10-KT/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

( ) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE YEAR ENDED DECEMBER 31, 2013

( X )  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM January 1, 2014 TO September 30, 2014

Commission File Number	Registrant, Address and Telephone Number	State of Incorporation	IRS Employer Identification Number
2-38960	Alabama Gas Corporation 2101 6th Avenue North Birmingham, Alabama 35203-2749 (205) 326-8100	Alabama	63-0022000

Securities Registered Pursuant to Section 12(b) of the Act: NONE

Securities Registered Pursuant to Section 12(g) of the Act: NONE

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES () NO (X )

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

YES ( ) NO (X)

Indicate by a check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities and Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. YES (X) NO ( )

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

YES (X) NO ( )

Indicate by a check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ( )

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ( ) Accelerated filer ( ) Non-accelerated filer (X) Smaller reporting company ( )

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES ( ) NO (X)

As of November 25, 2014, there were 1,972,052 shares of the registrant's common stock outstanding.

All of the registrant's equity securities are owned by The Laclede Group, Inc., its parent company and a 1934 Act Reporting Company. The registrant meets all of the conditions set forth in General Instruction I(1) (a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format pursuant to General Instruction I(2).

DOCUMENTS INCORPORATED BY REFERENCE

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	ALABAMA GAS CORPORATION FORM 10-K FOR THE TRANSITION PERIOD ENDED SEPTEMBER 30, 2014
TABLE OF CONTENTS
		Page
	PART I
Industry Glossary		3
Forward-Looking Statements		4
Item 1.	Business	5
Item 1A.	Risk Factors	8
Item 1B.	Unresolved Staff Comments	12
Item 2.	Properties	12
Item 3.	Legal Proceedings	12
	PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	13
Item 6.	Selected Financial Data	14
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	15
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	23
Item 8.	Financial Statements and Supplementary Data	24
Item 9.	Changes in and Disagreements With Accountants on Accounting and	51
	Financial Disclosure
Item 9A.	Controls and Procedures	52
Item 9B.	Other Information	53
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	54
Signatures		55
INDEX TO EXHIBITS		56

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PART I

INDUSTRY GLOSSARY For a more complete definition of certain terms defined below, as well as other terms and concepts applicable to successful efforts accounting, please refer to Rule 4-10(a) of Regulation S-X, promulgated pursuant to the Securities Act of 1933 and the Securities Exchange Act of 1934, each as amended.
APSC	Alabama Public Service Commission
ASC	Accounting Standards Codification
Basis	The difference between the futures price for a commodity and the corresponding cash spot price. This commonly is related to factors such as product quality, location and contract pricing.
Bcf	Billion Cubic Feet
CCM	Cost Control Mechanism
Energen	Energen Corporation, former owner of Alabama Gas Corporation before September 2, 2014.
EPA	U.S. Environmental Protection Agency
ESR	Enhanced Stability Reserve
FASB	Financial Accounting Standards Board
GAAP	Accounting Principles Generally Accepted in the United States of America
GSA	Gas Supply Adjustment
Laclede Group	The Laclede Group, Inc., parent company of Alabama Gas Corporation as of September 2, 2014.
LNG	Liquefied Natural Gas, which is natural gas that is liquefied by reducing the temperature to negative 260 degrees Fahrenheit. LNG typically is used to supplement traditional natural gas supplies during periods of peak demand.
Odorization	The adding of odorant to natural gas which is a characteristic odor so that leaks can be readily detected by smell.
RSE	Rate Stabilization and Equalization
SEC	U.S. Securities and Exchange Commission
Transportation	Moving gas through pipelines on a contract basis for others.

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FORWARD-LOOKING STATEMENTS

Certain matters discussed in this report, excluding historical information, include forward-looking statements. Certain words, such as “may,” “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan,” “seek,” and similar words and expressions identify forward-looking statements that involve uncertainties and risks. Future developments may not be in accordance with our current expectations or beliefs and the effect of future developments may not be those anticipated. Among the factors that may cause results to differ materially from those contemplated in any forward-looking statement are:

• weather conditions and catastrophic events, particularly severe weather in the natural gas producing areas of the country;

• volatility in gas prices, particularly sudden and sustained changes in natural gas prices;

• the impact of changes and volatility in natural gas prices on our competitive position in relation to suppliers of alternative heating sources, such as electricity;

• changes in gas supply and pipeline availability, including decisions by natural gas producers to reduce production or shut in producing natural gas wells, expiration of existing supply and transportation arrangements that are not replaced with contracts with similar terms and pricing, as well as other changes that impact supply for and access to the markets in which we transact business;

• legislative, regulatory and judicial mandates and decisions, some of which may be retroactive, including those affecting

• allowed rates of return

• incentive regulation

• industry structure

• gas supply adjustment provisions

• rate design structure and implementation

• regulatory assets

• non-regulated and affiliate transactions

• franchise renewals

• environmental or safety matters, including the potential impact of legislative and regulatory actions related to climate change and pipeline safety

• taxes

• pension and other postretirement benefit liabilities and funding obligations

• accounting standards;

• the results of litigation;

• the availability and access, in general, of funds to meet our debt obligations prior to or when they become due and to fund our operations and necessary capital expenditures, either through (i) cash on hand, (ii) operating cash flow, or (iii) access to the capital or credit markets;

• retention of, ability to attract, ability to collect from, and conservation efforts of, customers;

• our ability to comply with all covenants in our indentures and credit facilities any violations of which, if not cured in a timely manner, could trigger a default of our obligations;

• capital and energy commodity market conditions, including the ability to obtain funds with reasonable terms for necessary capital expenditures and general operations and the terms and conditions imposed for obtaining sufficient gas supply;

• discovery of material weakness in internal controls;

• our recent acquisition by Laclede Group and the costs and other impacts of the associated integration of our operations with those of Laclede Group; and

• employee workforce issues, including with respect to those associated with our integration with Laclede Group.

Readers are urged to consider the risks, uncertainties, and other factors that could affect our business as described in this report. All forward-looking statements made in this report rely upon the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. We do not, by including this statement, assume any obligation to review or revise any particular forward-looking statement in light of future events.

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ITEM 1.BUSINESS

($ in millions, customer count in actual)

Overview

Alabama Gas Corporation (the Company or Alagasco) was formed in 1948 by the merger of Alabama Gas Company into Birmingham Gas Company, the predecessors of which had been in existence since the mid-1800s. On April 5, 2014, The Laclede Group, Inc. (Laclede Group) entered into a Stock Purchase Agreement (the SPA) to acquire from Energen Corporation (Energen) all of the outstanding shares of stock of the Company (the Acquisition). On September 2, 2014, Laclede Group and Energen completed the Acquisition, with an effective time under the SPA of 11:59 p.m. on August 31, 2014

Effective September 2, 2014, the Company amended its bylaws to change the Company’s fiscal year from beginning January 1st and ending on December 31st, to beginning October 1st and ending on September 30th. As a result, this Form 10-K is a transition report and includes financial information for the period from January 1, 2014 through September 30, 2014. Subsequent to this report, the Company's annual reports on Form 10-K will cover the fiscal year October 1st to September 30th. The period beginning January 1, 2014 through September 30, 2014 is referred to as the “current period” or “transition period” and the period beginning October 1, 2014 through September 30, 2015 as “fiscal 2015”.

The information the Company files or furnishes to the Securities and Exchange Commission (SEC), including annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K and their amendments are available on our website, www.alagasco.com, and in the Investor Services section under SEC Filings as soon as reasonably practical after the information is filed with or furnished to the SEC.

The Company is the largest natural gas distribution utility in the State of Alabama. The Company purchases natural gas through interstate and intrastate suppliers and distributes the purchased gas through its distribution facilities for sale to residential, commercial and industrial customers and other end-users of natural gas. The Company also provides transportation services to large industrial and commercial customers located on its distribution system. These transportation customers, using the Company as their agent or acting on their own, purchase gas directly from marketers or suppliers and arrange for delivery of the gas into the Company's distribution system. The Company charges a fee to transport such customer-owned gas through its distribution system to its customers’ facilities.

The Company’s service territory is located in central and north Alabama and includes 186 cities and communities in 32 counties. The aggregate population of the counties served by the Company is estimated to be approximately 3 million . Among the cities served by the Company are Birmingham, the center of the largest metropolitan area in Alabama, and Montgomery, the state capital. During the transition period ended September 30, 2014, the Company served an average of 391,840 residential customers and 31,236 commercial, industrial and transportation customers. The Company’s distribution system includes approximately 11,000 miles of main and more than 12,000 miles of service lines, as well as odorization and regulation facilities, and customer meters.

Natural Gas Supply

The Company's fundamental gas supply strategy is to meet the two-fold objective of 1) ensuring that the gas supplies it acquires are dependable and delivered when needed and 2) insofar as is compatible with that dependability, purchasing gas that is economically priced. In structuring its natural gas supply portfolio, the Company continues to focus on natural gas assets that are strategically positioned to meet the Company's primary objectives.

The Company’s distribution system is connected to two major interstate natural gas pipeline systems, Southern Natural Gas Company, L.L.C. (Southern Natural Gas) and Transcontinental Gas Pipe Line Company, LLC (Transco). It is also connected to two intrastate natural gas pipeline systems and to the Company's four liquefied natural gas (LNG) facilities.

The Company purchases natural gas from various natural gas producers and marketers. Certain volumes are purchased under firm contractual commitments with other volumes purchased on a spot market basis. The purchased volumes are delivered to the Company’s system using a variety of firm transportation, interruptible transportation and storage capacity arrangements designed to meet the system’s varying levels of demand. The Company’s LNG facilities can provide the system with up to an additional 0.2 billion cubic feet per day (Bcf/d) of natural gas to meet peak day demand.

In the transition period ended September 30, 2014, the Company purchased natural gas from 18 different suppliers to meet current gas sales, storage injection, and LNG liquefaction requirements, of which eight are under long-term supply agreements. Approximately 46.5 Bcf was transported by Southern Natural Gas, 4.4 Bcf by Transco, and 3.9 Bcf through intrastate pipelines to the Company delivery points for its residential, commercial, and industrial customers.

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The 2014 calendar year peak day send out for the Company was 0.62 Bcf on Monday, January 6, 2014, when the average temperature was 15 degrees Fahrenheit in Birmingham, of which 55% was met with supplies transported through Southern Natural Gas, Transco, and intrastate facilities; 28% with the Company’s LNG peak shaving facilities, and 17% with upstream underground storage assets.

As of September 30, 2014, the Company had the following contracts in place for firm natural gas pipeline transportation:

(Bcf/d)	September 30, 2014
Southern Natural Gas firm transportation	0.1
Southern Natural Gas firm transportation no notice	0.2
Transco firm transportation	0.1

Natural Gas Storage

The Company has a contractual right to store 12.5 Bcf of gas with Southern Natural Gas, 0.2 Bcf of gas with Transco and 0.2 Bcf with Tennessee Gas Pipeline. In addition, the Company has 1.8 Bcf of LNG storage.

Regulatory Matters

Rate Stabilization and Equalization (RSE)

As an Alabama utility, the Company is subject to regulation by the APSC which established the RSE rate-setting process in 1983. The Company’s current RSE order had an original term extending through December 31, 2014. On December 20, 2013, the APSC issued a final written order modifying the RSE effective January 1, 2014 extending the term of the order beyond September 30, 2018, unless the APSC enters an order to the contrary in a manner consistent with law. In the event of unforeseen circumstances, whether physical or economic, of the nature of force majeure and including a change in control the APSC and the Company will consult in good faith with respect to modifications, if any. The Company’s allowed range of return on average common equity is 10.5 % to 10.95 % with an adjusting point of 10.8 %. The Company is eligible to receive a performance-based adjustment of an additional 5 basis points to the return on equity adjusting point, based on meeting certain customer satisfaction criteria.

Under the RSE, the APSC conducts quarterly reviews to determine whether the Company’s return on average common equity at the end of the Rate Year is within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each Rate Year, effective December 1, and cannot exceed 4% of prior-year revenues. The Company's year-end equity under the RSE is limited to 56.5% of total capitalization, subject to certain adjustments. The inflation-based CCM established by the APSC, allows for annual changes to operations and maintenance (O&M) expense compared to a Base Year, defined as the Company's 2007 actual Rate Year O&M, inflation-adjusted to September 30, 2013 using the Consumer Price Index for All Urban Consumer (Base Year O&M). An "Index Range" is established each Rate Year using Base Year O&M, inflation-adjusted using the June Consumer Price Index for All Urban Consumers for that Rate Year plus or minus 1.75% (Index Range). If Rate Year O&M expense falls within the Index Range, no adjustment is required. If Rate Year O&M expense exceeds the Index Range, three-quarters of the difference is returned to customers through future rate adjustments. To the extent that Rate Year O&M is less than the Index Range, the utility benefits by one-half of the difference through future rate adjustments. Certain items that fluctuate based on situations demonstrated to be beyond the Company’s control may be excluded from the CCM calculation.

The Company’s rate schedules for natural gas distribution charges contain a GSA rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. The Company’s tariff provides a temperature adjustment mechanism, also included in the GSA, which is designed to moderate the impact of departures from normal temperatures on the Company’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment.

In 1998 the APSC approved an Enhanced Stability Reserve (ESR), which was subsequently modified and expanded in 2010. As currently approved, the ESR provides deferred treatment and recovery for the following: (1) extraordinary O&M expenses related to environmental response costs; (2) extraordinary O&M expenses related to self-insurance costs that exceed $1.0 per occurrence; (3) extraordinary O&M expenses, other than environmental response costs and self-insurance costs, resulting from a single force majeure event or multiple force majeure events greater than $0.3 and $0.4, respectively, during a Rate Year; and (4) negative individual large commercial and industrial customer budget revenue variances that exceed $0.4 during a Rate Year.

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Employees

The Company employs approximately 949 employees. The Company believes that its relations with employees are good. Alagasco has labor agreements with three unions. Local Unions 12030, 12030-A of the United Steelworkers and Local Union 548 of the United Association Gas Fitters which make up approximately 44% Alagasco’s employees. Local Union 12030’s contract expires at midnight on December 18, 2014, Local Union 12030-A’s contract expires at midnight on April 30, 2017 and Local Union 548’s contract expires at midnight on June 30, 2016. Alagasco and USW Local Union 12030 will begin contract negotiations around mid-November 2014.

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ITEM 1A. RISK FACTORS

The Company's business and financial results are subject to a number of risks and uncertainties, including those set forth below. The risks described below are those the Company considers to be material. Investors should carefully consider the following information, as well as information contained in the caption "Forward-Looking Statements," Item 7A, and the other documents the Company files with the SEC. This list is not exhaustive, and the Company's management places no priority or likelihood based on the risk descriptions or order of presentation.

Regulation of the Company’s business may impact rates it is able to charge, costs, and profitability.

The APSC regulates many aspects of the Company’s operations, safety, the rates that the Company may charge customers, the terms of service to its customers, transactions with its affiliates, and the rate of return that it is allowed to realize; as well as the accounting treatment for certain aspects of its operations. For further discussion of these accounting matters, see Critical Accounting Policies pertaining to the Company’s operations. The Company’s ability to obtain and timely implement rate increases and rate supplements to maintain the current rate of return depends upon regulatory discretion. There can be no assurance that it will be able to obtain rate increases or rate supplements or continue earning the current authorized rates of return.

The Company could incur additional costs if required to adjust to new laws or regulations, revisions to existing laws or regulations or changes in interpretations of existing laws or regulations such as the Dodd-Frank Act. In addition, as the regulatory environment for the natural gas industry increases in complexity, the risk of inadvertent noncompliance could also increase. If the Company fails to comply with applicable laws and regulations, whether existing or new, it could be subject to fines, penalties or other enforcement action by the authorities that regulate its operations.

Increased inter-dependence on technology may adversely hinder the Company’s business operations and affect its financial condition and results of operations if such technologies fail or are compromised.

Over the last several years, the Company has implemented a variety of technological tools including both Company-owned information technology and technological services provided by outside parties. The failure of these important technologies, or the Company’s inability to have these technologies supported, updated, expanded, or integrated into other technologies, could hinder its business operations and adversely impact its financial condition and results of operations.

Although the Company has, when possible, developed alternative sources of technology and built redundancy into its computer networks and tools, there can be no assurance that these efforts to date would protect against all potential issues related to the loss of any such technologies or their use.

Furthermore, the Company is subject to cyber-security risks primarily related to breaches of security pertaining to sensitive customer, employee, and vendor information maintained by the Company in the normal course of business, as well as breaches in the technology that manages natural gas distribution operations and other business processes. A loss of confidential or proprietary data or security breaches of other technology business tools could adversely affect the Company’s reputation, diminish customer confidence, disrupt operations, and subject the Company to possible financial liability, any of which could have a material effect on the Company’s financial condition and results of operations. The Company closely monitors both preventive and detective measures to manage these risks and maintains cyber risk insurance to mitigate a significant portion, but not all, of these risks and losses. To the extent that the occurrence of any of these cyber events is not fully covered by insurance, it could adversely affect the Company’s financial condition and results of operations.

The Company's ability to meet its customers’ natural gas requirements may be impaired if contracted gas supplies, interstate pipeline and/or storage services are not available or delivered in a timely manner.

In order to meet its customers’ annual and seasonal natural gas demands, the Company must obtain sufficient supplies, interstate pipeline capacity, and storage capacity. If it is unable to obtain these, either from its suppliers’ inability to deliver the contracted commodity or the inability to secure replacement quantities, the Company's financial condition and results of operations may be adversely impacted. If a substantial disruption in interstate natural gas pipelines’ transmission and storage capacity were to occur during periods of heavy demand, the Company’s financial results could be adversely impacted.

The Company is dependent on bank lines of credit and continued access to capital markets to successfully execute its operating strategies.

The Company relies upon bank lines of credit to finance the execution of its operating strategies. The Company is dependent on these capital sources to purchase its natural gas supply and maintain properties. The availability and cost of these credit sources is cyclical and these capital sources may not remain available to the Company, or it may not be able to obtain funds at

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a reasonable cost in the future. The Company’s ability to borrow under existing lines of credit depends on its compliance with the obligations under the lines of credit. In addition, if the Company were to breach any of the financial or other covenants under these agreements, the debt repayment obligations under them could be accelerated. The Company's ability to issue long-term bonds, or to obtain new lines of credit also depends on current conditions in the credit markets. The Company’s access to funds under committed short-term credit facilities, which are currently provided by a number of banks, is dependent on the ability of the participating banks to meet the Company’s funding commitments. Those banks may not be able to meet the Company’s funding commitments if they experience shortages of capital and liquidity. Disruptions in the bank or capital financing markets as a result of economic uncertainty, changing or increased regulation of the financial sector, or failure of major financial institutions could adversely affect the Company’s access to capital and negatively impact the Company’s ability to run its businesses and make strategic investments.

The Company is subject to pipeline safety and system integrity laws and regulations that may require significant expenditures or significant increases in operating costs.

Such laws and regulations affect various aspects of the Company's present and future operations. These laws and regulations require the Company to maintain pipeline safety and system integrity by identifying and reducing pipeline risks. Compliance with these laws and regulations, or future changes in these laws and regulations, may result in increased capital, operating and other costs which may not be recoverable in a timely manner from customers in rates. Failure to comply may result in fines, penalties, or injunctive measures that would not be recoverable from customers in rates and could result in a material effect on the Company's financial condition and results of operations.

Environmental laws and regulations may require significant expenditures or increase operating costs.

The Company is subject to federal, state and local environmental laws and regulations affecting many aspects of its present and future operations. These laws and regulations require the Company to obtain and comply with a wide variety of environmental licenses, permits, inspections, and approvals. Failure to comply with these laws and regulations and failure to obtain any required permits and licenses may result in costs to the Company in the form of fines, penalties or business interruptions, which may be material. In addition, existing environmental laws and regulations could be revised or reinterpreted and/or new laws and regulations could be adopted or become applicable to the Company or its facilities, thereby impacting the Company’s cost of compliance. The discovery of presently unknown environmental conditions, including former manufactured gas plant sites, and claims against the Company under environmental laws and regulations may result in expenditures and liabilities, which could be material. To the extent environmental compliance costs are not fully covered by insurance or recovered in rates from the Company’s customers, those costs may have an adverse effect on the Company's financial condition and results of operations.

Unexpected losses may adversely affect the Company’s financial condition and results of operations.

As with most businesses, there are operations and business risks inherent in the activities of the Company. If, in the normal course of business, the Company becomes a party to litigation, such litigation could result in substantial monetary judgments, fines, or penalties or be resolved on unfavorable terms. In accordance with customary practice, the Company maintains insurance against a significant portion of, but not all, risks and losses. In addition, in the normal course of its operations, the Company may be exposed to loss from other sources, such as bad debt expense or the failure of a counterparty to meet its financial obligations. The Company employs many strategies to gain assurance that such risks are appropriately managed, mitigated, or insured, as appropriate. To the extent a loss is not fully covered by insurance or other risk mitigation strategies, that loss could adversely affect the Company’s financial condition and results of operations.

Workforce risks may affect the Company's financial results.

The Company is subject to various workforce risks, including, but not limited to, the risk that it will be unable to attract and retain qualified personnel; that it will be unable to effectively transfer the knowledge and expertise of an aging workforce to new personnel as those workers retire; and that it will be unable to reach collective bargaining arrangements with the unions that represent certain of its workers, which could result in work stoppages.

Changes in accounting standards may adversely impact the Company's financial condition and results of operations.

The Company is subject to changes in U.S. Generally Accepted Accounting Principles (GAAP), SEC regulations and other interpretations of financial reporting requirements for public utilities. The Company has no control over the impact these changes may have on its financial condition or results of operations nor the timing of such changes. The potential issues associated with rate-regulated accounting, along with other potential changes to GAAP that the U.S. Financial Accounting Standards Board (FASB) may be significant. The FASB continues to consider various changes to U.S. GAAP.

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The Company is involved in legal or administrative proceedings before various courts and governmental bodies that could adversely affect its results of operations, cash flows and financial condition.

The Company is involved in legal or administrative proceeds before various courts and governmental bodies with respect to general claims, rates, environmental issues, gas cost prudence reviews and other matters. Adverse decisions regarding these matters, to the extent they require the Company to make payments in excess of amounts provided for in its financial statements, or to the extent they are not covered by insurance, could adversely affect the Company’s results of operations, cash flows and financial condition.

The Company's liquidity may be adversely affected by delays in recovery of its costs, due to regulation.

In the normal course of business, there may be a lag between when the Company incurs increases in certain of its costs and the time in which those costs are considered for recovery in the ratemaking process. Cash requirements for increased operating costs, increased funding levels of defined benefit pension and postretirement costs, capital expenditures, and other increases in the costs of doing business may require outlays of cash prior to the authorization of increases in rates charged to customers, as approved by the APSC. Accordingly, the Company’s liquidity may be adversely impacted to the extent higher costs are not timely recovered from its customers.

The Company may be adversely affected by economic conditions.

Periods of slowed economic activity generally result in decreased energy consumption, particularly by industrial and large commercial companies. As a consequence, national or regional recessions or other downturns in economic activity could adversely affect the Company's revenues and cash flows or restrict its future growth. Economic conditions in its service territory may also adversely impact the Company’s ability to collect its accounts receivable resulting in an increase in bad debt expenses.

A downgrade in the Company’s credit rating may negatively affect its ability to access capital.

Standard & Poor’s and Moody’s Investors Service, from time to time implement new requirements for various ratings levels. To maintain its current credit ratings in light of any new requirements, the Company may find it necessary to take steps to change the Company’s business plans in ways that may affect the Company’s results of operations. The Company’s credit ratings remain at investment grade, but are subject to review and change by the rating agencies. On December 16, 2013, Standard & Poor’s lowered its debt ratings for the Company from investment grade with a stable outlook to investment grade with a negative outlook. In April 2014, upon the announcement of Laclede Group’s intent to acquire the Company, Standard & Poor’s upgraded the outlook to “positive.” Upon the completion of the acquisition by Laclede Group, Standard & Poor’s upgraded the Company’s debt ratings to A-, stable outlook. If the rating agencies lowered the Company’s ratings, particularly below investment grade, it could significantly limit the Company’s ability to secure new or additional credit and would increase the Company’s costs of borrowing. In addition, the Company would likely be required to pay a higher interest rate in future long-term financings and the Company’s potential pool of investors and funding sources would likely decrease. The Company’s ability to borrow under current or new credit facilities and costs of that borrowing have a direct impact on the Company’s ability to execute operating strategies.

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

There are inherent in gas distribution activities a variety of hazards and operations risks, such as leaks, accidental explosions, including third party damages, and mechanical problems, which could cause substantial financial losses. In addition, these risks could result in serious injury to employees and non-employees, loss of human life, significant damage to property, environmental pollution, impairment of operations, and substantial losses to the Company. 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. These activities may subject the Company to litigation or administrative proceedings from time to time. Such litigation or proceedings could result in substantial monetary judgments, fines, or penalties against the Company or be resolved on unfavorable terms. In accordance with customary industry practices, the Company maintains insurance against a significant portion, but not all, of these risks and losses. To the extent that the occurrence of any of these events is not fully covered by insurance, it could adversely affect the Company’s financial condition and results of operations.

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Because of the highly competitive nature of its business, the Company may not be able to retain existing customers or acquire new customers, which would have an adverse impact on its businesses, operating results and financial conditions.

The Company competes with several municipal gas distributors and other sources of energy such as electricity, fuel oil and propane, primarily on the basis of price, reliability of service and responsiveness to customer service needs. Each operating location operates in its own competitive environment.

If it is unable to compete effectively, the Company may lose existing customers and/or fail to acquire new customers, which would have a material adverse effect on its business, operating results and financial condition.

The Company faces the risk that customers may bypass gas distribution services by gaining distribution directly from interstate pipelines. The Company cannot provide any assurance that increased competition or other changes in legislation, regulation or policies will not have a material adverse effect on its business, financial condition or results of operation.

Changes in the wholesale costs of purchased natural gas supplies may adversely impact the Company’s competitive position compared with alternative energy sources.

The changes in wholesale natural gas prices compared with prices for electricity, fuel oil, coal, propane, or other energy sources may affect the Company’s retention of natural gas customers and adversely impact its financial condition and results of operations.

Significantly warmer-than-normal weather conditions, the effects of global warming and climate change, and other factors that influence customer usage may affect the Company’s sale of heating energy and adversely impact its financial position and results of operations.

The Company’s earnings are primarily generated by the sale of heating energy. However, significantly warmer-than-normal weather conditions in the Company’s service areas and other factors, such as global warming, climate change and alternative energy sources, may result in reduced profitability and decreased cash flows attributable to lower gas sales. Furthermore, continuation of the Company’s current RSE order is subject to regulatory discretion. In addition, the promulgation of regulations by the U.S. Environmental Protection Agency (EPA) to limit greenhouse gas emissions or the potential enactment of Congressional legislation addressing global warming and climate change may result in future additional compliance costs that could impact the Company’s financial conditions and results of operations.

Catastrophic events may adversely affect the Company's facilities and operations.

Catastrophic events such as fires, earthquakes, explosions, floods, tornadoes, hurricanes, tropical storms, terrorist acts, pandemic illness or other similar occurrences could adversely affect the Company's facilities and operations. The Company has emergency planning and training programs in place to respond to events that could cause business interruptions. However, unanticipated events or a combination of events, failure in resources needed to respond to events, or slow or inadequate response to events may have an adverse impact on the Company’s operations, financial condition, and results of operations. The availability of insurance covering catastrophic events may be limited or may result in higher deductibles, higher premiums, and more restrictive policy terms.

The Company’s operations depend upon the use of third party facilities and an interruption of its ability to utilize these facilities may adversely affect its financial condition and results of operations.

The Company is served by third party facilities. These facilities include third party oil and gas gathering, transportation, processing and storage facilities. The Company relies upon such facilities for access to natural gas supplies. Such facilities are typically limited in number and geographically concentrated. An extended interruption of access to or service from these facilities, whether caused by weather events, natural disaster, accident, mechanical failure, criminal act or otherwise could result in material adverse financial consequences to the Company.

The Company is subject to numerous federal, state and local laws and regulations that may require significant expenditures or impose significant restrictions on its operations.

The Company is subject to extensive federal, state and local regulation which significantly influences operations. Although the Company believes that its operations comply with applicable laws and regulations, failure to comply could result in the suspension or termination of operations and subject the Company to administrative, civil and criminal penalties. Federal, state and local legislative bodies and agencies frequently exercise their respective authority to adopt new laws and regulations and to amend, modify and interpret existing laws and regulations.  Such changes can subject the Company to significant tax or cost increases and can impose significant restrictions and limitations on the Company’s operations.

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The Acquisition may not achieve its intended results, including anticipated efficiencies cost savings, and the associated integration efforts may divert management’s attention or result in unanticipated costs.

Although Alagasco and the Laclede Group expect that the Acquisition will result in various benefits, including cost savings and other financial and operational benefits, there can be no assurance regarding when or the extent to which the Company will be able to realize benefits. Achieving the anticipated benefits is subject to a number of uncertainties, including whether the Company can be operated in the manner that the Laclede Group intended. Events outside of the Company’s control, including but not limited to regulatory changes or developments, could also adversely affect the Company’s ability to realize the anticipated benefits from the Acquisition.

In addition, the integration of the Company’s operations with the Laclede Group and its other subsidiaries may be unpredictable, subject to delays or changed circumstances. Accordingly, the Company can give no assurance that it will meet expectations with respect to its costs incurred in connection with such integration. Moreover, the integration may place an additional burden on the Company’s management and internal resources. Unanticipated or increased integration costs and the diversion of management’s attention during the integration process could have an adverse effect on the Company’s business, financial condition and expected operating results.

ITEM 1B.UNRESOLVED STAFF COMMENTS

None.

ITEM 2.PROPERTIES

The primary offices of the Company are located in leased office space in Birmingham, Alabama. See the discussion under Item 1, Business, for further information related to the Company’s business operations. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the future outlook and expectations for the Company. The lease extends through February 28, 2018 and there is no option for renewal.

The properties of the Company consist primarily of its gas distribution system, which includes approximately 11,000 miles of main and more than 12,000 miles of service lines, odorization and regulation facilities, and customer meters. The Company also has four LNG facilities, thirteen operation centers, two business centers, and other related property and equipment, some of which are leased by the Company. Other properties of the Company do not constitute a significant portion of its properties.

For further information on the Company’s leases see Note 7, Commitments and Contingencies, of the Notes to the Financial Statements.

ITEM 3.LEGAL PROCEEDINGS

The Company is involved in litigation, claims, and investigations arising in the normal course of business. Management, after discussion with counsel, believes the final outcomes will not have a material effect on the financial position or results of operations reflected in the financial statements presented herein.

For a description of environmental matters, see Note 7, Commitments and Contingencies, of the Notes to the Financial Statements. For a description of pending regulatory matters of the Company, see Note 3, Regulatory Matters and Note 12, Regulatory Assets and Liabilities, of the Notes to the Financial Statements.

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PART II

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

As of September 2, 2014 the Laclede Group, Inc. owned all of the Company's common stock. Prior to September 2, 2014, Energen owned all of the Company’s common stock. The Company made its first dividend payment to the Laclede Group in September 2014 in the amount of $5.0. The Company’s common stock is not traded on any stock exchange.

Total dividends declared on the common stock for the transition period ended September 30, 2014 and the calendar year ended December 31, 2013 were:

($ millions)	2014		2013
Quarter ended March 31	$	10.8	$	8.4
Quarter ended June 30	10.8		10.4
Quarter ended September 30	15.8		14.5
Quarter ended December 31	n/a		—

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ITEM 6.    SELECTED FINANCIAL DATA

The selected financial data set forth below should be read in conjunction with “Management’s Discussion and Analysis of Results of Operations and Financial Condition” and the Financial Statements and related Notes to Financial Statements included elsewhere in this Transition Report on Form 10-K.

SELECTED FINANCIAL DATA

	Nine Month Period Ended September 30,				Calendar Year Ended December 31,
($ Millions)	2014		2013		2013		2012		2011		2010
Statement of Income Data
Operating revenues	$	417.2	$	390.6	$	533.3	$	451.6	$	535.0	$	619.8
Operating expenses	355.0		331.6		439.6		358.3		448.7		531.4
Operating income	62.2		59.0		93.7		93.3		86.3		88.4
Net income	33.0		37.6		57.4		49.4		46.6		46.9
Balance Sheet
Net utility plant	$	898.7	$	876.6	$	885.5	$	842.7	$	813.5	$	782.7
Total assets	1,424.6		1,134.1		1,198.1		1,182.9		1,166.8		1,167.6
Total shareholder's equity	849.6		364.7		384.6		360.5		344.7		327.3
Long-term debt	249.8		250.0		249.9		250.0		250.2		200.8

SELECTED BUSINESS SEGMENT DATA

	Nine Month Period Ended September 30,						Calendar Year Ended December 31,
($ Millions)	2014			2013			2013			2012			2011			2010
Operating revenues
Residential		$276.7		$	259.5		$	340.6		$	277.7		$	343.7		$	414.9
Commercial and industrial	111.9			103.4			137.0			115.7			136.5			159.7
Transportation	44.9			45.3			61.3			58.9			55.2			57.0
Other (1)	(16.3		)	(17.6		)	(5.6		)	(0.7		)	(0.4		)	(11.8		)
Total		$417.2		390.6			$	533.3		$	451.6		$	535.0		$	619.8
Gas delivery volumes (bcf)
Residential	17.5			15.4			20.3			16.0			21.1			24.5
Commercial and industrial	8.5			7.4			10.0			8.4			10.0			11.0
Transportation	36.1			34.7			47.5			48.1			44.6			46.5
Total	62.1			57.5			77.8			72.5			75.7			82.0
Average number of customers
Residential	391,840			391,932			391,093			393,467			395,766			404,697
Commercial and industrial	31,236			31,254			31,174			31,450			31,840			32,632
Total	423,076			423,186			422,267			424,917			427,606			437,329
($Millions)
Other data
Depreciation and amortization	$	34.4		$	32.7		$	43.9		$	42.3		$	39.9		$	44.0
Capital expenditures	46.2			67.1			86.0			69.9			74.0			92.1

(1) Amount reflects the RSE adjustment related to customer give back. See Regulatory Matters for more details on give back.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

($ in millions, customer count in actual)

Introduction

This section analyzes the financial condition and results of operations of the Company. It includes management’s view of factors that affect its business, explanations of past financial results including changes in earnings and costs from the prior year periods, and their effects on the Company’s overall financial condition and liquidity. Reference is made to “Part I. Item 1A. Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements,” which describe important factors that could cause actual results to differ from expectations and non-historical information contained herein. In addition, the following discussion should be read in conjunction with the audited financial statements and accompanying notes thereto of the Company included in “Item 8. Financial Statements and Supplementary Data.”

The Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the Company’s financial statements and the notes thereto.

Change in Fiscal Year

Effective September 2, 2014, the Company changed its fiscal year end from December 31 to September 30. The various periods that are covered in the discussion below are defined as follows:

• “transition period” or “current period” — January 1, 2014 through September 30, 2014.

• “comparable unaudited nine-month period” or “prior period” — January 1, 2013 through September 30, 2013

• “calendar 2013” — January 1, 2013 through December 31, 2013.

• “calendar 2012” — January 1, 2012 through December 31, 2012.

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RESULTS OF OPERATIONS

Transition Period Ended September 30, 2014 compared to the comparable Nine-Month Period Ended September 30, 2013:

	Nine Months Ended
($ Millions)	September 30, 2014		September 30, 2013
Statements of Income data
Operating revenues	$	417.2	$	390.6
Operating expenses	355.0		331.6
Operating income	62.2		59.0
Income taxes	19.9		22.9
Net income	33.0		37.6

Operating revenues
Residential	$	276.7		$	259.5
Commercial and industrial	111.9			103.4
Transportation	44.9			45.3
Other (1)	(16.3		)	(17.6		)
Total	$	417.2		$	390.6
Gas delivery volumes (bcf)
Residential	17.5			15.4
Commercial and industrial	8.5			7.4
Transportation	36.1			34.7
Total	62.1			57.5
Average number of customers
Residential	391,840			391,932
Commercial, industrial and transportation	31,236			31,254
Total	423,076			423,186
Other data
Depreciation and amortization	$	34.4		$	32.7
Capital expenditures	46.2			67.1

(1) Amount reflects the RSE adjustment related to customer give back. See Regulatory Matters for more details on give back.

Operating Revenue

The Company’s operating revenues totaled $417.2, and $390.6 for the transition period ended September 30, 2014 and the comparable nine month period September 30, 2013, respectively. Operating revenue in the transition period ended September 30, 2014 rose primarily due to an increase in customer usage of approximately $28.4 due to colder weather, offset by a lower allowed net return on average equity of approximately $2.8. In the transition period ended September 30, 2014, weather that was 17.5% colder than in the comparable nine-month period ended September 30, 2013 contributed to a 13.6% increase in residential sales volumes, a 14.9% increase in commercial and industrial volumes and a 4.0% increase in transportation volumes.

Operations and Maintenance

O&M expense declined less than 1.0% in the transition period ended September 30, 2014 largely due to decreased labor-related costs of $3.2 and decreased business development costs of $1.5 partially offset by increased general and workers compensation insurance costs of $1.0 and information technology costs of $0.8. For the transition period ended September 30, 2014 the Company’s O&M expense fell below the Index Range, resulting in a pretax benefit of $2.4.  The Company’s O&M expense fell within the Index Range in the comparable nine-month period ended September 30, 2013. Depreciation expense increased 5.2% in the transition period ended September 30, 2014 largely due to the extension and replacement of the Company’s distribution system and replacement of its support systems. Approved depreciation rates averaged approximately

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3.2% and 3.1% for the transition period ended September 30, 2014 and the comparable nine-month period ended September 30, 2013, respectively.

Tax Expense

Income tax expense decreased $3.0 in the transition period from the same period in 2013 primarily due to lower pre-tax income. The effective tax rate for the transition period ended September 30, 2014 was 37.6% compared to 37.9% for the nine month period ended September 30, 2013.

Net Income

The Company earned net income of $33.0 for the transition period ended September 30, 2014 compared with net income of $37.6 in the comparable nine-month period ended September 30, 2013. The decline in net income is primarily attributable to a decrease in the allowed rate of return effective January 1, 2014, partially offset by earning on a higher level of equity.

Calendar 2013 compared to Calendar 2012

	Calendar Year Ended December 31,
($ Millions)	2013		2012
Statements of Income data
Operating revenues	$	533.3	$	451.6
Operating expenses	439.6		358.3
Income from operations	93.7		93.3
Income taxes	34.7		30.3
Net income	57.4		49.4

Operating revenues
Residential	$	340.6		$	277.7
Commercial and industrial	137.0			115.7
Transportation	61.3			58.9
Other	(5.6		)	(0.7		)
Total	$	533.3		$	451.6
Gas delivery volumes (bcf)
Residential	20.3			16.0
Commercial and industrial	10.0			8.4
Transportation	47.5			48.1
Total	77.8			72.5
Average number of customers
Residential	391,093			393,467
Commercial, industrial and transportation	31,174			31,450
Total	422,267			424,917
Other data
Depreciation and amortization	$	43.9		$	42.3
Capital expenditures	86.0			69.9

(1) Amount reflects the RSE adjustment related to customer give back. See Regulatory Matters for more details on give back.

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Operating Revenue

The Company’s operating revenues totaled $533.3 and $451.6 in calendar 2013 and 2012, respectively. Operating revenue in calendar 2013 rose primarily due to an increase in gas cost of approximately $37.0 along with an increase in customer usage of approximately $36.0. In calendar 2013, the Company had a net reduction in revenues of $10.6 pre-tax to bring the return on average equity to the midpoint within the allowed range of return. During calendar 2012, the Company had a net reduction in revenues of $6.3 to bring the return on average equity to the midpoint within the allowed range of return. In calendar 2013, weather that was 38.4% colder than in the prior year contributed to a 26.9% increase in residential sales volumes and a 19.0% increase in commercial and industrial volumes. Transportation volumes fell 1.2%.

Operations and Maintenance Expense

O&M expense at the Company rose 1.3% in calendar 2013 largely due to increased labor-related costs of $3.5 and increased bad debt expense of $0.6 partially offset by decreased consulting and technology costs of $1.0. The Company’s O&M expense fell within the Index Range for the Rate Years ended September 30, 2013 and 2012.

Depreciation expense increased 3.8% in calendar 2013, largely due to the extension and replacement of the Company’s distribution system and replacement of its support systems. Approved depreciation rates averaged approximately 3.1% and 3.2% in calendar 2013 and 2012, respectively.

Tax Expense

Income tax expense increased $4.4 in calendar 2013 compared with calendar 2012 primarily due to higher pre-tax income. The effective tax rate for calendar 2013 was 37.7% compared to 38.0% for calendar 2012.

Net Income

The Company’s net income of $57.4 in calendar 2013 compared to net income of $49.4 in calendar 2012. This increase in net income is largely attributable to an after-tax gain of $6.9 on the sale of the Metro Operations Center in 2013.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The Company’s discussion and analysis of its financial condition, results of operations, liquidity, and capital resources is based upon its financial statements, which have been prepared in accordance with GAAP, which requires that the Company make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. The Company evaluates its estimates on an ongoing basis. The Company bases its estimates on historical experience and on various other assumptions that it believes are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates. The Company believes the following represent the more significant items requiring the use of judgment and estimates in preparing its financial statements:

Regulatory Accounting - The Company accounts for its regulated operations in accordance with FASB ASC Topic 980, “Regulated Operations.” This Topic sets forth the application of GAAP for those companies whose rates are established by or are subject to approval by an independent third party regulator. The provisions of this accounting guidance require, among other things, that financial statements of a regulated enterprise reflect the actions of regulators, where appropriate. These actions may result in the recognition of revenues and expenses in time periods that are different than non-regulated enterprises. When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses when those amounts are reflected in rates. Also, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for recovery of costs that are expected to be incurred in the future (regulatory liabilities). Management believes that the current regulatory environment supports the continued use of these regulatory accounting principles and that all regulatory assets and regulatory liabilities are recoverable or refundable through the regulatory process.

The Company’s rate schedules for natural gas distribution charges contain a GSA rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. The Company’s tariff provides a temperature adjustment mechanism, also included in the GSA, which is designed to moderate the impact of departures from normal temperatures on the Company’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment. In prior years, the Company entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. The Company recognizes all derivatives at fair value as either assets or liabilities on the balance sheet. Any realized gains or losses are passed through to customers using the mechanisms of the GSA rider in accordance with the Company’s APSC approved tariff and are recognized as a regulatory asset or regulatory liability.

Employee Benefits and Postretirement Obligations - Pension and postretirement obligations are calculated utilizing several statistical factors and other assumptions related to future events, such as discount rates, returns on plan assets, compensation increases, and mortality rates. The amount of expense recognized and the amounts reflected in other comprehensive income are dependent upon the regulatory treatment provided for such costs, as discussed further below. Certain liabilities related to

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group medical benefits and workers’ compensation claims, portions of which are self-insured and/or contain “stop-loss” coverage with third party insurers to limit exposure, are established based on historical trends.

The amount of net periodic pension and other postretirement benefit cost recognized in the financial statements related to the Company’s qualified pension plans and other postretirement benefit plans is based upon allowances, as approved by the APSC. The allowances have been established in the rate-making process for the recovery of these costs from customers. The differences between these amounts and actual pension and other postretirement benefit costs incurred for financial reporting purposes are deferred as regulatory assets or regulatory liabilities. GAAP also requires that changes that affect the funded status of pension and other postretirement benefit plans, but that are not yet required to be recognized as components of pension and other postretirement benefit cost, be reflected in other comprehensive income. For the Company’s qualified pension plans and other postretirement benefit plans, amounts that would otherwise be reflected in other comprehensive income are deferred with entries to regulatory assets or regulatory liabilities.

The table below reflects the sensitivity of the Company's plans to potential changes in key assumptions:

Pension Plan Benefits:
Actuarial Assumptions	Increase/(Decrease)		Estimated Increase/(Decrease) to Projected Benefit Obligation (Millions)			Estimated Increase/(Decrease) to Annual Net Pension Cost* (Millions)
Discount Rate	0.25	%	$	(3.3	)	$	—
	(0.25	)%	3.4			—
Rate of Future Compensation Increase	0.25	%	6.0			0.1
	(0.25	)%	(6.0		)	(0.1		)
Expected Return on Plan Assets	0.25	%	—			—
	(0.25	)%	—			—
Postretirement Benefits:
Actuarial Assumptions	Increase/(Decrease)		Estimated Increase/(Decrease) to Projected Postretirement Benefit Obligation (Millions)			Estimated Increase/(Decrease) to Annual Net Postretirement Benefit Cost* (Millions)
Discount Rate	0.25	%	$	(1.7	)	$	—
	(0.25	)%	1.9			—
Expected Return on Plan Assets	0.25	%	—			—
	(0.25	)%	—			—
Annual Medical Cost Trend	1.00	%	0.7			—
	(1.00	)%	(0.7		)	—

* Excludes the impact of regulatory deferral mechanism. See Note 6, Pension Plans and Other Postretirement Benefits, of the Notes to the Financial Statements for information regarding the regulatory treatment of these costs.

Asset Retirement Obligations -Asset retirement obligations are recorded in accordance with GAAP using various assumptions related to the timing, method of settlement, inflation, and profit margins that third parties would demand to settle the future obligations. These assumptions require the use of judgment and estimates and may change in future periods as circumstances dictate. As authorized by the APSC, the Company accrues future removal costs associated with its property, plant and equipment through its depreciation rates, even if a legal obligation does not exist as defined by GAAP. The difference between removal costs recognized in depreciation rates and the accretion expense and depreciation expense recognizable pursuant to GAAP is a timing difference between the recovery of these costs in rates and their recognition for financial reporting purposes. The Company accrues removal costs on certain gas distribution assets over the useful lives of its property, plant and equipment through depreciation expense in accordance with rates approved by the APSC. The costs associated with asset retirement obligations are either currently being recovered in rates or are probable of recovery in future rates. The Company has estimated the asset retirement obligation of its long-lived assets. The valuation is preliminary and will be finalized upon completion of a detailed fair value analysis that is being performed by the Laclede Group.

For further discussion of significant accounting policies, see Note 1, Summary of Significant Accounting Policies, of the Notes to the Financial Statements.

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Accounting Pronouncements

The Company has evaluated, or is in the process of evaluating, the impact that recently issued accounting standards will have on the Company’s financial position or results of operations upon adoption. For disclosures related to the adoption of new accounting standards, see the New Accounting Standards section of Note 1 of the Notes to the Financial Statements.

Inflation

The accompanying financial statements reflect the historical costs of events and transactions, regardless of the purchasing power of the dollar at the time. Due to the capital-intensive nature of the business of the Company, the most significant impact of inflation is on the depreciation of utility plant. Rate regulation, to which the Company is subject, allows recovery through its rates of only the historical cost of utility plant as depreciation. The Company believes that any higher costs experienced upon replacement of existing facilities will be recovered through the normal regulatory process.

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FINANCIAL POSITION AND LIQUIDITY

Cash Flows

The Company’s net cash from operating activities totaled $115.0 for the transition period ended September 30, 2014, compared to $119.2 in the comparable period in 2013. This decrease consisted primarily of non-cash charges, including higher Depreciation, Depletion and Amortization (DD&A) and a gain on the sale of certain assets in 2013.

The Company's net cash used in investing activities totaled $45.4 for the transition period ended September 30, 2014, compared to $54.9 in the comparable period in 2013. This decrease was related to a decrease in capital expenditures of $20.9 and offset by a reduction in proceeds from the sale of assets of $13.8.

The Company's net cash used in financing activities totaled $67.0 for the transition period ended September 30, 2014, compared to $61.4 in the comparable period in 2013. This increase consisted primarily of an increase in payments of short-term debt of $6.0.

Liquidity and Capital Resources

Cash and Cash Equivalents

The Company had no short-term investments as of September 30, 2014. Its bank deposits were used to support the working capital needs of the Company.

Debt

Access to capital is an integral part of the Company’s business plan. While the Company expects to have ongoing access to its credit facility and the longer-term capital markets, continued access could be adversely affected by current and future economic and business conditions and credit rating actions.

On September 2, 2014, the Company, entered into a new syndicated revolving credit facility pursuant to a loan agreement (the Alagasco Loan Agreement) with Wells Fargo, as administrative agent, and several other participating banks. The initial borrowing under the Alagasco Loan Agreement was used to repay the approximately $15.0 of borrowings outstanding under the Company’s previous credit agreement, dated as of October 30, 2012, with Bank of America, N.A., as administrative agent, and several other participating banks, which was terminated in connection with the closing of the Alagasco Loan Agreement.

The Alagasco Loan Agreement is for a term of five years ending September 2, 2019, but the Company may request up to two one-year extensions. The Alagasco Loan Agreement contains affirmative and negative covenants, including, among other things, limitations on certain types of acquisitions, investments and sales of property. The Alagasco Loan Agreement also contains a financial covenant limiting the Company’s debt to 70% of the Company’s capitalization. At September 30, 2014, this ratio stood at 24%, as defined under the line of credit.

The Alagasco Loan Agreement has a credit commitment of $150.0. Under certain terms and conditions, the Company may request an increase of up to $50.0 in the credit commitment. The Alagasco Loan Agreement also provides for letters of credit in an aggregate amount up to $15.0, and swingline loans in an aggregate amount up to $15.0. Letters of credit and swingline loans will constitute usage under the Alagasco Loan Agreement. The Company expects to use the Alagasco Loan Agreement for working capital and general corporate purposes.

The Company was in compliance with the terms of the syndicated credit facilities at September 30, 2014.

Working capital of the Company is impacted by the recovery and pass-through of regulatory items and the seasonality of the Company’s business and reflects an expected pass-through to rate payers of $13.4 in refundable negative salvage costs representing a reduction in future revenues through lower tariff rates. The Company relies upon cash flows from operations supplemented by its syndicated unsecured credit facilities to fund working capital needs.

The Company has authority from the APSC to issue debt securities for up to $35.0. No securities have been issued under this authority.

Other

The Company’s access to capital markets and its financing costs, may depend on its credit rating at the time that it accesses the capital markets. The credit ratings of the Company remain at investment grade, but are subject to review and change by the rating agencies. On December 16, 2013, Standard & Poor’s lowered its debt ratings for the Company from investment grade with a stable outlook to investment grade with a negative outlook. On April 7, 2014, Standard & Poor’s changed the Company’s outlook to positive in light of its pending acquisition by the Laclede Group. At the completion of the acquisition, on September 2, 2014, Standard & Poor’s raised the Company’s rating to A- and adjusted its outlook to stable. Ratings from Moody’s Investors Service remained stable through this period.

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The Company is a mature utility operating in a slow-growth service area which includes municipalities that have in recent years experienced population declines. The Company’s average customer count for the transition period ended September 30, 2014 remained flat from the comparable nine-month period ended September 30, 2013 and reflected a moderate decline over the five-year trend. The Company monitors the bad debt reserve and makes adjustments as required based on its evaluation of receivables which are impacted by natural gas prices, weather conditions and the underlying current and future economic conditions facing the Company’s customer base.

The Company maintains an investment in storage gas that is expected to average $30.0 in fiscal 2015 but will vary depending upon the price of natural gas. During fiscal 2015, the Company plans to invest approximately $85.0 in capital expenditures for the normal needs of its distribution, support systems and technology-related projects designed to improve customer service and the construction of a service center to replace the Metro Operations Center sold during calendar 2013. The Company anticipates funding these capital requirements through internally generated capital and the utilization of its credit facilities. The Company also may issue long-term debt periodically to replace short-term obligations, enhance liquidity and provide for permanent financing.

In August 2013, the Company recorded a pre-tax gain of $10.9 related to the sale of its Metro Operations Center, which is located in Birmingham, Alabama, and has been in service since the 1940s. The Company received approximately $13.8 in cash proceeds from the sale of this property. The gain on the sale was recognized in other income and a related reduction in revenues was recognized to defer the gain as a regulatory liability pending review by the APSC. In conjunction with the receipt of the rate order from the APSC on December 20, 2013, the Company recognized the deferred revenues from this sale in the fourth calendar quarter of 2013. Effective upon the sale of the Metro Operations Center, the Company leased the facility from the purchaser for a period of approximately 20 months.

It is management’s view that the Company has adequate access to capital markets and will have sufficient capital resources, both internal and external, to meet anticipated capital requirements, which primarily include capital expenditures, scheduled maturities of long-term debt, short-term seasonal needs, and dividends.

Contractual Obligations

In the course of ordinary business activities, the Company enters into a variety of contractual cash obligations and other commitments. The following table summarizes the Company’s significant contractual cash obligations as of September 30, 2014:

	Payments Due By Period
(in Millions)	Total		Less than 1 year		1-3 years		3-5 Years		More than 5 years
Principal payments on long-term debt	$	265.8	$	—	$	80.0	$	16.0	$	169.8
Interest payments on long-term debt	132.7		12.9		28.1		22.8		68.9
Purchase obligations - natural gas (1)	133.9		46.5		84.4		0.9		2.1
Operating leases	26.3		4.3		7.9		5.0		9.1
Purchase obligations - other	15.0		10.1		4.5		0.1		0.3
Total contractual cash obligations (2)	$	573.7	$	73.8	$	204.9	$	44.8	$	250.2

(1) Certain of the Company’s long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $134.0 through September 2024. For the transition period ended September 30, 2014 and the calendar year ended December 31, 2013, the Company recognized approximately $33.8 and $50.0, respectively, of long-term commitments through expense and its regulatory accounts in the accompanying financial statements. The Company also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments total approximately 111 Bcf through August 2020 for $14.4.

(2) Commitments related to pension and postretirement benefit plans have been excluded from the table above. The Company expects to make benefit payments of $9.9 to participants in the qualified, trusteed pension plans in fiscal year 2015 and $3.8 to the postretirement benefits plan participants. For further discussion of the Company’s pension and postretirement benefit plans, refer to Note 6, Pension Plans and Other Postretirement Benefits, of the Notes to the Financial Statements. It is not anticipated that the funded status of the qualified pension plans will fall below statutory thresholds requiring accelerated funding or constraints on benefit levels or plan administration. The Company made a discretionary contribution of $1.6 to the qualified pension plans in January 2014. During fiscal 2015, the Company may make additional discretionary contributions to the qualified pension plans depending on the amount and timing of employee retirements and market conditions. The contractual obligations reported above exclude any payments the Company expects to make to postretirement benefit program assets.

MARKET RISK

Commodity Price Risk

22

The Company’s commodity price risk, which arises from market fluctuations in the price of natural gas, is primarily managed through the operation of the Company's GSA Rider. The Company did not have any derivative positions as of September 30, 2014. Accordingly, the Company does not expect any adverse earnings impact as a result of the use of derivative instruments. However, should the Company enter into any derivative transactions for this purpose, the timing of recovery for cash payments related to margin requirements could cause short-term cash requirements to vary. Nevertheless, carrying costs associated with such requirements, as well as other variations in the timing of collections of gas costs, would be recovered through the GSA rider.

Interest Rate Risk

The Company is subject to interest rate risk associated with its long-term and short-term debt issuances. Based on average short-term borrowings during the transition period ended September 30, 2014, an increase of 100 basis points in the underlying average interest rate for short-term debt would have caused an increase in interest expense of approximately $0.1 on an annual basis. Portions of such increases may be offset through the application of GSA carrying costs. At September 30, 2014, the Company had fixed-rate long-term debt totaling $249.8. While these long-term debt issues are fixed-rate, they are subject to changes in fair value as market interest rates change. However, increases or decreases in fair value would impact earnings and cash flows only if the Company were to reacquire any of these issues in the open market prior to maturity. Under GAAP applicable to the Company’s regulated operations, losses or gains on early redemptions of long-term debt would typically be deferred as regulatory assets or regulatory liabilities and amortized over a future period.

Environmental Matters

The Company owns and operates natural gas distribution, transmission, and storage facilities, the operations of which are subject to various environmental laws, regulations, and interpretations. While environmental issues resulting from such operations arise in the ordinary course of business, such issues have not materially affected the Company or the Company’s financial position and results of operations. As environmental laws, regulations, and their interpretations change, however, the Company may be required to incur additional costs. For information relative to environmental matters, see Note 7, Commitments and Contingencies, of the Notes to the Financial Statements.

Off-Balance Sheet Arrangements

At September 30, 2014, the Company did not have any off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business. The Company does not expect to engage in any significant off-balance-sheet financing arrangements in the near future.

ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information required by this item with respect to market risk is set forth in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations under the heading “Market Risk” and in Note 8, Financial Instruments and Risk Management, in the Notes to Financial Statements.

23

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
		Page
	Management Report on Internal Control Over Financial Reporting	25
	Reports of Independent Registered Public Accounting Firm	26
	Financial Statements:
	For Years Ended September 30, 2014, December 31, 2013 and 2012:
	Statements of Income	28
	Statements of Common Shareholders’ Equity	32
	Statements of Cash Flows	33
	As of September 30, 2014 and 2013:
	Balance Sheets	29
	Statements of Capitalization	31
	Notes to the Financial Statements:
	Note 1 Summary of Significant Accounting Policies	34
	Note 2 Acquisitions	36
	Note 3 Regulatory Matters	36
	Note 4 Long Term Debt and Notes Payable	37
	Note 5 Income Taxes	38
	Note 6 Pension Plans and Other Post Retirement Benefits	40
	Note 7 Commitments and Contingencies	45
	Note 8 Financial Instruments and Risk	46
	Note 9 Asset Retirement Obligations	47
	Note 10 Supplemental Cash Flow Information	47
	Note 11 Acquisition and Disposition of Properties	48
	Note 12 Regulatory Assets and Liabilities	48
	Note 13 Transactions with Related Parties	49
	Note 14 Comparable Nine-Month Financial Information	50
	Note 15 Summarized Quarterly Financial Data	50

24

Management’s Report on Internal Control over Financial Reporting

Management of Alabama Gas Corporation is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Alabama Gas Corporation’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Internal control over financial reporting includes those written policies and procedures that:

i pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of Alabama Gas Corporation;

ii provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of Alabama Gas Corporation are being made only in accordance with authorization of management and directors of Alabama Gas Corporation; and

iii provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 Management assessed the effectiveness of Alabama Gas Corporation’s internal control over financial reporting as of September 30, 2014. Management based this assessment on criteria for effective internal control over financial reporting described in “Internal Control - Integrated Framework” (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management’s assessment included an evaluation of the design of Alabama Gas Corporation’s internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Management reviewed the results of its assessment with the Audit Committee of its Board of Directors.

Based on this assessment, management determined that, as of September 30, 2014, Alabama Gas Corporation maintained effective internal control over financial reporting.

25

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of Alabama Gas Corporation

Birmingham, Alabama

We have audited the accompanying balance sheet and statement of capitalization of Alabama Gas Corporation (the "Company") as of September 30, 2014, and the related statements of income, common shareholder’s equity, and cash flows for the nine months ended September 30, 2014. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Alabama Gas Corporation as of September 30, 2014, and the results of its operations and its cash flows for the nine months ended September 30, 2014, in conformity with accounting principles generally accepted in the United States of America.

DELOITTE & TOUCHE LLP

Birmingham, Alabama

November 25, 2014

26

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of Alabama Gas Corporation:

In our opinion, the accompanying balance sheets and the related statements of income, shareholder’s equity and cash flows present fairly, in all material respects, the financial position of Alabama Gas Corporation (the “Company”) at December 31, 2013 and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Birmingham, Alabama

March 3, 2014

27

ALABAMA GAS CORPORATION
STATEMENTS OF INCOME	Nine Months Ending		Years Ended December 31,
($ Millions)	September 30, 2014		2013		2012
Operating Revenues:
Utility	$	417.2	$	533.3	$	451.6
Total Operating Revenues	417.2		533.3		451.6
Operating Expenses:
Utility
Natural gas	184.5		215.5		142.2
Other operation and maintenance expenses	107.5		143.1		141.3
Depreciation and amortization	34.4		43.9		42.3
Taxes, other than income taxes	28.6		37.1		32.5
Total Utility Operating Expenses	355.0		439.6		358.3
Operating Income	62.2		93.7		93.3
Other Income	2.2		14.0		2.7
Interest Charges:
Interest on long-term debt	10.1		13.5		13.7
Other interest charges	1.4		2.1		2.6
Total Interest Charges	11.5		15.6		16.3
Income Before Income Taxes	52.9		92.1		79.7
Income Tax Expense	19.9		34.7		30.3
Net Income	$	33.0	$	57.4	$	49.4

See the accompanying Notes to Financial Statements

28

ALABAMA GAS CORPORATION
BALANCE SHEETS	September 30,			December 31,
($ Millions)	2014			2013
ASSETS
Utility Plant	$	1,525.1		$	1,491.4
Less – Accumulated depreciation and amortization	626.4			605.9
Net Utility Plant	898.7			885.5
Other Property and Investments	—			0.1
Other Property and Investments	—			0.1
Current Assets:
Cash and cash equivalents	5.6			3.0
Accounts receivable:
Gas	39.0			103.3
Associated companies	—			4.7
Other	5.1			5.4
Allowance for doubtful accounts	(5.1		)	(5.0		)
Inventories:
Natural gas	45.2			32.1
Liquefied natural gas in storage	2.8			3.6
Materials and supplies	5.1			5.5
Income tax receivable	0.1			3.6
Deferred income taxes	2.3			20.0
Regulatory assets	8.8			2.8
Prepayments and other	1.5			4.7
Total Current Assets	110.4			183.7
Deferred Charges:
Regulatory assets	90.6			84.9
Deferred income taxes	277.8			—
Net asset available for other postretirement benefits	24.7			26.5
Other	22.4			17.4
Total Deferred Charges	415.5			128.8
Total Assets	$	1,424.6		$	1,198.1

See the accompanying Notes to Financial Statements

29

ALABAMA GAS CORPORATION
BALANCE SHEETS	September 30,		December 31,
($ Millions)	2014		2013
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock equity, $0.01 par value, 3,000,000 shares authorized, 1,972,052 shares issued at September 30, 2014 and December 31, 2013, respectively	849.6		384.6
Long-term debt (less current portion)	249.8		249.9
Total Capitalization	1,099.4		634.5
Current Liabilities:
Notes payable	16.0		50.0
Accounts payable	34.8		48.7
Accounts payable – associated companies	0.4		—
Advance customer billings	36.3		38.7
Wages and compensation accrued	7.1		7.7
Taxes accrued	29.8		28.0
Regulatory liabilities	63.1		49.0
Other	13.8		10.1
Total Current Liabilities	201.3		232.2
Deferred Credits and Other Liabilities:
Deferred income taxes	—		205.6
Pension and postretirement benefit costs	29.6		20.2
Regulatory liabilities	53.7		66.6
Other	40.6		39.0
Total Deferred Credits and Other Liabilities	123.9		331.4
Total Capitalization and Liabilities	$	1,424.6	$	1,198.1

See the accompanying Notes to Financial Statements

30

ALABAMA GAS CORPORATION
STATEMENTS OF CAPITALIZATION	September 30,		December 31,
($ Millions)	2014		2013
Common Stock Equity:
Common stock, par value $0.01 per share:
Authorized – September 30,2014 and December 31, 2013, 3,000,000 shares
Issued – September 30, 2014 and December 31, 2013, 1,972,052 shares	$	503.9	$	34.5
Retained earnings	345.7		350.1
Total Common Stock Equity	849.6		384.6
Long Term Debt
5.368% Notes, due December 1, 2015	80.0		80.0
5.20% Notes, due January 15, 2020	40.0		40.0
3.86% Notes, due December 21, 2021	50.0		50.0
5.70% Notes, due January 15, 2035	34.8		34.9
5.90% Notes, due January 15, 2037	45.0		45.0
Total	249.8		249.9
Total Capitalization	$	1,099.4	$	634.5

See the accompanying Notes to Financial Statements

31

ALABAMA GAS CORPORATION
STATEMENTS OF COMMON SHAREHOLDER'S EQUITY
	Common Stock Issued			Paid-in Capital		Retained Earnings
($ Millions, Except for Shares)	Shares	Amount							Total
BALANCE DECEMBER 31, 2011	1,972,052	$	31.7	$	2.8	$	310.2		$	344.7
Net income	—	—		—		49.4			49.4
Dividends declared:
Common stock	—	—		—		(33.6		)	(33.6		)
BALANCE DECEMBER 31, 2012	1,972,052	31.7		2.8		326.0			360.5
Net income	—	—		—		57.4			57.4
Dividends declared:
Common stock	—	—		—		(33.3		)	(33.3		)
BALANCE DECEMBER 31, 2013	1,972,052	31.7		2.8		350.1			384.6
Net income	—	—		—		33.0			33.0
Dividends declared:
Common stock	—	—		—		(37.4		)	(37.4		)
Purchase accounting adjustments	—			469.4		—			469.4
BALANCE SEPTEMBER 30, 2014	1,972,052	$	31.7	$	472.2	$	345.7		$	849.6

See the accompanying Notes to Financial Statements

32

ALABAMA GAS CORPORATION
STATEMENTS OF CASH FLOWS	Nine Months Ending			Years Ended December 31,
($ Millions)	September 30, 2014			2013			2012
Operating Activities:
Net Income	$	33.0		$	57.4		$	49.4
Adjustments to reconcile net income to net cash provided by       (used in) operating activities:
Depreciation, amortization, and accretion	34.4			43.9			42.3
Deferred income taxes	4.0			15.0			11.3
Gain on sale of assets	(0.7		)	(10.9		)	—
Other	2.0			14.1			10.8
Changes in assets and liabilities:
Accounts receivable - net	26.4			(23.2		)	(13.5		)
Inventories	(11.8		)	—			10.5
Accounts payable	(13.6		)	(2.5		)	(5.9		)
Advance customer billings	37.1			40.5			(57.8		)
Income tax receivable	3.5			(0.9		)	7.0
Pension and other postretirement benefit contributions	(1.6		)	(6.1		)	(2.7		)
Other assets and liabilities	2.3			2.7			(8.7		)
Net cash provided by operating activities	115.0			130.0			42.7
Investing Activities:
Capital expenditures	(46.2		)	(86.0		)	(69.9		)
Proceeds from sale of assets	0.8			13.8			—
Other, net	—			—			(3.2		)
Net cash used in investing activities	(45.4		)	(72.2		)	(73.1		)
Financing Activities:
Reduction of long-term debt	(0.1		)	(0.1		)	(0.2		)
(Repayment) issuance of notes payable - net	(34.0		)	(27.0		)	62.0
Debt issuance costs	(0.6		)	—			—
Dividends paid	(37.4		)	(33.3		)	(33.6		)
Repayment of advances from affiliates	5.1			—			—
Net cash (used in) provided by financing activities	(67.0		)	(60.4		)	28.2
Net Increase (Decrease) in Cash and Cash Equivalents	2.6			(2.6		)	(2.2		)
Cash and Cash Equivalents at Beginning of Year	3.0			5.6			7.8
Cash and Cash Equivalents at End of Year	$	5.6		$	3.0		$	5.6

See the accompanying Notes to Financial Statements

33

ALABAMA GAS CORPORATION

NOTES TO THE FINANCIAL STATEMENTS

($ in millions)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Alabama Gas Corporation (the Company or Alagasco) is engaged in the purchase, distribution and sale of natural gas principally in central and north Alabama and is headquartered in Birmingham, Alabama. The Company provides residential, commercial and industrial customers with safe and reliable natural gas service. Due to the seasonal nature of the Company, earnings are typically concentrated during the heating season of November through April each calendar year. The Company operates as a single reporting segment. The accompanying financial statements have been prepared in accordance with GAAP.

