10-K 1 a201510-k.htm 10-K 10-K

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, 2015
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. has (1) 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) 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 2015 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 Part III, Item 11 of this Form 10-K.
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, 2015, as reported by the New York Stock Exchange) was $5,591,017,687.
The number of shares of AGL Resources Inc.’s common stock outstanding as of February 5, 2016 was 120,384,325.







TABLE OF CONTENTS
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



GLOSSARY OF KEY TERMS
AFUDC
Allowance for funds used during construction
AGL Capital
AGL Capital Corporation
AGL Credit Facility
$1.3 billion credit agreement entered into by AGL Capital to support its 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
Board
AGL Resources Board of Directors
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
CUB
Citizens Utility Board
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 interest on debt and income tax expense
EPA
U.S. Environmental Protection Agency
ERC
Environmental remediation costs
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
Fitch
Fitch Ratings
Florida Commission
Florida Public Service Commission, the state regulatory agency for Florida City Gas
GAAP
Accounting principles generally accepted in the United States of America
Georgia Commission
Georgia Public Service Commission, the state regulatory agency for Atlanta Gas Light
Georgia Natural Gas
The trade name under which SouthStar does business in Georgia
Golden Triangle
Golden Triangle Storage, Inc.
Heating Degree Days
A measure of weather, 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
An interconnection point of natural gas pipelines in Erath, Louisiana where NYMEX natural gas future contracts are priced
Horizon Pipeline
Horizon Pipeline Company, LLC
Illinois Commission
Illinois Commerce Commission, the state regulatory agency for Nicor Gas
Jefferson Island
Jefferson Island Storage & Hub, LLC
LIBOR
London Inter-Bank Offered Rate
LIFO
Last-in, first-out
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
Merger Agreement
Agreement and Plan of Merger dated August 23, 2015 by Southern Company, AMS Corp., a subsidiary of Southern Company, and AGL Resources
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. - 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
PBR
Performance-based rate
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
PRP
Pipeline Replacement Program, Atlanta Gas Light's 15-year infrastructure replacement program, which ended in December 2013
S&P
Standard & Poor’s Ratings Services
Sawgrass Storage
Sawgrass Storage, LLC
SEC
Securities and Exchange Commission
Sequent
Sequent Energy Management, L.P.
Southern Company
The Southern Company
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, which was sold in 2014
U.S.
The United States of America
VaR
Value-at-risk
VIE
Variable interest entity
Virginia Commission
Virginia State Corporation Commission, the state regulatory agency for Virginia Natural Gas
Virginia Natural Gas
Virginia Natural Gas, Inc.
WACC
Weighted average cost of capital
WACOG
Weighted average cost of gas
WNA
Weather normalization adjustment



PART I
ITEM 1.   BUSINESS
Unless the context requires otherwise, references to “we,” “us,” “our,” “the company” or "AGL Resources" mean consolidated AGL Resources Inc. and its subsidiaries. AGL Resources was incorporated in 1995 under the laws of the State of Georgia and is headquartered in Atlanta, Georgia.
Business Overview
AGL Resources is an energy services holding company whose primary business is the safe, reliable and cost-effective distribution of natural gas through seven natural gas distribution utilities. We also are involved in several other businesses that are complementary to the distribution of natural gas. Our reportable segments, listed below, reflect how management views and manages our businesses. Our non-reportable subsidiaries are aggregated and presented as "other." In August 2015, we entered into the Merger Agreement with Southern Company, which we expect to become effective in the second half of 2016. For more information on this transaction, see Note 2 to our consolidated financial statements under Item 8 herein.
Distribution Operations
Operates, constructs and maintains 81,300 miles of natural gas pipeline and 14 storage facilities, with total capacity of 158 Bcf, to provide natural gas to residential, commercial and industrial customers
 
Serves 4.5 million customers across seven states
 
Rates of return are regulated by each individual state in return for exclusive franchises
Retail Operations
Provides natural gas commodity and related services to customers in competitive markets or markets that provide for customer choice
 
Serves 645,000 energy customers in seven states and 1.2 million service contracts across 17 states
Wholesale Services
Engages in natural gas storage and gas pipeline arbitrage, and provides natural gas asset management and related logistics services for most of our utilities, as well as 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 wholly owned natural gas storage facilities as well as partnerships and joint ventures in pipelines, enabling the provision of diverse sources of natural gas supplies to our customers
For more segment information, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the caption “Results of Operations” and Note 14 to our consolidated financial statements in Item 8 herein.
Distribution Operations
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
 
2,198

 
34,300

Atlanta Gas Light
Georgia
 
1,578

 
32,900

Virginia Natural Gas
Virginia
 
290

 
5,600

Elizabethtown Gas
New Jersey
 
283

 
3,200

Florida City Gas
Florida
 
107

 
3,600

Chattanooga Gas
Tennessee
 
64

 
1,600

Elkton Gas
Maryland
 
6

 
100

Total
 
 
4,526

 
81,300

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 in our service areas for customers who are considering switching to or from a natural gas appliance. Accordingly, the potential displacement or replacement of natural gas appliances is a competitive factor.
Competition for 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 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 of the U.S. have resulted in historically high supplies of natural gas and relatively 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 regulatory agencies. 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 regulatory agencies. 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
Our utilities are subject to regulations and oversight of the regulatory agencies in each of the states served 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, 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 our infrastructure replacement programs as well as our 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 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, encourages 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.
Dollars in millions
 
Nicor Gas
 
Atlanta Gas Light
 
Elizabethtown Gas
 
Virginia Natural Gas
 
Florida City Gas
 
Chattanooga Gas
Authorized return on rate base (1)
 
8.09%
 
8.10%
 
7.64%
 
7.38%
 
7.36%
 
7.41%
Estimated 2015 return on rate base (2)
 
7.20%
 
7.65%
 
7.83%
 
5.83%
 
4.40%
 
6.82%
Authorized return on equity (1)
 
10.17%
 
10.75%
 
10.30%
 
10.00%
 
11.25%
 
10.05%
Estimated 2015 return on equity (2)
 
9.66%
 
9.86%
 
10.70%
 
7.43%
 
5.80%
 
8.74%
Authorized rate base % of equity (1)
 
51.07%
 
51.00%
 
47.89%
 
45.36%
 
36.77%
 
46.06%
Rate base included in 2015 return on equity (2)
 
$1,654
 
$2,352
 
$555
 
$615
 
$194
 
$117
Weather normalization (3)
 
 
 
 
 
ü
 
ü
 
 
 
ü
Decoupled, including straight-fixed-variable rates (4)
 
 
 
ü
 
 
 
ü
 
 
 
ü
Regulatory infrastructure program rates (5)
 
ü
 
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 (9)
 
2009
 
2010
 
2009
 
2011
 
2004
 
2010
(1)
The authorized return on rate base, return on equity and rate base percentage of equity represent those authorized as of December 31, 2015.
(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 on earnings of weather and customer consumption. 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)
Allows 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 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)
Elizabethtown Gas has agreed to file a general rate case with the New Jersey BPU by September 2016.
Infrastructure Replacement Programs and 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 our customers, provide an appropriate return on invested capital and ensure the safety and reliability of our utility infrastructure. Total capital expenditures incurred during 2015 for our distribution operations segment were $957 million. The following table and discussions provide updates on some of our larger capital projects under various programs at our utilities, which update or expand our distribution systems to improve reliability and meet operational flexibility and growth. Our anticipated expenditures for these programs in 2016 are discussed in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” under the caption “Liquidity and Capital Resources.”






