10-K 1 form_10-k.htm FORM 10-K form_10-k.htm


 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549
   
FORM 10-K
   
(Mark One)
 
þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2007
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)
   
Georgia
58-2210952
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
   
Ten Peachtree Place NE,
404-584-4000
Atlanta, Georgia 30309
 
(Address and zip code of principal executive offices)
(Registrant’s telephone number, including area code)
   
Securities registered pursuant to Section 12(b) of the Act:
   
Title of Class
Name of each exchange on which registered
Common Stock, $5 Par Value
New York Stock Exchange
   
Securities registered pursuant to Section 12(g) of the Act: None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 under the Securities Act.   Yes þ  No  ¨
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Act.   Yes ¨  No  þ
 
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, and (2) has been subject to such filing requirements for the past 90 days. Yes þ  No  ¨
   
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨
   
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer.
Large accelerated filer  þ  Accelerated filer  ¨ Non-accelerated filer ¨
   
Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes ¨  No þ
 
The aggregate market value of the registrant’s voting and non-voting common equity held by non-affiliates of the registrant, computed by reference to the price at which the registrant’s common stock was last sold as of the last business day of the registrant’s most recently completed second fiscal quarter, was $3,148,134,781
   
The number of shares of the registrant’s common stock outstanding as of January 31, 2008 was 76,439,305
   
DOCUMENTS INCORPORATED BY REFERENCE:
 
Portions of the Proxy Statement for the 2008 Annual Meeting of Shareholders (“Proxy Statement”) to be held April 30, 2008, are incorporated by reference in Part III.

1


 
     
Page(s)
 
   
4
 
         
Part I
         
Item 1.
   
5-15
 
     
6-8
 
     
9-10
 
     
10-12
 
     
12-13
 
     
13-14
 
Item 1A.
   
15-21
 
Item 1B.
   
21
 
Item 2.
   
21-22
 
Item 3.
   
22
 
Item 4.
   
23
 
     
23
 
Part II
         
Item 5.
   
24-25
 
Item 6.
   
26
 
Item 7.
   
27-46
 
     
27
 
     
27-29
 
     
29-35
 
     
35-40
 
     
41-45
 
     
45-46
 
Item 7A.
   
46-50
 
Item 8.
   
51-91
 
     
51-52
 
     
53
 
     
54
 
     
55
 
     
56-63
 
     
63-65
 
     
66-72
 
     
73-77
 
     
78
 
     
79-81
 
     
82-84
 
     
84-86
 
 
Note 9 – Segment Information
   
86-88
 
     
89
 
     
90
 
Item 9.
   
91
 
Item 9A.
   
91
 
Item 9B.
   
91
 

2


TABLE OF CONTENTS – continued



3



Atlanta Gas Light
Atlanta Gas Light Company
AGL Capital
AGL Capital Corporation
AGL Networks
AGL Networks, LLC
AGSC
AGL Services Company
AIP
Annual Incentive Plan
Bcf
Billion cubic feet
Chattanooga Gas
Chattanooga Gas Company
Compass Energy
Compass Energy Services, Inc.
Credit Facility
Credit agreement supporting our commercial paper program
Deregulation Act
1997 Natural Gas Competition and Deregulation Act
Dominion Ohio
Dominion East of Ohio, a Cleveland, Ohio based natural gas company; a subsidiary of Dominion Resources, Inc.
EBIT
Earnings before interest and taxes, a non-GAAP measure that includes operating income, other income, equity in SouthStar’s income, minority interest in SouthStar’s earnings, donations and gain on sales of assets and excludes interest and income tax expense; as an indicator of our operating performance, EBIT should not be considered an alternative to, or more meaningful than, operating income or net income as determined in accordance with GAAP
EITF
Emerging Issues Task Force
Energy Act
Energy Policy Act of 2005
ERC
Environmental remediation costs
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
Fitch
Fitch Ratings
Florida Commission
Florida Public Service Commission
GAAP
Accounting principles generally accepted in the United States of America
Georgia Commission
Georgia Public Service Commission
Golden Triangle Storage
Golden Triangle Storage, Inc.
Heating Season
The period from November to 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 Island
Jefferson Island Storage & Hub, LLC
LIBOR
London interbank offered rate
LNG
Liquefied natural gas
LOCOM
Lower of weighted average cost or current market price
Louisiana DNR
Louisiana Department of Natural Resources
Maryland Commission
Maryland Public Service Commission
Marketers
Marketers selling retail natural gas in Georgia and certificated by the Georgia Commission
Medium-term notes
Notes issued by Atlanta Gas Light with scheduled maturities between 2012 and 2027 bearing interest rates ranging from 6.6% to 9.1%
MGP
Manufactured gas plant
Moody’s
Moody’s Investors Service
New Jersey Commission
New Jersey Board of Public Utilities
NUI
NUI Corporation
NYMEX
New York Mercantile Exchange, Inc.
OCI
Other comprehensive income
Operating margin
A 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 statements of consolidated income.
Piedmont
Piedmont Natural Gas
Pivotal Propane
Pivotal Propane of Virginia, Inc.
Pivotal Utility
Pivotal Utility Holdings, Inc., doing business as Elizabethtown Gas, Elkton Gas and Florida City Gas
PGA
Purchased gas adjustment
PRP
Pipeline replacement program for Atlanta Gas Light
S&P
Standard & Poor’s Ratings Services
Saltville
Saltville Gas Storage Company
SEC
Securities and Exchange Commission
Sequent
Sequent Energy Management, L.P.
SFAS
Statement of Financial Accounting Standards
SNG
Southern Natural Gas Company
SouthStar
SouthStar Energy Services LLC
Tennessee Commission
Tennessee Regulatory Authority
VaR
Value 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 Gas
Virginia Natural Gas, Inc.
Virginia Commission
Virginia State Corporation Commission
WACOG
Weighted average cost of goods
WNA
Weather normalization adjustment


APB 25
APB Opinion No. 25, “Accounting for Stock Issued to Employees”
EITF 98-10
EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities”
EITF 99-02
EITF Issue No. 99-02, “Accounting for Weather Derivatives”
EITF 00-11
EITF Issue No. 00-11, “Lessor's Evaluation of Whether Leases of Certain Integral Equipment Meet the Ownership Transfer Requirements of FASB Statement No.13, Accounting for Leases, for Leases of Real Estate"
EITF 02-03
EITF Issue No. 02-03, “Issues Involved in Accounting for Contracts under EITF Issue No. 98-10, ‘Accounting for Contracts Involved in Energy Trading and Risk Management Activities’”
FIN 39
FASB Interpretation No. (FIN) 39 “Offsetting of Amounts Related to Certain Contracts”
FSP FIN 39-1
FASB Staff Position 39-1 “Amendment of FIN 39
FIN 46 & FIN 46R
FIN 46, “Consolidation of Variable Interest Entities”
FIN 47
FIN 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143”
FIN 48
FIN 48, “Accounting for Uncertainty in Income Taxes, an interpretation of SFAS Statement No. 109”
SFAS 5
SFAS No. 5, “Accounting for Contingencies”
SFAS 13
SFAS No. 13, “Accounting for Leases”
SFAS 66
SFAS No. 66, “Accounting for Sales of Real Estate”
SFAS 71
SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation”
SFAS 87
SFAS No. 87, “Employers’ Accounting for Pensions”
SFAS 106
SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions”
SFAS 109
SFAS No. 109, “Accounting for Income Taxes”
SFAS 123 & SFAS 123R
SFAS No. 123, “Accounting for Stock-Based Compensation”
SFAS 133
SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS 141
SFAS No. 141, “Business Combinations”
SFAS 142
SFAS No. 142, “Goodwill and Other Intangible Assets”
SFAS 148
SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure”
SFAS 149
SFAS No. 149, “Amendment of SFAS 133 on Derivative Instruments and Hedging Activities”
SFAS 157
SFAS No. 157, “Fair Value Measurements”
SFAS 158
SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”
SFAS 159
SFAS No. 159, “The Fair Value Option for Financial Assets and Liabilities”
SFAS 160
SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements”



PART I

ITEM 1.  BUSINESS


Unless the context requires otherwise, references to “we,” “us,” “our,” the “company” and “AGL Resources” are intended to mean consolidated AGL Resources Inc. and its subsidiaries.

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. Our six utilities serve more than 2.2 million 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. 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 also own and operate a small telecommunications business that constructs and operates conduit and fiber infrastructure within select metropolitan areas.

We manage these businesses through four operating segments and a nonoperating corporate segment. Each operating segment’s percentage contribution to the total operating EBIT for the last three years is indicated in the following chart.

Over the last three years, on average, we have derived approximately 85% of our EBIT from our regulated natural gas distribution business and the sale of natural gas to end-use customers primarily in Georgia through SouthStar. This statistic is significant because it represents the portion of our earnings that directly results from the underlying business of supplying natural gas to retail customers. SouthStar, which is subject to a different regulatory framework from our utilities, is an integral part of the retail framework for providing natural gas service to end-use customers in Georgia.

We derived the remaining percentage (15% or less for the last three years) of our EBIT principally from businesses that are complementary to our natural gas distribution business. We engage in natural gas asset management and the operation of high-deliverability natural gas underground storage as ancillary activities to our utility franchises. These businesses allow us to be opportunistic in capturing incremental value at the wholesale level and provide us with deepened business insight about natural gas market dynamics. 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 business.

Operating revenues, operating margin, operating expenses and EBIT for each of our segments are presented in the following table for 2007, 2006 and 2005.

In millions
 
Operating revenues
   
Operating margin (1)
   
Operating expenses
   
EBIT (1)
 
2007
                       
Distribution operations
  $
1,665
    $
820
    $
485
    $
338
 
Retail energy operations
   
892
     
188
     
75
     
83
 
Wholesale services
   
83
     
77
     
43
     
34
 
Energy investments
   
42
     
40
     
25
     
15
 
Corporate (2)
    (188 )    
-
     
8
      (7 )
Consolidated
  $
2,494
    $
1,125
    $
636
    $
463
 
 
2006
                               
Distribution operations
  $
1,624
    $
807
    $
499
    $
310
 
Retail energy operations
   
930
     
156
     
68
     
63
 
Wholesale services
   
182
     
139
     
49
     
90
 
Energy investments
   
41
     
36
     
26
     
10
 
Corporate (2)
    (156 )    
1
     
9
      (9 )
Consolidated
  $
2,621
    $
1,139
    $
651
    $
464
 
 
2005
                               
Distribution operations
  $
1,753
    $
814
    $
518
    $
299
 
Retail energy operations
   
996
     
146
     
61
     
63
 
Wholesale services
   
95
     
92
     
42
     
49
 
Energy investments
   
56
     
40
     
23
     
19
 
Corporate (2)
    (182 )    
-
     
6
      (11 )
Consolidated
  $
2,718
    $
1,092
    $
650
    $
419
 
 
(1) These are non-GAAP measurements. A reconciliation of operating margin and EBIT
to our operating income and net income is contained in “Results of Operations” herein.
(2)  Includes intercompany eliminations



The distribution operations segment is the largest component of our business and includes six natural gas local distribution utilities. These utilities construct, manage and maintain intrastate natural gas pipelines and distribution facilities and include:

·  
Atlanta Gas Light
·  
Chattanooga Gas
·  
Elizabethtown Gas
·  
Elkton Gas
·  
Florida City Gas
·  
Virginia Natural Gas

Regulatory Environment

Each utility operates subject to regulations of the state regulatory agency in its service territories with respect to rates charged to our customers and various 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 allow recovery of all prudently incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable return on common equity. Rate base generally consists of the original cost of utility plant in service, working capital, inventories 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.

