UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
(Mark One) 
þQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 30, 2013
OR
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from        toQuarterly Period Ended March 31, 2014
 
Commission File Number 1-14174
 
AGL RESOURCES INC.
(Exact name of registrant as specified in its charter)Ten Peachtree Place NE, Atlanta, Georgia 30309
404-584-4000
 
Georgia58-2210952
(State or other jurisdiction of incorporation or organization)incorporation)(I.R.S. Employer Identification No.)
 
Ten Peachtree Place NE, Atlanta, Georgia 30309
(Address and zip code of principal executive offices)
404-584-4000
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrantAGL Resources Inc.: (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. Yes þ No ¨
 
Indicate by check mark whether the registrantAGL Resources Inc. has submitted electronically and posted on its corporate Web site, if any,website every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨
months.
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” ”accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

LargeAGL Resources Inc. is a large accelerated filer þ
and is not a shell company.
Accelerated filer ¨
Non-accelerated filer The number of shares of AGL Resources Inc.’s common stock, $5.00 Par Value¨, (Do not check if a smaller reporting company)
outstanding as of April 22, 2014 was 119,257,873Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes ¨ No þ
 
Indicate the number of shares outstanding of each of the issuer's classes of common stock as of the latest practicable date.
ClassOutstanding as of October 23, 2013
Common Stock, $5.00 Par Value118,788,590


 
 
 


AGL RESOURCES INC.
Quarterly Report on Form 10-Q
For the Quarter Ended September 30, 2013March 31, 2014

TABLE OF CONTENTS
  Page     Page 
Glossary of Key Terms
Glossary of Key Terms
  3 
Glossary of Key Terms
  3 
         
Item Number.Item Number.     Item Number.      
 
PART I - FINANCIAL INFORMATION
      
PART I - FINANCIAL INFORMATION
    
            
1 
Condensed Consolidated Financial Statements (Unaudited)
  4 1 
Condensed Consolidated Financial Statements (Unaudited)
  4 
  
Condensed Consolidated Statements of Financial Position
  4   
Condensed Consolidated Statements of Financial Position
  4 
  
Condensed Consolidated Statements of Income
  5   
Condensed Consolidated Statements of Income
  5 
  
Condensed Consolidated Statements of Other Comprehensive Income
  6   
Condensed Consolidated Statements of Other Comprehensive Income
  6 
  
Condensed Consolidated Statements of Equity
  7   
Condensed Consolidated Statements of Equity
  7 
  
Condensed Consolidated Statements of Cash Flows
  8   
Condensed Consolidated Statements of Cash Flows
  8 
  
Notes to Condensed Consolidated Financial Statements (Unaudited)
  9   
Notes to Condensed Consolidated Financial Statements (Unaudited)
  9 
  
Note 1 - Organization and Basis of Presentation
  9   
Note 1 - Organization and Basis of Presentation
  9 
  
Note 2 - Significant Accounting Policies and Methods of Application
  9   
Note 2 - Significant Accounting Policies and Methods of Application
  9 
  
Note 3 - Fair Value Measurements
  15   
Note 3 - Regulated Operations
  13 
  
Note 4 - Derivative Instruments
  16   
Note 4 - Fair Value Measurements
  14 
  
Note 5 - Employee Benefit Plans
  18   
Note 5 - Derivative Instruments
  15 
  
Note 6 - Debt and Credit Facilities
  19   
Note 6 - Employee Benefit Plans
  17 
  
Note 7 - Equity
  21   
Note 7 - Debt and Credit Facilities
  17 
  
Note 8 - Non-Wholly Owned Entities
  22   
Note 8 - Equity
  19 
  
Note 9 - Commitments, Guarantees and Contingencies
  24   
Note 9 - Non-Wholly Owned Entities
  20 
  
Note 10 - Segment Information
  27   
Note 10 - Commitments, Guarantees and Contingencies
  21 
2 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
  30   
Note 11 - Segment Information
  22 
  
Forward-Looking Statements
  30   
Note 12 – Subsequent Events
  23 
  
Executive Summary
  30 2 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
  24 
  
Results of Operations
  34   
Forward-Looking Statements
  24 
  
Liquidity and Capital Resources
  41   
Executive Summary
  25 
  
Critical Accounting Policies and Estimates
  46   
Results of Operations
  27 
3 
Quantitative and Qualitative Disclosures About Market Risk
  47   
Liquidity and Capital Resources
  34 
4 
Controls and Procedures
  50   
Critical Accounting Policies and Estimates
  37 
  
 
PART II - OTHER INFORMATION
      
Accounting Developments
  37 
       3 
Quantitative and Qualitative Disclosures About Market Risk
  38 
1 
Legal Proceedings
  50 4 
Controls and Procedures
  40 
   1A 
Risk Factors
  50   
 
PART II - OTHER INFORMATION
    
2 
Unregistered Sales of Equity Securities and Use of Proceeds
  50        
6 
Exhibits
  51 1 
Legal Proceedings
  41 
          1A 
Risk Factors
  41 
  
SIGNATURE
  52 2 
Unregistered Sales of Equity Securities and Use of Proceeds
  41 
6 
Exhibits
  41 
       
  
SIGNATURE
  42 



GLOSSARY OF KEY TERMS

20122013 Form 10-KOur Annual Report on Form 10-K for the year ended December 31, 2012,2013, filed with the SEC on February 6, 20132014
AFUDCAllowance for funds used during construction, which represents the estimated cost of funds, from both debt and equity sources, used to finance the construction of major projects and is capitalized in PP&E and considered rate base for ratemaking purposes
AGL CapitalAGL Capital Corporation
AGL Credit Facility$1.3 billion credit agreement entered into by AGL Capital to support the AGL Capitalits commercial paper program
AGL ResourcesAGL Resources Inc., together with its consolidated subsidiaries
Atlanta Gas LightAtlanta Gas Light Company
BcfBillion cubic feet
Central ValleyCentral Valley Gas Storage, LLC
Chattanooga GasChattanooga Gas Company
Compass EnergyCompass Energy Services, Inc.
EBIT
Earnings before interest and taxes, a non-GAAPthe primary measure thatof our operating segments’ profit or loss, which includes operating income and other income and excludes financing costs, including interest on debt, and income tax expense, each of which we evaluate on a consolidated level.
ERCEnvironmental remediation costs
FASBFinancial Accounting Standards Board
FitchFitch Ratings
GAAPAccounting principles generally accepted in the United States of America
Georgia CommissionGeorgia Public Service Commission, the state regulatory agency for Atlanta Gas Light
Golden Triangle StorageGolden Triangle Storage, Inc.
Heating Degree DaysA measure of the effects of weather on our businesses, calculated as the extent to whichwhen the average daily temperature istemperatures are less than 65 degrees Fahrenheit
Heating SeasonThe period from November through March when natural gas usage and operating revenues are generally higher
Horizon PipelineHorizon Pipeline Company, LLC
Illinois CommissionIllinois Commerce Commission, the state regulatory agency for Nicor Gas
Jefferson IslandJefferson Island Storage & Hub, LLC
LIFOLast-in, first-out
LNGLiquefied natural gas
LOCOMLower of weighted average cost or current market price
MarketersMarketers selling retail natural gas in Georgia and certificated by the Georgia Commission
Moody’sMoody’s Investors Service
New Jersey BPUNew Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown Gas
NicorNicor Inc. - an acquisition completed in December 2011 and former holding company of Nicor Gas
Nicor Advanced EnergyPrairie Point Energy, LLC, doing business as Nicor Advanced Energy
Nicor GasNorthern 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
Nicor ServicesNicor Energy Services Company
Nicor SolutionsNicor Solutions, LLC
NUINUI Corporation - an acquisition completed in November 2004
NYMEXNew York Mercantile Exchange, Inc.
OCIOther comprehensive income
Operating marginA non-GAAP measure of income, calculated as operating revenues minus cost of goods sold and revenue tax expense that excludes operation and maintenance expense, depreciation and amortization, certain taxes other than income taxes, Nicor merger expenses and gains or losses on the sale of our assets, if any.
OTCOver-the-counter
PBRPerformance-based rate a regulatory plan at Nicor Gas that provided economic incentives based on natural gas cost performance. The plan terminated in 2003.
PiedmontPiedmont Natural Gas Company, Inc.
Pivotal Home SolutionsNicor Energy Services Company, doing business as Pivotal Home Solutions
PP&EProperty, plant and equipment
S&PStandard & Poor’s Ratings Services
Sawgrass StorageSawgrass Storage, LLC
SECSecurities and Exchange Commission
SequentSequent Energy Management, L.P.
Seven SeasSeven Seas Insurance Company, Inc.
SouthStar
SouthStar Energy Services, LLC
STRIDEAtlanta Gas Light’s Strategic Infrastructure Development and Enhancement program
Tennessee AuthorityTennessee Regulatory Authority, the state regulatory agency for Chattanooga Gas
TEUTwenty-foot equivalent unit, a measure of volume in containerized shipping equal to one 20-foot-long container
Triton
Triton Container Investments, LLC
Tropical ShippingTropical Shipping and Construction Company Limited
U.S.United States
VaR
Value-at-risk is the maximum potential loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree of probability.
VIEVariable interest entity
Virginia CommissionVirginia State Corporation Commission, the state regulatory agency for Virginia Natural Gas
Virginia Natural GasVirginia Natural Gas, Inc.
WACOGWeighted average cost of gas



PART I – FINANCIAL INFORMATION
Item 1. Condensed Consolidated Financial Statements (Unaudited)(Unaudited)

AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
(UNAUDITED)

  As of  As of  
In millions, except share amounts September 30, 2013    December 31, 2012    September 30, 2012   March 31, 2014     December 31, 2013 March 31, 2013  
Current assets              
Cash and cash equivalents $131  $131  $91  $293  $105  $149 
Short-term investments  42   58   60   52   50   43 
Receivables                      
Energy marketing receivables  502   677   397 
Gas, unbilled and other receivables  341   686   305 
Energy marketing  1,226   786   627 
Gas, unbilled and other  1,109   772   874 
Less allowance for uncollectible accounts  32   28   31   49   29   39 
Total receivables  811   1,335   671 
Total receivables, net
  2,286   1,529   1,462 
Regulatory assets  297   162   119 
Inventories, net  797   708   778   263   667   393 
Regulatory assets  133   145   158 
Derivative instruments  97   130   144   127   99   100 
Other current assets  80   161   233 
Other  130   121   95 
Total current assets  2,091   2,668   2,135   3,448   2,733   2,361 
Long-term assets and other deferred debits                      
Property, plant and equipment  10,920   10,478   10,281   11,220   11,104   10,610 
Less accumulated depreciation  2,307   2,131   2,069   2,397   2,323   2,202 
Property, plant and equipment, net  8,613   8,347   8,212   8,823   8,781   8,408 
Goodwill  1,883   1,837   1,817   1,869   1,888   1,883 
Regulatory assets  871   944   994   736   737   878 
Intangible assets  180   96   96   170   173   156 
Derivative instruments  15   14   15   11   20   11 
Other long-term assets and deferred debits  251   235   234 
Other  319   324   243 
Total long-term assets and other deferred debits  11,813   11,473   11,368   11,928   11,923   11,579 
Total assets $13,904  $14,141  $13,503  $15,376  $14,656  $13,940 
Current liabilities                      
Energy marketing trade payables $1,119  $671  $653 
Short-term debt $832  $1,377  $1,048   741   1,171   868 
Energy marketing trade payable  539   611   444 
Accounts payable - trade
  304   334   292 
Other accounts payable - trade
  444   432   314 
Accrued expenses  390   210   166 
Temporary LIFO liquidation  252   -   179 
Current portion of long-term debt and capital leases  200   -   226 
Regulatory liabilities  174   161   117   161   183   238 
Accrued expenses  157   140   119 
Customer deposits and credit balances  140   143   159   104   136   115 
Accrued environmental remediation liabilities  48   57   61   82   70   63 
Derivative instruments  38   33   37   63   75   20 
Accrued regulatory infrastructure program costs  32   121   122 
Current portion of long-term debt and capital leases  -   226   226 
Other current liabilities  143   135   139 
Other  197   174   218 
Total current liabilities  2,407   3,338   2,764   3,753   3,122   3,060 
Long-term liabilities and other deferred credits                      
Long-term debt  3,816   3,327   3,330   3,610   3,813   3,324 
Accumulated deferred income taxes  1,587   1,588   1,555   1,699   1,667   1,568 
Regulatory liabilities  1,524   1,477   1,465   1,550   1,518   1,498 
Accrued pension and retiree welfare benefits  405   404   509 
Accrued environmental remediation liabilities  416   387   365   358   377   362 
Accrued retiree welfare benefits  262   268   296 
Accrued pension obligations  249   240   213 
Derivative instruments  6   6   5   19   5   4 
Other long-term liabilities and other deferred credits  74   75   112 
Other  71   74   74 
Total long-term liabilities and other deferred credits  7,934   7,368   7,341   7,712   7,858   7,339 
Total liabilities and other deferred credits  10,341   10,706   10,105   11,465   10,980   10,399 
Commitments, guarantees and contingencies (see Note 9)
             
Commitments, guarantees and contingencies (see Note 10)
             
Equity                      
Common stock, $5 par value; 750,000,000 shares authorized:
outstanding: 118,778,298 shares at September 30, 2013, 117,855,075 shares at December 31, 2012 and 117,743,809 shares at September 30, 2012
      595   590   590 
Additional paid in capital  2,046   2,014   2,012 
Common stock, $5 par value; 750,000,000 shares authorized:
outstanding: 119,247,421 shares at March 31, 2014, 118,888,876 shares at December 31, 2013 and 118,123,770 shares at March 31, 2013
  597   595   592 
Additional paid-in capital
  2,059   2,054   2,019 
Retained earnings  1,100   1,035   990   1,358   1,126   1,134 
Accumulated other comprehensive loss  (208)  (218)  (203)  (135)  (136)  (211)
Treasury shares, at cost: 216,523 shares at September 30, 2013 and December 31, 2012 and September 30, 2012  (8)  (8)  (8)
Treasury shares, at cost: 216,523 shares at March 31, 2014 and December 31, 2013 and March 31, 2013  (8)  (8)  (8)
Total common shareholders’ equity  3,525   3,413   3,381   3,871   3,631   3,526 
Noncontrolling interest  38   22   17   40   45   15 
Total equity  3,563   3,435   3,398   3,911   3,676   3,541 
Total liabilities and equity $13,904  $14,141  $13,503  $15,376  $14,656  $13,940 
See Notes to Condensed Consolidated Financial Statements (Unaudited).
See Notes to Condensed Consolidated Financial Statements (Unaudited).
      
See Notes to Condensed Consolidated Financial Statements (Unaudited).
      

4

AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)

         
 
Three months ended September 30,
  
Nine months ended September 30,
  
Three months ended March 31,
 
In millions, except per share amounts 2013  2012  2013  2012  2014  2013 
Operating revenues (includes revenue taxes of $8 and $82 for the three and nine months in 2013 and $8 and $63 for the three and nine months in 2012) $675  $614  $3,288  $2,704 
Operating revenues (includes revenue taxes of $68 for the three months in 2014 and $50 for the three months in 2013) $2,563  $1,709 
Operating expenses                        
Cost of goods sold  229   215   1,609   1,174   1,454   973 
Operation and maintenance  226   212   718   675   317   259 
Depreciation and amortization  109   104   325   310   98   107 
Taxes other than income taxes  29   27   144   123   89   71 
Nicor merger expenses  -   2   -   15 
Goodwill impairment loss  19   - 
Total operating expenses  593   560   2,796   2,297   1,977   1,410 
Gain on sale of Compass Energy  -   -   11   - 
Operating income  82   54   503   407   586   299 
Other income  7   6   19   19   3   5 
Interest expense, net  (43)  (45)  (135)  (137)  (48)  (46)
Earnings before income taxes  46   15   387   289 
Income before income taxes  541   258 
Income tax expense  18   6   145   106   239   94 
Net income  28   9   242   183   302   164 
Less net income attributable to the noncontrolling interest  -   -   11   10   12   10 
Net income attributable to AGL Resources Inc. $28  $9  $231  $173  $290  $154 
Per common share data                        
Basic earnings per common share attributable to AGL Resources Inc. common shareholders $0.24  $0.08  $1.96  $1.48  $2.44  $1.31 
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders $0.24  $0.08  $1.96  $1.48  $2.44  $1.31 
Cash dividends declared per common share $0.47  $0.46  $1.41  $1.28  $0.49  $0.47 
Weighted average number of common shares outstanding                        
Basic  118.2   117.1   117.8   116.9   118.5   117.4 
Diluted  118.5   117.5   118.1   117.3   118.9   117.7 

See Notes to Condensed Consolidated Financial Statements (Unaudited).

5


AGL RESOURCES INC. AND SUBSIDIARIES
 CONDENSED CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME
(UNAUDITED)

         
 
Three months ended September 30,
  
Nine months ended September 30,
  
Three months ended March 31,
 
In millions 2013  2012  2013  2012  2014  2013 
Net income $28  $9  $242  $183  $302  $164 
Other comprehensive income (loss), net of tax                
Other comprehensive income, net of tax        
Retirement benefit plans                        
Reclassification of actuarial losses to net benefit cost (net of income tax of $3 and $8 for the three and nine months ended September 30, 2013, and $2 and $6 for the three and nine months ended September 30, 2012)
  3   2   11   10 
Reclassification of prior service credits to net benefit cost (net of income tax of $(1) for the nine months ended September 30, 2013)  (2)  -   (3)  - 
Reclassification of actuarial losses to net benefit cost (net of income tax of $1 for the three months ended March 31, 2014, and $2 for the three months ended March 31, 2013)
  1   4 
Reclassification of prior service credits to net benefit cost  -   (1)
Retirement benefit plans  1   2   8   10   1   3 
Cash flow hedges, net of tax                        
Reclassification of realized derivative instrument (gains) losses to net income (net of income tax of $1 for the nine months ended September 30, 2013 and $1 and $2 for the three and nine months ended September 30, 2012)  -   2   2   4 
Net derivative instrument gains arising during the period (net of income tax of $1 for the three months ended March 31, 2013)  4   2 
Reclassification of realized derivative (gains) losses to net income (net of income tax of $1 for the three months ended March 31, 2013)  (4)  2 
Cash flow hedges, net  -   2   2   4   -   4 
Other comprehensive income, net of tax  1   4   10   14   1   7 
Comprehensive income  29   13   252   197   303   171 
Less comprehensive income attributable to noncontrolling interest  -   -   11   10   12   10 
Comprehensive income attributable to AGL Resources Inc. $29  $13  $241  $187  $291  $161 

See Notes to Condensed Consolidated Financial Statements (Unaudited).

6

AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
(UNAUDITED)

 AGL Resources Inc. Shareholders        AGL Resources Inc. Shareholders       
 Common stock  Additional paid-in  Retained  Accumulated other comprehensive  Treasury  Noncontrolling     Common stock  
Additional
paid-in
  Retained  Accumulated other comprehensive  Treasury  Noncontrolling    
In millions, except per share amounts Shares  Amount  capital  earnings  loss  shares  interest  Total  Shares  Amount  capital  earnings  loss  shares  interest  Total 
Balance as of December 31, 2011  117.0  $586  $1,989  $967  $(217) $(7) $21  $3,339 
Balance as of December 31, 2012  117.9  $590  $2,014  $1,035  $(218) $(8) $22  $3,435 
Net income  -   -   -   173   -   -   10   183   -   -   -   154   -   -   10   164 
Other comprehensive income  -   -   -   -   14   -   -   14   -   -   -   -   7   -   -   7 
Dividends on common stock ($1.28 per share)  -   -   -   (150)  -   -   -   (150)
Distributions to noncontrolling interest  -   -   -   -   -   -   (14)  (14)
Dividends on common stock ($0.47 per share)  -   -   -   (55)  -   -   -   (55)
Distributions to noncontrolling interests  -   -   -   -   -   -   (17)  (17)
Stock granted, share-based compensation, net of forfeitures  -   -   (9)  -   -   -   -   (9)  -   -   (6)  -   -   -   -   (6)
Stock issued, dividend reinvestment plan  0.2   1   7   -   -   -   -   8   -   1   2   -   -   -   -   3 
Stock issued, share-based compensation, net of forfeitures  0.5   3   17   -   -   (1)  -   19   0.2   1   6   -   -   -   -   7 
Stock-based compensation expense (net of tax)  -   -   8   -   -   -   -   8 
Balance as of September 30, 2012  117.7  $590  $2,012  $990  $(203) $(8) $17  $3,398 
Stock-based compensation expense, net of tax
  -   -   3   -   -   -   -   3 
Balance as of March 31, 2013  118.1  $592  $2,019  $1,134  $(211) $(8) $15  $3,541 

  AGL Resources Inc. Shareholders       
  Common stock  Additional paid-in  Retained  Accumulated other comprehensive  Treasury  Noncontrolling    
In millions, except per share amounts Shares  Amount  capital  earnings  loss  shares  interest  Total 
Balance as of December 31, 2012  117.9  $590  $2,014  $1,035  $(218) $(8) $22  $3,435 
Net income  -   -   -   231   -   -   11   242 
Other comprehensive income  -   -   -   -   10   -   -   10 
Dividends on common stock ($1.41 per share)
  -   -   -   (166)  -   -   -   (166)
Contribution from noncontrolling interest                          22   22 
Distributions to noncontrolling interest  -   -   -   -   -   -   (17)  (17)
Stock granted, share-based compensation, net of forfeitures  -   -   (6)      -   -   -   (6)
Stock issued, dividend reinvestment plans  0.2   1   7   -   -   -   -   8 
Stock issued, share-based compensation, net of forfeitures  0.7   4   22   -   -   -   -   26 
Stock-based compensation expense (net of tax)  -   -   9   -   -   -   -   9 
Balance as of September 30, 2013  118.8  $595  $2,046  $1,100  $(208) $(8) $38  $3,563 
  AGL Resources Inc. Shareholders       
  Common stock  
Additional
 paid-in
  Retained  Accumulated other comprehensive  Treasury  Noncontrolling    
In millions, except per share amounts Shares  Amount  capital  earnings  loss  shares  interest  Total 
Balance as of December 31, 2013  118.9  $595  $2,054  $1,126  $(136) $(8) $45  $3,676 
Net income  -   -   -   290   -   -   12   302 
Other comprehensive income  -   -   -   -   1   -   -   1 
Dividends on common stock ($0.49 per share)  -   -   -   (58)  -   -   -   (58)
Distributions to noncontrolling interests  -   -   -   -   -   -   (17)  (17)
Stock granted, share-based compensation, net of forfeitures  -   -   (12)  -   -   -   -   (12)
Stock issued, dividend reinvestment plan  -   -   2   -   -   -   -   2 
Stock issued, share-based compensation, net of forfeitures  0.3   2   12   -   -   -   -   14 
Stock-based compensation expense, net of tax
  -   -   3   -   -   -   -   3 
Balance as of March 31, 2014  119.2  $597  $2,059  $1,358  $(135) $(8) $40  $3,911 

See Notes to Condensed Consolidated Financial Statements (Unaudited).

7


 
AGL RESOURCES INC. AND SUBSIDIARIES
 CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)

      
 
Nine months ended September 30,
  
Three months ended March 31,
 
In millions 2013  2012  2014  2013 
Cash flows from operating activities            
Net income $242  $183  $302  $164 
Adjustments to reconcile net income to net cash flow provided by operating activities                
Depreciation and amortization  325   310   98   107 
Deferred income taxes  42   (24)
Goodwill impairment loss  19   - 
Change in derivative instrument assets and liabilities  37   61   (17)  18 
Deferred income taxes  (28)  89 
Gain on sale of Compass Energy  (11)  - 
Changes in certain assets and liabilities                
Receivables, other than energy marketing  354   403 
Inventories, net of temporary LIFO liquidation  656   494 
Accrued expenses  180   26 
Trade payables, other than energy marketing  51   (6)
Energy marketing receivables and trade payables, net  103   64   8   92 
Prepaid taxes  64   13   2   76 
Accrued expenses  17   (43)
Accrued natural gas costs  14   (4)
Inventories  (89)  (28)
Trade payables, other than energy marketing  (19)  14 
Receivables, other than energy marketing  (317)  (172)
Deferred/accrued natural gas costs  (228)  43 
Other, net
  61   (30)  57   32 
Net cash flow provided by operating activities  1,070   1,032   853   850 
Cash flows from investing activities                
Expenditures for property, plant and equipment  (535)  (569)  (164)  (148)
Acquisitions of assets  (154)  -   -   (122)
Disposition of assets  12   - 
Other, net  16   (8)  -   14 
Net cash flow used in investing activities  (661)  (577)  (164)  (256)
Cash flows from financing activities                
Issuance of senior notes  494   - 
Contribution from noncontrolling interest  22   - 
Net payments and borrowings of short-term debt  (545)  (273)
Payment of senior notes  (225)  - 
Net repayments of commercial paper  (430)  (509)
Dividends paid on common shares  (166)  (150)  (58)  (55)
Distribution to noncontrolling interest  (17)  (14)  (17)  (17)
Payment of medium-term notes  -   (15)
Proceeds from termination of interest rate swap  -   17 
Other, net  28   2   4   5 
Net cash flow used in financing activities  (409)  (433)  (501)  (576)
Net increase in cash and cash equivalents  -   22   188   18 
Cash and cash equivalents at beginning of period  131   69   105   131 
Cash and cash equivalents at end of period $131  $91  $293  $149 
Cash paid during the period for                
Interest $138  $142  $58  $58 
Income taxes $90  $4  $14  $26 
Non cash financing transaction                
Refinancing of gas facility revenue bonds $200  $-  $-  $200 

See Notes to Condensed Consolidated Financial Statements (Unaudited).

8

AGL RESOURCES INC. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 1 - Organization and Basis of Presentation

General

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

The December 31, 20122013 Condensed Consolidated Statement of Financial Position data was derived from our audited financial statements, but does not include all disclosures required by GAAP. 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 normally included in financial statements prepared in conformity with GAAP. 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 presentation of our financial results for the interim periods. These unaudited Condensed Consolidated Financial Statements should be read in conjunction with our Consolidated Financial Statements and related notes included in Item 8 of our 20122013 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 and 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, the accounts of our majority-owned andor otherwise controlled subsidiaries and the accounts of our consolidated VIE for which we are the primary beneficiary. For unconsolidated entities that we do not control, but exercise significant influence over, we use the equity method of accounting and our proportionate share of income or loss is recorded on the unaudited Condensed Consolidated Statements of Income. See Note 89 for additional information. We have eliminated intercompany profits and transactions in consolidation except for intercompany profits where recovery of such amounts is probable under the affiliates’ rate regulation process. Certain amounts from prior periods have been reclassified and revised to conform to the current period presentation. Such reclassifications and revisions had no material impact on prior periods.

During the three months ended September 30, 2013, we recorded a $4 million ($2 million net of tax) reduction to our interest expense to correct the amortization period of credit fees related to the execution of the AGL Credit Facility in 2010 and subsequent amendment in 2011.

Note 2 2 - Significant Accounting Policies and Methods of Application

Our accounting policies are described in Note 2 to our Consolidated Financial Statements and related notes included in Item 8 of our 20122013 Form 10-K. There were no significant changes to our accounting policies during the ninethree months ended September 30, 2013March 31, 2014.

Use of Accounting Estimates

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

Cash Cash Equivalents and Cash InvestmentsEquivalents

Our cash and cash equivalents primarily consist primarily of cash on deposit, money market accounts and certificates of deposit held by domestic subsidiaries with original maturities of three months or less. As of September 30,March 31, 2014 and 2013, and 2012, and December 31, 2012, we had $742013, $75 million, $76 million and $80 million, respectively, of cash and short-termshort and long-term investments was held by Tropical Shipping. ThisAs of March 31, 2014, in conjunction with negotiating the agreement to sell Tropical Shipping and Seven Seas, we determined that we no longer have the intent to indefinitely reinvest Tropical Shipping’s cash and short and long-term investments are available for use by our other operations only if we repatriate a portionoffshore. For more information on the sale of Tropical Shipping’s earningsShipping and Seven Seas, see Income Tax Expense and Goodwill within this note and Note 12.