Utility
 
Program
 
Program details
 
Recovery
 
Expenditures in 2015
(in millions)
 
Expenditures since project inception
(in millions)
 
Miles of pipe
installed since
project inception
 
Scope of
program
(miles)
 
Program duration (years)
 
Last
year of program
Nicor Gas
 
Investing in Illinois
 
(1)(2) 
 
Rider
 
252

 
273

 
164

 
800

 
9
 
2023
Atlanta Gas Light
 
Integrated Vintage Plastic Replacement Program (i-VPR)
 
(3) 
 
Rider
 
63

 
130

 
398

 
756

 
4
 
2017
Atlanta Gas Light
 
Integrated System Reinforcement Program (i-SRP)
 
(8) 
 
Rider
 
44

 
309

 
n/a

 
n/a

 
8
 
2017
Atlanta Gas Light
 
Integrated Customer Growth Program
(i-CGP)
 
(9) 
 
Rider
 
15

 
62

 
n/a

 
n/a

 
8
 
2017
Florida City Gas
 
Safety, Access and Facility Enhancement Program (SAFE)
 
(4) 
 
Rider
 
1

 
1

 
4

 
254

 
10
 
2025
Virginia Natural Gas
 
Steps to Advance Virginia’s Energy (SAVE)
 
(1) 
 
Rider
 
27

 
91

 
163

 
250

 
5
 
2017
Elizabethtown Gas
 
Aging Infrastructure Replacement (AIR)
 
(5) 
 
Base Rates
 
39

 
77

 
75

 
130

 
4
 
2017
Chattanooga Gas
 
Bare Steel & Cast Iron
 
(5) 
 
Base Rates
 
5

 
38

 
84

 
111

 
10
 
2020
Florida City Gas
 
Galvanized Replacement Program
 
(6) 
 
Base Rates
 

 
15

 
79

 
111

 
17
 
2017
Atlanta Gas Light
 
Savannah Backyard Main
 
(4) 
 
Base Rates
 
4

 
14

 
59

 
98

 
5
 
2017
Elizabethtown Gas
 
Elizabethtown Natural Gas Distribution Utility Reinforcement Effort (ENDURE)
 
(7) 
 
Base Rates
 
11

 
14

 
12

 
13

 
1
 
2015
Total
 
 
 
 
 
 
 
461

 
1,024

 
1,038

 
2,523

 
 
 
 
(1)
Cast iron, bare steel, mid vintage plastic and risk based materials.
(2)
Represents expenditures on qualifying infrastructure that have been placed into service after the rate freeze expiration date, December 9, 2014.
(3)
Early vintage plastic, risk based mid vintage plastic, mid vintage neighborhood convenience.
(4)
Backyard main replacement.
(5)
Cast iron and bare steel.
(6)
Galvanized and X-Tube steel. Reflects expenditures and miles of pipe installed since we acquired Florida City Gas in November 2004.
(7)
Cast iron and distribution reinforcement.
(8)
Large diameter pressure improvement and system reinforcement projects.
(9)
New business construction and strategic line extension.
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 nine-year regulatory infrastructure program, Investing in Illinois, under which we implemented rates that became effective in March 2015. As of December 31, 2015, we have placed into service $250 million of qualifying projects under this plan, which represents approximately 1.5% of annual average base rate revenues for 2015.
Atlanta Gas Light Our four-year STRIDE program, which was approved in December 2013, is comprised of i-SRP, i-CGP and i-VPR and consists of infrastructure development, enhancement and replacement programs that are used to update and expand distribution systems and liquefied natural gas facilities, improve system reliability and meet operational flexibility and growth. STRIDE includes a monthly surcharge on firm customers that was approved by the Georgia Commission to provide recovery of the revenue requirement for the ongoing programs and the PRP, which ended on December 31, 2013. This surcharge began in January 2015 and will continue through 2025.
The i-SRP program authorized $445 million of capital spending for projects 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 along with a new construction plan every three years for review and approval by the Georgia Commission. Our most recent plan was filed in August 2013 and approved in February 2014.
Our i-CGP authorizes Atlanta Gas Light to spend $91 million on projects to extend its pipeline facilities to serve customers in areas without pipeline access and create new economic development opportunities in Georgia.



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 should potentially 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.
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 third year performance rate update was approved by the Virginia Commission in July 2015 and became effective in August 2015. In November 2015, Virginia Natural Gas filed with the Virginia Commission for approval of an extension to the SAVE program through 2021.
Elizabethtown Gas Our extension of the AIR 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 in our pipeline system. Carrying charges on the additional capital spend are being accrued and deferred for regulatory purposes at a 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 Natural Gas Distribution Utility Reinforcement Effort (ENDURE), a program that improved our distribution system’s resiliency against coastal storms and floods. Under the plan, Elizabethtown Gas invested $15 million in infrastructure and related facilities and communication planning over a one year period from August 2014 through September 2015. Effective November 1, 2015, Elizabethtown Gas increased its base rates for investments made under the program.
In September 2015, we filed the Safety, Modernization and Reliability Tariff (SMART) plan with the New Jersey BPU seeking approval to invest more than $1.1 billion to replace 630 miles of vintage cast iron, steel and copper pipeline, as well as 240 regulator stations. If approved, the program is expected to be completed by 2027. As currently proposed, costs incurred under the program would be recovered through a rider surcharge over a period of 10 years.
Florida City Gas In September 2015, the Florida Commission approved our Safety, Access and Facility Enhancement (SAFE) program, under which costs incurred for replacing aging pipes will be recovered through a rate rider with annual adjustments and true-ups. Under the program, we expect to spend $105 million over a 10-year period on infrastructure relocation and enhancement projects. Florida City Gas began spending under the program during the fourth quarter of 2015 and plant in service associated with work performed in 2015 was included in the calculation of rates that began January 1, 2016.
Current Regulatory Proceedings
Atlanta Gas Light In February 2015, Atlanta Gas Light made a filing with the Georgia Commission for a rate true-up of allowed unrecovered revenue of $178 million through December 2014 related to its PRP. In October 2015, Atlanta Gas Light received a final order from the Georgia Commission allowing Atlanta Gas Light to recover $144 million of the $178 million. The remaining unrecovered amount relates primarily to recoveries of previously allowed rate of return amounts, which are included in our unrecognized ratemaking amount and does not have a material impact on our consolidated financial statements as of December 31, 2015. As a result of the order, we recognized $1 million of interest expense on our Consolidated Statements of Income in 2015 related to the PRP true-up.
We began recovering the $144 million in October 2015 through a monthly PRP surcharge, which increased by $0.82 on October 1, 2015 and will increase by an additional $0.81 on each of October 1, 2016 and October 1, 2017. The cumulative total monthly increase to the PRP surcharge will remain at $2.44 and be effective until the earlier of the full recovery of the under-recovered amount or December 31, 2025. 
Additionally, one of the capital projects under the PRP experienced construction issues on certain segments in late 2013, and prior to these segments being placed into service, it was necessary to complete mitigation work. The order from the Georgia Commission allows for the recovery of these mitigation costs in future base rates, but such recovery will be effective no earlier than March 31, 2017. As a result of the order we recognized $5 million in operation and maintenance expense on our Consolidated Statements of Income in 2015. Atlanta Gas Light continues to pursue contractual and legal claims against certain third-party contractors in connection with the mitigation costs relating to these construction issues. Any amounts recovered through the legal process will be retained by Atlanta Gas Light. At March 31, 2017, the total capitalized mitigation cost for which Atlanta Gas Light will seek recovery in future rates is approximately $28 million. 



