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, 2012
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 each 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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 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, a non-accelerated filer, or a smaller reporting company
 
Large accelerated filer  þ                 Accelerated filer  ¨                 Non-accelerated filer ¨                 Smaller reporting company ¨
   
                                                                                     (Do not check if smaller reporting company)
 
Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes ¨  No þ
 
The aggregate market value of the registrant’s common stock held by non-affiliates of the registrant (based on the closing sale price on June 29, 2012, as reported by the New York Stock Exchange), was $4,553,236,484.
   
The number of shares of the registrant’s common stock outstanding as of January 31, 2013 was 117,876,484.
   
DOCUMENTS INCORPORATED BY REFERENCE:
 
Portions of the Proxy Statement for the 2013 Annual Meeting of Shareholders (Proxy Statement) to be held on April 30, 2013, are incorporated by reference in Part III.

 
 

 
 
 

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AGL Capital
AGL Capital Corporation
 
AGL Credit Facility
$1.3 billion credit agreement entered into by AGL Capital to support the AGL Capital commercial paper program
 
AGL Resources
AGL Resources Inc., together with its consolidated subsidiaries
 
Atlanta Gas Light
Atlanta Gas Light Company
 
Bcf
Billion cubic feet
 
Bridge Facility
Credit agreement entered into by AGL Capital Corporation to finance a portion of the Nicor merger
 
Central Valley
Central Valley Gas Storage, LLC
 
Chattanooga Gas
Chattanooga Gas Company
 
Chicago Hub
A venture of Nicor Gas, which provides natural gas storage and transmission-related services to marketers and gas distribution companies
 
California Commission
California Public Utilities Commission, the state regulatory agency for Central Valley
 
EBIT
Earnings before interest and taxes, a non-GAAP measure that includes operating income and other income and excludes financing costs, including interest on debt and income tax expense
 
ERC
Environmental remediation costs associated with our distribution operations segment that are generally recoverable through rate mechanisms
 
FASB
Financial Accounting Standards Board
 
FERC
Federal Energy Regulatory Commission
 
Fitch
Fitch Ratings
 
Florida Commission
Florida Public Service Commission, the state regulatory agency for Florida City Gas
 
GAAP
Accounting principles generally accepted in the United States of America
 
Georgia Commission
Georgia Public Service Commission, the state regulatory agency for Atlanta Gas Light
 
Georgia Natural Gas
The trade name under which SouthStar does business in Georgia
 
Golden Triangle Storage
Golden Triangle Storage, Inc.
 
Hampton Roads
Virginia Natural Gas’ pipeline project that connects its northern and southern pipelines
 
Heating Degree Days
A measure of the effects of weather on our businesses, calculated when the average daily temperatures are less than 65 degrees Fahrenheit
 
Heating Season
The period from November through March when natural gas usage and operating revenues are generally higher because weather is colder
 
Henry Hub
A major interconnection point of natural gas pipelines in Erath, Louisiana where NYMEX natural gas future contracts are priced
 
Horizon Pipeline
Horizon Pipeline Company, LLC
 
Illinois Commission
Illinois Commerce Commission, the state regulatory agency for Nicor Gas
 
Jefferson Island
Jefferson Island Storage & Hub, LLC
 
LIBOR
London Inter-Bank Offered Rate
 
LIFO
Last-in, first-out, an accounting method used to account for inventory
 
LNG
Liquefied natural gas
 
LOCOM
Lower of weighted average cost or current market price
 
Magnolia
Magnolia Enterprise Holdings, Inc.
 
Marketers
Marketers selling retail natural gas in Georgia and certificated by the Georgia Commission
 
Merger Agreement
Agreement and Plan of Merger, dated December 6, 2010, as amended, by and among the Company, Nicor, Apollo Acquisition Corp, an Illinois corporation and wholly owned subsidiary of the Company, and Ottawa Acquisition LLC, an Illinois Limited Liability Company and a wholly owned subsidiary of the Company
 
MGP
Manufactured gas plant
 
Moody’s
Moody’s Investors Service
 
New Jersey BPU
New Jersey Board of Public Utilities, the state regulatory agency for Elizabethtown Gas
 
Nicor
Nicor Inc. - an acquisition completed in December 2011 and former holding company of Nicor Gas
 
Nicor Advanced Energy
Prairie Point Energy, LLC, doing business as Nicor Advanced Energy
 
Nicor Gas
Northern Illinois Gas Company, doing business as Nicor Gas Company
 
Nicor Gas Credit Facility
$700 million credit facility entered into by Nicor Gas to support its commercial paper program
 
Nicor Services
Nicor Energy Services Company
 
Nicor Solutions
Nicor Solutions, LLC
 
NUI
NUI Corporation - acquired in November 2004
 
NYMEX
New York Mercantile Exchange, Inc.
 
OCI
Other comprehensive income
 
Operating margin
A non-GAAP measure of income, calculated as operating revenues minus cost of goods sold and revenue tax expense
OTC
Over-the-counter
Pad gas
Volumes of non-working natural gas used to maintain the operational integrity of the natural gas storage facility, also known as base gas
PBR
Performance-based rate, a regulatory plan at Nicor Gas that provided economic incentives based on natural gas cost performance. The plan terminated in 2003
PGA
Purchased Gas Adjustment
Piedmont
Piedmont Natural Gas Company, Inc.
Pivotal Utility
Pivotal Utility Holdings, Inc., doing business as Elizabethtown Gas, Elkton Gas and Florida City Gas
PP&E
Property, plant and equipment
S&P
Standard & Poor’s Ratings Services
SEC
Securities and Exchange Commission
Sequent
Sequent Energy Management, L.P.
Seven Seas
Seven Seas Insurance Company, Inc.
SNG
Substitute natural gas, a synthetic form of gas manufactured from coal
SouthStar
SouthStar Energy Services LLC
STRIDE
Atlanta Gas Light’s Strategic Infrastructure Development and Enhancement program
Tennessee Authority
Tennessee Regulatory Authority, the state regulatory agency for Chattanooga Gas
Term Loan Facility
$300 million credit agreement entered into by AGL Capital to repay the $300 million senior notes due in 2011
TEU
Twenty-foot equivalent unit, a measure of volume in containerized shipping equal to one 20-foot-long container
Triton
Triton Container Investments LLC, a cargo container leasing company in which we have an investment
Tropical Shipping
Tropical Shipping and Construction Company Limited, a Cayman Islands company. A wholly owned business and a carrier of containerized freight in the Bahamas and the Caribbean region
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, the state regulatory agency for Virginia Natural Gas
WACOG
Weighted average cost of gas
WNA
Weather normalization adjustment



 
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Certain expectations and projections regarding our future performance referenced in this section and elsewhere in this report, as well as in other reports and proxy statements we file with the SEC or otherwise release to the public and on our website are forward-looking statements within the meaning of the United States federal securities laws and are subject to uncertainties and risks, as itemized in Item 1A “Risk Factors,” in this Form 10-K. Senior officers and other employees also may make verbal statements to analysts, investors, regulators, the media and others that are forward-looking.

Forward-looking statements involve matters that are not historical facts, and because these statements involve anticipated events or conditions, forward-looking statements often include words such as "anticipate," "assume," “believe,” "can," "could," "estimate," "expect," "forecast," "future," “goal,” "indicate," "intend," "may," “outlook,” "plan," “potential,” "predict," "project,” “proposed,” "seek," "should," "target," "would" or similar expressions. You are cautioned not to place undue reliance on our forward-looking statements. Our expectations are not guarantees and are based on currently available competitive, financial and economic data along with our operating plans. While we believe that our expectations are reasonable in view of currently available information, our expectations are subject to future events, risks and uncertainties, and there are numerous factors - many of which are beyond our control - that could cause our actual results to vary significantly from our expectations.

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

We caution readers that the important factors described elsewhere in this report, among others, could cause our business, results of operations or financial condition to differ significantly from those expressed in any forward-looking statements. There also may be other factors that we cannot anticipate or that are not described in this report that could cause our actual results to differ significantly from our expectations.

Forward-looking statements are only as of the date they are made. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of future events, new information or otherwise, except as required under United States federal securities law.



Unless the context requires otherwise, references to “we,” “us,” “our” and the “company” are intended to mean AGL Resources Inc. together with its consolidated subsidiaries. The operations and businesses described in this filing are owned and operated, and management services provided, by distinct direct and indirect subsidiaries of AGL Resources. AGL Resources Inc. was organized and incorporated in 1995 under the laws of the State of Georgia.

Nature of Our Business

AGL Resources Inc. is an energy services holding company. Our primary business is the distribution of natural gas in seven states - Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee and Maryland - through our seven natural gas distribution utilities. At December 31, 2012, our utilities served approximately 4.5 million end-use customers.

We also are involved in several other businesses that are primarily related and complementary to our primary business. Our retail operations segment serves more than one million retail customers and markets natural gas and related home services to end-use customers in Georgia, Illinois, Indiana, Ohio, Florida and New York. Our wholesale services segment engages in natural gas storage and gas pipeline arbitrage and related activities. Additionally, it provides natural gas asset management and/or related logistics services for each of our utilities, as well as for non-affiliated companies. Our midstream operations segment provides natural gas storage arbitrage and related activities and engages in the development and operation of high-deliverability natural gas storage assets. We also are involved in the shipping industry through our cargo shipping segment, which owns and operates Tropical Shipping, one of the largest containerized cargo carriers serving the Bahamas and the Caribbean.

 
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Our operating segments consist of the following five operating and reporting segments - distribution operations, retail operations, wholesale services, midstream operations, cargo shipping and one non-operating segment - other. These segments are consistent with how management views and manages our businesses. 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 13 to our consolidated financial statements under Item 8 herein.

Merger with Nicor

On December 9, 2011, we closed our merger with Nicor and created a combined company with increased scale and scope in the distribution, storage and transportation of natural gas. As a result, we are currently the nation’s largest natural gas distribution company based on customer count. The effects of Nicor’s results of operations and financial condition are reflected for the twelve months ended December 31, 2012, while our 2011 results include activity from December 10, 2011 through December 31, 2011. See Note 3 to our consolidated financial statements under Item 8 herein for more information on the impacts of the Nicor merger on our business.


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

Utility
 
State
 
Number of customers
(in thousands)
   
Approximate
miles of pipe
 
Nicor Gas
 
Illinois
    2,188       34,000  
Atlanta Gas Light
 
Georgia
    1,541       32,300  
Virginia Natural Gas
 
Virginia
    281       5,500  
Elizabethtown Gas
 
New Jersey
    277       3,150  
Florida City Gas
 
Florida
    104       3,450  
Chattanooga Gas
 
Tennessee
    62       1,600  
Elkton Gas
 
Maryland
    6       100  
Total
        4,459       80,100  

Our primary focus in our distribution operations business is the safe and reliable delivery of natural gas to our end-users. In integrating Nicor Gas into our existing distribution operations, we focused on the standardization of operational processes and continue to focus on delivering superior customer service.

We experienced a 0.1% increase in our total number of customers in 2012, consistent with the 0.1% increase in 2011, excluding Nicor Gas. The customer count of Nicor Gas remained flat in 2012, compared to the year ended 2011. We anticipate customer growth trends to improve slightly in 2013 compared to 2012.

Competition and Customer Demand

All of our utilities face competition from other energy products. Our principal competitors are electric utilities and oil and propane providers serving the residential and commercial markets throughout our service areas. Additionally, the potential displacement or replacement of natural gas appliances with electric appliances is a competitive factor.

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 commercial construction; and
·  
new housing starts.

We continue to develop and grow our business through our use of a variety of targeted marketing programs designed to attract new customers and to retain existing customers. These efforts include working to add residential customers, multifamily complexes and commercial customers who use natural gas for purposes other than space heating, as well as evaluating and launching new natural gas related programs, products and services to enhance customer growth, mitigate customer attrition and increase operating revenues.

 
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The natural gas related programs generally emphasize natural gas as the fuel of choice for customers and seek to expand the use of natural gas through a variety of promotional activities. In addition, we partner with numerous third-party entities such as builders, realtors, plumbers, mechanical contractors, architects and engineers to market the benefits of natural gas appliances and to identify potential retention options early in the process for those customers who might consider converting to alternative fuels.

We work with regulators and state agencies in each of our jurisdictions to educate customers throughout the year about energy costs in advance of the Heating Season, and to ensure that those customers qualifying for the Low Income Home Energy Assistance Program and other similar programs receive any needed assistance. We expect to continue this focus for the foreseeable future. We have also worked with the Illinois Commission, the Virginia Commission, the Tennessee Authority and the New Jersey BPU to educate our customers about energy efficiency and conservation and to provide rebates and other incentives for the purchase of high-efficiency natural gas-fueled equipment.

Sources of Natural Gas Supply

Procurement plans for natural gas supply and transportation to serve our regulated utility customers are reviewed and approved by our state utility commissions. Accordingly, we purchase natural gas supplies in the open market by contracting with producers and marketers. We also contract for transportation and storage services from interstate pipelines that are regulated by the FERC. When firm pipeline services are temporarily not needed, we may release the services in the secondary market under FERC-approved capacity release provisions or utilize asset management arrangements, reducing the cost of natural gas charged to customers for most of our utilities. Peak-use requirements are met through utilization of company-owned storage facilities, pipeline transportation capacity, purchased storage services, peaking facilities and other supply sources, arranged by either our transportation customers or us. We have been able to obtain sufficient supplies of natural gas to meet customer requirements. We believe natural gas supply and pipeline capacity will be sufficiently available to meet market demands in the foreseeable future.