Atlanta Gas Light does not sell natural gas directly to its customers and does not need or utilize a PGA. All of our other utilities are authorized to use a PGA mechanism that allows them to adjust their rates to reflect changes in the wholesale cost of natural gas and to ensure they recover 100% of the costs incurred in purchasing gas for their customers. We continuously monitor the performance of our utilities to determine whether rates need to be further adjusted through the regulatory process. We have fixed rate settlements in three of our six jurisdictions in Georgia, New Jersey and Virginia.

Atlanta Gas Light’s natural gas market was deregulated in 1997 with the Deregulation Act. Prior to this act, Atlanta Gas Light was the supplier and seller of natural gas to its customers. Today, Marketers sell natural gas to end-use customers in Georgia and handle customer billing functions. The Marketers file their rates monthly with the Georgia Commission. Atlanta Gas Light's role includes:

·  
distributing natural gas for Marketers
·  
constructing, operating and maintaining the gas system infrastructure, including responding to customer service calls and leaks
·  
reading meters and maintaining underlying customer premise information for Marketers

Atlanta Gas Light recognizes revenue under a straight-fixed-variable rate design whereby Atlanta Gas Light charges rates to its customers based primarily on monthly fixed charges. The Marketers bill these charges directly to their customers. This mechanism minimizes the seasonality of revenues since the monthly fixed charge is not volumetric or directly weather dependent. Weather indirectly influences the number of customers that have active accounts during the heating season, and this has a seasonal impact on Atlanta Gas Light’s revenues since generally more customers are connected in periods of colder weather than in periods of warmer weather.

Regulatory Agreements In September 2007, the Georgia Commission approved our request to obtain an undivided interest in pipelines connecting our Georgia service territory to liquefied natural gas facilities at Elba Island, Georgia. We along with SNG have undertaken this pipeline project in an effort to diversify our sources of natural gas. We currently receive the majority of our natural gas supply from a production region in and around the Gulf of Mexico and generally, demand for this natural gas is growing faster than supply. This project is contingent upon FERC approval and therefore SNG and ourselves jointly filed an application with the FERC in October 2007. We anticipate that we will receive FERC approval in 2008. Construction is expected to begin in 2008 and to be completed in 2009.

In December 2007, the Florida Commission approved our request to include the amortization of certain components of the purchase price we paid for Florida City Gas in our calculation of return on equity. The costs will not be amortized for financial reporting purposes in accordance with GAAP but will be amortized over a period of 5 to 30 years for our regulatory reporting to the Florida Commission in connection with the Florida Commission’s review of Florida City Gas’ return on equity. Additionally and under the same order, the Florida Commission approved a five-year base rate stay-out beginning October 2007, whereby base rates will not be increased, except for certain unforeseen acts beyond our control. The five-year stay-out provision does not preclude the Florida Commission from initiating over earning or other proceedings.

 
A November 2004 agreement between Elizabethtown Gas and the New Jersey Commission approved our acquisition of NUI Corporation. This agreement included, among other things, a base rate freeze for Elizabethtown Gas for the five-year period from November 2004 to October 2009. Beginning with the annual measurement period in December 2007, 75% of Elizabethtown Gas’ earnings in excess of an 11% return on equity would be shared with rate payers in the fourth and fifth years of the base rate stay-out period.

Weather Normalization Certain of our non-Georgia jurisdictions have various regulatory mechanisms that allow us to recover our costs in the event of unusual weather, but they are not direct offsets to the potential impacts of weather and customer consumption on earnings. The tariffs of Elizabethtown Gas, Virginia Natural Gas, and Chattanooga Gas contain WNA 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. The following table provides certain regulatory information for our largest utilities.
 
   
Atlanta Gas Light
   
Elizabethtown Gas
   
Virginia Natural Gas
   
Florida City Gas
   
Chattanooga Gas
State regulator
 
Georgia Commission
   
New Jersey Commission
   
Virginia Commission
   
Florida Commission
   
Tennessee Commission
Current rates effective until
 
May 2010
   
Jan. 2010
   
Aug. 2011
   
N/A
   
Jan. 2011
Authorized return on rate base (1)
    8.53 %     7.95 %     9.24 %     7.36 %     7.89 %
Estimated 2007 return on rate base (2) (4)
    8.59 %     8.46 %     7.90 %     6.09 %     7.53 %
Authorized return on equity
    10.9 %     10.0 %     10.9 %     11.25 %     10.2 %
Estimated 2007 return on equity (2) (4)
    11.03 %     10.32 %     8.96 %     7.04 %     9.40 %
Authorized rate base % of equity (3)
    47.9 %     53.0 %     52.4 %     36.8 %     44.8 %
Rate base included in 2007 return on equity (in millions) (3) (4)
  $
1,271
    $
441
    $
350
    $
146
    $
100
 
(1)  
The authorized return on rate base, return on equity, and percentage of equity reflected above were those authorized as of December 31, 2007.
(2)  
Estimate based on principles consistent with utility ratemaking in each jurisdiction. Returns are not necessarily consistent with GAAP returns.
(3)   Estimated based on 13-month average.
(4)  
 Florida City Gas includes the impacts of the acquisition adjustment, as approved by the Florida Commission in December 2007, in its rate base,
return on rate base and return on equity calculations
 
Customer Demand All of our utilities face competition from other energy products. Our principal competition arises from electric utilities and oil and propane providers serving the residential and commercial markets throughout our service areas and the potential displacement or replacement of natural gas appliances with electric appliances. The primary competitive factors are the prices for competing sources of energy as compared to natural gas and the desirability of natural gas heating versus alternative heating sources.

Competition for space heating and general household and small commercial energy needs generally occurs at the initial installation phase when the customer or builder makes decisions as to which types of equipment to install. Customers generally continue to use the chosen energy source for the life of the equipment. Customer demand for natural gas could be affected by numerous factors, including:

·  
changes in the availability or price of natural gas and other forms of energy
·  
general economic conditions
·  
energy conservation
·  
legislation and regulations
·  
the capability to convert from natural gas to alternative fuels
·  
weather
·  
new housing starts

In some of our service areas, net growth continues to be slowed due to the number of customers who leave our systems because of higher natural gas prices, slower economic growth in some of our service areas and competition from alternative fuel sources, including incentives offered by the local electric utilities to switch to electric alternatives.

Through our targeted marketing and customer retention programs, we have improved the retention of our existing customers. Additionally, these activities have enabled us to obtain new customers, although at a lower rate than expected, due in part to downturns in the general economy and the housing and related mortgage markets. We expect these conditions to continue for an extended period of time and that such conditions could impact our net customer growth. Consequently, we will focus even more on our marketing and customer retention efforts.

 
These efforts include working to add residential customers, multifamily complexes and high-value commercial customers that use natural gas for purposes other than space heating. In addition, we partner with numerous entities to market the benefits of gas appliances and to identify potential retention options early in the process for those customers who might consider converting to alternative fuels.

Collective Bargaining Agreements In 2007, collective bargaining agreements, representing 55 employees at Atlanta Gas Light, Chattanooga Gas and Elizabethtown Gas were terminated as a result of the decertification of the respective unions. Accordingly, these 55 employees are no longer represented by a bargaining agreement and now fall under our standard human resources pay and benefit plans and policies. In January 2008, approximately 55 Florida City Gas employees filed for decertification of their union. The vote is expected to occur in February 2008.
 
The following table provides information about the collective bargaining agreements to which our natural gas local distribution utilities are parties. Additionally, we believe that our relations with our employees are good.

 
Affiliated subsidiary
 
Approximate # of employees
 
Date of contract expiration
Teamsters (Local Nos. 769 and 385)
Florida City Gas
   
55
 
March 2008
Utility Workers Union of America (Local No. 424)
Elizabethtown Gas
   
160
 
November 2009
International Brotherhood of Electrical Workers (Local No. 50)
Virginia Natural Gas
   
140
 
May 2010
 
Total
   
355
   




Our retail energy operations segment consists of SouthStar, a joint venture owned 70% by our subsidiary, Georgia Natural Gas Company and 30% by Piedmont. SouthStar markets natural gas and related services under the trade name Georgia Natural Gas to retail customers on an unregulated basis, primarily in Georgia as well as to commercial and industrial customers, principally in Florida, Tennessee, North Carolina, South Carolina and Alabama. Based on its market share, SouthStar is the largest Marketer of natural gas in Georgia, with average customers in excess of 530,000 over the last three years.

SouthStar is governed by an executive committee, which is comprised of six members, three representatives from AGL Resources and three from Piedmont. Under a joint venture agreement, all significant management decisions require the unanimous approval of the SouthStar executive committee; accordingly, our 70% financial interest is considered to be noncontrolling. Although our ownership interest in the SouthStar partnership is 70%, under an amended and restated joint venture agreement (Restated 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 record the earnings allocated to Piedmont as a minority interest in our consolidated statements of income, and we record Piedmont’s portion of SouthStar’s capital as a minority interest in our consolidated balance sheets.

The Restated Agreement includes a provision granting us three opportunities to exercise an option to purchase Piedmont’s ownership interest in SouthStar. Our first option exercise opportunity was on November 1, 2007, which we did not exercise and we have two remaining opportunities on November 1, 2008 and 2009, to purchase certain portions of Piedmont’s interest, both of which would be effective on January 1 of the following year. If we were to exercise our option on November 1, 2008, Piedmont, at its discretion, could require us to purchase their entire ownership interest. The purchase price would be based on the fair market value of SouthStar.

In August 2006, SouthStar was awarded the right to supply a total of approximately 10 Bcf of natural gas to customers of Dominion Ohio through August 2008 (approximately 5 Bcf/year). As part of this agreement, SouthStar manages the supply, transportation and storage of natural gas on behalf of Dominion Ohio. The Dominion Ohio agreement did not materially affect our results of operations in 2007. SouthStar’s entrance into the Ohio market is part of its continued growth strategy.

SouthStar’s operations also are sensitive to customer consumption patterns similar to those affecting our utility operations. SouthStar uses a variety of hedging strategies, such as futures, options, swaps, weather derivative instruments and other risk management tools, to mitigate the potential effect of these issues on its operations.
 
Competition SouthStar competes with other energy marketers, including Marketers in Georgia, to provide natural gas and related services to customers in Georgia and the Southeast. In addition, similar to our distribution operations, SouthStar faces competition based on customer preferences for natural gas compared to other energy products and the comparative prices of those products. SouthStar’s principal competitors for other non-natural gas energy products relates to electric utilities and the potential displacement or replacement of natural gas appliances with electric appliances. This competition with other energy products has been exacerbated by price volatility in the wholesale natural gas commodity market and related significant increases in the cost of natural gas billed to SouthStar’s customers, especially during portions of 2005 and 2006.

Operating margin SouthStar generates operating margin primarily in three ways. The first is through the sale of natural gas to retail customers in the residential, commercial and industrial sectors, primarily in Georgia where SouthStar captures a spread between wholesale and retail natural gas prices. The second way is through the collection of monthly service fees and customer late payment fees.

SouthStar evaluates the combination of these two retail price components to ensure such pricing is structured to cover related retail customer costs, such as bad debt expense, customer service and billing, and lost and unaccounted-for gas, and to provide a reasonable profit, as well as being competitive to attract new customers and maintain market share. SouthStar’s operating margin is impacted by seasonal weather, natural gas prices, customer growth and SouthStar’s related market share in Georgia, which has historically been approximately 35%, based on number of customers. SouthStar employs strategies to attract and retain a higher credit-quality customer base. These strategies result not only in higher operating margin, as these customers tend to utilize higher volumes of natural gas, but also help to mitigate bad debt expense due to the higher credit-quality of customers.

