10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C.

FORM 10-K

ANNUAL REPORT

For the Fiscal Year Ended September 30, 2013

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C.

FORM 10-K

ANNUAL REPORT

For the Fiscal Year Ended September 30, 2013

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 or 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal Year Ended September 30, 2013

OR

[     ] TRANSITION REPORT PURSUANT TO SECTION 13 or 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Transition Period from ­__________ to __________

Commission File Number 1-16681

THE LACLEDE GROUP, INC.

(Exact name of registrant as specified in its charter)

Missouri (State of Incorporation)	74-2976504 (I.R.S. Employer Identification number)
720 Olive Street St. Louis, MO  63101 (Address and zip code of principal executive offices) 314-342-0500 (Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act

Title of Each Class	Name of Each Exchange On Which Registered
Common Stock $1.00 par value	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None.

Indicate by check mark if the registrant:

is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [ X ] No [     ]

is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes [    ] No [ X ]

(1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such report) and (2) has been subject to such filing requirements for the past 90 days. Yes [ X ] No [     ]

has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [ X ] No [     ]

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

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	[ X ]	Accelerated filer	[     ]
Non-accelerated filer	[     ]	Smaller reporting company	[     ]

is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes [    ] No [ X ]

The aggregate market value of the voting stock held by non-affiliates of The Laclede Group, Inc.

amounted to $906,985,448 as of March 31, 2013.

As of November 21, 2013, there were 32,709,763 shares of the registrant’s Common Stock, par value $1.00 per share, outstanding.

Document Incorporated by Reference:

Portions of Proxy Statement dated December 18, 2013 — Part III

Index to Exhibits is found on page 102.

TABLE OF CONTENTS		Page No.
PART I
Forward-Looking Statements		4
Item 1	Business	5
Item 1A	Risk Factors	9
Item 1B	Unresolved Staff Comments	18
Item 2	Properties	18
Item 3	Legal Proceedings	18
Executive Officers of the Registrant (Item 401(b) of Regulation S-K)		20
PART II
Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	22
Item 6	Selected Financial Data	23
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	44
Item 8	Financial Statements and Supplementary Data	45
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	93
Item 9A	Controls and Procedures	93
Item 9B	Other Information	93
PART III
Item 10	Directors, Executive Officers and Corporate Governance	94
Item 11	Executive Compensation	94
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	94
Item 13	Certain Relationships and Related Transactions, and Director Independence	94
Item 14	Principal Accounting Fees and Services	95
PART IV
Item 15	Exhibits, Financial Statement Schedule	96
SIGNATURES		97
FINANCIAL STATEMENT SCHEDULE		98
INDEX TO EXHIBITS		99

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Part I

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, including the related impact on margin deposits associated with the use of natural gas derivative instruments;

• 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 our subsidiaries 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

• purchased gas 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;

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

• 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; and

• employee workforce issues.

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

Overview

The Laclede Group, Inc. (Laclede Group or the Company) is a public utility holding company formed through a corporate restructuring that became effective October 1, 2001. The Company has two key business segments: Gas Utility and Gas Marketing. The Gas Utility segment includes the regulated operations of Laclede Gas Company (the Utility), Laclede Group’s largest subsidiary. Laclede Gas Company is a public utility engaged in the retail distribution and sale of natural gas, and is the largest natural gas distribution utility in Missouri, serving more than 1.13 million residential, commercial and industrial customers. The Utility serves St. Louis and eastern Missouri through Laclede Gas and serves Kansas City and western Missouri through Missouri Gas Energy (MGE), whose assets were acquired by the Utility on September 1, 2013. The Gas Marketing segment includes Laclede Energy Resources, Inc. (LER), a wholly owned subsidiary engaged in the marketing of natural gas and related activities on a non-regulated basis. As of September 30, 2013, Laclede Group had 2,326 employees, including 49 part-time employees.

Consolidated operating revenues contributed by each segment for the last three fiscal years are presented below. For more detailed financial information regarding the segments, see Note 15 of the Notes to Consolidated Financial Statements.

(Thousands)	2013		2012		2011
Gas Utility	$	847,224	$	763,447	$	913,190
Gas Marketing	165,146		358,145		669,375
Other	4,649		3,883		20,742
Total Operating Revenues	$	1,017,019	$	1,125,475	$	1,603,307

Laclede Group’s common stock is listed on The New York Stock Exchange and trades under the ticker symbol “LG.”

The following table reflects shares issued during the periods indicated:

	2013	2012
Common Stock Issuance	10,005,000	—
DRIP	44,074	46,107
Equity Incentive Plan	108,331	62,590
Total Shares Issued	10,157,405	108,697

Shares were issued during 2013 to effect the acquisition of the MGE assets as well as historically consistent levels for Laclede Group's Dividend Reinvestment and Stock Purchase Plan (DRIP) and its Equity Incentive Plan.

The information we file or furnish 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.TheLacledeGroup.com, in the Investor Services section under SEC Filings as soon as reasonably practical after the information is filed or furnished to the SEC.

Gas Utility

NATURAL GAS SUPPLY

The Utility focuses its gas supply portfolio around a number of large natural gas suppliers with equity ownership or control of assets strategically situated to complement its regionally diverse firm transportation arrangements.

The Utility's fundamental gas supply strategy is to meet the two-fold objective of 1) ensuring that the gas supplies it acquires are dependable and will be 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, Laclede Gas continues to focus on natural gas assets that are strategically positioned to meet the Utility’s primary objectives. Laclede Gas utilizes both Mid-Continent and Gulf Coast gas sources to provide a level of supply diversity that facilitates the optimization of pricing differentials as well as protecting against the potential of regional supply disruptions. MGE utilizes both Mid-Continent and Rocky Mountain gas sources to provide a level of supply diversity that accesses low cost supplies while providing a natural gas price arbitrage.

5

In fiscal year 2013, the Utility purchased natural gas from 35 different suppliers to meet current gas sales and storage injection requirements. The Utility entered into firm agreements with suppliers including major producers and marketers providing flexibility to meet the temperature sensitive needs of its customers. Natural gas purchased by the Laclede Gas for delivery to its service area through the Enable Mississippi River Transmission LLC (MRT) system totaled 55.0 billion cubic feet (Bcf). Laclede Gase also holds firm transportation on several other interstate pipeline systems that provide access to gas supplies upstream of MRT. In addition to deliveries from MRT, 8.6 Bcf of gas was purchased on MO Gas, 13.4 Bcf on the Southern Star Central Gas Pipeline, Inc. (Southern Star Central), 0.03 Bcf on the Panhandle Eastern Pipe Line Company system, and 0.1 BCF on the Postrock system. Some of the Utility’s commercial and industrial customers purchased their own gas with the Utility transporting 17.0 Bcf to them through the Utility’s distribution system.

The fiscal year 2013 peak day sendout of natural gas to Laclede Gas customers, including transportation customers, occurred on January 22, 2013, when the average temperature was 16 degrees Fahrenheit in St. Louis. On that day, Laclede Gas customers consumed 0.766 Bcf of natural gas. About 91% of this peak day demand was met with natural gas transported to St. Louis through the MRT, MO Gas, and Southern Star transportation systems, and the other 9% was met from Laclede Gas' on-system storage and peak shaving resources.

UNDERGROUND NATURAL GAS STORAGE

The Utility has a contractual right to store 23.1 Bcf of gas in MRT’s storage facility located in Unionville, Louisiana, 16.3 Bcf of gas storage in Southern Star Central system storage facilities located in Kansas and Oklahoma, and 1.4 Bcf of firm storage on Panhandle Eastern Pipe Line Company’s system storage. MRT’s tariffs allow injections into storage from May 16 through November 15 and require the withdrawal from storage of all but 2.2 Bcf from November 16 through May 15. Southern Star Central tariffs allow both injections and withdrawals into storage year round with ratchets that restrict the associated flows dependent upon the underlying inventory level per the contracts.

In addition, the Utility supplements flowing pipeline gas with natural gas withdrawn from its own underground storage field located in St. Louis and St. Charles Counties in Missouri. The field is designed to provide 0.3 Bcf of natural gas withdrawals on a peak day and annual withdrawals of approximately 4.0 Bcf of gas based on the inventory level that Laclede plans to maintain.

REGULATORY MATTERS

For details on regulatory matters, see the Regulatory and Other Matters discussion in the Management’s Discussion and Analysis of Financial Condition and Results of Operations, on page 36 of this Form 10-K.

OTHER PERTINENT MATTERS

The Utility's business has monopoly characteristics in that it is the only distributor of natural gas within its franchised service areas. The principal competition are the local electric companies. Other competitors in the Utility's service areas include suppliers of fuel oil, coal, propane, natural gas pipelines which can directly connect to large volume customers, and district steam systems in the downtown areas of both St. Louis and Kansas City.

The Utility’s residential, commercial, and small industrial markets represent approximately 85% of the Utility's operating revenue. Given the current level of natural gas supply and market conditions, the Utility believes that the relative comparison of natural gas equipment and operating costs with those of competitive fuels will not change significantly in the foreseeable future, and that these markets will continue to be supplied by natural gas. In new multi-family and commercial rental markets, the Utility's competitive exposure is presently limited to space and water heating applications. Certain alternative heating systems can be cost competitive in traditional markets.

Coal is price competitive as a fuel source for very large boiler plant loads, but environmental requirements for coal have shifted the economic advantage to natural gas. Oil and propane can be used to fuel boiler loads and certain direct-fired process applications, but these fuels require on-site storage, thus limiting their competitiveness. In certain cases, district steam has been competitive with gas for downtown St. Louis and Kansas City area heating users. The Utility offers gas transportation service to its large user industrial and commercial customers. The tariff approved for that type of serviceproduces a margin similar to that which the Utility would have received under its regular sales rates.

6

*****

The Utility is subject to various environmental laws and regulations that, to date, have not materially affected the Company’s financial position and results of operations. For a detailed discussion of environmental matters, see Note 16 of the Notes to Consolidated Financial Statements.

*****

Laclede Gas has labor agreements with Locals 884, 11-6 and 11-194 of the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial and Service Workers International Union (Union), which represent approximately 67% of Laclede Gas’ employees. The agreements with Locals 11-6 and 11-194 will expire at midnight on July 31, 2014. Laclede Gas and Local 884 have a labor agreement that expires on midnight on July 31, 2015.

MGE has labor agreements with Locals 12561, 14228 and 11-267 of the United Steelworkers (Union), which represents 26% of Missouri Gas Energy employees; Gasworkers Metal Trades Local 781 of the United Association of Journeymen and Apprentices of the Plumbing and Pipefitting Industry of the United States and Canada, A.F. of L. - C.I.O. (Union) which represents approximately 34% of Missouri Gas Energy employees; and Local 53 of the International Brotherhood of Electrical Workers (Union) which represents approximately 13% of Missouri Gas Energy employees. Missouri Gas Energy and Locals 12561, 14228, and 11-267, 781, and 53 have labor agreements that will expire at 11:59 p.m. on April 30, 2014.

*****

The business of the Utility is subject to seasonal fluctuations with the peak period occurring in the winter season.

*****

Revenues, therms sold and transported, and customers of the Utility for the last three fiscal years are as follows (before intersegment eliminations):

Gas Utility Operating Revenues
(Thousands)	2013*		2012		2011
Residential	$	556,818	$	487,529	$	584,788
Commercial & Industrial	184,101		161,866		202,017
Interruptible	3,524		2,105		3,659
Transportation	15,293		14,094		14,426
Off-System and Capacity Release	90,188		92,477		100,225
Other	7,838		6,580		8,075
Total	$	857,762	$	764,651	$	913,190
Gas Utility Therms Sold and Transported
(Thousands)	2013*		2012		2011
Residential	496,623		385,317		497,171
Commercial & Industrial	229,562		183,536		228,080
Interruptible	3,149		3,013		5,098
Transportation	160,411		146,117		155,067
System Therms Sold and Transported	889,745		717,983		885,416
Off-System	229,358		314,473		223,000
Total Therms Sold and Transported	1,119,103		1,032,456		1,108,416
Gas Utility Customers (End of Period)
	2013*		2012		2011
Residential	1,027,556		588,061		584,926
Commercial & Industrial	99,960		39,741		39,995
Interruptible	17		15		15
Transportation	1,003		140		141
Total Customers	1,128,536		627,957		625,077

*Includes MGE for the month of September 2013, and for the end of the period.

7

*****

The Utility has franchises in nearly all of the 236 Missouri communities where it provides service with terms varying from five years to an indefinite duration. Generally, a franchise allows the Utility, among other things, to install pipes and construct other facilities in the community. Certain franchise agreements have expired, including Clayton (in 2008), St. Charles County (in 2013), North Kansas City (in 2013), Cameron (in 2013), and Riverside (in 2013) and since that time the Utility has continued to provide service in those communities without formal franchises. All of the franchises are free from unduly burdensome restrictions and are adequate for the conduct of the Utility's current public utility business in the State of Missouri.

Gas Marketing

LER is engaged in the marketing of natural gas and providing energy services to both on-system utility transportation customers and customers outside of the Utility’s traditional service area. During fiscal year 2013, LER utilized 12 interstate pipelines and 93 suppliers to market natural gas to its customers primarily in the Midwest. LER served more than 205 retail customers and 100 wholesale customers. Through its retail operations, LER offers natural gas marketing services to large industrial customers, while its wholesale business consists of buying and selling natural gas to other marketers, producers, utilities, power generators, pipelines, and municipalities. Wholesale activities currently represent a large majority of LER’s total business. LER also serves power plants that use natural gas to generate electricity.

In the course of its business, LER enters into agreements to purchase natural gas at a future date in order to lock up supply to cover future sales commitments to its customers. To secure access to the markets it serves, LER contracts for transportation capacity on pipelines. During fiscal year 2013, LER had several long-term transportation contracts that came up for renewal and was able to lower its overall transportation costs through renegotiation of contracts at lower rates. In addition, LER further reduced its costs by allowing certain transportation contracts to lapse. To provide additional operational flexibility, LER enters into park and loan transactions with pipeline companies, whereby it pays a fee to deliver natural gas to the pipeline that is redelivered to LER at a future date, at which time LER sells the natural gas to a third party. Furthermore, beginning in August 2013, LER contracted for storage capacity in northeastern Louisiana under a long-term agreement to meet the future needs of the growing gas-fired power generation market.

Historically, LER’s business has been primarily comprised of physically settled sales of natural gas to its wholesale and retail customers, whereby LER purchased natural gas at one location and transported it on its pipeline capacity to a higher-priced location. In order to transport gas on pipelines, LER incurred fuel and commodity charges on each of the movements from one location to another. As a result of new pipeline infrastructure and an abundance of natural gas supply, regional price differences have narrowed and overall price volatility has been reduced.  This reduction in regional price differentials allows LER to satisfy its commitments without incurring fuel costs to transport natural gas to a different location. As a result, LER cannot be certain that all of its wholesale purchase and sale transactions will settle physically, so many transactions entered into in fiscal year 2013 are designated as trading activities for financial reporting purposes.  Results of operations from trading activities are reported on a net basis in Gas Marketing Operating Revenues.  This presentation has no effect on operating income or net income.

LER’s strategy is to leverage its market expertise and risk management skills to manage and optimize the value of its portfolio of commodity, transportation, park and loan, and storage contracts while controlling costs and acting on new marketplace opportunities. LER was profitable in fiscal year 2013, despite a challenging market.

Looking forward, market conditions continue to be challenging with low market volatility and historically small price differentials between geographic regions which drive transportation values and also seasonal spreads which drive storage and park and loan values.

OTHER

Laclede Pipeline Company, a wholly owned subsidiary, operates a propane pipeline under Federal Energy Regulatory Commission (FERC) jurisdiction. This pipeline connects the propane storage and vaporization facilities of the Utility to third-party propane supply terminal facilities located in Illinois, which allows the Utility to receive propane that is vaporized to supplement its natural gas supply and meet peak demands on its distribution system. Laclede Pipeline Company also provides transportation services to third parties.

8

Other also includes Laclede Group’s subsidiaries that are engaged in, among other activities, oil production, real estate development, compression of natural gas, and financial investments in other enterprises. These operations are conducted through seven subsidiaries. The Other category also includes the Utility’s non-regulated propane services business which involves providing propane-related services and storage to third parties and its affiliate, Laclede Pipeline Company. Beginning July 1, 2013, propane-related services are included within Gas Utility operations pursuant to the Utility's new rate case.

Item 1A. Risk Factors

Laclede Group’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. When considering any investment in Laclede Group securities, investors should carefully consider the following information, as well as information contained in the caption "Forward-Looking Statements," Item 7A, and other documents Laclede files with the SEC. This list is not exhaustive, and Laclede Group's management places no priority or likelihood based on the risk descriptions, order of presentation or grouping by subsidiary.

RISKS AND UNCERTAINTIES THAT RELATE TO THE BUSINESS AND FINANCIAL RESULTS OF LACLEDE GROUP AND ITS SUBSIDIARIES

As a holding company, Laclede Group depends on its operating subsidiaries to meet its financial obligations.

Laclede Group is a holding company with no significant assets other than the stock of its operating subsidiaries and cash investments. Laclede Group, and the Utility prior to Laclede Group’s formation, have paid dividends continuously since 1946. However, Laclede Group relies exclusively on dividends from its subsidiaries, on intercompany loans from its non-utility subsidiaries, and on the repayments of principal and interest from intercompany loans made to its subsidiaries for its cash flows. Laclede Group’s ability to pay dividends to its shareholders is dependent on the ability of its subsidiaries to generate sufficient net income and cash flows to pay upstream dividends and make loans or loan repayments.

A downgrade in Laclede Group’s credit ratings may negatively affect its ability to access capital.

Currently, Laclede Group has investment grade credit ratings, which are subject to review and change by the rating agencies. Laclede Group has working capital lines of credit to meet the short-term liquidity needs of its subsidiaries. If the rating agencies lowered Laclede Group’s credit rating, particularly below investment grade, it might significantly limit its ability to secure new or additional credit facilities and would increase its costs of borrowing. Laclede Group’s ability to borrow under current or new credit facilities and costs of that borrowing have a direct impact on its subsidiaries’ ability to execute their operating strategies. In the fourth quarter of 2013, Standard & Poor’s and Fitch Ratings each lowered their ratings of Laclede Group by one notch to A- and BBB+, respectively. There are no implications of this downgrade on our corporate funding ability or our ability to access the capital markets, nor does this downgrade trigger any collateralization requirements under our corporate guarantees. There is no assurance that such credit ratings will be issued or remain in effect for any given period of time or that such ratings will not be lowered, suspended or withdrawn entirely by the rating agencies, if, in each rating agency’s judgment, circumstances so warrant. For additional credit rating information, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” under the caption “Liquidity and Capital Resources.”

Unexpected losses may adversely affect Laclede Group’s financial condition and results of operations.

As with most businesses, there are operations and business risks inherent in the activities of Laclede Group’s subsidiaries. If, in the normal course of business, Laclede Group 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, Laclede Group and its subsidiaries maintain insurance against a significant portion of, but not all, risks and losses. In addition, in the normal course of its operations, Laclede Group and its subsidiaries may be exposed to loss from other sources, such as bad debt expense or the failure of a counterparty to meet its financial obligations. Laclede Group and its operating companies employ 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.

9

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

Over the last several years, Laclede Group and its subsidiaries have implemented a variety of technological tools including both Company-owned information technology and technological services provided by outside parties. In fiscal year 2013, the Company completed its implementation of a Company-wide enterprise resource planning (ERP) system. These tools and systems support critical functions including the Company’s integrated planning, scheduling and dispatching of field resources, its automated meter reading system, customer care and billing, procurement and accounts payable, operational plant logistics, management reporting, and external financial reporting. The failure of these or other similarly 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 affect 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 has also completed the acquisition of the assets and liabilities of MGE in Kansas City. Through fiscal 2015, the Utility will be integrating MGE’s data into Laclede’s systems. During this time the Utility will also be evaluating the security controls both process and tool based in place at MGE.

Resources expended to pursue business acquisitions, investments or other business arrangements may adversely affect Laclede Group’s financial position and results of operations and return on investments made may not meet expectations.

From time to time, Laclede Group may seek to grow through strategic acquisitions, investments or other business arrangements, including the Missouri Gas Energy transaction completed in fiscal year 2013. Attractive acquisition candidates may be difficult to acquire on economically acceptable terms. It is possible for Laclede Group to expend considerable resources pursuing an acquisition candidate, but for a variety of reasons such as changes in economic conditions, changes in the acquisition candidate’s business or concerns arising out of due diligence review, decide not to consummate a definitive transaction. To the extent that acquisitions are made, such acquisitions involve a number of risks, including but not limited to, the assumption of material liabilities, the diversion of management’s attention from daily operations to the integration of the acquisition, difficulties in assimilation and retention of employees, securing adequate capital to support the transaction, and regulatory approval. Uncertainties exist in assessing the value, risks, profitability, and liabilities associated with certain businesses or assets and there is a possibility that anticipated operating and financial synergies expected to result from an acquisition do not develop. The failure to complete an acquisition successfully, or to integrate future acquisitions that it may choose to undertake could have an adverse effect on its financial condition, results of operations and the market’s perception of the Company’s execution of its strategy.

In order to manage and diversify the risks of certain development projects, Laclede Group may use partnerships or other investments. Such business arrangements may limit Laclede Group’s ability to fully direct the management and policies of the business relationship. These arrangements may cause additional risks such as operating agreements limiting Laclede Group's control or Laclede Group's ability to appropriately value the business drivers or assets of the business arrangement. While Laclede Group would pursue strategies to mitigate these risks and enforce its interests, these risks may adversely impact the projects and Laclede Group’s financial condition, results of operations and cash flows.

10

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

Laclede group 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 our 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 considered by U.S. Financial Accounting Standards Board continues to consider various changes to U.S. GAAP may be significant.

RISKS RELATED TO THE COMPANY'S ACQUISITION OF MISSOURI GAS ENERGY (MGE) ASSETS AND LIABILITIES AS WELL AS THE ACQUISITION AGREEMENTS WITH SOUTHERN UNION COMPANY AND ALGONQUIN POWER & UTILITIES CORP REGARDING NEW ENGLAND GAS ASSETS AND LIABILITIES.

The New England Gas (NEG) transaction may not be completed or may be approved subject to unfavorable regulatory conditions, which could adversely affect anticipated benefits and/or Laclede Group's business, financial condition, results of operations and/or stock price.

On December 14, 2012, Laclede Group, through a wholly owned subsidiary, Plaza Massachusetts Acquisition, Inc. (Plaza Massachusetts), entered into an acquisition agreement to acquire from Southern Union Company (SUG) substantially all of the assets and liabilities of New England Gas Company (NEG). On February 11, 2013, the Company entered into an agreement with Algonquin Power & Utilities Corp. (APUC) that will allow an APUC subsidiary, through its acquisition of the stock of Plaza Massachusetts, to acquire the Company's rights to purchase the assets of NEG, subject to certain approvals and conditions. In order to close the NEG transaction, approval by the Massachusetts Department of Public Utilities (MDPU) of the acquisition of the assets of NEG by the APUC subsidiary must be received.

The sale of NEG to APUC is still pending before the MDPU. The acquisition agreement contains certain termination rights for both the Company and SUG, including, among others, the right to terminate if the transaction is not completed by October 14, 2013 (subject to up to four 30-day extensions under certain circumstances related to obtaining required regulatory approvals). The Company and SUG have agreed to extend the NEG purchase agreement twice until December 14, 2013 to enable the MDPU to complete its review process. Nonetheless, there can be no assurance that APUC will be able to satisfy all of the required conditions on or before the end of the extension periods. The Company's agreement to acquire NEG remains in effect if APUC cannot satisfy the conditions for closing before the expiration of the extension periods.

The pending transaction with APUC and SUG for the NEG assets subjects Laclede Group to a number of additional risks, including the following:

• the Company’s estimate of the costs to complete the sale of NEG may vary significantly from actual results;

• both before and after the sale of NEG to APUC, the attention of management may be diverted to the closing of the sale of NEG rather than to current operations, the integration of MGE or the pursuit of other opportunities that could be beneficial to the Company;

• the potential loss of key employees of the Company or of NEG who may be uncertain about their future roles if and when the NEG sale is completed; and

• the trading price of Laclede Group’s common stock may decline to the extent that the current market price reflects a market assumption that the transaction will be completed.

The occurrence of any of these events individually or in combination could have a material adverse effect on the Company's business, financial condition or results of operations or the trading price of its common stock.

On August 13, 2013, the Utility issued debt in the aggregate principal amount of $450 million to provide permanent financing for the acquisition of MGE and, as a result, the Company is subject to risks related to a higher level of indebtedness.

In connection with the MGE acquisition, the Utility incurred additional debt to pay a portion of the acquisition cost and transaction expenses. The Utility's total indebtedness as of September 30, 2013 was $1,011 million (including $121 million of short-term borrowings and $890 million of long-term debt).

The Utility’s debt service obligations with respect to this increased indebtedness could have an adverse impact on its earnings and cash flows (which after the acquisition include the earnings and cash flows of MGE) for as long as the indebtedness is outstanding.

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Among other risks, the increase in indebtedness may:

• make it more difficult for Laclede Group to pay or refinance its debts as they become due during adverse economic and industry conditions;

• limit the Company’s flexibility to pursue other strategic opportunities or react to changes in its business and the industry in which it operates and, consequently, place it at a competitive disadvantage to competitors with less debt;

• require an increased portion of the Company’s cash flows from operations of Laclede Group and the Utility to be used for debt service payments, thereby reducing the availability of its cash flow to fund working capital, capital expenditures, dividend payments and other general corporate purposes;

• result in a downgrade in the credit rating of Laclede Group’s or the Utility's indebtedness, which could limit their ability to borrow additional funds or increase the interest rates applicable to their indebtedness;

• result in higher interest expense in the event of an increase in market interest rates for both long-term debt and short-term commercial paper or bank loans at variable rates;

• reduce the amount of credit available to support hedging activities; and

• require that additional terms, conditions or covenants be placed on the Company.

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

In addition, in order to maintain investment-grade credit ratings, Laclede Group may consider it appropriate to reduce the amount of indebtedness outstanding following the acquisitions. This may be accomplished in several ways, including issuing additional shares of common stock or securities convertible into shares of common stock, reducing discretionary uses of cash or a combination of these and other measures. Issuances of additional shares of common stock or securities convertible into shares of common stock would have the effect of diluting the ownership percentage that shareholders hold in the combined company, increase the Company’s dividend payment obligations and might reduce the reported earnings per share.

The acquisition of MGE and associated costs and integration efforts may adversely affect the Company's business, financial condition or results of operations, which may negatively affect the market price of Laclede Group's common shares.

While management currently anticipates that the acquisition of MGE will be accretive to the Utility's net economic earnings in fiscal year 2014, and thereafter, this expectation is based on preliminary estimates which may materially change. Laclede Group may encounter additional transaction and integration-related costs, may fail to realize all of the anticipated synergies and benefits of the acquisitions or be subject to other factors that affect those preliminary estimates.

The process of integrating the operations of MGE could cause an interruption of, or loss of momentum in, the activities of one or more of those businesses and the possible loss of key personnel. Integration could take longer than anticipated and could result in inconsistencies in standards, controls, procedures, practices, policies and compensation arrangements. The diversion of management's attention and any delays or difficulties encountered in connection with the transaction and the integration of the companies' operations could have an adverse effect on the business, results of operations, financial condition or prospects of Laclede Group after the acquisitions are ultimately consummated.

The Company expects to incur costs associated with integrating the operations of the utilities, and management’s estimate of the costs and the operating performance after the transaction closes may vary significantly from actual results. In accordance with the Unanimous Stipulation and Agreement, the Utility may amortize and recover certain transition costs in future rate case proceedings subject to review of other parties’ and the Missouri Public Service Commission’s (MoPSC or Commission) approval of the Company’s quantification of such cost. Potential differences regarding these quantifications may impact the Company’s financial results. Additional unanticipated costs may be incurred in the integration of the businesses.

Any of these factors could cause a decrease in the price of Laclede Group's common shares.

The acquisition of MGE may not achieve its intended results, including anticipated synergies and cost savings.

Although we expect that the acquisition of MGE will result in various benefits, including a significant amount of synergies, cost savings and other financial and operational benefits, there can be no assurance regarding when or the extent to which we will be able to realize these synergies, cost savings or other benefits. Achieving the anticipated benefits, including synergies and cost savings, is subject to a number of uncertainties, including whether the assets acquired can be operated in the manner we intend. Events outside of our control, including but not limited to regulatory changes or developments, could also adversely affect our ability to realize the anticipated benefits from the MGE acquisition.

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Thus the integration of MGE may be unpredictable, subject to delays or changed circumstances, and we can give no assurance that the acquired assets will perform in accordance with our expectations or that our expectations with respect to integration, synergies or cost savings as a result of the MGE acquisition will materialize. In addition, our anticipated costs to achieve the integration of MGE may differ significantly from our current estimates. The integration may place an additional burden on our management and internal resources, and the diversion of management’s attention during the integration process could have an adverse effect on our business, financial condition and expected operating results.

We are dependent on ETE and SUG for certain transitional services for MGE to be provided pursuant to a continuing services agreement. The failure of ETE or SUG to perform its obligations under this agreement could adversely affect our business, financial results and financial condition.

We are initially dependent upon ETE and SUG to continue to provide certain shared services and business support functions in areas such as technology and human resources for a period of time after the close of the acquisition to facilitate the integration of MGE. The terms of these arrangements are governed by a continuing services agreement. If ETE or SUG fails to perform its obligations under the continuing services agreement, we may not be able to perform such services or obtain such services from third parties on favorable terms or at all. In addition, upon termination of the continuing services agreement, if we are unable to perform such services or obtain such services from third parties, it could adversely affect our business, financial results and financial condition.

In connection with the MGE acquisition, the Utility recorded goodwill and long-lived assets that could become impaired and adversely affect its financial condition and results of operations.

Laclede Group will assess goodwill for impairment annually or more frequently if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying value. The Company assesses its long-lived assets for impairment whenever events or circumstances indicate that an asset’s carrying amount may not be recoverable. To the extent the value of goodwill or long-lived assets becomes impaired, the Company may be required to incur impairment charges that could have a material impact on its results of operations. No impairment of long-lived assets was recorded during 2013.

Since interest rates are a key component, among other assumptions, in the models used to estimate the fair values of our reporting units, as interest rates rise, the calculated fair values decrease and future impairments may occur. Due to the subjectivity of the assumptions and estimates underlying the impairment analysis, Laclede Group cannot provide assurance that future analyses will not result in impairment. These assumptions and estimates include projected cash flows, current and future rates for contracted capacity, growth rates, weighted average cost of capital and market multiples. For additional information, see Item 7, “Critical Accounting Policies.”

RISKS THAT RELATE TO THE GAS UTILITY DISTRIBUTION SEGMENT

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

The Missouri Public Service Commission (MoPSC or Commission) regulates many aspects of the Utility’s distribution operations, including construction and maintenance of facilities, operations, safety, the rates that the Utility 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 Utility operations, beginning on page 34. The Utility'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. Furthermore, in accordance with the Unanimous Stipulation and Agreement, the Utility will not file a general rate case, other than the currently pending MGE rate case, for non-gas costs prior to October 1, 2015 unless a significant, unusual event impacts any of its operations. The first general rate case filed after October 1, 2015, requires that it be for both Laclede Gas and MGE.

The Utility 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 Utility 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.

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

The Utility is involved in legal or administrative proceedings 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 Utility to make payments in excess of amounts provided for in our financial statements, or to the extent they are not covered by insurance, could adversely affect the Utility's results of operations, cash flows and financial condition.

The Utility'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 Utility 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 MoPSC. Accordingly, the Utility’s liquidity may be adversely impacted to the extent higher costs are not timely recovered from its customers. In accordance with the Unanimous Stipulation and Agreement, the Utility will not file a general rate case for non-gas costs prior to October 1, 2015 unless a significant, unusual event impacts any of its operations. The first general rate case filed after October 1, 2015, is required to be for both Laclede Gas and MGE.

The Utility'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 Utility 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 Utility'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 Utility’s financial results could be adversely impacted.

The Utility's liquidity and, in certain circumstances, its results of operations may be adversely affected by the cost of purchasing natural gas during periods in which natural gas prices are rising significantly.

Laclede Gas’ and MGE's tariff rate schedules contain Purchased Gas Adjustment (PGA) Clauses that permit it to file for rate adjustments to recover the cost of purchased gas. Changes in the cost of purchased gas are flowed through to customers and may affect uncollectible amounts and cash flows and can therefore impact the amount of capital resources. Currently, Laclede Gas and MGE are allowed to adjust the gas cost component of their rates up to four times each year. The Utility must make a mandatory gas cost adjustment at the beginning of the winter, in November, and during the next twelve months it may make up to three additional discretionary gas cost adjustments, so long as each of these adjustments is separated by at least two months.

The MoPSC typically approves the Utility’s PGA changes on an interim basis, subject to refund and the outcome of a subsequent audit and prudence review. Due to such review process, there is a risk of a disallowance of full recovery of these costs. Any material disallowance of purchased gas costs would adversely affect revenues. Increases in the prices the Utility charges for gas may also adversely affect revenues because they could lead customers to reduce usage and cause some customers to have trouble paying the resulting higher bills. These higher prices may increase bad debt expenses and ultimately reduce earnings. The Utility has used short-term borrowings in the past to finance storage inventories and purchased gas costs, and expects to do so in the future. Rapid increases in the price of purchased gas may result in an increase in short-term debt.

To lower financial exposure to commodity price fluctuations, the Utility enters into contracts to hedge the forward commodity price of its natural gas supplies. As part of this strategy, the Utility may use fixed-price, forward, physical purchase contracts, swaps, futures, and option contracts. However, the Utility does not hedge the entire exposure of energy assets or positions to market price volatility, and the coverage will vary over time. Any costs, gains, or losses experienced through hedging procedures, including carrying costs, generally flow through the PGA Clause, thereby limiting the Utility’s exposure to earnings volatility. However, variations in the timing of collections of such gas costs under the PGA Clause and the effect of cash payments for margin deposits associated with the Utility’s use of natural gas derivative instruments may cause short-term cash requirements to vary. These procedures remain subject to prudence review by the MoPSC.

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The Utility 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 Utility's revenues and cash flows or restrict its future growth. Economic conditions in its service territory may also adversely impact the Utility’s ability to collect its accounts receivable resulting in an increase in bad debt expenses.

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

In addition to longer-term debt that is issued by the Utility under its mortgage and deed of trust dated February 1, 1945, the Utility has relied, and continues to rely, upon shorter term borrowings or commercial paper supported by bank lines of credit to finance the execution of a portion of its operating strategies. The Utility is dependent on these capital sources to purchase its natural gas supply and maintain its properties. The availability and cost of these credit sources is cyclical and these capital sources may not remain available to the Utility, or it may not be able to obtain funds at a reasonable cost in the future. the Utility's ability to borrow under its existing lines of credit depends on its compliance with the Utility’s obligations under the lines of credit. If the Utility were to breach any of the financial or other covenants under these agreements, its debt repayment obligations under them could be accelerated. The Utility's ability to issue commercial paper supported by its lines of credit, to issue long-term bonds, or to obtain new lines of credit also depends on current conditions in the credit markets. The Utility’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 their funding commitments. Those banks may not be able to meet their 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 Utility’s access to capital and negatively impact its ability to run its business and make strategic investments.

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

Standard & Poor’s, Moody’s Investors Service, and Fitch Ratings from time to time implement new requirements for various ratings levels. To maintain its current credit ratings in light of any new requirements, the Utility may find it necessary to take steps to change its business plans in ways that may affect its results of operations. The Utility’s credit ratings remain at investment grade, but are subject to review and change by the rating agencies. If the rating agencies lowered the Utility’s ratings, particularly below investment grade, it could significantly limit its ability to secure new or additional credit facilities and would increase its costs of borrowing. In addition, the Utility would likely be required to pay a higher interest rate in future long-term financings and the Utility’s potential pool of investors and funding sources would likely decrease. The Utility's ability to borrow under current or new credit facilities and costs of that borrowing have a direct impact on its ability to execute operating strategies.

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

The Utility 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 Utility 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 Utility 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 Utility or its facilities, thereby impacting the Utility’s cost of compliance. The discovery of presently unknown environmental conditions, including former manufactured gas plant sites, and claims against the Utility 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 Utility’s customers, those costs may have an adverse effect on the Utility's financial condition and results of operations.

The Utility 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 Utility's present and future operations. These laws and regulations require the Utility 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.

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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 Utility's financial condition and results of operations.

Transporting, distributing, and storing natural gas and transporting and storing propane 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 Utility. 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. Similar risks also exist for the Utility's propane storage and transmission operations. These activities may subject the Utility to litigation or administrative proceedings from time to time. Such litigation or proceedings could result in substantial monetary judgments, fines, or penalties against the Utility or be resolved on unfavorable terms. In accordance with customary industry practices, the Utility 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 Utility’s financial condition and results of operations.

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

The Utility is the only distributor of natural gas within its franchised service area. Nevertheless, the changes in wholesale natural gas prices compared with prices for electricity, fuel oil, coal, propane, or other energy sources may affect the Utility’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 Utility’s sale of heating energy and adversely impact its financial position and results of operations.

The Utility's earnings are primarily generated by the sale of heating energy. The Utility has weather mitigation rate designs, approved by the MoPSC, which provide better assurance of the recovery of the Utility’s fixed costs and margins during winter months despite variations in sales volumes due to the impacts of weather and other factors that affect customer usage.

However, significantly warmer-than-normal weather conditions in the Utility’s service area 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 weather mitigation rate design at Laclede Gas or the straight fixed variable rate design at MGE are subject to regulatory discretion. In addition, the promulgation of regulations by the U.S. Environmental Protection Agency or the potential enactment of Congressional legislation addressing global warming and climate change may result in future additional compliance costs that could impact the Utility’s financial condition and results of operations.

Regional supply/demand fluctuations and changes in national pipeline infrastructure, as well as regulatory discretion, may adversely affect the Utility's ability to profit from off-system sales and capacity release.

The Utility's income from off-system sales and capacity release is subject to fluctuations in market conditions and changing supply and demand conditions in areas the Utility holds pipeline capacity rights. Specific factors impacting the Utility’s income from off-system sales and capacity release include the availability of attractively-priced natural gas supply, availability of pipeline capacity, and market demand. Income from off-system sales and capacity release is shared with customers. The Utility is allowed to retain 15% to 25% of the first $6 million in annual income earned (depending on the level of income earned) and 30% of income exceeding $6 million annually. In accordance with the MoPSC agreement to suspend the procedural schedule in Laclede Gas’ base rate proceeding, the Utility deferred, until fiscal year 2017, its ability to retain 15% of the first $2 million. MGE is allowed to retain 15% to 25% of the first $3.6 million in annual income earned (depending on the level of income earned) and 30% of income exceeding $3.6 million annually. The Utility’s ability to retain such income in the future is subject to regulatory discretion in a base rate proceeding.

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Workforce risks may affect the Utility's financial results.

The Utility 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.

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

Catastrophic events such as fires, earthquakes, explosions, floods, tornados, terrorist acts, or other similar occurrences could adversely affect the Utility's facilities and operations. The Utility 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 Utility’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.

RISKS THAT RELATE TO THE GAS MARKETING SEGMENT

Increased competition, fluctuations in natural gas commodity prices, expiration of existing supply and transportation arrangements, and pipeline infrastructure projects may adversely impact LER’s future profitability.

Competition in the marketplace and fluctuations in natural gas commodity prices have a direct impact on LER’s business. Changing market conditions and prices, the narrowing of regional and seasonal price differentials, and limited future price volatility may adversely impact LER’s sales margins or affect LER’s ability to procure gas supplies and/or to serve certain customers, which may reduce sales profitability and/or increase certain credit requirements caused by reductions in netting capability. Also, LER’s profitability may be impacted by the effects of the expiration, in the normal course of business, of certain of its natural gas supply contracts if those contracts cannot be replaced and/or renewed with arrangements with similar terms and pricing. Although the FERC regulates the interstate transportation of natural gas and establishes the general terms and conditions under which LER may use interstate gas pipeline capacity to purchase and transport natural gas, LER must occasionally renegotiate its transportation agreements with a concentrated group of pipeline companies. Renegotiated terms of new agreements, or increases in FERC-authorized rates of existing agreements, may impact LER’s future profitability. Profitability may also be adversely impacted if pipeline capacity or future storage capacity secured by LER is not fully utilized and/or its costs are not fully recovered.

Reduced access to credit and/or capital markets may prevent LER from executing operating strategies.

LER relies on its cash flows, netting capability, parental guarantees, and access to Laclede Group’s liquidity resources to satisfy its credit and working capital requirements. LER’s ability to rely on parental guarantees is dependent upon Laclede Group’s financial condition and credit ratings. If the rating agencies lowered Laclede Group’s credit ratings, particularly below investment grade, counterparty acceptance of parental guarantees may diminish, resulting in decreased availability of credit. Additionally, under such circumstances, certain counterparties may require LER to provide prepayments or cash deposits, amounts of which would be dependent upon natural gas market conditions. Reduced access to credit or increased credit requirements, which may also be caused by factors such as higher overall natural gas prices, may limit LER’s ability to enter into certain transactions. In addition, LER has concentrations of counterparty credit risk in that a significant portion of its transactions are with (or are associated with) energy producers, utility companies, and pipelines. These concentrations of counterparties have the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that each of these three groups may be affected similarly by changes in economic, industry, or other conditions. LER also has concentrations of credit risk in certain individually significant counterparties. LER closely monitors its credit exposure and, although uncollectible amounts have not been significant, increased counterparty defaults are possible and may result in financial losses and/or capital limitations.

Risk management policies, including the use of derivative instruments, may not fully protect LER’s sales and results of operations from volatility and may result in financial losses.

In the course of its business, LER enters into contracts to purchase and sell natural gas at fixed prices and index-based prices. Commodity price risk associated with these contracts has the potential to impact earnings and cash flows. To minimize this risk, LER has a risk management policy that provides for daily monitoring of a number of business measures, including fixed price commitments.

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LER currently manages the commodity price risk associated with fixed-price commitments for the purchase or sale of natural gas by either closely matching the offsetting physical purchase or sale of natural gas at fixed prices or through the use of natural gas futures, options, and swap contracts traded on or cleared through the NYMEX and ICE to lock in margins. These exchange-traded/cleared contracts may be designated as cash flow hedges of forecasted transactions. However, market conditions and regional price changes may cause ineffective portions of matched positions to result in financial losses. Additionally, to the extent that LER’s natural gas contracts are classified as trading activities or do not otherwise qualify for the normal purchases or normal sales designation (or the designation is not elected), the contracts are recorded as derivatives at fair value each period. Accordingly, the associated gains and losses are reported directly in earnings and may cause volatility in results of operations. Gains or losses (realized and unrealized) on certain wholesale purchase and sale contracts, consisting of those classified as trading activities, are required to be presented on a net basis (instead of a gross basis) in the statements of consolidated income. Such presentation could result in reductions to and/or volatility in the Company’s operating revenues.

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

LER’s ability to deliver natural gas to its customers is contingent upon the ability of natural gas producers, other gas marketers, and interstate pipelines to fulfill their delivery obligations to LER under firm contracts. If these counterparties fail to perform, they have a contractual obligation to reimburse LER for any adverse consequences. LER will attempt to use such reimbursements to obtain the necessary supplies so that LER may fulfill its customer obligations. To the extent that it is unable to obtain the necessary supplies, LER’s financial position and results of operations may be adversely impacted.

Regulatory and legislative developments pertaining to the energy industry may adversely impact LER’s results of operations, financial condition and cash flows.

LER’s business is non-regulated in that the rates it charges its customers are not established by or subject to approval by any regulatory body. However, LER is subject to various laws and regulations affecting the energy industry. New regulatory and legislative actions may adversely impact LER’s results of operations, financial condition, and cash flows by potentially reducing customer growth opportunities and/or increasing the costs of doing business.

LER could incur additional costs to comply with new laws and 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 LER fails to comply with applicable laws and regulations, whether existing or new ones, it could be subject to fines, penalties or other enforcement action by the authorities that regulate its operations.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

The principal properties of the Utility consist of more than 30,000 miles of gas main and related service pipes, meters, and regulators. Other physical properties include regional service centers and related buildings. Extensive underground natural gas and propane storage facilities and equipment are located in an area in North St. Louis County extending under the Missouri River into St. Charles County. Substantially all of the Utility's utility plant is subject to the liens of its mortgage.

All of the properties of the Utility are held in fee, or by easement, or under lease agreements. The principal lease agreements include underground storage rights that are of indefinite duration, the downtown St. Louis office building and MGE's Kansas City, Missouri office building. The current lease on the downtown St. Louis office building extends through February 2015 with the option to renew for a term of five additional years. The current lease on MGE's Kansas City office lease extends through November 30, 2015 with the option to renew for four additional terms of five years each.