On September 2, 2014 the Company was acquired by The Laclede Group, Inc. (Laclede Group) for approximately $1,600.0, including the assumption of $250.0 of long-term debt, from Energen Corporation (Energen), with an effective time under the SPA of 11:59 p.m. on August 31, 2014.  Prior to the acquisition the Company was a wholly owned subsidiary of Energen.  Subsequent to the acquisition, the Company became a wholly owned subsidiary of Laclede Group, see Note 2, Acquisition.

Effective September 2, 2014, the Company amended its bylaws, to change the Company’s fiscal year from beginning January 1st and ending on December 31st, to beginning October 1st and ending on September 30th. As a result, the financial statements accompanying these Notes cover the period from January 1, 2014 through September 30, 2014 (the “transition period”) and are included in the Company’s transition report on form 10-K for such period. Subsequent to such report, the Company’s annual reports on Form 10-K will cover the fiscal year October 1^st to September 30^th. The period beginning January 1, 2013 through December 31, 2013 is referred to as “calendar 2013” and the period beginning January 1, 2012 through December 31, 2012 as “calendar 2012”. 

Use of Estimates - The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

Utility Plant and Depreciation - Utility plant is stated at original cost. The cost of additions to utility plant includes contracted work, direct labor and materials, allocable overheads, and an allowance for funds used during construction. The costs of units of property retired, replaced, or renewed are removed from utility plant and are charged to accumulated depreciation. Maintenance and repairs of property and replacement and renewal of items determined to be less than units of property are charged to maintenance expenses. Gains and losses on all dispositions of land are recognized at time of disposal.

Depreciation is provided using the composite method of depreciation on a straight-line basis over the estimated useful lives of property at rates approved by the Alabama Public Service Commission (APSC). On June 28, 2010, the APSC approved a reduction in depreciation rates, effective June 1, 2010, with the revised prospective composite depreciation rate approximating 3.1%. The Company anticipates refunding approximately $13.4 of refundable negative salvage costs through lower tariff rates over the next twelve months related to the lower depreciation rates.

Asset Retirement Obligations - The Company records legal obligations associated with the retirement of long-lived assets in the period in which the obligations are incurred, if sufficient information exists to reasonably estimate the fair value of the obligations. Obligations are recorded as both a cost of the related long-lived asset and as a corresponding liability. Subsequently, the asset retirement costs are depreciated over the life of the asset and the asset retirement obligations are accreted to the expected settlement amounts. The Company records asset retirement obligations associated with certain safety requirements to purge and seal gas distribution mains upon retirement, the plugging and abandonment of storage wells and other storage facilities, specific service line obligations, and certain removal and disposal obligations related to components of the Company’s distribution system and general plant. Such accruals are provided for through depreciation expense and are recorded with corresponding credits to regulatory liabilities. The costs associated with asset retirement obligations are either currently being recovered in rates or are probable of recovery in future rates.

Regulated Operations - The Company accounts for its regulated operations in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 980, “Regulated Operations.” This Topic sets forth the application of GAAP for those companies whose rates are established by or are subject to approval by an independent third party regulator. The provisions of this accounting guidance require, among other things, that financial statements of a regulated enterprise reflect the actions of regulators, where appropriate. These actions may result in the recognition of revenues and expenses in time periods that are different than non-regulated enterprises. When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses when those amounts are reflected in rates. Also, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for recovery of costs that are expected to be incurred in the future (regulatory liabilities). Management believes that the current regulatory environment supports the continued use of these regulatory accounting principles and that all regulatory assets and

34

regulatory liabilities are recoverable or refundable through the regulatory process. See additional discussion on regulated operations in Note 3 - Regulatory Matters and Note 12 - Regulatory Assets and Liabilities.

Natural Gas Stored Underground - Inventory of natural gas in storage is stated at average cost.

Revenue Recognition and Gas Costs - The Company records natural gas distribution revenues in accordance with the tariff established by the APSC. The margin and gas costs on service delivered to cycle customers but not yet billed are recorded in current assets as accounts receivable with a corresponding regulatory liability. Gas imbalances are settled on a monthly basis. Alagasco had no material imbalances at September 30, 2014 and December 31, 2013.

Gas Supply Adjustment - The Company’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. The Company’s tariff provides a temperature adjustment mechanism, also included in the GSA that is designed to moderate the impact of departures from normal temperatures on the Company’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment. In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Alagasco recognizes all derivatives at fair value as either assets or liabilities on the balance sheet. Any realized gains or losses are passed through to customers using the mechanisms of the GSA rider in accordance with Alagasco’s APSC approved tariff and are recognized as a regulatory asset or regulatory liability.

Income Taxes - The Company uses the asset and liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities, as well as tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change.

Gross Receipts Taxes, Franchise Fees and Sales Taxes - Gross receipts taxes and franchise fees associated with the Company’s natural gas utility services are imposed on the Company and billed to its customers. These amounts are recorded gross in the Company’s Statements of Income. Amounts recorded in the Company’s Operating Revenues were $20.6, $25.9 and $21.5 for the transition period ended September 30, 2014 and the calendar years ended December 31, 2013 and 2012, respectively. Gross receipts taxes and franchise fees are expensed and included in the Taxes, other than income taxes line. Sales taxes imposed on applicable sales are billed to customers. These amounts are not recorded in the Statements of Income, but are recorded as tax collections payable and included in other current liabilities on the balance sheets.

Accounts Receivable and Allowance for Doubtful Accounts - Trade accounts receivable are recorded at the amounts due from customers, including unbilled amounts. Estimates of the collectability of trade accounts receivable are based on historical trends, age of receivables, economic conditions, credit risk of specific customers, and other factors. Accounts receivable are written off against the allowance for doubtful accounts when they are deemed to be uncollectible.

Group Medical, General Liability and Workers’ Compensation Reserves - The Company self-insures its group medical, general liability and workers’ compensation costs and carries stop-loss coverage in relation to medical claims, general liability and workers’ compensation claims. Reserves for amounts incurred but not reported are established based on historical cost levels and lags between occurrences and reporting.

Fair Value Measurements - Certain assets and liabilities are recognized or disclosed at fair value, which is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). GAAP establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.

The levels of the hierarchy are described below:

• Level 1 - Unadjusted quoted prices in active markets for identical assets or liabilities.

• Level 2 - Pricing inputs other than quoted prices included within Level 1, which are either directly or indirectly observable for the asset or liability as of the reporting date. These inputs are derived principally from, or corroborated by, observable market data.

• Level 3 - Pricing that is based upon inputs that are generally unobservable that are based on the best information available and reflect management’s assumptions about how market participants would price the asset or liability.

Assessment of the significance of a particular input to the fair value measurements may require judgment and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. Additional information about fair value measurements is provided in Note 6, Pension Plans and Other Postretirement Benefits and Note 8, Financial Instruments and Risk Management.

35

New Accounting Standard - In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers. This standard is intended to improve the financial reporting requirements for revenue from contracts with customers by providing a principles-based approach to the recognition of revenue. The core principle of the standard is when an entity transfers goods or services to customers it will recognize revenue in an amount that reflects the consideration the entity expects to be entitled to for those goods or services. The standard outlines a five-step model and related application guidance, which replaces most existing revenue recognition guidance. ASU 2014-09 also requires disclosures that will enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption not permitted. The Company has not yet selected a transition method nor has it determined the impact, if any, of the standard on its ongoing financial condition and results of operations.

Reclassifications - Federal and state income taxes were previously presented as a component of total operating expenses and have been reclassified to conform with the current period presentation following income before income taxes in the Statement of Income.

2. ACQUISITION

On September 2, 2014, Laclede Group acquired all outstanding equity of the Company (the "Transaction") from Energen for approximately $1,600.0, including the assumption of $250.0 of the Company's long-term debt. The consideration is subject to certain post-closing adjustments for cash, indebtedness and working capital which at this time are not expected to be material. The Acquisition was accounted for under the acquisition method of accounting in accordance with ASC 805 (“Topic 805”), “Business Combinations". Laclede Group determined that the Acquisition met the scope exceptions for pushdown accounting, and as such the excess consideration transferred over the fair value of assets acquired was recorded at Laclede Group. Laclede Group and Energen made an election under Section 338(h)(10) of the Internal Revenue Code of 1986, as amended, to treat the Acquisition as a deemed purchase and sale of assets for tax purposes. As a result the existing deferred tax assets and liabilities were remeasured to zero as of September 2, 2014, with a deferred tax asset of $280.1 established for excess tax basis in assets resulting from the election.     

3. REGULATORY MATTERS

The Company is subject to regulation by the APSC which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. The Company’s current RSE order had an original term extending through December 31, 2014. On December 20, 2013, the APSC issued a final written order modifying the RSE effective January 1, 2014 extending the term of the order beyond September 30, 2018 unless the APSC enters an order to the contrary in a manner consistent with law. In the event of unforeseen circumstances, whether physical or economic, of the nature of the force majeure and including a change in control, the APSC and the Company will consult in good faith with respect to modifications, if any. Effective January 1, 2014, the Company’s allowed range of return on average common equity is 10.5% to 10.95% with an adjusting point of 10.8%. The Company is eligible to receive a performance-based adjustment of 5 basis points to the return on equity adjusting point, based on meeting certain customer satisfaction criteria. The Company's previous allowed return on average common equity was 13.15% to 13.65% through December 31, 2013.

Under the RSE, the APSC conducts quarterly reviews to determine whether the Company’s return on average common equity at the end of the Rate Year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each Rate Year, effective December 1, and cannot exceed 4.0% of prior-year revenues. The Company’s year-end equity under the RSE is limited to 56.5% of total capitalization, subject to certain adjustments. During the transition period ended September 30, 2014 and the calendar years ended December 31, 2013 and 2012, the Company had net pre-tax reductions in revenues of $22.5, $10.6 and $6.3 , respectively, to bring the return on average equity to the midpoint within the allowed range of return. Under the provisions of the RSE, there was no change to revenue effective December 1, 2014. There was an $8.5 decrease, a $10.3 and $7.8 increase in revenue, effective January 1, 2014, December 1, 2013 and 2012, respectively.

The inflation-adjusted Cost Control Mechanism (CCM) established by the APSC, allows for annual changes to operations and maintenance (O&M) expense compared to a Base Year, defined as Alagasco’s 2007 actual Rate Year O&M expense, inflation-adjusted to September 30, 2013 using the Consumer Price Index for All Urban Consumer (Base Year O&M). An “Index Range” is established each Rate Year using Base Year O&M, inflation-adjusted using the June Consumer Price Index For All Urban Consumers for that Rate Year plus or minus 1.75% (Index Range). If Rate Year O&M expense falls within the Index Range, no adjustment is required. If Rate Year O&M expense exceeds the Index Range, three quarters of the difference is returned to customers through future rate adjustments. To the extent that Rate Year O&M is less than the Index Range, the utility benefits by one half of the difference through future rate adjustments. Certain items that fluctuate based on situations demonstrated to be beyond the Company’s control may be excluded from the CCM calculation. The Company’s O&M expense fell within the

36

Index Range for the Rate Years ended September 30, 2013, 2012 and 2011. For the Rate Year ended September 30, 2014, the Company’s O&M expense fell below the Index Range resulting in the Company benefitting by one half of the difference, or $2.4 pre-tax, with the related impact to rates effective December 1, 2014.

The APSC approved an Enhanced Stability Reserve (ESR) in 1998 which was subsequently modified and expanded in 2010. As currently approved, the ESR provides deferred treatment and recovery for the following: (1) extraordinary O&M expenses related to environmental response costs; (2) extraordinary O&M expenses related to self-insurance costs that exceed $1.0 per occurrence; (3) extraordinary O&M expenses, other than environmental response costs and self-insurance costs, resulting from a single force majeure event or multiple force majeure events greater than $0.3 and $0.4, respectively, during a Rate Year; and (4) negative individual large commercial and industrial customer budget revenue variances that exceed $0.4 during a Rate Year.

Charges to the ESR are subject to certain limitations which may disallow deferred treatment and which proscribe the timing of recovery. Current funding of the ESR is provided as a reduction to the refundable negative salvage balance over its nine year term beginning December 1, 2010. Subsequent to the nine year period and subject to APSC authorization, The Company anticipates recovering underfunded ESR balances over a five year amortization period with an annual limitation of $0.7. Amounts in excess of this limitation are deferred for recovery in future years.

4. LONG-TERM DEBT AND NOTES PAYABLE

Long-term debt consisted of the following:

($ Millions)	September 30, 2014			December 31, 2013
5.368% Notes, due December 1, 2015	$	80.0		$	80.0
5.20% Notes, due January 15, 2020	40.0			40.0
3.86% Notes, due December 21, 2021	50.0			50.0
5.70% Notes, due January 15, 2035	34.8			34.9
5.90% Notes, due January 15, 2037	45.0			45.0
Revolving credit facility	16.0			50.0
Total debt	265.8			299.9
Less: current portion	(16.0		)	(50.0		)
Total long-term debt	$	249.8		$	249.9

The aggregate maturities of the Company’s long-term debt for the next five years are as follows:

Years ending September 30, ($ Millions)
2015	2016	2017	2018	2019	2020 and beyond
$0.0	$80.0	$0.0	$0.0	$16.0	$169.8

The long-term debt and short-term debt agreements of the Company contain financial and nonfinancial covenants including routine matters such as timely payment of principal and interest, maintenance of corporate existence and restrictions on liens. Although none of the agreements have covenants or events of default based on credit ratings, the interest rates applicable to the Company syndicated credit facility discussed below may be adjusted based on credit rating changes. All of the Company’s debt is unsecured.

The Company has authority from the APSC to issue debt securities for up to $35.0. No securities have been issued under this authority.

The Company's Credit Facility

On September 2, 2014 the Company entered into a new syndicated revolving credit facility pursuant to a loan agreement (the Alagasco Loan Agreement) The initial borrowings under the Alagasco Loan Agreement were used to repay the approximately $15.0 of borrowings outstanding under the Company's then existing credit agreement which was terminated in connection with the closing of the Alagasco Loan Agreement.

The Alagasco Loan Agreement is for a term of five years ending September 2, 2019, but the Company may request up to twoone-year extensions. The Alagasco Loan Agreement contains nonfinancial covenants, including limitations on certain types of acquisitions, investments and sales of property. The Alagasco Loan Agreement also contains a financial covenant limiting the Company's debt to 70% of its capitalization. At September 30, 2014, this ratio was 24.0%, as defined under the letter of credit.

The Alagasco Loan Agreement has a credit commitment of $150.0. Under certain terms and conditions, the Company may request an increase of up to $50.0 in the credit commitment. The Alagasco Loan Agreement also provides for letters of credit

37

in an aggregate amount up to $15.0, and swingline loans in an aggregate amount up to $15.0. Letters of credit and swingline loans will constitute usage under the Alagasco Loan Agreement.

The Company was in compliance with all covenants at September 30, 2014.

The following is a summary of information relating to the Company credit facility:

($ Millions)	September 30, 2014			December 31, 2013
	2014 and 2012 Facilities			(October 2012 Facility)
Maximum amount outstanding at any month-end	$	55.0		$	75.0
Average daily amount outstanding	13.7			35.0
Weighted average interest rates based on:
Average daily amount outstanding	1.30		%	1.12		%
Amount outstanding at year-end	1.16		%	1.26		%

Total interest expense for the Company was $11.5, $15.6 and $16.3 for the transition period ended September 30, 2014 and the calendar years ended December 31, 2013 and 2012, respectively.

5. INCOME TAXES

The components of the Company’s income taxes consisted of the following:

	Nine Months ended		Calender Year Ended December 31,
($ Millions)	September 30, 2014		2013		2012
Taxes estimated to be payable currently:
Federal	$	14.1	$	17.5	$	18.3
State	1.8		2.2		0.7
Total current	$	15.9	$	19.7	$	19.0
Taxes deferred:
Federal	$	3.5	$	13.3	$	9.1
State	0.5		1.7		2.2
Total deferred	$	4.0	$	15.0	$	11.3
Total income tax expense	$	19.9	$	34.7	$	30.3

Total income tax expense for the Company differed from the amount that would have been provided by applying the statutory federal income tax rate of 35% to earnings before taxes as illustrated below:

	Nine Months Ended			Calendar Year Ended December 31,
($ Millions)	September 30, 2014			2013			2012
Income tax expense at statutory federal income tax rate	$	18.5		$	32.2		$	27.9
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit	1.5			2.6			2.3
Other, net	(0.1		)	(0.1		)	0.1
Total income tax expense	$	19.9		$	34.7		$	30.3
Effective income tax rate (%)	37.6		%	37.7		%	38.0		%

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Temporary differences and carryforwards which gave rise to the Company’s deferred tax assets and liabilities were as follows:

($ Millions)	September 30, 2014				December 31, 2013
	Current		Noncurrent		Current		Noncurrent
Deferred tax assets:
Unbilled and deferred revenue	$	2.5	$	—	$	12.5	$	—
Allowance for doubtful accounts	—		—		1.8		—
Insurance accruals	—		—		1.8		—
Compensation accruals	—		—		2.5		—
Inventories	—		—		1.3		—
Gas supply adjustment related accruals	—		—		0.7		—
Pension and other costs	—		10.6		—		—
Goodwill	—		266.1		—		—
Net operating loss	—		5.1		—		—
Other	0.2		—		1.0		—
Total deferred tax assets	$	2.7	$	281.8	$	21.6	$	—
Deferred tax liabilities:
Depreciation and basis differences	$	—	$	4.0	$	—	$	186.6
Pension and other costs	—		—		—		19.0
Other	0.4		—		1.6		—
Total deferred tax liabilities	0.4		4.0		1.6		205.6
Net deferred tax assets (liabilities)	$	2.3	$	277.8	$	20.0	$	(205.6	)

No valuation allowance with respect to deferred taxes is deemed necessary as the Company anticipates generating adequate future taxable income to realize the benefits of all deferred tax assets.

The Company is part of a consolidated federal income tax return with Laclede Group, from September 2 through September 30, 2014. Prior to September 2, 2014, the Company was part of a consolidated federal and state income tax return with our former parent, Energen. Income taxes are allocated to the Company as if it were a separate taxpayer. Pursuant to GAAP, the Company may recognize the tax benefit from a tax position only if it is at least more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The Company records potential interest and penalties related to its uncertain tax positions as income tax expense. Unrecognized tax benefits, accrued interest payable, and accrued penalties payable are included in the Other line of the Deferred Credits and Other Liabilities section of the Balance Sheets. None of the Company’s unrecognized tax benefits at September 30, 2014 would impact the Company’s effective tax rate, if recognized.

A reconciliation of the Company’s beginning and ending amount of unrecognized tax benefits is as follows:

($ Millions)
Balance as of December 31, 2011	$	0.1
Additions based on tax positions related to the current year	0.1
Additions for tax positions of prior years	0.2
Reductions for tax positions of prior years (lapse of statute of limitations)	(0.1		)
Balance as of December 31, 2012	0.3
Reductions for tax positions of prior years (lapse of statute of limitations)	—
Balance as of December 31, 2013	0.3
Reductions for transfer of balances to Energen	(0.3		)
Balance as of September 30, 2014	$	—

The Company’s tax returns for the calendar years 2010-2013 remain open and subject to examination by the IRS and major state taxing jurisdictions. These returns cover periods during which the Company was owned by Energen. As such, the impact of any adjustments made by the relevant taxing authorities would be addressed by Energen.

In September 2013, the Internal Revenue Service and US Treasury Department released final regulations on the deduction and capitalization of expenditures related to tangible property. The regulations do not address the tax treatment for network

39

assets such as natural gas pipelines. These regulations apply to tax years beginning on or after January 1, 2014. The Company is evaluating the effects of the regulations, but does not believe that they will have a significant impact on its financial statements.

6. PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS

The Company has defined qualified benefit plans covering the majority of its employees. Qualified plan assets are comprised of United States equities consisting of mutual and commingled funds with varying strategies, global equities consisting of mutual funds, alternative investments of limited partnerships and commingled mutual funds and fixed income investments.

During the prior year and part of the current year, the Company participated in employee benefit plans with Energen. Effective April 30, 2014, Energen Corporation separated one of its defined benefit non-contributory pension plans into an Energen plan and a separate Alagasco plan. The separation of plan assets and obligations was completed in accordance with ERISA provisions. Also effective April 30, 2014, Energen separated its postretirement health care and life insurance benefit plans into separate plans established for Energen and the Company’s employees in accordance with ERISA provisions. Energen and the Company remeasured all of the aforementioned respective plans using current assumptions.

The prior year figures in the following tables, unless explicitly stated otherwise, represent the combined financial information of the defined qualified and nonqualified supplemental benefit plans along with the postretirement health care and life insurance benefit plans prior to the separation of the plans between the Company and Energen.

Pension costs in the transition period ended September 30, 2014 and the calendar years ended December 31, 2013 and 2012 amounted to $16.8, $26.6, and $16.4, respectively.

The net periodic pension costs include the following components:

	Nine Months Ended			Calendar Year Ended December 31,
($ Millions)	September 30, 2014			2013			2012
Pension Plans
Components of net periodic benefit cost:
Service cost	$	5.1		$	14.2		$	10.5
Interest cost	4.1			11.2			10.8
Expected long-term return on assets	(5.2		)	(14.7		)	(14.1		)
Prior service cost amortization	0.1			0.5			0.6
Actuarial loss amortization	2.2			14.0			8.6
Amortization of prior regulatory assets and liabilities	0.4			—			—
Settlement charge	10.1			1.4			—
Net periodic expense	$	16.8		$	26.6		$	16.4
Postretirement Benefit Plans
Components of net periodic benefit cost:
Service cost	$	0.4		$	1.7		$	1.9
Interest cost	1.9			3.5			4.2
Expected long-term return on assets	(3.6		)	(5.0		)	(4.4		)
Actuarial (gain) loss amortization	(1.0		)	(0.1		)	—
Transition obligation amortization	—			1.3			1.9
Amortization of prior regulatory assets and liabilities	(0.2		)	—			—
Curtailment gain	—			(1.2		)	—
Net periodic expense	$	(2.5	)	$	0.2		$	3.6

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Obligations recognized in other comprehensive income were as follows:

	Nine Months Ended			Calendar Year Ended December 31,
($ Millions)	September 30, 2014			2013			2012
Pension Plans
Net actuarial (gain) loss experienced during the year	$	1.5		$	(14.1	)	$	28.7
Net actuarial loss recognized as expense	—			(8.9		)	(4.9		)
Prior service cost recognized as expense	—			(0.3		)	(0.3		)
	1.5			(23.3		)	23.5
Transfer to regulatory assets (liabilities)	(1.5		)	—			—
Other Comprehensive Income	$	—		$	(23.3	)	$	23.5
Postretirement Benefit Plans
Net actuarial (gain) loss experienced during the year	$	1.1		$	(8.1	)	$	(1.8	)
Net actuarial gain recognized as expense	—			0.6			—
Transition obligation recognized as expense	—			(0.3		)	(0.3		)
	1.1			(7.8		)	(2.1		)
Transfer to regulatory assets (liabilities)	(1.1		)	—			—
Other Comprehensive Income	$	—		$	(7.8	)	$	(2.1	)

After the Acquisition, the Company began amortizing its existing regulatory assets and liabilities attributable to the pension and postretirement benefits over the average remaining service for active participants as of the date of the Acquisition. Therefore, any new regulatory asset or liability is attributable to the pension or postretirement benefit plans after the date of the Acquisition. The Company recognized a regulatory asset of $72.5 and a regulatory liability of $28.5, when the plans were remeasured at September 1, 2014.

During the transition period ended September 30, 2014 and calendar 2013 the Company incurred settlement charges of $0.0 and $0.5 respectively for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.0 and $0.1 respectively was expensed and $0.0 and $0.4 was recognized as a pension and postretirement asset in regulatory assets at the Company.

The following table sets forth the reconciliation of the beginning and ending balances of the pension benefit obligation:

	September 30,			December 31,			September 30,			December 31,
	2014			2013			2014			2013
($ MIllions)	Pension						Postretirement Benefits
Accumulated benefit obligation	$	129.6		$	253.0
Benefit obligation:
Balance at beginning of period	293.4			323.5			63.6			85.8
Energen portion of liability divested	(144.7		)	—			(13.3		)	—
Liability loss due to estimated allocation	16.9			—			7.7			—
Service cost	5.1			14.2			0.4			1.7
Interest cost	4.1			11.2			1.9			3.5
Actuarial (gain) loss	7.8			(28.3		)	4.3			(21.7		)
Curtailment gain	—			(4.2		)	—			(1.3		)
Retiree drug subsidy program	—			—			0.3			0.3
Benefits paid	(33.8		)	(23.0		)	(4.0		)	(4.7		)
Balance at end of period	$	148.8		$	293.4		$	60.9		$	63.6

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The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets:

	September 30,			December 31,			September 30,			December 31,
	2014			2013			2014			2013
($ Millions)	Pension						Postretirement Benefits
Plan assets:
Fair value of plan assets at beginning of period	$	219.5		$	209.3		$	98.9		$	87.1
Energen portion of assets divested	(90.9		)	—			(22.0		)	—
Asset gain due to estimated allocation	15.0			—			11.0			—
Actual return on plan assets	7.8			23.0			1.4			14.9
Employer contributions	1.6			10.2			0.3			1.6
Benefits paid	(33.8		)	(23.0		)	(4.0		)	(4.7		)
Fair value of plan assets at end of period	$	119.2		$	219.5		$	85.6		$	98.9
(Unfunded) funded status of plan	$	(29.6	)	$	(73.8	)	$	24.7		$	35.4

The following table sets forth the amounts recognized in the Balance Sheets:

	September 30,			December 31,			September 30,		December 31,
	2014			2013			2014		2013
($ Millions)	Pension						Postretirement Benefits
Noncurrent assets	$	—		$	—		$	24.7	$	35.4
Current liabilities	—			(6.1		)	—		—
Noncurrent liabilities	(29.6		)	(67.7		)	—		—
Net asset (liability) recognized	$	(29.6	)	$	(73.8	)	$	24.7	$	35.4

A summary of the Company's allocated share of the benefit plans described above is presented below as of the transition period and calendar year end, respectively:

	September 30,			December 31,			September 30,			December 31,
	2014			2013			2014			2013
($ MIllions)	Pension						Postretirement Benefits
Net benefit asset noncurrent	$	—		$	—		$	24.7		$	26.5
Net benefit liability noncurrent	(29.6		)	(20.2		)	—			—
Regulatory asset	67.8			58.5			4.7			—
Regulatory liability	$	(1.9	)	$	—		$	(26.6	)	$	(26.2	)

The pension regulatory assets and liabilities are allowed to be recovered or refunded through rates in subsequent years.

Assumptions are used based on the unique set of characteristics for each of the individual pension and postretirement plans.

	Nine Months Ended		Calendar Years Ended December 31,
	September 30, 2014		2013		2012
Pension Plans
Discount rate	4.00% & 4.05%		3.63	%	4.52	%
Expected long-term return on plan assets	7.25% & 7.00%		7.00	%	7.00	%
Rate of compensation increase for pay-related plans	2.92	%	3.71	%	3.59	%
Postretirement Benefit Plans
Discount rate	4.25	%	4.26	%	4.95	%
Expected long-term return on plan assets	7.25% & 4.75%		7.00	%	7.00	%

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The weighted average rate assumptions used to determine the projected benefit obligations at the measurement date were as follows:

	September 30, 2014		December 31, 2013
Pension Plans
Discount rate	4.15% & 4.25%		4.30	%
Rate of compensation increase for pay-related plans	2.92	%	3.60	%
Postretirement Benefit Plans
Discount rate	4.40	%	5.00	%

The assumed post-65 health care cost trend rates used to determine the postretirement benefit obligation at the measurement date were as follows:

	September 30, 2014		December 31, 2013
Health care cost trend rate assumed for next year	7.25	%	6.50	%
Rate to which the cost trend rate is assumed to decline	5.00	%	5.00	%
Year that rate reaches ultimate rate	2020		2020

Assumed health care cost trend rates used in determining the accumulated postretirement benefit obligation have an effect on the amounts reported. For example, revising the weighted average health care cost trend rate by 1 percentage point would have the following effects:

($ Millions)	1-Percentage Point Decrease			1-Percentage Point Increase
Effect on total of service and interest cost	$	—		$	—
Effect on net postretirement benefit obligation	(0.7		)	0.7

Following are the targeted and actual plan assets by asset category:

	Pension						Postretirement Benefits
	Target		September 30, 2014		December 31, 2013		Target		September 30, 2014		December 31, 2013
Asset category:
Equity securities	41.0	%	51.0	%	34.0	%	60.0	%	60.0	%	61.0	%
Debt securities	38.0	%	36.0	%	28.0	%	40.0	%	40.0	%	39.0	%
Other	21.0	%	13.0	%	38.0	%	—	%	—	%	—	%
Total	100.0	%	100.0	%	100.0	%	100.0	%	100.0	%	100.0	%

The Companyemploys a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets with a prudent level of risk. Risk tolerance is established through consideration of plan liabilities, plan funded status, corporate financial condition and market conditions.

The Company has developed an investment strategy that focuses on asset allocation, diversification and quality guidelines. The investment goals are to obtain an adequate level of return to meet future obligations of the plan by providing above average risk-adjusted returns with a risk exposure in the mid-range of comparable funds. Investment managers are retained by the Company to manage separate pools of assets. Funds are allocated to such managers in order to achieve an appropriate, diversified, and balanced asset mix. Comparative market and peer group benchmarks are utilized to ensure that investment managers are performing satisfactorily.

The Company seeks to maintain an appropriate level of diversification to minimize the risk of large losses in a single asset class. Accordingly, plan assets for the pension plans and the postretirement health care and life insurance benefit plan do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.

Equity securities for pension and postretirement benefits do not include the Laclede Group's common stock.

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Plan assets included in the funded status of the pension plans were as follows:

	September 30, 2014
($ Millions)	Level 1		Level 2		Level 3		Total
United States equities (1)	$	30.4	$	13.6	$	—	$	44.0
Global equities (2)	12.3		0.0		—		12.3
Fixed income (3)	11.5		31.9		—		43.4
Alternative investments (4)	—		17.6		—		17.6
Cash and cash equivalents	0.3		1.6		—		1.9
Total	$	54.5	$	64.7	$	—	$	119.2
	December 31, 2013
($ Millions)	Level 1		Level 2		Level 3		Total
United States equities (1)	$	34.1	$	8.1	$	—	$	42.2
Global equities (2)	20.1		13.3		—		33.4
Fixed income (3)	—		61.1		—		61.1
Alternative investments (4)	—		37.3		—		37.3
Cash and cash equivalents	6.0		39.5		—		45.5
Total	$	60.2	$	159.3	$	—	$	219.5

(1) United States equities consist of mutual and commingled funds with varying strategies. Such strategies include stock investments across market capitalizations and investment styles. 

(2) Global equities consist of mutual funds and a limited partnership that invest in United States and non-United States securities broadly diversified across mostly developed markets but with some tactical exposure to emerging markets.

(3) Fixed income securities consist of mutual funds and separate accounts. Fixed income securities are well diversified with allocations to investment grade and non-investment grade issues and issues that provide both intermediate and longer duration exposure.

(4) Alternative investments consist of limited partnerships and commingled and mutual funds with varying investment strategies. Alternative investments are meant to serve as a risk reducer at the total portfolio level as they provide asset class exposures not found elsewhere in the portfolio.

The following is a reconciliation of plan assets in Level 3 of the fair value hierarchy:

	Nine Months Ending September 30,		Calendar Year Ending December 31,
($ Millions)	2014		2013
Balance at beginning of period	$	—	$	14.5
Transfer out of level 3	—		(14.5		)
Balance at end of period	$	—	$	—

Plan assets included in the funded status of the postretirement benefit plans were as follows:

	September 30, 2014
($ Millions)	Level 1		Level 2		Total
United States equities (1)	$	43.9	$	—	$	43.9
Global equities (2)	7.2		—		7.2
Fixed income (3)	—		34.4		34.4
Cash and cash equivalents	0.1		—		0.1
Total	$	51.2	$	34.4	$	85.6

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	December 31, 2013
($ Millions)	Level 1		Level 2		Total
United States equities	$	43.1	$	—	$	43.1
Global equities	17.0		—		17.0
Fixed income	—		38.8		38.8
Cash and cash equivalents	—		—		—
Total	$	60.1	$	38.8	$	98.9

(1) United States equities consists of mutual funds with varying strategies. These funds invest largely in medium to large capitalized companies with exposure blending growth, market-oriented and value styles. Additional fund investments include small capitalization companies, and certain of these funds utilize tax-sensitive management approaches.