Transportation Our utilities use firm pipeline entitlements, storage services, and/or peaking capacity contracted with interstate capacity providers to serve the firm gas supply needs of our customers. In addition, Nicor Gas, Atlanta Gas Light, Chattanooga Gas, Elizabethtown Gas and Virginia Natural Gas operate on-system LNG facilities, underground natural gas storage fields and/or propane / air plants to meet the gas supply and deliverability requirements of their customers in the winter period. Generally, we work to build a portfolio of year-round firm transportation, seasonal storage and short-duration peaking services that will meet the needs of our customers under severe weather conditions with adequate operational flexibility to reliably manage the variability inherent in servicing customers using natural gas for space heatingWe believe that including seasonal storage and peaking services in this portfolio is more efficient and cost effective compared to reserving firm pipeline capacity rights all year for a limited number of cold winter days.

Typically, our firm contracts range in duration from 3 to 10 years. We work to stagger terms to maintain our ability to adjust the overall portfolio to meet changing market conditions. Our utilities have contracted for capacity that is predominately sourced from producing areas in the midcontinent and gulf coast regions and they continue to evaluate capacity options that will provide long-term access to reliable and affordable natural gas supply. We have and will continue to evaluate options to acquire capacity rights from shale gas being produced in close proximity to our service territories.

Given the number of agreements held by our utilities and the amount of capacity under contract, we make decisions as to the termination, extension or renegotiation of contracts every year. Slower demand associated with the weak economy and the recent warm winter season coupled with the growth in non-traditional supply basins have made the value assessment of capacity contracts more complex.

Supply Six of our utilities use asset management agreements with our wholly owned subsidiary, Sequent, with the primary goal of reducing our utility customers’ gas cost recovery rates through payments to the utilities by Sequent (for Atlanta Gas Light these payments are controlled by the Georgia Commission and utilized for infrastructure improvements and to fund heating assistance programs, rather than a reduction to gas cost recovery rates). Under these asset management agreements, Sequent supplies natural gas to the utility and markets excess capacity to improve the overall cost of supplying gas to the utility customers. At this time, the utilities purchase most of their gas from Sequent. The purchase agreements obligate Sequent to provide firm gas to our utilities. However, these utilities maintain the right and ability to make their own supply purchases. This right allows our utilities to make long-term supply arrangements if they believe it is in the best interest of their customers.

The agreements with Sequent have one of the following: an annual minimum guarantee within a profit sharing structure, a profit sharing structure without any annual minimum guarantee or a fixed fee. Under these agreements, Sequent made payments of $15 million to our utilities in 2012. From the inception of these agreements in 2001 through 2012, Sequent has made sharing payments under these agreements totaling $207 million.

 
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The following table provides payments made by Sequent to our utilities under these agreements during the last three years.

   
Total amount received
   
In millions
 
2012
   
2011
   
2010
 
Expiration Date
Atlanta Gas Light
  $ 5     $ 9     $ 4  
March 2017
Virginia Natural Gas
    3       9       5  
March 2016
Elizabethtown Gas
    5       9       10  
March 2014
Florida City Gas
    1       2       1  
March 2014
Chattanooga Gas
    1       3       4  
March 2014
Total
  $ 15     $ 32     $ 24    

In March 2012, the Georgia Commission authorized the renewal of the asset management agreement between Atlanta Gas Light and Sequent. The renewed five-year agreement requires Sequent to pay minimum annual fees of $3 million and includes a slight increase in sharing levels associated with storage inventory activity.

Nicor Gas is our only utility that has not entered into an affiliated asset management agreement with Sequent. Accordingly, it purchases its gas supply under firm contracts from a number of different suppliers, typically using the North American Energy Standards Board standard contract. The transactions conducted under the contracts include firm base load supplies, firm daily swing supplies and spot market purchases. The agreements often include some form of index pricing, but purchases may also be made using negotiated pricing. A majority of the purchases specify the pipeline receipt point associated with capacity held by Nicor Gas, but some purchases are made on a city-gate delivered basis.

Utility Regulation and Rate Design

Rate Structures Our utilities operate subject to regulations and oversight of the state regulatory agencies in each of the states served by our utilities with respect to rates charged to our customers, maintenance of accounting records and various service and safety matters. Rates charged to our customers vary according to customer class (residential, commercial or industrial) and rate jurisdiction. These agencies approve rates designed to provide us the opportunity to generate revenues to recover all prudently incurred costs, including a return on rate base sufficient to pay interest on debt and provide a reasonable return for our shareholders. Rate base generally consists of the original cost of the utility plant in service, working capital and certain other assets, less accumulated depreciation on the utility plant in service and net deferred income tax liabilities, and may include certain other additions or deductions.

The natural gas market for Atlanta Gas Light was deregulated in 1997. Accordingly, Marketers, rather than a traditional utility, sell natural gas to end-use customers in Georgia and handle customer billing functions. The Marketers file their rates monthly with the Georgia Commission. As a result of operating in a deregulated environment, 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; and
·  
planning and contracting for capacity on interstate transportation and storage systems.

Atlanta Gas Light earns revenue by charging rates to its customers based primarily on monthly fixed charges that are periodically adjusted. The Marketers add these fixed charges to customer bills. This mechanism, called a straight-fixed-variable rate design, minimizes the seasonality of Atlanta Gas Light’s revenues since the monthly fixed charge is not volumetric or directly weather dependent.

With the exception of Atlanta Gas Light, 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. Specifically, customer demand substantially increases during the Heating Season when natural gas is used for heating purposes. We have various mechanisms, such as weather normalization at some of our utilities, which limit our exposure to weather changes within typical ranges in these utilities’ respective service areas.

All of our utilities, excluding Atlanta Gas Light, are authorized to use natural gas cost recovery mechanisms that allow them to adjust their rates to reflect changes in the wholesale cost of natural gas and to ensure they recover all of the costs prudently incurred in purchasing gas for their customers. Since Atlanta Gas Light does not sell natural gas directly to its end-use customers, it does not need or utilize a natural gas cost recovery mechanism. However, Atlanta Gas Light does maintain inventory for the Marketers in Georgia and recovers the cost of this gas through recovery mechanisms approved by the Georgia Commission. In addition to natural gas recovery mechanisms, we have other cost recovery mechanisms, such as regulatory riders, which vary by utility but allow us to recover certain costs, such as those related to environmental remediation and energy efficiency plans.

 
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In traditional rate designs, utilities recover a significant portion of their fixed customer service and pipeline infrastructure costs based on assumed natural gas volumes used by our customers. Three of our utilities have decoupled regulatory mechanisms in place that encourage conservation. We believe that separating, or decoupling, the recoverable amount of these fixed costs from the customer throughput volumes, or amounts of natural gas used by our customers, allows us to encourage our customers’ energy conservation and ensures a more stable recovery of our fixed costs.

The following table provides regulatory information for our six largest utilities.

   
Nicor
Gas (9)
   
Atlanta Gas Light
   
Virginia Natural Gas
   
Elizabethtown Gas
   
Florida City Gas
   
Chattanooga Gas
 
Authorized return on rate base (1)
    8.09 %     8.10 %     7.38 %     7.64 %     7.36 %     7.41 %
Estimated 2012 return on rate base (2)
    6.24 %     8.71 %     7.74 %     8.51 %     6.07 %     7.99 %
Authorized return on equity (1)
    10.17 %     10.75 %     10.00 %     10.30 %     11.25 %     10.05 %
Estimated 2012 return on equity (2)
    6.50 %     11.94 %     10.79 %     12.11 %     10.42 %     11.29 %
Authorized rate base % of equity (1)
    51.1 %     51.0 %     45.4 %     47.9 %     36.8 %     46.1 %
Rate base included in 2012 return on equity (in millions) (2)
  $ 1,418     $ 2,045     $ 577     $ 478     $ 166     $ 90  
Weather normalization (3)
                 
ü
   
ü
           
ü
 
Decoupled or straight-fixed-variable rates (4)
         
ü
                           
ü
 
Regulatory infrastructure program rates (5)
         
ü
   
ü
   
ü
                 
Bad debt rider (6)
 
ü
           
ü
                   
ü
 
Synergy sharing policy (7)
         
ü
                                 
Energy efficiency plan (8)
 
ü
                   
ü
   
ü
   
ü
 
Last decision on change in rates
 
Oct. 2009
   
Oct. 2010
   
Dec. 2011
   
Dec. 2009
      N/A    
May 2010
 
(1)  
The authorized return on rate base, return on equity and percentage of equity were those authorized as of December 31, 2012.
(2)  
Estimates based on principles consistent with utility ratemaking in each jurisdiction. Rate base includes investments in regulatory infrastructure programs.
(3) 
Involves regulatory mechanisms that allow us to recover our costs in the event of unseasonal weather, but are not direct offsets to the potential impacts of weather and customer consumption on earnings. These mechanisms 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. Based on the structure of Atlanta Gas Light, it does not need or utilize a weather normalization recovery mechanism.
(4)  
Decoupled and straight-fixed-variable rate designs allow for the recovery of fixed customer service costs separately from assumed natural gas volumes used by our customers. Virginia Natural Gas filed for approval of a decoupled rate design in December 2012.
(5)  
Includes programs that update or expand our distribution systems and liquefied natural gas facilities.
(6) 
Involves the recovery (refund) of the amount of bad debt expense over (under) an established benchmark expense. Virginia Natural Gas and Chattanooga Gas recover the gas portion of bad debt expense through PGA mechanisms.
(7)  
Involves the recovery of 50% of net synergy savings achieved on future acquisitions.
(8)  
Includes the recovery of costs associated with plans to achieve specified energy savings goals.
(9)  
In connection with the Nicor merger, we agreed to (i) not initiate a rate proceeding for Nicor Gas that would increase base rates prior to December 2014, (ii) maintain 2,070 full-time equivalent employees involved in the operation of Nicor Gas for a period of three years and (iii) maintain the personnel numbers in specific areas of safety oversight of the Nicor Gas system for a period of five years.

Nicor Gas On January 1, 2000, Nicor Gas instituted a PBR plan for natural gas costs, which was terminated effective January 1, 2003. Under the PBR plan, Nicor Gas’ total gas supply costs were compared to a market-sensitive benchmark. Savings and losses relative to the benchmark were determined annually and shared equally with sales customers.

In February 2012, we committed to a stipulated resolution of issues with the Illinois Commission, which would include crediting Nicor Gas customers $64 million. The stipulated resolution does not constitute an admission of fault, is not final and is subject to review and approval by the Illinois Commission. The Citizens Utility Board (CUB) and the Illinois Attorney General’s Office (IAGO) are not parties to this stipulated resolution and continue to pursue their claims in this proceeding, requesting refunds of $305 million and $255 million, respectively. On November 5, 2012, the Administrative Law Judges issued a proposed order that Nicor Gas refund $72 million to ratepayers. We have increased our accrual by $8 million for a total of $72 million as a result of these developments and its effect on the estimated liability. The PBR plan is currently under review by the Illinois Commission and must be acted upon by them before becoming a final decision. We do not agree with the additional $8 million proposed by the Administrative Law Judges and will consider all legal recourse available should the Illinois Commission authorize a refund greater than the $64 million stipulation amount between Nicor Gas and the staff of the Illinois Commission. For more information on the PBR plan, see Note 11 to our consolidated financial statements under Item 8 herein.

Virginia Natural Gas In accordance with the State of Virginia Natural Gas Conservation and Ratemaking Efficiency Act (CARE), Virginia Natural Gas filed for approval of its CARE plan with the Virginia Commission on December 3, 2012. This plan includes a decoupling mechanism and authority to record accounting entries associated with such a mechanism. Our CARE plan has two principal components: (i) an Energy Conservation Plan component consisting of four cost-effective conservation and energy efficiency initiatives or programs plus a Community Outreach and Customer Education program; and (ii) a natural gas decoupling mechanism, Revenue Normalization Adjustment component and a designated Rider D, which provides for a sales adjustment consistent with the Virginia code. Our filing requests that the CARE plan become effective June 1, 2013 for a three-year period with a total cost of $5 million.

 
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Environmental Remediation Costs

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites.
 
As we continue to conduct the actual remediation and enter into cleanup contracts, we are increasingly able to provide conventional engineering estimates of the likely costs of many elements of the remediation program. These estimates contain various engineering uncertainties, and we regularly attempt to refine and update them. These costs are primarily recovered through rate riders.

See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the caption “Critical Accounting Policies and Estimates,” for additional information about our environmental remediation liabilities. Also see Note 11 to our consolidated financial statements under Item 8, “Financial Statements and Supplementary Data” for information on our environmental remediation efforts.

Capital Projects

We continue to focus on capital discipline and cost control while moving ahead with projects and initiatives that we expect will have current and future benefits to us and our customers, provide an appropriate return on invested capital and ensure the safety, reliability and integrity of our utility infrastructure. The following table and discussions provide updates on some of our larger capital projects in our distribution operations segment. These programs update or expand our distribution systems to improve system reliability and meet operational flexibility and growth. Our anticipated expenditures for these programs in 2013 are discussed in “Liquidity and Capital Resources” under the caption “Cash Flows from Financing Activities.”

Dollars in millions
 
 
Utility
 
2012 expenditures
   
Expenditures since project inception
   
Miles of
pipe replaced
   
Year project began
   
Anticipated year of completion
 
STRIDE program
Pipeline replacement program
 
 
Atlanta Gas Light
  $ 129     $ 697       2,625       1998       2013  
Integrated System Reinforcement Program
 
Atlanta Gas Light
    83       224       n/a       2009       2013  
Integrated Customer Growth Program
 
Atlanta Gas Light
    17       29       n/a       2010       2013  
Enhanced infrastructure program (1)
 
Elizabethtown Gas
    18       108       109       2009       2012  
Accelerated infrastructure program
 
Virginia Natural Gas
    16       16       42       2012       2017  
Total
      $ 263     $ 1,074       2,776                  
(1)  
In July 2012, we filed for a five-year extension of this program.

