	Note 3 - Significant Accounting Policies and Methods of Application	11
	Note 4 - Regulated Operations	14
	Note 5 - Fair Value Measurements	16
	Note 6 - Derivative Instruments	16
	Note 7 - Employee Benefit Plans	18
	Note 8 - Debt and Credit Facilities	19
	Note 9 - Equity	20
	Note 10 - Non-Wholly Owned Entities and Contingently Redeemable Noncontrolling Interest	21
	Note 11 - Commitments, Guarantees and Contingencies	23
	Note 12 - Segment Information	24
2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	27
	Forward-Looking Statements	27
	Executive Summary	28
	Results of Operations	30
	Liquidity and Capital Resources	37
	Critical Accounting Policies and Estimates	40
	Accounting Developments	40
3.	Quantitative and Qualitative Disclosures About Market Risk	40
4.	Controls and Procedures	43

	PART II - OTHER INFORMATION

1.	Legal Proceedings	43
1A.	Risk Factors	43
2.	Unregistered Sales of Equity Securities and Use of Proceeds	43
6.	Exhibits	44

	SIGNATURE	45

Glossary of Key Terms

Table of Contents



GLOSSARY OF KEY TERMS
2015 Form 10-K	Our Annual Report on Form 10-K for the year ended December 31, 2015, filed with the SEC on February 11, 2016
Atlanta Gas Light	Atlanta Gas Light Company
Atlantic Coast Pipeline	Atlantic Coast Pipeline, LLC
Bcf	Billion cubic feet
Central Valley	Central Valley Gas Storage, LLC
CUB	Citizens Utility Board
Dalton Pipeline	A 50% undivided ownership interest in a pipeline facility in Georgia
EBIT	Earnings before interest and taxes, the primary measure of our reportable segments’ profit or loss, which includes operating income and other income and excludes interest on debt and income tax expense
ERC	Environmental remediation costs
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings
GAAP	Accounting principles generally accepted in the United States of America
Georgia Commission	Georgia Public Service Commission, the state regulatory agency for Atlanta Gas Light
Golden Triangle	Golden Triangle Storage, Inc.
Heating Degree Days	A measure of weather, calculated when the average daily temperatures are less than 65 degrees Fahrenheit
Heating Season	The period from November through March when natural gas usage and operating revenues are generally higher
Horizon Pipeline	Horizon Pipeline Company, LLC
Illinois Commission	Illinois Commerce Commission, the state regulatory agency for Nicor Gas
Jefferson Island	Jefferson Island Storage & Hub, LLC
LIFO	Last-in, first-out
LOCOM	Lower of weighted average cost or current market price
Marketers	Marketers selling retail natural gas in Georgia and certificated by the Georgia Commission
Merger Agreement	Agreement and Plan of Merger entered into on August 23, 2015 by Southern Company, AMS Corp., a subsidiary of Southern Company, and Southern Company Gas
MGP	Manufactured Gas Plant
Moody’s	Moody’s Investors Service
New Jersey BPU	New Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown Gas
Nicor Gas	Northern Illinois Gas Company, doing business as Nicor Gas Company
Nicor Gas Credit Facility	$700 million credit facility entered into by Nicor Gas to support its commercial paper program
NYMEX	New York Mercantile Exchange, Inc.
OCI	Other comprehensive income
Operating margin	A non-GAAP measure of income, calculated as operating revenues minus cost of goods sold and revenue tax expense
PennEast Pipeline	PennEast Pipeline Company, LLC
Piedmont	Piedmont Natural Gas Company, Inc.
Pivotal Utility	Pivotal Utility Holdings, Inc., doing business as Elizabethtown Gas, Elkton Gas and Florida City Gas
PRP	Pipeline Replacement Program, Atlanta Gas Light's 15-year infrastructure replacement program, which ended in December 2013
S&P	S&P Global Ratings
SEC	Securities and Exchange Commission
Sequent	Sequent Energy Management, L.P.
Southern Company	The Southern Company
Southern Company Gas	Southern Company Gas (formerly known as AGL Resources Inc.)
Southern Company Gas Capital	Southern Company Gas Capital Corporation (formerly known as AGL Capital Corporation)
Southern Company Gas Credit Facility	$1.3 billion credit agreement entered into by Southern Company Gas Capital to support its commercial paper program
SouthStar	SouthStar Energy Services, LLC
Triton	Triton Container Investments, LLC
U.S.	The United States of America
VaR	Value-at-risk
VIE	Variable interest entity
Virginia Commission	Virginia State Corporation Commission, the state regulatory agency for Virginia Natural Gas
Virginia Natural Gas	Virginia Natural Gas, Inc.
WACOG	Weighted average cost of gas

Glossary of Key Terms

Table of Contents

PART I – FINANCIAL INFORMATION

Item 1. Condensed Consolidated Financial Statements (Unaudited)

SOUTHERN COMPANY GAS AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS - ASSETS

(UNAUDITED)



	As of
In millions	June 30, 2016		December 31, 2015		June 30, 2015
Current assets
Cash and cash equivalents	$	15	$	19	$	25
Receivables
Energy marketing	429		445		430
Natural gas, unbilled revenues and other	355		516		445
Less allowance for uncollectible accounts	38		29		46
Total receivables, net	746		932		829
Inventories
Natural gas	398		622		395
Other	29		29		26
Total inventories	427		651		421
Derivative instruments, including cash collateral	100		206		158
Current deferred income taxes	63		—		26
Prepaid expenses	60		218		51
Regulatory assets	47		68		48
Other	16		21		14
Total current assets	1,474		2,115		1,572
Long-term assets and other deferred debits
Property, plant and equipment	13,039		12,566		11,903
Less accumulated depreciation	2,891		2,775		2,524
Property, plant and equipment, net	10,148		9,791		9,379
Goodwill	1,813		1,813		1,827
Regulatory assets	679		670		642
Intangible assets	101		109		112
Other	273		256		303
Total long-term assets and other deferred debits	13,014		12,639		12,263
Total assets	$	14,488	$	14,754	$	13,835

See Notes to Condensed Consolidated Financial Statements (Unaudited).

Glossary of Key Terms

Table of Contents

SOUTHERN COMPANY GAS AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS - LIABILITIES, CONTINGENTLY REDEEMABLE NONCONTROLLING INTEREST AND EQUITY

(UNAUDITED)



	As of
In millions, except share and per share amounts	June 30, 2016			December 31, 2015			June 30, 2015
Current liabilities
Short-term debt	$	114		$	1,010		$	459
Current portion of long-term debt	575			545			125
Energy marketing trade payables	436			418			455
Other accounts payable – trade	278			255			272
Accrued expenses	221			200			183
Regulatory liabilities	156			134			154
Customer deposits and credit balances	143			165			115
Derivative instruments, including cash collateral	65			44			43
Accrued environmental remediation liabilities	59			67			83
Temporary LIFO liquidation	49			—			38
Current deferred income taxes	—			31			—
Other	109			131			120
Total current liabilities	2,205			3,000			2,047
Long-term liabilities and other deferred credits
Long-term debt	3,709			3,275			3,452
Accumulated deferred income taxes	1,992			1,912			1,780
Regulatory liabilities	1,627			1,611			1,622
Accrued pension and retiree welfare benefits	513			515			526
Accrued environmental remediation liabilities	379			364			346
Other	89			102			73
Total long-term liabilities and other deferred credits	8,309			7,779			7,799
Total liabilities and other deferred credits	10,514			10,779			9,846
Commitments, guarantees and contingencies (see Note 11)
Contingently redeemable noncontrolling interest	41			—			—
Equity
Common stock, $5 par value; 750,000,000 shares authorized; outstanding: 120,741,810 shares at June 30, 2016, 120,376,721 shares at December 31, 2015, and 120,081,995 shares at June 30, 2015	605			603			601
Additional paid-in capital	2,133			2,099			2,099
Retained earnings	1,424			1,421			1,425
Accumulated other comprehensive loss	(221		)	(186		)	(169		)
Treasury shares, at cost: 216,523 shares at June 30, 2016, December 31, 2015, and June 30, 2015	(8		)	(8		)	(8		)
Total common shareholders’ equity	3,933			3,929			3,948
Noncontrolling interest	—			46			41
Total equity	3,933			3,975			3,989
Total liabilities, redeemable noncontrolling interest and equity	$	14,488		$	14,754		$	13,835

See Notes to Condensed Consolidated Financial Statements (Unaudited).

Glossary of Key Terms

Table of Contents

SOUTHERN COMPANY GAS AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(UNAUDITED)



	Three Months Ended June 30,						Six Months Ended June 30,
In millions, except per share amounts	2016			2015			2016			2015
Operating revenues (includes revenue taxes of $17 and $57 for the three and six months ended June 30, 2016, respectively, and $18 and $74 for the three and six months ended June 30, 2015, respectively)	$	571		$	674		$	1,905		$	2,395
Operating expenses
Cost of goods sold	191			222			769			1,157
Operation and maintenance	213			209			454			458
Depreciation and amortization	104			98			206			195
Taxes other than income taxes	37			38			99			114
Merger-related expenses	53			—			56			—
Total operating expenses	598			567			1,584			1,924
Operating (loss) income	(27		)	107			321			471
Other income	3			4			6			7
Interest expense, net	(48		)	(42		)	(95		)	(86		)
(Loss) income before income taxes	(72		)	69			232			392
Income tax (benefit) expense	(24		)	25			87			143
Net (loss) income	(48		)	44			145			249
Less net income attributable to noncontrolling interest	3			2			14			14
Net (loss) income attributable to Southern Company Gas	$	(51	)	$	42		$	131		$	235
Per common share information attributable to Southern Company Gas
Basic (loss) earnings per common share	$	(0.43	)	$	0.35		$	1.09		$	1.97
Diluted (loss) earnings per common share	$	(0.43	)	$	0.35		$	1.09		$	1.96
Cash dividends declared per common share	$	0.53		$	0.51		$	1.06		$	1.02
Weighted average number of common shares outstanding
Basic	120.3			119.5			120.2			119.4
Diluted	120.5			119.8			120.5			119.7

See Notes to Condensed Consolidated Financial Statements (Unaudited).

Glossary of Key Terms

Table of Contents

SOUTHERN COMPANY GAS AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(UNAUDITED)



	Three Months Ended June 30,					Six Months Ended June 30,
In millions	2016			2015		2016			2015
Net (loss) income	$	(48	)	$	44	$	145		$	249
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 $4 for the three and six months ended June 30, 2016, respectively, and $2 and $4 for the three and six months ended June 30, 2015, respectively)	2			4		5			7
Retirement benefit plans, net	2			4		5			7
Cash flow hedges, net of tax
Net derivative (loss) gain arising during the period (net of income tax of $7 and $23 for the three and six months ended June 30, 2016, respectively, and $16 and $17 for the three and six months ended June 30, 2015, respectively)	(12		)	25		(41		)	27
Reclassification of realized derivative gain to net income (net of income tax of less than $1 for the three and six months ended June 30, 2016 and 2015)	2			4		1			4
Cash flow hedges, net	(10		)	29		(40		)	31
Other comprehensive (loss) income, net of tax	(8		)	33		(35		)	38
Comprehensive (loss) income	(56		)	77		110			287
Less comprehensive income attributable to noncontrolling interest	3			3		14			15
Comprehensive (loss) income attributable to Southern Company Gas	$	(59	)	$	74	$	96		$	272

See Notes to Condensed Consolidated Financial Statements (Unaudited).

