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EX-32.2 - EXHIBIT 32.2 - SOUTHERN Co GASq22016ex322.htm
EX-32.1 - EXHIBIT 32.1 - SOUTHERN Co GASq22016ex321.htm
EX-31.2 - EXHIBIT 31.2 - SOUTHERN Co GASq22016ex312.htm
EX-31.1 - EXHIBIT 31.1 - SOUTHERN Co GASq22016ex311.htm
EX-12 - EXHIBIT 12 - SOUTHERN Co GASq22016ex12.htm

 
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
 
Item Number.
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



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



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).










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
 
 
 
 
 
 
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
 
 
 
 
 
 
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
)