For further information on the Utility’s leases see Note 16, Commitments and Contingencies, of the Notes to Consolidated Financial Statements.

Other properties of Laclede Group, including LER, do not constitute a significant portion of its properties.

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Item 3. Legal Proceedings

For a description of environmental matters, see Note 16, Commitments and Contingencies, of the Notes to Consolidated Financial Statements. For a description of pending regulatory matters of Laclede Group, see the Regulatory and Other Matters discussion in the Management’s Discussion and Analysis of Financial Condition and Results of Operations, on page 36.

Laclede Group and its subsidiaries are involved in litigation, claims, and investigations arising in the normal course of business. Management, after discussion with counsel, believes the final outcome will not have a material effect on the consolidated financial position or results of operations reflected in the consolidated financial statements presented herein.

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EXECUTIVE OFFICERS OF THE REGISTRANT – Listed below are executive officers as defined by the SEC for Laclede Group. Their ages, at September 30, 2013, and positions are listed below along with their business experience during the past five years.

Name, Age, and Position with Company *		Appointed (1)
S. Sitherwood, Age 53
	Laclede Group
	President and Chief Executive Officer	February 2012
	President (2)	September 2011
	Laclede Gas
	Chairman of the Board and Chief Executive Officer (2)	October 2012
	Chairman of the Board, Chief Executive Officer and President	February 2012
S. L. Lindsey, Age 47
	Laclede Group
	Executive Vice President, Chief Operating Officer, Distribution Operations	October 2012
	Laclede Gas
	President (3)	October 2012
S. P. Rasche, Age 53
	Laclede Group
	Senior Vice President, Chief Financial Officer	October 2013
	Senior Vice President, Finance and Accounting	May 2012
	Laclede Gas
	Chief Financial Officer	May 2012
	Vice President, Finance (4)	November 2009
M. C. Darrell, Age 55
	Laclede Group
	Senior Vice President, General Counsel and Chief Compliance Officer	May 2012
	General Counsel (5)	May 2004
M. C. Kullman, Age 53
	Laclede Group
	Senior Vice President, Chief Administrative Officer and Corporate Secretary	May 2012
	Chief Governance Officer and Corporate Secretary	February 2004
	Laclede Gas
	Senior Vice President, Assistant Corporate Secretary	October 2013
	Corporate Secretary	May 2012
	Chief Governance Officer and Corporate Secretary	February 2004

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M. R. Spotanski, Age 53
	Laclede Group
	Senior Vice President, Chief Integration and Innovation Officer (6)	May 2012

* The information provided relates to the Company and its principal subsidiaries. Many of the executive officers have served or currently serve as officers or directors for other subsidiaries of the Company.

(1) Officers of Laclede are normally reappointed at the Annual Meeting of the Board of Directors in January of each year.

(2) Ms. Sitherwood served as President of Atlanta Gas Light Company, Chattanooga Gas Company, and Florida City Gas, all of which are subsidiaries of AGL Resources, Inc., from November 2004 to September 2011. During that time, she also served as Senior Vice President of Southern Operations for AGL Resources, Inc. From September 2011 to February 2012, Ms. Sitherwood served as President of The Laclede Group, Inc. and became its President and Chief Executive Officer effective February 1, 2012.

(3) Mr. Lindsey served as Senior Vice President, Southern Operations of AGL Resources, Inc. and President of its Atlanta Gas Light, Chattanooga Gas and Florida City Gas subsidiaries since December 2011. He also served as Vice President and General Manager of Atlanta Gas Light and Chattanooga Gas from 2005 to 2011.

(4) Mr. Rasche served as the Chief Financial Officer for TLCVision Corporation from 2004 to May 2009.

(5) Mr. Darrell previously served as Senior Vice President and General Counsel of Laclede Gas Company since October 2007.

(6) Mr. Spotanski previously served as Senior Vice President – Operations and Marketing of Laclede Gas Company since October 2007.

Mr. M. D. Waltermire, former Executive Vice President, Chief Financial Officer, retired from the Company and its subsidiaries effective October 1, 2013.

21

Part II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities

Laclede Group’s common stock trades on The New York Stock Exchange under the symbol “LG.” The high and the low sales price for the common stock for each quarter in the two most recent fiscal years are:

	Fiscal 2013				Fiscal 2012
	High		Low		High		Low
1st Quarter	$	44.04	$	37.35	$	42.81	$	37.23
2nd Quarter	42.89		37.43		43.00		38.58
3rd Quarter	48.50		41.83		40.39		36.53
4th Quarter	47.84		42.84		43.47		39.63

The number of holders of record as of September 30, 2013 was 4,015.

Dividends declared on the common stock for the two most recent fiscal years were:

	Fiscal 2013		Fiscal 2012
1st Quarter	$	0.425	$	0.415
2nd Quarter	0.425		0.415
3rd Quarter	0.425		0.415
4th Quarter	0.425		0.415

For disclosures related to securities authorized for issuance under equity compensation plans, see Item 12, page 94.

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Item 6. Selected Financial Data

The Laclede Group, Inc.

	Fiscal Years Ended September 30
(Thousands, Except Per Share Amounts)	2013			2012			2011			2010		2009
Income statement data
Operating Revenues:
Gas Utility	$	847,224		$	763,447		$	913,190		$	864,297	$	1,053,993
Gas Marketing	165,146			358,145			669,375			858,782		836,865
Other	4,649			3,883			20,742			11,950		4,340
Total Operating Revenues	1,017,019			1,125,475			1,603,307			1,735,029		1,895,198
Operating Expenses:
Gas Utility
Natural and propane gas	433,442			397,304			549,947			519,905		699,984
Other operation and maintenance expenses	180,342			167,351			172,938			169,239		174,360
Depreciation and amortization	48,283			40,739			39,214			37,572		36,751
Taxes, other than income taxes	60,079			53,672			60,752			61,407		68,639
Total Gas Utility Operating Expenses	722,146			659,066			822,851			788,123		979,734
Gas Marketing	176,554			353,283			652,567			836,687		787,056
Other	21,825			2,524			9,642			5,353		3,344
Total Operating Expenses	920,525			1,014,873			1,485,060			1,630,163		1,770,134
Operating Income	96,494			110,602			118,247			104,866		125,064
Other Income and (Income Deductions) - Net	2,444			3,272			177			3,120		1,453
Interest Charges	28,602			24,945			25,417			26,852		29,746
Income Before Income Taxes and Dividends on Laclede Gas Redeemable Preferred Stock	70,336			88,929			93,007			81,134		96,771
Income Tax Expense	17,578			26,289			29,182			27,094		32,509
Dividends on Laclede Gas Redeemable Preferred Stock	—			—			—			—		15
Net Income	$	52,758		$	62,640		$	63,825		$	54,040	$	64,247
Common stock data
Weighted  Average No.  of Common Shares Outstanding:
Basic	25,875			22,262			22,099			21,986		21,893
Diluted	25,952			22,340			22,171			22,039		21,960
Basic Earnings Per Share of Common Stock	$	2.03		$	2.80		$	2.87		$	2.43	$	2.90
Diluted Earnings Per Share of Common Stock	$	2.02		$	2.79		$	2.86		$	2.43	$	2.89
Dividends Declared Per Share of Common Stock	$	1.70		$	1.66		$	1.62		$	1.58	$	1.54
Statements of financial position data
Net Utility Plant	1,776,630			1,019,299			928,683			884,084		855,929
Other Property and Investments	313,078			56,814			55,373			54,777		49,034
Total Assets	3,125,386			1,880,262			1,783,082			1,840,196		1,762,018
Current Liabilities	353,178			252,124			231,934			333,924		299,140
Deferred Credits and Other Liabilities	813,214			687,111			613,460			606,397		556,608
Long-Term Debt (less current portion)	912,712			339,416			364,357			364,298		389,240
Cash flow data
Net cash provided by operating activities	163,914			128,101			167,187			106,915		228,753
Net cash used in investing activities	(1,108,299		)	(105,404		)	(67,007		)	(60,773)		(52,254)
Net cash provided by (used in) financing activities	969,909			(38,517		)	(143,822		)	(33,814)		(116,807)
Consolidated Net Economic Earnings Data (a)
Net Income (GAAP)	$	52,758		$	62,640		$	63,825		$	54,040	$	64,247
Unrealized loss (gain) on energy-related derivatives	614			(314		)	(1,415		)	2,125		(3,441		)
Lower of cost or market inventory adjustments	868			—			—			—		—
Realized (gain) loss on economic hedges prior to the sale of the physical commodity	(25		)	163			—			—		—
Acquisition, divestiture and restructuring activities	10,797			123			—			—		—
Net Economic Earnings (Non-GAAP)	$	65,012		$	62,612		$	62,410		$	56,165	$	60,806
Diluted Earnings per Share of Common Stock:
Net Income (GAAP)	$	2.02		$	2.79		$	2.86		$	2.43	$	2.89
Unrealized loss (gain) on energy-related derivatives	0.02			(0.02		)	(0.07		)	0.09		(0.15		)
Lower of cost or market inventory adjustments	0.03			—			—			—		—
Realized loss on economic hedges prior to the sale of the physical commodity	—			0.01			—			—		—
Acquisition, divestiture and restructuring activities	0.42			0.01			—			—		—
Weighted Average Shares Adjustment	0.38			—			—			—		—
Net Economic Earnings (Non-GAAP)	$	2.87		$	2.79		$	2.79		$	2.52	$	2.74

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(a) This section contains the non-GAAP financial measures of net economic earnings and net economic earnings per share. Refer to the Earnings section of Management’s Discussion and Analysis of Financial Condition and Results of Operations on page 28 for a discussion regarding the use of non-GAAP measures.

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

THE LACLEDE GROUP, INC.

INTRODUCTION

This section analyzes the financial condition and results of operations of The Laclede Group, Inc. (Laclede Group or the Company) and its subsidiaries. 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.

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

RESULTS OF OPERATIONS

Overview

Laclede Group’s earnings are primarily derived from its Gas Utility segment, which reflects the regulated activities of Laclede Gas Company (the Utility), Missouri’s largest natural gas distribution company. The Utility is regulated by the Missouri Public Service Commission (MoPSC) and serves the City of St. Louis and eastern Missouri through Laclede Gas and Kansas City and western Missouri through Missouri Gas Energy (MGE). The Utility delivers natural gas to retail customers at rates and in accordance with tariffs authorized by the MoPSC. The Utility’s earnings are primarily generated by the sale of heating energy. The Utility’s weather mitigation rate design and MGE's straight fixed variable rate design lessen the impact of weather volatility on its customers during cold winters and stabilizes the Utility’s earnings by recovering fixed costs more evenly during the heating season. Due to the seasonal nature of the business of the Utility, Laclede Group’s earnings are typically concentrated in the November through April period, which generally corresponds with the heating season.

On December 14, 2012, Laclede Group, through two wholly owned subsidiaries, Plaza Missouri Acquisition, Inc. (Plaza Missouri) and Plaza Massachusetts Acquisition, Inc. (Plaza Massachusetts), entered into acquisition agreements to acquire from Southern Union Company (SUG) substantially all of the assets and liabilities of MGE and New England Gas Company (NEG). Subsequently, on January 11, 2013, the Company and Plaza Missouri, with consent of SUG, entered into an agreement with the Utility to assign the MGE agreement to the Utility. On February 11, 2013, the Company entered into an agreement with Algonquin Power & Utilities Corp. (APUC) that will allow an APUC subsidiary, through its acquisition of the stock of Plaza Massachusetts, to acquire the Company's rights to purchase the assets of NEG, subject to certain approvals and conditions. In order to close the NEG transaction, approval by the Massachusetts Department of Public Utilities (MDPU) of the acquisition of the assets of NEG by the APUC subsidiary must be received.

On July 2, 2013, the Utility and other parties to the case filed a Unanimous Stipulation and Agreement with the MoPSC that authorized the Utility to complete the acquisition of MGE, subject to certain conditions, including restrictions relative to the timing of filing for general rate increases and reporting requirements. This Unanimous Stipulation and Agreement was approved by the MoPSC on July 17, 2013. Effective September 1, 2013, the Utility closed on the purchase of MGE assets and liabilities.

The sale of NEG to APUC is still pending before the MDPU. The acquisition agreement contains certain termination rights for both the Company and SUG, including, among others, the right to terminate if the transaction is not completed by October 14, 2013 (subject to up to four 30-day extensions under certain circumstances related to obtaining required regulatory approvals). The Company and SUG agreed to extend the NEG purchase agreement until December 14, 2013 to enable the MDPU to complete its review process. Nonetheless, there can be no assurance that APUC will be able to satisfy all of the required conditions on or before the end of the extension periods. The Company's agreement to acquire NEG remains in effect if APUC cannot satisfy the conditions for closing before the expiration of the extension periods.

Laclede Energy Resources, Inc. (LER) is engaged in the marketing of natural gas and related activities on a non-regulated basis and is reported in the Gas Marketing segment. LER markets natural gas to both on-system utility transportation customers and customers outside of the Utility’s traditional service territory, including large retail and wholesale customers. LER’s operations and customer base are more subject to fluctuations in market conditions than the Utility. LER entered into a new 10 year contract for 1 Bcf of natural gas storage effective August 1, 2013 and has an additional 1 Bcf storage contracted through January 2014.

25

On July 3, 2013, the Company announced that Mark D. Waltermire, Laclede Group's Executive Vice President and Chief Financial Officer, would retire effective October 1, 2013, after the end of the current fiscal year. On July 9, 2013, the Company announced that the board of directors named Steven P. Rasche, Senior Vice President of Finance and Accounting, as Laclede Group's Senior Vice President and Chief Financial Officer effective October 1, 2013.

Based on the nature of the business of the Company and its subsidiaries, as well as current economic conditions, management focuses on the following key variables in evaluating the financial condition and results of operations and managing the business:

Gas Utility Segment:

• the Utility’s ability to recover the costs of purchasing and distributing natural gas from its customers;

• the impact of weather and other factors, such as customer conservation, on revenues and expenses;

• changes in the regulatory environment at the federal, state, and local levels, as well as decisions by regulators, that impact the Utility’s ability to earn its authorized rate of return in all service territories it serves;

• the Utility’s ability to access credit markets and maintain working capital sufficient to meet operating requirements;

• the effect of natural gas price volatility on the business; and,

• the ability to integrate the operations of all acquisitions.

Gas Marketing Segment:

• the risks of competition;

• fluctuations in natural gas prices;

• new national pipeline infrastructure projects;

• the ability to procure firm transportation and storage services at reasonable rates;

• credit and/or capital market access;

• counterparty risks; and,

• the effect of natural gas price volatility on the business.

Further information regarding how management seeks to manage these key variables is discussed below.

The Utility provides reliable natural gas service at a reasonable cost, while maintaining and building a secure and dependable infrastructure. The Utility’s strategy focuses on improving both performance and the ability to recover its authorized distribution costs and rate of return. The Utility’s distribution costs are the essential, primarily fixed, expenditures it must incur to operate and maintain more than 30,000 miles of mains and services comprising its natural gas distribution system and related storage facilities. The Utility’s distribution costs include wages and employee benefit costs, depreciation and maintenance expenses, and other regulated utility operating expenses, excluding natural and propane gas expense. Distribution costs are considered in the ratemaking process, and recovery of these types of costs is included in revenues generated through the Utility’s tariff rates, as approved by the MoPSC.

The Utility’s income from off-system sales and capacity release remains subject to fluctuations in market conditions. The Utility is allowed to retain the following annual income (shown by legacy company):

Laclede Gas
Pre-tax Income	Customer Share	Company Share
First $2 million	100%	—%
Next $2 million	80%	20%
Next $2 million	75%	25%
Amounts exceeding $6 million	70%	30%
MGE
Pre-tax Income	Customer Share	Company Share
First $1.2 million	85%	15%
Next $1.2 million	80%	20%
Next $1.2 million	75%	25%
Amounts exceeding $3.6 million	70%	30%

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Some of the factors impacting the level of off-system sales include the availability and cost of the Utility’s natural gas supply, the weather in its service area, and the weather in other markets. When the Utility’s service area experiences warmer-than-normal weather while other markets experience colder weather or supply constraints, some of the Utility’s natural gas supply is available for off-system sales. See the Regulatory and Other Matters section on page 36 of this report for additional information on Laclede Gas' off-system sales.

The Utility works actively to reduce the impact of wholesale natural gas price volatility on its costs by strategically structuring its natural gas supply portfolio to increase its gas supply availability and pricing alternatives and through the use of derivative instruments to protect its customers from significant changes in the commodity price of natural gas. Nevertheless, the overall cost of purchased gas remains subject to fluctuations in market conditions. The Utility’s Purchased Gas Adjustment (PGA) Clause allows the Utility to flow through to customers, subject to prudence review by the MoPSC, the cost of purchased gas supplies, including costs, cost reductions, and related carrying costs associated with the use of derivative instruments to hedge the purchase price of natural gas, as well as gas inventory carrying costs. The Utility believes it will continue to be able to obtain sufficient gas supply. The price of natural gas supplies and other economic conditions may affect sales volumes, due to the conservation efforts of customers, and cash flows associated with the timing of collection of gas costs and related accounts receivable from customers.

The Utility relies on both short-term credit and long-term capital markets, as well as cash flows from operations, to satisfy its seasonal cash requirements and fund its capital expenditures. The Utility's ability to issue commercial paper supported by lines of credit, to issue long-term bonds, or to obtain new lines of credit is dependent on current conditions in the credit and capital markets. Management focuses on maintaining a strong balance sheet and believes it currently has adequate access to credit and capital markets and will have sufficient capital resources to meet its foreseeable obligations. See the Liquidity and Capital Resources section on page 39 for additional information.

LER provides both on-system Utility transportation customers and customers outside of the Utility's traditional service area with another choice in non-regulated natural gas suppliers. LER utilizes its natural gas supply agreements, transportation agreements, park and loan agreements, storage agreements, and other executory contracts to support a variety of services to its customers at competitive prices. It closely monitors and manages the natural gas commodity price and volatility risks associated with providing such services to its customers through the use of a variety of risk management activities, including the use of exchange-traded/cleared derivative instruments and other contractual arrangements. LER is committed to managing commodity price risk, while it seeks to expand the services that it now provides. Nevertheless, income from LER’s operations is more subject to fluctuations in market conditions than the Utility’s operations. LER’s business is directly impacted by the effects of competition in the marketplace, the impacts of new pipeline infrastructure and surplus natural gas supplies on natural gas commodity prices. Management expects that LER's net economic earnings (a non-GAAP measure, as discussed below) will continue to be negatively impacted by the expiration of favorable long-term natural gas supply contracts with the last such contract expiring on September 30, 2013.

In addition to its operating cash flows, LER relies on Laclede Group’s parental guarantees to secure its purchase and sales obligations of natural gas. LER also has access to Laclede Group’s liquidity resources. A large portion of LER’s receivables are from customers in the energy industry. LER also enters into netting arrangements with many of its energy counterparties to reduce overall credit and collateral exposure. Although LER’s uncollectible amounts are closely monitored and have not been significant, increases in uncollectible amounts from customers are possible and could adversely affect LER’s liquidity and results.

LER carefully monitors the creditworthiness of counterparties to its transactions. LER performs in-house credit reviews of potential customers and may require credit assurances such as prepayments, letters of credit, or parental guarantees when appropriate. Credit limits for customers are established and monitored.

As a result of new pipeline infrastructure, and an abundance of natural gas supply, regional price differences have narrowed resulting in reduced price volatility. This reduction in regional price differentials presents an opportunity for LER in its transportation capacity to enter into subsequent offsetting purchase or sale transactions at the same location. These arrangements allow LER to satisfy its commitments without incurring fuel costs to transport natural gas to a different location. Thus, LER cannot be certain that all of its wholesale purchase and sale transactions will settle physically. As such, certain transactions entered into in fiscal year 2013 are designated as trading activities for financial reporting purposes, due to their settlement characteristics, rather than elected for normal purchases or normal sales designations under generally accepted accounting principles (GAAP). Results of operations from trading activities are reported on a net basis in Gas Marketing Operating Revenues, which may cause reductions in and/or volatility in the Company’s operating revenues, but has no effect on operating income or net income.

27

In the course of its business, LER enters into commitments associated with the purchase or sale of natural gas. In accordance with GAAP, some of LER’s purchase and sale transactions are not recognized in earnings until the natural gas is physically delivered, while other energy-related transactions, including those designated as trading activities, are required to be accounted for as derivatives, with the changes in their fair value (representing unrealized gains or losses) recorded in earnings in periods prior to settlement. Because related transactions of a purchase and sale strategy may be accounted for differently, there may be timing differences in the recognition of earnings under GAAP and economic earnings realized upon settlement. The Company reports both GAAP and net economic earnings (non-GAAP), as discussed below.

EARNINGS

The Laclede Group reports net income and earnings per share determined in accordance with GAAP. Management also uses the non-GAAP measures of net economic earnings and net economic earnings per share when internally evaluating results of operations. These non-GAAP measures exclude from net income the after-tax impacts of fair value accounting and timing adjustments associated with energy-related transactions as well as acquisition, divestiture, and restructuring activities. These adjustments include timing differences where the accounting treatment differs from the economic substance of the underlying transaction, including the following:

• Net unrealized gains and losses on energy-related derivatives that are required by GAAP fair value accounting associated with current changes in the fair value of financial and physical transactions prior to their completion and settlement. These unrealized gains and losses result primarily from two sources:

1) changes in the fair values of physical and/or financial derivatives prior to the period of settlement; and,

2) ineffective portions of accounting hedges, required to be recorded in earnings prior to settlement, due to differences in commodity price changes between the locations of the forecasted physical purchase or sale transactions and the locations of the underlying hedge instruments;

• Lower of cost or market adjustments to the carrying value of commodity inventories resulting when the market price of the commodity falls below its original cost, to the extent that those commodities are economically hedged; and,

• Realized gains and losses resulting from the settlement of economic hedges prior to the sale of the physical commodity.

• Acquisition, divestiture, and restructuring activities, when evaluating on-going performance

These adjustments eliminate the impact of timing differences and the impact of current changes in the fair value of financial and physical transactions prior to their completion and settlement. Unrealized gains or losses are recorded in each period until being replaced with the actual gains or losses realized when the associated physical transaction(s) occur. While management uses these non-GAAP measures to evaluate both the Utility and LER, the net effect of adjustments on the Utility’s earnings is minimal because gains or losses on its natural gas derivative instruments are deferred pursuant to its PGA Clause, as authorized by the MoPSC.

Management believes that excluding the earnings volatility caused by recognizing changes in fair value prior to settlement and other timing differences associated with related purchase and sale transactions provides a useful representation of the economic effects of only the actual settled transactions and their effects on results of operations. When calculating net economic earnings per share, management excludes from the weighted average number of shares the impact of the May 2013 equity issuance, completed relating to the MGE acquisition. Management believes that this presentation provides a useful representation of operating performance by facilitating comparisons of year-over-year results. These internal non-GAAP operating metrics should not be considered as an alternative to, or more meaningful than, GAAP measures such as net income. Reconciliations of net economic earnings and net economic earnings per share to the Company’s most directly comparable GAAP measures are provided below.

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Overview – Net Income (Loss)

	(Millions, except per share amounts)	Gas Utility			Gas Marketing			Other			Consolidated			Per Share Amounts**
Year Ended September 30, 2013
	Net Income (Loss) (GAAP)	$	56.3		$	7.6		$	(11.1	)	$	52.8		2.02
	Unrealized loss on energy-related derivatives*	0.1			0.4			—			0.5			0.02
	Lower of cost or market inventory adjustments*	—			0.9			—			0.9			0.03
	Acquisition, divestiture and restructuring activities*	0.3			—			10.5			10.8			0.42
	Weighted Average Shares Adjustment**													0.38
	Net Economic Earnings (Losses) (Non-GAAP)	$	56.7		$	8.9		$	(0.6	)	$	65.0		2.87
Year Ended September 30, 2012
	Net Income (GAAP)	$	48.2		$	12.3		$	2.1		$	62.6		2.79
	Unrealized gain on energy-related derivatives*	(0.1		)	(0.2		)	—			(0.3		)	(0.02	)
	Realized gain on economic hedges prior    to the sale of the physical commodity*	—			0.2			—			0.2			0.01
	Acquisition, divestiture and restructuring activities*	—			—			0.1			0.1			0.01
	Net Economic Earnings (Non-GAAP)	$	48.1		$	12.3		$	2.2		$	62.6		2.79
Year Ended September 30, 2011
	Net Income (GAAP)	46.9			10.4			6.5			63.8			2.86
	Unrealized gain on energy-related derivatives*	—			(1.4		)	—			(1.4		)	(0.07	)
	Net Economic Earnings (Non-GAAP)	46.9			9.0			6.5			62.4			2.79

* Amounts presented net of income taxes. Income taxes are calculated by applying federal, state, and local income tax rates applicable to ordinary income to the amounts of the pre-tax reconciling items. For the fiscal years ended 2013, 2012, and 2011 the net income tax effect included in the reconciling items above was $7.5 million, $0.0 million, and $0.9 million, respectively.

** Net economic earnings per share is calculated by replacing consolidated net income with consolidated net economic earnings (losses) in the GAAP diluted earnings per share calculation. Also, net economic earnings per share exclude the impact of the May 2013 equity offering to fund the pending acquisition of MGE. The weighted-average diluted shares used in the net economic earnings per share calculation for the fiscal year ended September 30, 2013 was 22.5 million compared to 26.0 million in the GAAP EPS calculation.

2013 vs. 2012

Consolidated

Laclede Group’s net income was $52.8 million in fiscal year 2013, including net income of $1.8 million related to MGE, compared with $62.6 million in fiscal year 2012. Basic and diluted earnings per share were $2.03 and $2.02 respectively for fiscal year 2013 compared with basic and diluted earnings per share of $2.80 and $2.79 respectively for fiscal year 2012. Net economic earnings were $65.0 million in fiscal year 2013, compared with $62.6 million in fiscal year 2012. Net economic earnings per share were $2.87 in fiscal year 2013, compared with $2.79 for fiscal year 2012. Earnings decreased in fiscal year 2013 compared to fiscal year 2012 primarily due to acquisition costs incurred during the period recorded in Other partially offset by higher income reported by Gas Utility. Additionally, earnings were impacted by decreased income from the Gas Marketing Segment. The increase is primarily attributed to acquisition related items that are excluded from net economic earnings.

29

Gas Utility

Gas Utility net income and net economic earnings increased by $8.1 million and $8.6 million, respectively, in 2013, compared with 2012. Of the $8.1 million increase in net income, $1.8 million is attributed to the acquisition of MGE. The remaining increase was primarily due to (on a pre-tax basis) higher operating margin (a non-GAAP measure, as discussed below) of $18.9 million. These benefits were partially offset by higher depreciation and amortization expenses totaling $5.0 million, higher operation and maintenance expenses totaling $4.0 million, and higher interest expense totaling $1.0 million.

Gas Marketing

Gas Marketing reported GAAP earnings totaling $7.6 million, a decrease of $4.7 million compared with the same period last year. Net economic earnings for fiscal year 2013 decreased $3.4 million from fiscal year 2012. The decreases in net income and net economic earnings was primarily attributable to decreases in operating margin, as discussed below. On a GAAP basis, LER's results were further impacted by the effect of higher net unrealized losses from certain of LER's energy-related derivative contracts and the impact of lower of cost or market inventory adjustments.

Other

Other net income and other net economic earnings decreased $13.2 million and $2.8 million, respectively, compared with the same period last year. The decrease in net income is primarily due to incremental expenses in fiscal year 2013 as compared to fiscal year 2012 attributable to the acquisition of MGE and pending acquisition of NEG from SUG totaling $10.5 million, net of tax, and other minor variations.

Operating Revenues and Operating Expenses

In addition to operating revenues and operating expenses, management also uses the non-GAAP measure of operating margin when evaluating result of operations, as shown in the table below. The Utility passes on (subject to prudence review by the MoPSC) increases and decreases in the wholesale cost of natural gas in accordance with its PGA Clause to their customers. The volatility of the wholesale natural gas market results in fluctuations from period to period in the recorded levels of, among other items, revenues and natural gas cost expense. Nevertheless, increases and decreases in the cost of gas associated with system gas sales volumes have no direct effect on operating income. Reconciliations of operating margin to the most directly comparable GAAP measure are shown below.

30

(Millions)		Gas Utility		Gas Marketing		Other			Eliminations			Consolidated
Year Ended September 30, 2013
	Operating Revenues	$	857.8	$	189.4	$	6.2		$	(36.4	)	$	1,017.0
	Natural and propane gas expense	469.1		171.6		1.3			(35.8		)	606.2
	Gross receipts tax expense	40.2		0.1		—			—			40.3
	Operating margin (non-GAAP)	348.5		17.7		4.9			(0.6		)	370.5
	Remaining operating expenses	248.9		4.9		20.8			(0.6		)	274.0
	Operating income (GAAP)	$	99.6	$	12.8	$	(15.9	)	$	—		$	96.5
Year Ended September 30, 2012
	Operating revenues	$	764.7	$	373.5	$	4.9		$	(17.6	)	$	1,125.5
	Natural and propane gas expense	414.8		348.4		—			(17.6		)	745.6
	Gross receipts tax expense	35.5		0.1		—			—			35.6
	Operating margin (non-GAAP)	314.4		25.0		4.9			—			344.3
	Remaining operating expenses	226.3		4.8		2.6			—			233.7
	Operating income (GAAP)	$	88.1	$	20.2	$	2.3		$	—		$	110.6
Year Ended September 30, 2011
	Operating revenues	$	913.2	$	669.4	$	20.7		$	—		$	1,603.3
	Natural and propane gas expense	549.9		647.5		—			—			1,197.4
	Gross receipts tax expense	42.9		0.1		—			—			43.0
	Operating margin (non-GAAP)	320.4		21.8		20.7			—			362.9
	Remaining operating expenses	230.1		5.0		9.6			—			244.7
	Operating income (GAAP)	$	90.3	$	16.8	$	11.1		$	—		$	118.2

Consolidated

Laclede Group reported operating revenues of $1,017.0 million for the fiscal year ended September 30, 2013 compared with $1,125.5 million for the same period last year. Laclede Group's operating margin increased $26.2 million for the twelve months ended September 30, 2013, compared to the same period last year primarily due, to higher Gas Utility operating margin, partially offset by lower operating margin reported by Gas Marketing as discussed below. Remaining operating expenses were $274.0 million for the twelve months end September 30, 2013, compared with $233.7 million last year. The increase was primarily due to additional expenses related to MGE, as well as, higher depreciation and amortization expenses totaling $5.0 million and higher operation and maintenance expenses totaling $4.0 million.

Gas Utility

Operating Revenues - Gas Utility Operating Revenues for fiscal year 2013 increased $93.1 million, compared to fiscal year 2012, was primarily attributable to the following factors:

(Millions)
Higher system sales volumes and other variations	$	101.3
Lower wholesale gas costs passed on to Utility customers	(30.6		)
Lower off-system sales volumes	(24.0		)
Higher prices charged for off-system sales	19.9
New customer revenue from MGE acquisition	22.0
Higher ISRS revenues	4.5
Total Variation	$	93.1

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Temperatures experienced in the Utility’s service area during 2013 were 35.8% colder than the same period last year, which were the warmest on record. Total system therms sold and transported to the Utility’s customers within its service territory were 875.4 million for fiscal year 2013 compared with 718.0 million for fiscal year 2012. Total off-system therms sold and transported outside of the Utility’s service area were 229.4 million for fiscal year 2013 compared with 314.5 million for fiscal year 2012.

Operating Margin - Gas Utility operating margin was $348.5 million for fiscal year 2013, a $34.1 million increase over the same period last year. Of the $34.1 million increase, $15.2 million is attributed to the acquisition of MGE. The remaining increase is primarily due to increased sales margins reflecting colder weather this year totaling $13.3 million, higher Infrastructure System Replacement Surcharge (ISRS) revenues totaling $4.5 million, and other minor variations of $1.1 million.

Operating Expenses - Remaining operating expenses in fiscal year 2013 increased $22.6 million from fiscal year 2012. Other operation and maintenance expenses increased $4.0 million primarily due to increased compensation and benefits, maintenance, IT and professional fees, partially offset by a lower provision for uncollectible accounts and a decrease in customer accounts expenses. Depreciation and amortization expense increased $5.0 million primarily due to additional depreciable property. Taxes, other than income and gross receipts tax, increased $1.0 million primarily due to higher payroll taxes related to aforementioned employee expenses. The remaining increase is attributed to the acquisition of MGE.

Gas Marketing

Operating Revenues - Gas Marketing operating revenues decreased $184.1 million primarily due to the effect of recording certain transactions on a net basis, instead of a gross basis, partially offset by higher per unit gas prices and increases in volumes purchased and sold.

Operating Margin - Gas Marketing operating margin was $17.7 million for fiscal year 2013, a $7.3 million decrease compared to the same period last year. The decrease in operating margin was primarily attributable to low price volatility and basis differentials in the current natural gas market, the expiration of a favorable supply contract, and lower of cost or market inventory adjustments. These factors were partially offset by the effect of higher volumes purchased and sold.

Other

Operating Revenue and Operating Expenses - Other operating revenue increased $1.3 million primarily due to the sale of propane inventory by Laclede Pipeline totaling $1.7 million in fiscal year 2013. Other operating expenses increased $19.5 million primarily due to the acquisition-related expenses discussed above and expenses associated with the propane sale.

Interest Charges

Interest charges during fiscal year 2013 increased $3.7 million from fiscal year 2012 primarily due to expenses associated with the Company's bridge loan facility and higher interest from the issuance of long-term debt, partially offset by a reduction in interest charges related to the recognition of previously unrecognized tax benefits. The higher interest on long-term debt reflects the net effect of the December 2012, March 2013, and August 2013 issuances of additional long-term debt of $25 million, $100 million, and $450 million, respectively, and the October 2012 maturity of $25 million of 6 1/2% first mortgage bonds. Average short-term interest rates were 0.3% for both fiscal years 2013 and 2012. Average short-term borrowings were $34.2 million and $43.8 million for fiscal years 2013 and 2012, respectively.

Income Taxes

Income tax expense decreased $8.7 million in fiscal year 2013 from fiscal year 2012 primarily due to lower pre-tax income, various property-related deductions and other minor variations.

2012 vs. 2011

Consolidated

Laclede Group’s net income was $62.6 million in fiscal year 2012 compared with $63.8 million in fiscal year 2011. Basic and diluted earnings per share were $2.80 and $2.79, respectively for fiscal year 2012 compared with basic and diluted earnings per share of $2.87 and $2.86, respectively, for fiscal year 2011. Net economic earnings were $62.6 million for fiscal year 2012, compared with 62.4 million for fiscal year 2011. Net economic earnings per share were $2.79 for both fiscal years 2012 and 2011.

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Earnings decreased in fiscal year 2012 compared with fiscal year 2011 primarily due to the $6.1 million effect of an April 2011 non-regulated sale of propane inventory recorded in Other Operating income, partially offset by higher income reported by Laclede Group’s Gas Utility and Gas Marketing segments.

Gas Utility

Gas Utility net income and net economic earnings increased by $1.3 million and $1.2 million, respectively, in 2012, compared with 2011. The increase was primarily due to (on a pre-tax basis) lower operating margin (a non-GAAP measure, as discussed above) of $6.0 million and a decrease in operation and maintenance expenses, excluding pension and group insurance expenses, totaling $11.1 million These benefits were partially offset by higher pension and group insurance expenses totaling $5.5 million.

Gas Marketing

The Gas Marketing segment reported GAAP earnings totaling $12.3 million for fiscal 2012, an increase of $1.9 million compared with fiscal year 2011. Net economic earnings for fiscal year 2012 increased $3.3 million compared with fiscal year 2011. The increases in net income and net economic earnings was primarily attributable to LER's reduced transportation costs resulting from the renegotiation of contracts that were renewed during the latter halves of fiscal years 2011 and 2012. Increased transaction volume and LER's ability to procure gas supply at more favorable terms were largely offset by the effects of narrower regional price differences and reduced price volatility.

Other

Other net income and other net economic earnings decreased $4.4 million and $4.3 million, respectively, compared with the same period last year. The decrease was primarily due to the effect of Laclede Gas' April 2011 sale of 320,000 barrels of propane from inventory that were no longer required to serve utility customers. This transaction resulted in income, net of income taxes, totaling $6.1 million.

Operating Revenues and Operating Expenses

Gas Utility

Operating Revenues - Utility Operating Revenues for fiscal year 2012 decreased $148.5 million, compared to fiscal year 2011, primarily attributable to the following factors:

(Millions)
Lower system sales volumes and other variations	$	(114.5	)
Lower prices charged for off-system sales	(44.6		)
Higher off-system sales volumes	38.8
Lower wholesale gas costs passed on to Utility customers	(32.8		)
Higher ISRS revenues	4.6
Total Variation	$	(148.5	)

Temperatures experienced in the Utility’s service area during 2012, which were the warmest on record, were 27.9% warmer than in 2011. Total system therms sold and transported to the Utility’s customers within its service territory were 718.0 million for fiscal year 2012 compared with 885.4 million for fiscal year 2011. Total off-system therms sold and transported outside of the Utility’s service area were 308.0 million for fiscal year 2012 compared with 223.0 million for fiscal year 2011.

Operating Margin - Gas Utility operating margin was $314.4 million for fiscal year 2012, a $6.0 million decrease over the same period last year. The decrease is primarily due to decreased sales margins reflecting warmer weather totaling $7.8 million in 2012 compared to fiscal year 2011 as 2012 was the warmest on record, partially offset by increased ISRS revenues of $4.6 million.

Operating Expenses - Remainingoperating expenses in fiscal year 2012 decreased $3.8 million, from fiscal year 2011. Other operation and maintenance expenses decreased $5.6 million, primarily due to a higher rate of overheads capitalized, decreased maintenance charges, a lower provision for uncollectible accounts, and a decrease in customer accounts expenses.

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These factors were partially offset by higher pension and group insurance expenses. Depreciation and amortization expense increased $1.5 million, primarily due to additional depreciable property. Taxes, other than income taxes and gross receipts tax, increased $0.3 million, primarily due to higher payroll taxes.

Gas Marketing

Operating Revenues - Gas Marketing operating revenues and decreased $311.2 million primarily due to the effect of recording certain transactions on a net basis, instead of gross, and due to lower per unit gas prices.

Operating Margin - Gas Marketing operating margin was $25.0 million for fiscal year 2012, a $3.2 million increase compared to the same period last year. The increase was primarily attributable to LER's reduced transportation costs resulting from the renegotiation of contracts that were renewed during the latter halves of fiscal years 2011 and 2012. Increased transaction volume and LER's ability to procure gas supply at more favorable terms were largely offset by the effects of narrower regional price differences and reduced price volatility.

Other

Other Operating Revenues and Operating Expenses - Other operating revenues and other operating expenses decreased $16.9 million and $7.1 million, respectively, in fiscal year 2012 compared to fiscal year 2011. These year-to-year variations were primarily attributable to non-regulated sales of propane inventory in fiscal year 2011. These transactions resulted in pre-tax income of $10.0 million in fiscal year 2011. This type of transaction did not recur in fiscal year 2012.

Other Income and (Income Deductions)-Net

Other Income and (Income Deductions)–Net increased $3.1 million in fiscal year 2012 (compared to fiscal year 2011) primarily due to higher net investment gains, partially offset by increased charitable contributions.

Interest Charges

Interest charges decreased $0.5 million in fiscal year 2012 (from fiscal year 2011). The decrease was primarily due to lower interest on long-term debt, attributable to the November 2010 maturity of $25 million principal amount of 6 1/2% first mortgage bonds. Average short-term interest rates were 0.3% for fiscal years 2012 and 2011. Average short-term borrowings were $43.8 million and $54.7 million for fiscal years 2012 and 2011, respectively.

Income Taxes

Income tax expense decreased $2.9 million in fiscal year 2012 compared to fiscal year 2011. The decrease is primarily due to lower pre-tax income, as well as, net changes in unrecognized tax benefits recorded in earnings and various property-related deductions.

CRITICAL ACCOUNTING POLICIES

Our discussion and analysis of our financial condition, results of operations, liquidity, and capital resources is based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP), which requires that we make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We evaluate our estimates on an ongoing basis. We base our estimates on historical experience and on various other assumptions that we believe 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. We believe the following represent the more significant items requiring the use of judgment and estimates in preparing our consolidated financial statements:

Accounts Receivable and Allowance for Doubtful Accounts – Trade accounts receivable are recorded at the amounts due from customers, including unbilled amounts. Estimates of the collectibility 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. The Utility’s provision for uncollectible accounts includes the amortization of previously deferred uncollectible expenses, as approved by the MoPSC.

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Goodwill - For the MGE acquisition, goodwill was calculated as of the date of the acquisition, September 1, 2013, measured as the excess of the consideration transferred over the net amount of assets acquired less liabilities assumed. Goodwill will be tested for impairment beginning in fiscal year 2014 on an annual basis, or more frequently if circumstances surrounding the goodwill valuation change. The goodwill impairment test compares the fair value of a reporting unit, or operating segment, to its carrying amount, including goodwill.

Employee Benefits and Postretirement Obligations – Pension and postretirement obligations are calculated by actuarial consultants that utilize several statistical factors and other assumptions provided by management related to future events, such as discount rates, returns on plan assets, compensation increases, and mortality rates. For the Utility, 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 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 table below reflects the sensitivity of Laclede’s plans to potential changes in key assumptions:

Pension Plan Benefits:
Actuarial Assumptions	Increase/(Decrease)		Estimated Increase/(Decrease) to Projected Benefit Obligation (Thousands)			Estimated Increase/ (Decrease) to Annual Net Pension Cost* (Thousands)
Discount Rate	0.25	%	$	(13,210	)	$	400
	(0.25	)	13,510			(440		)
Rate of Future Compensation Increase	0.25	%	5,840			350
	(0.25	)	(5,720		)	(350		)
Expected Return on Plan Assets	0.25	%	—			(930		)
	(0.25	)	—			930
Postretirement Benefits:
Actuarial Assumptions	Increase/(Decrease)		Estimated Increase/(Decrease) to Projected Postretirement Benefit Obligation (Thousands)			Estimated Increase/(Decrease) to Annual Net Postretirement Benefit Cost* (Thousands)
Discount Rate	0.25	%	$	(4,000	)	$	(181	)
	(0.25	)	4,080			180
Expected Return on Plan Assets	0.25	%	—			(240		)
	(0.25	)	—			240
Annual Medical Cost Trend	1.00	%	7,060			1,520
	(1.00	)	(6,580		)	(1,390		)

* Excludes the impact of regulatory deferral mechanism. See Note 3, Pension Plans and Other Postretirement Benefits, of the Notes to Consolidated Financial Statements for information regarding the regulatory treatment of these costs.

Gas UtilityOperations – The Utility 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. Management believes the following represent the more significant items recorded through the application of this accounting guidance:

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PGA Clause

The Utility’s PGA Clause allows Laclede Gas and MGE to flow through to customers, subject to prudence review by the MoPSC, the cost of purchased gas supplies, including the costs, cost reductions, and related carrying costs associated with the Utility’s use of natural gas derivative instruments to hedge the purchase price of natural gas. The difference between actual costs incurred and costs recovered through the application of the PGA clauses are recorded as regulatory assets and regulatory liabilities that are recovered or refunded in a subsequent period. The PGA Clauses also permit the application of carrying costs to all over- or under-recoveries of gas costs, including costs and cost reductions associated with the use of derivative instruments, and also provide for a portion of income from off-system sales and capacity release revenues to be flowed through to customers. Laclede Gas' PGA Clause also authorizes the Utility to recover costs it incurs to finance its investment in gas supplies that are purchased during the storage injection season for sale during the heating season.

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 MoPSC, the Utility 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.

Defined Pension Benefit and Other Postretirement Benefits

The amount of net periodic pension and other postretirement benefit cost recognized in the financial statements related to the Utility’s qualified pension plans and other postretirement benefit plans is based upon allowances, as approved by the MoPSC, which 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 Utility’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. Accordingly, these differences are deferred as regulatory liabilities.

Gas Marketing Energy Contracts – LER routinely enters into contracts associated with the physical purchase or sale of natural gas in a future period. In determining the appropriate accounting treatment for these contracts, management is required to assess the contract terms and various other factors to determine if the contracts are subject to the derivative accounting guidance in ASC Topic 815, “Derivatives and Hedging.” If a contract is deemed to meet the definition of derivative, management’s judgment may be further required in determining if the contract is eligible for the normal purchases or normal sales election. Pursuant to GAAP, contracts not designated as normal purchases or normal sales are required to be accounted for as derivatives with changes in fair value recognized in earnings in the periods prior to physical delivery. In the absence of quoted prices in active markets for identical assets or liabilities, determining the fair value of a derivative contract requires judgment as to the appropriateness of various market inputs and involves making assumptions regarding how market participants would price the asset or liability. In addition to these physical contracts, LER also utilizes natural gas futures, swap, and option contracts traded on or cleared through the New York Mercantile Exchange (NYMEX) and Ice Clear Europe (ICE) to manage the price risk associated with certain of its fixed-price commitments. These contracts may be designated for hedge accounting treatment, as discussed in Note 11, Derivative Instruments and Hedging Activities, of the Notes to Consolidated Financial Statements.