Glossary of Key Terms

Table of Contents

SOUTHERN COMPANY GAS AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(UNAUDITED)



	Southern Company Gas
	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	—	—		—			235			—			—			14			249
Other comprehensive income	—	—		—			—			37			—			1			38
Dividends on common stock ($1.02 per share)	—	—		—			(122		)	—			—			—			(122		)
Distribution to noncontrolling interest	—	—		—			—			—			—			(18		)	(18		)
Stock granted, share-based compensation, net of forfeitures	—	—		(13		)	—			—			—			—			(13		)
Stock issued, dividend reinvestment plan	0.1	1		5			—			—			—			—			6
Stock issued, share-based compensation, net of forfeitures	0.4	1		14			—			—			—			—			15
Share-based compensation expense, net of tax	—	—		6			—			—			—			—			6
Balance as of June 30, 2015	120.1	$	601	$	2,099		$	1,425		$	(169	)	$	(8	)	$	41		$	3,989



	Southern Company Gas
	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 Southern Company Gas	—	—		—			131			—			—			—			131
Other comprehensive loss	—	—		—			—			(35		)	—			—			(35		)
Dividends on common stock ($1.06 per share)	—	—		—			(128		)	—			—			—			(128		)
Stock granted, share-based compensation, net of forfeitures	—	—		(9		)	—			—			—			—			(9		)
Stock issued, dividend reinvestment plan	—	—		6			—			—			—			—			6
Stock issued, share-based compensation, net of forfeitures	0.3	2		15			—			—			—			—			17
Share-based compensation expense, net of tax	—	—		22			—			—			—			—			22
Reclassification of noncontrolling interest	—	—		—			—			—			—			(46		)	(46		)
Balance as of June 30, 2016	120.7	$	605	$	2,133		$	1,424		$	(221	)	$	(8	)	$	—		$	3,933

See Notes to Condensed Consolidated Financial Statements (Unaudited).

Glossary of Key Terms

Table of Contents

SOUTHERN COMPANY GAS AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)



	Six Months Ended June 30,
In millions	2016			2015
Cash flows from operating activities:
Net income	$	145		$	249
Adjustments to reconcile net income to net cash flow provided by operating activities
Depreciation and amortization	206			195
Change in derivative instrument assets and liabilities	136			42
Deferred income taxes	8			27
Changes in certain assets and liabilities
Inventories, net of temporary LIFO liquidation	273			333
Prepaid and miscellaneous taxes	187			150
Receivables, other than energy marketing	174			363
Energy marketing receivables and trade payables, net	34			27
Trade payables, other than energy marketing	26			(41		)
Accrued natural gas costs, net	11			43
Accrued expenses	(20		)	(28		)
Other, net	(67		)	125
Net cash flow provided by operating activities	1,113			1,485
Cash flows from investing activities:
Expenditures for property, plant and equipment	(548		)	(452		)
Other, net	(11		)	5
Net cash flow used in investing activities	(559		)	(447		)
Cash flows from financing activities:
Issuance of long-term debt	596			—
Distribution to noncontrolling interest	(19		)	(18		)
Payment of long-term debt	(125		)	(200		)
Dividends paid on common shares	(128		)	(122		)
Net repayments of commercial paper	(896		)	(716		)
Other, net	14			12
Net cash flow used in financing activities	(558		)	(1,044		)
Net decrease in cash and cash equivalents	(4		)	(6		)
Cash and cash equivalents at beginning of period	19			31
Cash and cash equivalents at end of period	$	15		$	25
Cash paid (received) during the period for
Interest	$	119		$	93
Income taxes	(100		)	(57		)

See Notes to Condensed Consolidated Financial Statements (Unaudited).

Glossary of Key Terms

Table of Contents

SOUTHERN COMPANY GAS AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 - Organization and Basis of Presentation

General

Southern Company Gas (formerly known as AGL Resources Inc.) is an energy services holding company that conducts substantially all of its operations through its subsidiaries. As more fully described in Note 2 herein, on July 1, 2016, we became a wholly owned subsidiary of Southern Company. On July 11, 2016, we changed our name to Southern Company Gas. Unless the context requires otherwise, references to “we,” “us,” “our,” the “company” or “Southern Company Gas” mean consolidated Southern Company Gas 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.

Note 2 - Merger with Southern Company

On July 1, 2016, we completed the previously announced merger with Southern Company. In accordance with the Merger Agreement, a wholly owned subsidiary of Southern Company merged with and into the company, with us surviving as a wholly owned subsidiary of Southern Company.

At the effective time of the merger, each share of our common stock, other than certain excluded shares, was converted into the right to receive $66 in cash, without interest. Also at the effective time of the merger:


•	our outstanding restricted stock units, restricted stock awards and non-employee director stock awards were deemed fully vested and were canceled and converted into the right to receive an amount in cash equal to the product of (i) the total number of shares of our common stock subject to such award and (ii) the merger consideration of $66 per share;


•	our outstanding stock options, all of which were fully vested, were canceled and converted into the right to receive an amount in cash equal to the product of (i) the total number of shares of our common stock subject to such options and (ii) the excess of the merger consideration of $66 per share over the applicable exercise price per share of such options; and

•

each outstanding award of performance share units was converted into an award of Southern Company's restricted stock units. The conversion ratio was the product of (i) the greater of (a) 125% of the number of units underlying such award based on target level achievement of all relevant performance goals and (b) the number of units underlying such award based on the actual level of achievement of all relevant performance goals against target and (ii) an exchange ratio based on the merger consideration of $66 per share as compared to the volume-weighted average price per share of Southern Company common stock, on the same terms and conditions relating to vesting schedule and payment terms, and otherwise on similar terms and conditions, as were applicable to such performance share unit awards, subject to certain exceptions.

During the three and six months ended June 30, 2016, we recorded merger-related expenses on the accompanying unaudited Condensed Consolidated Statements of Income of $53 million ($39 million, net of tax) and $56 million ($41 million, net of tax), respectively. The transaction costs incurred for the three and six months ended June 30, 2016 were comprised of $29 million and $31 million, respectively, of financial advisory fees, legal expenses and other merger-related costs, including certain amounts payable upon successful completion of the merger, which was deemed probable on June 29, 2016, and $24 million and $25 million, respectively, of additional compensation related expenses, including accelerated vesting of share-based compensation expenses and certain merger-related compensation charges. We previously treated these costs as tax deductible since the requisite closing conditions to the merger had not yet been satisfied. During the second quarter of 2016, when the merger became probable, we re-evaluated the tax deductibility of these costs and reflected any non-deductible amounts in the effective tax rate.

Glossary of Key Terms

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The receipt of required regulatory approvals was conditioned upon certain terms and commitments. In connection with these regulatory approvals, certain regulatory agencies have prohibited us from recovering goodwill and merger-related expenses, required us to maintain a minimum number of employees for a set period of time to ensure that certain pipeline safety standards and the competence level of the employee workforce is not degraded, and/or required us to maintain our pre-merger level of support for various social and charitable programs. The most notable terms and commitments with potential financial impacts include:


•	rate credits of $18 million to be paid to customers in New Jersey and Maryland;


•	sharing of merger savings with customers in Georgia starting in 2020;


•	phasing-out the use of the Nicor name or logo by our retail energy subsidiaries in conducting non-utility business in Illinois;


•	reaffirming that Elizabethtown Gas will file a base rate case no later than September 1, 2016, with another base rate case no later than three years after the 2016 rate case;


•	requiring Elkton Gas to file a base rate case within 2 years of closing the merger; and


•	there is no restriction on our other utilities ability to file future rate cases.

As these terms and commitments are related to post-merger operations, our financial position and results of operations as of and for the three and six months ended June 30, 2016 did not reflect the financial impacts of these items.

Upon completion of the merger, we amended and restated our Bylaws and Articles of Incorporation, under which we now have the authority to issue no more than 110 million shares of stock consisting of (i) 100 million shares of common stock and (ii) 10 million shares of preferred stock, both categories of which have a par value of $0.01 per share. The amended and restated Articles of Incorporation do not allow any treasury shares to be held. Additionally, upon completion of the merger, we provided notice of our change in control to holders of certain senior notes and made an offer to prepay up to $275 million of such debt instruments. These senior notes are included in current portion of long-term debt on the accompanying unaudited Condensed Consolidated Balance Sheet as of June 30, 2016.

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 year.

Use of Accounting Estimates

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

Inventories

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

Nicor Gas’ inventory is carried at cost on a LIFO basis. 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 June 30, 2016 is expected to be restored prior to year-end and the inventory decrement as of June 30, 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 June 30,				Six Months Ended June 30,
In millions	2016		2015		2016		2015
LOCOM adjustments	$	—	$	—	$	3	$	10

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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 June 30, 2016 and 2015, and December 31, 2015 are provided in the following table.



In millions	Distribution operations		Retail operations		Midstream operations			Consolidated
Goodwill - June 30, 2015	$	1,640	$	173	$	14		$	1,827
Impairment ⁽¹⁾	—		—		(14		)	(14		)
Goodwill - December 31, 2015	1,640		173		—			1,813
Goodwill - June 30, 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.

(Loss) Earnings per Common Share

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



	Three Months Ended June 30,					Six Months Ended June 30,
In millions, except per share amounts	2016			2015		2016		2015
Net (loss) income attributable to Southern Company Gas	$	(51	)	$	42	$	131	$	235
Denominator
Basic weighted average number of shares outstanding ⁽¹⁾	120.3			119.5		120.2		119.4
Effect of dilutive securities	0.2			0.3		0.3		0.3
Diluted weighted average number of shares outstanding ⁽²⁾	120.5			119.8		120.5		119.7
(Loss) earnings per common share attributable to Southern Company Gas
Basic (loss) earnings per common share	$	(0.43	)	$	0.35	$	1.09	$	1.97
Diluted (loss) earnings per common share	$	(0.43	)	$	0.35	$	1.09	$	1.96


(1)	Daily weighted average shares outstanding.


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

Upon completing the merger with Southern Company on July 1, 2016, all of our common shares are held, beneficially and of record, by Southern Company. As a result, earnings per common share disclosures will no longer be included in our quarterly and annual reports.

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 "Accounting Developments" in 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.

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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 expect to adopt this new guidance in the third quarter of 2016 and 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 effective for us beginning January 1, 2017 with prospective application, 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.

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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 recorded on our unaudited Condensed Consolidated Balance Sheets as of the dates presented are summarized in the following table.



In millions	June 30, 2016		December 31, 2015		June 30, 2015
Regulatory assets
Recoverable ERC	$	18	$	31	$	27
Recoverable pension and retiree welfare benefit costs	12		12		11
Unrecovered weather normalization	9		—		1
Deferred natural gas costs	—		6		—
Recoverable seasonal rates	—		10		—
Other	8		9		9
Regulatory assets – current	47		68		48
Recoverable ERC	386		370		350
Recoverable pension and retiree welfare benefit costs	109		113		105
Recoverable regulatory infrastructure program costs	84		83		77
Long-term debt fair value adjustment	63		66		70
Other	37		38		40
Regulatory assets – long-term	679		670		642
Total regulatory assets	$	726	$	738	$	690
Regulatory liabilities
Accumulated removal costs	$	52	$	53	$	25
Bad debt over collection	49		42		27
Accrued natural gas costs	29		24		67
Deferred seasonal rates	8		—		8
Other	18		15		27
Regulatory liabilities – current	156		134		154
Accumulated removal costs	1,552		1,538		1,544
Regulatory income tax liability	24		27		27
Bad debt over collection	23		21		18
Unamortized investment tax credit	19		20		21
Other	9		5		12
Regulatory liabilities – long-term	1,627		1,611		1,622
Total regulatory liabilities	$	1,783	$	1,745	$	1,776

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	June 30, 2016		December 31, 2015		June 30, 2015
Atlanta Gas Light ⁽¹⁾	$	106	$	103	$	126
Virginia Natural Gas	12		12		11
Elizabethtown Gas	5		4		3
Nicor Gas	3		3		1
Total	$	126	$	122	$	141


(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.

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Environmental Remediation Costs We are subject to federal, state and local laws and regulations governing environmental quality and pollution control that require us to remove or remedy the effect on the environment of the disposal or release of specified substances at our current and former operating sites, substantially all of which is related to former MGP sites. The ERC assets and liabilities are associated with our distribution operations segment and remediation costs are generally recoverable from customers through rate mechanisms approved by regulatory agencies. 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 conventional engineering-based cost estimates and probabilistic models of estimated costs when such conventional 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 $18 million in revenues over the next 12 months, which is reflected as a current regulatory asset. The following table provides additional information on the estimated costs to remediate our current and former operating sites as of June 30, 2016.