In December 2014, the Georgia Commission approved a stipulation 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. During the first half of 2015, discretionary funds available to the Universal Service Fund, which is controlled by the Georgia Commission, were used to resolve the Georgia Commission's obligation of 25% of the total 4.6 Bcf imbalance, or approximately 1.15 Bcf of natural gas. Atlanta Gas Light was also obligated to resolve 25% of the imbalance through system injections, which were fully replaced by the end of the third quarter of 2015. The cost to resolve the remaining difference of approximately 2.3 Bcf of natural gas will be recovered from all of the Marketers over the five-year period permitted by the stipulation through charges for system retained storage gas as it is used by the Marketers.
In accordance with an order issued by the Georgia Commission, when 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 March 2015, the Georgia Commission approved the Report of Synergy Savings that we filed in connection with the Nicor merger. The net savings result in annual rate reductions of $5 million to the firm customers of Atlanta Gas Light. These surcredit adjustments are now a component of the Atlanta Gas Light base charge and began appearing on customers’ bills in June 2015.
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. All refunds were completed by the first half of 2014. The CUB's February 2014 appeal of the Illinois Commission's order requesting refunds consistent with its 2009 request was rejected by the appellate court in March 2015.
In August 2014, staff of the Illinois Commission and the CUB filed testimony in the 2003 gas cost prudence review disputing certain gas loan transactions offered by Nicor Gas under its Chicago Hub services and requesting refunds of $18 million and $22 million, respectively. In July 2015, the Administrative Law Judge issued a proposed order concluding that Nicor Gas' supply costs and purchases in 2003 were prudent, its reconciliation of the related costs was proper, and the propositions by the staff of the Illinois Commission and the CUB were based on hindsight speculation, which is expressly prohibited in a prudence review examination. In September 2015, the Illinois Commission issued a final order approving the proposal of the Administrative Law Judge. In November 2015, the Illinois Commission granted the CUB's petition for a rehearing on this matter, with action required by the Illinois Commission by April 2016. Additionally, in December 2015, all parties agreed on a plan to move forward with hearings on certain other open PGA reconciliation years. In February 2016, the Administrative Law Judge issued a proposed order on rehearing affirming the original order by the Illinois Commission, which now requires approval by the Illinois Commission.
We are currently unable to predict the ultimate outcomes and have recorded no liability for these matters.
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 2014. Nicor Gas spent $125 million on the program and reduced customer usage by an estimated 49 million therms, which was in excess of our planned goal of saving 40 million therms over the duration of this program. Additionally, in May 2014, the Illinois Commission approved Nicor Gas’ second energy efficiency program, energySMART, with expected spending of $93 million over a three-year period and an estimated therm reduction goal of 27 million therms. The program began in June 2014 and Nicor Gas spent $31 million in 2015 and $14 million in 2014 and have achieved approximately 17 million in therm reduction as of December 31, 2015. The costs incurred on the program will be recovered over a three-year period through a rider surcharge.
Asset Management Agreements
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. Nicor Gas has not entered into an asset management agreement with Sequent or any other parties. For Atlanta Gas Light, these payments are controlled by the Georgia Commission and are 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, but 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.
Each agreement provides for Sequent to make payments to the utilities through either an annual minimum guarantee within a profit sharing structure, a profit sharing structure without an annual minimum guarantee, or a fixed fee. From the inception of these agreements in 2001 through 2015, Sequent made sharing payments to our utilities under these agreements totaling $332 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
 
2015
 
2014
 
2013
 
Expiration Date
Elizabethtown Gas
 
$
28

 
$
18

 
$
6

 
March 2019
Virginia Natural Gas
 
15

 
14

 
4

 
March 2018
Atlanta Gas Light
 
15

 
13

 
6

 
March 2017
Florida City Gas
 
1

 
1

 
1

 
(1) 
Chattanooga Gas
 
1

 
1

 
1

 
March 2018
Total
 
$
60

 
$
47

 
$
18

 
 
(1) The agreement renews automatically each year unless terminated by either party.
Natural Gas 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, Elizabethtown Gas, Virginia Natural Gas and Chattanooga Gas operate on-system LNG facilities, underground natural gas storage fields and propane/air plants to meet the gas supply and deliverability requirements of our customers during the winter. Generally, we work to build a portfolio of year-round firm transportation, seasonal storage and short-duration peaking services to 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 heating. Including 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 with staggered terms to maintain our ability to adjust the overall portfolio to meet changing market conditions. Our utilities have contracted for capacity that is predominantly 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 supplies. We make decisions as to the termination, extension or renegotiation of contracts every year.
In 2014, our midstream operations segment entered into three pipeline projects that will provide access to shale gas in proximity to 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.
Environmental Remediation Costs
We are subject to federal, state and local laws and regulations governing environmental quality and pollution control that require us to remove or remedy the effect on the environment of the disposal or release of specified substances at our current and former operating sites, substantially all of which is related to former MGP sites. As we continue to conduct MGP remediation and enter into cleanup contracts, we are able to refine our engineering estimates of the likely costs. These estimates contain various engineering assumptions, which we refine and update on an ongoing basis. These costs are primarily recovered through rate riders. See Note 4 to our consolidated financial statements under Item 8 herein for additional information about our environmental remediation liabilities and efforts.
Retail Operations
Our retail operations segment is comprised of SouthStar and Pivotal Home Solutions, which serve approximately 645,000 natural gas commodity customers and 1.2 million service contracts.
SouthStar is one of the largest retail natural gas marketers in the U.S. and markets natural gas to residential, commercial and industrial customers, primarily in Georgia, Illinois and Ohio, where we capture spreads between wholesale and retail natural gas prices. We also offer our customers energy-related products that provide natural gas price stability and utility bill management. These products mitigate or eliminate the risks to customers of colder-than-normal weather and 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 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. On December 9, 2015, we notified Piedmont of our election, in accordance with the terms in the Second Amended and Restated Limited Liability Company Agreement of SouthStar, to purchase its entire 15% interest in SouthStar at fair market value. The parties currently are negotiating final terms.
Pivotal Home Solutions provides a suite of home protection products and services that offers 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. We serve customers in several states, primarily Illinois, Indiana, Massachusetts and Ohio. We continue to expand product offerings to customers of 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 SouthStar participates in various customer choice programs that were approved in various states to increase competition in natural gas markets. These programs are implemented by each state and vary by size, scope and participation. The customer choice programs provide for the ability of residential and commercial customers to choose their own natural gas supplier while the local distribution company continues to provide transportation and distribution services. The Georgia market continues to be the most comprehensive choice program in the U.S., whereby all of Atlanta Gas Light's customers purchase their natural gas directly from Marketers. SouthStar operates as Georgia Natural Gas and is the largest of 14 Marketers in Georgia, with average customers of nearly 500,000 and a leading market share of approximately 30%. SouthStar also operates within other customer choice markets that do not have the high level of customer participation as Georgia. SouthStar's ability to grow within these markets is dependent upon customer awareness of these programs primarily through marketing and continued participation by each state in these programs.
In Georgia, 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, many of SouthStar’s residential and commercial customers have migrated to fixed-price plans, which combined with increased competition from other Marketers has impacted our customer growth and 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 utilities. SouthStar’s retail pricing strategies and the use of a variety of hedging strategies, such as futures, options, swaps, weather derivative instruments and other risk management tools, help to ensure retail customer costs are covered to mitigate the potential effect of these issues 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 “Weather and Natural Gas Price Risks.” Our retail operations businesses also experience price, convenience, and service competition from other warranty companies. These businesses also bear risk from potential changes in the regulatory environment.
Wholesale Services
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 our customers. Our 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 as opportunities arise by optimizing the contracted assets through the application of our wholesale market knowledge and risk management skills. 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.
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 value 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 prior to the period the related physical storage and transportation transactions occur and are recognized in earnings. The changes in fair values of the hedging instruments are recognized in earnings in the period of change and are 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 the natural gas is physically withdrawn from storage or transported and sold at market prices and the related hedging instruments are settled.
We purchase natural gas for our storage portfolio when the current market price we pay plus the cost for transportation, storage and financing is less than the market price we anticipate receiving 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 manage costs, reduce price volatility and maintain a competitive advantage.
Midstream Operations
Storage and Fuels Our midstream operations segment includes a number of businesses that are related and complementary to our primary business of the safe and reliable delivery of natural gas. 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 and select pipeline investments.
Pipelines In 2014, we entered into three pipeline projects, which are currently awaiting FERC approval. These projects, along with our existing pipelines, 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 following table provides an overview of these pipeline projects. See Note 11 to the consolidated financial statements under Item 8 herein for additional information.
Dollars in millions
 
Miles of pipe
 
Expected capital
expenditures
 (1)
 
Ownership
interest 
(1)
 
FERC filing
 
Expected FERC approval
Atlantic Coast Pipeline (2)
 
564

 
$
260

 
5
%
 
2015
 
2016
PennEast Pipeline (3)
 
118

 
200

 
20
%
 
2015
 
2016
Dalton Pipeline (4)
 
106

 
210

 
50
%
 
2015
 
2016
Total
 
788

 
$
670

 
 
 
 
 
 
(1)
Represents our expected capital expenditures and ownership interest, which may change.
(2)
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.
(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 recent winters.
(4)
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.
Magnolia Enterprise Holdings, Inc. This wholly owned subsidiary operates a pipeline that connects our Georgia service territory to LNG imports and 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 that expires 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 2015, expiring storage capacity contracts were re-subscribed at lower prices and we anticipate these lower natural gas prices to



continue in 2016 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.
Other
Our “other” segment is an aggregation of AGL Services Company, AGL Capital, our investment in Triton and our other subsidiaries that individually are not significant on a stand-alone basis and that do not align with our reportable segments. 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; however, we do incur certain corporate costs that are not allocated to our reportable segments. Our EBIT results for our reportable segments include the impact of such operating expenses and the permitted allocations. 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. Triton is a full service global leasing company and owner-lessor of marine intermodal cargo containers.
Employees
As of December 31, 2015, we had 5,203 employees, all of whom were in the U.S. The following table provides information about our natural gas utilities’ collective bargaining agreements, which represent 33% of our total employees.
 