(2) Global equities are mutual funds that invest in non-United States securities broadly diversified across most developed markets with exposure blending growth, market-oriented and value styles.

(3)Fixed income securities are high-quality short-duration securities including investment-grade market sectors with tactical investments in non-investment grade sectors.

The following benefit payments, which reflect expected future service, as appropriate, are anticipated to be paid as follows. In addition, the following benefits reflect the expected prescription drug subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act). The Act includes a prescription drug benefit under Medicare Part D as well as a federal subsidy which began in 2007:

($ Millions)	Pension Benefits		Postretirement Benefits		Postretirement Benefits – Prescription Drug Subsidy
2015	$	9.9	$	3.8	$	(0.2	)
2016	10.2		3.8		(0.2		)
2017	10.6		3.8		(0.2		)
2018	10.6		3.8		(0.2		)
2019	11.2		3.8		(0.3		)
2020-2024	58.7		18.6		(1.3		)

There are no required contributions to the qualified pension plans during 2015. Additionally, it is not anticipated that the funded status of the qualified pension plans will fall below statutory thresholds requiring accelerated funding or constraints on benefit levels or plan administration. During fiscal 2015 the Company may make additional discretionary contributions to the qualified pension plans depending on the amount and timing of employee retirements and market conditions.

7. COMMITMENTS AND CONTINGENCIES

Commitments and Agreements:

Certain of the Company’s long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $134.0 through September 2024. During the transition period ended September 30, 2014 and the calendar years ended December 31, 2013 and 2012, the Company recognized approximately $33.8, $50.0 and $51.0, respectively, of current year commitments through expense and its regulatory accounts in the accompanying financial statements. The Company also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 111 bcf through August 2020.

Environmental Matters:

Various environmental laws and regulations apply to the operations of the Company. Historically, the cost of environmental compliance has not materially affected the Company’s financial position, results of operations or cash flows. New regulations, enforcement policies, claims for damages or other events could result in significant unanticipated costs.

The Company is in the chain of title of nine former manufactured gas plant sites, four of which it still owns, and five former manufactured gas distribution sites, one of which it still owns. Management expects that, should future remediation of the sites be required, the Company’s share of the remediation costs will not materially affect the financial position of the Company. During 2011, a removal action was completed at the Huntsville, Alabama manufactured gas plant site pursuant to an Administrative Settlement Agreement and Order on Consent among the EPA, the Company and the current site owner.

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In 2012, the Company responded to a U.S. Environmental Protection Agency (EPA) Request for Information Pursuant to Section 104 of Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) relating to the 35thAvenue Superfund Site located in North Birmingham, Jefferson County, Alabama. The Request related to a former site of a manufactured gas distribution facility owned by the Company and located in the vicinity of the 35thAvenue Superfund Site. In September 2013, the Company received from the EPA a General Notice Letter and Invitation to Conduct a Removal Action at the 35th Avenue Superfund Site. The letter identifies the Company as a Potentially Responsible Party (PRP) under CERCLA for the cleanup of the Site or costs the EPA incurs in cleaning up the Site. The EPA also offered the PRP group the opportunity to conduct Phase I of the proposed removal action which involved removal activities at approximately 50 residences that purportedly exceed certain risk levels for contamination. In August of 2014, the EPA offered the PRP group the opportunity to conduct Phase II of the proposed removal action which involved removal activities at approximately 30 additional residences that purportedly exceed certain risk levels for contamination. The Company has discussed its designation as a PRP with the EPA, and the Company has requested additional information from the EPA regarding its designation as a PRP. The Company has not been provided information at this time that would allow it to determine the extent, if any, of its potential liability with respect to the 35th Avenue Superfund Site and the proposed removal action; therefore, no amount has been accrued as of September 30, 2014.

Legal Matters:

The Company, from time to time, is party to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. The Company recognizes its liability for contingencies when information available indicates both a loss is probable and the amount of the loss can be reasonably estimated. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial position of the Company. It should be noted, however, that there is uncertainty in the valuation of pending claims and prediction of litigation results.

On December 17, 2013, an incident occurred at a Housing Authority apartment complex in Birmingham, Alabama which resulted in one fatality, personal injuries and property damage. The Company is cooperating with the National Transportation and Safety Board which is investigating the incident. The Company has been named as a defendant in several lawsuits arising from the incident and additional lawsuits and claims may be filed against the Company.

Lease Obligations:

The Company entered into an amendment to its lease for its primary offices in February 2013 with a term ending February 28, 2018. There is no renewal option. This lease is classified as an operating lease. The Company also has a lease obligation for additional office space which expires January 31, 2024. Under the terms of this lease, the Company has five renewal options to extend the lease term by five years under each renewal. This lease is accounted for as an operating lease. The Company has subleased all of this office space to Energen pursuant to a sublease that expires on December 31, 2019 with an option to extend through January 31, 2024.

The Company’s total payments related to leases included as operating expense were $1.8, $2.4 and $2.1 for the transition period ended September 30, 2014 and the calendar years ended December 31, 2013 and 2012, respectively. These amounts are net of approximately $0.0, $0.7 and $1.0 of sublease income in the transition period ended September 30, 2014 and the calendar years ended December 31, 2013 and 2012, respectively. Minimum future rental payments required after September 30, 2014 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:

($ Millions)
2015	2016	2017	2018	2019	2020 and thereafter
4.3	3.9	4.0	2.9	2.1	9.1

Included in the table above are approximately $11.0 of payments associated with subleasing of its previous headquarters, which are expected to be reimbursed to the Company by Energen through the remaining term of the related lease.

8. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Financial Instruments:

The stated value of cash and cash equivalents, short-term investments, trade receivables (net of allowance), and short-term debt approximates fair value due to the short maturity of the instruments. The fair value of the Company’s fixed-rate long-term debt, including the current portion, approximates $266.4 and $258.8 and has a carrying value of $249.8 and $249.9 at September 30, 2014 and December 31, 2013, respectively. The fair values were based on market prices of similar instruments having the same remaining maturities, redemption terms and credit rating. Short-term debt is classified as Level 1 fair value and long-term debt is classified as Level 2 fair value.

46

The Company purchases gas as an agent for certain of its large commercial and industrial customers. The Company has, in certain instances, provided commodity-related guarantees to counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the balance sheet. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, the Company can sell such gas for the customer, with the customer liable for any resulting loss. Although the substantial majority of purchases under these guarantees are for the customers’ current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At September 30, 2014, the fixed price purchases under these guarantees had a maximum term outstanding through August 2015 with an aggregate purchase price of $0.6 and a market value of $0.6.

Finance Receivables:

The Company finances third party contractor sales of merchandise including gas furnaces and appliances. At September 30, 2014 and December 31, 2013, the Company’s finance receivable totaled approximately $10.9 and $10.8, respectively. Financing is available only to qualified customers who meet creditworthiness thresholds for customer payment history and external agency credit reports. The Company relies upon ongoing payments as the primary indicator of credit quality during the term of each contract. The allowance for credit losses is recognized using an estimate of write-off percentages based on historical experience applied to an aging of the finance receivable balance. Delinquent accounts are evaluated on a case-by-case basis and, absent evidence of debt repayment after 90 days, are due in full and assigned to a third party collection agency. The remaining finance receivable is written off approximately 12 months after being assigned to the third party collection agency. The Company had finance receivables past due 90 days or more of $0.3 and $0.4 as of September 30, 2014 and December 31, 2013, respectively. The Company recorded an allowance for credit losses at September 30, 2014 and December 31, 2013 of $0.3 and $0.4, respectively.

Concentration of Credit Risk:

Natural gas distribution operating revenues and related accounts receivable are generated from state-regulated utility natural gas sales and transportation to approximately 423,000 residential, commercial and industrial customers located in central and north Alabama. A change in economic conditions may affect the ability of customers to meet their obligations; however, the Company believes that its provision for possible losses on uncollectible accounts receivable is adequate for its credit loss exposure.

9. ASSET RETIREMENT OBLIGATIONS

The Company recognizes conditional obligations if such obligations can be reasonably estimated and a legal requirement to perform an asset retirement activity exists. The Company accrues removal costs on certain gas distribution assets over the useful lives of its property, plant and equipment through depreciation expense in accordance with rates approved by the APSC. The Company recorded a conditional asset retirement obligation, on a discounted basis, of $27.7 and $27.5 to purge and cap its gas pipelines upon abandonment and to remediate other related obligations, as a regulatory liability as of September 30, 2014 and December 31, 2013, respectively. Regulatory assets for rate recovery of accumulated asset removal costs of $2.8 and $4.6 as of September 30, 2014 and December 31, 2013, respectively, are included as regulatory assets in noncurrent assets on the balance sheets. The costs associated with asset retirement obligations are either currently being recovered in rates or are probable of recovery in future rates.

The following table presents a reconciliation of the beginning and ending balances of asset retirement obligations at September 30, 2014 and December 31, 2013 as reported in the Balance Sheet:

($ Millions)	September 30, 2014			December 31, 2013
Asset retirement obligations, beginning of year	$	27.5		$	24.9
Liabilities incurred during the period	0.5			0.8
Liabilities settled during the period	(0.1		)	(0.1		)
Accretion	0.7			1.3
Revisions in estimated cash flows	(0.9		)	0.6
Asset retirement obligations, end of year	$	27.7		$	27.5

10. SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental information concerning the Company’s cash flow activities was as follows:

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	Nine Months Ended		Calendar Years Ended December 31,
($ Millions)	September 30, 2014		2013		2012
Interest paid, net of amount capitalized	$	9.6	$	13.5	$	13.5
Income taxes paid	20.4		23.1		16.8
Interest expense on affiliated company debt, net	—		—		0.3
Non-cash investing activities:
Accrued property, plant and equipment costs	5.0		5.5		3.5

Non cash activities related to capitalized depreciation, capitalized asset retirement obligation costs and allowance for funds used during construction were not significant for the transition period ended September 30, 2014 and the calendar years ended December 31, 2013 and 2012.

11. ACQUISITION AND DISPOSITION OF PROPERTIES

In August 2013, the Company recorded a pre-tax gain of $10.9 related to the sale of its Metro Operations Center, which is located in Birmingham, Alabama, and has been in service since the 1940s. The Company received approximately $13.8 in cash from the sale of this property. During the third calendar quarter of 2013, the gain on the sale was recognized in other income and a related reduction in revenues was recognized to defer the gain as a regulatory liability pending review by the APSC. In conjunction with the receipt of the rate order from the APSC on December 20, 2013, the Company recognized the deferred revenues from this sale in the fourth calendar quarter of 2013. Effective upon the sale of the Metro Operations Center, the Company leased the facility from the purchaser for a period of approximately 20 months.

12. REGULATORY ASSETS AND LIABILITIES

The Company accounts for regulated operations in accordance with ASC Topic 980, Regulated Operations. This topic sets forth the application of GAAP for those companies whose rates are established by or are subject to approval by an independent third party regulator. The provisions of this accounting guidance require, among other things, that financial statements of a regulated enterprise reflect the actions of regulators, where appropriate. These actions may result in the recognition of revenues and expenses in time periods that are different than non-regulated enterprises. When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses when those amounts are reflected in rates. Also, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for recovery of costs that are expected to be incurred in the future (regulatory liabilities).

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The following regulatory assets and regulatory liabilities were reflected in the Company's Balance Sheets and also included below:

	September 30, 2014				December 31, 2013
($ Millions)	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Postretirement assets	$	6.4	$	66.1	$	0.3	$	58.2
Accretion and depreciation for asset retirement obligation	—		18.3		—		18.0
Rate recovery of asset removal costs, net	—		2.8		—		4.7
Enhanced stability reserve	—		3.4		—		4.0
Gas supply adjustment	—		—		2.5		—
RSE adjustment	2.4		—		—		—
Total regulatory assets	$	8.8	$	90.6	$	2.8	$	84.9
Regulatory liabilities:
RSE adjustment	$	19.8	$	—	$	4.7	$	—
Unbilled service margin	5.2		—		28.5		—
Postretirement liabilities	2.3		26.2		—		26.2
Refundable negative salvage	13.4		26.8		15.8		39.7
Gas supply adjustment	22.4		—		—		—
Other	—		0.7		—		0.7
Total regulatory liabilities	$	63.1	$	53.7	$	49.0	$	66.6

13. TRANSACTIONS WITH RELATED PARTIES

Prior to the Transaction, Energen allocated certain corporate costs to the Company based on the nature of the expense using various factors including, but not limited to, total assets, earnings, or number of employees. The Company’s cash management program was established to minimize borrowing from outside sources through inter-company lending. Under this program, the Company borrowed from but did not lend to affiliates. The Company had net trade receivables from affiliates of $0.0 and $4.7 at September 30, 2014 and December 31, 2013, respectively. The Company had net trade payables to affiliates of $0.4 and $0.0 at September 30, 2014 and December 31, 2013, respectively. Interest income and expense between affiliates was calculated monthly based on the market weighted average interest rate. The Company had $0.0, $0.0 and $0.3 in affiliated company interest expense during the transition period ended September 30, 2014 and the calendar years ended December 31, 2013 and 2012, respectively. The Company paid dividends to Energen of $32.4, $33.3 and $33.6 during the transition period ended September 30, 2014 and the calendar years ended December 31, 2013 and 2012, respectively. The Company also paid dividends to Laclede of $5.0 in the transition period ended September 30, 2014.

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14. COMPARABLE NINE-MONTH FINANCIAL INFORMATION (UNAUDITED)

Effective as of September 2, 2014, the Company changed its fiscal year end from December 31 to September 30. Statements of Income for the nine months ended September 30, 2014 and 2013 are summarized below. All data for the nine months ended September 30, 2014 and 2013 are derived from the Company’s unaudited financial statements.

STATEMENTS OF INCOME	Nine Months Ended September 30,
($ Millions)	2014		2013
Operating Revenues:
Utility	$	417.2	$	390.6
Total Operating Revenues	417.2		390.6
Operating Expenses:
Utility
Natural gas	184.5		163.4
Other operation and maintenance expenses	107.5		107.7
Depreciation and amortization	34.4		32.7
Taxes, other than income taxes	28.6		27.8
Total Utility Operating Expenses	355.0		331.6
Operating Income	62.2		59.0
Other Income, Net	2.2		13.2
Interest Charges:
Interest on long-term debt	10.1		10.1
Other interest charges	1.4		1.6
Total Interest Charges	11.5		11.7
Income Before Income Taxes	52.9		60.5
Income Tax Expense	19.9		22.9
Net Income	$	33.0	$	37.6

15. SUMMARIZED QUARTERLY FINANCIAL DATA (UNAUDITED)

In the opinion of the Company, the quarterly information presented below for the nine month period ended September 30, 2014 and the calendar year ended December 31, 2013 includes all adjustments (consisting of only normal recurring accruals) necessary for a fair statement of the results of operations for such periods. Variations in operations reported on a quarterly basis primarily reflect the seasonal nature of the business of the Company.

	Nine Months Ended September 30, 2014
($ Millions)	First		Second			Third
Operating revenues	$	263.9	$	93.9		$	59.4
Operating income (loss)	72.4		1.9			(12.1		)
Net income (loss)	43.0		(0.6		)	(9.4		)
	Calendar Year Ended December 31, 2013
($ Millions)	First		Second			Third			Fourth
Operating revenues	$	237.7	$	104.5		$	48.4		$	142.7
Operating income (loss)	79.3		2.2			(22.5		)	34.7
Net income (loss)	47.2		(0.7		)	(8.9		)	19.8

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

There have been no changes in and disagreements on accounting and financial disclosure with Alabama Gas Corporation's outside auditors that are required to be disclosed.

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ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

As of the end of the period covered by this report, the Company carried out an evaluation, under the supervision and with participation of its management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures pursuant to Rule 13a-15e and Rule 15d-15e under the Securities Exchange Act of 1934, as amended. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company's disclosure controls and procedures are effective.

(b) Changes in Internal Controls

There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended September 30, 2014 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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ITEM 9B. OTHER INFORMATION

None.

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PART IV

Item 15. Exhibits

(a)    1.    Financial Statements:

See Item 8. Financial Statements and Supplementary Data, filed herewith, for a list of financial

statements.

2.Exhibits

Incorporated herein by reference to Index of Exhibits, page 77

(b)        Incorporated herein by reference to Exhibits, page 77

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

			ALABAMA GAS CORPORATION
Dated:	November 25, 2014	By	/s/ Steven P. Rasche
			Steven P. Rasche
			Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Date	Signature		Title
November 25, 2014	/s/	Suzanne Sitherwood	Chairman of the Board and
		Suzanne Sitherwood	Chief Executive Officer
			(Principal Executive Officer)
November 25, 2014	/s/	Steven P. Rasche	Director and Chief Financial Officer
		Steven P. Rasche	(Principal Financial and Accounting Officer)
November 25, 2014	/s/	Steve L. Lindsey	Director and President
		Steven L. Lindsey
November 25, 2014	/s/	Mark C. Darrell	Senior Vice President, General Counsel and Chief Compliance Officer
		Mark C. Darrell
November 25, 2014	/s/	Mary C. Kullman	Director and Senior Vice President and Corporate Secretary
		Mary C. Kullman

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INDEX TO EXHIBITS

Exhibit
No.
*3(a)	Articles of Amendment and Restatement of the Articles of Incorporation of Alabama Gas Corporation, dated September 27, 1995, which was filed as Exhibit 3(i) to the Registrant’s Annual Report on Form 10-K for the year ended September 30, 1995
3(b)	Bylaws of Alabama Gas Corporation (as amended September 2, 2014)
*4(a)	Indenture dated as of November 1, 1993, between Alabama Gas Corporation and NationsBank of Georgia, National Association, Trustee, (“Alagasco 1993 Indenture”), which was filed as Exhibit 4(k) to Alabama Gas Corporations’ Registration Statement on Form S-3 (Registration No. 33-70466)
*4(a)(i)	Officers’ Certificate, dated January 14, 2005, pursuant to Section 301 of the Alabama Gas Corporation 1993 Indenture setting forth the terms of the 5.70 percent Notes due January 15, 2035, which was filed as Exhibit 4.3 to Alabama Gas Corporations’ Current Report on Form 8-K filed January 14, 2005
*4(a)(ii)	Officers’ Certificate, dated January 14, 2005, pursuant to Section 301 of the Alabama Gas Corporation 1993 Indenture setting forth the terms of the 5.20 percent Notes due January 15, 2020, which was filed as Exhibit 4.4 to Alabama Gas Corporations’ Current Report on Form 8-K filed January 14, 2005
*4(a)(iii)	Officers’ Certificate, dated November 17, 2005, pursuant to Section 301 of the Alabama Gas Corporation 1993 Indenture setting forth the terms of the 5.368 percent Notes due December 1, 2015, which was filed as Exhibit 4.2 to Alabama Gas Corporations’ Current Report on Form 8-K filed November 17, 2005
*4(a)(iv)	Officers’ Certificate, dated January 16, 2007, pursuant to Section 301 of the Alabama Gas Corporation 1993 Indenture setting forth the terms of the 5.90 percent Notes due January 15, 2037, which was filed as Exhibit 4.2 to Alabama Gas Corporations’ Current Report on Form 8-K filed January 16, 2007
*10(b)	Credit Agreement dated September 2, 2014, by and among Alabama Gas Corporation, Wells Fargo Bank, National Association., as Administrative Agent, Credit Suisse AG, Cayman Islands Branch and U.S. Bank National Association, as CO-Syndication Agents, Wells Fargo Securities LLC, Credit Suisse Securities (USA) LLC and U.S. Bank National Association, as Joint Lead Arrangers and Joint Book Managers, and the lenders party thereto which was filed as Exhibit 991. to Alabama Gas Corporation’s Current Report on Form 8-K filed September 4, 2014.
*10(c)	Credit Agreement dated October 30, 2012, by and among Alabama Gas Corporation, Bank of America, N.A., as Administrative Agent, Swing Line Lender and an L/C Issuer, Wells Fargo Bank, National Association and Regions Bank, and Co-Syndication Agents and L/C Issuers, Compass Bank and U.S. Bank National Association, as Co- Documentation Agents and L/C Issuers, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Wells Fargo Securities LLC, Regions Capital Markets, a division of Regions Bank, Compass Bank and U.S. Bank National Association, as Joint Lead Arrangers and Joint Book Managers, and the lenders party thereto which was filed as Exhibit 10.2 to Energen’s Current Report on Form 8-K filed October 31, 2012
*10(d)	Note Purchase Agreement, dated December 22, 2011, among Alabama Gas Corporation and the Purchasers thereto (the AIG purchasers) with respect to $25 million 3.86 percent Senior Notes due December 22, 2021, which was filed as Exhibit 10.1 to Alabama Gas Corporation’s Current Report on Form 8-K filed December 22, 2011
*10(e)	Note Purchase Agreement, dated December 22, 2011, among Alabama Gas Corporation and the Purchasers thereto (the Prudential purchasers) with respect to $25 million 3.86 percent Senior Notes due December 22, 2021, which was filed as Exhibit 10.2 to Alabama Gas Corporation’s Current Report on Form 8-K filed December 22, 2011
*10(f)	Service Agreement Under Rate Schedule CSS (No. SSNG1), between Southern Natural Gas Company and Alabama Gas Corporation, dated as of September 1, 2005, which was filed as Exhibit 10(a) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2005
*10(g)	Amended Exhibit A, effective January 15, 2014, to Service Agreement Under Rate Schedule CSS (No. SSNG1) between Southern Natural Gas Company and Alabama Gas Corporation dated September 1, 2005
*10(h)	Firm Transportation Service Agreement Under Rate Schedule FT and/or FT-NN (No. FSNG1), between Southern Natural Gas Company and Alabama Gas Corporation dated as of September 1, 2005, which was filed as Exhibit 10(b) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2005
*10(i)	Amended Exhibit A, effective October 1, 2013, to Firm Transportation Service Agreement (No. FSNG1) between Southern Natural Gas Company and Alabama Gas Corporation
*10(j)	Amended Exhibit B, effective November 1, 2013, to Firm Transportation Service Agreement (No. FSNG1) between Southern Natural Gas Company and Alabama Gas Corporation
*10(k)	Form of Service Agreement Under Rate Schedule IT (No. 790420), between Southern Natural Gas Company and Alabama Gas Corporation, which was filed as Exhibit 10(b) to Energen’s Annual Report on Form 10-K for the year ended September 30, 1993

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*10(l)		Service Agreement between Transcontinental Gas Pipeline Corporation and Transco Energy Marketing Company as Agent for Alabama Gas Corporation, dated August 1, 1991 which was filed as Exhibit 3(e) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2003
*10(m)		Amendment to Service Agreement between Transcontinental Gas Pipeline Corporation and Alabama Gas Corporation, dated December 2, 2005, which was filed as Exhibit 10(e) to Energen’s Annual Report on Form 10-K for the year ended December 31, 2005
31		Alabama Gas Corporation Certifications of the CEO and CFO pursuant to Rule 13a-14(a) or 15d-14(a) 31(b)
32		Alabama Gas Corporation Certifications of the CEO and CFO pursuant to 18 U.S.C. Section 1350
101.INS	-	XBRL Instance Document. (1)
101.SCH	-	XBRL Taxonomy Extension Schema. (1)
101.CAL	-	XBRL Taxonomy Extension Calculation Linkbase. (1)
101.DEF	-	XBRL Taxonomy Definition Linkbase. (1)
101.LAB	-	XBRL Taxonomy Extension Labels Linkbase. (1)
101.PRE	-	XBRL Taxonomy Extension Presentation Linkbase. (1)

(1) Attached as Exhibit 101 to this Annual Report are the following documents formatted in extensible business reporting language (XBRL): (i) Document and Entity Information; (ii) Statements of Income for the nine months ended September 30, 2014 and the years ended December 31, 2013 and 2012; (iii) Balance Sheets at September 30, 2014 and December 31, 2013; (vi) Statements of Capitalization at September 30, 2014 and December 31, 2013; (vii) Statements of Common Shareholders' Equity for the nine months ended September 30, 2014 and the years ended December 31, 2013 and 2012; (v) Statements of Cash Flows for the nine months ended September 30, 2014 and the years ended December 31, 2013, and 2012; and (viii) Notes to the Financial Statements. We also make available on our website the Interactive Data Files submitted as Exhibit 101 to this Annual Report. 

*Incorporated by reference and made a part hereof. Alabama Gas Corporation File No. 2-38960

57

EX-3

AMENDED AND RESTATED BYLAWS

OF

ALABAMA GAS CORPORATION

(effective September 1, 2014)

ARTICLE I

OFFICES

Section 1. Principal Office. The principal office of Alabama Gas Corporation (the “Corporation”) shall be at such place as the Board of Directors may from time to time determine, but until a change is effected, such principal office shall be at 605 Richard Arrington Blvd., Birmingham, Alabama 35203.

Section 2. Other Offices. The Corporation may also have offices at such other places both within and without the State of Alabama as the Board may, from time to time, determine or the business of the Corporation may require.

ARTICLE II

SEAL

The Corporation's seal shall contain the name of the Corporation and the name of the state of incorporation. The seal may be used by impressing it or reproducing a facsimile of it or otherwise.

ARTICLE III

SHAREHOLDERS’ MEETINGS

Section 1. Annual Meetings. The annual meeting of the shareholders of the Corporation shall be held on the third Thursday of January in each year if not a legal holiday, and if a legal holiday, then on the next succeeding business day not a legal holiday. The purpose of the meeting shall be to elect directors and to transact such other business as properly brought before the meeting. If the Corporation fails to hold said meeting for the election of directors on the date aforesaid, the Board of Directors shall cause the election to be held by the shareholders as soon thereafter as convenient.

Section 2. Special Meetings. Special meetings of the shareholders may be called by or at the request of the Chairman of the Board, Chief Executive Officer or a majority of the number of Directors then in office.

Section 3. Notices of Meetings. Notice of each meeting of the shareholders stating the place, date and hour of the meeting, and, in case of a special meeting or where otherwise required by statute, the purpose or purposes for which the meeting is called, shall be sent or otherwise given in accordance with Section 4 of this Article not less than ten nor more than sixty

days before the date of the meeting, by or at the direction of the person calling the meeting, to each shareholder entitled to vote at such meeting.

Section 4. Method of Notice. Notice of any meeting of shareholders shall be given either personally or by mail, telecopy, telegram or other electronic or wireless means. Notices not personally delivered shall be sent charges prepaid and shall be addressed to the shareholder at the address of that shareholder appearing on the books of the Corporation. Notice shall be deemed to have been given at the time when delivered personally or deposited in the mail or sent by telecopy, telegram or other electronic or wireless means.

An affidavit of the mailing or other means of giving notice of any shareholders’ meeting, executed by the Secretary, Assistant Secretary or any transfer agent of the Corporation giving the notice, shall be prima facie evidence of the giving of such notice.

Section 5. Place of Meetings. Meetings of the Corporation’s shareholders may be held at such place, either within or without the State of Alabama, as may be fixed from time to time by resolution of the Board of Directors and designated in the notice of meeting.

Section 6. Quorum: Adjournments. The holders of a majority of the shares issued and outstanding and entitled to vote, present in person or represented by proxy, shall constitute a quorum at a meeting of the shareholders for the transaction of business, except as otherwise required by law, the Articles of Incorporation, as they may be amended (hereinafter the “Charter”), or these Bylaws. The shareholders present at a meeting at which a quorum is present may continue to transact business until adjournment, notwithstanding the withdrawal of such number of shareholders as to reduce the number of remaining shareholders to less than a quorum. The absence from any meeting of the number of shares required by law, the Charter or these Bylaws for action upon one matter shall not prevent action at such meeting upon any other matter or matters which may properly come before the meeting, if the number of shares required in respect of such other matters shall be present.

Whether or not a quorum is present, the chairman of the meeting or a majority of the shareholders entitled to vote thereat, present in person or represented by proxy, shall have power, except as otherwise provided by statute, successively to adjourn the meeting to such time and place as they may determine, to a date not longer than ninety days after each such adjournment, and no notice of any such adjournment need be given to shareholders other than the announcement of the adjournment at the meeting.

Section 7. Voting: Proxies. At each meeting of the shareholders, each shareholder of record entitled to vote thereat may vote in person or by written proxy. A written proxy may be in the form of a telegram, cablegram or other means of electronic transmission signed by the shareholder and filed with the Secretary of the Corporation. If the instrument designates two (2) or more persons to act as proxies, a majority of the proxies present at the meeting may exercise all of the powers conferred by the instrument, unless the instrument provides otherwise. No proxy shall be valid after eleven months from the date of its execution, unless otherwise provided in the proxy. A proxy shall be deemed signed if the shareholder’s name is placed on the proxy (whether by manual signature, typewriting, telegraphic transmission or otherwise) by the shareholder or the shareholder’s attorney-in-fact.

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Each shareholder shall have one vote for each share of stock which he or she is entitled to vote on such proposition, and, except as otherwise provided by law, the Charter or these Bylaws, the affirmative vote of a majority of the shares entitled to vote and present in person or represented by proxy at the meeting shall be the act of the shareholders.

The date for determining the shareholders entitled to vote at a meeting shall be determined pursuant to Article IX, Section 3 of these Bylaws.

Section 8. Organization. Every meeting of the shareholders for whatever purpose shall be convened by the Chairman of the Board, Chief Executive Officer, Secretary or other officer or person calling the meeting, and in the absence of such officer or person the meeting may be convened by any officer of the Corporation, and in the absence of an officer of the Corporation, the meeting may be convened by the person duly elected chairman of such meeting. Except as otherwise provided in these Bylaws, the officer or person convening the meeting shall act as chairman thereof. The Secretary of the Corporation shall act as secretary of all meetings of shareholders and in his or her absence the chairman of the meeting may designate an assistant secretary of the Corporation or another person to act as secretary of the meeting.

Except as may otherwise be required by applicable law or by rules and regulations adopted by the Board of Directors, the chairman of any meeting of shareholders shall prescribe such rules, regulations and procedures and do such acts, including causing the adjournment of the meeting without a vote of shareholders, that the chairman deems appropriate. Such rules, regulations or procedures, whether adopted by the Board or prescribed by the chair of the meeting, may include, but are not limited to, the following: (a) the establishment of an agenda or order of business for the meeting, including fixing the time for opening and closing the polls for voting on each matter; (b) rules and procedures for maintaining order at the meeting and the safety of those present; (c) limitations on attendance at or participation in the meeting to shareholders of record of the Corporation, their duly authorized and constituted proxies or such other persons as the chair shall permit; (d) restrictions on entry to the meeting after the time fixed for commencement thereof; and (e) limitation on the time allotted for questions or comments by participants. Unless and to the extent determined by the Board or the chair of the meeting, meetings of shareholders shall not be required to be held in accordance with rules of parliamentary procedure.

ARTICLE IV

DIRECTORS

Section 1. General Powers. The Board of Directors shall control and manage the property, business and affairs of the Corporation. The Board of Directors may also exercise all such powers of the Corporation and do all such lawful acts and things as are not by law, the Charter or these Bylaws directed or required to be exercised or done by the shareholders or some particular officer of the Corporation.

Section 2. Number and Term of Office. The number of directors shall be fixed from time to time by resolution of the Board of Directors provided that in no event shall the number of directors be less than 4 nor more than 7.

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The directors shall be elected to serve until the next annual meeting and until their respective successors shall be duly elected and qualified.

In case of any vacancy or vacancies in the Board of Directors, the Board of Directors by a vote of a majority of the remaining directors may fill the vacancy or vacancies for the unexpired term. A vacancy that will occur at a specified later date, by reason of a resignation effective at a later date, may be filled before the vacancy occurs, but the new director shall not take office until the vacancy occurs.

Section 3. Compensation. Directors who are not officers or employees of the Corporation may receive for their service as director such annual compensation as may be determined by resolution of the Board of Directors. In addition, all directors as such shall receive their expenses, if any, for attending meetings of the Board of Directors.

Members of special or standing committees of the Board of Directors shall receive their expenses, if any, for attending committee meetings.

Section 4. Qualifications. Directors need not be shareholders of the Corporation.

ARTICLE V

MEETINGS OF THE BOARD OF DIRECTORS

Section 1. Regular Annual Meeting. A regular annual meeting of the Board, including newly elected directors, shall be held immediately following the annual meeting of shareholders and shall be held at the principal office of the Corporation, unless another time or place shall be fixed therefor by the directors. No notice of such meeting shall be necessary to the directors in order, legally, to constitute a meeting, provided a majority of the whole Board shall be present. In the event such annual meeting of the Board is not held at the time and place specified herein, or at such other time and place as may be fixed by the directors, the meeting may be held at such time and place as shall be specified in a notice given in the same manner as provided in Section 3(a) or (b) of this Article for special meetings or as specified in a written waiver signed by all of the directors.