 
The third way SouthStar generates operating margin is through its commercial operations of optimizing storage and transportation assets and effectively managing commodity risk, which enables SouthStar to maintain competitive retail prices and operating margin. SouthStar is allocated storage and pipeline capacity that is used to supply natural gas to its customers in Georgia. Through hedging transactions, SouthStar manages exposures arising from changing commodity prices using natural gas storage transactions to capture operating margin from natural gas pricing differences that occur over time. SouthStar’s risk management policies allow the use of derivative instruments for hedging and risk management purposes but prohibit the use of derivative instruments for speculative purposes.

SouthStar accounts for its natural gas inventories at the lower of weighted average cost or current market price. SouthStar evaluates the weighted average cost of its natural gas inventories against market prices and determines whether any declines in market prices below the weighted average cost are other than temporary. For declines considered to be other than temporary, SouthStar records adjustments to cost of gas (LOCOM adjustments) in our consolidated statement of income to reduce the weighted average cost of the natural gas inventory to the current market price. SouthStar recorded a LOCOM adjustment of $6 million in 2006. SouthStar did not record a LOCOM adjustment in 2007 or 2005.

SouthStar also enters into weather derivative instruments in order to preserve operating margin profits in the event of warmer-than-normal weather in the winter months. These contracts are accounted for using the intrinsic value method under EITF 99-02. The weather derivative contracts contain settlement provisions based on cumulative heating degree days for the covered periods. SouthStar entered into weather derivatives (swaps and options) for both the 2006 to 2007, and 2007 to 2008 heating seasons. SouthStar recorded net gains on these weather derivatives of approximately $4 million in 2007 and $5 million in 2006. These gains were largely offset by corresponding losses of operating margin due to the warm weather the hedges were designed to protect against. SouthStar had no weather derivatives in 2005 and therefore no gains or losses were recorded during 2005.


Our wholesale services segment, which consists primarily of Sequent, focuses on asset management, transportation, storage, producer and peaking services and wholesale marketing. Sequent captures economic value from idle or underutilized natural gas assets, which are typically amassed by companies through investments in or contractual rights to natural gas transportation and storage assets. Operating margin is typically created in this business by participating in transactions that balance the needs of varying markets and time horizons.

In addition, Sequent takes advantage of arbitrage opportunities within the natural gas supply, storage and transportation markets to generate earnings, and its profitability is correlated to volatility in these markets. Natural gas market volatility can result 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 among geographic locations and various time horizons created by this volatility. In doing so, Sequent also seeks to mitigate the risks associated with this volatility and protect its operating margin through a variety of risk management and hedging activities.

Sequent provides its customers with natural gas from the major producing regions and market hubs primarily in the eastern and mid-continental United States. Sequent purchases transportation and storage capacity to meet its delivery requirements and customer obligations in the marketplace and its customers benefit from its logistics expertise and ability to deliver natural gas at prices that are advantageous relative to other alternatives. Sequent has entered into agreements that have facilitated the expansion of its operations into the western United States and Canada and plans to pursue additional opportunities in these regions during 2008. Sequent continues to work on projects and transactions to extend its operating territory and is entering into agreements of longer duration, as well as evaluating opportunities to expand its business focus and models including its commercial and industrial customer base through acquisitions and organic growth.

Competition Sequent competes for asset management business with other energy wholesalers, often through a competitive bidding process. There has been significant consolidation of energy wholesale operations, particularly among major natural gas producers. Financial institutions have also entered the marketplace. As a result, energy wholesalers have become increasingly willing to place bids for asset management transactions that are priced to capture market share. We expect this trend to continue in the near term, which could result in downward pressure on the volume of asset management transactions and the related operating margin available in this portion of Sequent’s business.

 
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.

The following table provides additional information on Sequent’s asset management agreements with its affiliated utilities.

 
Expiration
Timing of
Type of fee
 
% Shared or
   
Profit sharing / fees payments
 
In millions
date
payment
 structure
 
annual fee
   
2007
   
2006
   
2005
 
Elkton Gas
Mar 2008
Monthly
Fixed-fee
 
(A)
    $
-
    $
-
    $
-
 
Chattanooga Gas
Mar 2008
Annually
Profit -sharing
    50 %    
2
     
4
     
2
 
Elizabethtown Gas
Mar 2008
Monthly
Fixed -fee
   
$4
     
6
     
4
     
-
 
Florida City Gas
Mar 2008
Annually
Profit -sharing
    50 %    
1
     
-
     
-
 
Virginia Natural Gas
Mar 2009
Annually
Profit -sharing
 
(B)
     
7
     
2
     
5
 
Atlanta Gas Light
Mar 2012
Quarterly
Profit -sharing
    60 %    
9
     
6
     
4
 
    Total
                $
25
    $
16
    $
11
 
(A)  
Annual fixed fee is approximately $11,000.
(B)  
Profit sharing is based on a tiered sharing structure.
 
In October 2007, the Georgia Commission extended the asset management agreement between Sequent and Atlanta Gas Light to March 2012. Under the terms of the extended agreement, the sharing percentages are unchanged; however the agreement now includes guaranteed minimum annual payments to be made by Sequent of approximately $4 million. The contract year under the extended agreement will be April 1 to March 31 with Sequent making quarterly sharing payments. Sequent is actively negotiating the renewal of its remaining affiliate asset management agreements scheduled to expire in 2008, which require regulatory approval.

Transportation Transactions Sequent contracts for natural gas transportation capacity and participates in transactions that manage the natural gas commodity and transportation costs in an attempt to achieve the lowest cost to serve its various markets. Sequent seeks to optimize this process on a daily basis as market conditions change by evaluating all the natural gas supplies, transportation alternatives and markets to which it has access and identifying the least-cost alternatives to serve the various markets. This enables Sequent to capture geographic pricing differences across these various markets as delivered natural gas prices change.

As Sequent executes transactions to secure transportation capacity, it often enters into forward financial contracts to hedge its positions. The hedging instruments are derivatives, and Sequent reflects changes in the derivatives’ fair value in its reported operating results. During 2007, Sequent reported unrealized gains of $5 million associated with transportation capacity hedges, most of which are expected to be realized as these positions are settled in 2008. During 2006, Sequent reported unrealized gains of $12 million associated with transportation capacity hedges. The majority of this amount was realized during 2007 as the positions were settled. Sequent did not report any significant gains or losses on these types of hedges during 2005.

Producer Services Sequent’s producer services business primarily focuses on aggregating natural gas supply from various small and medium-sized producers located throughout the natural gas production areas of the United States, principally in the Gulf Coast region. Sequent provides producers with certain logistical and risk management services that offer producers attractive options to move their supply into the pipeline grid. Aggregating volumes of natural gas from these producers allows Sequent to provide markets to producers who seek a reliable outlet for their natural gas production.

Park and Loan Transactions Sequent routinely enters into park and loan transactions with various pipelines, which allow it to park gas on or borrow gas from the pipeline in one period and reclaim gas from or repay gas to the pipeline in a subsequent period. The economics of these transactions are evaluated and price risks are managed in much the same way traditional reservoir and salt dome storage transactions are evaluated and managed.

Sequent enters into forward NYMEX contracts to hedge its park and loan transactions. While the hedging instruments mitigate the price risk associated with the delivery and receipt of natural gas, they can also result in volatility in Sequent’s reported results during the period before the initial delivery or receipt of natural gas. During this period, if the forward NYMEX prices in the months of delivery and receipt do not change in equal amounts, Sequent will report a net unrealized gain or loss on the hedges.

Although Sequent’s quarterly results were modestly impacted by unrealized hedge losses during 2007 and 2006, on an annual basis Sequent did not report any significant gains or losses on park and loan hedges during 2007, 2006, or 2005.

 
Mark-to-Market Versus Lower of Average Cost or Market Sequent purchases natural gas for storage when the current market price it pays plus the cost for transportation and storage is less than the market price it could receive in the future. Sequent attempts to mitigate substantially all of the commodity price risk associated with its storage portfolio and uses derivative instruments to reduce the risk associated with future changes in the price of natural gas. Sequent sells NYMEX futures contracts or over-the-counter derivatives in forward months to substantially lock in the operating margin it will ultimately realize when the stored gas is actually sold.

We view Sequent’s trading margins from two perspectives. First, we base our commercial decisions on economic value, which is defined as the locked-in gain to be realized in the statement of income at the time the physical gas is withdrawn from storage and ultimately sold and the derivative instrument used to hedge natural gas price risk on that physical storage is settled. Second is the GAAP reported value both prior to and at the point of physical withdrawal. The GAAP amount is impacted by the process of accounting for the financial hedging instruments in interim periods at fair value between the time the natural gas is injected into storage and when it is ultimately withdrawn and the financial instruments are settled. The change in the fair value of the hedging instruments is recognized in earnings in the period of change and is recorded as unrealized gains or losses. The actual value, less any interim recognition of gains or losses on hedges and adjustments for LOCOM, is realized when the natural gas is delivered to its ultimate customer.
 
Sequent accounts for natural gas stored in inventory differently than the derivatives Sequent uses to mitigate the commodity price risk associated with its storage portfolio. The natural gas that Sequent purchases and injects into storage is accounted for at the lower of average cost or current market value. The derivatives that Sequent uses to mitigate commodity price risk are accounted for at fair value and marked to market each period. This difference in accounting treatment can result in volatility in Sequent’s reported results, even though the expected operating margin is essentially unchanged from the date the transactions were consummated. These accounting differences also affect the comparability of Sequent’s period-over-period results, since changes in forward NYMEX prices do not increase and decrease on a consistent basis from year to year. During most of 2007 and 2006, Sequent’s reported results were positively impacted by decreases in forward NYMEX prices, which resulted in the recognition of unrealized gains; however, the impact was more significant for 2006. During 2005, the reported results were negatively impacted by increases in forward NYMEX prices. As a result the more significant unrealized gains during 2006 increased the unfavorable variance between 2007 and 2006 and had a positive impact on the favorable variance between 2006 and 2005.


Our energy investments segment includes a number of businesses that are related and complementary to our primary business. The most significant of these businesses is our natural gas storage business, which develops, acquires and operates high-deliverability salt-dome storage assets in the Gulf Coast region of the United States. While this business also can generate additional revenue during times of peak market demand for natural gas storage services, the majority of our storage services are covered under medium to long-term contracts at a fixed market rate.

Jefferson Island This wholly owned subsidiary operates a salt dome storage and hub facility in Louisiana, approximately eight miles from the Henry Hub. The storage facility is regulated by the Louisiana DNR and by the FERC, which has limited regulatory authority over the storage and transportation services. The facility consists of two salt dome gas storage caverns with approximately 9.72 Bcf of total capacity and about 7.23 Bcf of working gas capacity. The facility has approximately 0.72 Bcf/day withdrawal capacity and 0.36 Bcf/day injection capacity. Jefferson Island provides storage and hub services through its direct connection to the Henry Hub via the Sabine Pipeline and its interconnection with seven other pipelines in the area. Jefferson Island’s entire portfolio is under firm subscription for the current heating season.

In August 2006, the Office of Mineral Resources of the Louisiana DNR informed Jefferson Island that its mineral lease – which authorizes salt extraction to create two new storage caverns – at Lake Peigneur had been terminated. The Louisiana DNR identified two bases for the termination: (1) failure to make certain mining leasehold payments in a timely manner, and (2) the absence of salt mining operations for six months.

 
In September 2006, Jefferson Island filed suit against the State of Louisiana to maintain its lease to complete an ongoing natural gas storage expansion project in Louisiana. The project would add two salt dome storage caverns under Lake Peigneur to the two caverns currently owned and operated by Jefferson Island. In its suit, Jefferson Island alleges that the Louisiana DNR accepted all leasehold payments without reservation and never provided Jefferson Island with notice and opportunity to cure, as required by state law. In its answer to the suit, the State denied that anyone with proper authority approved late payments. As to the second basis for termination, the suit contends that Jefferson Island’s lease with the State of Louisiana was amended in 2004 so that mining operations are no longer required to maintain the lease. The State’s answer denies that the 2004 amendment was properly authorized. During early 2008 we plan to intensify our efforts with the state of Louisiana to move the expansion project forward. If we are unable to reach a settlement, we are not able to predict the outcome of the litigation. As of January 2008, our current estimate of costs incurred that would be considered unusable if the Louisiana DNR was successful in terminating our lease and causing us to cease the expansion project is approximately $6 million.