 
Number of employees
 
Contract expiration date
Nicor Gas
 
 
 
 
International Brotherhood of Electrical Workers (Local No. 19)
 
1,422

 
February 2017
Virginia Natural Gas
 
 
 
 
International Brotherhood of Electrical Workers (Local No. 50) (1)
 
137

 
May 2019
Elizabethtown Gas
 
 
 
 
Utility Workers Union of America (Local No. 424) (2)
 
166

 
November 2019
Total
 
1,725

 
 
(1)
Virginia Natural Gas’ collective bargaining agreement expired in May 2015, and a new agreement was ratified in August 2015. The new agreement provides for additional operational enhancements and changes to certain benefits, but has no material effect on our consolidated financial statements.
(2)
Elizabethtown Gas' collective bargaining agreement expired in November 2015, and a new agreement was ratified in December 2015. The new agreement provides for additional operational enhancements and changes to certain benefits, but has no material effect on our consolidated financial statements.
We believe that we have a good working relationship with our unionized employees and there have been no work stoppages since we acquired those operations. As we have done historically, we remain committed to working 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
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.



ITEM 1A.   RISK FACTORS
Forward-Looking Statements
Certain expectations and projections regarding our future performance referenced in this section and elsewhere in this report, as well as in other reports and proxy statements we file with the SEC or otherwise release to the public and on our website are forward-looking statements and are subject to uncertainties and risks. Senior officers and other employees may also make verbal statements to analysts, investors, regulators, the media and others that are forward-looking.
Forward-looking statements often include words such as "anticipate," "assume," "believe," "can," "could," "estimate," "expect," "forecast," "future," "goal," "indicate," "intend," "may," "outlook," "plan," "potential," "predict," "project," "proposed," "seek," "should," "target," "would" or similar expressions. You are cautioned not to place undue reliance on 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 of which are 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:
certain risks and uncertainties associated with the proposed merger with Southern Company, including, without limitation:
the possibility that the proposed merger does not close due to the failure to satisfy the closing conditions, including, but not limited to, a failure to obtain the required regulatory approvals;
delays caused by required regulatory approvals, which may delay the proposed merger or cause the companies to abandon the transaction;
disruption from the proposed merger making it more difficult to maintain our business and operational relationships and the risk that unexpected costs will be incurred during this process; and
the diversion of management time on merger-related issues;
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, 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;
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 capacity of our gas storage caverns, which are subject to natural settling and other occurrences;
contracting rates at our midstream operations storage business;
the impact of our construction projects and related capital expenditures, including our pipeline projects;
the development, timing and anticipated costs relating to our pipeline projects;
the impact of changes in weather 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;
the effect of accounting pronouncements issued periodically by standard-setting bodies; and
the other factors discussed elsewhere herein and in our other filings with the SEC.
There may also be other factors that we do not anticipate or that we do not recognize as material that could cause results to differ materially from our expectations. Forward-looking statements speak only as of the date they are made. We expressly disclaim any obligation to 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 regulatory infrastructure 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 obtain the rate increases that we request in a timely manner, should we not 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.
The price for natural gas and competing energy sources, such as oil, can fluctuate widely. Generally, we pass through changes in prices to our utility customers, 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, which results in additional financing costs as a result of purchasing more expensive natural gas.
In addition, increases in natural 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 the desired 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 natural gas for 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 natural gas, the cost of natural 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 natural 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/or 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. 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 55% of all usage is for heating and approximately 73% 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 5,845 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 3 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.
SouthStar offers 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 operational interruptions.
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 4 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 additional debt borrowings. 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 legislation and regulation.
Climate change legislation is receiving increased 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. Below is a summary of recent global and federal actions related to climate change legislation.
In December 2015, the U.S. and 195 other nations adopted the United Nations sponsored Paris Agreement on global climate change (Paris Agreement), which establishes a universal framework for addressing greenhouse gas emissions based on nationally determined contributions. It also sets in place a process for increasing those commitments every five years. The ultimate impact of the Paris Agreement depends on its ratification and implementation by participating countries, and cannot be determined at this time.
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, the 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 directed 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 directed the EPA to finalize those regulations by June 1, 2015. The EPA complied and issued the commonly referred to Clean Power Plan, which seeks to reduce carbon dioxide emissions from existing electric utility generating units by 30% from 2005 levels and promotes increased use of natural gas and renewable energy. States are required to develop regulations implementing the EPA’s guidelines by September 6, 2016 and may seek a two-year extension. It also includes a wide variety of other initiatives designed to reduce greenhouse gas emissions and lead international efforts to address climate change.
The outcome of global, federal and state climate change legislation 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. Future regulation of methane, a greenhouse gas and primary constituent of natural gas, 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 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, 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 also rely on natural gas pipelines and other storage and transportation facilities owned and operated by third parties to deliver natural gas to wholesale markets and to our distribution systems.
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, 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 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 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 natural gas prices and low volatility, and we expect this to continue in 2016.
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 significant credit losses.
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 14 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 local distribution utilities, 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 wholesale services and the commodity and storage portfolios at midstream operations and retail operations 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 “Weather and Natural Gas Price Risks – VaR” herein.
Our accounting results may not be indicative of the risks we are taking or the economic results we expect in our nonregulated businesses.
Although we enter into various contracts to hedge the value of our energy assets and operations, the timing of the recognition of profits or losses in our financial results of our hedges does not always correspond to the economic results of the item being hedged. The difference in accounting can result in volatility in our 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 plan 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 plan 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 7 to the consolidated financial statements under Item 8 herein.
Natural disasters, terrorist activities, human error 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 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 others. In 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 had no material security breaches in 2015.