Section 2. Regular Meetings. Additional regular meetings of the Board of Directors shall be held without notice if the times of such meetings are fixed by the Board. If the time of a meeting is not so fixed by the Board, notice shall be given in the same manner as provided in Section 3(a) or (b) of this Article for special meetings. Regular meetings of the Board may be held at any place within or without the State of Alabama that has been designated from time to time by resolution of the Board. In the absence of such a designation, regular meetings shall be held at the principal executive office of the Corporation.

Section 3. Special Meetings. Special meetings of the Board of Directors may be called upon request of the Chairman of the Board, the Chief Executive Officer or a majority of the Board of Directors. The person(s) authorized to call a special meeting of the Board may fix the time and place of the meeting. Notice of the time, place and purpose of such meeting shall be given by any one or more of the following methods, and the method used need not be the same for each director being notified:

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(a)    written notice sent by mail at least three days prior to the meeting;

(b) personal service of the notice, telephonic notice or facsimile or other electronic or wireless transmission of the notice, in any case at least 24 hours prior to the date of the meeting.

Section 4. Quorum: Voting: Adjournments. At all meetings of the Board of Directors, a majority of the duly elected Board shall be necessary to constitute a quorum for the transaction of business, and no action shall be taken (except adjournment, as provided below, and to fill vacancies, as provided in Article IV, Section 2) until after a quorum has been established. The act of a majority of the directors present at any meeting shall be the act of the Board of Directors, regardless of whether or not a quorum is present at the time such action is taken, except as may be otherwise specifically provided by the Charter or by these Bylaws. In the absence of a quorum, a majority of the directors present shall have power to adjourn the meeting from time to time, without notice other than announcement at the meeting, until a quorum shall be present.

Section 5. Telephonic Participation. Members of the Board of Directors may participate in a meeting of the Board by means of conference telephone or similar communications equipment by means of which all persons participating in the meeting can hear each other, and participation in the meeting in this manner shall constitute presence at such meeting.

Section 6. Action by Written Consent. Any action required or permitted to be taken at any meeting of the Board of Directors (or of any committee thereof) may be taken without a meeting if all members of the Board (or committee) consent thereto in writing, and the writing or writings are filed with the minutes of the proceedings of the Board (or committee).

Section 7. Organization. Meetings of the Board of Directors shall be presided over by the Chairman of the Board. In the absence of the Chairman of the Board, a chairman pro tem chosen by a majority of the directors present shall preside at the meeting. The Secretary of the Corporation, or in his or her absence an Assistant Secretary or any person designated from time to time by the Board, shall act as its Secretary.

ARTICLE VI

COMMITTEES

Section 1. Committees. The Board of Directors may, in its discretion, by resolution, appoint committees, composed of two or more members, which shall have and may exercise such powers as shall be conferred or authorized by the resolution appointing them. Unless otherwise provided by the Board, a majority of the members of any such committee shall constitute a quorum and the acts of a majority of the members present at a meeting at which a quorum is present shall be the act of such committee. The Board shall have the power at any time to change the membership of any such committee, to fill vacancies and to discharge any such committee.

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ARTICLE VII

OFFICERS

Section 1. Titles. The officers of the Corporation shall be elected by the Board of Directors and shall consist of a Chairman of the Board, a President, a Secretary and a Treasurer. The Chief Executive Officer shall be determined as provided in Article VIII, Section 2. The Board may also elect one or more Vice Presidents, a Controller, one or more Assistant Treasurers, Assistant Secretaries, Assistant Controllers and such other officers as the Board may deem appropriate. The following offices may not be held by the same person: President and Secretary or Chief Executive Officer and Secretary. Vice Presidents may be given distinctive designations such as Executive Vice President, Group Vice President, Senior Vice President and the like.

Section 2. Election. The Board shall elect the officers at the Board’s annual meeting. The officers shall hold their offices for such terms and shall exercise such powers and perform such duties as shall be determined from time to time by the Board. In connection with the election of any officer of the Corporation, the Board may determine that such officers, in addition to the title of the office to which he or she is elected, shall have a further title such as Chief Executive Officer, Chief Administrative Officer, Chief Operating Officer or such other title as the Board may designate, and the Board may prescribe powers to be exercised and duties to be performed by any such officer to whom any such additional title of office is given in addition to those powers and duties provided for by these Bylaws for such office.

Section 3. Removal. Any officer or officers elected or appointed by the Board of Directors may be removed at any time, with or without cause, by the affirmative vote of a majority of the whole Board of Directors. Any vacancy occurring in any office may be filled only by the Board.

ARTICLE VIII

DUTIES OF OFFICERS

Section 1. Chairman of the Board. The Chairman of the Board (a) shall preside as chairman of all meetings of the Board of Directors and of the shareholders at which the Chairman shall be present, (b) shall be, ex-officio, a member of all standing Board Committees and (c) shall have such other powers, responsibilities and duties as shall be assigned by the Board. In the absence or disability of the Chief Executive Officer or the President, the Chairman shall exercise all of the powers and discharge all of the duties of the Chief Executive Officer or the President.

Section 2. Chief Executive Officer. The Chief Executive Officer of the Corporation shall be that person designated by the Board of Directors from among the Chairman of the Board or the President. In the absence of such a designation, the President shall be the Chief Executive Officer. The Chief Executive Officer shall have general supervision and control over all of the business and property of the Corporation and shall be responsible at all times to the Board of Directors. The Chief Executive Officer shall have the power to suspend any subordinate officer appointed by the Board until such Board may be convened. The Chief Executive Officer shall have full authority in respect to the signing and execution of deeds, bonds, mortgages, contracts and other instruments of the Corporation. In the absence or the disability of the Chairman of

6

the Board or President, when the Chief Executive Officer is not the Chairman of the Board or President, the Chief Executive Officer shall exercise all of the powers and discharge all of the duties of the Chairman of the Board or the President, as applicable. In the event the Chief Executive Officer shall fail or for any reason be unable to serve, the Board of Directors shall promptly act to fill such vacancy.

Section 3. President. The President shall be a director and shall have such powers, responsibilities and duties as shall be assigned by the Board of Directors, or, when he or she is not the Chief Executive Officer, by the Chief Executive Officer. The President shall have equal authority with the Chief Executive Officer with respect to the signing and execution of deeds, bonds, mortgages, contracts and other instruments of the Corporation. In the absence or disability of the Chief Executive Officer, when the Chief Executive Officer also serves as the Chairman of the Board and the President is not the Chief Executive Officer, the President shall exercise all of the powers and discharge all of the duties of the Chairman of the Board and Chief Executive Officer.

Section 4. Vice Presidents. Each Vice President shall perform and exercise such duties and powers as shall be assigned to that Vice President by the Board of Directors, the Chairman of the Board, the Chief Executive Officer or the President.

Section 5. Treasurer and Assistant Treasurer. The Treasurer shall have charge of the funds of the Corporation; shall keep the same in depositories designated by the Board or by officers of the Corporation authorized by the Board to make such designations; shall cause said funds to be disbursed upon checks, drafts, bills of exchange or orders for payment of money signed in such manner as the Board or authorized officers of the Corporation may, from time to time, direct; shall perform such other duties as are incident to his or her office, or as may be prescribed by the Chief Executive Officer, President or the Board of Directors from time to time; and if required by the Board of Directors, give bond for the faithful discharge of his or her duties, in such form and amount and with such surety or sureties as may be determined by the Board of Directors. The Assistant Treasurer(s) shall, in the absence or disability of the Treasurer, perform the duties and exercise the powers of the Treasurer and shall have such other duties and powers as the Board may prescribe.

Section 6. Secretary. The Secretary shall attend all meetings of the Board of Directors and all meetings of the shareholders and record all votes and the minutes of all proceedings of the same. He or she shall give notice of all meetings of shareholders and special meetings of the Board of Directors and, when appropriate, shall cause the corporate seal to be affixed to any instrument executed on behalf of the Corporation. The Secretary shall also superintend the keeping and have charge of the books, records and papers of the Corporation. Except when a Transfer Agent and Registrar for the stock of the Corporation is employed, the Secretary shall keep a register of the address of each shareholder, and make all proper changes in such register, retaining and filing his or her authority for all such entries. The Secretary shall perform such other duties as may be prescribed by the Chief Executive Officer, President or the Board of Directors from time to time, or as may be incident to his or her office. The Assistant Secretaries, if any, shall, during the absence of the Secretary, perform the duties and functions and exercise the powers of the Secretary. Each Assistant Secretary shall perform such other duties as the Chief Executive Officer, President, or Chairman of the Board shall, from time to time, assign.

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ARTICLE IX

STOCK

Section 1. Certificates of Stock. Shares of stock of the Company may be uncertificated or represented by certificates. Owners of shares of the stock of the Company shall be recorded in the share register of the Company; and ownership of such shares shall be evidenced by a certificate or book-entry notation in the share register of the Company. Any certificates representing such shares shall be signed by, or in the name of the Company by, the President or a Vice President and also by the Secretary or an Assistant Secretary or with facsimile signatures of the foregoing officers. In case any officer who has signed, or whose facsimile signature has been placed upon, a certificate shall cease to be such officer before such certificate is issued, the certificate may be issued by the Company with the same effect as if he or she were such officer at the date of issue.

Section 2. Transfers. Transfers of stock represented by a certificate may be made on the books of the Company only by the person(s) named in the certificate(s) or by the attorney lawfully constituted in writing representing such named person(s), and upon surrender of the certificate representing the same, properly endorsed. Uncertificated shares shall be transferred on the books of the Company upon the written instruction from the registered owner of such uncertificated shares, or from a duly authorized attorney or from an individual presenting proper evidence of succession, assignment or authority to transfer the stock.

Section 3. Record Date. The Board of Directors may close the transfer books in its discretion for a period not exceeding 60 days preceding the day appointed for any meeting, annual or special, of the shareholders, or the payment of a dividend or the allotment of rights, or in its discretion the Board of Directors may fix a date not exceeding 60 days preceding any such appointed day as a record date for the determination of shareholders entitled to notice of, and to vote at, such meeting or to receive such dividend or rights, as the case may be.

Section 4. Determination of Holders. The Corporation shall be entitled to treat the holder of record of any share(s) of stock as the holder in fact thereof and shall not be bound to recognize any equitable or other claim to or interest in such share or shares on the part of any other person, whether or not it shall have express or other notice thereof, except as expressly provided by the laws of the State of Alabama.

Section 5. Transfer Agent and Registrar. The Board of Directors may appoint one or more Transfer Agents and Registrars for its stock, and may require all stock certificates to bear the signature either of a Transfer Agent or of a Registrar, or both.

Section 6. Lost or Destroyed Certificates. Any person claiming a certificate of stock to be lost or destroyed shall make an affidavit or affirmation of that fact and advertise the same in such manner as the Board of Directors may require, and shall give the Corporation, its Transfer Agents and Registrars, if they shall so require, a bond of indemnity, in form and with one or more sureties satisfactory to the Board, the Transfer Agent and the Registrar of the Corporation, in the form and with such provisions as the Transfer Agent or Registrar may deem reasonably satisfactory, whereupon a new certificate may be issued of the same tenor and for the same number of shares as the one alleged to be lost or destroyed.

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ARTICLE X

MISCELLANEOUS

Section 1. Dividends. Subject to law and the provisions of the Charter, the Board of Directors shall have absolute discretion in the declaration of dividends and in fixing and changing the date for the declaration and payment of dividends. Before payment of any dividend or making any distribution of profits, the Board of Directors may set aside, out of the surplus or net profits of the Corporation, such sum or sums as the Board of Directors may from time to time in its absolute discretion deem proper as a reserve fund for depreciation or working capital, or for any other purpose which the Board of Directors shall deem conducive to the interests of the Corporation.

Section 2. Books and Records. When entitled to do so under applicable law, shareholders may inspect the books of the Corporation at the office of the Corporation during the usual business hours of the Corporation and in the presence of a representative of the Corporation, and under such other reasonable regulations as the officers of the Corporation may prescribe in the particular instance.

Section 3. Checks, Drafts, Evidence of Indebtedness. All checks, bills, notes, drafts, vouchers, and other evidences of indebtedness of the Corporation shall be signed for the Corporation by the Chief Executive Officer, the President, or Treasurer and may also be signed and countersigned by such person(s) as the Chief Executive Officer or President may designate, provided that instruments requiring execution with the formality of deeds shall be signed by the Chief Executive Officer, the President, Treasurer or a Vice President and impressed with the seal of the Corporation, duly attested by the Secretary or an Assistant Secretary.

Section 4. Contracts. All contracts, deeds, mortgages, leases or instruments that require the seal of the Corporation to be affixed thereto shall be signed by the Chief Executive Officer, the President or a Vice President, and by the Secretary or an Assistant Secretary, or by such other officer(s) or person(s) as the Board of Directors or Executive Committee may by resolution prescribe.

Section 5. Fiscal Year. The fiscal year of the Corporation shall begin on the first day of October and end on the thirtieth day of September of each year.

Section 6. Amendments. As provided by the Charter, the power to make, alter, amend or repeal these Bylaws is vested in the Board of Directors. Such power may be exercised by the vote of a majority of all of the directors at any annual or regular meeting or at a duly called special meeting.

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XML

LONG-TERM DEBT AND NOTES PAYABLE - Narrative (Details) (USD $)	9 Months Ended		12 Months Ended		0 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Dec. 31, 2012	Sep. 02, 2014 Line of Credit	Sep. 30, 2014 Line of Credit	Sep. 02, 2014 Line of Credit Extension	Sep. 30, 2014 Letter of Credit	Sep. 30, 2014 Swingline
Debt Instrument [Line Items]
Line of credit facility, short-term, authorized amount	$ 35,000,000
Repayments of lines of credit					15,000,000
Debt issued, maturity term					5 years
Number of extensions permitted under credit agreement							2
Extension period under credit agreement					1 year
Debt percentage to capitalization as financial covenants							70.00%
Ratio of Indebtedness to Net Capital						0.240
Line of credit facility borrowing capacity	150,000,000.0							15,000,000.0	15,000,000.0
Additional increase in borrowing capacity available	50,000,000.0
Interest expense	$ 11,500,000	$ 11,700,000	$ 15,600,000	$ 16,300,000

XML

PENSION PLANS AND OTHER POST-RETIREMENT BENEFITS - Fair Value Measurements of Plan Assets (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014		Dec. 31, 2013		Dec. 31, 2012
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	$ 0		$ 0		$ 14.5
Pension Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	119.2		219.5		209.3
Pension Plans | United States equities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	44.0	[1]	42.2	[1]
Pension Plans | Global equities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	12.3	[2]	33.4	[2]
Pension Plans | Fixed income
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	43.4	[3]	61.1	[3]
Pension Plans | Alternative investments
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	17.6	[4]	37.3	[4]
Pension Plans | Cash and cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	1.9		45.5
Pension Plans | Level 1
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	54.5		60.2
Pension Plans | Level 1 | United States equities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	30.4	[1]	34.1	[1]
Pension Plans | Level 1 | Global equities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	12.3	[2]	20.1	[2]
Pension Plans | Level 1 | Fixed income
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	11.5	[3]	0	[3]
Pension Plans | Level 1 | Alternative investments
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0	[4]	0	[4]
Pension Plans | Level 1 | Cash and cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.3		6.0
Pension Plans | Level 2
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	64.7		159.3
Pension Plans | Level 2 | United States equities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	13.6	[1]	8.1	[1]
Pension Plans | Level 2 | Global equities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0	[2]	13.3	[2]
Pension Plans | Level 2 | Fixed income
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	31.9	[3]	61.1	[3]
Pension Plans | Level 2 | Alternative investments
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	17.6	[4]	37.3	[4]
Pension Plans | Level 2 | Cash and cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	1.6		39.5
Pension Plans | Level 3
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0		0
Pension Plans | Level 3 | United States equities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0	[1]	0	[1]
Pension Plans | Level 3 | Global equities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0	[2]	0	[2]
Pension Plans | Level 3 | Fixed income
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0	[3]	0	[3]
Pension Plans | Level 3 | Alternative investments
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0	[4]	0	[4]
Pension Plans | Level 3 | Cash and cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0		0
Postretirement Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	85.6		98.9		87.1
Postretirement Plans | United States equities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	43.9	[1]	43.1
Postretirement Plans | Global equities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	7.2	[2]	17.0
Postretirement Plans | Fixed income
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	34.4	[3]	38.8
Postretirement Plans | Cash and cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.1		0
Postretirement Plans | Level 1
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	51.2		60.1
Postretirement Plans | Level 1 | United States equities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	43.9	[1]	43.1
Postretirement Plans | Level 1 | Global equities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	7.2	[2]	17.0
Postretirement Plans | Level 1 | Fixed income
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0	[3]	0
Postretirement Plans | Level 1 | Cash and cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0.1
Postretirement Plans | Level 2
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	34.4		38.8
Postretirement Plans | Level 2 | United States equities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0	[1]	0
Postretirement Plans | Level 2 | Global equities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	0	[2]	0
Postretirement Plans | Level 2 | Fixed income
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	34.4	[3]	38.8
Postretirement Plans | Level 2 | Cash and cash equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	$ 0

[1] United States equities consist of mutual and commingled funds with varying strategies. Such strategies include stock investments across market capitalizations and investment styles.

[2] Global equities consist of mutual funds and a limited partnership that invest in United States and non-United States securities broadly diversified across mostly developed markets but with some tactical exposure to emerging markets.

[3] Fixed income securities consist of mutual funds and separate accounts. Fixed income securities are well diversified with allocations to investment grade and non-investment grade issues and issues that provide both intermediate and longer duration exposure.

[4] Alternative investments consist of limited partnerships and commingled and mutual funds with varying investment strategies. Alternative investments are meant to serve as a risk reducer at the total portfolio level as they provide asset class exposures not found elsewhere in the portfolio.

XML

PENSION PLANS AND OTHER POST-RETIREMENT BENEFITS - Fair Value of Plan Assets Rollforward (Details) (USD $) In Millions, unless otherwise specified				9 Months Ended	12 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 30, 2014 Pension Plans	Dec. 31, 2013 Pension Plans	Sep. 30, 2014 Postretirement Plans	Dec. 31, 2013 Postretirement Plans
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of period	$ 0	$ 0	$ 14.5	$ 219.5	$ 209.3	$ 98.9	$ 87.1
Energen portion of assets divested				(90.9)	0	(22.0)	0
Asset gain due to estimated allocation				15.0	0	11.0	0
Actual return on plan assets				7.8	23.0	1.4	14.9
Employer contributions				1.6	10.2	0.3	1.6
Benefits paid				(33.8)	(23.0)	(4.0)	(4.7)
Fair value of plan assets at end of period	0	0	14.5	119.2	219.5	85.6	98.9
(Unfunded) funded status of plan				$ (29.6)	$ (73.8)	$ 24.7	$ 35.4

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- Reconciliation of Plan Assets in Level 3 (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Sep. 30, 2014
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of period	$ 14.5	$ 0
Transfer out of level 3	(14.5)
Fair value of plan assets at end of period	$ 0	$ 0

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PENSION PLANS AND OTHER POST-RETIREMENT BENEFITS - Expenses Recognized in Other Comprehensive Income (Loss) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net actuarial (gain) loss experienced during the year	$ 1.5	$ (14.1)	$ 28.7
Net actuarial gain (loss) recognized as expense	0	(8.9)	(4.9)
Prior service cost recognized as expense	0	(0.3)	(0.3)
Total recognized in other comprehensive income (loss)	1.5	(23.3)	23.5
Transfer to regulatory assets (liabilities)	(1.5)	0	0
Other Comprehensive Income	0	(23.3)	23.5
Postretirement Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net actuarial (gain) loss experienced during the year	1.1	(8.1)	(1.8)
Net actuarial gain (loss) recognized as expense	0	0.6	0
Transition obligation recognized as expense	0	(0.3)	(0.3)
Total recognized in other comprehensive income (loss)	1.1	(7.8)	(2.1)
Transfer to regulatory assets (liabilities)	(1.1)	0	0
Other Comprehensive Income	$ 0	$ (7.8)	$ (2.1)

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SUMMARIZED QUARTERLY FINANCIAL DATA (Unaudited) (Tables)

9 Months Ended

Sep. 30, 2014

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information Table

	Nine Months Ended September 30, 2014
($ Millions)	First		Second			Third
Operating revenues	$	263.9	$	93.9		$	59.4
Operating income (loss)	72.4		1.9			(12.1		)
Net income (loss)	43.0		(0.6		)	(9.4		)
	Calendar Year Ended December 31, 2013
($ Millions)	First		Second			Third			Fourth
Operating revenues	$	237.7	$	104.5		$	48.4		$	142.7
Operating income (loss)	79.3		2.2			(22.5		)	34.7
Net income (loss)	47.2		(0.7		)	(8.9		)	19.8

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PENSION PLANS AND OTHER POST-RETIREMENT BENEFITS - Narrative (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	12 Months Ended		9 Months Ended	12 Months Ended		9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Sep. 01, 2014	Sep. 30, 2014 Pension Plans	Dec. 31, 2013 Pension Plans	Dec. 31, 2012 Pension Plans	Sep. 30, 2014 Postretirement Plans	Dec. 31, 2013 Postretirement Plans	Dec. 31, 2012 Postretirement Plans	Sep. 30, 2014 Pension And Postretirement Cost	Dec. 31, 2013 Pension And Postretirement Cost
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory asset			$ 72.5	$ 67.8	$ 58.5		$ 4.7	$ 0		$ 0	$ 0.4
Regulatory liability			28.5	1.9	0		26.6	26.2
Settlement charge recognized for payment of lump sums from the nonqualified supplemental retirement plans	0	0.1		(10.1)	(1.4)	0
Settlements	0	0.5
Net periodic expense				16.8	26.6	16.4	(2.5)	0.2	3.6
Employer contributions				$ 1.6	$ 10.2		$ 0.3	$ 1.6

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LONG-TERM DEBT AND NOTES PAYABLE (Tables)

9 Months Ended

Sep. 30, 2014

Debt Disclosure [Abstract]

Schedule of long-term debt outstanding

Long-term debt consisted of the following:

($ Millions)	September 30, 2014			December 31, 2013
5.368% Notes, due December 1, 2015	$	80.0		$	80.0
5.20% Notes, due January 15, 2020	40.0			40.0
3.86% Notes, due December 21, 2021	50.0			50.0
5.70% Notes, due January 15, 2035	34.8			34.9
5.90% Notes, due January 15, 2037	45.0			45.0
Revolving credit facility	16.0			50.0
Total debt	265.8			299.9
Less: current portion	(16.0		)	(50.0		)
Total long-term debt	$	249.8		$	249.9

Schedule of maturities of long-term debt by fiscal year

The aggregate maturities of the Company’s long-term debt for the next five years are as follows:

Years ending September 30, ($ Millions)
2015	2016	2017	2018	2019	2020 and beyond
$0.0	$80.0	$0.0	$0.0	$16.0	$169.8

Short-term borrowings

The following is a summary of information relating to the Company credit facility:

($ Millions)	September 30, 2014			December 31, 2013
	2014 and 2012 Facilities			(October 2012 Facility)
Maximum amount outstanding at any month-end	$	55.0		$	75.0
Average daily amount outstanding	13.7			35.0
Weighted average interest rates based on:
Average daily amount outstanding	1.30		%	1.12		%
Amount outstanding at year-end	1.16		%	1.26		%

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PENSION PLANS AND OTHER POST-RETIREMENT BENEFITS - Assumptions Used to Calculate Net Periodic Cost and Benefit Obligations (Details)	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Dec. 31, 2012
Assumptions used to calculate benefit obligations [Abstract]
Weighted average rate of future compensation increase	2.92%
Pension Plans
Assumptions used to calculate net periodic cost [Abstract]
Weighted average discount rate		3.63%	4.52%
Expected long-term rate of return on plan assets		7.00%	7.00%
Weighted average rate of future compensation increase	2.92%	3.71%	3.59%
Assumptions used to calculate benefit obligations [Abstract]
Weighted average discount rate		4.30%
Weighted average rate of future compensation increase		3.60%
Postretirement Plans
Assumptions used to calculate net periodic cost [Abstract]
Weighted average discount rate	4.25%	4.26%	4.95%
Expected long-term rate of return on plan assets		7.00%	7.00%
Assumptions used to calculate benefit obligations [Abstract]
Weighted average discount rate	4.40%	5.00%
Minimum | Pension Plans
Assumptions used to calculate net periodic cost [Abstract]
Weighted average discount rate	4.00%
Expected long-term rate of return on plan assets	7.00%
Minimum | Postretirement Plans
Assumptions used to calculate net periodic cost [Abstract]
Expected long-term rate of return on plan assets	4.75%
Assumptions used to calculate benefit obligations [Abstract]
Weighted average discount rate	4.15%
Maximum | Pension Plans
Assumptions used to calculate net periodic cost [Abstract]
Weighted average discount rate	4.05%
Expected long-term rate of return on plan assets	7.25%
Maximum | Postretirement Plans
Assumptions used to calculate net periodic cost [Abstract]
Expected long-term rate of return on plan assets	7.25%
Assumptions used to calculate benefit obligations [Abstract]
Weighted average discount rate	4.25%

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INCOME TAXES - Effective Income Tax Rate Variation from Stated Tax Rate (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended		12 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Federal income tax statutory rate	35.00%
Income tax expense at statutory federal income tax rate	$ 18.5		$ 32.2	$ 27.9
State income taxes, net of federal income tax benefit	1.5		2.6	2.3
Other, net	(0.1)		(0.1)	0.1
Total income tax expense	$ 19.9	$ 22.9	$ 34.7	$ 30.3
Effective income tax rate (%)	37.60%		37.70%	38.00%

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LONG-TERM DEBT AND NOTES PAYABLE - Long-term Debt Outstanding (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Total debt	$ 265.8	$ 299.9
Less: current portion	(16.0)	(50.0)
Long-term debt (less current portion)	249.8	249.9
5.368% Notes, due December 1, 2015
Debt Instrument [Line Items]
Total debt	80.0	80.0
Debt instrument, interest rate, stated percentage	5.368%	5.368%
5.20% Notes, due January 15, 2020
Debt Instrument [Line Items]
Total debt	40.0	40.0
Debt instrument, interest rate, stated percentage	5.20%	5.20%
3.86% Notes, due December 21, 2021
Debt Instrument [Line Items]
Total debt	50.0	50.0
Debt instrument, interest rate, stated percentage	3.86%	3.86%
5.70% Notes, due January 15, 2035
Debt Instrument [Line Items]
Total debt	34.8	34.9
Debt instrument, interest rate, stated percentage	5.70%	5.70%
5.90% Notes, due January 15, 2037
Debt Instrument [Line Items]
Total debt	45.0	45.0
Debt instrument, interest rate, stated percentage	5.90%	5.90%
Revolving credit facility
Debt Instrument [Line Items]
Total debt	$ 16.0	$ 50.0

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PENSION PLANS AND OTHER POST-RETIREMENT BENEFITS - Assumed Medical Cost Trend Rates and Effect of 1% Changed (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014
Assumed 1% change in the assumed medical cost trend rate [Abstract]
Effect of 1% decrease on net periodic postretirement benefit cost	$ 0
Effect of 1% increase on net periodic postretirement benefit cost	0
Effect of 1% decrease on accumulated postretirement benefit obligation	(0.7)
Effect of 1% increase on accumulated postretirement benefit obligation	$ 0.7

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COMPARABLE NINE-MONTH FINANCIAL INFORMATION (UNAUDITED) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended							9 Months Ended		12 Months Ended
	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Dec. 31, 2012
Supplemental Income Statement Elements [Abstract]
Utility								$ 417.2	$ 390.6	$ 533.3	$ 451.6
Total Operating Revenues	59.4	93.9	263.9	142.7	48.4	104.5	237.7	417.2	390.6	533.3	451.6
Natural gas								184.5	163.4	215.5	142.2
Other operation and maintenance expenses								107.5	107.7	143.1	141.3
Depreciation and amortization								34.4	32.7	43.9	42.3
Taxes, other than income taxes								28.6	27.8	37.1	32.5
Total Utility Operating Expenses								355.0	331.6	439.6	358.3
Operating income (loss)	(12.1)	1.9	72.4	34.7	(22.5)	2.2	79.3	62.2	59.0	93.7	93.3
Other Income								2.2	13.2	14.0	2.7
Interest on long-term debt								10.1	10.1	13.5	13.7
Other interest charges								1.4	1.6	2.1	2.6
Total Interest Charges								11.5	11.7	15.6	16.3
Income Before Income Taxes								52.9	60.5	92.1	79.7
Income Tax Expense								19.9	22.9	34.7	30.3
Net Income	$ (9.4)	$ (0.6)	$ 43.0	$ 19.8	$ (8.9)	$ (0.7)	$ 47.2	$ 33.0	$ 37.6	$ 57.4	$ 49.4

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ASSET RETIREMENT OBLIGATIONS (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Regulatory Assets [Line Items]
Regulatory assets for rate recovery	$ 90.6	$ 84.9
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations, beginning of year	27.5	24.9
Liabilities incurred during the period	0.5	0.8
Liabilities settled during the period	(0.1)	(0.1)
Accretion	0.7	1.3
Revisions in estimated cash flows	(0.9)	0.6
Asset retirement obligations, end of year	27.7	27.5
Removal Costs
Regulatory Assets [Line Items]
Regulatory assets for rate recovery	2.8	4.7
Accrual Cost Of Removal
Regulatory Assets [Line Items]
Regulatory assets for rate recovery		$ 4.6

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PENSION PLANS AND OTHER POST-RETIREMENT BENEFITS - Benefit Obligation Rollforward (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Dec. 31, 2012
Pension Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated benefit obligation	$ 129.6	$ 253.0
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation, beginning of year	293.4	323.5
Energen portion of liability divested	(144.7)	0
Liability loss due to estimated allocation	16.9	0
Service cost	5.1	14.2	10.5
Interest cost	4.1	11.2	10.8
Actuarial (gain) loss	7.8	(28.3)
Curtailment gain	0	(4.2)
Retiree drug subsidy program	0	0
Benefits paid	(33.8)	(23.0)
Benefit obligation, end of year	148.8	293.4	323.5
Postretirement Plans
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation, beginning of year	63.6	85.8
Energen portion of liability divested	(13.3)	0
Liability loss due to estimated allocation	7.7	0
Service cost	0.4	1.7	1.9
Interest cost	1.9	3.5	4.2
Actuarial (gain) loss	4.3	(21.7)
Curtailment gain	0	(1.3)
Retiree drug subsidy program	0.3	0.3
Benefits paid	(4.0)	(4.7)
Benefit obligation, end of year	$ 60.9	$ 63.6	$ 85.8

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

9 Months Ended

Sep. 30, 2014

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Alabama Gas Corporation (the Company or Alagasco) is engaged in the purchase, distribution and sale of natural gas principally in central and north Alabama and is headquartered in Birmingham, Alabama. The Company provides residential, commercial and industrial customers with safe and reliable natural gas service. Due to the seasonal nature of the Company, earnings are typically concentrated during the heating season of November through April each calendar year. The Company operates as a single reporting segment. The accompanying financial statements have been prepared in accordance with GAAP.

On September 2, 2014 the Company was acquired by The Laclede Group, Inc. (Laclede Group) for approximately $1,600.0, including the assumption of $250.0 of long-term debt, from Energen Corporation (Energen), with an effective time under the SPA of 11:59 p.m. on August 31, 2014.  Prior to the acquisition the Company was a wholly owned subsidiary of Energen.  Subsequent to the acquisition, the Company became a wholly owned subsidiary of Laclede Group, see Note 2, Acquisition.

Effective September 2, 2014, the Company amended its bylaws, to change the Company’s fiscal year from beginning January 1st and ending on December 31st, to beginning October 1st and ending on September 30th. As a result, the financial statements accompanying these Notes cover the period from January 1, 2014 through September 30, 2014 (the “transition period”) and are included in the Company’s transition report on form 10-K for such period. Subsequent to such report, the Company’s annual reports on Form 10-K will cover the fiscal year October 1^st to September 30^th. The period beginning January 1, 2013 through December 31, 2013 is referred to as “calendar 2013” and the period beginning January 1, 2012 through December 31, 2012 as “calendar 2012”. 

Use of Estimates - The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

Utility Plant and Depreciation - Utility plant is stated at original cost. The cost of additions to utility plant includes contracted work, direct labor and materials, allocable overheads, and an allowance for funds used during construction. The costs of units of property retired, replaced, or renewed are removed from utility plant and are charged to accumulated depreciation. Maintenance and repairs of property and replacement and renewal of items determined to be less than units of property are charged to maintenance expenses. Gains and losses on all dispositions of land are recognized at time of disposal.

Depreciation is provided using the composite method of depreciation on a straight-line basis over the estimated useful lives of property at rates approved by the Alabama Public Service Commission (APSC). On June 28, 2010, the APSC approved a reduction in depreciation rates, effective June 1, 2010, with the revised prospective composite depreciation rate approximating 3.1%. The Company anticipates refunding approximately $13.4 of refundable negative salvage costs through lower tariff rates over the next twelve months related to the lower depreciation rates.