Energy Marketing Receivables and Payables

Our wholesale services segment provides services to retail and wholesale marketers and utility and industrial customers. These customers, also known as counterparties, utilize netting agreements that enable our wholesale services segment to net receivables and payables by counterparty upon settlement. Wholesale services also nets across product lines and against cash collateral, provided the master netting and cash collateral agreements include such provisions. While the amounts due from, or owed to, wholesale services’ counterparties are settled net, they are recorded on a gross basis in the formour unaudited Condensed Consolidated Statements of a dividend,Financial Position as energy marketing receivables and pay a significant amount of United States income tax. See Note 12 to our Consolidated Financial Statements included in Item 8 of our 2012 Form 10-K for additional information on our income taxes.energy marketing payables.

9
Our wholesale services segment has trade and credit contracts that contain minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, wholesale services would need to post collateral to continue transacting business with some of its counterparties. To date, our credit ratings have exceeded the minimum requirements. As of March 31, 2014 and 2013, and December 31, 2013, the collateral that wholesale services would have been required to post if our credit ratings had been downgraded to non-investment grade status would not have had a material impact to our consolidated results of operations, cash flows or financial condition. If such collateral were not posted, wholesale services’ ability to continue transacting business with these counterparties would be negatively impacted.

Inventories

For our regulated utilities, except Nicor Gas, our natural gas inventories and the inventories we hold for Marketers in Georgia are carried at cost on a WACOG basis. In Georgia’s competitive environment, Marketers sell natural gas to firm end-use customers at market-based prices. Part of the unbundling process, which resulted from deregulation and provides this competitive environment, is the assignment to Marketers of certain pipeline services that Atlanta Gas Light has under contract. On a monthly basis, Atlanta Gas Light assigns the majority of the pipeline storage services that it has under contract to Marketers, along with a corresponding amount of inventory. Atlanta Gas Light also retains and manages a portion of its pipeline storage assets and related natural gas inventories for system balancing and to serve system demand. See Note 910 for information regarding a regulatory filing by Atlanta Gas Light related to natural gas inventory.

Nicor Gas’ inventory is carried at cost on a LIFO basis. Inventory decrements occurring during interim periods that are expected to be restored prior to year-endyear 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 inventory liquidation. Any temporary LIFO liquidation is included as a current liability in our unaudited Condensed Consolidated Statements of Financial Position. Interim inventory decrements that are not expected to be restored prior to year-endyear end are charged to cost of goods sold at the actual LIFO cost of the layers liquidated. AsThe inventory decrement as of September 30,March 31, 2014 is expected to be restored prior to year end. The inventory decrement as of March 31, 2013 and 2012, there was no inventory decrement.restored prior to December 31, 2013.

Our retail operations, wholesale services and midstream operations segments are carriedcarry inventory at the lower of cost or market value, where cost is determined on a WACOG basis or market value.basis. For these segments, we evaluate the weighted average cost of their natural gas inventories against market prices to determine whether any declines in market prices below the WACOG are other than temporary. For any declines considered to be other than temporary, we record adjustments to reduce the weighted average cost of the natural gas inventory to market value. For the periods presented, wethree months ended March 31, 2014, wholesale services recorded a $2 million LOCOM adjustments to cost of goods sold in the following amountsadjustment to reduce the value of our inventories to market value.
  Three months ended September 30,  Nine months ended September 30, 
In millions 2013  2012  2013  2012 
Retail operations $1  $-  $1  $3 
Wholesale services  -   -   8   18 
Midstream operations  -   -   -   1 
value. We recorded no LOCOM adjustment for the three months ended March 31, 2013.

Energy Marketing Receivables and Payables

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

Our wholesale services segment has trade and credit contracts that contain minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, wholesale services would need to post collateral to continue transacting business with some of its counterparties. To date, our credit ratings have exceeded the minimum requirements. As of September 30, 2013, December 31, 2012 and September 30, 2012, the collateral that wholesale services would have been required to post if our credit ratings had been downgraded to non-investment grade status would not have had a material impact to our consolidated results of operations, cash flows or financial position. If such collateral were not posted, wholesale services’ ability to continue transacting business with these counterparties would be negatively impacted.

Fair Value Measurements

We have financial and nonfinancial assets and liabilities subject to fair value measurement. The financial assets and liabilities measured and carried at fair value include cash and cash equivalents, and derivative assets and liabilities. The carrying values of receivables, short and long-term investments, accounts payable, short-term debt, other current assets and liabilities, and accrued interest approximate fair value. Our nonfinancial assets and liabilities include pension and other retirement benefits, which are presented in Note 4 to our Consolidated Financial Statements and in related notes included in Item 8 of our 20122013 Form 10-K.

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

10
Derivative Instruments

The fair value of the natural gas and weather derivative instruments that we use to manage exposures arising from changing natural gas prices and weather risk reflects the estimated amounts that we would receive or pay to terminate or close the contracts at the reporting date, taking into account the current unrealized gains or losses on open contracts. We use external market quotes and indices to value substantially all of our derivative instruments. See Note 34 and Note 45 for additional derivative disclosures.

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

On June 28, 2013 we entered into an OTC weather derivative to reduce the risk of lower operating margins related to the risk of significantly warmer-than-normal weather in Illinois during the fourth quarter of 2013. The weather derivative is based on fourth quarter 2013 Heating Degree Days at Chicago Midway International Airport and is a cash-settled option. If weather is warmer than normal during the fourth quarter of 2013 the option would partially offset lower operating margin that would result from lower customer usage. Since the option would not be exercised if heating degree days are equal to or higher than normal, the option would not offset margins that are higher because of colder than normal weather.

Nicor Gas also enters into derivative instruments to reduce the earnings volatility of certain forecasted operating costs arising from fluctuations in natural gas prices, such as the purchase of natural gas for company use. These derivative instruments are carried at fair value. To the extent hedge accounting is not elected, changes in such fair values are recorded in the current period as operation and maintenance expenses.

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

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

We also enter into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal weather in the Heating Season. Exchange-traded options are carried at fair value, with changes reflected in operating revenues. Non exchange-traded options are accounted for using the intrinsic value method and do not qualify for hedge accounting designation. Changes in the intrinsic value for non exchange-traded contracts are also reflected in operating revenues in our unaudited Condensed Consolidated Statements of Income.

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

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

1110
Depreciation Expense

We compute depreciation expense for distribution operations by applying composite, straight-line rates (approved by the state regulatory agencies) to the investment in depreciable property.

On August 30, 2013 Nicor Gas filed a depreciation study with the Illinois Commission that proposed a composite depreciation rate of 3.07% compared to the current composite rate of 4.10%. On October 23, 2013 the Illinois Commission approved our proposed composite depreciation rate for Nicor Gas. The depreciation rate is effective as of the date the depreciation study was filed and a $4 million reduction to our depreciation expense will be recognized in the fourth quarter of 2013 for the period from August 30, 2013 through September 30, 2013.

Goodwill

OurDuring the first quarter of 2014, we completed an engineering study at our storage and fuels reporting unit within midstream operations, which indicated a reduced forecast of working gas capacity from what was projected when our 2013 annual goodwill impairment analysis that was performed during the fourth quarter of 20122013. Given that the 2013 annual goodwill impairment test indicated that the estimated fair value of athis reporting unit within our midstream operations segment, with $14 million of goodwill, exceeded its carrying valueamount by less than 10%5%, we considered this reduced storage capacity as of our testing date. During the third quarter of 2013 we identified a reduction in the near-term market rates at which we are able to re-contract capacity at our storage facilities. We considered a decline in near-term rates an indicator of potential impairment and, accordingly, conducted an interim goodwill impairment analysis during the thirdfirst quarter of 2013.2014.

The estimated fair value of this reporting unit was determined utilizing the income and market approaches. The market approach, is based on observable transactions of comparable companies and assets. The income approach estimateswhich estimated the fair value based upon the present value of estimated future cash flows discounted at an appropriate risk-free rate. Theseflows. The forecasts contain a degree of uncertainty, and changes in the projected cash flows could significantly increase or decrease the estimated fair value of the reporting unit. Key assumptions used in the income approach, included long-termwhich were updated during the first quarter of 2014 to reflect the contracting activity that occurred during the quarter, assume discrete period revenue growth through fiscal 2022 to reflect the recovery of subscription rates, stabilization of earnings and establishment of a reasonable base year that was used to determineestimate the terminal value atvalue. Consistent with our 2013 annual goodwill impairment testing, we assumed a long-term earnings growth rate in the endterminal year of 2.5%, which we believe is appropriate given the current economic and industry specific expectations. As of the discrete forecast period, current and future rates charged for contracted capacity andvaluation date, we utilized a discount rate. The discount rate of 7.0%, which we believe is applied to estimated future cash flowsappropriate as it reflects the relative risk and the time value of money, and is consistent with the peer group of this reporting unit as well as the discount rates that were utilized in our 2013 annual goodwill impairment tests.

The cash flow forecasts for this reporting unit assumed earnings growth over the next eight years. Should this growth not occur, this reporting unit may fail step one during a future goodwill impairment test. Along with any reductions to our cash flow forecasts, changes in other assumptions used in our impairment analysis may require us to proceed to step two of the most significant assumptions used to determine fair value under the income approach. As interest rates rise, the calculated fair values will decrease. The terminal growth rate was based ongoodwill impairment test in a combination of historical and forecasted statistics for real gross domestic product and personal income. The rates we charge to customers for capacity in the storage caverns are based on internal and external rates forecasts.future period.

While near-term rates have declined, management’s forecast for long-term rates have not significantly changed since our 2012 annual impairment analysis was completed. Our interim goodwill impairment test indicated that the estimated fair value of this reporting unit continues to exceed its carrying value. We continue to monitor this reporting unit for impairment and note that continuedamount with a cushion of less than 10%. Continued declines in capacity or subscription rates, or for a sustained period at the current marketsubscription rates or other changes to the assumptions and factors used in this analysis may result in ana future failure of step one of the goodwill impairment of goodwill.test. The risk of impairment of the underlying long-lived assets is not estimated to be significant becauseas the assets have long remaining useful lives and authoritative accounting guidance requires such assets to be tested for impairment based on the basis of undiscounted cash flows over their remaining useful lives.

Regulatory Assets and Liabilities We will continue to monitor this reporting unit for potential impairment.

In April 2014 we entered into a definitive agreement to sell Tropical Shipping and Seven Seas. We accounthave determined, based on the agreed-upon sale price, that $19 million of goodwill attributable to cargo shipping was impaired as of March 31, 2014. Accordingly, this impairment expense was recorded as a separate line item in our unaudited Condensed Consolidated Statements of Income. Changes in the amount of goodwill for the financial effects of regulation in accordance with authoritative guidance related to regulated entities whose ratesthree months ended March 31, 2014 and 2013 are designed to recover the costs of providing service. In accordance with this guidance, incurred costs and estimated future expenditures that otherwise would be charged to expenseprovided in the current period are capitalized as regulatoryfollowing table.
In millions Distribution Operations  Retail Operations  Wholesale Services  Midstream Operations  Cargo Shipping  Other  Consolidated 
Goodwill - December 31, 2012 $1,640  $122  $-  $14  $61  $-  $1,837 
2013 activity  -   46   -   -   -   -   46 
Goodwill - March 31, 2013 $1,640  $168  $-  $14  $61  $-  $1,883 
                             
Goodwill - December 31, 2013 $1,640  $173  $-  $14  $61  $-  $1,888 
Cargo shipping impairment  -   -   -   -   (19)  -   (19)
Goodwill - March 31, 2014 $1,640  $173  $-  $14  $42  $-  $1,869 

See Note 2 to our Consolidated Financial Statements included in Item 8 of our 2013 Form 10-K for additional information on impairment of assets when it.

Other Income

Our other income is probable that such costs or expenditures will be recovered in ratesdetailed in the future. Similarly, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for estimated expenditures that have not yet been incurred. Generally, regulatory assets are amortized into expense and regulatory liabilities are amortized intofollowing table. For more information on our equity investment income, over the period authorized by the regulatory commissions. We are not aware of any evidence that these costs will not be recoverable through either rate riders or base rates, and we believe that we will be able to recover such costs consistent with our historical recoveries. In the event that the provisions of authoritative guidance related to regulated operations were no longer applicable, we would recognize a write-off of regulatory assets that would result in a charge to net income and be classified as an extraordinary item.see Note 9.

    
  Three months ended March 31, 
In millions 2014  2013 
Equity investment income $3  $3 
AFUDC - equity  1   3 
Other, net  (1)  (1)
Total other income $3  $5 

1211
Income Tax Expense

Our regulatory assetsAs a result of our agreement to sell Tropical Shipping and liabilities are summarizedSeven Seas, we have determined that the cumulative foreign earnings of cargo shipping will no longer be indefinitely reinvested offshore, and we recognized tax expense of $31 million in the following table.

In millions September 30, 2013  December 31, 2012  
September 30, 2012
 
Regulatory assets         
Recoverable regulatory infrastructure program costs $46  $47  $46 
Recoverable environmental remediation costs  30   38   33 
Recoverable pension and retiree welfare benefit costs  19   19   27 
Other regulatory assets  38   41   52 
Total regulatory assets - current  133   145   158 
Recoverable environmental remediation costs  456   438   421 
Recoverable pension and retiree welfare benefit costs  183   196   228 
Recoverable regulatory infrastructure program costs  104   167   194 
Long-term debt fair value adjustment  84   90   92 
Other regulatory assets  44   53   59 
Total regulatory assets - long-term  871   944   994 
Total regulatory assets $1,004  $1,089  $1,152 
 
Regulatory liabilities
            
Accrued natural gas costs $104  $93  $62 
Bad debt rider  37   37   30 
Accumulated removal costs  17   16   14 
Other regulatory liabilities  16   15   11 
Total regulatory liabilities - current  174   161   117 
Accumulated removal costs  1,448   1,393   1,381 
Unamortized investment tax credit  26   29   30 
Regulatory income tax liability  26   27   23 
Bad debt rider  20   17   16 
Other regulatory liabilities  4   11   15 
Total regulatory liabilities - long-term  1,524   1,477   1,465 
Total regulatory liabilities $1,698  $1,638  $1,582 

Therethree months ended March 31, 2014 related to the cumulative earnings for which no tax liabilities previously had been recorded. This resulted in an effective tax rate of 45.2% for the three months ended March 31, 2014 compared to 37.9% for the same period last year. As of March 31, 2014, we have been no significant new types$57 million of regulatory assets ordeferred income tax liabilities beyond those discussed in Note 2on our unaudited Condensed Consolidated Statements of Financial Position related to our Consolidated Financial Statements and related notes in Item 8the cumulative earnings of our 2012 Form 10-K.

Other Income

Our other income is detailed in the following table for the periods presented.
  
Three months ended September 30,
  Nine months ended September 30, 
In millions 2013  2012  2013  2012 
Allowance for funds used during construction (AFUDC) - equity $3  $2  $9  $4 
Equity investment income (1)
  3   2   8   10 
Other, net  1   2   2   5 
Total other income $7  $6  $19  $19 
(1)  
Primarily relates to our investment in Triton. See Note 8 for additional information.
foreign subsidiaries that have not been repatriated.

Earnings Per Common Share

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

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

13
The following table shows the calculation of our diluted shares attributable to AGL Resources Inc. common shareholders for the periods presented, if performance units currently earned under the plan ultimately vest and if
stock options currently exercisable at prices below the average market prices are exercised.
  
Three months ended September 30,
  
Nine months ended September 30,
 
In millions (except per share amounts) 2013  2012  2013  2012 
Net income attributable to AGL Resources Inc. $28  $9  $231  $173 
                 
Denominator:                
Basic weighted average number of shares outstanding (1)
  118.2   117.1   117.8   116.9 
Effect of dilutive securities  0.3   0.4   0.3   0.4 
Diluted weighted average number of shares outstanding  118.5   117.5   118.1   117.3 
                 
Earnings per share:                
Basic $0.24  $0.08  $1.96  $1.48 
Diluted $0.24  $0.08  $1.96  $1.48 
(1)  Daily weighted average shares outstanding.                

Acquisitions
  
Three months ended March 31,
 
In millions (except per share amounts) 2014  2013 
Net income attributable to AGL Resources Inc. $290  $154 
         
Denominator:        
Basic weighted average number of shares outstanding (1)
  118.5   117.4 
Effect of dilutive securities  0.4   0.3 
Diluted weighted average number of shares outstanding  118.9   117.7 
         
Earnings per share:        
Basic $2.44  $1.31 
Diluted $2.44  $1.31 
(1)  Daily weighted average shares outstanding.

On January 31, 2013 our retail operations segment acquired approximately 500,000 service plans and certain other assets from NiSource Inc. for $120 million, plus $2 million of working capital. These service plans provide home warranty protection solutions and energy efficiency leasing solutions for residential and small business utility customers and complement the retail services business acquired in the Nicor merger. The preliminary allocation of the purchase price is as follows:

In millions   
Current assets $5 
PP&E  11 
Goodwill  46 
Intangible assets  64 
Current liabilities  (4)
Total purchase price $122 

Intangible assets related to this acquisition are primarily customer relationships of $47 million and trade names of $17 million. The amortization periods are estimated to be 14 years for customer relationships and 10 years for trade names.

On June 30, 2013 our retail operations segment acquired approximately 33,000 residential and commercial energy customer relationships in Illinois for $32 million. These customer relationships have been recorded as an intangible asset and are expected to be amortized on a straight-line basis over an estimated period of 14 to 16 years.

Sale of Compass Energy

On May 1, 2013 we sold Compass Energy, a non-regulated retail natural gas business supplying commercial and industrial customers, which was part of our wholesale services segment. We received an initial cash payment of $12 million, which resulted in an $11 million pre-tax gain ($5 million net of tax). Under the terms of the purchase and sale agreement, we are eligible to receive contingent cash consideration up to $8 million with a guaranteed minimum receipt of $3 million. The contingent cash consideration will be received from the buyer over a five-year earn out period based upon the financial performance of Compass Energy.

Accounting Developments

On January 1, 2013 we adopted ASU 2011-11, Disclosures about Offsetting Assets and Liabilities and ASU 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, which require disclosures about offsetting and related arrangements in order to help financial statement users better understand the effect of those arrangements on our financial position. This guidance had no impact on our unaudited Condensed Consolidated Financial Statements. See Note 4 for additional disclosures about our offsetting of derivative assets and liabilities.

On January 1, 2013 we adopted ASU 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, which requires enhanced disclosures of amounts reclassified out of accumulated other comprehensive income by component. This guidance had no impact on our unaudited Condensed Consolidated Financial Statements. See Note 7 for additional disclosures relating to accumulated other comprehensive income.


1412


Note 3- Regulated Operations

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

In millions March 31, 2014  December 31, 2013  March 31, 2013 
Regulatory assets         
Deferred natural gas costs $161  $1  $- 
Recoverable regulatory infrastructure program costs  48   48   47 
Recoverable ERC  38   45   28 
Recoverable pension and retiree welfare benefit costs  9   9   19 
Other  41   59   25 
Total regulatory assets - current  297   162   119 
Recoverable ERC  419   433   415 
Recoverable pension and retiree welfare benefit costs  97   99   192 
Recoverable regulatory infrastructure program costs  96   87   135 
Long-term debt fair value adjustment  80   82   88 
Other  44   36   48 
Total regulatory assets - long-term  736   737   878 
Total regulatory assets $1,033  $899  $997 
 
Regulatory liabilities
            
Bad debt over collection $41  $41  $39 
Accumulated removal costs  27   27   17 
Accrued natural gas costs  24   92   133 
Deferred seasonal rates  20   -   20 
Other  49   23   29 
Total regulatory liabilities - current  161   183   238 
Accumulated removal costs  1,456   1,445   1,413 
Regulatory income tax liability  27   27   26 
Unamortized investment tax credit  25   26   28 
Bad debt over collection  14   17   20 
Other  28   3   11 
Total regulatory liabilities - long-term  1,550   1,518   1,498 
Total regulatory liabilities $1,711  $1,701  $1,736 

Base rates are designed to provide the opportunity for both a recovery of cost and 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 commission during future rate proceedings. We believe that we will be able to recover such costs consistent with our historical recoveries.

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

Natural Gas Costs We charge our utility customers for natural gas consumed using natural gas cost recovery mechanisms set by the state regulatory agencies. Under these mechanisms, all prudently incurred natural gas costs are passed through to customers without markup, subject to regulatory review. 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. Deferred natural gas costs are reflected as regulatory assets and accrued natural gas costs are reflected as regulatory liabilities. The following table illustrates the change in net position of these costs from March 31, 2013 to March 31, 2014.

In millions March 31, 2014  March 31, 2013  Change 
Deferred natural gas costs $161  $-  $161 
Accrued natural gas costs  (24)  (133)  109 
Total (1)
 $137  $(133) $270 
(1)  The $270 million change resulted from increased natural gas prices during the first quarter of 2014 compared to the first quarter of 2013, primarily driven by colder weather experienced in the current quarter. These costs will be fully recovered in future periods.

13
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. The ERC assets and liabilities are associated with our distribution operations segment and are generally recoverable through rate mechanisms.

Our ERC liabilities are estimates of future remediation costs for investigation and cleanup of our current and former operating sites that are contaminated. These estimates are based on conventional engineering estimates and the use of probabilistic models of potential costs when such estimates cannot be made, on an undiscounted basis. As cleanup options and plans mature and cleanup contracts are entered into, we are increasingly able to provide conventional engineering estimates of the likely costs of many elements of the remediation program. These estimates contain various engineering 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. The following table provides additional information on the costs related to remediation of our current and former operating sites as of March 31, 2014 and reflects minor changes in estimates since we filed our 2013 Form 10-K.

In millions Probabilistic model cost estimates  
Engineering
estimates
  Amount recorded  Expected costs over next 12 months 
Illinois $211 - $461  $42  $246  $39 
New Jersey  139 - 233   6   144   25 
Georgia and Florida  28 - 112   8   39   10 
North Carolina  n/a   11   11   8 
Total $378 - $806  $67  $440  $82 

Note 4 3 - Fair Value Measurements

The methods used to determine the fair values of our assets and liabilities are described within Note 2.

Derivative Instruments

The following table summarizes, by level within the fair value hierarchy, our derivative assets and liabilities that were carried at fair value on a recurring basis in our unaudited Consolidated Statements of Financial Position as of the dates presented. See Note 45 for additional derivative instrument information.

 Recurring fair values - Derivative instruments 
 September 30, 2013  December 31, 2012  September 30, 2012  March 31, 2014  December 31, 2013  March 31, 2013 
In millions 
Assets (1)
  Liabilities  
Assets (1)
  Liabilities  
Assets (1)
  Liabilities  
Assets (1)
  Liabilities  
Assets (1)
  Liabilities  
Assets (1)
  Liabilities 
Natural gas derivatives                                    
Quoted prices in active markets (Level 1) $4  $(52) $8  $(45) $11  $(55) $18  $(38) $6  $(79) $14  $(38)
Significant other observable inputs (Level 2)  60   (41)  96   (30)  100   (33)  50   (75)  67   (79)  49   (23)
Netting of cash collateral  45   49   33   36   47   46   69   31   43   78   40   37 
Total carrying value (2) (3)
 $109  $(44) $137  $(39) $158  $(42) $137  $(82) $116  $(80) $103  $(24)
Interest rate derivatives                                                
Significant other observable inputs (Level 2) $-  $-  $3  $-  $-  $-  $-  $-  $-  $-  $6  $- 
(1)  Balances of $3$1 million of premium at September 30, 2013, $4March 31, 2014, $3 million at December 31, 20122013 and $1$2 million at September 30, 2012March 31, 2013 associated with certain weather derivatives have been excluded, as they are not material and some are accounted for based on intrinsic value rather than fair value.
(2) There were no materialsignificant unobservable inputs (Level 3) for any of the dates presented.
(3)  There were no materialsignificant transfers between Level 1, Level 2 or Level 3 for any of the dates presented.

Money Market Funds

The fair values of our money market funds were recorded within short-term investments as follows:of the following dates.

In millions At September 30, 2013  At December 31, 2012  
At September 30, 2012
  March 31, 2014  December 31, 2013  
March 31, 2013
 
Money market funds (1)
 $48  $66  $69  $48  $48  $48 
(1) Carried at fair value and classified as Level 1 within the fair value hierarchy.

Debt

Our long-term debt is recorded at amortized cost, with the exception of Nicor Gas’ first mortgage bonds, which wereare recorded at their acquisition date fair value. The fair value adjustment of Nicor Gas’ first mortgage bonds is being amortized over the lives of the bonds. We estimate the fair value of our debt using a discounted cash flow technique that incorporates a market interest yield curve with adjustments for duration, optionality and risk profile. The following table presents the amortized costcarrying amount and fair value of our long-term debt as of the following dates.

In millions September 30, 2013  December 31, 2012  September 30, 2012  March 31, 2014  December 31, 2013  March 31, 2013 
Long-term debt amortized cost $3,816  $3,553  $3,556 
Long-term debt carrying amount $3,810  $3,813  $3,550 
Long-term debt fair value (1)
  4,024   4,057   4,100   4,095   3,956   4,006 
(1)  Fair value determined using Level 2 inputs.


1514

Note 5 4 - Derivative Instruments

A description of our objectives and strategies for using derivative instruments, related accounting policies and methods used to determine their fair values are described in Note 2. See Note 34 for additional fair value disclosures.

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 September 30, 2013,March 31, 2014, for agreements with such features, derivative instruments with liability fair values totaled $44$82 million, for which we had posted no collateral to our counterparties. In addition, our energy marketing receivablesThe maximum collateral that could be required with these features is $15 million. For more information, see “Energy Marketing Receivables and payables,Payables” in Note 2, which also have credit-risk-related or other contingent features, are discussed in Note 2.features. Our derivative instrument activities are included within operating cash flows as an adjustment to net income of $37($17) million and $61$18 million for the ninethree months ended September 30,March 31, 2014 and 2013, and 2012, respectively. See Note 34 for additional derivative instrument information. The following table summarizes the various ways in which we account for our derivative instruments and the impact on our unaudited Condensed Consolidated Financial Statements.

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

Distribution Operations

The following amounts represent net realized gains (losses) related to hedging natural gas costs for the periods presented.
  Three months ended September 30,  Nine months ended September 30, 
In millions 2013  2012  2013  2012 
Nicor Gas $(6) $(12) $2  $(60)
Elizabethtown Gas  (1)  (6)  (5)  (23)

Quantitative Disclosures Related to Derivative Instruments

As of the dates presented, our derivative instruments were comprised of both long and short natural gas positions. A long position is a contract to purchase natural gas, and a short position is a contract to sell natural gas. We had a net long natural gas contracts position outstanding in the following quantities:

In Bcf (1) 
September 30, 2013 (2)
  December 31, 2012  September 30, 2012  
March 31, 2014 (2)
  December 31, 2013  March 31, 2013 
Hedge designation                  
Cash flow hedges  3   6   7   6   6   6 
Not designated as hedges  40   96   35   277   183   304 
Total hedges  43   102   42   283   189   310 
Hedge position                        
Short position  (2,788)  (1,955)  (1,994)  (2,491)  (2,622)  (1,902)
Long position  2,831   2,057   2,036   2,774   2,811   2,212 
Net long position  43   102   42   283   189   310 
(1)  Volumes related to Nicor Gas exclude variable-priced contracts, which are accounted for as derivatives,carried at fair value, but whose fair values are not directly impacted by changes in commodity prices.
(2)  Approximately 97% of these contracts have durations of two years or less and the remaining 3% expire between 2 and 6 years.

16
Derivative Instruments in our Unaudited Condensed Consolidated Statements of Financial Position

In accordance with regulatory requirements, gains and losses on derivative instruments used to hedge natural gas purchases for customer use at Nicor Gas and Elizabethtown Gas are reflected in accrued natural gas costs within our Consolidated Statements of Financial Position until billed to customers. The following amounts represent the net realized gains (losses) related to these natural gas cost hedges for the periods presented.
  
Three months ended March 31,
 
In millions 2014  2013 
Nicor Gas $2  $(1)
Elizabethtown Gas  3   (3)

15
The following table presents the fair values and unaudited Condensed Consolidated Statements of Financial Position classifications of our derivative instruments as of the dates presented.