We may pursue acquisitions, divestitures and other strategic transactions, 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 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.
Future impairments of goodwill or long-lived assets could have a material adverse effect on our results of operations.
We assess goodwill for impairment at least annually and more frequently if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value. We assess our long-lived assets, including 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. In the third quarter of 2015, we recorded a non-cash impairment charge of $14 million ($9 million, net of tax) of goodwill in our midstream operations segment. No impairment of goodwill was recorded as a result of our 2015 annual impairment testing for any of our other segments, as the fair value of each reporting unit was in excess of the carrying value. See Note 3 to our consolidated financial statements under Item 8 herein for additional information on impairment of assets. Additionally, no impairment of long-lived assets was recorded during 2015.
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. Due to the subjectivity of the assumptions and estimates underlying the impairment analysis, future analyses may 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.
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 these 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 and 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 and related interest rate swaps, which could lead to changes in interest expense and adversely affect our earnings.
We are subject to interest rate risk 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 restriction. In addition, Nicor Gas is not permitted to make money pool loans to affiliates.
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.
Risk Factors Related to the Merger Agreement
The merger is subject to receipt of consent or approval from various governmental entities that could delay or prevent the completion of the merger or, in order to receive such consent or approval, the governmental entities may impose restrictions or conditions that could have a material adverse effect on the combined company or that could cause abandonment of the transaction.
Completion of the merger is contingent upon, among other things, satisfaction or waiver of specified closing conditions, including (i) the receipt of required regulatory approvals from the Federal Communications Commission, California Public Utilities Commission, Georgia Commission, Illinois Commission, Maryland Commission, New Jersey BPU and Virginia Commission, and such approvals having become final orders and (ii) the absence of a judgment, order, decision, injunction, ruling or other finding or agency requirement of a governmental entity prohibiting the consummation of the merger. For more information, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the caption “Executive Summary” and the subheading “Proposed Merger With Southern Company” and Note 2 to the consolidated financial statements under Item 8 herein.
We may not receive the required statutory approvals and other clearances for the merger, or we may not receive them in a timely manner. If such approvals and clearances are received, they may impose terms, conditions or restrictions (i) that cause a failure of the closing conditions set forth in the Merger Agreement, which could permit us or Southern Company to terminate the Merger Agreement and abandon the transaction or (ii) that could reasonably be expected to have a detrimental impact on the combined company following completion of the merger. A substantial delay in obtaining the required authorizations, approvals or consents or the imposition of unfavorable terms, conditions or restrictions contained in such authorizations, approvals or consents could prevent the completion of the merger or have an adverse effect on the anticipated benefits of the merger, thereby impacting the business, financial condition or results of operations of the combined company.
Notwithstanding the expiration of the waiting period under the Hart-Scott-Rodino Act, governmental authorities could seek to block or challenge the merger as they deem necessary or desirable in the public interest.



Failure to complete the merger could adversely affect our stock price, future business operations and financial results.
Completion of the merger is subject to risks, including the risks that approval of the transaction by governmental agencies will not be obtained or that certain other closing conditions will not be satisfied. If we are unable to complete the merger, our ongoing business may be adversely affected and we would be subject to a number of risks, including the following:
we will have paid certain significant transaction costs, including legal, financial advisory and filing, printing and mailing fees, and in certain circumstances, a termination fee to Southern Company of $201 million;
the attention of our management may have been diverted to the merger rather than to our operations and the pursuit of other opportunities that could have been beneficial to us;
the potential loss of key personnel during the pendency of the merger as employees may experience uncertainty about their future roles with the combined company;
we will have been subject to certain restrictions on the conduct of our business, which may prevent us from making certain acquisitions or dispositions or pursuing certain business opportunities while the merger is pending; and
the trading price of our common stock may decline to the extent that the current market price reflects a market assumption that the merger will be completed.
A failure to complete the merger may also result in negative publicity, additional litigation against the company or its directors and officers, and a negative impression of the company in the investment community. The occurrence of any of these events individually or in combination could have a material adverse effect on our results of operations or the trading price of our common stock.
We are subject to contractual restrictions in the Merger Agreement that may hinder operations pending the merger.
The Merger Agreement restricts the Company, without Southern Company's consent, from making certain acquisitions and taking other specified actions until the merger occurs or the Merger Agreement terminates. For instance, the Company is limited in the amount of indebtedness for borrowed money it may incur and additional common shares that it may issue. These restrictions may prevent us from pursuing otherwise attractive business opportunities and making other changes to our business prior to completion of the merger or termination of the Merger Agreement.
We will be subject to various uncertainties while the merger is pending that may cause disruption and may make it more difficult to maintain relationships with employees, suppliers or customers.
Uncertainty about the effect of the merger on employees, suppliers and customers may have an adverse effect on us. Although we intend to take steps designed to reduce any adverse effects, these uncertainties may impair our abilities to attract, retain and motivate key personnel until the merger is completed and for a period of time thereafter, and could cause customers, suppliers and others that deal with us to seek to change or terminate existing business relationships with us or not enter into new relationships or transactions.
Employee retention and recruitment may be particularly challenging prior to the completion of the merger, as employees and prospective employees may experience uncertainty about their future roles with the combined company. If, despite our retention and recruiting efforts, key employees depart or fail to continue employment with us because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company, our financial results could be adversely affected. Furthermore, the combined company’s operational and financial performance following the merger could be adversely affected if it is unable to retain key employees and skilled workers. The loss of the services of key employees and skilled workers and their experience and knowledge regarding our business could adversely affect the combined company’s future operating results and the successful ongoing operation of its businesses.



ITEM 1B.   UNRESOLVED STAFF COMMENTS
We do not have any unresolved comments from the SEC staff regarding our periodic or current reports under the Securities Exchange Act of 1934, as amended.
ITEM 2.   PROPERTIES
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.
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, 2015, our distribution operations segment owned approximately 81,300 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 approximately 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 total LNG storage capacity of approximately 7.6 Bcf. In addition, we own one propane storage facility in Virginia with 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, Inc., 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 any expansion of our operations.
ITEM 3.   LEGAL PROCEEDINGS
The nature of our business ordinarily results in periodic regulatory proceedings before various state and federal authorities. In addition, we are party as both plaintiff and defendant to a number of lawsuits related to our business on an ongoing basis. Management believes that the outcome of all regulatory proceedings and litigation in which we are currently involved will not have a material adverse effect on our consolidated financial condition or results of operations.
For more information regarding our regulatory proceedings and litigation, see Note 12 to our consolidated financial statements under the caption “Litigation” under Item 8 herein.
ITEM 4.   MINE SAFETY DISCLOSURES
Not applicable.



PART II
ITEM 5.   MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Holders of Common Stock, Stock Price and Dividend Information
Our common stock is listed on the New York Stock Exchange under the ticker symbol GAS. At February 5, 2016, there were 20,743 record holders of our common stock. Quarterly information concerning our high and low stock prices and cash dividends paid in 2015 and 2014 is as follows:
 
 
Sales price of common stock
 
Cash dividend per
common share
 
 
 
Sales price of common stock
 
Cash dividend per
common share
Quarter ended:
 
High
 
Low
 
 
Quarter ended:
 
High
 
Low
 
March 31, 2015
 
$
57.75

 
$
46.50

 
$
0.51

 
March 31, 2014
 
$
49.84

 
$
45.17

 
$
0.49

June 30, 2015
 
51.88

 
46.45

 
0.51

 
June 30, 2014
 
55.10

 
48.29

 
0.49

September 30, 2015 (1)
 
63.37

 
46.36

 
0.51

 
September 30, 2014
 
55.30

 
48.72

 
0.49

December 31, 2015
 
63.99

 
60.55

 
0.51

 
December 31, 2014
 
56.67

 
50.10

 
0.49

 
 
 
 
 
 
$
2.04

 
 
 
 
 
 
 
$
1.96

(1) On August 23, 2015, we entered into the Merger Agreement with Southern Company.
We have paid 272 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" under the captions "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, legal requirements and other factors.
Issuer Purchases of Equity Securities
Except for common stock returned to us by employees in satisfaction of withholding tax requirements and exercise consideration for stock options, there were no purchases of our common stock by us or any affiliated purchasers during the three months ended December 31, 2015. There were 93,842 shares of common stock returned to us by employees related to equity awards for the three months ended December 31, 2015.