Dollars in millions	# of sites	Probabilistic model cost estimates	Engineering-based cost estimates		Amount recorded		Expected costs over next 12 months		Cost recovery period
Illinois ⁽¹⁾	26	$206 - $470	$	46	$	252	$	27	As incurred
New Jersey	6	111 - 190	8		119		14		7 years
Georgia and Florida	13	38 - 64	24		62		18		5 years
North Carolina ⁽²⁾	1	n/a	5		5		—		No recovery
Total	46	$355 - $724	$	83	$	438	$	59


(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 to replace more than 200 miles of aging pipeline infrastructure. Under this program, Virginia Natural Gas is allowed to invest up to $30 million in 2016 and $35 million annually in years 2017 through 2021 on qualifying infrastructure projects.

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Note 5 - Fair Value Measurements

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

Derivative Instruments

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



	June 30, 2016					December 31, 2015					June 30, 2015
In millions	Assets ⁽¹⁾		Liabilities			Assets ⁽¹⁾		Liabilities			Assets⁽¹⁾		Liabilities
Quoted prices in active markets (Level 1)	$	17	$	(80	)	$	53	$	(63	)	$	3	$	(53	)
Significant other observable inputs (Level 2)	50		(76		)	122		(46		)	128		(45		)
Netting of counterparty offset and cash collateral	43		77			33		63			64		53
Total carrying value ⁽²⁾	$	110	$	(79	)	$	208	$	(46	)	$	195	$	(45	)


(1)	Balances of $5 million at June 30, 2016, $10 million at December 31, 2015 and $2 million at June 30, 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.

Long-Term 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	June 30, 2016		December 31, 2015		June 30, 2015
Long-term debt carrying amount	$	4,284	$	3,820	$	3,577
Long-term debt fair value ⁽¹⁾	4,836		4,066		3,857


(1)	Fair value determined using Level 2 inputs.

Note 6 - Derivative Instruments

Our objectives and strategies for using derivative instruments, and the related accounting policies and methods used to determine their fair values are described within "Fair Value Measurements" in Note 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 June 30, 2016, December 31, 2015 and June 30, 2015, for agreements with such features, derivative instruments with liability fair values totaled $79 million, $46 million and $45 million, respectively, for which we had posted no collateral to our counterparties as we exceed the minimum credit rating requirements. As of June 30, 2016, 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 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 $136 million and $42 million for the six months ended June 30, 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⁾	June 30, 2016 ⁽²⁾		December 31, 2015		June 30, 2015
Cash flow hedges	4		5		6
Not designated as hedges	38		(14	)	24
Total volumes	42		(9	)	30
Short position – cash flow hedges	(5	)	(6	)	(8	)
Short position – not designated as hedges	(3,092	)	(3,089	)	(2,930	)
Long position – cash flow hedges	9		11		14
Long position – not designated as hedges	3,130		3,075		2,954
Net long (short) position	42		(9	)	30


(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)	97% of these contracts have durations of two years or less and 3% expire between two and five years.

In addition to natural gas derivative contracts, we entered into interest rate swaps, which we account for as cash flow hedges. See Note 8 herein for additional information on our interest rate swaps.

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Derivative Instruments on our Unaudited Condensed Consolidated Balance Sheets

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



	Three Months Ended June 30,						Six Months Ended June 30,
In millions	2016			2015			2016			2015
Nicor Gas	$	(10	)	$	(18	)	$	(12	)	$	(21	)
Elizabethtown Gas	(4		)	(4		)	(10		)	(8		)

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



		June 30, 2016						December 31, 2015						June 30, 2015
In millions	Classification	Assets			Liabilities			Assets			Liabilities			Assets			Liabilities
Designated as cash flow hedges
Natural gas contracts	Current	$	4		$	(4	)	$	3		$	(5	)	$	—		$	(4	)
Natural gas contracts	Long-term	—			(1		)	—			(2		)	—			(1		)
Interest rate swap agreements	Current	—			(30		)	9			—			24			—
Interest rate swap agreements	Long-term	—			—			—			—			23			—
Total designated as cash flow hedges		$	4		$	(35	)	$	12		$	(7	)	$	47		$	(5	)
Not designated as hedges
Natural gas contracts	Current	$	520		$	(557	)	$	751		$	(672	)	$	473		$	(481	)
Natural gas contracts	Long-term	83			(99		)	179			(187		)	92			(91		)
Total not designated as hedges		$	603		$	(656	)	$	930		$	(859	)	$	565		$	(572	)
Gross amounts of recognized assets and liabilities ^{(1) (2)}		$	607		$	(691	)	$	942		$	(866	)	$	612		$	(577	)
Gross amounts offset on our unaudited Condensed Consolidated Balance Sheets⁽²⁾		(492		)	612			(724		)	820			(415		)	532
Net amounts of assets and liabilities presented on our unaudited Condensed Consolidated Balance Sheets⁽³⁾		$	115		$	(79	)	$	218		$	(46	)	$	197		$	(45	)


(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 $120 million as of June 30, 2016, $96 million as of December 31, 2015, and $117 million as of June 30, 2015. Cash collateral is included in the “Gross amounts offset on our unaudited Condensed Consolidated Balance Sheets” line of this table.


(3)	As of June 30, 2016, December 31, 2015, and June 30, 2015, we held letters of credit from counterparties that under master netting arrangements would offset an insignificant portion of these assets.

Derivative Instruments on our Unaudited Condensed Consolidated Statements of Income

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



	Three Months Ended June 30,						Six Months Ended June 30,
In millions	2016			2015			2016			2015
Designated as cash flow hedges ⁽¹⁾
Natural gas contracts - net loss reclassified from OCI into cost of goods sold	$	(1	)	$	(3	)	$	(1	)	$	(4	)
Natural gas contracts - net loss reclassified from OCI into operation and maintenance expense	—			(1		)	—			(1		)
Interest rate swaps - net (loss) gain reclassified from OCI into interest expense	(1		)	—			—			1
Total designated as cash flow hedges, net of tax	(2		)	(4		)	(1		)	(4		)
Not designated as hedges ⁽¹⁾
Natural gas contracts - net fair value adjustments recorded in operating revenues	(93		)	3			(73		)	(21		)
Natural gas contracts - net fair value adjustments recorded in cost of goods sold ⁽²⁾	5			1			4			(1		)
Income tax	33			(1		)	26			9
Total not designated as hedges, net of tax	(55		)	3			(43		)	(13		)
Total losses on derivative instruments, net of tax	$	(57	)	$	(1	)	$	(44	)	$	(17	)


(1)	Associated with the fair value of derivative instruments held at June 30, 2016 and 2015.


(2)	Excludes gains (losses) recorded in cost of goods sold associated with weather derivatives of less than $1 million and $3 million for the three and six months ended June 30, 2016, respectively, and $1 million and $(1) million for the three and six months ended June 30, 2015, respectively, as they are accounted for based on intrinsic value rather than fair value.

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Amounts recognized in income related to ineffectiveness or due to a forecasted transaction that is no longer expected to occur were immaterial for all periods presented. Upon settlement of our interest rate swaps on May 13, 2016, we realized a $26 million loss that was recognized in accumulated other comprehensive loss on our unaudited Condensed Consolidated Balance Sheet as of June 30, 2016. 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 $3 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 June 30, 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 herein 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

Effective July 1, 2016, in connection with the approval of the merger, Southern Company Services, Inc. became the sponsor of the two benefit plans discussed below.

Pension Benefits

The benefits of our Southern Company Gas Retirement Plan, a tax-qualified defined benefit retirement plan for our eligible employees, 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 pension costs for the periods indicated.



	Three Months Ended June 30,						Six Months Ended June 30,
In millions	2016			2015			2016			2015
Service cost ⁽¹⁾	$	7		$	7		$	13		$	14
Interest cost ⁽¹⁾	11			12			21			23
Expected return on plan assets	(17		)	(17		)	(33		)	(33		)
Net amortization of prior service credit	(1		)	—			(1		)	(1		)
Recognized actuarial loss	7			7			13			15
Net periodic pension benefit cost	$	7		$	9		$	13		$	18

(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 Southern Company Gas 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 June 30,						Six Months Ended June 30,
In millions	2016			2015			2016			2015
Service cost ⁽¹⁾	$	—		$	—		$	1		$	1
Interest cost ⁽¹⁾	2			3			5			6
Expected return on plan assets	(1		)	(2		)	(3		)	(4		)
Net amortization of prior service credit	—			(1		)	(1		)	(1		)
Recognized actuarial loss	1			2			2			3
Net periodic welfare benefit cost	$	2		$	2		$	4		$	5

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Note 8 - Debt and Credit Facilities

The following table provides maturity dates or ranges, year-to-date weighted average interest rates and amounts outstanding for our various debt securities and facilities for the periods presented. We fully and unconditionally guarantee all debt issued by Southern Company Gas Capital (whose name was changed from AGL Capital Corporation effective July 19, 2016) and the gas facility revenue bonds issued by Pivotal Utility. 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.



		June 30, 2016								June 30, 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 - Southern Company Gas Capital ⁽²⁾	2016	0.8	%	$	20		$	471		0.5	%	$	269
Commercial paper - Nicor Gas ⁽²⁾	2016	0.6		94			539			0.4		190
Total short-term debt		0.7	%	$	114		$	1,010		0.4	%	$	459
Current portion of long-term debt ⁽³⁾	2016	4.6	%	$	575		$	545		4.6	%	$	125
Long-term debt - excluding current portion
Senior notes	2019-2043	4.9	%	$	2,650		$	2,455		5.0	%	$	2,625
First mortgage bonds	2019-2038	5.8		625			375			5.9		375
Gas facility revenue bonds	2022-2033	1.1		200			200			0.9		200
Medium-term notes	2017-2027	7.8		181			181			7.8		181
Total principal long-term debt		4.9	%	$	3,656		$	3,211		4.9	%	$	3,381
Unamortized fair value adjustment	n/a	n/a		$	63		$	68		n/a		$	74
Unamortized debt premium, net	n/a	n/a		14			16			n/a		16
Unamortized debt issuance costs	n/a	n/a		(24		)	(20		)	n/a		(19		)
Total non-principal long-term debt	n/a	n/a		$	53		$	64		n/a		$	71
Total long-term debt - excluding current portion		n/a		$	3,709		$	3,275		n/a		$	3,452
Total debt		n/a		$	4,398		$	4,830		n/a		$	4,036


(1)	Interest rates are calculated based on the daily weighted average balance outstanding for the six months ended June 30, 2016 and 2015.


(2)	As of June 30, 2016, the effective interest rates on our commercial paper were 0.7% for Southern Company Gas Capital and 0.5% for Nicor Gas.


(3)	Balance as of June 30, 2016 includes $275 million of senior notes subject to potential prepayment in August 2016 due to a change of control provision.

Commercial Paper Programs

We maintain commercial paper programs at Southern Company Gas Capital and at Nicor Gas that consist of short-term, unsecured promissory notes, which are 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 Southern Company Gas Capital’s commercial paper program. During the first six months of 2016, our commercial paper maturities ranged from 1 to 59 days, and at June 30, 2016, the remaining term to maturity was 1 day. During the first six months of 2016, there were no commercial paper issuances with original maturities over three months.

Long-Term Debt

On February 1, 2016 and May 15, 2016, $75 million and $50 million, respectively, of Nicor Gas' first mortgage bonds matured and were repaid using the proceeds from commercial paper borrowings. On June 23, 2016, Nicor Gas issued $250 million aggregate principal amount of first mortgage bonds with the following terms: $100 million at 2.66% due June 20, 2026, $100 million at 2.91% due June 20, 2031 and $50 million at 3.27% due June 20, 2036. The net proceeds were used to repay short-term indebtedness incurred under the Nicor Gas commercial paper program and for other working capital needs.

On May 18, 2016, Southern Company Gas Capital issued $350 million aggregate principal amount of 3.250% senior notes due June 15, 2026, which are guaranteed by Southern Company Gas. A portion of the net proceeds was used to repay $300 million aggregate principal amount of 6.375% senior notes that matured on July 15, 2016, and the remaining net proceeds were used for general corporate purposes.

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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 issuances of long-term debt in the fourth quarter of 2015 and in the first six months of 2016 as well as our anticipated issuance later in 2016. We designated the forward-starting interest rate swaps, which are settled on the respective debt issuance dates, as cash flow hedges. In conjunction with the aforementioned debt issuances, we settled $200 million of these interest rate swaps in November 2015 for an immaterial loss and an additional $400 million of these interest rate swaps upon pricing the first mortgage bonds in May 2016 and realized a loss of $26 million that was recognized in accumulated other comprehensive income. We performed a qualitative assessment of effectiveness on the remaining $200 million of interest rate swaps as of June 30, 2016 and concluded that the remaining hedges are highly effective.

