Glossary of Key Terms
 
Table of Contents


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-Q
                                                                  (Mark One) 
þ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
 
For the Quarterly Period Ended September 30, 2008March 31, 2009
 
OR
 
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from        to
 
Commission File Number 1-14174
 
AGL RESOURCES INC.
(Exact name of registrant as specified in its charter)
 
Georgia58-2210952
(State or other jurisdiction of incorporation or organization)(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 registrant (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 registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨
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.

Large accelerated filer þ
     Accelerated filer ¨
Non-accelerated filer ¨ (Do not check if a smaller reporting company)
     Smaller 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 22, 2008April 23, 2009
Common Stock, $5.00 Par Value
                        76,780,43977,170,946
 


Glossary of Key Terms
 
Table of Contents

AGL RESOURCES INC.

Quarterly Report on Form 10-Q

For the Quarter Ended September 30, 2008March 31, 2009

 TABLE OF CONTENTS    
      Page(s)  
 
Glossary of Key Terms & Referenced Accounting Standards 
  3  
        
 Item       
 Number       
     PART 1 – FINANCIAL INFORMATION  4-38 
        
 1 
Condensed Consolidated Financial Statements (Unaudited)
  4-7 
   
Condensed Consolidated Balance Sheets
  4 
   
Condensed Consolidated Statements of Income
  5 
   
Condensed Consolidated Statements of Common Shareholders’ Equity
  6 
   
Condensed Consolidated Statements of Cash Flows
  7 
   
Notes to Condensed Consolidated Financial Statements
  8-19 
   
Note 1 - Accounting Policies and Methods of Application
  8-11 
   
Note 2 - Financial Instruments and Risk Management
  11-13 
   
Note 3 - Employee Benefit Plans
  13-14 
   
Note 4 - Common Shareholders’ Equity
  14 
   
Note 5 - Debt
  15 
   
Note 6 - Commitments and Contingencies
  16-17 
   
Note 7 - Segment Information
  17-19 
 2 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
  20-38 
   
Forward-Looking Statements
  20 
   
Overview
  20 
   
Executive Summary
  20-22 
   
Distribution Operations
  22 
   
Retail Energy Operations
  23 
   
Wholesale Services
  23-24 
   
Energy Investments
  24 
   
Corporate
  25 
   
Results of Operations
  25-30 
   
Liquidity and Capital Resources
  30-33 
   
Critical Accounting Policies and Estimates
  34 
   
Accounting Developments
  34 
 3 
Quantitative and Qualitative Disclosures About Market Risk
  34-38 
 4 
Controls and Procedures
  38 
        
   
PART II – OTHER INFORMATION
  39-40 
        
 1 
Legal Proceedings
  39 
 2 
Unregistered Sales of Equity Securities and Use of Proceeds
  39 
 6 
Exhibits
  39 
        
   
SIGNATURE
  40 
      
TABLE OF CONTENTS
   
   Page(s) 
Glossary of Key Terms & Referenced Accounting Standards
  3 
       
Item      
Number      
       
  
PART 1 – FINANCIAL INFORMATION
  4-38 
       
 1 
Condensed Consolidated Financial Statements (Unaudited)
  4-21 
   
Condensed Consolidated Statements of Financial Position
  4 
   
Condensed Consolidated Statements of Income
  5 
   
Condensed Consolidated Statements of Equity
  6 
   
Condensed Consolidated Statements of Comprehensive Income
  7 
   
Condensed Consolidated Statements of Cash Flows
  8 
   
Notes to Condensed Consolidated Financial Statements
  9 – 21 
   
Note 1 - Accounting Policies and Methods of Application
  9 – 11 
   
Note 2 - Fair Value Measurements
  11 – 12 
   
Note 3 - Derivative Financial Instruments
  12 – 15 
   
Note 4 - Employee Benefit Plans
  16 
   
Note 5 - Equity
  17 
   
Note 6 - Debt
  18 
   
Note 7 - Commitments and Contingencies
  18 – 19 
   
Note 8 - Segment Information
  20 – 21 
 2 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
  22 – 35 
   
Forward-Looking Statements
  22 
   
Overview
  22 
   
Executive Summary
  23 
   
Distribution Operations
  23 – 24 
   
Retail Energy Operations
  24 – 25 
   
Wholesale Services
  25 – 26 
   
Energy Investments
  27 
   
Corporate
  27 
   
Results of Operations
  27 – 31 
   
Liquidity and Capital Resources
  31 – 34 
   
Critical Accounting Policies and Estimates
  34 
   
Accounting Developments
  34 – 35 
 3 
Quantitative and Qualitative Disclosures About Market Risk
  35 – 38 
 4 
Controls and Procedures
  38 
        
   
PART II – OTHER INFORMATION
  39 
        
 1 
Legal Proceedings
  39 
 2 
Unregistered Sales of Equity Securities and Use of Proceeds
  39 
 6 
Exhibits
  39 
        
   
SIGNATURE
  40 

 
Glossary of Key Terms
2
Table of Contents

GLOSSARY OF KEY TERMS

AFUDCAllowance for funds used during construction, which has been authorized by applicable state regulatory agencies to record the cost of debt and equity funds as part of the cost of construction projects
AGL CapitalAGL Capital Corporation
AGL NetworksAGL Networks, LLC
Atlanta Gas LightAtlanta Gas Light Company
BcfBillion cubic feet
Chattanooga GasChattanooga Gas Company
Credit FacilityFacilitiesCredit agreements supporting our commercial paper program
EBITEarnings before interest and taxes, a non-GAAP measure that includes operating income, other income minority interest in SouthStar’s earnings and gain on sales of assets and excludes interest expense, and income tax expense; as an indictorindicator of our operating performance, EBIT should not be considered an alternative to, or more meaningful than, operating income, net income, or net income attributable to AGL Resources Inc. as determined in accordance with GAAP
EITFEmerging Issues Task Force
ERCEnvironmental remediation costs associated with our distribution operations segment which are recoverable through rates mechanisms
FASBFinancial Accounting Standards Board
FERCFederal Energy Regulatory Commission
FINFASB Interpretation Number
FitchFitch Ratings
Florida CommissionFlorida Public Service Commission
FSPFASB Staff Position
GAAPAccounting principles generally accepted in the United States of America
Georgia CommissionGeorgia Public Service Commission
GNGGeorgia Natural Gas, the name under which SouthStar does business in Georgia
GNGCGeorgia Natural Gas Company, our wholly-owned subsidiary
Golden Triangle StorageGolden Triangle Storage, Inc.
Heating Degree DaysA measure of the effects of weather on our businesses, calculated when the average daily actual temperatures are less than a baseline temperature of 65 degrees Fahrenheit.
Heating SeasonThe period from November tothrough March when natural gas usage and operating revenues are generally higher because more customers are connected to our distribution systems when weather is colder
Jefferson IslandJefferson Island Storage & Hub, LLC
LOCOMLower of weighted average cost or current market price
Maryland CommissionMaryland Public Service Commission
MarketersMarketers selling retail natural gas in Georgia and certificated by the Georgia Commission
MMBtuNYMEX equivalent contract units of 10,000 million British thermal units
Moody’sMoody’s Investors Service
New Jersey CommissionNew Jersey Board of Public Utilities
NYMEXNew York Mercantile Exchange, Inc.
OCIOther comprehensive income
Operating marginA non-GAAP measure of income, calculated as revenues minus cost of gas, that excludes operation and maintenance expense, depreciation and amortization, taxes other than income taxes, and the gain or loss on the sale of our assets; these items are included in our calculation of operating income as reflected in our condensed consolidated statements of consolidated income. Operating margin should not be considered an alternative to, or more meaningful than, operating income, net income, or net income attributable to AGL Resources Inc. as determined tinin accordance with GAAP
OTCOver-the-counter
PiedmontPiedmont Natural Gas
Pivotal UtilityPivotal Utility Holdings, Inc., doing business as Elizabethtown Gas, Elkton Gas and Florida City Gas
PGAPurchased gas adjustment
PP&EProperty, plant and equipment
PRPPipeline replacement program for Atlanta Gas Light
S&PStandard & Poor’s Ratings Services
SECSecurities and Exchange Commission
SequentSequent Energy Management, L.P.
SFASStatement of Financial Accounting Standards
SouthStarSouthStar Energy Services LLC
VaRValue at risk is defined as 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
Virginia Natural GasVirginia Natural Gas, Inc.
Virginia CommissionVirginia State Corporation Commission
WACOGWeighted average cost of gas
WNAWeather normalization adjustment

REFERENCED ACCOUNTING STANDARDS

FSP FIN 39-1FASB Staff Position 39-1 “Amendment of FIN 39”
FIN 46 & FIN 46RFIN 46, “Consolidation of Variable Interest Entities”
FIN 48FIN 48, “Accounting for Uncertainty in Income Taxes, an interpretation of SFAS Statement No. 109”
FSP EITF 03-6-1FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities”
FSP EITF 06-3FSP EITF 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should be Presented in the Income Statement (That Is, Gross versus Net Presentation)”
FSP FAS 132(R)-1FSP No. FAS 132(R)-1,"Employers' Disclosures about Postretirement Benefit Plan Assets"
FSP FAS 133-1FSP No. FAS 133-1, “Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133”
FSP FAS 157-3FSP No. FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active”
SFAS 71SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation”
SFAS 133SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS 141SFAS No. 141, “Business Combinations”
SFAS 157SFAS No. 157, “Fair Value Measurements”
SFAS 160SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements”
SFAS 161SFAS No. 161, “Disclosure about Derivative Instruments and Hedging Activities, an amendment of SFAS 133”

Glossary of Key Terms
3
��
Table of Contents


PART 1 – Financial Information
Item 1. Financial Statements
AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS                        STATEMENTS OF FINANCIAL POSITION
(UNAUDITED)

     As of    
In millions, except share data September 30, 2008  December 31, 2007  September 30, 2007 
Current assets         
Cash and cash equivalents $11  $19  $14 
Energy marketing receivables  535   598   363 
Inventories  811   551   654 
Receivables (less allowance for uncollectible accounts of $17 at Sept. 30, 2008, $14 at Dec. 31, 2007 and $15 at Sept. 30, 2007)  189   391   143 
Energy marketing and risk management assets  172   69   90 
Unrecovered PRP costs – current portion  40   31   27 
Unrecovered ERC – current portion  20   23   24 
Other current assets  162   115   100 
Total current assets  1,940   1,797   1,415 
Property, plant and equipment            
Property, plant and equipment  5,377   5,177   5,142 
Less accumulated depreciation  1,651   1,611   1,610 
Property, plant and equipment-net  3,726   3,566   3,532 
Deferred debits and other assets            
Goodwill  418   420   420 
Unrecovered PRP costs  202   254   261 
Unrecovered ERC  124   135   132 
Other  94   86   71 
Total deferred debits and other assets  838   895   884 
Total assets $6,504  $6,258  $5,831 
Current liabilities            
Short-term debt $769  $580  $576 
Energy marketing trade payables  568   578   383 
Accounts payable - trade  181   172   131 
Accrued expenses  83   87   82 
Accrued PRP costs – current portion  43   55   47 
Customer deposits  39   35   39 
Energy marketing and risk management liabilities – current portion  34   16   9 
Deferred purchased gas adjustment  14   28   15 
Accrued environmental remediation liabilities – current portion  16   10   11 
Other current liabilities  75   73   73 
Total current liabilities  1,822   1,634   1,366 
Accumulated deferred income taxes  625   566   527 
Long-term liabilities and other deferred credits (excluding long-term debt)            
Accumulated removal costs  176   169   168 
Accrued PRP costs  152   190   204 
Accrued environmental remediation liabilities  89   97   88 
Accrued pension obligations  43   43   83 
Accrued postretirement benefit costs  19   24   25 
Other long-term liabilities and other deferred credits  150   152   158 
Total long-term liabilities and other deferred credits (excluding long-term debt)  629   675   726 
Commitments and contingencies (Note 6)            
Minority interest  29   47   41 
Capitalization            
Long-term debt  1,675   1,675   1,548 
Common shareholders’ equity, $5 par value; 750,000,000 shares authorized  1,724   1,661   1,623 
Total capitalization  3,399   3,336   3,171 
Total liabilities and capitalization $6,504  $6,258  $5,831 
See Notes to Condensed Consolidated Financial Statements (Unaudited).
     
     As of    
In millions, except share data March 31, 2009  December 31, 2008  March 31, 2008 
Current assets         
Cash and cash equivalents $21  $16  $20 
Receivables            
Gas, unbilled and other receivables  458   472   480 
Energy marketing receivables  326   549   624 
Less allowance for uncollectible accounts  (20)  (16)  (18)
Total receivables  764   1,005   1,086 
Inventory, net (Note 1)  348   663   356 
Derivative financial instruments – current portion (Note 2 and Note 3)  202   207   56 
Unrecovered pipeline replacement program costs – current portion (Note 1)  42   41   35 
Unrecovered environmental remediation costs – current portion (Note 1)  16   18   21 
Other current assets  38   92   52 
Total current assets  1,431   2,042   1,626 
Long-term assets and other deferred debits            
Property, plant and equipment  5,592   5,500   5,222 
Less accumulated depreciation  1,706   1,684   1,612 
Property, plant and equipment-net  3,886   3,816   3,610 
Goodwill  418   418   420 
Unrecovered pipeline replacement program costs (Note 1)  177   196   236 
Unrecovered environmental remediation costs (Note 1)  121   125   130 
Derivative financial instruments (Note 2 and Note 3)  48   38   11 
Other  76   75   73 
Total long-term assets and other deferred debits  4,726   4,668   4,480 
Total assets $6,157  $6,710  $6,106 
Current liabilities            
Short-term debt (Note 6) $403  $866  $369 
Energy marketing trade payables  342   539   711 
Accounts payable - trade  193   202   166 
Accrued expenses  151   113   125 
Customer deposits  58   50   34 
Derivative financial instruments – current portion (Note 2 and Note 3)  43   50   37 
Accrued pipeline replacement program costs – current portion (Note 1)  43   49   55 
Deferred natural gas costs  33   25   38 
Accrued environmental remediation liabilities – current portion (Note 1)  20   17   13 
Other current liabilities  62   72   58 
Total current liabilities  1,348   1,983   1,606 
Long-term liabilities and other deferred credits            
Long-term debt (Note 6)  1,675   1,675   1,516 
Accumulated deferred income taxes  586   571   570 
Accumulated removal costs  194   178   173 
Accrued pension obligations (Note 4)  188   199   43 
Accrued pipeline replacement program costs (Note 1)  126   140   176 
Accrued environmental remediation liabilities (Note 1)  85   89   92 
Accrued postretirement benefit costs (Note 4)  45   46   22 
Derivative financial instruments (Note 2 and Note 3)  8   6   5 
Other long-term liabilities and other deferred credits  139   139   149 
Total long-term liabilities and other deferred credits  3,046   3,043   2,746 
Commitments and contingencies (Note 7)            
Equity (Note 5)            
AGL Resources Inc. common shareholders’ equity, $5 par value; 750,000,000 shares authorized  1,734   1,652   1,722 
Noncontrolling interest  29   32   32 
Total equity  1,763   1,684   1,754 
Total liabilities and equity $6,157  $6,710  $6,106 
 
See Notes to Condensed Consolidated Financial Statements (Unaudited).
     

Glossary of Key Terms
4

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

     Three months ended    Nine months ended  
     September 30,    September 30,  
In millions, except per share amounts   2008   2007  2008    2007  
Operating revenues $539  $369  $1,995  $1,809 
Operating expenses                 
Cost of gas  261   159   1,193   987 
Operation and maintenance  104   107   337   334 
Depreciation and amortization  38   37   112   108 
Taxes other than income taxes  10   11   33   31 
Total operating expenses  413   314   1,675   1,460 
Operating income  126   55   320   349 
Other income  2   -   6   1 
Minority interest  5   -   (12)  (24)
Interest expense, net  (29)  (34)  (85)  (92)
Earnings before income taxes  104   21   229   234 
Income tax expense  39   8   86   89 
Net income $65  $13  $143  $145 
Per common share data                 
Basic earnings per common share $0.85  $0.17  $1.87  $1.88 
Diluted earnings per common share $0.85  $0.17  $1.87  $1.87 
Cash dividends declared per common share $0.42  $0.41  $1.26  $1.23 
Weighted-average number of common shares outstanding                 
Basic  76.4   77.0   76.2   77.4 
Diluted  76.6   77.4   76.5   77.8 

See notes to Condensed Consolidated Financial Statements (Unaudited).

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AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITYINCOME
(UNAUDITED)

              Other  Shares held    
  Common stock  Premium on  Earnings  comprehensive  in treasury    
In millions, except per share amount Shares  Amount  common stock  reinvested  loss  and trust  Total 
Balance as of December 31, 2007  76.4  $390  $667  $680  $(13) $(63) $1,661 
Comprehensive income:                            
Net income  -   -   -   143   -   -   143 
Net realized gains from hedging activities (net of tax of $-)  -   -   -   -   (1)  -   (1)
Total comprehensive income                          142 
Dividends on common stock ($1.26 per share)  -   -   -   (96)  -   3   (93)
Issuance of treasury shares  0.4   -   (1)  (4)  -   12   7 
Stock-based compensation expense (net of tax of $1)  -   -   7   -   -   -   7 
Balance as of September 30, 2008  76.8  $390  $673  $723  $(14) $(48) $1,724 

See Notes to Condensed Consolidated Financial Statements (Unaudited).




Glossary of Terms
6
AGL RESOURCES INC. AND SUBSIDIARIES                            
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)            

       
  Nine months ended 
  September 30, 
In millions 2008  2007 
Cash flows from operating activities      
Net income $143  $145 
Adjustments to reconcile net income to net cash flow provided by operating activities        
Depreciation and amortization  112   108 
Change in energy marketing and risk management assets and liabilities  (86)  27 
Minority interest  12   24 
Deferred income taxes  66   8 
Changes in certain assets and liabilities        
Gas, unbilled and other receivables  202   232 
Energy marketing receivables and energy marketing trade payables, net  53   15 
Inventories  (260)  (57)
Gas and trade payables  9   (82)
Other – net  (79)  (34)
Net cash flow provided by operating activities  172   386 
Cash flows from investing activities        
Property, plant and equipment expenditures  (254)  (193)
Other  -   2 
Net cash flow used in investing activities  (254)  (191)
Cash flows from financing activities        
Net payments and borrowings of short-term debt  189   49 
Issuance of variable rate gas facility revenue bonds  161   - 
Payments of long-term debt  (161)  (86)
Dividends paid on common shares  (93)  (92)
Distribution to minority interest  (30)  (23)
Issuance of treasury shares  7   13 
Purchase of treasury shares  -   (57)
Other  1   (2)
Net cash flow provided by (used in) financing activities  74   (198)
Net decrease in cash and cash equivalents  (8)  (3)
Cash and cash equivalents at beginning of period  19   17 
Cash and cash equivalents at end of period $11  $14 
Cash paid during the period for        
Interest $88  $92 
Income taxes $27  $89 
  Three months ended March 31,
In millions, except per share amounts 2009  2008 
Operating revenues $995  $1,012 
Operating expenses        
Cost of gas  589   657 
Operation and maintenance  125   119 
Depreciation and amortization  39   36 
Taxes other than income taxes  12   12 
Total operating expenses  765   824 
Operating income  230   188 
Other income  2   1 
Interest expense, net  (25)  (30)
Earnings before income taxes  207   159 
Income tax expense  72   54 
Net income  135   105 
Less net income attributable to the noncontrolling interest (Note 5)  16   16 
Net income attributable to AGL Resources Inc. $119  $89 
Per common share data (Note 1)        
Basic earnings per common share attributable to AGL Resources Inc. common shareholders $1.55  $1.17 
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders $1.55  $1.16 
Cash dividends declared per common share $0.43  $0.42 
Weighted average number of common shares outstanding (Note 1)        
Basic  76.7   76.0 
Diluted  76.8   76.3 

See Notes to Condensed Consolidated Financial Statements (Unaudited).

Glossary of Key Terms
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AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
(UNAUDITED)

  AGL Resources Inc. Shareholders       
  Common stock  Premium on common  Earnings  Accumulated other comprehensive  Shares held in treasury and  Noncontrolling    
In millions, except per share amount Shares  Amount  stock  reinvested  loss  trust  interest  Total 
Balance as of December 31, 2008  76.9  $390  $676  $763  $(134) $(43) $32  $1,684 
Net income  -   -   -   119   -   -   16   135 
Other comprehensive loss  -   -   -   -   (7)  -   (4)  (11)
Dividends on common stock ($0.43 per share)  -   -   -   (33)  -   1   -   (32)
Distributions to noncontrolling interest  -   -   -   -   -   -   (15)  (15)
Issuance of treasury shares  0.3   -   (6)  (2)  -   9   -   1 
Stock-based compensation expense (net of taxes) (Note 5)  -   -   1   -   -   -   -   1 
Balance as of March 31, 2009  77.2  $390  $671  $847  $(141) $(33) $29  $1,763 

See Notes to Condensed Consolidated Financial Statements (Unaudited).


Glossary of Key Terms
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AGL RESOURCES INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)

    
Components of other comprehensive loss
(net of taxes)
    
    Cash flow hedges    
In millions Net income Derivative financial instruments unrealized (losses) gains arising during the period  Reclassification of derivative financial instruments realized losses (gains) included in net income  Other comprehensive loss  Comprehensive income (Note 5)
Three months ended March 31, 2009:
             
AGL Resources $119 $(9) $2  $(7) $112 
Noncontrolling interest  16  (5)  1   (4)  12 
Consolidated $135 $(14) $3  $(11) $124 
                    
Three months ended March 31, 2008:
                   
AGL Resources $89 $2  $(4) $(2) $87 
Noncontrolling interest  16  1   (2)  (1)  15 
Consolidated $105 $3  $(6) $(3) $102 

See Notes to Condensed Consolidated Financial Statements (Unaudited).

Glossary of Key Terms
7
Table of Contents

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

       
  Three months ended 
  March 31, 
In millions 2009  2008 
Cash flows from operating activities      
Net income $135  $105 
Adjustments to reconcile net income to net cash flow provided by operating activities        
Depreciation and amortization  39   36 
Change in derivative financial instrument assets and liabilities  (10)  36 
Deferred income taxes  (10)  (18)
Changes in certain assets and liabilities        
Inventories  315   195 
Accrued expenses  38   38 
Energy marketing receivables and energy marketing trade payables, net  26   107 
Gas, unbilled and other receivables  18   (71)
Gas and trade payables  (9)  (6)
Other – net  69   89 
Net cash flow provided by operating activities  611   511 
Cash flows from investing activities        
Payments to acquire, property, plant and equipment  (97)  (80)
Net cash flow used in investing activities  (97)  (80)
Cash flows from financing activities        
Net payments and borrowings of short-term debt  (463)  (324)
Dividends paid on common shares  (32)  (31)
Distribution to noncontrolling interest  (15)  (30)
Payments of long-term debt  -   (47)
Issuance of treasury shares  1   2 
Net cash flow used in financing activities  (509)  (430)
Net increase in cash and cash equivalents  5   1 
Cash and cash equivalents at beginning of period  16   19 
Cash and cash equivalents at end of period $21  $20 
Cash paid during the period for        
Interest $29  $34 
Income taxes $16  $2 

See Notes to Condensed Consolidated Financial Statements (Unaudited).