 Classification  
September 30,  2013
  December 31, 2012  
September 30,  2012
  December 31, 2011   
March 31,  2014
  December 31, 2013  
March 31, 2013
 
In millions  (1) (2)  Assets  Liabilities  Assets  Liabilities  Assets  Liabilities  Assets  Liabilities Classification Assets  Liabilities  Assets  Liabilities  Assets  Liabilities 
Designated as cash flow hedges and fair value hedgesDesignated as cash flow hedges and fair value hedges                         Designated as cash flow hedges and fair value hedges                  
Natural gas contracts Current  $6  $(5) $1  $(2) $4  $(3) $9  $(12)Current $2  $-  $3  $(1) $3  $(1)
Natural gas contracts Long-term   -   -   3   -   -   -   -   - 
Interest rate swap agreements Long-term   -   -   -   -   -   -   13   (13)Current  -   -   -   -   5   - 
Total      6   (5)  4   (2)  4   (3)  22   (25)   2   -   3   (1)  8   (1)
                                    
Not designated as cash flow hedgesNot designated as cash flow hedges                                 Not designated as cash flow hedges                        
Natural gas contracts Current   445   (462)  394   (355)  427   (408)  706   (689)Current  675   (703)  691   (761)  332   (327)
Natural gas contracts Long-term   143   (153)  45   (50)  54   (50)  133   (116)Long-term  80   (98)  206   (220)  46   (48)
Total      588   (615)  439   (405)  481   (458)  839   (805)   755   (801)  897   (981)  378   (375)
Gross amount of recognized assets and liabilities   594   (620)  443   (407)  485   (461)  861   (830)
Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position   (482)  576   (299)  368   (326)  419   (573)  720 
Net amounts of assets and liabilities presented in our unaudited Condensed Consolidated Statements of Financial Position  $112  $(44) $144  $(39) $159  $(42) $288  $(110)
Gross amount of recognized assets and liabilities (1)
Gross amount of recognized assets and liabilities (1)
  757   (801)  900   (982)  386   (376)
Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position (2)
Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position (2)
  (619)  719   (781)  902   (275)  352 
Net amounts of assets and liabilities presented in our unaudited Condensed Consolidated Statements of Financial Position (3)
Net amounts of assets and liabilities presented in our unaudited Condensed Consolidated Statements of Financial Position (3)
 $138  $(82) $119  $(80) $111  $(24)
(1)  
The gross amounts of recognized assets and liabilities are netted within our unaudited Condensed Consolidated Statements of Financial Position 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 above do not include cash collateral held on deposit in broker margin accounts of $94$100 million as of September 30, 2013, $69March 31, 2014, $121 million as of December 31, 2012, $932013 and $77 million as of September 30, 2012 and $147 million as of DecemberMarch 31, 2011.2013. Cash collateral is included in the “Gross amounts offset in our unaudited Condensed Consolidated Statements of Financial Position” line of this table.
(3)  At March 31, 2014, December 31, 2013 and March 31, 2013 we held letters of credit from counterparties that would offset, under master netting arrangements, an insignificant portion of these assets.

Derivative Instruments Impacts in ourthe Unaudited Condensed Consolidated Statements of Income

The following table presents the after tax amountsimpacts of our derivative instruments in our unaudited Condensed Consolidated Statements of Income for the periods presented.

 Three months ended September 30,  Nine months ended September 30,  Three months ended March 31, 
In millions 2013  2012  2013  2012  2014  2013 
            
Designated as cash flow hedges                  
Natural gas contracts - gain reclassified from OCI to cost of goods sold $(1) $(2) $-  $(2)
Natural gas contracts - gain reclassified from OCI to operation and maintenance expense  -   (2)  -   (1)
Interest rate swaps - loss (gain) reclassified from OCI to interest expense  1   2   (2)  (1)
                
Natural gas contracts - net gain reclassified from OCI to cost of goods sold $3  $- 
Natural gas contracts - net gain reclassified from OCI to operation and maintenance expense
  1   - 
Interest rate swaps - loss reclassified from OCI to interest expense  -   (3)
Income tax benefit  -   1 
Net of tax  4   (2)
Not designated as hedges(1)                        
Natural gas contracts - net fair value adjustments recorded in operating revenues (1)
  (14)  (17)  (16)  (40)  (30)  (24)
Natural gas contracts - net fair value adjustments recorded in cost of goods sold (2)
  -   1   (1)  (2)  2   - 
Total gain (losses) on derivative instruments $(14) $(18) $(19) $(46)
Income tax benefit  11   8 
Net of tax  (17)  (16)
Total losses on derivative instruments, net of tax $(13) $(18)
(1)  
Associated with the fair value of existing derivative instruments held at September 30,March 31, 2014 and 2013 and 2012..
(2)  
Excludes losses recorded in operating revenues or cost of goods sold associated with weather derivatives of $3$5 million for the ninethree months ended September 30, 2013March 31, 2014 and gains of $14$2 million for the ninethree months ended September 30, 2012.March 31, 2013.

Any amounts recognized in operating income, related to ineffectiveness or due to a forecasted transaction that is no longer expected to occur were immaterial for the ninethree months ended September 30,March 31, 2014 and 2013 and 2012.

Our expected pre-tax net lossgains to be reclassified from OCI and recognized ininto cost of goods sold, operation and maintenance expensesexpense, interest expense and interest expenseoperating revenues and recognized in our unaudited Condensed Consolidated Statements of Income over the next 12 months is less than $1are $3 million. These pre-tax deferred gains and losses are recorded in OCI related to natural gas derivative contracts associated with retail operations and Nicor Gas and interest rate swaps with AGL Capital.Gas’ system use. The expected lossesgains are based upon the fair values of these financial instruments at September 30, 2013March 31, 2014.

There have been no other significant changes to our derivative instruments, as described in Note 2, Note 4 and Note 45 to our Consolidated Financial Statements and related notes included in Item 8 of our 20122013 Form 10-K.


1716


Note 6 5 - Employee Benefit Plans

Pension Benefits

On December 31, 2012We sponsor the AGL Resources Inc. Retirement Plan, (AGL Plan), the Nicor Companies Pension and Retirement Plan (Nicor Plan) and the Employees’ Retirement Plan of NUI Corporation (NUI Plan) were merged with, and into, the AGL Plan. The eligibility anda tax-qualified defined benefit termsretirement plan for participants under the Nicor Plan and the NUI Plan were not changed as a result of the plan merger. The AGL Planour eligible employees, which is described in Note 6 to our Consolidated Financial Statements and related notes included in Item 8 of our 20122013 Form 10-K.

Following are the components of our pension benefit costs for the periods indicated.

 
Three months ended September 30,
  
Nine months ended September 30,
  
Three months ended March 31,
 
In millions 2013  2012  2013  2012  2014  2013 
Service cost $7  $7  $22  $21  $6  $8 
Interest cost  11   10   32   32   12   10 
Expected return on plan assets  (16)  (16)  (47)  (48)  (16)  (16)
Net amortization of prior service cost  -   -   (1)  (1)
Recognized actuarial loss  9   9   26   26   5   8 
Net periodic pension benefit cost $11  $10  $32  $30  $7  $10 

Retiree Welfare Benefits

On December 31, 2012 the Nicor Gas Welfare Benefit Plan (Nicor Welfare Plan) was terminated and asThe benefits of January 1, 2013 all participants under that plan became eligible to participate in theour Health and Welfare Plan for Retirees and Inactive Employees of AGL Resources Inc. (AGL Welfare Plan). This change in plan participation eligibility did not affect the benefit terms under the predecessor plans. The Nicor Welfare Plan benefits are now being offered to such participants under the AGL Welfare Plan. The benefits of the AGL Welfare Plan are described in Note 6 to our Consolidated Financial Statements and related notes included in Item 8 of our 20122013 Form 10-K.

Following are the components of our retiree welfare benefit costs for the periods indicated.

  Three months ended September 30,  Nine months ended September 30, 
In millions 2013  2012  2013  2012 
Service cost $1  $1  $2  $3 
Interest cost  3   4   10   12 
Expected return on plan assets  (1)  (1)  (4)  (4)
Net amortization of prior service cost  (1)  (1)  (3)  (2)
Recognized actuarial loss  2   2   6   7 
Net periodic welfare benefit cost $4  $5  $11  $16 

Capitalized Costs

Net pension benefit and net welfare benefit costs are included in operation and maintenance expense, except for a portion that is capitalized as a cost of constructing natural gas distribution facilities.

Contributions

Our employees generally do not contribute to these pension and retiree welfare plans. We fund the qualified pension plan by contributing at least the minimum amounts required by applicable regulations and as recommended by our actuary. However, we may contribute in excess of the minimum required amounts.

As a result of the 2012 merging of our pension plans, there were no contributions required during the nine months ended September 30, 2013. We contributed a combined $32 million to the AGL Plan and the NUI Plan during the same period last year. For more information on our pension plans, see Note 6 to our Consolidated Financial Statements and related notes included in Item 8 of our 2012 Form 10-K.


18
  Three months ended March 31, 
In millions 2014  2013 
Service cost $1  $1 
Interest cost  4   3 
Expected return on plan assets  (2)  (1)
Net amortization of prior service cost  (1)  (1)
Recognized actuarial loss  1   2 
Net periodic welfare benefit cost $3  $4 

Note 7 6 - Debt and Credit Facilities

The following table provides maturity dates, year-to-date weighted average interest rates and amounts outstanding for our various debt securities and facilities that are included in our unaudited Condensed Consolidated Statements of Financial Position.for the periods presented. We fully and unconditionally guarantee all debt issued by AGL Capital. For additional information on our debt, see Note 8 in our Consolidated Financial Statements and related notes in Item 8 of our 20122013 Form 10-K.

     September 30, 2013     September 30, 2012 
Dollars in millions Year(s) due  
Weighted average interest rate (1)
  Outstanding  Outstanding at December 31, 2012  
Weighted average interest rate (1)
  Outstanding 
Short-term debt                  
Commercial paper - AGL Capital (2)
 2013   0.4% $680  $1,063   0.5% $875 
Commercial paper - Nicor Gas (2) 2013   0.3   152   314   0.5   173 
Total short-term debt     0.4   832   1,377   0.5   1,048 
Current portion of long-term debt and capital leases                       
Current portion of long-term debt  n/a   -   -   225   4.6   225 
Current portion of capital leases  n/a   -   -   1   4.9   1 
Total current portion of long-term debt and capital leases      -  $-  $226   4.6% $226 
Long-term debt - excluding current portion
                     
Senior notes  2015-2043   5.1% $2,825  $2,325   5.1% $2,325 
First mortgage bonds  2016-2038   5.6   500   500   5.6   500 
Gas facility revenue bonds  2022-2033   0.8   200   200   1.1   200 
Medium-term notes  2017-2027   7.8   181   181   7.8   181 
Total principal long-term debt      4.9   3,706   3,206   5.0   3,206 
Fair value adjustment of long-term debt (3)
  2016-2038   n/a   94   103   n/a   106 
Unamortized debt premium, net  n/a   n/a   16   18   n/a   18 
Total non-principal long-term debt      n/a   110   121   n/a   124 
Total long-term debt         $3,816  $3,327      $3,330 
Total debt         $4,648  $4,930      $4,604 
 
     March 31, 2014     March 31, 2013 
Dollars in millions Year(s) due  
Weighted average interest rate (1)
  Outstanding  Outstanding at December 31, 2013  
Weighted average interest rate (1)
  Outstanding 
Short-term debt                  
Commercial paper - AGL Capital (2)
 2014   0.3% $440  $857   0.5% $868 
Commercial paper - Nicor Gas (2)
 2014   0.2   301   314   0.4   - 
Total short-term debt     0.3   741   1,171   0.5   868 
Current portion of long-term debt and capital leases                       
Current portion of long-term debt 2015   5.0   200   -   4.5   225 
Current portion of capital leases  n/a   -   -   -   5.0   1 
Total current portion of long-term debt and capital leases      5.0% $200  $-   4.5% $226 
Long-term debt - excluding current portion
                     
Senior notes  2016-2043   5.0% $2,625  $2,825   5.1% $2,325 
First mortgage bonds  2016-2038   5.6   500   500   5.6   500 
Gas facility revenue bonds  2022-2033   0.9   200   200   1.2   200 
Medium-term notes  2017-2027   7.8   181   181   7.8   181 
Total principal long-term debt      4.9%  3,506   3,706   5.0%  3,206 
Fair value adjustment of long-term debt (3)
  2016-2038   n/a   88   91   n/a   100 
Unamortized debt premium, net  n/a   n/a   16   16   n/a   18 
Total non-principal long-term debt      n/a   104   107   n/a   118 
Total long-term debt         $3,610  $3,813      $3,324 
Total debt         $4,551  $4,984      $4,418 
(1)  Interest rates are calculated based on the daily weighted average balance outstanding for the ninethree months ended September 30.March 31.
(2)  
As of September 30, 2013,March 31, 2014, the effective interest rates on our commercial paper borrowings were 0.4%3% for AGL Capital and 0.2% for Nicor Gas.
(3)  See Note 34 for additional information on our fair value measurements.

AGL and Nicor Gas Credit Facilities

In October 2013 we notified the administrative agents for our two credit facilities of our request to extend the maturity date of each facility by one year, in accordance with the terms of the respective credit agreements. Subject to receiving the required lender consents for the extensions, the AGL Credit Facility and Nicor Gas Credit Facility maturity dates will be extended to November 10, 2017 and December 15, 2017, respectively. The existing terms, conditions and pricing under the agreements will remain unchanged. Upon receipt of consents from all lenders under the respective agreements, we will pay $1 million in extension fees, which will be amortized over the remaining periods of the respective credit facilities.

Long-Term Debt

On May 16, 2013 we issued $500 million in 30-year senior notes with a fixed interest rate of 4.4%. The net proceeds were used to repay a portion of AGL Capital’s commercial paper, including $225 million we borrowed to redeem our senior notes that matured on April 15, 2013. We fully and unconditionally guarantee all debt issued by AGL Capital.

During the first quarter of 2013, we refinanced $200 million of our outstanding tax-exempt gas facility revenue bonds, $180 million of which were previously issued by the New Jersey Economic Development Authority and $20 million of which were previously issued by Brevard County, Florida. The refinancing involved a combination of the issuance of $60 million of refunding bonds to, and the purchase of $140 million of existing bonds by, a syndicate of banks. Our relationship with the syndicate of banks regarding the bonds is governed by an agreement that contains representations, warranties, covenants and default provisions consistent with those contained in similar financing documents of ours. All of the bonds are floating-rate instruments. AGL Resources had no cash receipts or payments in connection with the refinancing. The letters of credit providing credit support for the outstanding revenue bonds along with other related agreements were terminated as a result of the refinancing.


1917



Interest Rate SwapsCommercial Paper Programs

On April 4, 2013 we entered into two ten-year,We maintain commercial paper programs at AGL Capital and Nicor Gas that consist of short-term, unsecured promissory notes used in conjunction with cash from operations to fund our seasonal working capital requirements. Working capital needs fluctuate during the year and are highest during the injection period in advance of the Heating Season. The Nicor Gas commercial paper program supports working capital needs at Nicor Gas, while all of our other subsidiaries and SouthStar participate in the AGL Capital commercial paper program. During the first quarter of 2014, our commercial paper maturities ranged from 1 to 108 days, and at March 31, 2014, remaining terms to maturity ranged from 1 to 35 days. Total borrowings and repayments netted to a payment of $430 million during the first quarter of 2014. For commercial paper issuances with original maturities over 3 months, borrowings and repayments were $50 million fixed-rate forward-starting interest rate swaps to hedge any potential interest rate volatility prior to our issuance of senior notes in the second quarter 2013. The average interest rate on these swaps was 1.98%. Including existing forward-starting interest rate swap hedges, which were executed last year, we had fixed-rate swaps totaling $300and $145 million, in notional value at an average interest rate of 1.85%. We designated the forward-starting interest rate swaps as cash flow hedges of our second quarter 2013 senior note issuance. The interest rate swaps were settled on May 16, 2013, the senior note issuance date, at which time we received $6 million in proceeds. The $6 million will be amortized to reduce interest expense overrespectively, during the first 10 yearsquarter of the 30-year senior notes.2014.

Financial and Non-Financial Covenants

The AGL Credit Facility and the Nicor Gas Credit Facility each include a financial covenant that requires us to maintain a ratio of total debt to total capitalization of no more than 70% at the end of any fiscal month; however, our goal is to maintain these ratios at levels between 50% and 60%.month. These ratios, as calculated in accordance with the debt covenants, include standby letters of credit and surety bonds and exclude accumulated OCI items related to non-cash OCI pension adjustments, other post-retirementwelfare benefits liability adjustments and accounting adjustments for cash flow hedges. Adjusting for these items, the following table contains our debt-to-capitalization ratios for the dates presented, which are below the maximum allowed.

 September 30, 2013  December 31, 2012  September 30, 2012  March 31, 2014  December 31, 2013  March 31, 2013 
AGL Credit Facility  55%  58%  56%  53%  57%  54%
Nicor Gas Credit Facility  50%  55%  51%  54%  55%  43%

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:

·a maximum leverage ratio
·insolvency events and nonpayment of scheduled principal or interest payments
·acceleration of other financial obligations
·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.


2018


Note 8 7 - Equity

Our other comprehensive incomeOCI amounts are aggregated within our accumulated other comprehensive loss. The following table provides changes in the components of our accumulated other comprehensive loss balance, net of the related income tax effects.

   
2013
 
In millions (1) Cash flow hedges  Retirement benefit plans    Total 
For the three months ended September 30         
Balance as of June 30
 $(1) $(208) $(209)
Other comprehensive income, before reclassifications  -   -   - 
Amounts reclassified from accumulated other comprehensive income  -   1   1 
Net current-period other comprehensive (loss) income  -   1   1 
Balance as of September 30 $(1) $(207) $(208)
             
For the nine months ended September 30            
Balance as of December 31, prior year $(3) $(215) $(218)
Other comprehensive income, before reclassifications  -   -   - 
Amounts reclassified from accumulated other comprehensive income  2   8   10 
Net current-period other comprehensive income  2   8   10 
Balance as of September 30 $(1) $(207) $(208)
In millions (1)
 Cash flow hedges  Retirement benefit plans  Total 
As of December 31, 2012 $(3) $(215) $(218)
OCI, before reclassifications  2   -   2 
Amounts reclassified from accumulated OCI  2   3   5 
As of March 31, 2013  1   (212)  (211)
             
As of December 31, 2013  1   (137)  (136)
OCI, before reclassifications  4   -   4 
Amounts reclassified from accumulated OCI  (4)  1   (3)
As of March 31, 2014 $1  $(136) $(135)
(1)  All amounts are net of income taxes. Amounts in parentheses indicate debits to accumulated other comprehensive loss.

The following table provides details of the reclassifications out of accumulated other comprehensive loss for the three and nine months ended September 30, 2013, and the ultimate impact on net income.

In millions Three Months  Nine Months  
 Three months ended March 31, 
In millions (1)
 2014  2013 
Cash flow hedges             
Natural gas contracts  $(1)  $- Cost of goods sold
Interest rate contracts  1   (3)Interest expense, net
Natural gas contracts (2)
 $4  $- 
Interest rate contracts (3)
  -   (3)
Total before income tax  4   (3)
Income tax benefit  -   1    -   1 
Total cash flow hedges  -   (2)   4   (2)
Retirement benefit plan amortization of                 
Actuarial losses  (6)  (19)
See (2), below
Prior service credits  2   4 
See (2), below
Actuarial losses (4)
  (2)  (6)
Prior service credits (4)
  -   1 
Total before income tax  (4)  (15)   (2)  (5)
Income tax benefit  3   7    1   2 
Total retirement benefit plans  (1)  (8)   (1)  (3)
Total reclassification for the period $(1) $(10)  $3  $(5)
(1)  Amounts in parentheses indicate debits, or reductions, to profit/loss and credits to accumulated other comprehensive loss. Except for retirement benefit plan amounts, the profit/loss impacts are immediate.
(2)
Amounts included within cost of goods sold.
    (3)  Amounts included within interest expense, net.
    (4)  
Amortization of these accumulated other comprehensive loss components is included in the computation of net periodic benefit cost. See Note 56 for additional details about net periodic benefit cost.


2119


Note 9 8 - Non-Wholly Owned Entities

Variable Interest Entities

On a quarterly basis, we evaluate all of our ownership interests to determine if they represent a VIE as defined by the authoritative accounting guidance on consolidation, and if so, which party is the primary beneficiary. We have determined that SouthStar, a joint venture owned 85% by us and 15% by Piedmont, is our only VIE for which we are the primary beneficiary, which requires us to consolidate its assets, liabilities and statements of income. See Note 10 to our Consolidated Financial Statements and related notes included in Item 8 of our 20122013 Form 10-K. Earnings from SouthStar in 20132014 and 20122013 were allocated entirely in accordance with the ownership interests.

On September 1, 2013 we contributed to SouthStar our Illinois retail energy businesses with approximately 108,000 customers. Additionally, Piedmont contributed to SouthStar $22.5 million in cash to maintain its 15% ownership in the joint venture. In connection with the contribution of our Illinois retail energy businesses, we provided certain limited protections to Piedmont regarding the value of the contributed businesses related to goodwill and other intangible assets. Piedmont’s contribution is reflected as an increase to noncontrolling interest on our unaudited Condensed Consolidated Statements of Financial Position and a financing activity on our unaudited Condensed Consolidated Statements of Cash Flows. These funds were used to reduce our commercial paper borrowings.

SouthStar markets natural gas and related services under the trade name Georgia Natural Gas to retail customers primarily in Georgia, under various other trade names to retail customers in Illinois, Ohio, Florida, Maryland and New York, and to commercial and industrial customers in the southeastern United States.

There have been no significant changes to the primary risks associated with SouthStar beyond those discussed in our risk factors included in Item 1A of our 2012 Form 10-K.

SouthStar’s financial results are seasonal in nature, with the majority of its earnings occurring during the first and fourth quarters of each year. SouthStar’s current assets consist primarily of natural gas inventory, derivative instruments and receivables from its customers. SouthStar also has receivables from us due to its participation in AGL Capital’s commercial paper program. See Note 2 for additional discussions of inventories. SouthStar’s restricted assets consist of customer deposits and were immaterial as of September 30, 2013 and 2012. SouthStar’s current liabilities consist primarily of accounts payable for natural gas purchases, other accrued expenses, customer deposits, derivative instruments and payables to us from its participation in AGL Capital’s commercial paper program.

SouthStar’s other contractual commitments and obligations, including operating leases and agreements with third party providers, do not contain terms that would trigger material financial obligations in the event that such contracts were terminated. SouthStar’s creditors have no recourse to our general credit beyond our corporate guarantees that we have provided to SouthStar’s counterparties and natural gas suppliers. We have provided no financial or other support that was not previously contractually required. With the exception of our corporate guarantees, we have not entered into any arrangements that could require us to provide financial support to SouthStar.

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

Cash flows used in our investing activities include capital expenditures for SouthStar of $2 million for the ninethree months ended September 30, 2013March 31, 2014 and 2012.$1 million for the three months ended March 31, 2013. 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. Generally, this distribution occurs in the first quarter of each fiscal year. For each of the ninethree months ended September 30,March 31, 2014 and 2013, SouthStar distributed $17 million to Piedmont and $14 million during the same period last year. The increase was primarily the result of increased earnings year-over-year and a distribution of excess working capital from the joint venture.


22


The following table provides additional information on all ofabout SouthStar’s assets and liabilities as of the dates presented, which are consolidated within our unaudited Condensed Consolidated Statements of Financial Position.

 September 30, 2013  December 31, 2012  September 30, 2012  March 31, 2014    December 31, 2013   March 31, 2013    
In millions Consolidated  SouthStar     Consolidated  SouthStar     Consolidated  SouthStar     Consolidated  
SouthStar (1)
   % (2)    Consolidated 
SouthStar (1)
  % (2)   Consolidated  
SouthStar (1)
  % (2)     
Current assets $2,091  $192   9% $2,668  $201   8% $2,135  $152   7% $3,448  $318   9% $2,733  $264   10% $2,361  $143   6%
Goodwill and other intangible assets  2,063   141   7%  1,933   -   -   1,913   -   -   2,039   138   7   2,061   139   7   2,039   -   - 
Long-term assets and other deferred debits  9,750   11   -   9,540   10   -   9,455   10   -   9,889   20   -   9,862   12   -   9,540   10   - 
Total assets $13,904  $344   2% $14,141  $211   1% $13,503  $162   1% $15,376  $476   3% $14,656  $415   3% $13,940  $153   1%
Current liabilities $2,407  $73   3% $3,338  $62   2% $2,764  $42   2% $3,753  $171   5% $3,122  $95   3% $3,060  $51   2%
Long-term liabilities and other deferred credits  7,934   -   -   7,368   -   -   7,341   -   -   7,712   16   -   7,858   -   -   7,339   -   - 
Total Liabilities  10,341   73   1%  10,706   62   1   10,105   42   -   11,465   187   2   10,980   95   1   10,399   51   1 
Equity  3,563   271   8%  3,435   149   4   3,398   120   4   3,911   289   7   3,676   320   9   3,541   102   3 
Total liabilities and equity $13,904  $344   2% $14,141  $211   1%  13,503  $162   1% $15,376  $476   3% $14,656  $415   3% $13,940  $153   1%
(1)  These amounts reflect information for SouthStar and exclude intercompany eliminations and the balances of our wholly owned subsidiary with an 85% ownership interest in SouthStar.
(2)  SouthStar’s percentage of the amount on our Statements of Financial Position.

The following table provides additional 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 September 30,  Nine months ended September 30,  
Three months ended March 31,
 
In millions 2013  2012  2013  2012  2014  2013 
Operating revenues $98  $87  $464  $401  $374  $250 
Operating expenses                        
Cost of goods sold  81   73   340   286   270   164 
Operation and maintenance  16   13   49   44   24   18 
Depreciation and amortization  1   1   2   2   2   1 
Taxes other than income taxes  -   -   1   2 
Total operating expenses  98   87   392   334   296   183 
Operating income $-  $-  $72  $67  $78  $67 

Equity Method Investments

Income from our equity method investments is classified as other income in our unaudited Condensed Consolidated Statements of Income. The following table provides the income from our equity method investments. For more information about our equity method investments, see Note 10 to our Consolidated Financial Statements underand related notes in Item 8 included inof our 20122013 Form 10-K.

  Three months ended September 30,  Nine months ended September 30, 
In millions 2013  2012  2013  2012 
Triton $3  $2  $7  $8 
Other  -   -   1   2 
The carrying amounts of our investments that are accounted for under the equity method at March 31 were as follows:

In millions 2014  2013 
Triton $67  $72 
Horizon Pipeline  15   16 
Other (1)
  1   9 
Total $83  $97 
(1)  Includes our investment in Sawgrass Storage. In December 2013, the joint venture decided to terminate the development of the Sawgrass storage facility and reduced the carrying amount of the joint venture’s long-lived assets to fair value.


2320


The following table provides the income from our equity method investments for the three months ended March 31.
In millions 2014  2013 
Triton $2  $2 
Horizon Pipeline  1   1 
Total $3  $3 

Note 10 9 - Commitments, Guarantees and Contingencies

Other than the changes in our debt, see Note 6 herein, there were no significant changes to our contractual obligations beyond those described in Note 11 to our Consolidated Financial Statements and related notes as filed in Item 8 of our 2012 Form 10-K.

We have incurred various contractual obligations and financial commitments in the normal course of our operating and financing activities 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 from commercial arrangements that are directly supported by related revenue-producing activities.

We also are involved in legal or administrative proceedings before various courts and agencies with respect to general claims, taxes, environmental, gas cost prudence reviews and other matters. Although we are unable to determine the ultimate outcomes of these other 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 11 in our Consolidated Financial Statements and related notes in Item 8 of our 2013 Form 10-K.

Contingencies and Guarantees

Contingent financial commitments, such as financial guarantees, represent obligations that become payable only if certain predefined events occur and include the nature of the guarantee and the maximum potential amount of future payments that could be required of us as the guarantor.. 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 and indemnities is remote. No liability has been recorded for such guarantees and indemnifications as the fair value is insignificant.immaterial.

Regulatory Matters

On December 21, 2012 Atlanta Gas Light filed a petition with the Georgia Commission for approval to resolve an imbalance of approximately 4.8 Bcf of natural gas related to Atlanta Gas Light’s use of retained storage assets to operationally balance the system for the benefit of the natural gas market. We believe that any costs associated with resolving the imbalance are recoverable from Marketers. TheWe are currently working with the Marketers to settle this matter, and the resolution of this imbalance will ultimately be decided by the Georgia Commission and weCommission. We are currently unable to predict the ultimate outcome.outcome and recovery.

Environmental Matters

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulationscontrol 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. The following table provides more information on the costs related to remediation of our current and former operating sites as of September 30, 2013 and reflects changes in estimates since our 2012 Form 10-K.