ITEM 6.   SELECTED FINANCIAL DATA
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 on our Consolidated Statements of Income. The operations of our former Tropical Shipping business, which was sold during 2014, are reflected as discontinued operations in 2014 and all prior periods have been recast to reflect the discontinued operations. Material changes from 2013 to 2014 and 2014 to 2015 are due primarily to increased earnings from our wholesale services segment in 2014 that resulted mainly from the extreme weather and associated natural gas price volatility. 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
 
2015
 
2014
 
2013
 
2012
 
2011
Income statement data
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
$
3,941

 
$
5,385

 
$
4,209

 
$
3,562

 
$
2,305

Income from continuing operations
 
373

 
580

 
308

 
274

 
179

(Loss) income from discontinued operations, net of tax
 

 
(80
)
 
5

 
1

 

Net income
 
373

 
500

 
313

 
275

 
179

Less net income attributable to the noncontrolling interest
 
20

 
18

 
18

 
15

 
14

Net income attributable to AGL Resources
 
$
353

 
$
482

 
$
295

 
$
260

 
$
165

Net income attributable to AGL Resources
 
 

 
 

 
 

 
 

 
 

Income from continuing operations attributable to AGL Resources
 
$
353

 
$
562

 
$
290

 
$
259

 
$
165

(Loss) income from discontinued operations, net of tax
 

 
(80
)
 
5

 
1

 

Net income attributable to AGL Resources
 
$
353

 
$
482

 
$
295

 
$
260

 
$
165

Per common share information
 
 

 
 

 
 

 
 

 
 

Diluted weighted average common shares outstanding
 
119.9

 
119.2

 
118.3

 
117.5

 
80.9

Diluted earnings (loss) per common share
 
 

 
 

 
 

 
 

 
 

Continuing operations
 
$
2.94

 
$
4.71

 
$
2.45

 
$
2.20

 
$
2.04

Discontinued operations
 

 
(0.67
)
 
0.04

 
0.01

 

Diluted earnings per common share attributable to AGL Resources common shareholders
 
$
2.94

 
$
4.04

 
$
2.49

 
$
2.21

 
$
2.04

Cash dividends declared per common share
 
$
2.04

 
$
1.96

 
$
1.88

 
$
1.74

 
$
1.90

Dividend payout ratio
 
69
%
 
49
%
 
76
%
 
79
%
 
93
%
Dividend yield (1)
 
3.2
%
 
3.6
%
 
4.0
%
 
4.4
%
 
4.5
%
Price range:
 
 

 
 

 
 

 
 

 
 

High
 
$
63.99

 
$
56.67

 
$
49.31

 
$
42.88

 
$
43.69

Low
 
$
46.36

 
$
45.17

 
$
38.86

 
$
36.59

 
$
34.08

Close (2)
 
$
63.81

 
$
54.51

 
$
47.23

 
$
39.97

 
$
42.26

Market value (2)
 
$
7,681

 
$
6,522

 
$
5,615

 
$
4,711

 
$
4,946

Balance sheet data (2)
 
 

 
 

 
 

 
 

 
 

Total assets (3) (4)
 
$
14,754

 
$
14,888

 
$
14,528

 
$
14,051

 
$
13,841

Property, plant and equipment, net
 
9,791

 
9,090

 
8,643

 
8,205

 
7,741

Long-term debt (4)
 
3,820

 
3,781

 
3,791

 
3,533

 
3,555

Total equity
 
3,975

 
3,828

 
3,613

 
3,391

 
3,305

Financial ratios (2)
 
 

 
 

 
 

 
 

 
 

Debt
 
55
%
 
56
%
 
58
%
 
59
%
 
60
%
Equity
 
45
%
 
44
%
 
42
%
 
41
%
 
40
%
Total
 
100
%
 
100
%
 
100
%
 
100
%
 
100
%
Return on average equity
 
9.0
%
 
13.0
%
 
8.4
%
 
7.8
%
 
6.4
%
(1)
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.
(2)
As of the last day of the fiscal period.
(3)
Total assets for 2011-2013 include assets held for sale, which reflect the assets of our former Tropical Shipping business.
(4)
Total assets and long-term debt for 2011-2014 have been adjusted to reflect the netting of debt issuance costs with its debt carrying amount in accordance with our 2015 adoption of new accounting guidance related to this balance sheet presentation.



ITEM 7.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Executive Summary
We are an energy services holding company whose principal business is the safe, reliable and cost-effective 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 our primary business. We have four reportable segments – 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 discontinued operations. See Note 15 to our consolidated financial statements under Item 8 herein for additional information regarding discontinued operations. The following table shows the proportion of certain financial metrics attributable to our segments.
 
 
EBIT
 
Assets
 
Capital expenditures
 
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
Distribution operations
 
76
 %
 
52
 %
 
84
 %
 
85
 %
 
81
 %
 
82
%
 
93
%
 
93
%
 
93
%
Retail operations
 
20

 
12

 
20

 
5

 
5

 
5

 
1

 
1

 
1

Wholesale services
 
14

 
38

 

 
6

 
9

 
8

 

 

 

Midstream operations
 
(3
)
 
(1
)
 
(2
)
 
5

 
5

 
5

 
3

 
2

 
2

Other/intercompany eliminations
 
(7
)
 
(1
)
 
(2
)
 
(1
)
 

 

 
3

 
4

 
4

Total
 
100
 %
 
100
 %
 
100
 %
 
100
 %
 
100
 %
 
100
%
 
100
%
 
100
%
 
100
%
Business Objectives Our priorities for 2016 are consistent with the direction we have taken the company over the last several years. We will remain focused on safe and efficient operations across all of our businesses, improving customer satisfaction and awareness of the benefits of our product and investment in infrastructure for the future. Several of our specific business objectives are detailed as follows:
Distribution Operations: Invest necessary capital to enhance and maintain safety and reliability in delivering natural gas; remain an efficiency leader within the industry while maintaining a focus on customer satisfaction; expand the natural gas distribution system and educate energy consumers on the benefits of converting to natural gas. We intend to continue investing in our regulatory infrastructure programs to minimize the lag in recovery of our capital. We continue to effectively manage costs and leverage our shared services model across our businesses to combat inflationary effects. 
Retail Operations: Maintain our current customer base in Georgia and Illinois while continuing to expand into other profitable retail markets and expand our warranty businesses through partnership opportunities with affiliates and third parties. We will focus on products that are responsive to our customers' needs. 
Wholesale Services: 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 relative to other marketers. 
Midstream Operations: Invest in natural gas based projects, some of which remain subject to regulatory approvals, along with our existing pipelines and storage to 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. For additional information on our pipeline projects, see Note 3 and Note 11 to our consolidated financial statements under Item 8 herein and Item 1, “Business” under the caption “Midstream Operations.”
Additionally, we intend to 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 14 to our consolidated financial statements under Item 8 herein and Item 1, “Business.”
Performance and Non-GAAP Measures We evaluate segment performance using the measures of EBIT and operating margin. EBIT includes operating income and other income and expenses and excludes interest expense and income taxes, 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 expenses, depreciation and amortization, taxes other than income taxes, merger-related expenses, goodwill impairment charges and the gain or loss on the sale of our assets, which are included in our calculation of operating income as calculated in accordance with GAAP and reflected on our Consolidated Statements of Income.
We believe that the presentation of operating margin provides useful information to management and investors regarding 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 further believe that operating margin at our retail operations, wholesale services and midstream operations segments allows us to focus on a direct measure of operating margin before overhead costs.



We present the non-GAAP measure of diluted earnings per share - as adjusted, which exclude merger-related expenses and a non-cash goodwill impairment charge at midstream operations. As we do not regularly engage in transactions of the magnitude of the proposed merger with Southern Company, and consequently do not regularly incur merger expenses of correlative size, we believe presenting diluted earnings per share excluding merger expenses provides investors with an additional measure of our core operating performance. We also have chosen to exclude a non-cash goodwill impairment related to our midstream operations segment because management believes that investors may find it useful to assess our core operating performance without this non-cash item.
Operating margin and diluted earnings per share - as adjusted should not be considered as alternatives to, or more meaningful indicators of, our operating performance than net income attributable to AGL Resources, operating income or diluted earnings per share from continuing operations as determined in accordance with GAAP. In addition, our operating margin and diluted earnings per share - as adjusted may not be comparable to similarly titled measures of other companies.
Summary of Results:
The table below reconciles (i) operating revenues and operating margin to operating income, (ii) EBIT to income before income taxes and net income and (iii) non-GAAP diluted earnings per share - as adjusted to GAAP diluted earnings per common share from continuing operations, together with other consolidated financial information for the last three years.
In millions, except per share amounts
 
2015
 
2014
 
2013
Operating revenues (1)
 
$
3,941

 
$
5,385

 
$
4,209

Cost of goods sold
 
(1,645
)
 
(2,765
)
 
(2,110
)
Revenue tax expense (2)
 
(101
)
 
(130
)
 
(110
)
Operating margin
 
2,195

 
2,490

 
1,989

Operating expenses (3)
 
(1,550
)
 
(1,527
)
 