Atlanta Gas Light Our STRIDE program comprises the ongoing pipeline replacement program, the Integrated System Reinforcement Program (i-SRP) and the Integrated Customer Growth Program (i-CGP). These pipeline replacement programs are used to update and expand distribution systems and liquefied natural gas facilities, improve system reliability and meet operations flexibility and growth. The purpose of i-SRP is to upgrade our distribution system and liquefied natural gas facilities in Georgia, improve our peak-day system reliability and operational flexibility, and create a platform to meet long-term forecasted growth. The i-CGP authorizes Atlanta Gas Light to extend its pipeline facilities to serve customers in areas without pipeline access and create new economic development opportunities in Georgia. The STRIDE program requires us to file an updated ten-year forecast of infrastructure requirements under i-SRP along with a new construction plan every three years for review and approval by the Georgia Commission. The deadline for filing our next STRIDE construction plan was extended by the Georgia Commission to August 2013 to allow additional time to complete the installation of the initial i-SRP construction program.

On November 21, 2012 we filed the Integrated Vintage Plastic Replacement Program (i-VPR) with the Georgia Commission, as a new component of STRIDE. If approved, this program would replace aging plastic pipe that was installed primarily in the mid-1960’s to the early 1980’s. We have identified approximately 3,300 miles of vintage plastic mains in our system that potentially should be considered for expedited replacement over the next 15 - 20 years as it reaches the end of its useful life. However, the initial request to the Georgia Commission is to replace approximately 756 miles over the next three to four years. The estimated cost of the first tranche of pipe to be replaced under construction activity under i-VPR is $275 million. A decision on how to proceed with the replacement of vintage plastic pipes is expected later in 2013.
 
Virginia Natural Gas On January 31, 2012, Virginia Natural Gas filed SAVE, an accelerated infrastructure replacement program, with the Virginia Commission, which involves replacing aging infrastructure as prioritized through Virginia Natural Gas’ distribution integrity management program. SAVE was filed in accordance with a Virginia statute providing a regulatory cost recovery mechanism to recover the costs associated with certain infrastructure replacement programs. The Virginia Commission approved SAVE on June 25, 2012, for a five-year period which includes a maximum allowance for capital expenditure of $25 million per year, not to exceed $105 million in total. SAVE is subject to annual review by the Virginia Commission. We began recovering costs based on this program through a rate rider that became effective August 1, 2012.

 
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Elizabethtown Gas The New Jersey BPU-approved accelerated enhanced infrastructure program was created in response to the New Jersey Governor’s request for utilities to assist in the economic recovery by increasing infrastructure investments. On May 16, 2011, the New Jersey BPU approved Elizabethtown Gas’ request to spend an additional $40 million under this program before the end of 2012. Costs associated with the investment in this program are recovered through periodic adjustments to base rates. In July 2012, we filed for an extension of the program to add $135 million in additional spend over five years. A ruling is expected from the New Jersey BPU in the first half of 2013.


The companies in our retail operations segment market natural gas and related home services, such as appliance repair and gas and electric line protection plans. This segment also offers products that provide protection and comfort services as well as natural gas price risk and utility bill management services. Companies within our retail operations segment include SouthStar, Nicor Advanced Energy, Nicor Solutions and Nicor Services.

Our retail operations businesses generate earnings through the sale of natural gas to residential, commercial and industrial customers, primarily in Georgia and Illinois where we capture spreads between wholesale and retail natural gas prices. We offer our customers energy-related products that provide for natural gas price stability and utility bill management. These products mitigate and/or eliminate the risks to customers of colder-than-normal weather and/or changes in natural gas prices. We charge a fee or premium for these services.

We also collect monthly service fees and customer late payment fees. We evaluate 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.

Through our commercial operations, we optimize storage and transportation assets and effectively manage commodity risk, which enables SouthStar to maintain competitive retail prices and operating margin. SouthStar, a joint venture currently owned 85% by us and 15% by Piedmont, markets natural gas and related services to retail customers on an unregulated basis, primarily in Georgia under the trade name Georgia Natural Gas. SouthStar also serves retail customers primarily in Ohio, Florida and New York. We have no contractual rights to acquire Piedmont’s remaining 15% ownership interest.

SouthStar is governed by an executive committee, which comprises six members, three representatives from AGL Resources and three representatives from Piedmont. Under the joint venture agreement, all significant management decisions require the unanimous approval of the SouthStar executive committee; accordingly, our 85% financial interest is considered to be noncontrolling. We record the earnings allocated to Piedmont as a noncontrolling interest in our Consolidated Statements of Income, and we record Piedmont’s portion of SouthStar’s capital as a noncontrolling interest in our Consolidated Statements of Financial Position.

SouthStar’s operations are sensitive to seasonal weather, natural gas prices, customer growth and consumption patterns similar to those affecting our utility operations. SouthStar’s retail pricing strategies and the use of a variety of hedging strategies, such as the use of futures, options, swaps, weather derivative instruments and other risk management tools, help to ensure retail customer costs are covered to mitigate the potential effect of these issues and commodity price risk on its operations. For more information on SouthStar’s energy marketing and risk management activities, see Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” under the caption “Natural Gas Price Risk.”

Nicor Solutions offers its residential and small commercial customers, primarily in the Nicor Gas service territory, energy-related products that provide for natural gas price stability and utility bill management. These products mitigate and/or eliminate the risks to customers of colder-than-normal weather and/or changes in natural gas prices. Nicor Advanced Energy is certified by the Illinois Commission as an Alternate Gas Supplier, authorizing it to be a non-utility marketer of natural gas for residential and small commercial customers. Nicor Advanced Energy presently operates in northern Illinois, offering customers an alternative to the utility as its natural gas supplier.

Our retail operations businesses also provide protection solutions to customers through Nicor Services. Such services include a gas line repair plan and a heating, ventilation, and air conditioning repair and/or maintenance plan, whereby we, in return for a predetermined monthly amount collected from customers, provide repair and/or maintenance per the contracted terms. In addition, we also provide customers with move connection services for utilities. Currently, our retail operations businesses primarily provide warranty protection solutions to customers in Illinois, Indiana and Ohio under the Nicor National brand. We intend to expand this business in 2013 to include our service territories in Georgia, Virginia and Tennessee. We anticipate this expansion will provide growth opportunities in 2013 and beyond.

 
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On January 31, 2013, Nicor Services acquired approximately 500,000 service plans and certain other assets of NiSource Inc.’s retail services business for approximately $120 million. We believe this acquisition will drive expansion in seven states and provide a platform for growth and continued expansion.

Competition Our retail operations business competes with other energy marketers to provide natural gas and related services to customers in Georgia, Illinois, Indiana, Ohio, New York and the Southeast region. In the Georgia market, SouthStar operates as Georgia Natural Gas and is the largest of eleven Marketers, with average customers of nearly 500,000 over the last three years and market share of approximately 32%.

In recent years, increased competition and the heavy promotion of fixed-price plans by SouthStar’s competitors has resulted in increased pressure on retail natural gas margins. In response to these market conditions SouthStar’s residential and commercial customers have been migrating to fixed-price plans, which, combined with increased competition from other Marketers, has impacted SouthStar’s customer growth as well as margins.

In addition, similar to our natural gas utilities, our retail operations businesses face competition based on customer preferences for natural gas compared to other energy products, primarily electricity, and the comparative prices of those products. We continue to use a variety of targeted marketing programs to attract new customers and to retain existing customers.

Our retail operations businesses also experience price, convenience and service competition from other warranty and HVAC companies. These businesses also bear risk from potential changes in the regulatory environment. As a condition of the merger, Nicor Gas is no longer permitted to use its call center personnel to solicit its affiliates’ products, most notably the warranty products.

Wholesale Services

Our wholesale services segment primarily consists of our wholly owned subsidiaries Sequent and Compass Energy (Compass). Sequent is involved in asset management and optimization, storage, transportation, producer and peaking services and wholesale marketing of natural gas across the United States and in Canada. Nicor Enerchange, which was integrated into Sequent as part of the Nicor merger, expands Sequent’s wholesale marketing of natural gas supply services in the Midwest, enables Sequent to serve commercial and industrial customers in the Midwest primarily in the northern Illinois market area and manages Nicor Solutions’ and Nicor Advanced Energy’s product risks, including the purchase of natural gas supplies. In 2013, we anticipate that SouthStar will assume the product risks for Nicor Solutions and Nicor Advanced Energy. Compass provides natural gas supply and services to commercial, industrial and governmental customers primarily in Kentucky, Ohio, Pennsylvania, Virginia and West Virginia.

Wholesale services utilizes a portfolio of natural gas storage assets, contracted supply from all of the major producing regions, as well as contracted storage and transportation capacity across the Gulf Coast, Eastern, Midwestern and Western sections of the United States and Canada to provide these services to its customers, consisting primarily of electric and natural gas utilities, power generators and large industrial customers. Our logistical expertise enables us to provide our customers with natural gas from the major producing regions and market hubs in the United States and Canada and meet our delivery requirements and customer obligations at competitive prices by leveraging our portfolio of natural gas storage assets and contracted natural gas supply, transportation and storage capacity.

Wholesale services’ portfolio of storage and transportation capacity enables us to generate additional operating margin by optimizing the contracted assets through the application of our wholesale market knowledge and risk management skills as opportunities arise in the Gulf Coast, Eastern, Midwestern and Western sections of the United States and Canada. These asset optimization opportunities focus on capturing the value from idle or underutilized assets, typically by participating in transactions to take advantage of volatility in pricing differences between varying geographic locations and time horizons (location and seasonal spreads) within the natural gas supply, storage and transportation markets to generate earnings. We seek to mitigate the commodity price and volatility risks and protect our operating margin through a variety of risk management and economic hedging activities.

Competition Wholesale services competes for asset management, long-term supply and seasonal peaking service contracts with other energy wholesalers, often through a competitive bidding process. We are able to price competitively by utilizing our portfolio of contracted storage and transportation assets and by renewing and adding new contracts at prevailing market rates. We will continue to broaden our market presence in sections of the United States and Canada where our portfolio of contracted storage and transportation assets provides us a competitive advantage, as well as continue our pursuit of additional opportunities with power generation companies located in the areas of the country in which we operate. We are also focused on building our fee-based services in part to have a source of operating margin that is less impacted by volatility in the marketplace.

Asset Management Transactions Our asset management customers include affiliated and non-affiliated 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 that exceed their actual requirements. We enter into structured agreements with these customers, whereby we, on behalf of the customers, optimize the transportation and storage capacity during periods when customers do not use it for their own needs. We may capture incremental operating margin through optimization, and either share margins with customers or pay them a fixed amount.

 
11

 
Transportation Transactions We enter into contracts for natural gas transportation capacity and participate in forward financial and related commodity transactions that manage the natural gas commodity and transportation costs in an attempt to achieve the lowest cost to serve our various markets. We seek 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 we have access and identifying the lowest-cost alternatives to serve our markets. This enables us to capture geographic pricing differences across these various markets as delivered natural gas prices change.

As we execute transactions to secure transportation capacity, we often enter into forward financial contracts to hedge the associated price risks to substantially lock in a margin on future transportation activities. The hedging instruments are derivatives, and we reflect changes in the derivatives’ fair value in our reported operating results in the period of change, which can be in periods prior to actual utilization of the transportation capacity.

Park and Loan Transactions We routinely enter into park and loan transactions with various pipelines and storage facilities, which allow us 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. For these services, we charge, or pay, rates which include the retention of natural gas lost and unaccounted for in-kind. The economics of these transactions are evaluated and price risks are managed in much the same way as traditional reservoir and salt-dome storage transactions are evaluated and managed.

We enter into forward NYMEX contracts to hedge the natural gas price risk associated with the 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 our 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, we will report a net unrealized gain or loss on the hedges. Once gas is delivered under the park and loan transaction, earnings volatility is essentially eliminated since the park and loan transaction contains an embedded derivative, which is also marked to market and would substantially offset subsequent changes in value of the forward NYMEX contracts used to hedge the park and loan transaction.

Natural Gas Storage Inventory and Transactions We maintain natural gas storage balances for volumes associated with energy marketing activities, parked gas transactions and sales to wholesale and commercial and industrial customers and record these within natural gas stored underground inventory on our Consolidated Statements of Financial Position. Further, and generally in connection with non-affiliated asset management transactions, our recorded natural gas stored underground inventory includes volumes of natural gas that we manage for our customers by purchasing the natural gas inventory from and physically delivering volumes of natural gas back to our customers based on specific delivery dates. The cost at which we purchase the volumes of natural gas from our customers, or WACOG, is also the same price at which we sell the natural gas volumes to our customers. Consequently, we make no margin on the purchase and sale of the natural gas but make operating margin through our natural gas storage optimization activities of these volumes under management. As of December 31, 2012, we had $262 million of natural gas stored underground inventory within our Consolidated Statements of Financial Position, representing 89 Bcf at an overall WACOG of $2.94.

Natural Gas Price Volatility and Energy Marketing Activities We purchase natural gas for storage when the current market price we pay plus the cost for transportation, storage and financing is less than the market price we anticipate we could receive in the future. We attempt to mitigate substantially all of the commodity price risk associated with our storage portfolio by using derivative instruments to reduce the risk associated with future changes in the price of natural gas. We sell NYMEX futures contracts or OTC derivatives in forward months to substantially lock in the operating revenue we will ultimately realize when the stored gas is actually sold.

We view our trading margins from two perspectives. First, we base our commercial decisions on economic value, which is defined as the operating revenue to be realized at the time the physical gas is withdrawn from storage and sold and the derivative instrument used to economically hedge natural gas price risk on that physical storage is settled. Second is the GAAP reported value, both in periods prior to and in the period of physical withdrawal and sale of inventory. The GAAP amount is affected by the process of accounting for the financial hedging instruments in interim periods at fair value between the period when the natural gas is injected into storage and when it is ultimately withdrawn and the derivative 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 eventual customer.

We account for natural gas stored in inventory differently than the derivatives we use to mitigate the commodity price risk associated with our storage portfolio. The natural gas that we purchase and inject into storage is accounted for at the LOCOM value. The derivatives we use 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 wholesale services reported results, even though the expected operating revenue is essentially unchanged from the date the transactions were initiated. These accounting differences also affect the comparability of wholesale services period-over-period results, since changes in forward NYMEX prices do not increase and decrease on a consistent basis from year to year.