8

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

Note 1 - Accounting Policies and Methods of Application

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,” or “the company” mean consolidated AGL Resources Inc. and its subsidiaries (AGL Resources).

The year-end condensed balance sheetstatement 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 of the SEC. Under such rules and regulations, we have condensed or omitted certain information and notes normally included in financial statements prepared in conformity with GAAP. However, the 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. For a glossary of key terms and referenced accounting standards, see page 3. You should read these condensed consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our Annual Report on Form 10-K for the year ended December 31, 2007,2008, filed with the SEC on February 7, 2008.5, 2009.

Due to the seasonal nature of our business, our results of operations for the three and nine months ended September 30,March 31, 2009 and 2008, and 2007, and our financial condition as of December 31, 2007, and September 30, 2008, and 2007,March 31, 2009 and 2008, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.

Basis of Presentation

Our condensed consolidated financial statements include our accounts, the accounts of our majority-owned and controlled subsidiaries and the accounts of variable interest entities for which we are the primary beneficiary. This means that our accounts are combined with our subsidiaries’ accounts. We have eliminated any intercompany profits and transactions in consolidation; however, we have not eliminated intercompany profits when such amounts are probable of recovery under the affiliates’ rate regulation process. Certain amounts from prior periods have been reclassified and revised to conform to the current period presentation.

We currently own a noncontrolling 70% financial interest in SouthStar and Piedmont owns the remaining 30%. Our 70% interest is noncontrolling because all significant management decisions require approval by both owners. We record the earnings allocated to Piedmont as a minority interest in our condensed consolidated statements of income and we record Piedmont’s portion of SouthStar’s capital as a minority interest in our condensed consolidated balance sheets.

We are the primary beneficiary of SouthStar’s activities and have determined that SouthStar is a variable interest entity as defined by FIN 46, which was revised in December 2003, FIN 46R. We determined that SouthStar is a variable interest entity because our equal voting rights with Piedmont are not proportional to our contractual obligation to absorb 75% of any losses or residual returns from SouthStar, except those losses and returns related to customers in Ohio and Florida. Earnings related to SouthStar’s customers in Ohio and Florida are allocated 70% to us and 30% to Piedmont. In addition, SouthStar obtains substantially all its transportation capacity for delivery of natural gas through our wholly owned subsidiary, Atlanta Gas Light.

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 of contingent assets and liabilities. We based our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, and we evaluate our estimates on an ongoing basis. Each of our estimates involves complex situations requiring a high degree of judgment either in the application and interpretation of existing financial accounting literature or in the development of estimates that impact our financial statements. The most significant estimates include our PRP accruals, environmental liability accruals, allowance for uncollectible accounts and other allowance for contingencies, pension and postretirement obligations, derivative and hedging activities, unbilled revenues and provision for income taxes. Our actual results could differ from our estimates, and such differences could be material.

Energy Marketing Receivables and Payables

Our wholesale services segment provides services to retail marketers and utility and industrial customers. These customers, also known as counterparties, utilize netting agreements, which enable wholesale services 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. The amounts due from or owed to wholesale services’ counterparties are netted and recorded on our condensed consolidated statements of financial position as energy marketing receivables and energy marketing payables.

Wholesale services has some 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, wholesale services would need to post collateral to continue transacting business with some of its counterparties. Posting collateral would have a negative effect on our liquidity. If such collateral were not posted, wholesale services ability to continue transacting business with these counterparties would be impaired.

Inventories

For our distribution operations segment, we record natural gas stored underground at WACOG. For Sequent and SouthStar, we account for natural gas inventory at the lower of WACOG or market price.

Sequent and SouthStar evaluate the 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 price. SouthStar recorded LOCOM adjustments of $18$6 million in the three and nine months ended September 30, 2008March 31, 2009 and did not record LOCOM adjustments in 2007.the three months ended March 31, 2008. Sequent recorded LOCOM adjustments of $34$8 million in the three and nine months ended September 30, 2008March 31, 2009 and $1 million and $4 milliondid not record LOCOM adjustments for the three and nine months ended September 30, 2007, respectively.March 31, 2008.

Glossary of Key Terms
89
Table of Contents
Stock-Based Compensation
Regulatory Assets and Liabilities

InWe have recorded regulatory assets and liabilities in our condensed consolidated statements of financial position in accordance with SFAS 71. Our regulatory assets and liabilities, and associated liabilities for our unrecovered PRP costs, unrecovered ERC and the first nine months of 2008, we issued grants of approximately 258,000 stock optionsassociated assets and 207,000 restricted stock units, which will resultliabilities for our Elizabethtown Gas derivative financial instruments, are summarized in the recognition of approximately $2 million of stock-based compensation expense in 2008. No material share awards have been granted to employees whose compensation is subject to capitalization. We use the Black-Scholes pricing model to determine the fair value of the options granted. On an annual basis, we evaluate the assumptions and estimates used to calculate our stock-based compensation expense.following table.
  Mar. 31  Dec. 31  Mar. 31
In millions 2009  2008  2008
Regulatory assets        
Unrecovered PRP costs $219  $237  $271 
Unrecovered ERC  137   143   151 
Unrecovered postretirement benefit costs  11   11   12 
Unrecovered seasonal rates  -   11   - 
Unrecovered natural gas costs  -   19   18 
Elizabethtown Gas derivative financial instruments  -   -   16 
Other  28   30   24 
Total regulatory assets  395   451   492 
Associated assets            
Elizabethtown Gas derivative financial instruments  29   23   - 
Total regulatory and associated assets $424  $474  $492 
Regulatory liabilities            
Accumulated removal costs $194  $178  $173 
Deferred natural gas costs  33   25   38 
Elizabethtown Gas derivative financial instruments  29   23   - 
Deferred seasonal rates  22   -   22 
Regulatory tax liability  18   19   20 
Unamortized investment tax credit  14   14   15 
Other  19   22   20 
  Total regulatory liabilities  329   281   288 
Associated liabilities            
PRP costs  169   189   231 
ERC  95   96   95 
Elizabethtown Gas derivative financial instruments  -   -   16 
Total associated liabilities  264   285   342 
Total regulatory and associated liabilities $593  $566  $630 

There have been no significant changes to our stock-based compensation,regulatory assets and liabilities as described in Note 41 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2007.2008.

Comprehensive Income Taxes

Our comprehensiveAs a result of our adoption of SFAS 160, income includestax expense and our effective tax rate are determined from earnings before income tax less net income plus OCI, which includes other gains and losses affecting shareholders’ equity that GAAP excludes from net income. Such items consist primarilyattributable to the noncontrolling interest. For more information on our adoption of gains and losses on certain derivatives designated as cash flow hedges and unfunded or over funded pension and postretirement obligations. The following table illustrates our OCI activity.SFAS 160, see Note 5.

  Three months ended September 30, 
In millions 2008  2007 
Cash flow hedges:      
Net derivative unrealized gains (losses) arising during the period (net of taxes of $- in 2008 and $1 in 2007)
 $(1) $2 
Less reclassification of realized losses included in income (net of taxes of $- in 2008 and $1 in 2007)
  1   1 
Total $-  $3 

  Nine months ended September 30, 
In millions 2008  2007 
Cash flow hedges:      
Net derivative unrealized gains arising during the period (net of taxes of $2 in 2008 and $1 in 2007)
 $3  $2 
Less reclassification of realized gains included in income (net of taxes of $3 in 2008 and $3 in 2007)
  (4)  (5)
Pension adjustments (net of taxes of $- in 2007)
  -   1 
Total $(1) $(2)
There have been no significant changes to our income taxes as described in Note 8 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2008.

Earnings per Common Share

We compute basic earnings per common share by dividing our net income availableattributable to our common shareholders by the daily weighted-average number of common shares outstanding daily.outstanding. Diluted earnings per common share reflect the potential reduction in earnings per common share that could occur when potentially dilutive common shares are added to common shares outstanding.  We adopted FSP EITF 03-6-1 on January 1, 2009, which provides guidance on the computation of earnings per share when a company has unvested share awards outstanding that have the nonforfeitable right to receive dividends. The effects of this FSP were immaterial to our calculation of earnings per share.

We derive our potentially dilutive common shares by calculating the number of shares issuable under restricted stock, restricted stock units and stock options. The future issuance of shares underlying the restricted stock and restricted share units depends on the satisfaction of certain performance criteria. The future issuance of shares underlying the outstanding stock options depends upon whether the exercise prices of the stock options are less than the average market price of the common shares for the respective periods. The following table shows the calculation of our diluted shares, for the periods presented, assuming restricted stock and restricted stock units currently awarded under the plan ultimately vest and stock options currently exercisable at prices below the average market prices are exercised.

  Three months ended September 30, 
In millions 2008  2007 
Denominator for basic earnings per share (1)
  76.4   77.0 
Assumed exercise of restricted stock, restricted stock units and stock options  0.2   0.4 
Denominator for diluted earnings per share  76.6   77.4 
(1) Daily weighted-average shares outstanding.
 
  
Nine months ended
September 30,
 
In millions 2008  2007 
Denominator for basic earnings per share (1)
  76.2   77.4 
Assumed exercise of restricted stock, restricted stock units and stock options  0.3   0.4 
Denominator for diluted earnings per share  76.5   77.8 
(1) Daily weighted-average shares outstanding.
 
  Three months ended March 31, 
In millions 2009  2008 
Denominator for basic earnings per share (1)
  76.7   76.0 
Assumed exercise of restricted stock, restricted stock units and stock options  0.1   0.3 
Denominator for diluted earnings per share  76.8   76.3 
(1) Daily weighted-average shares outstanding.
 

10

The following table contains the weighted average shares attributable to outstanding stock options that were excluded from the computation of diluted earnings per share because their effect would have been anti-dilutive, as the exercise prices were greater than the average market price:

  September 30, 
In millions 2008  
2007 (1)
 
Three months ended  2.1   0.1 
Nine months ended  1.6   0.0 
(1)  0.0 values represent amounts less than 0.1 million.
  March 31, 
In millions 2009  2008 
Three months ended  2.2   1.6 

The increase in the number of 0.6 million shares thatwhich were excluded from the computation is theof diluted earnings per share and considered anti-dilutive was a result of a significant decline in the average market value of our common shares at September 30, 2008March 31, 2009 as compared to September 30, 2007.

9
Income Taxes

We adopted FIN 48 on January 1, 2007, and as of September 30, 2008, DecemberMarch 31, 2007 or September 30, 2007, we did not have a liability for unrecognized tax benefits.

We do not collect income taxes from our customers on behalf of governmental authorities. We do collect and remit state and local taxes and record these amounts within our condensed consolidated balance sheets. Therefore, EITF No. 06-3 does not apply to us.

There have been no significant changes to our income taxes as described in Note 8 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2007.

Regulatory Assets and Liabilities

We have recorded regulatory assets and liabilities in our condensed consolidated balance sheets in accordance with SFAS 71. Our regulatory assets and liabilities, and associated liabilities for our unrecovered PRP costs, unrecovered ERC and the associated assets and liabilities for our Elizabethtown Gas hedging program, are summarized in the following table.
  Sept. 30  Dec. 31  Sept. 30 
In millions 2008  2007  2007 
Regulatory assets         
Unrecovered PRP costs $242  $285  $288 
Unrecovered ERC  144   158   156 
Unrecovered postretirement benefit costs  11   12   12 
Unrecovered seasonal rates  10   11   10 
Unrecovered PGA  33   23   15 
Other  31   24   24 
Total regulatory assets  471   513   505 
Associated assets            
Elizabethtown Gas hedging program  15   4   9 
Total regulatory and associated assets $486  $517  $514 
Regulatory liabilities            
Accumulated removal costs $176  $169  $168 
Elizabethtown Gas hedging program  15   4   9 
Unamortized investment tax credit  15   16   16 
Deferred PGA  14   28   15 
Regulatory tax liability  19   20   21 
Other  21   19   18 
  Total regulatory liabilities  260   256   247 
Associated liabilities            
PRP costs  195   245   251 
ERC  95   96   90 
Total associated liabilities  290   341   341 
Total regulatory and associated liabilities $550  $597  $588 

There have been no significant changes to our regulatory assets and liabilities as described in Note 1 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2007.

Accounting Developments

Previously discussed

SFAS 160 In December 2007, the FASB issued SFAS 160, which is effective for fiscal years beginning after December 15, 2008. SFAS 160 will require us to present our minority interest, to be referred to as a noncontrolling interest, separately within the capitalization section of our consolidated balance sheets. We will adopt SFAS 160 on January 1, 2009.

SFAS 161 In March 2008, the FASB issued SFAS 161, which is effective for fiscal years beginning after November 15, 2008. SFAS 161 amends the disclosure requirements of SFAS 133 to provide an enhanced understanding of how and why derivative instruments are used, how they are accounted for and their effect on an entity’s financial condition, performance and cash flows. We will adopt SFAS 161 on January 1, 2009 which will require additional disclosures, but will not have a financial impact to our consolidated results of operations, cash flows or financial condition.

FSP EITF 03-6-1 The FASB issued this FSP in June 2008 and it is effective for fiscal years beginning after December 15, 2008. This FSP classifies unvested share-based payment grants containing nonforfeitable rights to dividends as participating securities that will be included in the computation of earnings per share. As of September 30, 2008, we had approximately 149,000 restricted shares with nonforfeitable dividend rights. We will adopt FSP EITF 03-6-1 on January 1, 2009.

Recently issued

FSP FAS 133-1 The FASB issued this FSP in September 2008 and it is effective for fiscal years beginning after November 15, 2008. This FSP requires more detailed disclosures about credit derivatives, including the potential adverse effects of changes in credit risk on the financial position, financial performance and cash flows of the sellers of the instruments. This FSP will have no financial impact to our consolidated results of operations, cash flows or financial condition. We will adopt FSP FAS 133-1 on January 1, 2009.

10
FSP FAS 157-3 The FASB issued this FSP in October 2008 and it is effective upon issuance including prior periods for which financial statements have not been issued. This FSP clarifies the application of SFAS 157 in an inactive market, including; how internal assumptions should be considered when measuring fair value, how observable market information in a market that is not active should be considered and how the use of market quotes should be used when assessing observable and unobservable data. We adopted this FSP as of September 30, 2008, which had no financial impact to our consolidated results of operations, cash flows or financial condition.

Note 2 – Financial Instruments and Risk Management- Fair Value Measurements

Netting of Cash Collateral and Derivative Assets and Liabilities under Master Netting Arrangements

We maintain accounts with brokers to facilitate financial derivative transactions in support of our energy marketing and risk management activities. Based on the value of our positions in these accounts and the associated margin requirements, we may be required to deposit cash into these broker accounts.

On January 1, 2008, we adopted FIN 39-1, which required that we offset cash collateral held in these broker accounts on our condensed consolidated balance sheets with the associated fair value of the instruments in the accounts. Prior to the adoption of FIN 39-1, we presented such cash collateral on a gross basis within other current assets and liabilities on our condensed consolidated balance sheets. Our cash collateral amounts are provided in the following table.

     As of    
In millions Sept. 30, 2008  Dec. 31, 2007  Sept. 30, 2007 
Right to reclaim cash collateral $53  $3  $18 
Obligations to return cash collateral  (1)  (10)  - 
Total cash collateral $52  $(7) $18 
Fair value measurements

In September 2006, the FASB issued SFAS 157, which establishes a framework for measuring fair value and requires expanded disclosures regarding fair value measurements. SFAS 157 does not require any new fair value measurements; however, it eliminates inconsistencies in the guidance provided in previous accounting pronouncements. The carrying value of cash and cash equivalents, receivables, accounts payable, short-term debt, other current liabilities, derivative financial instrument assets, derivative financial instrument liabilities and accrued interest approximate fair value. The following table shows the carrying amounts and fair values of our long-term debt including any current portions included in our condensed consolidated balance sheets.statements of financial position.

In millions Carrying amount  Estimated fair value 
As of September 30, 2008 $1,675  $1,671 
As of December 31, 2007  1,675   1,710 
As of September 30, 2007  1,548   1,556 
In millions Carrying amount  Estimated fair value 
As of March 31, 2009 $1,676  $1,633 
As of December 31, 2008  1,676   1,647 
As of March 31, 2008 (1)
  1,678   1,734 

(1)  Includes $161 million of gas facility revenue bonds which we repurchased with proceeds from our commercial paper program in March and April 2008.

We estimate the fair value of our long-term debt using a discounted cash flow technique that incorporates a market interest yield curve with adjustments for duration, optionality and risk profile. In determining the market interest yield curve, we considered our currently assigned ratings for unsecured debt of BBB+ by S&P, Baa1 by Moody’s and A- by Fitch.

SFAS 157 was effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. In December 2007, the FASB provided a one-year deferral of SFAS 157 for nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value on a recurring basis, at least annually. We adopted SFAS 157 on January 1, 2008, for our financial assets and liabilities, which primarily consist of derivatives we record in accordance with SFAS 133. The adoption of SFAS 157 primarily impacts our disclosures and did not have a material impact on our condensed consolidated results of operations, cash flows and financial condition. We will adoptadopted SFAS 157 for our nonfinancial assets and liabilities on January 1, 2009, and are currently evaluating thewhich had no impact to our condensed consolidated results of operations, cash flows and financial condition.

As defined in SFAS 157, 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 pricing 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 and endeavor 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 are able to classify fair value balances based on the observance of those inputs. SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1) and the lowest priority to unobservable inputs (level 3). The three levels of the fair value hierarchy defined by SFAS 157 are as follows:

Level 1

Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 items consist of financial instruments with exchange-traded derivatives.

11
Level 2

Pricing inputs are other than quoted prices in active markets included in level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial and commodity instruments that are valued using valuation methodologies. These methodologies are primarily industry-standard methodologies that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. We obtain market price data from multiple sources in order to value some of our Level 2 transactions and this data is representative of transactions that occurred in the market place. As we aggregate our disclosures by counterparty, the underlying transactions for a given counterparty may be a combination of exchange-traded derivatives and values based on other sources. Instruments in this category include shorter tenor exchange-traded and non-exchange-traded derivatives such as OTC forwards and options.

Level 3

Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. We do not have any material assets or liabilities classified as level 3.

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2008.March 31, 2009. As required by SFAS 157, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

  Recurring fair value measurements as of September 30, 2008 
                
In millions Quoted prices in active markets (Level 1)  
Significant other observable inputs
(Level 2)
  
Significant unobservable inputs
 (Level 3)
  Netting of cash collateral  Total carrying value 
Assets: (1)
               
Derivatives at wholesale services $27  $87  $-  $26  $140 
Derivatives at distribution operations  -   15   -   -   15 
Derivatives at retail energy operations (3)
  32   -   -   -   32 
Total assets $59  $102  $-  $26  $187 
Liabilities: (2)
                    
Derivatives at wholesale services $11  $20  $-  $(7) $24 
Derivatives at distribution operations  -   15   -   1   16 
Derivatives at retail energy operations  20   1   -   (20)  1 
Total liabilities $31  $36  $-  $(26) $41 
    (1)Includes $172 million of current assets and $16 million of long-term assets reflected within our condensed consolidated balance sheet.
(2)Includes $34 million of current liabilities and $7 million of long-term liabilities reflected within our condensed consolidated balance sheet.
(3)$1 million premium associated with weather derivatives has been excluded as they are based on intrinsic value, not fair value.
The determination of the fair values above incorporates various factors required under SFAS 157. These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of our nonperformance risk on our liabilities.

Derivatives at distribution operations relate to Elizabethtown Gas and are utilized in accordance with a directive from the New Jersey Commission to create a program to hedge the impact of market fluctuations in natural gas prices. These derivative products are accounted for at fair value each reporting period. In accordance with regulatory requirements, realized gains and losses related to these derivatives are reflected in purchased gas costs and ultimately included in billings to customers. Unrealized gains and losses are reflected as a regulatory asset or liability, as appropriate, in our condensed consolidated balance sheets.

Sequent’s and SouthStar’s derivatives includeOur exchange-traded and OTC derivative contracts. Exchange-traded derivative contracts, which include futures and exchange-traded options, are generally based on unadjusted quoted prices in active markets and are classified within level 1. Some exchange-traded derivatives are valued using broker or dealer quotation services, or market transactions in either the listed or OTC markets, which are classified within level 2.

AtThe determination of the beginningfair values in the following table incorporates various factors required under SFAS 157. These factors include not only the credit standing of 2008, we had a notional principal amount of $100 million of interest rate swap agreements associated with our senior notes. In March 2008, we terminated these interest rate swap agreements. We received a payment of $2 million, which included accrued interestthe counterparties involved and the fair valueimpact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the interest rate swap agreements at the termination date. The payment was recorded as deferred income and classified as a liability in our condensed consolidated balance sheets. The amount will be amortized through January 2011, the remaining life of the associated senior notes. The following table sets forth a reconciliation of the terminationeffect of our interest rate swaps, classified as level 3 in the fair value hierarchy.nonperformance risk on our liabilities. For more information on our derivative financial instruments, see Note 3.


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In millions
 Nine months ended September 30, 2008 
Balance as of January 1, 2008 $(2)
Realized and unrealized gains  - 
Settlements  2 
Transfers in or out of level 3  - 
Balance as of September 30, 2008 $- 
Change in unrealized gains (losses) relating to instruments held as of September 30, 2008 $- 
  
Recurring fair values
Commodity derivative financial instruments
 
  March 31, 2009  December 31, 2008  March 31, 2008 
In millions Assets  Liabilities  
Assets (1)
  Liabilities  Assets  Liabilities 
Quoted prices in active markets (Level 1) $39  $(198) $52  $(117) $28  $(34)
Significant other observable inputs (Level 2)  163   (19)  154   (28)  39   (44)
Netting of cash collateral
  48   166   35   89   -   36 
Total carrying value (2)
 $250  $(51) $241  $(56) $67  $(42)
(1) $4 million premium associated with weather derivatives has been excluded as they are based on intrinsic value, not fair value. For more information see Note 3.
(2) There were no significant unobservable inputs (level 3) for any of the periods presented.
 

Transfers in or out of levelNote 3 represent existing assets or liabilities that were either previously categorized as a higher level for which the methodology inputs became unobservable or assets and liabilities that were previously classified as level 3 for which the lowest significant input became observable during the period.- Derivative Financial Instruments

Risk ManagementNetting of Cash Collateral with Derivative Assets and Liabilities under Master Netting Arrangements

We maintain accounts with exchange brokers to facilitate financial derivative transactions in support of our energy marketing and risk management activities. Based on the value of our positions in these accounts and the associated margin requirements, we may be required to deposit cash into these broker accounts. We are required to offset this cash collateral with the associated fair value of the derivative financial instruments. Our cash collateral amounts are provided in the following table.


     As of    
In millions Mar. 31, 2009  Dec. 31, 2008  Mar. 31, 2008 
Right to reclaim cash collateral $214  $128  $37 
Obligations to return cash collateral  -   (4)  (1)
Total cash collateral $214  $124  $36 
Derivative Financial Instruments

Our risk management activities are monitored by our Risk Management Committee (RMC) which consists of members of senior management and our Finance and Risk Management Committee (FRMC) which consists of members from our Board of Directors. Both the RMC and FRMC are charged with reviewing and enforcing our risk management activities. Our risk management policies limit the use of derivative financial instruments and physical transactions withinis limited to predefined risk tolerances associated with pre-existing or anticipated physical natural gas sales and purchases and system use and storage. We use the following derivative financial instruments and physical transactions to manage commodity price, interest rate, weather, automobile fuel price and foreign currency risks:

·  forward contracts
·  futures contracts
·  options contracts
·  financial swaps
·  treasury locks
·  weather derivative contracts
·  storage and transportation capacity transactions
·  foreign currency forward contracts

Our derivative financial instruments do not contain any material credit-risk-related or other contingent features that could cause us to make accelerated payments over and above collateral we post in the normal course of business when our financial instruments are in net liability positions. For information on our energy marketing receivables and payables, which do have credit-risk-related or other contingent features refer to Note 1. Our risk management activities are monitored by our Risk Management Committee (RMC), which consists of members of senior management. The RMC is charged with reviewing and enforcing our risk management activities and policies.