Financial and Non-Financial Covenants

The Southern Company Gas 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.



	Southern Company Gas						Nicor Gas
	June 30, 2016		December 31, 2015		June 30, 2015		June 30, 2016		December 31, 2015		June 30, 2015
Debt covenants ⁽¹⁾	52	%	54	%	49	%	45	%	56	%	49	%


(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 June 30
As of beginning of period	$	(28	)	$	(185	)	$	(213	)	$	(4	)	$	(197	)	$	(201	)
OCI, before reclassifications	(12		)	—			(12		)	25			—			25
Amounts reclassified from accumulated OCI	2			2			4			3			4			7
Net current-period other comprehensive (loss) income	(10		)	2			(8		)	28			4			32
As of end of period	$	(38	)	$	(183	)	$	(221	)	$	24		$	(193	)	$	(169	)
For the six months ended June 30
As of beginning of period	$	2		$	(188	)	$	(186	)	$	(6	)	$	(200	)	$	(206	)
OCI, before reclassifications	(41		)	—			(41		)	27			—			27
Amounts reclassified from accumulated OCI	1			5			6			3			7			10
Net current-period other comprehensive (loss) income	(40		)	5			(35		)	30			7			37
As of end of period	$	(38	)	$	(183	)	$	(221	)	$	24		$	(193	)	$	(169	)


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

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



	Three Months Ended June 30,						Six Months Ended June 30,
In millions⁽¹⁾	2016			2015			2016			2015
Cash flow hedges
Cost of goods sold (natural gas contracts)	$	(1	)	$	(3	)	$	(1	)	$	(4	)
Operation and maintenance expense (natural gas contracts)	—			(1		)	—			(1		)
Interest expense (interest rate contracts)	(1		)	—			—			1
Cash flow hedges, net of income tax	(2		)	(4		)	(1		)	(4		)
Less noncontrolling interest	—			(1		)	—			(1		)
Total cash flow hedges, net of income tax	(2		)	(3		)	(1		)	(3		)
Retirement benefit plans
Operation and maintenance expense (actuarial losses) ⁽²⁾	(4		)	(6		)	(9		)	(11		)
Total retirement benefit plans	(4		)	(6		)	(9		)	(11		)
Income tax benefit	2			2			4			4
Total retirement benefit plans, net of income tax	(2		)	(4		)	(5		)	(7		)
Total reclassification for the period	$	(4	)	$	(7	)	$	(6	)	$	(10	)


(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	14
Distribution to noncontrolling interest	(19		)
Balance as of June 30, 2016	$	41

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Cash flows used in our investing activities include capital expenditures for SouthStar of $2 million for the six months ended June 30, 2016 and 2015. Cash flows used in our financing activities include SouthStar’s distribution to Piedmont for its portion of SouthStar’s annual earnings from the previous year, which generally occurs in the first quarter of each fiscal year. For the six months ended June 30, 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.



	June 30, 2016						December 31, 2015						June 30, 2015
In millions	Consolidated		SouthStar		%		Consolidated		SouthStar		%		Consolidated		SouthStar		%
Current assets	$	1,474	$	199	14	%	$	2,115	$	245	12	%	$	1,572	$	192	12	%
Goodwill and other intangible assets	1,914		111		6		1,922		114		6		1,939		117		6
Long-term assets and other deferred debits	11,100		17		—		10,717		16		—		10,324		17		—
Total assets	$	14,488	$	327	2	%	$	14,754	$	375	3	%	$	13,835	$	326	2	%
Current liabilities	$	2,205	$	37	2	%	$	3,000	$	54	2	%	$	2,047	$	40	2	%
Long-term liabilities and other deferred credits	8,309		1		—		7,779		—		—		7,799		1		—
Total liabilities	10,514		38		—		10,779		54		1		9,846		41		—
Contingently redeemable noncontrolling interest	41		—		—		—		—		—		—		—		—
Equity	3,933		289		7		3,975		321		8		3,989		285		7
Total liabilities, redeemable noncontrolling interest and equity	$	14,488	$	327	2	%	$	14,754	$	375	3	%	$	13,835	$	326	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 June 30,				Six Months Ended June 30,
In millions	2016		2015		2016		2015
Operating revenues	$	118	$	122	$	372	$	433
Operating expenses
Cost of goods sold	77		89		234		292
Operation and maintenance	18		18		40		41
Depreciation and amortization	2		3		4		5
Taxes other than income taxes	1		—		1		1
Total operating expenses	98		110		279		339
Operating income	$	20	$	12	$	93	$	94

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:



In millions	June 30, 2016		December 31, 2015		June 30, 2015
Triton	$	46	$	49	$	53
PennEast Pipeline	15		9		3
Horizon Pipeline	14		14		14
Atlantic Coast Pipeline	14		7		4
Other	1		1		1
Total	$	90	$	80	$	75

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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 June 30,				Six Months Ended June 30,
In millions	2016		2015		2016		2015
Triton	$	1	$	1	$	1	$	1
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. As discussed in Note 8 herein, Nicor Gas issued $250 million of first mortgage bonds on June 23, 2016 and Southern Company Gas Capital issued $350 million of senior notes on May 18, 2016. The principal amounts of these long-term debt instruments are due in 2026 and thereafter. Under these debt instruments, interest payments of $10 million will be made in 2016, $19 million will be made annually in 2017 through 2020 and $141 million will be made thereafter.

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 purchased gas adjustment 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.

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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 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. Retail operations also 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 Chairman, 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 June 30, 2016



In millions	Distribution operations		Retail operations		Wholesale services ⁽¹⁾			Midstream operations			Other			Intercompany eliminations			Consolidated
Operating revenues from external parties	$	509	$	149	$	(95	)	$	10		$	2		$	(4	)	$	571
Intercompany revenues	38		—		—			—			—			(38		)	—
Total operating revenues	547		149		(95		)	10			2			(42		)	571
Operating expenses
Cost of goods sold	144		83		1			4			—			(41		)	191
Operation and maintenance	164		31		14			6			—			(2		)	213
Depreciation and amortization	89		5		1			5			4			—			104
Taxes other than income taxes	33		1		1			1			1			—			37
Merger-related expenses	—		—		—			—			53			—			53
Total operating expenses	430		120		17			16			58			(43		)	598
Operating income (loss)	117		29		(112		)	(6		)	(56		)	1			(27		)
Other income	2		—		—			1			—			—			3
EBIT	$	119	$	29	$	(112	)	$	(5	)	$	(56	)	$	1		$	(24	)
Capital expenditures	$	280	$	2	$	1		$	25		$	5		$	—		$	313

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Three months ended June 30, 2015



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

Six months ended June 30, 2016



In millions	Distribution operations		Retail operations		Wholesale services⁽¹⁾			Midstream operations			Other			Intercompany eliminations			Consolidated
Operating revenues from external parties	$	1,492	$	435	$	(32	)	$	25		$	4		$	(19	)	$	1,905
Intercompany revenues	83		—		—			—			—			(83		)	—
Total operating revenues	1,575		435		(32		)	25			4			(102		)	1,905
Operating expenses
Cost of goods sold	608		245		4			10			—			(98		)	769
Operation and maintenance	349		68		30			13			(2		)	(4		)	454
Depreciation and amortization	178		11		1			9			7			—			206
Taxes other than income taxes	89		2		2			2			4			—			99
Merger-related expenses	—		—		—			—			56			—			56
Total operating expenses	1,224		326		37			34			65			(102		)	1,584
Operating income (loss)	351		109		(69		)	(9		)	(61		)	—			321
Other income	2		—		1			3			—			—			6
EBIT	$	353	$	109	$	(68	)	$	(6	)	$	(61	)	$	—		$	327
Total assets	$	12,499	$	672	$	753		$	744		$	9,493		$	(9,673	)	$	14,488
Capital expenditures	$	484	$	4	$	1		$	43		$	16		$	—		$	548

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Six months ended June 30, 2015



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

(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 June 30, 2016	$	1,061	58	1,119	1,214	$	(95	)
Three months ended June 30, 2015	$	1,291	89	1,380	1,376	$	4
Six months ended June 30, 2016	$	2,500	143	2,643	2,675	$	(32	)
Six months ended June 30, 2015	$	3,436	239	3,675	3,581	$	94

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



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

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and the related notes in this quarterly report, as well as with our 2015 Form 10-K. Results for the interim periods presented are not necessarily indicative of the results to be expected for the full fiscal period due to seasonal and other factors.

Forward-Looking Statements

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

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

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


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


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


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


•	changes in price, supply and demand for natural gas and related products;


•	the impact of changes in state and federal legislation and regulation, including any changes related to climate matters;


•	actions taken by government agencies on rates and other matters;


•	concentration of credit risk;


•	utility and energy industry consolidation;


•	the impact on cost and timeliness of construction projects, including our pipeline projects, from government and other approvals, project delays, adequacy of supply of diversified vendors and unexpected changes in project costs;


•	the cost of funds to finance our construction projects and our ability to recover certain project costs from our customers;


•	limits on pipeline capacity;


•	the impact of acquisitions and divestitures;


•	our ability to successfully integrate operations that we have or may acquire or develop in the future;


•	direct or indirect effects on our business, financial condition or liquidity resulting from a change in our credit ratings or the credit ratings of our counterparties or competitors;


•	interest rate fluctuations;


•	financial market conditions, including disruptions in the capital markets and lending environment;


•	general economic conditions;


•	uncertainties about environmental issues and the related impact of such issues, including our environmental remediation plans;


•	the capacity of our gas storage caverns, which are subject to natural settling and other occurrences;


•	contracting rates at our midstream operations storage business;


•	the impact of weather on the temperature-sensitive portions of our business;


•	the impact of natural disasters, such as hurricanes, on the supply and price of natural gas;


•	acts of war or terrorism;


•	the outcome of litigation;


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


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

There may be other factors that we do not anticipate or that we do not recognize as material that could cause results to differ materially from our expectations. Forward-looking statements speak only as of the date they are made. We expressly disclaim any obligation to update or revise any forward-looking statement, whether as a result of future events, new information or otherwise, except as required by law.

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Executive Summary

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

Merger With Southern Company On July 1, 2016, we completed our merger with Southern Company, pursuant to which we became a wholly owned subsidiary of Southern Company. Upon consummation of the merger, our common stock is no longer listed or traded on the NYSE. We will continue to maintain our own management team, board of directors and corporate headquarters, located in Atlanta. In addition, our utility customers will continue to be served by our current natural gas local distribution utilities.

We recorded $53 million and $56 million in merger-related expenses during the three and six months ended June 30, 2016, respectively, which primarily consisted of financial advisory and legal expenses, including certain amounts payable upon successful completion of the merger, which was deemed probable on June 29, 2016, as well as additional compensation-related expenses, including accelerated vesting of share-based compensation expenses and certain merger-related compensation charges. Additionally, we re-evaluated the tax deductibility of all of the merger-related costs to reflect any non-deductible amounts in the effective tax rate.

For additional information relating to this transaction, see Note 2 to our unaudited condensed consolidated financial statements under Part I, Item 1 herein and the current report on Form 8-K filed with the SEC on July 1, 2016.

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

•

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

Nicor Gas In July 2014, the Illinois Commission approved our nine-year regulatory infrastructure program, Investing in Illinois. Nicor Gas expects to invest $281 million on qualifying assets under this program during 2016, $78 million of which was incurred during the first six months of 2016.

Atlanta Gas Light Atlanta Gas Light's Strategic Infrastructure Development and Enhancement (STRIDE) program, which started in 2009, consists of three individual programs that update and expand distribution systems and liquefied natural gas facilities as well as improve system reliability to meet operational flexibility and customer growth. Through the programs under STRIDE, Atlanta Gas Light expects to invest $157 million during 2016, $68 million of which was incurred during the first six months of 2016.

Additionally, the Georgia Commission approved an extension of Atlanta Gas Light's asset management agreement with Sequent to March 31, 2020.

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

The New Jersey BPU approved the extension of our Aging Infrastructure Replacement (AIR) program in August 2013, under which Elizabethtown Gas expects to invest $29 million in 2016, $12 million of which was incurred during the first six months of 2016. As part of this approval, we agreed and are on track to file a general base rate case by September 1, 2016.