(1,471
)
Revenue tax expense (2)
 
101

 
130

 
110

Gain on disposition of assets
 

 
2

 
11

Operating income
 
746

 
1,095

 
639

Other income
 
13

 
14

 
16

EBIT
 
759

 
1,109

 
655

Interest expense, net
 
(173
)
 
(179
)
 
(170
)
Income before income taxes
 
586

 
930

 
485

Income tax expense
 
(213
)
 
(350
)
 
(177
)
Income from continuing operations
 
373

 
580

 
308

(Loss) income from discontinued operations, net of tax
 

 
(80
)
 
5

Net income
 
373

 
500

 
313

Less net income attributable to the noncontrolling interest
 
20

 
18

 
18

Net income attributable to AGL Resources
 
$
353

 
$
482

 
$
295

Net income attributable to AGL Resources
 
 

 
 

 
 

Income from continuing operations attributable to AGL Resources
 
$
353

 
$
562

 
$
290

(Loss) income from discontinued operations, net of tax (4)
 

 
(80
)
 
5

Net income attributable to AGL Resources
 
$
353

 
$
482

 
$
295

Per common share data
 
 

 
 

 
 

Diluted earnings per common share from continuing operations
 
$
2.94

 
$
4.71

 
$
2.45

Diluted (loss) earnings per common share from discontinued operations (4)
 

 
(0.67
)
 
0.04

Merger-related expenses
 
0.23

 

 

Goodwill impairment
 
0.07

 

 

Diluted earnings per share - as adjusted
 
$
3.24

 
$
4.04

 
$
2.49

(1)
Our revenues declined significantly in 2015 compared to 2014 primarily due to lower natural gas prices and lower volumes of gas sold to customers due to weather in 2015 that was warmer than the extreme cold experienced in 2014.
(2)
Adjusted for Nicor Gas’ revenue tax expenses, which are passed through directly to customers.
(3)
Operating expenses for 2015 include $44 million of merger-related expenses and a $14 million goodwill impairment charge.
(4)
In September 2014, we sold Tropical Shipping. See Note 15 to our consolidated financial statements under Item 8 herein for additional information.
2015 Results In 2015, our income from continuing operations attributable to AGL Resources decreased by $209 million, or 37%, compared to 2014. This decrease was due primarily to lower consolidated EBIT of $350 million, largely driven by wholesale services, and was partially offset by lower income tax expense of $137 million due to lower earnings in 2015.
Included in the 2015 EBIT were $44 million of merger-related expenses and a $14 million non-cash goodwill impairment charge at our midstream operations segment. Excluding these items and the $314 million year-over-year change in results of wholesale services, EBIT increased by $22 million in 2015, compared to 2014, primarily as a result of the following:
$34 million in additional operating margin at distribution operations from regulatory infrastructure programs, partially offset by $19 million in higher depreciation expense.
$19 million in additional operating margin at retail operations due to the recovery of prior year hedge losses and lower current year derivative losses resulting from changes in natural gas prices.



These increases were partially offset by weather at distribution operations and retail operations due to significantly warmer temperatures in 2015, compared to 2014.
Wholesale services reported $108 million of EBIT in 2015, compared to $422 million in 2014, a decrease of $314 million. In 2014, wholesale services benefited from increased natural gas volatility that was generated by significantly colder-than-normal weather through higher commercial activity and net hedge gains. Wholesale services continued to benefit from market volatility in 2015 and generated EBIT that was significantly higher than its average economic earnings expectation of $50 million.
2014 Results In 2014, our income from continuing operations attributable to AGL Resources 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 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 from a reduction in the estimated cavern capacity as a result of naturally occurring shrinkage, 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 an $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.
The variances for each reportable segment are contained within the year-over-year discussions on the following pages.
Proposed Merger With Southern Company In August 2015, we entered into the Merger Agreement with Southern Company, which, based on the number of common shares and the fair value of debt outstanding as of December 31, 2015, reflects an estimated business enterprise value of AGL Resources of $13.0 billion, including a total equity value of $7.9 billion. When the merger becomes effective, which is expected to occur in the second half of 2016, each share of our common stock, other than certain excluded shares, will convert into the right to receive $66 in cash, without interest, less any applicable withholding taxes. Completion of the merger is conditioned upon, among other things, the approval of certain state utility and other regulatory agencies. On November 19, 2015, the proposed merger was approved by our shareholders at a special meeting. At closing, the transaction is expected to create the second largest utility in the U.S. by customer base and we will become a wholly owned subsidiary of Southern Company and continue to maintain our own management team. For additional information relating to this transaction, see Note 2 and Note 12 to our consolidated financial statements under Item 8 herein. See Item 1A, "Risk Factors" herein for information on the merger-related risks.
Results of Operations
Operating Revenues We generate the majority of our operating revenues through the sale, distribution and storage of natural gas. Our consolidated revenues include an estimate of revenues from natural gas distributed, but not yet billed to our 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
 
2015
 
2014
 
2013
Residential
 
$
2,129

 
$
2,877

 
$
2,422

Commercial
 
617

 
861

 
696

Transportation
 
526

 
458

 
487

Industrial
 
203

 
242

 
180

Other (1)
 
466

 
947

 
424

Total operating revenues
 
$
3,941

 
$
5,385

 
$
4,209

(1)
Includes significantly higher-than-normal revenues at wholesale services in 2014, which are not indicative of future performance.
Operating metrics Our operating metrics of weather impact, customer count, natural gas volumes and the seasonality of our operating results are presented below.
Weather We measure weather and its effect on our business by using Heating Degree Days. 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 regulatory mechanisms, such as weather normalization, which limit our exposure to weather changes within typical ranges in each of our utilities’ respective service areas. However, our utility customers in Illinois and our retail operations customers in Georgia can be impacted by warmer- or colder-than-normal weather. Additionally, we utilize weather hedges at distribution operations and retail operations to reduce negative earnings impacts in the event of warmer-than-normal weather, while retaining all of the earnings upside in the event of colder-than-normal weather for distribution operations in Illinois and most of the earnings upside for our retail operations. We also consider operating costs that may vary with the effects



of weather, particularly in periods that are significantly colder-than-normal. The following table presents the Heating Degree Days information for those locations.
 
 
Years ended December 31,
 
2015 vs. 2014
 
2014 vs. 2013
 
2015 vs. normal
 
2014 vs. normal
 
2013 vs. normal
 
 
Normal (1)
 
2015
 
2014
 
2013
 
(warmer)
 
colder
 
(warmer)
 
colder
 
colder
Illinois (2)
 
5,845

 
5,433

 
6,556

 
6,305

 
(17
)%
 
4
%
 
(7
)%
 
12
%
 
8
%
Georgia
 
2,628

 
2,204

 
2,882

 
2,689

 
(24
)%
 
7
%
 
(16
)%
 
10
%
 
2
%
(1)
Normal represents the 10-year average from January 1, 2005 through December 31, 2014, 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 5,600 for the 12 months from 1998 through 2007.
In 2015, we experienced weather in Illinois that was 7% warmer-than-normal and 17% warmer than 2014. In the first quarter of 2015 weather in Illinois was 10% colder-than-normal, while weather in the fourth quarter of 2015 was 28% warmer-than-normal in Illinois. Since we hedged our Illinois weather risk for these quarterly periods separately and hedged only exposure for warmer-than-normal weather, the EBIT impact of weather for the year was favorable by $2 million, net of the impact of our weather hedging for distribution operations. The colder-than-normal weather in Illinois in 2014 primarily drove an EBIT increase of $22 million, for distribution operations, based on 10-year normal weather. For our retail operations in Georgia, weather in 2015 was 16% warmer-than-normal and 24% warmer than the same period last year. Similar to our strategy for distribution operations, because we hedged weather risk for our retail operations for the first and fourth quarters separately and hedged exposure for warmer-than-normal weather, the EBIT impact of weather for the year was slightly unfavorable by $1 million in 2015. The colder-than-normal weather increased EBIT by $8 million in 2014 compared to expected levels based on 10-year normal weather for our retail operations.
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 presented in the following table highlight the average number of customers to which we provided services for the specified periods.
 