In millions Probabilistic model cost estimates  Engineering estimates  Amount recorded  Expected costs over next twelve months 
Illinois $208 - $458  $45  $248  $34 
New Jersey     146 -   240   5   150   5 
Georgia and Florida  42  -   100   11   55   2 
North Carolina                            n/a   11   11   7 
Total $396 -  $798  $72  $464  $48 

Our environmental remediation cost liabilities are estimates of future remediation costsSee Note 3 for our current and former operating sites that are contaminated. Our estimates are based on conventional engineering estimates and the use of probabilistic models of potential costs when such estimates cannot be made, which is generally the case when remediation has not commenced or during the early years of a remediation effort. For those elements of the program where we cannot perform engineering estimates, there remains considerable variability in future cost estimates. Accordingly, we have established a probabilistic model to determine a range of potential expenditures to remediate and monitor our former operating sites. We cannot, at this time, identify any single number within this range as a better estimate of likely future costs, and we generally have recorded the low end of the range for our probabilistic cost estimates.

As we conduct the actual remediation and enter into cleanup contracts, we are increasingly able to provide conventional engineering estimates of the likely costs of many elements of the remediation program. These estimates contain various engineering assumptions, which we refine and update on an ongoing basis. With the exception of our North Carolina site, these costs are recoverable from our customers as they are paid and, accordingly, we have recorded a regulatory asset associated with the recorded liabilities. For more information on our environmental remediation costs, see Note 11 to our Consolidated Financial Statements and related notes as filed in Item 8 of our 2012 Form 10-K.



additional information.

Litigation

We are involved in litigation arising in the normal course of business. Although in some cases the company is 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 the companyus to take charges against, or will result in reductions in, future earnings. Management believes that while the resolution of these contingencies, whether individually or in aggregate, could be material to earnings in a particular period, they will not have a material adverse effect on our consolidated financial position or cash flows. For additional litigation information, see Note 11 in our Consolidated Financial Statements and related notes in Item 8 of our 20122013 Form 10-K.

PBR Proceeding FromNicor Gas’ PBR plan was a regulatory plan that provided economic incentives based on natural gas cost performance. The PBR plan went into effect in 2000 to 2002 and was terminated effective January 1, 2003, following allegations that Nicor Gas operated a PBR plan for natural gas costs.acted improperly in connection with the plan. Under this plan, Nicor Gas’ total gas supply costs were compared to a market-sensitive benchmark. Savings and losses relative to the benchmark were determined annually and shared equally with sales customers. The PBR plan was under reviewSince 2002 the amount of the savings and losses required to be shared has been disputed by the Illinois Commission since 2002 due to allegations that Nicor Gas acted improperly in connection with the plan. On June 27, 2002, the Citizens Utility Board (CUB) filed a motion to reopen the record inand others, with the Illinois Commission’sAttorney General (IAG) intervening, and subject to extensive contested discovery and other regulatory proceedings to reviewbefore administrative law judges and the PBR plan (the “Illinois Commission Proceedings”). As a result of the motion to reopen, Nicor Gas entered into a stipulation withIllinois Commission. In 2009, the staff of the Illinois Commission, and CUB providing for additional discovery. The Illinois Attorney General’s Office (IAGO) has also intervened in this matter. In addition, the IAGO issued Civil Investigation Demands (CIDs) to CUB and the Illinois Commission staff. The CIDs ordered that CUB and the Illinois Commission staff produce all documents relating to any claims that Nicor Gas may have presented, or caused to be presented, regarding false information related to its PBR plan. We have committed to cooperate fully in the reviews of the PBR plan.

The Nicor Board of Directors directed management to, among other things, make appropriate adjustments to account for, and fully address, the adverse consequences to ratepayers, and conduct a detailed study of the adequacy of internal accounting and regulatory controls. The adjustments were made in prior years’ financial statements resulting in a $25 million liability. Included in this $25 million liability is a $4 million loss contingency. A $2 million adjustment to the previously recorded liability, which is discussed below, was made in 2004 increasing the recorded liability to $27 million. By the end of 2003, Nicor Gas completed steps to correct the weaknesses and deficiencies identified in the detailed study of the adequacy of internal controls.

On February 5, 2003 CUB filed a motion for $27 million in sanctions against Nicor Gas in the Illinois Commission Proceedings. In that motion, CUB alleged that Nicor Gas’ responses to certain CUB data requests were false. Also on February 5, 2003, CUB stated in a press release that, in addition to $27 million in sanctions, it would seek additional refunds to consumers. On March 5, 2003 the Illinois Commission staff filed a response brief in support of CUB’s motion for sanctions. On May 1, 2003 the Administrative Law Judges assigned to the proceeding issued a ruling denying CUB’s motion for sanctions. CUB has filed an appeal of the motion for sanctions with the Illinois Commission, and the Illinois Commission has indicated that it will not rule on the appeal until the final disposition of the Illinois Commission Proceedings. It is not possible to determine how the Illinois Commission will resolve the claims of CUB or other parties to the Illinois Commission Proceedings.

In 2004 Nicor Gas became aware of additional information relating to the activities of individuals affecting the PBR plan for the period from 1999 through 2002, including information consisting of third party documents and recordings of telephone conversations from Entergy-Koch Trading, LP (EKT), a natural gas, storage and transportation trader and consultant with whom Nicor Gas did business under the PBR plan. Review of additional information completed in 2004 resulted in the $2 million adjustment to the previously recorded liability referenced above.

The evidentiary hearings on this matter were stayed in 2004 in order to permit the parties to undertake additional third party discovery from EKT. In December 2006 the additional third party discovery from EKT was obtained and the Administrative Law Judge issued a scheduling order that provided for Nicor Gas to submit direct testimony by April 13, 2007. Nicor Gas submitted direct testimony in April 2007, rebuttal testimony in April 2011 and surrebuttal testimony in December 2011. In surrebuttal testimony, we sought $6 million, which included interest due to us of $2 million, as of December 31, 2011. The staff of the Illinois Commission, IAGO and CUB submitted direct testimony to the Illinois Commission in April 2009 and rebuttal testimony in October 2011. In rebuttal testimony, the staff of the Illinois Commission, IAGOIAG and CUB requested refunds of $85 million, $255 million and $305 million, respectively.

In February 2012 we committed to a stipulated resolution of issues, which existed prior to our acquisition of Nicor Gas,stipulation with the staff of the Illinois Commission that would includefor a resolution of the dispute through the crediting to Nicor Gas customers of $64 million. There were no new developments between the date of acquisition and the date of the stipulated resolution. The CUB and IAGO were not parties to the stipulated resolution and continue to pursue their claims in this proceeding. Evidentiary hearings before the Administrative Law Judges were held during the first quarter of 2012 and post-trial legal briefs from the parties were submitted during the second quarter of 2012. Following the submission of legal briefs, onOn November 5, 2012 the Administrative Law Judges issued a proposed order for a refund of $72 million to ratepayers. DuringIn the fourth quarter of 2012, we increased our accrual for this dispute by $8 million for a total of $72 million as a result of these developments and itstheir effect on the estimated liability.

2521
On June 7, 2013 the Illinois Commission issued an order requiring us to refund $72 million to current Nicor Gas’ currentGas customers over a 12-month period. We maintain that the appropriate PBR refund is $64 million, consistent with the stipulated resolution with the staff of the Illinois Commission, and filed an appeal for the amount in excess of that specified in the stipulated resolution. The CUB has also filed an appeal. During the third quarter of 2013 the Illinois Commission denied all applications for rehearing of its June order and the Illinois appellate court denied Nicor Gas’s request for a stay on the obligation to refund the amount in excess of $64 million. On July 1, 2013 we began refunding customers the full $72 million through our purchased gas adjustment mechanism. The amount refunded ismechanism based upon actualon natural gas throughput and $5throughput. Of this amount, $35 million was refunded during the thirdfirst quarter of 2014 and $29 million was refunded in 2013.

Nicor Services Warranty Product Actions Nicor Gas, Nicor Services and Nicor are defendants in a putative class action initially filed in September 2011, in stateCUB appealed the Illinois Commission’s order to the appellate court in Cook County, Illinois. The plaintiffs purport to represent a class of customers ofOn February 28, 2014 CUB filed its initial brief with the appellate court requesting refunds consistent with its 2009 request. Nicor Gas who purchased the Gas Line Comfort Guard product from Nicor Services. The plaintiffs variously allege that the marketing, sale and billing of the Nicor Services Gas Line Comfort Guard violate the Illinois Consumer Fraud and Deceptive Business Practices Act, constitute common law fraud and result in unjust enrichment of Nicor Services and Nicor Gas. The plaintiffs seek, on behalf of the classes they purport to represent, actual and punitive damages, interest, costs, attorney fees and injunctive relief. While we are unable to predict the outcome of these matters or to reasonably estimate our potential exposure related thereto, if any, and have not recorded a liability associated with this contingency, the final disposition of this matterGas’ reply is not expected to have a material adverse impact on our liquidity or financial condition.

Other We also are involved in an investigation by the United States Environmental Protection Agency regarding the applicable regulatory requirements for polychlorinated biphenyl in the Nicor Gas distribution system. While we are unable to predict the outcome of this matter or to reasonably estimate our potential exposure related thereto, if any, and have not recorded a liability associated with this contingency, the final disposition of this matter is not expected to have a material adverse impact on our liquidity or financial condition.

For additional litigation information on these matters, see Note 11 in our Consolidated Financial Statements and related notes in Item 8 of our 2012 Form 10-K.

In addition to the matters set forth above, we are involved in legal or administrative proceedings before various courts and agencies with respect to general claims, taxes, environmental, gas cost prudence reviews and other matters. Although we are unable to determine the ultimate outcomes of these other contingencies, we believe that our financial statements appropriately reflect these amounts, including the recording of liabilities when a loss is probable and reasonably estimable.


due May 16, 2014.

Note 11 10 - Segment Information

Our operating segments comprise revenue-generating components of our company for which we produce separate financial information internally that weis regularly useused 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 five operating segments - distribution operations, retail operations, wholesale services, midstream operations, cargo shipping - and other, a non-operating segment.

Our distribution operations segment is the largest component of our business and includes natural gas local distribution utilities in seven states - Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee and Maryland.states. These utilities construct, manage and maintain intrastate natural gas pipelines and distribution facilities. Although the operations of our distribution operations segment are geographically dispersed, the operating subsidiaries within the distribution operations segment are regulated utilities, with rates determined by individual state regulatory commissions. These natural gas distribution utilities have similar economic and risk characteristics.

We are also involved in several related and complementary businesses. Our retail operations segment includes retail natural gas marketing to end-use customers primarily in Georgia, as well as various businesses that market retail energy-related products and services to residential and small business customers primarily in Illinois, such as warrantyIllinois. Additionally, retail operations provide home protection solutions to customersproducts and customer move connection services for other utilities.services. Our wholesale services segment includesengages in natural gas storage and gas pipeline arbitrage and related activities. Additionally, they provide natural gas asset management andand/or related logistics activitiesservices for each of our utilities except Nicor Gas, as well as for nonaffiliated companies, natural gas storage arbitrage and related activities.companies. Our midstream operations segment includes our non-utility storage fuels and pipeline operations, including the development and operation of high-deliverability natural gas storage assets.

Our cargo shipping segment transports containerized freightcargo between Florida, the eastern coast of Canada, the Bahamas and the Caribbean region. Our cargo shipping segment also includes amounts related to cargo insurance coverage sold to our customers and other third parties. Our cargo shipping segment’s vessels are under foreign registry, and its containers are considered instruments of international trade. Although the majority of its long-lived assets are foreign owned and its revenues are derived from foreign operations, the functional currency is generally the United States dollar. Our cargo shipping segment also includes an equity investment in Triton, a cargo container leasing business. Profits and losses are generally allocated to investors’ capital accounts in proportion to their capital contributions. Our investment in Triton is accounted for under the equity method, and our share of earnings is reported within other income in our unaudited Condensed Consolidated Statements of Income.

Our other segment includes intercompany eliminations and aggregated subsidiaries that are individually not significant enough to be reportable.on a stand-alone basis and that do not fit into one of our other five operating segments.

We evaluate segment performance usingThe chief operating decision maker of the non-GAAPcompany is the Chairman, President and Chief Executive Officer who utilizes EBIT as the primary measure of profit and loss in assessing the results of our segments and operations. EBIT that includes operating income and other income and expenses, and equity investment income.expenses. Items we do not include in EBIT are income taxes and financing costs, including interest and debt expense, each of which we evaluate on a consolidated basis. We believe EBIT is a useful measurement of our performance because it provides information that can be used to evaluate the effectiveness of our businesses from an operational perspective, exclusive of the costs to finance those activities and exclusive of income taxes, neither of which is directly relevant to the efficiency of those operations.

You should not consider EBIT an alternative to, or a more meaningful indicator of, our operating performance than operating income or net income as determined in accordance with GAAP. In addition, our EBIT may not be comparable to a similarly titled measure of another company. The reconciliations of EBIT to operating income, earnings before income taxes and net income for the periods presented are as follows:

  Three months ended September 30,  Nine months ended September 30, 
In millions 2013  2012  2013  2012 
Operating income $82  $54  $503  $407 
Other income  7   6   19   19 
EBIT  89   60   522   426 
Interest expense  43   45   135   137 
Earnings before income taxes  46   15   387   289 
Income taxes  18   6   145   106 
Net income $28  $9  $242  $183 



Information by segment on our Statements of Financial Position as of December 31, 20122013 is as follows:

In millions 
Identifiable and total assets (1)
  Goodwill  
Identifiable and total assets (1)
  Goodwill 
Distribution operations $11,320  $1,640  $11,727  $1,640 
Retail operations  511   122   694   173 
Wholesale services  1,218   -   1,166   - 
Midstream operations  720   14   713   14 
Cargo shipping  464   61   445   61 
Other (2)
  (92)  -   (89)  - 
Consolidated $14,141  $1,837  $14,656  $1,888 
(1)  Identifiable assets are those assets used in each segment’s operations.
(2)  
The assets of our other segment consist primarily of cash and cash equivalents and PP&E, and reflect the effect of intercompany eliminations.


22


Summarized Statements of Income, Statements of Financial Position and capital expenditure information by segment as of and for the periods presented are shown in the following tables.

Three months ended September 30,March 31, 2014

In millions Distribution operations  
Retail
operations
  
Wholesale
 services (1)
  
Midstream
 operations
  
Cargo
shipping
  
Other and intercompany eliminations (3)
  Consolidated 
Operating revenues from external parties $1,738  $406  $286  $44  $89  $-  $2,563 
Intercompany revenues  75   -   47   -   -   (122)  - 
Total operating revenues  1,813   406   333   44   89   (122)  2,563 
Operating expenses                            
Cost of goods sold  1,202   280   3   36   55   (122)  1,454 
Operation and maintenance  211   37   36   6   29   (2)  317 
Depreciation and amortization  80   6   -   5   5   2   98 
Taxes other than income taxes  82   1   1   1   2   2   89 
Goodwill impairment loss  -   -   -   -   19   -   19 
Total operating expenses  1,575   324   40   48   110   (120)  1,977 
Operating income (loss)  238   82   293   (4)  (21)  (2)  586 
Other income  1   -   -   1   2   (1)  3 
EBIT $239  $82  $293  $(3) $(19) $(3) $589 
Identifiable and total assets (2)
 $11,923  $749  $1,782  $698  $419  $(195) $15,376 
Capital expenditures $150  $3  $1  $-  $3  $7  $164 


Three months ended March 31, 2013

In millions Distribution operations  Retail operations  Wholesale services  Midstream operations  Cargo shipping  
Other and intercompany eliminations (4)
  Consolidated 
Operating revenues from external parties $420  $138  $13  $19  $89  $(4) $675 
Intercompany revenues (1)
  36   -   -   -   -   (36)  - 
Total operating revenues  456   138   13   19   89   (40)  675 
Operating expenses                            
Cost of goods sold  111   92   1   9   55   (39)  229 
Operation and maintenance  150   31   13   5   29   (2)  226 
Depreciation and amortization  91   6   -   5   4   3   109 
Taxes other than income taxes  22   1   1   1   2   2   29 
Total operating expenses  374   130   15   20   90   (36)  593 
Operating income (loss)  82   8   (2)  (1)  (1)  (4)  82 
Other income  4   -   -   -   3   -   7 
EBIT $86  $8  $(2) $(1) $2  $(4) $89 
Capital expenditures $200  $3  $-  $3  $6  $5  $217 

Three months ended September 30,2012

In millions Distribution operations  Retail operations  Wholesale services  Midstream operations  Cargo shipping  
Other and intercompany eliminations (4)
  Consolidated 
Operating revenues from external parties $405  $118  $(12) $22  $83  $(2) $614 
Intercompany revenues (1)
  37   -   -   -   -   (37)  - 
Total operating revenues  442   118   (12)  22   83   (39)  614 
Operating expenses                            
Cost of goods sold  107   83   -   12   51   (38)  215 
Operation and maintenance  148   26   11   4   29   (6)  212 
Depreciation and amortization  88   3   -   4   5   4   104 
Taxes other than income taxes  21   1   1   1   1   2   27 
Nicor merger expenses (2)
  -   -   -   -   -   2   2 
Total operating expenses  364   113   12   21   86   (36)  560 
Operating income (loss)  78   5   (24)  1   (3)  (3)  54 
Other income  2   -   1   -   2   1   6 
EBIT $80  $5  $(23) $1  $(1) $(2) $60 
Capital expenditures $189  $3  $1  $18  $1  $7  $219 


28

Nine months ended September 30, 2013

In millions Distribution operations  Retail operations  Wholesale services  Midstream operations  Cargo shipping  
Other and intercompany eliminations (4)
  Consolidated 
Operating revenues from external parties $2,299  $605  $73  $58  $264  $(11) $3,288 
Intercompany revenues (1)
  134   -   -   -   -   (134)  - 
Total operating revenues  2,433   605   73   58   264   (145)  3,288 
Operating expenses                            
Cost of goods sold  1,142   402   21   25   162   (143)  1,609 
Operation and maintenance  494   94   36   17   87   (10)  718 
Depreciation and amortization  271   16   1   13   14   10   325 
Taxes other than income taxes  124   3   2   4   5   6   144 
Total operating expenses  2,031   515   60   59   268   (137)  2,796 
Gain on sale of Compass Energy  -   -   11   -   -   -   11 
Operating income (loss)  402   90   24   (1)  (4)  (8)  503 
Other income (loss)  11   -   -   2   7   (1)  19 
EBIT $413  $90  $24  $1  $3  $(9) $522 
                             
Identifiable and total assets (3)
 $11,300  $652  $930  $726  $464  $(168) $13,904 
Goodwill $1,640  $168  $-  $14  $61  $-  $1,883 
Capital expenditures $495  $7  $-  $11  $9  $13  $535 

Nine months ended September 30,2012

In millions Distribution operations  Retail operations  Wholesale services  Midstream operations  Cargo shipping  
Other and intercompany eliminations (4)
  Consolidated  Distribution operations  
Retail
operations
  
Wholesale
services (1)
  
Midstream
operations
  
Cargo
 shipping
  
Other and intercompany eliminations (3)
  Consolidated 
Operating revenues from external parties $1,848  $517  $59  $56  $247  $(23) $2,704  $1,264  $302  $39  $24  $87  $(7) $1,709 
Intercompany revenues (1)
  124   -   -   -   -   (124)  -   55   -   -   -   -   (55)  - 
Total operating revenues  1,972   517   59   56   247   (147)  2,704   1,319   302   39   24   87   (62)  1,709 
Operating expenses                                                        
Cost of goods sold  767   342   34   24   152   (145)  1,174   765   195   10   12   53   (62)  973 
Operation and maintenance  473   83   35   13   83   (12)  675   185   31   13   6   28   (4)  259 
Depreciation and amortization  262   10   1   10   17   10   310   90   5   -   4   5   3   107 
Taxes other than income taxes  103   3   3   4   4   6   123   64   1   1   1   1   3   71 
Nicor merger expenses (2)
  -   -   -   -   -   15   15 
Total operating expenses  1,605   438   73   51   256   (126)  2,297   1,104   232   24   23   87   (60)  1,410 
Operating income (loss)  367   79   (14)  5   (9)  (21)  407   215   70   15   1   -   (2)  299 
Other income  7   -   1   1   8   2   19   3   -   -   1   2   (1)  5 
EBIT $374  $79  $(13) $6  $(1) $(19) $426  $218  $70  $15  $2  $2  $(3) $304 
                            
Identifiable and total assets (3)
 $10,970  $472  $970  $712  $482  $(103) $13,503 
Goodwill $1,591  $122  $-  $14  $90  $-  $1,817 
Identifiable and total assets (2)
 $11,258  $668  $1,005  $714  $459  $(164) $13,940 
Capital expenditures $457  $7  $1  $77  $2  $25  $569  $137  $1  $-  $4  $1  $5  $148 
(1)  Intercompany revenues - wholesaleWholesale services records its energy marketing and risk management revenues on a net basis and its totalbasis. A reconciliation of our operating revenues includeand our intercompany revenues of $69 million and $312 million foris shown in the three and nine months ended September 30, 2013, respectively, and $93 million and $230 million for the three and nine months ended September 30, 2012, respectively.following table.

In millions 
Third party
gross revenues
  Intercompany revenues  
Total gross
revenues
  
Less gross
gas costs
  
Operating
revenues
 
Three months ending March 31, 2014 $4,051  $298  $4,349  $4,016  $333 
Three months ending March 31, 2013  2,094   140   2,234   2,195   39 
(2)Transaction expenses associated with the Nicor merger are shown separately to better compare year-over-year results.
(3)  Identifiable assets are those used in each segment’s operations.
(4)(3)  The assets of our other segment consist primarily of cash and cash equivalents and PP&E, and reflect the effect of intercompany eliminations.

Note 12 - Subsequent Events

Sale of Tropical Shipping and Seven Seas On April 4, 2014 we entered into a definitive agreement to sell Tropical Shipping and Seven Seas after we obtained board approval for the transaction on such date, and we expect to close the transaction during the third quarter of 2014. After-tax cash proceeds and distributions from the transaction are expected to be $220 million, subject to certain defined post-closing adjustments. As discussed in Note 2, we recognized income tax expense of $31 million in the three months ended March 31, 2014 related to the cumulative earnings for which no tax liabilities had previously been recorded and we expect to record additional income tax expense of $29 million in the third quarter of 2014 related to the taxable gain on the sale. Completion of the transaction is conditioned upon, among other things, the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and approval by the Florida Office of Insurance Regulation.

2923
As discussed in Note 2, we recorded a $19 million impairment loss related to goodwill that was assigned to cargo shipping in conjunction with our 2011 merger with Nicor. This impairment loss represents one-third of the total goodwill that was assigned to this operating segment in purchase accounting. The goodwill impairment was recognized as of March 31, 2014 since we had indication that the fair value of Tropical Shipping and Seven Seas was below the carrying value.

Tropical Shipping and Seven Seas have operated within our cargo shipping segment. Financial results for these entities will be classified as discontinued operations beginning in the second quarter of 2014. Cargo shipping also includes our investment in Triton, which will be reclassified into the other segment.

Dalton Lateral Pipeline On April 11, 2014 we entered into two arrangements associated with the Dalton Lateral pipeline. The first was a construction and ownership agreement through which we will have a 50% undivided ownership interest in the 106 mile Dalton Lateral pipeline that will be constructed in Georgia and serve as an extension of the Transco natural gas pipeline system into northwest Georgia. Our 50% undivided ownership interest is expected to cost approximately $210 million. We also entered into an agreement to lease our 50% undivided ownership in the Dalton Lateral pipeline once it is placed in-service. The annual lease payments to be received are $26 million for an initial term of 25 years. The lessee will be responsible for maintaining the pipeline during the lease term and for providing service to transportation customers under its FERC regulated tariff. Engineering design work has commenced and construction is expected to begin in the second quarter of 2016 with a targeted completion date in the second quarter of 2017. On April 14, 2014, Atlanta Gas Light entered into an agreement with the lessee to acquire firm transportation capacity of 240,000 dekatherms per day associated with the Dalton Lateral pipeline. This capacity will be allocated to the Marketers and will further enhance system reliability as well as provide access to a more diverse supply of natural gas.

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

The following discussion and analysis should be read in conjunction with our unaudited Condensed Consolidated Financial Statements and the notes to our unaudited Condensed Consolidated Financial Statements in this quarterly filing, as well as our 20122013 Form 10-K. Results for the interim periods presented are not necessarily indicative of the results to be expected for the full fiscal period due to seasonal and other factors.

Forward-LookingForward-Looking Statements

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

Forward-looking statements often include words such as "anticipate," "assume," “believe,” "can," "could," "estimate," "expect," "forecast," "future," “goal,” "indicate," "intend," "may," “outlook,” "plan," “potential,” "predict," "project,” “proposed,” "seek," "should," "target," "would," or similar expressions. You are cautioned not to place undue reliance on our forward-looking statements. While we believe that our expectations are reasonable in view of the available information that we currently have, our expectations are subject to future events, risks and uncertainties, and there are numerous factors - many beyond our control - that could cause our actual results to vary from our expectations.

Such events, risks and uncertainties include, but are not limited to, changes in price, supply and demand for natural gas and related products; the impact of changes in state and federal legislation and regulation including any changes related to climate change; actions taken by government agencies on rates and other matters; concentration of credit risk; utility and energy industry consolidation; the impact on cost and timeliness of construction projects by government and other approvals, development project delays, adequacy of supply of diversified vendors, unexpected change in project costs, including the cost of funds to finance these projects and our ability to recover our project costs from our customers; limits on pipeline capacity; the impact of acquisitions and divestitures; our ability to successfully integrate operations that we have or may acquire or develop in the future; direct or indirect effects on our business, financial condition or liquidity resulting from any change in our credit ratings, or any change in the credit ratings of our counterparties or competitors; interest rate fluctuations; financial market conditions, including disruptions in the capital markets and lending environment; general economic conditions; uncertainties about environmental issues and the related impact of such issues, including our environmental remediation plans; the impact of our depreciation study for Nicor Gas and related legislation; conditions to closing the sale of Tropical Shipping and Seven Seas; the capacity of our gas storage caverns; the impact of our construction projects and related capital expenditures; the impact of changes in weather, including climate change, on the temperature-sensitive portions of our business; the impact of natural disasters, such as hurricanes, on the supply and price of natural gas and on our cargo shipping business; acts of war or terrorism; the outcome of litigation; and other factors discussed elsewhere herein and in our other filings with the SEC. There also may be other factors that we do not anticipate or that we do not recognize as material that are not described in this report that could cause our actual results to differ materially from our expectations.

Forward-looking statements speak only as of the date they are made. We expressly disclaim any obligation to publicly update or revise any forward-looking statement, whether as a result of future events, new information or otherwise, except as required under United StatesU.S. federal securities law.

24
Executive Summary Summary

We are an energy services holding company whose principal business is the distribution of natural gas in seven states - Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee and Maryland - through our seven natural gas distribution utilities. We are also involved in several other businesses that are primarily related and complementary to the distribution of natural gas. Our operating segments consist of the following five operating and reporting segments –- distribution operations, retail operations, wholesale services, midstream operations and cargo shipping and one non-operating segment - other. These segments are consistent with how management views and operates our business. For additional information on our operating segments, see Note 10 to our unaudited Condensed Consolidated Financial Statements herein and Item 1, “Business” of our 20122013 Form 10-K. Following are summarized recent developments for our operating segments.

In April 2014, we entered into a definitive agreement to sell Tropical Shipping and Seven Seas, and we anticipate closing the transaction in the third quarter of 2014. After-tax cash proceeds and distributions from the transaction are expected to be $220 million, subject to certain defined post-closing adjustments. Completion of the transaction is conditioned Overview upon, among other things, the expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and approval by the Florida Office of Insurance Regulation.

As a result of the sale, we expect to pay income taxes of approximately $60 million. During the first quarter of 2014, we recorded income tax expense of $31 million related to cumulative foreign earnings for which income taxes had not previously been recorded. We also recorded a goodwill impairment charge of $19 million, for which there is no income tax benefit, during the first quarter of 2014 based upon the agreed-upon sale price. Upon closing, we expect to record income tax expense of $29 million associated with the taxable gain on the sale. On a combined basis, this is expected to result in a reported income tax and impairment expense of approximately $0.66 per share, of which $0.42 was recorded in the first quarter of 2014 with the remainder to be recorded upon completion of the sale.

Tropical Shipping and Seven Seas have operated as part of our cargo shipping segment. Financial results for these entities will be classified as discontinued operations beginning in the second quarter of 2014. The cargo shipping segment also includes our investment in Triton, which will be reclassified into our other segment.

