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

Attached files

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8-K - 8-K - SOUTHERN CO	soq22016proform8-k.htm
EX-99.2 - EXHIBIT 99.2 - SOUTHERN CO	proformafinancials-q22016.htm

Exhibit 99.1

SOUTHERN COMPANY GAS QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2016

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).

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).

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).

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).

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).

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).

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.

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

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.

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.

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.

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.

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.

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.

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

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.

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.

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

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

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.

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

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

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

SOUTHERN CO - FORM 8-K - EX-99.1 - EXHIBIT 99.1 - August 8, 2016

Attached files

SOUTHERN CO Reports