 
Years ended December 31,
 
2015 vs. 2014 change
 
2014 vs. 2013 change
In thousands
 
2015
 
2014
 
2013
 
#
 
%
 
#
 
%
Distribution operations customers (1)
 
4,526

 
4,497

 
4,479

 
29

 
0.6
 %
 
18

 
0.4
 %
Retail operations
 
 

 
 

 
 

 
 

 
 

 
 

 
 

Energy customers (2)
 
645

 
628

 
619

 
17

 
3
 %
 
9

 
1
 %
Service contracts (3)
 
1,171

 
1,182

 
1,127

 
(11
)
 
(1
)%
 
55

 
5
 %
Market share in Georgia
 
29.7
%
 
30.6
%
 
31.4
%
 
 

 
(0.9
)%
 
 

 
(0.8
)%
(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 compared to 2013.
(2)
The increase from 2013 to 2014 is primarily due to the addition of approximately 33,000 residential and commercial customer relationships acquired in Illinois in June 2013.
(3)
Includes approximately 43,000 customer warranty contracts acquired in Connecticut and Massachusetts in the second half of 2015.
We anticipate overall customer growth trends at distribution operations for 2015 to continue in 2016 as we expect continued improvement in the economy, the related housing market and 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 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 2016, we intend to continue efforts in our retail operations segment to enter into targeted markets and expand energy customers and 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, as shown in the following table, illustrate the effects of weather and customer demand for natural gas compared to the prior year. Wholesale services’ physical sales volumes represent the daily average natural gas volumes sold to our customers.
 
 
Year ended December 31,
 
2015 vs. 2014 % change
 
2014 vs. 2013 % change
Distribution operations (In Bcf)
 
2015
 
2014
 
2013
 
 
Firm
 
695

 
766

 
720

 
(9
)%
 
6
 %
Interruptible
 
99

 
106

 
111

 
(7
)
 
(5
)
Total
 
794

 
872

 
831

 
(9
)%
 
5
 %
Retail operations (In Bcf)
 
 

 
 

 
 

 
 

 
 

Georgia firm
 
35

 
41

 
38

 
(15
)%
 
8
 %
Illinois
 
13

 
17

 
9

 
(24
)
 
89

Other (includes Florida, Maryland, Michigan, New York and Ohio)
 
11

 
10

 
8

 
10

 
25

Wholesale services
 
 

 
 

 
 

 
 

 
 

Daily physical sales (Bcf/day)
 
6.79

 
6.32

 
5.73

 
7
 %
 
10
 %

Within midstream operations, 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 its earnings and maximize the value of its investments.
Our midstream operations storage business is cyclical, and the abundant supply of natural gas in recent years and resulting lack of market and price volatility have negatively impacted the profitability of our storage facilities. The rates at which we may re-contract expiring capacity may not be as high as expected and may also remain below historical averages in 2016. The prices for natural gas storage capacity are expected to increase as supply and demand quantities reach equilibrium with continued economic improvement, expected exports of LNG, and projected demand increases in response to low prices and expanded uses for natural gas. The following table contains the overall monthly average firm subscription rates per facility and amount of firm capacity subscription for all periods presented. These amounts exclude 5 Bcf contracted by Sequent as of December 31, 2015, at an average monthly rate of $0.080 and 7 Bcf as of December 31, 2014, at an average monthly rate of $0.050.
 
 
December 31, 2015
 
December 31, 2014
 
 
Average rates
(per dekatherm)
 
Firm capacity under subscription (Bcf)
 
Average rates
(per dekatherm)
 
Firm capacity under subscription (Bcf)
Jefferson Island
 
$
0.092

 
4.2

 
$
0.108

 
4.6

Golden Triangle
 
0.041

 
5.0

 
0.114

 
5.0

Central Valley
 
0.047

 
4.0

 
0.062

 
2.5

Seasonality of our Results During the Heating Season, natural gas usage and operating revenues are generally higher as more customers are connected to our distribution systems and natural gas usage is higher in periods of colder weather. Occasionally in the summer, wholesale services' operating revenues are impacted due to peak usage by power generators in response to summer energy demands. Seasonality also affects the comparison of certain Consolidated Balance Sheets items across quarters, including receivables, unbilled revenue, inventories and short-term debt. However, these items are comparable when reviewing our annual results. Our base operating expenses, excluding cost of goods sold, interest expense, bad debt expense and certain incentive compensation costs, are incurred relatively equally over any given year. Thus, our operating results can vary significantly from quarter to quarter as a result of seasonality, which is illustrated in the table below.
 
 
Percent generated during Heating Season
 
 
Revenues
 
EBIT
2015
 
70
%
 
80
%
2014
 
73

 
81

2013
 
68

 
72




Segment Information
Three years of operating margin, operating expenses and EBIT information for each of our segments is contained in the following table. See Note 14 to our consolidated financial statements under Item 8 herein for additional segment information.
 
 
Operating Margin (1) (2)
 
Operating Expenses (2)
 
EBIT (1)
In millions
 
2015
 
2014
 
2013
 
2015 (3)
 
2014
 
2013
 
2015
 
2014
 
2013 (4)
Distribution operations
 
$
1,657

 
$
1,648

 
$
1,615

 
$
1,086

 
$
1,075

 
$
1,083

 
$
580

 
$
581

 
$
546

Retail operations
 
317

 
311

 
294

 
165

 
179

 
162

 
152

 
132

 
132

Wholesale services
 
183

 
501

 
39

 
71

 
79

 
53

 
108

 
422

 
(3
)
Midstream operations
 
36

 
31

 
41

 
62

 
50

 
46

 
(23
)
 
(17
)
 
(10
)
Other
 
7

 
7

 
8

 
70

 
22

 
25

 
(58
)
 
(9
)
 
(10
)
Intercompany eliminations
 
(5
)
 
(8
)
 
(8
)
 
(5
)
 
(8
)
 
(8
)
 

 

 

Consolidated
 
$
2,195

 
$
2,490

 
$
1,989

 
$
1,449

 
$
1,397

 
$
1,361

 
$
759

 
$
1,109

 
$
655

(1)
Operating margin is a non-GAAP measure. A reconciliation of operating margin to operating revenues and operating income, and a reconciliation of EBIT to income before income taxes and net income is contained in “Results of Operations” herein.
(2)
Operating margin and operating expenses are adjusted for revenue tax expenses, which are passed through directly to our customers.
(3)
Operating expenses for 2015 include a $14 million goodwill impairment charge recorded during the third quarter at midstream operations and $44 million of merger-related expenses recorded within our other segment.
(4)
EBIT for 2013 includes an $11 million pre-tax gain on the sale of Compass Energy in wholesale services and an $8 million pre-tax loss associated with the termination of the Sawgrass Storage project within midstream operations.
Distribution Operations Our distribution operations segment is the largest component of our business and is subject to regulation and oversight by agencies in each of the states we serve. These agencies approve natural gas rates designed to provide us the opportunity to generate revenues to recover the cost of natural gas delivered to our customers and our fixed and variable costs, such as depreciation, interest, maintenance and overhead costs, and to earn a reasonable return for our shareholders.
With the exception of Atlanta Gas Light, our second largest utility, the earnings of our regulated utilities can be affected by customer consumption patterns that are a function of weather conditions, price levels for natural gas and general economic conditions that may impact our customers’ ability to pay for natural gas consumed. We have various weather mechanisms, such as weather normalization mechanisms and weather derivative instruments, that limit our exposure to weather changes within typical ranges in their respective service areas.
In millions
 
2015
 
2014
EBIT - prior year
 
$
581

 
$
546

Operating margin
 
 

 
 

Increase from regulatory infrastructure programs, primarily at Atlanta Gas Light and Nicor Gas
 
34

 
10

Increase mainly driven by non-weather-related customer usage and growth
 
13

 
22

Decrease in rider program recoveries at Nicor Gas, offset by operating expenses below
 
(18
)
 
(12
)
(Decrease) increase in weather-related customer usage, net of weather hedging
 
(20
)