In the first ninethree months of 2014, our net income attributable to AGL Resources Inc. was $290 million, an increase of $136 million compared to the same period in 2013, as we benefited from the return to more normalsignificantly colder-than-normal weather in most of our businesses as compared to the historically warmslightly colder-than-normal weather in 2012.the first quarter of 2013. This cold weather contributed an additional $11 million of operating margin for distribution operations compared to the first quarter of 2013, particularly in Illinois due to the near-record cold. This cold weather also increased the operating margin for retail operations by $11 million, primarily related to Georgia and Illinois, compared to the first quarter of 2013. Additionally, we experienced increased natural gas price volatility that enabled us to capture value in wholesale services. As a result, our operating margin for wholesale services was $301 million higher than the same period in 2013. Wholesale services operating margin for the first quarter 2014 also includes $45 million related to 2013 year-to-date transportation and forward commodity derivative losses associated with 2014 transportation capacity. This is compared to $2 million of similar transportation derivative losses in the first quarter of 2013 related to 2012 year-to-date transportation and forward commodity derivative losses associated with 2013 transportation capacity. Excluding the favorable weather impacts at distribution operations and retail operations, we also achieved growth in our operating margins of $12 million during the first ninethree months of 20132014 primarily as a result of our regulatory infrastructure programs in our distribution operations, targeted acquisition growth in our2013 acquisitions at retail operations and higher contributions from commercial activity in our wholesale operations.

We continue to effectively manage costs and leverage our shared services model across our businesses to largely overcome inflationary effects. Our operation and maintenanceoperating expenses in the first nine monthsquarter of 20132014 were largely consistent with prior yearshigher compared to the same period last year as we achieved efficiencies that offset inflationary costs anda result of an increase in incentive compensation that reflects year over year performance. Our, as we experienced a higher concentration of our annual forecasted earnings in the first quarter as compared to last year. Additionally, our operation and maintenance expense increased at Nicor Gas associated with the cold weather. During this significantly colder-than-normal weather, our employees worked extensive hours to ensure the safe and reliable delivery of natural gas to our customers.

As discussed in Note 2 to the unaudited Condensed Consolidated Financial Statements under Part 1, Item 1 herein, our income tax expenses include a modest increase in bad debt expense compared to 2012 for some of our businesseswere higher by $31 million as a result of colder weather and higher natural gas prices,the cumulative foreign earnings of cargo shipping, which will no longer be indefinitely reinvested offshore. This resulted in higher average customer bills.an effective tax rate of 45.2% for the three months ended March 31, 2014 compared to 37.9% for the same period last year.

Several of our specific business objectives are as follows:

·
Distribution Operations: Invest necessary capital to enhance and maintain safety and reliability; remain a low-cost leader within the industry; opportunistically expand the system and capitalize on potential customer conversions. We intend to continue investing in our regulatory infrastructure programs in Georgia, Virginia, New Jersey and Tennessee to minimize regulatory lag and the recovery cycle.

3025
Distribution Operations At September 30, 2013 our seven utilities within distribution operations served approximately 4.5 million end-use customers with their primary focus being the safe and reliable delivery of natural gas.

Nicor Gas In June 2013 the Illinois Commission issued an order requiring us to refund $72 million to Nicor Gas’ current customers over a 12-month period in connection with Nicor Gas’ operation of a PBR plan from 2000 to 2002. We continue to maintain that the appropriate PBR refund is $64 million, consistent with our stipulated resolution agreed to by Nicor Gas and the staff of the Illinois Commission, and have appealed the amount in excess of that specified in the stipulated resolution. There is no deadline for the Illinois Appellate Court to act on the appeal and we do not expect a decision before the middle of 2014. On July 1, 2013 Nicor Gas began refunding the $72 million through its purchased gas adjustment mechanism based on natural gas throughput, with approximately 40% expected to be refunded in 2013 and 60% expected to be refunded in 2014. During the third quarter of 2013 $5 million was refunded. Nicor Gas previously accrued $72 million for this contingent liability, which is in line with the order issued by the Illinois Commission. See Note 9 to our unaudited Condensed Consolidated Financial Statements for additional information.

In June 2013 we entered into an OTC weather derivative to reduce the risk of lower operating margins related to the risk of significantly warmer-than-normal weather in Illinois during the fourth quarter of 2013. The weather derivative is based on fourth quarter 2013 Heating Degree Days at Chicago Midway International Airport and is a cash-settled option. If weather is warmer than normal during the fourth quarter of 2013 the option would partially offset lower operating margin that would result from lower customer usage. Since the option would not be exercised if heating degree days are equal to or higher than normal, the option would not offset margins that are higher because of colder than normal weather. We continue to evaluate ways to mitigate our Illinois weather risk on an ongoing basis.

In July 2013 Illinois enacted legislation that will allow Nicor Gas to provide more widespread safety and reliability enhancements to its system in a timelier manner than under traditional utility regulation, and to pass along lower program costs to its customers.distribution system. The legislation requiresstipulates that rate increases to customer bills as a result of the investmentany infrastructure investments shall not exceed an annual average 4.0% of base rate revenues. In April 2014 we filed for an infrastructure program under this legislation that would allow us to implement rates under the program effective in January 2015. Our filing included qualified infrastructure cost estimates for three years of $171 million in 2015, $173 million in 2016 and $171 million in 2017. We expectcontinue to submit a plan for approval by the Illinois Commission in mid-2014.effectively manage costs and leverage our shared services model across our businesses to largely overcome inflationary effects.

In July 2013 Illinois enacted legislation that provides a streamlined process to revise depreciation rates for natural gas utilities. On August 30, 2013 Nicor Gas filed a depreciation study with the Illinois Commission that proposed a composite depreciation rate of 3.07% compared to the current composite rate of 4.10%. The composite depreciation rate, if applied to Nicor Gas’ property, plantcollective bargaining agreement expired in February 2014, and equipment as of December 31, 2012, would have resulteda new agreement was ratified in April 2014. During the interim period we operated under a decrease of approximately $50 million in annual depreciation expense. In October 2013 the Illinois Commission approved our proposed composite depreciation ratecontinuity agreement. The new collective bargaining agreement provides for Nicor Gas. The depreciation rate is effective as of the date the depreciation study was filedadditional operational enhancements and an adjustmentchanges to depreciation expense will be recognized during the fourth quarter of 2013. This will reduce our depreciation expense by $4 million for the period from August 30, 2013 through September 30, 2013. A lower composite depreciation ratecertain benefits, but is not expected to impact customer rates and we believe that it would provide an incentive to increase Nicor Gas’ capital expenditures, potentially creating more jobs in the communities that are served by Nicor Gas.have a material effect on our consolidated financial statements.

In September 2013 Nicor Gas filed its second Energy Efficiency Plan, which outlines program offerings and therm reduction goals with spending of $93 million over thea three-year period beginning in June 2014 through May 2017.2014. Nicor Gas’ first Energy Efficiency Program is currently in its third year and will end in May 2014. Although there is no statutory deadline for approval of gas utility plans, Nicor Gas requested approval in the same 5 month timeframe, or by March 1, 2014, as established by statute for electric utilities. The new plan must be implemented by June 1, 2014. A procedural scheduleAll testimony in the case has not been established for this case.filed with the Illinois Commission, and evidentiary hearings were held in March 2014. We expect to receive a final ruling by the Illinois Commission in mid-May 2014, to be effective in June 2014.

Atlanta Gas Light In December 2012accordance with an order issued by the Georgia Commission, where AGL Resources makes a business acquisition that reduces the costs allocated or charged to Atlanta Gas Light for shared services, the net savings to Atlanta Gas Light will be shared equally between the firm customers of Atlanta Gas Light and our shareholders for a ten-year period. In December 2013 we filed a petitionReport of Synergy Savings with the Georgia Commission for approvalin connection with the Nicor acquisition. If and when approved, the net savings are expected to resolve an imbalanceresult in annual rate reductions to the firm customers of approximately 4.8 Bcf of natural gas related to Atlanta Gas Light’s useLight of retained storage assets to operationally balance the system for the benefit of the natural gas market.$5 million. We believe that any costs associated with resolving the imbalance are recoverable from Marketers. The resolution of this imbalance will be decided byexpect the Georgia Commission and we are unable to predictrule on the ultimate outcome.report in the second or third quarter of 2014.

Virginia Natural Gas In May 2013April 2014 the Governor of Virginia signed into law legislation that enables the state's natural gas utilities, including Virginia Natural Gas, to acquire long-term supplies of natural gas and make capital investments to facilitate the delivery of low-cost shale and coal-bed methane gas to Virginia homeowners and businesses. Under the terms of the new statute, Virginia Natural Gas could enter into commercial agreements to obtain up to 25% of its annual firm sales demand for natural gas through long-term contracts or investments such as purchases of reserves. Recovery on investments would be based upon the utility's authorized return on rate base, which would flow through the purchased gas adjustment mechanism or similar mechanism, and approval in advance by the Virginia CommissionCommission. The new statute will also allow us to build pipelines and other infrastructure that deliver shale and coal-bed methane gas into the state's markets that seek to reduce natural gas supply costs or reduce price volatility for consumers, if approved by the Virginia Natural Gas’ Conservation and Ratemaking Efficiency (CARE) plan. The plan provides for a modified CARE plan that includes a more limited set of conservation programs and measures at a reduced cost of $2 million over a three-year period.Commission.

ChattanoogaElizabethtown GasIn AprilMarch 2013, legislation was signed into lawthe New Jersey BPU issued an order inviting the submission of proposals from utilities in New Jersey for infrastructure upgrades designed to protect utility infrastructure from future major storm events. In September 2013, in response to this request, Elizabethtown Gas filed for a Natural Gas Distribution Utility Reinforcement Effort (ENDURE), a program that giveswill improve our distribution system’s resiliency against coastal storms and floods. Under the Tennessee Authority proposed plan, Elizabethtown Gas will invest $15 million in infrastructure and related facilities and communication planning over a one-year period beginning January 2014. Elizabethtown Gas is proposing to accrue and defer carrying charges on the abilityinvestment until its next rate case proceeding. According to approve alternative regulatory mechanisms. The law allows the Tennessee Authority to: (i) implement separate rate adjustment mechanisms that track specific costs, (ii) implement annual rate reviewsprocedural order in lieuthe case, a ruling by the New Jersey BPU is expected in the third quarter of traditional rate cases and (iii) adopt other policies or procedures that permit a more timely review and revision of rates, streamline the regulatory process, and reduce the cost and time associated with the traditional ratemaking processes.2014.

·
Retail Operations: Maintain operating margin in Georgia and Illinois while continuing to expand into other profitable retail markets; integrate our warranty businesses and expand our overall market reach through partnership opportunities with our affiliates. With the continued adoption of fixed-price plans, we expect the Georgia retail market to remain highly competitive; however, our operating margins are forecasted to remain stable with modest growth from the acquisitions completed in 2013 and expansion into new markets.

·
Wholesale Services: Maximize strong storage and transportation positions, including the creation of additional economic value in 2014; effectively perform on existing asset management agreements and expand customer base and maintain cost structure in line with market fundamentals. We anticipate low volatility in certain areas of our portfolio; however, we expect a continuation of volatility in the supply-constrained Northeast corridor in the near-term. We continue to position our business model to secure sufficient supplies of natural gas to meet the needs of our utility customers and to hedge gas prices to effectively manage costs, reduce price volatility and maintain a competitive advantage.

·
Midstream Operations: Optimize storage portfolio, including contracts that have expired or will expire, pursue LNG transportation and natural gas pipeline opportunities and evaluate alternate uses for our storage facilities. In April 2014 we entered into a collaborative arrangement to construct a lateral pipeline in Georgia that will connect with the Transco pipeline system. Also in April 2014 we entered into an agreement to lease our 50% ownership in this lateral pipeline extension once it is placed in-service. For more information on the transactions, see Note 12 to the unaudited Condensed Consolidated Financial Statements under Part I, Item 1 herein.

3126
In April 2013 Chattanooga Gas filed a proposal with the Tennessee AuthorityWe will continue to extend its energy conservation programs and associated rate adjustment mechanismidentify opportunities that adjusts rates to recover reduced operating revenuesarise as a result of reduced customer usage. In August 2013 a status conference was held by the Tennessee Authority and a procedural schedule was established whereby the Tennessee Authority’s Staff will issue a report on the evaluation of the conservation programs, which is expected in 2014. After the Tennessee Authority issues its report, Chattanooga Gas will be requiredattractive natural gas pricing relative to file a report on the impacts of the rate adjustment mechanism within 45 days. Interveners will then have 30 days to respond to Chattanooga Gas’s report and recommendations. The Tennessee Authority granted Chattanooga Gas an extension of its rate adjustment mechanism until the completion of the proceeding.

Retail Operations Our retail operations businesses serve approximately 600,000 energy customers and approximately 1.2 million service contracts in Florida, Georgia, Illinois, Indiana, Kentucky, Ohio, Maryland, Massachusetts, New York, Pennsylvania and West Virginia. SouthStar, Nicor Advanced Energy and Nicor Solutions generate earnings throughother fuel sources. Additionally, the sale of natural gasTropical Shipping and Seven Seas allows us to residential, commercialfocus on growing our core business of operating regulated utilities and industrial customers, primarily in Georgia and Illinois where we capture spreads between wholesale and retail natural gas prices. Additionally, these businesses offer our customers energy-related products that provide for natural gas price stability and utility bill management. These products mitigate and/or eliminate the risks to customers of colder-than-normal weather and/or changes in natural gas prices.complementary non-regulated businesses. We charge a fee or premium for these services. Our retail operations businesseswill also provide warranty protection and home solutions that include gas and electric line repair, equipment repair, insurance and maintenance through Pivotal Home Solutions and represent customers who are on monthly service contracts or warranty products billed at a fixed monthly amount.

In September 2013 we contributed our wholly owned subsidiaries Nicor Advanced Energy and Nicor Solutions, our Illinois retail energy subsidiaries, to our SouthStar joint venture. Piedmont contributed $22.5 million in cash to SouthStarcontinue to maintain its 15% ownership interest in the joint venture. In connection with the contribution of our Illinois retail energy businesses, we provided certain limited protectionsstrong balance sheet and liquidity profile, solid investment grade ratings and our commitment to Piedmont regarding the value of the contributed businesses related to goodwill and other intangible assets. sustainable annual dividend growthSee Note 8 for more information.

As described in Note 2 to our unaudited Condensed Consolidated Financial Statements, during June 2013, our retail operations segment acquired approximately 33,000 residential and commercial relationships in Illinois for $32 million. The transaction significantly increases the size of our retail energy customer portfolio in Illinois with minimal incremental operating expenses. We expect this transaction to result in approximately $4 million of EBIT during 2013.

In January 2013 our retail operations segment acquired approximately 500,000 service plans and certain other assets for $120 million, plus $2 million of working capital. We believe this acquisition will provide an enhanced platform for growth and continued expansion of this business into a number of key markets.

Wholesale Services Our wholesale services segment consists of our wholly owned subsidiary Sequent and engages in asset management and optimization, storage, transportation, producer and peaking services and wholesale marketing of natural gas across the United States and in Canada. It also provides natural gas asset management and/or related logistics services for most of our utilities, as well as for non-affiliated companies. In April 2013 the Tennessee Authority authorized an extension of the asset management agreement between Chattanooga Gas and Sequent. The terms of the agreement remain unchanged, except the expiration date is now March 2015.

In May 2013 we sold Compass Energy, a non-regulated retail natural gas business supplying commercial and industrial customers. We received an initial cash payment of $12 million, which resulted in an $11 million pre-tax gain ($5 million net of tax). Additionally, we are eligible to receive contingent cash consideration up to $8 million with a guaranteed minimum receipt of $3 million. The amount of the contingent cash consideration will be received from the buyer over a five-year earn out period based upon the financial performance of Compass Energy. See Note 2 to our unaudited Condensed Consolidated Financial Statements for additional information.

Midstream Operations Our midstream operations segment includes a number of businesses that are related and complementary to our primary business. The most significant of these businesses is our natural gas storage business, which develops and operates high-deliverability underground natural gas storage assets primarily in the Gulf Coast region of the United States and in northern California. While this business can generate additional revenue during times of peak market demand for natural gas storage services, many of our natural gas storage facilities are covered under a portfolio of short, medium and long-term contracts at fixed market rates.

Golden Triangle Storage’s Cavern 1 began commercial operations in September 2010 and Cavern 2 began commercial operations in September 2012. Cavern 1 is currently going through a process to assess its working gas capacity. The process began in early 2013 and is expected to continue during the fourth quarter of 2013. Limited commercial service resumed in the third quarter 2013 and full commercial service is expected to resume in the first quarter of 2014. Cavern 2 has been covering, and will continue to cover, the obligations of Cavern 1 during this process. Central Valley, located in northern California, began commercial operations for firm customers during the second quarter of 2012.

32
Through our wholly owned subsidiary Cypress Creek Gas Storage, LLC and as a result of our merger with Nicor, we own a 50% interest in Sawgrass Storage, LLC (Sawgrass Storage), a joint venture between us and a privately held energy exploration and production company. Sawgrass Storage was granted certification from the Federal Energy Regulatory Commission (FERC) in March 2012 for the development of an underground natural gas storage facility in Louisiana with 30 Bcf of working gas capacity (expandable to 40 Bcf). The FERC certificate is set to expire in March 2014 if not extended. Given the current weakness in the natural gas storage market and the impending expiration of the FERC certificate, we along with our joint venture partner continue to evaluate our on-going strategy for the Sawgrass Storage facility. Currently, our investment in Sawgrass Storage is $9 million, which could potentially be written-off or impaired in the event of a continued decline in natural gas market fundamentals and the rates for contracting availability capacity, the FERC certificate not being extended or other strategic decisions made by us, our joint venture partner or the joint venture.

Cargo Shipping Our cargo shipping segment consists of Tropical Shipping; multiple wholly owned foreign subsidiaries of Tropical Shipping that are treated as disregarded entities for United States income tax purposes; Seven Seas, a wholly owned domestic cargo insurance company; and an equity investment in Triton, a cargo container leasing business.

In September 2013 we entered into a contract to sell one of our 12 cargo vessels. We will replace this vessel with a chartered vessel, which is expected to provide greater capacity and operational flexibility.

Natural Gas Market Fundamentals Volatility in the natural gas market arises from a number of factors, such as weather fluctuations or changes in supply of, or demand for natural gas in different regions of the country or portions of the interstate and intrastate gas pipeline systems.country. The volatility of natural gas commodity prices has a significant impact on our customer rates, our long-term competitive position against other energy sources and the ability of our retail operations and wholesale services segments to capture value from location and seasonal spreads. Additionally, changes in commodity prices subject a significant portion of our operations to earnings variability. Since 2011 the volatility of the daily Henry Hub spot market prices for natural gas – a benchmark measure for natural gas generally - in the United States has been significantly lower than it had been in previous years. This is the result of a robust

While natural gas supply increased during the weak economy and ample natural gas storage.

Our utility natural gas acquisition strategy is designed to secure sufficient supplies of natural gas and2013/2014 Heating Season in the rights to physically flow natural gas between delivery points in orderU.S., it was not enough to meet the needs of our utility customers and to hedgeincreased demand, resulting in the lowest storage levels in over a decade. Assuming normal weather during the next year, we expect this will result in higher natural gas prices and location spreads to manage costs, reduce price volatility for our utility customers and maintain a competitive advantage.as storage levels are restored.

Our non-utility businesses principally use physical and financial arrangements to reduce the risks associated with both weather-related seasonal fluctuations in market conditions and changing commodity prices. Additionally, our hedging strategies and physical natural gas supplies in storage enable us to reduce earnings risk exposure due to higher gas costs. These economic hedges may not qualify, or may not be designated, for hedge accounting treatment. As a result, our reported earnings for the wholesale services, retail operations and midstream operations segments reflect changes in the fair values of certain derivatives. Accordingly, a decline in natural gas prices or decreases in transportation spreads generally results in hedgederivative gains and correspondinglycorresponding increases in EBIT, while an increase in natural gas prices or a widening of transportation spreads generally results in hedgederivative losses and correspondinglycorresponding decreases in EBIT. These values may change significantly from period to period and are reflected as gains or losses within our operating revenues or our OCI for those derivative instruments that qualify and are designated as accounting hedges.

It is possible that natural gas prices will remain low for an extended period based on current levelsResults of excess supply relative to market demand for natural gas, in part due to abundant sources of new shale natural gas reserves and the lack of demand by commercial and industrial enterprises. However, as economic conditions continue to improve, the demand for natural gas may increase, natural gas prices could rise and higher volatility could return to the natural gas markets. Consequently, we are working to reposition our wholesale services business model with respect to fixed costs, and the types of contracts pursued and executed.

The market fundamentals of midstream operations storage business are cyclical, and as discussed above, the abundant supply of natural gas in recent years and the resulting lack of market and price volatility have negatively impacted the profitability of our storage facilities. In 2013 expiring storage capacity contracts were re-subscribed at lower prices and we anticipate these lower natural gas prices to continue throughout 2013 and 2014 as compared to historical averages. Due to the current market storage rates, we did not re-contract 2.0 Bcf at Golden Triangle Storage and intend to provide other services until market conditions improve to support longer-term contracts. As of September 30, 2013 the overall average firm subscription rate per facility is as follows:
Average Monthly Rate per Dekatherm
Jefferson Island (1)
$0.111
Golden Triangle (1)
0.182
Central Valley0.130
(1)Includes firm capacity contracted by Sequent at April 1, 2013 of 1.5 Bcf at an average monthly rate of $0.07 per dekatherm at Jefferson Island and 2 Bcf at an average monthly rate of $0.125 per dekatherm at Golden Triangle.


33
Results of Operations

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

The operating revenues and EBIT of our distribution operations and retail operations segments are seasonal. During the Heating Season, natural gas usage and operating revenues are generally higher as more customers are connected to our distribution systems and natural gas usage is higher in periods of colder weather. Our base operating expenses, excluding cost of gas, revenue taxes, interest expense and certain incentive compensation costs, are generally incurred relatively equallyevenly over any given year. The revenues of our cargo shipping business are generally higher in the fourth quarter, due to increased tourist-related shipments as the hotels, resorts, and cruise ships typically have increased occupancy rates commencing in the fourth quarter and increasing further into the first quarter as well as consumer spending generally increasing during traditional holiday periods. Revenues for cargo shipping are also impacted during the fourth quarter by peak season surcharges. Thus, our operating results vary significantly from quarter to quarter as a result of seasonality.

We evaluate segment performance using the measures of EBIT and operating marginmargin. EBIT includes operating income and other income and expenses. Items that we do not include in EBIT are financing costs (including interest) and income taxes, each of which include the effects of corporate expense allocations.we evaluate on a consolidated basis. Operating margin is a non-GAAP measure that is calculated as operating revenues minus cost of goods sold and revenue tax expense in distribution operations. Operating margin excludes operation and maintenance expense, depreciation and amortization, certain taxes other than income taxes, and the gain or loss on the sale of our assets, if any. These items are included in our calculation of operating income as reflected in our unaudited Condensed Consolidated Statements of Income. EBIT is also a non-GAAP measure that includes operating income and other income and expenses. Items that we do not include in EBIT are financing costs, including interest and debt expense and income taxes, each of which we evaluate on a consolidated basis.

We believe operating margin is a better indicator than operating revenues of the contribution resulting from customer growth in our distribution operations segment, since the cost of goods sold and revenue tax expenses can vary significantly and are generally billed directly to our customers. We also consider operating margin to be a better indicator in our retail operations, wholesale services, midstream operations and cargo shipping, segments, since it is a direct measure of operating margin generated before overhead costs.

We believe EBIT is a useful measurement of our operating segments’ performance because it provides information that can be used to evaluate the effectiveness of our businesses from an operational perspective, exclusive of the costs to finance those activities and exclusive of income taxes, neither of which is directly relevant to the efficiency of those operations. You should not consider operating margin or EBIT an alternative to, or a more meaningful indicator of, our operating performance than operating income or net income attributable to AGL Resources Inc. as determined in accordance with GAAP. In addition, our operating margin and EBIT measures may not be comparable to similarly titled measures of other companies.

27
We also believe presenting the non-GAAP measurementsmeasurement of basic and diluted earnings per share - as adjusted, which excludes Nicor merger-related expenses, provides investors with an additional measure of our performance that excludes the impact of goodwill impairment and tax expense due to the sale of Tropical Shipping and Seven Seas and is more indicative of our ongoing performance. Adjusted basic and diluted earnings per share should not be considered an alternative to, or a more meaningful indicator of, our operating performance than our GAAP basic and diluted earnings per share. The following table reconciles operating revenue and operating margin to operating income, andincome; EBIT to earningsincome before income taxes and net income,income; and our GAAP basic and diluted earnings per common share to our non-GAAP basic and diluted earnings per share – as adjusted, together with other consolidated financial information for the periods presented.

34

 
Three months ended September 30,
  
Nine months ended September 30,
   Three months ended March 31,   
In millions, except per share amounts 2013  2012  Change  2013  2012  Change  2014  2013  Change 
Operating revenues $675  $614  $61  $3,288  $2,704  $584  $2,563  $1,709  $854 
Cost of goods sold  (229)  (215)  (14)  (1,609)  (1,174)  (435)  (1,454)  (973)  (481)
Revenue tax expense (1)
  (8)  (8)  -   (81)  (62)  (19)  (67)  (49)  (18)
Operating margin  438   391   47   1,598   1,468   130   1,042   687   355 
Operating expenses (2)
  (364)  (343)  (21)  (1,187)  (1,108)  (79)  (523)  (437)  (86)
Revenue tax expense (1)
  8   8   -   81   62   19   67   49   18 
Gain on sale of Compass Energy  -   -   -   11   -   11 
Nicor merger expenses (2)
  -   (2)  2   -   (15)  15 
Operating income  82   54   28   503   407   96   586   299   287 
Other income  7   6   1   19   19   -   3   5   (2)
EBIT  89   60   29   522   426   96   589   304   285 
Interest expenses  (43)  (45)  2   (135)  (137)  2   (48)  (46)  (2)
Earnings before income taxes  46   15   31   387   289   98 
Income before income taxes  541   258   283 
Income tax expenses  (18)  (6)  (12)  (145)  (106)  (39)  (239)  (94)  (145)
Net income  28   9   19   242   183   59   302   164   138 
Less net income attributable to the noncontrolling interest  -   -   -   (11)  (10)  (1)  12   10   2 
Net income attributable to AGL Resources Inc. $28  $9  $19  $231  $173  $58  $290  $154  $136 
Per common share data                                    
Basic earnings per common share attributable to AGL Resources Inc. common shareholders (3)
 $0.24  $0.08  $0.16  $1.96  $1.48  $0.48 
Transaction costs of Nicor merger  -   0.01   (0.01)  -   0.08   (0.08)
Basic earnings per share - as adjusted $0.24  $0.09  $0.15  $1.96  $1.56  $0.40 
                        
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders (3)
 $0.24  $0.08  $0.16  $1.96  $1.48  $0.48 
Transaction costs of Nicor merger  -   0.01   (0.01)  -   0.08   (0.08)
Diluted earnings per share - as adjusted $0.24  $0.09  $0.15  $1.96  $1.56  $0.40 
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders $2.44  $1.31  $1.13 
Goodwill impairment and tax expense due to sale of Tropical Shipping and Seven Seas  0.42   -   0.42 
Diluted earnings per share – as adjusted $2.86  $1.31  $1.55 
(1)  Adjusted for Nicor Gas’ revenue tax expenses, which are passed directly through to customers.
(2)  Expenses associated with the Nicor merger are part of operating expenses, but are shown separately to better compare year-over-year results.
(3)  Sale of Compass Energy generated basic and diluted EPS of $0.04 for the nine months ended September 30, 2013.

For the third quarter of 2013 our net income attributable to AGL Resources Inc. increased by $19 million compared to the same period last year.
·  
The increase was primarily the result of higher commercial activity in our wholesale services segment, increased operating margin at distribution operations as a result of increased regulatory infrastructure program revenues at Atlanta Gas Light, increased customer usage and customer growth for most of our utilities, as well as the acquisition of retail service customers in our retail operations segment.
·  This increase was partially offset by increased incentive compensation expenses across our businesses as our incentive compensation expense increased from significantly below targeted levels in 2012 to above targeted levels in 2013 based on improved financial and operational performance and higher bad debt expense at retail operations primarily as a result of higher natural gas prices compared to the same period in the prior year.

