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
   
ANNUAL REPORT PURSUANT TO SECTION 13 OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2014
 
Commission File Number 1-14174
 
AGL RESOURCES INC.
Ten Peachtree Place NE,
Atlanta, Georgia 30309
404-584-4000
   
Georgia
58-2210952
(State of incorporation)
(I.R.S. Employer Identification No.)
   
   
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
   
 
 
AGL Resources Inc. is a well-known seasoned issuer.
 
AGL Resources Inc. is required to file reports pursuant to Section 13 of the Securities Exchange Act.
 
AGL Resources Inc.: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 days.
   
AGL Resources Inc. has submitted electronically and posted on its corporate website every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months.
 
AGL Resources Inc. believes that during the 2014 fiscal year, its executive officers, directors and 10% beneficial owners subject to Section 16(a) of the Securities Exchange Act complied with all applicable filing requirements, except as set forth under the caption “Section 16(a) Beneficial Ownership Reporting Compliance” in AGL Resources Inc.’s Proxy     Statement for the 2015 Annual Meeting of Shareholders.
 
AGL Resources Inc. is a large accelerated filer and is not a shell company.
 
The aggregate market value of AGL Resources Inc.’s common stock held by non-affiliates of the registrant (based on the closing sale price on June 30, 2014, as reported by the New York Stock Exchange), was $6,574,107,387.
   
The number of shares of AGL Resources Inc.’s common stock outstanding as of February 4, 2015 was 119,656,937
   
DOCUMENTS INCORPORATED BY REFERENCE:
 
Portions of the Proxy Statement for the 2015 Annual Meeting of Shareholders (Proxy Statement) to be held on April 28, 2015, are incorporated by reference in Part III of this Form 10-K.

 
 
 
 
     
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AFUDC
Allowance for funds used during construction, which represents the estimated cost of funds, from both debt and equity sources, used to finance the construction of major projects and is capitalized in rate base for ratemaking purposes when the completed projects are placed in service
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
Atlantic Coast Pipeline
Atlantic Coast Pipeline, LLC
Bcf
Billion cubic feet
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
Compass Energy
Compass Energy Services, Inc., which was sold in 2013
Dalton Pipeline
A 50% undivided ownership interest in a pipeline facility in Georgia
EBIT
Earnings before interest and taxes, the primary measure of our reportable segments’ profit or loss, which includes operating income and other income and excludes financing costs, including interest on debt and income tax expense
EPA
U.S. Environmental Protection Agency
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
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
Golden Triangle Storage, Inc.
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
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
HVAC
Heating, ventilation and air conditioning
Illinois Commission
Illinois Commerce Commission, the state regulatory agency for Nicor Gas
Jefferson Island
Jefferson Island Storage & Hub, LLC
LDC
Local Distribution Company
LIBOR
London Inter-Bank Offered Rate
LIFO
Last-in, first-out
LNG
Liquefied natural gas
LOCOM
Lower of weighted average cost or current market price
Marketers
Marketers selling retail natural gas in Georgia and certificated by the Georgia Commission
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 Gas
Northern Illinois Gas Company, doing business as Nicor Gas Company
Nicor Gas Credit Facility
$700 million credit facility entered into by Nicor Gas to support its commercial paper program
NYMEX
New York Mercantile Exchange, Inc.
OCI
Other comprehensive income
Operating margin
A non-GAAP measure of income, calculated as operating revenues minus cost of goods sold and revenue tax expense
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
PennEast Pipeline
PennEast Pipeline Company, LLC
PGA
Purchased Gas Adjustment
Piedmont
Piedmont Natural Gas Company, Inc.
Pivotal Home Solutions
Nicor Energy Services Company, doing business as Pivotal Home Solutions
PP&E
Property, plant and equipment
S&P
Standard & Poor’s Ratings Services
Sawgrass Storage
Sawgrass Storage, LLC
SEC
Securities and Exchange Commission
Sequent
Sequent Energy Management, L.P.
SouthStar
SouthStar Energy Services LLC
STRIDE
Atlanta Gas Light’s Strategic Infrastructure Development and Enhancement program
Triton
Triton Container Investments LLC
Tropical Shipping
Tropical Shipping and Construction Company Limited
U.S.
United States
VaR
Value-at-risk is the maximum potential loss in portfolio value over a specified time period that is not expected to be exceeded within a given degree of probability.
Virginia Natural Gas
Virginia Natural Gas, Inc.
Virginia Commission
Virginia State Corporation Commission, the state regulatory agency for Virginia Natural Gas
WACC
Weighted average cost of capital
WACOG
Weighted average cost of gas
WNA
Weather normalization adjustment

 
 
 

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

Business Overview

AGL Resources, headquartered in Atlanta, Georgia, is an energy services holding company whose primary business is the distribution of natural gas through our natural gas distribution utilities. We also are involved in several other businesses that are mainly related and complementary to our primary business. Our segments consist of the following four reportable segments, which are consistent with how management views and manages our businesses.

Distribution Operations
· Operation, construction and maintenance of 80,700 miles of natural gas pipeline and 14 storage facilities to provide safe and cost-effective service of natural gas to residential, commercial and industrial customers
· Serves 4.5 million customers across 7 states
· Rates of return are regulated by each individual state in return for exclusive franchises
   
Retail Operations
· Provision of natural gas commodity and related services to customers in competitive markets or markets that provide for customer choice
· Serves 628,000 energy customers and 1.2 million service contracts across 15 states
   
Wholesale Services
· Engages in natural gas storage, gas pipeline arbitrage and provides natural gas asset management and/or related logistics services for most of our utilities, as well as for non-affiliated companies
· Serves a variety of customers in the natural gas value chain with operations structured to optimize storage and transportation portfolios under a wide range of market conditions through the use of hedging tools that allow us to capture additional value while limiting risk
   
Midstream Operations
· Consists primarily of high deliverability natural gas storage facilities and select pipelines, enabling the provision of diverse sources of natural gas supplies to our customers

For more 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.


Our distribution operations segment is the largest component of our business and includes seven natural gas local distribution utilities with their primary focus being the safe and reliable delivery of natural gas. 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   2,195       34,100  
Atlanta Gas Light
Georgia
    1,560       32,600  
Virginia Natural Gas
Virginia
    287       5,500  
Elizabethtown Gas
New Jersey
    281       3,200  
Florida City Gas
Florida
    105       3,600  
Chattanooga Gas
Tennessee
    63       1,600  
Elkton Gas
Maryland
    6       100  
Total
      4,497       80,700  

Competition and Customer Demand

Our utilities do not compete with other distributors of natural gas in their exclusive franchise territories, but face competition from other energy products. Our principal competitors are electric utilities and fuel oil and propane providers serving the residential, commercial and industrial markets throughout our service areas for our customers who are considering switching from a natural gas appliance. Accordingly, 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 use the chosen energy source for the life of the equipment. Customer demand for natural gas could be affected by numerous factors, including:

    ·  
change in the availability or price of natural gas and other forms of energy;
    ·  
general economic conditions;
    ·  
energy conservation, including state-supported energy efficiency programs;
    ·  
legislation and regulations; and
    ·  
the cost and capability to convert from natural gas to alternative energy products;

 
 
We continue to develop and grow our business through the 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 might use natural gas, 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.

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.

Recent advances in natural gas drilling in shale producing regions in the U.S. have resulted in historically high supplies of natural gas and historically low prices for natural gas. This dynamic has provided solid cost advantages for natural gas when compared to electricity, fuel oil and propane and opportunities for growth for our businesses.

Sources of Natural Gas Supply and Transportation Services

Procurement plans for natural gas supply and transportation to serve our regulated utility customers are reviewed and approved by our state utility commissions. We purchase natural gas supplies in the open market by contracting with producers, marketers and from our wholly owned subsidiary, Sequent, under asset management agreements in states where this is approved by the state commission. 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, thereby reducing the net 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 consistently 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.

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 set by the Georgia Commission and periodically adjusted. The Marketers add these fixed charges when billing customers. 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 largely 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 mechanisms and weather derivative instruments, in place at most of our utilities that 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 nor utilize a traditional natural gas cost recovery mechanism. However, Atlanta Gas Light does maintain natural gas inventory for the Marketers in Georgia and recovers the cost of this gas through recovery mechanisms approved by the Georgia Commission specific to Georgia’s deregulated market. 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. 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.


$ in millions
 
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 2014 return on rate base (2)
    8.56%       7.80%       6.45%       8.22%       5.37%       7.94%  
Authorized return on equity (1)
    10.17%       10.75%       10.00%       10.30%       11.25%       10.05%  
Estimated 2014 return on equity (2)
    12.12%       10.16%       8.77%       11.52%       8.41%       11.19%  
Authorized rate base % of equity (1)
    51.07%       51.00%       45.36%       47.89%       36.77%       46.06%  
Rate base included in 2014 return on equity (2)
  $ 1,561     $ 2,315     $ 590     $ 519     $ 182     $ 104  
Weather normalization (3)
                 
ü
   
ü
           
ü
 
Decoupled or straight-fixed-variable rates (4)
         
ü
   
ü
                   
ü
 
Regulatory infrastructure program rates (5)
 
ü
   
ü
   
ü
   
ü
                 
Bad debt rider (6)
 
ü
           
ü
                   
ü
 
Synergy sharing policy (7)
         
ü
                                 
Energy efficiency plan (8)
 
ü
           
ü
   
ü
   
ü
   
ü
 
Last decision on change in rates
    2009       2010       2011       2009       N/A       2010  
(1)  
The authorized return on rate base, return on equity and percentage of equity were those authorized as of December 31, 2014.
(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.
(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.
(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 purchased gas adjustment (PGA) mechanisms.
(7)  
Involves the recovery of 50% of net synergy savings achieved on mergers and acquisitions.
(8)  
Includes the recovery of costs associated with plans to achieve specified energy savings goals.
 (9
In connection with the December 2011 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.
 