 
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Volatility in the natural gas market arises from a number of factors such as weather fluctuations or changes in supply or demand for natural gas in different regions of the country. The volatility of natural gas commodity prices has a significant impact on our customer rates, our long-term competitive position against other energy sources and the ability of our wholesale services segment to capture value from location and seasonal spreads. During 2012, 2011 and 2010, the volatility of daily Henry Hub spot market prices for natural gas in the United States was significantly lower than it had been for several prior years. This is the result of a robust natural gas supply, the weak economy, mild weather and ample storage. Our natural gas acquisition strategy is designed to secure sufficient supplies of natural gas to meet the needs of our utility customers and to hedge gas prices to effectively manage costs, reduce price volatility and maintain a competitive advantage. Additionally, our hedging strategies and physical natural gas supplies in storage enable us to reduce earnings risk exposure due to higher gas costs.

It is possible that natural gas prices will remain low for an extended period based on current levels of excess supply relative to market demand for natural gas, in part due to abundant sources of new shale natural gas reserves, particularly in the Marcellus Shale producing region where Sequent has natural gas receipt requirements, and the lack of demand growth by commercial and industrial enterprises. However, as economic conditions improve the demand for natural gas may increase, natural gas prices could rise and higher volatility could return to the natural gas markets. Consequently, we are repositioning Sequent’s business model with respect to fixed costs and the types of contracts pursued and executed.

Sequent’s expected natural gas withdrawals from storage are presented in the following table along with the operating revenues expected at the time of withdrawal. Sequent’s expected operating revenues are net of the estimated impact of profit sharing under our asset management agreements and reflect the amounts that are realizable in future periods based on the inventory withdrawal schedule and forward natural gas prices at December 31, 2012 and 2011. A portion of Sequent’s storage inventory is economically hedged with futures contracts, which results in realization of a substantially fixed margin, timing notwithstanding.

Withdrawal schedule
 
Total storage (in Bcf)
(WACOG $2.78)
   
Expected operating revenues
(in millions)
 
2013
           
First quarter
    38     $ 17  
Second quarter
    9       6  
Third quarter
    3       3  
Fourth quarter
    1       1  
Total at Dec. 31, 2012
    51     $ 27  
Total at Dec. 31, 2011
    37     $ 3  

Sequent’s storage balances and expected operating revenues are higher in 2012 than 2011, reflecting the effects of the warmer weather in 2012, year-over-year improvements in seasonal price differentials and the ability to achieve higher economic value in 2013 than 2012. If Sequent’s storage withdrawals associated with existing inventory positions are executed as planned, it expects operating revenues from storage withdrawals of $27 million in 2013. This will change as Sequent adjusts its daily injection and withdrawal plans in response to changes in market conditions in future months and as forward NYMEX prices fluctuate.

The operating revenues expected to be generated from the physical withdrawal of natural gas from storage, do not reflect the earnings impact related to the movement in our hedges to lock in the forward location spread for the delivery of natural gas between two transportation delivery points associated with our transportation capacity portfolio. For the year ended December 31, 2012, we have recorded $3 million in losses associated with the hedging of our transportation portfolio, or $11 million lower as compared to the same period last year. These hedge losses primarily relate to forward transportation and commodity positions for 2013, during which we expect to physically flow natural gas between the hedged transportation delivery points and utilize the contracted transportation capacity. For more information on Sequent’s energy marketing and risk management activities, see Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” under the caption “Natural Gas Price Risk.”

Midstream Operations

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

 
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The market fundamentals of the natural gas storage business are cyclical. Low natural gas prices and lack of volatility in recent years have negatively impacted the profitability of our storage facilities as expiring storage capacity contracts were re-subscribed at lower prices. We anticipate lower natural gas prices to continue in 2013 as compared to historical averages. The prices for natural gas storage capacity are expected to increase as supply and demand quantities reach equilibrium as the economy improves, and/or natural gas demand increases in response to low prices and expanded uses for natural gas. While the natural gas market is growing there are significant barriers to develop new storage facilities which we believe provide our storage facilities with an advantage as market conditions improve. The following table shows the working gas capacity and firm subscription amounts by storage facility as of December 31, 2012.

             
Subscribed (2)
 
In Bcf
State
Type
 
Working Gas Capacity
   
Amount
   
%
 
Jefferson Island
Louisiana
Salt-dome
    7.3       6.1       84%  
Golden Triangle Storage (1)
Texas
Salt-dome
    13.5       4.0       30%  
Central Valley
California
Depleted field
    11.0       4.5       41%  
Total
        31.8       14.6          
(1)  
In January 2013, we began an assessment of the working gas capacity at Cavern 1, which is expected to slightly increase the size of the facility. The process is expected to continue through the third quarter of 2013. Cavern 2 will cover the obligations of Cavern 1 during this process.
(2)  
The amount and percentage of firm capacity under subscription does not include 1 Bcf of capacity under contract at Jefferson Island and 2 Bcf of capacity under contract at Golden Triangle Storage by Sequent at December 31, 2012.

Jefferson Island This wholly owned subsidiary operates a salt-dome storage and hub facility approximately eight miles from the Henry Hub. The storage facility is regulated by the Louisiana Department of Natural Resources and by the FERC, which has regulatory authority over storage and transportation services. Jefferson Island provides storage and hub services through its direct connection to the Henry Hub and its direct interconnections with eight pipelines in the area. The level of firm subscription has remained consistent over the last three years. We intend to solicit interest for 3.4 Bcf of subscribed capacity at an average rate of $0.103 per Bcf that expires at the end of March 2013, and expect the subscription rate to be lower than the current contract.

In December 2009, the Louisiana Mineral and Energy Board approved an operating agreement between Jefferson Island and the State of Louisiana. In June 2010, Jefferson Island filed a permit application with the Louisiana Department of Natural Resources to expand its natural gas storage facility through the addition of two caverns. We continue to seek approval to expand our storage facility; however, we cannot predict when or if this approval will be obtained. The expansion would increase the total working gas capacity at Jefferson Island to approximately 19.5 Bcf of working gas capacity.

Golden Triangle Storage This wholly owned subsidiary operates a salt-dome storage facility and is regulated by the FERC. Golden Triangle Storage owns an approximately nine-mile dual 24” natural gas pipeline to connect the storage facility with three interstate and three intrastate pipelines.

Cavern 1, with 6 Bcf of working capacity, began commercial service in September 2010. Cavern 2, with 7.5 Bcf of working capacity, began commercial operations in September 2012. We spent $15 million in capital expenditures for this project in 2012. At the end of March 2013, Golden Triangle Storage has 2 Bcf of firm contracted capacity at an expiring rate of $0.045 per Bcf. We will evaluate our strategy to re-contract the facility on a firm basis or to provide other services in order to contract at rates at or above the expiring rate.

Central Valley This wholly owned subsidiary operates an underground natural gas storage facility in the Sacramento River valley of north-central California. We converted the depleted Princeton Gas Field into a high-deliverability, multi-cycle storage field. This includes the addition of a 14.9 mile 24-inch diameter gas pipeline connecting the facility to a major pipeline. The storage facility is regulated by the California Commission. Central Valley began commercial operations and providing services to firm customers during the second quarter 2012, with 4.5 Bcf subscribed at December 31, 2012. We plan to solicit interest for additional firm capacity up to 3 Bcf and provide additional storage services for the remaining open capacity.

Magnolia This wholly owned subsidiary operates a pipeline that provides our Georgia customers access to LNG from the Elba Island terminal near Savannah, Georgia. The pipeline was completed in November 2009, and provides diversification of natural gas sources and increased reliability of service in the event that supplies coming from other supply sources are disrupted.

Horizon Pipeline This 50% owned joint venture with Natural Gas Pipeline Company of America operates an approximate 70 mile natural gas pipeline stretching from Joliet, Illinois to near the Wisconsin/Illinois border. Nicor Gas has contracted for approximately 80% of Horizon Pipeline’s total throughput capacity of 0.38 Bcf under an agreement expiring in 2015 at rates that have been accepted by the FERC.

Competition Our natural gas storage facilities primarily compete with natural gas facilities in the Gulf Coast region of the United States as the majority of the existing and proposed high deliverability salt-dome natural gas storage facilities in North America are located in the Gulf Coast region. Salt caverns have also been leached from bedded salt formations in the Northeastern and Midwestern states. Competition for our Central Valley storage facility primarily consists of storage facilities in northern California and western North America. Storage values have declined over the past three years due to low gas prices, abundant supplies of natural gas and low volatility and we expect this to continue in 2013 and potentially longer.

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

Tropical Shipping is a transporter of containerized freight and provides southbound scheduled services from the United States and Canada to twenty-five ports in the Bahamas and the Caribbean, interisland service between several of the Caribbean ports and operates from St. Thomas and St. Croix as its hubs in the Caribbean. In addition, it provides northbound shipments from those islands to the United States and Canada. Other related services, such as inland transportation and cargo insurance, are also provided by Tropical Shipping or its other subsidiaries and affiliates.

Tropical Shipping’s southbound cargo consists mainly of building materials, food and other necessities for developers, distributors and residents in the Caribbean and the Bahamas, as well as tourist-related shipments intended for use by hotels, resorts, and cruise ships. Tropical Shipping’s interisland shipments consist primarily of consumer staples and northbound shipments primarily consist of apparel, rum and agricultural products.

On average, approximately 70% - 75% of Tropical Shipping’s total volumes shipped are in the southbound market, 15% - 20% interisland and 5% - 10% northbound. Tropical Shipping measures volumes and capacity of vessels and containers in TEU’s. Details of Tropical Shipping’s properties are discussed in Item 2, “Properties” under the caption “Vessels and shipping containers.”

Tropical Shipping’s operations are structured to allow us to take advantage of certain provisions of the American Jobs Creation Act of 2004 that provide the opportunity for certain tax savings. Generally, to the extent foreign shipping earnings are not repatriated to the United States, these earnings are not expected to be subject to current taxation. To the extent such earnings are expected to be indefinitely reinvested offshore, no deferred income tax expense is recorded by the company. For more information on management’s indefinite reinvestment assertion, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” under the caption “Liquidity and Capital Resources.” See also Note 2 and Note 12 to our consolidated financial statements under Item 8 herein.

Our cargo shipping segment also includes Triton, a full-service global leasing company and an owner-lessor of marine intermodal cargo containers. Profits and losses are generally allocated to investor’s capital accounts in proportion to their capital contributions. Our investment in Triton is accounted for under the equity method, and our share of earnings is reported within “Other Income” on our Consolidated Statements of Income. For more information about our investment in Triton, see Note 10 to the consolidated financial statements under Item 8 herein.

Seven Seas is a Florida domestic insurance corporation that provides cargo insurance policies mainly between Tropical Shipping and its customers. During 2012, 66% of Seven Seas’ revenues were generated from Tropical Shipping’s customers. Policy coverage is from the point when the cargo leaves the shipper’s possession to the point when the customer takes delivery.

Competition Cargo shipping has five main competitors that serve the same major transportation areas. Our volumes shipped increased during 2012, but were partially offset by lower overall shipping rates.

Operations Tropical Shipping’s operating results are cyclical and very much aligned with the level of global gross domestic product, tourism and the cost of fuel. Overall, the economies of the Bahamas and the Virgin Islands are highly dependent on tourism from the United States, and the Caribbean’s Windward and Leeward Island economies primarily depend on tourism from Europe. Fuel price volatility also impacts our earnings. Bunker surcharge rates are charged to customers and are used to mitigate the fluctuations in fuel transportation costs. In 2013, we expect similar general market challenges as those experienced in 2012 with respect to overall levels of competition and related impacts on shipping volumes and rate pressure.

Tropical Shipping generates revenues primarily by three main services, which include Full Container Load (FCL) service, Less-than Container Load (LCL) service and break bulk service, which is cargo that cannot ship in a container. Tropical Shipping also generates revenues from handling “project cargo,” which provides a coordinated service for construction projects. Tropical Shipping’s FCL cargo service revenues typically consist of an empty container delivery to the customer’s site via truck or rail or coordinating a customer pick up at the port. The customer fills and seals the container and either requests Tropical to pick it up or delivers it back to the port. Tropical Shipping generates revenues from LCL services primarily by providing packaging and transporting services for smaller cargos or customers, including individuals, who may have only a few items to ship.

Seven Seas generates revenues from premiums received on insurance policies subscribed to primarily by customers of Tropical Shipping. Seven Seas’ results depend on its ability to generate revenues from the premiums and to manage risk.
 
 
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Our other segment primarily includes our non-operating business units. AGL Services Company is a service company we established to provide certain centralized shared services to our operating segments. We allocate substantially all of AGL Services Company’s operating expenses and interest costs to our operating segments in accordance with state regulations. However, merger-related costs are not allocated to our operating segments.

AGL Capital, our wholly owned finance subsidiary, provides for our ongoing financing needs through a commercial paper program, the issuance of various debt and hybrid securities and other financing arrangements. This 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.

Employees

As of December 31, 2012, we had approximately 6,121 employees, 5,649 of whom were in the United States.

The following table provides information about our natural gas utilities’ collective bargaining agreements, which represent approximately 27% of our total employees.

   
# of Employees
 
Contract Expiration Date
Nicor Gas
    International Brotherhood of Electrical Workers (Local No. 19)
    1,338  
Feb-2014
Virginia Natural Gas
International Brotherhood of Electrical Workers (Local No. 50)
    127  
May-2015
Elizabethtown Gas
Utility Workers Union of America (Local No. 424)
    173  
Nov-2015
 Total
    1,638    

We believe that we have a good working relationship with our unionized employees and there have been no work stoppages at Virginia Natural Gas, Elizabethtown Gas, or Nicor Gas since we acquired those operations in 2000, 2004, and 2011, respectively. As we have historically done, we remain committed to work in good faith with the unions to renew or renegotiate collective bargaining agreements that balance the needs of the Company and our employees. Our current collective bargaining agreements do not require our participation in multiemployer retirement plans and we have no obligation to contribute to any such plans.