Golden Triangle Storage In December 2006, we announced that our wholly-owned subsidiary, Golden Triangle Storage, plans to build a natural gas storage facility in the Beaumont, Texas area in the Spindletop salt dome. The project will initially consist of two underground salt dome storage caverns approximately a half-mile to a mile below ground that will hold about 12 Bcf of working natural gas storage capacity initially, or a total cavern capacity of approximately 17 Bcf. The facility potentially can be expanded to a total of five caverns with 28 Bcf of working natural gas storage capacity in the future based on customer interest. Golden Triangle Storage also intends to build an approximately nine-mile natural gas pipeline to connect the storage facility with three interstate and three intrastate pipelines. In May 2007, Golden Triangle Storage held a non-binding open season for service offerings at the proposed facility, which resulted in indications of market support for the facility.

Our current cost estimate for this facility is up to $265 million, but the actual cost will depend upon the facility’s configuration, materials and drilling costs, 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), and financing costs. This estimate could change due to changes in these factors, among others, as we refine our engineering estimates.

In December 2007, Golden Triangle Storage received an order from the FERC granting a Certificate of Public Convenience and Necessity to construct and operate the storage facility and approving market-based rates for services to be provided. We accepted this FERC order in January 2008. The FERC will serve as the lead agency overseeing the participation of a number of other federal, state and local agencies in reviewing and permitting the facility. Timelines associated with our commencement of commercial operations remain on track with initial construction on the first cavern expected to begin in early 2008.

AGL Networks This wholly owned subsidiary provides telecommunications conduit and dark fiber. AGL Networks leases and sells its fiber to a variety of customers in the Atlanta, Georgia and Phoenix, Arizona metropolitan areas, with a small presence in other cities in the United States. Its customers include local, regional and national telecommunications companies, internet service providers, educational institutions and other commercial entities. AGL Networks typically provides underground conduit and dark fiber to its customers under leasing arrangements with terms that vary from one to twenty years. In addition, AGL Networks offers telecommunications construction services to its customers. AGL Networks’ competitors are any entities that have laid or will lay conduit and fiber on the same route as AGL Networks in the respective metropolitan areas.


Our corporate segment includes our nonoperating business units, including AGSC and AGL Capital. AGL Capital, our wholly owned subsidiary, provides for our ongoing financing needs through a commercial paper program, the issuance of various debt and hybrid securities, and other financing arrangements.

We allocate substantially all of AGSC’s operating expenses and interest costs to our operating segments in accordance with various regulations. Our corporate segment also includes intercompany eliminations for transactions between our operating business segments. Our EBIT results include the impact of these allocations to the various operating segments. The acquisition of additional assets, such as NUI and Jefferson Island, typically enables us to allocate corporate costs across a larger number of businesses and, as a result, lower the relative allocations charged to those business units we owned prior to the acquisition of the new businesses.

Our corporate segment also includes Pivotal Energy Development, which coordinates among our related operating segments the development, construction or acquisition of assets in the southeastern, mid-Atlantic and northeastern regions in order to extend our natural gas capabilities and improve system reliability while enhancing service to our customers in those areas. The focus of Pivotal Energy Development’s commercial activities is to improve the economics of system reliability and natural gas deliverability in these targeted regions.

 
Additional Information

For additional information on our segments, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the caption “Results of Operations” and “Note 9, Segment Information,” set forth in Item 8, “Financial Statements and Supplementary Data.”

Information on our environmental remediation efforts, is contained in “Note 7, Commitments and Contingencies,” set forth in Item 8, “Financial Statements and Supplementary Data.”

Hedges

Changes in commodity prices subject a significant portion of our operations to earnings variability. Our nonutility businesses principally use physical and financial arrangements to reduce the risks associated with both weather-related seasonal fluctuations and changing commodity prices. In addition, because these economic hedges are generally not designated for hedge accounting treatment, our reported earnings for the wholesale services and retail energy operations segments reflect changes in the fair values of certain derivatives. These values may change significantly from period to period and are reflected as gains or losses within our operating margin or our OCI for those derivative instruments that qualify and are designated as accounting hedges.

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.

Approximately 61% of these segments’ operating revenues and 69% of these segments’ EBIT for the year ended December 31, 2007 were generated during the heating season and are reflected in our statements of consolidated income for the quarters ended March 31, 2007 and December 31, 2007. 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 sheet items such as receivables, unbilled revenue, inventories and short-term debt across quarters. However, these items are comparable when reviewing our annual results.

Available Information

Detailed information about us is contained in our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements and other reports, and amendments to those reports, that we file with or furnish to the SEC. These reports are available free of charge at our website, www.aglresources.com, as soon as reasonably practicable after we electronically file such reports with or furnish such reports to the SEC. However, our website and any contents thereof should not be considered to be incorporated by reference into this document. We will furnish copies of such reports free of charge upon written request to our Investor Relations department. You can contact our Investor Relations department at:

AGL Resources Inc.
Investor Relations - Dept. 1071
          P.O. Box 4569
Atlanta, GA 30309-4569
404-584-3801

In Part III of this Form 10-K, we incorporate by reference from our Proxy Statement for our 2008 annual meeting of shareholders certain information. We expect to file that Proxy Statement with the SEC on or about March 19, 2008, and we will make it available on our website as soon as reasonably practicable. Please refer to the Proxy Statement when it is available.

Additionally, our corporate governance guidelines, code of ethics, code of business conduct and the charters of each of our Board of Directors committees are available on our website. We will furnish copies of such information free of charge upon written request to our Investor Relations department.



ITEM 1A.  RISK FACTORS

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Certain expectations and projections regarding our future performance referenced in this report, in other materials we file with the SEC or otherwise release to the public, and on our website are forward-looking statements. Senior officers 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, such as statements in “Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere regarding our future operations, prospects, strategies, financial condition, economic performance (including growth and earnings), industry conditions and demand for our products and services. We have tried, whenever possible, to identify these statements by using 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," and similar expressions.

You are cautioned not to place undue reliance on our forward-looking statements. Our forward-looking statements are not guarantees of future performance and are based on currently available competitive, financial and economic data along with our operating plans. While we believe that our expectations for the future are reasonable in view of the currently available information, our expectations are subject to future events, risks and inherent uncertainties, as well as potentially inaccurate assumptions, and there are numerous factors - many beyond our control - that could cause results to differ significantly from our expectations. Such events, risks and uncertainties include, but are not limited to those set forth below and in the other documents that we file with the SEC. We note these factors for investors as permitted by the Private Securities Litigation Reform Act of 1995. There also may be other factors that we cannot anticipate or that are not described in this report, generally because we do not perceive them to be material, which could cause results to differ significantly from our expectations.

Forward-looking statements are only as of the date they are made, and we do not undertake any obligation to update these statements to reflect subsequent circumstances or events. You are advised, however, to review any further disclosures we make on related subjects in our Form 10-Q and Form 8-K reports to the SEC.
 
Risks Related to Our Business

Risks related to the regulation of our businesses could affect the rates we are able to charge, our costs and our profitability.

Our businesses are subject to regulation by federal, state and local regulatory authorities. In particular, at the federal level our businesses are regulated by the FERC. At the state level, our businesses are regulated by the Georgia Commission, the Tennessee Commission, the New Jersey Commission, the Florida Commission, the Virginia Commission and the Maryland Commission.

These authorities regulate many aspects of our operations, including construction and maintenance of facilities, operations, safety, rates that we charge customers, rates of return, the authorized cost of capital, recovery of pipeline replacement and environmental remediation costs, relationships with our affiliates, and carrying costs we charge Marketers selling retail natural gas in Georgia for gas held in storage for their customer accounts. Our ability to obtain rate increases and rate supplements to maintain our current rates of return and recover regulatory assets and liabilities recorded in accordance with SFAS 71 depends on regulatory discretion, and there can be no assurance that we will be able to obtain rate increases or rate supplements or continue receiving our currently authorized rates of return including the recovery of our regulatory assets and liabilities. In addition, if we fail to comply with applicable regulations, we could be subject to fines, penalties or other enforcement action by the authorities that regulate our operations, or otherwise be subject to material costs and liabilities.

Deregulation in the natural gas industry is the separation of the provision and pricing of local distribution gas services into discrete components. Deregulation typically focuses on the separation of the gas distribution business from the gas sales business and is intended to cause the opening of the formerly regulated sales business to alternative unregulated suppliers of gas sales services.

In 1997, the Georgia legislature enacted the Deregulation Act. To date, Georgia is the only state in the nation that has fully deregulated gas distribution operations, which ultimately resulted in Atlanta Gas Light exiting the retail natural gas sales business while retaining its gas distribution operations. Marketers then assumed the retail gas sales responsibility at deregulated prices. The deregulation process required Atlanta Gas Light to completely reorganize its operations and personnel at significant expense. It is possible that the legislature could reverse or amend portions of the deregulation process and require or permit Atlanta Gas Light to provide retail gas sales service once again or require our retail energy operations segment, SouthStar, to change the nature of how it provides natural gas and the rates used to charge certain customers. In addition, the Georgia Commission has statutory authority on an emergency basis to order Atlanta Gas Light to provide temporarily the same retail gas service that it provided prior to deregulation. If any of these events were to occur, we would incur costs to reverse the restructuring process or potentially lose the earnings opportunity embedded within the current marketing framework. Furthermore, the Georgia Commission has authority to change the terms under which we charge Marketers for certain supply-related services, which could also affect our future earnings.

 
Our business is subject to environmental regulation in all jurisdictions in which we operate, and our costs to comply are significant. Any changes in existing environmental regulation could affect our results of operations and financial condition.
 
Our operations and properties are subject to extensive environmental regulation pursuant to a variety of federal, state and municipal laws and regulations. Such environmental legislation imposes, among other things, restrictions, liabilities and obligations in connection with storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances into the environment. Environmental legislation also requires that our facilities, sites and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Our current costs to comply with these laws and regulations are significant to our results of operations and financial condition. Failure to comply with these laws and regulations and failure to obtain any required permits and licenses may expose us to fines, penalties or interruptions in our operations that could be material to our results of operations.
 
In addition, claims against us under environmental laws and regulations could result in material costs and liabilities. Existing environmental regulations could also be revised or reinterpreted, new laws and regulations could be adopted or become applicable to us or our facilities, and future changes in environmental laws and regulations could occur. With the trend toward stricter standards, greater regulation, more extensive permit requirements and an increase in the number and types of assets operated by us subject to environmental regulation, our environmental expenditures could increase in the future, particularly if those costs are not fully recoverable from our customers. Additionally, the discovery of presently unknown environmental conditions could give rise to expenditures and liabilities, including fines or penalties, which could have a material adverse effect on our business, results of operations or financial condition.

There are a number of legislative and regulatory proposals to address greenhouse gas emissions such as carbon dioxide, which are in various phases of discussion or implementation. The outcome of federal and state actions to address global climate change could result in a variety of regulatory programs including potential new regulations, additional charges to fund energy efficiency activities, or other regulatory actions. These actions could:
  •  result in increased costs associated with our operations,
  •  increase other costs to our business,
  •  could affect the demand for natural gas and
  •  impact the prices we charge our customers.
Because natural gas is a fossil fuel with low carbon content, it is possible that future carbon constraints could create additional demand for natural gas, both for production of electricity and direct use in homes and businesses.
 
Our infrastructure improvement and customer growth may be restricted by the capital-intensive nature of our business.