Current Regulatory Proceedings

Nicor Gas In June 2013, in connection with the PBR plan, the Illinois Commission issued an order requiring us to refund $72 million to current Nicor Gas customers through our PGA mechanism based upon natural gas throughput over 12 months beginning in July 2013. Approximately $43 million was refunded during 2014 and $29 million was refunded during 2013. For more information on the PBR plan, see Note 11 to our consolidated financial statements under Item 8 herein.

In August 2014, staff of the Illinois Commission and the Citizens Utility Board (CUB) filed testimony in the 2003 gas cost prudence review disputing certain gas loan transactions offered by Nicor Gas under its Chicago Hub services, requesting refunds of $18 million and $22 million, respectively. We filed surrebuttal testimony in December 2014 disputing that any refund is due, as Nicor Gas was authorized to enter into these transactions and revenues associated with such reduced rate payer costs as either credits to the PGA or reductions to base rates were consistent with then-current Illinois Commission orders governing these activities. We believe these claims engage in hindsight speculation, which is expressly prohibited in a prudence review examination, and we intend to vigorously defend against these claims. Evidentiary hearings are scheduled for March 2015. Similar gas loan transactions were provided in other open review years. The resolution will ultimately be decided by the Illinois Commission. We are currently unable to predict the ultimate outcome and have recorded no liability for this matter.

Nicor Gas’ first three-year energy efficiency program, which outlines energy efficiency program offerings and therm reduction goals for a three-year period, ended in May 2014Nicor Gas spent $125 million on the program and reduced customer usage by an estimated 46 million therms. Additionally, in May 2014, the Illinois Commission approved Nicor Gas’ second energy efficiency program, Energy Smart Plan, with expected spending of $93 million over a three-year period that began in June 2014. Nicor Gas spent $14 million on this new program in 2014.

 
 
Atlanta Gas Light In December 2012, Atlanta Gas Light filed a petition with the Georgia Commission for approval to resolve a volumetric imbalance of natural gas related to Atlanta Gas Light’s use of retained storage assets to operationally balance the system for the benefit of the natural gas market. In September 2014, we filed a stipulation that was entered between us, staff of the Georgia Commission and several Marketers that included a resolution of the 4.6 Bcf imbalance over a five-year period from January 1, 2015 through December 31, 2019. The Georgia Commission approved the stipulation in December 2014. Over the five-year period, discretionary funds available to the Universal Service Fund, which is controlled by the Georgia Commission, will be used to resolve 25% of the imbalance, or approximately 1.15 Bcf of natural gas. Atlanta Gas Light is obligated to resolve 25% and we have recorded a reserve in our Consolidated Statements of Financial Position representing the future estimated cost to purchase the approximately 1.15 Bcf of natural gas. The cost to resolve the remaining difference of approximately 2.3 Bcf of natural gas will be recovered from all certificated Marketers through charges for system retained storage gas as it is used by the certificated Marketers.

In accordance with an order issued by the Georgia Commission, where AGL Resources makes a business acquisition that reduces the costs allocated or charged to Atlanta Gas Light for shared services, the net savings to Atlanta Gas Light will be shared equally between the firm customers of Atlanta Gas Light and our shareholders for a ten-year period. In December 2013, we filed a Report of Synergy Savings with the Georgia Commission in connection with the Nicor acquisition. If and when approved, the net savings should result in annual rate reductions to the firm customers of Atlanta Gas Light of $5 million. We expect this filing to be discussed by the staff of the Georgia Commission in February 2015.

We expect Atlanta Gas Light to file a petition with the Georgia Commission for approval of a rate increase to our STRIDE surcharge associated with the final accounting of our pipeline replacement program (PRP) in February 2015. The proposed rate increase is designed to collect the unrecovered revenue requirement of the program and is in accordance with the requirements set forth by the Georgia Commission that allows Atlanta Gas Light to make a true-up filing at the end of the program to recover the actual costs of the program. The program ended December 31, 2013.

Virginia Natural Gas In April 2014, the Governor of Virginia signed into law legislation that enables the state's natural gas utilities, including Virginia Natural Gas, to acquire long-term supplies of natural gas and make capital investments to facilitate the delivery of low-cost shale and coal-bed methane gas to Virginia homeowners and businesses. Under the terms of the new statute, Virginia Natural Gas could enter into commercial agreements to obtain up to 25% of its annual firm sales demand for natural gas through long-term contracts or investments such as purchases of reserves. Recovery on investments would be based upon the utility's authorized return on rate base, which would flow through the PGA mechanism or a similar mechanism. The new statute also allows us to build pipelines and other infrastructure that deliver shale and coal-bed methane gas into the state's markets that seek to reduce natural gas supply costs or reduce price volatility for consumers. All filings under this legislation require approval by the Virginia Commission, and we have not made any filings to date.

Supply Six of our utilities use asset management agreements with our wholly owned subsidiary, Sequent, for the primary purpose 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 for a reduction to gas cost recovery rates. Under these asset management agreements, Sequent supplies natural gas to the utility and markets available pipeline and storage capacity to improve the overall cost of supplying gas to the utility customers. Currently, the utilities primarily purchase their gas from Sequent. The purchase agreements require Sequent to provide firm gas to our utilities. However, these utilities maintain the right and ability to make their own gas 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. Nicor Gas has not entered into an asset management agreement with Sequent or any other parties.

Each agreement with Sequent has either an annual minimum guarantee within a profit sharing structure, a profit sharing structure without any annual minimum guarantee, or a fixed fee. From the inception of these agreements in 2001 through 2014, Sequent has made sharing payments under these agreements totaling $272 million. The following table provides payments made by Sequent to our utilities under these agreements during the last three years.

   
Total amount received
       
In millions
 
2014
   
2013
   
2012
   
Expiration Date
 
Elizabethtown Gas
  $ 18     $ 6     $ 5    
March 2019
 
Virginia Natural Gas
    14       4       3    
March 2016
 
Atlanta Gas Light
    13       6       5    
March 2017
 
Florida City Gas
    1       1       1     (1)  
Chattanooga Gas
    1       1       1    
March 2018
 
Total
  $ 47     $ 18     $ 15          
(1)  
The term of the agreement is evergreen and renews automatically each year unless terminated by either party.

 
 
Transportation Our utilities use firm pipeline entitlements, storage services and/or peaking capacity contracted with interstate capacity providers to serve the firm natural 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 heatingIncluding seasonal storage and peaking services in this portfolio is more efficient and cost effective than reserving firm pipeline capacity rights all year for a limited number of cold winter days.

Our firm contracts range in duration from 3 to 25 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 suppliesDuring 2014, we announced our participation in three pipeline projects that will provide access to shale gas in the proximity of our service territories. We have entered into longer-term contracts in connection with these pipeline projects, which resulted in an increase in the duration of our firm contracts compared to prior years. 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.

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. Total capital expenditures incurred during 2014 for our distribution operations segment were $715 million. The following table and discussions provide updates on some of our larger capital projects under various programs at our distribution operations segment. These programs update or expand our distribution systems to improve system reliability and meet operational flexibility and growth. Our anticipated expenditures for these programs in 2015 are discussed in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the caption “Liquidity and Capital Resources.”
 
 
Program
 
Program details
 
Recovery
 
Expenditures in 2014
(in millions)
   
Expenditures since project inception
(in millions)
   
Miles of pipe
installed since
project inception
   
Scope of
program
(total miles)
   
Program duration (years)
   
Last
year of program
 
Atlanta Gas Light
Integrated Vintage Plastic Replacement Program (i-VPR)
    (1)  
Rider
  $ 62     $ 67       194       756       4       2017  
Atlanta Gas Light
Integrated System Reinforcement Program (i-SRP)
    (2)  
Rider
    13       264       n/a       n/a       8       2017  
Atlanta Gas Light
Integrated Customer Growth Program (i-CGP)
    (3)  
Rider
    7       47       n/a       n/a       8       2017  
Chattanooga Gas
Bare Steel & Cast Iron
    (4)  
Rate Based
    17       32       71       111       10       2020  
Elizabethtown Gas
Aging Infrastructure Replacement (AIR)
    (4)  
Rider / Rate Based
    32       38       40       130       4       2017  
Elizabethtown Gas
Elizabethtown Natural Gas Distribution Utility Reinforcement Effort (ENDURE)
    (5)  
Rate Based
    2       2       4       13       1       2015  
Florida City Gas
Galvanized Replacement Program
    (6)  
Rate Based
    1       14       75       111       17       2017  
Nicor Gas
Investing in Illinois (Qualified Infrastructure)
    (7)(8)  
Rider
    22       22       13       800       9       2023  
Virginia Natural Gas
Steps to Advance Virginia’s Energy (SAVE)
    (7)  
Rider
    24       64       127       250       5       2017  
Total
 
            $ 180     $ 550       524       2,171                  
(1)  
Early vintage plastic, risk based mid vintage plastic, mid vintage neighborhood convenience.
(2)  
Large diameter pressure improvement and system reinforcement projects.
(3)  
New business construction and strategic line extension.
(4)  
Cast iron and bare steel.
(5)  
Cast iron and distribution reinforcement.
(6)  
Galvanized and X-Tube steel. Expenditures and miles reported are post AGL Resources acquisition.
(7)  
Cast iron, bare steel, mid vintage plastic and risk based materials.
(8)  
Represents expenditures on qualifying infrastructure that will be placed into service after the rate freeze date, December 9, 2014.