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

REGULATORY AND OTHER MATTERS

The MoPSC Staff previously proposed disallowances related to Laclede Gas' recovery of its purchased gas costs totaling $6.0 million pertaining to Laclede Gas' purchase of gas from a marketing affiliate, LER, applicable to fiscal years 2005 through 2007. The MoPSC Staff also proposed a number of non-monetary recommendations, based on its review of gas costs for fiscal years 2008 through 2011. In a related matter, on October 6, 2010, the MoPSC Staff filed a complaint against Laclede Gas alleging that Laclede Gas' affiliate transactions and its Cost Allocation Manual (CAM) violated the MoPSC's affiliate transaction rules.

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Laclede Gas responded with a counterclaim that the MoPSC Staff had failed to adhere to the affiliate transaction rules and the Company's CAM. On July 16, 2013, Laclede Gas, the MoPSC Staff and the Office of the Public Counsel requested MoPSC approval of a unanimous stipulation and agreement resolving the affiliate transaction matters for fiscal years 2005 through 2011, resolving the October 6, 2010 complaint, resolving Laclede Gas' counterclaim, presenting a revised CAM for MoPSC approval, and establishing standards of conduct for gas purchases and sales. While the PSC Staff's disallowances were withdrawn as part of the stipulation, Laclede Gas agreed to a minor adjustment to the off-system sales and capacity release sharing mechanism. For a three-year period ending September 3, 2016, Laclede Gas' share of the first $2 million in net margin is reduced from 15% to 0%. None of the other sharing percentages are affected, and beginning October 1, 2016, Laclede's sharing percentage of the first $2 million in net margins returns to 15%. The stipulation and agreement was approved by the MoPSC in an order issued on August 14, 2013.

On July 7, 2010, the MoPSC Staff filed a complaint against Laclede Gas alleging that, by stating that it was not in possession of proprietary LER documents, Laclede Gas violated the MoPSC Order authorizing the holding company structure (2001 Order). Laclede Gas counterclaimed stating the Staff failed to adhere to pricing provisions of the MoPSC's affiliate transaction rules and Laclede Gas' Cost Allocation Manual. By orders dated November 3, 2010 and February 4, 2011, respectively, the MoPSC dismissed Laclede's counterclaim and granted summary judgment to Staff, finding that Laclede Gas violated the terms of the 2001 Order and authorizing its General Counsel to seek penalties in court against Laclede Gas. On May 19, 2011, the MoPSC's General Counsel filed a petition seeking penalties against Laclede Gas for violation of the 2001 Order. The MoPSC and Laclede Gas agreed to hold the penalty case in abeyance pending the outcome of Laclede's appeal of the November 3, 2010 and February 4, 2011 orders. These Orders were reversed by the Cole County Circuit Court, but later upheld by the Western District Court of Appeals. On March 19, 2013, the Missouri Supreme Court declined Laclede Gas' request to review the opinion of the Western District Court of Appeals. As a result, Laclede Gas produced certain LER documentation that had been requested by the MoPSC Staff and, pursuant to agreement between the MoPSC and Laclede Gas, the MoPSC's May 2011 penalty case was dismissed.

On December 21, 2012, Laclede Gas filed tariff sheets in a new general rate case proceeding that were designed to increase total revenues by $58.4 million, less the current annualized ISRS revenues that were already being recovered from customers. On June 26, 2013, the MoPSC approved a Unanimous Stipulation and Agreement in which the Utility will incorporate its then current annualized ISRS revenues of $14.8 million into its base rates, effective September 1, 2013. At that time, the ISRS charge was reset to zero, and the Utility will be permitted to make future ISRS filings for any qualifying expenditures incurred after January 31, 2013.

On January 14, 2013, the Company filed an application with the MoPSC for approval to acquire the assets of MGE from Southern Union Company (SUG). On July 2, 2013, the Utility and other parties to the proceeding filed a Unanimous Stipulation and Agreement (Agreement) with the MoPSC resolving all matters in the case, which was approved by the Commission on July 17, 2013. The Agreement authorizes Laclede Gas to acquire MGE and obtain the necessary financing, subject to various conditions set forth in the Agreement. Under the Agreement, the Utility would generally be precluded from filing a general rate case for either Laclede Gas or MGE prior to October 1, 2015, except that a general rate case for the MGE service territory could be filed no later than September 18, 2013. ISRS filings and the collection of gas costs under Laclede Gas' PGA Clause would not be impacted. The Agreement also allows for the deferral for future recovery of a portion of one-time costs incurred associated with the integration of MGE. The Agreement sets forth a number of other conditions including those related to credit ratings, gas supply, service quality, gas safety, and reporting requirements.

A petition was filed with the Massachusetts Department of Public Utilities (MDPU) on January 24, 2013 for approval of the Company's acquisition of NEG. An amended petition was filed with DPU on February 19, 2013 requesting that the DPU authorize the sale of NEG to Liberty Utilities, a subsidiary of Algonquin Power Utilities Corporation. Evidentiary hearings were held in June and August 2013. The matter is now awaiting a decision by the DPU.

On June 29, 2010, the Office of Federal Contract Compliance Programs issued a Notice of Violations to Laclede Gas alleging lapses in certain employment selection procedures during a two-year period ending in February 2006. On July 2, 2013, Laclede Gas executed a Conciliation Agreement with the OFCCP in which the Company did not admit to liability, but agreed to provide make whole relief of back pay and interest to the impacted individuals from 2004-2006. The Company's agreement to provide make whole relief will not have a material effect on the consolidated financial position and results of operations, or cash flows of the Company.

On September 16, 2013, MGE filed tariff sheets in a new general rate case proceeding that were designed to increase the Utility's total revenues by $23.4 million, less the current annualized ISRS revenues of $6.3 million that were already being recovered from customers. Consistent with its normal practice, the MoPSC suspended implementation of the MGE proposed rates on September 17, 2013 and set the case for hearing in April 2014.

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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 Consolidated Financial Statements.

The Company continues to monitor the developments of the Financial Accounting Standards Board (FASB) relative to possible changes in accounting standards. Currently, the FASB is considering various changes to U. S. GAAP, some of which may be significant, as part of a joint effort with the International Accounting Standards Board to converge accounting standards. Future developments, depending on the outcome, have the potential to impact the Company’s financial condition and results of operations.

INFLATION

The accompanying consolidated 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 Utility is subject, allows recovery through its rates of only the historical cost of utility plant as depreciation. The Utility expects to incur significant capital expenditures during the next few years, primarily related to a significant software replacement project to enhance technology, customer service, and business processes and the planned increased replacements of distribution plant. The Company believes that any higher costs experienced upon replacement of existing facilities will be recovered through the normal regulatory process.

FINANCIAL CONDITION

CASH FLOWS

The Company’s short-term borrowing requirements typically peak during colder months when the Utility borrows money to cover the lag between when it purchases its natural gas and when its customers pay for that gas. Changes in the wholesale cost of natural gas, including cash payments for margin deposits associated with the Utility’s use of natural gas derivative instruments, variations in the timing of collections of gas cost under the Utility’s PGA Clause, the seasonality of accounts receivable balances, and the utilization of storage gas inventories cause short-term cash requirements to vary during the year and from year to year, and may cause significant variations in the Company’s cash provided by or used in operating activities.

Net cash provided by operating activities for fiscal years 2013, 2012 and 2011 was $163.9 million, $128.1 million and $167.2 million, respectively. The increase in net cash provided by operating activities in fiscal year 2013 as compared to fiscal year 2012 is primarily attributable to variations associated with the timing of collections of gas cost under the Utility’s PGA Clause, including the net effect of increased cash payments for margin deposits associated with the Utility’s use of natural gas derivative instruments. The variation also reflects decreased cash payments for the funding of pension plans and for the payment of income taxes. These benefits were partially offset by changes in delayed and advanced customer billings. The decrease in net cash provided by operating activities in fiscal year 2012 as compared to fiscal year 2011 is primarily attributable to variations associated with the timing of collections of gas cost under the Utility’s PGA Clause, including the net effect of increased cash payments for margin deposits associated with the Utility’s use of natural gas derivative instruments and changes in the cost of natural gas storage inventories. The decrease is also attributable to the effect of a non-regulated sale of propane inventory in fiscal year 2011 and increased cash payments for the funding of pension plans in 2012.

Net cash used in investing activities for fiscal years 2013, 2012 and 2011 was $1,108.3 million, $105.4 million and $67.0 million, respectively. Net cashed used in 2013 includes $975.0 million for the acquisition of MGE. The remaining net cash used in investing activities primarily reflected capital expenditures in all periods. The variations primarily reflect additional capital expenditures for distribution plant and information technology investments.

Net cash provided in financing activities for fiscal years 2013 was $969.9 million and the net cash used in financing activities for 2012 and 2011 was $38.5 million, and $143.8 million, respectively. The increase in net cash provided in financing activities in fiscal year 2013 from fiscal year 2012 primarily reflects the May 2013 common stock issuance of 10.0 million shares and issuance of long-term debt of $450.0 million for the acquisition of MGE. The decrease in net cash used in fiscal 2012 from fiscal year 2011 primarily reflects decreased repayments of short-term debt and the effect of the maturity of long-term debt in 2011.

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LIQUIDITY AND CAPITAL RESOURCES

Cash and Cash Equivalents

Laclede Group had no temporary cash investments as of September 30, 2013. During fiscal year 2013, short-term investments were diversified among highly-rated money market funds, interest-bearing deposits, and commercial paper issues. The money market funds were accessible by the Company on demand. The bank deposits were also generally available on demand, though the banks reserve the right to require seven days’ notice for a withdrawal. These funds were used to support the working capital needs of the Company’s subsidiaries and as a store of liquidity in advance of the MGE acquisition. The balance of short-term investments ranged between $0 and $969.4 million during fiscal year 2013 and ranged between $5.3 million and $23.3 million during fiscal year 2012. Due to lower yields available to Laclede Group on its short-term investments, Laclede Group elected to provide a portion of the Utility’s short-term funding through intercompany lending during fiscal years 2013 and 2012.

Short-term Debt

The Company’s short-term borrowing requirements typically peak during the colder months. These short-term cash requirements can be met through the sale of commercial paper supported by lines of credit with banks or through direct use of the lines of credit. At September 30, 2012, Laclede Gas had a syndicated line of credit in place of $300 million from seven banks. On September 3, 2013, the Utility entered into a new syndicated line of credit for $450 million with nine banks, which will expire in September 2018. The previous syndicated line of credit was terminated at that time. The largest portion provided by a single bank under the current line is 15.6%. The Utility’s line of credit includes a covenant limiting total debt, including short-term debt, to no more than 70% of total capitalization. As defined in the line of credit, total debt was 48% of total capitalization on September 30, 2013.

Short-term cash requirements outside of the Utility have generally been met with internally-generated funds. On September 30, 2012, Laclede Group had a syndicated line of credit for $50 million from seven banks. On September 3, 2013, Laclede Group entered into a new $150 million syndicated line of credit, which expires in September 2018. The line of credit has a covenant limiting the total debt of the consolidated Laclede Group to no more than 70% of the Company’s total capitalization. As defined in the line of credit, this ratio stood at 49% on September 30, 2013. Laclede Group’s line may be used to provide for the funding needs of various subsidiaries. There were no borrowings under Laclede Group’s line during fiscal years 2013 and 2012.

Information about Laclede Group’s consolidated short-term borrowings during the 12 months ended September 30, 2013 and 2012 and as of September 30, 2013 and 2012, is presented below:

	Commercial Paper Borrowings
Twelve Months Ended September 30, 2013
Weighted average borrowings outstanding	$34.2 million
Weighted average interest rate	0.3%
Range of borrowings outstanding	$0 – $99.4 million
As of September 30, 2013
Borrowings outstanding at end of period	$74.0 million
Weighted average interest rate	0.3%
Twelve Months Ended September 30, 2012
Weighted average borrowings outstanding	$43.8 million
Weighted average interest rate	0.3%
Range of borrowings outstanding	$0 – $133.5 million
As of September 30, 2012
Borrowings outstanding at end of period	$40.1 million
Weighted average interest rate	0.2%

Based on average short-term borrowings for the 12 months ended September 30, 2013, an increase in the average interest rate of 100 basis points would decrease Laclede Group’s pre-tax earnings and cash flows by approximately $0.3 million on an annual basis, portions of which may be offset through the application of PGA carrying costs.

39

Long-term Debt and Equity

Laclede Group issued $25 million of 3.31% 10-year unsecured notes in a private placement on December 14, 2012, which had been committed to in August 2012. The proceeds of all the issue were used for general corporate purposes.

On March 15, 2013, the Utility issued $100 million of first mortgage bonds in a private placement that also had been committed to in August 2012. Of this, $55 million were issued at 3.00% for a 10-year term, maturing in March 2023, and $45 million were issued at 3.40% for a 15-year term, maturing in March 2028. The proceeds of both the issues were used for the repayment of short-term debt and general corporate purposes.

On May 29, 2013 the Laclede Group received approximately $428 million from the issuance of 10.0 million common shares to fund a portion of the purchase of MGE. These funds were invested in high quality, short-term instruments until the MGE acquisition was completed on September 3, 2013.

On August 13, 2013 Laclede Gas Company issued $450 million of first mortgage bonds. Of this, $100 million was issued at 2.00% maturing in August 2018, $250 million was issued at 3.40% maturing in August 2023, and $100 million was issued at 4.625% maturing in August 2043. The proceeds were used to fund a portion of the MGE acquisition.

The Utility has MoPSC authority to issue debt securities and preferred stock, including on a private placement basis, as well as to issue common stock, receive paid-in capital, and enter into capital lease agreements, all for a total of up to $518 million. This authorization was originally effective through June 30, 2013. In August 2012, Laclede Gas filed a request with the MoPSC to extend this authority for an additional two years, to June 30, 2015. This extension became effective on November 23, 2012. During the year ended September 30, 2013, pursuant to this authority, the Utility sold 11,745 shares of its common stock to Laclede Group for $476.5 million. As of November 26, 2013, $370.8 million remains available under this authorization.

At September 30, 2013, the Company had fixed-rate long-term debt totaling $915 million. On October 15, 2012, the Utility paid at maturity $25 million principal amount of 6 1/2% first mortgage bonds. While the remaining long-term debt issues are fixed-rate, they are subject to changes in their 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 Utility’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. Of the Company’s $915 million in long-term debt, $50 million have no call option, $435 million have make-whole call options, $350 million are callable at par three to six months prior to maturity and $80 million are callable at par beginning in October 2013. None of the debt has any put options.

Shelf Registration Statement

On August 6, 2013, Laclede Gas and Laclede Group filed with the SEC a joint shelf registration statement on Form S-3 ASR for issuance of debt and equity securities, which expires August 5, 2016. The amount, timing, and type of additional financing to be issued under this shelf registration statement will depend on cash requirements and market conditions. Laclede Gas' $450 million issuance of bonds on August 13, 2013 was under this registration statement.

Laclede Group also has a registration statement on Form S-3 for the issuance and sale of up to 285,222 shares of its common stock under its Dividend Reinvestment and Stock Purchase Program. There were 194,246 and 186,919 shares at September 30, 2013 and November 26, 2013, respectively, remaining available for issuance under its Form S-3.

Other

The Company’s and the Utility’s access to capital markets, including the commercial paper market, and their respective financing costs, may depend on the credit rating of the entity that is accessing the capital markets. The credit ratings of the Company and the Utility remain at investment grade, but are subject to review and change by the rating agencies.

The Utility's capital expenditures were $128.5 million for fiscal 2013, compared with $106.7 million and $67.3 million for fiscal years 2012 and 2011, respectively. The increases in capital expenditures, compared with prior periods, are primarily attributable to additional expenditures for distribution plant and information technology investments.

40

Non-utility capital expenditures for fiscal year 2013 were $2.3 million compared with $2.1 million in fiscal year 2012 and $0.3 million in fiscal year 2011, and are estimated to be approximately $10 million for fiscal year 2014. The Utility's capital expenditures are expected to be approximately $175 million in fiscal year 2014.

Consolidated capitalization at September 30, 2013 consisted of 53.4% Laclede Group common stock equity and 46.6% of long-term debt, compared to 63.9% Laclede Group common stock equity and 36.1% of long-term debt at September 30, 2012.

Laclede Group’s ratio of earnings to fixed charges was 3.3 for fiscal year 2013 and 4.4 for fiscal years 2012 and 2011.

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

As of September 30, 2013, Laclede Group had contractual obligations with payments due as summarized below (in millions):

			Payments due by period
			Less than		1-3		3-5		More than
Contractual Obligations	Total		1 Year		Years		Years		5 Years
Principal Payments on Long-Term Debt	$	915.0	$	—	$	—	$	100.0	$	815.0
Interest Payments on Long-Term Debt	695.5		40.5		80.9		80.9		493.2
Capital Leases (a)	0.2		0.1		0.1		—		—
Operating Leases (a)	11.6		6.0		4.9		0.7		—
Purchase Obligations – Natural Gas (b)	981.2		528.6		231.0		149.4		72.2
Purchase Obligations – Other (c)	76.1		25.7		19.1		18.4		12.9
Other Long-Term Liabilities	159.2		15.2		30.9		31.5		81.6
Total (d)	$	2,838.8	$	616.1	$	366.9	$	380.9	$	1,474.9

(a) Lease obligations are primarily for office space, vehicles, and power operated equipment. Additional payments will be incurred if renewal options are exercised under the provisions of certain agreements.

(b) These purchase obligations represent the minimum payments required under existing natural gas transportation and storage contracts and natural gas supply agreements in the Gas Utility and Gas Marketing segments including the LER ten-year storage agreement with Perryville Gas Storage. These amounts reflect fixed obligations as well as obligations to purchase natural gas at future market prices, calculated using September 30, 2013 forward market prices. Laclede Gas recovers the costs related to its purchases, transportation, and storage of natural gas through the operation of its PGA Clause, subject to prudence review by the MoPSC; however, variations in the timing of collections of gas costs from customers affect short-term cash requirements. Additional contractual commitments are generally entered into prior to or during the heating season.

(c) These purchase obligations primarily reflect miscellaneous agreements for the purchase of materials and the procurement of services necessary for normal operations.

(d) Long-term liabilities associated with unrecognized tax benefits, totaling $2.4 million, have been excluded from the

table above because the timing of future cash outflows, if any, cannot be reasonably estimated. Also, commitments related to pension and postretirement benefit plans have been excluded from the table above. The Company expects to make contributions to its qualified, trusteed pension plans totaling $24.0 million in fiscal year 2014. The Utility anticipates a $0.3 million contribution relative to its non-qualified pension plans during fiscal year 2014. With regard to the postretirement benefits, the Company anticipates the Utility will contribute $19.2 million to the qualified trusts and $0.3 million directly to participants from the Utility's funds during fiscal year 2014. For further discussion of the Company’s pension and postretirement benefit plans, refer to Note 3, Pension Plans and Other Postretirement Benefits, of the Notes to Consolidated Financial Statements.

41

MARKET RISK

Commodity Price Risk

The Utility’s commodity price risk, which arises from market fluctuations in the price of natural gas, is primarily managed through the operation of Laclede Gas' and MGE's PGA Clauses. The PGA Clauses allow the Utility to flow through to customers, subject to prudence review by the MoPSC, the cost of purchased gas supplies. The Utility is allowed the flexibility to make up to three discretionary PGA changes during each year, in addition to its mandatory November PGA change, so long as such changes are separated by at least two months. The Utility is able to mitigate, to some extent, changes in commodity prices through the use of physical storage supplies and regional supply diversity. Laclede Gas and MGE also have risk management policies that allow for the purchase of natural gas derivative instruments with the goal of managing its price risk associated with purchasing natural gas on behalf of its customers. These policies prohibit speculation. Costs and cost reductions, including carrying costs, associated with the Utility’s use of natural gas derivative instruments are allowed to be passed on to the Utility’s customers through the operation of its PGA Clause. Accordingly, the Utility does not expect any adverse earnings impact as a result of the use of these derivative instruments. However, the timing of recovery for cash payments related to margin requirements may 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, are recovered through the PGA Clause. For more information about the Utility’s natural gas derivative instruments, see Note 11, Derivative Instruments and Hedging Activities, of the Notes to Consolidated Financial Statements.

In the course of its business, Laclede Group’s non-regulated gas marketing subsidiary, LER, enters into contracts to purchase and sell natural gas at fixed prices and natural gas index-based prices. Commodity price risk associated with these contracts has the potential to impact earnings and cash flows. To minimize this risk, LER has a risk management policy that provides for daily monitoring of a number of business measures, including fixed price commitments. In accordance with the risk management policy, LER manages the price risk associated with its fixed-price commitments. This risk is currently managed either by closely matching the offsetting physical purchase or sale of natural gas at fixed-prices or through the use of natural gas futures, options, and swap contracts traded on or cleared through the NYMEX and ICE to lock in margins. At September 30, 2013 and 2012, LER’s unmatched fixed-price positions were not material to Laclede Group’s financial position or results of operations.

As mentioned above, LER uses natural gas futures, options, and swap contracts traded on or cleared through the NYMEX and ICE to manage the commodity price risk associated with its fixed-price natural gas purchase and sale commitments. These derivative instruments may be designated as cash flow hedges of forecasted purchases or sales. Such accounting treatment, if elected, generally permits a substantial portion of the gain or loss to be deferred from recognition in earnings until the period that the associated forecasted purchase or sale is recognized in earnings. To the extent a hedge is effective, gains or losses on the derivatives will be offset by changes in the value of the hedged forecasted transactions. Information about the fair values of LER’s exchange-traded/cleared natural gas derivative instruments is presented below:

(Thousands)	Derivative Fair Values			Cash Margin			Derivatives and Cash Margin
Net balance of derivative assets at September 30, 2012	$	(3,515	)	$	5,489		$	1,974
Changes in fair value	5,044			—			5,044
Settlements/purchases - net	1,114			—			1,114
Changes in cash margin	—			(5,235		)	(5,235		)
Net balance of derivative assets at September 30, 2013	$	2,643		$	254		$	2,897

(Thousands)	As of September 30, 2013
	Maturity by Fiscal Year
	Total			2014			2015		2016
Fair values of exchange-traded/cleared natural gas derivatives - net	$	2,643		$	2,632		$	11	$	—
MMBtu – net long futures/swap/option positions	(11,058		)	(11,198		)	125		15

Certain of LER’s physical natural gas derivative contracts are designated as normal purchases or normal sales, as permitted by GAAP. This election permits the Company to account for the contract in the period the natural gas is delivered. Contracts not designated as normal purchases or normal sales, including those designated as trading activities, are accounted for as derivatives with changes in fair value recognized in earnings in the periods prior to settlement.

42

Below is a reconciliation of the beginning and ending balances for physical natural gas contracts accounted for as derivatives, none of which will settle beyond fiscal year 2016:

(Thousands)
Net balance of derivative assets at September 30, 2012	$	2,741
Changes in fair value	16
Settlements	(2,658		)
Net balance of derivative assets at September 30, 2013	$	99

For further details related to LER’s derivatives and hedging activities, see Note 11, Derivative Instruments and Hedging Activities, of the Notes to Consolidated Financial Statements.

Counterparty Credit Risk

LER has concentrations of counterparty credit risk in that a significant portion of its transactions are with energy producers, utility companies, and pipelines. These concentrations of counterparties have the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that each of these three groups may be affected similarly by changes in economic, industry, or other conditions. LER also has concentrations of credit risk with certain individually significant counterparties. To the extent possible, LER enters into netting arrangements with its counterparties to mitigate exposure to credit risk. LER is also exposed to credit risk associated with its derivative contracts designated as normal purchases and normal sales. LER closely monitors its credit exposure and, although uncollectible amounts have not been significant, increased counterparty defaults are possible and may result in financial losses and/or capital limitations. For more information on these concentrations of credit risk, including how LER manages these risks, see Note 12, Concentrations of Credit Risk, of the Notes to Consolidated Financial Statements.

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 fiscal year 2013, 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 $0.3 million on an annual basis. Portions of such increases may be offset through the application of PGA carrying costs. At September 30, 2013, Laclede Gas had fixed-rate long-term debt totaling $890 million. Additionally, Laclede Group had fixed-rate long-term debt totaling $25 million. 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 Utility’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.

The Company entered into and settled certain interest rate swap transactions to protect itself against adverse movements in interest rates associated with the issuance of long-term debt to fund the acquisition of MGE. Refer to Note 11, Derivative Instruments and Hedging Activities, of the Notes to Consolidated Financial Statements for additional details on these interest rate swap transactions.

ENVIRONMENTAL MATTERS

The Utility 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’s or the Utility's financial position and results of operations. As environmental laws, regulations, and their interpretations change, however, the Utility may be required to incur additional costs. For information relative to environmental matters, see Note 16, Commitments and Contingencies, of the Notes to Consolidated Financial Statements.

OFF-BALANCE SHEET ARRANGEMENTS

Laclede Group has no off-balance sheet arrangements.

43

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

For this discussion, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Risk, on page 42 of this report.

44

Item 8. Financial Statements and Supplementary Data
		2013 10-K Page
	Management Report on Internal Control Over Financial Reporting	46
	Reports of Independent Registered Public Accounting Firm	47
	Financial Statements:
	For Years Ended September 30, 2013, 2012, and 2011:
	Statements of Consolidated Income	49
	Statements of Consolidated Comprehensive Income	50
	Consolidated Statements of Common Shareholders’ Equity	54
	Statements of Consolidated Cash Flows	55
	As of September 30, 2013 and 2012:
	Consolidated Balance Sheets	51
	Statements of Consolidated Capitalization	53
	Notes to Consolidated Financial Statements:
	Note 1 Summary of Significant Accounting Policies	56
	Note 2 MGE Acquisition	61
	Note 3 Pension Plans and Other Postretirement Benefits	64
	Note 4 Stock-Based Compensation	72
	Note 5 Earnings Per Common Share	75
	Note 6 Stockholders’ Equity	75
	Note 7 Long-Term Debt	76
	Note 8 Notes Payable and Credit Agreements	77
	Note 9 Fair Value of Financial Instruments	78
	Note 10 Fair Value Measurements	79
	Note 11 Derivative Instruments and Hedging Activities	80
	Note 12 Concentrations of Credit Risk	84
	Note 13 Income Taxes	85
	Note 14 Other Income and (Income Deductions) – Net	86
	Note 15 Information By Operating Segment	86
	Note 16 Commitments and Contingencies	88
	Note 17 Interim Financial Information (Unaudited)	92

45

Management Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Company’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. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risks that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

The Company’s management, including our Chief Executive Officer and Chief Financial Officer, conducted an assessment of the effectiveness of the Company’s internal control over financial reporting as of September 30, 2013. In making this assessment, management used the criteria in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. As permitted, that assessment excluded the business operations of Missouri Gas Energy (MGE), which was completed on September 3, 2013, and whose financial statements constitute 50 percent and 36 percent of net and total assets, respectively, 2 percent of revenues, and 3 percent of net income, of the consolidated financial statement amounts as of and for the year ended September 30, 2013. Refer to Note 2, Acquisition of MGE in the Notes to Consolidated Financial Statements for further discussion of the acquisition. Based on that assessment, management concluded that the Company’s internal control over financial reporting was effective as of September 30, 2013. Deloitte & Touche LLP, an independent registered public accounting firm, has issued an attestation report on the Company’s internal control over financial reporting, which is included herein.

46

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

The Laclede Group, Inc.

St. Louis, Missouri

We have audited the internal control over financial reporting of The Laclede Group, Inc. and subsidiaries (the "Company") as of September 30, 2013, based on criteria established in Internal Control - Integrated Framework(1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. As described in Management’s Report on Internal Control over Financial Reporting, management excluded from its assessment the internal controls over financial reporting at Missouri Gas Energy (“MGE”), which was acquired on September 3, 2013 and whose financial statements constitute 50 percent and 36 percent of net and total assets, respectively, two percent of total revenues, and three percent of net income of the consolidated financial statements as of and for the year ended September 30, 2013. Accordingly, our audit did not include the internal control over financial reporting at MGE. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2013, based on the criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended September 30, 2013 of the Company and our report dated November 26, 2013 expressed an unqualified opinion on those consolidated financial statements and financial statement schedule.

/s/ DELOITTE & TOUCHE LLP

St. Louis, Missouri

November 26, 2013

47

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

The Laclede Group, Inc.

St. Louis, Missouri

We have audited the accompanying consolidated balance sheets and statements of consolidated capitalization of The Laclede Group, Inc. and subsidiaries (the “Company”) as of September 30, 2013 and 2012, and the related consolidated statements of income, comprehensive income, common shareholders’ equity, and cash flows for each of the three years in the period ended September 30, 2013. Our audits also included the financial statement schedule listed in the Index at Item 15. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and financial statement schedule based on our audits.

We conducted our audits 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of The Laclede Group, Inc. and subsidiaries as of September 30, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2013, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of September 30, 2013, based on the criteria established in Internal Control-Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated November 26, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

St. Louis, Missouri

November 26, 2013

48

THE LACLEDE GROUP, INC.
STATEMENTS OF CONSOLIDATED INCOME
(Thousands, Except Per Share Amounts)
Years Ended September 30	2013		2012		2011
Operating Revenues:
Gas Utility	$	847,224	$	763,447	$	913,190
Gas Marketing	165,146		358,145		669,375
Other	4,649		3,883		20,742
Total Operating Revenues	1,017,019		1,125,475		1,603,307
Operating Expenses:
Gas Utility
Natural and propane gas	433,442		397,304		549,947
Other operation and maintenance expenses	180,342		167,351		172,938
Depreciation and amortization	48,283		40,739		39,214
Taxes, other than income taxes	60,079		53,672		60,752
Total Gas Utility Operating Expenses	722,146		659,066		822,851
Gas Marketing	176,554		353,283		652,567
Other	21,825		2,524		9,642
Total Operating Expenses	920,525		1,014,873		1,485,060
Operating Income	96,494		110,602		118,247
Other Income and (Income Deductions) – Net	2,444		3,272		177
Interest Charges:
Interest on long-term debt	25,539		22,958		23,161
Other interest charges	3,063		1,987		2,256
Total Interest Charges	28,602		24,945		25,417
Income Before Income Taxes	70,336		88,929		93,007
Income Tax Expense	17,578		26,289		29,182
Net Income	$	52,758	$	62,640	$	63,825
Weighted Average Number of Common Shares Outstanding:
Basic	25,875		22,262		22,099
Diluted	25,952		22,340		22,171
Basic Earnings Per Share of Common Stock	$	2.03	$	2.80	$	2.87
Diluted Earnings Per Share of Common Stock	$	2.02	$	2.79	$	2.86

See the accompanying Notes to Consolidated Financial Statements.

49

THE LACLEDE GROUP, INC.
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
(Thousands)
Years Ended September 30	2013			2012			2011
Net Income	$	52,758		$	62,640		$	63,825
Other Comprehensive Income (Loss), Before Tax:
Net gains (losses) on cash flow hedging derivative instruments:
Net hedging gain arising during the period	5,047			4,802			5,581
Reclassification adjustment for (gains) losses included in net income	302			(8,397		)	1,861
Net unrealized (losses) gains on cash flow hedging derivative instruments	5,349			(3,595		)	7,442
Defined benefit pension and other postretirement benefit plans:
Net actuarial (loss) gain arising during the period	(120		)	(3,397		)	339
Amortization of actuarial loss included in net periodic pension and postretirement benefit cost	195			3,706			426
Net defined benefit pension and other postretirement benefit plans	75			309			765
Other Comprehensive (Loss) Income, Before Tax	5,424			(3,286		)	8,207
Income Tax (Benefit) Expense Related to Items of Other Comprehensive (Loss) Income	2,094			(1,270		)	3,170
Other Comprehensive (Loss) Income, Net of Tax	3,329			(2,016		)	5,037
Comprehensive Income	$	56,087		$	60,624		$	68,862

See the accompanying Notes to Consolidated Financial Statements.

50

THE LACLEDE GROUP, INC.
CONSOLIDATED BALANCE SHEETS
(Thousands)
September 30	2013			2012
ASSETS
Utility Plant	$	2,271,189		$	1,497,419
Less – Accumulated depreciation and amortization	494,559			478,120
Net Utility Plant	1,776,630			1,019,299
Non-utility property (net of accumulated depreciation and amortization, 2013, $5,886; 2012, $10,018)	7,694			6,039
Goodwill	247,078			—
Other investments	58,306			50,775
Other Property and Investments	313,078			56,814
Current Assets:
Cash and cash equivalents	52,981			27,457
Accounts receivable:
Utility	101,118			64,027
Non-utility	63,752			51,042
Other	14,451			26,478
Allowance for doubtful accounts	(8,046		)	(7,705		)
Inventories:
Natural gas stored underground	182,035			92,729
Propane gas	8,962			10,200
Materials and supplies at average cost	8,154			3,543
Natural gas receivable	18,782			22,377
Derivative instrument assets	3,291			2,855
Unamortized purchased gas adjustments	17,533			40,674
Prepayments and other	12,867			9,339
Total Current Assets	475,880			343,016
Deferred Charges:
Regulatory assets	545,947			456,047
Other	13,851			5,086
Total Deferred Charges	559,798			461,133
Total Assets	$	3,125,386		$	1,880,262

51

THE LACLEDE GROUP, INC.
CONSOLIDATED BALANCE SHEETS (Continued)
(Thousands)
September 30	2013		2012
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock equity	$	1,046,282	$	601,611
Long-term debt (less current portion)	912,712		339,416
Total Capitalization	1,958,994		941,027
Current Liabilities:
Notes payable	74,000		40,100
Accounts payable	140,234		89,503
Advance customer billings	23,736		25,146
Current portion of long-term debt	—		25,000
Wages and compensation accrued	20,807		13,908
Dividends payable	14,556		9,831
Customer deposits	15,062		8,565
Interest accrued	8,335		8,590
Taxes accrued	32,896		11,304
Deferred income taxes	1,012		6,675
Other	22,540		13,502
Total Current Liabilities	353,178		252,124
Deferred Credits and Other Liabilities:
Deferred income taxes	379,114		355,509
Unamortized investment tax credits	2,900		3,113
Pension and postretirement benefit costs	228,653		196,558
Asset retirement obligations	74,554		40,368
Regulatory liabilities	82,560		56,319
Other	45,433		35,244
Total Deferred Credits and Other Liabilities	813,214		687,111
Commitments and Contingencies (Note 16)
Total Capitalization and Liabilities	$	3,125,386	$	1,880,262

See the accompanying Notes to Consolidated Financial Statements.

52

THE LACLEDE GROUP, INC.
STATEMENTS OF CONSOLIDATED CAPITALIZATION
(Thousands, Except for Shares and Per Share Amounts)
September 30	2013			2012
Common Stock Equity:
Common stock, par value $1 per share:
Authorized – 2013 and 2012, 70,000,000 shares
Issued – 2013, 32,696,836 shares; and 2012, 22,539,431 shares	$	32,697		$	22,539
Paid-in capital	594,269			168,607
Retained earnings	420,103			414,581
Accumulated other comprehensive loss	(787		)	(4,116		)
Total Common Stock Equity	1,046,282			601,611
Long Term Debt - Laclede Group:
3.31% Notes Payable, due December 15, 2022	25,000			—
Long-Term Debt – Laclede Gas:
First Mortgage Bonds:
5-1/2% Series, due May 1, 2019	50,000			50,000
7% Series, due June 1, 2029	25,000			25,000
7.90% Series, due September 15, 2030	30,000			30,000
6% Series, due May 1, 2034	100,000			100,000
6.15% Series, due June 1, 2036	55,000			55,000
6.35% Series, due October 15, 2038	80,000			80,000
3% Series, due March 15, 2023	55,000			—
3.40% Series, due March 15, 2028	45,000			—
2% Series, due August 15, 2018	100,000			—
3.40% Series, due August 15, 2023	250,000			—
4.625% Series, due August 15, 2043	100,000			—
Total	915,000			340,000
Unamortized discount, net of premium, on long-term debt	(2,288		)	(584		)
Total Long-Term Debt	912,712			339,416
Total Capitalization	$	1,958,994		$	941,027

Long-term debt dollar amounts are exclusive of current portion.

See the accompanying Notes to Consolidated Financial Statements.

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THE LACLEDE GROUP, INC.
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS’ EQUITY
	Common Stock Issued			Paid-in			Retained			Accum. Other Comp.
(Thousands, Except for Shares and Per Share Amounts)	Shares	Amount		Capital			Earnings			Income (Loss)			Total
BALANCE OCTOBER 1, 2010	22,292,804	$	22,293	$	158,698		$	361,723		$	(7,137	)	$	535,577
Net income	—	—		—			63,825			—			$	63,825
Dividend reinvestment plan	43,354	43		1,571			—			—			$	1,614
Stock-based compensation costs	—	—		3,949			—			—			$	3,949
Equity Incentive Plan	94,576	95		840			—			—			$	935
Employees’ taxes paid associated with restricted     shares withheld upon vesting	—	—		(1,162		)	—			—			$	(1,162	)
Non-employee directors’ restricted stock awards	—	—		(494		)	—			—			$	(494	)
Tax benefit – stock compensation	—	—		300			—			—			$	300
Dividends declared:
Common stock ($1.62 per share)	—	—		—			(36,250		)	—			$	(36,250	)
Other comprehensive loss, net of tax	—	—		—			—			5,037			$	5,037
BALANCE SEPTEMBER 30, 2011	22,430,734	22,431		163,702			389,298			(2,100		)	573,331
Net income	—	—		—			62,640			—			$	62,640
Dividend reinvestment plan	46,107	46		1,795			—			—			$	1,841
Stock-based compensation costs	—	—		2,702			—			—			$	2,702
Equity Incentive Plan	62,590	62		2,408			—			—			$	2,470
Employees’ taxes paid associated with restricted     shares withheld upon vesting	—	—		(1,203		)	—			—			$	(1,203	)
Non-employee directors’ restricted stock awards	—	—		(565		)	—			—			$	(565	)
Tax benefit – stock compensation	—	—		(232		)	—			—			$	(232	)
Dividends declared:
Common stock ($1.66 per share)	—	—		—			(37,357		)	—			$	(37,357	)
Other comprehensive income, net of tax	—	—		—			—			(2,016		)	$	(2,016	)
BALANCE SEPTEMBER 30, 2012	22,539,431	22,539		168,607			414,581			(4,116		)	601,611
Net income	—	—		—			52,758			—			$	52,758
Common stock offering	10,005,000	10,005		417,157			—			—			$	427,162
Dividend reinvestment plan	44,074	44		1,803			—			—			$	1,847
Stock-based compensation costs	—	—		4,441			—			—			$	4,441
Equity Incentive Plan	108,331	109		2,565			—			—			$	2,674
Employees’ taxes paid associated with restricted     shares withheld upon vesting	—	—		(931		)	—			—			$	(931	)
Non-employee directors’ restricted stock awards	—	—					—			—			$	—
Tax benefit – stock compensation	—	—		627			—			—			$	627
Dividends declared:
Common stock ($1.70 per share)	—	—		—			(47,236		)	—			$	(47,236	)
Other comprehensive loss, net of tax	—	—		—			—			3,329			$	3,329
BALANCE SEPTEMBER 30, 2013	32,696,836	$	32,697	$	594,269		$	420,103		$	(787	)	$	1,046,282

See the accompanying Notes to Consolidated Financial Statements.

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THE LACLEDE GROUP, INC.
STATEMENTS OF CONSOLIDATED CASH FLOWS
(Thousands)
Years Ended September 30	2013			2012			2011
Operating Activities:
Net Income	$	52,758		$	62,640		$	63,825
Adjustments to reconcile net income to
net cash provided by (used in) operating activities:
Depreciation, amortization and accretion	49,283			41,339			39,764
Deferred income taxes and investment tax credits	22,053			30,554			23,885
Other - net	957			75			3,431
Changes in assets and liabilities:
Accounts receivable – net	(650		)	(9,359		)	3,106
Unamortized purchased gas adjustments	23,141			(14,955		)	(2,001		)
Deferred purchased gas costs	13,300			11,090			44,565
Accounts payable	35,445			(8,790		)	(4,860		)
Advance customer billings – net	(8,248		)	9,916			(1,579		)
Taxes accrued	3,666			(1,169		)	1,387
Natural gas stored underground	(30,626		)	22,441			(1,594		)
Other assets and liabilities	2,835			(15,681		)	(2,742		)
Net cash provided by operating activities	163,914			128,101			167,187
Investing Activities:
Capital expenditures	(130,788		)	(108,843		)	(67,638		)
Other investments	(2,511		)	3,439			631
Acquisition of MGE	(975,000		)	—			—
Net cash used in investing activities	(1,108,299		)	(105,404		)	(67,007		)
Financing Activities:
Issuance of first mortgage bonds	550,000			—			—
Maturity of first mortgage bonds	(25,000		)	—			(25,000		)
Issuance (Repayment) of short-term debt - net	33,900			(5,900		)	(83,650		)
Notes Payable Issued	25,000			—			—
Change in book overdrafts	(1,255		)	1,455			(545		)
Issuance of common stock	431,682			4,311			2,549
Non-employee directors’ restricted stock awards	—			(565		)	(494		)
Dividends paid	(42,518		)	(36,896		)	(35,821		)
Employees’ taxes paid associated with restricted shares withheld upon vesting	(931		)	(1,203		)	(1,162		)
Excess tax benefits from stock-based compensation	1,778			338			314
Other	(2,747		)	(57		)	(13		)
Net cash provided by (used in) financing activities	969,909			(38,517		)	(143,822		)
Net (Decrease) Increase in Cash and Cash Equivalents	25,524			(15,820		)	(43,642		)
Cash and Cash Equivalents at Beginning of Year	27,457			43,277			86,919
Cash and Cash Equivalents at End of Year	$	52,981		$	27,457		$	43,277
Supplemental Disclosure of Cash Paid (Refunded) During the Year for:
Interest	$	26,304		$	24,557		$	25,332
Income taxes	(9,375		)	1,540			6,860

See the accompanying Notes to Consolidated Financial Statements.

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THE LACLEDE GROUP, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

BASIS OF CONSOLIDATION - The consolidated financial statements include the accounts of Laclede Group and its subsidiary companies, including the recent acquisition of Missouri Gas Energy (MGE). All subsidiaries are wholly owned. Laclede Gas and other subsidiaries of Laclede Group may engage in related party transactions during the ordinary course of business. All material intercompany balances have been eliminated from the consolidated financial statements of Laclede Group. Transactions include sales of natural gas and transportation services between subsidiaries. These revenues are shown on the Intersegment revenues lines in the table included in Note 15, Information by Operating Segment.

NATURE OF OPERATIONS - The Laclede Group, Inc. (NYSE: LG), headquartered in St. Louis, Missouri, is a public utility holding company. The Gas Utility segment serves St. Louis and eastern Missouri through Laclede Gas and serves Kansas City and western Missouri through Missouri Gas Energy. Together they provide more than 1.13 million residential, commercial and industrial customers with safe and reliable natural gas service. Laclede’s primary non-utility business, Laclede Energy Resources, Inc., included in the Gas Marketing segment, provides non-regulated natural gas services. The activities of other subsidiaries and the non-regulated activities of Laclede Gas are described in Note 15, Information by Operating Segment, and are included in the Other column.

USE OF ESTIMATES - The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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.

SYSTEM OF ACCOUNTS - The accounts of Laclede Gas are maintained in accordance with the Uniform System of Accounts prescribed by the Missouri Public Service Commission (MoPSC or Commission), which system substantially conforms to that prescribed by the Federal Energy Regulatory Commission (FERC).

UTILITY PLANT, DEPRECIATION AND AMORTIZATION - 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.

Utility plant is depreciated on a straight-line basis at rates based on estimated service lives of the various classes of property. In fiscal year 2013, annual depreciation and amortization expense averaged 3.2% of the original cost of depreciable and amortizable property, compared to 3.1% in both fiscal years 2012 and 2011.

The Utility’s capital expenditures were $128.5 million, $106.7 million, and $67.3 million for fiscal years 2013, 2012, and 2011, respectively. Additionally, the Utility had recorded accruals for capital expenditures totaling $4.7 million at September 30, 2013, $9.7 million at September 30, 2012, and $8.2 million at September 30, 2011. Accrued capital expenditures are excluded from the Statements of Consolidated Cash Flows.