Available Information

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and proxy statements, and amendments to those reports that we file with, or furnish to, the SEC are available free of charge at the SEC website http://www.sec.gov and 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
P.O. Box 4569
Atlanta, GA 30302-4569
404-584-4000
 
In Part III of this Form 10-K, we incorporate certain information by reference from our Proxy Statement for our 2013 annual meeting of shareholders. We expect to file that Proxy Statement with the SEC on or about March 15, 2013, 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 committee of our Board of Directors are available on our website. We will furnish copies of such information free of charge upon written request to our Investor Relations department.


 
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ITEM 1A. RISK FACTORS

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 regulatory authorities in Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee and Maryland.

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 costs associated with our regulatory infrastructure projects, including our pipeline replacement program and environmental remediation activities, energy efficiency programs, 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 authoritative guidance related to regulated operations 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.

We could incur significant compliance costs if we are required to adjust to new regulations. In addition, as the regulatory environment for our industry increases in complexity, the risk of inadvertent noncompliance could also increase. If we fail to comply with applicable regulations, whether existing or new, 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.

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 associated with storage, transportation, treatment and disposal of MGP residuals and waste 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 also could be revised or reinterpreted, and new laws and regulations could be adopted or become applicable to us or our facilities. 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, and such expenditures may not be 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.

Our infrastructure improvement and customer growth may be restricted by the capital-intensive nature of our business.

We must construct additions and replacements to our natural gas distribution systems to continue the expansion of our customer base and improve system reliability, especially during peak usage. We also may need to construct expansions of our existing natural gas storage facilities or develop and construct new natural gas storage facilities. The cost of such 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, the projected construction schedule and the completion timeline of a project. Our cash flows may not be fully adequate to finance the cost of such 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 it may impair our ability to complete the expansions or development projects. We anticipate spending $212 million on these types of programs in 2013.
 
 
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We may be exposed to certain regulatory and financial risks related to climate change and associated legislation and regulation.

Climate change is expected to receive increasing attention from the current federal administration, non-governmental organizations and legislators. Debate continues as to the extent to which our climate is changing, the potential causes of any change and its potential impacts. Some attribute global warming to increased levels of greenhouse gases, including carbon dioxide, which has led to significant legislative and regulatory efforts to limit greenhouse gas emissions.

Presently, there are no federally mandated greenhouse gas reduction requirements that directly affect our operations. However, there is the possibility of new legislative and regulatory proposals to address greenhouse gas emissions, which are in various phases of discussion or implementation. Absent new enabling legislation, in 2012 the United States Environmental Protection Agency has begun using provisions of the 1990 Clean Air Act Amendments to treat carbon dioxide as a pollutant to regulate existing sources of emissions, such as automobiles. Enhanced reporting and categorization of sources is now in place, but additional and potentially costly controls are currently not required in our operations.

The outcome of additional federal and state actions to address climate change could potentially result in new regulations, additional charges to fund energy efficiency activities or other regulatory actions, which in turn could:

·  
result in increased costs associated with our operations,
·  
increase other costs to our business,
·  
affect the demand for natural gas (positively or negatively), and
·  
impact the prices we charge our customers.

Because natural gas is a fossil fuel with low carbon content, it is likely that future carbon constraints will create additional demand for natural gas, both for production of electricity and direct use in homes and businesses. The impact is already being seen in the power production sector due to both environmental regulations and low natural gas costs.

Any adoption by federal or state governments mandating a substantial reduction in greenhouse gas emissions could have far-reaching and significant impacts on the energy industry. We cannot predict the potential impact of such laws or regulations on our future consolidated financial condition, results of operations or cash flows.

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

Our gas distribution and storage activities involve a variety of inherent hazards and operating risks, such as leaks, accidents, including third party damages, and mechanical problems, which could cause substantial financial losses. In addition, these risks could result in serious injury to employees and non-employees, 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, which may limit our ability to grow our business.

The natural gas business is highly competitive, increasingly complex, 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 retail businesses is affected by competition from other energy marketers providing retail natural gas services in our service territories, most notably in Illinois and Georgia. 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 natural 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 retail energy business markets fixed-price and fixed-bill contracts that protect customers against higher natural gas prices, or protect customers against both higher natural gas prices and colder weather. The sale of these fixed-price contracts may be adversely affected if natural gas prices are, or are perceived to be, low and stable.

Our retail services business faces risks in the form of price, convenience and service competition from other warranty and HVAC companies. Retail services also bears risk from potential changes in the regulatory environment, and in fact regulatory-change risk was incurred in late 2011. As a condition of the merger, Nicor Gas is no longer permitted to use its call center personnel to solicit its affiliates’ products, most notably the warranty products offered by Nicor Services.

 
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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.

Our midstream operations segment competes with natural gas facilities in the Gulf Coast region of the United States as the majority of the existing and proposed high deliverability salt-dome natural gas storage facilities in North America are located in the Gulf Coast region. Competition for our Central Valley storage facility in northern California primarily consists of storage facilities in northern California and western North America. Storage values have declined over the past three years due to low gas prices and low volatility and we expect this to continue in 2013.

Our cargo shipping segment competes with international maritime companies. The current expansion of the Panama Canal, which is expected to be completed and open for commercial ship transit in 2015, may lead to increased competition as larger vessels may gain access to the Caribbean. In addition, the growing development of the global logistic environment has moved away from port-to-port operations and towards the combined transport supply chain of various combinations of road, rail, sea and inland waterways. Globally, this has resulted in the need to improve ship productivity, sometimes via third party ship management, development of hub and spoke systems, larger ships, faster ship turnaround time and increased use of technology. Additionally, there are increased pricing pressures and decreased shipping volumes for the islands that Tropical Shipping currently serves. Increased competition may affect our volumes, market share, pricing structure and operating margin. Tropical Shipping does not have fuel contracts, but reduces its fuel price risk through fuel surcharges. Tropical Shipping has five primary competitors that serve the same major areas, some of which are larger and better capitalized than we are and have more global exposure than we do.

Changes or downturns in the economy could adversely affect our customers and negatively impact our financial results.

The weak economy in the United States has adversely impacted the financial well-being of many households in the United States. While the economy of the United States seems to be slowly improving, we cannot predict if the administrative and legislative actions to address this situation will be successful in reducing the severity or duration of this downturn. As a result, our customers may use less gas in future Heating Seasons and it may become more difficult for them to pay their natural gas bills. This may slow collections and lead to higher-than-normal levels of accounts receivables, bad debt and financing requirements. Sales to large industrial customers may be impacted by economic downturns. The manufacturing industry in the United States is subject to changing market conditions including international competition, fluctuating product demand and increased costs and regulation.

Tropical Shipping’s business consists primarily of the shipment of building materials, food and other necessities from the United States and Canada to developers, distributors and residents in the Bahamas and the Caribbean region, as well as tourist-related shipments intended for use in hotels, resorts and on cruise ships. As a result, Tropical Shipping’s results of operations, cash flows and financial condition can be significantly affected by adverse general economic conditions in the United States, Bahamas, Caribbean region and Canada. Also, a shift in buying patterns that results in such goods being sourced directly from other parts of the world, including China and India, rather than the United States and Canada, could significantly affect Tropical Shipping’s results of operations, cash flows and financial condition.

A significant portion of our accounts receivable is subject to collection risks, due in part to a concentration of credit risk at Nicor Gas, Atlanta Gas Light, SouthStar and Sequent.

Nicor Gas and Sequent often extend credit to their counterparties. Despite performing credit analyses prior to extending credit and seeking to effectuate netting agreements, Nicor Gas and Sequent are exposed to the risk that they may not be able to collect amounts owed to them. If the counterparty to such a transaction fails to perform and any collateral Nicor Gas or Sequent has secured is inadequate, they 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 50% of Sequent’s credit exposure is concentrated in its top 20 counterparties. 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 to Sequent could result in credit losses that would negatively impact our wholesale services segment.

 
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We have accounts receivable collection risks in Georgia due to a concentration of credit risks related to the provision of natural gas services to Marketers. At December 31, 2012, Atlanta Gas Light provided services to eleven certificated and active Marketers in Georgia, four of which (based on customer count) accounted for approximately 17% of our consolidated operating margin for 2012. As a result, Atlanta Gas Light depends on a concentrated number of customers for revenues. The provisions of Atlanta Gas Light’s tariff allow it to obtain security support in an amount equal to no less than two times a Marketer’s highest month’s estimated bill in the form of cash deposits, letters of credit, surety bonds or guarantees. 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. AGL Resources provides a guarantee to Atlanta Gas Light as security support for SouthStar. 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.

The asset management arrangements between Sequent and our local distribution companies, and between Sequent and its non-affiliated 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, Virginia Natural Gas, Elizabethtown Gas, Florida City Gas, Chattanooga Gas and Elkton Gas. The profits it earns from the management of those assets with these affiliates are shared with their respective customers and for Atlanta Gas Light with the Georgia Commissions’ Universal Service Fund, with the exception of Chattanooga Gas and Elkton Gas where Sequent is assessed annual fixed-fees. Entry into and renewal of these agreements are subject to regulatory approval. The agreements with Florida City Gas, Chattanooga Gas and Elizabethtown Gas expire in March 2014 and we cannot predict whether such agreements will be renewed or the terms of such renewal.

Sequent also has asset management agreements with certain non-affiliated 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, midstream operations and retail operations.

The commodity, storage and transportation portfolios at Sequent and the commodity and storage portfolios at midstream operations and 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, our portfolio of positions as of December 31, 2012 had a VaR of $1.8 million at wholesale services and less than $0.1 million at retail operations.

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 initiated.

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 or summer period, can have a significant impact on demand for and cost of natural gas.

At Nicor Gas, approximately 50% of all usage is for space heating and approximately 75% of the usage and revenues occur from October through March. Weather fluctuations have the potential to significantly impact year-to-year comparisons of operating income and cash flow. We estimate that a 100 degree-day variation from normal weather impacts Nicor Gas’ margin, net of income taxes, by approximately $1 million under its current rate structure.

We have a WNA mechanism for Virginia Natural Gas, Elizabethtown Gas and Chattanooga Gas that partially offsets the impact of unusually cold or warm weather on residential and commercial customer billings and on 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 10.3%.

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 stabilize the impact on its operating margin in the event of warmer or colder-than-normal weather in the winter months. However, these instruments do not fully protect SouthStar’s earnings from the effects of unusually warm or cold weather.

 
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Wholesale services’ earnings are impacted by changes in weather conditions as weather impacts the demand for natural gas and volatility in the natural gas market. The volatility of natural gas commodity prices has a significant impact on our customer rates, our long-term competitive position against other energy sources and the ability of our wholesale services segment to capture value from location and seasonal spreads. The volatility of natural gas prices has been significantly lower than it has been for several prior years in part due to mild hurricane seasons and mild summer and winter weather. Through the acquisition of natural gas and hedging of natural gas prices, wholesale services reduces the risk to its results of operations, cash flows and financial condition.

Tropical Shipping’s operations are affected by weather conditions in Florida, Canada, the Bahamas and Caribbean regions. During hurricane season in the summer and fall, Tropical Shipping may be subject to revenue loss, higher operating expenses, business interruptions, delays, and ship, equipment and facilities damage which could adversely affect Tropical Shipping’s results of operations, cash flows and financial condition. In addition, Seven Seas’ results of operations, cash flows and financial condition may be adversely affected due to increased insured losses relating to claims arising from hurricane-related events.

Nicor Solutions and Nicor Advanced Energy offer utility-bill management products that mitigate and/or eliminate the risks to customers of variations in weather and we hedge this risk to reduce any adverse effect to our results of operations, cash flows and financial condition.

A decrease in the availability of adequate pipeline transportation capacity due to weather conditions could reduce our revenues and profits. Our gas supply for our distribution operations, retail operations, wholesale services and midstream operations segments depends on 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 may 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 may 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 confirmed ten sites in Georgia and three in Florida where Atlanta Gas Light, or its predecessors, own all or part of an MGP site. We are required to investigate possible environmental contamination at those MGP sites and, if necessary, cleanup any contamination. As of December 31, 2012, the soil and sediment remediation program was substantially complete for all Georgia sites, except for a few remaining areas of recently discovered impact, although groundwater cleanup continues. As of December 31, 2012, projected costs related to the MGP sites associated with Atlanta Gas Light range from $65 million to $118 million. For elements of the MGP program where we still cannot provide engineering cost estimates, considerable variability remains in future cost estimates.

We have identified 26 sites in Illinois for which we may have some responsibility. Nicor Gas and Commonwealth Edison Company are parties to an agreement to cooperate in cleaning up residue at many of these sites. The agreement allocates to Nicor Gas 51.7% of cleanup costs for 23 sites. In addition to the agreement with Commonwealth Edison Company there are 3 sites in which we have sole responsibility. Information regarding site reviews has been presented to the Illinois Environmental Protection Agency for certain sites. The results of the detailed site-by-site investigations determined the extent additional remediation is necessary and provided a basis for estimating additional future costs. Our ERC liabilities are customarily reported estimates of future remediation costs for our former operating sites that are contaminated based on our probabilistic models of potential costs and on an undiscounted basis. In 2012, we completed our probabilistic models and engineering estimates for our sites in Illinois, which primarily contributed to the $117 million increase from the amount recorded at December 31, 2011. Based on the estimates we have performed, the cleanup costs for these Illinois sites range from $243 million to $489 million. In accordance with Illinois Commission authorization, we have been recovering, and expect to continue to recover, these costs from our customers, subject to annual prudence reviews.

 
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In addition, we are associated with former MGP sites in New Jersey and North Carolina. 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, preliminary cleanup cost estimates range from $122 million to $209 million. Preliminary costs have been estimated at $11 million for one site in North Carolina.

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

Inflation has caused increases in certain operating 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 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 could 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, we would expect increases in our short-term debt, accounts receivable and bad debt expense.