We adopted SFAS 161 on January 1, 2009, which amends the disclosure requirements of SFAS 133 and requires specific disclosures regarding how and why we use derivative instruments; the accounting for derivative instruments and related hedged items; and how derivative instruments and related hedged items affect our financial position, results of operations and cash flows. As SFAS 161 only requires additional disclosures concerning derivatives and hedging activities, this standard did not have an impact on our financial position, results of operations or cash flows.

We adopted FSP FAS 133-1 on January 1, 2009. This FSP requires more detailed disclosures about credit derivatives, including the potential adverse effects of changes in credit risk on the financial position, financial performance and cash flows of the sellers of the instruments. This FSP had no financial impact to our results of operations, cash flows or financial condition.

Interest Rate Derivative Financial Instruments

To maintain an effective capital structure, our policy is to borrow funds using a mix of fixed-rate and variable-rate debt. We have previously entered into interest rate swap agreements for the purpose of managing the appropriate mix of risk associated with our fixed-rate and variable-rate debt obligations. We designated these interest rate swaps as fair value hedges in accordance with SFAS 133 and recorded the gain or loss on fair value hedges in earnings in the period of change, together with the offsetting loss or gain on the hedged item attributable to the interest rate risk being hedged. As of March 31, 2009, December 31, 2008 and March 31, 2008, we did not have any interest rate swap agreements.


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Commodity Derivative Financial Instruments

All activities associated with commodity price risk management activities and derivative instruments are included as a component of cash flows from operating activities in our condensed consolidated statements of cash flows. Our derivatives not designated as hedges under SFAS 133, are included within operating cash flows as a source (use) of cash totaling $(10) million in 2009 and $36 million in 2008.

Distribution Operations In accordance with a directive from the New Jersey Commission, Elizabethtown Gas enters into derivative financial instruments to hedge the impact of market fluctuations in natural gas prices. Pursuant to SFAS 133, such derivative transactions are accounted for at fair value each reporting period in our condensed consolidated statements of financial position. In accordance with regulatory requirements realized gains and losses related to these derivatives are reflected in natural gas costs and ultimately included in billings to customers. However, these derivative financial instruments are not designated as hedges in accordance with SFAS 133. For more information on our regulatory assets and liabilities see Note 1.

Retail Energy Operations SouthStar uses commodity-related derivative financial instruments (futures, options and swaps) to manage exposures arising from changing commodity prices. SouthStar’s objective for holding these derivatives is to utilize the most effective method to reduce or eliminate the impact of this exposure. We have designated a portion of SouthStar’s derivative transactions, consisting of financial swaps to manage the commodity risk associated with forecasted purchases and sales of natural gas, as cash flow hedges under SFAS 133. We record derivative gains or losses arising from cash flow hedges in OCI and reclassify them into earnings in the same period as the settlement of the underlying hedged item. SouthStar currently has minimal hedge ineffectiveness, defined as when the gains or losses on the hedging instrument do not offset and are greater than the losses or gains on the hedged item. This cash flow hedge ineffectiveness is recorded in cost of gas in our condensed consolidated statements of income in the period in which it occurs. We have not designated the remainder of SouthStar’s derivative instruments as hedges under SFAS 133 and, accordingly, we record changes in their fair value within cost of gas in our condensed consolidated statements of income in the period of change. For more information on SouthStar’s gains and losses reported within comprehensive income that affects equity, see our condensed consolidated statements of comprehensive income. SouthStar has hedged its exposures to commodity risk to varying degrees in the markets in which it serves retail, commercial and industrial customers. Approximately 80% of SouthStar’s purchase instruments and 56% of its sales instruments are scheduled to mature in 2009 and the remaining 20% and 44%, respectively, in less than 2 years.

SouthStar also enters into both exchange and OTC derivative transactions to hedge commodity price risk. Credit risk is mitigated for exchange transactions through the backing of the NYMEX member firms. For OTC transactions, SouthStar utilizes master netting arrangements to reduce overall credit risk. As of March 31, 2009, SouthStar’s maximum exposure to any single OTC counterparty was $6 million.

Wholesale Services Sequent uses derivative financial instruments to reduce our exposure to the risk of changes in the prices of natural gas. The fair value of these derivative financial instruments 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 the derivative financial instruments we use.

We mitigate substantially all the commodity price risk associated with Sequent’s natural gas portfolio by locking in the economic margin at the time we enter into natural gas purchase transactions for our stored natural gas. We purchase natural gas for storage when the difference in the current market price we pay to buy and transport natural gas plus the cost to store 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 contracts and other OTC derivatives to sell natural gas at that future price to substantially lock in the operating margin we will ultimately realize when the stored natural gas is actually sold. These futures contracts meet the definition of derivatives under SFAS 133 and are accounted for at fair value in our condensed consolidated statements of financial position, with changes in fair value recorded in our condensed consolidated statements of income in the period of change. However, these futures contracts are not designated as hedges in accordance with SFAS 133.

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 commodity price risk associated with our storage portfolio. This difference in accounting can result in volatility in our reported earnings, even though the economic margin is essentially unchanged from the date the transactions were consummated. Approximately 95% of Sequent’s purchase instruments and 96% of its sales instruments are scheduled to mature in less than 2 years and the remaining 5% and 4%, respectively, in 3 to 9 years.

The changes in fair value of Sequent’s derivative instruments utilized in its energy marketing and risk management activities and contract settlements decreased the net fair value of its contracts outstanding by $75 million during both the three months ended March 31, 2009 and the three months ended March 31, 2008.

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Weather Derivative Financial Instruments

In 2009 and 2008, SouthStar entered into weather derivative contracts as economic hedges of operating margins in the event of warmer-than-normal and colder-than-normal weather in the heating season, primarily from November through March. SouthStar accounts for these contracts using the intrinsic value method under the guidelines of EITF 99-02, and accordingly these derivative financial instruments are not designated as derivatives or hedges under SFAS 133. SouthStar recorded a net payable for this hedging activity of less than $1 million at March 31, 2009 and at March 31, 2008 and a current asset of $4 million at December 31, 2008. In the three months ended March 31, 2009 and 2008, SouthStar recognized $4 million and $5 million of losses on its weather derivative financial instruments, which were reflected in cost of gas on our condensed consolidated statements of income.

Quantitative Disclosures Related to Derivative Financial Instruments

As of March 31, 2009, our derivative financial instruments were comprised of both long and short commodity positions, whereby a long position is a contract to purchase the commodity, and a short position is a contract to sell the commodity. As of March 31, 2009, we had net long commodity contracts outstanding in the following quantities:

  Commodity contracts (in Bcf) 
Hedge designation under SFAS 133 Distribution operations  Retail energy operations  Wholesale services  Consolidated 
Cash flow  -   9   -   9 
Not designated  11   13   199   223 
Total  11   22   199   232 

Derivative Financial Instruments on the Condensed Consolidated Statements of Income

The following table presents the gain or (loss) on derivative financial instruments in our condensed consolidated statements of income for the three months ended March 31, 2009.

  
Three months ended
March 31, 2009
 
In millions Retail energy operations  Wholesale services 
       
Designated as cash flow hedges under SFAS 133      
Commodity contracts – loss reclassified from OCI into cost of gas for settlement of hedged item $(4) $- 
         
Not designated as hedges under SFAS 133:        
Commodity contracts – fair value adjustments recorded in operating revenues (1)  -   20 
Commodity contracts – fair value adjustments recorded in cost of gas (2)
  (1)  - 
Total (losses) gains on derivative financial instruments $(5) $20 

(1) Associated with the fair value of existing derivative financial instruments at March 31, 2009.
(2) Excludes $4 million of losses recorded in cost of gas associated with weather derivatives accounted for in accordance with EITF 99-02.

In accordance with regulatory requirements, any realized gains and losses on derivative financial instruments used in our distribution operations segment are reflected in deferred natural gas costs within our condensed consolidated statements of financial position. In the three months ended March 31, 2009, Elizabethtown Gas recognized $13 million of losses on its derivative financial instruments and less than $1 million in gains for the same period in 2008.

The following amounts (pre-tax) represent the expected recognition in our condensed consolidated statements of income of the deferred losses recorded in OCI associated with retail energy operations’ derivative financial instruments, based upon the fair values of these financial instruments as of March 31, 2009:

In millions Retail energy operations 
Designated as hedges under SFAS 133   
Commodity contracts – expected net loss reclassified from OCI into cost of gas for settlement of hedged item:   
Next twelve months $(27)
Thereafter  - 
Total $(27)

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Derivative Financial Instruments on the Statements of Financial Position

The following table presents the fair value and statements of financial position classification of our derivative financial instruments by operating segment as of March 31, 2009.
   As of March 31, 2009 
In millions
Statements of financial position location (1)
 Distribution operations  Retail energy operations  Wholesale services  
Consolidated (2)
 
              
Designated as cash flow hedges under SFAS 133:             
Asset Financial Instruments             
Current commodity contractsDerivative financial instruments assets and liabilities – current portion $-  $12  $-  $12 
Noncurrent commodity contractsDerivative financial instruments assets and liabilities  -   -       - 
Liability Financial Instruments                 
Current commodity contractsDerivative financial instruments assets and liabilities – current portion  -   (32)  -   (32)
Noncurrent commodity contractsDerivative financial instruments assets and liabilities  -   -   -   - 
Total   -   (20)  -   (20) 
                  
Not designated as hedges under SFAS 133:                 
Asset Financial Instruments                 
Current commodity contractsDerivative financial instruments assets and liabilities – current portion  23   3   520   546 
Noncurrent commodity contractsDerivative financial instruments assets and liabilities  6   -   85   91 
Liability Financial Instruments                 
Current commodity contractsDerivative financial instruments assets and liabilities – current portion  (23)  (5)  (535)  (563)
Noncurrent commodity contractsDerivative financial instruments assets and liabilities  (6)  -   (63)  (69)
Total   -   (2)  7   5 
Total derivative financial instruments  $-  $(22) $7  $(15)

(1)  These amounts are netted within our condensed consolidated statements of financial position. Some of our derivative financial instruments have asset positions which are presented as a liability in our condensed consolidated statements of financial position, and we have derivative instruments that have liability positions which are presented as an asset in our condensed consolidated statements of financial position.
(2)  
As required by SFAS 161, the fair value amounts above are presented on a gross basis. Additionally, the amounts above do not include $214 million of cash collateral held on deposit in broker margin accounts as of March 31, 2009. As a result, the amounts above will differ from the amounts presented on our condensed consolidated statements of financial position, and the fair value information presented for our financial instruments in Note 2.



15

Note 34 - Employee Benefit Plans

FSP FAS 132(R)-1

This FSP requires additional disclosures relating to postretirement benefit plan assets to provide transparency regarding the types of assets and the associated risks within the types of plan assets. The required disclosures include:

·  How investment allocation decisions are made, including information that provides an understanding of investment policies and strategies,
·  The major categories of plan assets,
·  Inputs and valuation techniques used to measure the fair value of plan assets, including those measurements using significant unobservable inputs, on changes in plan assets for the period, and
·  Significant concentrations of risk within plan assets.

This FSP is effective for fiscal years ending after December 15, 2009 and requires additional disclosures in our notes to condensed consolidated financial statements, but will not have a material impact on our financial position, results of operations or cash flows.

Pension Benefits

We sponsor two tax-qualified defined benefit retirement plans for our eligible employees, the AGL Resources Inc. Retirement Plan and the Employees’ Retirement Plan of NUI Corporation. A defined benefit plan specifies the amount of benefits an eligible participant eventually will receive using information about the participant. The followingFollowing are the combined cost components of our two defined benefit pension plans for the periods indicated:
  
Three months ended
September 30,
 
In millions 2008  2007 
Service cost $2  $2 
Interest cost  7   6 
Expected return on plan assets  (9)  (8)
Amortization of prior service cost  -   (1)
Recognized actuarial loss  -   2 
Net pension cost $-  $1 
indicated.

  
Nine months ended
September 30,
 
In millions 2008  2007 
Service cost $6  $6 
Interest cost  20   18 
Expected return on plan assets  (25)  (24)
Amortization of prior service cost  (1)  (2)
Recognized actuarial loss  2   5 
Net pension cost $2  $3 
  
Three months ended
March 31,
 
In millions 2009  2008 
Service cost $2  $2 
Interest cost  7   7 
Expected return on plan assets  (7)  (8)
Amortization of prior service cost  (1)  (1)
Recognized actuarial loss  2   1 
Net pension benefit cost $3  $1 

Our employees do not contribute to thethese retirement plans. We fund the plans by contributing at least the minimum amount required by applicable regulations and as recommended by our actuary. However, we may also contribute in excess of the minimum required amount. We calculate the minimum amount of funding using the projected unit credit cost method. The Pension Protection Act (the Act) of 2006 containscontained new funding requirements for single employer defined benefit pension plans. The Act establishes a 100% funding target for plan years beginning after December 31, 2007. However, a delayed effective date of 2011 may apply if the pension plan meets the following targets: 92% funded in 2008; 94% funded in 2009; and 96% funded in 2010. NoIn December 2008, the Worker, Retiree and Employer Recovery Act of 2008 allowed us to measure our 2008 and 2009 funding target at 92%. During the first three months of 2009, we made a $14 million contribution isto our qualified plans. We expect to make additional contributions to our pension plans of $18 million during the remainder of 2009. In 2008, we did not make a contribution, as one was not required for our qualified plans in 2008.pension plans.

Postretirement Benefits
The Health and Welfare Plan for Retirees and Inactive Employees of AGL Resources Inc. Postretirement Health Care Plan (AGL Postretirement Plan) covers all eligible AGL Resources employees who were employed as of September 30, 2002, if they reach retirement age while working for us. Eligibility for benefits under the AGL Postretirement Plan is based on age and years of service. The state regulatory commissions have approved phase-ins that defer a portion of other postretirement benefits expense for future recovery. Effective December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 was signed into law. This act provides for a prescription drug benefit under Medicare (Part D), as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D.
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Eligibility for benefits under Medicare-eligible participants in the AGL Postretirement Plan is based on agereceive prescription drug benefits through a Medicare Part D plan offered by a third party and yearsto which we subsidize participant premiums. Medicare-eligible retirees who opt out of service. the AGL Postretirement Plan are eligible to receive a cash subsidy which may be used towards eligible prescription drug expenses.

Following are the cost components of the AGL Postretirement Plan for the periods indicated.
 
  
Three months ended
September 30,
  
Nine months ended
September 30,
 
In millions 2008  2007  2008  2007 
Service cost $-  $-  $1  $- 
Interest cost  1   1   4   4 
Expected return on plan assets  (1)  (1)  (4)  (3)
Amortization of prior service cost  (1)  (1)  (3)  (3)
Recognized actuarial loss  -   1   -   1 
Net postretirement benefit cost $(1) $-  $(2) $(1)
  
Three months ended
March 31,
 
In millions 2009  2008 
Service cost $-  $- 
Interest cost  1   1 
Expected return on plan assets  (1)  (1)
Amortization of prior service cost  (1)  (1)
Recognized actuarial loss  1   - 
Net postretirement benefit cost $-  $(1)

Employee Savings Plan Benefits

We sponsor the Retirement Savings Plus Plan (RSP Plan), a defined contribution benefit plan that allows eligible participants to make contributions to their accounts up to specified limits. Under the RSP Plan, we made $5$2 million in matching contributions to participant accounts in the first ninethree months of 20082009 and $5$2 million in the same period last year.


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Note 45 - Common Shareholders’ Equity

Share Repurchase ProgramNoncontrolling Interests

We currently own a noncontrolling 70% financial interest in SouthStar, a joint venture with Piedmont who owns the remaining 30%. Our 70% interest is noncontrolling because all significant management decisions require approval by both owners. Although our ownership interest in the SouthStar partnership is 70%, under an amended and restated joint venture agreement executed in March 2004, SouthStar's earnings are allocated 75% to us and 25% to Piedmont except for earnings related to customers in Ohio and Florida, which are allocated 70% to us and 30% to Piedmont.

We are the primary beneficiary of SouthStar’s activities and have determined that SouthStar is a variable interest entity as defined by FIN 46R which requires us to consolidate the variable interest entity. The assets, liabilities, and noncontrolling interests of a consolidated variable interest entity are accounted for in our condensed consolidated financial statements as if the entity were consolidated based on voting interests.

The Company determined that SouthStar was a variable interest entity because its equal voting rights with Piedmont are not proportional to its economic obligation to absorb 75% of any losses or residual returns from SouthStar, except those losses and returns related to customers in Ohio and Florida. In addition, SouthStar obtains substantially all its transportation capacity for delivery of natural gas through our wholly-owned subsidiary, Atlanta Gas Light.

On January 1, 2009, we adopted SFAS 160, and applied the presentation and disclosure requirements retrospectively for all periods presented. SFAS 160 does not change the requirements of FIN 46R and provides that the noncontrolling interest should be reported as a separate component of equity on our condensed consolidated statements of financial position. Additionally, prior to adoption of SFAS 160, we recorded our earnings allocated to Piedmont as a component of earnings before income taxes in our condensed consolidated statements of income. SFAS 160 requires that any net income attributable to the noncontrolling interest be presented separately in our condensed consolidated statements of income. As a result, net income from noncontrolling interest is reported after net income in order to report net income attributable to the parent and the noncontrolling interest. The adoption of SFAS 160 has no effect on our calculation of basic or diluted earnings per share amounts, which will continue to be based upon amounts attributable to AGL Resources.

The March 2001, our Board2004 amended and restated joint venture agreement includes a series of Directors approvedoptions granting us the evergreen opportunity to purchase all or a portion of Piedmont’s ownership interest in SouthStar. We have the right to exercise an option to purchase on or before November of each year, with the purchase being effective as of upJanuary 1, of the following year. We currently have two vested options to 600,000 sharespurchase a portion of Piedmont’s ownership interest (33 1/3% and 50%, respectively). Effective January 1, 2010, our common stock to be used for issuances under the Officer Incentive Plan. In the first nine months of 2008, we purchased 10,333 shares under this plan. As of September 30, 2008, we had purchased a total 307,567 shares, leaving 292,433 shares available for purchase.

In February 2006, our Board of Directors authorized a planoption vests to purchase up to 8 million shares100% of Piedmont’s ownership interest. If we were to exercise any option to purchase less than 100% of Piedmont’s ownership interest in SouthStar, Piedmont, at its discretion, could require us to purchase their entire ownership interest. The purchase price, in any exercise of our outstanding common stock over a five-year period. These purchasesoption, would be based on the then current fair market value of SouthStar. SFAS 160 requires that increases in our ownership interest are intendedrecorded as equity transactions, with no adjustment to offset share issuances underthe carrying amounts of the assets and liabilities. Piedmont has challenged our employee and non-employee director incentive compensation plans and our dividend reinvestment and stock purchase plans. Stock purchases under this program may be madeinterpretation of the duration of the various options in the open market oramended and restated agreement as described in private transactions at times and in amounts that we deem appropriate. There is no guarantee as to the exact number of shares that we will purchase, and we can terminate or limit the program at any time. We will hold the purchased shares as treasury shares. We did not purchase shares under this program duringNote 7.

Stock-Based Compensation

In the first ninethree months of 2008. As2009, we issued grants of September 30, 2008,approximately 250,000 stock options and 211,000 restricted stock units, which will result in the recognition of approximately $2 million of stock-based compensation expense in 2009. No material share awards have been granted to employees whose compensation is subject to capitalization. We use the Black-Scholes pricing model to determine the fair value of the options granted. On an annual basis, we had repurchased 3,049,049 shares at a weighted average priceevaluate the assumptions and estimates used to calculate our stock-based compensation expense.

There have been no significant changes to our stock-based compensation, as described in Note 4 to our Consolidated Financial Statements in Item 8 of $38.58.our Annual Report on Form 10-K for the year ended December 31, 2008.

Comprehensive Income

Our comprehensive income includes net income plus OCI, which includes other gains and losses affecting equity that GAAP excludes from net income. Such items consist primarily of gains and losses on certain derivatives designated as cash flow hedges and unfunded or overfunded pension and postretirement obligation adjustments.


Glossary of Key Terms
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Table of Contents

Note 56 - Debt

Our issuance of various securities, including long-term and short-term debt, is subject to customary approval or authorization by, or filings with, state and federal regulatory bodies, including state public service commissions, the SEC and the FERC as granted bypursuant to the Energy Policy Act of 2005. The following table provides more information on our various debt securities. For more information on our debt, see Note 6 in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2008.

        Weighted  Outstanding as of 
In millions 
Year(s) due (1)
  
Interest rate (1)
  
average interest rate(2)
  
Sept. 30,
2008
  
Dec. 31,
2007
  
Sept.30,
2007
 
Short-term debt                  
Credit Facility 2008   3.5%  3.5% $485  $-  $- 
Commercial paper 2008   4.6   3.5   198   566   549 
SouthStar line of credit 2008   3.5   3.5   55   -   - 
Sequent lines of credit 2008   2.8   2.7   20   1   13 
Pivotal Utility line of credit 2008   1.6   2.9   10   12   13 
Capital leases 2008   4.9   4.9   1   1   1 
Total short-term debt     3.7%  3.4% $769  $580  $576 
Long-term debt - net of current portion                       
Senior notes  2011-2034   4.5-7.1%  5.9% $1,275  $1,275  $1,150 
Gas facility revenue bonds  2022-2033   4.2-8.1   3.5   200   200   200 
Medium-term notes  2012-2027   6.6-9.1   7.8   196   196   196 
Capital leases 2013   4.9   4.9   4   6   5 
Interest rate swaps  -   -   -   -   (2)  (3)
Total long-term debt      6.0%  5.8% $1,675  $1,675  $1,548 
                         
Total debt      5.3%  5.4% $2,444  $2,255  $2,124 
        Weighted�� Outstanding as of 
In millions Year(s) due  
Interest rate (1)
  
average interest rate(2)
  
Mar. 31,
2009
  
Dec. 31,
2008
  
Mar.31,
2008
 
Short-term debt                       
Commercial paper & Credit Facilities 2009   0.9%  1.2% $335  $773  $213 
SouthStar line of credit 2009   1.1   1.1   45   75   - 
Sequent lines of credit 2009   0.9   0.9   22   17   31 
Pivotal Utility line of credit  -   -   -   -   -   10 
Current portion of long-term debt  -   -   -   -   -   114 
Capital leases 2009   4.9   4.9   1   1   1 
Total short-term debt      1.0%  1.1% $403  $866  $369 
Long-term debt - net of current portion                        
Senior notes  2011-2034   4.5-7.1%  5.9% $1,275  $1,275  $1,275 
Gas facility revenue bonds  2022-2033   0.2-5.3   1.3   200   200   40 
Medium-term notes  2012-2027   6.6-9.1   7.8   196   196   196 
Capital leases 2013   4.9   4.9   4   4   5 
Total long-term debt      5.5%  5.5% $1,675  $1,675  $1,516 
                         
Total debt      4.6%  4.3% $2,078  $2,541  $1,885 
(1)  As of September 30, 2008March 31, 2009
(2)  For the ninethree months ended September 30, 2008March 31, 2009.