For the nine months ended September 30, 2013 our net income attributable to AGL Resources Inc. increased by $58 million, or 34%, compared to the same period last year.
·  The increase was primarily the result of increased operating margin at distribution operations and retail operations due to colder weather and increased average customer usage compared to the same period in the prior year, increased regulatory infrastructure program revenues at Atlanta Gas Light and the acquisition of retail services customers in January 2013.
·  The increase also was favorably impacted by higher commercial activity and the $11 million pre-tax gain on the sale of Compass Energy in our wholesale services segment.
·  This increase was partially offset by increased incentive compensation expenses across our businesses as our incentive compensation expense increased from significantly below targeted levels in 2012 to above targeted levels in 2013 based on improved financial and operational performance. In addition, our bad debt expense increased at retail operations primarily as a result of colder weather combined with natural gas prices that were higher than in the same period of the prior year.
·  During the nine months ended September 30, 2012 we recorded $15 million ($9 million net of tax) of Nicor merger related expenses.

For the third quarter of 2013 our income tax expense increased by $12 million compared to the third quarter of 2012 and by $39 million for the nine months ended September 30, 2013 compared to the same period of 2012. The increases were primarily due to higher consolidated earnings, as previously discussed. Our income tax expense is determined from earnings before income taxes less net income attributable to noncontrolling interest.

35
Operating Metrics

Weather We measure the effects of weather on our business through Heating Degree Days. Generally, increased Heating Degree Days result in higher demand for natural gas on our distribution systems. With the exception of Nicor Gas and Florida City Gas, we have various regulatory mechanisms, such as weather normalization, mechanisms, which limit our exposure to weather changes within typical ranges in each of our utilities’ respective service areas. However, our customers in Illinois and retail operations’ customers in Georgia can be impacted by warmer or colder than normalcolder-than-normal weather. We have presented the Heating Degree Day information for those locations in the following table.

  2013  2013 
 Nine months ended September 30,  vs. 2012  vs. normal         
Weather (Heating Degree Days) Normal  2013  2012  colder  colder     Three months ended March 31,  2014 vs. 2013  2014 vs. normal 
 Normal  2014  2013  colder  colder 
Illinois (1) (2)
  3,680   3,922   2,973   32%  7%  2,985   3,756   3,153   19%  26%
Georgia (1)
  1,591   1,640   1,056   55%  3%  1,442   1,733   1,461   19%  20%
(1)  Normal represents the ten-year average from January 1, 20032004 through September 30, 2012,March 31, 2013, for Illinois at Chicago Midway International Airport, and for Georgia at Atlanta Hartsfield-Jackson International Airport as obtained from the National Oceanic and Atmospheric Administration, National Climatic Data Center.
(2)  The 10-year average Heating Degree Days for the period, as established by the Illinois Commission in our last rate case, is 3,5802,902 for the first ninethree months from 1998 through 2007.

For our weather risk associated with Nicor Gas, we implemented a corporate weather hedging program in 2013 that utilizes OTC weather derivatives to reduce the risk of lower operating margins potentially resulting from decreased customer usage in the event of significantly warmer-than-normal weather in Illinois. We purchased a put option covering January through April 2014. Since the first three months of 2014 were significantly colder-than-normal, this option was not exercised during the first quarter of 2014. We will continue to evaluate and use available methods to mitigate our exposure to weather in Illinois for future periods.

During the ninethree months ended September 30, 2013March 31, 2014 we experienced weather in Illinois that was 7%26% colder-than-normal and 32%19% colder than last year. The 2013/2014 Heating Season was one of the same periodcoldest on record for Illinois, which positively impacted our operating margin by $17 million in the prior year.first quarter of 2014 compared to normal weather. Georgia also experienced 3%20% colder-than-normal weather, and 55%19% colder than the same period last year. This colder weather positively impacted our operating margin in Georgia by $18 million in the first quarter of 2014 compared to normal weather.

28
Customers Our customer metrics highlight the average number of customers for which we provide services and are provided in the table below. The number of customers at distribution operations and energy customers at retail operations can be impacted by natural gas prices, economic conditions and competition from alternative fuels. Our year-over-year consolidated utility customer growth rate was 0.4% for the three and nine months ended September 30, 2013. We anticipate overall utility customer growth trends for 2013 to improve compared to prior year as a result of the improving economy and the reduced volatility of natural gas prices.

Our energy customers at retail operations are primarily located in Georgia and Illinois.

 Customers and service contracts (average end-use, in thousands) 
Three months ended March 31,
  
2014 vs. 2013
 
  2014  2013  % change 
Distribution operations customers  4,532   4,501   1%
Retail operations            
Energy customers (1)
  636   613   4%
Service contracts (2)
  1,197   997   20%
Market share in Georgia  31%  32%  (3)%
(1)  Increase primarily represents the addition of approximately 33,000 residential and commercial customer relationships acquired in Illinois in June 2013.
(2)  Increase primarily due to acquisition of approximately 500,000 service contracts on January 31, 2013. Prior year amount revised to reflect a change in methodology.

Our year-over-year consolidated utility customer growth rate was 1% for the three months ended March 31, 2014. We anticipate overall utility customer growth trends for 2014 to continue improving based on an expectation of improvement in the economy and relatively low natural gas prices.

Retail operations’ market share in Georgia has decreased slightly primarily as a result of a highly competitive marketing environment, which we expect will continue for the foreseeable future. In 20132014 our retail operations segment intends to continue its efforts to enter and expand withininto targeted markets to increaseand expand its energy customers and expand ourits service contracts to include our service territoriescontracts. We anticipate this expansion will provide growth opportunities in Virginia and Tennessee.future years.

  Customers and service contracts 
Three months ended September 30,
  
2013 vs. 2012
  
Nine months ended September 30,
  
2013 vs. 2012
(average end-use, in thousands) 2013  2012  % change  2013  2012  
% change
Distribution operations customers  4,447   4,429   0.4%  4,480   4,461   0.4%
Retail operations                        
Energy customers (1)
  621   600   4%  617   630   (2)%
Service contracts (2)
  1,168   664   76%  1,119   689   62%
Market share in Georgia  31%  32%  (3)%  32%  32%  -%
(1)  A portion of the energy customers represents customer equivalents in Ohio, which are computed by the actual delivered volumes divided by the expected average customer usage. The increase for the three months ended September 30, 2013 primarily represents the addition of approximately 33,000 residential and commercial customer relationships acquired in Illinois in June 2013. The decrease for the nine months ended September 30, 2013 is primarily due to our contract to serve approximately 50,000 customer equivalents that ended in April 2012.
(2)  Increase primarily due to acquisition of approximately 500,000 service contracts on January 31, 2013.

36
Volumes Our natural gas volume metrics for distribution operations and retail operations, as shown in the following table, present the effects of weather and our customers’ demand for natural gas compared to prior year. The cold weather experienced during this past Heating Season resulted in a decrease in the natural gas inventory in our storage facilities, which has fallen to its lowest level since 2003. This weather contributed to increased revenues as a result of peak market demand for natural gas storage services. However, the storage business remains challenged due to continued oversupply of natural gas.

Wholesale services’ daily physical sales volumes represent the daily average natural gas volumes sold to its customers. Within our midstream operations segment, our natural gas storage businesses seek to have a significant percentage of their working natural gas capacity under firm subscription, but also take into account current and expected market conditions. This allows our natural gas storage business to generate additional revenue during times of peak market demand for natural gas storage services, but retain some consistency with their earnings and maximize the value of the investments. Additionally, our cargo shipping segment measures the volume of shipments during the period in TEUs. We continue to seek opportunities to profitably increase our number of TEUs and maximize the utilization of our containers and vessels.

Our midstream operations storage business is cyclical. The abundant supply of natural gas in recent years and the resulting lack of market and price volatility have negatively impacted the profitability of our storage facilities. Consistent with our expectations, we had contracts expire on March 31, 2014 that were subscribed at lower prices as compared to prior years. We anticipate these lower natural gas prices to continue throughout 2014 as compared to historical averages. The prices for natural gas storage capacity are expected to increase as supply and demand quantities reach equilibrium as the economy improves, expected exports of LNG occur and/or natural gas demand increases in response to low prices and expanded uses for natural gas. As of April 1, 2014 and 2013 the overall monthly average firm subscription rates per facility were as follows:

  Average Monthly Rate per Dekatherm 
  
April 1, 2014 (1)
  April 1, 2013 
Jefferson Island (2)
 $0.108  $0.122 
Golden Triangle (2)
  0.123   0.240 
Central Valley (2)  0.062   0.130 
(1)  Includes contracts beginning April 15, 2014 and May 1, 2014.
(2) Excludes 7.0 Bcf of firm capacity contracted by Sequent as of April 1, 2014 at an average monthly rate of $0.055 and 3.5 Bcf as of April 1, 2013 at an average monthly rate of $0.101.

29
Our volume metrics are presented in the following table:

Volumes 
Three months ended March 31,
  2014 vs. 2013 
 
Three months ended September 30,
  2013 vs. 2012  
Nine months ended September 30,
  2013 vs. 2012  2014  2013  % change 
Volumes 2013  2012  % change  2013  2012  % change 
Distribution operations (In Bcf)
                           
Firm  71   75   (5)%  487   408   19%  362   309   17%
Interruptible  27   26   4%  83   79   5%  28   30   (7)%
Total  98   101   (3)%  570   487   17%  390   339   15%
Retail operations (In Bcf)
                                    
Georgia firm  3   3   0%  26   20   30%  21   18   17%
Illinois  2   -   N/A   7   5   40%  10   4   150%
Other (1)
  1   1   0%  5   6   (17)%  4   3   33%
Wholesale services                                    
Daily physical sales (Bcf / day)  5.4   5.3   2%  5.7��  5.4   6%  7.3   6.3   16%
Cargo shipping (TEU’s - in thousands)
                                    
Shipments  46   43   7%  136   124   10%  46   45   2%
 As of September 30,                 
  2013   2012                 
Midstream operations                        
Working natural gas capacity (in Bcf) (2)
  31.8   30.3                 
% of firm capacity under subscription by third parties (3)
  33%  48%                
  As of March 31, 
  2014  2013 
Midstream operations      
Estimated working natural gas capacity (in Bcf)  31.8   31.8 
% of firm capacity under subscription by third parties (2)
  38%  46%
(1)  Includes Florida, Maryland, New York and Ohio.
(2)  Golden Triangle Storage’s Cavern 1 is currently going through a process to assess its working gas capacity. The process began in early 2013 and is expected to continue with full commercial service operations resuming in the first quarter of 2014. Limited commercial operations resumed in the third quarter 2013. Cavern 2 has been covering obligations of Cavern 1 during the process.
(3)  
The percentage of firm capacity under subscription does not include 3.54.5 Bcf of capacity under contract with Sequent at September 30, 2013March 31, 2014 and 3 Bcf of capacity under contract with Sequent at September 30, 2012March 31, 2013.

Three and nine months ended September 30, 2013 compared to the same periods ended September 30, 2012

Segment Information Operating margin, operating expenses and EBIT information for each of our segments are contained in the following tables:

  Three months ended September 30, 2013  Three months ended September 30, 2012 
 In millions 
Operating margin
(1) (2)
  
Operating expenses (2)
  
EBIT (1)
  
Operating margin
(1) (2)
  
Operating expenses (2) (3)
  
EBIT (1)
 
Distribution operations $337  $255  $86  $327  $249  $80 
Retail operations  46   38   8   35   30   5 
Wholesale services  12   14   (2)  (12)  12   (23)
Midstream operations  10   11   (1)  10   9   1 
Cargo shipping  34   35   2   32   35   (1)
Other  (1)  3   (4)  (1)  2   (2)
Consolidated $438  $356  $89  $391  $337  $60 
                         

 Nine months ended September 30, 2013  Nine months ended September 30, 2012  
Three months ended March 31, 2014
  
Three months ended March 31, 2013
 
In millions 
Operating margin
(1) (2)
  
Operating expenses (2)
  
EBIT (1) (4)
  
Operating margin
(1) (2)
  
Operating expenses (2) (3)
  
EBIT (1)
  
Operating
 margin (1) (2)
  
Operating
expenses (2)
  
EBIT (1)
  
Operating
margin (1) (2)
  
Operating
expenses (2)
  
EBIT (1)
 
Distribution operations $1,210  $808  $413  $1,143  $776  $374  $544  $306  $239  $505  $290  $218 
Retail operations  203   113   90   175   96   79   126   44   82   107   37   70 
Wholesale services (4)
  52   39   24   25   39   (13)  330   37   293   29   14   15 
Midstream operations  33   34   1   32   27   6   8   12   (3)  12   11   2 
Cargo shipping  102   106   3   95   104   (1)  34   55   (19)  34   34   2 
Other  (2)  6   (9)  (2)  19   (19)  -   2   (3)  -   2   (3)
Consolidated $1,598  $1,106  $522  $1,468  $1,061  $426  $1,042  $456  $589  $687  $388  $304 
(1)  These are
Operating margin is a non-GAAP measures.measure. A reconciliation of operating revenue and operating margin to operating income, and EBIT to earningsincome before income taxes and net income is contained in “Results of Operations” herein. See Note 1011 to our unaudited Condensed Consolidated Financial Statements under Part I, Item 1 herein for additional segment information.
(2)  Operating margin and expenseoperating expenses are adjusted for revenue tax expense for Nicor Gas, which is passed directly through to customers.
(3)  Includes $2 million and $15 million in Nicor merger transaction expenses for the three and nine months ended September 30, 2012, respectively.
(4)  EBIT for the nine months ended September 30, 2013, includes $11 million pre-tax gain on sale of Compass Energy.

Distribution Operations

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

37
With the exception of Atlanta Gas Light, our second-largest utility, the earnings of our regulated utilities can be affected by customer consumption patterns that are a function of weather conditions, price levels for natural gas and general economic conditions that may impact our customers’ ability to pay for natural gas consumed. Depreciation expense at distribution operations decreased by $10 million, primarily due to Nicor Gas’ new composite depreciation rate that became effective August 30, 2013, partially offset by capital investments. Nicor Gas’ lower composite depreciation rate did not impact customer rates. For the three and nine months ended September 30, 2013March 31, 2014 distribution operations’ EBIT increased by $6$21 million or 8% and $39 million, or 10%, respectively, compared to the same period during the prior year, as shown in the following table.

30


In millions Three months ended  Nine months ended 
EBIT - for September 30, 2012
 $80  $374 
         
Operating margin        
Increased operating margin mainly driven by colder weather, higher customer usage and customer growth compared to prior year  3   30 
Increased rider revenues primarily as a result of energy efficiency program recoveries at Nicor Gas  -   12 
Increased revenues from regulatory infrastructure programs, primarily at Atlanta Gas Light  7   25 
Increase in operating margin  10   67 
         
Operating expenses        
Increased rider expenses primarily as a result of energy efficiency program expenses at Nicor Gas  -   12 
Increased incentive compensation costs that reflect year over year performance  4   13 
Increased depreciation expense as a result of increased PP&E from infrastructure additions and improvements  3   9 
Other  (1)  (2)
Increase in operating expenses  6   32 
Increased AFUDC equity primarily from STRIDE projects at Atlanta Gas Light  2   4 
EBIT - for September 30, 2013
 $86  $413 

In millionsThree months ended 
EBIT - for March 31, 2013
 $218 
Operating margin    
Increased operating margin mainly driven by significantly colder-than-normal weather, higher customer usage and customer growth compared to prior year  24 
Increased rider revenues primarily as a result of energy efficiency program recoveries at Nicor Gas  11 
Increased revenues from regulatory infrastructure replacement programs, primarily at Atlanta Gas Light  4 
Increase in operating margin  39 
Operating expenses    
Increased variable compensation costs as a result of overtime related to colder-than-normal weather, higher earnings and the seasonality of earnings  16 
Increased rider expenses primarily as a result of energy efficiency program expenses at Nicor Gas  11 
Increased outside services and other expenses primarily from costs related to weather  3 
Decreased depreciation expense primarily due to the impact of Nicor Gas’ new composite depreciation rate  (10)
Decreased pension and health benefits expenses primarily related to retiree health care costs and change in actuarial gains and losses  (4)
Increase in operating expenses  16 
Decreased AFUDC equity from STRIDE projects at Atlanta Gas Light  (2)
EBIT - for March 31, 2014
 $239 

Retail Operations

Our retail operations segment, which consists of SouthStar and several businesses that provide energy-related products and services to retail markets,Pivotal Home Solutions, is also is weather sensitive and uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to mitigate potential weather impacts. For the three and nine months ended September 30, 2013March 31, 2014 retail operations’ EBIT increased by $3$12 million, or 60% and $11 million or 14%17%, respectively, compared to the same periodsperiod during the prior year, as shown in the following table.

In millionsThree months ended  Nine months ended 
EBIT - for September 30, 2012
 $5  $79 
         
Operating margin        
Increased margin primarily related to average customer usage in Georgia due to increased demand and colder weather relative to prior year, net of weather hedges  1   13 
Increased margin primarily due to 2013 retail acquisitions in January and June  12   24 
Storage inventory write-down (LOCOM) in 2012  -   3 
Decrease related to higher gas costs and lower retail price spreads, partially offset by favorable customer portfolio  (2)  (12)
Increase in operating margin  11   28 
         
Operating expenses        
Increased expenses primarily due to 2013 retail acquisitions in January and June  6   15 
Increased bad debt expense primarily related to colder weather and higher natural gas prices  1   3 
Other  1   (1)
Increase in operating expenses  8   17 
EBIT - for September 30, 2013
 $8  $90 
In millionsThree months ended
EBIT - for March 31, 2013
 $70 
Operating margin     
Increased margin primarily due to retail acquisitions in 2013  12 
Increased margin primarily related to average customer usage in Georgia due to colder-than-normal weather and increased demand relative to prior year, net of weather hedges  7 
Increased margin in Illinois mainly due to favorable gas costs, lower supply agreement fees and timing of hedge gains, partially offset by unfavorable timing of revenue associated with fixed bill products  3  
Decrease related to increased gas costs and lower retail price spreads  (5) 
Increased margin for large commercial and industrial customers due to increased peaking sales  2  
Increase in operating margin  19  
Operating expenses     
Increased expenses primarily due to retail acquisitions in 2013  4  
Increased customer care and marketing expenses associated with attracting and retaining customers  2  
Increased bad debt expense primarily related to colder-than-normal weather and higher natural gas prices  1  
Increase in operating expenses  7  
EBIT - for March 31, 2014
 $82  



38

Wholesale Services

Our wholesale services segment is involved in asset management and optimization, storage, transportation, producer and peaking services, natural gas supply, natural gas services and wholesale marketing. Sequent has positioned the business to generate positive economic earnings even under low volatility market conditions. However, when market price volatility increases as we experienced in the first quarter of 2014, we believe Sequent is well positioned to capture significant value and generate stronger results. EBIT for our wholesale services segment is impacted by volatility in the natural gas market arising from a number of factors, including weather fluctuations and changes in supply or demand for natural gas in different regions of the country. For the three and nine months ended September 30, 2013,March 31, 2014, wholesale services’ EBIT increased by $21$278 million and $37 million, respectively, compared to prior year, as shown in the following table.

31


In millions Three months ended  Nine months ended 
EBIT - for September 30, 2012
 $(23) $(13)
         
Operating margin        
Change in commercial activity largely driven by the withdrawal of a portion of the storage inventory economically hedged at the end of 2012, colder weather and increased cash optimization opportunities in the supply-constrained Northeast corridor  29   62 
Change in value on storage hedges as a result of changes in NYMEX natural gas prices  17   22 
Change in value on transportation and forward commodity hedges from price movements related to natural gas transportation positions  (21)  (59)
Change in storage inventory LOCOM adjustment, net of estimated recoveries  (1)  2 
Increase in operating margin  24   27 
         
Operating expenses        
Increased incentive compensation expense, offset by lower costs due to sale of Compass Energy and other costs  2   - 
Increase in operating expenses  2   - 
Gain on sale of Compass Energy  -   11 
Decrease in other income  (1)  (1)
EBIT - for September 30, 2013
 $(2) $24 
In millionsThree months ended 
EBIT - for March 31, 2013
 $15 
Operating margin    
Change in commercial activity associated with the transportation and storage portfolios in the Northeast and Midwest largely driven by price volatility resulting from extremely cold temperatures  331 
Change in value on storage derivatives as a result of changes in NYMEX natural gas prices  15 
Change in LOCOM adjustment, net of derivative recoveries  (2)
Decreased operating margin due to sale of Compass Energy in May 2013  (4)
Change in value on transportation and forward commodity derivatives from price movements related to natural gas transportation positions  (39)
Increase in operating margin  301 
Operating expenses    
Increased incentive compensation costs due to higher operating revenues  25 
Decreased expenses due to sale of Compass Energy in May 2013  (2)
Increase in operating expenses  23 
EBIT - for March 31, 2014
 $293 

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

 
Three months ended September 30,
  Nine months ended September 30,  
Three months ended March 31,
 
In millions 2013  2012  2013  2012  2014  2013 
Commercial activity recognized $27  $(2) $79  $17  $377  $50 
Gain (loss) on storage hedges  2   (15)  9   (13)
(Loss) gain on transportation and forward commodity hedges  (16)  5   (31)  28 
Storage inventory LOCOM adjustment, net of estimated recoveries  (1)  -   (5)  (7)
Loss on storage derivatives  (2)  (17)
Inventory LOCOM adjustment, net of estimated current period recoveries  (2)  - 
Loss on transportation and forward commodity derivatives  (43)  (4)
Operating margin $12  $(12) $52  $25  $330  $29 


Change in commercial activity The commercial activity at wholesale services includes recognized storage and transportation values that were generated in prior periods, which reflect the impact of prior period hedgederivative gains and losses as associated physical transactions occur in the period. Additionally, the commercial activity includes significantly higher operating margin generated and recognized in the current period. For the first ninethree months of 2013,2014, commercial activity increased significantly due to (i) the recognition of operating margin resulting from the withdrawal of storage inventory hedged at the end of 2012 that was included in the storage withdrawal schedule with a value of $27 million as of December 31, 2012, (ii) the effects of colder weather and (iii) increased cash optimization opportunities related to certain of our transportation portfolio positions, particularly in the Northeastern United States. As previously discussed, our operating margin opportunities continued to be lower in 2013 due to lower volatility and lower seasonal price spreads associated with our storage portfolio.to:

·the recognition of operating margin associated with our transportation and storage portfolios, particularly in the Northeast and Midwest regions, from price volatility generated by significantly colder-than-normal weather, in part reflecting Sequent’s strategy and focus on providing asset management type services to producers around the major shale producing regions and to gas fired power generators, enabling Sequent to optimize the associated pipeline transportation and storage capacity assets,
·the recognition of operating margin resulting from the withdrawal of storage inventory at the end of 2013 that was included in the storage withdrawal schedule with a value of $28 million as of December 31, 2013,
·the recognition of operating margin resulting from mark-to-market accounting derivative losses at the end of 2013
Change in storage and transportation hedgesderivatives Seasonal (storage) and geographical location (transportation) spreads and overall natural gasThe first quarter of 2014 showed a return of significantly higher price volatility benefitting Sequent’s portfolio of pipeline transportation and storage capacity assets throughout the country, primarily in general continuedthe Northeast and Midwest markets. Although we do not expect this high level of price volatility to remain low relativecontinue, we see the potential for market fundamentals indicating some level of increased volatility which would continue to historical periods. Duringbenefit Sequent’s portfolio of pipeline transportation capacity should this occur. Storage derivative losses during the thirdfirst quarter andof 2014 are primarily due to the nine months ended September 30, 2013, the downward movementincrease in natural gas prices resulted in storage hedge gains as compared to storage hedge losses last yearprimarily resulting from an upward movementcolder weather. Losses in the natural gas prices. Gains on our transportation derivative positions in 2012 were primarily due to large transportation spreads at the time our transportation positions were executed and the subsequent narrowing of regional transportation spreads. However, similar toduring the first halfquarter of 2014 are the year, significant volatility continued during the current quarterresult of widening transportation basis spreads, associated with significantly colder-than-normal weather and higher demand experienced at natural gas receipt and delivery points throughoutprimarily in the Northeast corridor relativeand the Midwest regions related to natural gas receipt and deliverytransportation constraints in the region, resulting in losses on our transportation position.region. These losses are temporary and, based on current expectations, will largely be recovered in 2014 through 2016 with the fourth quarterphysical flow of 2013natural gas and utilization of the first quarter of 2014 when the related physical transactions occur and are recognized.contracted transportation capacity.

3932
Withdrawal schedule Sequent’s expected natural gas withdrawals from storage and expected recovery of derivative losses associated with Sequent’s transportation portfolio are presented in the following tabletables, along with the net operating revenues expected at the time of withdrawal.withdrawal from storage and the physical flow of natural gas between contracted transportation receipt and delivery points. Sequent’s expected net operating revenues exclude storage and transportation demand charges, as well as other variable fuel, withdrawal, receipt and delivery charges, but are net of the estimated impact of profit sharing under our asset management agreements and reflectagreements. Further, the amounts that are realizable in future periods are based on the inventory withdrawal schedule, planned physical flow of natural gas between the transportation receipt and delivery points and forward natural gas prices at September 30, 2013 and 2012.March 31, 2014. A portion of Sequent’s storage inventory and transportation capacity is economically hedged with futures contracts, which results in realization of substantially fixed net operating revenues, timing notwithstanding. For more information on Sequent’s energy marketing and risk management activities, see Item 7A, “Quantitative and Qualitative Disclosures About Market Risk - Commodity Price Risk” of our 20122013 Form 10-K.

Withdrawal schedule 
Total storage (in Bcf) 
(WACOG $3.29)
  
Expected operating revenues (1)
(in millions)
 
2013      
Fourth quarter  39   13 
2014        
First quarter  16   8 
Second quarter  2   2 
Total at September 30, 2013  57  $23 
Total at December 31, 2012  51  $27 
Total at September 30, 2012  58  $65 
Withdrawal schedule 
Total storage (in Bcf)
(WACOG $2.57)
  
Expected operating
revenues (1) (in millions)
 
2014  4  $6 
2015  5   6 
Total at March 31, 2014  9  $12 
Total at December 31, 2013  36  $28 
Total at March 31, 2013  32  $34 
(1)  Represents expected operating revenues from planned storage withdrawals associated with existing inventory positions and could change as Sequent adjusts its daily injection and withdrawal plans in response to changes in future market conditions and forward NYMEX price fluctuations.

The following table shows the periods associated with the transportation derivative losses during which the derivatives will be settled and the physical transportation transactions will occur that offset the derivative losses recognized in 2013, and during the first quarter of 2014.

In millions 
Expected net
 operating revenues
 
2014 $14 
2015  26 
2016 and thereafter  3 
Total at March 31, 2014 $43 
Total at December 31, 2013 $73 
Total at March 31, 2013 $4 

The unrealized storage and transportation derivative losses do not change the underlying economic value of our storage and transportation positions, and based on current expectations, will largely be reversed in 2014 and 2015 when the related transactions occur and are recognized. For more information on Sequent’s energy marketing and risk management activities, see Item 7A “Quantitative and Qualitative Disclosures About Market Risk” under the caption “Natural Gas Price Risk” of our 2013 Form 10-K.

Midstream Operations

Our midstream operations segment’s primary activity is operating non-utility storage and pipeline facilities, including the development and operation of high-deliverability underground natural gas storage assets. While this business can also generate additional revenue during times of peak market demand for natural gas storage services, certain of our storage services are covered under short, medium and long-term contracts at fixed market rates. Based on an engineering study completed in the first quarter of 2014, we identified a potentially lower amount of working natural gas capacity at Jefferson Island. We believe the decrease in working natural gas capacity is a result of naturally occurring salt creep or shrinkage of the storage cavern. We will conduct required mechanical integrity tests of both caverns during the first half of 2014 to more precisely measure the capacity of the facility. For the three and nine months ended September 30, 2013March 31, 2014 midstream operations’ EBIT decreased by $2 million and $5 million respectively, compared to prior year, as shown in the following table.