We must construct additions to our natural gas distribution system to continue the expansion of our customer base. We may also need to construct expansions of our existing natural gas storage facilities or develop and construct new natural gas storage facilities. The cost of this construction may be affected by the cost of obtaining government and other approvals, development project delays, adequacy of supply of diversified vendors, or unexpected changes in project costs. Weather, general economic conditions and the cost of funds to finance our capital projects can materially alter the cost, and projected construction schedule and completion timeline of a project. Our cash flows may not be fully adequate to finance the cost of this construction. As a result, we may be required to fund a portion of our cash needs through borrowings or the issuance of common stock, or both. For our distribution operations segment, this may limit our ability to expand our infrastructure to connect new customers due to limits on the amount we can economically invest, which shifts costs to potential customers and may make it uneconomical for them to connect to our distribution systems. For our natural gas storage business, this may significantly reduce our earnings and return on investment from what would be expected for this business, or may impair our ability to complete the expansions or development projects.

 
Transporting and storing natural gas involves numerous risks that may result in accidents and other operating risks and costs.

Our gas distribution activities involve a variety of inherent hazards and operating risks, such as leaks, accidents and mechanical problems, which could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, environmental pollution and impairment of our operations, which in turn could lead to substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The location of pipelines and storage facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. The occurrence of any of these events not fully covered by insurance could adversely affect our financial position and results of operations.
 
We face increasing competition, and if we are unable to compete effectively, our revenues, operating results and financial condition will be adversely affected and may limit our ability to grow our business.

The natural gas business is highly competitive, and we are facing increasing competition from other companies that supply energy, including electric companies, oil and propane providers and, in some cases, energy marketing and trading companies. In particular, the success of our investment in SouthStar is affected by the competition SouthStar faces from other energy marketers providing retail natural gas services in the Southeast. Natural gas competes with other forms of energy. The primary competitive factor is price. Changes in the price or availability of natural gas relative to other forms of energy and the ability of end-users to convert to alternative fuels affect the demand for natural gas. In the case of commercial, industrial and agricultural customers, adverse economic conditions, including higher gas costs, could also cause these customers to bypass or disconnect from our systems in favor of special competitive contracts with lower per-unit costs.

Our wholesale services segment competes with national and regional full-service energy providers, energy merchants and producers and pipelines for sales based on our ability to aggregate competitively priced commodities with transportation and storage capacity. Some of our competitors are larger and better capitalized than we are and have more national and global exposure than we do. The consolidation of this industry and the pricing to gain market share may affect our operating margin. We expect this trend to continue in the near term, and the increasing competition for asset management deals could result in downward pressure on the volume of transactions and the related operating margin available in this portion of Sequent’s business.
 
A significant portion of our accounts receivable is subject to collection risks, due in part to a concentration of credit risk in Georgia and at Sequent.

We have accounts receivable collection risk in Georgia due to a concentration of credit risk related to the provision of natural gas services to Marketers. At December 31, 2007, Atlanta Gas Light had 12 certificated and active Marketers in Georgia, four of which (based on customer count and including SouthStar) accounted for approximately 38% of our consolidated operating margin for 2007. As a result, Atlanta Gas Light depends on a concentrated number of customers for revenues. The failure of these Marketers to pay Atlanta Gas Light could adversely affect Atlanta Gas Light’s business and results of operations and expose it to difficulties in collecting Atlanta Gas Light’s accounts receivable. The provisions of Atlanta Gas Light’s tariff allow it to obtain security support in an amount equal to a minimum of two times a Marketer’s highest month’s estimated bill. Additionally, SouthStar markets directly to end-use customers and has periodically experienced credit losses as a result of severe cold weather or high prices for natural gas that increase customers’ bills and, consequently, impair customers’ ability to pay.

Sequent often extends credit to its counterparties. Despite performing credit analyses prior to extending credit and seeking to effectuate netting agreements, Sequent is exposed to the risk that it may not be able to collect amounts owed to it. If the counterparty to such a transaction fails to perform and any collateral Sequent has secured is inadequate, Sequent could experience material financial losses. Further, Sequent has a concentration of credit risk, which could subject a significant portion of its credit exposure to collection risks. Approximately 53% of Sequent’s credit exposure is concentrated in 20 counterparties. Although most of this concentration is with counterparties that are either load-serving utilities or end-use customers that have supplied some level of credit support, default by any of these counterparties in their obligations to pay amounts due Sequent could result in credit losses that would negatively impact our wholesale services segment.
 

The asset management arrangements between Sequent and our local distribution companies, and between Sequent and its nonaffiliated customers, may not be renewed or may be renewed at lower levels, which could have a significant impact on Sequent’s business.

Sequent currently manages the storage and transportation assets of our affiliates Atlanta Gas Light, Chattanooga Gas, Elizabethtown Gas, Elkton Gas, Florida City Gas, and Virginia Natural Gas and shares profits it earns from the management of those assets with those customers and their respective customers, except at Elizabethtown Gas and Elkton Gas where Sequent is assessed annual fixed-fees payable in monthly installments. Additionally, for the newly extended Atlanta Gas Light asset management agreement, Sequent will be required to make annual minimum payments of approximately $4 million payable on a quarterly basis. Entry into and renewal of these agreements are subject to regulatory approval and four are subject to renewal in 2008. In addition, Sequent has asset management agreements with certain nonaffiliated customers. Sequent’s results could be significantly impacted if these agreements are not renewed or are amended or renewed with less favorable terms.
 
We are exposed to market risk and may incur losses in wholesale services and retail energy operations.

The commodity, storage and transportation portfolios at Sequent and the commodity and storage portfolios at SouthStar consist of contracts to buy and sell natural gas commodities, including contracts that are settled by the delivery of the commodity or cash. If the values of these contracts change in a direction or manner that we do not anticipate, we could experience financial losses from our trading activities. Based on a 95% confidence interval and employing a 1-day holding period for all positions, Sequent’s and SouthStar’s portfolio of positions as of December 31, 2007 had a 1-day holding period VaR of $1.2 million and $0.03 million, respectively.

Our accounting results may not be indicative of the risks we are taking or the economic results we expect for wholesale services.

Although Sequent enters into various contracts to hedge the value of our energy assets and operations, the timing of the recognition of profits or losses on the hedges does not always correspond to the profits or losses on the item being hedged. The difference in accounting can result in volatility in Sequent’s reported results, even though the expected operating margin is essentially unchanged from the date the transactions were consummated.

Changes in weather conditions may affect our earnings.

Weather conditions and other natural phenomena can have a large impact on our earnings. Severe weather conditions can impact our suppliers and the pipelines that deliver gas to our distribution system. Extended mild weather, during either the winter period or summer period, can have a significant impact on demand for and cost of natural gas.

We have a WNA mechanism for Elizabethtown Gas and Chattanooga Gas that partially offsets the impact of unusually cold or warm weather on residential and commercial customer billings and our operating margin. At Elizabethtown Gas we could be required to return a portion of any WNA surcharge to its customers if Elizabethtown Gas’ return on equity exceeds its authorized return on equity of 10%.

Additionally, Virginia Natural Gas has a WNA mechanism for its residential customers that partially offsets the impact of unusually cold or warm weather. In September 2007, the Virginia Commission approved Virginia Natural Gas’ application for an Experimental Weather Normalization Adjustment Rider (the Rider) for its commercial customers. The Rider applies to the 2007 and 2008 heating seasons, with an opportunity for Virginia Natural Gas to extend the Rider for additional years.

These WNA regulatory mechanisms are most effective in a reasonable temperature range relative to normal weather using historical averages. The protection afforded by the WNA depends on continued regulatory approval. The loss of this continued regulatory approval could make us more susceptible to weather-related earnings fluctuations.

Changes in weather conditions may also impact SouthStar’s earnings. As a result, SouthStar uses a variety of weather derivative instruments to mitigate the impact on its operating margin in the event of warmer than normal weather in the winter months. However, these instruments do not fully protect SouthStar’s earnings from the effects of unusually warm weather.
 
A decrease in the availability of adequate pipeline transportation capacity could reduce our revenues and profits.

Our gas supply depends on the availability of adequate pipeline transportation and storage capacity. We purchase a substantial portion of our gas supply from interstate sources. Interstate pipeline companies transport the gas to our system. A decrease in interstate pipeline capacity available to us or an increase in competition for interstate pipeline transportation and storage service could reduce our normal interstate supply of gas.
 
 
Our profitability may decline if the counterparties to Sequent’s asset management transactions fail to perform in accordance with Sequent’s agreements.

Sequent focuses on capturing the value from idle or underutilized energy assets, typically by executing transactions that balance the needs of various markets and time horizons. Sequent is exposed to the risk that counterparties to our transactions will not perform their obligations. Should the counterparties to these arrangements fail to perform, we might be forced to enter into alternative hedging arrangements, honor the underlying commitment at then-current market prices or return a significant portion of the consideration received for gas. In such events, we might incur additional losses to the extent of amounts, if any, already paid to or received from counterparties.
 
We could incur additional material costs for the environmental condition of some of our assets, including former manufactured gas plants.

We are generally responsible for all on-site and certain off-site liabilities associated with the environmental condition of the natural gas assets that we have operated, acquired or developed, regardless of when the liabilities arose and whether they are or were known or unknown. In addition, in connection with certain acquisitions and sales of assets, we may obtain, or be required to provide, indemnification against certain environmental liabilities. Before natural gas was widely available, we manufactured gas from coal and other fuels. Those manufacturing operations were known as MGPs, which we ceased operating in the 1950s.

We have identified ten sites in Georgia and three in Florida where we own all or part of an MGP site. We are required to investigate possible environmental contamination at those MGP sites and, if necessary, clean up any contamination. As of December 31, 2006, the soil and sediment remediation program was complete for all Georgia sites, although groundwater cleanup continues. As of December 31, 2007, projected costs associated with the MGP sites associated with Atlanta Gas Light were $35 million. For elements of the MGP program where we still cannot provide engineering cost estimates, considerable variability remains in future cost estimates.

In addition, we are associated with former sites in New Jersey, North Carolina and other states that we assumed with our acquisition of NUI in November 2004. Material cleanups of these sites have not been completed nor are precise estimates available for future cleanup costs and therefore considerable variability remains in future cost estimates. For the New Jersey sites, cleanup cost estimates range from $61 million to $119 million. Costs have been estimated for only one of the non-New Jersey sites, for which current estimates range from $11 million to $20 million.

Inflation and increased gas costs could adversely impact our ability to control operating expenses, increase our level of indebtedness and adversely impact our customer base.

Inflation has caused increases in certain operating expenses that have required us to replace assets at higher costs. We attempt to control costs in part through implementation of best practices and business process improvements, many of which are facilitated through investments in information systems and technology. We have a process in place to continually review the adequacy of our utility gas rates in relation to the increasing cost of providing service and the inherent regulatory lag in adjusting those gas rates. Historically, we have been able to budget and control operating expenses and investments within the amounts authorized to be collected in rates, and we intend to continue to do so. However, any inability by us to control our expenses in a reasonable manner would adversely influence our future results.

Rapid increases in the price of purchased gas cause us to experience a significant increase in short-term debt because we must pay suppliers for gas when it is purchased, which can be significantly in advance of when these costs may be recovered through the collection of monthly customer bills for gas delivered. Increases in purchased gas costs also slow our utility collection efforts as customers are more likely to delay the payment of their gas bills, leading to higher-than-normal accounts receivable. This situation results in higher short-term debt levels and increased bad debt expense. Should the price of purchased gas increase significantly during the upcoming heating season, we would expect increases in our short-term debt, accounts receivable and bad debt expense during 2008.