Asset Retirement Obligations - The Company records legal obligations associated with the retirement of long-lived assets in the period in which the obligations are incurred, if sufficient information exists to reasonably estimate the fair value of the obligations. Obligations are recorded as both a cost of the related long-lived asset and as a corresponding liability. Subsequently, the asset retirement costs are depreciated over the life of the asset and the asset retirement obligations are accreted to the expected settlement amounts. The Company records asset retirement obligations associated with certain safety requirements to purge and seal gas distribution mains upon retirement, the plugging and abandonment of storage wells and other storage facilities, specific service line obligations, and certain removal and disposal obligations related to components of the Company’s distribution system and general plant. Such accruals are provided for through depreciation expense and are recorded with corresponding credits to regulatory liabilities. The costs associated with asset retirement obligations are either currently being recovered in rates or are probable of recovery in future rates.

Regulated Operations - The Company accounts for its regulated operations in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 980, “Regulated Operations.” This Topic sets forth the application of GAAP for those companies whose rates are established by or are subject to approval by an independent third party regulator. The provisions of this accounting guidance require, among other things, that financial statements of a regulated enterprise reflect the actions of regulators, where appropriate. These actions may result in the recognition of revenues and expenses in time periods that are different than non-regulated enterprises. When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses when those amounts are reflected in rates. Also, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for recovery of costs that are expected to be incurred in the future (regulatory liabilities). Management believes that the current regulatory environment supports the continued use of these regulatory accounting principles and that all regulatory assets and regulatory liabilities are recoverable or refundable through the regulatory process. See additional discussion on regulated operations in Note 3 - Regulatory Matters and Note 12 - Regulatory Assets and Liabilities.

Natural Gas Stored Underground - Inventory of natural gas in storage is stated at average cost.

Revenue Recognition and Gas Costs - The Company records natural gas distribution revenues in accordance with the tariff established by the APSC. The margin and gas costs on service delivered to cycle customers but not yet billed are recorded in current assets as accounts receivable with a corresponding regulatory liability. Gas imbalances are settled on a monthly basis. Alagasco had no material imbalances at September 30, 2014 and December 31, 2013.

Gas Supply Adjustment - The Company’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. The Company’s tariff provides a temperature adjustment mechanism, also included in the GSA that is designed to moderate the impact of departures from normal temperatures on the Company’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment. In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Alagasco recognizes all derivatives at fair value as either assets or liabilities on the balance sheet. Any realized gains or losses are passed through to customers using the mechanisms of the GSA rider in accordance with Alagasco’s APSC approved tariff and are recognized as a regulatory asset or regulatory liability.

Income Taxes - The Company uses the asset and liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities, as well as tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change.

Gross Receipts Taxes, Franchise Fees and Sales Taxes - Gross receipts taxes and franchise fees associated with the Company’s natural gas utility services are imposed on the Company and billed to its customers. These amounts are recorded gross in the Company’s Statements of Income. Amounts recorded in the Company’s Operating Revenues were $20.6, $25.9 and $21.5 for the transition period ended September 30, 2014 and the calendar years ended December 31, 2013 and 2012, respectively. Gross receipts taxes and franchise fees are expensed and included in the Taxes, other than income taxes line. Sales taxes imposed on applicable sales are billed to customers. These amounts are not recorded in the Statements of Income, but are recorded as tax collections payable and included in other current liabilities on the balance sheets.

Accounts Receivable and Allowance for Doubtful Accounts - Trade accounts receivable are recorded at the amounts due from customers, including unbilled amounts. Estimates of the collectability of trade accounts receivable are based on historical trends, age of receivables, economic conditions, credit risk of specific customers, and other factors. Accounts receivable are written off against the allowance for doubtful accounts when they are deemed to be uncollectible.

Group Medical, General Liability and Workers’ Compensation Reserves - The Company self-insures its group medical, general liability and workers’ compensation costs and carries stop-loss coverage in relation to medical claims, general liability and workers’ compensation claims. Reserves for amounts incurred but not reported are established based on historical cost levels and lags between occurrences and reporting.

Fair Value Measurements - Certain assets and liabilities are recognized or disclosed at fair value, which is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). GAAP establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.

The levels of the hierarchy are described below:

• Level 1 - Unadjusted quoted prices in active markets for identical assets or liabilities.

• Level 2 - Pricing inputs other than quoted prices included within Level 1, which are either directly or indirectly observable for the asset or liability as of the reporting date. These inputs are derived principally from, or corroborated by, observable market data.

• Level 3 - Pricing that is based upon inputs that are generally unobservable that are based on the best information available and reflect management’s assumptions about how market participants would price the asset or liability.

Assessment of the significance of a particular input to the fair value measurements may require judgment and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. Additional information about fair value measurements is provided in Note 6, Pension Plans and Other Postretirement Benefits and Note 8, Financial Instruments and Risk Management.

New Accounting Standard - In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers. This standard is intended to improve the financial reporting requirements for revenue from contracts with customers by providing a principles-based approach to the recognition of revenue. The core principle of the standard is when an entity transfers goods or services to customers it will recognize revenue in an amount that reflects the consideration the entity expects to be entitled to for those goods or services. The standard outlines a five-step model and related application guidance, which replaces most existing revenue recognition guidance. ASU 2014-09 also requires disclosures that will enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption not permitted. The Company has not yet selected a transition method nor has it determined the impact, if any, of the standard on its ongoing financial condition and results of operations.

Reclassifications - Federal and state income taxes were previously presented as a component of total operating expenses and have been reclassified to conform with the current period presentation following income before income taxes in the Statement of Income.

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SUPPLEMENTAL CASH FLOW INFORMATION (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Dec. 31, 2012
Supplemental Cash Flow Elements [Abstract]
Interest paid, net of amount capitalized	$ 9.6	$ 13.5	$ 13.5
Income taxes paid	20.4	23.1	16.8
Interest expense on affiliated company debt, net	0	0	0.3
Accrued property, plant and equipment costs	$ 5.0	$ 5.5	$ 3.5

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INCOME TAXES - Significant Items in Net Deferred Tax Liability (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Deferred tax assets:
Deferred tax assets, Current	$ 2.7	$ 21.6
Deferred tax assets, Noncurrent	281.8	0
Deferred tax liabilities:
Deferred tax liabilities, Current	0.4	1.6
Deferred tax liabilities, Noncurrent	4.0	205.6
Deferred Tax Assets, Net, Current	2.3	20.0
Deferred Tax Assets, Net, Noncurrent	277.8	0
Deferred Tax Liabilities, Net, Noncurrent	0	(205.6)
Deferred tax assets, Current
Deferred tax assets:
Unbilled and deferred revenue	2.5	12.5
Allowance for doubtful accounts	0	1.8
Insurance accruals	0	1.8
Compensation accruals	0	2.5
Inventories	0	1.3
Gas supply adjustment related accruals	0	0.7
Pension and other costs	0	0
Goodwill	0	0
Net operating loss	0	0
Other	0.2	1.0
Deferred tax assets, Noncurrent
Deferred tax assets:
Unbilled and deferred revenue	0	0
Allowance for doubtful accounts	0	0
Insurance accruals	0	0
Compensation accruals	0	0
Inventories	0	0
Gas supply adjustment related accruals	0	0
Pension and other costs	10.6	0
Goodwill	266.1	0
Net operating loss	5.1	0
Other	0	0
Deferred tax liabilities, Current
Deferred tax liabilities:
Depreciation and basis differences	0	0
Pension and other costs	0	0
Other	0.4	1.6
Deferred tax liabilities, Noncurrent
Deferred tax liabilities:
Depreciation and basis differences	4.0	186.6
Pension and other costs	0	19.0
Other	$ 0	$ 0

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ASSET RETIREMENT OBLIGATIONS (Tables)

9 Months Ended

Sep. 30, 2014

Asset Retirement Obligation Disclosure [Abstract]

Schedule of asset retirement obligations

The following table presents a reconciliation of the beginning and ending balances of asset retirement obligations at September 30, 2014 and December 31, 2013 as reported in the Balance Sheet:

($ Millions)	September 30, 2014			December 31, 2013
Asset retirement obligations, beginning of year	$	27.5		$	24.9
Liabilities incurred during the period	0.5			0.8
Liabilities settled during the period	(0.1		)	(0.1		)
Accretion	0.7			1.3
Revisions in estimated cash flows	(0.9		)	0.6
Asset retirement obligations, end of year	$	27.7		$	27.5

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COMMITMENTS AND CONTINGENCIES (Tables)

9 Months Ended

Sep. 30, 2014

Commitments and Contingencies Disclosure [Abstract]

Schedule of minimum future rental payments

Minimum future rental payments required after September 30, 2014 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:

($ Millions)
2015	2016	2017	2018	2019	2020 and thereafter
4.3	3.9	4.0	2.9	2.1	9.1

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PENSION PLANS AND OTHER POST-RETIREMENT BENEFITS - Expected Future Benefit Payments (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014
Pension Plans
Expected benefit payments [Abstract]
2015	$ 9.9
2016	10.2
2017	10.6
2018	10.6
2019	11.2
2020 - 2024	58.7
Postretirement Plans
Expected benefit payments [Abstract]
2015	3.8
2016	3.8
2017	3.8
2018	3.8
2019	3.8
2020 - 2024	18.6
Prescription Drug Subsidy Receipts, Fiscal Year Maturity [Abstract]
2015	(0.2)
2016	(0.2)
2017	(0.2)
2018	(0.2)
2019	(0.3)
2020-2024	$ (1.3)

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INCOME TAXES - Unrecognized Tax Benefit Reconciliation (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Dec. 31, 2012
Unrecognized tax benefits [Roll Forward]
Unrecognized tax benefits, beginning of year	$ 0.3	$ 0.3	$ 0.1
Additions based on tax positions related to the current year			0.1
Additions for tax positions of prior years			0.2
Reductions for tax positions of prior years (lapse of statute of limitations)	(0.3)	0	(0.1)
Unrecognized tax benefits, end of year	$ 0	$ 0.3	$ 0.3

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SUPPLEMENTAL CASH FLOW INFORMATION (Tables)

9 Months Ended

Sep. 30, 2014

Supplemental Cash Flow Elements [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

Supplemental information concerning the Company’s cash flow activities was as follows:

	Nine Months Ended		Calendar Years Ended December 31,
($ Millions)	September 30, 2014		2013		2012
Interest paid, net of amount capitalized	$	9.6	$	13.5	$	13.5
Income taxes paid	20.4		23.1		16.8
Interest expense on affiliated company debt, net	—		—		0.3
Non-cash investing activities:
Accrued property, plant and equipment costs	5.0		5.5		3.5

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REGULATORY ASSETS AND LIABILITIES (Tables)

9 Months Ended

Sep. 30, 2014

Regulated Operations [Abstract]

Regulatory Assets

The following regulatory assets and regulatory liabilities were reflected in the Company's Balance Sheets and also included below:

	September 30, 2014				December 31, 2013
($ Millions)	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Postretirement assets	$	6.4	$	66.1	$	0.3	$	58.2
Accretion and depreciation for asset retirement obligation	—		18.3		—		18.0
Rate recovery of asset removal costs, net	—		2.8		—		4.7
Enhanced stability reserve	—		3.4		—		4.0
Gas supply adjustment	—		—		2.5		—
RSE adjustment	2.4		—		—		—
Total regulatory assets	$	8.8	$	90.6	$	2.8	$	84.9
Regulatory liabilities:
RSE adjustment	$	19.8	$	—	$	4.7	$	—
Unbilled service margin	5.2		—		28.5		—
Postretirement liabilities	2.3		26.2		—		26.2
Refundable negative salvage	13.4		26.8		15.8		39.7
Gas supply adjustment	22.4		—		—		—
Other	—		0.7		—		0.7
Total regulatory liabilities	$	63.1	$	53.7	$	49.0	$	66.6

Regulatory Liabilities

The following regulatory assets and regulatory liabilities were reflected in the Company's Balance Sheets and also included below:

	September 30, 2014				December 31, 2013
($ Millions)	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Postretirement assets	$	6.4	$	66.1	$	0.3	$	58.2
Accretion and depreciation for asset retirement obligation	—		18.3		—		18.0
Rate recovery of asset removal costs, net	—		2.8		—		4.7
Enhanced stability reserve	—		3.4		—		4.0
Gas supply adjustment	—		—		2.5		—
RSE adjustment	2.4		—		—		—
Total regulatory assets	$	8.8	$	90.6	$	2.8	$	84.9
Regulatory liabilities:
RSE adjustment	$	19.8	$	—	$	4.7	$	—
Unbilled service margin	5.2		—		28.5		—
Postretirement liabilities	2.3		26.2		—		26.2
Refundable negative salvage	13.4		26.8		15.8		39.7
Gas supply adjustment	22.4		—		—		—
Other	—		0.7		—		0.7
Total regulatory liabilities	$	63.1	$	53.7	$	49.0	$	66.6

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STATEMENTS OF CASH FLOWS (USD $) In Millions, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating Activities:
Net Income	$ 33.0	$ 57.4	$ 49.4
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, amortization, and accretion	34.4	43.9	42.3
Deferred income taxes	4.0	15.0	11.3
Gain on sale of assets	(0.7)	(10.9)	0
Other	2.0	14.1	10.8
Changes in assets and liabilities:
Accounts receivable - net	26.4	(23.2)	(13.5)
Inventories	(11.8)	0	10.5
Accounts payable	(13.6)	(2.5)	(5.9)
Advance customer billings	37.1	40.5	(57.8)
Income tax receivable	3.5	(0.9)	7.0
Pension and other postretirement benefit contributions	(1.6)	(6.1)	(2.7)
Other assets and liabilities	2.3	2.7	(8.7)
Net cash provided by operating activities	115.0	130.0	42.7
Investing Activities:
Capital expenditures	(46.2)	(86.0)	(69.9)
Proceeds from sale of assets	0.8	13.8	0
Other, net	0	0	(3.2)
Net cash used in investing activities	(45.4)	(72.2)	(73.1)
Financing Activities:
Reduction of long-term debt	(0.1)	(0.1)	(0.2)
(Repayment) issuance of notes payable - net	(34.0)	(27.0)	62.0
Debt issuance costs	(0.6)	0	0
Dividends paid	(37.4)	(33.3)	(33.6)
Repayment of advances from affiliates	5.1	0	0
Net cash (used in) provided by financing activities	(67.0)	(60.4)	28.2
Net Increase (Decrease) in Cash and Cash Equivalents	2.6	(2.6)	(2.2)
Cash and Cash Equivalents at Beginning of Year	3.0	5.6	7.8
Cash and Cash Equivalents at End of Year	$ 5.6	$ 3.0	$ 5.6

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COMPARABLE NINE-MONTH FINANCIAL INFORMATION (UNAUDITED) (Tables)

9 Months Ended

Sep. 30, 2014

Supplemental Income Statement Elements [Abstract]

Comparable Nine-month Statements of Income

Effective as of September 2, 2014, the Company changed its fiscal year end from December 31 to September 30. Statements of Income for the nine months ended September 30, 2014 and 2013 are summarized below. All data for the nine months ended September 30, 2014 and 2013 are derived from the Company’s unaudited financial statements.

STATEMENTS OF INCOME	Nine Months Ended September 30,
($ Millions)	2014		2013
Operating Revenues:
Utility	$	417.2	$	390.6
Total Operating Revenues	417.2		390.6
Operating Expenses:
Utility
Natural gas	184.5		163.4
Other operation and maintenance expenses	107.5		107.7
Depreciation and amortization	34.4		32.7
Taxes, other than income taxes	28.6		27.8
Total Utility Operating Expenses	355.0		331.6
Operating Income	62.2		59.0
Other Income, Net	2.2		13.2
Interest Charges:
Interest on long-term debt	10.1		10.1
Other interest charges	1.4		1.6
Total Interest Charges	11.5		11.7
Income Before Income Taxes	52.9		60.5
Income Tax Expense	19.9		22.9
Net Income	$	33.0	$	37.6

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LONG-TERM DEBT AND NOTES PAYABLE - Short-term Borrowings (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Debt Disclosure [Abstract]
Maximum amount outstanding at any month-end	$ 55.0	$ 75.0
Average daily amount outstanding	$ 13.7	$ 35.0
Weighted average interest rate, Average daily amount outstanding	1.30%	1.12%
Weighted average interest rate, Amount outstanding at year-end	1.16%	1.26%

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PENSION PLANS AND OTHER POST-RETIREMENT BENEFITS - Targeted and Actual Plan Assets by Category (Details)	9 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Pension Plans
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	100.00%
Actual allocation of plan assets	100.00%	100.00%
Pension Plans | Equity Markets
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	41.00%
Actual allocation of plan assets	51.00%	34.00%
Pension Plans | Debt Securities
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	38.00%
Actual allocation of plan assets	36.00%	28.00%
Pension Plans | Other
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	21.00%
Actual allocation of plan assets	13.00%	38.00%
Postretirement Plans
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	100.00%
Actual allocation of plan assets	100.00%	100.00%
Postretirement Plans | Equity Markets
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	60.00%
Actual allocation of plan assets	60.00%	61.00%
Postretirement Plans | Debt Securities
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	40.00%
Actual allocation of plan assets	40.00%	39.00%
Postretirement Plans | Other
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	0.00%
Actual allocation of plan assets	0.00%	0.00%

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STATEMENTS OF INCOME (USD $) In Millions, unless otherwise specified	3 Months Ended							9 Months Ended		12 Months Ended
	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Dec. 31, 2012
Operating Revenues:
Utility								$ 417.2	$ 390.6	$ 533.3	$ 451.6
Total Operating Revenues	59.4	93.9	263.9	142.7	48.4	104.5	237.7	417.2	390.6	533.3	451.6
Utility
Natural gas								184.5	163.4	215.5	142.2
Other operation and maintenance expenses								107.5	107.7	143.1	141.3
Depreciation and amortization								34.4	32.7	43.9	42.3
Taxes, other than income taxes								28.6	27.8	37.1	32.5
Total Utility Operating Expenses								355.0	331.6	439.6	358.3
Operating Income	(12.1)	1.9	72.4	34.7	(22.5)	2.2	79.3	62.2	59.0	93.7	93.3
Other Income								2.2	13.2	14.0	2.7
Interest Charges:
Interest on long-term debt								10.1	10.1	13.5	13.7
Other interest charges								1.4	1.6	2.1	2.6
Total Interest Charges								11.5	11.7	15.6	16.3
Income Before Income Taxes								52.9	60.5	92.1	79.7
Income Tax Expense								19.9	22.9	34.7	30.3
Net Income	$ (9.4)	$ (0.6)	$ 43.0	$ 19.8	$ (8.9)	$ (0.7)	$ 47.2	$ 33.0	$ 37.6	$ 57.4	$ 49.4

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PENSION PLANS AND OTHER POST-RETIREMENT BENEFITS - Net Periodic Cost (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Settlement charge	$ 0	$ (0.1)
Pension Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	5.1	14.2	10.5
Interest cost	4.1	11.2	10.8
Expected long-term return on assets	(5.2)	(14.7)	(14.1)
Prior service cost amortization	0.1	0.5	0.6
Actuarial (gain) loss amortization	2.2	14.0	8.6
Settlement charge	10.1	1.4	0
Amortization of prior regulatory assets and liabilities	0.4	0	0
Net periodic expense	16.8	26.6	16.4
Postretirement Plans
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	0.4	1.7	1.9
Interest cost	1.9	3.5	4.2
Expected long-term return on assets	(3.6)	(5.0)	(4.4)
Actuarial (gain) loss amortization	(1.0)	(0.1)	0
Transition obligation amortization	0	1.3	1.9
Amortization of prior regulatory assets and liabilities	(0.2)
Curtailment gain	0	(1.2)	0
Net periodic expense	$ (2.5)	$ 0.2	$ 3.6

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STATEMENTS OF CAPITALIZATION (Parenthetical) (USD $)	Sep. 30, 2014	Dec. 31, 2013
Schedule of Capitalization, Long-term Debt [Line Items]
Common Stock, Par or Stated Value Per Share (in dollars per share)	$ 0.01	$ 0.01
Common Stock, Shares Authorized	3,000,000	3,000,000
Common Stock, Shares, Issued	1,972,052	1,972,052
5.20% Notes, due January 15, 2020
Long Term Debt
Debt instrument, interest rate, stated percentage	5.20%	5.20%
5.70% Notes, due January 15, 2035
Long Term Debt
Debt instrument, interest rate, stated percentage	5.70%	5.70%
5.368% Notes, due December 1, 2015
Long Term Debt
Debt instrument, interest rate, stated percentage	5.368%	5.368%
5.90% Notes, due January 15, 2037
Long Term Debt
Debt instrument, interest rate, stated percentage	5.90%	5.90%
3.86% Notes, due December 21, 2021
Long Term Debt
Debt instrument, interest rate, stated percentage	3.86%	3.86%

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COMMITMENTS AND CONTINGENCIES - Lease Obligations (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended	9 Months Ended	12 Months Ended
	Feb. 28, 2013 Lease_Renewal	Sep. 30, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating Leased Assets [Line Items]
Number of renewal options available under operating lease arrangement	5
Operating leases renewal term	5 years
Total lease payments		$ 1.8	$ 2.4	$ 2.1
Lease expense paid by parent company		0	0.7	1.0
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2015		4.3
2016		3.9
2017		4.0
2018		2.9
2019		2.1
2020 and thereafter		9.1
Company's headquarters
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Payments associated with leasing of Company's headquarters		$ 11.0

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ACQUISITION (Details) (USD $)	0 Months Ended
	Sep. 02, 2014	Sep. 02, 2014
Business Acquisition [Line Items]
Deferred tax asset established	$ 280,100,000	$ 280,100,000
Deferred tax assets and liabilities	0	0
Laclede Group Inc | Alagasco
Business Acquisition [Line Items]
Total consideration transferred	1,600,000,000
Long-term debt assumed in a business combination		$ 250,000,000

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REGULATORY ASSETS AND LIABILITIES - Regulatory Liabilities (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	$ 63.1	$ 49.0
Regulatory liabilities, noncurrent	53.7	66.6
RSE adjustment
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	19.8	4.7
Regulatory liabilities, noncurrent	0	0
Unbilled service margin
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	5.2	28.5
Regulatory liabilities, noncurrent	0	0
Postretirement liabilities
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	2.3	0
Regulatory liabilities, noncurrent	26.2	26.2
Refundable negative salvage
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	13.4	15.8
Regulatory liabilities, noncurrent	26.8	39.7
Gas supply adjustment
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	22.4	0
Regulatory liabilities, noncurrent	0	0
RSE adjustment
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	0	0
Regulatory liabilities, noncurrent	$ 0.7	$ 0.7

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COMPARABLE NINE-MONTH FINANCIAL INFORMATION (UNAUDITED)

9 Months Ended

Sep. 30, 2014

Supplemental Income Statement Elements [Abstract]

COMPARABLE NINE-MONTH FINANCIAL INFORMATION (UNAUDITED)

COMPARABLE NINE-MONTH FINANCIAL INFORMATION (UNAUDITED)

Effective as of September 2, 2014, the Company changed its fiscal year end from December 31 to September 30. Statements of Income for the nine months ended September 30, 2014 and 2013 are summarized below. All data for the nine months ended September 30, 2014 and 2013 are derived from the Company’s unaudited financial statements.

STATEMENTS OF INCOME	Nine Months Ended September 30,
($ Millions)	2014		2013
Operating Revenues:
Utility	$	417.2	$	390.6
Total Operating Revenues	417.2		390.6
Operating Expenses:
Utility
Natural gas	184.5		163.4
Other operation and maintenance expenses	107.5		107.7
Depreciation and amortization	34.4		32.7
Taxes, other than income taxes	28.6		27.8
Total Utility Operating Expenses	355.0		331.6
Operating Income	62.2		59.0
Other Income, Net	2.2		13.2
Interest Charges:
Interest on long-term debt	10.1		10.1
Other interest charges	1.4		1.6
Total Interest Charges	11.5		11.7
Income Before Income Taxes	52.9		60.5
Income Tax Expense	19.9		22.9
Net Income	$	33.0	$	37.6

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REGULATORY MATTERS (Details) (USD $)	0 Months Ended	9 Months Ended	12 Months Ended				0 Months Ended	9 Months Ended	12 Months Ended		0 Months Ended	12 Months Ended	0 Months Ended	9 Months Ended	12 Months Ended	0 Months Ended
	Dec. 01, 2010	Sep. 30, 2014	Dec. 31, 2010 APSC Approved Expension of ESR, November 1, 2010	Dec. 31, 2010 Self Insurance Costs APSC Approved Expension of ESR, November 1, 2010	Dec. 31, 2010 Force Majeure Event Costs APSC Approved Expension of ESR, November 1, 2010	Dec. 31, 2010 Force Majeure Events Costs APSC Approved Expension of ESR, November 1, 2010	Jan. 01, 2014 Alabama Public Service Commission	Sep. 30, 2014 Alabama Public Service Commission	Dec. 31, 2013 Alabama Public Service Commission	Dec. 31, 2012 Alabama Public Service Commission	Jan. 01, 2014 Alabama Public Service Commission Minimum	Dec. 31, 2013 Alabama Public Service Commission Minimum	Jan. 01, 2014 Alabama Public Service Commission Maximum	Sep. 30, 2014 Alabama Public Service Commission Maximum	Dec. 31, 2013 Alabama Public Service Commission Maximum	Jan. 01, 2014 Alabama Public Service Commission, Performance Based Adjustment	Dec. 01, 2014 Scenario, Forecast Alabama Public Service Commission
Public Utilities, General Disclosures [Line Items]
Public utilities, approved return on equity, percentage							10.80%				10.50%	13.15%	10.95%		13.65%	500.00%
Public utilities, approved equity capital structure, percentage														56.50%
Public utilities, maximum return on equity, percentage of prior year revenues								4.00%
Public utilities, reduction to revenues for rate making purposes								$ 22,500,000	$ 10,600,000	$ 6,300,000
Public utilities, approved rate increase (decrease), amount								(8,500,000)	10,300,000	7,800,000							2,400,000
Public utilities, rate increase (decrease), index range, margin								1.75%
Extraordinary Operating and maintenance expenses, minimum amount, charged to enhanced stability reserve				1,000,000.0	300,000	400,000
Negative revenue variance, large commercial and industrial customer budget, minimum amount, charged to enhanced stability reserve			400,000
Public utilities, recovery period	9 years	5 years
Amortization expense, enhanced stability reserve, annual amount		$ 700,000

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

9 Months Ended

Sep. 30, 2014

Accounting Policies [Abstract]

Use of Estimates

Use of Estimates - The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

Utility Plant and Depreciation

Utility Plant and Depreciation - Utility plant is stated at original cost. The cost of additions to utility plant includes contracted work, direct labor and materials, allocable overheads, and an allowance for funds used during construction. The costs of units of property retired, replaced, or renewed are removed from utility plant and are charged to accumulated depreciation. Maintenance and repairs of property and replacement and renewal of items determined to be less than units of property are charged to maintenance expenses. Gains and losses on all dispositions of land are recognized at time of disposal.

Depreciation is provided using the composite method of depreciation on a straight-line basis over the estimated useful lives of property at rates approved by the Alabama Public Service Commission (APSC). On June 28, 2010, the APSC approved a reduction in depreciation rates, effective June 1, 2010, with the revised prospective composite depreciation rate approximating 3.1%. The Company anticipates refunding approximately $13.4 of refundable negative salvage costs through lower tariff rates over the next twelve months related to the lower depreciation rates.

Asset Retirement Obligations

Asset Retirement Obligations - The Company records legal obligations associated with the retirement of long-lived assets in the period in which the obligations are incurred, if sufficient information exists to reasonably estimate the fair value of the obligations. Obligations are recorded as both a cost of the related long-lived asset and as a corresponding liability. Subsequently, the asset retirement costs are depreciated over the life of the asset and the asset retirement obligations are accreted to the expected settlement amounts. The Company records asset retirement obligations associated with certain safety requirements to purge and seal gas distribution mains upon retirement, the plugging and abandonment of storage wells and other storage facilities, specific service line obligations, and certain removal and disposal obligations related to components of the Company’s distribution system and general plant. Such accruals are provided for through depreciation expense and are recorded with corresponding credits to regulatory liabilities. The costs associated with asset retirement obligations are either currently being recovered in rates or are probable of recovery in future rates.

Regulated Operations

Regulated Operations - The Company accounts for its regulated operations in accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 980, “Regulated Operations.” This Topic sets forth the application of GAAP for those companies whose rates are established by or are subject to approval by an independent third party regulator. The provisions of this accounting guidance require, among other things, that financial statements of a regulated enterprise reflect the actions of regulators, where appropriate. These actions may result in the recognition of revenues and expenses in time periods that are different than non-regulated enterprises. When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses when those amounts are reflected in rates. Also, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for recovery of costs that are expected to be incurred in the future (regulatory liabilities). Management believes that the current regulatory environment supports the continued use of these regulatory accounting principles and that all regulatory assets and regulatory liabilities are recoverable or refundable through the regulatory process.

Inventories

Natural Gas Stored Underground - Inventory of natural gas in storage is stated at average cost.

Revenue Recognition and Gas Costs

Revenue Recognition and Gas Costs - The Company records natural gas distribution revenues in accordance with the tariff established by the APSC. The margin and gas costs on service delivered to cycle customers but not yet billed are recorded in current assets as accounts receivable with a corresponding regulatory liability. Gas imbalances are settled on a monthly basis. Alagasco had no material imbalances at September 30, 2014 and December 31, 2013.

Gas Supply Adjustment - The Company’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. The Company’s tariff provides a temperature adjustment mechanism, also included in the GSA that is designed to moderate the impact of departures from normal temperatures on the Company’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment. In prior years, Alagasco entered into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Alagasco recognizes all derivatives at fair value as either assets or liabilities on the balance sheet. Any realized gains or losses are passed through to customers using the mechanisms of the GSA rider in accordance with Alagasco’s APSC approved tariff and are recognized as a regulatory asset or regulatory liability.

Income Taxes

Income Taxes - The Company uses the asset and liability method of accounting for income taxes. Under this method, a deferred tax asset or liability is recognized for the estimated future tax effects attributable to temporary differences between the financial statement basis and the tax basis of assets and liabilities, as well as tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period of the change.

Gross Receipts Taxes, Franchise Fees and Sales Taxes

Gross Receipts Taxes, Franchise Fees and Sales Taxes - Gross receipts taxes and franchise fees associated with the Company’s natural gas utility services are imposed on the Company and billed to its customers. These amounts are recorded gross in the Company’s Statements of Income. Amounts recorded in the Company’s Operating Revenues were $20.6, $25.9 and $21.5 for the transition period ended September 30, 2014 and the calendar years ended December 31, 2013 and 2012, respectively. Gross receipts taxes and franchise fees are expensed and included in the Taxes, other than income taxes line. Sales taxes imposed on applicable sales are billed to customers. These amounts are not recorded in the Statements of Income, but are recorded as tax collections payable and included in other current liabilities on the balance sheets.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts Receivable and Allowance for Doubtful Accounts - Trade accounts receivable are recorded at the amounts due from customers, including unbilled amounts. Estimates of the collectability of trade accounts receivable are based on historical trends, age of receivables, economic conditions, credit risk of specific customers, and other factors. Accounts receivable are written off against the allowance for doubtful accounts when they are deemed to be uncollectible.

Group Medical, General Liability and Workers' Compensation Reserves

Group Medical, General Liability and Workers’ Compensation Reserves - The Company self-insures its group medical, general liability and workers’ compensation costs and carries stop-loss coverage in relation to medical claims, general liability and workers’ compensation claims. Reserves for amounts incurred but not reported are established based on historical cost levels and lags between occurrences and reporting.

Fair Value Measurements

Fair Value Measurements - Certain assets and liabilities are recognized or disclosed at fair value, which is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). GAAP establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.

The levels of the hierarchy are described below:

• Level 1 - Unadjusted quoted prices in active markets for identical assets or liabilities.

• Level 2 - Pricing inputs other than quoted prices included within Level 1, which are either directly or indirectly observable for the asset or liability as of the reporting date. These inputs are derived principally from, or corroborated by, observable market data.

• Level 3 - Pricing that is based upon inputs that are generally unobservable that are based on the best information available and reflect management’s assumptions about how market participants would price the asset or liability.

Assessment of the significance of a particular input to the fair value measurements may require judgment and may affect the valuation of the asset or liability and its placement within the fair value hierarchy.

New Accounting Standard

New Accounting Standard - In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers. This standard is intended to improve the financial reporting requirements for revenue from contracts with customers by providing a principles-based approach to the recognition of revenue. The core principle of the standard is when an entity transfers goods or services to customers it will recognize revenue in an amount that reflects the consideration the entity expects to be entitled to for those goods or services. The standard outlines a five-step model and related application guidance, which replaces most existing revenue recognition guidance. ASU 2014-09 also requires disclosures that will enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption not permitted. The Company has not yet selected a transition method nor has it determined the impact, if any, of the standard on its ongoing financial condition and results of operations.