ASSET RETIREMENT OBLIGATIONS - Laclede Group 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 has recorded 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 Utility’s distribution system and general plant. Asset retirement obligations recorded by Laclede Group’s other subsidiaries are not material. As authorized by the MoPSC, the Utility accrues future asset removal costs associated with its property, plant and equipment even if a legal obligation does not exist. Such accruals are provided for through depreciation expense and are recorded with corresponding credits to regulatory liabilities. When the Utility retires depreciable utility plant and equipment, it charges the associated original costs to accumulated depreciation and amortization, and any related removal costs incurred are charged to regulatory liabilities. The difference between removal costs recognized in depreciation rates and the accretion expense and depreciation expense recognized for financial reporting purposes is a timing difference between recovery of these costs in rates and their recognition for financial reporting purposes.

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Accordingly, these differences are deferred as regulatory liabilities. In the rate setting process, the regulatory liability is deducted from the rate base upon which the Utility has the opportunity to earn its allowed rate of return.

As part of the MGE acquisition, the Utility has estimated the asset retirement obligation of MGE’s long-lived assets as of the acquisition date. This allocation of asset retirement obligations is preliminary and will be finalized upon completion of a detailed fair value analysis that is being performed by the Company in the first quarter of fiscal 2014.

The following table presents a reconciliation of the beginning and ending balances of asset retirement obligations at September 30 as reported in the Consolidated Balance Sheets:

(Thousands)	2013			2012
Asset retirement obligations, beginning of year	$	40,368		$	27,495
Liabilities incurred during the period	801			851
Liabilities settled during the period	(1,089		)	(601		)
Accretion	2,322			1,637
Revisions in estimated cash flows	—			10,986
Addition of MGE asset retirement obligation	32,152			—
Asset retirement obligations, end of year	$	74,554		$	40,368

REGULATED OPERATIONS - The Utility accounts for its regulated operations in accordance with ASC Topic 980. This Topic sets forth the application of generally accepted accounting principles in the United States of America (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 Consolidated Balance Sheets as of September 30:

(Thousands)	2013		2012
Regulatory Assets:
Future income taxes due from customers	$	112,912	$	118,997
Pension and postretirement benefit costs	381,395		304,446
Unamortized purchased gas adjustments	17,533		40,674
Purchased gas costs	18,249		18,386
Compensated absences	8,004		7,836
Other	25,387		6,382
Total Regulatory Assets	$	563,480	$	496,721
Regulatory Liabilities:
Unamortized investment tax credits	$	2,900	$	3,113
Accrued cost of removal	59,066		55,103
Other	23,494		1,216
Total Regulatory Liabilities	$	85,460	$	59,432

The regulatory assets are expected to be recovered in rates charged to customers. A portion of the Company's regulatory assets are not earning a return; however, these regulatory assets are expected to be recovered from customers in future rates. Excluding deferred income taxes and purchased gas adjustment items, as of September 30, 2013 and 2012, approximately $17.2 million and $7.8 million, respectively, of regulatory assets were not earning a rate of return. The Company expects these items to be recovered over a period not to exceed 15 years consistent with precedent set by the MoPSC. The portion of the regulatory asset related to pensions and other postemployment benefits that relates to unfunded differences between the projected benefit obligation and plan assets also does not earn a rate of return.

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As authorized by the MoPSC, the Utility discontinued deferring certain costs for future recovery, as expenses associated with those specific areas were included in approved rates effective December 27, 1999. Previously deferred costs of $10.5 million are being recovered and amortized on a straight-line basis over a fifteen-year period, without return on investment. Amortization of these costs totaled $9.7 million from December 27, 1999 through September 30, 2013.

NATURAL GAS STORED UNDERGROUND AND PROPANE GAS – For Laclede Gas, inventory of natural gas in storage is priced on a last-in, first-out (LIFO) basis and inventory of propane gas in storage is priced on a first-in, first-out (FIFO) basis. For MGE, inventory of natural gas in storage is priced on a weighted average cost basis. The replacement cost of Laclede Gas' natural gas stored underground for current use at September 30, 2013 and September 30, 2012 was less than the LIFO cost by $13.3 million and $24.3 million, respectively. The carrying value of the Utility inventory is not adjusted to the lower of cost or market prices because, pursuant to both Laclede Gas' and MGE's Purchased Gas Adjustment (PGA) Clauses, actual gas costs are recovered in customer rates. Natural gas and propane gas storage inventory in Laclede Group’s other operating segments is recorded at the lower of average cost or market.

BUSINESS COMBINATIONS - The Company's acquisition of MGE was accounted for by the Company using business combination accounting. Under this method, the purchase price paid by the acquirer is allocated to the assets acquired and liabilities assumed as of the acquisition date based on their fair value. For additional information on the Company's acquisition of MGE, refer to Note 2, MGE Acquisition.

GOODWILL - Goodwill is measured as the excess of the acquisition-date fair value of the consideration transferred over the amount of acquisition-date identifiable assets acquired net of assumed liabilities. Laclede Group recorded $247.1 million of goodwill as part of the MGE acquisition.

REVENUE RECOGNITION - The Utility reads meters and bills its customers on monthly cycles. The Utility records its Gas Utility revenues from gas sales and transportation services on an accrual basis that includes estimated amounts for gas delivered, but not yet billed. The accruals for unbilled revenues are reversed in the subsequent accounting period when meters are actually read and customers are billed. The amounts of accrued unbilled revenues at September 30, 2013 and 2012, for the Utility, were $25.2 million and $11.6 million, respectively.

Laclede Group’s other subsidiaries, including LER, record revenues when earned, either when the product is delivered or when services are performed.

In the course of its business, LER enters into commitments associated with the purchase or sale of natural gas. Certain of LER’s derivative natural gas contracts are designated as normal purchases or normal sales, and, as such, are excluded from the scope of ASC Topic 815, “Derivatives and Hedging.” Those contracts are accounted for as executory contracts and recorded on an accrual basis. Revenues and expenses from such contracts are recorded using a gross presentation. Contracts not designated as normal purchases or normal sales are recorded as derivatives with changes in fair value recognized in earnings in the periods prior to physical delivery. For additional information on derivative instruments, refer to Note 11, Derivative Instruments and Hedging Activities. Certain of LER’s wholesale purchase and sale transactions entered on or after January 1, 2012 are classified as trading activities for financial reporting purposes. Under GAAP, revenues and expenses associated with trading activities are presented on a net basis in Gas Marketing Operating Revenues in the Statements of Consolidated Income. This net presentation has no effect on operating income or net income.

PURCHASED GAS ADJUSTMENTS AND DEFERRED ACCOUNT – As authorized by the MoPSC, the PGA Clause allows Laclede Gas to flow through to customers, subject to prudence review by the MoPSC, the cost of purchased gas supplies. To better match customer billings with market natural gas prices, the Utility is allowed to file to modify, on a periodic basis, the level of gas costs in its PGA. Certain provisions of the PGA Clause are included below:

• The Utility has a risk management policy that allows for the purchase of natural gas derivative instruments with the goal of managing price risk associated with purchasing natural gas on behalf of its customers. The MoPSC clarified that costs, cost reductions, and carrying costs associated with the Utility’s use of natural gas derivative instruments are gas costs recoverable through the PGA mechanism.

• The tariffs allow the Utility flexibility to make up to three discretionary PGA changes during each year, in addition to its mandatory November PGA change, so long as such changes are separated by at least two months.

• The Utility is authorized to recover gas inventory carrying costs through its PGA rates to recover costs it incurs to finance its investment in gas supplies that are purchased during the storage injection season for sale during the heating season. The Utility is also authorized to apply carrying costs to all over- or under-recoveries of gas costs, including costs and cost reductions associated with the use of derivative instruments, including cash payments for margin deposits.

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• The MoPSC approved a plan applicable to Laclede Gas' gas supply commodity costs under which it retains a portion of cost savings associated with the acquisition of natural gas below an established benchmark level. This gas supply cost management program allows Laclede Gas to retain 10% of cost savings, up to a maximum of $3.0 million annually. Laclede Gas did not record any income under the plan during the three fiscal years reported. Income recorded under the plan, if any, is included in Gas Utility Operating Revenues on the Statements of Consolidated Income.

Pursuant to the provisions of the PGA Clause, the difference between actual costs incurred and costs recovered through the application of the PGA are reflected as a deferred charge or credit at the end of the fiscal year. These costs include costs and cost reductions associated with the use of derivative instruments and gas inventory carrying costs, amounts due to or from customers related to operation of the gas supply cost management program, refunds received from the Company’s suppliers in connection with gas supply, transportation, and storage services, and carrying costs on such over- or under-recoveries. At that time, the balance is classified as a current asset or current liability and recovered from, or credited to, customers over an annual period commencing in November. The balance in the current account is amortized as amounts are reflected in customer billings. The PGA Clause also provides for the treatment of income from off-system sales and capacity release revenues. Pre-tax income from off-system sales and capacity release revenues is shared with customers, with an estimated amount assumed in PGA rates. The difference between the actual amount allocated to customers for each fiscal year and the estimated amount assumed in PGA rates is recovered from, or credited to, customers over an annual period commencing in the subsequent November. The customer share of such income is determined in accordance with the tables below, which is shown for each legacy company (Laclede Gas and MGE) under which the PGA Clauses were approved by the MoPSC.

Laclede Gas
Pre-tax Income	Customer Share	Company Share
First $2 million	100%	—%
Next $2 million	80%	20%
Next $2 million	75%	25%
Amounts exceeding $6 million	70%	30%
MGE
Pre-tax Income	Customer Share	Company Share
First $1.2 million	85%	15%
Next $1.2 million	80%	20%
Next $1.2 million	75%	25%
Amounts exceeding $3.6 million	70%	30%

See the Regulatory and Other Matters section on page 36 of this report for additional information on Laclede Gas' off-system sales.

INCOME TAXES - Laclede Group and its subsidiaries have elected, for tax purposes only, various accelerated depreciation provisions of the Internal Revenue Code. In addition, certain other costs are expensed currently for tax purposes while being deferred for book purposes. GAAP permits the benefit from a tax position to be recognized only if, and to the extent that, it is more likely than not that the tax position will be sustained upon examination by the taxing authority, based on the technical merits of the position. Unrecognized tax benefits and related interest and penalties, if any, are recorded as liabilities or as a reduction to deferred tax assets. Laclede Group companies record deferred tax liabilities and assets measured by enacted tax rates for the net tax effect of all temporary differences between the tax basis and the related carrying amounts of assets and liabilities in the financial statements. Changes in enacted tax rates, if any, and certain property basis differences are reflected by entries to regulatory asset or regulatory liability accounts for regulated companies, and are reflected as income or loss for non-regulated companies.

The Utility’s investment tax credits utilized prior to 1986 have been deferred and are being amortized in accordance with regulatory treatment over the useful life of the related property.

CASH AND CASH EQUIVALENTS - All highly liquid debt instruments purchased with original maturities of three months or less are considered to be cash equivalents. Such instruments are carried at cost, which approximates market value.

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Outstanding checks on the Company’s controlled disbursement bank accounts in excess of funds on deposit create book overdrafts (which are funded at the time checks are presented for payment) and are classified as Other in the Current Liabilities section of the Consolidated Balance Sheets. Changes in book overdrafts between periods are reflected as Financing Activities in the Statements of Consolidated Cash Flows.

NATURAL GAS RECEIVABLE – LER enters into natural gas transactions with natural gas pipeline companies known as park and loan arrangements. Under the terms of the arrangements, LER purchases natural gas from a third party and delivers that natural gas to the pipeline company for the right to receive the same quantity of natural gas from the pipeline company at the same location in a future period. These arrangements are accounted for as non-monetary transactions under GAAP and are recorded at the carrying amount. As such, natural gas receivables are reflected on the Consolidated Balance Sheets at cost, which includes related pipeline fees associated with the transactions. In the period that the natural gas is returned to LER, concurrent with the sale of the natural gas to a third party, the related natural gas receivable is expensed in the Statements of Consolidated Income. In conjunction with these transactions, LER usually enters into New York Mercantile Exchange (NYMEX) and Ice Clear Europe (ICE) natural gas futures, options, and swap contracts or fixed price sales agreements to protect against market changes in future sales prices.

EARNINGS PER COMMON SHARE - GAAP requires dual presentation of basic and diluted earnings per share (EPS). EPS is computed using the two-class method, which is an earnings allocation method for computing EPS that treats a participating security as having rights to earnings that would otherwise have been available to common shareholders. Certain of the Company’s stock-based compensation awards pay nonforfeitable dividends to the participants during the vesting period and, as such, are deemed participating securities. Basic EPS is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding that are increased for additional shares that would be outstanding if potentially dilutive non-participating securities were converted to common shares, pursuant to the treasury stock method. Shares attributable to non-participating stock options and time-vested restricted stock/units are excluded from the calculation of diluted earnings per share if the effect would be antidilutive. Shares attributable to non-participating performance-contingent restricted stock awards are only included in the calculation of diluted earnings per share to the extent the underlying performance and/or market conditions are satisfied (a) prior to the end of the reporting period or (b) would be satisfied if the end of the reporting period were the end of the related contingency period and the result would be dilutive. The Company’s EPS computations are presented in Note 5, Earnings Per Common Share.

GROSS RECEIPTS AND SALES TAXES - Gross receipts taxes associated with the Utility's natural gas utility service are imposed on the Utility and billed to its customers. These amounts are recorded gross in the Statements of Consolidated Income. Amounts recorded in Gas Utility Operating Revenues were $40.8 million, $35.9 million, and $43.5 million for fiscal years 2013, 2012, and 2011, respectively. Gross receipts taxes are expensed by the Utility and included in the Taxes, other than income taxes line.

Sales taxes imposed on applicable Company sales are billed to customers. These amounts are not recorded in the Statements of Consolidated Income, but are recorded as tax collections payable and included in the Other line of the Current Liabilities section of the Consolidated 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 collectibility 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. The Utility’s provision for uncollectible accounts includes the amortization of previously deferred uncollectible expenses, as approved by the MoPSC.

GROUP MEDICAL AND WORKERS’ COMPENSATION RESERVES - The Company self-insures its group medical and workers’ compensation costs and carries stop-loss coverage in relation to medical claims 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.

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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 3, Pension Plans and Other Postretirement Benefits, Note 9, Fair Value of Financial Instruments, and Note 10, Fair Value Measurements.

STOCK-BASED COMPENSATION – The Company measures stock-based compensation awards at fair value at the date of grant and recognizes the compensation cost of the awards over the requisite service period. Forfeitures are estimated at the time of grant and revised, if necessary, in subsequent periods if the actual forfeitures differ from those estimates. Refer to Note 4, Stock-Based Compensation, for further discussion of the accounting for the Company’s stock-based compensation plans.

NEW ACCOUNTING STANDARDS – In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities,” to amend ASC Topic 210, “Balance Sheet,” to require additional disclosures about financial instruments and derivative instruments that have been presented on a net basis (offset) in the balance sheet. Additionally, information about financial instruments and derivative instruments that are subject to enforceable master netting arrangements or similar agreements, irrespective of whether they are presented net in the balance sheet, is required to be disclosed. The ASU impacts disclosures only and will not require any changes to financial statement presentation. The Company will present the new disclosures retrospectively beginning in the first quarter of fiscal year 2014.

In February 2013, the FASB issued ASU No. 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income.” This ASU amends Accounting Standards Codification (ASC) Topic 220, “Comprehensive Income,” by requiring entities to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to provide information on significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income, but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. The Company will present the new disclosures prospectively beginning in the first quarter of fiscal year 2014.

2.     ACQUISITION OF MGE

Effective September 1, 2013, Laclede Group completed the purchase of substantially all of the assets and liabilities of Missouri Gas Energy (MGE), a utility engaged in the distribution of natural gas on a regulated basis in western Missouri, from Southern Union Company (SUG), an affiliate of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. The purchase was completed pursuant to the purchase agreement dated December 14, 2012. Under the terms of the purchase agreement, Laclede Group acquired MGE for a purchase price of $975 million. The acquisition was supported through a combination of the issuance of 10.0 million shares of Laclede Group common stock, completed on May 29, 2013, the issuance by Laclede Gas of $450.0 million of first mortgage bonds, completed on August 13, 2013, short-term borrowings, and available cash.

The acquisition was accounted for under the acquisition method of accounting in accordance with ASC 805 (“Topic 805”), “Business Combinations.” Accordingly, goodwill was measured as the excess of the acquisition-date fair value of the consideration transferred over the amount of acquisition-date identifiable assets acquired net of assumed liabilities. Laclede Group recorded $247.1 million of goodwill as an asset in the consolidated balance sheet, which has been assigned to the Company’s Gas Utility segment.

As part of the MGE acquisition, Laclede Gas has estimated the asset retirement obligation of MGE’s long-lived assets as of the acquisition date. This allocation of asset retirement obligations is preliminary and will be finalized upon completion of a detailed fair value analysis that is being performed by the Company in the first quarter of fiscal 2014.

Under Topic 805, merger-related transaction costs (such as advisory, legal, valuation and other professional fees) are not included as components of consideration transferred but are accounted for as expenses in the periods in which the costs are incurred. During the years ended September 30, 2013 and 2012, Laclede Group incurred $17.0 million and $0.2 million, respectively, of third party pre-tax expenses associated with the transaction. These expenses are included in the Statement of Consolidated Income, with $15.1 million included in Other Operating Expenses and $1.9 million included in Interest on Long-term Debt.

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On November 13, 2013, in accordance with Section 3.2 of the purchase agreement for MGE, the Utility provided to SUG a reconciliation of certain balance sheet accounts as of August 31, 2013, the date immediately prior to the closing of the acquisition to the initial valuation date of September 30, 2012. The resulting difference adjusts for changes in the actual net assets transferred to the Utility at closing from the level at September 30, 2012. Section 3.2 also contains a process to resolve any disagreements among the parties, and the Utility plans to adjust cash and goodwill for any change as a result of this process upon final settlement, which is anticipated to be in the first quarter of fiscal 2014.

The amount of revenue and earnings of MGE included in our Statements of Consolidated Income subsequent to the September 1, 2013 acquisition date are as follows:

(Thousands, Except Per Share Amounts)	September 1, 2013 - September 30, 2013
Total net revenues	$	21,985
Net Income	1,795
Earnings/(loss) per share:
Basic	$	0.07
Diluted	$	0.07

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The following table summarizes the preliminary fair value of assets acquired and liabilities assumed at the date of the acquisition:

(Thousands)
Assets:
Utility plant	$	671,793
Non-utility property	238
Other investments	3,096
Goodwill	247,078
Other Property and Investments	922,205
Accounts receivable:
Utility	19,963
Other	6,119
Delayed customer billings	10,701
Inventories:
Natural gas stored underground	58,679
Materials and supplies at average cost	3,988
Prepayments and other	487
Total Current Assets	99,937
Deferred Charges:
Regulatory assets	84,014
Other	4,928
Total Deferred Charges	88,942
Total Assets Acquired	$	1,111,084
Liabilities:
Accounts payable	$	20,154
Wages and compensation accrued	5,088
Customer deposits	8,362
Interest accrued	183
Taxes accrued	17,197
Other	12,620
Total Current Liabilities	63,604
Pension and postretirement benefit costs	24,466
Asset retirement obligations	32,056
Regulatory liabilities	2,249
Other	13,709
Total Deferred Credits and Other Liabilities	72,480
Total Liabilities Assumed	$	136,084
Net Assets Acquired	$	975,000

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The following unaudited pro forma financial information presents the combined results of operations as if the acquisition had occurred on October 1, 2011. The pro forma financial information does not reflect the costs of any integration activities. The pro forma results include estimates and assumptions, which management believes are reasonable. The unaudited pro forma financial information below is not necessarily indicative of either future results of operations or results that might have been achieved had MGE been part of the Utility as of the beginning of fiscal year 2012.

	Twelve Months Ended September 30,
(Thousands, Except Per Share Amounts)	2013		2012
Total net revenues	$	1,518,201	$	1,581,425
Net Income	83,642		81,722
Earnings per share:
Basic	$	2.57	$	2.52
Diluted	$	2.56	$	2.51

3.     PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS

This footnote includes all pension plans of the Company whether historical plans or those acquired as part of the purchase of certain assets and liabilities of MGE on September 1, 2013. The net pension and postretirement obligations were remeasured at that time as well as at the fiscal year end.

Pension Plans

The Utility has non-contributory, defined benefit, trusteed forms of pension plans covering the majority of its employees. Plan assets consist primarily of corporate and U.S. government obligations and a growth segment consisting of exposure to equity markets, commodities, real estate and inflation-indexed securities, achieved through derivative instruments and investments in diversified mutual funds.

Pension costs in 2013, 2012, and 2011 amounted to $17.5 million, $20.1 million, and $14.3 million, respectively, including amounts charged to construction.

The net periodic pension costs include the following components:

(Thousands)	2013			2012			2011
Service cost – benefits earned during the period	$	9,209		$	9,203		$	9,553
Interest cost on projected benefit obligation	16,959			19,358			18,819
Expected return on plan assets	(19,358		)	(19,595		)	(18,849		)
Amortization of prior service cost	544			592			642
Amortization of actuarial loss	10,724			9,040			10,228
Loss on lump-sum settlements	26,996			20,051			943
Sub-total	45,074			38,649			21,336
Regulatory adjustment	(27,532		)	(18,579		)	(7,066		)
Net pension cost	$	17,542		$	20,070		$	14,270

Other changes in plan assets and pension benefit obligations recognized in other comprehensive income include the following:

(Thousands)	2013			2012			2011
Current year actuarial loss (gain)	$	17,030		$	32,884		$	(13,485	)
Amortization of actuarial loss	(10,724		)	(29,091		)	(11,171		)
Acceleration of loss recognized due to settlement	(26,996		)	—			—
Amortization of prior service cost	(544		)	(592		)	(642		)
Sub-total	(21,234		)	3,201			(25,298		)
Regulatory adjustment	21,159			(3,510		)	24,533
Total recognized in other comprehensive income	$	(75	)	$	(309	)	$	(765	)

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Pursuant to the provisions of the Utility pension plans, pension obligations may be satisfied by lump-sum cash payments. Pursuant to a MoPSC Order, lump-sum payments are recognized as settlements (which can result in gains or losses) only if the total of such payments exceeds 100% of the sum of service and interest costs. Lump-sum payments recognized as settlements during fiscal year 2013, 2012, and 2011 were $79.5 million, $60.1 million, and $2.3 million, respectively.

Pursuant to a MoPSC Order, the return on plan assets is based on the market-related value of plan assets implemented prospectively over a four-year period. Gains or losses not yet includible in pension cost are amortized only to the extent that such gain or loss exceeds 10% of the greater of the projected benefit obligation or the market-related value of plan assets. Such excess is amortized over the average remaining service life of active participants. The recovery in rates for Laclede Gas' qualified pension plan is based on an annual allowance of $4.8 million effective August 1, 2007 and $15.5 million effective January 1, 2011. The recovery in rates for MGE's qualified pension plan is based on an annual allowance of $10.0 million effective February 20, 2010. The difference between these amounts and pension expense as calculated pursuant to the above and that otherwise would be included in the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income is deferred as a regulatory asset or regulatory liability.

The following table sets forth the reconciliation of the beginning and ending balances of the pension benefit obligation at September 30:

(Thousands)	2013			2012
Benefit obligation, beginning of year	$	412,171		$	384,163
Service cost	9,209			9,203
Interest cost	16,959			19,358
Actuarial (gain) loss	(23,921		)	52,161
MGE acquisition	151,424			—
Settlement loss	24,999			14,348
Gross benefits paid *	(87,023		)	(67,062		)
Benefit obligation, end of year	$	503,818		$	412,171
Accumulated benefit obligation, end of year	$	444,129		$	353,061

* Includes $79,484 and $60,085 lump-sum payments recognized as settlements in fiscal years 2013 and 2012, respectively.

The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets at September 30:

(Thousands)	2013			2012
Fair value of plan assets, beginning of year	$	274,130		$	247,959
Actual return on plan assets	3,387			53,220
Employer contributions	27,991			40,013
MGE acquisition	126,958			—
Gross benefits paid *	(87,023		)	(67,062		)
Fair value of plan assets, end of year	$	345,443		$	274,130
Funded status of plans, end of year	$	(158,375	)	$	(138,041	)

*  Includes $79,484 and $60,085 lump-sum payments recognized as settlements in fiscal years 2013 and 2012, respectively.

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The following table sets forth the amounts recognized in the Consolidated Balance Sheets at September 30:

(Thousands)	2013			2012
Current liabilities	$	(442	)	$	(468	)
Noncurrent liabilities	(157,933		)	(137,573		)
Total	$	(158,375	)	$	(138,041	)
Pre-tax amounts recognized in accumulated other comprehensive income not yet recognized as components of net periodic pension cost consist of:
Net actuarial loss	$	115,775		$	136,464
Prior service costs	4,467			5,011
Sub-total	120,242			141,475
Adjustments for amounts included in Regulatory Assets	(116,686		)	(137,845		)
Total	$	3,556		$	3,630

At September 30, 2013, the following pre-tax amounts are expected to be amortized from accumulated other comprehensive income into net periodic pension cost during fiscal year 2014:

(Thousands)	2014
Amortization of net actuarial loss	$	7,088
Amortization of prior service cost	497
Sub-total	7,585
Regulatory adjustment	(7,196		)
Total	$	389

The assumptions used to calculate net periodic pension costs are as follows:

	2013	2012	2011
Weighted average discount rate*	3.95%	5.10%	4.75%
Weighted average rate of future compensation increase	3.00%	3.00%	3.00%
Expected long-term rate of return on plan assets	7.75%	7.75%	8.00%

* Weighted average discount rate assumption for the MGE pension plan is 5.05%.

The weighted average discount rate is based on long-term, high quality bond indices at the measurement date. The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Assumed projected rates of return for each asset class were selected after analyzing historical experience and future expectations of the returns. The overall expected rate of return for the portfolio was developed based on the target allocation for each class. The expected return is a long-term assumption that generally does not change annually. However, in 2012 and 2011, the expected return assumption was adjusted to reflect capital market volatility in recent years.

The assumptions used to calculate the benefit obligations are as follows:

	2013	2012
Weighted average discount rate *	4.70%	3.95%
Weighted average rate of future compensation increase	3.00%	3.00%

* Weighted average discount rate assumption for the MGE pension plan is 5.00%.

Following are the projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for plans that have a projected benefit obligation and an accumulated benefit obligation in excess of plan assets:

(Thousands)	2013		2012
Projected benefit obligation	$	503,818	$	412,171
Accumulated benefit obligation	444,129		353,061
Fair value of plan assets	345,443		274,130

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Following are the targeted and actual plan assets by category as of September 30 of each year:

	Target		2013 Actual		2012 Actual
Growth Strategy
Equity Markets	42.5	%	45.9	%	37.3	%
Commodities	2.5	%	1.6	%	2.2	%
Real Estate	2.5	%	3.0	%	2.2	%
Inflation-Indexed Securities	2.5	%	1.4	%	2.2	%
Debt Securities	50.0	%	43.3	%	41.1	%
Other*	—	%	4.8	%	15.0	%
Total	100.0	%	100.0	%	100.0	%

* Other investments in 2013 consist of cash equivalents. The relatively large cash position at September 30, 2012 was

due to a transition taking place between investment managers and was invested in debt securities in a matter of days.

The Utility's investment policy is designed to maximize, to the extent possible, the funded status of the plan over time, and minimize volatility of funding and costs. The policy seeks to maximize investment returns consistent with these objectives and he Utility’s tolerance for risk. The duration of plan liabilities and the impact of potential changes in asset values on the funded status are fundamental considerations in the selection of plan assets. Outside investment management specialists are utilized in each asset class. Such specialists are provided with guidelines, where appropriate, designed to ensure that the investment portfolio is managed in accordance with the policy. The policy seeks to avoid significant concentrations of risk by investing in a diversified portfolio of assets. Investments in corporate, U.S. government and agencies, and, to a lesser extent, international debt securities seek to provide duration matching with plan liabilities, and typically have investment grade ratings and reflect allocations across various entities and industries. During 2012, exposures to additional asset types were added to the target portfolio: commodities, real estate and inflation-indexed securities. The investment policy permits the use of derivative instruments, which may be used to achieve the desired market exposure of an index, adjust portfolio duration, or rebalance the total portfolio to the target asset allocation. The Growth Strategy utilizes a combination of derivative instruments and debt securities to achieve diversified exposure to equity and other markets while generating returns from the fixed-income investments and providing further duration matching with the liabilities. The assets acquired with the MGE pension plan include diversified funds that are equity-oriented and larger holdings of cash. These are being evaluated along with the liabilities of the MGE plan. Performance and compliance with the guidelines is regularly monitored. The policy calls for increased allocations to debt securities as the funded status improves.

Following are expected pension benefit payments for the succeeding five fiscal years, and in aggregate for the five years thereafter:

(Millions)	Pensions from Qualified Trust		Pensions from Laclede Gas Funds
2014	$	22.9	$	0.4
2015	25.3		0.5
2016	27.2		0.5
2017	30.8		0.6
2018	34.2		0.6
2019 – 2023	227.2		4.5

The funding policy of the Utility is to contribute an amount not less than the minimum required by government funding standards, nor more than the maximum deductible amount for federal income tax purposes. Contributions to the pension plans in fiscal year 2014 are anticipated to be $24.0 million into the qualified trusts, and $0.4 million into the non-qualified plans.

Postretirement Benefits

The Utility provides certain life insurance benefits at retirement. Medical insurance is available after early retirement until age 65. The transition obligation not yet includible in postretirement benefit cost is being amortized over 20 years. Postretirement benefit costs in 2013, 2012, and 2011 amounted to $9.5 million, $9.5 million, and $9.1 million, respectively, including amounts charged to construction.

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Net periodic postretirement benefit costs consisted of the following components:

(Thousands)	2013			2012			2011
Service cost – benefits earned during the period	$	10,162		$	8,060		$	7,676
Interest cost on accumulated postretirement benefit obligation	5,234			5,521			4,843
Expected return on plan assets	(4,447		)	(3,965		)	(3,646		)
Amortization of transition obligation	93			136			136
Amortization of prior service credit	3			(2,072		)	(2,328		)
Amortization of actuarial loss	5,300			4,261			4,443
Sub-total	16,345			11,941			11,124
Regulatory adjustment	(6,821		)	(2,417		)	(2,071		)
Net postretirement benefit cost	$	9,524		$	9,524		$	9,053

Other changes in plan assets and postretirement benefit obligations recognized in other comprehensive income include the following:

(Thousands)	2013			2012			2011
Current year actuarial loss	$	16,300		$	10,138		$	1,696
Amortization of actuarial loss	(5,300		)	(4,261		)	(4,443		)
Amortization of prior service credit	(3		)	2,072			2,328
Amortization of transition obligation	(93		)	(136		)	(136		)
Sub-total	10,904			7,813			(555		)
Regulatory adjustment	(10,904		)	(7,813		)	555
Total recognized in other comprehensive income	$	—		$	—		$	—

Pursuant to a MoPSC Order, the return on plan assets is based on the market-related value of plan assets implemented prospectively over a four-year period. Gains and losses not yet includible in postretirement benefit cost are amortized only to the extent that such gain or loss exceeds 10% of the greater of the accumulated postretirement benefit obligation or the market-related value of plan assets. Such excess is amortized over the average remaining service life of active participants. The recovery in rates for Laclede Gas' postretirement benefit plans is based on an annual allowance of $7.6 million effective August 1, 2007 and $9.5 million effective January 1, 2011. The difference between these amounts and postretirement benefit cost based on the above and that otherwise would be included in the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income is deferred as a regulatory asset or regulatory liability.

The following table sets forth the reconciliation of the beginning and ending balances of the postretirement benefit obligation at September 30:

(Thousands)	2013			2012
Benefit obligation, beginning of year	$	127,217		$	103,991
Service cost	10,162			8,060
Interest cost	5,234			5,521
Actuarial loss (gain)	17,514			15,895
MGE acquisition	28,444			—
Gross benefits paid	(8,449		)	(6,250		)
Benefit obligation, end of year	$	180,122		$	127,217

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The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets at September 30:

(Thousands)	2013			2012
Fair value of plan assets at beginning of year	$	67,442		$	51,744
Actual return on plan assets	5,660			9,722
Employer contributions	16,596			12,226
MGE acquisition	30,396			—
Gross benefits paid	(8,449		)	(6,250		)
Fair value of plan assets, end of year	$	111,645		$	67,442
Funded status of plans, end of year	$	(68,477	)	$	(59,775	)

The following table sets forth the amounts recognized in the Consolidated Balance Sheets at September 30:

(Thousands)	2013			2012
Noncurrent assets	$	2,543		$	—
Current liabilities	(300		)	(790		)
Noncurrent liabilities	(70,720		)	(58,985		)
Total	$	(68,477	)	$	(59,775	)
Pre-tax amounts recognized in accumulated other comprehensive income not yet recognized as components of net periodic postretirement benefit cost consist of:
Net actuarial loss	$	63,573		$	52,573
Prior service credit	(27		)	(24		)
Transition obligation	—			93
Sub-total	63,546			52,642
Adjustments for amounts included in Regulatory Assets	(63,546		)	(52,642		)
Total	$	—		$	—

At September 30, 2013, the following pre-tax amounts are expected to be amortized from accumulated other comprehensive income into net periodic postretirement benefit cost during fiscal year 2014:

(Thousands)
Amortization of net actuarial loss	$	6,021
Amortization of prior service cost	(4		)
Sub-total	6,017
Regulatory adjustment	(6,017		)
Total	$	—

The assumptions used to calculate net periodic postretirement benefit costs are as follows:

	2013		2012		2011
Weighted average discount rate *	3.80	%	5.05	%	4.70	%
Weighted average rate of future compensation increase	3.00	%	3.00	%	3.00	%
Expected long-term rate of return on plan assets **	7.75	%	7.75	%	8.00	%

* Weighted average discount rate assumption for the MGE postretirement plan is 5.05%.

**    Expected long-term rate of return on plan assets assumption for the MGE postretirement plan is 5.75%.

The weighted average discount rate is based on long-term, high quality bond indices at the measurement date. The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Assumed projected rates of return for each asset class were selected after analyzing historical experience and future expectations of the returns. The overall expected rate of return for the portfolio was developed based on the target allocation for each class. The expected return is a long-term assumption that generally does not change annually. However, in 2012 and 2011, the expected return assumption was adjusted to reflect capital market volatility in recent years.

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The assumptions used to calculate the accumulated postretirement benefit obligations are as follows:

	2013	2012
Weighted average discount rate *	4.60%	3.80%
Weighted average rate of future compensation increase	3.00%	3.00%

* Weighted average discount rate assumption for the MGE postretirement plan is 4.95%.

The assumed medical cost trend rates at September 30 are as follows:

	2013	2012
Medical cost trend assumed for next year	7.50%	7.00%
Rate to which the medical cost trend rate is assumed to decline (the ultimate medical cost trend rate)	5.00%	5.00%
Year the rate reaches the ultimate trend	2020	2017

The following table presents the effect of an assumed 1% change in the assumed medical cost trend rate:

(Thousands)	1% Increase		1% Decrease
Effect on net periodic postretirement benefit cost	$	1,520	$	(1,390	)
Effect on accumulated postretirement benefit obligation	7,060		(6,580		)

Following are the targeted and actual plan assets by category as of September 30 of each year:

	Target		2013 Actual		2012 Actual
Equity Securities	60.0	%	59.0	%	59.0	%
Debt Securities	40.0	%	39.0	%	39.0	%
Other	—	%	2.0	%	2.0	%
Total	100.0	%	100.0	%	100.0	%

Missouri state law provides for the recovery in rates of costs accrued pursuant to GAAP provided that such costs are funded through an independent, external funding mechanism. The Utility established Voluntary Employees’ Beneficiary Association and Rabbi trusts as its external funding mechanisms. The Utility’s investment policy seeks to maximize investment returns consistent with the Utility's tolerance for risk. Outside investment management specialists are utilized in each asset class. Such specialists are provided with guidelines, where appropriate, designed to ensure that the investment portfolio is managed in accordance with policy. Performance and compliance with the guidelines is regularly monitored. The Utility's current investment policy targets an asset allocation of 60% to equity securities and 40% to debt securities, excluding cash held in short-term debt securities for the purpose of making benefit payments. The Utility currently invests in a mutual fund which is rebalanced on an ongoing basis to the target allocation. The mutual fund is diversified across U.S. stock and bond markets.

Following are expected postretirement benefit payments for the succeeding five fiscal years, and in aggregate for the five years thereafter:

(Millions)	Benefits Paid from Qualified Trust		Benefits Paid from Laclede Gas Funds
2014	$	9.5	$	0.3
2015	9.9		0.3
2016	10.7		0.3
2017	11.7		0.4
2018	12.8		0.4
2019 – 2023	84.1		2.2

The Utility's funding policy is to contribute amounts to the trusts equal to the periodic benefit cost calculated pursuant to GAAP as recovered in rates. Contributions to the postretirement plans in fiscal year 2014 are anticipated to be $19.2 million to the qualified trusts, and $0.3 million paid directly to participants from Laclede Gas funds.

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Other Plans

The Utility sponsors 401(k) plans that cover substantially all employees. The plans allow employees to contribute a portion of their base pay in accordance with specific guidelines. The Utility provides a match of such contributions within specific limits. The cost of the defined contribution plans of the Utility amounted to $5.0 million, $3.8 million, and $3.6 million for fiscal years 2013, 2012, and 2011, respectively.

Fair Value Measurements of Pension and Other Postretirement Plan Assets

The table below categorizes the fair value measurements of the Utility's’ pension plan assets:

(Thousands)	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total
As of September 30, 2013
Cash and cash equivalents	$	18,177	$	—		$	—	$	18,177
Stock/Bond mutual fund	—		115,817			—		115,817
Debt Securities
U.S. bond mutual funds	17,682		—			—		17,682
U.S. government	—		55,743			—		55,743
U.S. corporate	—		110,925			—		110,925
U.S. municipal	—		6,799			—		6,799
International	—		21,594			—		21,594
Derivative instruments (a)	—		(1,294		)	—		(1,294		)
Total	$	35,859	$	309,584		$	—	$	345,443
As of September 30, 2012
Cash and cash equivalents	$	57,614	$	—		$	—	$	57,614
Debt Securities
U.S. bond mutual funds	36,767		—			—		36,767
U.S. government	—		57,925			—		57,925
U.S. corporate	—		93,169			—		93,169
U.S. municipal	—		9,493			—		9,493
International	—		18,885			—		18,885
Derivative instruments (b)	—		277			—		277
Total	$	94,381	$	179,749		$	—	$	274,130

(a) Derivative assets of $4,186 net of cash margin payable of $5,480.

(b) Derivative assets of $3,027 net of cash margin payable of $2,750.

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The table below categorizes the fair value measurements of The Utility's postretirement plan assets:

(Thousands)	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
As of September 30, 2013
Cash and cash equivalents	$	1,411	$	—	$	—	$	1,411
U.S. stock/bond mutual fund	110,234		—		—		110,234
Total	$	111,645	$	—	$	—	$	111,645
As of September 30, 2012
Cash and cash equivalents	$	1,106	$	—	$	—	$	1,106
U.S. stock/bond mutual fund	66,336		—		—		66,336
Total	$	67,442	$	—	$	—	$	67,442

Cash and cash equivalents include money market mutual funds valued based on quoted market prices. Fair values of derivative instruments are calculated by investment managers who use valuation models that incorporate observable market inputs. Debt securities are valued based on broker/dealer quotations or by using observable market inputs. The stock and bond mutual funds are valued at the quoted market price of the identical securities.

4.     STOCK-BASED COMPENSATION

The Laclede Group 2006 Equity Incentive Plan (the 2006 Plan) was amended and approved at the annual meeting of shareholders of Laclede Group on January 26, 2012, as discussed below. The purpose of the 2006 Plan is to encourage directors, officers, and employees of the Company and its subsidiaries to contribute to the Company’s success and align their interests with that of shareholders. To accomplish this purpose, the Compensation Committee (Committee) of the Board of Directors may grant awards under the 2006 Plan that may be earned by achieving performance objectives and/or other criteria as determined by the Committee. Under the terms of the 2006 Plan, officers and employees of the Company and its subsidiaries, as determined by the Committee, are eligible to be selected for awards. Effective February 1, 2012, members of the Company’s Board of Directors are also eligible to participate in the 2006 Plan and no additional awards will be granted under the Restricted Stock Plan for Non-Employee Directors. The 2006 Plan provides for restricted stock, restricted stock units, qualified and non-qualified stock options, stock appreciation rights, and performance shares payable in stock, cash, or a combination of both. The 2006 Plan generally provides a minimum vesting period of at least three years for each type of award, with pro rata vesting permitted during the minimum three year vesting period. The maximum number of shares reserved for issuance under the 2006 Plan is 1,250,000. The 2006 Plan replaced the Laclede Group Equity Incentive Plan (the 2003 Plan). Shares reserved under the 2003 Plan, other than those needed for currently outstanding awards, were canceled upon shareholder approval of the 2006 Plan.

The Company issues new shares to satisfy employee restricted stock awards and stock option exercises. Prior to February 1, 2012, shares for non-employee directors were purchased on the open market.

Restricted Stock Awards

During fiscal year 2013, the Company granted 108,419 performance-contingent restricted share units to executive officers and key employees at a weighted average grant date fair value of $34.49 per share. This number represents the maximum shares that can be earned pursuant to the terms of the awards. The share units have a performance period ending September 30, 2014. While the participants have no interim voting rights on these share units, dividends accrue during the performance period and are paid to the participants upon vesting, but are subject to forfeiture if the underlying share units do not vest. The number of share units that will ultimately vest is dependent upon the attainment of certain levels of earnings and other strategic goals, as well as the Company’s level of total shareholder return (TSR) during the performance period relative to a comparator group of companies. This TSR provision is considered a market condition under GAAP and is discussed further below.

The weighted average grant date fair value of performance-contingent restricted shares and share units granted during fiscal years 2012 and 2011 was $36.55 and $30.68 per share, respectively.

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Fiscal year 2013 activity of restricted stock and restricted stock units subject to performance and/or market conditions is presented below:

	Shares/ Units		Weighted Average Grant Date Fair Value
Nonvested at September 30, 2012	232,403		$	30.89
Granted (maximum shares that can be earned)	108,419		$	34.49
Vested	(47,436	)	$	27.61
Forfeited	(51,118	)	$	26.11
Nonvested at September 30, 2013	242,268		$	34.15

During fiscal year 2013, the Company granted 43,924 shares of time-vested restricted stock to executive officers and key employees at a weighted average grant date fair value of $40.03 per share. These shares were awarded on October 1, 2012 and December 3, 2012 and vest October 1, 2014 and December 1, 2015, respectively. In the interim, participants receive full voting rights and dividends, which are not subject to forfeiture. The weighted average grant date fair value of time-vested restricted stock and restricted stock units awarded to employees during fiscal year 2012 and 2011 was $39.72 and $35.93 per share, respectively.

During fiscal year 2013, the Company granted 15,200 shares of time-vested restricted stock to non-employee directors at a weighted average grant date fair value of $39.92 per share. The weighted average grant date fair value of restricted stock awarded to non-employee directors during fiscal years 2012 and 2011 was $41.36 and $39.48 per share, respectively. These shares were granted under the Restricted Stock Plan for Non-Employee Directors and vest depending on the participant’s age upon entering the plan and years of service as a director. The plan’s trustee acquired the shares for the awards in the open market and holds the shares as trustee for the benefit of the non-employee directors until the restrictions expire. In the interim, the participants receive full dividends and voting rights. As discussed above, effective February 1, 2012, any awards to non-employee directors will be made pursuant under The Laclede Group 2006 Equity Incentive Plan.

Time-vested restricted stock and stock unit activity for fiscal year 2013 is presented below:

	Shares/ Units		Weighted Average Grant Date Fair Value
Nonvested at September 30, 2012	115,115		$	36.54
Granted	59,124		$	40.00
Vested	(43,785	)	$	34.95
Forfeited	(11,050	)	$	38.61
Nonvested at September 30, 2013	119,404		$	38.64

During fiscal year 2013, 91,221 shares of restricted stock and stock units (performance-contingent and time-vested), awarded on November 4, 2008, December 1, 2009, January 4, 2010, May 3, 2010, and July 1, 2010 vested. The Company withheld 23,311 of the vested shares at a weighted average price of $39.96 per share pursuant to elections by employees to satisfy tax withholding obligations. During fiscal year 2012, 90,839 shares of restricted stock (performance-contingent and time-vested), awarded on February 14, 2008, November 5, 2008, and March 31, 2009, vested. The Company withheld 30,052 of these vested shares at a weighted average price of $40.02 per share pursuant to elections by employees to satisfy tax withholding obligations. During fiscal year 2011, 94,500 shares of performance-contingent restricted stock, awarded on December 5, 2007, vested. The Company withheld 32,373 of these vested shares at a weighted average price of $35.90 per share pursuant to elections by employees to satisfy tax withholding obligations.