Credit Facility

In September 2008, we completed a $140 million Credit Facility that expires in September 2009, which will provide additional liquidity for working capital and capital expenditure needs. This Credit Facility provides us the option to request an increase in the borrowing capacity to $150 million and supplements our existing $1.0 billion Credit Facility which expires in August 2011.

Gas Facility Revenue Bonds

In 2008, a portion of our gas facility revenue bonds failed to draw enough potential buyers due to the dislocation or disruption in the auction markets as a result of the downgrades to the bond insurers that provide credit protections for these instruments which reduced investor demand and liquidity for these types of investments. In March and April 2008, we tendered these bonds with a cumulative principal amount of $161 million through commercial paper borrowings.

In June and September 2008, we completed a Letter of Credit Agreement for these bonds which provided additional credit support which increased investor demand for the bonds. As a result, these bonds with a cumulative principal amount of $161 million were successfully auctioned and issued as variable rate gas facility bonds and reduced our commercial paper borrowings. The bonds with principal amounts of $55 million, $47 million and $39 million now have interest rates that reset daily and the bond with a principal amount of $20 million has an interest rate that resets weekly. There was no change to the maturity dates on these bonds.

SouthStar Credit Facility

SouthStar’s five-year $75 million unsecured credit facility expires in November 2011. SouthStar will use this line of credit for working capital and its general corporate needs. We do not guarantee or provide any other form of security for the repayment of this credit facility.

Sequent Lines of Credit

In June 2008, we extended one of Sequent’s lines of credit in the amount of $25 million to June 2009. This line of credit  bears interest at the federal funds effective rate plus 0.75%. In September 2008, Sequent obtained a second line of credit for $20 million that bears interest at the LIBOR Rate plus 1.0% to September 2009. This line of credit replaced the line of credit that expired in August 2008. Both lines of credit are used for the posting of margin deposits for NYMEX transactions and are unconditionally guaranteed by us.

15

Note 67 - Commitments and Contingencies

Contractual Obligations and Commitments

We have incurred various contractual obligations and financial commitments in the normal course of our operating and financing activities.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. As we do for other subsidiaries, we provide guarantees to certain gas suppliers for SouthStar in support of payment obligations. There were no significant changes to our contractual obligations described in Note 7 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2007.2008.

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. The following table illustrates our contingent financial commitments as of September 30, 2008.March 31, 2009.

  
Commitments due before
Dec. 31,
 
In millions Total  2008  2009 & thereafter 
Standby letters of credit and performance and surety bonds $48  $8  $40 
  
Commitments due before
Dec. 31,
 
In millions Total  2009  2010 & thereafter 
Standby letters of credit and performance and surety bonds $51  $45  $6 

Litigation

We are involved in litigation arising in the normal course of business. The ultimate resolution of such litigation will not have a material adverse effect on our condensed consolidated financial condition,position, results of operations or cash flows.

In March 2008, Jefferson Island served discovery requests
Information on the State of Louisiana and sought a trial date in its pending lawsuit over its natural gas storage expansion project at Lake Peigneur. Jefferson Island also asserted additional claims against the State seeking to obtain a declaratory ruling that Jefferson Island’s surface lease, under which it operates its existing two storage caverns, authorizes the creation of the two new expansion caverns separate and apart from the mineral lease challenged by the State. Jefferson Island originally filed the suit against the State in the 19th Judicial District Court in Baton Rouge in September 2006.

In addition, in June 2008, the State of Louisiana passed legislation restricting water usage from the Chicot aquifer, which is a main source of fresh water required for the expansion of our Jefferson Island capacity. We contend that this legislation is unconstitutional and have sought to amend the pending litigation to seek a declaration that the legislation is invalid and cannot be enforced. Even if we are not successful on those grounds, we believe the legislation does not materially impact the feasibility of the expansion project.

Additional information in the Jefferson Island Storage & Hub, LLC vs. State of Louisiana litigation is described in Note 7 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2007.2008. In April 2009, the trial court ruled that the legislation that restricted Jefferson Island's ability to use water from the Chicot aquifer to expand its existing storage facility is unconstitutional and invalid. In addition, the court scheduled a trial in September 2009 on Jefferson Island's claim that it is authorized to expand the facility under its mineral lease. The ultimate resolution of such litigation cannot be determined, but it is not expected to have a material adverse effect on our condensed consolidated financial condition,position, results of operations or cash flows.
In March 2009, Piedmont filed a lawsuit in the Court of Chancery of the State of Delaware against GNGC, asking the court to enter a judgment declaring that GNGC’s right to purchase Piedmont’s ownership interest in SouthStar expires on November 1, 2009. We believe that, under the March 2004 amended and restated joint venture agreement, GNGC has the evergreen opportunity, throughout the term of the joint venture, to exercise its options to purchase a portion of, or all of, Piedmont’s interest in SouthStar by notifying Piedmont on or before November 1, of each year, with the purchase being effective as of January 1 of the following year. The ultimate resolution of this litigation cannot be determined, but we believe that the dispute will be resolved before our next option exercise notification date on November 1, 2009.

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In February 2008, the consumer affairs staff of the Georgia Commission alleged that GNG charged its customers on variable rate plans prices for natural gas that were in excess of the published price, that it failed to give proper notice regarding the availability of potentially lower price plans and that it changed its methodology for computing variable rates. GNG asserted that it fully complied with all applicable rules and regulations, that it properly charged its customers on variable rate plans the rates on file with the Georgia Commission, and that, consistent with its terms and conditions of service, it routinely switched customers who requested to move to another price plan for which they qualified. In order to resolve this matter GNG agreed to pay $2.5 million in the form of credits to customers, or as directed by the Georgia Commission, which was recorded in our condensed consolidated statements of consolidated income for the nine monthsyear ended September 30,December 31, 2008.

In February 2008, a class action lawsuit was filed in the Superior Court of Fulton County in the State of Georgia against GNG containing similar allegations to those asserted by the Georgia Commission staff and seeking damages on behalf of a class of GNG customers. This lawsuit was dismissed in September 2008. In October 2008, the plaintiffs appealed the dismissal of the lawsuit and the Georgia Court of Appeals heard oral arguments in 2009. GNG is awaiting the Georgia Court of Appeal’s ruling on the lawsuit.

In March 2008, a second class action suit was filed against GNG in the State Court of Fulton County in the State of Georgia, regarding monthly service charges. This lawsuit alleges that GNG arbitrarily assigned customer service charges rather than basing each customer service charge on a specific credit score. GNG asserts that no violation of law or Georgia Commission rules has occurred, that this lawsuit is without merit and has filed motions to dismiss this class action suit on various grounds. The ultimate resolutionThis lawsuit was dismissed with prejudice in March 2009. In April 2009, plaintiffs appealed the dismissal of this lawsuit cannot be determined, but is not expected to have a material adverse effect on our condensed consolidated results of operations, cash flows or financial condition.the lawsuit.


16

Review of Compliance with FERC Regulations

We recentlyIn 2008 we conducted an internal review of our compliance with FERC interstate natural gas pipeline capacity release rules and regulations. Independent of our internal review, we also received data requests from FERC’s Office of Enforcement relating specifically to compliance with FERC’s capacity release posting and bidding requirements. We have responded to FERC’s data requests and are fully cooperating with FERC in its investigation. As a result of this process, we have identified certain instances of possible non-compliance. We are committed to full regulatory compliance and we have met and continue to meet with the FERC Enforcement staff to discuss with them these instances of possible non-compliance. AtAccordingly we have accrued an appropriate estimate of possible penalties assessed by the FERC. While we continue to adjust this time we are unableestimate as more information becomes available, the estimate does not have, and management does not believe the ultimate resolution will have, a material financial impact to predict the outcomeour condensed consolidated results of the FERC investigation.operations, cash flows or financial position.
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Note 78 - Segment Information

We are an energy services holding company whose principal business is the distribution of natural gas in six states - Florida, Georgia, Maryland, New Jersey, Tennessee and Virginia. We generate nearly all our operating revenues through the sale, distribution, transportation and storage of natural gas. We are involved in several related and complementary businesses, including retail natural gas marketing to end-use customers primarily in Georgia; natural gas asset management and related logistics activities for each of our utilities as well as for nonaffiliated companies; natural gas storage arbitrage and related activities; and the development and operation of high-deliverability natural gas storage assets. We manage these businesses through four operating segments – distribution operations, retail energy operations, wholesale services and energy investments and a nonoperating corporate segment which includes intercompany eliminations.

We evaluate segment performance based primarily on the non-GAAP measure of EBIT, which includes the effects of corporate expense allocations. EBIT is a non-GAAP measure that includes operating income and other income and expenses and minority interest.expenses. Items 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 level. 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 attributable to AGL Resources Inc. as determined in accordance with GAAP. In addition, our EBIT may not be comparable to a similarly titled measure of another company. The following table contains the reconciliations of EBIT to operating income, earnings before income taxes and net income attributable to AGL Resources Inc. for the three and nine months ended September 30, 2008March 31, 2009 and 2007.2008.

  
Three months ended
September 30,
 
In millions 2008  2007 
Operating revenues $539  $369 
Operating expenses  413   314 
Operating income  126   55 
Minority interest  5   - 
Other income  2   - 
EBIT  133   55 
Interest expense, net  (29)  (34)
Earnings before income taxes  104   21 
Income tax expense  39   8 
Net income $65  $13 
  
Three months ended
March 31,
 
In millions 2009  2008 
Operating revenues $995  $1,012 
Operating expenses  765   824 
Operating income  230   188 
Other income  2   1 
EBIT  232   189 
Interest expense, net  (25)  (30)
Earnings before income taxes  207   159 
Income tax expense  72   54 
Net income  135   105 
Net income attributable to the noncontrolling interest  16   16 
Net income attributable to AGL Resources Inc. $119  $89 

  
Nine months ended
September 30,
 
In millions 2008  2007 
Operating revenues $1,995  $1,809 
Operating expenses  1,675   1,460 
Operating income  320   349 
Minority interest  (12)  (24)
Other income  6   1 
EBIT  314   326 
Interest expense, net  (85)  (92)
Earnings before income taxes  229   234 
Income taxes  86   89 
Net income $143  $145 

Balance sheetStatements of financial position information at December 31, 2007,2008, is as follows:
In millions   
Identifiable and total assets (1)
 
 
  Goodwill 
Distribution operations $4,847  $406 
Retail energy operations  282   - 
Wholesale services  890   - 
Energy investments  287   14 
Corporate and intercompany eliminations (2)
  (48)  - 
Consolidated AGL Resources $6,258  $420 
In millions Identifiable and total assets (1)  
 
Goodwill
 
Distribution operations $5,138  $404 
Retail energy operations  315   - 
Wholesale services  970   - 
Energy investments  353   14 
Corporate and intercompany eliminations (2)
  (66)  - 
Consolidated AGL Resources Inc. $6,710  $418 

(1)  Identifiable assets are those assets used in each segment’s operations.
(2)  Our corporate segment’s assets consist primarily of cash and cash equivalents and property, plant and equipment and reflect the effect of intercompany eliminations.



Glossary of Key Terms
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Summarized income statement information, identifiable and total assets, goodwill and property, plant and equipment expenditures as of and for the three and nine months ended September 30,March 31, 2009 and 2008, and 2007, by segment, are shown in the following tables.

Three months ended September 30, 2008March 31, 2009
In millions 
Distribution operations
  
Retail
energy
operations
  
Wholesale services
  
Energy investments
  
Corporate and intercompany eliminations (3)
  Consolidated AGL Resources 
Operating revenues from external parties $237  $149  $138  $13  $2  $539 
Intercompany revenues (1)
  35   -   -   -   (35)  - 
Total operating revenues  272   149   138   13   (33)  539 
Operating expenses                        
Cost of gas  101   154   37   3   (34)  261 
Operation and maintenance  72   15   13   6   (2)  104 
Depreciation and amortization  32   1   1   1   3   38 
Taxes other than income taxes  9   -   1   -   -   10 
Total operating expenses  214   170   52   10   (33)  413 
Operating income (loss)  58   (21)   86   3   -   126 
Other income  1   -   -   -   1   2 
Minority interest  -   5   -   -   -   5 
EBIT $59  $(16)  $86  $3  $1  $133 
                         
Capital expenditures for property, plant and equipment $62  $-  $-  $23  $3  $88 
In millions Distribution operations  Retail    energy operations  Wholesale services  Energy investments  
Corporate and intercompany eliminations (3)
  Consolidated AGL Resources 
Operating revenues from external parties $572  $343  $68  $10  $2  $995 
Intercompany revenues (1)
  35   -   -   -   (35)  - 
Total operating revenues  607   343   68   10   (33)  995 
Operating expenses                        
Cost of gas  355   259   9   -   (34)  589 
Operation and maintenance  83   20   19   5   (2)  125 
Depreciation and amortization  32   1   1   2   3   39 
Taxes other than income taxes  9   -   1   1   1   12 
Total operating expenses  479   280   30   8   (32)  765 
Operating income (loss)  128   63   38   2   (1)  230 
Other income  2   -   -   -   -   2 
EBIT $130  $63  $38  $2  $(1) $232 
                         
Identifiable and total assets (2)
 $5,095  $261  $653  $373  $(225) $6,157 
Goodwill $404  $-  $-  $14  $-  $418 
Capital expenditures for property, plant and equipment $69  $-  $-  $23  $5  $97 


Three months ended September 30, 2007March 31, 2008
In millions 
Distribution operations
  
Retail
energy
operations
  
Wholesale services
  
Energy investments
  
Corporate and intercompany eliminations (3)
  Consolidated AGL Resources 
Operating revenues from external parties $219  $128  $13  $9  $-  $369 
Intercompany revenues (1)
  37   -   -   -   (37)  - 
Total operating revenues  256   128   13   9   (37)  369 
Operating expenses                        
Cost of gas  83   112   1   -   (37)  159 
Operation and maintenance  79   16   10   4   (2)  107 
Depreciation and amortization  30   1   1   2   3   37 
Taxes other than income taxes  9   1   -   -   1   11 
Total operating expenses  201   130   12   6   (35)  314 
Operating income (loss)  55   (2)   1   3   (2)  55 
Other income (expense)  -   1   -   -   (1)  - 
Minority interest  -   -   -   -   -   - 
EBIT $55  $(1)  $1  $3  $(3) $55 
                         
Capital expenditures for property, plant and equipment $52  $2  $-  $8  $6  $68 


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Nine months ended September 30, 2008
In millions 
Distribution operations
  
Retail
energy
operations
  
Wholesale services
  
Energy investments
  
Corporate and intercompany eliminations (3)
  Consolidated AGL Resources 
Operating revenues from external parties $1,146  $701  $104  $43  $1  $1,995 
Intercompany revenues (1)
  147   -   -   -   (147)  - 
Total operating revenues  1,293   701   104   43   (146)  1,995 
Operating expenses                        
Cost of gas  694   600   41   4   (146)  1,193 
Operation and maintenance  241   50   35   16   (5)  337 
Depreciation and amortization  94   3   4   4   7   112 
Taxes other than income taxes  27   1   2   1   2   33 
Total operating expenses  1,056   654   82   25   (142)  1,675 
Operating income (loss)  237   47   22   18   (4)  320 
Other income  2   -   -   -   4   6 
Minority interest  -   (12)  -   -   -   (12)
EBIT $239  $35  $22  $18  $-  $314 
                         
Identifiable and total assets (2) $ 4,992  $271  $1,007  $ 326  $  (92)  $ 6,504 
Goodwill  $404  $-   $-   $ 14  $  -  $ 418 
Capital expenditures for property, plant and equipment $196  $7  $-  $44  $7  $254 
Nine months ended September 30, 2007
In millions 
Distribution operations
  
Retail
energy
operations
  
Wholesale services
  
Energy investments
  
Corporate and intercompany eliminations (3)
  Consolidated AGL Resources 
Operating revenues from external parties $1,079  $653  $50  $27  $-  $1,809 
Intercompany revenues (1)
  137   -   -   -   (137)  - 
Total operating revenues  1,216   653   50   27   (137)  1,809 
Operating expenses                        
Cost of gas  612   508   4   -   (137)  987 
Operation and maintenance  250   50   27   14   (7)  334 
Depreciation and amortization  89   4   2   4   9   108 
Taxes other than income taxes  25   1   1   1   3   31 
Total operating expenses  976   563   34   19   (132)  1,460 
Operating income (loss)  240   90   16   8   (5)  349 
Other income (expense)  2   1   -   (1)   (1)  1 
Minority interest  -   (24)  -   -   -   (24)
EBIT $242  $67  $16  $7  $(6) $326 
                         
Identifiable and total assets (2) $ 4,780  $211  $699  $ 276  $  (135)  $ 5,831 
Goodwill  $406  $-   $-   $ 14  $  -  $ 420 
Capital expenditures for property, plant and equipment $145  $3  $1  $18  $26  $193 
In millions Distribution operations  Retail energy operations  Wholesale services  Energy investments  
Corporate and intercompany eliminations (3)
  Consolidated AGL Resources 
Operating revenues from external parties $610  $375  $17  $11  $(1) $1,012 
Intercompany revenues (1)
  66   -   -   -   (66)  - 
Total operating revenues  676   375   17   11   (67)  1,012 
Operating expenses                        
Cost of gas  428   293   2   -   (66)  657 
Operation and maintenance  86   19   12   4   (2)  119 
Depreciation and amortization  31   1   1   1   2   36 
Taxes other than income taxes  9   -   1   1   1   12 
Total operating expenses  554   313   16   6   (65)  824 
Operating income (loss)  122   62   1   5   (2)  188 
Other income  1   -   -   -   -   1 
EBIT $123  $62  $1  $5  $(2) $189 
                         
Identifiable and total assets (2)
 $4,769  $296  $968  $287  $(214) $6,106 
Goodwill $406  $-  $-  $14  $-  $420 
Capital expenditures for property, plant and equipment $59  $6  $-  $11  $4  $80 

(1)  Intercompany revenues – Wholesale services records its energy marketing and risk management revenue on a net basis. Wholesale services’ total operating revenues include intercompany revenues of $289$165 million and $120$273 million for the three months ended September 30,March 31, 2009 and 2008, and 2007, respectively; and $806 million and $473 million for the nine months ended September 30, 2008 and 2007, respectively.
(2)  Identifiable assets are those used in each segment’s operations.
(3)  Our corporate segment’s assets consist primarily of cash and cash equivalents, property, plant and equipment and reflect the effect of intercompany eliminations.


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

FORWARD-LOOKING STATEMENTS

Certain expectations and projections regarding our future performance referenced in this Management’s
Discussion and Analysis of Financial Condition and
Results of Operations 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. OfficersSenior officers and other employees may also make verbal statements to analysts, investors, regulators, the media and others that are forward-looking.

Forward-looking statements involve matters that are not historical facts, and because these statements involve anticipated events or conditions, 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,” "seek," "should," "target," "will," "would," or similar expressions. You are cautioned not to place undue reliance on our forward-looking statements. Our expectations are not guarantees and are based on currently available competitive, financial and economic data along with our operating plans. While we believe that our expectations are reasonable in view of currently available information, our expectations are subject to future events, risks and uncertainties, and there are several factors - - many beyond our control - that could cause our results to differ significantly 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;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; the impact of acquisitions and divestitures; direct or indirect effects on our business, financial condition or liquidity resulting from a change in our credit ratings or the credit ratings of our counterparties or competitors; interest rate fluctuations; financial market conditions, including recent disruptions in the capital markets and lending environment and the current economic downturn; and general economic conditions; uncertainties about environmental issues and the related impact of such issues; 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; acts of war or terrorism; and other factors described in detail in our filings with the SEC.

We caution readers that, in addition to the important factors described elsewhere in this report, the factors set forth in Item 1A, Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2007,2008, among others, could cause our business, results of operations or financial condition in 20082009 and thereafter to differ significantly from those expressed in any forward-looking statements. There also may be other factors that we cannot anticipate or that are not described in our Form 10-K or in this report that could cause results to differ significantly from our expectations.

Forward-looking statements are only as of the date they are made. We do not update these statements to reflect subsequent circumstances or events.

Overview

We are an energy services holding company whose principal business is the distribution of natural gas through our regulated natural gas distribution business and the sale of natural gas to end-use customers primarily in Georgia through our retail natural gas marketing business. For the ninethree months ended September 2008,March 31, 2009, our six utilities serve approximately 2.3 million average end-use customers, making us the largest distributor of natural gas in the southeastern and mid-Atlantic regions of the United States based on customer count. Although our retail natural gas marketing business is not subject to the same regulatory framework as our utilities, it is an integral part of the framework for providing natural gas service to end-use customers in Georgia.

We also engage in natural gas asset management and related logistics activities for our own utilities as well as for non-affiliated companies; natural gas storage arbitrage and related activities; and the development and operation of high-deliverability underground natural gas storage assets. These businesses allow us to be opportunistic in capturing incremental value at the wholesale level, provide us with deepened business insight about natural gas market dynamics and facilitate our ability, in the case of asset management, to provide transparency to regulators as to how that value can be captured to benefit our utility customers through profit-sharing arrangements. Given the volatile and changing nature of the natural gas resource base in North America and globally, we believe that participation in these related businesses strengthens our company. We manage these businesses through four operating segments - distribution operations, retail energy operations, wholesale services, energy investments and a non-operating corporate segment.

Executive Summary

Customer growth - We continue to see challenging economic conditions in all the areas we serve and, as a result, have experienced lower than expected customer growth throughout 2008, a trend we expect to continue through 2009.
Glossary of Key Terms
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For
Executive Summary

We intend to continue executing our plan for long-term earnings and dividend growth. Central to that plan is the nine months ended September 30, 2008,execution of our consolidatedregulatory strategy through the filing of rate cases to recover the investments we have made, and should continue to make, to enhance our infrastructure and improve customer service. Further, we are collaborating with regulatory agencies and other companies to promote and encourage conservation through innovative rate design mechanisms that we believe are positioning our utility customer growth rate was 0.1%, comparedbusinesses to 1.0% for the comparable period last year. We had anticipated customer growthbenefit in 2008 of about 0.5%. The reduction in customer count is primarily a result of much slower growth in the residential housing markets throughout our service territories. This trend has been offset slightly by growth in the commercial customer segment in certain areas, primarily as a result of conversions to natural gas from other fuel sources.an economic recovery.

We continue to useexplore select opportunities to expand our businesses in strategic areas and maintain a variety of targeted marketing programs to attract new customers and to retain existing ones. These programs generally emphasizedisciplined approach around current capital projects. Our major capital projects - our Golden Triangle Storage natural gas as the fuel of choice for customersstorage facility project and seek to expand the use of natural gas through a variety of promotional activities.

We have seen a 3% decline in average customer count at SouthStar for the nine months ended September 30, 2008, as compared to the same period in 2007. This decline reflects some of the sameour Hampton Roads Crossing and Magnolia pipeline connection projects - are on schedule and within budget. In these challenging economic conditions we continue to aggressively focus on capital discipline and cost control, while moving ahead with projects and initiatives that we expect to have affected our utility businesses as well as a more competitive market for natural gas in Georgia. As a result of recent disruptions in the credit markets, one of the smaller Marketers in Georgia filed for bankruptcy in October 2008, after being unable to obtain ongoing funding for working capital needs. Another Marketer assumed responsibility for the bankrupt Marketer’s 30,000 customers, undercurrent and future benefits and provide an agreement approved by the Georgia Commission. Our financial exposure to this Marketer is immaterial.appropriate return on capital.