In millions Three months ended  Nine months ended 
EBIT - for September 30, 2012
 $1  $6 
         
Operating margin        
Increased revenues at Golden Triangle as a result of Cavern 2 beginning commercial service in third quarter 2012, as well as revenue due to entry into LNG market, partially offset by lower revenues at Jefferson Island as a result of lower subscription rates and lower revenues at Central Valley  -   1 
Increase in operating margin  -   1 
         
Operating expenses        
Increased depreciation, property taxes, storage expenses, payroll and outside services largely due to Central Valley and Cavern 2 at Golden Triangle beginning commercial service in 2012 and entry into the LNG market
  2   7 
Increase in operating expenses  2   7 
Increase from equity investment in Horizon Pipeline  -   1 
EBIT - for September 30, 2013
 $(1) $1 
In millionsThree months ended 
EBIT - for March 31, 2013
 $2 
Operating margin    
Decreased margin at Jefferson Island due to changes in estimates for retained fuel, partially offset by higher operating margin at Golden Triangle and Central Valley due to optimizing the facilities during the colder weather in 2014  (3)
Decreased margin at Jefferson Island, Golden Triangle and Central Valley as a result of lower subscription rates  (1)
Decrease in operating margin  (4)
Operating expenses    
Increased depreciation expenses and other  1 
Increase in operating expenses  1 
EBIT - for March 31, 2014
 $(3)

Cargo Shipping

Our cargo shipping segment’s primary activity is transporting containerized freight in the Bahamas and the Caribbean, a region that has historically been characterized by modest market growth and intense competition. Such shipments consist primarily of southbound cargo such as building materials, food and other necessities for developers, distributors and residents in the region, as well as tourist-related shipments intended for use in hotels and resorts and on cruise ships. The balance of the cargo consists primarily of interisland shipments of consumer staples and northbound shipments of apparel, rum and agricultural products. Other related services, such as inland transportation and cargo insurance, are also provided within the cargo shipping segmentships. Our cargo shipping segment also includes an equity investment in Triton, a cargo container leasing business. For more information about our investment in Triton, see Note 10 to our Consolidated Financial Statements under Item 8 included in our 2012 Form 10-K.


4033

In April 2014 we signed a definitive agreement to sell Tropical Shipping and Seven Seas, which have operated as part of our cargo shipping operating segment. For more information on the sale, see Note 12 to the unaudited Condensed Consolidated Financial Statements under Part I, Item 1 herein. For the third quarter of 2013three months ended March 31, 2014 cargo shipping’s EBIT increaseddecreased by $3$21 million compared to the third quarter of 2012 and increased by $4 million for the nine months ended September 30, 2013, compared to prior year, as shown in the following table.

In millions Three months ended  Nine months ended 
EBIT - for September 30, 2012 $(1) $(1)
         
Operating margin        
TEU volume increased due to market share expansion and modest improvement in economic conditions in our service regions; leverage effect of volume increases on fuel expense  3   15 
Increased (decreased) average TEU rates due to general ocean freight rate increases, changes in cargo mix and competitive pressures  2   (6)
Increased brokerage and container storage costs combined primarily with lower other non-shipping revenues  (3)  (2)
Increase in operating margin  2   7 
         
Operating expenses        
Increased payroll, benefits, outside services and other  1   5 
Decreased depreciation expense  (1)  (3)
Increase in operating expenses  -   2 
Increase (decrease) from equity investment income in Triton  1   (1)
EBIT - for September 30, 2013 $2  $3 
In millionsThree months ended 
EBIT - for March 31, 2013 $2 
Operating margin    
TEU volume increased due to market share expansion and modest improvement in economic conditions in our service regions; leverage effect of volume increases on fuel expense  2 
Decreased average TEU rates due to changes in cargo mix and destination, and competitive pressures, partially offset by general ocean freight rate increases  (2)
Other    
Increase in operating margin  - 
Operating expenses    
Goodwill impairment loss  19 
Increased payroll, benefits, vessel charter expense, outside services and other  2 
Increase in operating expenses  21 
EBIT - for March 31, 2014 $(19)

Liquidity and Capital Resources

Overview The acquisition of natural gas and pipeline capacity, payment of dividends and funding of working capital needs primarily related to our natural gas inventory are our most significant short-term financing requirements. The need for long-term capital is driven primarily by capital expenditures and maturities of long-term debt. The liquidity required to fund our working capital, capital expenditures and other cashthese short-term needs is primarily provided by our operating activities,. Our short-term cash requirements and any needs not met with cash from operations are primarily satisfied with short-term borrowings under our commercial paper programs, which are supported by the AGL Credit Facility and the Nicor Gas Credit Facility. The need for long-term capital is driven primarily by capital expenditures and maturities of long-term debt. Periodically, we raise funds supporting our long-term cash needs from the issuance of long-term debt or equity securities. We regularly evaluate our funding strategy and profile to ensure that we have sufficient liquidity for our short-term and long-term needs in a cost-effective manner. Consistent with this strategy, in May 2013 we issued $500 million in 30-year senior notes with a fixed interest rate of 4.4%.

Our capital market strategy is focused on maintaining strong Consolidated Statements of Financial Position, ensuring ample cash resources and daily liquidity, accessing capital markets at favorable times as necessary, managing critical business risks and maintaining a balanced capital structure through the appropriate issuance of equity or long-term debt securities.

Our financing activities, including long-term and short-term debt and equity, are subject to customary approval or review by state and federal regulatory bodies, including the various commissions of the states in which we conduct business. Certain financing activities we undertake may also be subject to approval by state regulatory agencies. A substantial portion of our consolidated assets, earnings and cash flows is derived from the operation of our regulated utility subsidiaries, whose legal authority to pay dividends or make other distributions to us is subject to regulation. Nicor Gas is restricted by regulation to the extent of its retained earnings balance in the amount it can dividend or loan to affiliates and is not permitted to make money pool loans to affiliates. Dividends are allowed only to the extent of Nicor Gas’ retained earnings balance, which was $473 million at September 30, 2013.affiliates.

We believe the amounts available to us under our senior notes, AGL Credit Facilitylong-term debt and Nicor Gas Credit Facility,credit facilities as well as through the issuance of debt and equity securities, combined with cash provided by operating activities, will continue to allow us to meet our needs for working capital, pension and retiree welfare benefits, capital expenditures, anticipated debt redemptions, interest payments on debt obligations, dividend payments and other cash needs through the next several years. Our ability to satisfy our working capital requirements and our debt service obligations, or fund planned capital expenditures, will substantially depend upon our future operating performance (which will be affected by prevailing economic conditions), and financial, business and other factors, some of which we are unable to control. These factors include, among others, regulatory changes, the price of and demand for natural gas and operational risks.

AsUpon closing our sale of September 30, 2013Tropical Shipping and 2012,Seven Seas, which we anticipate to occur during the third quarter of 2014, we expect to receive after-tax cash proceeds and December 31, 2012,distributions of $220 million, subject to certain defined post-closing adjustments. During the first quarter of 2014, we had $74 million, $76 million and $80 million, respectively, ofdecided that we no longer have the intent to indefinitely reinvest Tropical Shipping’s cash and short-termshort and long-term investments held by Tropical Shipping. This cash and investments are available for use by our other operations only if we repatriate a portion of Tropical Shipping’s earnings in the form of a dividend, and pay a significant amount of United States income tax.offshore. See Note 122 to our unaudited Condensed Consolidated Financial Statements under Part 1, Item 8 included in our 2012 Form 10-K1 herein for additional information on our income taxes.

debt securities and equity. This strategy includes active management of the percentage of total debt relative to total capitalization, appropriate mix of debt with fixed to floating interest rates (our variable debt target is 20% to 45% of total debt), as well as the term and interest rate profile of our debt securities. At March 31, 2014, our variable-rate debt was 21% of our total debt, compared to 28% as of December 31, 2013 and 25% as of March 31, 2013. The decrease from December 31, 2013 was primarily due to decreased commercial paper borrowings.
41

We will continue to evaluate our need to increase available liquidity based on our view of working capital requirements, including the impact of changes in natural gas prices, liquidity requirements established by rating agencies and other factors. See Item 1A, “Risk Factors,” in our 20122013 Form 10-K for additional information on items that could impact our liquidity and capital resource requirements.

34
Capital Projects We continue to focus on capital discipline and cost control while moving ahead with projects and initiatives that we expect will have current and future benefits to us and our customers, provide an appropriate return on invested capital and ensure the safety, reliability and integrity of our utility infrastructure. The following table and discussions provide updates on some of our larger capital projects under various programs at our distribution operations segment. These programs update or expand our distribution systems to improve system reliability and meet operational flexibility and growth. Our anticipated expenditures for these programs in 20132014 are discussed in “Liquidity and Capital Resources” under the caption ‘Cash FlowsFlow from FinancingInvesting Activities’ under Item 7 in our 20122013 Form 10-K and our 2013 estimated expenditures have increased from $212 million to $262 million.10-K.

Dollars in millionsUtility   Expenditures in 2013  Expenditures since project inception  Miles of pipe replaced  Year project began  Anticipated year of completion Utility 
Expenditures
 in 2014
  Expenditures since project inception  
Miles of
pipe installed
  Year project began  Scheduled year of completion 
STRIDE program (1)
                                
Pipeline replacement programAtlanta Gas Light $114  $796   2,690   1998   2013 
Integrated System Reinforcement ProgramAtlanta Gas Light  22   246   n/a   2009   2013 
Integrated Customer Growth ProgramAtlanta Gas Light  11   40   n/a   2010   2013 
Integrated System Reinforcement Program (i-SRP)Atlanta Gas Light $3  $254   n/a   2009   2017 
Integrated Customer Growth Program (i-CGP)Atlanta Gas Light  1   40   n/a   2010   2017 
Integrated Vintage Plastic Replacement Program (i-VPR)Atlanta Gas Light  11   16   42   2013   2017 
Enhanced infrastructure programElizabethtown Gas  1   109   96   2009   2017 Elizabethtown Gas  2   118   113   2009   2017 
Accelerated infrastructure programVirginia Natural Gas  17   33   72   2012   2017 
Accelerated infrastructure replacement program (SAVE)Virginia Natural Gas  7   47   95   2012   2017 
Total  $165  $1,224   2,858           $24  $475   250         

Short-term Debt Our short-term debt comprises borrowings under our commercial paper programs and current portions of our senior notes and capital leases. The following table provides additional information on our short-term debt.

In millions 
Period end balance outstanding (1)
  
Daily average balance outstanding (2)
  
Minimum balance outstanding (2)
  
Largest balance outstanding (2)
 
Commercial paper - AGL Capital $440  $756  $440  $1,006 
Commercial paper - Nicor Gas  301   232   97   344 
Senior notes   200   169   -    200 
Total short-term debt and current portions of long-term debt and capital leases $941  $1,157  $537  $1,550 
(1)  
As of March 31, 2014.
(2)  
For the three months ended March 31, 2014. The i-VPR program began in 2013minimum and aslargest balances outstanding for each debt instrument occurred at different times during the period. Consequently, the total balances are not indicative of September 30, 2013 has incurred less than $1 million of expenditures.actual borrowings on any one day during the period.

Nicor Gas The largest, minimum and daily average balances borrowed under our commercial paper programs are important when assessing the intra-period fluctuations of our short-term borrowings and potential liquidity risk. The fluctuations are due to ourIn July 2013 Illinois enacted legislation that provides for infrastructure investment by seasonal cash requirements to fund working capital needs, in particular the purchase of natural gas utilities serving more than 700,000 customers, which includes Nicor Gas. This bill will allow Nicor Gas to provide more widespread safetyinventory, margin calls and reliability enhancements to its pipelines in a timelier manner than under traditional utility regulation, and pass along lower program costs to our customers. We expect to submit a plan for approval by the Illinois Commission in mid-2014.

Atlanta Gas Light Our STRIDE program is comprised of the ongoing pipeline replacement program, the Integrated System Reinforcement Program (i-SRP), the Integrated Customer Growth Program (i-CGP) and the Integrated Vintage Plastic Replacement Program (i-VPR). The purpose of the i-SRP is to upgrade our distribution system and liquefied natural gas facilities in Georgia, improve our peak day system reliability and operational flexibility, and create a platform to meet long-term forecasted growth. Our i-CGP authorizes Atlanta Gas Light to extend its pipeline facilities to serve customers in areas without pipeline access and create new economic development opportunities in Georgia. The STRIDE program requires us to file an updated ten-year forecast of infrastructure requirements under i-SRP along with a new construction plan every three years for review and approval by the Georgia Commission. These programs remain on track for completion in 2013.

We filed a new $260 million STRIDE program in August 2013, $214 million of which will be for i-SRP related projects and $46 million of which will be for i-CGP related projects. In addition to the $260 million request in new investment and programs, Atlanta Gas Light also requested an additional $5 million of investment for i-CGP projects from the initial i-CGP plan. Under the current procedural schedule, hearings will be held in November 2013 with a ruling scheduled for December 2013.

In November 2012 we filed i-VPR with the Georgia Commission, as a new component of STRIDE. This program would replace aging plastic pipe that was installed primarily in the mid-1960’s to the early 1980’s. We have identified approximately 3,300 miles of vintage plastic mains in our system that potentially should be considered for replacement over the next 15 - 20 years as it reaches the end of its useful life. Our initial request to the Georgia Commission was to replace approximately 756 miles over the next three to four years. The estimated cost of the first tranche of pipe to be replaced under i-VPR is $275 million. In August, 2013 the Georgia Commission voted unanimously to approve the replacement of 756 miles of vintage plastic pipe over four years at an estimated cost of $275 million. Additional reporting requirements and monitoring by the staff of the Georgia Commission were also included in the stipulation, which authorized a phased-in approach to funding the program.

The approximately $275 million construction program will be funded through a rider of $0.48 through December 2014. Additional surcharges of $0.48 and $0.49 will be applied in January 2015 and January 2016, respectively, and will continue through 2025.

42
Elizabethtown Gas In August 2013 the New Jersey BPU approved the recovery of investments under the accelerated enhanced infrastructure program through a permanent adjustment to base rates. The base rate adjustments associated with this program were previously implemented on a provisional basis. Also in August 2013 our request under the accelerated infrastructure replacement (AIR) program was approved by the New Jersey BPU under modified terms from Elizabethtown Gas’ initial request. The approval allows for infrastructure investment of $115 million over four years, effective as of September 2013. Carrying charges on the additional capital spend will be accrued and deferred at a weighted average cost for capital of 6.65%, and there will be no adjustment to base rates until Elizabethtown Gas files its next rate case. We agreed to file a general rate case by September 2016. This rate case requirement is consistent with the approvals the New Jersey BPU has given to other gas utilities in the state related to their similar filingscollateral.

In March 2013, the BPU issued an order inviting the submission of proposals from utilities for infrastructure upgrades designed to protect New Jersey’s utility infrastructure from future major storm events. In September 2013 in response to this request, Elizabethtown Gas filed forIncreasing natural gas commodity prices can have a Natural Gas Distribution Utility Reinforcement Effort (ENDURE), a program that will improve the distribution system resiliency against coastal storms and floods. Under the proposed plan, Elizabethtown will invest $15 million in infrastructure and related facilities and communication planning over a one year period beginning January 2014. Elizabethtown Gas is proposing to accrue and defer carrying chargessignificant impact on the investment until its next rate case proceeding.
Virginia Natural Gas In January 2012 Virginia Natural Gas filed SAVE, an accelerated infrastructure replacement program, with the Virginia Commission, which involves replacing aging infrastructure as prioritized through Virginia Natural Gas’ distribution integrity management program. SAVE was filed in accordance with a Virginia statute providing a regulatory cost recovery mechanism to recover the costs associated with certain infrastructure replacement programs. The Virginia Commission approved SAVE in June 2012 for a five-year period, which includes a maximum allowance for capital expenditure of $25 million per year, not to exceed $105 million in total. SAVE is subject to annual review by the Virginia Commission. We began recovering costs basedour commercial paper borrowings. Based on this program through a rate rider that became effective August 1, 2012. In May 2013 we filed our annual SAVE rate update detailing the first year performancecurrent natural gas prices and our expected future budget, whichinjection plan, a $1 NYMEX price increase could result in a $211 million change of working capital requirements during the 2014 injection season. This range is subjectsensitive to reviewthe timing of storage injections and approval bywithdrawals, collateral requirements and our portfolio position. Based on current natural gas prices and our expected purchases during the Virginia Commission. The rate update was approved with minor modifications byremainder of the Virginia Commission in July 2013 and became effective as of August 2013.injection season, we believe that we have sufficient liquidity to cover our working capital needs for the upcoming Heating Season.

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

Credit ratings and outlooks are opinions subject to ongoing review by the rating agencies and may periodically change. The rating agencies regularly review our performance prospects and financial condition and reevaluate their ratings of our long-term debt and short-term borrowings, our corporate ratings and our ratings outlook. There is no guarantee that a rating will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. A credit rating is not a recommendation to buy, sell or hold securities and each rating should be evaluated independently of other ratings.

35
Factors we consider important to assessing our credit ratings include our Consolidated Statements of Financial Position, leverage, capital spending, earnings, cash flow generation, available liquidity and overall business risks. We do not have any triggering events in our debt instruments that are tied to changes in our specified credit ratings or our stock price and have not entered into any agreements that would require us to issue equity based on credit ratings or other trigger events. The following table summarizes our credit ratings as of September 30, 2013March 31, 2014 and reflects no change from December 31, 2012what was reported in our 2013 Form 10-K.

  AGL Resources  Nicor Gas 
  S&P  Moody’s  Fitch  S&P  Moody’s  Fitch 
Corporate rating BBB+   n/a  BBB+  BBB+   n/a   A 
Commercial paper  A-2   P-2   F2   A-2   P-2P-1   F1 
Senior unsecured BBB+Baa1BBB+BBB+   A3 BBB+ BBB+A2   A+ 
Senior secured  n/a   n/a   n/a   A    A1Aa3    AA- 
Ratings outlook Stable  Stable  Stable  Stable  Stable  Stable 

Our credit ratings depend largely on our financial performance, and aA downgrade in our current ratings, particularly below investment grade, would increase our borrowing costs and could limit our access to the commercial paper market. In addition, we would likely be required to pay a higher interest rate in future financings, and our potential pool of investors and funding sources could decrease.

Default Provisions Our debt instruments and other financial obligations include provisions that, if not complied with, could require early payment or similar actions. Our credit facilities contain customary events of default, including, but not limited to, the failure to comply with certain affirmative and negative covenants, cross-defaults to certain other material indebtedness and a change of control.

43
Our 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.

Our credit facilities 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 fiscal month. However, our goal, subject to extraordinary events such as acquisitions, iswe typically seek to maintain these ratios at levels between 50% and 60%. These ratios, as defined within our debt agreements, include standby letters of credit, performance/surety bonds and exclude accumulated OCI items, except for temporary increases related to non-cash pension adjustments, other post-retirement benefits liability adjustmentsthe timing of acquisition and accounting adjustments for cash flow hedges.financing activities. Adjusting for these items, the following table contains our debt-to-capitalization ratios for the dates presented, which are below the maximum allowed.

  September 30, 2013  December 31, 2012  September 30, 2012 
AGL Credit Facility  55%  58%  56%
Nicor Gas Credit Facility  50%  55%  51%

We were in compliance with all of our debt provisions and covenants, both financial and non-financial, for all periods presented.

Our ratio of total debt to total capitalization, on a consolidated basis, is typically greater at the beginning of the Heating Season, as we make additional short-term borrowings to fund our natural gas purchases and meet our working capital requirements. We attempt to maintain our ratio of total debt to total capitalization in a target range of 50% to 60%. Accomplishing this capital structure objective and maintaining sufficient cash flow are necessary to maintain attractive credit ratings. For more information on our default provisions, see Note 6 to our unaudited Condensed Consolidated Financial Statements under Item 1 herein. The components of our capital structure, as calculated from our unaudited Condensed Consolidated Statements of Financial Position, as of the dates indicated are provided in the following table.
  AGL Resources  Nicor Gas 
   
Mar. 31,
   
Dec. 31,
   
Mar. 31,
   
Mar. 31,
   
Dec. 31,
   
Mar. 31,
 
   2014   2013   2013   2014   2013   2013 
Debt-to-capitalization ratio as calculated from our unaudited Condensed Consolidated Statement of Financial Position  54%  58%  55%  53%  54%  42%
Adjustments (1)
  (1)  (1)  (1)  1   1   1 
Debt-to-capitalization ratio as calculated from our credit facilities  53%  57%  54%  54%  55%  43%

  September 30, 2013  December 31, 2012  September 30, 2012 
Short-term debt  10%  16%  13%
Long-term debt  47   43   45 
Total debt  57   59   58 
Equity  43   41   42 
Total capitalization  100%  100%  100%
(1)  As defined in credit facilities, includes standby letters of credit, performance/surety bonds and excludes accumulated OCI items related to non-cash pension adjustments, other post-retirement benefits liability adjustments and accounting adjustments for cash flow hedges.

Cash Flows The following table provides a summary of our operating, investing and financing cash flows for the periods presented.

 
Nine months ended September 30,
   Three months ended March 31,  
In millions 2013  2012  Variance  2014  2013  Variance 
Net cash provided by (used in):Net cash provided by (used in):    Net cash provided by (used in):    
Operating activities $1,070  $1,032  $38  $853  $850  $3 
Investing activities  (661)  (577)  (84)  (164)  (256)  92 
Financing activities  (409)  (433)  24   (501)  (576)  75 
Net increase in cash and cash equivalents  -   22   (22)  188   18   170 
Cash and cash equivalents at beginning of period  131   69   62   105   131   (26)
Cash and cash equivalents at end of period $131  $91  $40  $293  $149  $144 

Cash Flow from Operating Activities The $38$3 million increase in cash from operating activities for the ninethree months ended September 30, 2013March 31, 2014 compared to the same period in 20122013 was primarily related to increased cash provided by (i) net energy marketing receivables and payables, duehigher earnings year over year largely attributed to higher cash receivedsignificantly colder-than-normal weather in the current period relatedyear and increased price volatility that enabled us to higher sales volumes at higher pricescapture value in December 2012 versus the same period in 2011,wholesale services, (ii) prepaid taxes,inventories, net of LIFO liquidation, due to decreased prepaid positions forincreased LIFO liquidation at Nicor Gas and increased withdrawals at our distribution and midstream operations, partially offset by a decrease in withdrawals at Sequent, and (iii) accrued expenses due to higher federal and state income taxes and (iii) lower payments for incentive compensation in 2013payable as a result of reducedhigher earnings in 2012 as compared to the current year and the utilization of a prior year.period net operating loss that reduced the tax obligation in 2013. This increase in cash provided by operating activities was partiallylargely offset by decreased cash provided by (i) receivables, other than energy marketing, due to colder weather in 2013,2014, which resulted in higher volumes primarily at distribution operations and retail operations that will be collected in future periods, (ii) deferred natural gas costs, due to an increase in the price paid for natural gas in the first quarter of 2014 associated with the extremely cold weather, primarily in Illinois, that led to an under-collected position in the current year, and (ii) inventories,(iii) net energy marketing receivables and payables, due to higher inventory injections at distribution operations, retail energy and midstream operations.cash received in 2013 that related to December 2012.

36
Cash Flow from Investing Activities The $84$92 million increasedecrease in cash flow used in investing activities was primarily the result of our $122 million acquisition of approximately 500,000 service plans during the first quarter of 2013 and our $32 million acquisition of approximately 33,000 residential and commercial energy customer relationships in Illinois during the second quarter of 2013. This increasedecrease was partially offset by decreasedincreased spending for property, plant and equipmentPP&E expenditures of $34 million, a net decrease in short-term investments of $24 million and $12 million from the sale of Compass Energy.$16 million.

44
Cash Flow from Financing Activities The decreased use of cash for our financing activities for the ninethree months ended September 30, 2013March 31, 2014 compared to the same period in 20122013 was primarily the result of our May 2013 issuance of senior notes and the cash contribution received from Piedmont that was used to reduce ourlower commercial paper borrowings,repayments due to higher working capital needs at distribution operations, partially offset by higher short-term debt paymentsrecovery of $272 million and our April 2013 payment of $225 million of senior notes.

At September 30, 2013 our variable-rate debt was 23% of our total debt, compared to 32%, as of December 31, 2012 and 27% as of September 30, 2012. The decrease from December 31, 2012 was primarily due to decreased commercial paper borrowings. As of September 30, 2013 our commercial paper borrowings of $832 million were 40% lower than as of December 31, 2012, primarily a result of our repayment of a portion of AGL Capital’s commercial paper borrowings.working capital at wholesale services. For more information on our debt, see Note 67 to our unaudited Condensed Consolidated Financial Statements under Part I, Item 1 herein.

In April 2013 our $225 million 4.45% senior notes matured. Repayment of these senior notes was funded through our commercial paper program. In May 2013, we issued $500 million in 30-year senior notes. The net proceeds of $494 million were used to repay a portion of AGL Capital’s commercial paper, including $225 million we borrowed to repay our senior notes that matured in April 2013.

Short-term Debt Our short-term debt comprises borrowings under our commercial paper programs and current portions of our senior notes and capital leases. The following table provides additional information on our short-term debt.

In millions 
Period end balance outstanding (1)
  
Daily average balance outstanding (2)
  
Minimum balance outstanding (2)
  
Largest balance outstanding (2)
 
Commercial paper - AGL Capital $680  $757  $380  $1,064 
Commercial paper - Nicor Gas  152   57   -   314 
Senior notes  -   86   -    225 
Capital leases  -   1   -   1 
Total short-term debt and current portions of long-term debt and capital leases $832  $901  $380  $1,604 
(1)  
As of September 30, 2013.
(2)  
For the nine months ended September 30, 2013. The minimum and largest balances outstanding for each short-term debt instrument occurred at different times during the period. Consequently, the total balances are not indicative of actual borrowings on any one day during the period.

The largest, minimum and daily average balances borrowed under our commercial paper programs are important when assessing the intra-period fluctuations of our short-term borrowings and potential liquidity risk. The fluctuations are due to our seasonal cash requirements to fund working capital needs, in particular the purchase of natural gas inventory.

Increasing natural gas commodity prices can have a significant impact on our commercial paper borrowings. Based on current natural gas prices and our expected injection plan, a $1 increase NYMEX price change could result in a $24 million change of working capital requirements during the 2013 injection season. This range is sensitive to the timing of storage injections and withdrawals, collateral requirements and our portfolio position. Based on current natural gas prices and our expected purchases during the remainder of the injection season, we believe that we have sufficient liquidity to cover our working capital needs for the upcoming Heating Season.

In October 2013 we notified the administrative agents for our two credit facilities of our request to extend the maturity date of each facility by one year, in accordance with the terms of their respective agreements. Subject to receiving the required lender consents for the extensions, the AGL Credit Facility and Nicor Gas Credit facility maturity dates will be extended to November 10, 2017 and December 15, 2017, respectively. The existing terms, conditions and pricing under the agreements remain unchanged. We anticipate paying a fee to the consenting lenders for the one-year extension. Upon receipt of consents from all lenders under the agreements, we would pay $1 million in extension fees, which will be amortized over the remaining period of the respective credit facilities.

The lenders under our credit facilities and lines of credit are major financial institutions with $2.2 billion of committed balances and all had investment grade credit ratings as of September 30, 2013. It is possible that one or more lending commitments could be unavailable to us if the lender defaulted due to lack of funds or insolvency. However, based on our current assessment of our lenders’ creditworthiness, we believe the risk of lender default is minimal.

Long-term Debt Our long-term debt matures more than one year from September 30, 2013 and consists of medium-term notes: Series A, Series B, and Series C, which we issued under an indenture during December 1989; senior notes; first mortgage bonds; and gas facility revenue bonds.

45
During the first quarter of 2013 we refinanced $200 million of our outstanding tax-exempt gas facility revenue bonds, $180 million of which were previously issued by the New Jersey Economic Development Authority and $20 million of which were previously issued by Brevard County, Florida. The refinancing involved a combination of the issuance of $60 million of refunding bonds to and the purchase of $140 million of existing bonds by a syndicate of banks. Our relationship with the syndicate of banks regarding the bonds is governed by an agreement that contains representations, warranties, covenants and default provisions consistent with those contained in similar financing documents of ours. All of the bonds remain floating-rate instruments and we anticipate interest expense savings of approximately $2 million annually over the 5.5 year term of the agreement. AGL Resources had no cash receipts or payments in connection with the refinancing. The letters of credit providing credit support for the retired bonds along with other related agreements were terminated as a result of the refinancing. Costs associated with these refinancings will be amortized over the remaining life of the bonds.

Noncontrolling Interest We recorded cash distributions for SouthStar’s dividend distributions to Piedmont of $17 million for the nine months ended September 30, 2013 and $14 million for the same period in 2012. The primary reason for the increase in the distribution to Piedmont during the current year was increased earnings for 2012 compared to 2011. In September 2013 Piedmont contributed to SouthStar $22.5 million in cash to maintain its 15% ownership in the joint venture subsequent to our contribution of our Illinois retail energy businesses.