The total fair value of restricted stock (performance-contingent and time-vested) vested during fiscal years 2013, 2012, and 2011 was $3.8 million, $4.2 million, and $3.6 million, respectively, and the related actual tax benefit realized was $1.4 million, $1.6 million, and $1.4 million, respectively.

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Stock Option Awards

No stock options were granted during fiscal years 2013, 2012, and 2011. Stock option activity for fiscal year 2013 is presented below:

	Stock Options		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (Years)	Aggregate Intrinsic Value ($000)
Outstanding at September 30, 2012	214,000		$	31.02
Granted	—		$	—
Exercised	(80,500	)	$	29.61
Forfeited	—		$	—
Expired	—		$	—
Outstanding at September 30, 2013	133,500		$	31.87	2.8	$	1,752
Fully Vested and Expected to Vest at September 30, 2013	133,500		$	31.87	2.8	$	1,752
Exercisable at September 30, 2013	133,500		$	31.87	2.8	$	1,752

Exercise prices of options outstanding at September 30, 2013 range from $28.85 to $34.95. During fiscal year 2013, cash received from the exercise of stock options was $2.7 million, the intrinsic value of the options exercised was $1.0 million and the related actual tax benefit realized was $0.4 million. During fiscal year 2012, cash received from the exercise of stock options was $2.5 million, the intrinsic value of the options exercised was $1.0 million and the related actual tax benefit realized was $0.4 million. During fiscal year 2011, cash received from the exercise of stock options was $0.9 million, the intrinsic value of the options exercised was $0.2 million and the related actual tax benefit realized was $0.1 million.

The closing price of the Company’s common stock was $45.00 at September 30, 2013.

Equity Compensation Costs

Compensation cost for performance-contingent restricted stock and stock unit awards is based upon the probable outcome of the performance conditions. For shares or units that do not vest or that are not expected to vest due to the outcome of the performance conditions (excluding market conditions), no compensation cost is recognized and any previously recognized compensation cost is reversed.

The fair value of awards of performance-contingent and time-vested restricted stock and restricted stock units, not subject to the TSR provision, is estimated using the closing price of the Company’s stock on the date of the grant. For those awards that do not pay dividends during the vesting period, the estimate of fair value is reduced by the present value of the dividends expected to be paid on the Company’s common stock during the performance period, discounted using an appropriate U.S. Treasury yield. For shares subject to the TSR provision, the estimated impact of this market condition is reflected in the grant date fair value per share of the awards. Accordingly, compensation cost is not reversed to reflect any actual reductions in the awards that may result from the TSR provision. However, if the Company’s TSR during the performance period ranks below the level specified in the award agreements, relative to a comparator group of companies, and the Committee elects not to reduce the award (or reduce by a lesser amount), this election would be accounted for as a modification of the original award and additional compensation cost would be recognized at that time. The grant date fair value of the awards subject to the TSR provision awarded during fiscal years 2013, 2012, and 2011 was valued by a Monte Carlo simulation model that assessed the probabilities of various TSR outcomes. The significant assumptions used in the Monte Carlo simulations are as follows:

	2013		2012		2011
Risk free interest rate	0.32	%	0.39	%	0.79	%
Expected dividend yield of stock	—		—		—
Expected volatility of stock	19.60	%	23.21	%	33.42	%
Vesting period	2.8 years		2.8 years		2.8 years

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The risk free interest rate was based on the yield on U.S. Treasury securities matching the vesting period. The expected volatility is based on the historical volatility of the Company’s stock. Volatility assumptions were also made for each of the companies included in the comparator group. The vesting period is equal to the performance period set forth in the terms of the award.

The amounts of compensation cost recognized for share-based compensation arrangements are presented below:

(Thousands)	2013			2012			2011
Total equity compensation cost	$	4,453		$	2,707		$	3,980
Compensation cost capitalized	(1,366		)	(808		)	(924		)
Compensation cost recognized in net income	3,087			1,899			3,056
Income tax benefit recognized in net income	(1,182		)	(733		)	(1,179		)
Compensation cost recognized in net income, net of income tax	1,905			1,166			1,877

As of September 30, 2013, there was $4.9 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements. That cost is expected to be recognized over a weighted average period of 2.0 years.

5.     EARNINGS PER COMMON SHARE    

(Thousands, Except Per Share Amounts)	2013		2012		2011
Basic EPS:
Net Income	$	52,758	$	62,640	$	63,825
Less: Income allocated to participating securities	245		340		497
Net Income Available  to Common Shareholders	$	52,513	$	62,300	$	63,328
Weighted Average Shares Outstanding	25,875		22,262		22,099
Earnings Per Share of Common Stock	$	2.03	$	2.80	$	2.87
Diluted EPS:
Net Income	$	52,758	$	62,640	$	63,825
Less: Income allocated to participating securities	245		340		496
Net Income Available to Common Shareholders	$	52,513	$	62,300	$	63,329
Weighted Average Shares Outstanding	25,875		22,262		22,099
Dilutive Effect of Stock Options, Restricted Stock, and Restricted Stock Units	77		78		72
Weighted Average Diluted Shares	25,952		22,340		22,171
Earnings Per Share of Common Stock	$	2.02	$	2.79	$	2.86
Outstanding Shares Excluded from the Calculation of Diluted EPS Attributable to:
Antidilutive stock options	—		—		—
Restricted stock and stock units subject to performance and/or market conditions	188		195		203
Total	188		195		203

6.     STOCKHOLDER'S EQUITY

Total shares of common stock outstanding were 32.70 million and 22.54 million at September 30, 2013 and 2012, respectively.

Common stock and paid-in capital increased $435.8 million in fiscal year 2013. The issuance of 44,074 common shares under the Dividend Reinvestment and Stock Purchase Plan increased common stock and paid-in capital by $1.8 million. The remaining $434.0 million increase was due to the issuance of 10,005,000 shares in May 2013, stock-based compensation costs and the issuance of 108,331 shares of common stock under the Equity Incentive Plan. Common stock and paid-in capital increased $5.0 million in fiscal year 2012. The issuance of 46,107 common shares under the Dividend Reinvestment and Stock Purchase Plan increased common stock and paid-in capital by $1.8 million. The remaining $3.2 million increase was primarily due to stock-based compensation costs and the issuance of 62,590 shares of common stock under the Equity Incentive Plan. Substantially all of the Utility's plant is subject to the liens of its first mortgage bonds. The mortgage contains several restrictions on the Utility's ability to pay cash dividends on its common stock.

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These provisions are applicable regardless of whether the stock is publicly held or, as has been the case since the formation of Laclede Group, held solely by the Utility’s parent company. Under the most restrictive of these provisions, no cash dividend may be declared or paid if, after the dividend, the aggregate net amount spent for all dividends after September 30, 1953, would exceed a maximum amount determined by a formula set out in the mortgage. Under that formula, the maximum amount is the sum of $8 million plus earnings applicable to common stock (adjusted for stock repurchases and issuances) for the period from September 30, 1953, to the last day of the quarter before the declaration or payment date for the dividends. As of September 30, 2013 and 2012, the amount under the mortgage’s formula that was available to pay dividends was $833 million and $355 million, respectively. Thus, all of the Utility’s retained earnings were free from such restrictions as of those dates. The substantial increase in 2013 was primarily due to the issuance of stock to Laclede Group to fund a portion of the MGE acquisition.

Laclede Group has a registration statement on file on Form S-3 for the issuance and sale of up to 285,222 shares of its common stock under its Dividend Reinvestment and Stock Purchase Program. There were 194,246 and 186,919 shares at September 30, 2013 and November 26, 2013, respectively, remaining available for issuance under this Form S-3. The Company filed this Form S-3 on July 29, 2011.

On August 6, 2013, Laclede Group and Laclede Gas filed with the SEC a joint shelf registration statement on Form S-3 for issuance of various types of debt and equity securities, which registration statement will expire August 5, 2016. Bonds totaling $450 million were issued by Laclede Gas from this shelf registration statement on August 13, 2013. The amount, timing, and type of additional financing to be issued under this shelf registration statement will depend on cash requirements and market conditions.

The Utility has authority from the MoPSC to issue up to $518 million in debt securities and preferred stock, including on a private placement basis, as well as to enter into capital leases, issue common stock and receive paid-in capital. This authorization was originally effective through June 30, 2013. In August 2012, the Utility filed a request with the MoPSC to extend this authority for an additional two years, to June 30, 2015. This extension was approved October 24, 2012, to be effective on November 23, 2012. At September 30, 2013, $370.8 million remained under this authorization. The amount, timing, and type of additional financing to be issued will depend on cash requirements and market conditions.

The components of accumulated other comprehensive income (loss), net of income taxes, recognized in the

Consolidated Balance Sheets at September 30 were as follows:

(Thousands)	Net Unrealized Gains (Losses) on Cash Flow Hedges			Defined Benefit Pension and Other Postretirement Benefit Plans			Total
Balance at September 30, 2011	$	320		$	(2,420	)	$	(2,100	)
Current-period change	(2,206		)	190			(2,016		)
Balance at September 30, 2012	(1,886		)	(2,230		)	(4,116		)
Current-period change	3,281			48			3,329
Balance at September 30, 2013	1,395			(2,182		)	(787		)

Income tax expense (benefit) recorded for items of other comprehensive income reported in the Statements of Consolidated Comprehensive Income is calculated by applying statutory federal, state, and local income tax rates applicable to ordinary income. The tax rates applied to individual items of other comprehensive income are similar within each reporting period.

7. LONG-TERM DEBT

Maturities on long-term debt for the five fiscal years subsequent to September 30, 2013 are as follows:

2014	—
2015	—
2016	—
2017	—
2018	$	100	million

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On October 15, 2012, the Utility paid at maturity $25 million principal amount of 6 1/2% first mortgage bonds. This maturity was funded through short-term borrowings. Laclede Group issued $25 million of 3.31%10-year unsecured notes in a private placement on December 14, 2012 and the Utility issued $100 million of first mortgage bonds in a private placement on March 15, 2013, that had been committed to in August 2012. Of this $100 million, $55 million were issued at 3.00% for a 10-year term, maturing in March 2023, and $45 million were issued at 3.40% for a 15-year term, maturing in March 2028. The proceeds were used for the repayment of short-term debt and general corporate purposes. The Utility issued $450 million of first mortgage bonds on August 13, 2013. Of this $450 million, $100 million was issued at 2.00% maturing in August 2018, $250 million was issued at 3.40% maturing in August 2023, and $100 million was issued at 4.625% maturing in August 2043. The proceeds were used to fund a portion of the MGE acquisition.

At September 30, 2013, the Company had fixed-rate long-term debt totaling $915 million. While these long-term debt issues are fixed-rate, they are subject to changes in fair value as market interest rates change. Of the Company’s $915 million in long-term debt, $50 million have no call options, $435 million have make-whole call options, $350 million are callable at par three to six months prior to maturity and $80 million are callable at par beginning in October 2013. None of the debt has any put options.

On August 6, 2013, Laclede Group and Laclede Gas filed with the SEC a joint shelf registration statement on Form S-3 for issuance of various types of debt and equity securities, which expires August 5, 2016. Bonds totaling $450 million were issued by Laclede Gas from this registration statement on August 13, 2013. The amount, timing, and type of additional financing to be issued under these shelf registrations will depend on cash requirements and market conditions.

The Utility has authority from the MoPSC to issue up to $518 million in debt securities and preferred stock, including on a private placement basis, as well as to enter into capital leases, issue common stock and receive paid-in capital. This authorization was originally effective through June 30, 2013. In August 2012, the Utility filed a request with the MoPSC to extend this authority for an additional two years, to June 30, 2015. This extension was approved October 24, 2012, to be effective on November 23, 2012. At November 26, 2013, $370.8 million remained under this authorization. The amount, timing, and type of additional financing to be issued will depend on cash requirements and market conditions.

Substantially all of the Utility plant is subject to the liens of its first mortgage bonds. The mortgage contains several restrictions on the Utility's ability to pay cash dividends on its common stock, which are described more fully in Note 6, Stockholders’ Equity.

At September 30, 2013 and 2012, the Utility had authorized 1,480,000 shares of preferred stock, but none were issued and outstanding.

For information on additional financing commitments, refer to Note 16, Commitments and Contingencies.

8. NOTES PAYABLE AND CREDIT AGREEMENTS

The Company’s short-term borrowing requirements typically peak during the colder months. These short-term cash requirements can be met through the sale of commercial paper supported by lines of credit with banks or through direct use of the lines of credit. On September 3, 2013, the Utility entered into a new syndicated line of credit for $450 million with nine banks, which will expire in September 2018. The largest portion provided by a single bank is 15.6%. The previous syndicated line of credit agreement was terminated at that time.

The Utility’s line of credit includes a covenant limiting total debt, including short-term debt, to no more than 70% of total capitalization. On September 30, 2013, total debt was 48% of total capitalization.

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Information about the Laclede Group’s short-term borrowings (excluding intercompany borrowings) during the 12 months ended September 30, and as of September 30, is presented below for 2013 and 2012:

	Commercial Paper Borrowings
Twelve Months Ended September 30, 2013
Weighted average borrowings outstanding	$34.2 million
Weighted average interest rate	0.3%
Range of borrowings outstanding	$0 – $99.4 million
As of September 30, 2013
Borrowings outstanding at end of period	$74.0 million
Weighted average interest rate	0.3%
Twelve Months Ended September 30, 2012
Weighted average borrowings outstanding	$43.8 million
Weighted average interest rate	0.3%
Range of borrowings outstanding	$0 – $133.5 million
As of September 30, 2012
Borrowings outstanding at end of period	$40.1 million
Weighted average interest rate	0.2%

Short-term cash requirements outside of the Utility have generally been met with internally-generated funds. On September 3, 2013, Laclede Group entered into a new $150 million in a syndicated line of credit, which expires September 2018. The previous syndicated line of credit agreement was terminated at that time. Laclede Group's line of credit has covenants limiting the total debt of the consolidated Laclede Group to no more than 70% of the Company’s total capitalization. This ratio stood at 49% on September 30, 2013. Occasionally, Laclede Group’s lines may be used to provide for the funding needs of various subsidiaries. There were no borrowings under Laclede Group’s lines during fiscal years 2013 and 2012.

9. FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying amounts and estimated fair values of financial instruments not measured at fair value on a recurring basis at September 30, 2013 and 2012 are as follows:

					Classification of Estimated Fair Value
(Thousands)	Carrying Amount		Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
As of September 30, 2013
Cash and cash equivalents	$	52,981	$	52,981	$	52,824	$	157	$	—
Short-term debt	74,000		74,000		—		74,000		—
Long-term debt, including current portion	912,712		954,126		—		954,126		—
As of September 30, 2012
Cash and cash equivalents	$	27,457	$	27,457	$	17,380	$	10,077	$	—
Short-term debt	40,100		40,100		—		40,100		—
Long-term debt, including current portion	364,416		452,768		—		452,768		—

The carrying amounts for cash and cash equivalents and short-term debt approximate fair value due to the short maturity of these instruments. The fair values of long-term debt are estimated based on market prices for similar issues. Refer to Note 10, Fair Value Measurements, for information on financial instruments measured at fair value on a recurring basis.

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10.    FAIR VALUE MEASUREMENTS

The following table categorizes the assets and liabilities in the Consolidated Balance Sheets that are accounted for at fair value on a recurring basis in periods subsequent to initial recognition.

(Thousands)	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Effects of Netting and Cash Margin Receivables /Payables			Total
As of September 30, 2013
Assets
U. S. Stock/Bond Mutual Funds	$	14,500	$	—	$	—	$	—		$	14,500
NYMEX/ICE natural gas contracts	4,333		330		—		(2,145		)	$	2,518
OTCBB natural gas contracts	—		232		—		(232		)	—
NYMEX gasoline and heating oil contracts	105		—		—		(105		)	$	—
Natural gas commodity contracts	—		1,129		150		(495		)	$	784
Total	$	18,938	$	1,691	$	150	$	(2,977	)	$	17,802
Liabilities
NYMEX/ICE natural gas contracts	$	3,687	$	321	$	—	$	(4,008	)	$	—
OTCBB natural gas contracts	—		5,443		—		(232		)	$	5,211
NYMEX gasoline and heating oil contracts	—		—		—		—			$	—
Natural gas commodity contracts	—		1,140		40		(495		)	$	685
Total	$	3,687	$	6,904	$	40	$	(4,735	)	$	5,896
As of September 30, 2012
Assets
U. S. Stock/Bond Mutual Funds	$	13,187	$	—	$	—	$	—		$	13,187
NYMEX/ICE natural gas contracts	7,411		994		—		(8,405		)	$	—
NYMEX gasoline and heating oil contracts	344		—		—		(344		)	$	—
Natural gas commodity contracts	—		3,060		113		(299		)	$	2,874
Total	$	20,942	$	4,054	$	113	$	(9,048	)	$	16,061
Liabilities
NYMEX/ICE natural gas contracts	$	12,253	$	1,891	$	—	$	(14,144	)	$	—
NYMEX gasoline and heating oil contracts	—		—		—		—			$	—
Natural gas commodity contracts	—		428		4		(299		)	$	133
Total	$	12,253	$	2,319	$	4	$	(14,443	)	$	133

The mutual funds included in Level 1 are valued based on exchange-quoted market prices of identical securities. Derivative instruments included in Level 1 are valued using quoted market prices on the NYMEX. Derivative instruments classified in Level 2 include physical commodity derivatives that are valued using Over The Counter Bulletin Board (OTCBB), broker, or dealer quotation services whose prices are derived principally from, or are corroborated by, observable market inputs. Also included in Level 2 are certain derivative instruments that have values that are similar to, and correlate with, quoted prices for exchange-traded instruments in active markets. Derivative instruments included in Level 3 are valued using generally unobservable inputs that are based upon the best information available and reflect management’s assumptions about how market participants would price the asset or liability. The Company’s policy is to recognize transfers between the levels of the fair value hierarchy, if any, as of the beginning of the interim reporting period in which circumstances change or events occur to cause the transfer. The following is a reconciliation of the Level 3 beginning and ending net derivative balances:

(Thousands)	2013			2012
Beginning of period	$	109		$	13
Settlements	(269		)	(54		)
Net losses related to derivatives not held at end of period	(99		)	(68		)
Net gains related to derivatives still held at end of period	369			218
End of period	$	110		$	109

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The mutual funds are included in the Other investments line of the Consolidated Balance Sheets. Derivative assets and liabilities, including receivables and payables associated with cash margin requirements, are presented net in the Consolidated Balance Sheets when a legally enforceable netting agreement exists between the Company and the counterparty to a derivative contract. For additional information on derivative instruments, see Note 11, Derivative Instruments and Hedging Activities.

11. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

The Utility has a risk management policy that allows for the purchase of natural gas derivative instruments with the goal of managing price risk associated with purchasing natural gas on behalf of its customers. This policy prohibits speculation and permits the Utility to hedge up to 70% of its normal volumes purchased for up to a 36-month period. Costs and cost reductions, including carrying costs, associated with the Utility’s use of natural gas derivative instruments are allowed to be passed on to the Utility’s customers through the operation of its PGA Clause, through which the MoPSC allows the Utility to recover gas supply costs, subject to prudence review by the MoPSC. Accordingly, the Utility does not expect any adverse earnings impact as a result of the use of these derivative instruments. The Utility does not designate these instruments as hedging instruments for financial reporting purposes because gains or losses associated with the use of these derivative instruments are deferred and recorded as regulatory assets or regulatory liabilities pursuant to ASC Topic 980, “Regulated Operations,” and, as a result, have no direct impact on the Statements of Consolidated Income. The timing of the operation of the PGA Clause may cause interim variations in short-term cash flows, because the Utility is subject to cash margin requirements associated with changes in the values of these instruments. Nevertheless, carrying costs associated with such requirements are recovered through the PGA Clause.

From time to time, the Utility purchases NYMEX futures and options contracts to help stabilize operating costs associated with forecasted purchases of gasoline and diesel fuels used to power vehicles and equipment used in the course of its business. At September 30, 2013, Laclede Gas held 0.3 million gallons of gasoline futures contracts at an average price of $2.23 per gallon. Most of these contracts, the longest of which extends to April 2014, are designated as cash flow hedges of forecasted transactions pursuant to ASC Topic 815. The gains or losses on these derivative instruments are not subject to the Utility’s PGA Clause.

In the course of its business, Laclede Group’s non-regulated gas marketing subsidiary, LER, which includes its wholly owned subsidiary LER Storage Services, Inc., enters into commitments associated with the purchase or sale of natural gas. Certain of LER’s derivative natural gas contracts are designated as normal purchases or normal sales and, as such, are excluded from the scope of ASC Topic 815 and are accounted for as executory contracts on an accrual basis. Any of LER’s derivative natural gas contracts that are not designated as normal purchases or normal sales are accounted for at fair value. At September 30, 2013, the fair values of 67.4 million MMBtu of non-exchange traded natural gas commodity contracts were reflected in the Consolidated Balance Sheet. Of these contracts, 58.5 million MMBtu will settle during fiscal year 2014, 8.1 million MMBtu will settle during fiscal year 2015, while the remaining 0.8 million MMBtu will settle during fiscal year 2016. These contracts have not been designated as hedges; therefore, changes in the fair value of these contracts are reported in earnings each period. Furthermore, LER manages the price risk associated with its fixed-priced commitments by either closely matching the offsetting physical purchase or sale of natural gas at fixed prices or through the use of NYMEX or ICE futures, swap, and option contracts to lock in margins. At September 30, 2013, LER’s unmatched fixed-price positions were not material to Laclede Group’s financial position or results of operations. LER’s NYMEX and ICE natural gas futures, swap, and option contracts used to lock in margins may be designated as cash flow hedges of forecasted transactions for financial reporting purposes.

Derivative instruments designated as cash flow hedges of forecasted transactions are recognized on the Consolidated Balance Sheets at fair value and the change in the fair value of the effective portion of these hedge instruments is recorded, net of tax, in other comprehensive income (OCI). Accumulated other comprehensive income (AOCI) is a component of Total Common Stock Equity. Amounts are reclassified from AOCI into earnings when the hedged items affect net income, using the same revenue or expense category that the hedged item impacts. Based on market prices at September 30, 2013, it is expected that approximately $2.3 million of pretax losses will be reclassified into the Statements of Consolidated Income during fiscal year 2014. Cash flows from hedging transactions are classified in the same category as the cash flows from the items that are being hedged in the Statements of Consolidated Cash Flows.

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The Company’s exchange-traded/cleared derivative instruments consist primarily of NYMEX and ICE positions. The NYMEX is the primary national commodities exchange on which natural gas derivatives are traded. Open NYMEX/ICE and OTCBB natural gas futures and swap positions at September 30, 2013 were as follows:

	Laclede Gas Company			Laclede Energy Resources, Inc.
	MMBtu (millions)	Avg. Price Per MMBtu		MMBtu (millions)	Avg. Price Per MMBtu
NYMEX/ICE open short futures/swap positions
Fiscal 2014	—	$	—	12.91	$	3.98
Fiscal 2015	—	—		0.06	4.21
NYMEX/ICE open long futures/swap positions
Fiscal 2014	7.26	$	3.99	1.71	$	3.94
Fiscal 2015	0.94	3.84		0.19	4.06
Fiscal 2016	—	—		0.02	4.15
OTCBB open long futures
Fiscal 2014	16.81	$	3.97	—	$	—
Fiscal 2015	7.58	4.22		—	—

At September 30, 2013, the Utility and LER also had 23.6 million MMBtu and 0.0 million MMBtu, respectively, of other price mitigation in place through the use of NYMEX and OTCBB natural gas option-based strategies.

In February 2013, Laclede Group entered into certain interest rate swap agreements, with a notional amount of $355 million, to effectively lock in interest rates on a portion of the long-term debt it anticipated issuing to finance its acquisition of Missouri Gas Energy (MGE). These derivative instruments had been designated as cash flow hedges of forecasted transactions. These forward starting swaps involve the payment of a fixed interest rate and the receipt of a floating interest rate (the London Interbank Offered Rate, also known as LIBOR) over the terms specified in the contracts. On August 6, 2013, the interest rate swap agreements were terminated and the settlement resulted in a $20.8 million gain by Laclede Group. The Company assigned the gain as a regulatory liability since the interest rate swaps were entered into to hedge the interest payments on the $450 million of long-term debt issued on August 13, 2013 by Laclede Gas.

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The Effect of Derivative Instruments on the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income
	Location of Gain (Loss)
(Thousands)	Recorded in Income	2013			2012			2011
Derivatives in Cash Flow Hedging Relationships
Effective portion of gain (loss) recognized in OCI on derivatives:
NYMEX/ICE natural gas contracts		$	4,923		$	4,505		$	5,226
NYMEX gasoline and heating oil contracts		123			297			355
Total		$	5,046		$	4,802		$	5,581
Effective portion of gain (loss) reclassified from AOCI to income:
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	$	(4	)	$	18,929		$	7,443
	Gas Marketing Operating Expenses	(509		)	(10,532		)	(9,770		)
Sub-total		$	(513	)	$	8,397		$	(2,327	)
NYMEX gasoline and heating oil contracts	Gas Utility Other Operation Expenses	211			—			466
Total		$	(302	)	$	8,397		$	(1,861	)
Ineffective portion of gain (loss) on derivatives     recognized in income:
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	$	(420	)	$	(36	)	$	966
	Gas Marketing Operating Expenses	(239		)	(263		)	(1,322		)
Sub-total		$	(659	)	$	(299	)	$	(356	)
NYMEX gasoline and heating oil contracts	Gas Utility Other Operation Expenses	(127		)	175			12
Total		$	(786	)	$	(124	)	$	(344	)
Derivatives Not Designated as Hedging Instruments*
Gain (loss) recognized in income on derivatives:
Natural gas commodity contracts	Gas Marketing Operating Revenues	$	(78	)	$	3,782		$	(660	)
	Gas Marketing Operating Expenses	—			687			4,229
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	(778		)	(615		)	(115		)
	Gas Marketing Operating Expenses	—			(625		)	(3		)
NYMEX gasoline and heating oil contracts	Other Income and (Income Deductions) - Net	41			19			37
Total		$	(815	)	$	3,248		$	3,488

* Gains and losses on the Utility’s natural gas derivative instruments, which are not designated as hedging instruments for financial reporting purposes, are deferred pursuant to the Utility’s PGA Clause and initially recorded as regulatory assets or regulatory liabilities. These gains and losses are excluded from the table above because they have no direct impact on the Statements of Consolidated Income. Such amounts are recognized in the Statements of Consolidated Income as a component of Regulated Gas Distribution Natural and Propane Gas operating expenses when they are recovered through the PGA Clause and reflected in customer billings.

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Fair Value of Derivative Instruments in the Consolidated Balance Sheet at September 30, 2013
	Asset Derivatives*				Liability Derivatives*
(Thousands)	Balance Sheet Location	Fair Value			Balance Sheet Location	Fair  Value
Derivatives designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets	$	2,222		Derivative Instrument Assets	$	440
	Other Deferred Charges	22			Other Deferred Charges	11
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	105			Accounts Receivable - Other	—
Sub-total		2,349				451
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets	950			Derivative Instrument Assets	100
	Accounts Receivable - Other	1,434			Accounts Receivable - Other	3,455
	Other Deferred Charges	32			Other Deferred Charges	—
OTCBB natural gas contracts	Other Current Liabilities	228			Other Current Liabilities	4,045
	Other Deferred Credits	4			Other Deferred Credits	1,398
Natural gas commodity contracts	Derivative Instrument Assets	991			Derivative Instrument Assets	90
	Other Deferred Charges	20			Other Deferred Charges	137
	Other Current Liabilities	247			Other Current Liabilities	830
	Other Deferred Credits	21			Other Deferred Credits	123
Sub-total		3,927				10,178
Total derivatives		$	6,276			$	10,629
Fair Value of Derivative Instruments in the Consolidated Balance Sheet at September 30, 2012
	Asset Derivatives				Liability Derivatives
(Thousands)	Balance Sheet Location	Fair Value		*	Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments
NYMEX/ICE natural gas contracts	Accounts Receivable - Other	$	405		Accounts Receivable - Other	$	3,413
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	334			Accounts Receivable - Other	—
Sub-total		739				3,413
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Accounts Receivable - Other	8,000			Accounts Receivable - Other	10,731
	Other Deferred Charges	—			Other Deferred Charges	—
Natural gas commodity contracts	Derivative Instrument Assets	3,150			Derivative Instrument Assets	295
	Other Current Liabilities	4			Other Current Liabilities	137
	Other Deferred Charges	19			Other Deferred Charges	—
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	10			Accounts Receivable - Other	—
Sub-total		11,183				11,163
Total derivatives		$	11,922			$	14,576

* The fair values of Asset Derivatives and Liability Derivatives exclude the fair value of cash margin receivables or payables with counterparties subject to netting arrangements. Fair value amounts of derivative contracts (including the fair value amounts of cash margin receivables and payables) for which there is a legal right to set off are presented net on the Consolidated Balance Sheets. As such, the gross balances presented in the table above are not indicative of the Company’s net economic exposure. Refer to Note 10, Fair Value Measurements, for information on the valuation of derivative instruments.

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Following is a reconciliation of the amounts in the tables above to the amounts presented in the Consolidated Balance Sheets:

(Thousands)	2013			2012
Fair value of asset derivatives presented above	6,276			11,922
Fair value of cash margin receivables offset with derivatives	1,765			5,478
Netting of assets and liabilities with the same counterparty	(4,739		)	(14,526		)
Total	3,302			2,874
Derivative Instrument Assets, per Consolidated Balance Sheets:
Derivative instrument assets	3,291			2,855
Other deferred charges	11			19
Total	3,302			2,874
Fair value of liability derivatives presented above	10,629			14,576
Fair value of cash margin payables offset with derivatives	6			83
Netting of assets and liabilities with the same counterparty	(4,739		)	(14,526		)
Derivative instrument liabilities, per Consolidated Balance Sheets	5,896			133
Derivative Instrument Liabilities, per Consolidated Balance Sheets:
Other current liabilities	$	4,400		$	133
Other deferred credits	1,496			—
Total	$	5,896		$	133

Additionally, at September 30, 2013 and 2012, the Company had $3.2 million and $10.0 million, respectively, in cash margin receivables not offset with derivatives, that are presented in Accounts Receivable – Other.

12. CONCENTRATION OF CREDIT RISK

A significant portion of LER’s transactions are with (or are associated with) energy producers, utility companies, and pipelines. These concentrations of transactions with these counterparties have the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that each of these three groups may be affected similarly by changes in economic, industry, or other conditions. To manage this risk, as well as credit risk from significant counterparties in these and other industries, LER has established procedures to determine the creditworthiness of its counterparties. These procedures include obtaining credit ratings and credit reports, analyzing counterparty financial statements to assess financial condition, and considering the industry environment in which the counterparty operates. This information is monitored on an ongoing basis. In some instances, LER may require credit assurances such as prepayments, letters of credit, or parental guarantees. In addition, LER may enter into netting arrangements to mitigate credit risk with counterparties in the energy industry from which LER both sells and purchases natural gas. Sales are typically made on an unsecured credit basis with payment due the month following delivery. Accounts receivable amounts are closely monitored and provisions for uncollectible amounts are accrued when losses are probable. To date, losses have not been significant. LER records accounts receivable, accounts payable, and prepayments for physical sales and purchases of natural gas on a gross basis. The amount included in accounts receivable attributable to energy producers and their marketing affiliates amounted to $22.8 million at September 30, 2013. However, due to netting arrangements, there were no net receivable amounts from these customers on that same date. Accounts receivable attributable to utility companies and their marketing affiliates comprised $23.5 million of total accounts receivable at September 30, 2013, while net receivable amounts from these customers, reflecting netting arrangements, were $16.6 million. LER also has concentrations of credit risk with certain individually significant counterparties. At September 30, 2013, the amounts included in accounts receivable from LER’s five largest counterparties (in terms of net accounts receivable exposure), were $16.6 million. These five counterparties are either investment-grade rated or owned by investment-grade rated companies. Net receivable amounts from these customers on the same date, reflecting netting arrangements, were $14.5 million. Additionally, LER has concentrations of credit risk with pipeline companies associated with its natural gas receivable amounts.

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13. INCOME TAXES

The net provisions for income taxes charged during the fiscal years ended September 30, 2013, 2012, and 2011 are as follows:

(Thousands)	2013			2012			2011
Included in Statements of Consolidated Income:
Federal
Current	$	(4,173	)	$	(3,835	)	$	4,724
Deferred	19,925			26,365			20,602
Investment tax credits	(213		)	(213		)	(213		)
State and local
Current	(301		)	(430		)	573
Deferred	2,340			4,402			3,496
Total Income Tax Expense	$	17,578		$	26,289		$	29,182

The effective income tax rate varied from the federal statutory income tax rate for each year due to the following:

	2013		2012		2011
Federal income tax statutory rate	35.0	%	35.0	%	35.0	%
State and local income taxes, net of federal income tax benefits	3.5		2.9		2.8
Certain expenses capitalized on books and deducted on tax return	(9.7	)	(6.9	)	(5.0	)
Taxes related to prior years	(1.6	)	(0.8	)	(0.7	)
Other items – net	(2.2	)	(0.6	)	(0.7	)
Effective income tax rate	25.0	%	29.6	%	31.4	%

The significant items comprising the net deferred tax liability recognized in the Consolidated Balance Sheets as of September 30 are as follows:

(Thousands)	2013			2012
Deferred tax assets:
Reserves not currently deductible	$	13,933		$	16,400
Pension and other postretirement benefits	71,367			73,480
Unamortized investment tax credits	1,799			1,955
Other*	12,522			18,224
Total deferred tax assets	99,621			110,059
Deferred tax liabilities:
Relating to property	341,975			303,474
Regulatory pension and other postretirement benefits	124,871			121,554
Deferred gas costs	7,112			20,652
Other	5,789			26,563
Total deferred tax liabilities	479,747			472,243
Net deferred tax liability	380,126			362,184
Net deferred tax liability – current*	(1,012		)	(6,675		)
Net deferred tax liability – non-current*	$	379,114		$	355,509

* The Company periodically invests in tax credits. As of September 30, 2013, $7.1 million of state tax credits are included in Other and Net deferred tax liability. $4.7 million of state tax credits were classified as current. $2.4 million of state tax credits were classified as non-current.

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 interest expense and other income deductions, respectively. 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 Consolidated Balance Sheets.

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The following table presents a reconciliation of the beginning and ending balances of unrecognized tax benefits at September 30 as reported in the Consolidated Balance Sheets:

(Thousands)	2013			2012
Unrecognized tax benefits, beginning of year	$	5,810		$	5,596
Increases related to prior year tax positions	145			78
Increases related to tax positions taken in current year	1,450			547
Reductions due to lapse of applicable statute of limitations	(5,018		)	(411		)
Unrecognized tax benefits, end of year	$	2,387		$	5,810

The amount of unrecognized tax benefits which, if recognized, would affect the Company’s effective tax rate were $1.9 million and $1.4 million as of September 30, 2013 and 2012, respectively. It is reasonably possible that events will occur in the next 12 months that could increase or decrease the amount of the Company’s unrecognized tax benefits. The Company does not expect that any such change will be significant to the Consolidated Balance Sheets.

Interest accrued associated with the Company’s uncertain tax positions as of September 30, 2013 and 2012 were $0.1 million and $0.6 million, respectively, and an immaterial amount of penalties were accrued as of September 30, 2013. Interest expense accrued during fiscal year 2013 was $0.1 million, $0.2 million for fiscal year 2012, and $0.2 million for fiscal year 2011. During fiscal year 2013, the Company reversed $0.6 million of accrued interest expense in the Consolidated Statements of Income.

The Company is subject to U.S. federal income tax as well as income tax of state and local jurisdictions. The Company is no longer subject to examination for fiscal years prior to 2010.

In September 2013, the Internal Revenue Service and U.S. 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. Laclede is evaluating the effects of the regulations, but does not believe that they will have a significant impact on its consolidated financial statements.

14. OTHER INCOME AND (INCOME DEDUCTIONS) – NET

(Thousands)	2013			2012			2011
Interest income	$	1,088		$	1,309		$	1,136
Net investment gain	2,857			3,124			185
Other income	377			811			118
Other income deductions	(1,878		)	(1,972		)	(1,262		)
Other Income and (Income Deductions) – Net	$	2,444		$	3,272		$	177

15.    INFORMATION BY OPERATING SEGMENT

All of Laclede Group’s subsidiaries are wholly owned. In the first quarter of fiscal year 2013, the Company retitled its segment names. The Gas Utility segment, previously titled Regulated Gas Distribution, consists of the regulated operations of the Utility and is the core business segment of Laclede Group. The Utility is a public utility engaged in the retail distribution and sale of natural gas serving an area in eastern Missouri, including the City of St. Louis, through Laclede Gas and an area in western Missouri, including Kansas City, through MGE. The Gas Marketing segment, previously titled Non-Regulated Gas Marketing, includes the results of LER, a subsidiary engaged in the non-regulated marketing of natural gas and related activities, and LER Storage Services, Inc., which became operational in January 2012 and utilizes natural gas storage contracts for providing natural gas sales. Other includes Laclede Pipeline Company’s transportation of liquid propane regulated by the Federal Energy Regulatory Commission (FERC) as well as non-regulated activities, including, among other activities, real estate development, the compression of natural gas, and financial investments in other enterprises. These operations are conducted through seven subsidiaries. Other also includes the Utility’s non-regulated business activities, which are comprised of its propane storage and related services. Beginning July 1, 2013, propane-related services were included within Gas Utility operations pursuant to Laclede Gas' most recent rate case. Accounting policies are described in Note 1, Summary of Significant Accounting Policies. Intersegment transactions include sales of natural gas from the Utility to LER, propane storage services provided by the Utility to Laclede Pipeline Company, sales of natural gas from LER to the Utility, and propane transportation services provided by Laclede Pipeline Company to the Utility.

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Management evaluates the performance of the operating segments based on the computation of net economic earnings. Net economic earnings exclude from reported net income the after-tax impacts of net unrealized gains and losses and other timing differences associated with energy-related transactions. Net economic earnings also excludes the after-tax impacts related to acquisition, divestiture, and restructuring activities.

	Gas Utility		Gas Marketing			Other				Eliminations			Consolidated
(Thousands)
Fiscal 2013
Revenues from external customers	$	847,224	$	165,146		$	4,649			$	—		$	1,017,019
Intersegment revenues	10,538		24,185			1,625				(36,348		)	—
Total Operating Revenues	857,762		189,331			6,274				(36,348		)	1,017,019
Operating Expenses
Gas Utility
Natural and Propane Gas	469,098		—			—				(35,656		)	433,442
Other Operation and Maintenance	180,702		—			—				(360		)	180,342
Depreciation and Amortization	48,283		—			—				—			48,283
Taxes, Other than Income Taxes	60,079		—			—				—			60,079
Total Gas Utility Operating Expenses	758,162		—			—				(36,016		)	722,146
Gas Marketing	—		176,554		(a)	—				—			176,554
Other	—		—			22,157			(b)	(332		)	21,825
Total Operating Expenses	758,162		176,554			22,157				(36,348		)	920,525
Operating Income	99,599		12,777			(15,882		)		—			96,494
Interest income	947		103			343				(305		)	1,088
Interest charges	26,137		135			2,635				(305		)	28,602
Income tax expense	19,243		5,162			(6,827		)		—			17,578
Net economic earnings	56,635		8,936			(559		)		—			65,012
Total assets	2,981,016		163,944			115,560				(135,134		)	3,125,386
Capital expenditures	128,496		44			2,248				—			130,788
Fiscal 2012
Revenues from external customers	$	763,447	$	358,145		$	3,883			$	—		$	1,125,475
Intersegment revenues	1,204		15,330			1,042				(17,576		)	—
Total Operating Revenues	764,651		373,475			4,925				(17,576		)	1,125,475
Operating Expenses
Gas Utility
Natural and Propane Gas	414,846		—			—				(17,542		)	397,304
Other Operation and Maintenance	167,351		—			—				—			167,351
Depreciation and Amortization	40,739		—			—				—			40,739
Taxes, Other than Income Taxes	53,672		—			—				—			$	53,672
Total Gas Utility Operating Expenses	676,608		—			—				(17,542		)	659,066
Gas Marketing	—		353,286		(a)	—				(3		)	353,283
Other	—		—			2,555			(b)	(31		)	2,524
Total Operating Expenses	676,608		353,286			2,555				(17,576		)	1,014,873
Operating Income	88,043		20,189			2,370				—			110,602
Interest income	1,230		175			371				(467		)	1,309
Interest charges	25,156		81			175				(467		)	24,945
Income tax expense	17,393		7,966			930				—			26,289
Net economic earnings	48,089		12,273			2,250				—			62,612
Total assets	1,758,952		190,709			102,241				(171,640		)	1,880,262
Capital expenditures	106,734		140			1,969				—			108,843

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Fiscal 2011
Revenues from external customers	$	911,614	$	645,042		$	19,704		$	—		1,576,360
Intersegment revenues	1,576		24,333			1,038			—			26,947
Total Operating Revenues	913,190		669,375			20,742			—			1,603,307
Operating Expenses
Gas Utility
Natural and Propane Gas	549,947		—			—			—			549,947
Other Operation and Maintenance	172,938		—			—			—			172,938
Depreciation and Amortization	39,214		—			—			—			$	39,214
Taxes, Other than Income Taxes	60,752		—			—			—			60,752
Total Gas Utility Operating Expenses	822,851		—			—			—			$	822,851
Gas Marketing	—		652,567		(a)	—			—			652,567
Other	—		—			9,642		(b)	—			9,642
Total Operating Expenses	822,851		652,567			9,642			—			1,485,060
Operating Income	90,339		16,808			11,100			—			118,247
Interest income	1,057		165			217			(303		)	1,136
Interest charges	25,544		14			162			(303		)	25,417
Income tax expense	18,694		6,570			3,918			—			29,182
Net economic earnings	46,952		8,962			6,496		(c)	—			62,410
Total assets	1,641,386		175,352			129,176			(162,832		)	1,783,082
Capital expenditures	67,304		215			119			—			67,638

(a) Depreciation and amortization for Gas Marketing is included in Gas Marketing Expenses on the Statements of Consolidated Income ($0.3 million for fiscal year 2013, $0.3 million for fiscal year 2012, and $0.1 million for fiscal year 2011).

(b) Depreciation, amortization, and accretion for Other is included in the Other Operating Expenses on the Statements of Consolidated Income ($0.6 million for fiscal year 2013, $0.3 million for fiscal year 2012 and $0.2 million for fiscal year 2011).

(c) Net economic earnings include income realized by the Utility from separate non-regulated sales of propane inventory no longer needed to serve utility customers, of which occurred in fiscal year 2011. This transaction resulted in after-tax earnings totaling $6.1 million.

Reconciliation of Consolidated Net Income to Consolidated Net Economic Earnings
(Thousands)	2013			2012			2011
Net Income (GAAP)	$	52,758		$	62,640		$	63,825
Unrealized loss (gain) on energy-related      derivatives	614			(314		)	(1,415		)
Lower of cost or market inventory adjustments	868			—			—
Realized (gain) loss on economic hedges prior      to the sale of the physical commodity	(25		)	163			—
Acquisition, divestiture and restructuring activities	10,797			123			—
Net Economic Earnings (Non-GAAP)	$	65,012		$	62,612		$	62,410

16.    COMMITMENTS AND CONTINGENCIES

Commitments

The Utility estimates total Utility capital expenditures for fiscal 2014 at approximately $175 million. In fiscal 2011, the Utility initiated a multi-year project to replace its existing customer relationship and work management, financial, and supply chain software applications to enhance its technology, customer service, and business processes. At September 30, 2013, the Company was contractually committed to costs of approximately $1.5 million related to this project.

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Fiscal year 2014 capital expenditures for non-regulated subsidiaries will depend on the nature and magnitude of investments with the current estimate at $10 million. There are no material contractual commitments at September 30, 2013 related to these estimated capital expenditures.

The Utility and LER have entered into various contracts, expiring on dates through 2019, for the storage, transportation, and supply of natural gas. Minimum payments required under the contracts in place at September 30, 2013 are estimated at approximately $981 million. The Utility recovers its costs from customers in accordance with the PGA Clause.

Leases and Guarantees

The lease agreement covering the main office space of the Utility extends through February 2015 with the option to renew for five additional years. The aggregate rental expense for fiscal years 2013, 2012, and 2011 was approximately $1.0 million, $0.9 million, and $0.9 million, respectively. The annual minimum rental payment for fiscal year 2014 is anticipated to be approximately $1.0 million through fiscal year 2015. The annual rental amount for the lease agreement covering MGE's main office space is approximately $0.6 million, and the lease term extends through November 30, 2015.

The Utility has entered into various operating lease agreements for the rental of vehicles and power operated equipment. The rental costs will be approximately $2.7 million in fiscal year 2014, $1.8 million in fiscal year 2015, $1.0 million in fiscal year 2016, and $0.4 million in fiscal year 2017, and $0.1 million in fiscal year 2018. The Utility and LER have other relatively minor rental arrangements that provide for minimum rental payments.