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SUMMARIZED QUARTERLY FINANCIAL DATA (Unaudited) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended							9 Months Ended		12 Months Ended
	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 59.4	$ 93.9	$ 263.9	$ 142.7	$ 48.4	$ 104.5	$ 237.7	$ 417.2	$ 390.6	$ 533.3	$ 451.6
Operating income (loss)	(12.1)	1.9	72.4	34.7	(22.5)	2.2	79.3	62.2	59.0	93.7	93.3
Net income (loss)	$ (9.4)	$ (0.6)	$ 43.0	$ 19.8	$ (8.9)	$ (0.7)	$ 47.2	$ 33.0	$ 37.6	$ 57.4	$ 49.4

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STATEMENTS OF COMMON SHAREHOLDERS' EQUITY (USD $) In Millions, except Share data, unless otherwise specified	Total	Common Stock Issued	Paid-in Capital	Retained Earnings
BALANCE at Dec. 31, 2011	$ 344.7	$ 31.7	$ 2.8	$ 310.2
BALANCE (in shares) at Dec. 31, 2011		1,972,052
Stockholders' Equity Rollforward
Net Income	49.4	0	0	49.4
Common stock	(33.6)	0	0	(33.6)
BALANCE at Dec. 31, 2012	360.5	31.7	2.8	326.0
BALANCE (in shares) at Dec. 31, 2012		1,972,052
Stockholders' Equity Rollforward
Net Income	57.4	0	0	57.4
Common stock	(33.3)	0	0	(33.3)
BALANCE at Dec. 31, 2013	384.6	31.7	2.8	350.1
BALANCE (in shares) at Dec. 31, 2013		1,972,052
Stockholders' Equity Rollforward
Net Income	33.0	0	0	33.0
Common stock	(37.4)	0	0	(37.4)
Purchase accounting adjustments	469.4		469.4	0
BALANCE at Sep. 30, 2014	$ 849.6	$ 31.7	$ 472.2	$ 345.7
BALANCE (in shares) at Sep. 30, 2014		1,972,052

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BALANCE SHEETS (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
ASSETS
Utility Plant	$ 1,525.1	$ 1,491.4
Less – Accumulated depreciation and amortization	626.4	605.9
Net Utility Plant	898.7	885.5
Other Property and Investments	0	0.1
Other Property and Investments	0	0.1
Current Assets:
Cash and cash equivalents	5.6	3.0
Accounts receivable:
Gas	39.0	103.3
Associated companies	0	4.7
Other	5.1	5.4
Allowance for doubtful accounts	(5.1)	(5.0)
Inventories:
Natural gas	45.2	32.1
Liquefied natural gas in storage	2.8	3.6
Materials and supplies	5.1	5.5
Income tax receivable	0.1	3.6
Deferred income taxes	2.3	20.0
Regulatory assets	8.8	2.8
Prepayments and other	1.5	4.7
Total Current Assets	110.4	183.7
Deferred Charges:
Regulatory assets	90.6	84.9
Deferred income taxes	277.8	0
Net asset available for other postretirement benefits	24.7	26.5
Other	22.4	17.4
Total Deferred Charges	415.5	128.8
Total Assets	1,424.6	1,198.1
Capitalization:
Common stock equity, $0.01 par value, 3,000,000 shares authorized, 1,972,052 shares issued at September 30, 2014 and December 31, 2013, respectively	849.6	384.6
Long-term debt (less current portion)	249.8	249.9
Total Capitalization	1,099.4	634.5
Current Liabilities:
Notes payable	16.0	50.0
Accounts payable	34.8	48.7
Accounts payable – associated companies	0.4	0
Advance customer billings	36.3	38.7
Wages and compensation accrued	7.1	7.7
Taxes accrued	29.8	28.0
Regulatory liabilities	63.1	49.0
Other	13.8	10.1
Total Current Liabilities	201.3	232.2
Deferred Credits and Other Liabilities:
Deferred income taxes	0	205.6
Pension and postretirement benefit costs	29.6	20.2
Regulatory liabilities	53.7	66.6
Other	40.6	39.0
Total Deferred Credits and Other Liabilities	123.9	331.4
Total Capitalization and Liabilities	$ 1,424.6	$ 1,198.1

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ASSET RETIREMENT OBLIGATIONS

9 Months Ended

Sep. 30, 2014

Asset Retirement Obligation Disclosure [Abstract]

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS

The Company recognizes conditional obligations if such obligations can be reasonably estimated and a legal requirement to perform an asset retirement activity exists. The Company accrues removal costs on certain gas distribution assets over the useful lives of its property, plant and equipment through depreciation expense in accordance with rates approved by the APSC. The Company recorded a conditional asset retirement obligation, on a discounted basis, of $27.7 and $27.5 to purge and cap its gas pipelines upon abandonment and to remediate other related obligations, as a regulatory liability as of September 30, 2014 and December 31, 2013, respectively. Regulatory assets for rate recovery of accumulated asset removal costs of $2.8 and $4.6 as of September 30, 2014 and December 31, 2013, respectively, are included as regulatory assets in noncurrent assets on the balance sheets. The costs associated with asset retirement obligations are either currently being recovered in rates or are probable of recovery in future rates.

The following table presents a reconciliation of the beginning and ending balances of asset retirement obligations at September 30, 2014 and December 31, 2013 as reported in the Balance Sheet:

($ Millions)	September 30, 2014			December 31, 2013
Asset retirement obligations, beginning of year	$	27.5		$	24.9
Liabilities incurred during the period	0.5			0.8
Liabilities settled during the period	(0.1		)	(0.1		)
Accretion	0.7			1.3
Revisions in estimated cash flows	(0.9		)	0.6
Asset retirement obligations, end of year	$	27.7		$	27.5

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Document and Entity Information (USD $)	9 Months Ended
	Sep. 30, 2014	Nov. 25, 2014	Mar. 31, 2014
Document and Entity Information [Abstract]
Entity Registrant Name	ALABAMA GAS CORP
Entity Central Index Key	0000003146
Current Fiscal Year End Date	--09-30
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float			$ 0
Entity Common Stock, Shares Outstanding		1,972,052
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Document Type	10-KT
Amendment Flag	false
Document Period End Date	Sep. 30, 2014

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SUPPLEMENTAL CASH FLOW INFORMATION

9 Months Ended

Sep. 30, 2014

Supplemental Cash Flow Elements [Abstract]

SUPPLEMENTAL CASH FLOW INFORMATION

SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental information concerning the Company’s cash flow activities was as follows:

	Nine Months Ended		Calendar Years Ended December 31,
($ Millions)	September 30, 2014		2013		2012
Interest paid, net of amount capitalized	$	9.6	$	13.5	$	13.5
Income taxes paid	20.4		23.1		16.8
Interest expense on affiliated company debt, net	—		—		0.3
Non-cash investing activities:
Accrued property, plant and equipment costs	5.0		5.5		3.5

Non cash activities related to capitalized depreciation, capitalized asset retirement obligation costs and allowance for funds used during construction were not significant for the transition period ended September 30, 2014 and the calendar years ended December 31, 2013 and 2012.

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BALANCE SHEETS (Parenthetical) (USD $)	Sep. 30, 2014	Dec. 31, 2013
Statement of Financial Position [Abstract]
Common Stock, Par or Stated Value Per Share (in dollars per share)	$ 0.01	$ 0.01
Common Stock, Shares Authorized	3,000,000	3,000,000
Common Stock, Shares, Issued	1,972,052	1,972,052

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LONG-TERM DEBT AND NOTES PAYABLE

9 Months Ended

Sep. 30, 2014

Debt Disclosure [Abstract]

LONG-TERM DEBT AND NOTES PAYABLE

LONG-TERM DEBT AND NOTES PAYABLE

Long-term debt consisted of the following:

($ Millions)	September 30, 2014			December 31, 2013
5.368% Notes, due December 1, 2015	$	80.0		$	80.0
5.20% Notes, due January 15, 2020	40.0			40.0
3.86% Notes, due December 21, 2021	50.0			50.0
5.70% Notes, due January 15, 2035	34.8			34.9
5.90% Notes, due January 15, 2037	45.0			45.0
Revolving credit facility	16.0			50.0
Total debt	265.8			299.9
Less: current portion	(16.0		)	(50.0		)
Total long-term debt	$	249.8		$	249.9

The aggregate maturities of the Company’s long-term debt for the next five years are as follows:

Years ending September 30, ($ Millions)
2015	2016	2017	2018	2019	2020 and beyond
$0.0	$80.0	$0.0	$0.0	$16.0	$169.8

The long-term debt and short-term debt agreements of the Company contain financial and nonfinancial covenants including routine matters such as timely payment of principal and interest, maintenance of corporate existence and restrictions on liens. Although none of the agreements have covenants or events of default based on credit ratings, the interest rates applicable to the Company syndicated credit facility discussed below may be adjusted based on credit rating changes. All of the Company’s debt is unsecured.

The Company has authority from the APSC to issue debt securities for up to $35.0. No securities have been issued under this authority.

The Company's Credit Facility

On September 2, 2014 the Company entered into a new syndicated revolving credit facility pursuant to a loan agreement (the Alagasco Loan Agreement) The initial borrowings under the Alagasco Loan Agreement were used to repay the approximately $15.0 of borrowings outstanding under the Company's then existing credit agreement which was terminated in connection with the closing of the Alagasco Loan Agreement.

The Alagasco Loan Agreement is for a term of five years ending September 2, 2019, but the Company may request up to twoone-year extensions. The Alagasco Loan Agreement contains nonfinancial covenants, including limitations on certain types of acquisitions, investments and sales of property. The Alagasco Loan Agreement also contains a financial covenant limiting the Company's debt to 70% of its capitalization. At September 30, 2014, this ratio was 24.0%, as defined under the letter of credit.

The Alagasco Loan Agreement has a credit commitment of $150.0. Under certain terms and conditions, the Company may request an increase of up to $50.0 in the credit commitment. The Alagasco Loan Agreement also provides for letters of credit in an aggregate amount up to $15.0, and swingline loans in an aggregate amount up to $15.0. Letters of credit and swingline loans will constitute usage under the Alagasco Loan Agreement.

The Company was in compliance with all covenants at September 30, 2014.

The following is a summary of information relating to the Company credit facility:

($ Millions)	September 30, 2014			December 31, 2013
	2014 and 2012 Facilities			(October 2012 Facility)
Maximum amount outstanding at any month-end	$	55.0		$	75.0
Average daily amount outstanding	13.7			35.0
Weighted average interest rates based on:
Average daily amount outstanding	1.30		%	1.12		%
Amount outstanding at year-end	1.16		%	1.26		%

Total interest expense for the Company was $11.5, $15.6 and $16.3 for the transition period ended September 30, 2014 and the calendar years ended December 31, 2013 and 2012, respectively.

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REGULATORY MATTERS

9 Months Ended

Sep. 30, 2014

Regulated Operations [Abstract]

REGULATORY MATTERS

REGULATORY MATTERS

The Company is subject to regulation by the APSC which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. The Company’s current RSE order had an original term extending through December 31, 2014. On December 20, 2013, the APSC issued a final written order modifying the RSE effective January 1, 2014 extending the term of the order beyond September 30, 2018 unless the APSC enters an order to the contrary in a manner consistent with law. In the event of unforeseen circumstances, whether physical or economic, of the nature of the force majeure and including a change in control, the APSC and the Company will consult in good faith with respect to modifications, if any. Effective January 1, 2014, the Company’s allowed range of return on average common equity is 10.5% to 10.95% with an adjusting point of 10.8%. The Company is eligible to receive a performance-based adjustment of 5 basis points to the return on equity adjusting point, based on meeting certain customer satisfaction criteria. The Company's previous allowed return on average common equity was 13.15% to 13.65% through December 31, 2013.

Under the RSE, the APSC conducts quarterly reviews to determine whether the Company’s return on average common equity at the end of the Rate Year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each Rate Year, effective December 1, and cannot exceed 4.0% of prior-year revenues. The Company’s year-end equity under the RSE is limited to 56.5% of total capitalization, subject to certain adjustments. During the transition period ended September 30, 2014 and the calendar years ended December 31, 2013 and 2012, the Company had net pre-tax reductions in revenues of $22.5, $10.6 and $6.3 , respectively, to bring the return on average equity to the midpoint within the allowed range of return. Under the provisions of the RSE, there was no change to revenue effective December 1, 2014. There was an $8.5 decrease, a $10.3 and $7.8 increase in revenue, effective January 1, 2014, December 1, 2013 and 2012, respectively.

The inflation-adjusted Cost Control Mechanism (CCM) established by the APSC, allows for annual changes to operations and maintenance (O&M) expense compared to a Base Year, defined as Alagasco’s 2007 actual Rate Year O&M expense, inflation-adjusted to September 30, 2013 using the Consumer Price Index for All Urban Consumer (Base Year O&M). An “Index Range” is established each Rate Year using Base Year O&M, inflation-adjusted using the June Consumer Price Index For All Urban Consumers for that Rate Year plus or minus 1.75% (Index Range). If Rate Year O&M expense falls within the Index Range, no adjustment is required. If Rate Year O&M expense exceeds the Index Range, three quarters of the difference is returned to customers through future rate adjustments. To the extent that Rate Year O&M is less than the Index Range, the utility benefits by one half of the difference through future rate adjustments. Certain items that fluctuate based on situations demonstrated to be beyond the Company’s control may be excluded from the CCM calculation. The Company’s O&M expense fell within the Index Range for the Rate Years ended September 30, 2013, 2012 and 2011. For the Rate Year ended September 30, 2014, the Company’s O&M expense fell below the Index Range resulting in the Company benefitting by one half of the difference, or $2.4 pre-tax, with the related impact to rates effective December 1, 2014.

The APSC approved an Enhanced Stability Reserve (ESR) in 1998 which was subsequently modified and expanded in 2010. As currently approved, the ESR provides deferred treatment and recovery for the following: (1) extraordinary O&M expenses related to environmental response costs; (2) extraordinary O&M expenses related to self-insurance costs that exceed $1.0 per occurrence; (3) extraordinary O&M expenses, other than environmental response costs and self-insurance costs, resulting from a single force majeure event or multiple force majeure events greater than $0.3 and $0.4, respectively, during a Rate Year; and (4) negative individual large commercial and industrial customer budget revenue variances that exceed $0.4 during a Rate Year.

Charges to the ESR are subject to certain limitations which may disallow deferred treatment and which proscribe the timing of recovery. Current funding of the ESR is provided as a reduction to the refundable negative salvage balance over its nine year term beginning December 1, 2010. Subsequent to the nine year period and subject to APSC authorization, The Company anticipates recovering underfunded ESR balances over a five year amortization period with an annual limitation of $0.7. Amounts in excess of this limitation are deferred for recovery in future years.

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SUMMARIZED QUARTERLY FINANCIAL DATA (Unaudited)

9 Months Ended

Sep. 30, 2014

Quarterly Financial Information Disclosure [Abstract]

SUMMARIZED QUARTERLY FINANCIAL DATA (UNAUDITED)

SUMMARIZED QUARTERLY FINANCIAL DATA (UNAUDITED)

In the opinion of the Company, the quarterly information presented below for the nine month period ended September 30, 2014 and the calendar year ended December 31, 2013 includes all adjustments (consisting of only normal recurring accruals) necessary for a fair statement of the results of operations for such periods. Variations in operations reported on a quarterly basis primarily reflect the seasonal nature of the business of the Company.

	Nine Months Ended September 30, 2014
($ Millions)	First		Second			Third
Operating revenues	$	263.9	$	93.9		$	59.4
Operating income (loss)	72.4		1.9			(12.1		)
Net income (loss)	43.0		(0.6		)	(9.4		)
	Calendar Year Ended December 31, 2013
($ Millions)	First		Second			Third			Fourth
Operating revenues	$	237.7	$	104.5		$	48.4		$	142.7
Operating income (loss)	79.3		2.2			(22.5		)	34.7
Net income (loss)	47.2		(0.7		)	(8.9		)	19.8

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ACQUISITION AND DISPOSITION OF PROPERTIES

9 Months Ended

Sep. 30, 2014

Leases [Abstract]

ACQUISITION AND DISPOSITION OF PROPERTIES

ACQUISITION AND DISPOSITION OF PROPERTIES

In August 2013, the Company recorded a pre-tax gain of $10.9 related to the sale of its Metro Operations Center, which is located in Birmingham, Alabama, and has been in service since the 1940s. The Company received approximately $13.8 in cash from the sale of this property. During the third calendar quarter of 2013, the gain on the sale was recognized in other income and a related reduction in revenues was recognized to defer the gain as a regulatory liability pending review by the APSC. In conjunction with the receipt of the rate order from the APSC on December 20, 2013, the Company recognized the deferred revenues from this sale in the fourth calendar quarter of 2013. Effective upon the sale of the Metro Operations Center, the Company leased the facility from the purchaser for a period of approximately 20 months.

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COMMITMENTS AND CONTINGENCIES

9 Months Ended

Sep. 30, 2014

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

Commitments and Agreements:

Certain of the Company’s long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $134.0 through September 2024. During the transition period ended September 30, 2014 and the calendar years ended December 31, 2013 and 2012, the Company recognized approximately $33.8, $50.0 and $51.0, respectively, of current year commitments through expense and its regulatory accounts in the accompanying financial statements. The Company also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 111 bcf through August 2020.

Environmental Matters:

Various environmental laws and regulations apply to the operations of the Company. Historically, the cost of environmental compliance has not materially affected the Company’s financial position, results of operations or cash flows. New regulations, enforcement policies, claims for damages or other events could result in significant unanticipated costs.

The Company is in the chain of title of nine former manufactured gas plant sites, four of which it still owns, and five former manufactured gas distribution sites, one of which it still owns. Management expects that, should future remediation of the sites be required, the Company’s share of the remediation costs will not materially affect the financial position of the Company. During 2011, a removal action was completed at the Huntsville, Alabama manufactured gas plant site pursuant to an Administrative Settlement Agreement and Order on Consent among the EPA, the Company and the current site owner.

In 2012, the Company responded to a U.S. Environmental Protection Agency (EPA) Request for Information Pursuant to Section 104 of Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) relating to the 35thAvenue Superfund Site located in North Birmingham, Jefferson County, Alabama. The Request related to a former site of a manufactured gas distribution facility owned by the Company and located in the vicinity of the 35thAvenue Superfund Site. In September 2013, the Company received from the EPA a General Notice Letter and Invitation to Conduct a Removal Action at the 35th Avenue Superfund Site. The letter identifies the Company as a Potentially Responsible Party (PRP) under CERCLA for the cleanup of the Site or costs the EPA incurs in cleaning up the Site. The EPA also offered the PRP group the opportunity to conduct Phase I of the proposed removal action which involved removal activities at approximately 50 residences that purportedly exceed certain risk levels for contamination. In August of 2014, the EPA offered the PRP group the opportunity to conduct Phase II of the proposed removal action which involved removal activities at approximately 30 additional residences that purportedly exceed certain risk levels for contamination. The Company has discussed its designation as a PRP with the EPA, and the Company has requested additional information from the EPA regarding its designation as a PRP. The Company has not been provided information at this time that would allow it to determine the extent, if any, of its potential liability with respect to the 35th Avenue Superfund Site and the proposed removal action; therefore, no amount has been accrued as of September 30, 2014.

Legal Matters:

The Company, from time to time, is party to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. The Company recognizes its liability for contingencies when information available indicates both a loss is probable and the amount of the loss can be reasonably estimated. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial position of the Company. It should be noted, however, that there is uncertainty in the valuation of pending claims and prediction of litigation results.

On December 17, 2013, an incident occurred at a Housing Authority apartment complex in Birmingham, Alabama which resulted in one fatality, personal injuries and property damage. The Company is cooperating with the National Transportation and Safety Board which is investigating the incident. The Company has been named as a defendant in several lawsuits arising from the incident and additional lawsuits and claims may be filed against the Company.

Lease Obligations:

The Company entered into an amendment to its lease for its primary offices in February 2013 with a term ending February 28, 2018. There is no renewal option. This lease is classified as an operating lease. The Company also has a lease obligation for additional office space which expires January 31, 2024. Under the terms of this lease, the Company has five renewal options to extend the lease term by five years under each renewal. This lease is accounted for as an operating lease. The Company has subleased all of this office space to Energen pursuant to a sublease that expires on December 31, 2019 with an option to extend through January 31, 2024.

The Company’s total payments related to leases included as operating expense were $1.8, $2.4 and $2.1 for the transition period ended September 30, 2014 and the calendar years ended December 31, 2013 and 2012, respectively. These amounts are net of approximately $0.0, $0.7 and $1.0 of sublease income in the transition period ended September 30, 2014 and the calendar years ended December 31, 2013 and 2012, respectively. Minimum future rental payments required after September 30, 2014 under leases with initial or remaining noncancelable lease terms in excess of one year are as follows:

($ Millions)
2015	2016	2017	2018	2019	2020 and thereafter
4.3	3.9	4.0	2.9	2.1	9.1

Included in the table above are approximately $11.0 of payments associated with subleasing of its previous headquarters, which are expected to be reimbursed to the Company by Energen through the remaining term of the related lease.

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FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Aggregate purchase price of guarantees	$ 0.6
Market value an aggregate purchase price of guarantees	0.6
Financing receivable, net	10.9	10.8
Threshold period past due for collection	90 days
Threshold period past due for write-off of financing receivable	12 months
Financing receivable, recorded investment, equal to greater than 90 days past due	0.3	0.4
Allowance for credit losses recognized	0.3	0.4
Natural Gas Distribution
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Number of customers	423,000
Estimate of Fair Value Measurement
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fair value	266.4	258.8
Carrying Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, fair value	$ 249.8	$ 249.9

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INCOME TAXES

9 Months Ended

Sep. 30, 2014

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

The components of the Company’s income taxes consisted of the following:

	Nine Months ended		Calender Year Ended December 31,
($ Millions)	September 30, 2014		2013		2012
Taxes estimated to be payable currently:
Federal	$	14.1	$	17.5	$	18.3
State	1.8		2.2		0.7
Total current	$	15.9	$	19.7	$	19.0
Taxes deferred:
Federal	$	3.5	$	13.3	$	9.1
State	0.5		1.7		2.2
Total deferred	$	4.0	$	15.0	$	11.3
Total income tax expense	$	19.9	$	34.7	$	30.3

Total income tax expense for the Company differed from the amount that would have been provided by applying the statutory federal income tax rate of 35% to earnings before taxes as illustrated below:

	Nine Months Ended			Calendar Year Ended December 31,
($ Millions)	September 30, 2014			2013			2012
Income tax expense at statutory federal income tax rate	$	18.5		$	32.2		$	27.9
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit	1.5			2.6			2.3
Other, net	(0.1		)	(0.1		)	0.1
Total income tax expense	$	19.9		$	34.7		$	30.3
Effective income tax rate (%)	37.6		%	37.7		%	38.0		%

Temporary differences and carryforwards which gave rise to the Company’s deferred tax assets and liabilities were as follows:

($ Millions)	September 30, 2014				December 31, 2013
	Current		Noncurrent		Current		Noncurrent
Deferred tax assets:
Unbilled and deferred revenue	$	2.5	$	—	$	12.5	$	—
Allowance for doubtful accounts	—		—		1.8		—
Insurance accruals	—		—		1.8		—
Compensation accruals	—		—		2.5		—
Inventories	—		—		1.3		—
Gas supply adjustment related accruals	—		—		0.7		—
Pension and other costs	—		10.6		—		—
Goodwill	—		266.1		—		—
Net operating loss	—		5.1		—		—
Other	0.2		—		1.0		—
Total deferred tax assets	$	2.7	$	281.8	$	21.6	$	—
Deferred tax liabilities:
Depreciation and basis differences	$	—	$	4.0	$	—	$	186.6
Pension and other costs	—		—		—		19.0
Other	0.4		—		1.6		—
Total deferred tax liabilities	0.4		4.0		1.6		205.6
Net deferred tax assets (liabilities)	$	2.3	$	277.8	$	20.0	$	(205.6	)

No valuation allowance with respect to deferred taxes is deemed necessary as the Company anticipates generating adequate future taxable income to realize the benefits of all deferred tax assets.

The Company is part of a consolidated federal income tax return with Laclede Group, from September 2 through September 30, 2014. Prior to September 2, 2014, the Company was part of a consolidated federal and state income tax return with our former parent, Energen. Income taxes are allocated to the Company as if it were a separate taxpayer. Pursuant to GAAP, the Company may recognize the tax benefit from a tax position only if it is at least more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The Company records potential interest and penalties related to its uncertain tax positions as income tax expense. Unrecognized tax benefits, accrued interest payable, and accrued penalties payable are included in the Other line of the Deferred Credits and Other Liabilities section of the Balance Sheets. None of the Company’s unrecognized tax benefits at September 30, 2014 would impact the Company’s effective tax rate, if recognized.

A reconciliation of the Company’s beginning and ending amount of unrecognized tax benefits is as follows:

($ Millions)
Balance as of December 31, 2011	$	0.1
Additions based on tax positions related to the current year	0.1
Additions for tax positions of prior years	0.2
Reductions for tax positions of prior years (lapse of statute of limitations)	(0.1		)
Balance as of December 31, 2012	0.3
Reductions for tax positions of prior years (lapse of statute of limitations)	—
Balance as of December 31, 2013	0.3
Reductions for transfer of balances to Energen	(0.3		)
Balance as of September 30, 2014	$	—

The Company’s tax returns for the calendar years 2010-2013 remain open and subject to examination by the IRS and major state taxing jurisdictions. These returns cover periods during which the Company was owned by Energen. As such, the impact of any adjustments made by the relevant taxing authorities would be addressed by Energen.

In September 2013, the Internal Revenue Service and US Treasury Department released final regulations on the deduction and capitalization of expenditures related to tangible property. The regulations do not address the tax treatment for network

assets such as natural gas pipelines. These regulations apply to tax years beginning on or after January 1, 2014. The Company is evaluating the effects of the regulations, but does not believe that they will have a significant impact on its financial statements.

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PENSION PLANS AND OTHER POST-RETIREMENT BENEFITS

9 Months Ended

Sep. 30, 2014

Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS

The Company has defined qualified benefit plans covering the majority of its employees. Qualified plan assets are comprised of United States equities consisting of mutual and commingled funds with varying strategies, global equities consisting of mutual funds, alternative investments of limited partnerships and commingled mutual funds and fixed income investments.

During the prior year and part of the current year, the Company participated in employee benefit plans with Energen. Effective April 30, 2014, Energen Corporation separated one of its defined benefit non-contributory pension plans into an Energen plan and a separate Alagasco plan. The separation of plan assets and obligations was completed in accordance with ERISA provisions. Also effective April 30, 2014, Energen separated its postretirement health care and life insurance benefit plans into separate plans established for Energen and the Company’s employees in accordance with ERISA provisions. Energen and the Company remeasured all of the aforementioned respective plans using current assumptions.

The prior year figures in the following tables, unless explicitly stated otherwise, represent the combined financial information of the defined qualified and nonqualified supplemental benefit plans along with the postretirement health care and life insurance benefit plans prior to the separation of the plans between the Company and Energen.

Pension costs in the transition period ended September 30, 2014 and the calendar years ended December 31, 2013 and 2012 amounted to $16.8, $26.6, and $16.4, respectively.

The net periodic pension costs include the following components:

	Nine Months Ended			Calendar Year Ended December 31,
($ Millions)	September 30, 2014			2013			2012
Pension Plans
Components of net periodic benefit cost:
Service cost	$	5.1		$	14.2		$	10.5
Interest cost	4.1			11.2			10.8
Expected long-term return on assets	(5.2		)	(14.7		)	(14.1		)
Prior service cost amortization	0.1			0.5			0.6
Actuarial loss amortization	2.2			14.0			8.6
Amortization of prior regulatory assets and liabilities	0.4			—			—
Settlement charge	10.1			1.4			—
Net periodic expense	$	16.8		$	26.6		$	16.4
Postretirement Benefit Plans
Components of net periodic benefit cost:
Service cost	$	0.4		$	1.7		$	1.9
Interest cost	1.9			3.5			4.2
Expected long-term return on assets	(3.6		)	(5.0		)	(4.4		)
Actuarial (gain) loss amortization	(1.0		)	(0.1		)	—
Transition obligation amortization	—			1.3			1.9
Amortization of prior regulatory assets and liabilities	(0.2		)	—			—
Curtailment gain	—			(1.2		)	—
Net periodic expense	$	(2.5	)	$	0.2		$	3.6

Obligations recognized in other comprehensive income were as follows:

	Nine Months Ended			Calendar Year Ended December 31,
($ Millions)	September 30, 2014			2013			2012
Pension Plans
Net actuarial (gain) loss experienced during the year	$	1.5		$	(14.1	)	$	28.7
Net actuarial loss recognized as expense	—			(8.9		)	(4.9		)
Prior service cost recognized as expense	—			(0.3		)	(0.3		)
	1.5			(23.3		)	23.5
Transfer to regulatory assets (liabilities)	(1.5		)	—			—
Other Comprehensive Income	$	—		$	(23.3	)	$	23.5
Postretirement Benefit Plans
Net actuarial (gain) loss experienced during the year	$	1.1		$	(8.1	)	$	(1.8	)
Net actuarial gain recognized as expense	—			0.6			—
Transition obligation recognized as expense	—			(0.3		)	(0.3		)
	1.1			(7.8		)	(2.1		)
Transfer to regulatory assets (liabilities)	(1.1		)	—			—
Other Comprehensive Income	$	—		$	(7.8	)	$	(2.1	)

After the Acquisition, the Company began amortizing its existing regulatory assets and liabilities attributable to the pension and postretirement benefits over the average remaining service for active participants as of the date of the Acquisition. Therefore, any new regulatory asset or liability is attributable to the pension or postretirement benefit plans after the date of the Acquisition. The Company recognized a regulatory asset of $72.5 and a regulatory liability of $28.5, when the plans were remeasured at September 1, 2014.

During the transition period ended September 30, 2014 and calendar 2013 the Company incurred settlement charges of $0.0 and $0.5 respectively for the payment of lump sums from the nonqualified supplemental retirement plans, of which $0.0 and $0.1 respectively was expensed and $0.0 and $0.4 was recognized as a pension and postretirement asset in regulatory assets at the Company.

The following table sets forth the reconciliation of the beginning and ending balances of the pension benefit obligation:

	September 30,			December 31,			September 30,			December 31,
	2014			2013			2014			2013
($ MIllions)	Pension						Postretirement Benefits
Accumulated benefit obligation	$	129.6		$	253.0
Benefit obligation:
Balance at beginning of period	293.4			323.5			63.6			85.8
Energen portion of liability divested	(144.7		)	—			(13.3		)	—
Liability loss due to estimated allocation	16.9			—			7.7			—
Service cost	5.1			14.2			0.4			1.7
Interest cost	4.1			11.2			1.9			3.5
Actuarial (gain) loss	7.8			(28.3		)	4.3			(21.7		)
Curtailment gain	—			(4.2		)	—			(1.3		)
Retiree drug subsidy program	—			—			0.3			0.3
Benefits paid	(33.8		)	(23.0		)	(4.0		)	(4.7		)
Balance at end of period	$	148.8		$	293.4		$	60.9		$	63.6

The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets:

	September 30,			December 31,			September 30,			December 31,
	2014			2013			2014			2013
($ Millions)	Pension						Postretirement Benefits
Plan assets:
Fair value of plan assets at beginning of period	$	219.5		$	209.3		$	98.9		$	87.1
Energen portion of assets divested	(90.9		)	—			(22.0		)	—
Asset gain due to estimated allocation	15.0			—			11.0			—
Actual return on plan assets	7.8			23.0			1.4			14.9
Employer contributions	1.6			10.2			0.3			1.6
Benefits paid	(33.8		)	(23.0		)	(4.0		)	(4.7		)
Fair value of plan assets at end of period	$	119.2		$	219.5		$	85.6		$	98.9
(Unfunded) funded status of plan	$	(29.6	)	$	(73.8	)	$	24.7		$	35.4

The following table sets forth the amounts recognized in the Balance Sheets:

	September 30,			December 31,			September 30,		December 31,
	2014			2013			2014		2013
($ Millions)	Pension						Postretirement Benefits
Noncurrent assets	$	—		$	—		$	24.7	$	35.4
Current liabilities	—			(6.1		)	—		—
Noncurrent liabilities	(29.6		)	(67.7		)	—		—
Net asset (liability) recognized	$	(29.6	)	$	(73.8	)	$	24.7	$	35.4

A summary of the Company's allocated share of the benefit plans described above is presented below as of the transition period and calendar year end, respectively:

	September 30,			December 31,			September 30,			December 31,
	2014			2013			2014			2013
($ MIllions)	Pension						Postretirement Benefits
Net benefit asset noncurrent	$	—		$	—		$	24.7		$	26.5
Net benefit liability noncurrent	(29.6		)	(20.2		)	—			—
Regulatory asset	67.8			58.5			4.7			—
Regulatory liability	$	(1.9	)	$	—		$	(26.6	)	$	(26.2	)

The pension regulatory assets and liabilities are allowed to be recovered or refunded through rates in subsequent years.

Assumptions are used based on the unique set of characteristics for each of the individual pension and postretirement plans.