Finally, higher costs of natural gas in recent years have already caused many of our utility customers to conserve in the use of our gas services and could lead to even more customers utilizing such conservation methods or switching to other competing products. The higher costs have also allowed competition from products utilizing alternative energy sources for applications that have traditionally used natural gas, encouraging some customers to move away from natural gas fired equipment to equipment fueled by other energy sources.
 

 
The cost of providing pension and postretirement health care benefits to eligible employees and qualified retirees is subject to changes in pension fund values and changing demographics and may have a material adverse effect on our financial results.

We have defined benefit pension and postretirement health care benefit plans for the benefit of substantially all full-time employees and qualified retirees. The cost of providing these benefits to eligible current and former employees is subject to changes in the market value of our pension fund assets, changing demographics, including longer life expectancy of beneficiaries, changes in health care cost trends, and an expected increase in the number of eligible former employees over the next five years.

Any sustained declines in equity markets and reductions in bond yields may have a material adverse effect on the value of our pension funds. In these circumstances, we may be required to recognize an increased pension expense or a charge to our statement of consolidated income to the extent that the pension fund values are less than the total anticipated liability under the plans.
 
Natural disasters, terrorist activities and the potential for military and other actions could adversely affect our businesses.

Natural disasters may damage our assets. The threat of terrorism and the impact of retaliatory military and other action by the United States and its allies may lead to increased political, economic and financial market instability and volatility in the price of natural gas that could affect our operations. In addition, future acts of terrorism could be directed against companies operating in the United States, and companies in the energy industry may face a heightened risk of exposure to acts of terrorism. These developments have subjected our operations to increased risks. The insurance industry has also been disrupted by these events. As a result, the availability of insurance covering risks against which we and our competitors typically insure may be limited. In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms.
 
Risks Related to Our Corporate and Financial Structure

We depend on our ability to successfully access the capital and financial markets. Any inability to access the capital or financial markets may limit our ability to execute our business plan or pursue improvements that we may rely on for future growth.

We rely on access to both short-term money markets (in the form of commercial paper and lines of credit) and long-term capital markets as a source of liquidity for capital and operating requirements not satisfied by the cash flow from our operations. If we are not able to access financial markets at competitive rates, our ability to implement our business plan and strategy will be affected. Certain market disruptions may increase our cost of borrowing or affect our ability to access one or more financial markets. Such market disruptions could result from:

·  
adverse economic conditions
·  
adverse general capital market conditions
·  
poor performance and health of the utility industry in general
·  
bankruptcy or financial distress of unrelated energy companies or Marketers
·  
significant decrease in the demand for natural gas
·  
adverse regulatory actions that affect our local gas distribution companies and our natural gas storage business
·  
terrorist attacks on our facilities or our suppliers
·  
extreme weather conditions

If we breach any of the financial covenants under our various credit facilities, our debt service obligations could be accelerated.

Our existing Credit Facility and the SouthStar line of credit contain financial covenants. If we breach any of the financial covenants under these agreements, our debt repayment obligations under them could be accelerated. In such event, we may not be able to refinance or repay all our indebtedness, which would result in a material adverse effect on our business, results of operations and financial condition.
 
A downgrade in our credit rating could negatively affect our ability to access capital.

Our senior unsecured debt is currently assigned a rating of BBB+ by S&P, Baa1 by Moody's and A- by Fitch. Our commercial paper currently is rated A2 by S&P, P2 by Moody's and F2 by Fitch, respectively. 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 likely decrease.
 
 
Additionally, if our credit rating by either S&P or Moody’s falls to non-investment grade status, we will be required to provide additional support for certain customers of our wholesale business. As of December 31, 2007, if our credit rating had fallen below investment grade, we would have been required to provide collateral of approximately $26 million to continue conducting our wholesale services business with certain counterparties.
 
We are vulnerable to interest rate risk with respect to our debt, which could lead to changes in interest expense and adversely affect our earnings.

We are subject to interest rate risk in connection with the issuance of fixed-rate and variable-rate debt. In order to maintain our desired mix of fixed-rate and variable-rate debt, we use interest rate swap agreements and exchange fixed-rate and variable-rate interest payment obligations over the life of the arrangements, without exchange of the underlying principal amounts. See Item 7A, “Quantitative and Qualitative Disclosures About Market Risk.” We cannot ensure that we will be successful in structuring such swap agreements to manage our risks effectively. If we are unable to do so, our earnings may be reduced. In addition, higher interest rates, all other things equal, reduce the earnings that we derive from transactions where we capture the difference between authorized returns and short-term borrowings.

We are a holding company and are dependent on cash flow from our subsidiaries, which may not be available in the amounts and at the times we need.

A portion of our outstanding debt was issued by our wholly-owned subsidiary, AGL Capital, which we fully and unconditionally guarantee. Since we are a holding company and have no operations separate from our investment in our subsidiaries, we are dependent on cash in the form of dividends or other distributions from our subsidiaries to meet our cash requirements. The ability of our subsidiaries to pay dividends and make other distributions is subject to applicable state law. Refer to Item 5 “Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” for additional dividend restriction information.
 
The use of derivative contracts in the normal course of our business could result in financial losses that negatively impact our results of operations.

We use derivatives, including futures, forwards and swaps, to manage our commodity and financial market risks. We could recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform under a contract. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could adversely affect the value of the reported fair value of these contracts.
 
As a result of cross-default provisions in our borrowing arrangements, we may be unable to satisfy all our outstanding obligations in the event of a default on our part.

Our Credit Facility under which our debt is issued contains cross-default provisions. Accordingly, should an event of default occur under some of our debt agreements, we face the prospect of being in default under other of our debt agreements, obliged in such instance to satisfy a large portion of our outstanding indebtedness and unable to satisfy all our outstanding obligations simultaneously.
 

We do not have any unresolved comments from the SEC staff regarding our periodic or current reports under the Securities Exchange Act of 1934, as amended.

ITEM 2.  PROPERTIES

Distribution Operations As of December 31, 2007, the properties of our distribution operations segment represented approximately 91% of the net property, plant and equipment in our consolidated balance sheet. This property primarily includes assets used for the distribution of natural gas to our customers in our service areas, including more than 44,000 miles of distribution and transmission mains. We have approximately 7.35 Bcf of LNG storage capacity in five LNG plants located in Georgia, New Jersey and Tennessee. In addition, we own three propane storage facilities in Virginia and Georgia that have a combined storage capacity of approximately 4.5 million gallons. These LNG plants and propane facilities supplement the gas supply during peak usage periods.

 
Energy Investments The properties in our energy investments segment are primarily investments that are complementary to our distribution operations or provide services consistent with our core enterprises, including a natural gas storage and hub facility in Louisiana located approximately eight miles from the Henry Hub. 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. Our natural gas storage and hub facility consists of two salt dome gas storage caverns with approximately 9.72 Bcf of total capacity and about 7.23 Bcf of working gas capacity. The facility has approximately 0.72 Bcf/day withdrawal capacity and 0.36 Bcf/day injection capacity. We completed a project during 2005 to expand compression capability, enabling us to increase the number of times a customer can inject and withdraw their total gas inventory annually from 10 to 12.

In addition, energy investments’ properties include telecommunications conduit and fiber in public rights-of-way that are leased to our customers primarily in Atlanta and Phoenix. This includes over 93,000 fiber miles, a 17,000 mile increase compared to 2006, of which approximately 29% of our dark fiber in Atlanta and 28% of our dark fiber in Phoenix has been leased.

Retail Energy Operations, Wholesale Services and Corporate The properties used at our retail energy operations, wholesale services and corporate segments consist primarily of leased and owned office space in Atlanta and Houston and their contents, including furniture and fixtures. The majority of our Atlanta-based employees are located at our corporate headquarters, a leased building with approximately 227,000 square feet of office space. In addition, our retail energy operations segment leases approximately 30,200 square feet at another office building in Atlanta. We lease approximately 50,000 square feet of office space for our employees in Houston.

We own or lease additional office, warehouse and other facilities throughout our operating areas. We consider our properties and the properties of our subsidiaries to be well maintained, in good operating condition and suitable for their intended purpose. We expect additional or substitute space to be available as needed to accommodate expansion of our operations.

ITEM 3.  LEGAL PROCEEDINGS

The nature of our business ordinarily results in periodic regulatory proceedings before various state and federal authorities. In addition, we are party, as both plaintiff and defendant, to a number of lawsuits related to our business on an ongoing basis. Management believes that the outcome of all regulatory proceedings and litigation in which we are currently involved will not have a material adverse effect on our consolidated financial condition or results of operations. Information regarding some of these proceedings is contained in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the caption “Results of Operations” and in Note 7“Commitments and Contingencies” to our consolidated financial statements under the caption “Litigation” set forth in Item 8, “Financial Statements and Supplementary Data.”




No matters were submitted to a vote of our security holders during the fourth quarter ended December 31, 2007.


Set forth below are the names, ages and positions of our executive officers along with their business experience during the past five years. All officers serve at the discretion of our Board of Directors. All information is as of the date of the filing of this report.

Name, age and position with the company
Periods served
   
John W. Somerhalder II, Age 52 (1)
 
Chairman, President and Chief Executive Officer
October 2007 - Present
President and Chief Executive Officer
March 2006 – October 2007
   
Andrew W. Evans, Age 41
 
Executive Vice President and Chief Financial Officer
May 2006 – Present
Senior Vice President and Chief Financial Officer
September 2005 – May 2006
Vice President and Treasurer
April 2002 – September 2005
   
Ralph Cleveland, Age 45
 
Senior Vice President, Engineering and Operations
November 2004 - Present
Vice President, Engineering and Construction
June 2002 – November 2004
   
Henry P. Linginfelter, Age 47
 
Executive Vice President, Utility Operations
June 2007 - Present
Senior Vice President, Mid-Atlantic Operations
November 2004– June 2007
President, Virginia Natural Gas, Inc.
October 2000 – November 2004
   
Kevin P. Madden, Age 55
 
Executive Vice President, External Affairs
November 2005 – Present
    Executive Vice President, Distribution and Pipeline Operations
April 2002 – November 2005
   
Melanie M. Platt, Age 53
 
Senior Vice President, Human Resources
September 2004 – Present
Senior Vice President and Chief Administrative Officer
November 2002 – September 2004
   
Douglas N. Schantz, Age 52 (2)
 
President, Sequent Energy Management, L.P.
May 2003 – Present
   
Paul R. Shlanta, Age 50
 
Executive Vice President, General Counsel and Chief Ethics and Compliance Officer
September 2005 – Present
Senior Vice President, General Counsel and Chief Corporate Compliance Officer
September 2002 – September 2005
   
   
(1)  
Mr. Somerhalder was executive vice president of El Paso Corporation (NYSE: EP) from 2000 until May 2005,
and he continued service under a professional services agreement from May 2005 until March 2006.
(2)  
Mr. Schantz served as vice president of the gas origination division at Cinergy Marketing & Trading, LP,
an affiliate of Cinergy Corp (NYSE: CIN) from September 2000 to April 2003.