A consolidated subsidiary is a general partner in an unconsolidated partnership that invests in real estate partnerships. The subsidiary and third parties are jointly and severally liable for the payment of mortgage loans in the aggregate outstanding amount of approximately $1.6 million incurred in connection with various real estate ventures. Laclede Group has no reason to believe that the other principal liable parties will not be able to meet their proportionate share of these obligations. Laclede Group further believes that the asset values of the real estate properties are sufficient to support these mortgage loans.

Contingencies

The Utility 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’s or the Utility's financial position and results of operations. As environmental laws, regulations, and their interpretations change, however, the Utility may be required to incur additional costs.

Similar to other natural gas utility companies, Laclede Gas Company faces the risk of incurring environmental liabilities. In the natural gas industry, these are typically associated with sites formerly owned or operated by gas distribution companies like Laclede Gas and MGE or its predecessor companies at which manufactured gas operations took place. At this time, Laclede Gas has identified three former manufactured gas plant (MGP) sites where costs have been incurred and claims have been asserted: one in Shrewsbury, Missouri and two in the City of St. Louis, Missouri. Laclede Gas has enrolled the two sites in the City of St. Louis in the Missouri Department of Natural Resources Brownfields/Voluntary Cleanup Program (BVCP). MGE has enrolled all of its owned former manufactured gas plant sites in the BVCP.

With regard to the former MGP site located in Shrewsbury, Missouri, Laclede Gas and state and federal environmental regulators agreed upon certain remedial actions to a portion of the site in a 1999 Administrative Order on Consent (AOC), which actions have been completed. On September 22, 2008, EPA Region VII issued a letter of Termination and Satisfaction terminating the AOC. However, if after this termination of the AOC, regulators require additional remedial actions, or additional claims are asserted, Laclede Gas may incur additional costs.

One of the sites located in the City of St. Louis is currently owned by a development agency of the City, which, together with other City development agencies, has selected a developer to redevelop the site. In conjunction with this redevelopment effort, Laclede Gas and another former owner of the site entered into an agreement (Remediation Agreement) with the City development agencies, the developer, and an environmental consultant that obligates one of the City agencies and the environmental consultant to remediate the site and obtain a No Further Action letter from the Missouri Department of Natural Resources.

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The Remediation Agreement also provides for a release of Laclede Gas and the other former site owner from certain liabilities related to the past and current environmental condition of the site and requires the developer and the environmental consultant to maintain certain insurance coverages, including remediation cost containment, premises pollution liability, and professional liability.

The operative provisions of the Remediation Agreement were triggered on December 20, 2010, on which date Laclede Gas and the other former site owner, as full consideration under the Remediation Agreement, paid a small percentage of the cost of remediation of the site. The amount paid by Laclede Gas did not materially impact the financial condition, results of operations, or cash flows of the Company.

Laclede Gas has not owned the other site located in the City of St. Louis for many years. In a letter dated June 29, 2011, the Attorney General for the State of Missouri informed Laclede Gas that the Missouri Department of Natural Resources had completed an investigation of the site. The Attorney General requested that Laclede Gas participate in the follow up investigations of the site. In a letter dated January 10, 2012, Laclede Gas stated that it would participate in future environmental response activities at the site in conjunction with other potentially responsible parties that are willing to contribute to such efforts in a meaningful and equitable fashion. 

To date, amounts required for remediation at these sites have not been material. However, the amount of costs relative to future remedial actions at these and other sites is unknown and may be material. Laclede Gas has notified its insurers that it seeks reimbursement for costs incurred in the past and future potential liabilities associated with the MGP sites. While some of the insurers have denied coverage and reserved their rights, Laclede Gas continues to discuss potential reimbursements with them. In 2005, the Utility’s outside consultant completed an analysis of the MGP sites to determine cost estimates for a one-time contractual transfer of risk from each of the Utility’s insurers of environmental coverage for the MGP sites. That analysis demonstrated a range of possible future expenditures to investigate, monitor, and remediate these MGP sites from $5.8 million to $36.3 million based upon then currently available facts, technology, and laws and regulations. The actual costs that Laclede Gas may incur could be materially higher or lower depending upon several factors, including whether remedial actions will be required, final selection and regulatory approval of any remedial actions, changing technologies and governmental regulations, the ultimate ability of other potentially responsible parties to pay, the successful completion of remediation efforts required by the Remediation Agreement described above, and any insurance recoveries.

MGE has seven owned MGP sites enrolled in the BVCP, including Joplin MGP #1, St. Joseph MGP #1, Kansas City Coal Gas Station B, Kansas City Station A Railroad, Kansas City Coal Gas Station A North, Kansas City Coal Gas Station A South, and Independence MGP #2. The Missouri Department of Natural Resources awarded a Certificate of Completion to Missouri Gas Energy in 2001 for a site located at 20th and Indiana in Kansas City after an initial site analysis and the property was subsequently sold. Source removal has been conducted at all of the owned sites since 2003 with the exception of Joplin, which is in the early stages of site analysis and characterization. Remediation efforts at these sites are at various stages of completion, ranging from groundwater monitoring and sampling following source removal activities to early site characterization in Joplin. As part of its participation in the BVCP, MGE communicates regularly with the Missouri Department of Natural Resources with respect to its remediation efforts and monitoring activities at these sites.

Costs associated with environmental remediation activities are accrued when such costs are probable and reasonably estimable. The Utility anticipates that any costs it may incur in the future to remediate these sites, less any amounts received as insurance proceeds or as contributions from other potentially responsible parties, would be deferred and recovered in rates through periodic adjustments approved by the MoPSC. Accordingly, any potential liabilities that may arise associated with remediating these sites are not expected to have a material impact on the future financial position and results of operations of the Utility or the Company.

The MoPSC Staff proposed disallowances related to Laclede Gas' recovery of its gas costs totaling $6.0 million pertaining to Laclede Gas' purchase of gas from a marketing affiliate, LER, applicable to fiscal years 2005 through 2007. The MoPSC staff also proposed a number of non-monetary recommendations, based on its review of gas costs for fiscal years 2008 through 2011. In a related matter, on October 6, 2010, the MoPSC Staff filed a complaint against Laclede Gas alleging that Laclede Gas' affiliate transactions and its Cost Allocation Manual (CAM) violated the MoPSC's affiliate transaction rules. Laclede Gas responded with a counterclaim that the MoPSC Staff had failed to adhere to the affiliate transaction rules and the Company's CAM. On July 16, 2013, Laclede Gas, the MoPSC Staff and the Office of the Public Counsel requested MoPSC approval of a unanimous stipulation and agreement resolving the affiliate transaction matters for fiscal years 2005 through 2011, resolving the October 6, 2010 complaint, resolving Laclede Gas' counterclaim, presenting a revised CAM for MoPSC approval, and establishing standards of conduct for gas purchases and sales. While the PSC Staff's disallowances were withdrawn as part of the stipulation, Laclede Gas agreed to a minor adjustment to the off-system sales and capacity release sharing mechanism.

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For a three-year period ending September 30, 2016, Laclede Gas' share of the first $2 million in net margin is reduced from 15% to 0%. None of the other sharing percentages are affected, and beginning October 1, 2016, Laclede's sharing percentage of the first $2 million in net margins returns to 15%. The Stipulation and agreement was approved by the MoPSC in an order issued on August 14, 2013.

On July 7, 2010, the MoPSC Staff filed a complaint against Laclede Gas alleging that, by stating that it was not in possession of proprietary LER documents, Laclede Gas violated the MoPSC Order authorizing the holding company structure (2001 Order). Laclede Gas counterclaimed stating the Staff failed to adhere to pricing provisions of the MoPSC's affiliate transaction rules and Laclede Gas' Cost Allocation Manual. By orders dated November 3, 2010 and February4,2011, respectively, the MoPSC dismissed Laclede's counterclaim and granted summary judgment to Staff, finding that Laclede Gas violated the terms of the 2001 Order and authorizing its General Counsel to seek penalties in court against Laclede Gas. On May 19, 2011, the MoPSC's General Counsel filed a petition seeking penalties against Laclede Gas for violation of the 2001 Order. The MoPSC and Laclede Gas agreed to hold the penalty case in abeyance pending the outcome of Laclede's appeal of the November 3, 2010 and February 4, 2011 orders. These Orders were reversed by the Cole County Circuit Court, but later upheld by the Western District Court of Appeals. On March 19, 2013, the Missouri Supreme Court declined Laclede Gas' request to review the opinion of the Western District Court of Appeals. As a result, Laclede Gas produced certain LER documentation that had been requested by the MoPSC Staff and, pursuant to agreement between the MoPSC and Laclede Gas, the MoPSC’s May 2011 penalty case was dismissed.

On June 29, 2010, the Office of Federal Contract Compliance Programs (OFCCP) issued a Notice of Violations to Laclede Gas alleging lapses in certain employment selection procedures during a two-year period ending in February 2006. On July 2, 2013, Laclede Gas executed a Conciliation Agreement with the OFCCP in which the Company did not admit to liability, but agreed to provide make whole relief of back pay and interest to the impacted individuals from 2004-2006. The Company's agreement to provide make whole relief will not have a material effect on the consolidated financial position and results of operations, or cash flows of the Company.

As discussed in Note 11, Derivative Instruments and Hedging Activities, Laclede Gas and LER enter into NYMEX and ICE exchange-traded/cleared derivative instruments. Previously, these instruments were held in accounts at MF Global, Inc. On October 31, 2011, affiliated entities of MF Global filed a Chapter 11 petition at the U.S. Bankruptcy Court in the Southern District of New York. Subsequently, the court-appointed bankruptcy trustee transferred all of the open positions and a significant portion of the margin deposits of Laclede Gas and LER to a new brokerage firm. On June 27, 2013, the bankruptcy Trustee issued a statement projecting that MF Global customers would receive a full payout of their claims. As of November 26, 2013, Laclede Gas and LER had $0.2 million and $0.1 million, respectively, on deposit with MF Global that remain unavailable pending final resolution by the bankruptcy trustee. As the Company has recovered 98% of the amount at issue in the MF Global bankruptcy, the total remaining exposure is not considered material.

On February 19, 2013, Heartland Midwest, LLC, a contractor for Time Warner Cable, hit a MGE natural gas line causing a gas leak while directionally boring during underground cable installation. The natural gas leak resulted in an explosion and fire which killed one person, injured approximately seventeen (including three MGE employees who were at the scene), caused major damage to JJ's restaurant, and caused property damage to adjacent buildings. Several lawsuits have been filed in state court in Jackson County, Missouri, alleging wrongful death, personal injury, property damage, and business interruption. The lawsuits are in the early stages of discovery. While the Company's total exposure is not considered material at this time, management plans to vigorously defend the matter and will continue to evaluate its exposure as discovery proceeds. Management believes, after discussion with counsel, that the final outcome of this matter will not have a material effect on the consolidated financial position, results of operations, or cash flows of the Company.

Laclede Group is involved in other litigation, claims, and investigations arising in the normal course of business. Management, after discussion with counsel, believes that the final outcome will not have a material effect on the consolidated financial position, results of operations, or cash flows of the Company.

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17.    INTERIM FINANCIAL INFORMATION (UNAUDITED)

In the opinion of Laclede Group, the quarterly information presented below for fiscal years 2013 and 2012 includes all adjustments (consisting of only normal recurring accruals) necessary for a fair statement of the results of operations for such periods. Variations in consolidated operations reported on a quarterly basis primarily reflect the seasonal nature of the business of the Utility.

(Thousands, Except Per Share Amounts)
Three Months Ended	Dec. 31		March 31		June 30		Sept. 30
Fiscal Year 2013
Total Operating Revenues	$	307,003	$	397,613	$	165,289	$	147,114
Operating Income (Loss)	42,085		51,849		12,282		(9,722		)
Net Income (Loss)	25,568		30,242		6,584		(9,636		)
Basic Earnings (Loss) Per Share of Common Stock	1.14		1.34		0.25		(0.30		)
Diluted Earnings (Loss) Per Share of Common Stock	1.14		1.34		0.25		(0.30		)
Three Months Ended	Dec. 31		March 31		June 30		Sept. 30
Fiscal Year 2012
Total Operating Revenues	$	410,913	$	358,175	$	186,849	$	169,538
Operating Income	43,105		50,583		15,045		1,869
Net Income (Loss)	25,174		29,684		8,433		(651		)
Basic Earnings (Loss) Per Share of Common Stock	1.13		1.33		0.38		(0.03		)
Diluted Earnings (Loss) Per Share of Common Stock	1.12		1.32		0.38		(0.03		)

All quarters of 2013 reflect transaction costs incurred associated with the acquisition of MGE. The fourth quarter of 2013 includes one month of activity of the operations of MGE, significant transaction costs incurred in the quarter and the interest impact of the debt issued in the quarter. Total impact of all of these during the quarter was a decrease in net income of $5.5 million.

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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 Laclede’s outside auditors that are required to be disclosed.

Item 9A. Controls and Procedures

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with participation of our management, including our 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 our disclosure controls and procedures are effective.

(b) Change in Internal Controls

During our fourth fiscal quarter we implemented a new customer care and billing application. The new system and related changes to processes have changed and enhanced our internal control over customer billing and financial reporting. We have taken the necessary steps to test the operating effectiveness of all key controls in the new system and maintain appropriate internal control over financial reporting during fiscal year 2013. Other than the system implementation discussed above, there have been no changes in our internal control over financial reporting that occurred during our fourth fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

The Management Report on Internal Control Over Financial Reporting and the Reports of Independent Registered Public Accounting Firm are included under Item 8, pages 46 through 48.

Item 9B. Other Information

None.

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Part III

Item 10. Directors, Executive Officers and Corporate Governance

Information about:

• our directors is incorporated by reference from the discussion under Proposal 1 of our proxy statement dated December 18, 2013 (2013 proxy statement);

• our executive officers is reported in Part I of this Form 10-K;

• compliance with Section 16(a) of the Exchange Act is incorporated by reference from the discussion in our 2013 proxy statement under the heading “Section 16(a) Beneficial Ownership Reporting Compliance”;

• Financial Code of Ethics is posted on our website, www.TheLacledeGroup.com, in the Investor Services section under Governance Documents; and,

• our audit committee, our audit committee financial experts, and submitting nominations to the Corporate Governance Committee is incorporated by reference from the discussion in our 2013 proxy statement under the heading “Corporate Governance.”

In addition, our Code of Business Conduct, Corporate Governance Guidelines, and charters for our audit, compensation and corporate governance committees are available on our website, and a copy will be sent to any shareholder upon written request.

Item 11. Executive Compensation

Information about director and executive compensation is incorporated by reference from the discussion in our 2013 proxy statement under the headings: “Directors’ Compensation,” “Compensation Discussion and Analysis,” and “Executive Compensation.” The 2013 proxy statement also includes the “Compensation Committee Report,” which is deemed furnished and not filed.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information about security ownership of certain beneficial owners and management is incorporated by reference from the discussion in our 2013 proxy statement under “Beneficial Ownership of Laclede Group Common Stock.”

The following table sets forth aggregate information regarding the Company’s equity compensation plans as of September 30, 2013:

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
	(a)	(b)		(c)
Equity compensation plans approved by security holders (1)	338,924	$	31.87	550,331
Equity compensation plans not approved by security holders	—	—		—
Total	338,924	31.87		550,331

(1) Reflects the Company’s Equity Incentive Plan. Included in column (a) are 205,424 nonvested restricted stock units issued under the Equity Incentive Plan for which the weighted average exercise price in column (b) does not take into account.

Information regarding the above referenced plans is set forth in Note 4 of the Notes to Consolidated Financial Statements in this report.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Information about:

• our policy and procedures for related party transactions and

• the independence of our directors

is included in our 2013 proxy statement under “Corporate Governance” and is incorporated by reference. There were no related party transactions in fiscal year 2013.

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Item 14. Principal Accounting Fees and Services

Information about fees paid to our independent registered public accountant and our policy for pre-approval of services provided by our independent registered public accountant is incorporated by reference from our 2013 proxy statement under “Fees of Independent Registered Public Accountant” and “Corporate Governance,” respectively.

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Part IV

Item 15. Exhibits, Financial Statement Schedule
			2013 10-K Page
(a)	1.	Financial Statements:
		See Item 8. Financial Statements and Supplementary Data, filed herewith, for a list of financial statements.
	2.	Supplemental Schedule
		II – Reserves	98
		Schedules not included have been omitted because they are not applicable or the required data has been included in the financial statements or notes to financial statements.
	3.	Exhibits	99
		Incorporated herein by reference to Index to Exhibits, page 99.
Item 15(a)(3) See the marked exhibits in the Index to Exhibits, page 99.
(b)		Incorporated herein by reference to Index to Exhibits, page 99.

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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.

		THE LACLEDE GROUP, INC.
November 26, 2013	By /s/	Steven P. Rasche
		Steven P. Rasche
		Senior Vice President
		and 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 26, 2013	/s/	Suzanne Sitherwood	Director, President,
		Suzanne Sitherwood	and Chief Executive Officer
			(Principal Executive Officer)
November 26, 2013	/s/	Steven P. Rasche	Senior Vice President
		Steven P. Rasche	and Chief Financial Officer
			(Principal Finance and Accounting Officer)
November 26, 2013	/s/	William E. Nasser	Chairman of the Board
		William E. Nasser
November 26, 2013			Director
		Arnold W. Donald
November 26, 2013	/s/	Edward L. Glotzbach	Director
		Edward L. Glotzbach
November 26, 2013	/s/	Anthony V. Leness	Director
		Anthony V. Leness
November 26, 2013	/s/	W. Stephen Maritz	Director
		W. Stephen Maritz
November 26, 2013	/s/	Brenda D. Newberry	Director
		Brenda D. Newberry
November 26, 2013	/s/	John P. Stupp, Jr.	Director
		John P. Stupp, Jr.
November 26, 2013	/s/	Mary Ann Van Lokeren	Director
		Mary Ann Van Lokeren

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SCHEDULE II

THE LACLEDE GROUP, INC. AND SUBSIDIARY COMPANIES

RESERVES

FOR THE YEARS ENDED SEPTEMBER 30, 2013, 2012, AND 2011

COLUMN A	COLUMN B		COLUMN C						COLUMN D			COLUMN E
	BALANCE AT		ADDITIONS			CHARGED			DEDUCTIONS			BALANCE
	BEGINNING		TO			TO OTHER			FROM			AT CLOSE
DESCRIPTION	OF PERIOD		INCOME			ACCOUNTS			RESERVES			OF PERIOD
(Thousands of Dollars)
YEAR ENDED SEPTEMBER 30, 2013:
DOUBTFUL ACCOUNTS	$	7,705	$	5,584		$	8,234	(b)	$	13,477	(c)	$	8,046
MISCELLANEOUS:
Injuries and property damage	$	4,540	$	1,934		$	—		$	2,135	(d)	$	4,339
Deferred compensation	14,205		1,781			—			1,306			14,680
Group medical claims incurred but not reported	1,560		17,205			—			16,116		(d)	2,649
TOTAL	$	20,305	$	20,920	(a)	$	—	(a)	$	19,557	(a)	$	21,668
YEAR ENDED SEPTEMBER 30, 2012:
DOUBTFUL ACCOUNTS	$	10,073	$	6,011		$	10,145	(b)	$	18,524	(c)	$	7,705
MISCELLANEOUS:
Injuries and property damage	$	3,603	$	3,150		$	—		$	2,213	(d)	$	4,540
Deferred compensation	13,474		1,756			—			1,025			14,205
Group medical claims incurred but not reported	1,300		15,381			—			15,121		(d)	1,560
TOTAL	$	18,377	$	20,287		$	—		$	18,359		$	20,305
YEAR ENDED SEPTEMBER 30, 2011:
DOUBTFUL ACCOUNTS	$	10,295	$	7,242		$	11,340	(b)	$	18,804	(c)	$	10,073
MISCELLANEOUS:
Injuries and property damage	$	3,228	$	2,416		$	—		$	2,041	(d)	$	3,603
Deferred compensation	12,571		1,893			—			990			13,474
Group medical claims incurred but not reported	1,450		14,171			—			14,321		(d)	1,300
TOTAL	$	17,249	$	18,480		$	—		$	17,352		$	18,377

(a) Totals for the year ended September 30, 2013 includes one month of MGE activity.

(b) Accounts reinstated, cash recoveries, etc.

(c) Accounts written off.

(d) Claims settled, less reimbursements from insurance companies.

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INDEX TO EXHIBITS

Exhibit
No.
2.01*	-	Agreement and Plan of Merger and Reorganization; filed as Appendix A to proxy statement/prospectus contained in the Company’s registration statement on Form S-4, No. 333-48794.
3.01(i)*	-	The Company’s Articles of Incorporation, as amended; filed as Exhibit 3.1 to the Company’s Form 8-K filed January 26, 2006.
3.01(ii)*	-	The Company’s Bylaws, as amended; filed as Exhibit 3.2 to the Company’s 10-Q for the fiscal quarter ended March 31, 2012.
4.01*	-	Mortgage and Deed of Trust, dated as of February 1, 1945; filed as Exhibit 7-A to registration statement No. 2-5586.
4.02*	-	Fourteenth Supplemental Indenture, dated as of October 26, 1976; filed on June 26, 1979 as Exhibit b-4 to registration statement No. 2-64857.
4.04*	-	Twenty-Fourth Supplemental Indenture dated as of June 1, 1999; filed on June 4, 1999 as Exhibit 4.01 to Laclede’s Form 8-K.
4.05*	-	Twenty-Fifth Supplemental Indenture dated as of September 15, 2000; filed on September 27, 2000 as Exhibit 4.01 to Laclede’s Form 8-K.
4.06*	-	Twenty-Seventh Supplemental Indenture dated as of April 15, 2004; filed on April 28, 2004 as Exhibit 4.01 to Laclede’s Form 8-K.
4.07*	-	Twenty-Eighth Supplemental Indenture dated as of April 15, 2004; filed on April 28, 2004 as Exhibit 4.02 to Laclede’s Form 8-K.
4.08*	-	Twenty-Ninth Supplemental Indenture dated as of June 1, 2006; filed on June 9, 2006, as Exhibit 4.1 to Laclede’s Form 8-K
4.09*	-	Thirtieth Supplemental Indenture dated as of September 15, 2008; filed on September 23, 2008 as Exhibit 4.1 to Laclede’s Form 8-K.
4.10*	-	Thirty-First Supplemental Indenture dated as of March 15, 2013; filed as Exhibit 4.1 to the Company's Form 10-Q for the quarter ended March 31, 2013.
4.11*	-	Thirty-Second Supplemental indenture dated as of August 13, 2013; filed August 13, 2013 as Exhibit 4.1 to the Company's Form 8-K filed August 13, 2013.
4.12*	-	Laclede Gas Company Board of Directors’ Resolution dated August 28, 1986 which generally provides that the Board may delegate its authority in the adoption of certain employee benefit plan amendments to certain designated Executive Officers; filed as Exhibit 4.12 to the Company’s 1991 10-K.
4.13*	-	Company Board of Directors’ Resolutions dated March 27, 2003, updating authority delegated pursuant to August 28, 1986 Laclede Gas Company resolutions; filed as Exhibit 4.19(a) to the Company’s Form 10-K for the year ended September 30, 2003.
10.04*	-	Restated Laclede Gas Company Supplemental Retirement Benefit Plan, as amended and restated effective as of November 1, 2005; filed as Exhibit 10.06 to the Company’s 10-Q for the fiscal quarter ended December 31, 2008.
10.05*	-	Amended and Restated Storage Service Agreement For Rate Schedule FSS, Contract #3147 between Centerpoint Energy-Mississippi River Transmission Corporation (MRT) and Laclede dated July 30, 2013; filed as 10.1 to the Company's Form 8-K filed August 2, 2013.
10.05a*	-	Amended and Restated Transportation Service Agreement for Rate Schedule FTS, Contract #3310 between Laclede and MRT dated July 30, 2013; filed as Exhibit 10.2 to the Company's Form 8-K filed August 2, 2013.
10.05b*	-	Amended and Restated Transportation Service Agreement for Rate Schedule FTS, Contract #3311, between Laclede and MRT dated July 30, 2013; filed as Exhibit 10.3 to the Company's Form 8-K filed August 2, 2013.
10.06*	-	Laclede Supplemental Retirement Benefit Plan II, effective as of January 1, 2005; filed as Exhibit 10.7 to the Company’s 10-Q for the fiscal quarter ended December 31, 2008.
10.07*	-	Amendment and Restatement of Retirement Plan for Non-Employee Directors as of November 1, 2002; filed as Exhibit 10.08c to the Company’s 10-K for the fiscal year ended September 30, 2002.
10.07a*	-	Amendment to Terms of Retirement Plan for Non-Employee Directors as of October 1, 2004; filed as Exhibit 10.w to the Company’s Form 10-Q for the fiscal quarter ended June 30, 2004.
10.08*	-	Salient Features of the Laclede Gas Company Deferred Income Plan for Directors and Selected Executives, including amendments adopted by the Board of Directors on July 26, 1990; filed as Exhibit 10.12 to the Company’s 1991 10-K.
10.08a*	-	Amendment to Laclede’s Deferred Income Plan for Directors and Selected Executives, adopted by the Board of Directors on August 27, 1992; filed as Exhibit 10.12a to the Company’s 1992 10-K.

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Exhibit
No.
10.09*	-	Form of Indemnification Agreement between Laclede and its Directors and Officers; filed as Exhibit 10.13 to the Company’s 1990 10-K.
10.10*	-	The Laclede Group Management Continuity Protection Plan, effective as of January 1, 2005; filed as Exhibit 10.5 to the Company’s 10-Q for the fiscal quarter ended December 31, 2008.
10.10a*	-	Form of Management Continuity Protection Agreement; Filed as Exhibit 10.05a to the Company’s 10-Q for the fiscal quarter ended December 31, 2008.
10.11*	-	Restricted Stock Plan for Non-Employee Directors as amended and effective January 29, 2009; filed as Exhibit 10.1 to the Company’s Form 10-Q for the fiscal quarter ended March 31, 2009.
10.11a*	-	Amendment to Restricted Stock Plan for Non-Employee Directors; filed as Exhibit 10.6 to the Company’s Form 10-Q for the fiscal quarter ended June 30, 2011.
10.12*	-	Salient Features of the Laclede Gas Company Deferred Income Plan II for Directors and Selected Executives (as amended and restated effective as of January 1, 2005); filed as Exhibit 10.1 to the Company’s 10-Q for the fiscal quarter ended December 31, 2008.
10.13*	-	Salient Features of the Company’s Deferred Income Plan for Directors and Selected Executives (effective as of January 1, 2005); filed as Exhibit 10.2 to the Company’s 10-Q for the fiscal quarter ended December 31, 2008.
10.14*	-	The Laclede Group, Inc. 2002 Equity Incentive Plan; filed as Exhibit 10.22 to the Company’s Form 10-K for the year ended September 30, 2002.
10.14a*	-	Form of Non-Qualified Stock Option Award Agreement with Mandatory Retirement Provisions; filed as Exhibit 10.1 to the Company’s Form 8-K filed November 5, 2004.
10.14b*	-	Form of Non-Qualified Stock Option Award Agreement without Mandatory Retirement Provisions; filed as Exhibit 10.2 to the Company’s Form 8-K filed November 5, 2004.
10.15*	-	Lease between Laclede Gas Company, as Lessee and First National Bank in St. Louis, Trustee, as Lessor; filed as Exhibit 10.23 to the Company’s Form 10-K for the fiscal year ended September 30, 2002.
10.16*	-	Automated Meter Reading Services Agreement executed March 11, 2005; filed as Exhibit 10.1 to the Company’s Form 10-Q for the fiscal quarter ended March 31, 2005. Confidential portions of this exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.
10.17*	-	The Laclede Group, Inc. Annual Incentive Plan; filed as Appendix 1 to the Company’s proxy statement filed December 17, 2010.
10.18*	-	The Laclede Group, Inc. 2006 Equity Incentive Plan; filed as Exhibit 10.1 to the Company’s 10-Q for the fiscal quarter ended March 31, 2012.
10.18a*	-	Form of Restricted Stock Award Agreement filed as Exhibit 10.8 to the Company’s 10-Q for the fiscal quarter ended December 31, 2008.
10.18b*	-	Form of Performance Contingent Restricted Stock Award Agreement; filed as Exhibit 10.2 to the Company’s 10-Q for the fiscal quarter ended December 31, 2009.
10.18c*	-	Form of Performance Contingent Restricted Stock Unit Award Agreement; filed as Exhibit 10.1 to the Company’s 10-Q for the fiscal quarter ended December 31, 2011.
10.18d*	-	Form of Performance Contingent Restricted Stock Unit Award Agreement; filed as Exhibit 10.1 to the Company's Form 10-Q for the fiscal quarter ended December 31, 2012.
10.19*	-	Amended and Restated Firm (Rate Schedule FT) Transportation Service Agreement between Laclede Energy Resources, Inc. and Centerpoint Energy Gas Transmission Company TSA #1006667; filed as Exhibit 10.1 to the Company’s 10-Q for the fiscal quarter ended June 30, 2012.
10.20	-	Loan agreement with The Laclede Group, Inc. dated September 3, 2013 with several banks, including Wells Fargo Bank, National Association, as Administrative Agent, U. S. Bank National Association and JPMorgan Chase Bank, N. A. as Co-Syndication Agents; Bank of America, N.A., Fifth Third Bank and Morgan Stanley Bank, N.A., as Co-Documentation Agents; and Wells Fargo Securities LLC, U.S. Bank National Assocation and J.P. Morgan Securities LLC as Joint Lead Arrangers and Joint Bookrunners; and Commerce Bank, UMB Bank, N.A., and Stifel Bank & Trust as the other participating banks.
10.21*	-	The Laclede Group 2011 Management Continuity Protection Plan; filed as Exhibit 10.25 to the Company’s Form 10-K for the fiscal year ended September 30, 2010.
10.21a*	-	Form of Agreement Under The Laclede Group 2011 Management Continuity Protection Plan; filed as Exhibit 10.25a to the Company’s Form 10-K for the fiscal year ended September 30, 2010.

100

Exhibit
No.
10.22*	-	Severance Benefits Agreement between The Laclede Group, Inc. and Suzanne Sitherwood effective September 1, 2011; filed as Exhibit 10.1 to the Company’s Form 10-Q for the fiscal quarter ended June 30, 2011.
10.23*	-	Performance Contingent Restricted Stock Agreement between The Laclede Group, Inc. and Suzanne Sitherwood effective September 1, 2011; filed as Exhibit 10.2 to the Company’s Form 10-Q for the fiscal quarter ended June 30, 2011.
10.24*	-	Restricted Stock Unit Award Agreement between The Laclede Group, Inc. and Suzanne Sitherwood effective September 1, 2011; filed as Exhibit 10.3 to the Company’s Form 10-Q for the fiscal quarter ended June 30, 2011.
10.25*	-	Restricted Stock Unit Award Agreement between The Laclede Group, Inc. and Steve Lindsey effective October 1, 2012; filed as Ex 10.25 to the Company's Form 10-K for the fiscal year ended September 30, 2012.
10.26*	-	Performance Contingent Restricted Stock Unit Award Agreement between The Laclede Group, Inc. and Steve Lindsey effective October 1, 2012; filed as Exhibit 10.26 to the Company's Form 10-K for the fiscal year ended September 30, 2012.
10.27*	-	Severance Benefits Agreement between The Laclede Group, Inc. and Steve Lindsey effective October 1, 2012; filed as Exhibit 10.27 to the Company's Form 10-K for the fiscal year ended September 30, 2012.
10.28*	-	Note Purchase Agreement between The Laclede Group, Inc. and certain institutional purchasers effective August 3, 2012; filed as Exhibit 10.28 to the Company's Form 10-K for the fiscal year ended September 30, 2012.
10.30*		Laclede Gas Company Cash Balance Supplemental Retirement Benefit Plan, effective as of January 1, 2009; filed as Exhibit 10.30 to the Company's Form 10-K for the fiscal year ended September 30, 2012.
10.31*		Purchase and Sale Agreement between Southern Union Company, Plaza Missouri Acquisition, Inc. and The Laclede Group, Inc. (Solely for purposes of Section 13.19 of the Agreement) dated as of December 14, 2012; filed December 14, 2013 as Exhibit 2.1 to Form 8-K.
10.31a*		Employee Agreement between Southern Union Company, Plaza Missouri Acquisition, Inc. and, for purposes of Section 13.19 of the Purchase and Sale Agreement, dated of even date herewith, to the extent incorporated herein, The Laclede Group, Inc. dated as of December 14, 2012; filed December 14, 2013 as Exhibit 2.3 to Form 8-K.
10.31b*		Assignment and Assumption Agreement by and between Plaza Missouri Acquisition, Inc. and Laclede Gas Company dated as of January 11, 2013; filed January 11, 2013 as Exhibit 99.1 to the Company's Form 8-K.
10.31c*		Consent to Assignment executed by Southern Union Company dated as of January 11, 2013; filed January 11, 2013 as Exhibit 99.2 to the Company's Form 8-K.
10.32*		Purchase and Sale Agreement between Southern Union Company, Plaza Massachusetts Acquisition, Inc. and The Laclede Group, Inc. (Solely for purposes of Section 13.19 of the Agreement) dated as of December 14, 2012; filed December 14, 2013 as Exhibit 2.2 to Form 8-K.
10.32a*		Employee Agreement between Southern Union Company, Plaza Massachusetts Acquisition, Inc. and, for purposes of Section 13.19 of the Purchase and Sale Agreement, dated of even date herewith, to the extent incorporated herein, The Laclede Group, Inc. dated as of December 14, 2012; filed December 14, 2013 as Exhibit 2.4 to Form 8-K.
10.32b*		Stock Purchase Agreement by and among The Laclede Group, Inc., Plaza Massachusetts Acquisition, Inc., and Algonquin Power & Utilities Corp. dated as February 11, 2013; filed February 11, 2013 as Exhibit 2.1 to the Company Form 8-K.
10.32c*		Consent Agreement by and among The Laclede Group, Inc., Plaza Massachusetts Acquisition, Inc. Southern Union Company and Algonquin Power & Utilities Corp. dated as of February 11, 2013; filed February 11, 2013 as Exhibit 2.2 to the Company Form 8-K.
12	-	Ratio of Earnings to Fixed Charges.
21	-	Subsidiaries of the Registrant.
23	-	Consent of Independent Registered Public Accounting Firm.
31	-	Certificates under Rule 13a-14(a) of the CEO and CFO of The Laclede Group, Inc.
32	-	Section 1350 Certifications under Rule 13a-14(b) of the CEO and CFO of The Laclede Group, Inc.
101.INS	-	XBRL Instance Document. (1)
101.SCH	-	XBRL Taxonomy Extension Schema. (1)
101.CAL	-	XBRL Taxonomy Extension Calculation Linkbase. (1)

101

Exhibit
No.
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 Consolidated Income for the years ended September 30, 2013, 2012, and 2011; (iii) Statements of Consolidated Comprehensive Income for the years ended September 30, 2013, 2012, and 2011; (iv) Consolidated Statements of Common Shareholders’ Equity for the years ended September 30, 2013, 2012, and 2011; (v) Statements of Consolidated Cash Flows for the years ended September 30, 2013, 2012, and 2011; (vi) Consolidated Balance Sheets at September 30, 2013 and 2012; (vii) Statements of Consolidated Capitalization at September 30, 2013 and 2012;

(viii) Notes to the Consolidated Financial Statements. We also make available on our website the Interactive Data Files submitted as Exhibit 101 to this Annual Report. 

*Incorporated herein by reference and made a part hereof. the Company’s File No. 1-16681.

Bold items reflect management, contract or compensatory plan or arrangement.

102

EX-10.20

EXECUTION VERSION

Published CUSIP Number: 50559XAC1

Revolving Credit CUSIP Number: 50559XAD9

LOAN AGREEMENT

BY AND AMONG

THE LACLEDE GROUP, INC.,

WELLS FARGO BANK, NATIONAL ASSOCIATION,

AS ADMINISTRATIVE AGENT,

U.S. BANK NATIONAL ASSOCIATION AND JPMORGAN CHASE BANK, N.A.,

AS CO-SYNDICATION AGENTS,

BANK OF AMERICA, N.A., FIFTH THIRD BANK AND MORGAN STANLEY BANK, N.A., AS CO-DOCUMENTATION AGENTS

AND

THE BANKS PARTY HERETO

WELLS FARGO SECURITIES LLC,

U.S. BANK NATIONAL ASSOCIATION, AND

J.P. MORGAN SECURITIES LLC

AS JOINT LEAD ARRANGERS AND JOINT BOOKRUNNERS

September 3, 2013

TABLE OF CONTENTS

Page

SECTION 1. DEFINITIONS.....................................................................................................    1

1.01 Definitions..............................................................................................................    1

1.02 Accounting Terms.................................................................................................    22

1.03 Other Terms; Construction....................................................................................    23

SECTION 2. THE LOANS......................................................................................................    23

2.01 Revolving Credit Commitments...........................................................................    23

2.02 Method of Borrowing...........................................................................................    28

2.03 Notes.....................................................................................................................    31

2.04 Duration of Interest Periods and Selection of Interest Rates................................    32

2.05 Interest Rates........................................................................................................    33

2.06 Computation of Interest........................................................................................    35

2.07 Fees.......................................................................................................................    35

2.08 Prepayments..........................................................................................................    36

2.09 General Provisions as to Payments.......................................................................    37

2.10 Funding Losses.....................................................................................................    39

2.11 Basis for Determining Interest Rate Inadequate or Unfair...................................    39

2.12 Illegality................................................................................................................    40

2.13 Increased Cost.......................................................................................................    40

2.14 Base Rate Loans Substituted for Affected LIBOR Loans....................................    41

2.15 Capital Adequacy..................................................................................................    41

2.16 Survival of Indemnities........................................................................................    41

2.17 Discretion of Banks as to Manner of Funding......................................................    42

2.18 Obligations of Banks are Several; Sharing of Payments......................................    42

2.19 Substitution of Bank.............................................................................................    43

2.20 Taxes.....................................................................................................................    44

2.21 Defaulting Banks..................................................................................................    46

SECTION 3. LETTERS OF CREDIT......................................................................................    48

3.01 Issuance.................................................................................................................    48

3.02 Notices..................................................................................................................    49

3.03 Participations........................................................................................................    49

3.04 Reimbursement.....................................................................................................    50

3.05 Payment by Revolving Loans...............................................................................    50

3.06 Payment to Banks.................................................................................................    51

3.07 Obligations Absolute............................................................................................    51

3.08 Cash Collateral Account.......................................................................................    53

3.09 The Issuing Banks.................................................................................................    53

3.10 Effectiveness.........................................................................................................    53

SECTION 4. CONDITIONS PRECEDENT............................................................................    54

4.01 Conditions to Closing and Initial Loans...............................................................    54

4.02 All Extensions of Credit.......................................................................................    55

i

TABLE OF CONTENTS

(continued)

Page

SECTION 5. REPRESENTATIONS AND WARRANTIES...................................................    56

5.01 Corporate Existence and Power............................................................................    56

5.02 Corporate Authorization.......................................................................................    56

5.03 Binding Effect.......................................................................................................    56

5.04 Governmental and Third-Party Authorization......................................................    57

5.05 Litigation..............................................................................................................    57

5.06 Taxes.....................................................................................................................    57

5.07 Subsidiaries...........................................................................................................    57

5.08 No Material Adverse Effect..................................................................................    57

5.09 Financial Statements.............................................................................................    58

5.10 Compliance With Other Instruments; None Burdensome....................................    58

5.11 ERISA...................................................................................................................    58

5.12 Regulation U.........................................................................................................    59

5.13 Investment Company Act of 1940........................................................................    59

5.14 [Reserved].............................................................................................................    59

5.15 Labor Relations.....................................................................................................    59

5.16 Use of Proceeds....................................................................................................    59

5.17 Compliance with Laws.........................................................................................    59

5.18 Full Disclosure......................................................................................................    59

5.19 OFAC; Anti-Terrorism Laws................................................................................    60

5.20 No Default............................................................................................................    60

SECTION 6. COVENANTS....................................................................................................    60

6.01 Affirmative Covenants of Borrower.....................................................................    60

6.02 Maximum Consolidated Capitalization Ratio......................................................    64

6.03 Negative Covenants of Borrower..........................................................................    64

6.04 Use of Proceeds....................................................................................................    66

SECTION 7. EVENTS OF DEFAULT....................................................................................    67

SECTION 8. ADMINISTRATIVE AGENT............................................................................    69

8.01 Appointment and Authority..................................................................................    69

8.02 Rights as a Bank...................................................................................................    69

8.03 Exculpatory Provisions.........................................................................................    70

8.04 Reliance by Administrative Agent........................................................................    71

8.05 Delegation of Duties.............................................................................................    71

8.06 Resignation of Administrative Agent....................................................................    71

8.07 Non-Reliance on Administrative Agent and Other Banks....................................    72

8.08 No Other Duties, Etc.............................................................................................    72

8.09 Enforcement..........................................................................................................    72

8.10 Issuing Bank and Swingline Bank........................................................................    72

SECTION 9. GENERAL.........................................................................................................    73

9.01 No Waiver.............................................................................................................    73

ii

TABLE OF CONTENTS

(continued)

Page

9.02 Right of Set-Off....................................................................................................    73

9.03 Costs and Expenses; General Indemnity..............................................................    73

9.04 Notices..................................................................................................................    76

9.05 Consent to Jurisdiction; Waiver of Jury Trial.......................................................    76

9.06 Governing Law.....................................................................................................    77

9.07 Amendments and Waivers....................................................................................    78

9.08 References; Headings for Convenience................................................................    79

9.09 Successors and Assigns.........................................................................................    79

9.10 Entire Agreement..................................................................................................    82

9.11 Severability...........................................................................................................    82

9.12 Counterparts..........................................................................................................    82

9.13 Confidentiality......................................................................................................    82

9.14 USA Patriot Act Notice.........................................................................................    83

9.15 [Reserved].............................................................................................................    83

9.16 No Fiduciary Duty................................................................................................    83

iii

TABLE OF CONTENTS

(continued)

Page

Schedules

1.01 Revolving Credit Commitments and Pro Rata Shares

2.02 Authorized Individuals

5.04 Authorizations

5.07 Subsidiaries

5.11(a) ERISA

9.04 Notice Addresses

Exhibits

A-1 Form of Revolving Credit Note

A-2 Form of Swingline Note

B-1 Form of Notice of Borrowing

B-2 Form of Notice of Swingline Borrowing

B-3 Form of Notice of Election

B-4 Form of Letter of Credit Notice

C Form of Compliance Certificate

D Form of Assignment and Assumption Agreement

iv

LOAN AGREEMENT

THIS LOAN AGREEMENT (this “Agreement”) is made and entered into as of September 3, 2013, by and among THE LACLEDE GROUP, INC., a Missouri corporation (“Borrower”), the Banks from time to time party hereto and WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent for the Banks.

RECITALS

A.Borrower has requested that the Banks make available to Borrower a revolving credit facility in the aggregate principal amount of ONE HUNDRED AND FIFTY MILLION DOLLARS ($150,000,000). Borrower will use the proceeds of this facility for working capital and general corporate purposes.

B.The Banks are willing to make available to Borrower the credit facility described herein subject to and on the terms and conditions set forth in this Agreement.

AGREEMENT

NOW, THEREFORE, in consideration of the premises and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Borrower, the Issuing Banks, the Swingline Bank, the Banks and the Administrative Agent hereby mutually covenant and agree as follows:

SECTION 1.DEFINITIONS.

1.01Definitions. In addition to the terms defined elsewhere in this Agreement or in any Exhibit or Schedule hereto, when used in this Agreement, the following terms shall have the following meanings (such meanings shall be equally applicable to the singular and plural forms of the terms used, as the context requires):

“Account Designation Letter” means a letter from Borrower to the Administrative Agent, duly completed and signed by an Authorized Individual of Borrower and in form and substance reasonably satisfactory to the Administrative Agent, listing any one or more accounts to which Borrower may from time to time request the Administrative Agent to forward the proceeds of any Loans made hereunder.

“Acquisition” shall mean any transaction or series of related transactions, consummated on or after the date of this Agreement, by which Borrower or any Subsidiary directly or indirectly (a) acquires all or substantially all of the assets comprising one or more business units of any other Person, whether through purchase of assets, merger or otherwise or (b) acquires (in one transaction or as the most recent transaction in a series of transactions) at least (i) a majority (in number of votes) of the stock and/or other securities of a corporation having ordinary voting power for the election of directors (other than stock and/or other securities having such power only by reason of the happening of a contingency), (ii) a majority (by percentage of voting power) of the outstanding partnership interests of a partnership, (iii) a majority (by percentage voting power) of the outstanding membership interests of a limited liability company or (iv) a

majority of the ownership interests in any organization or entity other than a corporation, partnership or limited liability company.