Natural gas prices - Increased energy and transportation prices are expected to impact a significantly larger portion of consumer household incomes as we move into the 2008/2009 winter heating season. Although natural gas prices dropped during the third quarter of 2008, industry projections are that customers’ heating costs in the U.S. could increase as much as 30% over last year. As a result, we may incur additional bad debt expense during the winter season as well as lower operating margins due to increased customer conservation in an environment of high natural gas prices. While we expect these factors could adversely impact our results of operations, we expect regulatory and operational mechanisms in place in most of our jurisdictions will help mitigate our exposure to these factors.Distribution Operations

These risks of increased bad debt expense and decreased operating margins from conservation are minimized at our largest utility, Atlanta Gas Light, as a result of its straight-fixed variable rate structure. In addition, customers in Georgia buy their natural gas from certificated marketers rather than from Atlanta Gas Light. Our credit exposure at Atlanta Gas Light is primarily related to the provision of services to the certificated marketers, but that exposure is mitigated, as we obtain security support in an amount equal to a minimum of two times a marketer’s highest month’s estimated bill. At our other utilities, while customer conservation could adversely impact our operating margins, we will utilize measures to collect delinquent accounts and continue to be rigorous in monitoring and mitigating the impact of these expenses. We do, however, expect that our bad debt expense for the upcoming winter heating season will be higher than the prior year.

We are working with regulators and state agencies in each of our jurisdictions to educate customers about these issues in advance of the winter heating season, in particular to ensure that those qualified for the Low Income Home Energy Assistance Program funds and other similar programs will receive that assistance.

SouthStar may also be affected by the conservation and bad debt trends, but its overall exposure is partially mitigated by the high credit quality of SouthStar’s customer base, disciplined collection practices and the unregulated pricing structure in Georgia.

The rising commodity prices during the first six month of 2008, along with reduced opportunities related to the management of storage and transportation assets throughout the first nine months of 2008 further negatively impacted SouthStar’s operating margin by $15 million. More favorable market conditions and decreasing natural gas prices in the first six months of 2007 as compared to rising prices during the same time frame in 2008 enabled SouthStar to recognize higher operating margins for year-to-date September 30, 2007 as compared to 2008. SouthStar’s reported results were also negatively impacted during the current year quarter by the significant decrease in natural gas prices during the three months ended September 30, 2008 as SouthStar was required to record an $18 million LOCOM adjustment to reduce its natural gas inventory to market.

Due to the rising commodity price environment and the widening of transportation basis spreads during the first six months of 2008, Sequent recorded $70 million in losses on the financial instruments it uses to hedge its storage and transportation positions. The natural gas market remained volatile with significant decreases in prices and narrowing of basis spreads during the quarter ended September 30, 2008. Consequently Sequent recognized gains on hedging instruments of $117 million for the quarter and $47 million for the first nine months of 2008. This is a $106 million and $30 million net increase compared to last year’s third quarter and year-to-date periods, respectively. In addition to the increase in hedge gains Sequent’s commercial activity improved by $16 million and $19 million for the quarter ended and year-to-date periods ended September 30, 2008, respectively due to more favorable business opportunities presented by the greater volatility in the marketplace than in 2007. This improvement was due in part to increased hurricane activity, although the market did not react as strongly as it did after hurricanes Rita and Katrina in 2005 as there was less damage to the natural gas infrastructure and increased onshore production.
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In addition, the decrease in forward prices caused Sequent to be subject to a LOCOM adjustment on its natural gas inventory. The increase in the impact of the adjustment, net of estimated hedging recoveries, was $33 million and $32 million for the quarter and year-to-date periods, respectively. These changes resulted in Sequent reporting operating margin that was $89 million and $17 million higher for the current quarter and year-to-date periods ended September 30, 2008, respectively, as compared to last year.

Distribution Operations - Our distribution operations segment is the largest component of our business and includes thesesix natural gas local distribution utilities. These utilities in six states:construct, manage and maintain intrastate natural gas pipelines and distribution facilities and include:

·  Atlanta Gas Light in Georgia
·  Chattanooga Gas in Tennessee
·  Elizabethtown Gas in New Jersey
·  Elkton Gas in Maryland
·  Florida City Gas in Florida
·  Virginia Natural Gas in Virginia

Each utility operates subject to regulations of the state regulatory agencies in its service territories with respect to rates charged to our customers, maintenance of accounting records and various other service and safety matters. Rates charged to our customers vary according to customer class (residential, commercial or industrial) and rate jurisdiction. Rates are set at levels that generally should allow us to recover all prudently incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable return for our shareholders. Rate base generally consists of the original cost of utility plant in service, working capital and certain other assets; less accumulated depreciation on utility plant in service and net deferred income tax liabilities, and may include certain other additions or deductions.

We continuously monitor the performance of our utilities to determine whether rates need to be adjusted through the regulatory process. We have long-term fixed rate settlements in our three largest franchises in Georgia, New Jersey and Virginia.

With the exception of Atlanta Gas Light and Elkton Gas, earningsCustomer growth declined slightly in our distribution operations segment canin the first three months of 2009 relative to last year, a trend we expect to continue through 2009. For the three months ended March 31, 2009, our year-over-year consolidated utility customer growth rate was slightly negative or (0.1)%, compared to 0.3% for the same period of 2008. We anticipate overall customer growth in 2009 to be affected byflat to negative, primarily as a result of much slower growth in the residential housing markets throughout most of our service territories and the effects of a weak economy on our commercial and industrial customers. Over the last 3 years we have reduced our customer consumption patterns thatattrition rates. As a result, we believe we should be well positioned when the economy recovers.

The weak economy also impacted a significantly larger portion of consumer household incomes during the most recent winter heating season. As a result, we incurred additional bad debt expense and increased customer conservation. We expect these factors may continue to adversely impact our results of operations during the current economic situation. However, we expect operational and collections efforts combined with regulatory mechanisms in place in most of our jurisdictions to help mitigate some of our exposure to these factors.

The risks of increased bad debt expense and decreased operating margins from conservation are a function of weather conditions and price levels for natural gas.minimized at our largest utility, Atlanta Gas Light, charges ratesas a result of its straight-fixed variable rate structure. In addition, customers in Georgia buy their natural gas from Marketers rather than from Atlanta Gas Light. Our credit exposure at Atlanta Gas Light is primarily related to its customers primarily as monthly fixed charges. In May 2008, new rates became effective for Elkton Gas which included mechanismsthe provision of services to the Marketers, but that returnedexposure is mitigated, because we obtain security support in an amount equal to a minimum of no less than two times a Marketer’s highest month’s estimated bill. At our other utilities, while customer conservation could adversely impact our operating margin per customermargins, we utilize measures to levels approved bycollect delinquent accounts and continue to be rigorous in monitoring and mitigating the Maryland Commission in itsimpact of these expenses. Due to the timing of usage and billing, the full effects of the most recent rate decision.heating season will not be known until several months following the end of the heating season.

OurWe worked with regulators and state agencies in each of our jurisdictions to educate customers about higher energy costs in advance of the winter heating season, in particular, to ensure that those customers qualified for the Low Income Home Energy Assistance Program and other jurisdictions have various regulatory mechanisms that allow ussimilar programs receive any needed assistance and we expect to recover our costs, but they are not direct offsets tocontinue this focus for the potential impactsforeseeable future.

Glossary of weather and customer consumption on earnings. In our New Jersey, Virginia and Tennessee utilities, their respective tariffs contain WNA or similar provisions that are designed to help stabilize operating results by increasing base rate amounts charged to customers when weather is warmer than normal and decreasing amounts charged when weather is colder than normal. The WNA is most effective in a reasonable temperature range relative to normal weather using historical averages.Key Terms

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Upcoming rate cases Beginning inIn 2009 throughand 2010, we willexpect to file base rate cases in four of our six jurisdictions. Over the past several years our utilities have been fulfilling their long-term commitments to rate freezes, which begin expiring in 2009. As these rate cases are filed, we plan to seek rate reforms that encourage conservation and “decoupling.” In traditional rate designs, our utilities’ recovery of a significant portion of their fixed customer service costs is tied to assumed natural gas volumes used by our customers. We believe separating, or decoupling, the recovery of these fixed costs from the natural gas deliveries will align the interests of our customers and utilities by encouraging energy conservation, achieving rate stability for our customers and ensuring stable returns for our shareholders. These rate case filings are required due to settlements we reached with the applicable state authority in previous rate case or acquisition proceedings. The expected filing dates and dates for which current rates are expected to be effective are outlined in the chart below:

Company
Expected
filing date
Current rates effective until
Elizabethtown GasQ1 2009Q4 2009 - Q1 2010
Atlanta Gas LightQ4 2009Q2 2010
Virginia Natural GasQ1Q2 2010Q3 2011
Chattanooga GasQ2 2010Q1 2011

Virginia NaturalElizabethtown Gas In July 2008, Virginia Natural GasAfter a 5-year rate freeze and in accordance with the New Jersey Commission’s order, we filed a Conservation and Ratemaking Efficiency Plan (Conservation Plan)rate case in March 2009 with the Virginia Commission. The plan was filed pursuanta proposed effective date of January 1, 2010. We are requesting an annual increase to a Virginia law that allows natural gas utilities to implementbase rates of $25 million. This filing included energy conservation programs and alternative rate designs which would allow the utility to recover the cost of providing safe and reliable service based on normal customer usage. On Octoer 29, 2008, Virginia Natural Gas filed with the Virginia Commission a motion for approval of a proposed stipulation.Efficiency Usage and Adjustment mechanism (EUA), which is a form of decoupling. If the proposed stipulationEUA is approved, the current weather normalization clause would be eliminated. Our requested increase consists of:

·  increased carrying costs and depreciation expense associated with increased rate base ($15 million)
·  increased operating expenses, including higher bad debt expenses and other ($6 million)
·  increased return on equity from 10% to 11.25% and return on rate base from 7.95% to 8.57% ($4 million)

In January 2009, and in response to New Jersey Governor Corzine’s call for utilities to assist in the economic recovery by increasing infrastructure investments, Elizabethtown Gas proposed an accelerated $60 million enhanced infrastructure program over the next two years. In April 2009, the New Jersey Commission approved a stipulation between Elizabethtown Gas and certain intervenors to the case. Under the stipulation, the infrastructure program should begin in 2009 and end in 2011, unless extended by the Virginia Commission, Virginia Natural GasNew Jersey Commission. A regulatory cost recovery mechanism will invest approximately $7 million over three years in new conservation programs. Virginia Natural Gas will also implement an accompanying decoupled rate design mechanism that will mitigatebe established with estimated rates put into effect at the impactbeginning of conservation and declining usage and provide the utility with an opportunity to recover its fixed costs. Hearings on the Conservation Plan and proposed stipulation were held in October 2008, and the Virginia Commission is expected to issue a ruling byeach year. At the end of 2008.the program the regulatory cost recovery mechanism will be trued-up and any remaining costs not previously collected will be included in base rates.

Magnolia Enterprise Holdings, Inc. (Magnolia)Atlanta Gas Light In September 2007, we received approval fromMarch 2009 the Georgia Commission for Atlanta Gas Light’s capacity supply plan in Georgia. A key part of that agreement was the ability to diversify our supply sourcesapproved a new economic development and environmental program developed by gaining more access to the Elba Island liquefied natural gas (LNG) facility. As a result, Southern Natural Gas (SNG) and our affiliate, Magnolia filed a joint application with the FERC to obtain an undivided interest in pipelines connecting our Georgia service territory to the Elba Island LNG facility and for approval of the project. Under the proposed transaction, Magnolia would purchase the undivided interest and lease the interest to SNG. Atlanta Gas Light would then subscribe to the associated capacity from SNG.encourage smart new investment in Georgia. The projectnew program, Georgia Sustainable Environmental Economic Development (Georgia SEED), is expecteddesigned to be completedattract and retain jobs, support projects to reduce carbon emissions and encourage new investment in 2010.Georgia.

Under Georgia SEED, Atlanta Gas Light will contract with new and existing business customers that may be considering expanding into Georgia. Atlanta Gas Light will have the option to invest capital to help customers finance line extensions, new natural gas equipment and equipment installations. This is a five-year experimental program and offers three potential avenues for contracts:

·  Providing customers with the benefit of a new utility service extension to plant sites;
22
·  Offering financing for the purchase and installation of new higher-efficiency gas equipment, such as engines, boilers, fleet vehicles, refueling stations and gas-fired air conditioning equipment; and
·  Discounting utility rates to help lower overall energy costs.

Retail Energy Operations-

Our retail energy operations segment consists of SouthStar, a joint venture owned 70% by us and 30% by Piedmont. SouthStar markets natural gas and related services to retail customers on an unregulated basis, principally in Georgia, as well as to commercial and industrial customers in Alabama, Florida, Ohio, Tennessee, North Carolina and South Carolina. SouthStar is the largest marketer of natural gas in Georgia with an approximate 35%34% market share based on customer count.

Although our ownership interest in the SouthStar partnership is 70%, the majority of SouthStar's earnings in Georgia are allocated by contract 75% to us and 25% to Piedmont. SouthStar’s earnings related to customers in Ohio and Florida are allocated 70% to us and 30% to Piedmont. We record the earnings allocated to Piedmont as a minoritynoncontrolling interest in our condensed consolidated statements of income, and we record Piedmont’s portion of SouthStar’s capital as a minoritynoncontrolling interest in our condensed consolidated balance sheets.statements of financial position. The majority of SouthStar’s earnings allocated to us for the three and nine months ended September 30, 2008,March 31, 2009, were at the 75% contractual rate.

BeginningOur amended and restated joint venture agreement with Piedmont includes a series of options granting us the evergreen opportunity to purchase all or a portion of Piedmont’s ownership interest in October 2008, SouthStar was awardedSouthStar. We have the right to supplyexercise an option to purchase on or before November of each year, with the purchase being effective as of January 1, of the following year. We currently have options to purchase up to 50% of Piedmonts’ ownership interest. Effective November 1, 2009, the option allows us to purchase 100% of Piedmont’s ownership interest. If we were to exercise any option to purchase less than 100% of Piedmont’s ownership interest in SouthStar, Piedmont, at its discretion, could require us to purchase their entire ownership interest. The purchase price, in any exercise of our option, would be based on the then current fair market value of SouthStar. In March 2009, Piedmont filed a totallawsuit against GNGC regarding GNGC’s right to purchase Piedmont’s interest in SouthStar. See Note 7 of approximately 15 Bcfthe financial statements for additional information.

Glossary of natural gas to customersKey Terms
24
Table of Vectren Energy Delivery of Ohio (VEDO) through March 2010. As part of this agreement, SouthStar will manage the supply, transportation and storage of natural gas on behalf of VEDO.Contents

SouthStar’s operations are sensitive to seasonal weather, natural gas prices, retail pricing plans and strategies, customer growth and consumption patterns similar to those affecting our utility operations. SouthStar’s retail pricing strategies and use of various economic hedging strategies, such as futures, options, swaps, weather derivative instruments and other risk management tools, help to ensure retail customer costs are covered to mitigate the potential effect of these issues on its operations.

In the Georgia market, we have experienced and expect through 2009 that we will experience the negative impact to operating margins from increased competition and an increase in the number of customers shopping for lower retail natural gas prices. Further, the number of customers switching Marketers in the Georgia market has increased in part due to customers seeking the most competitive price plans.

SouthStar continues to use a variety of targeted marketing programs to attract new customers and to retain existing ones. These programs emphasize GNG as the Marketer of choice. Despite these efforts we have seen a 3% decline in average customer count at SouthStar for the three months ended March 31, 2009, as compared to the same period of 2008. We believe this decline reflects some of the same economic conditions that have affected our utility businesses as well as the more competitive retail pricing market for natural gas in Georgia.

SouthStar may also be affected by the conservation and bad debt trends, but its overall exposure is partially mitigated by the high credit quality of SouthStar’s customer base, lower wholesale natural gas prices, disciplined collection practices and the unregulated pricing structure in Georgia.

SouthStar continues to expand its business in other states as well. We are currently focusing these efforts on Ohio and Florida, which are growing more rapidly than anticipated.

Wholesale Services-

Our wholesale services segment consists primarily of Sequent, our subsidiary involved in asset management and optimization, storage, transportation, producer and peaking services and wholesale marketing. Sequent seeks asset optimization opportunities, which focus on capturing the value from idle or underutilized assets, typically by participating in transactions to take advantage of pricing differences between varying markets and time horizons within the natural gas supply, storage and transportation markets to generate earnings. These activities are generally referred to as arbitrage opportunities.

Sequent’s profitability is driven by volatility in the natural gas marketplace. Volatility arises from a number of factors such as weather fluctuations or the change in supply of, or demand for, natural gas in different regions of the country. Sequent seeks to capture value from the price disparity across geographic locations and various time horizons (location and seasonal spreads). In doing so, Sequent also seeks to mitigate the risks associated with this volatility and protect its margin through a variety of risk management and economic hedging activities.

Sequent provides its customers with natural gas from the major producing regions and market hubs in the U.S. and Canada. Sequent acquires transportation and storage capacity to meet its delivery requirements and customer obligations in the marketplace. Sequent’s
customers benefit from its logistics expertise and ability to deliver natural gas at prices that are advantageous relative to other alternatives available to its customers.

During the third quarter of 2008, Sequent negotiated an agreement for 40,000 dekatherms per day of transportation capacity for a period of 25 years beginning in August 2009. Upon execution of thisThis agreement was executed in April 2009, and as a result, we will includehave included approximately $89 million of future demand payments associated with this capacity within our unrecorded contractual obligations and commitment disclosures. As with its other transportation capacity agreements, Sequent has and will identify opportunities to lock-in economic value associated with this capacity through the use of financial hedges. TheSince the duration of this agreement is significantly longer than the average duration of Sequent’s portfolio, the hedging of the capacity may increasehas increased our exposure to hedge gains and losses as well as potentially impactimpacting Sequent’s VaR. During the second half of 2008 we began executing hedging transactions related to this transportation capacity. As a result of changes in the fair value of these hedges, Sequent reported hedge gains of $19 million during the first quarter of 2009. There was no significant impact to hedge gains or losses or VaR during the period.


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Asset management transactions Sequent’s asset management customers include affiliated utilities, nonaffiliated utilities, municipal utilities, power generators and large industrial customers. These customers, due to seasonal demand or levels of activity, may have contracts for transportation and storage capacity, which may exceed their actual requirements. Sequent enters into structured agreements with these customers, whereby Sequent, on behalf of the customer, optimizes the transportation and storage capacity during periods when customers do not use it for their own needs. Sequent may capture incremental operating margin through optimization, and either share margins with the customers or pay them a fixed amount.

In 2009, Sequent extended its asset management agreement with Virginia Natural Gas for three additional years. The new agreement includes a tiered structure of profit sharing along with guaranteed annual minimums. With this renewal, Sequent has completed renewal of all its affiliated asset management contracts for multi-year periods.

The following table provides updated information on Sequent’s asset management agreements with its affiliated utilities, including amended or extended agreements in 2008 and 2009 with Florida City Gas, Chattanooga Gas, Elizabethtown Gas and ElizabethtownVirginia Natural Gas.

   % of shared 
 
Expiration
date
 profits or annual fee 
Virginia Natural GasMar 2009March 2012 (A) (B) 
Chattanooga GasMarMarch 2011  50% (B) 
Elizabethtown GasMarMarch 2011 (A) (B) 
Atlanta Gas LightMarMarch 2012 up to 60% (B) (B)
Florida City GasMarMarch 2013  50% 
(A)  Shared on a tiered structure.
(B)  
Includes aggregate annual minimum payments of $12$14 million
for Chattanooga Gas, Elizabethtown Gas, Virginia Natural Gas and Atlanta Gas Light.

Storage inventory outlook The following graph presents the NYMEX forward natural gas prices as of September 30, 2008, June 30, 2008March 31, 2009 and December 31, 2007,2008, for the period of October 2008April 2009 through September 2009,March 2010, and reflects the prices at which Sequent could buy natural gas at the Henry Hub for delivery in the same time period. The Henry Hub is the largest centralized point for natural gas spot and futures trading in the United States. The NYMEX uses the Henry Hub as the point of delivery for its natural gas futures contracts. Many natural gas marketers also use the Henry Hub as their physical contract delivery point or their price benchmark for spot trades of natural gas.

NYMEX Graph

GlossaryDuring the last half of Terms
2008 and continuing into 2009, natural gas prices declined significantly, reflecting the decline in the U.S. economy, increasing natural gas supplies and above-average storage volumes, among other factors. These lower gas prices expected for 2009, as reflected in the NYMEX forward curve, would result in significantly lower levels of working capital necessary for Sequent to purchase its natural gas inventories as compared to 2008, which saw significantly higher prices.
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Table of Contents
NYMEX Graph

Sequent’s expected natural gas withdrawals from physical salt dome and reservoir storage are presented in the following table along with the operating revenues expected at the time of withdrawal. Sequent’s expected operating revenues are net of the estimated impact of regulatory sharing and reflect the amounts that are realizable in future periods based on the inventory withdrawal schedule and forward natural gas prices at September 30, 2008.March 31, 2009. Sequent’s storage inventory is economically hedged with futures contracts, which results in an overall locked-in margin, timing notwithstanding.

   
Withdrawal schedule
(in Bcf)
    
  
Salt dome (WACOG $6.82)
  
Reservoir (WACOG $6.84)
  
Expected
operating revenues
(in millions)
 
2008         
Fourth quarter  2   9  $7 
2009            
First quarter  -   5   5 
Total  2   14  $12 
     
Withdrawal schedule
(in Bcf)
 
  
Salt dome (WACOG $3.96)
  
Reservoir (WACOG $2.94)
  
Expected operating revenues
(in millions)
 
2009         
Second quarter  -   1  $1 
Third quarter  2   2   2 
Fourth quarter  -   1   1 
2010            
First quarter  -   1   1 
Total  2   5  $5 

If Sequent’s optimization effortsstorage withdrawals associated with existing inventory positions are executed as planned, it expects operating revenues from storage withdrawals of approximately $7$5 million during the three months ending December 31, 2008 and $5 million in 2009.next twelve months. This could change as Sequent adjusts its daily injection and withdrawal plans in response to changes in market conditions in future months and as forward NYMEX prices fluctuate. Based upon Sequent’s current projection of year-end storage positions at December 31, 2008, a $1.00 increase in the first quarter 2009 forward NYMEX prices could result in a $4 million reduction to Sequent’s reported operating revenues for the year ending December 31, 2008, after regulatory sharing. A $1.00 decrease in forward NYMEX prices would result in a $4 million positive impact to Sequent’s reported operating revenues; however additional LOCOM adjustments could potentially offset a portion of the positive impact. This amount does not include operating expenses that will be incurred to realize this amount. For more information on Sequent’s energy marketing and risk management activities, see Item 3, Quantitative and Qualitative Disclosures About Market Risk - Commodity Price Risk.
Glossary of Key Terms
26
Table of Contents
Energy Investments

Energy Investments - - Our energy investments segment includes a number of businesses that are related or complementary to our primary business. The most significant of these businesses is our natural gas storage business, Jefferson Island, which operates a high-deliverability salt-dome storage assetfacility in the Gulf Coast region of the U.S. While our salt-dome storage business also can generate additional revenue during times of peak market demand for natural gas storage services, the majority of its storage services are covered under medium to long-term contracts at a fixed market rate.