Finally, higher costs of natural gas can cause our utility customers to conserve their use of our gas services or switch to other competing products. Higher natural gas costs may increase competition from products utilizing alternative energy sources for applications that have traditionally used natural gas, encouraging some customers to move away from natural gas fueled equipment to equipment fueled by other energy sources.
 
The cost of providing retirement plan benefits to eligible employees and qualified retirees is subject to changes in pension fund values and changes in liabilities as a result of updated demographics and assumptions. These changes may have a material adverse effect on our financial results.

Effective December 31, 2012, the Nicor Companies Pension and Retirement Plan (Nicor Plan) and the Employees’ Retirement Plan of NUI Corporation (NUI Plan) were merged with and into the AGL Resources Inc. Retirement Plan (AGL Plan). In addition, the Nicor Welfare Plan was terminated and as of January 1, 2013, all participants under that plan became eligible to participate in the AGL Welfare Plan. This change in plan participation eligibility did not affect the benefit terms.

The Nicor Plan is a noncontributory defined benefit pension plan covering substantially all of its employees hired prior to 1998 and a retiree health care plan for the benefit of substantially all of its employees (Nicor Gas retirees make contributions to their health care plan). AGL Resources maintains a noncontributory defined benefit pension plan and retiree health care plan for its pre-Nicor merger full-time employees and qualified retirees. Further, the AGL retiree health care plan only includes medical coverage for eligible AGL Resources employees who were employed as of June 30, 2002, if they reach retirement age while working for us; additionally the pre-65 retirees make contributions to their health care plan. Effective January 1, 2012, the AGL Plan was frozen with respect to participation for non-union employees hired on or after that date. Such employees will be entitled to employer provided benefits under their defined contribution plan, that exceed defined contribution benefits for employees who participate in the defined benefit plans.
 
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 and assumptions, including longer life expectancy of beneficiaries and changes in health care cost trends. 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 and a charge to our other comprehensive income to the extent that the actual return on assets in the pension fund is less than the expected return. We may be required to make additional contributions in 2013 in order to preserve the current level of benefits under the plans and in accordance with the funding requirements of The Pension Protection Act of 2006 (Pension Protection Act). As of December 31, 2012, our pension plans assets represented 80% of our total pension plan obligations.

For more information regarding some of these obligations, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the caption “Contractual Obligations and Commitments” and the subheading “Pension and Other Retirement Plans” and Note 6 to the consolidated financial statements under Item 8 herein.
 
 
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Natural disasters, terrorist activities and the potential for military and other actions could adversely affect our businesses.

Natural disasters may damage our assets and interrupt our business operations. 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.

Changes in the laws and regulations regarding the sale and marketing of products and services offered by our retail operations segment could adversely affect our results of operations, cash flows and financial condition.

Our retail operations segment provides various energy-related products and services. These include sales of natural gas and utility-bill management services to residential and small commercial customers, and the sale, repair, maintenance and warranty of heating, air conditioning and indoor air quality equipment. The sale and marketing of these products and services are subject to various state and federal laws and regulations. Changes in these laws and regulations could impose additional costs on or restrict or prohibit certain activities, which could adversely affect our results of operations, cash flows and financial condition.

In 1997, Georgia enacted legislation allowing deregulation of gas distribution operations. 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, including our majority-owned subsidiary, SouthStar, 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. We are not aware of any movement to do so, but it is possible that the legislature could reverse or amend portions of the deregulation process.

Changes in the laws and regulations regarding maritime activities offered by our cargo shipping segment could adversely affect our results of operations, cash flows and financial condition.

Tropical Shipping is subject to the International Ship and Port Facility Security Code and is also subject to the United States Maritime Transportation Security Act, both of which require extensive security assessments, plans and procedures. Tropical Shipping is also subject to the regulations of the Federal Maritime Commission, the Surface Transportation Board, as well as other federal agencies and local laws, where applicable. Additional costs that could result from changes in the rules and regulations of these regulatory agencies would adversely affect our results of operations, cash flows and financial condition.
 
Conservation could adversely affect our results of operations, cash flows and financial condition.

As a result of recent legislative and regulatory initiatives on energy conservation, we have put into place programs to promote additional energy efficiency by our customers. Funding for such programs is being recovered through cost recovery riders. However, the adverse impact of lower deliveries and resulting reduced margin could adversely affect our results of operations, cash flows and financial condition.

A security breach could disrupt our operating systems, shutdown our facilities or expose confidential personal information.

Security breaches of our information technology infrastructure, including cyber-attacks and cyber terrorism, could lead to system disruptions or generate facility shutdowns. If such an attack or security breach were to occur, our business, results of operations and financial condition could be materially adversely affected. In addition, such an attack could affect our ability to service our indebtedness, our ability to raise capital and our future growth opportunities.

Additionally, the protection of customer, employee and company data is critical to us. A breakdown or a breach in our systems that results in the unauthorized release of individually identifiable customer or other sensitive data could occur and have a material adverse effect on our reputation, operating results and financial condition. Such a breakdown or breach could also materially increase the costs we incur to protect against such risks. There is no guarantee that the procedures that we have implemented to protect against unauthorized access to secured data are adequate to safeguard against all data security breaches.

 
23

 
We could be adversely affected by violations of the Foreign Corrupt Practices Act and similar worldwide anti-bribery laws.

Our international operations require us to comply with a number of U.S. and international laws and regulations, including those involving anti-bribery and anti-corruption. The Foreign Corrupt Practices Act (FCPA) generally prohibits United States companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or maintaining business or obtaining an improper business benefit. Although our policies require compliance with these laws, we may be held liable for actions taken by our strategic or local partners in foreign jurisdictions, even though these partners may not be subject to the FCPA. Violations of these laws, or allegations of such violations, could disrupt our business and result in a material adverse effect on our business and results of operations, cash flows and financial condition.

We may pursue acquisitions, divestitures and other strategic transactions, the success of which may impact our results of operations, cash flows and financial condition.

In the past, we have pursued acquisitions to complement or expand our business, divestures and other strategic transactions. Such future transactions are part of our general strategic objectives and may occur. If we identify an acquisition candidate, we may not be able to successfully negotiate or finance the acquisition or integrate the acquired businesses with our existing business and services. Future acquisitions could result in potentially dilutive issuances of equity securities and the incurrence of debt and contingent liabilities, amortization expenses and substantial goodwill. We may be affected materially and adversely if we are unable to successfully integrate businesses that we acquire. Similarly, we may divest portions of our business, which may also have material and adverse effects.

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 negatively affected, and we may be forced to postpone, modify or cancel capital projects. 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 or
·  
extreme weather conditions.

The amount of our working capital requirements in the near-term will primarily depend on the market price of natural gas and weather. Higher natural gas prices may adversely impact our accounts receivable collections and may require us to increase borrowings under our credit facilities to fund our operations.

While we believe we can meet our capital requirements from our operations and our available sources of financing, we can provide no assurance that we will continue to be able to do so in the future, especially if the market price of natural gas increases significantly in the near-term. The future effects on our business, liquidity and financial results due to market disruptions could be material and adverse to us, both in the ways described above, or in ways that we do not currently anticipate.

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

The AGL Credit Facility and the Nicor Gas Credit Facility 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 of our indebtedness, which would result in a material adverse effect on our business, results of operations and financial condition.

 
24

 
A downgrade in our credit rating could negatively affect our ability to access capital, or may require us to provide additional collateral to certain counterparties.

Our senior debt is currently assigned investment grade credit ratings. 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. In December 2012, Fitch lowered the ratings of AGL Resources from A- to BBB+. There are no implications of this downgrade on our corporate funding ability or our ability to access the capital markets, nor does this downgrade trigger any collateralization requirements under our corporate guarantees. As of December 31, 2012, if our credit rating had fallen below investment grade, we would have been required to provide collateral of $22 million to continue conducting business with certain customers. For additional credit rating information, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the caption “Liquidity and Capital Resources.”
 
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 may 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. For additional information, see Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” Under the caption “Interest Rate 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 significant 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 the net income and cash flows of our subsidiaries and their ability to pay upstream dividends or other distributions to meet our financial obligations and to pay dividends on our common stock. The ability of our subsidiaries to pay upstream dividends and make other distributions is subject to applicable state law and regulatory restrictions. In addition, Nicor Gas is not permitted to make money pool loans to affiliates. Refer to Item 5, “Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” for additional information. Our subsidiaries are separate legal entities and have no obligation to provide us with funds.
 
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 addition, derivative contracts entered for hedging purposes may not offset the underlying exposure being hedged as expected, resulting in financial losses. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these derivative 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 reported fair value of these contracts.

The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 introduced a comprehensive new regulatory framework requiring certain over-the-counter derivatives, or swaps, to be centrally cleared and executed through an exchange or other approved trading platform. Although the CFTC and the SEC are still in the process of adopting rules to implement the new framework, based on current interpretation, we were not considered to be a “swap dealer” or “major swap participant” in 2012 so we were exempt from the clearing, exchange trading and margin requirements under the Dodd-Frank Act. If these provisions were to apply to our derivative activities, we could be subject to higher costs for our derivative activities, including from higher margin requirements. In addition, implementation of, and compliance with, the over-the-counter derivatives provisions of the Dodd-Frank Act by our swap counterparties could result in increased costs related to our derivative activities.

 
25

 
As a result of cross-default provisions in our borrowing arrangements, we may be unable to satisfy all of our outstanding obligations in the event of a default on our part.

The AGL Credit Facility and the Nicor Gas Credit Facility contain cross-default provisions. Should an event of default occur under some of our debt agreements, we face the prospect of being in default under our other debt agreements, obligated in such instance to satisfy a large portion of our outstanding indebtedness and unable to satisfy all of our outstanding obligations simultaneously.

Changes in taxation could adversely affect our results of operations, cash flows and financial condition.

Various tax and fee increases may occur in locations in which we operate. We cannot predict whether other legislation or regulation will be introduced, the form of any legislation or regulation, or whether any such legislation or regulation will be passed by the legislatures or other governmental bodies. New taxes or an increase in tax rates would increase tax expense and could adversely affect our results of operations, cash flows and financial condition.

Risks Related to Our Merger with Nicor

Our merger with Nicor may not achieve its intended results and we may be unable to fully integrate successfully.

We entered into the Merger Agreement with the expectation that the merger would result in various benefits, including, among other things, increased operating efficiencies and reduced costs. Achieving the anticipated benefits of the merger depends on whether the businesses can be integrated completely in an efficient and effective manner. Integration could take longer than anticipated and could result in the loss of valuable employees, the disruption of our ongoing businesses, processes and systems or inconsistencies in standards, controls, procedures, practices, policies and compensation arrangements, any of which could adversely affect our ability to achieve the anticipated benefits of the merger. We may have difficulty addressing possible differences in corporate cultures and management philosophies. Many of our employees are in new positions following the merger and are required to comply with policies that are new to them, including policies related to risk management. The integration process is subject to a number of uncertainties, and no assurance can be given that the anticipated benefits will be realized or, if realized, the timing of their realization. Failure to achieve these anticipated benefits could result in increased costs or decreases in the amount of expected revenues and could adversely affect our future business, financial condition, operating results and prospects.

The merger may not be accretive to our earnings and may cause dilution to our earnings per share, which may negatively affect the market price of our common shares.

We may encounter additional transaction and integration-related costs, may fail to realize all of the benefits anticipated in the merger or be subject to other factors that affect preliminary estimates. Any of these factors could cause a decrease in our earnings per share or decrease or delay the expected accretive effect of the merger and contribute to a decrease in the price of our common shares.

In connection with the Nicor merger, we recorded goodwill and long-lived assets, including intangible assets, which could become impaired and adversely affect our financial condition and results of operations.

We assess goodwill for impairment at least annually and more frequently if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value. We assess our long-lived assets, including intangible assets, for impairment whenever events or circumstances indicate that an asset’s carrying amount may not be recoverable. To the extent the value of goodwill or long-lived assets become impaired, we may be required to incur impairment charges that could have a material impact on our results of operations. No impairment of goodwill was recorded as a result of our 2012 annual impairment testing as the fair value of each reporting unit was in excess of the carrying value. Additionally, no impairment of long-lived assets was recorded during 2012.
 
Since interest rates are a key component, among other assumptions, in the models used to estimate the fair values of our reporting units, as interest rates rise, the calculated fair values decrease and future impairments may occur. Further, the rates for contracting capacity at Jefferson Island, Golden Triangle Storage and Central Valley are also key components in the models used to estimate their fair value. Consequently, a further decline in market fundamentals and the rates for contracting availability could result in future impairments. Due to the subjectivity of the assumptions and estimates underlying the impairment analysis, we cannot provide assurance that future analyses will not result in impairment. These assumptions and estimates include projected cash flows, current and future rates for contracted capacity, growth rates, weighted average cost of capital and market multiples. For additional information, see Item 7, “Critical Accounting Policies and Estimates.”

 
26

 
Our indebtedness following the merger is higher than our previous indebtedness, which could limit our operations and opportunities, make it more difficult for us to pay or refinance our debts and may cause us to issue additional equity in the future, which would increase the dilution of our shareholders or reduce earnings.

In connection with the merger, we assumed Nicor’s outstanding debt and incurred additional debt to pay the cash portion of the merger consideration and transactions expenses. Our total indebtedness as of December 31, 2012 was $4.9 billion (including $1.4 billion of short-term borrowings and $3.5 billion of long-term debt and other long-term obligations).

Our debt service obligations with respect to this increased indebtedness could have an adverse impact on our earnings and cash flows (which after the merger include the earnings and cash flows of Nicor) for as long as the indebtedness is outstanding.