 
 
Atlanta Gas Light Our STRIDE program is comprised of i-SRP, i-CGP and i-VPR. STRIDE includes a surcharge on firm customers that provides recovery of the revenue requirement for the ongoing programs and the PRP, which ended on December 31, 2013. These infrastructure development, enhancement and replacement programs are used to update and expand distribution systems and liquefied natural gas facilities, improve system reliability and meet operational flexibility and growth. The purpose of the i-SRP is to upgrade our distribution system and liquefied natural gas facilities in Georgia, improve our peak-day system reliability and operational flexibility, and create a platform to meet long-term forecasted growth. Under I-SRP, we must 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. Our i-CGP authorizes Atlanta Gas Light to extend its pipeline facilities to serve customers in areas without pipeline access and create new economic development opportunities in Georgia.

A new $260 million, four-year STRIDE program was approved in December 2013, of which $214 million is for i-SRP related projects and $46 million is for i-CGP related projects. The program will be funded through a monthly rider surcharge per customer of $0.48 beginning in January 2015, which will increase to $0.96 beginning in January 2016 and to $1.43 beginning in January 2017. This surcharge will continue through 2025.

The purpose of the i-VPR program is to replace aging plastic pipe that was installed primarily in the mid-1960’s to the early 1980’s. We have identified approximately 3,300 miles of vintage plastic mains in our system that potentially should be considered for replacement over the next 15 - 20 years as it reaches the end of its useful life. In 2013, the Georgia Commission approved i-VPR, which includes the replacement of the first 756 miles of vintage plastic pipe over four years for $275 million. The program is being funded through an increase in the STRIDE monthly rider surcharge per customer of $0.48 through December 2014, which increases to $0.96 beginning in January 2015 and to $1.45 beginning in January 2016. This surcharge will continue through 2025. If the Georgia Commission elects to extend the i-VPR program beyond 2017, the remaining vintage plastic mains in our system could be considered for replacement through the program over the next 15 - 20 years as it reaches the end of its useful life. In December 2014, the Georgia Commission approved a stipulation between Atlanta Gas Light and the staff of the Georgia Commission that allows for the recovery or refund of certain operation and maintenance expenses associated with the i-VPR program that are above or below an established baseline amount of $7 million.

Nicor Gas In July 2013, Illinois enacted legislation that allows Nicor Gas to provide more widespread safety and reliability enhancements to its system. The legislation stipulates that rate increases to customer bills as a result of any infrastructure investments shall not exceed an annual average 4.0% of base rate revenues. In July 2014, the Illinois Commission approved our new regulatory infrastructure program, Investing in Illinois (previously known as Qualified Infrastructure Plant), for which we may implement rates under the program effective in March 2015. Our filing included a project scope with cost estimates for three years of $171 million in 2015, $173 million in 2016 and $171 million in 2017. Our current project scope includes cost estimates that are approximately $200 million in 2015 and $250 million in each of 2016 and 2017. These expenditure levels represent approximately 1.3%, 3.5% and 4.0% of annual average base rate revenues for 2015, 2016 and 2017, respectively, which are all within the program requirements.

Elizabethtown Gas Our extension of the enhanced infrastructure program in 2013 allowed for infrastructure investment of $115 million over four years, effective as of September 2013, and is focused on the replacement of aging cast iron of our pipeline system. Carrying charges on the additional capital spend are being accrued and deferred for regulatory purposes at a weighted average cost of capital (WACC) of 6.65%. We agreed to file a general rate case by September 2016. Prior accelerated infrastructure investments under this program will be recovered through a permanent adjustment to base rates.

In July 2014, the New Jersey BPU approved ENDURE, a program that will improve our distribution system’s resiliency against coastal storms and floods. Under the proposed plan, Elizabethtown Gas will invest $15 million in infrastructure and related facilities and communication planning over a one year period from August 2014 through September 2015. The plan allows Elizabethtown Gas to increase its base rates effective November 1, 2015 for investments made under the program.

Virginia Natural Gas The SAVE program, which was approved in August 2012, 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 for costs associated with certain infrastructure replacement programs. This five-year program 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 in August 2012. The second year performance rate update was approved by the Virginia Commission in July 2014 and became effective as of August 2014.

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 our current and former operating sites. As we continue to conduct the MGP remediation and enter into cleanup contracts, we are increasingly able to provide conventional engineering estimates of the likely costs of many elements of the remediation program. These estimates contain various engineering assumptions, which we refine and update on an ongoing basis. 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” and Note 3 to our consolidated financial statements under Item 8 herein for additional information about our environmental remediation liabilities and efforts.

 
 

Our retail operations segment serves approximately 628,000 natural gas commodity customers and 1.2 million service contracts. Companies within our retail operations segment include SouthStar and Pivotal Home Solutions.

SouthStar is one of the largest retail natural gas marketers in the United States and markets natural gas to residential, commercial and industrial customers, primarily in Georgia and Illinois, where we capture spreads between wholesale and retail natural gas prices. Additionally, 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. Through our commercial operations, we optimize storage and transportation assets and effectively manage commodity risk, which enables us to maintain competitive retail prices and operating margin.

SouthStar is a joint venture owned 85% by us and 15% by Piedmont and is governed by an executive committee with equal representation by both owners. After considering the relevant factors, we consolidate SouthStar in our financial statements. See Note 10 to our consolidated financial statements under Item 8 herein for more information.

Pivotal Home Solutions provides a suite of home protection products and services that offer homeowners additional financial stability regarding their energy service delivery, systems and appliances. We offer a proprietary line of customizable home warranty and energy efficiency plans that can be co-branded with utility and energy companies. We have a portable product suite, which can be offered in most geographies and markets. Pivotal Home Solutions serves customers in several states, primarily Illinois, Indiana and Ohio. Additionally, we are working to expand product offerings to customers in our affiliate companies to enhance the customer experience and retention, as well as promote switching to natural gas from other energy products, such as electricity, propane or fuel oil.

Competition and Operations Our retail operations business competes with other energy marketers to provide natural gas and related services to customers in the areas in which they operate. In the Georgia market, SouthStar operates as Georgia Natural Gas and is the largest of 12 Marketers in the state, with average customers of nearly 500,000 over the last three years and market share of approximately 31% during 2014.

In recent years, increased competition and the heavy promotion of fixed-price plans by SouthStar’s competitors have 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. However, SouthStar has utilized new products and marketing partnerships to stabilize its portfolio mix in Georgia and has entered new retail markets to position the company for future growth.

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.

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.”

Our retail operations business also experiences price, convenience and service competition from other warranty and HVAC companies. These businesses also bear risk from potential changes in the regulatory environment.


Our wholesale services segment consists of our wholly owned subsidiary, Sequent, which engages in asset management and optimization, storage, transportation, producer and peaking services and wholesale marketing of natural gas across the U.S. and Canada. 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 to provide these services to its customers. Its customers consist 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. We also leverage our portfolio of natural gas storage assets and contracted natural gas supply, transportation and storage capacity to meet our delivery requirements and customer obligations at competitive prices.

 
 
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. These asset optimization opportunities focus on capturing the value from idle or underutilized assets, typically by participating in transactions that 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.

In May 2013, we sold Compass Energy, a non-regulated retail natural gas business supplying commercial and industrial customers. Under the terms of the purchase and sale agreement, we received an initial cash payment of $12 million, resulting in a pre-tax gain of $11 million ($5 million net of tax) and were eligible to receive contingent cash consideration up to $8 million with a guaranteed minimum receipt of $3 million that was recognized during 2013. In the third quarter of 2014, we negotiated with the buyer to settle the future earn-out payments and we received a cash payment of $4 million, resulting in the recognition of a $3 million gain. We have a five-year agreement through April 2018 to supply natural gas to our former customers.

Competition and operations 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 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 and natural gas producers located in the areas of the country in which we operate. We are also focused on building our fee-based services as a source of operating margin that is less impacted by volatility in the marketplace.

We view our wholesale margins from two perspectives. First, we base our commercial decisions on economic value for both our natural gas storage and transportation transactions. For our natural gas storage transactions, economic value is determined based on the net 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 the physical storage is settled. Similarly, for our natural gas transportation transactions, economic value is determined based on the net operating revenue to be realized at the time the physical gas is purchased, transported, and sold utilizing our transportation capacity along with the settlement value associated with any derivative instruments.

The second perspective is the values reported in accordance with GAAP and encompassing periods prior to and in the period of physical withdrawal and sale of inventory or purchase, transportation and sale of natural gas. We enter into derivatives to hedge price risk prior to when the related physical storage withdrawal or transportation transactions occur based upon our commercial evaluation of future market prices. The reported GAAP amount is affected by the process of accounting for the financial hedging instruments in interim periods at fair value and prior to the period the related physical storage and transportation transactions occur and are recognized in earnings. The change in fair value of the hedging instruments is recognized in earnings in the period of change and is recorded as unrealized gains or losses. This results in reported earnings volatility during the interim periods; however, the expected margin based upon the hedged economic value is ultimately realized in the period natural gas is physically withdrawn from storage or transported and sold at market prices and the related hedging instruments are settled.