We are actively pursuing litigation against the State of Louisiana to obtain a court order or settlement confirming Jefferson Island’s right to expand its existing facility. Jefferson Island’s litigation with the State of Louisiana is described in further detail in Note 6, “Commitments and Contingencies.”7 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2008. In June 2008,April 2009, the State of Louisiana passedtrial court ruled that the legislation restricting water usage from the Chicot aquifer which is a main source of fresh water required for the expansion of the Jefferson Island capacity. We contend that this legislationto expand its existing storage facility is unconstitutional and have sought to amendinvalid. In addition, the pending litigation to seekcourt scheduled a declarationtrial for September 28, 2009 on Jefferson Island's claim that it is invalid andauthorized to expand the facility under its mineral lease. The ultimate resolution of such trial cannot be enforced. Even if we aredetermined, but it is not successfulexpected to have a material adverse effect on those grounds, we believe the legislation does not materially impact the feasibilityour consolidated financial condition, results of the expansion project.operations or cash flows.

Through Golden Triangle Storage, we are constructing a new salt-dome storage facility in the Gulf Coast region of the U.S. In May 2008, Golden Triangle Storage started construction on both caverns, with the first cavern. Hurricanes Gustavexpected to be in service in the third quarter of 2010 and Ike caused some damage and minor delaysthe second cavern in September 2008, but our timelines associated with commencementthe second quarter of commercial operations remain on schedule.2012. We previously estimated, based on then current prices for labor, materials and pad gas that costs to construct the facility would be approximately $265 million. However, prices for labor materials and pad gasmaterials have risen significantly in the ensuing months, increasing the estimated construction cost by approximately 10% to 20%. The actual project costs depend upon the facility’s configuration, materials, drilling costs, financing costs and the amount and cost of pad gas, which includes volumes of non-working natural gas used to maintain the operational integrity of the cavern facility. The costs for the vast majorityapproximately 57% of these items have not been fixed and are subject to continued variability during the period of construction. Further, since we are not able to predict whether these costs of construction will continue to increase, moderate or decrease from current levels, we believe that there could be continued volatility in the construction cost estimates.

We also own and operate a telecommunications business, AGL Networks, which constructs and operates conduit and fiber infrastructure within select metropolitan areas.

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Corporate -

Our corporate segment includes our nonoperating business units, including AGL Services Company and AGL Capital.

We allocate substantially all of our corporate segment operating expenses and interest costs to our operating segments in accordance with state regulations. Our segment results include the impact of these allocations to the various operating segments. Our corporate segment also includes intercompany eliminations for transactions between our operating business segments.

Results of Operations

Operating margin and EBIT We evaluate segment performance using the measures of operating margin and EBIT, which include the effects of corporate expense allocations. Our operating margin and EBIT are not measures that are considered to be calculated in accordance with GAAP. EBIT is a non-GAAP measure that includes operating income, other income and expenses and minority interest. 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 level. Operating margin is also a non-GAAP measure that is calculated as operating revenues minus cost of gas, which excludes operation and maintenance expense, depreciation and amortization, taxes other than income taxes, and the gain or loss on the sale of our assets; these items are included in our calculation of operating income as reflected in our condensed consolidated statements of income. EBIT is also a non-GAAP measure that includes operating income, 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 level.

We believe operating margin is a better indicator than operating revenues for the contribution resulting from customer growth in our distribution operations segment since the cost of gas can vary significantly and is generally passedbilled directly to our customers. We also consider operating margin to be a better indicator in our retail energy operations, wholesale services and energy investments segments since it is a direct measure of gross profitoperating margin 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 or EBIT measures may not be comparable to similarly titled measures from other companies.

Glossary of Key Terms
27
Table of Contents
Seasonality The operating revenues and EBIT of our distribution operations, retail energy operations and wholesale services segments are seasonal. During the heating season, natural gas usage and operating revenues are generally higher because more customers are connected to our distribution systems and natural gas usage is higher in periods of colder weather than in periods of warmer weather. Occasionally in the summer, Sequent’s operating margins are impacted due to peak usage by power generators in response to summer energy demands. Our base operating expenses, excluding cost of gas, interest expense and certain incentive compensation costs, are incurred relatively equally over any given year. Thus, our operating results vary significantly from quarter to quarter as a result of seasonality.

Seasonality also affects the comparison of certain balance sheetstatement of financial position items, such as receivables, inventories and short-term debt across quarters. However, these items are comparable when reviewing our annual results. Accordingly, we have presented the condensed consolidated balance sheetsstatement of financial position as of September 30, 2007,March 31, 2008, to provide comparisons of these items to December 31, 2007,2008, and September 30, 2008.March 31, 2009.

Hedging Changes in commodity prices subject a significant portion of our operations to earnings variability. Our nonutility businesses principally use physical and financial arrangements economically to hedge the risks associated with seasonal fluctuations in market conditions, changing commodity prices and weather. In addition, because these economic hedges may not qualify, or are not designated, for hedge accounting treatment, our reported earnings for the wholesale services and retail energy operations segments include the changes in the fair values of certain derivatives. These values may change significantly from period to period and are reflected as mark-to-marketfair value adjustments within our operating margin.

Elizabethtown Gas utilizes certain derivatives in accordance with a directive from the New Jersey Commission to create a hedging program to hedge the impact of market fluctuations in natural gas prices. These derivative products are accounted for at fair value each reporting period. In accordance with regulatory requirements, realized gains and losses related to these derivatives are reflected in purchaseddeferred natural gas costs and ultimately included in billings to customers. Unrealized gains and losses are reflected as a regulatory asset or liability, as appropriate, in our condensed consolidated balance sheets.

financial position.
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The following table sets forth a reconciliation of our operating margin and EBIT to our operating income, earnings before income taxes and net income attributable to AGL Resources Inc., together with other consolidated financial information for the three and nine months ended September 30, 2008March 31, 2009 and 2007.2008.

  Three months ended September 30,Nine months ended September 30, 
 In millions, except per share data 2008  2007  Change  2008  2007  Change 
Operating revenues $539  $369  $170  $1,995  $1,809  $186 
Cost of gas  261   159   102   1,193   987   206 
Operating margin (1)
  278   210   68   802   822   (20)
Operating expenses  152   155   (3)  482   473   9 
Operating income  126   55   71   320   349   (29)
Other income  2   -   2   6   1   5 
Minority interest  5   -   5   (12)  (24)  12 
EBIT (1)
  133   55   78   314   326   (12)
Interest expense, net  29   34   (5)  85   92   (7)
Earnings before income taxes  104   21   83   229   234   (5)
Income tax expense  39   8   31   86   89   (3)
Net income $65  $ 13  $ 52  $ 143  $ 145  $ (2)
                         
Earnings per common share                        
Basic $0.85  $0.17  $0.68  $1.87  $1.88  $(0.01)
Diluted $0.85  $0.17  $0.68  $1.87  $1.87  $- 
Weighted-average number of common shares outstanding                        
Basic�� 76.4   77.0   (0.6)  76.2   77.4   (1.2)
Diluted  76.6   77.4   (0.8)  76.5   77.8   (1.3)
  Three months ended March 31,    
In millions, except per share data 2009  2008  Change 
Operating revenues $995  $1,012  $(17)
Cost of gas  589   657   (68)
Operating margin (1)
  406   355   51 
Operating expenses  176   167   9 
Operating income  230   188   42 
Other income  2   1   1 
EBIT (1)
  232   189   43 
Interest expense, net  25   30   (5)
Earnings before income taxes  207   159   48 
Income tax expense  72   54   18 
Net income  135   105   30 
Net income attributable to the noncontrolling interest  16   16   - 
Net income attributable to AGL Resources Inc. $119  $89  $30 
             
Earnings per common share            
Basic – attributable to AGL Resources Inc. common shareholders $1.55  $1.17  $0.38 
Diluted – attributable to AGL Resources Inc. common shareholders $1.55  $1.16  $0.39 
Weighted-average number of common shares outstanding            
Basic  76.7   76.0   0.7 
Diluted  76.8   76.3   0.5 
(1)  These are non-GAAP measurements.


Selected weather, customer and volume metrics, which we consider to be some of the key performance indicators for our operating segments, for the three and nine months ended September 30,March 31, 2009 and 2008, and 2007, are presented in the following tables. We measure the effects of weather on our business through heating degree days. Generally, increased heating degree days result in greater demand for gas on our distribution systems. However, extended and unusually mild weather during the heating season can have a significant negative impact on demand for natural gas. Our marketing and customer retention initiatives are measured by our customer metrics which can be impacted by natural gas prices, economic conditions and competition from alternative fuels. Volume metrics for distribution operations and retail energy operations present the effects of weather and our customer’scustomers’ demand for natural gas. Wholesale services’ daily physical sales represent the daily average natural gas volumes sold to its customers.

Weather              
Heating degree days (1)            
  
Nine months ended
September 30,
  2008 vs. normal colder  2008 vs. 2007 colder  
  Normal  2008  2007  (warmer)  (warmer)  
Florida  336   215   281   (36)%  (23)%
Georgia  1,587   1,654   1,489   4%  11%
Maryland  3,032   2,828   3,063   (7)%  (8)%
New Jersey  3,031   2,918   3,172   (4)%  (8)%
Tennessee  1,807   1,888   1,753   4%  8%
Virginia  2,052   1,880   2,090   (8)%  (10)%
(1)Obtained from weather stations relevant to our service areas at the National Oceanic and Atmospheric Administration, National Climatic Data Center. Normal represents ten-year averages from October 1999 through September 2008.
Weather             
Heating degree days (1)           
  Three months ended Mar. 31,  2009 vs. normal colder  2009 vs. 2008 colder 
  Normal  2009  2008  (warmer)  (warmer) 
Florida  332   369   197   11%  87%
Georgia  1,441   1,434   1,510   -   (5)%
Maryland  2,510   2,612   2,339   4%  12%
New Jersey  2,527   2,627   2,422   4%  8%
Tennessee  1,640   1,664   1,721   1%  (3)%
Virginia  1,800   1,988   1,601   10%  24%
(1) Obtained from weather stations relevant to our service areas at the National Oceanic and Atmospheric Administration, National Climatic Data Center. Normal represents ten-year averages from April 2000 through March 2009.
 
 
  Three months ended       Nine months ended     
Customers September 30,      September 30,     
   2008   2007  % Change   2008   2007  % Change 
Distribution Operations                        
Average end-use customers
  (in thousands)
                        
 Atlanta Gas Light  1,536   1,539   (0.2)%  1,564   1,564   - 
 Chattanooga Gas  60   60   -   61   61   - 
 Elizabethtown Gas  272   271   0.4%  273   272   0.4%
 Elkton Gas  6   6   -   6   6   - 
 Florida City Gas  103   104   (1.0)%  104   104   - 
 Virginia Natural Gas  268   265   1.1.%  271   269   0.7%
Total  2,245   2,245   -   2,279   2,276   0.1%
Operation and maintenance per customer $32  $35   (9)% $106  $110   (4)%
EBIT per customer $26  $24   8% $105  $106   (1)%
                         
Retail Energy Operations                        
Average customers in Georgia (in thousands)
  518   535   (3)%  529   543   (3)%
Market share in Georgia  34%  35%  (1)%  35%  35%  - 
      
Customers Three months ended March 31,   
  2009  2008  % change 
Distribution Operations         
Average end-use customers (in thousands)
         
Atlanta Gas Light  1,577   1,582   (0.3)%
Chattanooga Gas  63   63   - 
Elizabethtown Gas  275   274   0.4% 
Elkton Gas  6   6   - 
Florida City Gas  103   104   (1.0)% 
Virginia Natural Gas  276   274   0.7 
Total  2,300   2,303   (0.1)%
Operation and maintenance expenses per customer $36  $37   (3)%
EBIT per customer $57  $53   8%
             
Retail Energy Operations            
Average customers in Georgia (in thousands)
  518   536   (3)%
Market share in Georgia  34%  35%  (3 )%
 
       
Volumes Three months ended March 31,    
In billion cubic feet (Bcf) 2009  2008  % change 
Distribution Operations         
Firm  99   98   1%
Interruptible  26   29   (10)%
 Total  125   127   (2)%
             
Retail Energy Operations            
Georgia firm  18   19   (5)%
Ohio and Florida  5   2   150%
             
Wholesale Services            
Daily physical sales (Bcf/day)  3.1   2.7   15%
 

Volumes Three months ended September 30,     Nine months ended September 30,    
In billion cubic feet (Bcf) 2008  2007  % change  2008  2007  % change 
Distribution Operations                  
Firm  20.0   20.1   (1)%  146.8   148.9   (1)%
Interruptible  24.1   25.1   (4)%  78.1   80.9   (3)%
 Total  44.1   45.2   (2)%  224.9   229.8   (2)%
                         
Retail Energy Operations                        
Georgia firm  3.5   3.5   -   27.0   27.1   - 
Ohio and Florida  0.3   0.3   -   3.3   3.1   6%
                         
Wholesale Services                        
Daily physical sales (Bcf/day)  2.6   2.3   13%  2.5   2.3   9%


2729

ThirdFirst quarter 20082009 compared to thirdfirst quarter 20072008

Segment information Operating revenues, operating margin, operating expenses and EBIT information for each of our segments are contained in the following table for the three months ended September 30, 2008March 31, 2009 and 2007.2008.

In millions  Operating revenues  Operating margin (1)  Operating expenses  EBIT(1) 
2008            
Distribution operations $272  $171  $113  $59 
Retail energy operations  149   (5)  16   (16)
Wholesale services  138   101   15   86 
Energy investments  13   10   7   3 
Corporate (2)
  (33)  1   1   1 
Consolidated $539  $278  $152  $133 
In millions Operating revenues  Operating margin (1)  Operating expenses  EBIT(1) 
2009            
Distribution operations $607  $252  $124  $130 
Retail energy operations  343   84   21   63 
Wholesale services  68   59   21   38 
Energy investments  10   10   8   2 
Corporate (2)
  (33)  1   2   (1)
Consolidated $995  $406  $176  $232 

In millions Operating revenues  Operating margin (1)  Operating expenses  EBIT(1) 
2007            
Distribution operations $256  $173  $118  $55 
Retail energy operations  128   16   18   (1)
Wholesale services  13   12   11   1 
Energy investments  9   9   6   3 
Corporate (2)
  (37)  -   2   (3)
Consolidated $369  $210  $155  $55 
In millions Operating revenues  Operating margin (1)  Operating expenses  EBIT(1) 
2008            
Distribution operations $676  $248  $126  $123 
Retail energy operations  375   82   20   62 
Wholesale services  17   15   14   1 
Energy investments  11   11   6   5 
Corporate (2)
  (67)  (1)  1   (2)
Consolidated $1,012  $355  $167  $189 
(1)  
These are non-GAAP measures. A reconciliation of operating margin and EBIT to our
operating income, (loss) earnings before income taxes and net income attributable to AGL Resources Inc.
is located in “Results of Operations” herein.
(2)  Includes intercompany eliminations.

For the thirdfirst quarter of 2008,2009, net income attributable to AGL Resources Inc. increased by $52$30 million and earnings per share attributable to AGL Resources Inc. increased by $0.68$0.38 per basic and $0.39 per diluted share compared to the same period last year. The variance between the two quarters was primarily the result of the effects of changes in forward natural gas prices on thehigher operating margins at retail energy operations and wholesale services as discussed in more detail below.offset by higher operating expenses largely a result of higher incentive compensation costs due to higher earnings

Operating margin Our operating margin for the thirdfirst quarter of 20082009 increased by $68$51 million or 32%14% compared to the same period last year. This increase was primarily due to increased operating margins at wholesale services, and energy investments partially offsetsupplemented by decreasedhigher operating margins atin the distribution operations and retail energy operations.operations segments.

Distribution operations’ operating margin decreasedincreased by $2$4 million or 1%2% compared to last year. The following table indicates the significant changes in distribution operations’ operating margin for the three months ended September 30, 2008March 31, 2009 compared to 2007.2008.

In millions   
Operating margin for third quarter of 2007 $173 
Reduced customer growth and usage  (3)
Higher PRP revenues at Atlanta Gas Light  2 
Other  (1)
Operating margin for third quarter of 2008 $171 
In millions   
Operating margin for first quarter of 2008 $248 
Increased margins from gas storage carrying amounts at Atlanta Gas Light  3 
Higher PRP revenues at Atlanta Gas Light  2 
Reduced customer growth and usage  (1)
Operating margin for first quarter of 2009 $252 

Retail energy operations’ operating margin decreasedincreased by $21$2 million or 131%2%. The following table indicates the significant changes in retail energy operations’ operating margin for the three months ended September 30, 2008March 31, 2009 compared to 2007.2008.


In millions   
Operating margin for third quarter of 2007 $16 
Inventory LOCOM  (18)
Decrease in average number of customers and other  (2)
Lower operating margins in Ohio  (1)
Operating margin for third quarter of 2008 $(5)
In millions   
Operating margin for first quarter of 2008 $82 
Higher contributions from the management of storage and transportation assets largely due to declining commodity prices in 2009  13 
2008 pricing settlement with Georgia Commission  3 
Higher operating margins in Ohio and Florida  3 
Average customer usage  1 
Change in retail pricing plan mix and decrease in average number of customers  (12)
Inventory LOCOM  (6)
Operating margin for first quarter of 2009 $84 

Wholesale services’ operating margin increased $89$44 million compared to the thirdfirst quarter of 20072008 primarily due to gains on the instruments used toa $47 million increase in reported hedge its storage and transportation positionsgains as a result of a significant decreasedecreases in forward NYMEX natural gas prices and the narrowing of transportation basis spreads in the current period compared to moderate price declines experiencedrising natural gas prices and expanding transportation basis spreads in 2007.2008. In addition, commercial activity increased $5 million due to higher volatility in the marketplace primarily associated with colder temperatures at the beginning of the period. These gainsincreases were partially offset by a larger requiredan $8 million LOCOM adjustment in the current period. The following table indicates the significant changes in wholesale services’ operating margin for the three months ended September 30, 2008March 31, 2009 and 2007.2008.

In millions 2008  2007 
Gain on storage hedges $105  $12 
Commercial activity  18   2 
Gain (loss) on transportation hedges  12   (1)
Inventory LOCOM, net of hedging recoveries  (34)  (1)
Operating margin $101  $12 
In millions 2009  2008 
Commercial activity $35  $30 
Gain (loss) on transportation hedges  24   (4)
Gain (loss) on storage hedges  8   (11)
Inventory LOCOM  (8)  - 
Operating margin $59  $15 

For more information on Sequent’s expected operating revenues from its storage inventory in the remainder of 20082009 and in 20092010 and discussion of the increased commercial activity as compared to last year, see the description of wholesale services’ business in this section beginning on page 21.25.


Operating Expenses Our operating expenses for the thirdfirst quarter of 2008 decreased $32009 increased $9 million or 2%5% as compared to the thirdfirst quarter of 2007.2008. The following table indicates the significant changes in our operating expenses.


In millions    
Operating expenses for third quarter of 2007 $155 
Increased bad debt expenses at distribution operations due to higher natural gas prices  3 
Decreased pension expenses at distribution operations, primarily due to updated actuarial expense estimates  (4)
Decreased incentive compensation program expenses at distribution operations  (3)
Increased incentive compensation costs at wholesale services due to increased earnings  3 
Decreased operating costs at retail energy operations due to slightly lower outside services and marketing costs  (2) 
Operating expenses for third quarter of 2008 $152 
In millions    
Operating expenses for first quarter of 2008 $167 
Increased incentive compensation costs at wholesale services and retail energy operations due to increased earnings  7 
Increased bad debt expense at distribution operations  1 
Increased depreciation expense at distribution operations and energy investments  2 
Increased legal expenses related to Jefferson Island litigation  1 
Other  2 
Decreased outside services, marketing and other expenses at distribution operations  (4)
Operating expenses for first quarter of 2009 $176 


28
Interest Expense Interest expense decreased by $5 million or 15%17% for the three months ended September 30, 2008,March 31, 2009, primarily due to the decrease in short-term interest rates partially offset by higher average debt outstanding as indicated in the following table.

  Three months ended September 30, 
In millions 2008  2007  Change 
Average debt outstanding (1) $2,225  $1,997  $228 
Average rate  5.2%  6.2%  (1.0)%

(1) Daily average of all outstanding debt.

Nine months 2008 compared to nine months 2007

Segment information Operating revenues, operating margin, operating expenses and EBIT information for each of our segments are contained in the following table for the nine months ended September 30, 2008 and 2007.

In millions Operating revenues   Operating margin (1)  Operating expenses  EBIT(1) 
2008            
Distribution operations $1,293  $599  $362  $239 
Retail energy operations  701   101   54   35 
Wholesale services ��104   63   41   22 
Energy investments  43   39   21   18 
Corporate (2)
  (146)  -   4   - 
Consolidated $1,995  $802  $482  $314 

In millions Operating revenues  Operating margin (1)  Operating expenses  EBIT(1) 
2007            
Distribution operations $1,216  $604  $364  $242 
Retail energy operations  653   145   55   67 
Wholesale services  50   46   30   16 
Energy investments  27   27   19   7 
Corporate (2)
  (137)  -   5   (6)
Consolidated $1,809  $822  $473  $326 
 (1)   These are non-GAAP measures. A reconciliation of operating margin and EBIT to our operating income, earnings before income taxes and net income is located in “Results of Operations” herein.
(2)   Includes intercompany eliminations.

For the nine months ended September 30, 2008, net income decreased by $2 million and basic earnings per share was down $0.01 compared to the same period last year. This variance was primarily the result of changes in forward natural gas prices on the operating margins at retail energy operations and wholesale services and reduced natural gas usage at distribution operations and retail energy operations as discussed in more detail below.

Operating margin Our operating margin for the nine months ended September 30, 2008, decreased by $20 million or 2% compared to the same period last year. This decrease was primarily due to decreased operating margins at retail energy operations and distribution operations partially offset by increased operating margins at wholesale services and energy investments.

Distribution operations’ operating margin decreased by $5 million or 1% compared to the same period last year. The following table indicates the significant changes in distribution operations’ operating margin for the nine months ended September 30, 2008 compared to 2007.

In millions   
Operating margin for the first nine months of 2007 $604 
Customer growth and lower natural gas usage  (4)
Revision in estimated unbilled natural gas volumes at Elizabethtown Gas  (3)
Lower natural gas storage carrying costs at Atlanta Gas Light  (2)
Higher PRP revenues at Atlanta Gas Light  4 
Operating margin for the first nine months of 2008 $599 

Retail energy operations’ operating margin decreased by $44 million or 30%. The following table indicates the significant changes in retail energy operations’ operating margin for the nine months ended September 30, 2008 compared to 2007.