Virginia Natural Gas In March 2016, the Virginia State Commission approved the SAVE II infrastructure replacement project, under which Virginia Natural Gas expects to invest $30 million on qualifying infrastructure projects in 2016, $16 million of which was incurred during the first six months of 2016, and up to $35 million annually thereafter through 2021 to replace more than 200 miles of aging pipeline infrastructure.

Florida City Gas The Florida Public Service Commission approved Florida City Gas' Safety, Access and Facility Enhancement (SAFE) program in September 2015. Under the program, Florida City Gas expects to spend $11 million in 2016, $4 million of which was incurred during the first six months of 2016.

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

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


•	Wholesale Services: Position our business to secure sufficient supplies of natural gas to meet the needs of our utility and third-party customers and to hedge natural gas prices to effectively manage costs, reduce price volatility and maintain a competitive advantage relative to other marketers.


•	Midstream Operations: Invest in natural gas based projects along with our existing pipelines and storage facilities to support our efforts to provide diverse sources of natural gas supplies to our customers, resolve current and long-term supply planning for new capacity, enhance system reliability and generate economic development in the areas served.

We are currently involved in three significant pipeline projects. We expect to receive FERC approval for Dalton Pipeline and begin construction of the 111 mile project in the second half of 2016. We expect to receive FERC approval for Atlantic Coast Pipeline and PennEast Pipeline in 2017. Given this updated timing, and other factors, capital expenditures may exceed our initial expectations.

Natural Gas Market Fundamentals Volatility in the natural gas market arises from a number of factors, such as weather fluctuations or changes in supply or demand for natural gas in different regions of the country. The volatility of natural gas commodity prices has a significant impact on our customer rates, our long-term competitive position against other energy sources and the ability of our retail operations and wholesale services segments to capture value from locational and seasonal spreads. Additionally, changes in commodity prices subject a significant portion of our operations to earnings variability.

Our non-utility businesses generally use physical and financial instruments to reduce the risks associated with fluctuations in market conditions and changing commodity prices. These economic hedges may not qualify, or may not be designated, for hedge accounting treatment. As a result, our reported earnings for wholesale services, retail operations and midstream operations reflect changes in the fair values of certain derivatives. A general decline in natural gas prices or a narrowing of transportation spreads generally results in derivative gains and corresponding increases in EBIT, while an increase in natural gas prices or a widening of transportation spreads generally results in derivative losses and corresponding decreases in EBIT. These values may change significantly from period to period and are reflected as gains or losses within our operating revenues, cost of goods sold or our OCI for those derivative instruments that qualify, and are designated, as accounting hedges.

We generate the majority of our operating revenues through the sale, distribution and storage of natural gas. We include in our consolidated revenues an estimate of revenues from natural gas distributed, but not yet billed to residential, commercial and industrial customers from the date of the last bill to the end of the reporting period. No individual customer or industry accounts for a significant portion of our revenues.

Our operating results can vary significantly from quarter to quarter as a result of the seasonality of operating revenues and EBIT at distribution operations and retail operations. During the Heating Season, natural gas usage and operating revenues are generally higher as more customers are connected to our distribution systems and natural gas usage is higher in periods of colder weather. Alternatively, our base operating expenses, excluding cost of gas, revenue taxes and certain incentive compensation costs, are incurred relatively evenly over any given year, resulting in variability in the quarterly pattern of earnings.

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

We believe that the presentation of operating margin provides useful information to management and investors regarding the contribution resulting from customer growth in our distribution operations segment since the cost of goods sold and revenue tax expenses can vary significantly and are generally billed directly to our customers. We further believe that operating margin at our retail operations, wholesale services and midstream operations segments allows us to focus on a direct measure of operating margin before overhead costs.

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

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

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



	Three months ended June 30,									Six months ended June 30,
In millions, except per share amounts	2016			2015			Change			2016			2015			Change
Operating revenues	$	571		$	674		$	(103	)	$	1,905		$	2,395		$	(490	)
Cost of goods sold	(191		)	(222		)	31			(769		)	(1,157		)	388
Revenue tax expense ⁽¹⁾	(17		)	(18		)	1			(56		)	(73		)	17
Operating margin	363			434			(71		)	1,080			1,165			(85		)
Operating expenses ⁽²⁾	(407		)	(345		)	(62		)	(815		)	(767		)	(48		)
Revenue tax expense ⁽¹⁾	17			18			(1		)	56			73			(17		)
Operating (loss) income	(27		)	107			(134		)	321			471			(150		)
Other income	3			4			(1		)	6			7			(1		)
EBIT	(24		)	111			(135		)	327			478			(151		)
Interest expense, net	(48		)	(42		)	(6		)	(95		)	(86		)	(9		)
(Loss) income before income taxes	(72		)	69			(141		)	232			392			(160		)
Income tax benefit (expense)	24			(25		)	49			(87		)	(143		)	56
Net (loss) income	(48		)	44			(92		)	145			249			(104		)
Less net income attributable to noncontrolling interest	3			2			1			14			14			—
Net (loss) income attributable to Southern Company Gas	$	(51	)	$	42		$	(93	)	$	131		$	235		$	(104	)
Per common share data
Diluted (loss) earnings per common share	$	(0.43	)	$	0.35		$	(0.78	)	$	1.09		$	1.96		$	(0.87	)
Merger-related expenses	0.32			—			0.32			$	0.34		$	—		$	0.34
Diluted (loss) earnings per common share - as adjusted	$	(0.11	)	$	0.35		$	(0.46	)	$	1.43		$	1.96		$	(0.53	)


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


(2)	Operating expenses for the three and six months ended June 30, 2016 include $53 million and $56 million of merger-related expenses, respectively.

2016 Results For the second quarter of 2016, we reported a net loss attributable to Southern Company Gas of $51 million, compared to $42 million in net income attributable to Southern Company Gas in the same period in 2015. This $93 million decrease was due primarily to $135 million lower consolidated EBIT and $6 million higher interest expense, partially offset by $49 million lower income tax expense. The EBIT decrease was largely driven by $53 million in merger-related expenses in the current year quarter and a $104 million decrease at wholesale services from net mark-to-market losses and lower commercial activity in the current year quarter compared to net mark-to-market gains in the same period in 2015. Offsetting these EBIT declines, EBIT increased $22 million in the second quarter of 2016 over 2015 due primarily to higher operating margin at distribution operations from continued investment in infrastructure programs and higher operating margin at retail operations from the timing of mark-to-market hedge gains.

For the first six months of 2016, our net income attributable to Southern Company Gas was $131 million, a decrease of $104 million compared to the same period in 2015. This decrease was due primarily to $151 million lower consolidated EBIT and $9 million higher interest expense, partially offset by $56 million lower income tax expense. The EBIT decrease was largely driven by a $19 million negative weather impact, net of hedge costs, due to warmer-than-normal weather in 2016 compared to colder-than-normal weather in 2015, a $116 million EBIT decrease at wholesale services and $56 million in merger-related expenses incurred during 2016. Offsetting these EBIT declines, EBIT increased $40 million in 2016 over 2015 due primarily to higher operating margin at distribution operations from infrastructure programs and increased non-weather consumption through usage and customer growth.

Further discussion of the year-over-year drivers are detailed at the segment level within "Results of Operations" below.

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Results of Operations

Operating Metrics:

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



	Three months ended June 30,			2016 vs. 2015		2016 vs. normal		Six months ended June 30,			2016 vs. 2015		2016 vs. normal
	Normal ⁽¹⁾	2016	2015	colder		colder/(warmer)		Normal ⁽¹⁾	2016	2015	warmer		warmer
Illinois ⁽²⁾	618	639	535	19.4	%	3.4	%	3,715	3,340	3,892	(14.2	)%	(10.1	)%
Georgia	126	114	61	86.9	%	(9.5	)%	1,610	1,448	1,653	(12.4	)%	(10.1	)%


(1)	Normal represents the 10-year average from January 1, 2006 through June 30, 2015 for Illinois at Chicago Midway International Airport and for Georgia at Atlanta Hartsfield-Jackson International Airport, as obtained from the National Oceanic and Atmospheric Administration, National Climatic Data Center.


(2)	The 10-year average Heating Degree Days established by the Illinois Commission in our last rate case is 617 for the second quarter and 3,519 for the first six months from 1998 through 2007.

Weather typically does not have a significant EBIT impact during the non-Heating Season. For the second quarter of 2016, the year-over-year weather-related EBIT impact, net of our weather hedging, was favorable by $2 million due to colder weather in the current period. In the first half of 2016, the unfavorable weather-related EBIT impact from the warmer-than-normal weather was $7 million, net of the impact of our weather hedging, compared to a $12 million favorable weather impact for the same period in 2015, when weather was significantly colder-than-normal.

Customers The number of customers at distribution operations and energy customers at retail operations can be impacted by natural gas prices, economic conditions and competition from alternative fuels. Our energy customers at retail operations are primarily located in Georgia and Illinois. Our customer metrics presented in the following table highlight the average number of customers to which we provide services for the specified periods.



	Three months ended June 30,				2016 vs. 2015		Six months ended June 30,				2016 vs. 2015
In thousands	2016		2015		% change		2016		2015		% change
Distribution operations	4,567		4,534		0.7	%	4,576		4,545		0.7	%
Retail operations
Energy customers	642		657		(2.3	)%	650		647		0.5	%
Service contracts ⁽¹⁾	1,201		1,155		4.0	%	1,201		1,157		3.8	%
Market share of energy customers in Georgia	29.3	%	29.8	%			29.3	%	29.9	%

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

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

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

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



	Three months ended June 30,		2016 vs. 2015		Six months ended June 30,		2016 vs. 2015
	2016	2015	% change		2016	2015	% change
Distribution operations (In Bcf)
Firm	107	99	8.1	%	396	444	(10.8	)%
Interruptible	22	24	(8.3	)	49	51	(3.9	)
Total	129	123	4.9	%	445	495	(10.1	)%
Retail operations (In Bcf)
Firm:
Georgia	4	4	—	%	21	23	(8.7	)%
Illinois	2	2	—		8	9	(11.1	)
Other emerging markets	2	2	—		7	6	16.7
Interruptible:
Large commercial and industrial customers	4	3	33.3		8	7	14.3
Total	12	11	9.1	%	44	45	(2.2	)%
Wholesale services
Daily physical sales (Bcf/day)	7.2	5.9	22.0	%	7.6	6.9	10.1	%

Within midstream operations, our natural gas storage businesses seek to have a significant portion of their working natural gas capacity under firm subscription, but also take into account current and expected market conditions. This allows our natural gas storage business to generate additional revenue during times of peak market demand for natural gas storage services, but retain some consistency with its earnings and maximize the value of its investments. Our midstream operations storage business is cyclical, and the abundant supply of natural gas in recent years and resulting reduced market and price volatility have negatively impacted the profitability of our storage facilities. The prices for natural gas storage capacity have increased in 2016 relative to the last few years and are expected to continue to increase as supply and demand quantities reach equilibrium with sustained economic improvement, expected exports of liquefied natural gas, and projected demand increases in response to low prices and expanded uses for natural gas. The following table illustrates the overall monthly average firm subscription rates per storage facility and the amount of firm capacity subscription for the periods presented. The amounts as of June 30, 2015 exclude 5.0 Bcf contracted by Sequent at an average monthly rate of $0.072. Sequent had no capacity contracted as of June 30, 2016. Additionally, there were no new subscriptions that started during the second quarter of 2016.



	June 30, 2016			June 30, 2015
	Average rates (per dekatherm)		Firm capacity under subscription (Bcf)	Average rates (per dekatherm)		Firm capacity under subscription (Bcf)
Jefferson Island	$	0.103	2.2	$	0.092	4.2
Golden Triangle⁽¹⁾	0.051		2.5	0.098		7.0
Central Valley	0.058		2.5	0.047		4.0

(1) The decline in rates in 2016 is the result of a 2.0 Bcf contract at $0.240 that expired in August 2015. The decrease in capacity subscribed in 2016 is due to delayed re-contracting until the second half of 2016 to allow for completion of routine maintenance activities. We have contracted 5.0 Bcf at an average rate of $0.061 to start in the second half of 2016, of which 2.75 Bcf at an average rate of $0.054 relates to capacity contracted by Sequent.