“Acquisition Date” means the date the MGE Acquisition is consummated.

“Adjusted Base Rate” shall mean the Base Rate plus the Applicable Rate for Base Rate Loans.

“Adjusted LIBOR Rate” shall mean, at any time with respect to any LIBOR Loan, a rate per annum equal to the LIBOR Rate as in effect at such time plus the Applicable Rate for LIBOR Loans as in effect at such time.

“Administrative Agent” shall mean Wells Fargo, in its capacity as administrative agent for the Banks under this Agreement and certain of the other Transaction Documents and its successors in such capacity.

“Administrative Questionnaire” shall mean an Administrative Questionnaire in a form supplied by the Administrative Agent.

“Affected Bank” shall have the meaning ascribed thereto in Section 2.19.

“Affiliate” shall mean, with respect to a specified Person, another Person that directly, or indirectly through one or more intermediaries, controls or is controlled by or is under common control with the Person specified. For purposes of this definition, “control” shall mean the power to direct or cause the direction of the management and policies of a Person, directly or indirectly, whether through the ownership of voting securities, by contract or otherwise. Notwithstanding the foregoing, neither the Administrative Agent nor any Bank shall be deemed an “Affiliate” of Borrower.

“Agreement” shall mean this Loan Agreement.

“Applicable Rate” shall mean the corresponding percentages per annum as set forth below based on the applicable Debt Rating (as defined below):

Pricing Level	Debt Rating	Commitment Fee Rate	LIBOR Loans and Letter of Credit Fees	Base Rate Loans
I	≥A+/A1/A+	0.075%	0.875%	0%
II	A/A2/A	0.100%	1.000%	0%
III	A-/A3/A-	0.125%	1.125%	0.125%
IV	BBB+/Baa1/BBB+	0.175%	1.250%	0.250%

2    

V ≤BBB/Baa2/BBB 0.225% 1.500% 0.500%

“Debt Rating” means, with respect to Borrower as of any date of determination, the rating as determined by any of S&P, Fitch or Moody’s of Borrower’s senior unsecured non-credit enhanced long-term indebtedness; provided, that if Borrower does not have a Debt Rating available, then the applicable Pricing Level will be determined by reference to the issuer credit rating assigned to Borrower by S&P, the issuer rating assigned to Borrower by Moody’s and the issuer default rating assigned to Borrower by Fitch (which rating shall be deemed the Debt Rating for the succeeding sentences of this paragraph). If at any time (i) there is a split among Debt Ratings by S&P, Fitch and Moody’s such that all three Debt Ratings fall in different Pricing Levels, the applicable Pricing Level shall be determined by the Debt Rating that is neither the highest nor the lowest of the three Debt Ratings; (ii) there is a split among Debt Ratings by S&P, Fitch and Moody’s such that two of such Debt Ratings are in one Pricing Level (the “Majority Level”) and the third rating is in a different Pricing Level, the applicable Pricing Level shall be at the Majority Level; and (iii) the applicable pricing level in the Laclede Gas Loan Agreement is lower than the applicable Pricing Level in this Agreement (Pricing Level I being the highest Pricing Level), the applicable Pricing Level in this Agreement shall be determined by reference to the applicable pricing level in the Laclede Gas Loan Agreement. In the event that Borrower shall maintain Debt Ratings from only two of S&P, Moody’s and Fitch and Borrower is split-rated and the Debt Ratings differential is one level, the higher Debt Rating will apply and if the Debt Ratings differential is two levels or more, the level one level lower than the higher Debt Rating will apply. If at any time Borrower does not have a Debt Rating from at least one of S&P or Moody’s, the applicable Pricing Level shall be set at Pricing Level V.

“Approved Fund” shall mean any Fund that is administered or managed by (i) a Bank, (ii) an Affiliate of a Bank, or (iii) a Person (or an Affiliate of a Person) that administers or manages a Bank.

“Arrangers” shall mean Wells Fargo Securities, U.S. Bank and JPM Securities.

“Assignee” shall have the meaning ascribed thereto in Section 9.09(c).

“Assignment and Assumption” shall mean an Assignment and Assumption entered into by any Bank or Assignee (with the consent of any Person whose consent is required by Section 9.09), substantially in the form of Exhibit D or any other form approved by the Administrative Agent.

“Authorized Individuals” shall have the meaning ascribed thereto in Section 2.02(i).

“Banks” shall mean the banks from time to time party to this Agreement and their successors and permitted assigns. Unless the context clearly indicates otherwise, the term “Banks” shall include the Issuing Banks and the Swingline Bank.

“Base Rate” shall mean, at any time, the highest of (a) the Prime Rate, (b) the Fed Funds Rate plus 0.50% and (c) LIBOR for an Interest Period of one month plus 1%; each change in the

3    

Base Rate shall take effect simultaneously with the corresponding change or changes in the Prime Rate, the Federal Funds Rate or LIBOR.

“Base Rate Loan” shall mean, at any time, any Loan that bears interest at such time at the applicable Adjusted Base Rate.

“Borrower” shall have the meaning ascribed thereto in the introductory paragraph hereof.

“Borrower’s Obligations” shall mean any and all present and future indebtedness (principal, interest (including interest accruing after the filing of a petition or commencement of a case by or with respect to Borrower seeking relief under any applicable federal and state laws pertaining to bankruptcy, reorganization, arrangement, moratorium, readjustment of debts, dissolution, liquidation or other debtor relief and any fraudulent transfer and fraudulent conveyance laws, whether or not the claim for such interest is allowed in such proceeding), fees, collection costs and expenses, attorneys’ fees and other amounts), liabilities and obligations (including, without limitation, indemnity obligations) of Borrower to the Administrative Agent, the Swingline Bank, any Issuing Bank, any other Bank, or any other Person entitled thereto evidenced by or arising under or in respect of this Agreement, any Note and/or any other Transaction Document.

“Business Day” shall mean (a) for all purposes other than as set forth in clause (b) below, any day other than a Saturday, Sunday or legal holiday on which banks in Charlotte, North Carolinaand New York, New York, are open for the conduct of their commercial banking business, and (b) with respect to all notices and determinations in connection with, and payments of principal and interest on, any LIBOR Rate Loan, or any Base Rate Loan as to which the interest rate is determined by reference to LIBOR,any day that is a Business Day described in clause (a) and that is also a day for trading by and between banks in Dollar deposits in the London interbank market.

“Capital Stock” shall mean (a) with respect to any Person that is a corporation, any and all shares, interests or equivalents in Capital Stock (whether voting or nonvoting, and whether common or preferred) of such corporation, and (b) with respect to any Person that is not a corporation, any and all partnership, membership, limited liability company or other equity interests of such Person; and in each case, any and all warrants, rights or options to purchase any of the foregoing.

“Capitalized Lease” shall mean any lease of property, whether real and/or personal, by a Person as lessee which in accordance with GAAP is required to be capitalized on the balance sheet of such Person.

“Capitalized Lease Obligations” of any Person shall mean, as of the date of any determination thereof, the amount at which the aggregate rental obligations due and to become due under all Capitalized Leases under which such Person is a lessee would be reflected as a liability on a balance sheet of such Person in accordance with GAAP.

“Cash Collateral Account” shall have the meaning ascribed to such term inSection 3.08.

4    

“Cash Collateralize” means to pledge and deposit with or deliver to the Administrative Agent, for the benefit of the Administrative Agent, any Issuing Bank or the Swingline Bank (as applicable) and the Banks, to be held as collateral for the Letter of Credit Exposure, the Swingline Exposure, or obligations of Banks to fund participations in respect of either thereof (as the context may require), cash or deposit account balances or, if the Issuing Bank or the Swingline Bank benefiting from such collateral shall agree in its sole discretion, other credit support, in each case pursuant to documentation in form and substance satisfactory to (a) the Administrative Agent and (b) such Issuing Bank or the Swingline Bank. “Cash Collateral” shall have a meaning correlative to the foregoing and shall include the proceeds of such cash collateral and other credit support.

“Change of Control Event” shall mean an event or series of events by which:

(a)any “person” or “group” (as such terms are used in Sections 13(d) and 14(d) of the Exchange Act, but excluding any employee benefit plan of such person or its Subsidiaries, and any person or entity acting in its capacity as trustee, agent or other fiduciary or administrator of any such plan) becomes the “beneficial owner” (as defined in Rules 13d-3 and 13d-5 under the Exchange Act, except that a “person” or “group” shall be deemed to have “beneficial ownership” of all Capital Stock that such “person” or “group” has the right to acquire, whether such right is exercisable immediately or only after the passage of time (such right, an “option right”)), directly or indirectly, of more than thirty percent (30%) of the Capital Stock of the Borrower entitled to vote in the election of members of the board of directors (or equivalent governing body) of Borrower or (ii) a majority of the members of the board of directors (or other equivalent governing body) of Borrower shall not constitute Continuing Directors; or

(b)Borrower shall fail to own legally or beneficially one hundred percent (100%) (by number of votes) of the Voting Stock of Laclede Gas.

“Closing Date” shall mean the first date upon which each of the conditions set forth in Section 4.01shall have been satisfied or waived in accordance with the terms of this Agreement.

“Code” shall mean the Internal Revenue Code of 1986.

“Commitment Letter” shall mean that certain commitment letter agreement, dated June 25, 2013, among Wells Fargo, Wells Fargo Securities, US Bank, JPMorgan, JPM Securities, Borrower and Laclede Gas, as the same may from time to time be amended, modified, extended, renewed or restated.

“Compliance Certificate” shall mean a fully completed and duly executed certificate substantially in the form of Exhibit C, together with a Covenant Compliance Worksheet.

“Consolidated Capitalization” shall mean, as of the date of any determination thereof, the sum of Consolidated Debt as of such day plus Consolidated Net Worth as of such day, all determined on a consolidated basis and in accordance with GAAP.

“Consolidated Capitalization Ratio” shall mean, as of the date of any determination thereof, the ratio (expressed as a percentage) of Consolidated Debt as of such day to

5    

Consolidated Capitalization as of such day, all determined on a consolidated basis and in accordance with GAAP.

“Consolidated Debt” shall mean, as of the date of any determination thereof, all Debt of Borrower and its Subsidiaries as of such date, determined on a consolidated basis and in accordance with GAAP.

“Consolidated Net Worth” shall mean, as of the date of any determination thereof, the amount of the Capital Stock accounts (net of treasury stock, at cost) of Borrower and its Subsidiaries as of such date plus (or minus in the case of a deficit) the surplus and retained earnings of Borrower and its Subsidiaries as of such date, all determined on a consolidated basis and in accordance with GAAP.

“Continuing Directors” shall mean the directors of Borrower on the Closing Date and each other director of Borrower, if, in each case, such other director’s nomination for election to the board of directors (or equivalent governing body) of Borrower is recommended by at least 51% of the then Continuing Directors.

“Covenant Compliance Worksheet” means a fully completed worksheet in the form of Attachment A to Exhibit C.

“Debt” of any Person shall mean, as of the date of determination thereof, the sum of (a) all indebtedness of such Person for borrowed money or incurred in connection with the purchase or other acquisition of property (other than trade accounts payable incurred in the ordinary course of business not more than ninety (90) days past due) including, but not limited to, obligations of such Person evidenced by notes, bonds, debentures or similar instruments, or upon which interest payments are customarily made plus (b) all Capitalized Lease Obligations of such Person plus (c) the aggregate undrawn face amount of all letters of credit and/or surety bonds issued for the account and/or upon the application of such Person together with all unreimbursed drawings with respect thereto plus (d) all indebtedness created or arising under any conditional sale or other title retention agreement with respect to property acquired by such Person plus (e) all Disqualified Capital Stock issued by such Person, with the amount of indebtedness represented by such Disqualified Capital Stock being equal to the greater of its voluntary or involuntary liquidation preference and its maximum fixed repurchase price plus (f) the principal balance outstanding and owing by such Person under any synthetic lease, tax retention operating lease or similar off-balance sheet financing product plus (g) all Guarantees by such Person of Debt of others plus (h) for all purposes other than Section 6.02, the net obligations of such Person under any Swap Contracts plus (i) all indebtedness of the types referred to in clauses (a) through (h) above (i) of any partnership or unincorporated joint venture in which such Person is a general partner or joint venturer to the extent such Person is liable therefor or (ii) secured by any Lien (other than leases qualified as operating leases under GAAP) on any property or asset owned or held by such Person regardless of whether or not the indebtedness secured thereby shall have been incurred or assumed by such Person or is nonrecourse to the credit of such Person, the amount thereof being equal to the value of the property or assets subject to such Lien. The amount of any net obligation under any Swap Contract on any date shall be deemed to be the Swap Termination Value thereof as of such date. For the avoidance of doubt and

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notwithstanding anything to the contrary set forth above, Permitted Commodity Hedging Obligations shall not constitute Debt for purposes of this Agreement.

“Default” shall mean any event or condition the occurrence of which would, with the lapse of time or the giving of notice or both, become an Event of Default.

“Defaulting Bank” means, subject to Section 2.21(b), any Bank that (a) has failed to perform any of its funding or issuing obligations hereunder, including in respect of its Loans, Letters of Credit or participations in Letters of Credit or Swingline Loans, within three (3) Business Days of the date required to be funded by it hereunder, unless such Bank notifies the Administrative Agent and the Borrower in writing that such failure is the result of such Bank’s determination that one or more conditions precedent to funding or issuing (each of which conditions precedent, together with any applicable default, shall be specifically identified in such writing) has not been satisfied, (b) has notified Borrower or the Administrative Agent that it does not intend to comply with its funding obligations or has made a public statement to that effect with respect to its funding obligations hereunder or under other agreements in which it commits to extend credit (unless such writing or public statement relates to such Bank’s obligation to fund a Loan or issue a Letter of Credit hereunder and states that such position is based on such Bank’s determination that a condition precedent to funding or issuing (which condition precedent, together with any applicable default, shall be specifically identified in such writing or public statement) cannot be satisfied), (c) has failed, within three (3) Business Days after written request by the Administrative Agent or the Borrower, to confirm in writing to the Administrative Agent and the Borrower that it will comply with its prospective funding obligations hereunder (provided that such Bank shall cease to be a Defaulting Bank pursuant to this clause (c) upon receipt of such written confirmation by the Administrative Agent and Borrower), or (d) has, or has a direct or indirect parent company that has (i) become the subject of a proceeding under any bankruptcy, insolvency or other similar laws, or (ii) had appointed for it a receiver, custodian, conservator, trustee, administrator, assignee for the benefit of creditors or similar Person charged with reorganization or liquidation or its business or assets, including the Federal Deposit Insurance Corporation or any other state or federal regulatory authority acting in such a capacity; provided that a Bank shall not be a Defaulting Bank solely by virtue of the ownership or acquisition of any equity interest in that Bank or any direct or indirect parent company thereof by a Governmental Authority so long as such ownership interest does not result in or provide such Bank with immunity from the jurisdiction of courts within the United States or from the enforcement of judgments or writs of attachment on its assets or permit such Bank (or such Governmental Authority) to reject, repudiate, disavow or disaffirm any contracts or agreements made with such Bank. Any determination by the Administrative Agent that a Bank is a Defaulting Bank under any one or more of clauses (a) through (d) above shall be conclusive and binding absent manifest error, and such Bank shall be deemed to be a Defaulting Bank (subject to Section 2.21(b)) upon delivery of written notice of such determination to Borrower, each Issuing Bank, the Swingline Lender and each Bank.

“Disqualified Capital Stock” shall mean, with respect to any Person, any Capital Stock of such Person that, by its terms (or by the terms of any security into which it is convertible or for which it is exchangeable), or upon the happening of any event or otherwise, (a) matures or is mandatorily redeemable or subject to any mandatory repurchase requirement, pursuant to a sinking fund obligation or otherwise, (b) is redeemable or subject to any mandatory repurchase

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requirement at the sole option of the holder thereof, or (c) is convertible into or exchangeable for (whether at the option of the issuer or the holder thereof) (i) debt securities or (ii) any Capital Stock referred to in (a) or (b) above, in each case under (a), (b) or (c) above at any time on or prior to the first anniversary of the last day of the Revolving Credit Period; provided, however, that only the portion of Capital Stock that so matures or is mandatorily redeemable, is so redeemable at the option of the holder thereof, or is so convertible or exchangeable on or prior to such date shall be deemed to be Disqualified Capital Stock.

“Dollar” or “$” shall mean dollars of the United States of America.

“ERISA” shall mean the Employee Retirement Income Security Act of 1974.

“ERISA Affiliate” shall mean any Person (including any trade or business, whether or not incorporated) deemed to be under “common control” with, or a member of the same “controlled group” as, Borrower or any of its Subsidiaries, within the meaning of Sections 414(b), (c), (m) or (o) of the Code or Section 4001 of ERISA.

“ERISA Event” shall mean any of the following with respect to a Plan or Multiemployer Plan, as applicable: (a) a Reportable Event, (b) a complete or partial withdrawal by Borrower or any ERISA Affiliate from a Multiemployer Plan that results in liability under Section 4201 or 4204 of ERISA, or the receipt by Borrower or any ERISA Affiliate of notice from a Multiemployer Plan that it is in reorganization or insolvency pursuant to Section 4241 or 4245 of ERISA or that it intends to terminate or has terminated under Section 4041A of ERISA, (c) the distribution by Borrower or any ERISA Affiliate under Section 4041 or 4041A of ERISA of a notice of intent to terminate any Plan or the taking of any action to terminate any Plan, (d) the commencement of proceedings by the PBGC under Section 4042 of ERISA for the termination of, or the appointment of a trustee to administer, any Plan, or the receipt by Borrower or any ERISA Affiliate of a notice from any Multiemployer Plan that such action has been taken by the PBGC with respect to such Multiemployer Plan, (e) the institution of a proceeding by any fiduciary of any Multiemployer Plan against Borrower or any ERISA Affiliate to enforce Section 515 of ERISA, which is not dismissed within 30 days, (f) the imposition upon Borrower or any ERISA Affiliate of any liability under Title IV of ERISA, other than for PBGC premiums due but not delinquent under Section 4007 of ERISA, or the imposition or threatened imposition of any Lien upon any assets of Borrower or any ERISA Affiliate as a result of any alleged failure to comply with the Code or ERISA in respect of any Plan, (g) the engaging in or otherwise becoming liable for a nonexempt Prohibited Transaction by Borrower or any ERISA Affiliate, or a violation of the applicable requirements of Section 404 or 405 of ERISA or the exclusive benefit rule under Section 401(a) of the Code by any fiduciary of any Plan for which Borrower or any of its ERISA Affiliates may be directly or indirectly liable, (h) the failure of any Plan to satisfy the minimum funding standard of Section 302 of ERISA and Section 412 of the Code, whether or not waived, (i) with respect to plan years beginning prior to January 1, 2008, the adoption of an amendment to any Plan that, pursuant to Section 307 of ERISA, would require the provision of security to such Plan by Borrower or an ERISA Affiliate, or (j) with respect to plan years beginning on or after the PPA 2006 Effective Date, the incurrence of an obligation to provide a notice under Section 101(j) of ERISA, the adoption of an amendment which may not take effect due to the application of Section 436(c)(1) of the Code or Section 206(g)(2)(A) of

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ERISA, or the payment of a contribution in order to satisfy the requirements of Section 436(c)(2) of the Code or Section 206(g)(2)(B) of ERISA.

“Event of Default” shall have the meaning ascribed thereto in Section 7.

“Exchange Act” shall mean the Securities Exchange Act of 1934.

“Excluded Taxes” shall mean, with respect to the Administrative Agent, any Bank, any Issuing Bank or any other recipient of any payment to be made by or on account of any obligation of Borrower hereunder, (a) taxes imposed on or measured by its overall net income (however denominated), and franchise taxes imposed on it (in lieu of net income taxes), by the jurisdiction (or any political subdivision thereof) under the laws of which such recipient is organized or in which its principal office is located or, in the case of any Bank, in which its applicable Lending Office is located, (b) any branch profits taxes imposed by the United States of America or any similar tax imposed by any other jurisdiction in which Borrower is located, (c) in the case of a Foreign Bank (other than an assignee pursuant to a request by Borrower under Section 2.19), any withholding tax that is imposed on amounts payable to such Foreign Bank at the time such Foreign Bank becomes a party hereto (or designates a new Lending Office) or is attributable to such Foreign Bank’s failure or inability (other than as a result of a Regulatory Change) to comply with Section 2.20(e), except to the extent that such Foreign Bank (or its assignor, if any) was entitled, at the time of designation of a new lending office (or assignment), to receive additional amounts from Borrower with respect to such withholding tax pursuant to Section 2.20(a) and (d) any U.S. Federal withholding taxes imposed by FATCA.

“Existing Loan Agreement” shall mean that certain loan agreement, dated July 18, 2011, among Borrower, Wells Fargo, as administrative agent, and the lenders party thereto, as amended by the First Extension Agreement, dated August 17, 2012, and the First Amendment to Loan Agreement, dated January 16, 2013, and as otherwise amended or modified from time to time.

“Extension Request” shall have the meaning ascribed thereto in Section 2.01(f).

“FATCA” shall mean Sections 1471 through 1474 of the Code, as of the date of this Agreement (or any amended version that is substantively comparable), any current or future regulations or official interpretations thereof and any agreements entered into pursuant to Section 1471(b)(1) of the Code.

“Fed Funds Rate” shall mean, for any day, the rate per annum (rounded upward, if necessary, to the nearest 1/100 of 1%) equal to the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds brokers on such day, as published by the Federal Reserve Bank of New York on the Business Day next succeeding such day; provided that (a) if such day is not a Business Day, the Fed Funds Rate for such day shall be such rate on such transactions on the next preceding Business Day as so published on the next succeeding Business Day and (b) if no such rate is so published on such next succeeding Business Day, the Fed Funds Rate for such day shall be the average rate quoted to the Administrative Agent from three (3) federal funds brokers of

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recognized standing on such day on such transactions as determined in good faith by the Administrative Agent.

“Fee Letter” shall mean the Wells Fargo Fee Letter and/or the Passive Arrangers’ Fee Letter, as applicable.

“Financial Officer” shall mean, with respect to Borrower, the chief financial officer, vice president - finance, controller or treasurer of Borrower.

“Fitch” shall mean Fitch Rating Services, Inc.

“Foreign Bank” shall mean, with respect to Borrower, any Bank that is organized under the laws of a jurisdiction other than that in which Borrower is resident for tax purposes. For purposes of this definition, the United States, each State thereof and the District of Columbia shall be deemed to constitute a single jurisdiction.

“Fronting Exposure” shall mean, at any time there is a Defaulting Bank, (a) with respect to any Issuing Bank, such Defaulting Bank’s Letter of Credit Exposure with respect to Letters of Credit issued by such Issuing Bank other than such portion of such Defaulting Bank’s Letter of Credit Exposure as to which such Defaulting Bank’s participation obligation has been reallocated to other Banks or Cash Collateralized in accordance with Section 2.21, and (b) with respect to any Swingline Bank, such Defaulting Bank’s Swingline Exposure with respect to outstanding Swingline Loans made by the Swingline Bank other than Swingline Loans as to which such Defaulting Bank’s participation obligation has been reallocated to other Banks or Cash Collateralized in accordance with Section 2.21.

“Fund” means any Person (other than a natural person) that is (or will be) engaged in making, purchasing, holding or otherwise investing in commercial loans and similar extensions of credit in the ordinary course of its business.

“GAAP” shall mean, at any time, generally accepted accounting principles at such time in the United States (subject to the provisions of Section 1.02).

“Governmental Authority” shall mean the government of the United States of America or any other nation, or of any political subdivision thereof, whether state or local, and any agency, authority, instrumentality, regulatory body, court, central bank or other entity exercising executive, legislative, judicial, taxing, regulatory or administrative powers or functions of or pertaining to government (including any supra-national bodies such as the European Union or the European Central Bank).

“Guarantee” by any Person shall mean any obligation (other than endorsements of negotiable instruments for deposit or collection in the ordinary course of business), contingent or otherwise, of such Person guaranteeing, or in effect guaranteeing, any indebtedness or other obligation of any other Person who is not a Subsidiary of Borrower (the “primary obligor”) in any manner, whether directly or indirectly, including, without limitation, all obligations incurred through an agreement, contingent or otherwise, by such Person: (a) to purchase such indebtedness or obligation or any property constituting security therefor, or (b) to advance or supply funds (i) for the purchase or payment of such indebtedness or obligation, (ii) to maintain

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working capital or other balance sheet condition or otherwise to advance or make available funds for the purchase or payment of such indebtedness or obligation, (iii) to lease property or to purchase securities or other property or services primarily for the purpose of assuring the owner of such indebtedness or obligation of the ability of the primary obligor to make payment of the indebtedness or obligation or (iv) otherwise to assure the owner of the indebtedness or obligation of the primary obligor against loss in respect thereof. For the purposes of all computations made under this Agreement, a Guarantee in respect of any Debt shall be deemed to be Debt equal to the then outstanding principal amount of such Debt which has been guaranteed or such lesser amount to which the maximum exposure of the guarantor shall have been specifically limited. “Guarantee” when used as a verb shall have a correlative meaning.

“Indemnified Liabilities” shall have the meaning ascribed thereto in Section 9.03(b).

“Indemnified Taxes” shall means (i) Taxes, other than Excluded Taxes, imposed on or with respect to any payment made by or on account of any obligation of Borrower under any Transaction Document and (ii) to the extent not otherwise described in clause (i), Other Taxes.

“Indemnitees” shall have the meaning ascribed thereto in Section 9.03(b).

“Interest Period” shall mean with respect to each LIBOR Loan: (a) initially, the period commencing on the date of such Loan and ending 1, 2, 3 or 6 months thereafter (or 7 days thereafter if agreed upon by Borrower and each Bank), as Borrower may elect in the applicable Notice of Borrowing; and (b) thereafter, each period commencing on the last day of the immediately preceding Interest Period applicable to such Loan and ending 1, 2, 3 or 6 months thereafter (or 7 days thereafter if agreed upon by Borrower and each Bank), as Borrower may elect pursuant to Section 2.04(a); provided that: (c) subject to clauses (d) and (e) below, any Interest Period which would otherwise end on a day which is not a Business Day shall be extended to the next succeeding Business Day unless such Business Day falls in another calendar month, in which case such Interest Period shall end on the immediately preceding Business Day; (d) subject to clause (e) below, any Interest Period (other than an Interest Period of 7 days) which begins on the last Business Day of a calendar month (or on a day for which there is no numerically corresponding day in the calendar month at the end of such Interest Period) shall end on the last Business Day of the relevant calendar month at the end of such Interest Period; and (e) no Interest Period may extend beyond the last day of the Revolving Credit Period.

“Investment” shall mean any investment (including, without limitation, any loan or advance) of Borrower or any Subsidiary in or to any Person, whether payment therefor is made in cash or Capital Stock of Borrower or any Subsidiary, and whether such investment is directly or indirectly by acquisition of Capital Stock or Debt, or by loan, advance, transfer of property out of the ordinary course of business, capital contribution, equity or profit sharing interest, extension of credit on terms other than those normal in the ordinary course of business or otherwise.

“ISP” shall have the meaning ascribed thereto in Section 9.06.

“Issuing Bank” means each of Wells Fargo, U.S. Bank, and JPMorgan, each in its capacity as issuer thereof, or any successor thereto.

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“JPM Securities” means J.P. Morgan Securities LLC.

“JPMorgan” means JPMorgan Chase Bank, N.A.

“Laclede Gas” shall mean Laclede Gas Company, a Missouri corporation, and a wholly-owned Subsidiary of Borrower.

“Laclede Gas Loan Agreement” shall mean that certain loan agreement between Laclede Gas and the Administrative Agent dated as of even date herewith.

“Lending Office” shall mean, with respect to any Bank, the office of such Bank designated as such in such Bank’s Administrative Questionnaire or in connection with an Assignment and Assumption, or such other office as may be otherwise designated in writing from time to time by such Bank to Borrower and the Administrative Agent. A Bank may designate separate Lending Offices as provided in the foregoing sentence for the purposes of making or maintaining different Types of Loans, and, with respect to LIBOR Loans, such office may be a domestic or foreign branch or Affiliate of such Bank.

“Letter of Credit Commitment” means, as to any Issuing Bank, the obligation of such Issuing Bank to issue Letters of Credit for the account of the Borrower from time to time in an aggregate amount equal to $20,000,000. The aggregate Letter of Credit Commitment from all Issuing Banks on the Closing Date shall be $60,000,000.

“Letter of Credit Exposure” shall mean, with respect to any Bank at any time, such Bank’s Pro Rata Share of the sum of (a) the aggregate Stated Amount of all Letters of Credit outstanding at such time and (b) the aggregate amount of all Reimbursement Obligations outstanding at such time.

“Letter of Credit Maturity Date” shall mean the fifth Business Day prior to the last day of the Revolving Credit Period.

“Letter of Credit Notice” shall have the meaning ascribed thereto in Section 3.02.

“Letters of Credit” shall have the meaning ascribed thereto in Section 3.01.

“LIBOR Loan” shall mean any Loan bearing interest based on the Adjusted LIBOR Rate.

“LIBOR Market Index Rate” shall mean, with respect to any day, the rate per annum for one month Dollar deposits appearing on Reuters Screen LIBOR01 Page (or any successor page) as of 11:00 a.m., London time, on such day.

“LIBOR Rate” shall mean, with respect to each LIBOR Loan comprising part of the same borrowing for any Interest Period, an interest rate per annum obtained by dividing (a) (i) the rate of interest appearing on Reuters Screen LIBOR01 Page (or any successor page) that represents an average British Bankers Association Interest Settlement Rate for Dollar deposits or (ii) if no such rate is available, the rate of interest determined by the Administrative Agent to be the rate or the arithmetic mean of rates at which Dollar deposits in immediately available funds are offered to first-tier banks in the London interbank Eurodollar market, in each case under (i) and

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ii) above at approximately 11:00 a.m., London time, two (2) Business Days prior to the first day of such Interest Period for a period substantially equal to such Interest Period and in minimum amounts of at least $5,000,000 (rounded upward, if necessary, to the nearest 1/1000th of 1%), by (b) the amount equal to 1.00 minus the Reserve Requirement (expressed as a decimal) for such Interest Period.

“Lien” shall mean any interest in any property securing an obligation owed to, or a claim by, a Person other than the owner of the property, whether such interest is based on common law, statute or contract, including, without limitation, any security interest, mortgage, deed of trust, pledge, hypothecation, judgment lien or other lien or encumbrance of any kind or nature whatsoever, any conditional sale or trust receipt, any lease, consignment or bailment for security purposes and any Capitalized Lease.

“Loan” and “Loans” shall mean any or all of the Revolving Loans and the Swingline Loans.

“Material Adverse Effect” shall mean (a) a material adverse effect on the properties, assets, liabilities, business, operations, or financial condition of Borrower and its Subsidiaries taken as a whole, (b) a material impairment of Borrower’s ability to perform any of its obligations under this Agreement, any Note, and/or any other Transaction Document or (c) a material adverse effect on the validity or enforceability against Borrower of this Agreement or any Note.

“Material Subsidiary” means any Subsidiary of Borrower whose assets exceed 10% of the total consolidated assets of Borrower and its Subsidiaries as of the end of the most recently completed fiscal year.

“MGE” means Missouri Gas Energy, and shall include any Subsidiary of Borrower that, at any time on or after the Acquisition Date, owns all or substantially all of the assets acquired in the MGE Acquisition.

“MGE Acquisition” means the Acquisition, pursuant to the MGE Acquisition Agreement, of MGE by Laclede Gas.

“MGE Acquisition Agreement” means the Purchase and Sale Agreement, dated as of December 14, 2012, among Borrower, Plaza Missouri Acquisitions, Inc., and Southern Union Company, which was assigned to and assumed by Laclede Gas pursuant to an Assignment and Assumption Agreement, dated as of January 11, 2013, between Laclede Gas and Plaza Missouri Acquisitions, Inc.

“Moody’s” shall mean Moody’s Investors Service, Inc.

“Multiemployer Plan” shall mean any “multiemployer plan” within the meaning of Section 4001(a)(3) of ERISA to which Borrower or any ERISA Affiliate makes, is making or is obligated to make contributions or has made or been obligated to make contributions.

“Non-Consenting Bank” shall have the meaning ascribed thereto in Section 2.01(f).

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“Notes” shall mean any or all of the Revolving Credit Notes and Swingline Note.

“Notice of Borrowing” shall have the meaning ascribed thereto in Section 2.02(a).

“Notice of Election” shall have the meaning ascribed thereto in Section 2.04(a).

“Notice of Swingline Borrowing” shall have the meaning ascribed thereto in Section 2.02(c).

“OFAC” shall mean the U.S. Department of the Treasury’s Office of Foreign Assets Control, and any successor thereto.

“Other Taxes” shall mean all present or future stamp, court or documentary, intangible, recording, filing or similar Taxes that arise from any payment made under, from the execution, delivery, performance, enforcement or registration of, from the receipt or perfection of a security interest under, or otherwise with respect to, any Transaction Document.

“Participant” shall have the meaning ascribed thereto in Section 9.09(b).

“Passive Arrangers’ Fee Letter” shall mean that certain fee letter agreement, dated June 25, 2013, between JPMorgan, JPM Securities, U.S Bank, Borrower and Laclede Gas, as the same may from time to time be amended, modified, extended, renewed or restated.

“PATRIOT Act” shall mean the Uniting and Strengthening America by Providing Appropriate Tools Required to Intercept and Obstruct Terrorism (USA PATRIOT Act) of 2001, as amended from time to time, and any successor statute, and all rules and regulations from time to time promulgated thereunder.

“PBGC” shall mean the Pension Benefit Guaranty Corporation established pursuant to Subtitle A of Title IV of ERISA, and any successor thereto.

“Permitted Commodity Hedging Obligations” means obligations of the Borrower with respect to commodity agreements or other similar agreements or arrangements entered into in the ordinary course of business designed to protect against, or mitigate risks with respect to, fluctuations of commodity prices to which the Borrower is exposed in the conduct of its business so long as (a) the management of the Borrower has determined that entering into such agreements or arrangements are bona fide hedging activities which comply with the Borrower’s risk management policies and (b) such agreements or arrangements are not entered into for speculative purposes.

“Permitted Investment” shall mean any Investment or Acquisition, or any expenditure or any incurrence of any liability to make any expenditure for an Investment or Acquisition, other than (a) any Investment or Acquisition the result of which would be to change substantially the nature of the business engaged in by Borrower and its Subsidiaries, considered as a whole, as of the date of this Agreement, and reasonable extensions thereof, (b) any Investment that is in the nature of a hostile or contested Acquisition, and (c) any Investment that would result in a Default or Event of Default; provided, that it is expressly agreed that all Investments under Borrower’s gas supply risk management program are Permitted Investments.

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“Permitted Liens” shall mean, with respect to any Person, any of the following:

(a)(i) Liens created pursuant to the Transaction Documents and (ii) Liens on cash or deposits granted in favor of the Swingline Bank or any Issuing Bank to Cash Collateralize any Defaulting Bank’s participation in Letters of Credit or Swingline Loans;

(b)Liens for taxes, assessments and other governmental charges or levies (excluding any Lien imposed pursuant to any of the provisions of ERISA or environmental laws) (i) not yet due or as to which the period of grace (not to exceed sixty (60) days), if any, related thereto has not expired or (ii) which are being contested in good faith and by appropriate proceedings if adequate reserves are maintained to the extent required by GAAP;

(c)Liens in respect of property imposed by law such as materialmen’s, mechanics’, carriers’, warehousemen’s, processors’ or landlords’ and other nonconsensual statutory liens incurred in the ordinary course of business, which (i) are not overdue for a period of more than sixty (60) days, or if more than sixty (60) days overdue, no action has been taken to enforce such Liens or such Liens are being contested in good faith and by appropriate proceedings if adequate reserves are maintained to the extent required by GAAP and (ii) do not, individually or in the aggregate, materially impair the use thereof in the operation of the business of the Borrower or any of its Subsidiaries;

(d)Liens arising from good faith performance of bids, tenders, contracts (other than contracts for the payment of money), leases, statutory obligations, surety and appeal bonds, and other obligations of like nature arising in the ordinary course of such Person’s business, including, without limitation, deposits and pledges of funds securing Permitted Commodity Hedging Obligations;

(e)encumbrances in the nature of zoning restrictions, easements, rights of way or restrictions of record on the use of real property, which in the aggregate do not, in any material respect, impair the use thereof in the ordinary conduct of business;

(f)Liens arising from the filing of precautionary UCC financing statements relating solely to personal property leased pursuant to operating leases entered into in the ordinary course of business of the Borrower and its Subsidiaries;

(g)Liens securing Debt incurred in connection with Capitalized Leases; provided that (i) such Liens shall be created substantially simultaneously with the acquisition, repair, improvement or lease, as applicable, of the related property and (ii) such Liens do not at any time encumber any property other than the property financed by such Debt;

(h)Liens securing judgments for the payment of money not constituting an Event of Default under Section 7(j) or securing appeal or other surety bonds relating to such judgments;

(i)Liens on property (i) of any Person which are in existence at the time that such Person is acquired pursuant to an Acquisition that constitutes a Permitted Investment and (ii) of the Borrower or any of its Subsidiaries existing at the time such tangible property or tangible assets are purchased or otherwise acquired by the Borrower or such Subsidiary thereof pursuant to a transaction permitted pursuant to this Agreement; provided that, with respect to each of the

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foregoing clauses (i) and (ii), (A) such Liens are not incurred in connection with, or in anticipation of, such Acquisition, purchase or other acquisition, (B) such Liens are not “blanket” or all asset Liens and (C) such Liens do not attach to any other property of the Borrower or any of its Subsidiaries;

(j)Liens under the Laclede Gas Mortgage and Deed of Trust dated as of February 1, 1945;

(k)(i) Liens of a collecting bank arising in the ordinary course of business under Section 4-210 of the Uniform Commercial Code in effect in the relevant jurisdiction and (ii) Liens of any depositary institution in connection with statutory, common law and contractual rights relating to liens, rights of set-off, recoupment or similar rights with respect to any deposit account or other fund of any Borrower or any Subsidiary thereof;

(l)(i) contractual or statutory Liens of landlords to the extent relating to the property and assets relating to any lease agreements with such landlord, and (ii) contractual Liens of suppliers (including sellers of goods) or customers granted in the ordinary course of business to the extent limited to the property or assets relating to such contract;

(m)any interest or title of a licensor, sublicensor, lessor or sublessor with respect to any assets under any license or lease agreement entered into in the ordinary course of business which do not (i) interfere in any material respect with the business of the Borrower or its Subsidiaries or materially detract from the value of the relevant assets of the Borrower or its Subsidiaries or (ii) secure any Debt;

(n)Liens incurred in connection with the Permitted Securitization;

(o)Liens incurred under and pursuant to the Laclede Gas Loan Agreement;

(p)pledges or deposits made in the ordinary course of business to secure payment of worker’s compensation insurance, unemployment insurance, pensions or social security programs;

(q)Liens arising from good faith deposits in connection with or to secure performance of statutory obligation and surety and appeal bonds;

(r)Liens on the proceeds of assets that were subject to Liens permitted hereunder or on assets acquired with such proceeds as a replacement of such former assets;

(s)any Lien on any assets securing purchase money Debt or Debt incurred or assumed for the purpose of financing all or any part of the cost of acquiring, developing, operating, constructing, altering, repairing or improving all or part of such assets; provided such Lien attached to such asset concurrently with or within ninety (90) days after the acquisition thereof, completion of construction, improvement or repair, or commencement of commercial operation of such assets;

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(t)Liens constituted by a right of set off or rights over a margin call account, or any form of cash collateral, or any similar arrangement, securing Permitted Commodity Hedging Obligations and/or physical trade obligations;

(u)Liens not otherwise permitted hereunder securing Debt or other obligations in the aggregate principal amount not to exceed 15% of Consolidated Net Worth at any time outstanding, less any amount outstanding under the Permitted Securitization; and

(v)any extension, renewal or replacement (or successive extensions, renewals or replacements), as a whole or in part, of any Liens referred to in the foregoing clauses (a) through (u) for amounts not exceeding the principal of the indebtedness (including undrawn commitments) secured by the Lien so extended, renewed or replaced; provided that such extension, renewal or replacement Lien is limited to all or part of the same property or assets that were covered by the Lien extended, renewed, or replaced (plus improvements on such property or assets);

provided, however, notwithstanding the foregoing, Permitted Liens shall not include (1) other than the Permitted Securitization, Liens on the accounts receivable of Borrower and its Subsidiaries generated from the sale of natural gas, (2) Liens on the natural gas inventory of Borrower and its Subsidiaries, (3) Liens imposed by ERISA, the creation of which would result in an Event of Default under Section 7(l) and (4) Liens on any of the common stock of any Subsidiary of Borrower.

“Permitted Securitization” shall mean any sale, assignment, conveyance, grant or contribution, or series of related sales, assignments, conveyances, grants or contributions, by Laclede Gas of any accounts receivable and related rights from its sale of natural gas, and any supporting obligations and other financial assets related thereto not to exceed in the aggregate $100,000,000, that are transferred, or in respect of which security interests are granted in one or more transactions that are customary for asset securitizations of such receivables to a trust, corporation or other entity, where the purchase of such receivables is funded or exchanged in whole or in part by the incurrence or issuance by the purchaser, grantee or any successor entity of indebtedness or securities that are to receive payments from, or that represent interests in, the cash flow derived primarily from such receivables (provided, however, that “indebtedness” as used in this definition shall not include indebtedness incurred by any trust, partnership or other Person established by Borrower or any of its Subsidiaries to implement a Permitted Securitization owed to Laclede Gas or any of its Subsidiaries, which indebtedness represents all or a portion of the purchase price or other consideration paid by such trust, partnership or other Person for such receivables or interests therein).

“Person” shall mean any individual, sole proprietorship, partnership, joint venture, limited liability company, trust, unincorporated organization, association, corporation, institution, other entity of any kind or government (whether national, federal, state, county, city, municipal or otherwise, including, without limitation, any instrumentality, division, agency, body or department thereof).

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“Plan” shall mean any “employee pension benefit plan” within the meaning of Section 3(2) of ERISA that is subject to the provisions of Title IV of ERISA (other than a Multiemployer Plan) and to which Borrower or any ERISA Affiliate may have any liability.

“PPA 2006 Effective Date” shall mean, with respect to any Plan, except as hereinafter provided, the first day of the first plan year beginning on or after January 1, 2008. However, solely with respect to a Plan maintained pursuant to one or more collective bargaining agreements between employee representatives and one or more employers ratified before January 1, 2008, such term means the first day of the first plan year beginning on or after the earlier of (a) and (b), where (a) is the later of (i) the date on which the last collective bargaining agreement relating to the Plan terminates (determined without regard to any extension thereof agreed to after August 17, 2006), or (ii) the first day of the first plan year beginning on or after January 1, 2008; and (b) is January 1, 2010.

“Prime Rate” shall mean, at any time, the rate of interest per annum publicly announced from time to time by the Administrative Agent as its prime rate. Each change in the Prime Rate shall be effective as of the opening of business on the day such change in such prime rate occurs. The parties hereto acknowledge that the rate announced publicly by the Administrative Agent as its prime rate is an index or base rate and shall not necessarily be its lowest or best rate charged to its customers or other banks.

“Prohibited Transaction” shall mean any transaction described in (a) Section 406 of ERISA that is not exempt by reason of Section 408 of ERISA or by reason of a Department of Labor prohibited transaction individual or class exemption or (b) Section 4975(c) of the Code that is not exempt by reason of Section 4975(c)(2) or 4975(d) of the Code.

“Pro Rata Share” shall mean for the item at issue, with respect to each Bank, a fraction (expressed as a percentage), the numerator of which is the portion of such item owned or held by such Bank and the denominator of which is the total amount of such item owned or held by all of the Banks. For example, (a) if the amount of the Revolving Credit Commitment of a Bank is $1,000,000 and the total amount of the Revolving Credit Commitments of all of the Banks is $5,000,000, such Bank’s Pro Rata Share of the Revolving Credit Commitments would be 20% and (b) if the original principal amount of a Loan is $5,000,000 and the portion of such Loan made by one Bank is $500,000, such Bank’s Pro Rata Share of such Loan would be 10%. As of the date of this Agreement, the Pro Rata Shares of the Banks with respect to the Revolving Credit Commitments and the Loans are as set forth on Schedule 1.01 attached hereto and incorporated herein by reference.

“Purchasing Bank” shall have the respective meanings ascribed thereto in Section 2.19.

“Refunded Swingline Loans” shall have the meaning ascribed thereto in Section 2.02(d).

“Register” shall have the meaning ascribed thereto in Section 9.09(h).

“Regulations D, T, U and X” shall mean Regulations D, T, U and X, respectively, of the Board of Governors of the Federal Reserve System, as amended, and any successor regulations.