For our natural gas storage portfolio, 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 protect the operating revenue that we will ultimately realize when the stored gas is actually sold.

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 natural 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.


Our midstream operations segment includes a number of businesses that are related and complementary to our primary business. The most significant of these businesses is our natural gas storage business, which develops, acquires and operates high-deliverability underground natural gas storage assets in the Gulf Coast region of the U.S. and in northern California. While this business can generate additional revenue during times of peak market demand for natural gas storage services, our natural gas storage facilities have a portfolio of short, medium and long-term contracts at fixed market rates. In addition to natural gas storage, this segment also includes our developing LNG business, which focuses on LNG for transportation, and select pipeline investments that are outside of state regulatory jurisdiction.

 
 
Pipelines During 2014, we entered into three pipeline agreements, as indicated in the following table, which are subject to regulatory approvals. These projects, along with our existing pipelines discussed below, will support our efforts to provide diverse sources of natural gas supplies to our customers, resolve current and long-term supply planning for new capacity, enhance system reliability and generate economic development in the areas served. The pipeline development projects will be financed through a combination of commercial paper and long-term debt issuances. See Note 10 to the consolidated financial statements under Item 8 herein for additional information.
 
   
 
   
Expected capital
   
Ownership
   
Scheduled year
   
Expected FERC filing process
 
Dollars in millions
 
Miles of pipe
   
expenditures (1)
   
interest (1)
   
of completion
   
File date
   
Approval date
 
Dalton Pipeline (2)
    106     $ 210       50 %     2017       2015       2016  
PennEast Pipeline (3)
    108       200       20 %     2017       2015       2016  
Atlantic Coast Pipeline (4)
    550       260       5 %     2018       2015       2016  
Total
    764     $ 670                                  
(1)  
Represents our expected capital expenditures and ownership interest, which may change.
(2)  
In April 2014, we entered into two agreements associated with the construction of the Dalton Lateral Pipeline, which will serve as an extension of the Transco pipeline system and provide additional natural gas supply to our customers in Georgia. The first is a construction and ownership agreement and the second is an agreement to lease our ownership in this lateral pipeline extension once it is placed in service.
(3)  
In August 2014, we entered into a joint venture to construct and operate a natural gas pipeline that will transport low-cost natural gas from the Marcellus Shale area to our customers in New Jersey. We believe this will alleviate takeaway constraints in the Marcellus region and help mitigate some of the price volatility experienced during the past winter.
(4)  
In September 2014, we entered into a joint venture to construct and operate a natural gas pipeline that will run from West Virginia through Virginia and into eastern North Carolina to meet the region’s growing demand for natural gas. The proposed pipeline project is expected to transport natural gas to our customers in Virginia.

Magnolia Enterprise Holdings, Inc. This wholly owned subsidiary operates a pipeline that provides our Georgia customers 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 May 2025.

Competition and operations Our natural gas storage facilities primarily compete with natural gas facilities in the Gulf Coast region of the U.S., 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.

The market fundamentals of the natural gas storage business are cyclical. The abundant supply of natural gas in recent years and the resulting lack of market and price volatility have negatively impacted the profitability of our storage facilities. In 2014, expiring storage capacity contracts were re-subscribed at lower prices and we anticipate these lower natural gas prices to continue in 2015 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 continues to improve, expected exports of LNG occur and/or natural gas demand increases in response to low prices and expanded uses for natural gas. We believe our storage assets are strategically located to benefit from these expected improvements in market fundamentals, including the overall growth in the natural gas market, and there are significant barriers to developing new storage facilities, including construction time and other costs, federal, state and local permitting and approvals and suitable and available sites, to capitalize on these expected improvements in market conditions.


Our “other” non-reportable segment includes aggregated subsidiaries that individually are not significant on a stand-alone basis and that do not fit into one of our reportable segments. This segment includes our investment in Triton, which was not part of the sale of Tropical Shipping that closed on September 1, 2014. See Note 14 to the consolidated financial statements under Item 8 herein for additional information on the disposition of Tropical Shipping. AGL Services Company is a service company we established to provide certain centralized shared services to our reportable segments. We allocate substantially all of AGL Services Company’s operating expenses and interest costs to our reportable segments in accordance with state regulations. Our EBIT results include the impact of these allocations to the various reportable segments.

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

 
 
Employees

As of December 31, 2014, we had approximately 5,165 employees, all of whom were in the U.S. The decrease in total employees from 2013 primarily resulted from the sale of our Tropical Shipping business in 2014.

The following table provides information about our natural gas utilities’ collective bargaining agreements, which represent approximately 33% of our total employees.

   
Number of employees
 
Contract expiration date
Nicor Gas
    International Brotherhood of Electrical Workers (Local No. 19) (1)
    1,386  
February 2017
Virginia Natural Gas
International Brotherhood of Electrical Workers (Local No. 50) (2)
    139  
May 2015
Elizabethtown Gas
Utility Workers Union of America (Local No. 424)
    171  
November 2015
 Total
    1,696    
(1) Nicor Gas’ collective bargaining agreement expired in February 2014, and a new agreement was ratified in April 2014. The new agreement provides for additional operational enhancements and changes to certain benefits, but does not have a material effect on our consolidated financial statements.
(2) Contract negotiations are ongoing; however, we do not expect a new contract to be finalized prior to the expiration of the current contract. We have a continuation agreement in place and do not expect this to result in a work stoppage.

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 done historically, 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 2015 annual meeting of shareholders. We expect to file that Proxy Statement with the SEC on or about March 17, 2015, and we will make it available on our website as soon as reasonably practicable thereafter. 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.

 
Forward-Looking Statements

This report and the documents incorporated by reference herein contain “forward-looking statements.” These statements, which may relate to such matters as future earnings, growth, liquidity, supply and demand, costs, subsidiary performance, credit ratings, dividend payments, new technologies and strategic initiatives, 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 forward-looking statements. While we believe that our expectations are reasonable in view of the information that we currently have, these expectations are subject to future events, risks and uncertainties, and there are numerous factors—many beyond our control—that could cause actual results to vary materially from these 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 matters; actions taken by government agencies on rates and other matters; concentration of credit risk; utility and energy industry consolidation; the impact on cost and timeliness of construction projects by government and other approvals, development project delays, adequacy of supply of diversified vendors, and unexpected changes in project costs, including the cost of funds to finance these projects and our ability to recover our project costs from our customers; limits on pipeline capacity; the impact of acquisitions and divestitures, including recent acquisitions in our retail operations segment; our ability to successfully integrate operations that we have or may acquire or develop in the future; direct or indirect effects on our business, financial condition or liquidity resulting from a change in our credit ratings or 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 the new depreciation rates for Nicor Gas; the impact of changes in weather, including climate change, on the temperature-sensitive portions of our business; the impact of natural disasters, such as hurricanes, on the supply and price of natural gas; acts of war or terrorism; the outcome of litigation; and the factors described in this Item 1A, “Risk Factors” and the other factors discussed in our filings with the SEC.

There also may be other factors that we do not anticipate or that we do not recognize are material that could cause results to differ materially from expectations. Forward-looking statements speak only as of the date they are made. We expressly disclaim any obligation to update or revise any forward-looking statement, whether as a result of future events, new information or otherwise, except as required by law.

 
 
Risks Related to Our Business

Our business is subject to substantial regulation by federal, state and local regulatory authorities. Adverse determinations by them and, in some instances, the absence of timely determinations, could adversely affect our business.

At the federal level, our business is regulated by the FERC. At the state level, our business is regulated by public service commissions or similar authorities, as well as local governing bodies with respect to certain issues.

Depending upon the jurisdiction, these regulatory authorities are generally entitled to review and approve many aspects of our operations, including the rates that we charge customers (including the recovery of costs for pipeline replacement and other capital projects), the rates of return on our equity investments in our operating companies, how we operate our business, and the interaction between our regulated operating companies and other subsidiaries that might provide products or services to those companies. In addition, our operating companies are generally subject to franchise agreements that entitle them to provide products and services.

While applicable law often provides a framework for the approvals that we need, the regulatory authorities generally have broad discretion. Moreover, in some jurisdictions, the regulatory process involves elected officials and is subject to inherent political issues, which can impact the approvals that we request. As a result, we may or may not be able to obtain the approvals that we request, the timing of obtaining those approvals can be uncertain, and the approvals can be subject to conditions that may or may not be favorable to our business. Should we not be able to obtain the rate increases that we request in a timely manner, should we not be able to fully recover the costs that we incur, or should we otherwise not obtain favorable approvals for the operation of our business, our business will be adversely impacted. 

In addition, the regulatory environment in which we operate has increased in complexity over time, and further change is likely in many jurisdictions. These changes may or may not be favorable to our business. As the regulatory environment grows in complexity, inadvertent noncompliance is increasingly a greater risk. Noncompliance can, depending upon the circumstances, result in fines, penalties or other enforcement action by regulatory authorities, as well as damage our reputation and standing in the community, all of which would adversely impact our business.

Energy prices can fluctuate widely and quickly. To the extent that we have not anticipated and planned for those changes, our business can be adversely affected.

Recently, the price for natural gas and competing energy sources, such as oil, have fluctuated widely. Generally, we pass through changes in prices to the customers of our operating companies, and we have a process in place to continually review the adequacy of our utility gas rates and to take appropriate action with the applicable regulatory authorities. However, there is an inherent regulatory lag in adjusting rates and, in an increasing price environment, we have to bear the increased costs on an interim basis. We also have to incur additional financing costs as a result of purchasing more expensive gas.