	Nine Months Ended		Calendar Years Ended December 31,
	September 30, 2014		2013		2012
Pension Plans
Discount rate	4.00% & 4.05%		3.63	%	4.52	%
Expected long-term return on plan assets	7.25% & 7.00%		7.00	%	7.00	%
Rate of compensation increase for pay-related plans	2.92	%	3.71	%	3.59	%
Postretirement Benefit Plans
Discount rate	4.25	%	4.26	%	4.95	%
Expected long-term return on plan assets	7.25% & 4.75%		7.00	%	7.00	%

The weighted average rate assumptions used to determine the projected benefit obligations at the measurement date were as follows:

	September 30, 2014		December 31, 2013
Pension Plans
Discount rate	4.15% & 4.25%		4.30	%
Rate of compensation increase for pay-related plans	2.92	%	3.60	%
Postretirement Benefit Plans
Discount rate	4.40	%	5.00	%

The assumed post-65 health care cost trend rates used to determine the postretirement benefit obligation at the measurement date were as follows:

	September 30, 2014		December 31, 2013
Health care cost trend rate assumed for next year	7.25	%	6.50	%
Rate to which the cost trend rate is assumed to decline	5.00	%	5.00	%
Year that rate reaches ultimate rate	2020		2020

Assumed health care cost trend rates used in determining the accumulated postretirement benefit obligation have an effect on the amounts reported. For example, revising the weighted average health care cost trend rate by 1 percentage point would have the following effects:

($ Millions)	1-Percentage Point Decrease			1-Percentage Point Increase
Effect on total of service and interest cost	$	—		$	—
Effect on net postretirement benefit obligation	(0.7		)	0.7

Following are the targeted and actual plan assets by asset category:

	Pension						Postretirement Benefits
	Target		September 30, 2014		December 31, 2013		Target		September 30, 2014		December 31, 2013
Asset category:
Equity securities	41.0	%	51.0	%	34.0	%	60.0	%	60.0	%	61.0	%
Debt securities	38.0	%	36.0	%	28.0	%	40.0	%	40.0	%	39.0	%
Other	21.0	%	13.0	%	38.0	%	—	%	—	%	—	%
Total	100.0	%	100.0	%	100.0	%	100.0	%	100.0	%	100.0	%

The Companyemploys a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets with a prudent level of risk. Risk tolerance is established through consideration of plan liabilities, plan funded status, corporate financial condition and market conditions.

The Company has developed an investment strategy that focuses on asset allocation, diversification and quality guidelines. The investment goals are to obtain an adequate level of return to meet future obligations of the plan by providing above average risk-adjusted returns with a risk exposure in the mid-range of comparable funds. Investment managers are retained by the Company to manage separate pools of assets. Funds are allocated to such managers in order to achieve an appropriate, diversified, and balanced asset mix. Comparative market and peer group benchmarks are utilized to ensure that investment managers are performing satisfactorily.

The Company seeks to maintain an appropriate level of diversification to minimize the risk of large losses in a single asset class. Accordingly, plan assets for the pension plans and the postretirement health care and life insurance benefit plan do not have a concentration of assets in a single entity, industry, country, commodity or class of investment fund.

Equity securities for pension and postretirement benefits do not include the Laclede Group's common stock.

Plan assets included in the funded status of the pension plans were as follows:

	September 30, 2014
($ Millions)	Level 1		Level 2		Level 3		Total
United States equities (1)	$	30.4	$	13.6	$	—	$	44.0
Global equities (2)	12.3		0.0		—		12.3
Fixed income (3)	11.5		31.9		—		43.4
Alternative investments (4)	—		17.6		—		17.6
Cash and cash equivalents	0.3		1.6		—		1.9
Total	$	54.5	$	64.7	$	—	$	119.2
	December 31, 2013
($ Millions)	Level 1		Level 2		Level 3		Total
United States equities (1)	$	34.1	$	8.1	$	—	$	42.2
Global equities (2)	20.1		13.3		—		33.4
Fixed income (3)	—		61.1		—		61.1
Alternative investments (4)	—		37.3		—		37.3
Cash and cash equivalents	6.0		39.5		—		45.5
Total	$	60.2	$	159.3	$	—	$	219.5

(1) United States equities consist of mutual and commingled funds with varying strategies. Such strategies include stock investments across market capitalizations and investment styles. 

(2) Global equities consist of mutual funds and a limited partnership that invest in United States and non-United States securities broadly diversified across mostly developed markets but with some tactical exposure to emerging markets.

(3) Fixed income securities consist of mutual funds and separate accounts. Fixed income securities are well diversified with allocations to investment grade and non-investment grade issues and issues that provide both intermediate and longer duration exposure.

(4) Alternative investments consist of limited partnerships and commingled and mutual funds with varying investment strategies. Alternative investments are meant to serve as a risk reducer at the total portfolio level as they provide asset class exposures not found elsewhere in the portfolio.

The following is a reconciliation of plan assets in Level 3 of the fair value hierarchy:

	Nine Months Ending September 30,		Calendar Year Ending December 31,
($ Millions)	2014		2013
Balance at beginning of period	$	—	$	14.5
Transfer out of level 3	—		(14.5		)
Balance at end of period	$	—	$	—

Plan assets included in the funded status of the postretirement benefit plans were as follows:

	September 30, 2014
($ Millions)	Level 1		Level 2		Total
United States equities (1)	$	43.9	$	—	$	43.9
Global equities (2)	7.2		—		7.2
Fixed income (3)	—		34.4		34.4
Cash and cash equivalents	0.1		—		0.1
Total	$	51.2	$	34.4	$	85.6

	December 31, 2013
($ Millions)	Level 1		Level 2		Total
United States equities	$	43.1	$	—	$	43.1
Global equities	17.0		—		17.0
Fixed income	—		38.8		38.8
Cash and cash equivalents	—		—		—
Total	$	60.1	$	38.8	$	98.9

(1) United States equities consists of mutual funds with varying strategies. These funds invest largely in medium to large capitalized companies with exposure blending growth, market-oriented and value styles. Additional fund investments include small capitalization companies, and certain of these funds utilize tax-sensitive management approaches.

(2) Global equities are mutual funds that invest in non-United States securities broadly diversified across most developed markets with exposure blending growth, market-oriented and value styles.

(3)Fixed income securities are high-quality short-duration securities including investment-grade market sectors with tactical investments in non-investment grade sectors.

The following benefit payments, which reflect expected future service, as appropriate, are anticipated to be paid as follows. In addition, the following benefits reflect the expected prescription drug subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act). The Act includes a prescription drug benefit under Medicare Part D as well as a federal subsidy which began in 2007:

($ Millions)	Pension Benefits		Postretirement Benefits		Postretirement Benefits – Prescription Drug Subsidy
2015	$	9.9	$	3.8	$	(0.2	)
2016	10.2		3.8		(0.2		)
2017	10.6		3.8		(0.2		)
2018	10.6		3.8		(0.2		)
2019	11.2		3.8		(0.3		)
2020-2024	58.7		18.6		(1.3		)

There are no required contributions to the qualified pension plans during 2015. Additionally, it is not anticipated that the funded status of the qualified pension plans will fall below statutory thresholds requiring accelerated funding or constraints on benefit levels or plan administration. During fiscal 2015 the Company may make additional discretionary contributions to the qualified pension plans depending on the amount and timing of employee retirements and market conditions.

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FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

9 Months Ended

Sep. 30, 2014

Fair Value Disclosures [Abstract]

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Financial Instruments:

The stated value of cash and cash equivalents, short-term investments, trade receivables (net of allowance), and short-term debt approximates fair value due to the short maturity of the instruments. The fair value of the Company’s fixed-rate long-term debt, including the current portion, approximates $266.4 and $258.8 and has a carrying value of $249.8 and $249.9 at September 30, 2014 and December 31, 2013, respectively. The fair values were based on market prices of similar instruments having the same remaining maturities, redemption terms and credit rating. Short-term debt is classified as Level 1 fair value and long-term debt is classified as Level 2 fair value.

The Company purchases gas as an agent for certain of its large commercial and industrial customers. The Company has, in certain instances, provided commodity-related guarantees to counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the balance sheet. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, the Company can sell such gas for the customer, with the customer liable for any resulting loss. Although the substantial majority of purchases under these guarantees are for the customers’ current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At September 30, 2014, the fixed price purchases under these guarantees had a maximum term outstanding through August 2015 with an aggregate purchase price of $0.6 and a market value of $0.6.

Finance Receivables:

The Company finances third party contractor sales of merchandise including gas furnaces and appliances. At September 30, 2014 and December 31, 2013, the Company’s finance receivable totaled approximately $10.9 and $10.8, respectively. Financing is available only to qualified customers who meet creditworthiness thresholds for customer payment history and external agency credit reports. The Company relies upon ongoing payments as the primary indicator of credit quality during the term of each contract. The allowance for credit losses is recognized using an estimate of write-off percentages based on historical experience applied to an aging of the finance receivable balance. Delinquent accounts are evaluated on a case-by-case basis and, absent evidence of debt repayment after 90 days, are due in full and assigned to a third party collection agency. The remaining finance receivable is written off approximately 12 months after being assigned to the third party collection agency. The Company had finance receivables past due 90 days or more of $0.3 and $0.4 as of September 30, 2014 and December 31, 2013, respectively. The Company recorded an allowance for credit losses at September 30, 2014 and December 31, 2013 of $0.3 and $0.4, respectively.

Concentration of Credit Risk:

Natural gas distribution operating revenues and related accounts receivable are generated from state-regulated utility natural gas sales and transportation to approximately 423,000 residential, commercial and industrial customers located in central and north Alabama. A change in economic conditions may affect the ability of customers to meet their obligations; however, the Company believes that its provision for possible losses on uncollectible accounts receivable is adequate for its credit loss exposure.

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REGULATORY ASSETS AND LIABILITIES - Regulatory Assets (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Regulatory Assets [Line Items]
Regulatory assets, current	$ 8.8	$ 2.8
Regulatory assets, noncurrent	90.6	84.9
Postretirement assets
Regulatory Assets [Line Items]
Regulatory assets, current	6.4	0.3
Regulatory assets, noncurrent	66.1	58.2
Accretion and depreciation for asset retirement obligation
Regulatory Assets [Line Items]
Regulatory assets, current	0	0
Regulatory assets, noncurrent	18.3	18.0
Rate recovery of asset removal costs, net
Regulatory Assets [Line Items]
Regulatory assets, current	0	0
Regulatory assets, noncurrent	2.8	4.7
Enhanced stability reserve
Regulatory Assets [Line Items]
Regulatory assets, current	0	0
Regulatory assets, noncurrent	3.4	4.0
Gas supply adjustment
Regulatory Assets [Line Items]
Regulatory assets, current	0	2.5
Regulatory assets, noncurrent	0	0
RSE adjustment
Regulatory Assets [Line Items]
Regulatory assets, current	2.4	0
Regulatory assets, noncurrent	$ 0	$ 0

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TRANSACTIONS WITH RELATED PARTIES (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Dec. 31, 2012
Related Party Transaction [Line Items]
Net trade receivables from affiliates	$ 0	$ 4.7
Due to Related Parties	0.4	0
Interest revenue from affiliates	0	0	0.3
Dividends paid to Laclede Group	5.0
Energen Corporation
Related Party Transaction [Line Items]
Dividends, Cash	$ 32.4	$ 33.3	$ 33.6

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ACQUISITION AND DISPOSITION OF PROPERTIES (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended
	Aug. 31, 2013
Leases [Abstract]
Gain recognized related to sale	$ 10.9
Proceeds from sale, pre-tax	$ 13.8
Length of lease	20 months

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Narrative (Details) (USD $)	0 Months Ended	9 Months Ended	12 Months Ended		0 Months Ended
	Jun. 01, 2010	Sep. 30, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 02, 2014 Laclede Group Inc Alagasco	Sep. 02, 2014 Laclede Group Inc Alagasco
Business Acquisition [Line Items]
Consideration transferred					$ 1,600,000,000
Long-term debt assumed in a business combination						250,000,000
Composite depreciation rate (percent)	3.10%
Refundable gas costs		13,400,000
Gas imbalances		0	0
Taxes on revenues		$ 20,600,000	$ 25,900,000	$ 21,500,000

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PENSION PLANS AND OTHER POST-RETIREMENT BENEFITS - Post-65 Health Care Cost Trend Rates (Details)	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]
Health care cost trend rate assumed for next year	7.25%	6.50%
Rate to which the cost trend rate is assumed to decline	5.00%	5.00%
Year that rate reaches ultimate rate	2020	2020

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TRANSACTIONS WITH RELATED PARTIES

9 Months Ended

Sep. 30, 2014

Related Party Transactions [Abstract]

TRANSACTIONS WITH RELATED PARTIES

TRANSACTIONS WITH RELATED PARTIES

Prior to the Transaction, Energen allocated certain corporate costs to the Company based on the nature of the expense using various factors including, but not limited to, total assets, earnings, or number of employees. The Company’s cash management program was established to minimize borrowing from outside sources through inter-company lending. Under this program, the Company borrowed from but did not lend to affiliates. The Company had net trade receivables from affiliates of $0.0 and $4.7 at September 30, 2014 and December 31, 2013, respectively. The Company had net trade payables to affiliates of $0.4 and $0.0 at September 30, 2014 and December 31, 2013, respectively. Interest income and expense between affiliates was calculated monthly based on the market weighted average interest rate. The Company had $0.0, $0.0 and $0.3 in affiliated company interest expense during the transition period ended September 30, 2014 and the calendar years ended December 31, 2013 and 2012, respectively. The Company paid dividends to Energen of $32.4, $33.3 and $33.6 during the transition period ended September 30, 2014 and the calendar years ended December 31, 2013 and 2012, respectively. The Company also paid dividends to Laclede of $5.0 in the transition period ended September 30, 2014.

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INCOME TAXES (Tables)

9 Months Ended

Sep. 30, 2014

Income Tax Disclosure [Abstract]

Net Provision For Income Tax

The components of the Company’s income taxes consisted of the following:

	Nine Months ended		Calender Year Ended December 31,
($ Millions)	September 30, 2014		2013		2012
Taxes estimated to be payable currently:
Federal	$	14.1	$	17.5	$	18.3
State	1.8		2.2		0.7
Total current	$	15.9	$	19.7	$	19.0
Taxes deferred:
Federal	$	3.5	$	13.3	$	9.1
State	0.5		1.7		2.2
Total deferred	$	4.0	$	15.0	$	11.3
Total income tax expense	$	19.9	$	34.7	$	30.3

Significant Items in Net Deferred Tax Liability

Temporary differences and carryforwards which gave rise to the Company’s deferred tax assets and liabilities were as follows:

($ Millions)	September 30, 2014				December 31, 2013
	Current		Noncurrent		Current		Noncurrent
Deferred tax assets:
Unbilled and deferred revenue	$	2.5	$	—	$	12.5	$	—
Allowance for doubtful accounts	—		—		1.8		—
Insurance accruals	—		—		1.8		—
Compensation accruals	—		—		2.5		—
Inventories	—		—		1.3		—
Gas supply adjustment related accruals	—		—		0.7		—
Pension and other costs	—		10.6		—		—
Goodwill	—		266.1		—		—
Net operating loss	—		5.1		—		—
Other	0.2		—		1.0		—
Total deferred tax assets	$	2.7	$	281.8	$	21.6	$	—
Deferred tax liabilities:
Depreciation and basis differences	$	—	$	4.0	$	—	$	186.6
Pension and other costs	—		—		—		19.0
Other	0.4		—		1.6		—
Total deferred tax liabilities	0.4		4.0		1.6		205.6
Net deferred tax assets (liabilities)	$	2.3	$	277.8	$	20.0	$	(205.6	)

Effective income tax rate variation from stated tax rate

Total income tax expense for the Company differed from the amount that would have been provided by applying the statutory federal income tax rate of 35% to earnings before taxes as illustrated below:

	Nine Months Ended			Calendar Year Ended December 31,
($ Millions)	September 30, 2014			2013			2012
Income tax expense at statutory federal income tax rate	$	18.5		$	32.2		$	27.9
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit	1.5			2.6			2.3
Other, net	(0.1		)	(0.1		)	0.1
Total income tax expense	$	19.9		$	34.7		$	30.3
Effective income tax rate (%)	37.6		%	37.7		%	38.0		%

Unrecognized Tax Benefit Reconciliation

A reconciliation of the Company’s beginning and ending amount of unrecognized tax benefits is as follows:

($ Millions)
Balance as of December 31, 2011	$	0.1
Additions based on tax positions related to the current year	0.1
Additions for tax positions of prior years	0.2
Reductions for tax positions of prior years (lapse of statute of limitations)	(0.1		)
Balance as of December 31, 2012	0.3
Reductions for tax positions of prior years (lapse of statute of limitations)	—
Balance as of December 31, 2013	0.3
Reductions for transfer of balances to Energen	(0.3		)
Balance as of September 30, 2014	$	—

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- Amounts Recognized in Consolidated Balance Sheets (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 01, 2014	Dec. 31, 2013
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Noncurrent assets	$ 24.7		$ 26.5
Noncurrent liabilities	(29.6)		(20.2)
Regulatory asset		72.5
Regulatory liability		(28.5)
Pension Plans
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Noncurrent assets	0		0
Current liabilities	0		(6.1)
Noncurrent liabilities	(29.6)		(67.7)
Net benefit asset noncurrent	0		0
Net benefit liability noncurrent	(29.6)		(20.2)
Regulatory asset	67.8		58.5
Regulatory liability	(1.9)		0
Net asset (liability) recognized	(29.6)		(73.8)
Postretirement Plans
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Noncurrent assets	24.7		35.4
Current liabilities	0		0
Noncurrent liabilities	0		0
Net benefit asset noncurrent	24.7		26.5
Net benefit liability noncurrent	0		0
Regulatory asset	4.7		0
Regulatory liability	(26.6)		(26.2)
Net asset (liability) recognized	$ 24.7		$ 35.4

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INCOME TAXES - Net Provisions for Income Taxes (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended		12 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Dec. 31, 2012
Taxes estimated to be payable currently:
Federal	$ 14.1		$ 17.5	$ 18.3
State	1.8		2.2	0.7
Total current	15.9		19.7	19.0
Taxes deferred:
Federal	3.5		13.3	9.1
State	0.5		1.7	2.2
Total deferred	4.0		15.0	11.3
Total income tax expense	$ 19.9	$ 22.9	$ 34.7	$ 30.3

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STATEMENTS OF CAPITALIZATION (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Common Stock Equity:
Common stock equity, $0.01 par value, 3,000,000 shares authorized, 1,972,052 shares issued at September 30, 2014 and December 31, 2013, respectively	$ 503.9	$ 34.5
Retained earnings	345.7	350.1
Total Common Stock Equity	849.6	384.6
Long Term Debt
Debt instrument, principal outstanding	249.8	249.9
Total Capitalization	1,099.4	634.5
5.368% Notes, due December 1, 2015
Long Term Debt
Debt instrument, principal outstanding	80.0	80.0
5.20% Notes, due January 15, 2020
Long Term Debt
Debt instrument, principal outstanding	40.0	40.0
3.86% Notes, due December 21, 2021
Long Term Debt
Debt instrument, principal outstanding	50.0	50.0
5.70% Notes, due January 15, 2035
Long Term Debt
Debt instrument, principal outstanding	34.8	34.9
5.90% Notes, due January 15, 2037
Long Term Debt
Debt instrument, principal outstanding	$ 45.0	$ 45.0

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ACQUISITION

9 Months Ended

Sep. 30, 2014

Business Combinations [Abstract]

ACQUISITION

ACQUISITION

On September 2, 2014, Laclede Group acquired all outstanding equity of the Company (the "Transaction") from Energen for approximately $1,600.0, including the assumption of $250.0 of the Company's long-term debt. The consideration is subject to certain post-closing adjustments for cash, indebtedness and working capital which at this time are not expected to be material. The Acquisition was accounted for under the acquisition method of accounting in accordance with ASC 805 (“Topic 805”), “Business Combinations". Laclede Group determined that the Acquisition met the scope exceptions for pushdown accounting, and as such the excess consideration transferred over the fair value of assets acquired was recorded at Laclede Group. Laclede Group and Energen made an election under Section 338(h)(10) of the Internal Revenue Code of 1986, as amended, to treat the Acquisition as a deemed purchase and sale of assets for tax purposes. As a result the existing deferred tax assets and liabilities were remeasured to zero as of September 2, 2014, with a deferred tax asset of $280.1 established for excess tax basis in assets resulting from the election.

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COMMITMENTS AND CONTINGENCIES (Details) (USD $) In Millions, unless otherwise specified					9 Months Ended	12 Months Ended		9 Months Ended
	Sep. 30, 2014 site	Sep. 30, 2013 Removal Action, Phase I 35th Avenue Superfund Site Resident	Sep. 30, 2013 Removal Action, Phase II 35th Avenue Superfund Site Resident	Sep. 30, 2014 Sites owned by Alagasco site	Sep. 30, 2014 Natural Gas, Delivery and Storage	Dec. 31, 2013 Natural Gas, Delivery and Storage	Dec. 31, 2012 Natural Gas, Delivery and Storage	Sep. 30, 2014 Natural Gas MMcf
Site Contingency [Line Items]
Minimum total payments required for natural gas contracts					$ 134.0
Long-term contracts expense recognized in financial statements					$ 33.8	$ 50.0	$ 51.0
Long-term contracts, minimum quantity commitments (in millions of cubic feet)								111,000
Chain of title, manufactured gas plant sites	9			4
Chain of title, manufactured gas distribution sites	5			1
Site contingency, number of residents contaminated		50	30

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PENSION PLANS AND OTHER POST-RETIREMENT BENEFITS (Tables)

9 Months Ended

Sep. 30, 2014

Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]

Net Periodic Cost

The net periodic pension costs include the following components:

	Nine Months Ended			Calendar Year Ended December 31,
($ Millions)	September 30, 2014			2013			2012
Pension Plans
Components of net periodic benefit cost:
Service cost	$	5.1		$	14.2		$	10.5
Interest cost	4.1			11.2			10.8
Expected long-term return on assets	(5.2		)	(14.7		)	(14.1		)
Prior service cost amortization	0.1			0.5			0.6
Actuarial loss amortization	2.2			14.0			8.6
Amortization of prior regulatory assets and liabilities	0.4			—			—
Settlement charge	10.1			1.4			—
Net periodic expense	$	16.8		$	26.6		$	16.4
Postretirement Benefit Plans
Components of net periodic benefit cost:
Service cost	$	0.4		$	1.7		$	1.9
Interest cost	1.9			3.5			4.2
Expected long-term return on assets	(3.6		)	(5.0		)	(4.4		)
Actuarial (gain) loss amortization	(1.0		)	(0.1		)	—
Transition obligation amortization	—			1.3			1.9
Amortization of prior regulatory assets and liabilities	(0.2		)	—			—
Curtailment gain	—			(1.2		)	—
Net periodic expense	$	(2.5	)	$	0.2		$	3.6

Other changes in plan assets and benefit obligations recognized in other comprehensive income

Obligations recognized in other comprehensive income were as follows:

	Nine Months Ended			Calendar Year Ended December 31,
($ Millions)	September 30, 2014			2013			2012
Pension Plans
Net actuarial (gain) loss experienced during the year	$	1.5		$	(14.1	)	$	28.7
Net actuarial loss recognized as expense	—			(8.9		)	(4.9		)
Prior service cost recognized as expense	—			(0.3		)	(0.3		)
	1.5			(23.3		)	23.5
Transfer to regulatory assets (liabilities)	(1.5		)	—			—
Other Comprehensive Income	$	—		$	(23.3	)	$	23.5
Postretirement Benefit Plans
Net actuarial (gain) loss experienced during the year	$	1.1		$	(8.1	)	$	(1.8	)
Net actuarial gain recognized as expense	—			0.6			—
Transition obligation recognized as expense	—			(0.3		)	(0.3		)
	1.1			(7.8		)	(2.1		)
Transfer to regulatory assets (liabilities)	(1.1		)	—			—
Other Comprehensive Income	$	—		$	(7.8	)	$	(2.1	)

Reconciliation of the beginning and ending balances of benefit obligation

The following table sets forth the reconciliation of the beginning and ending balances of the pension benefit obligation:

	September 30,			December 31,			September 30,			December 31,
	2014			2013			2014			2013
($ MIllions)	Pension						Postretirement Benefits
Accumulated benefit obligation	$	129.6		$	253.0
Benefit obligation:
Balance at beginning of period	293.4			323.5			63.6			85.8
Energen portion of liability divested	(144.7		)	—			(13.3		)	—
Liability loss due to estimated allocation	16.9			—			7.7			—
Service cost	5.1			14.2			0.4			1.7
Interest cost	4.1			11.2			1.9			3.5
Actuarial (gain) loss	7.8			(28.3		)	4.3			(21.7		)
Curtailment gain	—			(4.2		)	—			(1.3		)
Retiree drug subsidy program	—			—			0.3			0.3
Benefits paid	(33.8		)	(23.0		)	(4.0		)	(4.7		)
Balance at end of period	$	148.8		$	293.4		$	60.9		$	63.6

Changes in fair value of plan assets

The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets:

	September 30,			December 31,			September 30,			December 31,
	2014			2013			2014			2013
($ Millions)	Pension						Postretirement Benefits
Plan assets:
Fair value of plan assets at beginning of period	$	219.5		$	209.3		$	98.9		$	87.1
Energen portion of assets divested	(90.9		)	—			(22.0		)	—
Asset gain due to estimated allocation	15.0			—			11.0			—
Actual return on plan assets	7.8			23.0			1.4			14.9
Employer contributions	1.6			10.2			0.3			1.6
Benefits paid	(33.8		)	(23.0		)	(4.0		)	(4.7		)
Fair value of plan assets at end of period	$	119.2		$	219.5		$	85.6		$	98.9
(Unfunded) funded status of plan	$	(29.6	)	$	(73.8	)	$	24.7		$	35.4

Amounts recognized in consolidated balance sheets

The following table sets forth the amounts recognized in the Balance Sheets:

	September 30,			December 31,			September 30,		December 31,
	2014			2013			2014		2013
($ Millions)	Pension						Postretirement Benefits
Noncurrent assets	$	—		$	—		$	24.7	$	35.4
Current liabilities	—			(6.1		)	—		—
Noncurrent liabilities	(29.6		)	(67.7		)	—		—
Net asset (liability) recognized	$	(29.6	)	$	(73.8	)	$	24.7	$	35.4

A summary of the Company's allocated share of the benefit plans described above is presented below as of the transition period and calendar year end, respectively:

	September 30,			December 31,			September 30,			December 31,
	2014			2013			2014			2013
($ MIllions)	Pension						Postretirement Benefits
Net benefit asset noncurrent	$	—		$	—		$	24.7		$	26.5
Net benefit liability noncurrent	(29.6		)	(20.2		)	—			—
Regulatory asset	67.8			58.5			4.7			—
Regulatory liability	$	(1.9	)	$	—		$	(26.6	)	$	(26.2	)

Assumptions used to calculate net periodic cost and benefit obligations.

Assumptions are used based on the unique set of characteristics for each of the individual pension and postretirement plans.

	Nine Months Ended		Calendar Years Ended December 31,
	September 30, 2014		2013		2012
Pension Plans
Discount rate	4.00% & 4.05%		3.63	%	4.52	%
Expected long-term return on plan assets	7.25% & 7.00%		7.00	%	7.00	%
Rate of compensation increase for pay-related plans	2.92	%	3.71	%	3.59	%
Postretirement Benefit Plans
Discount rate	4.25	%	4.26	%	4.95	%
Expected long-term return on plan assets	7.25% & 4.75%		7.00	%	7.00	%

The weighted average rate assumptions used to determine the projected benefit obligations at the measurement date were as follows:

	September 30, 2014		December 31, 2013
Pension Plans
Discount rate	4.15% & 4.25%		4.30	%
Rate of compensation increase for pay-related plans	2.92	%	3.60	%
Postretirement Benefit Plans
Discount rate	4.40	%	5.00	%

Schedule of assumed post-65 health care cost trend rates

The assumed post-65 health care cost trend rates used to determine the postretirement benefit obligation at the measurement date were as follows:

	September 30, 2014		December 31, 2013
Health care cost trend rate assumed for next year	7.25	%	6.50	%
Rate to which the cost trend rate is assumed to decline	5.00	%	5.00	%
Year that rate reaches ultimate rate	2020		2020

Schedule of effect of one-percent point change in assumed health care cost trend rates

Assumed health care cost trend rates used in determining the accumulated postretirement benefit obligation have an effect on the amounts reported. For example, revising the weighted average health care cost trend rate by 1 percentage point would have the following effects:

($ Millions)	1-Percentage Point Decrease			1-Percentage Point Increase
Effect on total of service and interest cost	$	—		$	—
Effect on net postretirement benefit obligation	(0.7		)	0.7

Targeted and actual plan assets by category

Following are the targeted and actual plan assets by asset category:

	Pension						Postretirement Benefits
	Target		September 30, 2014		December 31, 2013		Target		September 30, 2014		December 31, 2013
Asset category:
Equity securities	41.0	%	51.0	%	34.0	%	60.0	%	60.0	%	61.0	%
Debt securities	38.0	%	36.0	%	28.0	%	40.0	%	40.0	%	39.0	%
Other	21.0	%	13.0	%	38.0	%	—	%	—	%	—	%
Total	100.0	%	100.0	%	100.0	%	100.0	%	100.0	%	100.0	%

Plan assets included in the funded status of the postretirement benefit plans were as follows:

	September 30, 2014
($ Millions)	Level 1		Level 2		Total
United States equities (1)	$	43.9	$	—	$	43.9
Global equities (2)	7.2		—		7.2
Fixed income (3)	—		34.4		34.4
Cash and cash equivalents	0.1		—		0.1
Total	$	51.2	$	34.4	$	85.6

	December 31, 2013
($ Millions)	Level 1		Level 2		Total
United States equities	$	43.1	$	—	$	43.1
Global equities	17.0		—		17.0
Fixed income	—		38.8		38.8
Cash and cash equivalents	—		—		—
Total	$	60.1	$	38.8	$	98.9

Plan assets included in the funded status of the pension plans were as follows:

	September 30, 2014
($ Millions)	Level 1		Level 2		Level 3		Total
United States equities (1)	$	30.4	$	13.6	$	—	$	44.0
Global equities (2)	12.3		0.0		—		12.3
Fixed income (3)	11.5		31.9		—		43.4
Alternative investments (4)	—		17.6		—		17.6
Cash and cash equivalents	0.3		1.6		—		1.9
Total	$	54.5	$	64.7	$	—	$	119.2
	December 31, 2013
($ Millions)	Level 1		Level 2		Level 3		Total
United States equities (1)	$	34.1	$	8.1	$	—	$	42.2
Global equities (2)	20.1		13.3		—		33.4
Fixed income (3)	—		61.1		—		61.1
Alternative investments (4)	—		37.3		—		37.3
Cash and cash equivalents	6.0		39.5		—		45.5
Total	$	60.2	$	159.3	$	—	$	219.5

Reconciliation of plan assets in Level 3 of fair value hierarchy

The following is a reconciliation of plan assets in Level 3 of the fair value hierarchy:

	Nine Months Ending September 30,		Calendar Year Ending December 31,
($ Millions)	2014		2013
Balance at beginning of period	$	—	$	14.5
Transfer out of level 3	—		(14.5		)
Balance at end of period	$	—	$	—

Expected benefit payments for the succeeding five fiscal years

The following benefit payments, which reflect expected future service, as appropriate, are anticipated to be paid as follows. In addition, the following benefits reflect the expected prescription drug subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Act). The Act includes a prescription drug benefit under Medicare Part D as well as a federal subsidy which began in 2007:

($ Millions)	Pension Benefits		Postretirement Benefits		Postretirement Benefits – Prescription Drug Subsidy
2015	$	9.9	$	3.8	$	(0.2	)
2016	10.2		3.8		(0.2		)
2017	10.6		3.8		(0.2		)
2018	10.6		3.8		(0.2		)
2019	11.2		3.8		(0.3		)
2020-2024	58.7		18.6		(1.3		)

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LONG-TERM DEBT AND NOTES PAYABLE - Maturities of Long-term Debt (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014
Maturities on long-term debt [Abstract]
2015	$ 0
2016	80.0
2017	0
2018	0
2019	16.0
2020 and beyond	$ 169.8

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REGULATORY ASSETS AND LIABILITIES

9 Months Ended

Sep. 30, 2014

Regulated Operations [Abstract]

REGULATORY ASSETS AND LIABILITIES

REGULATORY ASSETS AND LIABILITIES

The Company accounts for regulated operations in accordance with ASC Topic 980, Regulated Operations. This topic sets forth the application of GAAP for those companies whose rates are established by or are subject to approval by an independent third party regulator. The provisions of this accounting guidance require, among other things, that financial statements of a regulated enterprise reflect the actions of regulators, where appropriate. These actions may result in the recognition of revenues and expenses in time periods that are different than non-regulated enterprises. When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses when those amounts are reflected in rates. Also, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for recovery of costs that are expected to be incurred in the future (regulatory liabilities).

The following regulatory assets and regulatory liabilities were reflected in the Company's Balance Sheets and also included below:

	September 30, 2014				December 31, 2013
($ Millions)	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Postretirement assets	$	6.4	$	66.1	$	0.3	$	58.2
Accretion and depreciation for asset retirement obligation	—		18.3		—		18.0
Rate recovery of asset removal costs, net	—		2.8		—		4.7
Enhanced stability reserve	—		3.4		—		4.0
Gas supply adjustment	—		—		2.5		—
RSE adjustment	2.4		—		—		—
Total regulatory assets	$	8.8	$	90.6	$	2.8	$	84.9
Regulatory liabilities:
RSE adjustment	$	19.8	$	—	$	4.7	$	—
Unbilled service margin	5.2		—		28.5		—
Postretirement liabilities	2.3		26.2		—		26.2
Refundable negative salvage	13.4		26.8		15.8		39.7
Gas supply adjustment	22.4		—		—		—
Other	—		0.7		—		0.7
Total regulatory liabilities	$	63.1	$	53.7	$	49.0	$	66.6