 

PART II

 
Holders of Common Stock, Stock Price and Dividend Information

Our common stock is listed on the New York Stock Exchange under the symbol ATG. At January 31, 2008, there were 10,697 record holders of our common stock. Quarterly information concerning our high and low stock prices and cash dividends paid in 2007 and 2006 is as follows:
 
   
Sales price of common stock
   
Cash dividend per common
 
Quarter ended:
 
High
   
Low
   
share
 
2007
                 
March 31, 2007
  $
42.99
    $
38.20
    $
0.41
 
June 30, 2007
   
44.67
     
39.52
     
0.41
 
September 30, 2007
   
41.51
     
35.24
     
0.41
 
December 31, 2007
   
41.16
     
35.42
     
0.41
 
                    $
1.64
 
2006
                       
March 31, 2006
  $
36.48
    $
34.40
    $
0.37
 
June 30, 2006
   
38.13
     
34.43
     
0.37
 
September 30, 2006
   
40.00
     
34.76
     
0.37
 
December 31, 2006
   
40.09
     
36.04
     
0.37
 
                    $
1.48
 

We have historically paid dividends to common shareholders four times a year: March 1, June 1, September 1 and December 1. We have paid 240 consecutive quarterly dividends beginning in 1948. Our common shareholders may receive dividends when declared at the discretion of our Board of Directors. See Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Cash Flow from Financing Activities – Dividends on Common Stock.” Dividends may be paid in cash, stock or other form of payment, and payment of future dividends will depend on our future earnings, cash flow, financial requirements and other factors, some of which are noted below. In certain cases, our ability to pay dividends to our common shareholders is limited by the following:

·  
our ability to satisfy our obligations under certain financing agreements, including debt-to-capitalization and total shareholders’ equity covenants
·  
our ability to satisfy our obligations to any preferred shareholders

Under Georgia law, the payment of cash dividends to the holders of our common stock is limited to our legally available assets and subject to the prior payment of dividends on any outstanding shares of preferred stock. Our assets are not legally available for paying cash dividends if, after payment of the dividend:

·  
we could not pay our debts as they become due in the usual course of business, or
·  
our total assets would be less than our total liabilities plus, subject to some exceptions, any amounts necessary to satisfy (upon dissolution) the preferential rights of shareholders whose preferential rights are superior to those of the shareholders receiving the dividends



Issuer Purchases of Equity Securities

The following table sets forth information regarding purchases of our common stock by us and any affiliated purchasers during the three months ended December 31, 2007. 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)
 
October 2007
   
446,788
    $
38.99
     
446,788
     
5,084,912
 
November 2007
   
133,961
     
38.63
     
133,961
     
4,950,951
 
December 2007
   
2,592
     
37.48
     
-
     
4,950,951
 
Total fourth quarter
   
583,341
    $
38.90
     
580,749
         
(1)  
The total number of shares purchased includes an aggregate of 2,592 shares surrendered to us to satisfy tax withholding obligations
in connection with the vesting of shares of restricted stock and/or 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 any shares for such purposes in the fourth quarter of 2007.
As of December 31, 2007, we had purchased a total 297,234 of the 600,000 shares authorized for purchase, leaving 302,766 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.

The information required by this item regarding securities authorized for issuance under our equity compensation plans will be set forth under the caption “Executive Compensation – Equity Compensation Plan Information” in the Proxy Statement for our 2008 Annual Meeting of Shareholders or in a subsequent amendment to this report. All such information will be incorporated by reference from the Proxy Statement in Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” hereof or set forth in such amendment to this report.
 



Selected financial data about AGL Resources for the last five years is set forth in the table below. You should read the data in the table in conjunction with the consolidated financial statements and related notes set forth in Item 8, “Financial Statements and Supplementary Data.”

Dollars and shares in millions, except per share amounts
 
2007
   
2006
   
2005
   
2004
   
2003
 
Income statement data
                             
Operating revenues
  $
2,494
    $
2,621
    $
2,718
    $
1,832
    $
983
 
Cost of gas
   
1,369
     
1,482
     
1,626
     
995
     
339
 
Operating margin (1)
   
1,125
     
1,139
     
1,092
     
837
     
644
 
Operating expenses
                                       
     Operation and maintenance
   
451
     
473
     
477
     
377
     
283
 
     Depreciation and amortization
   
144
     
138
     
133
     
99
     
91
 
     Taxes other than income taxes
   
41
     
40
     
40
     
29
     
28
 
         Total operating expenses
   
636
     
651
     
650
     
505
     
402
 
Gain on sale of Caroline Street campus
   
-
     
-
     
-
     
-
     
16
 
Operating income
   
489
     
488
     
442
     
332
     
258
 
Equity in earnings of SouthStar Energy Services LLC
   
-
     
-
     
-
     
-
     
46
 
Other income (expense)
   
4
      (1 )     (1 )    
-
      (6 )
Minority interest
    (30 )     (23 )     (22 )     (18 )    
-
 
Earnings before interest and taxes (EBIT) (1)
   
463
     
464
     
419
     
314
     
298
 
Interest expense
   
125
     
123
     
109
     
71
     
75
 
Earnings before income taxes
   
338
     
341
     
310
     
243
     
223
 
Income taxes
   
127
     
129
     
117
     
90
     
87
 
Income before cumulative effect of change in accounting principle
   
211
     
212
     
193
     
153
     
136
 
Cumulative effect of change in accounting principle, net of $5 in income taxes
   
-
     
-
     
-
     
-
      (8 )
Net income
  $
211
    $
212
    $
193
    $
153
    $
128
 
Common stock data
                                       
Weighted average shares outstanding basic
   
77.1
     
77.6
     
77.3
     
66.3
     
63.1
 
Weighted average shares outstanding diluted
   
77.4
     
78.0
     
77.8
     
67.0
     
63.7
 
Total shares outstanding (2)
   
76.4
     
77.7
     
77.8
     
76.7
     
64.5
 
Earnings per share - basic
  $
2.74
    $
2.73
    $
2.50
    $
2.30
    $
2.03
 
Earnings per share - diluted
  $
2.72
    $
2.72
    $
2.48
    $
2.28
    $
2.01
 
Dividends declared per share
  $
1.64
    $
1.48
    $
1.30
    $
1.15
    $
1.11
 
Dividend payout ratio
    60 %     54 %     52 %     50 %     55 %
Dividend yield
    4.4 %     3.8 %     3.7 %     3.5 %     3.8 %
Book value per share (3)
  $
21.74
    $
20.72
    $
19.27
    $
18.04
    $
14.66
 
Price-earnings ratio
   
13.7
     
14.3
     
13.9
     
14.5
     
14.3
 
Stock price market range
   
$35.24-$44.67
     
$34.40-$40.09
     
$32.00-$39.32
     
$26.50-$33.65
     
$21.90-$29.35
 
Market value per share (4)
  $
37.64
    $
38.91
    $
34.81
    $
33.24
    $
29.10
 
Market value (2)
  $
2,876
    $
3,023
    $
2,708
    $
2,551
    $
1,877
 
Balance sheet data (2)
                                       
Total assets
  $
6,268
    $
6,147
    $
6,320
    $
5,637
    $
3,972
 
Property, plant and equipment – net
   
3,566
     
3,436
     
3,333
     
3,178
     
2,345
 
Working capital
   
166
     
156
     
73
      (20 )     (306 )
Total debt
   
2,254
     
2,161
     
2,137
     
1,957
     
1,340
 
Common shareholders’ equity
   
1,661
     
1,609
     
1,499
     
1,385
     
945
 
Cash flow data
                                       
Net cash provided by operating activities
  $
376
    $
354
    $
80
    $
287
    $
122
 
Property, plant and equipment expenditures
   
259
     
253
     
267
     
264
     
158
 
Net borrowings and (payments) of short-term debt
   
52
     
6
     
188
      (480 )     (82 )
Financial ratios (2)
                                       
Total debt
    58 %     57 %     59 %     59 %     59 %
Common shareholders’ equity
    42 %     43 %     41 %     41 %     41 %
  Total
    100 %     100 %     100 %     100 %     100 %
Return on average common shareholders’ equity
    12.9 %     13.6 %     13.4 %     13.1 %     15.5 %
(1)  
These are non-GAAP measurements. A reconciliation of operating margin and EBIT to our operating income and net income is contained in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations-AGL Resources-Results of Operations.”
(2)  
As of the last day of the fiscal period.
(3)  
Common shareholders’ equity divided by total outstanding common shares as of the last day of the fiscal period.
(4)  
Closing price of common stock on the New York Stock Exchange as of the last trading day of the fiscal period.
 
 
 


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. Our six utilities serve more than 2.2 million 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. We are involved in various related businesses, including retail natural gas marketing to end-use customers primarily in Georgia; natural gas asset management and related logistics activities for our own utilities as well as for nonaffiliated companies; natural gas storage arbitrage and related activities; and the development and operation of high-deliverability underground natural gas storage assets. We also own and operate a small telecommunications business that constructs and operates conduit and fiber infrastructure within select metropolitan areas. We manage these businesses through four operating segments – distribution operations, retail energy operations, wholesale services and energy investments – and a nonoperating corporate segment. As of January 31, 2008, we employed a total of 2,332 employees across these five segments.

The distribution operations segment is the largest component of our business and is subject to regulation and oversight by agencies in each of the six states we serve. These agencies approve natural gas rates designed to provide us the opportunity to generate revenues to recover the cost of natural gas delivered to our customers and our fixed and variable costs such as depreciation, interest, maintenance and overhead costs, and to earn a reasonable return for our shareholders. With the exception of Atlanta Gas Light, our largest utility, the earnings of our regulated utilities can be affected by customer consumption patterns that are a function of weather conditions and price levels for natural gas. Various mechanisms exist that limit our exposure to weather changes within typical ranges in all of our jurisdictions. Our retail energy operations segment, which consists of SouthStar, also is weather sensitive and uses a variety of hedging strategies, such as weather derivative instruments and other risk management tools, to mitigate potential weather impacts. Our Sequent subsidiary within our wholesale services segment is relatively temperature sensitive, but has greater opportunity to capture margin as price volatility increases. Our energy investments segment’s primary activity is our natural gas storage business, which develops, acquires and operates high-deliverability salt-dome storage assets in the Gulf Coast region of the United States. While this business also can generate additional revenue during times of peak market demand for natural gas storage services, the majority of our storage services are covered under medium to long-term contracts at a fixed market rate.


In support of our goals for 2007, we focused our efforts around five key operating priorities as discussed below.

Marketing and customer retention investments in distribution operations and retail energy operations

We targeted overall net customer growth rates for our distribution operations business in the range of 1% to 1.5%. In each of our utility service areas, we implemented targeted marketing and growth programs aimed at emphasizing natural gas as the fuel of choice for customers and expanding the use of natural gas through a variety of promotional activities. In 2007, we grew our average customer count by approximately 21,000, a 0.9% increase as compared to last year. While this increase is slightly below our targeted range, the increase in the growth rate is an improvement over our relatively flat customer growth in 2006. Last year we had slower customer growth coming out of the winter heating season due in part to much higher natural gas prices, warmer weather and a higher average customer attrition rate of 1.9% in 2006 as compared to 1.2% in 2007, which reflects a 37% improvement. Our customer growth rate was negatively impacted by the downturn in the housing market during 2007; factors which are expected to continue to have a negative impact on customer growth in 2008. We continue to focus significant efforts in our distribution operations business on improving our net customer growth trends, despite the overall economy and the industry-wide challenges of rising natural gas prices, competition from alternative fuels and declining natural gas usage per customer.

These factors also impact customer growth at SouthStar where we are also focused on similar customer growth initiatives. We will continue to enter new markets and improve the overall profitability of its customers through a variety of enhancements to existing, and the implementation of new, product offerings and pricing plans. In 2007, SouthStar grew its average customer count by approximately 7,000 or a 1.3% increase over last year.