In addition, increases in gas prices, both in absolute terms and relative to alternative energy sources, negatively impacts demand, the ability of customers to pay their utility bills and the timing of those payments (which lead to larger accounts receivable and greater bad debt expense) and various other factors. While the impact of some of these factors can be passed through to customers, there is generally a delay in that process that can adversely affect our business.

As noted below, for some portions of our business, we hedge the risk of price changes through the purchase of futures contracts and other means. These efforts, while designed to minimize the adverse impact of price changes, cannot assure that result. As a result, we retain exposure to price changes that can, in a volatile energy market, be extremely material and can adversely affect our business.

 
 
Variations in weather beyond what we have planned for can adversely impact our business.

A substantial portion of our revenue is derived from the transportation or sale of gas for space heating purposes. We plan for the demand of gas for this purpose based upon historical weather patterns and resulting demand. Where weather varies significantly beyond the range that we have planned for, it can impact us in many ways, including through increasing or decreasing the demand for gas, the cost of gas to us, and the availability, sufficiency and cost of transportation and storage capacity.

A decrease in the availability of adequate pipeline transportation capacity due to weather conditions or otherwise could adversely impact our business. We depend upon having access to adequate transportation and storage capacity for virtually all of our operations. A decrease in interstate pipeline capacity available to us, or an increase in competition for interstate pipeline transportation and storage capacity (e.g., even as a result of weather in regions that we do not significantly serve) could reduce our normal interstate supply of gas or cause rates to fluctuate.

We have WNA mechanisms for Virginia Natural Gas, Elizabethtown Gas and Chattanooga Gas that partially offset the impact of unusually cold or warm weather on residential and commercial customer billings and on our operating margin, although 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. Outside of those ranges, our financial exposure is greater.

We also have decoupled rate designs, including straight-fixed-variable, at Atlanta Gas Light, Virginia Natural Gas and Chattanooga Gas that allow for the recovery of fixed customer service costs separately from assumed natural gas volumes used by our customers. For more information, see Item 1, “Business” under the caption “Rate Structures” herein.

At Nicor Gas, approximately 60% 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 operating income and cash flow. For example, we estimate that a 100 degree-day variation from normal weather of 5,752 Heating Degree Days impacts Nicor Gas’ margin, net of income taxes, by approximately $1 million under its current rate structure. For our weather risk associated with Nicor Gas, we utilize weather derivatives to reduce, but not eliminate, the risk of lower operating margins potentially resulting from significantly warmer-than-normal weather in Illinois. For more information, see Note 2 to the consolidated financial statements under Item 8 herein.

Changes in weather conditions may also impact SouthStar’s earnings. As a result, SouthStar uses a variety of weather derivative instruments to mitigate the impact on its operating margin in the event of warmer or colder-than-normal weather in the winter months. However, these instruments do not fully mitigate the effects of unusually warm or cold weather.

Similarly, changes in weather conditions may also impact wholesale services’ earnings. In addition to the impacts described above, weather impacts the ability of our wholesale services segment to capture value from location and seasonal spreads. Through the acquisition of natural gas and hedging of natural gas prices, wholesale services reduces some of the weather-related risks that it faces, but it cannot eliminate all of those risks.

Our retail energy businesses in Illinois, Nicor Solutions and Nicor Advanced Energy, offer utility-bill management products that mitigate and/or eliminate the risks of variations in weather to customers. We hedge this risk to reduce any adverse effects to us from weather variations.

We are subject to environmental regulation and our costs to comply are significant. Any changes in existing environmental regulation could adversely affect our business.

We are subject to extensive environmental regulation pursuant to a variety of federal, state and municipal laws and regulations. Such environmental regulation 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. Failure to comply with these laws and regulations and failure to obtain any required permits and licenses may expose us to material fines, penalties or interruptions in our operations.

We are generally responsible for 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. A number of environmental issues may exist with respect to MGP’s. For more information regarding these obligations, see Note 11 to the consolidated financial statements under Item 8 herein. Claims against us under environmental laws and regulations could result in material costs and liabilities.

Existing environmental laws and regulations could also 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 that could have a material adverse effect on our business.

 
 
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 may also need to construct expansions of our existing natural gas storage facilities or develop and construct new natural gas storage facilities. The cost of such construction may be affected by the cost of obtaining government and other approvals, project delays, adequacy of supply of vendors, vendor performance, 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, 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 may be exposed to regulatory and financial risks related to the impact of 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 climate change to increased levels of greenhouse gases, including carbon dioxide and methane, which has led to significant legislative and regulatory efforts to limit greenhouse gas emissions.

The EPA has begun using provisions of the Clean Air Act to regulate greenhouse gas emissions, including carbon dioxide and methane, differently than under historical precedent. Thus far, EPA has imposed greenhouse gas regulations on automobiles and implemented new permitting requirements for the construction or modification of major stationary sources of greenhouse gas emissions, including natural gas-fired power plants.

In addition, President Obama issued a Presidential Memorandum on June 25, 2013, directing the EPA to adopt performance standards to regulate greenhouse gas emissions from power plants. Specifically, the Presidential Memorandum directs the EPA to propose standards for future power plants by September 20, 2013 and propose regulations and emission guidelines for modified, reconstructed, and existing power plants by June 1, 2014. The Presidential Memorandum directs the EPA to finalize those regulations by June 1, 2015. States would be required to develop regulations implementing the EPA’s guidelines by June 30, 2016. It also includes a wide variety of other initiatives designed to reduce greenhouse gas emissions, prepare for the impacts of climate change, and lead international efforts to address climate change.

The outcome of 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 and affect the competitive position of natural gas.
 
Because natural gas is a fossil fuel with low carbon content relative to other traditional fuels, future carbon constraints may 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. However, methane, the primary constituent of natural gas, is a potent greenhouse gas. Future regulation of methane could likewise result in increased costs to us and affect the demand for natural gas, as well as the prices we charge our customers and the competitive position of natural gas.

Any adoption of regulation 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 business.

 
 
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 explosions, and mechanical problems, which 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 operations segment 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 operations segment also faces risks in the form of price, convenience and service competition from other warranty and HVAC companies.

Our wholesale services segment competes for sales with national and regional full-service energy providers, energy merchants and producers, and pipelines 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 U.S., 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 several years due to low gas prices and low volatility, and we expect this to continue in 2015.

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 counterparties. Despite performing credit analyses prior to extending credit and seeking to implement netting agreements, if the counterparties fail to perform and any collateral Nicor Gas or Sequent has secured is inadequate, we could experience material financial losses.

Further, Sequent has a concentration of credit risk with a limited number of parties. 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 could be significant.

We have accounts receivable collection risks in Georgia due to a concentration of credit risks related to the provision of natural gas services to approximately 12 Marketers. As a result, Atlanta Gas Light depends on a limited number of customers for a significant portion of its revenues.

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. For more information, see Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” under the caption “Credit Risk” herein.

The asset management arrangements between Sequent and our LDC’s, 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 Commission’s 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, 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. Sustained low natural gas prices could reduce the demand for these types of asset management arrangements.

 
 
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. For more information, see Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” under the caption “VaR” herein.

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.

The cost of providing retirement plan benefits to eligible current and former employees is subject to changes in the performance of investments, demographics, and various other factors and assumptions. These changes may have a material adverse effect on us.

The cost of providing retirement plan 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 will have an adverse effect on the value of our pension plan assets. 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 future periods in order to preserve the current level of benefits under the plans and in accordance with federal funding requirements.

For more information, 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 Welfare Obligations” and Note 6 to the consolidated financial statements under Item 8 herein.

Natural disasters, terrorist activities and similarly unpredictable events could adversely affect our businesses.

Natural disasters may damage our assets, interrupt our business operations and adversely impact the demand for natural gas. Future acts of terrorism could be directed against companies operating in the U.S., and companies in the energy industry may face a heightened risk of exposure. The insurance industry has been disrupted by these types of events. As a result, the availability of insurance covering risks against which we and similar businesses typically insure may be limited or insufficient. In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms. In addition, an employee or third party may purposely, or inadvertently, fail to adhere to our policies and procedures or our policies and procedures may not be effective; this could result in the violation of a law or regulation, a material error or misstatement, damage to our reputation or the incurrence of substantial expense.

Work stoppages could adversely impact our businesses.

Some of our businesses are dependent upon employees who are represented by unions and are covered by collective bargaining agreements. These agreements may increase our costs, affect our ability to continue offering market-based salaries and benefits, and limit our ability to implement efficiency-related improvements. Disputes with the unions could result in work stoppages that could impact the delivery of natural gas and other services, which could strain relationships with customers, vendors and regulators. We believe that we have a good working relationship with our unionized employees and 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. For more information, see Item 1, “Business” under the caption “Employees” herein.

Changes in 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, restrict or prohibit certain activities, which could 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 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, could lead to system disruptions or generate facility shutdowns. If a cyber-attack or security breach were to occur, our business, results of operations and financial condition could be materially adversely affected. In addition, a cyber-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 could expose us to liability to our customers, vendors, financial institutions and othersIn addition, 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, although, to our knowledge, we did not have any material security breaches in 2014.

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

We have pursued acquisitions to complement or expand our business, divestures and other strategic transactions in the past and expect to in the future. 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. Acquisitions may result in dilutive issuances of equity securities and the incurrence of debt and contingent liabilities, amortization expenses and substantial goodwill. Acquisitions 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. Any failure to successfully integrate businesses that we acquire in an efficient and effective manner could have a material adverse effect on us. Similarly, we may divest portions of our business, which may also have material and adverse effects.