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Segment information:

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



	Three months ended June 30, 2016									Three months ended June 30, 2015
In millions	Operating margin ^{(1) (2)}			Operating expenses^{(2) (3)}			EBIT ^{(1) (3)}			Operating margin ^{(1) (2)}			Operating expenses ⁽²⁾			EBIT⁽¹⁾
Distribution operations	$	386		$	269		$	119		$	362		$	259		$	106
Retail operations	66			37			29			58			41			17
Wholesale services	(96		)	16			(112		)	4			12			(8		)
Midstream operations	6			12			(5		)	9			11			(2		)
Other	2			58			(56		)	3			6			(2		)
Intercompany eliminations	(1		)	(2		)	1			(2		)	(2		)	—
Consolidated	$	363		$	390		$	(24	)	$	434		$	327		$	111



	Six months ended June 30, 2016									Six months ended June 30, 2015
In millions	Operating margin ^{(1) (2)}			Operating expenses ^{(2) (3)}			EBIT^{(1) (3)}			Operating margin ^{(1) (2)}			Operating expenses ⁽²⁾			EBIT⁽¹⁾
Distribution operations	$	911		$	560		$	353		$	872		$	542		$	334
Retail operations	190			81			109			189			85			104
Wholesale services	(36		)	33			(68		)	85			37			48
Midstream operations	15			24			(6		)	18			23			(4		)
Other	4			65			(61		)	4			10			(4		)
Intercompany eliminations	(4		)	(4		)	—			(3		)	(3		)	—
Consolidated	$	1,080		$	759		$	327		$	1,165		$	694		$	478


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


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


(3)	Includes $53 million and $56 million of merger-related expenses for the three and six months ended June 30, 2016, respectively, recorded within our other segment.

Distribution Operations Our distribution operations segment is the largest component of our business and is subject to regulation and oversight by agencies in each of the states we serve. These agencies approve natural gas rates designed to provide us the opportunity to generate revenues to recover the cost of natural gas delivered to our customers and our fixed and variable costs, such as depreciation, interest, maintenance and overhead costs, and to earn a reasonable return on our investments.

With the exception of Atlanta Gas Light, our second largest utility, the earnings of our regulated utilities can be affected by customer consumption patterns that are a function of weather conditions, price levels for natural gas and general economic conditions that may impact our customers’ ability to pay for natural gas consumed. We have various weather mechanisms, such as weather normalization mechanisms and weather derivative instruments, that limit our exposure to weather changes within typical ranges in their respective service areas. For the three and six months ended June 30, 2016, distribution operations’ EBIT increased by $13 million and $19 million, respectively, compared to the same periods in 2015, as shown in the following table.

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In millions	Three months ended			Six months ended
EBIT - June 30, 2015	$	106		$	334
Operating margin
Increase from pipeline infrastructure programs, primarily at Atlanta Gas Light and Nicor Gas	19			36
Increase mainly driven by non-weather-related customer usage and growth	4			11
Increase in rider program recoveries at Nicor Gas, offset by operating expenses below	1			7
Decrease in weather-related customer usage, net of weather hedges	—			(15		)
Increase in operating margin	24			39
Operating expenses
Increase in depreciation expense due to additional assets placed in service	7			13
Increase in outside services and other expenses primarily due to pipeline compliance and maintenance costs	6			8
Increase in rider program recoveries at Nicor Gas, offset by operating margin above	1			7
Decrease in variable incentive compensation costs	(1		)	(5		)
Decrease in benefit expenses primarily related to lower pension costs	(3		)	(5		)
Increase in operating expenses	10			18
Decrease in other income primarily due to tax gross-up of contributions received from customers	(1		)	(2		)
EBIT - June 30, 2016	$	119		$	353

Retail Operations Our retail operations segment consists of several businesses that provide energy related products and services to retail markets. Retail operations is weather sensitive and uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to partially mitigate potential weather impacts. For the three and six months ended June 30, 2016, retail operations’ EBIT increased by $12 million and $5 million, respectively, compared to the same periods in 2015, as shown in the following table.



In millions	Three months ended			Six months ended
EBIT - June 30, 2015	$	17		$	104
Operating margin
Increase (decrease) in value of unrealized hedge movement as a result of changes in NYMEX natural gas prices, net of recoveries	4			(1		)
Increase (decrease) in weather-related customer usage, net of weather hedging	2			(4		)
Increase in retail margins	1			6
Increase in warranty margins, including the impact of warranty service contracts acquired in the second half of 2015	1			4
Decrease in interruptible commercial opportunities	—			(3		)
LOCOM adjustments, net of recoveries	—			(1		)
Increase in operating margin	8			1
Operating expenses
Decrease in depreciation and amortization	(1		)	(1		)
Decrease in other expenses, primarily marketing and bad debt expense	(3		)	(3		)
Decrease in operating expenses	(4		)	(4		)
EBIT - June 30, 2016	$	29		$	109

Wholesale Services Our wholesale services segment is involved in asset management and optimization, storage, transportation, producer and peaking services, natural gas supply, natural gas services and wholesale marketing. We have positioned the business to generate positive economic earnings even under low volatility market conditions that can result from a number of factors. When market price volatility increases as we experienced in 2015, we are well positioned to capture significant value and generate stronger results. During the second quarter of 2016, wholesale services recorded net mark-to-market losses on its storage and transportation and forward commodity derivatives totaling $88 million largely due to increases in forward natural gas prices and widening transportation spreads. Despite these losses, wholesale services generated strong economic results for the three and six months ended June 30, 2016, primarily due to capturing natural gas storage value resulting from widening forward storage seasonal spreads that will be realized upon the ultimate withdrawal from storage and sale of natural gas. For the three and six months ended June 30, 2016, EBIT decreased by $104 million and $116 million, respectively, compared to the same period last year, as shown in the following table.

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In millions	Three months ended			Six months ended
EBIT - June 30, 2015	$	(8	)	$	48
Operating margin
Decrease in commercial activity driven by lower price volatility	(9		)	(74		)
Increase in mark-to-market losses of storage derivatives as a result of changes in NYMEX natural gas prices	(32		)	(39		)
Increase in mark-to-market losses of transportation and forward commodity derivatives from price movements related to natural gas transportation positions	(59		)	(14		)
LOCOM adjustments, net of recoveries	—			6
Decrease in operating margin	(100		)	(121		)
Operating expenses
Increase (decrease) in payroll and benefits largely driven by incentive compensation due to year-over-year changes in earnings and capture of natural gas storage value	3			(5		)
Other	1			1
Increase (decrease) in operating expenses	4			(4		)
Increase in other income due to favorable tax refund settlement	—			1
EBIT - June 30, 2016	$	(112	)	$	(68	)

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



	Three months ended June 30,						Six months ended June 30,
In millions	2016			2015			2016			2015
Commercial activity recognized	$	(8	)	$	1		$	34		$	108
(Loss) gain on storage derivatives	(36		)	(4		)	(38		)	1
(Loss) gain on transportation and forward commodity derivatives	(52		)	7			(31		)	(17		)
LOCOM adjustments, net of recoveries	—			—			(1		)	(7		)
Operating margin	$	(96	)	$	4		$	(36	)	$	85

Change in commercial activity The commercial activity at wholesale services includes recognized storage and transportation values that were generated in prior periods, which reflect the impact of prior period hedge gains and losses as associated physical transactions occur in the period. Additionally, the commercial activity includes operating margin generated and recognized in the current period. For the three and six months ended June 30, 2016, commercial activity decreased due to:


•	Lower price volatility due to higher volatility experienced in 2015 as a result of colder weather;


•	Lower transportation and storage spreads experienced in the second quarter of 2016; and


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

Increases in natural gas supply and warmer weather during the 2015/2016 Heating Season and the resulting higher natural gas inventories at the end of 2015 caused natural gas prices to decline in the early part of 2016. During the second quarter of 2016, increases in natural gas prices along with higher forward storage or time spreads due to continued increases in natural gas supply and the need to accommodate the higher natural gas inventory levels enabled us to capture higher storage values. While we experienced unusually high volatility in natural gas prices in early 2015 and low volatility in 2016 due partly to weather, in the near term we anticipate continued low volatility in certain areas of our portfolio. Over the longer term, we expect volatility to be low to moderate and locational or transportation spreads to decrease over time as new pipelines are built to reduce the existing supply constraints in the shale areas of the Northeast U.S. To the extent these pipelines are delayed or not built, volatility could increase. Additional economic factors may contribute to this environment, including the significant drop in oil and natural gas prices, which could lead to consolidation of natural gas producers or reduced levels of natural gas production. Further, if economic conditions continue to improve, the demand for natural gas may increase, which may cause natural gas prices to rise and drive higher volatility in the natural gas markets on a longer-term basis.

Change in storage and transportation derivatives There has been little price volatility in 2016 to benefit wholesale services’ aggregate portfolio of pipeline transportation and storage capacity assets throughout the country beyond our original expectations. Although we do not expect a high level of price volatility, we see the potential for market fundamentals indicating some level of increased volatility that would potentially benefit wholesale services’ portfolio of pipeline transportation capacity should this occur. The storage derivative losses, primarily recorded in the second quarter of 2016, are mainly due to increases in natural gas prices and forward storage or time spreads applicable to the locations of our specific storage positions. Losses in our transportation and forward commodity derivative positions in 2016 are primarily the result of widening transportation basis spreads due to continued supply constraints and increases in natural gas supply, which impacted forward prices at natural gas

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receipt and delivery points, primarily in the Northeast and Midwest regions. These losses are temporary and are expected to be largely recovered in 2017 and the balance thereafter with the physical flow of natural gas and utilization of the contracted transportation capacity at their higher rates.

Withdrawal schedule and physical transportation transactions The expected natural gas withdrawals from storage and expected offset to prior hedge losses/gains associated with the transportation portfolio of wholesale services are presented in the following table, along with the net operating revenues expected at the time of withdrawal from storage and the physical flow of natural gas between contracted transportation receipt and delivery points. Wholesale services’ expected net operating revenues exclude storage and transportation demand charges, as well as other variable fuel, withdrawal, receipt and delivery charges, but are net of the estimated impact of profit sharing under our asset management agreements. Further, the amounts that are realizable in future periods are based on the inventory withdrawal schedule, planned physical flow of natural gas between the transportation receipt and delivery points and forward natural gas prices at June 30, 2016. A portion of wholesale services’ storage inventory and transportation capacity is economically hedged with futures contracts, which results in the realization of substantially fixed net operating revenues, timing notwithstanding.



	Storage withdrawal schedule
Dollars in millions	Total storage (in Bcf) (WACOG $1.94)	Expected net operating gains ⁽¹⁾		Physical transportation transactions – expected net operating (losses) gains ⁽²⁾
2016	28.8	$	28	$	(1	)
2017 and thereafter	34.0	47		32
Total at June 30, 2016	62.8	$	75	$	31


(1)	Represents expected operating gains from planned storage withdrawals associated with existing inventory positions and could change as wholesale services adjusts its daily injection and withdrawal plans in response to changes in future market conditions and forward NYMEX price fluctuations.


(2)	Represents the periods associated with the transportation derivative (gains) losses during which the derivatives will be settled and the physical transportation transactions will occur that offset the derivative (gains) losses recognized during the first six months of 2016.

The unrealized storage and transportation derivative losses do not change the underlying economic value of our storage and transportation positions and, based on current expectations, will primarily be reversed in 2017 and the balance thereafter when the related transactions occur and are recognized. For more information on wholesale services’ energy marketing and risk management activities, see Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” under the caption “Weather and Natural Gas Price Risks” of our 2015 Form 10-K.

Midstream Operations Our midstream operations segment’s primary activity is operating non-utility storage and pipeline facilities, including the development and operation of high-deliverability underground natural gas storage and pipeline assets. While this business can also generate additional revenue during times of peak market demand for natural gas storage services, certain of our storage services are covered under short-, medium- and long-term contracts at fixed market rates. For the three and six months ended June 30, 2016, midstream operations’ EBIT decreased by $3 million and $2 million, respectively, compared to the same periods during the prior year.