In millions   
Operating margin for the first nine months of 2007 $145 
Lower contributions from the management of storage and transportation assets largely due to rising commodity prices in 2008  (15)
Inventory LOCOM adjustment  (18)
Retail pricing settlement with Georgia Commission  (3)
Colder weather  5 
Lower number of customers and usage  (3)
Ohio and Florida margins  (2)
Loss on weather derivatives  (7)
Other  (1)
Operating margin for the first nine months of 2008 $101 

Wholesale services’ operating margin increased $17 million or 37% compared to the first nine months of 2007 primarily due to stronger commercial activity and gains on the instruments used to hedge its storage positions resulting from falling natural gas prices. These gains were partially offset by a $34 million LOCOM adjustment in the current period as compared to a $2 million LOCOM adjustment (net of hedging recoveries) last year. The following table indicates the significant changes in wholesale services’ operating margin for the nine months ended September 30, 2008 and 2007.
In millions 2008  2007 
Commercial activity $50  $31 
Gain on storage hedges  46   15 
Gain on transportation hedges  1   2 
Inventory LOCOM, net of hedging recoveries  (34)  (2)
Operating margin $63  $46 

The increase of $30 million in gains associated with storage and transportation hedge positions was primarily due to larger decreases in forward NYMEX prices during the current period compared to those experienced in 2007. For more information on Sequent’s expected operating revenues from its storage inventory in the remainder of 2008 and in 2009 and discussion of the increased commercial activity as compared to last year, see the description of wholesale services’ business in this section beginning on page 21.

Glossary of Terms
29
Energy investments’ operating margin increased $12 million or 44% primarily due to higher operating margins at AGL Networks of $10 million due to a network expansion project and $2 million at Jefferson Island as a result of increased interruptible operating margins.

Operating Expenses Our operating expenses for the nine months ended September 30, 2008, increased $9 million or 2% as compared to the same period of 2007. The following table indicates the significant changes in our operating expenses.
In millions    
Operating expenses for the first nine months of 2007 $473 
Increased operating costs at wholesale services due to continued commercial expansion and incentive compensation costs associated with earnings  11 
Increased depreciation expenses at distribution operations due to PP&E placed into service  5 
Increased bad debt expenses primarily at Elizabethtown Gas and Virginia Natural Gas in distribution operations due to higher natural gas prices and decline in the economy  5 
Increased bad debt expenses at retail energy operations due to higher natural gas prices  2 
Increased operating costs due to AGL Networks expansion project  2 
Decreased operating costs at retail energy operations due to lower compensation, marketing, outside services and other costs  (3)
Decreased operating costs at distribution operations due to lower costs related to benefits and incentives, marketing, customer service and outside services offset by higher fuel costs and property taxes  (8)
Decreased pension expenses at distribution operations primarily due to updated actuarial expense estimate  (4)
Lower corporate costs  (1)
Operating expenses for the first nine months of 2008 $482 

Interest Expense The decrease in interest expense of $7 million or 8% for the nine months ended September 30, 2008, was primarily due to the decrease in short-term interest rates partially offset by higher average debt outstanding as indicated in the following table.

 Nine months ended September 30,  Three months ended March 31, 
In millions 2008  2007  Change  2009  2008  Change 
Average debt outstanding (1) $2,046  $1,899  $147  $2,333  $2,098  $235 
Average rate  5.5%  6.2%  (0.7)%  4.3%  5.7%  (1.4)%

(1) Daily average of all outstanding debt.

Liquidity and Capital Resources

Our primary sources of liquidity are cash provided by operating activities, short termshort-term borrowings under our commercial paper program (which is supported by our Credit Facilities) and borrowings under subsidiary lines of credit. Additionally, from time to time, we raise funds from the public debt and equity capital markets through our existing shelf registration statement to fund our liquidity and capital resource needs. We believe these sources will continue to allow us to meet our needs for working capital, construction expenditures, anticipated debt redemptions, interest payments on debt obligations, dividend payments, common share repurchases and other cash needs.

Our issuance of various securities, including long-term and short-term debt, is subject to customary approval or authorization by, or filings with, state and federal regulatory bodies including state public service commissions, the SEC and the SEC.FERC. Furthermore, a substantial portion of our consolidated assets, earnings and cash flow 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.

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,” of our Annual Report on Form 10-K for the year ended December 31, 2007,2008, for additional information on items that could impact our liquidity and capital resource requirements. The following table provides a summary of our operating, investing and financing activities.

  Nine months ended Sept. 30, 
In millions 2008  2007 
Net cash provided by (used in):      
Operating activities $172  $386 
Investing activities  (254)  (191)
Financing activities  74   (198)
Net decrease in cash and cash equivalents $(8) $(3)
  Three months ended Mar. 31, 
In millions 2009  2008 
Net cash provided by (used in):      
Operating activities $611  $511 
Investing activities  (97)  (80)
Financing activities  (509)  (430)
Net increase in cash and cash equivalents $5  $1 

Cash Flow from Operating Activities In the first ninethree months of 2008,2009, our net cash flow provided from operating activities was $172$611 million, a decreasean increase of $214$100 million or 55%20% from the same period in 2007.2008. This was primarily a result of a larger decrease in inventory in 2009 than 2008, primarily related to the higher cost of inventory sold in 2009. This was partially offset by increased working capitalcash collateral requirements principally driven by risingfor our derivative financial instrument activities due to the change in hedge values due to the downward shift in the forward NYMEX curve prices in 2009.

The downward shift in the forward curve results in unrealized losses on the hedging instruments, comprised primarily of exchange traded derivatives, associated with anticipated natural gas prices during the first halfpurchases. We maintain accounts with brokers to facilitate financial derivative transactions in support of 2008. In addition, as a result of the increase in natural gas prices, our margin requirements for our energy marketing and risk management activities were higher thanactivities. Based on the value of our positions in these accounts and the associated margin requirements, we may be required to deposit cash into these broker accounts. These unrealized losses are substantially offset by gains on derivative financial instruments utilized to hedge the price risk associated with the anticipated sale of these natural gas purchases. The anticipated economics of these transactions will ultimately be realized in the prior year which included approximately $114 million of cash received upon settlement of derivative positions versus $58 million inperiod when the current period.natural gas is bought and sold.

Cash Flow from Investing Activities Our investing activities consisted of PP&E expenditures of $254$97 million for the ninethree months ended September 30, 2008March 31, 2009 and $193$80 million for the same period in 2007.2008. The increase of $61$17 million or 32%21% in PP&E expenditures was primarily due to a $51$10 million increase at distribution operations, which included higher spending for the pipeline replacement program and expenditures for Virginia Natural Gas’ Hampton Roads Crossing pipeline project connecting its northern and southern systems.

Additionally, our retail energy operations’ PP&E expenditures increased $4 million as a result of its purchase of information technology assets in support of its transition to a new customer care and call center vendor. Our energy investments’ PP&E expenditures increased $26$12 million primarily from increased expenditures at Golden Triangle Storage as we began construction on our planned natural gas storage facility and from increasedpartially offset by decreased telecommunication expenditures at AGL Networks onwhich expanded its Phoenix network expansion.in 2008. These PP&E expenditure increases were partially offset by decreased expenditures at our corporate segmentretail energy operations’ of $19$6 million primarily due to decreased spending primarily on information technology.technology assets compared to 2008, when the segment transitioned to a new customer care and call center vendor.

Cash Flow from Financing Activities Our financing activities are primarily composed of borrowings and payments of short-term debt, payments of medium-term notes, borrowingsissuances of senior notes, distributions to minoritynoncontrolling interests, cash dividends on our common stock, issuances, and purchases and issuances of treasury shares. Our capitalization and financing strategy is intended to ensure that we are properly capitalized with the appropriate mix of equity and debt securities. 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-rate debt target is 20% to 45% of total debt), as well as the term and interest rate profile of our debt securities. As of September 30, 2008,March 31, 2009, our variable-rate debt was 38%27% of our total debt, compared to 39%20% as of September 30, 2007.March 31, 2008. We may issue additional long-term debt in 2009 in consideration of our working capital needs and capital expenditure plans to maintain an appropriate mix.

We also work to maintain or improve our credit ratings to manage our existing financing costs effectively and enhance our ability to raise additional capital on favorable terms. Factors we consider important in assessing our credit ratings include our balance sheetstatements of financial position leverage, capital spending, earnings, cash flow generation, available liquidity and overall business risks. We do not have any trigger 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, 2008,March 31, 2009, and reflects no change from December 31, 2007.2008.

  S&P  Moody’s  Fitch 
Corporate rating  A-       
Commercial paper  A-2  P-2   F-2 
Senior unsecured BBB+  Baa1   A- 
Ratings outlook Stable  Stable  Stable 

A credit rating is not a recommendation to buy, sell or hold securities. The highest investment grade credit rating for S&P is AAA, Moody’s is Aaa and Fitch is AAA. The lowest investment grade credit rating for S&P is BBB-, Moody’s is Baa3 and Fitch is BBB-. Our credit ratings may be subject to revision or withdrawal at any time by the assigning rating organization, and each rating should be evaluated independently of any other rating. We cannot ensure 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. If the rating agencies downgrade our ratings, particularly below investment grade, it may significantly limit our access to the commercial paper market and our borrowing costs would increase. 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 would decrease.

Default events Our debt instruments and other financial obligations include provisions that, if not complied with, could require early payment, additional collateral support or similar actions. Our most important default events include maintaining covenants with respect to a maximum leverage ratio, insolvency events, nonpayment of scheduled principal or interest payments, and acceleration of other financial obligations and change of control provisions.

Our Credit Facility’sFacilities have financial covenant requirescovenants that require us to maintain a ratio of total debt to total capitalization of no greater than 70%; however, our goal is to maintain this ratio at levels between 50% and 60%. Our ratio of total debt to total capitalization calculation contained in our debt covenant includes minoritynoncontrolling interest, standby letters of credit, surety bonds and the exclusion of other comprehensive income pension adjustments. If these items were included, ourOur debt-to-equity calculation, would increaseas defined by 1-2%.our Credit Facilities was 53% at March 31, 2009 and 59% at December 31, 2008 and 52% at March 31, 2008. These amounts are within our required and targeted ranges. Our debt and equity capitalization ratios, as of the dates indicated, are summarized in the following table.

  Sept. 30, 2008  Dec. 31, 2007  Sept. 30, 2007 
Short-term debt  19%  15%  15%
Long-term debt  40   43   42 
Total debt  59   58   57 
Common shareholders’ equity  41   42   43 
Total capitalization  100%  100%  100%
  Mar. 31, 2009  Dec. 31, 2008  Mar. 31, 2008 
Short-term debt  10%  20%  10%
Long-term debt  44   40   42 
Total debt  54   60   52 
Equity  46   40   48 
Total capitalization  100%  100%  100%

We believe that accomplishing our capitalization objectives and maintaining sufficient cash flow are necessary to maintain our investment-grade credit ratings and to allow us access to capital at reasonable costs. We currently comply with all existing debt provisions and covenants. For more information on our debt, see Note 56 “Debt.“Debt.”

Short-term debt Our short-term debt is composed of borrowings and payments under our Credit Facilities and commercial paper program, Credit Facilities, lines of credit at Sequent, SouthStar and Pivotal Utility, and the current portion of our capital leases. In June 2008, we extended one of Sequent’s lines of credit to June 2009. In September 2008, Sequent obtained a second line of credit for $20 million that bears interest at the LIBOR Rate plus 1.0% to September 2009. This line of credit replaced the line of credit that expired in August 2008. Both lines of credit are used for the posting of margin deposits for NYMEX transactions and are unconditionally guaranteed by us.

In September 2008, we completed a $140 million Credit Facility that expires in September 2009, which will provide additional liquidity for working capital and capital expenditure needs. This $140 million Credit Facility allows for the option to request an increase in the borrowing capacity to $150 million and supplements our existing $1.0 billion Credit Facility which expires in August 2011. More information on our short-term debt as of September 30, 2008, which we consider one of our primary sources of liquidity, is presented in the following table:

In millions Capacity  Outstanding 
Credit Facilities (1)
 $1,140  $683 
SouthStar line of credit  75   55 
Sequent lines of credit  45   20 
Pivotal Utility line of credit  20   10 
Total $1,280  $768 
(1)  
Supported by our $1.0 billion and $140 million Credit Facilities, and
includes $198 million of commercial paper borrowings.

Our short-term debt financing generally increases between June and December because our payments for natural gas and pipeline capacity are generally made to suppliers prior to the collection of accounts receivable from our customers. We typically reduce short-term debt balances in the spring because a significant portion of our current assets are converted into cash at the end of the heating season. As

Excluding the current portions of gas facility revenue bonds of $114 million that we refinanced in 2008, our outstanding short-term borrowings, as of March 31, 2009, increased by $193$148 million or 34% as58% compared to the same timeperiod last year,year. This was primarily a result of increased working capital$178 million increase in our margin requirements primarily for our energy marketing and risk management activities compared to the higher costprior year. More information on our short-term debt as of natural gas inventories and increased PP&E expendituresMarch 31, 2009, which we consider one of $61 million.our primary sources of liquidity, is presented in the following table:

In millions Capacity  Outstanding 
Credit Facilities (1)
 $1,140  $335 
SouthStar line of credit  75   45 
Sequent lines of credit  30   22 
Total $1,245  $402 
(1)  Supported by our $1.0 billion and $140 million Credit Facilities, and includes $335 million of commercial paper borrowings.

As of September 30,March 31, 2009 and March 31, 2008 we had $485 million outstanding under our $1.0 billion Credit Facility. In the third quarter 2008 due to disruption in the credit markets, we were unable to issue commercial paper at acceptable interest rates and relied upon our Credit Facility for our liquidity and capital resource needs. We expect to repay the amounts outstanding under our Credit Facility with commercial paper borrowings. As of September 30, 2007 and December 31, 2007, we had no outstanding borrowings under our Credit Facilities. As of December 31, 2008, we had $500 million of outstanding borrowings under the Credit Facility. Our exposureFacilities. These unsecured promissory notes are supported by our $1 billion Credit Facility which expires in August 2011 and a supplemental $140 million Credit Facility that expires in September 2009. We have the option to financial institutions that experienced difficulty during the disruptionrequest an increase in the credit markets was limited.

aggregate principal amount available for borrowing under the $1 billion Credit Facility to $1.25 billion on not more than three occasions during each calendar year. The availability of borrowings and unused availability under our$140 million Credit Facilities is limited and subjectFacility allows for the option to conditions specified withinrequest an increase in the Credit Facilities, which we currently meet. These conditions include:

·  the maintenance of a ratio of total debt to total capitalization of no greater than 70%; however, our goal is to maintain this ratio at levels between 50% and 60%. As of September 30, 2008, our ratio of total debt of 59% to total capitalization was within our targeted and required ranges
·  the continued accuracy of representations and warranties contained in the agreement
borrowing capacity to $150 million.

Long-term debt Our long-term debt matures more than one year from the balance sheet date of our statements of financial position and consists of medium-term notes, senior notes, gas facility revenue bonds, and capital leases.

In 2008, a portion of our gas facility revenue bonds failed to draw enough potential buyers due to the dislocation or disruption in the auction markets as a result of the downgrades to the bond insurers which reduced investor demand and liquidity for these types of investments. Three of these bonds with principal amounts of $55 million, $47 million and $20 million had interest rates that were adjusted every 35-days, and one of the bonds with a principal amount of $39 million had an interest rate which was reset daily. In March and April 2008, we tendered these bonds with a cumulative principal amount of $161 million through commercial paper borrowings.

In June and September 2008, we completed Letter of Credit Agreements for these bonds which provided credit support and enhanced investor demand. As a result, these bonds were successfully issued as variable rate gas facility revenue bonds and reduced our commercial paper borrowings. The bonds with principal amounts of $55 million, $47 million and $39 million now have interest rates that reset daily and the bond with a principal amount of $20 million has an interest rate that resets weekly. There was no change to the maturity dates on these bonds. Currently, these bonds have potential buyers; however, should these bonds fail to draw buyers, we would be required to either draw on the Letter of Credit Agreements or tender these bonds with commercial paper. For more information on the maturity of the gas facility revenue bondsour long-term debt see Note 6 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2007.2008.

Share repurchases In February 2006, our Board of Directors authorized a plan to purchase up to 8 million shares of our outstanding common stock over a five-year period. For the nine months ended September 30, 2008, we did not purchase any shares of our common stock under this plan. During the same period in 2007, we purchased approximately 1.4 million shares of our common stock at a weighted average cost of $39.82 per share and an aggregate cost of $57 million. We hold the purchased shares as treasury shares.

Contractual Obligations and Commitments We have incurred various contractual obligations and financial commitments in the normal course of our operating and financing activities. 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 have incurred various financial commitments in the normal course of business. 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.

In recent months, declines in the investment markets have negatively impactedMarch 2009, we contributed $14 million to our pension plan assets. In orderplans. We expect to complymake additional contributions to our pension plans of $18 million in 2009 for a total of $32 million. We previously expected that our total required and additional contributions to our pension plans would be approximately $68 million to preserve the current levels of benefits under our pension plans and in accordance with the funding requirements fromof the Pension Protection ActAct. The reduction in our expected contributions are a result of 2006, we anticipate that we will be requireda notice from the Internal Revenue Service with respect to make a contributionproposed changes to our pension plan in 2009. The decline in investment values could also result in a charge to other comprehensive income for the increased difference between investment values and the pension liabilities at our next measurement date of December 31, 2008, as well as an increasefunding rules that resulted in the amountuse of pension expense we would recognize in 2009 and beyond. We are currently unable to determine these amounts since actual asset performance through the end of the year anda discount rate that was higher than the discount rate at year-end can significantly impactwe used in our previous estimate. Consequently, our pension liabilities as calculated under the determinationfunding rules were reduced and the 2009 funding requirements decreased to maintain current benefits levels.

The following tables illustratetable illustrates our expected future contractual obligationsobligation payments such as debt and lease agreements, and commitments and contingencies as of September 30, 2008.March 31, 2009.

        2009 &  2011 &  2013 & 
In millions Total  2008  2010  2012  thereafter 
Recorded contractual obligations:               
Long-term debt $1,675  $1  $3  $315  $1,356 
Short-term debt  769   769   -   -   - 
PRP costs (1)
  195   7   102   63   23 
Environmental remediation liabilities (1)
  105   3   34   39   29 
Total $2,744  $780  $139  $417  $1,408 

        2010 &   2012 &   2014 &  
In millions Total  2009  2011  2013  thereafter 
Recorded contractual obligations:               
                
Long-term debt $1,675  $-  $302  $240  $1,133 
Short-term debt  403   403   -   -   - 
PRP costs (1)
  169   43   78   48   - 
Environmental remediation liabilities (1)
  105   15   40   39   11 
  Total $2,352  $461  $420  $327  $1,144 
Unrecorded contractual obligations and commitments (2):
               
                
Pipeline charges, storage capacity and gas supply (3)
 $1,713  $420  $603  $332  $358 
Interest charges (4)
  933   70   166   135   562 
Operating leases  130   23   45   25   37 
Standby letters of credit, performance / surety bonds  51   45   6   -   - 
Asset management agreements (5)
  37   12   23   2   - 
  Total $2,864  $570  $843  $494  $957 
(1)  Includes charges recoverable through rate rider mechanisms.

        2009 &  2011 &  2013 & 
In millions Total  2008  2010  2012  thereafter 
Unrecorded contractual obligations and commitments (1):
               
Pipeline charges, storage capacity and gas supply (2)
 $1,751  $164  $736  $402  $449 
Interest charges (3)
  1,135   26   204   161   744 
Operating leases  136   7   50   34   45 
Standby letters of credit, performance / surety bonds  48   8   40   -   - 
Asset management agreements (4)
  43   3   24   16   - 
Total $3,113  $208  $1,054  $613  $1,238 

(1)(2)  In accordance with generally accepted accounting principles,GAAP, these items are not reflected in our condensed consolidated balance sheet.statements of financial position.
(2)(3)  Charges recoverable through a PGAnatural gas cost recovery mechanism or alternatively billed to Marketers.Marketers, and includes demand charges associated with Sequent. Also includes SouthStar’s gas commodity purchase commitments of 11.622 Bcf at floating gas prices calculated using forward natural gas prices as of September 30, 2008,March 31, 2009, and are valued at $90 million.  Additionally, includes amounts associated with a subsidiary of NUI which entered into two long-term20-year agreements for the firm transportation and storage of natural gas during 2003 with annual aggregate demand charges of approximately $5 million. As a result of our acquisition of NUI and in accordance with SFAS 141, we valued the contracts at fair value and established a long-term liability of $38 million for the excess liability. This excess liability is beingthat will be amortized to our condensed consolidated statements of income over the remaining lives of the contracts of $2 million annually through November 2023 and $1 million annually from November 2023 to November 2028.
(3)(4)  Floating rate debt is based on the interest rate as of September 30, 2008,March 31, 2009, and the maturity of the underlying debt instrument. As of September 30, 2008,March 31, 2009, we have $32$31 million of accrued interest on our condensed consolidated balance sheet.statements of financial position that will be paid in 2009.
    (4)(5)  Represent fixed-fee or guaranteed minimum payments for Sequent’s affiliated asset management agreements between its affiliated utilities.management.


Critical Accounting Policies and Estimates

The preparation of our financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures of contingent assets and liabilities. We base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. We evaluate our estimates on an ongoing basis, and our actual results may differ from these estimates. Our critical accounting policies used in the preparation of our condensed consolidated financial statements include the following:

·  Pipeline Replacement Program
·  Environmental Remediation Liabilities
·  Derivatives and Hedging Activities
·  Allowance for Uncollectible Accounts and other Contingencies
·  Pension and Other Postretirement Plans
·  Income Taxes

Each of our critical accounting policies and 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. There have been no significant changes to our critical accounting policies from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2007.2008.

Accounting Developments

Previously discussed

SFAS 160 In December 2007, the FASB issued SFAS 160 which is effective for fiscal years beginning after December 15, 2008. SFAS 160 will requirerequires us to present our minority interest, to be referred to as a noncontrolling interest, separately within the capitalization section of our condensed consolidated balance sheets.statements of financial position. We will adoptadopted SFAS 160 on January 1, 2009. More information on our adoption of SFAS 160 is discussed in Note 5.

SFAS 161 In March 2008, the FASB issued SFAS 161, which is effective for fiscal years beginning after November 15, 2008. SFAS 161 amends the disclosure requirements of SFAS 133 to provide an enhanced understanding of how and why derivative instruments are used, how they are accounted for and their effect on an entity’s financial condition, performance and cash flows. We will adoptadopted SFAS 161 on January 1, 2009 which will requireand provided the required additional disclosures, but will not have ait had no financial impact to our consolidated results of operations, cash flows or financial condition.More information on our adoption of SFAS 160 is discussed in Note 3.

FSP EITF 03-6-1 The FASB issued this FSP in June 2008 and is effective for fiscal years beginning after December 15, 2008. This FSP classifies unvested share-based payment grants containing nonforfeitable rights to dividends as participating securities that will be included inbecame effective on January 1, 2009 and provides guidance on the computation of earnings per share. Asshare when a company has unvested share awards outstanding that have the right to receive dividends. The effects of September 30, 2008, we had approximately 149,000 restricted shares with nonforfeitable dividend rights, which potentially could be included inthis FSP were immaterial to our basiccalculation of earnings per share calculation. We will adopt FSP EITF 03-6-1 on January 1, 2009.share.

Recently issued

FSP FAS 133-1 The FASB issued this FSP in September 2008 and it is effective for fiscal years beginning after November 15, 2008. This FSP requires more detailed disclosures about credit derivatives, including the potential adverse effects of changes in credit risk on the financial position, financial performance and cash flows of the sellers of the instruments. This FSP will havehad no financial impact to our consolidated results of operations, cash flows or financial condition. We will adoptadopted FSP FAS 133-1 on January 1, 2009.