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 finite-lived 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 2014 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 2014.

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 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, WACC and market multiples. For additional information, see Item 7,”Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the caption “Critical Accounting Policies and Estimates” herein.
 19

Risks Related to Our Corporate and Financial Structure

We depend on access to the capital and financial markets to fund our business. 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 sources 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.

A downgrade in our credit rating would require us to pay higher interest rates and 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 would be required to provide additional collateral to continue conducting business with certain customers. For additional credit rating and interest rate information, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the caption “Liquidity and Capital Resources” and Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” under the caption “Interest Rate Risk” herein.

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” herein. However, we may not structure these swap agreements in a manner that manages 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” herein for additional information.

The use of derivative contracts in the normal course of our business could result in financial losses that negatively impact our results of operations.

We use derivative instruments, including futures, options, 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 into 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 values of these contracts.

 
 
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.

Our credit facilities 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.
 

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.


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 customers in our service areas. These systems consist primarily of distribution and transmission mains, compressor stations, peak shaving/storage plants, service lines, meters and regulators. At December 31, 2014, our distribution operations segment owned approximately 80,700 miles of underground distribution and transmission mains, which are located on easements or rights-of-way that generally provide for perpetual use. We maintain our mains through a program of continuous inspection and repair, and believe that our distribution systems are in good condition.

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. This level of storage capability provides us with supply flexibility, improves the reliability of deliveries and can help mitigate the risk associated with seasonal price movements.

We have five LNG plants located in Georgia, New Jersey and Tennessee with LNG storage capacity of approximately 7.6 Bcf. In addition, we own one propane storage facility in Virginia with a storage capacity of approximately 0.3 Bcf. The LNG plants and propane storage facility 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 that are operated by our midstream operations segment. Jefferson Island operates a storage facility in Louisiana currently consisting of two salt dome gas storage caverns. Golden Triangle operates a storage facility in Texas consisting of two salt dome caverns. Central Valley operates a depleted field storage facility in California. In addition, we have an LNG facility in Alabama that produces LNG for Pivotal LNG, a wholly owned subsidiary, to support its business of selling LNG as a substitute fuel in various markets. For additional information on our storage facilities, see Item 1, “Business” under the caption “Midstream Operations” herein.

Offices

All of our reportable 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 our regulatory proceedings and litigation, see Note 11 to our consolidated financial statements under the caption “Litigation” under Item 8 herein.


Not applicable.
 
 
 
 
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 February 4, 2015, there were 21,551 record holders of our common stock. Quarterly information concerning our high and low stock prices and cash dividends paid in 2014 and 2013 is as follows:

   
Sales price of common stock
   
Cash dividend per
     
Sales price of common stock
   
Cash dividend per
 
Quarter ended:
 
High
   
Low
   
common share
 
Quarter ended:
 
High
   
Low
   
common share
 
March 31, 2014
  $ 49.84     $ 45.17     $ 0.49  
March 31, 2013
  $ 42.37     $ 38.86     $ 0.47  
June 30, 2014
    55.10       48.29       0.49  
June 30, 2013
    44.85       41.21       0.47  
September 30, 2014
    55.30       48.72       0.49  
September 30, 2013
    47.00       41.94       0.47  
December 31, 2014
    56.67       50.10       0.49  
December 31, 2013
    49.31       44.56       0.47  
                    $ 1.96                       $ 1.88  
   
We have paid 268 consecutive quarterly dividends to our common shareholders beginning in 1948, historically four times each year: March 1, June 1, September 1 and December 1. 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” herein. 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.
 
Issuer Purchases of Equity Securities

There were no purchases of our common stock by us or any affiliated purchasers during the three months ended December 31, 2014.
 
 
 

Selected financial data about AGL Resources for the last five years is set forth in the table below which should be read in conjunction with the consolidated financial statements and related notes set forth in Item 8, “Financial Statements and Supplementary Data” herein. Additionally, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” herein for a discussion of the primary factors impacting the changes in our results of operations for the periods reflected in our Consolidated Statements of Income. The operations of our former Tropical Shipping business, which was sold during 2014, are reflected as discontinued operations and all prior periods have been recast to reflect the discontinued operations. Material changes from 2013 to 2014 are due primarily to earnings from our wholesale services segment, resulting mainly from colder-than-normal weather and associated natural gas price volatility in 2014. Material changes from 2011 to 2012 are primarily due to the Nicor merger, which closed on December 9, 2011.

 
Dollars and shares in millions, except per share amounts
 
2014
   
2013
   
2012
   
2011
   
2010
 
Income statement data
                             
Operating revenues
  $ 5,385     $ 4,209     $ 3,562     $ 2,305     $ 2,373  
Operating expenses
                                       
Cost of goods sold
    2,765       2,110       1,583       1,085       1,164  
Operation and maintenance (1)
    939       887       816       497       497  
Depreciation and amortization
    380       397       394       182       160  
Nicor merger expenses (1)
    -       -       20       57       6  
Taxes other than income taxes
    208       187       159       57       46  
Total operating expenses
    4,292       3,581       2,972       1,878       1,873  
Gain on disposition of assets
    2       11       -       -       -  
Operating income
    1,095       639       590       427       500  
Other income (expense)
    14       16       24       7       (1 )
EBIT
    1,109       655       614       434       499  
Interest expense, net
    179       170       183       134       109  
Income before income taxes
    930       485       431       300       390  
Income tax expense
    350       177       157       121       140  
Income from continuing operations
    580       308       274       179       250  
(Loss) income from discontinued operations, net of tax
    (80 )     5       1       -       -  
Net income
    500       313       275       179       250  
Less net income attributable to the noncontrolling interest
    18       18       15       14       16  
Net income attributable to AGL Resources Inc.
  $ 482     $ 295     $ 260     $ 165     $ 234  
Amounts attributable to AGL Resources Inc.
                                       
Income from continuing operations attributable to AGL Resources Inc.
  $ 562     $ 290     $ 259     $ 165     $ 234  
(Loss) income from discontinued operations, net of tax
    (80 )     5       1       -       -  
Net income attributable to AGL Resources Inc.
  $ 482     $ 295     $ 260     $ 165     $ 234  
Per common share information
                                       
Diluted weighted average common shares outstanding
    119.2       118.3       117.5       80.9       77.8  
Diluted earnings (loss) per common share
                                       
Continuing operations
  $ 4.71     $ 2.45     $ 2.20     $ 2.04     $ 3.00  
Discontinued operations
    (0.67 )     0.04       0.01       -       -  
Diluted earnings per common share attributable to AGL Resources Inc. common shareholders
  $ 4.04     $ 2.49     $ 2.21     $ 2.04     $ 3.00  
Dividends declared per common share
  $ 1.96     $ 1.88     $ 1.74     $ 1.90     $ 1.76  
Dividend payout ratio
    49 %     76 %     79 %     93 %     58 %
Dividend yield (2)
    3.6 %     4.0 %     4.4 %     4.5 %     4.9 %
Price range:
                                       
High
  $ 56.67     $ 49.31     $ 42.88     $ 43.69     $ 40.08  
Low
  $ 45.17     $ 38.86     $ 36.59     $ 34.08     $ 34.21  
Close (3)
  $ 54.51     $ 47.23     $ 39.97     $ 42.26     $ 35.85  
Market value (3)
  $ 6,522     $ 5,615     $ 4,711     $ 4,946     $ 2,800  
Statements of Financial Position data (3)
                                       
Total assets (4)
  $ 14,909     $ 14,550     $ 14,070     $ 13,862     $ 7,481  
Property, plant and equipment – net
    9,090       8,643       8,205       7,741       4,396  
Long-term debt
    3,802       3,813       3,553       3,578       1,971  
Total equity
    3,828       3,613       3,391       3,305       1,809  
Financial ratios (3)
                                       
Debt
    57 %     58 %     59 %     60 %     60 %
Equity
    43 %     42 %     41 %     40 %     40 %
Total
    100 %     100 %     100 %     100 %     100 %
Return on average equity
    13.0 %     8.4 %     7.8 %     6.4 %     12.9 %
(1)  
Transaction expenses associated with the Nicor merger were excluded from operation and maintenance expenses and presented separately.
(2)  
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.
(3)  
As of the last day of the fiscal period.
(4)  
Amounts for all periods include assets held for sale, which reflect the assets of our former Tropical Shipping business.

 
 


We are an energy services holding company whose principal business is the distribution of natural gas in seven states – Illinois, Georgia, Virginia, New Jersey, Florida, Tennessee and Maryland – through our seven natural gas distribution utilities. We are also involved in several other businesses that are complementary to the distribution of natural gas. We have four reportable segments that consist of the following – distribution operations, retail operations, wholesale services and midstream operations – and one non-reportable segment – other. These segments are consistent with how management views and operates our business. Amounts shown in this Item 7, unless otherwise indicated, exclude assets held for sale and discontinued operations. See Note 14 to our consolidated financial statements under Item 8 herein for additional information. The following table provides certain information on our segments.