 
Return to normal weather and usage patterns

In 2007, we saw average customer usage patterns related to natural gas price and weather conditions return to levels more consistent with historical averages. As the weather grew colder, compared to last year, and moved closer to 10-year average weather patterns primarily in Maryland, New Jersey and Virginia, we saw the conservation that occurred a year ago largely reverse itself and return to expected levels. Due to these factors, coupled with our targeted marketing and growth programs mentioned above, our overall throughput in 2007 at distribution operations increased 1% as compared to prior year and 3% at SouthStar for its customers in Georgia. While we saw these improvements in throughput and weather that was colder than last year by 10% in Maryland, 17% in New Jersey and 6% in Virginia, weather did not completely return to normal and consequently our earnings continue to be negatively impacted by warmer-than-normal weather. We attempt to stabilize and mitigate the impact to our earnings due to weather through hedging activities at SouthStar and through WNA regulatory mechanisms in distribution operations. While our hedging activities in 2007 at SouthStar largely offset the negative impact to earnings due to weather that was warmer than normal, distribution operations earnings were negatively impacted by $9 million due to weather that was warmer than normal and because the WNA regulatory mechanisms did not completely offset the negative impact to earnings from decreased consumption resulting from the warmer weather. These WNA regulatory mechanisms are most effective in reasonable temperature ranges relative to normal weather using historical averages due in part to their inherent design but also due to customer consumption patterns that are affected by weather conditions other than temperature. These other weather conditions include wind, cloud cover, precipitation and the duration of colder weather, among others, that are not captured in weather normalization adjustments, which are based primarily on average temperatures.

There are a number of legislative and regulatory proposals to address greenhouse gas emissions such as carbon dioxide, which are in various phases of discussion or implementation. We continue to actively monitor these proposals and discussions because the results could negatively impact our operations through reduced demand for natural gas and increased costs to our business. While we are unable to predict the outcome and quantify any impacts from these discussions and proposals at this point, we are active in promoting natural gas as the cleanest and most efficient burning fossil fuel with the lowest carbon content as compared to oil and coal.
 
Volatility in wholesale markets

Lower volatility in the natural gas markets, as compared to last year, has limited Sequent’s asset optimization and arbitrage opportunities to generate operating margin in 2007. An important component of Sequent’s business is its ability to capture operating margin based on seasonal and locational spreads, both of which were significantly reduced in 2007 as compared to 2006. We continue to expect less volatility in the natural gas markets and, therefore, we expect Sequent’s abilities to capture economic value from asset optimization and arbitrage opportunities to be more consistent with those captured in 2007 as opposed to 2006 and 2005.

Operational efficiency and cost control

We continue to focus on operating our business as efficiently as possible, especially within our distribution operations and corporate segments through control of our operating costs. One of the key metrics we monitor in distribution operations is our operation and maintenance expenses per customer that was $145 per customer for 2007 as compared to $156 per customer in 2006, a 7% decrease year-over-year. This decrease was largely driven by a decrease in incentive compensation for employees at distribution operations and corporate as compared to last year due to lower payouts resulting from lower earnings per share in 2007 as compared to our AIP earning per share goals. Additionally in 2006 our earnings per share results were at the top end of the goals under the AIP, resulting in higher incentive compensation for 2006.

We further utilize outside vendors to assist us with the execution of business processes that are ancillary to our delivery of natural gas and related to the performance of basic business functions. This allows us to control operating costs, increase the efficiency through which these functions are executed and improve our service levels to customers. Most recently, we partnered with third parties in India to provide certain call center operations, as well as certain support functions related to information technology, finance, supply chain and engineering.

 
New market growth and regulatory opportunities

The four previous operating priorities require us to actively and continuously monitor the emerging issues and trends within our current operations and industry to allow us to take advantage of opportunities that complement and add value to our existing business operations. In 2007, we continued to expand Sequent’s operations into the western United States and Canada, as well as SouthStar’s operations into Ohio and Florida. Further, in October 2007, we acquired and have included within our wholesale services operating segment Compass Energy, which has enabled us to serve a broader geography of commercial and industrial customers. Additionally, we continued to focus our efforts around our storage business, particularly our Golden Triangle Storage underground natural gas storage project. We achieved a significant milestone in this project at the end of 2007 as the FERC issued an order granting a Certificate of Public Convenience and Necessity to construct and operate the underground storage project and approving market-based rates for the services Golden Triangle Storage will provide. In January 2008, we accepted the FERC’s certificate and expect construction to begin in the first half of 2008.

In distribution operations, we were also successful with certain regulatory initiatives that are critical to the fundamentals of our business as they help to preserve the long-term success and earnings potential of our utility businesses. In September 2007, we received approval from the Georgia Commission on our capacity supply plan in Georgia, and a key part of that agreement was the ability to diversify our supply sources by gaining more access to the Elba Island LNG facility. As a result, we have negotiated an agreement with SNG to obtain an undivided interest in pipelines connecting our Georgia service territory to the Elba Island LNG facility and have filed a joint application with the FERC for approval of the project, which is expected to cost $22 million. In October 2007, the Georgia Commission approved the extension of the asset management agreement between Sequent and Atlanta Gas Light through March 2012. We are actively working with the respective commissions to renew or amend the existing agreements set to expire in 2008 in our other jurisdictions.

In September 2007, the Virginia Commission approved Virginia Natural Gas’ WNA rider for commercial customers that applies to the 2007 and 2008 heating seasons. In Florida, we received approval from the Florida Commission in December 2007 to include the amortization of certain components of the purchase price we paid for Florida City Gas in our return on equity calculation for regulatory reporting purposes. Additionally, the Florida Commission’s approval included provisions for a five-year stay out. As a result, Florida City Gas’ base rates will not change during this period, except for unforeseen events beyond our control and the Florida Commission initiating base rate proceedings.

In November 2007, Elkton Gas filed a base rate case with the Maryland Commission requesting a rate increase of less than $1 million. Starting in 2009 through 2011, we will be required to file base rate cases for Atlanta Gas Light, Virginia Natural Gas, Elizabethtown Gas and Chattanooga Gas. While we are unable to predict the outcome of these base rate proceedings, we will focus on incorporating and potentially proposing regulatory solutions into our base rate filings for many of the areas related to our key operation priorities as well as other emerging issues and trends impacting our utilities.


Revenues We generate nearly all our operating revenues through the sale, distribution and storage of natural gas. We include in our consolidated revenues an estimate of revenues from natural gas distributed, but not yet billed, to residential and commercial customers from the latest meter reading date to the end of the reporting period. The following table provides more information regarding the components of our operating revenues.

In millions
 
2007
   
2006
   
2005
 
Residential
  $
1,143
    $
1,127
    $
1,177
 
Commercial
   
500
     
460
     
452
 
Transportation
   
401
     
434
     
450
 
Industrial
   
250
     
310
     
412
 
Other
   
200
     
290
     
227
 
Total operating revenues
  $
2,494
    $
2,621
    $
2,718
 

Operating margin and EBIT We evaluate the performance of our operating segments using the measures of operating margin and EBIT. 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 billed 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 operating 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.
 
 
Our operating margin and EBIT are not measures that are considered to be calculated in accordance with GAAP. 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 as determined in accordance with GAAP. In addition, our operating margin and EBIT measures may not be comparable to similarly titled measures of other companies. The table below sets forth a reconciliation of our operating margin and EBIT to our operating income and net income, together with other consolidated financial information for the years ended December 31, 2007, 2006 and 2005.

In millions, except per share amounts
 
2007
   
2006
   
2005
 
Operating revenues
  $
2,494
    $
2,621
    $
2,718
 
Cost of gas
   
1,369
     
1,482
     
1,626
 
Operating margin
   
1,125
     
1,139
     
1,092
 
Operating expenses
                       
Operation and maintenance
   
451
     
473
     
477
 
Depreciation and amortization
   
144
     
138
     
133
 
Taxes other than income
   
41
     
40
     
40
 
Total operating expenses
   
636
     
651
     
650
 
Operating income
   
489
     
488
     
442
 
Other income (expense)
   
4
      (1 )     (1 )
Minority interest
    (30 )     (23 )     (22 )
EBIT
   
463
     
464
     
419
 
Interest expense
   
125
     
123
     
109
 
Earnings before income taxes
   
338
     
341
     
310
 
Income taxes
   
127
     
129
     
117
 
Net income
  $
211
    $
212
    $
193
 
Earnings per common share:
                       
Basic
  $
2.74
    $
2.73
    $
2.50
 
Diluted
  $
2.72
    $
2.72
    $
2.48
 
Weighted average number of common shares outstanding:
                       
Basic
   
77.1
     
77.6
     
77.3
 
Diluted
   
77.4
     
78.0
     
77.8
 


 
 
Selected weather, customer and volume metrics for 2007, 2006 and 2005, are presented in the following table.
 
Weather
                         
2007 vs.
   
2006 vs.
   
2007 vs.
   
2006 vs.
2005 vs 
 
Heating degree days (1)
   
Year ended December 31,
   
2006
   
2005
   
normal
   
normal
 normal
 
   
Normal
   
2007
   
2006
   
2005
   
colder (warmer)
   
colder (warmer)
   
colder (warmer)
   
colder (warmer)
colder (warmer)
 
Florida
   
495
     
326
     
468
     
552
      (30 )%     (15 )%     (34 )%     (5 )%     12 %
Georgia
   
2,582
     
2,366
     
2,455
     
2,739
      (4 )%     (10 )%     (8 )%     (5 )%     6 %
Maryland
   
4,659
     
4,621
     
4,205
     
4,966
      10 %     (15 )%     (1 )%     (10 )%     7 %
New Jersey
   
4,588
     
4,777
     
4,074
     
4,931
      17 %     (17 )%     4 %     (11 )%     7 %
Tennessee
   
2,950
     
2,722
     
2,892
     
3,119
      (6 )%     (7 )%     (8 )%     (2 )%     6 %
Virginia
   
3,126
     
3,055
     
2,870
     
3,469
      6 %     (17 )%     (2 )%     (8 )%     11 %
 
(1) Obtained from the National Oceanic and Atmospheric Administration. National Climatic Data Center.
      Normal represents the ten-year averages from January 1998 to December 2007.
 
Customers
 
Year ended December 31,
   
2007 vs. 2006
   
2006 vs. 2005
 
   
2007
   
2006
   
2005
   
% change
   
% change
 
Distribution Operations
                             
Average end-use customers (in thousands)
                             
Atlanta Gas Light
   
1,559
     
1,546
     
1,545
      0.8 %     0.1 %
Chattanooga Gas
   
61
     
61
     
61
     
-
     
-
 
Elizabethtown Gas
   
272
     
269
     
266
     
1.1
     
1.1
 
Elkton Gas
   
6
     
6
     
6
     
-
     
-
 
Florida City Gas
   
104
     
104
     
103
     
-
     
1.0
 
Virginia Natural Gas
   
269
     
264
     
261
     
1.9
     
1.2
 
Total
   
2,271
     
2,250
     
2,242
      0.9 %     0.4 %
Operation and maintenance expenses per customer
  $
145
    $
156
    $
166
      (7 )%     (6 )%
EBIT per customer
  $
149
    $
138
    $
133
      8 %     4 %
                                         
Retail Energy Operations
                                       
Average customers (in thousands)
   
540
     
533
     
531
      1.3 %     0.4 %
Market share in Georgia
    35 %     35 %     35 %    
-
     
-
 
      
                
Volumes
In billion cubic feet (Bcf)
 
Year ended December 31,
   
2007 vs. 2006
   
2006 vs. 2005
 
   
2007
   
2006
   
2005
   
% change
   
% change
 
Distribution Operations
                             
    Firm
   
211
     
199
     
228
      6 %     (13 )%
    Interruptible
   
108
     
117
     
117
      (8 )%     -  
Total
   
319
     
316
     
345
      1 %     (8 )%
                                         
Retail Energy Operations
                                       
    Georgia firm
   
38.5
     
37.2
     
42.6
      3 %     (13 )%
    Ohio and Florida
   
4.5
     
1.3
     
-
      246 %     100 %
                                         
Wholesale Services
                                       
    Daily physical sales (Bcf / day)
   
2.35
     
2.20
     
2.17
      7 %     1 %

Segment information Operating revenues, operating margin, operating expenses and EBIT information for each of our segments are contained in the following tables for the years ended December 31, 2007, 2006 and 2005.

In millions
 
Operating revenues
   
Operating margin (1)
   
Operating expenses
   
EBIT (1)
 
2007