Recently issued

FSP FAS 157-3132(R)-1 This FSP requires additional disclosures relating to postretirement benefit plan assets to provide transparency regarding the types of assets and the associated risks within the types of plan assets. The FASB issued thisrequired disclosures include:

·  How investment allocation decisions are made, including information that provides an understanding of investment policies and strategies,
·  The major categories of plan assets,
·  Inputs and valuation techniques used to measure the fair value of plan assets, including those measurements using significant unobservable inputs, on changes in plan assets for the period, and
·  Significant concentrations of risk within plan assets.

This FSP in October 2008 and it is effective upon issuance including prior periods for whichfiscal years ending after December 15, 2009 and requires additional disclosures in our notes to condensed consolidated financial statements, but will not have not been issued. This FSP clarifies the application of SFAS 157 in an inactive market, including; how internal assumptions should be considered when measuring fair value, how observable market information in a market that is not active should be considered and how the use of market quotes should be used when assessing observable and unobservable data. We adopted this FSP as of September 30, 2008, which had nomaterial impact on our financial impact to our consolidatedposition, results of operations or cash flows or financial condition.flows.

Item 3. Quantitative and Qualitative Disclosures
About Market Risk

We are exposed to risks associated with commodity prices, interest rates and credit. Commodity price risk is defined as the potential loss that we may incur as a result of changes in the fair value of natural gas. Interest rate risk results from 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 Risk Management Committee (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 commodity 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 treatments for our derivative financial instruments are described in further detail in Note 3.

Commodity Price Risk

Retail Energy Operations SouthStar’s use of derivativesderivative financial instruments is governed by a risk management policy, approved and monitored by its Finance and Risk and Asset Management Committee, which prohibits the use of derivatives for speculative purposes.

Energy marketing and risk management assets and liabilities SouthStar routinely utilizes various types of derivative financial and other instruments to mitigate certain commodity price and weather risk inherent in the natural gas industry. These instruments includeThis includes the active management of storage positions through a variety of exchange-tradedhedging transactions for the purpose of managing exposures arising from changing commodity prices. SouthStar uses these hedging instruments to lock in economic margins (as spreads between wholesale and OTC energy contracts, such as forward contracts, futures contracts, options contractsretail commodity prices widen between periods) and financial swap agreements.thereby minimize its exposure to declining operating margins.

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We have designated a portion of SouthStar’s derivative transactions as cash flow hedges in accordance with SFAS 133. We record derivative gains or losses arising from cash flow hedges in OCI and reclassify them into earnings in the same period as the underlying hedged item occurs and is recorded in earnings. We record any hedge ineffectiveness, defined as when the gains or losses on the hedging instrument do not offset and are greater than the losses or gains on the hedged item, in cost of gas in our condensed consolidated statement of income in the period in which the ineffectiveness occurs. SouthStar currently has minimal hedge ineffectiveness. We have not designated the remainder of SouthStar’s derivative instruments as hedges under SFAS 133 and, accordingly we record changes in their fair value in earnings in the period of change.

SouthStar experienced an increase of $2 million in the net fair value of derivative instruments utilized in its energy marketing and risk management activities in the first nine months of 2008 compared to $6 million decrease for the same period last year. The following tables illustrate the change in the net fair value of the derivative financial instruments and energy-trading contracts during the three and nine months ended September 30,March 31, 2009 and 2008, and 2007, and provide details of the net fair value of contractsderivative financial instruments outstanding as of September 30, 2008.March 31, 2009.

  Three months ended Sept. 30,
In millions 2008  2007 
Net fair value of contracts outstanding at beginning of period $8  $3 
Contracts realized or otherwise settled during period  6   6 
Change in net fair value of contracts  (2)  2 
Net fair value of contracts outstanding at end of period  12   11 
Netting of cash collateral  20   10 
Cash collateral and net fair value of contracts outstanding at end of period $32  $21 

  Three months ended Mar. 31, 
In millions 2009  2008 
Net fair value of derivative financial instruments outstanding at beginning of period $(17) $10 
Derivative financial instruments realized or otherwise settled during period  4   (7)
Change in net fair value of derivative financial instruments  (9)  3 
Net fair value of derivative financial instruments outstanding at end of period  (22)  6 
Netting of cash collateral  27   - 
Cash collateral and net fair value of derivative financial instruments outstanding at end of period $5  $6 
  Nine months ended Sept. 30, 
In millions 2008  2007 
Net fair value of contracts outstanding at beginning of period $10  $17 
Contracts realized or otherwise settled during period  (10)  (15)
Change in net fair value of contracts  12   9 
Net fair value of contracts outstanding at end of period  12   11 
Netting of cash collateral  20   10 
Cash collateral and net fair value of contracts outstanding at end of period $32  $21 

The sources of SouthStar’s net fair value of its commodity-related derivative financial instruments at September 30, 2008,March 31, 2009, are as follows:

In millions 
Prices actively quoted (1)
  Prices provided by other external sources 
Mature through 2008 $8  $(1)
Mature through 2009  4   - 
Mature through 2010  1   - 

In millions 
Prices actively quoted
(Level 1) (1)
  
Significant other observable inputs
(Level 2)
  
Significant unobservable inputs
(Level 3)
 
Mature through         
2009 $(28) $(1) $- 
2010  7   -   - 
Total derivative financial instruments (2)
 $(21) $(1) $- 
(1)  Valued using NYMEX futures prices.
(2)  Excludes cash collateral amounts.

The following tables include the cash collateral fair values and average values of SouthStar’s energy marketing and risk management assets and liabilitiesderivative financial instruments as of September 30, 2008, December 31, 2007 and September 30, 2007.the dates indicated. SouthStar bases the average values on monthly averages for the ninethree months ended September 30, 2008March 31, 2009 and 2007.2008.

  Average values at Sept. 30, 
In millions 2008  2007 
Asset (1)
 $13  $10 
Liability (1)
  5   4 
  
Derivative financial instruments
average fair values (1) at Mar. 31,
 
In millions 2009  2008 
Asset $11  $5 
Liability  35   1 

(1) Average values represent only the derivative instruments and excludes netting ofExcludes cash collateral amounts.

  Cash collateral and fair values at 
In millions 
Sept. 30,
2008
  
Dec. 31,
2007
  
Sept. 30,
2007
 
Asset $33  $13  $21 
Liability  1   -   - 
  Derivative financial instruments fair values netted with cash collateral at 
In millions 
Mar. 31,
2009
  
Dec. 31,
2008
  
Mar. 31,
2008
 
Asset $10  $16  $7 
Liability  5   2   1 

Value at Risk A 95% confidence interval is used to evaluate VaR exposure. A 95% confidence interval means that over the holding period, an actual loss in portfolio value is not expected to exceed the calculated VaR more than 5% of the time. We calculate VaR based on the variance-covariance technique. This technique requires several assumptions for the basis of the calculation, such as price distribution, price volatility, confidence interval and holding period. Our VaR may not be comparable to a similarly titled measure of another company because, although VaR is a common metric in the energy industry, there is no established industry standard for calculating VaR or for the assumptions underlying such calculations. SouthStar’s portfolio of positions for the three months ended September 30,March 31, 2009 and 2008 and 2007, had quarterly average 1-day holding period VaRs of less than $100,000 and its high, low and period end 1-day holding period VaR were immaterial.

Wholesale Services Sequent routinely utilizes various types of derivative financial and other instruments to mitigate certain commodity price risks inherent in the natural gas industry. These instruments include a variety of exchange-traded and OTC energy contracts, such as forward contracts, futures contracts, options contracts and financial swap agreements.

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Energy marketing and risk management assets and liabilities The following tables include the cash collateral, fair values and average values of Sequent’s energy marketing and risk management assets and liabilitiesderivative financial instruments as of September 30, 2008, December 31, 2007 and September 30, 2007.the dates indicated. Sequent bases the average values on monthly averages for the ninethree months ended September 30, 2008March 31, 2009 and 2007.2008.

  Average values at Sept. 30, 
In millions 2008  2007 
Asset (1)
 $72  $61 
Liability (1)
  48   17 
  
Derivative financial instruments average values (1) at Mar. 31,
 
In millions 2009  2008 
Asset $187  $42 
Liability  82   37 

(1) Average values represent only the derivative instruments and excludes netting of
(1)  Excludes cash collateral amounts.


  Cash collateral and fair values at 
In millions 
Sept. 30,
2008
  
Dec. 31,
2007
  
Sept. 30,
2007
 
Asset $140  $61  $68 
Liability  24   13   7 

At September 30, 2008, Sequent’s commodity-related derivative financial instruments represented purchases (long) of 708 Bcf and sales (short) of 697 Bcf, with approximately 90% and 94% scheduled to mature in less than two years and the remaining 10% and 6% in three to nine years, respectively.
  Derivative financial instruments fair values netted with cash collateral at 
In millions 
Mar. 31,
2009
  
Dec. 31,
2008
  
Mar. 31,
2008
 
Asset $211  $206  $44 
Liability  17   27   26 

Sequent experienced a change$75 million decrease in the net fair value of its outstanding contracts of $26 million during the first ninethree months of 2009 and 2008 compared to a $59 million decrease during the same period last year due to changes in the fair value of derivative financial instruments utilized in its energy marketing and risk management activities and contract settlements.

The following tables illustrate the change in the net fair value of Sequent’s derivative financial instruments and energy trading contracts during the three and nine months ended September 30,March 31, 2009 and 2008, and 2007, and provide details of the net fair value of contracts outstanding as of September 30, 2008.March 31, 2009.

  Three months ended Sept. 30, 
In millions 2008  2007 
Net fair value of contracts outstanding at beginning of period $(96) $51 
Contracts realized or otherwise settled during period  60   (17)
Change in net fair value of contracts  119   26 
Net fair value of contracts outstanding at end of period  83   60 
Netting of cash collateral  33   1 
Cash collateral and net fair value of contracts outstanding at end of period $116  $61 
  Three months ended Mar. 31, 
In millions 2009  2008 
Net fair value of derivative financial instruments outstanding at beginning of period $82  $57 
Derivative financial instruments realized or otherwise settled during period  (95)  (42)
Change in net fair value of derivative financial instruments  20   (33)
Net fair value of derivative financial instruments outstanding at end of period  7   (18)
Netting of cash collateral  187   36 
Cash collateral and net fair value of derivative financial instruments outstanding at end of period $194  $18 
 
  Nine months ended Sept. 30, 
In millions 2008  2007 
Net fair value of contracts outstanding at beginning of period $57  $119 
Contracts realized or otherwise settled during period  (48)  (99)
Change in net fair value of contracts  74   40 
Net fair value of contracts outstanding at end of period  83   60 
Netting of cash collateral  33   1 
Cash collateral and net fair value of contracts outstanding at end of period $116  $61 

The sources of Sequent’s net fair value of its commodity-related derivative financial instruments at September 30, 2008,March 31, 2009, are as follows:

In millions 
Prices actively quoted (1)
  
Prices provided by other external sources (2)
 
Mature through 2008 $27  $56 
Mature 2009 – 2010  (11)  9 
Mature 2011 – 2013  -   2 
Total net fair value $16  $67 
In millions 
Prices actively quoted
(Level 1) (1)
  
Significant other observable inputs
(Level 2) (2)
  
Significant unobservable inputs
(Level 3)
 
Mature through         
2009 $(120) $105  $- 
    2010 - 2011  (20)   33   - 
2012 - 2014  2   7   - 
Total derivative financial instruments (3)
 $(138) $145  $- 

(1)  Valued using NYMEX futures prices and other quoted sources.
(2)  
Valued using basis transactions that represent the cost to transport the commodity
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.

Due to the $62 million lower net fair value of contracts outstanding at the beginning of the year in 2008 as compared to the prior period, the amount of contracts that were realized or otherwise settled by Sequent during the nine months ended September 30, 2008 decreased by $51 million as compared to 2007. Additionally, as a result of decreases in forward natural gas prices during the nine months ended September 30, 2008, compared to the prior year’s more modest price declines, the change in fair value was an increase of $34 million. These changes resulted in the net fair value of its contracts being $23 million more than last year.
(3)  Excludes cash collateral amounts.

Value at Risk Sequent’s 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 Sequent generally manages physical gas assets and economically protects its positions by hedging in the futures markets, its open exposure is generally immaterial, permitting Sequent to operate within relatively low VaR limits. Sequent employs daily risk testing, using both VaR and stress testing, to evaluate the risks of its open positions.

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Sequent’s management actively monitors open commodity positions and the resulting VaR. Sequent continues to maintain a relatively matched book, where its total buy volume is close to sell volume with minimal open commodity risk. Based on a 95% confidence interval and employing a 1-day holding period for all positions, Sequent’s portfolio of positions for the three and nine months ended September 30,March 31, 2009 and 2008 and 2007 had the following VaRs.

   Three months ended September 30,  Nine months ended September 30, 
 In millions  2008     2007   2008   2007 
Period end $1.9  $1.0  $1.9  $1.0 
Average  1.8   1.4   1.7   1.4 
High  2.4   2.3   2.9   2.3 
Low  1.0   0.9   0.8   0.9 
  Three months ended March 31, 
In millions 2009  2008 
Period end $2.1  $2.9 
    Average  1.9   1.4 
    High  3.3   2.9 
Low  1.3   0.8 

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 $929$563 million of variable-rate debt, which includes $768$402 million of our variable-rate short-term debt and $161 million of variable-rate gas facility revenue bonds outstanding at September 30, 2008,March 31, 2009, a 100 basis point change in market interest rates from 4.06%0.76% to 5.06%1.76% would have resulted in an increase in pretax interest expense of $9$6 million on an annualized basis.

At the beginning of 2008, we had a notional principal amount of $100 million of interest rate swap agreements associated with our senior notes. In March 2008, we terminated these interest rate swap agreements. We received a payment of $2 million, which included accrued interest and the fair value of the interest rate swap agreements at the termination date which was recorded as a liability in our condensed consolidated balance sheets and will be amortized through January 2011, which is the remaining life of the associated senior notes.

Credit Risk

Wholesale Services Sequent has established credit policies to determine and monitor the creditworthiness of counterparties, as well as the quality of pledged collateral. Sequent also utilizes master netting agreements whenever possible to mitigate exposure to counterparty credit risk. When Sequent is engaged in more than one outstanding derivative transaction with the same counterparty and it has 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 Sequent’s credit risk. Sequent also uses other netting agreements with certain counterparties with whom it conducts significant transactions. Master netting agreements enable Sequent to net certain assets and liabilities by counterparty. Sequent also nets across product lines and against cash collateral provided the master netting and cash collateral agreements include such provisions.

Additionally, Sequent may require counterparties to pledge additional collateral when deemed necessary. Sequent conducts credit evaluations and obtains appropriate internal approvals for its counterparty’s line of credit before any transaction with the counterparty is executed. In most cases, the counterparty must have a minimum long-term debt rating of Baa3 from Moody’s and BBB- from S&P. Generally, Sequent requires credit enhancements by way of guaranty, cash deposit or letter of credit for counterparties that do not meet the minimum long-term debt rating threshold.

Sequent, which provides services to marketers and utility and industrial customers, also has a concentration of credit risk as measured by its 30-day receivable exposure plus forward exposure. As of September 30, 2008,March 31, 2009, Sequent’s top 20 counterparties represented approximately 60%69% of the total counterparty exposure of $425$325 million, derived by adding together the top 20 counterparties’ exposures and dividing by the total of Sequent’s counterparties’ exposures.


As of September 30, 2008,March 31, 2009, Sequent’s counterparties, or the counterparties’ guarantors, had a weighted-average S&P equivalent credit rating of A-, which is consistent with the rating at December 31, 20072008 and September 30, 2007.March 31, 2008. The S&P equivalent credit rating is determined by a process of converting the lower of the S&P and Moody’s ratings to an internal rating ranging from 9 to 1, with 9 being the 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 for that counterparty. To arrive at the weighted average credit rating, each counterparty’s assigned internal ratio is multiplied by the counterparty’s 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. There were no credit defaults with Sequent’s counterparties as a result of the disruption in the credit markets.counterparties.
 

The following table shows Sequent’s third-party commodity receivable and payable positions as of September 30,March 31, 2009 and 2008 and 2007 and December 31, 2007.2008.

  Gross receivables  Gross payables 
  September 30,  December 31,  September 30,  September 30,  December 31,  September 30, 
In millions 2008  2007  2007  2008  2007  2007 
Netting agreements in place:                  
  Counterparty is investment grade $446  $437  $256  $338  $356  $231 
  Counterparty is non-investment grade  10   24   13   16   18   28 
  Counterparty has no external rating  76   134   94   212   204   124 
No netting agreements in place:                        
  Counterparty is investment grade  3   3   -   2   -   - 
  Amount recorded on balance sheet $535  $598  $363  $568  $578  $383 
  Gross receivables  Gross payables 
  March 31,  Dec. 31,  March 31,  March 31,  Dec. 31,  March 31, 
In millions 2009  2008  2008  2009  2008  2008 
Netting agreements in place:                  
  Counterparty is investment grade $237  $398  $483  $168  $266  $439 
  Counterparty is non-investment grade  8   15   46   19   41   30 
  Counterparty has no external rating  76   129   91   153   228   239 
No netting agreements in place:                        
  Counterparty is investment grade  5   7   4   2   4   3 
Amount recorded on statements of financial position $326  $549  $624  $342  $539  $711 

Sequent has 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, Sequent would need to post collateral to continue transacting business with some of its counterparties. Posting collateral would have a negative effect on our liquidity. If such collateral were not posted, Sequent’s ability to continue transacting business with these counterparties would be impaired. If, at September 30, 2008,March 31, 2009, our credit ratings had been downgraded to non-investment grade status, the required amounts to satisfy potential collateral demands under such agreements between Sequent and its counterparties would have totaled $15$12 million.

There have been no other significant changes to our credit risk related to our other segments, as described in Item 7A ”Quantitative and Qualitative Disclosures about Market Risk” of our Annual Report on Form 10-K for the year ended December 31, 2007.2008.

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 in Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act), as of September 30, 2008,March 31, 2009, 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, 2008,March 31, 2009, 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 during our most recent fiscal quarter 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 and litigation incidental to the business. For information regarding pending federal and state regulatory matters, see “Note 67 - Commitments and Contingencies” contained in Item 1 of Part I under the caption “Notes to Condensed Consolidated Financial Statements (Unaudited).”
In March 2009, Piedmont filed a lawsuit in the Court of Chancery of the State of Delaware against GNGC, asking the court to enter a judgment declaring that GNGC’s right to purchase Piedmont’s ownership interest in SouthStar expires on November 1, 2009. We believe that, under the March 2004 amended and restated joint venture agreement, GNGC has the evergreen opportunity, throughout the term of the joint venture, to exercise its options to purchase a portion of, or all of, Piedmont’s interest in SouthStar by notifying Piedmont on or before November of each year, with the purchase being effective as of January 1 of the following year. The ultimate resolution of this litigation cannot be determined, but we believe that the dispute will be resolved before our next option exercise date on November 1, 2009.

With regard to other legal proceedings, we are a party, as both plaintiff and defendant, to a number of other suits, claims and counterclaims on an ongoing basis. Management believes that the outcome of all such other litigation in which it is involved will not have a material adverse effect on our consolidated financial statements. There have been no significant changes in the litigation which was described in Note 7 to our Consolidated Financial Statements in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2007. We believe the ultimate resolution of such litigation will not have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

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

The following table sets forth information regarding purchases of our common stock by us and any affiliated purchasers during the three months ended September 30, 2008.March 31, 2009. Stock repurchases may be made in the open market or in private transactions at times and in amounts that we deem appropriate. However, there is no guarantee as to the exact number of additional shares that may be repurchased, and we may terminate or limit the stock repurchase program at any time. We will hold the repurchased shares as treasury shares.

Period Total number of shares purchased (1) (2) (3)  Average price paid per share  Total number of shares purchased as part of publicly announced plans or programs (3)  Maximum number of shares that may yet be purchased under the publicly announced plans or programs (3) 
July 2008  -  $-   -   4,950,951 
August 2008  89   32.92   -   4,950,951 
September 2008  2,108   32.87   -   4,950,951 
  Total third quarter
  2,197  $32.87   -     
Period Total number of shares purchased (1) (2) (3)  Average price paid per share  Total number of shares purchased as part of publicly announced plans or programs (3)  Maximum number of shares that may yet be purchased under the publicly announced plans or programs (3) 
January 2009  4,500  $30.33   -   4,950,951 
February 2009  14,200   33.53   -   4,950,951 
March 2009  -   -   -   4,950,951 
  Total first quarter
  18,700  $32.76   -     

(1)  The total number of shares purchased includes an aggregate of 2,1978,650 shares surrendered to us to satisfy tax withholding obligation in connection with the vesting of shares of restricted stock and the exercise of stock options.
(2)  On March 20, 2001, our Board of Directors approved the purchase of up to 600,000 shares of our common stock in the open market to be used for issuances under the Officer Incentive Plan (Officer Plan). We did not purchase anypurchased 10,050 shares for such purposes in the thirdfirst quarter of 2008.2009. As of September 30, 2008,March 31, 2009, we had purchased a total 307,567322,417 of the 600,000 shares authorized for purchase, leaving 292,433277,583 shares available for purchase under this program.
(3)  On February 3, 2006, we announced that our Board of Directors had authorized a plan to repurchase up to a total of 8 million shares of our common stock, excluding the shares remaining available for purchase in connection with the Officer Plan as described in note (2) above, over a five-year period.

Item 6. Exhibits

3.1Amended and Restated Articles of Incorporation filed November 2, 2005 with the Secretary of State of the state of Georgia (Exhibit 3.1, AGL Resources Inc. Form 8-K dated November 2, 2005).

3.210.6Bylaws, asFourth Modification to the amended on October 31, 2007 (Exhibit 3.2, AGL Resources Inc. Form 8-K dated October 31, 2007).

4.1Specimen form of Common Stock certificate (Exhibit 4.1, AGL Resources Inc. Form 10-K for the fiscal year ended September 30, 1999).

10.1Letter of Credit and SecurityRestated Master Environmental Management Services Agreement dated as of September 4, 2008February 1, 2009 by and among Pivotal Utility Holdings,between Atlanta Gas Light Company and the RETEC Group, Inc. as borrower, AGL Resources Inc. as Guarantor, Bank of America, N.A. as Administrative Agent, The Bank of Tokyo-Mitsubishi UFJ, LTD. as Syndication Agent and Bank of America, N.A. as Issuing Bank.

10.2Credit Agreement as of September 30, 2008 by and among AGL Resources Inc., AGL Capital Corporation, Wachovia Bank, N.A. as Administrative Agent, Wachovia Capital Markets, LLC as sole lead arranger and sole lead bookrunner. SunTrust Bank, NA, The Bank of Tokyo-Mitsubishi UFJ, LTD., Calyon New York Brand and The Royal Bank of Scotland PLC. as Co-Documentation Agents (Exhibit 10.1, AGL Resources Inc. Form 8-K dated September 30, 2008).

31.1Certification of John W. Somerhalder II pursuant to Rule 13a - 14(a).

31.231.2         Certification of Andrew W. Evans pursuant to Rule 13a - - 14(a).

32.1Certification of John W. Somerhalder II pursuant to 18 U.S.C. Section 1350.

32.2Certification of Andrew W. Evans pursuant to 18 U.S.C. Section 1350.




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: October 30, 2008April 29, 2009                                  /s/ Andrew W. Evans
Executive Vice President and Chief Financial Officer