   
EBIT
   
Assets
   
Capital expenditures
 
   
2014 (1)
   
2013
   
2012
   
2014
   
2013
   
2012
   
2014
   
2013
   
2012
 
Distribution operations
    52 %     84 %     84 %     81 %     82 %     82 %     93 %     93 %     84 %
Retail operations
    12       20       18       5       5       4       1       1       1  
Wholesale services
    38       -       -       9       8       9       -       -       -  
Midstream operations
    (1 )     (2 )     2       5       5       5       2       2       8  
Other/intercompany eliminations
    (1 )     (2 )     (4 )     -       -       -       4       4       7  
Total
    100 %     100 %     100 %     100 %     100 %     100 %     100 %     100 %     100 %
 (1)  
The EBIT in 2014 was impacted by significantly higher-than-normal commercial activity realized in wholesale services, which is not indicative of future performance.

In the third quarter of 2014, we adjusted the accounting treatment for our previously reported non-cash revenue recognition associated with our regulatory infrastructure programs in our distribution operations segment. The adjustments did not affect previously reported operating cash flows, nor are they expected to affect capital expenditure plans or dividend payments. We do not expect these adjustments to impact the levels of return from our infrastructure replacement programs, as all amounts will be recovered in accordance with allowed recovery mechanisms. The adjustments relate only to the timing of recognition and do not impact rates charged to customers. Additionally, we adjusted the amortization of intangible assets for customer relationships and trade names in our retail operations segment to reflect the amortization expense on a basis consistent with the pattern of undiscounted cash flows used to determine their fair values. In November 2014, we amended our 2013 Form 10-K and our Forms 10-Q for the quarters ended March 31, 2014 and June 30, 2014 to revise our financial statements to reflect these adjustments. Our prior-period financial statements included herein reflect these adjustments.

In September 2014, we closed on the sale of Tropical Shipping and received after-tax cash proceeds of approximately $225 million, as well as repatriated $86 million in cash. The transaction resulted in expenses, including taxes, of approximately $80 million or $(0.67) per share in 2014. Tropical Shipping operated as part of our cargo shipping segment and the financial results are classified as discontinued operations. Accordingly, all references to continuing operations exclude the operations of Tropical Shipping. The sale of Tropical Shipping allows us to focus on growing our core business of operating regulated utilities and complementary non-regulated energy businesses and provided us with flexibility around our near-term financing plans. For additional information on our discontinued operations, see Note 14 to our consolidated financial statements under Item 8 herein.

In 2014, our net income from continuing operations was $580 million, an increase of $272 million compared to income from continuing operations in 2013. This increase was primarily the result of significantly higher commercial activity and net hedge gains at wholesale services, mainly due to natural gas market volatility. This volatility was primarily generated by significantly colder-than normal weather in the first quarter of 2014, which also increased the operating margins at distribution operations and retail operations. Excluding the favorable weather impacts, we also achieved growth in our operating margins during 2014 as a result of targeted acquisition growth in retail operations. Our operating expenses in 2014 were higher compared to 2013 mainly as a result of higher incentive compensation expenses primarily related to higher earnings in 2014.

Our priorities for 2015 are consistent with the direction we have taken the company over the last several years. We will remain focused on efficient operations across all of our businesses, including offsetting inflationary pressures by aggressive cost controls, spreading costs across a broader customer base and sizing our operations to properly reflect market conditions. Several of our specific business objectives are detailed as follows:
 
    ·  
Distribution Operations: Invest necessary capital to enhance and maintain safety and reliability; remain a low-cost leader within the industry; opportunistically expand the system and capitalize on potential customer conversions. We intend to continue investing in our regulatory infrastructure programs in Georgia, Virginia, New Jersey and Tennessee to minimize regulatory lag and the recovery cycle. In July 2014, the Illinois Commission approved our new regulatory infrastructure program, Investing in Illinois (previously known as Qualified Infrastructure Plant), for which we will implement rates under the program effective in March 2015. We continue to effectively manage costs and leverage our shared services model across our businesses to largely overcome inflationary effects.
 
    ·  
Retail Operations: Maintain operating margins in Georgia and Illinois while continuing to expand into other profitable retail markets; expand our warranty businesses through partnership opportunities with our affiliates. We expect the Georgia retail market to remain highly competitive; however, our operating margins are forecasted to remain stable with modest growth and expansion into new markets.
 
    ·  
Wholesale Services: Maximize storage and transportation positions; effectively perform on existing asset management agreements, and expand customer base and maintain cost structure in line with market fundamentals. We anticipate volatility to remain low to moderate in certain areas of our portfolio; however, we expect near-term volatility in the supply-constrained Northeast corridor until expected new pipeline projects are completed and new capacity is placed into service. We continue to position our business to secure sufficient supplies of natural gas to meet the needs of our utility and third-party customers and to hedge natural gas prices to manage costs effectively, reduce price volatility and maintain a competitive advantage.
 
    ·  
Midstream Operations: Optimize storage portfolio, including contracts that have expired or will expire, pursue LNG transportation and natural gas pipeline opportunities and evaluate alternate uses for our storage facilities. In 2014, we announced our participation in three pipeline projects that we expect to provide a diverse source of natural gas to our customers in Georgia, New Jersey and Virginia. Subject to regulatory approvals, construction is expected to begin in the 2016-2017 timeframe with completion targeted in 2017-2018. For additional information on our pipeline projects, see Note 2 and Note 10 to our consolidated financial statements under Item 8 herein and Item 1, “Business” under the caption “Midstream Operations.”

Additionally, we will maintain our strong balance sheet and liquidity profile, solid investment grade ratings and our commitment to sustainable annual dividend growth. For additional information on our reportable segments, see Note 13 to our consolidated financial statements under Item 8 herein and Item 1, “Business.

 
 

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
 
2014
   
2013
   
2012
 
Residential
  $ 2,877     $ 2,422     $ 2,011  
Commercial
    861       696       656  
Transportation
    458       487       474  
Industrial
    242       180       262  
Other (1)
    947       424       159  
Total operating revenues
  $ 5,385     $ 4,209     $ 3,562  
(1)  
Includes significantly higher-than-normal revenues at wholesale services in 2014, which are not indicative of future performance.

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

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 and midstream operations segments since it is a direct measure of operating margin before overhead costs. You should not consider operating margin 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, operating margin may not be comparable to similarly titled measures of other companies.

 
 
We also believe presenting the non-GAAP measurements of basic and diluted earnings per share - as adjusted, which excludes Nicor merger-related expenses and the additional accrual for the Nicor Gas PBR issue, provides investors with an additional measure of our performance. Adjusted basic and diluted earnings per share should not be considered an alternative to, or a more meaningful indicator of, our operating performance than our GAAP basic and diluted earnings per share. The following table reconciles operating revenue and operating margin to operating income 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, except per share amounts
 
2014
   
2013
   
2012
 
Operating revenues
  $ 5,385     $ 4,209     $ 3,562  
Cost of goods sold
    (2,765 )     (2,110 )     (1,583 )
Revenue tax expense (1)
    (130 )     (110 )     (85 )
Operating margin
    2,490       1,989       1,894  
Operating expenses
    (1,527 )     (1,471 )     (1,369 )
Revenue tax expense (1)
    130       110       85  
Gain on disposition of assets
    2       11       -  
Nicor merger expenses
    -       -       (20 )
Operating income
    1,095       639       590  
Other income
    14       16       24  
EBIT
    1,109       655       614  
Interest expense, net
    (179 )     (170 )     (183 )
Income before income taxes
    930       485       431  
Income tax expense
    (350 )     (177 )     (157 )
Income from continuing operations
    580       308       274  
(Loss) income from discontinued operations, net of tax
    (80 )     5       1  
Net income
    500       313       275  
Less net income attributable to the noncontrolling interest
    18       18       15  
Net income attributable to AGL Resources Inc.
  $ 482     $ 295     $ 260  
Amounts attributable to AGL Resources Inc.
                       
Income from continuing operations attributable to AGL Resources Inc.
  $ 562     $ 290     $ 259  
(Loss) income from discontinued operations, net of tax
    (80 )     5       1  
Net income attributable to AGL Resources Inc.
  $ 482     $ 295     $ 260  
Per common share data
                       
Diluted earnings per common share from continuing operations
  $ 4.71     $ 2.45     $ 2.20  
Diluted (loss) earnings per common share from discontinued operations (2)
    (0.67 )     0.04       0.01  
Additional accrual for Nicor Gas PBR issue
    -       -       0.04  
Transaction costs of Nicor merger
    -       -       0.11  
Diluted earnings per share - as adjusted
  $ 4.04     $ 2.49     $ 2.36  
 (1)  
Adjusted for Nicor Gas’ revenue tax expenses, as they are passed through directly to customers.
 (2)  
In September 2014, we closed on the sale of Tropical Shipping. See Note 14 to our consolidated financial statements under Item 8 herein for additional information.

In 2014, our income from continuing operations attributable to AGL Resources Inc. increased by $272 million, or 94% compared to 2013. This increase was primarily the result of the following:

    ·  
Significantly higher commercial activity primarily in the first quarter of 2014, and mark-to-market hedge gains, net of LOCOM adjustments at wholesale services in 2014 from price volatility generated by colder-than-normal weather, which increased operating margin by $462 million compared to 2013.
    ·  
Increased operating margin at distribution operations and retail operations of $50 million mainly due to significantly colder-than-normal weather in 2014 compared to slightly colder-than-normal weather in 2013, as well as customer usage and customer growth. We also achieved growth as a result of our 2013 acquisitions and expansion into additional markets at retail operations.
    ·  
These increases were partially offset by a decrease in margin of $10 million at midstream operations primarily due to a retained fuel true-up at one of our storage facilities as a result of naturally occurring shrinkage of the caverns, as well as lower contracted firm rates at Jefferson Island and Central Valley.
    ·  
Favorability year-over-year was negatively impacted by higher incentive compensation expenses primarily related to higher earnings in 2014 and increased outside services expenses of $49 million, and the $8 million higher pre-tax gain in 2013 related to the sale of Compass Energy.
    ·  
Our income tax expense from continuing operations increased by $173 million for 2014 compared to 2013, primarily due to higher consolidated earnings. The increase was primarily a result of increased earnings at wholesale services.
 