Other Our "other" segment includes our investment in Triton, AGL Services Company and Southern Company Gas Capital as well as various corporate operating expenses that we do not allocate to our reportable segments. For the three and six months ended June 30, 2016, such operating expenses included merger-related expenses of $53 million and $56 million, respectively. These expenses are primarily comprised of financial advisory and legal expenses, including certain amounts payable upon successful completion of the merger, which was deemed probable on June 29, 2016, and additional compensation-related expenses, including acceleration of share-based compensation expenses and certain merger-related compensation charges.

Interest Expense:

Interest expense increased by $6 million and $9 million for the three and six months ended June 30, 2016, respectively, compared to the same periods in 2015 due primarily to higher long-term debt balances as a result of issuances of long-term debt in November 2015, May 2016 and June 2016, partially offset by scheduled debt repayments, and an increase in regulatory infrastructure programs expenses as we expensed previously deferred interest with the corresponding recovery in revenue.

Income Tax Expense:

Income tax expense decreased for both the three and six months ended June 30, 2016, primarily due to lower earnings in the current periods. The changes in the effective tax rates in 2016 were related to deductibility of certain merger-related expenses, which were re-assessed in the second quarter of 2016 when the merger became probable. Removing the impact of the merger-related expenses, the effective tax rates are comparable with the prior year.

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Liquidity and Capital Resources

Overview The acquisition of natural gas and pipeline capacity, payment of dividends and funding of working capital needs primarily related to our natural gas inventory are our most significant short-term financing requirements. The liquidity required to fund these short-term needs is generally provided by our operating activities, and any needs not met are primarily satisfied with short-term borrowings under our commercial paper programs, which are supported by the Southern Company Gas Credit Facility and the Nicor Gas Credit Facility. For more information on the seasonality of our short-term borrowings, see "Short-Term Debt" later in this section. The need for long-term capital is driven primarily by capital expenditures, maturities of long-term debt and potential strategic investments. Periodically, we raise funds supporting our long-term cash needs from the issuance of long-term debt, subject to certain limitations. We regularly evaluate our funding strategy and profile to ensure that we have sufficient liquidity for our short-term and long-term needs in a cost-effective manner.

Our financing activities, including long-term and short-term debt, are subject to customary approval or review by the state regulatory agencies in which we conduct business. A substantial portion of our consolidated assets, earnings and cash flows is derived from the operation of our regulated utility subsidiaries, whose legal authority to pay dividends or make other distributions to us may be subject to regulation. By regulation, Nicor Gas is restricted, to the extent of its retained earnings balance, in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. Elizabethtown Gas is restricted by its dividend policy as established by the New Jersey BPU in the amount it can dividend to us to the extent of 70% of its quarterly net income. Additionally, as stipulated in the New Jersey BPU's order approving the Southern Company merger, we are prohibited from paying dividends to our parent company, Southern Company, if our senior unsecured debt rating falls below investment grade.

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

The ability to satisfy our working capital requirements and our debt service obligations, or fund planned capital expenditures, substantially depends upon our future operating performance and financial, business and other factors, some of which we are unable to control. These factors include, among others, economic conditions, regulatory changes, the price of and demand for natural gas, and operational risks.

Our capitalization and financing strategy is intended to ensure that we are properly capitalized with the appropriate mix of debt and equity securities. This strategy includes active management of the percentage of total debt relative to total capitalization, as well as the term and interest rate profile of our debt securities and maintenance of an appropriate mix of debt with fixed and floating interest rates. Our variable-rate debt target is 20% to 45% of total debt. As of June 30, 2016, our variable-rate debt was 10% of our total debt, compared to 28% as of December 31, 2015 and 20% as of June 30, 2015. The decrease from December 31, 2015 was largely driven by decreased commercial paper borrowings resulting from issuances of long-term debt, customer collections on winter sales of natural gas and other seasonal working capital needs.

On February 1, 2016 and May 15, 2016, $75 million and $50 million, respectively, of Nicor Gas' first mortgage bonds matured and were repaid using the proceeds from commercial paper borrowings. On June 23, 2016, Nicor Gas issued $250 million aggregate principal amount of Nicor Gas first mortgage bonds with the following terms: $100 million at 2.66% due June 20, 2026, $100 million at 2.91% due June 20, 2031 and $50 million at 3.27% due June 20, 2036. The net proceeds were used to repay short-term indebtedness incurred under the Nicor Gas commercial paper program and for other working capital needs.

On May 18, 2016, Southern Company Gas Capital issued $350 million aggregate principal amount of 3.250% senior notes due June 15, 2026. A portion of the net proceeds was used to repay at maturity $300 million aggregate principal amount of 6.375% senior notes due July 15, 2016, and the remaining net proceeds were used to repay short-term indebtedness incurred under our commercial paper program and for general corporate purposes.

In January 2015, we executed $800 million in notional value of 10-year and 30-year fixed-rate forward-starting interest rate swaps to hedge potential interest rate volatility prior to our issuances of long-term debt in the fourth quarter of 2015 and in the first six months of 2016 as well as our anticipated issuance of long-term debt later in 2016. We designated the forward-starting interest rate swaps, which mature on the respective debt issuance dates, as cash flow hedges. In conjunction with the aforementioned debt issuances, we settled $200 million of these interest rate swaps in November 2015 for an immaterial loss and an additional $400 million in May 2016 at which time we realized a loss of $26 million that was recognized in accumulated other comprehensive income. The remaining $200 million of interest rate swaps, which represent a fair value liability of $30 million as of June 30, 2016, are expected to be settled in the second half of 2016. See Part I, Item 3, “Quantitative and Qualitative Disclosures About Market Risk,” under the caption “Interest Rate Risk” herein for additional information.

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Certain of our senior notes with a principal amount of $275 million are subject to change in control provisions that were triggered by the merger with Southern Company. Under the applicable Note Purchase Agreement, Southern Company Gas Capital was required to provide notice to the holders of these notes of the change in control and offer to prepay these notes. Up to $275 million of our senior notes, which are presented as current portion of long-term debt on the accompanying unaudited Condensed Consolidated Balance Sheet as of June 30, 2016, are subject to repayment, along with accrued interest, in August 2016.

Our objective remains to maintain a strong balance sheet and liquidity profile and solid investment grade ratings. Additionally, we will continue to evaluate our need to increase available liquidity based on our view of working capital requirements, including the impact of changes in natural gas prices, liquidity requirements established by rating agencies, acquisitions and other factors. Our last quarterly dividend prior to the merger with Southern Company was declared on May 3, 2016 and paid on June 1, 2016 for shareholders of record at the close of business on May 13, 2016. See Item 1A, “Risk Factors,” in our 2015 Form 10-K for additional information on items that could impact our liquidity and capital resource requirements.

Capital Projects We continue to focus on capital discipline while moving forward with projects and initiatives that we expect will have current and future benefits to us and our customers, provide an appropriate return on invested capital and ensure the safety, reliability and integrity of our utility infrastructure. These capital projects update or expand our distribution systems to improve system reliability and meet operational flexibility and growth. Our anticipated expenditures for these programs in 2016 are discussed in “Liquidity and Capital Resources” under the caption "Cash Flow from Investing Activities" under Item 7 of our 2015 Form 10-K. For additional information on our capital projects, see "Infrastructure Replacement Programs and Capital Projects" under Item 1 “Business” in our 2015 Form 10-K.

Short-Term Debt Our short-term debt table includes information relating to borrowings under our commercial paper programs and the current portion of our long-term debt. Our commercial paper borrowings are supported by the $1.3 billion Southern Company Gas Credit Facility and the $700 million Nicor Gas Credit Facility. The Nicor Gas Credit Facility can only be used for the working capital needs of Nicor Gas.



In millions	Period end balance outstanding⁽¹⁾		Daily average balance outstanding ⁽²⁾		Minimum balance outstanding ⁽²⁾		Largest balance outstanding ⁽²⁾
Commercial paper – Southern Company Gas Capital	$	20	$	225	$	—	$	471
Commercial paper – Nicor Gas	94		388		57		550
Current portion of long-term debt	575		472		420		575
Total	$	689	$	1,085	$	477	$	1,596


(1)	As of June 30, 2016.


(2)	For the six months ended June 30, 2016.

The largest, minimum and daily average balances borrowed under our commercial paper programs are important when assessing the intra-period fluctuations of our short-term borrowings and potential liquidity risk. The fluctuations are due to our seasonal cash requirements to fund working capital needs, in particular the purchase of natural gas inventory, margin calls and collateral posting requirements. The largest and minimum balances outstanding for each debt instrument occurred at different times during the period. Therefore, the total balances are not indicative of actual borrowings on any one day during the period. As the current portions of long-term debt mature throughout the remainder of 2016, we expect to refinance the maturing bonds with new issuances of long-term debt.

Increasing natural gas commodity prices can significantly impact our commercial paper borrowings. Based on current natural gas prices and our expected injection plan, a $1 NYMEX price increase could result in a $122 million change of working capital requirements during 2016. This range is sensitive to the timing of storage injections and withdrawals, collateral requirements and our portfolio position. Based upon our total debt outstanding as of June 30, 2016, and our maximum 70% debt to total capitalization allowed under our financial covenants, we could potentially borrow an additional $1.2 billion of commercial paper under the Southern Company Gas Credit Facility and an additional $606 million of commercial paper under the Nicor Gas Credit Facility. As a result, based on current natural gas prices and our expected purchases as we make natural gas storage injections in advance of the upcoming Heating Season, we believe that we have sufficient liquidity to cover our working capital needs.

Credit Ratings Our borrowing costs and our ability to obtain adequate and cost-effective financing are directly impacted by our credit ratings and the availability of financial markets. Credit ratings are important to our counterparties when we engage in certain transactions, including over-the-counter derivatives. It is our long-term objective to maintain or improve our credit ratings in order to manage our existing financing costs and enhance our ability to raise additional capital on favorable terms.

Credit ratings and outlooks are opinions subject to ongoing review by the rating agencies and may periodically change. The rating agencies regularly review our performance and financial condition and reevaluate their ratings of our long-term debt and

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short-term borrowings, our corporate ratings and our ratings outlook. There is no guarantee that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. A credit rating is not a recommendation to buy, sell or hold securities, and each rating should be evaluated independently of other ratings.

Factors we consider important to assessing our credit ratings include our condensed consolidated balance sheets, leverage, capital spending, earnings, cash flow generation, available liquidity and overall business risks. We do not have any triggering events in our debt instruments that are tied to changes in our specified credit ratings and have not entered into any agreements that would require us to issue equity based on credit ratings or other trigger events. A downgrade in our current ratings, particularly below investment grade, would increase our borrowing costs and could limit our access to the commercial paper market. In addition, we would likely be required to pay a higher interest rate in future financings, and our potential pool of investors and funding sources could decrease. The table below summarizes our current credit ratings. In May 2016, Fitch updated its outlook for Southern Company Gas from positive to stable. In conjunction with the close of the merger, S&P raised Southern Company Gas' and Nicor Gas' corporate and senior unsecured credit ratings from BBB+ to A- and updated their rating outlooks from positive to negative. All other ratings and outlooks reflect no change from December 31, 2015.

Southern Company Gas

Nicor Gas

S&P

Moody’s ⁽¹⁾

Fitch

S&P

Moody’s

Fitch

Corporate rating

A-

n/a

BBB+

A-

n/a

Commercial paper

A-2

P-2

A-2

P-1

Senior unsecured

A-

Baa1

BBB+

A-

A+

Senior secured

n/a

Aa3

AA-

Ratings outlook

Negative

Stable

Negative

Stable


(1)	Credit ratings are for Southern Company Gas Capital, whose obligations are fully and unconditionally guaranteed by Southern Company Gas.

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

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



	Six months ended June 30,
In millions	2016			2015			Variance
Net cash provided by (used in)
Operating activities	$	1,113		$	1,485		$	(372	)
Investing activities	(559		)	(447		)	(112		)
Financing activities	(558		)	(1,044		)	486
Net decrease in cash and cash equivalents	(4		)	(6		)	2
Cash and cash equivalents at beginning of period	19			31			(12		)
Cash and cash equivalents at end of period	$	15		$	25		$	(10	)

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

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

Cash Flow from Financing Activities The decreased use of cash for our financing activities was driven primarily by proceeds received from debt issuances during the second quarter of 2016, a portion of which was used to repay maturing debt as well as commercial paper borrowings.