This increased indebtedness could also have important consequences to shareholders. For example, it could:

·  
make it more difficult for us to pay or refinance our debts as they become due during adverse economic and industry conditions because any decrease in revenues could cause us to not have sufficient cash flows from operations to make our scheduled debt payments
·  
limit our flexibility to pursue other strategic opportunities or react to changes in our business and the industry in which we operate and, consequently, place us at a competitive disadvantage to competitors with less debt
·  
require a substantial portion of our cash flows from operations to be used for debt service payments, thereby reducing the availability of our cash flow to fund working capital, capital expenditures, acquisitions, dividend payments and other general corporate purposes
·  
result in a downgrade in the credit rating of our indebtedness, which could limit our ability to borrow additional funds or increase the interest rates applicable to our indebtedness
·  
reduce the amount of credit available to us to support hedging activities
·  
result in higher interest expense in the event of increases in interest rates since some of our borrowings are, and will continue to be, at variable rates.

Based upon current levels of operations, we expect to be able to generate sufficient cash on a consolidated basis to make all of the principal and interest payments when such payments are due under our existing credit agreements, indentures and other instruments governing our outstanding indebtedness, and under the indebtedness of Nicor and its subsidiaries that remained outstanding after the merger; but there can be no assurance that we will be able to repay or refinance such borrowings and obligations in future periods.

We are committed to maintaining and improving our credit ratings. In order to maintain and improve these credit ratings, we may consider it appropriate to reduce the amount of indebtedness outstanding. This may be accomplished in several ways, including issuing additional shares of common stock or securities convertible into shares of common stock, reducing discretionary uses of cash or a combination of these and other measures. Issuances of additional shares of common stock or securities convertible into shares of common stock would have the effect of diluting the ownership percentage that shareholders will hold in the combined company and might reduce the reported earnings per share. The specific measures that we may ultimately decide to use to maintain or improve our credit ratings and their timing will depend upon a number of factors, including market conditions and forecasts at the time those decisions are made.

ITEM 1B. UNRESOLVED STAFF COMMENTS

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.

 
27

 
 
 
We consider our properties to be well maintained, in good operating condition and suitable for their intended purpose. The following provides the location and general character of the materially important properties that are used by our segments. Substantially all of Nicor Gas’ properties are subject to the lien of the indenture securing its first mortgage bonds. See Note 8 to our consolidated financial statements under Item 8 herein.

Distribution and transmission mains

Our distribution systems transport natural gas from our pipeline suppliers to our customers in our service areas. At December 31, 2012, our distribution operations segment owned approximately 80,000 miles of underground distribution and transmission mains. These distribution and transmission mains are located on easements or rights-of-way which generally provide for perpetual use.

Storage assets

Distribution Operations We own and operate eight underground natural gas storage facilities in Illinois with a total inventory capacity of about 150 Bcf, approximately 135 Bcf of which can be cycled on an annual basis. The system is designed to meet about 50% of the estimated peak-day deliveries and approximately 40% of its normal winter deliveries in Illinois. In addition to the facilities we own, we have about 40 Bcf of purchased storage services under contracts with Natural Gas Pipeline Company of America that expire in 2013. This level of storage capability provides us with supply flexibility, improves the reliability of deliveries and can mitigate the risk associated with seasonal price movements.

We have approximately 7.7 Bcf of LNG storage capacity in seven LNG plants located in Georgia, New Jersey and Tennessee. In addition, we own two propane storage facilities in Virginia that have a combined storage capacity of approximately 0.4 Bcf. The LNG plants and propane storage facilities are used by our distribution operations segment to supplement natural gas supply during peak usage periods.

Midstream Operations We own three high-deliverability natural gas storage and hub facilities which are operated by our midstream operations segment. Jefferson Island operates a salt-dome storage facility in Louisiana currently consisting of two salt dome gas storage caverns with approximately 10 Bcf of total capacity and about 7.3 Bcf of working gas capacity. Golden Triangle Storage operates a salt-dome storage facility in Texas designed for approximately 13.5 Bcf of working natural gas capacity and total cavern capacity of 20 Bcf. Cavern 1, with 6 Bcf of working capacity, was completed and began commercial service in September 2010. Cavern 2, with 7.5 Bcf of working capacity, was completed and began commercial service in September 2012. Central Valley developed an underground natural gas storage facility in California with 11 Bcf of working natural gas capacity which was placed into commercial service in June 2012. In addition to the LNG facilities that support utility operations, we have recently placed into commercial operations an LNG facility purchased from the Trussville Utilities District in Alabama. This facility produces LNG for Pivotal LNG, a wholly owned subsidiary, to support its business of selling LNG as a substitute fuel in various market segments.

Vessels and shipping containers

Our cargo shipping segment operates 12 owned vessels and 2 chartered vessels with a container capacity totaling approximately 6,000 TEUs. The owned vessels range in age from 2 - 36 years, and vary in length from 235 - 525 feet. In addition to the vessels, we own and/or lease containers, freight-handling equipment, chassis and other equipment.

Offices

All of our segments own or lease office, warehouse and other facilities throughout our operating areas. We expect additional or substitute space to be available as needed to accommodate the expansion of our operations.


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.

For more information regarding some of these proceedings, see Note 11 to our consolidated financial statements under Item 8 herein under the caption “Litigation.


Not applicable.

 
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ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Holders of Common Stock, Stock Price and Dividend Information

Our common stock is listed on the New York Stock Exchange under the ticker symbol GAS. At January 31, 2013, there were 22,221 record holders of our common stock. Quarterly information concerning our high and low stock prices and cash dividends paid in 2012 and 2011 is as follows:

   
Sales price of common stock
   
Cash dividend per common
     
Sales price of common stock
   
Cash dividend per common
 
Quarter ended:
 
High
   
Low
   
Share
 
Quarter ended:
 
High
   
Low
   
share
 
March 31, 2012
  $ 42.88     $ 38.42     $ 0.36  
March 31, 2011
  $ 39.91     $ 35.65     $ 0.45  
June 30, 2012
    40.29       36.59       0.46  
June 30, 2011
    42.34       38.58       0.45  
September 30, 2012
    41.95       38.45       0.46  
September 30, 2011
    42.40       34.08       0.45  
December 31, 2012
    41.71       36.90       0.46  
December 31, 2011 (1)
    43.69       37.95       0.55  
                    $ 1.74                       $ 1.90  
(1)  
As a result of the Nicor merger, AGL Resources shareholders of record as of the close of business on December 8, 2011, received a pro rata dividend of $0.0989 for the stub period, accruing from November 19, 2011. For presentation purposes the amount in the table was rounded to $0.10.

We have historically paid dividends to common shareholders four times a year: March 1, June 1, September 1 and December 1. We have paid 260 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 covenants, and
·  
our ability to satisfy our obligations to any future 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 rights are superior to those of the shareholders receiving the dividends.
 
Securities Authorized for Issuance Under Equity Compensation Plans

See Part III, Item 12 “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” under the heading “Executive Compensation -- Equity Compensation Plan Information.”

Issuer Purchases of Equity Securities

There were no purchases of our common stock by us and any affiliated purchasers during the three months ended December 31, 2012.


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.” Material changes from 2011 to 2012 and 2010 to 2011 are primarily due to the Nicor merger which closed on December 9, 2011. See Note 3 to our consolidated financial statements under Item 8 herein for additional merger related information.

 
29

 

 
Dollars and shares in millions, except per share amounts
 
2012 (1)
   
2011 (1)
   
2010
   
2009
   
2008
 
Income statement data
                             
Operating revenues
  $ 3,922     $ 2,338     $ 2,373     $ 2,317     $ 2,800  
Operating expenses
                                       
Cost of goods sold
    1,791       1,097       1,164       1,142       1,654  
Operation and maintenance (2)
    921       501       497       497       472  
Depreciation and amortization
    415       186       160       158       152  
Nicor merger expenses (2)
    20       57       6       0       0  
Taxes other than income taxes
    165       57       46       44       44  
Total operating expenses
    3,312       1,898       1,873       1,841       2,322  
Operating income
    610       440       500       476       478  
Other income (expense)
    24       7       (1 )     9       6  
Earnings before interest and taxes (EBIT) (3)
    634       447       499       485       484  
Interest expenses
    184       136       109       101       115  
Earnings before income taxes
    450       311       390       384       369  
Income taxes
    164       125       140       135       132  
Net income
    286       186       250       249       237  
Less net income attributable to the noncontrolling interest
    15       14       16       27       20  
Net income attributable to AGL Resources Inc.
  $ 271     $ 172     $ 234     $ 222     $ 217  
Common stock data
                                       
Weighted average common shares outstanding basic
    117.0       80.4       77.4       76.8       76.3  
Weighted average common shares outstanding diluted
    117.5       80.9       77.8       77.1       76.6  
Total shares outstanding (4)
    117.9       117.0       78.0       77.5       76.9  
Basic earnings per common share attributable to AGL Resources Inc. common shareholders
  $ 2.32     $ 2.14     $ 3.02     $ 2.89     $ 2.85  
Diluted earnings per common share - attributable to AGL Resources Inc. common shareholders
  $ 2.31     $ 2.12     $ 3.00     $ 2.88     $ 2.84  
Dividends declared per common share (5)
  $ 1.74     $ 1.90     $ 1.76     $ 1.72     $ 1.68  
Dividend payout ratio
    75 %     89 %     58 %     60 %     59 %
Dividend yield (6)
    4.4 %     4.5 %     4.9 %     4.7 %     5.4 %
Price range:
                                       
High
  $ 42.88     $ 43.69     $ 40.08     $ 37.52     $ 39.13  
Low
  $ 36.59     $ 34.08     $ 34.21     $ 24.02     $ 24.02  
Close (4)
  $ 39.97     $ 42.26     $ 35.85     $ 36.47     $ 31.35  
Market value (4)
  $ 4,711     $ 4,946     $ 2,800     $ 2,826     $ 2,411  
Statements of Financial Position data (4)
                                       
Total assets
  $ 14,141     $ 13,913     $ 7,520     $ 7,079     $ 6,710  
Property, plant and equipment - net
    8,347       7,900       4,405       4,146       3,816  
Short-term debt
    1,377       1,321       733       602       866  
Long-term debt
    3,553       3,578       1,971       1,974       1,675  
Total debt
    4,930       4,899       2,704       2,576       2,541  
Total equity
    3,435       3,339       1,836       1,819       1,684  
Cash flow data
                                       
Net cash flow provided by operating activities
  $ 1,003     $ 451     $ 526     $ 592     $ 227  
Net cash flow used in investing activities
    (786 )     (1,339 )     (442 )     (476 )     (372 )
Net cash flow (used in) provided by financing activities
    (155 )     933       (86 )     (106 )     142  
Net borrowings and (payments) of short-term debt
    56       91       131       (264 )     286  
Financial ratios (4)
                                       
Debt
    59 %     59 %     60 %     59 %     60 %
Equity
    41 %     41 %     40 %     41 %     40 %
Total
    100 %     100 %     100 %     100 %     100 %
Return on average equity
    8.0 %     6.6 %     12.8 %     12.7 %     12.8 %
                                         
(1)  
Material changes from 2011 to 2012 and 2010 to 2011 are primarily due to the Nicor merger on December 9, 2011. The year ending December 31, 2011 includes only 22 days of Nicor activity from December 10, 2011 through December 31, 2011. See Note 3 for additional merger related information.
(2)  
Transaction expenses associated with the Nicor merger were excluded from operation and maintenance expenses and presented separately.
(3)  
This is a non-GAAP measurement. A reconciliation of EBIT to earnings before income taxes 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.”
(4)  
As of the last day of the fiscal period.
(5)  
As a result of the Nicor merger, AGL Resources shareholders of record as of the close of business on December 8, 2011, received a pro rata dividend of $0.0989 for the stub period, accruing from November 19, 2011. For presentation purposes the amount in the table was rounded to $0.10.
(6)  
Dividends declared per common share during the fiscal period divided by market value per common share as of the last day of the fiscal period.


 
30

 

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS


We are the nation’s largest natural gas-only distribution company based on customer count. Our regulated utility and non-regulated businesses are summarized below:

·  
Seven regulated natural gas distribution companies providing natural gas services to approximately 4.5 million customers in Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee and Maryland
·  
Over 1 million retail customers in our unregulated businesses
·  
Physical wholesale gas business delivering approximately 5.5 Bcf of natural gas per day
·  
Natural gas storage facilities that provided approximately 31.8 Bcf of working gas storage capacity in 2012
·  
One of the largest containerized cargo carriers in the Caribbean and Bahamas

The following table provides certain information on our segments, which changed as a result of the Nicor merger in 2011. See Note 13 to our consolidated financial statements under Item 8 herein for additional segment information.

   
EBIT
   
Assets
   
Capital Expenditures
 
   
2012
   
2011
   
2010
   
2012
   
2011
   
2010
   
2012
   
2011
   
2010
 
Distribution operations
    84 %     92 %     70 %     80 %     79 %     73 %     83 %     85 %     70 %
Retail operations
    18       21       21       4       4       3       1       1       1  
Wholesale services
    0       1       10       9       9       18       0       0       0  
Midstream operations
    2       2       1       5       5       6       8       8       25  
Cargo shipping
    1       0       n/a       3       3       n/a       1       0       n/a  
Other
    (5 )     (16 )     (2 )     (1 )     0       0       7       6       4  
Total
    100 %     100 %     100 %     100 %     100 %     100 %     100 %     100 %     100 %
 
Legislative and regulatory update We continue to actively pursue a regulatory strategy that improves customer service and reduces the lag between our investments in infrastructure and the recovery of those investments through various rate mechanisms. If our rate design proposals are not approved, we will continue to work cooperatively with our regulators, legislators and others to create a framework that is conducive to our business goals and the interests of our customers and shareholders. In 2013, we anticipate resolution of the Nicor Gas PBR issue, for which we have accrued $72 million as potential refunds to our Illinois customers. Additionally, our pipeline replacement program is expected to be completed in 2013 and we will work to successfully achieve our targets with our other regulatory infrastructure programs. We expect to spend $212 million on these regulatory infrastructure programs in 2013. For more information on our regulatory items and capital projects, see Item 1, “Business - Utility Regulation and Rate Design” and “Capital Projects.”