 
 
In 2013, our income from continuing operations attributable to AGL Resources Inc. increased by $31 million, or 12% compared to 2012.
 
    ·  
The overall increase was primarily the result of increased operating margin at distribution operations and retail operations due to weather that was both colder-than-normal and colder than the prior year, increased regulatory infrastructure program revenues at Atlanta Gas Light, the acquisition of service contracts and residential and commercial energy customer relationships in our retail operations segment, as well as lower depreciation expense at Nicor Gas.
    ·  
The increase was unfavorably impacted by mark-to-market accounting hedge losses in our wholesale services segment during the second half of 2013, offset by higher commercial activity and the $11 million pre-tax gain on the sale of Compass Energy in 2013.
    ·  
Our midstream operations segment was unfavorable compared to 2012 due to the $8 million loss associated with the termination of the Sawgrass Storage project in 2013, as well as lower contracted firm rates at Jefferson Island and higher operating expenses at Golden Triangle, Central Valley and Pivotal LNG resulting from full year operations in 2013 as compared to partial year operations in 2012.
    ·  
Favorability year-over-year was also partially offset by higher incentive compensation expenses in most of our businesses, as our incentive compensation expense was above targeted levels in 2013 based on improved financial and operational performance compared to significantly below targeted annual levels in 2012 due to below target performance. In addition, our bad debt expense increased at distribution operations and retail operations primarily as a result of higher revenues from colder weather combined with natural gas prices that were higher than the prior year.
    ·  
In 2012, we recorded $20 million ($13 million net of tax) of Nicor merger-related expenses.
    ·  
In 2013, our interest expense decreased by $13 million compared to 2012. This decrease was the result of overall lower interest rates mostly offset by higher average debt outstanding primarily as a result of issuing $500 million of senior notes in place of variable-rate debt.
    ·  
In 2013, our income tax expense increased by $20 million or 13% compared to 2012 primarily due to higher consolidated earnings, as previously discussed.
 
The variances for each reportable segment are contained within the year-over-year discussion on the following pages.


Weather We measure the effects of weather on our business primarily through Heating Degree Days, and we also consider operating costs that may vary with the effects of weather. Generally, increased Heating Degree Days result in higher demand for gas on our distribution systems. With the exception of Nicor Gas and Florida City Gas, we have various regulatory mechanisms, such as weather normalization mechanisms, which limit our exposure to weather changes within typical ranges in each of our utilities’ respective service areas. However, our customers in Illinois and our retail operations customers in Georgia can be impacted by warmer or colder-than-normal weather. We have presented the Heating Degree Day information for those locations in the following table.
     
 
                         
         
2014 vs. 2013
   
2013 vs. 2012
   
2014 vs. normal
   
2013 vs. normal
   
2012 vs. normal
 
   
Normal (1)
   
2014
   
2013
   
2012
   
colder (warmer)
   
colder (warmer)
   
colder (warmer)
   
colder (warmer)
   
colder (warmer)
 
Year ended December 31,
                                                     
     Illinois (2)
    5,752       6,556       6,305       4,863       4 %     30 %     14 %     10 %     (15 )%
     Georgia
    2,599       2,882       2,689       1,934       7 %     39 %     11 %     3 %     (26 )%
Quarter ended December 31,
                                                                       
     Illinois (2)
    2,085       2,103       2,383       1,890       (12 )%     26 %     1 %     14 %     (9 )%
     Georgia
    1,014       1,003       1,049       878       (4 )%     19 %     (1 )%     3 %     (13 )%
(1)  
Normal represents the 10-year average from January 1, 2004 through December 31, 2013, for Illinois at Chicago Midway International Airport and for Georgia at Atlanta Hartsfield-Jackson International Airport, as obtained from the National Oceanic and Atmospheric Administration, National Climatic Data Center.
(2)  
The 10-year average Heating Degree Days established by the Illinois Commission in our last rate case, is 2,020 for the fourth quarter and 5,600 for the 12 months from 1998 through 2007.

In 2014, we experienced weather in Illinois that was 14% colder-than-normal and 4% colder than 2013. This weather positively impacted our 2014 EBIT at our utilities, primarily at Nicor Gas, by $20 million, and drove an increase of $12 million in 2013 based on 10-year normal weather. Georgia also experienced 11% colder-than-normal weather, and 7% colder weather than the same period last year. Colder-than-normal weather increased EBIT at retail operations by $14 million in 2014 and $9 million in 2013 compared to expected levels based on 10-year normal weather.
 
Customers The number of customers at distribution operations and energy customers at retail operations can be impacted by natural gas prices, economic conditions and competition from alternative fuels. Our energy customers at retail operations are primarily located in Georgia and Illinois. Our customer metrics highlight the average number of customers to which we provide services and are presented in the following table.
 
   
Years ended December 31,
   
2014 vs. 2013 change
   
2013 vs. 2012 change
 
(in thousands)
 
2014
   
2013
   
2012
      #    
%
      #    
%
 
Distribution operations customers (1)
    4,497       4,479       4,459       18       0.4 %     20       0.4 %
Retail operations
                                                       
Energy customers (2)
    628       619       623       9       1 %     (4 )     (1 )%
Service contracts (3)
    1,182       1,127       684       55       5 %     443       65 %
Market share in Georgia
    31 %     31 %     32 %             - %             (1 )%
 (1)  
In 2014, we implemented a process change at Nicor Gas that adversely impacted our customer count. This had the effect of immaterial growth for Nicor Gas from last year. Excluding Nicor Gas, our customer growth rate for 2014 was 0.8%.
 (2)  
Increase from 2013 to 2014 primarily due to the addition of approximately 33,000 residential and commercial customer relationships acquired in Illinois in June 2013.
 (3)  
Increase from 2012 to 2013 primarily due to acquisition of approximately 500,000 contracts on January 31, 2013.

 
 
We anticipate overall utility customer growth trends for 2014 to continue in 2015 based on an expectation of continuing improvement in the economy and relatively low natural gas prices. We use a variety of targeted marketing programs to attract new customers and to retain existing customers. These efforts include adding residential customers, multifamily complexes and commercial and industrial 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. We also target customer conversions to natural gas from other energy sources, emphasizing the pricing advantage of natural gas. These programs focus on premises that could be connected to our distribution system at little or no cost to the customer. In cases where conversion cost can be a disincentive, we may employ rebate programs and other assistance to address customer cost issues.

In 2015, we intend to continue efforts in our retail operations segment to enter into targeted markets and expand energy customers and its service contracts. We anticipate this expansion will provide growth opportunities in future years.

Volume Our natural gas volume metrics for distribution operations and retail operations present the effects of weather and customers’ demand for natural gas compared to the prior year. Wholesale services’ daily physical sales volumes represent the daily average natural gas volumes sold to its customers. Our volume metrics are presented in the following table:

 
 
Year ended December 31,
             
Distribution operations (In Bcf)
 
2014
   
2013
   
2012
   
2014 vs. 2013 % change
   
2013 vs. 2012 % change
 
Firm (1)
    766       720       606       6 %     19 %
Interruptible
    106       111       107       (5 )%     4  
Total
    872       831       713       5 %     17 %
Retail operations (In Bcf)
                                       
Georgia firm
    41       38       31       8 %     23 %
Illinois
    17       9       8       89 %     13 %
Other (includes Florida, Maryland, New York and Ohio)
    10       8       8       25 %     -  
Wholesale services
                                       
Daily physical sales (Bcf/day)
    6.32       5.73       5.54       10 %     3 %
(1)  
Year-over-year increases are primarily a result of colder weather.

Within our midstream operations segment, our natural gas storage businesses seek to have a significant portion 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 midstream operations storage business is cyclical, and the abundant supply of natural gas in recent years and the resulting lack of market and price volatility have negatively impacted the profitability of our storage facilities. Consistent with our expectations, we had contracts expire in 2014 that were re-subscribed at lower prices as compared to prior years. We anticipate these lower natural gas prices to continue in 2015 as compared to historical averages. We expect the rates at which we re-contract expiring capacity in 2015 to be marginally higher than re-contracting rates in 2014, but still significantly below historical averages. The prices for natural gas storage capacity are expected to increase as supply and demand quantities reach equilibrium as the economy continues to improve, expected exports of LNG occur and/or natural gas demand increases in response to low prices and expanded uses for natural gas. As of the periods presented, the overall monthly average firm subscription rates per facility and amount of firm capacity subscription were as follows:

   
December 31, 2014
   
December 31, 2013
 
   
Average rates (1)
   
Firm capacity under subscription (1)
   
Average rates (1)
   
Firm capacity under subscription (1)
 
Jefferson Island
  $ 0.108       4.6     $ 0.122       5.6  
Golden Triangle
    0.114       5.0       0.240       2.0  
Central Valley
    0.062       2.5       0.130       3.0  
 (1)  
Rates are per dekatherm. Firm capacity under subscription excludes 7 Bcf contracted by Sequent as of December 31, 2014, at an average monthly rate of $0.050 and 3.5 Bcf as of December 31, 2013, at an average monthly rate of $0.091.