Dividends on Common Stock Our common stock dividend payments were $166 million for the nine months ended September 30, 2013 and $150 million for the same period in 2012. The increase is primarily due to the $0.10 stub period dividend paid in December 2011, which reduced the dividend paid in the first quarter of 2012 by the same amount and the annual dividend increase of $0.04 per share.herein.

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

Other than the changes in our debt, see Note 67 to our unaudited Condensed Consolidated Financial Statements under Part I, Item 1 herein, there were no significant changes to our contractual obligations described in Note 11 to our Consolidated Financial Statements and related notes as filed in Item 8 of our 20122013 Form 10-K.

Pension and retiree welfare plan obligations Primarily as a result of merging our pension plans in December 2012, no contributions were required thus far this year or are expected for the remainder of 2013. During the first nine months of 2012 we contributed $32 million to certain of our qualified pension plans and an additional $8 million in October 2012 for a total of $40 million through October 2012. Based on the current funding status of our merged pension plan, we do not believe additional contributions to the pension plan will be required during 2013.

During the nine months ended September 30, 2013 we recorded net periodic benefit costs of $43 million related to our defined benefit plans compared to $46 million during the same period last year. The final annual expense is expected to be $57 million, before capitalization, for 2013 compared to actual expense of $61 million for 2012. We estimate that during the remainder of 2013 we will record net periodic benefit costs of $14 million.

Critical Accounting Policies and Estimates

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

Each of our critical accounting estimates involves complex situations requiring a high degree of judgment either in the application and interpretation of existing literature or in the development of estimates that impact our financial statements. Except as described below, there have been no significant changes to our critical accounting estimates from those disclosed in our Management’s Discussion and Analysis of Financial Condition and Results of Operations as filed on our 20122013 Form 10-K. Our critical accounting estimates used in the preparation of our unaudited Condensed Consolidated Financial Statements include the following:

· Regulatory Infrastructure Program Liabilities
·Environmental Remediation LiabilitiesAccounting for Rate-Regulated Subsidiaries
· Derivatives and Hedging Activities
· Goodwill and Long-Lived Assets, including Other Intangible Assets
· Contingencies
· Pension and Retiree WelfareOther Retirement Plans
· Provisions for Income Taxes
46

Goodwill Impairment Testing OurDuring the first quarter of 2014 we conducted an engineering study that indicated a reduction in our estimated working gas capacity from what was projected when our 2013 annual goodwill impairment analysis that was performed duringin the fourth quarter of 20122013. Given that the 2013 annual goodwill impairment test indicated that the estimated fair value of athe storage and fuels reporting unit within our midstream operations segment, with $14 million of goodwill, exceeded its carrying valueamount by less than 10% as5%, we considered this reduced forecast of our testing date. During the third quarter of 2013 we identified a reduction in the near-term market rates at which we are able to re-contractstorage capacity at our storage facilities. We considered the decline in near term rates as an indicator of potential impairment and, accordingly, conducted an interim goodwill impairment analysis during the thirdfirst quarter of 2013.2014. See Note 2 to our unaudited Condensed Consolidated Financial Statements under Part I, Item 1 herein for additional information.
Accounting Developments

On April 10, 2014, the FASB issued authoritative guidance related to reporting discontinued operations. The fair valueguidance generally raises the threshold for disposals to qualify as discontinued operations and requires new disclosures of this reporting unit was determined utilizingboth discontinued operations and certain other material disposals that do not meet the incomedefinition of a discontinued operation. The guidance will be effective for us prospectively beginning January 1, 2015 and market approaches. The market approach is based on observable transactions of comparable companies and assets. The income approach estimates fair value based upon the present value of estimated future cash flows discounted at an appropriate risk-free rate. These forecasts contain a degree of uncertainty, and changes in the projected cash flows could significantly increase or decrease the estimated fair value of the reporting unit. Key assumptions used in the income approach included long-term growth rates used to determine the terminal value at the end of the discrete forecast period, current and future rates charged for contracted capacity and a discount rate. The discount rate is applied to estimated future cash flows and is one of the most significant assumptions used to determine fair value under the income approach. As interest rates rise, the calculated fair values will decrease. The terminal growth rate was based on a combination of historical and forecasted statistics for real gross domestic product and personal income. The rates we charge to customers for capacity in the storage caverns are based on internal and external rates forecasts.

While near-term rates have declined, management’s forecast for long-term rates have not significantly changed since our 2012 impairment analysis was performed. Our interim goodwill impairment test indicated that the estimated fair value of this reporting unit continues to exceed its carrying value. We continue to monitor this reporting unit for impairment and note that continued declines in capacity or subscription rates or for a sustained period at the current market rates may result in an impairment of goodwill. Our risk of impairment of the underlying long-lived assetsit is not estimatedexpected to be significant becausehave a material impact on our consolidated financial statements. While permitted, we do not intend to adopt the assets have long remaining useful lives and authoritative accounting guidance requires such assets to be tested for impairment based on the basisearly.


37

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

We are exposed to risks associated with natural gas prices, interest rates, credit and fuel prices. Natural gas price risk is defined as the potential loss that we may incur as a result ofresults from changes in the fair value of natural gas. Interest rate risk results fromis caused by fluctuations in interest rates related to our portfolio of debt and equity instruments that we issue to provide financing and liquidity for our business. Credit risk results from the extension of credit throughout all aspects of our business, but is particularly concentrated at Atlanta Gas Light in distribution operations and in wholesale services. Our fuelFuel price risk, is primarily in our cargo shipping whichsegment, is a product of the fluctuation in fuel prices; however, this risk is partially reduced through fuel surcharges. With the exception of fuel price risk in our cargo shipping segment, we use derivative instruments to manage these risks. Our use of derivative instruments is governed by a risk management policy, approved and monitored by our Risk Management Committee (RMC)., which prohibits the use of derivatives for speculative purposes.

Our RMC is responsible for establishing the overall risk management policies and monitoring compliance with, and adherence to, the terms within these policies, including approval and authorization levels and delegation of these levels. Our RMC consists of members of senior management who monitor open natural gas price risk positions and other types of risk, corporate exposures, credit exposures and overall results of our risk management activities. It is chaired by our chief risk officer, who is responsible for ensuring that appropriate reporting mechanisms exist for the RMC to perform its monitoring functions. Our risk management activities and related accounting treatment for our derivative instruments are described in further detail in Note 45 of our unaudited Condensed Consolidated Financial Statements included herein.

Natural Gas Price Risk

The following tables include the fair values and average values of our consolidated derivative instruments as of the dates indicated. We base the average values on monthly averages for the ninethree months ended September 30,March 31, 2014 and 2013 and 2012.

 
Derivative instruments average values at September 30, (1)
  
Derivative instruments average values at March 31, (1)
 
In millions 2013  2012  2014  2013 
Asset $106  $213  $213  $114 
Liability  42   97   183   29 
(1) Excludes cash collateral amounts.

47



 Derivative instruments fair values netted with cash collateral at  Derivative instruments fair values netted with cash collateral at 
In millions 
September 30, 2013
  December 31, 2012  
September 30, 2012
  
March 31, 2014
  December 31, 2013  
March 31, 2013
 
Asset $112  $144  $159  $138  $119  $111 
Liability  44   39   42   82   80   24 

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

   
 
Three months ended September 30,
  
Nine months ended September 30,
  
Three months ended March 31,
 
In millions 2013  2012  2013  2012  2014  2013 
Net fair value of derivative instruments outstanding at beginning of period $(3) $23  $36  $31  $(82) $36 
Derivative instruments realized or otherwise settled during period  (11)  (16)  (55)  (65)  57   (43)
Net fair value of derivative instruments acquired during period  -   -   -   - 
Change in net fair value of derivative instruments  (12)  17   (7)  58   (19)  17 
Net fair value of derivative instruments outstanding at end of period  (26)  24   (26)  24   (44)  10 
Netting of cash collateral  94   93   94   93   100   77 
Cash collateral and net fair value of derivative instruments outstanding at end of period $68  $117  $68  $117  $56  $87 

The sources of our net fair value at September 30, 2013,March 31, 2014, are as follows.

In millions 
Prices actively quoted (Level 1) (1)
  
Significant other observable inputs (Level 2) (2)
 
Mature through 2013 $(1) $6 
Mature 2014 - 2015
  (40)  10 
Mature 2016 - 2017
  (4)  3 
Total derivative instruments (3)
 $(45) $19 
In millions 
Prices actively quoted (Level 1) (1)
  
Significant other observable inputs
 (Level 2) (2)
 
Mature through 2014 $8  $(5)
Mature 2015 - 2016
  (26)  (19)
Mature 2017 - 2018
  (2)  - 
Total derivative instruments (3)
 $(20) $(24)
(1)   Valued using NYMEX futures prices.
(2)  Valued using basis transactions that represent the cost to transport natural gas from a NYMEX delivery point to the contract delivery point. These transactions are based on quotes obtained either through electronic trading platforms or directly from brokers.
(3)   Excludes cash collateral amounts.

38
Value atVaR Our VaR may not be comparable to that of other entities due to differences in the factors used to calculate VaR. Our VaR is determined on a 95% confidence interval and a 1-day holding period, which means that 95% of the time, the risk Value at risk is the maximum potential of loss in a day from a portfolio value over a specified time period thatof positions is not expected to be exceeded within a given degreeless than or equal to the amount of probability.VaR calculated. Our open exposure is managed in accordance with established policies that limit market risk and require daily reporting of potential financial exposure to senior management, including the chief risk officer. Because we generally manage physical gas assets and economically protect our positions by hedging in the futures markets, our open exposure is generally immaterial, permitting us to operate within relatively low VaR limits.mitigated. We employ daily risk testing, using both VaR and stress testing, to evaluate the risks of our open positions. Our VaR is determined on a 95% confidence interval and a 1-day holding period. In simple terms, this means that 95% of the time, the risk of loss from a portfolio of positions is expected to be less than or equal to the amount of VaR calculated.

Natural gas markets experienced levels of high volatility and increased prices due to the extended extreme cold weather during the first quarter of 2014, resulting in our VaR to be at elevated levels during the quarter as compared to prior periods. We actively managed and monitored the open positions and exposures that were driving the elevated VaR levels to not only remain in compliance with established policies, but to also mitigate the operational risks of not being able to meet customer needs under these extreme conditions. As conditions moderated at the end of the quarter, our period-end VaR was consistent with historical periods. We actively monitor open commodity positions and the resulting VaR. We also continue to maintain a relatively matched book, where our total buy volume is close to our sell volume, with minimal open natural gas price risk. Based on a 95% confidence interval and employing a 1-day holding period, for all positions, our portfolio positions for the periods presentedwe had the following VaRs.VaRs.

 
Three months ended September 30,
  
Nine months ended September 30,
  
Three months ended March 31,
 
In millions 2013  2012  2013  2012  2014  2013 
Period end $2.5  $1.7  $2.5  $1.7  $3.2  $1.7 
Average  2.3   1.5   2.0   2.2   6.4   1.9 
High  3.1   1.8   3.1   4.8   19.7   2.6 
Low  1.9   1.3   1.2   1.3   3.2   1.6 

Fuel Price Risk

Cargo Shipping Tropical Shipping’s objective is to reduce its exposure to higher fuel costs through fuel surcharges. However, these fuel surcharges do not remove our entire risk in periods of increasing fuel prices and volatility, or increased competition, and any relief may not be realized in the same period as the cost incurred. An increase of 10% in Tropical Shipping’s average cost per gallon for vessel fuel would result in $6 million in additional annual fuel expense. Fuel surcharges would be implemented to reduce the impact of the increased fuel expense.

Interest Rate Risk

Interest rate fluctuations expose our variable-rate debt to changes in interest expense and cash flows. Our policy is to manage interest expense using a combination of fixed-rate and variable-rate debt. Based on $1.0$0.9 billion of variable-rate debt outstanding at September 30, 2013,March 31, 2014, a 100 basis point change in market interest rates would have resulted in an increase in pre-tax interest expense of $10$9 million on an annualized basis.

We useutilize interest rate swaps to help us achieve our desired mix of variable to fixed--rate debt. Our variable-rate debt target generally ranges from 20% to 45% of total debt. We also may use forward-starting interest rate swaps and interest rate lock agreements to lock in fixed interest rates on our forecasted issuances of debt. The objective of these hedges is to offset the variability of future payments associated with the interest rate on debt instruments we expect to issue.

48
We have $300 million of 6.4% senior notes due in July 2016. In May 2011 we entered intoThe gain or loss on the interest rate swaps designated as cash flow hedges is generally deferred in accumulated OCI until settlement, at which point it is amortized to interest expense over the period of the related hedge interest payments. For additional information, see Note 5 to these senior notes to effectively convert $250 million from a fixed-rate to a variable-rate obligation. On September 6, 2012, we settled this $250 million interest rate swap, which resulted in our receipt of a $17 million cash payment.unaudited Condensed Consolidated Financial Statements included under Part 1, Item 1 herein.

On May 16, 2013, we issued $500 million of 30-year senior notes with a fixed interest rate of 4.4%. We had entered into $300 million, in notional amount, of fixed-rate forward-starting interest rate swaps to hedge the first ten years of potential interest rate volatility prior to this issuance. The weighted average interest rate of these swaps was a 10-year United StatesU.S. Treasury rate of 1.85%. On May 16, 2013, we settled these swaps, which resulted in our receipt of a $6 million cash payment.

The gain or loss on the interest rate swaps designated as cash flow hedges is generally deferred in accumulated OCI until settlement, at which point it is$6 million will be amortized to reduce interest expense over the periodfirst ten years of the related hedged interest payments. For additional information, see Note 4 to our unaudited Condensed Consolidated Financial Statements under Item 1 herein.30-year senior notes.

CreditFuel Price Risk

Wholesale ServicesCargo Shipping We have established credit policiesTropical Shipping’s objective is to determinereduce its exposure to higher fuel costs through fuel surcharges. However, these fuel surcharges do not remove our entire risk in periods of increasing fuel prices and monitorvolatility, or increased competition, and any relief may not be realized in the creditworthiness of counterparties, as wellsame period as the qualitycost incurred. An increase of pledged collateral. We also utilize master netting agreements whenever possible10% in Tropical Shipping’s average cost per gallon for vessel fuel would result in $6 million in additional annual fuel expense. Fuel surcharges would be implemented to mitigate exposure to counterparty credit risk. When we are engaged in more than one outstanding derivative transaction withreduce the same counterparty and we also have a legally enforceable netting agreement with that counterparty, the “net” mark-to-market exposure represents the nettingimpact of the positive and negative exposures with that counterparty and a reasonable measure of credit risk. We also use other netting agreements with certain counterparties with whom we conduct significant transactions. Master netting agreements enable us to net certain assets and liabilities by counterparty. We also net across product lines and against cash collateral provided the master netting and cash collateral agreements include such provisions.increased fuel expense.

Additionally, weInterest Rate Risk

Interest rate fluctuations expose our variable-rate debt to changes in interest expense and cash flows. Our policy is to manage interest expense using a combination of fixed-rate and variable-rate debt. Based on $0.9 billion of variable-rate debt outstanding at March 31, 2014, a 100 basis point change in market interest rates would have resulted in an increase in pre-tax interest expense of $9 million on an annualized basis.

We utilize interest rate swaps to help us achieve our desired mix of variable to fixed-rate debt. Our variable-rate debt target generally ranges from 20% to 45% of total debt. We also may require counterpartiesuse forward-starting interest rate swaps and interest rate lock agreements to pledge additional collateral when deemed necessary. We conduct credit evaluations and obtain appropriate internal approvals for each counterparty’s linelock in fixed interest rates on our forecasted issuances of credit before any transactiondebt. The objective of these hedges is to offset the variability of future payments associated with the counterpartyinterest rate on debt instruments we expect to issue. The gain or loss on the interest rate swaps designated as cash flow hedges is executed. In most cases,generally deferred in accumulated OCI until settlement, at which point it is amortized to interest expense over the counterparty must have an investment grade rating, which includes a minimum long-term debt ratingperiod of Baa3 from Moody’s and BBB- from S&P. Generally, we require credit enhancements by way of guaranty, cash deposit or letter of credit for transaction counterparties that do not have investment grade ratings.the related hedge interest payments. For additional information, see Note 5 to our unaudited Condensed Consolidated Financial Statements included under Part 1, Item 1 herein.

On May 16, 2013, we issued $500 million of 30-year senior notes with a fixed interest rate of 4.4%. We havehad entered into $300 million, in notional amount, of fixed-rate forward-starting interest rate swaps to hedge the first ten years of potential interest rate volatility prior to this issuance. The weighted average interest rate of these swaps was a concentration10-year U.S. Treasury rate of credit risk as measured by1.85%. On May 16, 2013, we settled these swaps, which resulted in our 30-day receivable exposure plus forward exposure. Asreceipt of September 30, 2013 our top 20 counterparties represented approximately 52%a $6 million cash payment. The $6 million will be amortized to reduce interest expense over the first ten years of the total counterparty exposure of $333 million, derived by adding together the top 20 counterparties’ exposures, exclusive of customer deposits, and dividing by the total of our counterparties’ exposures.30-year senior notes.

As of September 30, 2013 our counterparties, or the counterparties’ guarantors, had a weighted average S&P equivalent credit rating of A-, which is consistent with the prior year. The S&P equivalent credit rating is determined by a process of converting the lower of the S&P or Moody’s ratings to an internal rating ranging from 9 to 1, with 9 being equivalent to AAA/Aaa by S&P and Moody’s and 1 being D or Default by S&P and Moody’s. A counterparty that does not have an external rating is assigned an internal rating based on the strength of the financial ratios of that counterparty. To arrive at the weighted average credit rating, each counterparty is assigned an internal ratio, which is multiplied by their credit exposure and summed for all counterparties. The sum is divided by the aggregate total counterparties’ exposures, and this numeric value is then converted to an S&P equivalent. The following table shows our third-party natural gas contracts receivable and payable positions.

  Gross receivables  Gross payables 
In millions 
Sept. 30, 2013
  
Dec. 31, 2012
  
Sept. 30, 2012
  
Sept. 30,2013
  
Dec. 31, 2012
  
Sept. 30, 2012
 
Netting agreements in place:                  
Counterparty is investment grade $310  $485  $293  $229  $282  $201 
Counterparty is non-investment grade  -   9   15   7   13   20 
Counterparty has no external rating  185   175   87   302   315   223 
No netting agreements in place:                        
Counterparty is investment grade  4   7   1   -   1   - 
Counterparty has no external rating  3   1   1   1   -   - 
Amount recorded on unaudited Condensed Consolidated Statements of Financial Position $502  $677  $397  $539  $611  $444 

We have certain trade and credit contracts that have explicit minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, we would need to post collateral to continue transacting business with some of our counterparties. If such collateral were not posted, our ability to continue transacting business with these counterparties would be impaired. If our credit ratings had been downgraded to non-investment grade status, the required amounts to satisfy potential collateral demands under such agreements with our counterparties would have totaled $14 million at September 30, 2013, which would not have a material impact on our consolidated results of operations, cash flows or financial condition.

49
There have been no significant changes to our credit risk related to any of our segments other than wholesale services, as described in Item 7A ”Quantitative and Qualitative Disclosures about Market Risk” of our 2012 Form 10-K.

Fuel Price Risk

Cargo Shipping Tropical Shipping’s objective is to reduce its exposure to higher fuel costs through fuel surcharges. However, these fuel surcharges do not remove our entire risk in periods of increasing fuel prices and volatility, or increased competition, and any relief may not be realized in the same period as the cost incurred. An increase of 10% in Tropical Shipping’s average cost per gallon for vessel fuel resultswould result in approximately $5$6 million in additional annual fuel expense. Fuel surcharges would be implemented to reduce the impact of the increased fuel expense.

Interest Rate Risk

Interest rate fluctuations expose our variable-rate debt to changes in interest expense and cash flows. Our policy is to manage interest expense using a combination of fixed-rate and variable-rate debt. Based on $0.9 billion of variable-rate debt outstanding at March 31, 2014, a 100 basis point change in market interest rates would have resulted in an increase in pre-tax interest expense of $9 million on an annualized basis.

We utilize interest rate swaps to help us achieve our desired mix of variable to fixed-rate debt. Our variable-rate debt target generally ranges from 20% to 45% of total debt. We also may use forward-starting interest rate swaps and interest rate lock agreements to lock in fixed interest rates on our forecasted issuances of debt. The objective of these hedges is to offset the variability of future payments associated with the interest rate on debt instruments we expect to issue. The gain or loss on the interest rate swaps designated as cash flow hedges is generally deferred in accumulated OCI until settlement, at which point it is amortized to interest expense over the period of the related hedge interest payments. For additional information, see Note 5 to our unaudited Condensed Consolidated Financial Statements included under Part 1, Item 1 herein.

On May 16, 2013, we issued $500 million of 30-year senior notes with a fixed interest rate of 4.4%. We had entered into $300 million, in notional amount, of fixed-rate forward-starting interest rate swaps to hedge the first ten years of potential interest rate volatility prior to this issuance. The weighted average interest rate of these swaps was a 10-year U.S. Treasury rate of 1.85%. On May 16, 2013, we settled these swaps, which resulted in our receipt of a $6 million cash payment. The $6 million will be amortized to reduce interest expense over the first ten years of the 30-year senior notes.

Credit Risk

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

39
Additionally, we may require counterparties to pledge additional collateral when deemed necessary. We conduct credit evaluations and obtain appropriate internal approvals for a counterparty’s line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have an investment grade rating, which includes a minimum long-term debt rating of Baa3 from Moody’s and BBB- from S&P. Generally, we require credit enhancements by way of guaranty, cash deposit or letter of credit for transaction counterparties that do not have investment grade ratings.

We have a concentration of credit risk as measured by our 30-day receivable exposure plus forward exposure. As of March 31, 2014, our top 20 counterparties represented 52% of the total counterparty exposure of $822 million, derived by adding together the top 20 counterparties’ exposures, exclusive of customer deposits, and dividing by the total of our counterparties’ exposures.

As of March 31, 2014, our counterparties, or the counterparties’ guarantors, had a weighted average S&P equivalent credit rating of A-, which is consistent with the prior year. The S&P equivalent credit rating is determined by a process of converting the lower of the S&P or Moody’s ratings to an internal rating ranging from 9 to 1, with 9 being equivalent to AAA/Aaa by S&P and Moody’s and 1 being D or Default by S&P and Moody’s. A counterparty that does not have an external rating is assigned an internal rating based on the strength of the financial ratios of that counterparty. To arrive at the weighted average credit rating, each counterparty is assigned an internal ratio, which is multiplied by their credit exposure and summed for all counterparties. The sum is divided by the aggregate total counterparties’ exposures, and this numeric value is then converted to an S&P equivalent. The following table shows our third-party natural gas contracts receivable and payable positions.

  Gross receivables  Gross payables 
  
Mar. 31,
  
Dec. 31,
  Mar. 31,  
Mar. 31,
  
Dec. 31,
  
Mar. 31,
 
In millions 2014  2013  2013  2014  2013  2013 
Netting agreements in place:                  
Counterparty is investment grade $737  $496  $286  $453  $265  $198 
Counterparty is non-investment grade  2   -   4   16   10   13 
Counterparty has no external rating  427   260   319   631   393   431 
No netting agreements in place:                        
Counterparty is investment grade  53   29   12   3   2   10 
Counterparty is non-investment grade  3   -   -   -   -   - 
Counterparty has no external rating  4   1   6   16   1   1 
Amount recorded on unaudited Condensed Consolidated Statements of Financial Position $1,226  $786  $627  $1,119  $671  $653 

We have certain trade and credit contracts that have explicit minimum credit rating requirements. These credit rating requirements typically give counterparties the right to suspend or terminate credit if our credit ratings are downgraded to non-investment grade status. Under such circumstances, we would need to post collateral to continue transacting business with some of our counterparties. If such collateral were not posted, our ability to continue transacting business with these counterparties would be impaired. If our credit ratings had been downgraded to non-investment grade status, the required amounts to satisfy potential collateral demands under such agreements with our counterparties would have totaled $15 million at March 31, 2014, which would not have a material impact on our consolidated results of operations, cash flows or financial condition.

There have been no significant changes to our credit risk related to any of our segments other than wholesale services, as described in Item 7A ”Quantitative and Qualitative Disclosures about Market Risk” of our 2013 Form 10-K.

ITEM 4. CONTROLS AND PROCEDURES.

(a) Evaluation of disclosure controls and procedures. Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of September 30, 2013,March 31, 2014, the end of the period covered by this report. Based on this evaluation, our principal executive officer and our principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2013,March 31, 2014, in providing a reasonable level of assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods in SEC rules and forms, including a reasonable level of assurance that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our principal executive officer and our principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

(b) Changes in Internal Control over Financial Reporting. There were no changes in our internal control over financial reporting that occurred during the third quarter ended September 30, 2013,March 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.



PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

The nature of our business ordinarily results in periodic regulatory proceedings before various state and federal authorities. In addition, we are party, as both plaintiff and defendant, to a number of lawsuits related to our business on an ongoing basis. Management believes that the outcome of all regulatory proceedings and litigation in which we are currently involved will not have a material adverse effect on our consolidated financial condition. For more information, see Note 910 to our unaudited Condensed Consolidated Financial Statements in this quarterly filing under the caption “Litigation.”“Litigation” and Part I, Item 3. Legal Proceedings in our 2013 Form 10-K.

We recently commenced an investigation into payments to local officials and related persons at one of the foreign ports serviced by Tropical Shipping. While the investigation is ongoing, we believe that a number of payments were made over a series of years and the aggregate amount of these payments is less than $200,000 based upon information obtained to date. In October 2013, we voluntarily disclosed these matters to the U.S. Department of Justice (DOJ) and the SEC. We will cooperate with any investigation by the DOJ and the SEC. We presently are unable to predict the duration, scope or result of this investigation or of any governmental investigation.

Item 1A. Risk Factors.

For information regarding our risk factors, see the factors discussed in Part I, Item 1A. Risk Factors in our 20122013 Form 10-K and Part II Item 1A. Risk Factors in our second quarter 2013 Form 10-Q.. These risk factors could materially affect our business, financial condition or future results. There have been no significant changes to our risk factors included in Item 1A of our 2013 Form 10-K.The risks described in the referenced documentsdocument are not the only risks facing our Company.the company. Additional risks and uncertainties not currently known to us or that we currently do not recognize as material also may materially adversely affect our business, financial condition or future results.

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

There were no purchases of our common stock by us or any affiliated purchasers during the thirdfirst quarter of 20132014 and no unregistered sales of equity securities were made during this period.

Item 6. Exhibits



Item 6. Exhibits.
Exhibit Number 
Description of Exhibit
10
Filer
Second Amended and Restated Limited Liability Company Agreement of SouthStar Energy Services LLC, dated September 6, 2013
The Filings Referenced for
Incorporation by and between Georgia Natural Gas Company and Piedmont Energy Company.
Reference
 12 Statement of Computation of Ratio of Earnings to Fixed Charges.
ChargesAGL ResourcesFiled herewith
 31.1 
Certification of John W. Somerhalder II pursuant to Rule 13a - 14(a).
AGL ResourcesFiled herewith
 31.2 Certification of Andrew W. Evans pursuant to Rule 13a - 14(a).
AGL ResourcesFiled herewith
 32.1 Certification of John W. Somerhalder II pursuant to 18 U.S.C. Section 1350.
AGL ResourcesFiled herewith
 32.2 Certification of Andrew W. Evans pursuant to 18 U.S.C. Section 1350.
AGL ResourcesFiled herewith
101.INS XBRL Instance Document.
DocumentAGL ResourcesFiled herewith
101.SCH XBRL Taxonomy Extension Schema.
SchemaAGL ResourcesFiled herewith
101.CAL XBRL Taxonomy Extension Calculation Linkbase.
LinkbaseAGL ResourcesFiled herewith
101.DEF XBRL Taxonomy Definition Linkbase.
LinkbaseAGL ResourcesFiled herewith
101.LAB XBRL Taxonomy Extension Labels Linkbase.
LinkbaseAGL ResourcesFiled herewith
101.PRE XBRL Taxonomy Extension Presentation Linkbase.LinkbaseAGL ResourcesFiled herewith






SIGNATURE

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

 
AGL RESOURCES INC.
(Registrant)
Date: April 29, 2014 /s/ Andrew W. Evans
Executive Vice President and Chief Financial Officer


Date: October 30, 2013                                                                                                  /s/ Andrew W. Evans
 Executive Vice President and Chief Financial Officer