Customer growth initiatives While there has been some improvement in the economic conditions within the areas we serve, we continue to feel the effect of a weak economy. We have experienced a slight customer gain in our distribution operations segment and a slight customer loss in our retail operations segment throughout 2012. We anticipate improved customer trends in 2013 compared to our 2012 results.

We use a variety of targeted marketing programs to attract new customers and to retain existing customers. These efforts include working to add residential customers, multifamily complexes and commercial customers who use natural gas for purposes other than space heating, as well as evaluating and launching new natural gas related programs, products and services to enhance customer growth, mitigate customer attrition and increase operating revenues. These programs generally emphasize natural gas as the fuel of choice for customers and seek to expand the use of natural gas through a variety of promotional activities.

Additionally, we intend to expand our retail services business in 2013 to include our service territories in Georgia, Virginia and Tennessee. We anticipate this expansion will provide growth opportunities in 2013 and in the future.

Natural gas price volatility Volatility in the natural gas market arises from a number of factors, such as weather fluctuations or changes in supply or demand for natural gas in different regions of the country. The volatility of natural gas commodity prices has a significant impact on our customer rates, our long-term competitive position against other energy sources and the ability of our wholesale services segment to capture value from location and seasonal spreads. During 2012 and 2011, the volatility of the daily Henry Hub spot market prices for natural gas in the United States has been significantly lower than it had been in prior years. This is the result of a robust natural gas supply, the weak economy, mild weather and ample storage. Our utility natural gas acquisition strategy is designed to secure sufficient supplies of natural gas to meet the needs of our utility customers and to hedge gas prices to effectively manage costs, reduce price volatility for our utility customers and maintain a competitive advantage. Additionally, our hedging strategies and physical natural gas supplies in storage enable us to reduce earnings risk exposure due to higher gas costs.

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

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

Seasonality The operating revenues and EBIT of our distribution operations, retail operations, wholesale services and cargo shipping 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. Occasionally in the summer, wholesale services operating revenues are impacted due to peak usage by power generators in response to summer energy demands. Seasonality also affects the comparison of certain Consolidated Statements of Financial Position items across quarters, including receivables, unbilled revenue, inventories and short-term debt. However, these items are comparable when reviewing our annual results.

Additionally, the revenues of our cargo shipping business are generally higher in the fourth quarter, as our customers require more tourist-related shipments as the hotels, resorts, and cruise ships typically have increased occupancy rates commencing in the fourth quarter and increasing further into the first quarter and consumer spending increases during traditional holiday periods. Revenues are impacted during the fourth quarter by Peak Season Surcharges in effect from early October through mid-December.

67% of these segments’ operating revenues and 75% of these segments’ EBIT for the year ended December 31, 2012 were generated during the first and fourth quarters of 2012, and are reflected in our Consolidated Statements of Income for the quarters ended March 31, 2012 and December 31, 2012. Our base operating expenses, excluding cost of goods sold, interest expense and certain incentive compensation costs, are incurred relatively equally over any given year. Thus, our operating results can vary significantly from quarter to quarter as a result of seasonality.
 

We generate the majority of our operating revenues through the sale, distribution and storage of natural gas. We include in our consolidated revenues an estimate of revenues from natural gas distributed, but not yet billed, to residential, commercial and industrial customers from the date of the last bill to the end of the reporting period. No individual customer or industry accounts for a significant portion of our revenues. The following table provides more information regarding the components of our operating revenues.
 
In millions
 
2012
   
2011 (1)
   
2010
 
Residential
  $ 2,011     $ 1,065     $ 1,083  
Commercial
    656       467       521  
Transportation
    492       403       404  
Shipping
    342       19       0  
Industrial
    262       289       205  
Other
    159       95       160  
Total operating revenues
  $ 3,922     $ 2,338     $ 2,373  
(1)  
As a result of our merger with Nicor, our results of operations for the year ending December 31, 2011 includes 22 days of activity from the acquired subsidiaries from December 10, 2011 through December 31, 2011.

We evaluate segment performance using the measures of operating margin and EBIT, which include the effects of corporate expense allocations. Operating margin is a non-GAAP measure that is calculated as operating revenues minus cost of goods sold and revenue tax expense in distribution operations. Operating margin excludes operation and maintenance expense, depreciation and amortization, 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 Consolidated Statements of Income. EBIT is also a non-GAAP measure that includes operating income and other income and expenses. Items that we do not include in EBIT are financing costs, including interest and debt expense and income taxes, each of which we evaluate on a consolidated basis.

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

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

We do not routinely engage in transactions of the magnitude of the Nicor merger, and consequently do not regularly incur transaction and integration-related expenses of correlative size. We believe presenting the non-GAAP measurements of basic and diluted earnings per share - as adjusted, which excludes Nicor merger-related expenses, provides investors with an additional measure of our performance. Additionally, we have excluded the additional accrual for the Nicor Gas PBR issue as it was a one-time expense that is not expected to be recurring. Adjusted basic and diluted earnings per share should not be considered an alternative to, or a more meaningful indicator of our operating performance than our GAAP basic and diluted earnings per share. The following table reconciles operating revenue and operating margin to operating income and EBIT to earnings before income taxes and net income and our GAAP basic and diluted earnings per common share to our non-GAAP basic and diluted earnings per share – as adjusted, together with other consolidated financial information for the last three years.

In millions
 
2012
   
2011
   
2010
 
Operating revenues
  $ 3,922     $ 2,338     $ 2,373  
Cost of goods sold
    (1,791 )     (1,097 )     (1,164 )
Revenue tax expense (1)
    (85 )     (9 )     0  
Operating margin (2)
    2,046       1,232       1,209  
Operating expenses (3) (5)
    (1,501 )     (744 )     (703 )
Revenue tax expense (1)
    85       9       0  
Nicor merger expenses (4)
    (20 )     (57 )     (6 )
Operating income
    610       440       500  
Other income (expense)
    24       7       (1 )
EBIT
    634       447       499  
Interest expenses
    (184 )     (136 )     (109 )
Earnings before income taxes
    450       311       390  
Income tax expenses
    (164 )     (125 )     (140 )
Net income
    286       186       250  
Less net income attributable to the noncontrolling interest
    15       14       16  
Net income attributable to AGL Resources Inc.
  $ 271     $ 172     $ 234  
Per common share data
                       
Basic earnings per common share attributable to AGL Resources Inc. common shareholders
  $ 2.32     $ 2.14     $ 3.02  
   Additional accrual for Nicor Gas PBR issue
    0.04       0.00       0.00  
   Transaction costs of Nicor merger
    0.11       0.80       0.05  
Basic earnings per share – as adjusted
  $ 2.47     $ 2.94     $ 3.07  
                         
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders
  $ 2.31     $ 2.12     $ 3.00  
   Additional accrual for Nicor Gas PBR issue
    0.04       0.00       0.00  
   Transaction costs of Nicor merger
    0.11       0.80       0.05  
Diluted earnings per share – as adjusted
  $ 2.46     $ 2.92     $ 3.05  
(1)  
Adjusted for revenue tax expenses for Nicor Gas which are passed directly through to customers.
(2)  
Our operating margin was negatively impacted by warmer-than-normal weather by $33 million in 2012.
(3)  
Excludes expenses associated with the merger with Nicor of $20 million ($13 million net of tax) in 2012, $57 million ($48 million net of tax) in 2011 and $6 million ($4 million net of tax) in 2010.
(4)  
Expenses associated with the Nicor merger are part of operating expenses, but are shown separately to better compare year-over-year results. Our 2011 merger expenses include debt issuance costs and interest expense on pre-funding the cash portion of the purchase consideration of $25 million ($16 million net of taxes), while there is no such expense in our 2010 merger expenses.
(5)  
Our 2012 operating expenses were favorably impacted by reduced incentive compensation accruals of $29 million compared to targeted amounts. We expect these amounts to return to targeted levels in 2013.

In 2012, our net income attributable to AGL Resources Inc. increased by $99 million or 58% compared to last year. The increase was primarily the result of increased operating income at distribution operations, retail operations and cargo shipping as a result of the Nicor merger, and increased regulatory infrastructure program revenues at Atlanta Gas Light. The increases were partially offset by the effect of warmer-than-normal weather in our distribution operations and retail operations segments, and significantly lower margins at wholesale services resulting from mark-to-market accounting hedge losses. Additionally, during 2012, we recorded $37 million less expenses associated with the merger with Nicor compared to 2011.

 
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In 2011, our net income attributable to AGL Resources Inc. decreased by $62 million or 26% compared to 2010. The decrease was primarily the result of $57 million ($48 million net of tax) of transaction expenses associated with the merger with Nicor in 2011. We incurred $6 million ($4 million net of tax) of Nicor transaction costs in 2010. Additionally, we experienced reduced EBIT at wholesale services and retail energy operations due to decreased average customer usage, warmer weather, losses associated with pipeline constraints in the Marcellus shale gas region and significantly lower natural gas volatility. This decrease was partially offset by higher EBIT at distribution operations due to increased revenues from new rates at Atlanta Gas Light and increased regulatory infrastructure program revenues at Atlanta Gas Light and Elizabethtown Gas. The decrease in our net income attributable to AGL Resources Inc. was also unfavorably impacted by increased interest expenses resulting from higher average debt outstanding, primarily the result of the additional long-term debt issuance used to fund the Nicor merger. The variances for each operating segment are contained within the year-over-year discussion on the following pages.

Interest expense In 2012 our interest expense increased by $48 million or 35% compared to 2011. These increases were the result of higher average debt outstanding primarily as a result of the additional long-term debt issued to fund the Nicor merger and the long-term debt assumed in the transaction.

The increase in our interest expenses of $27 million in 2011 compared to 2010 was primarily the result of our prefunding the cash portion of the merger consideration through the issuance of $975 million of long-term debt during the year. This increased our annual interest expense by $17 million. The remaining increase during 2011 related primarily to fees paid on our Term Loan Facility and our Bridge Facility, both of which terminated in 2011. The following table provides additional detail on interest expense for the last three years and the primary items that affect year-over-year change.

In millions
 
2012
   
2011
   
2010
 
Interest expenses
  $ 184     $ 136     $ 109  
Average debt outstanding (1)
  $ 4,378     $ 2,652     $ 2,393  
Average rate (2)
    4.2 %     5.1 %     4.6 %
(1)  
Daily average of all outstanding debt.
(2)  
Increase in the 2011 average interest rate is due to our senior note issuances during the current year.

Income tax expense In 2012, our income tax expense increased by $39 million or 31% compared to the same period in 2011 primarily due to higher consolidated earnings. Our effective tax rate was 37.7% in 2012 compared to 42.2% in 2011. The decreased effective tax rate was primarily due to the non-deductible merger transaction expenses in 2011. Our estimated effective tax rate for 2013 is 37.9%.

In 2011, our income tax expense decreased by $15 million or 11% compared to 2010. The decrease was primarily due to lower consolidated earnings as previously discussed. Our effective tax rate was 42.1% in 2011 and 37.5% in 2010. The increased effective tax rate in 2011 was primarily due to non-deductible merger transaction expenses.

As a result of the authoritative guidance related to consolidations, income tax expense and our effective tax rate are determined from earnings before income taxes less net income attributable to the noncontrolling interest. For more information on our income taxes, including a reconciliation between the statutory federal income tax rate and our effective tax rate, see Note 12 to our consolidated financial statements under Item 8 herein.

Operating metrics Selected weather, customer and volume metrics for 2012, 2011 and 2010, which we consider to be some of the key performance indicators for our operating segments, are presented in the following tables. For the businesses that were acquired from the Nicor merger we only include the 22 days of activity from December 10, 2011 through December 31, 2011. We measure the effects of weather on our business through heating degree days. Generally, increased heating degree days result in greater demand for gas on our distribution systems. However, extended and unusually mild weather during the Heating Season can have a significant negative impact on demand for natural gas in our distribution operations and retail operations segments.
 
Volume metrics for distribution operations and retail operations, as shown in the following table, present the effects of weather and our customers’ demand for natural gas compared to prior year. Our customer metrics highlight the average number of customers to which we provide services. This number of customers can be impacted by natural gas prices, economic conditions and competition from alternative fuels.

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

 
34

 
 
Customers (average end-use - in thousands)
 
Year ended December 31,
   
2012 vs. 2011
   
2011 vs. 2010
 
   
2012
   
2011
   
2010
   
% change
   
% change
 
Distribution Operations
    4,459       4,454       2,264       0.1 %     n/a  
Retail Operations
                                       
Georgia
    485       489       496       (1 )%     (1 )%
Illinois
    462       515       n/a       (10 )%     n/a  
Ohio and Florida (1)
    83       104       77       (20 )%     35 %
Indiana
    41       37       n/a       11 %     n/a  
Other
    11       4       n/a       175 %     n/a  
Total
    1,082       1,149       573       (6 )%     n/a  
Market share in Georgia
    32 %     33 %     33 %     (3 )%     n/a  
 

 
Weather (Heating Degree Days) (2)
   
2012 vs.
   
2011 vs.
   
2012 vs.
   
2011 vs.
   
2010 vs.
 
                           
2011
   
2010
   
normal
   
normal
   
normal
 
   
Normal
   
2012
   
2011
   
2010
   
colder (warmer)
   
colder (warmer)
   
colder (warmer)
   
colder (warmer)
   
colder (warmer)
 
Year ended December 31,
                                                     
Illinois
    5,630       4,863       5,892       n/a       (17 )%     n/a       (14 )%     5 %     n/a  
Georgia
    2,600       1,934       2,454       3,209       (21 )%     (24 )%     (26 )%     (6 )%     23 %
                                                                         
Quarter ended December 31,
                                                                       
Illinois
    2,020       1,890       1,810       n/a       4 %     n/a       (6 )%     (10 )%     n/a  
Georgia
    1,009       878       852       1,187       3 %     (28 )%     (13 )%     (16 )%     18 %