Contractual Obligations and Commitments We incur various contractual obligations and financial commitments in the normal course of business that are reasonably likely to have a material effect on liquidity or the availability of requirements for capital resources. Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities. Contingent financial commitments represent obligations that become payable only if certain predefined events occur, such as financial guarantees, and include the nature of the guarantee and the maximum potential amount of future payments that could be required of us as the guarantor. For additional information, see Note 11 to our unaudited condensed consolidated financial statements under Part I, Item 1 herein.

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Critical Accounting Policies and Estimates

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

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


•	Rate-Regulated Subsidiaries;


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


•	Derivatives and Hedging Activities;


•	Contingencies;


•	Pension and Welfare Plans; and


•	Income Taxes.

Accounting Developments

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

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

Natural Gas Price Risk

The following tables include the fair values and average values of our consolidated derivative instruments as of the dates indicated. We base the average values on monthly averages for the six months ended June 30, 2016 and 2015.



	Derivative instruments average values for the six months ended ⁽¹⁾
In millions	June 30, 2016		June 30, 2015
Asset	$	168	$	190
Liability	69		96

(1) Excludes cash collateral amounts.



	Derivative instruments fair values netted with cash collateral at
In millions	June 30, 2016		December 31, 2015		June 30, 2015
Asset	$	115	$	218	$	197
Liability	79		46		45

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The following table illustrates the change in the net fair value of our derivative instruments during the periods presented, and provides details of the net fair value of contracts outstanding as of the dates presented.



	Three months ended June 30,						Six months ended June 30,
In millions	2016			2015			2016			2015
Net fair value of derivative instruments outstanding at beginning of period	$	(44	)	$	(49	)	$	75		$	61
Derivative instruments realized or otherwise settled during period	8			32			(77		)	(38		)
Change in net fair value of derivative instruments	(48		)	52			(82		)	12
Net fair value of derivative instruments outstanding at end of period	(84		)	35			(84		)	35
Netting of cash collateral	120			117			120			117
Cash collateral and net fair value of derivative instruments outstanding at end of period ⁽¹⁾	$	36		$	152		$	36		$	152


(1)	Net fair value of derivative instruments outstanding includes $5 million and $2 million premium and associated intrinsic value at June 30, 2016 and 2015, respectively, associated with weather derivatives.

The sources of our net fair value at June 30, 2016, are as follows.



In millions	Prices actively quoted (Level 1) ⁽¹⁾			Significant other observable inputs (Level 2) ⁽²⁾
Mature through 2016	$	(20	)	$	(7	)
Mature 2017 - 2018	(31		)	(12		)
Mature 2019 and thereafter	(12		)	(2		)
Total derivative instruments ⁽³⁾	$	(63	)	$	(21	)


(1)	Valued using NYMEX futures prices.


(2)	Valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers.


(3)	Excludes cash collateral amounts.

VaR VaR is the maximum potential loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree of probability. Our VaR may not be comparable to that of other companies due to differences in the factors used to calculate VaR. Our VaR is determined on a 95% confidence interval and a 1-day holding period, which means that 95% of the time, the risk of loss in a day from a portfolio of positions is expected to be less than or equal to the amount of VaR calculated. Our open exposure is managed in accordance with established policies that limit market risk and require daily reporting of potential financial exposure to senior management, including the Chief Risk Officer. Because we generally manage physical gas assets and economically protect our positions by hedging in the futures markets, our open exposure is generally mitigated. We employ daily risk testing, using both VaR and stress testing, to evaluate the risks of our open positions.

We actively monitor open commodity positions and the resulting VaR. We also continue to maintain a relatively matched book, where our total buy volume is close to our sell volume, with minimal open natural gas price risk. Based on a 95% confidence interval and employing a 1-day holding period, SouthStar’s portfolio of positions for the six months ended June 30, 2016 and 2015 were less than $0.1 million and wholesale services had the following VaRs.



	Three months ended June 30,				Six months ended June 30,
In millions	2016		2015		2016		2015
Period end	$	1.9	$	3.4	$	1.9	$	3.4
Average	2.0		3.3		2.0		3.7
High	2.4		4.6		2.5		7.3
Low	1.6		2.6		1.6		2.6

Interest Rate Risk

Interest rate fluctuations expose our variable-rate debt to changes in interest expense and cash flows. Our policy is to manage interest expense using a combination of fixed-rate and variable-rate debt. Based on $434 million of variable-rate debt outstanding at June 30, 2016, a 100 basis point change in market interest rates would have resulted in an increase in pre-tax interest expense of $4 million on an annualized basis.

We utilize interest rate swaps to help us achieve our desired mix of variable to fixed-rate debt. Our variable-rate debt target generally ranges from 20% to 45% of total debt. We also use forward-starting interest rate swaps and interest rate lock agreements to lock in fixed interest rates on our forecasted issuances of debt. The objective of these hedges is to offset the variability of future payments associated with the interest rate on debt instruments we expect to issue. The gain or loss on the interest rate swaps designated as cash flow hedges is generally deferred in accumulated OCI until settlement, at which point it is amortized to interest expense over the life of the related debt. For additional information, see Note 6 to our unaudited condensed consolidated financial statements included under Part I, Item 1 herein.

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Credit Risk

Wholesale Services We have established credit policies to determine and monitor the creditworthiness of counterparties, as well as the quality of pledged collateral. We also utilize master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When we are engaged in more than one outstanding derivative transaction with the same counterparty and we also have a legally enforceable netting agreement with that counterparty, the “net” mark-to-market exposure represents the netting of the positive and negative exposures with that counterparty and a reasonable measure of our credit risk. We also use other netting agreements with certain counterparties with whom we conduct significant transactions. Master netting agreements enable us to net certain assets and liabilities by counterparty. We also net across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions.

We may require counterparties to pledge additional collateral when deemed necessary. We conduct credit evaluations and obtain appropriate internal approvals for a counterparty’s line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody’s and BBB- from S&P. Generally, we require credit enhancements by way of guaranty, cash deposit or letter of credit for transaction counterparties that do not have investment grade ratings.

We have a concentration of credit risk as measured by our 30-day receivable exposure plus forward exposure. As of June 30, 2016, our top 20 counterparties represented 46%, or $132 million, of our total counterparty exposure and had a weighted average S&P equivalent credit rating of A-, which is consistent with the prior year. The S&P equivalent credit rating is determined by a process of converting the lower of the S&P or Moody’s ratings to an internal rating ranging from 9 to 1, with 9 being equivalent to AAA/Aaa by S&P and Moody’s, respectively, and 1 being D or Default by S&P and Moody’s, respectively. A counterparty that does not have an external rating is assigned an internal rating based on the strength of the financial ratios of that counterparty. To arrive at the weighted average credit rating, each counterparty is assigned an internal ratio, which is multiplied by their credit exposure and summed for all counterparties. The sum is divided by the aggregate total counterparties’ exposures, and this numeric value is then converted to an S&P equivalent. The following table provides credit risk information related to our third-party natural gas contracts receivable and payable positions as of the periods presented.



	Gross receivables						Gross payables
	Jun. 30,		Dec. 31,		Jun. 30,		Jun. 30,		Dec. 31,		Jun. 30,
In millions	2016		2015		2015		2016		2015		2015
Netting agreements in place
Counterparty is investment grade	$	274	$	299	$	307	$	145	$	136	$	146
Counterparty is non-investment grade	7		8		5		16		17		11
Counterparty has no external rating	145		133		114		275		265		297
No netting agreements in place
Counterparty is investment grade	3		5		4		—		—		1
Amount recorded on unaudited Condensed Consolidated Balance Sheets	$	429	$	445	$	430	$	436	$	418	$	455

We have certain trade and credit contracts that have explicit minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, we would need to post collateral to continue transacting business with some of our counterparties. If such collateral were not posted, our ability to continue transacting business with these counterparties would be impaired. If our credit ratings had been downgraded to non-investment grade status, the required amounts to satisfy potential collateral demands under such agreements with our counterparties would have totaled $2 million at June 30, 2016, which would not have had a material impact on our consolidated results of operations, cash flows or financial condition.

There have been no significant changes to our credit risk related to any of our segments other than wholesale services, as described in Item 7A ”Quantitative and Qualitative Disclosures about Market Risk” of our 2015 Form 10-K.

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Item 4. Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of June 30, 2016, the end of the period covered by this report. No system of controls, no matter how well-designed and operated, can provide absolute assurance that the objectives of the system of controls are met, and no evaluation of controls can provide assurance that the system of controls has operated effectively in all cases. Our disclosure controls and procedures, however, are designed to provide reasonable assurance that the objectives of disclosure controls and procedures are met.

Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were effective as of June 30, 2016. Our disclosure controls and procedures are designed to ensure that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods in SEC rules and forms and that such information is accumulated and communicated to our management, including our principal executive officer and our principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

(b) Changes in Internal Control over Financial Reporting There were no changes in our internal control over financial reporting that occurred during the quarter ended June 30, 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

The nature of our business ordinarily results in periodic regulatory proceedings before various state and federal authorities. In addition, we are party as both plaintiff and defendant to a number of lawsuits related to our business on an ongoing basis. Management believes that while the resolutions of these regulatory proceedings and litigation, whether individually or in the aggregate, could possibly be material to earnings in a particular quarter, they will not have a material adverse effect on our consolidated balance sheets or cash flows for the year. For more information regarding our regulatory proceedings and litigation, see Note 11 to our unaudited condensed consolidated financial statements under Part I, Item 1 herein.

Item 1A. Risk Factors

For information regarding our risk factors, see the factors discussed in Part I, Item 1A, “Risk Factors” in our 2015 Form 10-K. These risk factors could materially affect our business, financial condition or future results. Other than certain risk factors associated with completion of the merger with Southern Company, there have been no significant changes to our risk factors included in Item 1A of our 2015 Form 10-K. The risks described in the referenced document are not the only risks facing the company. Additional risks and uncertainties not currently known to us or that we currently do not recognize as material may also materially adversely affect our business, financial condition or future results.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

There were no purchases of our common stock by us or any affiliated purchasers during the second quarter of 2016, and no unregistered sales of equity securities were made during this period.

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Item 6. Exhibits



Exhibit Number	Description of Exhibit	Filer	The Filings Referenced for Incorporation by Reference
3.1	Amended and Restated Articles of Incorporation of Southern Company Gas	Southern Company Gas	July 11, 2016, Form 8-K, Exhibit 3.1
3.2	Amended and Restated Bylaws of Southern Company Gas	Southern Company Gas	July 11, 2016, Form 8-K, Exhibit 3.2
4.2	Southern Company Gas Capital Corporation 3.250% Senior Notes due 2026	Southern Company Gas	May 18, 2016, Form 8-K, Exhibit 4.2
4.3	Southern Company Gas Guarantee related to the 3.250% Senior Notes due 2026	Southern Company Gas	May 18, 2016, Form 8-K, Exhibit 4.3
12	Computation of Ratio of Earnings to Fixed Charges	Southern Company Gas	Filed herewith
31.1	Certification of Andrew W. Evans	Southern Company Gas	Filed herewith
31.2	Certification of Elizabeth W. Reese	Southern Company Gas	Filed herewith
32.1	Certification of Andrew W. Evans	Southern Company Gas	Filed herewith
32.2	Certification of Elizabeth W. Reese	Southern Company Gas	Filed herewith
101.INS	XBRL Instance Document	Southern Company Gas	Filed herewith
101.SCH	XBRL Taxonomy Extension Schema	Southern Company Gas	Filed herewith
101.CAL	XBRL Taxonomy Extension Calculation Linkbase	Southern Company Gas	Filed herewith
101.DEF	XBRL Taxonomy Definition Linkbase	Southern Company Gas	Filed herewith
101.LAB	XBRL Taxonomy Extension Labels Linkbase	Southern Company Gas	Filed herewith
101.PRE	XBRL Taxonomy Extension Presentation Linkbase	Southern Company Gas	Filed herewith

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



		Southern Company Gas
		(Registrant)

Date:	July 26, 2016	/s/ Elizabeth W. Reese
		Elizabeth W. Reese
		Executive Vice President and Chief Financial Officer

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