“Reimbursement Obligation” shall have the meaning ascribed thereto in Section 3.04.

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“Related Parties” shall mean, with respect to any Person, such Person’s Affiliates and the partners, directors, officers, employees, agents, advisors and representatives of such Person and of such Person’s Affiliates.

“Regulatory Change” shall mean the occurrence, after the date of this Agreement, of any of the following: (i) the adoption or taking effect of any law, rule, regulation or treaty, (ii) any change in any law, rule, regulation or treaty or in the administration, interpretation, implementation or application thereof by any Governmental Authority or (iii) the making or issuance of any request, rule, guideline or directive (whether or not having the force of law) by any Governmental Authority; provided that notwithstanding anything herein to the contrary, (x) the Dodd-Frank Wall Street Reform and Consumer Protection Act and all requests, rules, guidelines or directives thereunder or issued in connection therewith and (y) all requests, rules, guidelines or directives promulgated by the Bank for International Settlements, the Basel Committee on Banking Supervision (or any successor or similar authority) or the United States or foreign regulatory authorities, in each case pursuant to Basel III, shall in each case be deemed to be a Regulatory Change, regardless of the date enacted, adopted or issued.

“Reportable Event” shall mean, with respect to any Plan, (a) any “reportable event” within the meaning of Section 4043(c) of ERISA for which the 30-day notice under Section 4043(a) of ERISA has not been waived by the PBGC (including, without limitation, any failure to meet the minimum funding standard of, or timely make any required installment under, Section 412 of the Code or Section 302 of ERISA, regardless of the issuance of any waivers in accordance with Section 412 of the Code), (b) any such “reportable event” subject to advance notice to the PBGC under Section 4043(b)(3) of ERISA, (c) any application for a funding waiver or an extension of any amortization period pursuant to Section 412 of the Code, and (d) a cessation of operations described in Section 4062(e) of ERISA.

“Required Banks” shall mean at any time Banks holding more than fifty percent (50%) of the aggregate amount of the Revolving Credit Commitments or, if the Revolving Credit Commitments have been terminated, more than fifty percent (50%) of the aggregate Revolving Credit Exposure of all of the Banks; provided that the Revolving Credit Commitment of, and the portion of the Revolving Credit Exposure, as applicable, held or deemed held by, any Defaulting Bank shall be excluded for purposes of making a determination of Required Banks.

“Requirement of Law” shall mean, with respect to any Person, the charter, articles or certificate of organization or incorporation and bylaws or other organizational or governing documents of such Person, and any statute, law, treaty, rule, regulation, order, decree, writ, injunction or determination of any arbitrator or court or other Governmental Authority, in each case applicable to or binding upon such Person or any of its property or to which such Person or any of its property is subject or otherwise pertaining to any or all of the transactions contemplated by this Agreement and the other Transaction Documents.

“Reserve Requirement” shall mean, with respect to any Interest Period, the reserve percentage (expressed as a decimal and rounded upwards, if necessary, to the next higher 1/100^th of 1%) in effect from time to time during such Interest Period, as provided by the Board of Governors of the Federal Reserve System, applied for determining the maximum reserve requirements (including, without limitation, basic, supplemental, marginal and emergency

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reserves) applicable to Wells Fargo under Regulation D with respect to “Eurocurrency liabilities” within the meaning of Regulation D, or under any similar or successor regulation with respect to Eurocurrency liabilities or Eurocurrency funding.

“Response Date” shall have the meaning ascribed thereto in Section 2.01(f).

“Revolving Credit Commitment” shall mean, subject to (a) any reduction of the Revolving Credit Commitments pursuant to Section 2.01(d), (b) any increase in the Revolving Credit Commitments pursuant to Section 2.01(e) and (c) assignments of the Revolving Credit Commitments by the Banks to the extent permitted by Section 9.09, with respect to each Bank the amount set forth opposite such Bank’s name on Schedule 1.01 attached hereto and incorporated herein by reference.

“Revolving Credit Exposure” shall mean, with respect to any Bank at any time, the sum of (a) the aggregate principal amount of all Revolving Loans made by such Bank that are outstanding at such time, (b) such Bank’s Letter of Credit Exposure at such time and (c) such Bank’s Swingline Exposure at such time.

“Revolving Credit Note” shall have the meaning ascribed thereto in Section 2.03(a).

“Revolving Credit Period” shall mean the period commencing on the date of this Agreement and ending September 3, 2018, as may be extended pursuant to Section 2.01(f) with respect to the applicable Banks; provided, however, that the Revolving Credit Period shall end on the date the Revolving Credit Commitment is terminated pursuant to Section 7 or otherwise.

“Revolving Loans” shall have the meaning ascribed thereto in Section 2.01(a).

“S&P” shall mean Standard and Poor’s Ratings Services, a division of McGraw-Hill Companies.

“Sanctioned Country” means a country subject to a sanctions program identified on the list maintained by OFAC and available at http://www.treasury.gov/resource-center/sanctions/Programs/Pages/Programs.aspx, or as otherwise published from time to time.

“Sanctioned Person” means (a) a Person named on the list of “Specially Designated Nationals and Blocked Persons” maintained by OFAC available at http://www.treasury.gov/resource-center/sanctions/SDN-List/Pages/default.aspx, or as otherwise published from time to time, or (b) (i) an agency of the government of a Sanctioned Country, (ii) an organization controlled by a Sanctioned Country, or (iii) a person resident in a Sanctioned Country, to the extent subject to a sanctions program administered by the U.S. Department of the Treasury’s Office of Foreign Assets Control.

“Stated Amount” shall mean, with respect to any Letter of Credit at any time, the aggregate amount available to be drawn thereunder at such time (regardless of whether any conditions for drawing could then be met).

“Subsidiary” shall mean, with respect to any Person, any corporation or other entity of which more than fifty percent (50%) of the issued and outstanding Capital Stock entitled to vote

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for the election of directors or persons performing similar functions (other than by reason of default in the payment of dividends or other distributions) is at the time owned or controlled, directly or indirectly, by such Person and one or more of its other Subsidiaries or a combination thereof (irrespective of whether, at the time, securities of any other class or classes of any such corporation or other Person shall or might have voting power by reason of the happening of any contingency). When used without reference to a parent entity, the term “Subsidiary” shall be deemed to refer to a Subsidiary of Borrower.

“Swap Contract” shall mean any interest rate or currency swap agreement, interest rate or currency future agreement, interest rate collar agreement, swap agreement (as defined in 11 U.S.C. § 101), interest rate or currency hedge agreement, and any put, call or other agreement or arrangement designed to protect such Person against fluctuations in interest rates or currency exchange rates.

“Swap Termination Value” shall mean, in respect of any one or more Swap Contracts, after taking into account the effect of any legally enforceable netting agreement relating to such Swap Contracts, (a) for any date on or after the date such Swap Contracts have been closed out and termination value(s) determined in accordance therewith, such termination value(s), and (b) for any date prior to the date referenced in clause (a), the amount(s) determined as the mark-to-market value(s) for such Swap Contracts, as determined based upon one or more mid-market or other readily available quotations provided by any recognized dealer in such Swap Contracts (which may include a Bank or any Affiliate of a Bank).

“Swingline Bank” shall mean Wells Fargo in its capacity as maker of Swingline Loans, and its successors in such capacity, or such other Bank as Borrower may from time to time select as the Swingline Bank hereunder; provided that such Bank has agreed to be a Swingline Bank.

“Swingline Commitment” shall mean FIFTEEN MILLION DOLLARS ($15,000,000) or, if less, the aggregate Revolving Credit Commitments at the time of determination, as such amount may be reduced at or prior to such time pursuant to the terms hereof.

“Swingline Exposure” shall mean, with respect to any Bank at any time, its maximum aggregate liability to make Refunded Swingline Loans pursuant to Section 2.02(d) to refund, or to purchase participations pursuant to Section 2.02(e) in, Swingline Loans that are outstanding at such time.

“Swingline Loans” has the meaning given to such term in Section 2.01(c).

“Swingline Maturity Date” shall mean the fifth (5^th) Business Day prior to the last day of the Revolving Credit Period.

“Swingline Note” shall mean, if requested by the Swingline Bank, the promissory note of Borrower in favor of the Swingline Bank evidencing the Swingline Loans made by the Swingline Bank pursuant to Section 2.01(c), in substantially the form of Exhibit A-2, together with any amendments, modifications and supplements thereto, substitutions therefor and restatements thereof.

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“Taxes” shall mean all present or future taxes, levies, imposts, duties, deductions, withholdings (including backup withholding), assessments, fees or other charges imposed by any Governmental Authority, including any interest, additions to tax or penalties applicable thereto.

“Transaction Documents” shall mean this Agreement, the Notes and any and all other agreements, documents and instruments heretofore, now or hereafter delivered to the Administrative Agent or any Bank with respect to or in connection with or pursuant to this Agreement, any Loans made hereunder or any of the other Borrower’s Obligations, and executed by or on behalf of Borrower, all as the same may from time to time be amended, modified, extended, renewed or restated.

“Type” shall refer to whether a Loan is a Base Rate Loan or a LIBOR Loan.

“U.S. Bank” shall mean U.S. Bank National Association.

“U.S. Federal Income Tax” shall mean any U.S. federal Tax described in Section 871(a) or 881(a) of the Code, or any successor provision (or any withholding with respect to such Tax).

“Unfunded Pension Liability” shall mean, with respect to any Plan, the excess of its benefit liabilities under Section 4001(a)(16) of ERISA over the current value of its assets, determined in accordance with the applicable assumptions used for funding under Section 412 of the Code for the applicable plan year.

“Unutilized Revolving Credit Commitment” shall mean, with respect to any Bank at any time, such Bank’s Revolving Credit Commitment at such time less its Revolving Credit Exposure at such time.

“Unutilized Swingline Commitment” shall mean, with respect to the Swingline Bank at any time, the Swingline Commitment at such time less the aggregate principal amount of all Swingline Loans that are outstanding at such time.

“Voting Stock” shall mean, with respect to any corporation or other entity, any Capital Stock of such corporation or other entity whose holders are entitled under ordinary circumstances to vote for the election of directors (or Persons performing similar functions) of such corporation or other entity (irrespective of whether at the time Capital Stock of any other class or classes shall have or might have voting power by reason of the happening of any contingency).

“Wells Fargo” shall mean Wells Fargo Bank, National Association.

“Wells Fargo Fee Letter” shall mean that certain fee letter agreement, dated June 25, 2013, between Wells Fargo, Wells Fargo Securities, Borrower and Laclede Gas, as the same may from time to time be amended, modified, extended, renewed or restated.

“Wells Fargo Securities” shall mean Wells Fargo Securities, LLC.

1.02Accounting Terms. Unless otherwise specified herein, all accounting terms used herein shall be interpreted, all accounting determinations hereunder shall be made, and all

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financial statements required to be delivered hereunder shall be prepared in accordance with, GAAP, applied on a basis consistent with the most recent audited consolidated financial statements of Borrower delivered to the Banks prior to the Closing Date; provided that if Borrower notifies the Administrative Agent that it wishes to amend any financial covenant in Section 6.02 to eliminate the effect of any change in GAAP on the operation of such covenant (or if the Administrative Agent notifies Borrower that the Required Banks wish to amend Section 6.02 for such purpose), then Borrower’s compliance with such covenant shall be determined on the basis of GAAP as in effect immediately before the relevant change in GAAP became effective, until either such notice is withdrawn or such covenant is amended in a manner satisfactory to Borrower and the Required Banks. Notwithstanding the foregoing, for purposes of determining compliance with any covenant (including the computation of any financial covenant) contained herein, Debt of the Borrower and its Subsidiaries shall be deemed to be carried at 100% of the outstanding principal amount thereof, plus or minus any associated unamortized original issue premium or discount, and the effects of FASB ASC 825 and FASB ASC 470-20 on financial liabilities shall be disregarded.

1.03Other Terms; Construction. The definitions of terms herein shall apply equally to the singular and plural forms of the terms defined. Whenever the context may require, any pronoun shall include the corresponding masculine, feminine and neuter forms. The words “include,” “includes” and “including” shall be deemed to be followed by the phrase “without limitation.” The word “will” shall be construed to have the same meaning and effect as the word “shall.” Unless the context requires otherwise (i) any definition of or reference to any agreement, instrument or other document herein shall be construed as referring to such agreement, instrument or other document as from time to time amended, supplemented or otherwise modified (subject to any restrictions on such amendments, supplements or modifications set forth herein), (ii) any reference herein to any Person shall be construed to include such Person’s successors and assigns, (c) the words “herein,” “hereof” and “hereunder,” and words of similar import, shall be construed to refer to this Agreement in its entirety and not to any particular provision hereof, (d) all references herein to Sections, Exhibits and Schedules shall be construed to refer to Sections of, and Exhibits and Schedules to, this Agreement, (e) any reference to any law or regulation herein shall, unless otherwise specified, refer to such law or regulation as amended, modified or supplemented from time to time, and (f) the words “asset” and “property” shall be construed to have the same meaning and effect and to refer to any and all tangible and intangible assets and properties, including cash, securities, accounts and contract rights.

SECTION 2.THE LOANS.

2.01Revolving Credit Commitments.

(a)Subject to the terms and conditions set forth in this Agreement, during the Revolving Credit Period, each Bank severally agrees to make loans (each a “Revolving Loan” and collectively the “Revolving Loans”) to Borrower as Borrower may from time to time request pursuant to Section 2.02(a). Each Loan under this Section 2.01(a) which is a Base Rate Loan shall be for an aggregate principal amount of at least $500,000 (or if less, in the amount of the aggregate Revolving Credit Commitments less the aggregate Revolving Credit Exposure). Each Revolving Loan under this Section 2.01(a) which is a LIBOR Loan shall be for an aggregate

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principal amount of at least $2,500,000. The aggregate principal amount of Revolving Loans which each Bank shall be required to have outstanding under this Agreement as of any date shall not exceed the amount of such Bank’s Revolving Credit Commitment; provided, however, that in no event shall (i) the aggregate Revolving Credit Exposures exceed the aggregate Revolving Credit Commitments of all of the Banks as of such date or (ii) the Revolving Credit Exposure of any Bank exceed such Bank’s Revolving Credit Commitment. Each Loan under this Section 2.01 shall be made from the Banks severally and ratably in proportion to their respective Pro Rata Shares. Within the foregoing limits, Borrower may borrow under this Section 2.01(a), prepay under Section 2.08 and reborrow at any time during the Revolving Credit Period under this Section 2.01(a). All Loans not paid prior to the last day of the Revolving Credit Period, together with all accrued and unpaid interest thereon and all fees and other amounts owing by Borrower to the Administrative Agent and/or any Bank with respect thereto, shall be due and payable on the last day of the Revolving Credit Period. The failure of any Bank to make any Loan required under this Agreement shall not release any other Bank from its obligation to make Loans as provided herein.

(b)If the total Revolving Credit Commitments of all of the Banks on any date (excluding the aggregate amount of any Swingline Loans to be repaid with the proceeds of Revolving Loans made on the date of determination) should be less than the aggregate Revolving Credit Exposure of the Banks outstanding on such date (after giving effect to any concurrent termination or reduction thereof), whether as a result of Borrower’s election to decrease the amount of the Revolving Credit Commitments of the Banks pursuant to Section 2.01(d) or otherwise, Borrower shall be automatically required (without demand or notice of any kind by the Administrative Agent or any Bank, all of which are hereby expressly waived by Borrower) to immediately repay the outstanding principal amount of the Swingline Loans and, to the extent of any excess remaining after repayment in full of the outstanding Swingline Loans, repay the outstanding principal amount of the Revolving Loans in an amount sufficient to reduce the aggregate principal amount of outstanding Loans to an amount equal to or less than the total Revolving Credit Commitments of all of the Banks; provided that, to the extent such excess amount is greater than the aggregate principal amount of Swingline Loans and Revolving Loans outstanding immediately prior to the application of such prepayment, the amount so prepaid shall be retained by the Administrative Agent and held in the Cash Collateral Account as cover for Letter of Credit Exposure, as more particularly described in Section 3.08, and thereupon such cash shall be deemed to reduce the aggregate Letter of Credit Exposure by an equivalent amount.

(c)The Swingline Bank agrees, subject to and on the terms and conditions of this Agreement, to make loans (each, a “Swingline Loan,” and collectively, the “Swingline Loans”) to Borrower, from time to time on any Business Day during the period from the Closing Date to but not including the Swingline Maturity Date (or if earlier, the last day of the Revolving Credit Period) in an aggregate principal amount at any time outstanding not exceeding the Swingline Commitment. Each Swingline Loan shall be due and payable in full on the earlier of (i) the Swingline Maturity Date and (ii) within fourteen (14) Business Days of such Loan being made. Swingline Loans may be made even if the aggregate principal amount of Swingline Loans outstanding at any time, when added to the Revolving Credit Exposure of the Swingline Bank in its capacity as a Bank outstanding at such time, would exceed the Swingline Bank’s own Revolving Credit Commitment at such time, provided that no borrowing of Swingline Loans shall be made if, immediately after giving effect thereto, (y) the Revolving Credit Exposure of

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any Bank would exceed its Revolving Credit Commitment at such time or (z) the aggregate Revolving Credit Exposure would exceed the aggregate Revolving Credit Commitments at such time, and providedfurther that the Swingline Bank shall not make any Swingline Loan if any Bank is at that time a Defaulting Bank, unless the Swingline Bank has entered into arrangements, including the delivery of Cash Collateral, satisfactory to the Swingline Bank (in its sole discretion) with Borrower or such Defaulting Bank to eliminate the Swingline Bank’s actual or potential Fronting Exposure (after giving effect to Section 2.21(a)(iii)) with respect to the Defaulting Bank arising from either the Swingline Loan then proposed to be made or such Swingline Loan and all other Swingline Loans as to which the Swingline Bank has actual or potential Fronting Exposure, as it may elect in its sole discretion. Subject to and on the terms and conditions of this Agreement, Borrower may borrow, repay (including by means of a borrowing of Revolving Loans pursuant to Section 2.02(d)) and reborrow Swingline Loans. At the option of the Borrower, all Swingline Loans shall bear interest at either (A) a rate based on the Adjusted Base Rate or (B) a rate based on the LIBOR Market Index Rate plus the Applicable Rate for LIBOR Loans.

(d)Borrower may terminate entirely at any time, or proportionately reduce the aggregate Unutilized Revolving Credit Commitments or the Unutilized Swingline Commitment from time to time, upon five (5) Business Days’ prior written notice to the Administrative Agent and each Bank (and in the case of the Unutilized Swingline Commitment, the Swingline Bank), on a ratable basis among the Banks based on their respective Pro Rata Shares by an aggregate amount of $5,000,000 ($500,000 in the case of the Unutilized Swingline Commitment) or any larger multiple of $1,000,000; provided, however, that (i) at no time shall the Revolving Credit Commitments be reduced to a figure less than the aggregate principal amount of outstanding Loans, (ii) at no time shall the Revolving Credit Commitments be reduced to a figure greater than zero but less than $50,000,000 and (iii) except as set forth in Section 2.01(e), any such termination or reduction shall be permanent and Borrower shall have no right to thereafter reinstate or increase, as the case may be, the Revolving Credit Commitment of any Bank. Notwithstanding any provision of this Agreement to the contrary, any reduction of the Revolving Credit Commitments pursuant to this Section 2.01(d) that has the effect of reducing the aggregate Revolving Credit Commitments to an amount less than the amount of the Swingline Commitment or the aggregate Letter of Credit Commitment at such time shall result in an automatic corresponding reduction of the Swingline Commitment or the aggregate Letter of Credit Commitment (with each Issuing Bank’s Letter of Credit Commitment being reduced ratably), as the case may be, to the amount of the aggregate Revolving Credit Commitments (as so reduced), without any further action on the part of Borrower, the Swingline Bank or any other Bank.

(e)So long as no Default or Event of Default shall have occurred and be continuing, Borrower shall have the right from time to time upon not less than ten (10) Business Days’ prior written notice to the Administrative Agent to increase the amount of the aggregate Revolving Credit Commitments; provided that:

(i)no Bank shall have any obligation to increase its Revolving Credit Commitment;

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(ii)Borrower shall only be permitted to request such an increase on three (3) separate occasions within any twelve-month period;

(iii)each such requested increase shall be in a minimum principal amount of $5,000,000;

(iv)in no event shall the Revolving Credit Commitments be increased to an aggregate amount greater than $200,000,000 less any reductions of the Revolving Credit Commitments pursuant to Section 2.01(d);

(v)contemporaneously with requesting each such increase, Borrower certifies to the Administrative Agent and each Bank in writing that immediately before and immediately after giving effect to such increase (A) all of the representations and warranties of Borrower in this Agreement and/or in any other Transaction Document (i) that are qualified by materiality or Material Adverse Effect shall be true and correct as so qualified, and (ii) that are not qualified by materiality or Material Adverse Effect shall be true and correct in all material respects; in each case on and as of the effective date of such increase in the Revolving Credit Commitments (except to the extent any such representation or warranty is expressly stated to have been made as of a specific date, in which case such representation or warranty shall be true and correct as of such date) and (B) no Default or Event of Default has occurred and is continuing;

(vi)any increase in the Revolving Credit Commitments which is accomplished by increasing the Revolving Credit Commitment of any Bank or Banks who are at the time of such increase party to this Agreement (which Bank or Banks shall consent to such increase in their sole and absolute discretion) shall be accomplished as follows: (A) this Agreement will be amended by Borrower, the Administrative Agent and those Bank(s) whose Revolving Credit Commitment(s) is or are being increased (but without any requirement that the consent of any other Bank be obtained) to reflect the revised Revolving Credit Commitments of each Bank, (B) the Administrative Agent will deliver an updated Schedule 1.01 to Borrower and each Bank reflecting the revised Revolving Credit Commitments and Pro Rata Shares of each Bank, (C) Borrower will deliver to the Administrative Agent (x) an opinion or opinions of counsel for Borrower, addressed to the Administrative Agent and the Banks, in form and substance reasonably satisfactory to the Administrative Agent,(y) any authorizing corporate documents as the Administrative Agent may reasonably request and (z) if applicable, a duly executed Notice of Borrowing, (D) the outstanding Loans will be reallocated on the effective date of such increase among the Banks in accordance with their revised Pro Rata Shares (and the Banks agree to make all payments and adjustments necessary to effect the reallocation and Borrower shall pay any and all costs required pursuant to Section 2.10 in connection with such reallocation as if such reallocation were a repayment) and (E) if requested by such Bank or Banks, Borrower will deliver new Note(s) to the Bank or Banks whose Revolving Credit Commitment(s) is or are being increased reflecting the revised Revolving Credit Commitments of such Bank(s); and

(vii)any increase in the Revolving Credit Commitments which is accomplished by addition of a new Bank under this Agreement shall be accomplished as follows: (A)

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such new Bank shall be subject to the consent of the Administrative Agent and Borrower, which consent shall not be unreasonably withheld, (B) this Agreement will be amended by Borrower, the Administrative Agent and such new Bank (but without any requirement that the consent of any other Bank be obtained) to reflect the addition of such new Bank as a Bank hereunder, (C) Borrower will deliver to the Administrative Agent (x) an opinion or opinions of counsel for Borrower, addressed to the Administrative Agent and the Banks, in form and substance reasonably satisfactory to the Administrative Agent, (y) any authorizing corporate documents as the Administrative Agent may reasonably request and (z) if applicable, a duly executed Notice of Borrowing, (D) the Administrative Agent will deliver an updated Schedule 1.01 to Borrower and each Bank reflecting the revised Revolving Credit Commitments and Pro Rata Shares of each Bank, (E) the outstanding Loans will be reallocated on the effective date of such increase among the Banks in accordance with their revised Pro Rata Shares (and the Banks agree to make all payments and adjustments necessary to effect the reallocation and Borrower shall pay any and all costs required pursuant to Section 2.10 in connection with such reallocation as if such reallocation were a repayment) and (F) if requested by such new Bank, Borrower will deliver a Note to such new Bank.

(f)So long as no Default or Event of Default shall have occurred and be continuing, Borrower shall have the right from time to time upon prior written notice to Administrative Agent provided no more than ninety (90) days before any anniversary date of this Agreement, to request a one-year extension of the Revolving Credit Period (each, an “Extension Request”), provided that Borrower shall make no more than three (3) Extension Requests during the term of this Agreement. Each Extension Request shall specify the date (which must be at least thirty (30) days after the date the Extension Request is delivered to Administrative Agent) as of which the Banks must respond to such Extension Request (the “Response Date”). Promptly upon receipt of an Extension Request, Administrative Agent shall notify each Bank of the contents thereof, and each Bank shall, not later than the Response Date for any Extension Request, deliver a written response to Administrative Agent, approving or rejecting such Extension Request, and any Bank that fails to deliver such a response by the Response Date shall be deemed to have rejected such Extension Request. If Banks holding more than fifty percent (50%) of the aggregate amount of the Revolving Credit Commitments approve an Extension Request (which approval shall be at the sole discretion of each Bank), then the Revolving Credit Period for each approving Bank shall be extended for one (1) additional year. If Banks holding more than fifty percent (50%) of the aggregate amount of the Revolving Credit Commitments reject an Extension Request, then the last day of the Revolving Credit Period for all Banks shall remain unchanged. If a Bank does not approve an Extension Request (any such Bank, a “Non-Consenting Bank”), Borrower may elect to replace such Non-Consenting Bank as a Bank party to this Agreement, provided that no Default or Event of Default shall have occurred and be continuing at the time of such replacement, and providedfurther that, concurrently with such replacement, another bank or other financial institution reasonably satisfactory to Administrative Agent, the Issuing Banks and Borrower shall enter into an Assignment and Assumption and comply with the requirements of Section 9.09(c). Any Non-Consenting Bank that is not replaced shall continue to have the same Revolving Credit Period that is in effect immediately prior to the effective date of the applicable extension of the Revolving Credit Period. Notwithstanding the foregoing, the extension of the Revolving Credit Period pursuant to this Section shall not be effective with respect to any Bank unless: (i) no Default or Event of Default shall have occurred

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and be continuing on the date of such extension and after giving effect thereto; and (ii) all of the representations and warranties of Borrower in this Agreement and/or in any other Transaction Document (A) that are qualified by materiality or Material Adverse Effect shall be true and correct as so qualified, and (B) that are not qualified by materiality or Material Adverse Effect shall be true and correct in all material respects; in each case on and as of the effective date of such extension (except to the extent any such representation or warranty is expressly stated to have been made as of a specific date, in which case such representation or warranty shall be true and correct as of such date). On or before the end of the then-existing Revolving Credit Period of each Non-Consenting Bank, Borrower shall pay in full the principal of and interest on all of the Loans made by such Non-Consenting Bank hereunder and all other amounts owing to such Bank hereunder.

2.02Method of Borrowing.

(a)In order to make a borrowing of Revolving Loans (other than (i) borrowings of Swingline Loans, which shall be made pursuant to Section 2.02(c), (ii) borrowings for the purpose of repaying Refunded Swingline Loans, which shall be made pursuant to Section 2.02(d), (iii) borrowings for the purpose of paying unpaid Reimbursement Obligations, which shall be made pursuant to Section 3.05, and (iv) borrowings involving continuations or conversions of outstanding Loans, which shall be made pursuant to Section 2.04), Borrower shall give notice (each, a “Notice of Borrowing”) substantially in the form of Exhibit B-1 to the Administrative Agent by 11:00 a.m. (Charlotte time) on the Business Day of each Base Rate Loan to be made to Borrower, and by 11:00 a.m. (Charlotte time) at least three (3) Business Days before each LIBOR Loan to be made to Borrower, specifying: (i) the date of such Revolving Loan, which shall be a Business Day during the Revolving Credit Period; (ii) the aggregate principal amount of such Revolving Loan; (iii) the initial Type of the Loan, provided that if Borrower shall have failed to designate the Type of such Loan, Borrower shall be deemed to have requested a borrowing comprised of Base Rate Loans; and (iv) in the case of a LIBOR Loan, the duration of the initial Interest Period applicable thereto, subject to the provisions of the definition of Interest Period, provided that if Borrower shall have failed to select the duration of the applicable Interest Period, then Borrower shall be deemed to have selected an Interest Period with a duration of one month.

(b)Not later than 2:00 p.m. (Charlotte time) on the date of each Revolving Loan, each Bank shall make available its Pro Rata Share of such Revolving Loan, in Dollars and in funds immediately available to the Administrative Agent at its address specified in Schedule 9.04. The Administrative Agent will make the funds so received from the Banks available to Borrower immediately thereafter at the Administrative Agent’s aforesaid address by crediting such funds to the deposit account specified by Borrower on the Account Designation Letter (or such other account mutually agreed upon in writing between the Administrative Agent and Borrower). The Administrative Agent shall not be required to make any amount available to Borrower hereunder except to the extent the Administrative Agent shall have received such amounts from the Banks as set forth herein, provided, however, that unless the Administrative Agent shall have been notified by a Bank prior to the time a Loan is to be made hereunder that such Bank does not intend to make its Pro Rata Share of such Loan available to the Administrative Agent, the Administrative Agent may assume that such Bank has made such Pro Rata Share available to the Administrative Agent prior to such time, and the Administrative Agent may in reliance upon such assumption, but shall not be required to, make available to Borrower a corresponding amount. If such corresponding amount is not in fact made available to

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the Administrative Agent by such Bank and the Administrative Agent has made such amount available to Borrower, the applicable Bank and Borrower severally agree to pay to the Administrative Agent forthwith and on demand such corresponding amount, together with interest thereon in respect of each day during the period from and including the date such amount was made available to Borrower to but excluding the date the Administrative Agent recovers such amount at (i) in the case of a payment to be made by such Bank, the greater of the Fed Funds Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation and (ii) in the case of a payment to be made by Borrower, the Adjusted Base Rate.

(c)In order to make a borrowing of a Swingline Loan, Borrower will give the Administrative Agent and the Swingline Bank written notice not later than 11:00 a.m., Charlotte time, on the date of such borrowing. Each such notice (each, a “Notice of Swingline Borrowing”) substantially in the form of Exhibit B-2, shall be irrevocable and shall specify (i) the principal amount of the Swingline Loan to be made pursuant to such borrowing (which shall not be less than $100,000 and, if greater, shall be in an integral multiple of $100,000 in excess thereof (or, if less, in the amount of the Unutilized Swingline Commitment)) and (ii) the date of such Swingline Loan, which shall be a Business Day during the Revolving Credit Period, but not later than the Swingline Maturity Date. Not later than 2:00 p.m., Charlotte time, on the date of the Swingline Loan, the Swingline Bank will make available an amount equal to the amount of such Swingline Loan, in Dollars and in funds immediately available in Charlotte, North Carolina to the Administrative Agent. To the extent the Swingline Bank has made such amount available to the Administrative Agent as provided hereinabove, the Administrative Agent will make such amount available to Borrower in like funds as received by the Administrative Agent.

(d)With respect to any outstanding Swingline Loans, the Swingline Bank may at any time (whether or not an Event of Default has occurred and is continuing) in its sole and absolute discretion, and is hereby authorized and empowered by Borrower to, cause a borrowing of Revolving Loans to be made for the purpose of repaying such Swingline Loans by delivering to the Administrative Agent (if the Administrative Agent is not also the Swingline Bank) and each other Bank (on behalf of, and with a copy to, Borrower), not later than 11:00 a.m., Charlotte time, on the proposed date of such Revolving Loan, a notice (which shall be deemed to be a Notice of Borrowing given by Borrower) requesting the Banks to make Revolving Loans (which shall be made initially as Base Rate Loans) on such date in an aggregate amount equal to the amount of such Swingline Loans (the “Refunded Swingline Loans”) outstanding on the date such notice is given that the Swingline Bank requests to be repaid. Not later than 2:00 p.m., Charlotte time, on the requested date of such Revolving Loans, each Bank (other than the Swingline Bank) will make available its Pro Rata Share of such Revolving Loan, in Dollars and in funds immediately available to the Administrative Agent. To the extent the Banks have made such amounts available to the Administrative Agent as provided hereinabove, the Administrative Agent will make the aggregate of such amounts available to the Swingline Bank in like funds as received by the Administrative Agent, which shall apply such amounts in repayment of the Refunded Swingline Loans. Notwithstanding any provision of this Agreement to the contrary, on the date of such Loan, the Refunded Swingline Loans (including the Swingline Bank’s Pro Rata Share thereof, in its capacity as a Bank) shall be deemed to be repaid with the proceeds of the Revolving Loans made as provided above (including a Revolving Loan deemed to have been

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made by the Swingline Bank), and such Refunded Swingline Loans deemed to be so repaid shall no longer be outstanding as Swingline Loans but shall be outstanding as Revolving Loans. If any portion of any such amount repaid (or deemed to be repaid) to the Swingline Bank shall be recovered by or on behalf of Borrower from the Swingline Bank in any bankruptcy, insolvency or similar proceeding or otherwise, the loss of the amount so recovered shall be shared ratably among all the Banks based on each Bank’s Pro Rata Share.

(e)If, as a result of any bankruptcy, insolvency or similar proceeding with respect to Borrower, Revolving Loans are not made pursuant to Section 2.02(d) in an amount sufficient to repay any amounts owed to the Swingline Bank in respect of any outstanding Swingline Loans, or if the Swingline Bank is otherwise precluded for any reason from giving a notice on behalf of Borrower as provided for hereinabove, the Swingline Bank shall be deemed to have sold without recourse, representation or warranty, and each Bank shall be deemed to have purchased and hereby agrees to purchase, a participation in such outstanding Swingline Loans in an amount equal to its Pro Rata Share at such time of the unpaid amount thereof together with accrued interest thereon. Upon one (1) Business Day’s prior notice from the Swingline Bank, each Bank (other than the Swingline Bank) will make available its Pro Rata Share of such Revolving Loan, in Dollars and in funds immediately available in Charlotte, North Carolina to the Administrative Agent. To the extent the Banks have made such amounts available to the Administrative Agent as provided hereinabove, the Administrative Agent will make the aggregate of such amounts available to the Swingline Bank in like funds as received by the Administrative Agent. In the event any such Bank fails to make available to the Administrative Agent the amount of such Bank’s participation as provided in this Section 2.02(e), the Swingline Bank shall be entitled to recover such amount on demand from such Bank, together with interest thereon for each day from the date such amount is required to be made available for the account of the Swingline Bank until the date such amount is made available to the Swingline Bank at the Fed Funds Rate for the first three (3) Business Days and thereafter at the Adjusted Base Rate applicable to Revolving Loans. Promptly following its receipt of any payment by or on behalf of Borrower in respect of a Swingline Loan, the Swingline Bank will pay to each Bank that has acquired a participation therein such Bank’s Pro Rata Share of such payment.

(f)Notwithstanding any provision of this Agreement to the contrary, the obligation of each Bank (other than the Swingline Bank) to make Revolving Loans for the purpose of repaying any Refunded Swingline Loans pursuant to Section 2.02(d) and each such Bank’s obligation to purchase a participation in any unpaid Swingline Loans pursuant to Section 2.02(e) shall be absolute and unconditional and shall not be affected by any circumstance or event whatsoever, including, without limitation, (i) any set-off, counterclaim, recoupment, defense or other right that such Bank may have against the Swingline Bank, the Administrative Agent, Borrower or any other Person for any reason whatsoever, (ii) the occurrence or continuance of any Default or Event of Default, (iii) the failure of the amount of such borrowing of Revolving Loans to meet the minimum borrowing amount specified in Section 2.01(a), or (iv) the failure of any conditions set forth in Section 4.02 or elsewhere herein to be satisfied.

(g)The obligations of the Banks hereunder to make Loans, to fund participations in Letters of Credit and Swingline Loans and to make payments pursuant to Section 9.03(c) are several and not joint. The failure of any Bank to make any Loan, to fund any such participation or to make any such payment on any date shall not relieve any other Bank of its corresponding

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obligation, if any, hereunder to do so on such date, but no Bank shall be responsible for the failure of any other Bank to so make its Loan, purchase its participation or to make any such payment required hereunder.

(h)Each Bank may, at its option, make and maintain any Loan at, to or for the account of any of its Lending Offices, provided that any exercise of such option shall not affect the obligation of Borrower to repay such Loan to or for the account of such Bank in accordance with the terms of this Agreement.

(i)Borrower hereby irrevocably authorizes the Administrative Agent to rely on telephonic, telegraphic, telecopy, telex or written instructions of any person identifying himself or herself as one of the individuals listed on Schedule 2.02 attached hereto (or any other individual from time to time authorized to act on behalf of Borrower pursuant to a resolution adopted by the Board of Directors of Borrower and certified by the Secretary of Borrower and delivered to the Administrative Agent) (the “Authorized Individuals”) with respect to any request to make a Loan or a repayment hereunder, and on any signature which the Administrative Agent believes to be genuine, and Borrower shall be bound thereby in the same manner as if such individual were actually authorized or such signature were genuine; provided that the Administrative Agent shall not be obligated under any circumstances to forward amounts to any account not listed on an Account Designation Letter. Borrower may at any time deliver to the Administrative Agent an Account Designation Letter listing any additional accounts or deleting any accounts listed in a previous Account Designation Letter. Borrower also hereby agrees to defend and indemnify the Administrative Agent and each Bank and hold the Administrative Agent and each Bank harmless from and against any and all claims, demands, damages, liabilities, losses, costs and expenses (including, without limitation, reasonable attorneys’ fees and expenses) relating to or arising out of or in connection with the acceptance of instructions for making Loans or repayments under this Agreement; providedthat the Administrative Agent and each Bank will not have any right to indemnification for any of the foregoing to the extent resulting from the Administrative Agent’s or such Bank’s own fraud, gross negligence or willful misconduct or a breach in bad faith by the Administrative Agent or such Bank of its obligations hereunder, in each case, as determined by a final non-appealable judgment of a court of competent jurisdiction.

2.03Notes.

(a)If requested by any Bank, the Revolving Loans of such Bank to Borrower shall be evidenced by a Revolving Credit Note of Borrower payable to the order of such Bank in a principal amount equal to the amount of such Bank’s Revolving Credit Commitment, each of which Revolving Credit Notes shall be in substantially the form of Exhibit A-1 attached hereto and incorporated herein by reference (with appropriate insertions) (collectively, as the same may from time to time be amended, modified, extended, renewed, restated or replaced (including, without limitation, any Revolving Credit Note issued in full or partial replacement of an existing Revolving Credit Note as a result of an assignment by a Bank), the “Revolving Credit Notes”).

(b)If requested by the Swingline Bank, the Swingline Loans shall be evidenced by a Swingline Note of Borrower payable to the order of the Swingline Bank in a principal amount

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equal to the Swingline Commitment, which Swingline Note shall be in substantially the form of Exhibit A-2 attached hereto and incorporated herein by reference (the “Swingline Note”).

(c)Each Bank shall record in its books and records the date, amount, Type and Interest Period (if any) of each Loan made by it to Borrower and the date and amount of each payment of principal and/or interest made by Borrower with respect thereto; provided, however, that the obligation of Borrower to repay each Loan made by a Bank to Borrower under this Agreement shall be absolute and unconditional, notwithstanding any failure of such Bank to make any such recordation or any mistake by such Bank in connection with any such recordation. The books and records of each Bank showing the account between such Bank and Borrower shall be conclusive evidence of the items set forth therein in the absence of manifest error.

(d)The Administrative Agent shall maintain the Register pursuant to Section 9.09(h), and a subaccount for each Bank, in which Register and subaccounts (taken together) shall be recorded (i) date, amount, Type and Interest Period (if any) of each such Loan, (ii) the amount of any principal or interest due and payable or to become due and payable from Borrower to each Bank hereunder in respect of each such Loan and (iii) the amount of any sum received by the Administrative Agent hereunder from Borrower in respect of each such Loan and each Bank’s share thereof.

(e)The entries made in the books, records and Register and subaccounts maintained pursuant to Section 2.03(c) (and, if consistent with the entries of the Administrative Agent, Section 2.03(d)) shall, to the extent permitted by applicable law, be prima facie evidence of the existence and amounts of the obligations of Borrower therein recorded; provided, however, that the failure of any Bank or the Administrative Agent to maintain such account, such Register or such subaccount, as applicable, or any error therein, shall not in any manner affect the obligation of Borrower to repay (with applicable interest) the Loans made to Borrower by such Bank in accordance with the terms of this Agreement.

2.04Duration of Interest Periods and Selection of Interest Rates.

(a)The duration of the initial Interest Period for each LIBOR Loan shall be as specified in the applicable Notice of Borrowing; provided, all LIBOR Loans comprising a single borrowing must at all times have the same Interest Period. More than one borrowing may be made on the same Business Day. Borrower may elect to continue each such LIBOR Loan by selecting the duration of each subsequent Interest Period applicable to such LIBOR Loan and the interest rate to be applicable during such subsequent Interest Period (and Borrower shall have the option (i) in the case of any Base Rate Loan, to elect that such Base Rate Loan be converted into a LIBOR Loan and the Interest Period to be applicable thereto, and (ii) in the case of any LIBOR Loan, to elect that such LIBOR Loan be converted into a Base Rate Loan), in each case by giving written notice of such election to the Administrative Agent (each a “Notice of Election”) substantially the form of Exhibit B-3 by 11:00 a.m. Charlotte time on the Business Day of the end of the immediately preceding Interest Period applicable thereto, in the case of the election of the Adjusted Base Rate, and by 11:00 a.m. Charlotte time at least three (3) Business Days before the end of the immediately preceding Interest Period applicable thereto, in the case of the election of the LIBOR Rate; provided, however, that notwithstanding the foregoing, in addition

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to and without limiting the rights and remedies of the Administrative Agent and the Banks under Section 7 hereof, (A) any such election that LIBOR Loans be converted into Base Rate Loans shall involve an aggregate principal amount of not less than $500,000; any such election that Base Rate Loans be converted into, or any continuation of, LIBOR Loans shall involve an aggregate principal amount of not less than $2,500,000; and no partial conversion of LIBOR Loans made pursuant to a single borrowing shall reduce the outstanding principal amount of such LIBOR Loans to less than $2,500,000, (B) except as otherwise provided in Section 2.12, LIBOR Loans may be converted into Base Rate Loans only on the last day of the Interest Period applicable thereto (and, in any event, if a LIBOR Loan is converted into a Base Rate Loan on any day other than the last day of the Interest Period applicable thereto, Borrower will pay, upon such conversion, all amounts required under Section 2.10 to be paid as a consequence thereof), (C) no such conversion or continuation shall be permitted with regard to any Base Rate Loans that are Swingline Loans, and (D) so long as any Default or Event of Default under this Agreement has occurred and is continuing, Borrower shall not be permitted to continue any LIBOR Loan as a LIBOR Loan or to convert any Base Rate Loan into a LIBOR Loan.

(b)Each Notice of Election shall specify (i) the date of such election (which shall be a Business Day), (ii) in the case of an election that a Base Rate Loan be converted into a LIBOR Loan, or a continuation of, LIBOR Loans, the Interest Period to be applicable thereto, and (iii) the aggregate amount and Type of the Loans being converted or continued. Upon receipt of a Notice of Election by Borrower to the Administrative Agent under this Section 2.04, the Administrative Agent shall notify each Bank by 12:00 p.m. Charlotte time on the date of receipt of such notice (which must be a Business Day) of the contents thereof. If the Administrative Agent does not receive a Notice of Election for a Loan pursuant to this Section 2.04(b) as specified herein, with respect to any outstanding LIBOR Loans, such LIBOR Loans shall automatically be converted into Base Rate Loans upon the expiration of the current Interest Period applicable thereto (unless repaid pursuant to the terms hereof). In the event Borrower shall have failed to select in a Notice of Election the duration of the Interest Period to be applicable to any conversion into, or continuation of, LIBOR Loans, then Borrower shall be deemed to have selected an Interest Period with a duration of one month.

(c)Borrower may not have outstanding and the Banks shall not be obligated to make more than eight (8) LIBOR Loans at any one time.

2.05Interest Rates.

(a)So long as no Event of Default under this Agreement has occurred and is continuing, each Base Rate Loan shall bear interest on the outstanding principal amount thereof, for each day from the date such Base Rate Loan is made until it becomes due, at a rate per annum equal to the Adjusted Base Rate. Interest shall be payable quarterly in arrears on the first Business Day of each calendar quartercommencing on the first such date after such Base Rate Loan is made, and at the maturity of the Loans (whether by reason of acceleration or otherwise); provided, that in the event the Loans are repaid or prepaid in full and the Revolving Credit Commitments have been terminated, then accrued interest in respect of all Base Rate Loans shall be payable together with such repayment or prepayment on the date thereof. So long as any Event of Default under this Agreement has occurred and is continuing, each Base Rate Loan shall bear interest on the outstanding principal amount thereof, for each day from the date such

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Base Rate Loan is made until it becomes due, at a rate per annum equal to two percent (2%) over and above the Adjusted Base Rate and such default interest shall be payable on demand. From and after the maturity of the Loans, whether by reason of acceleration or otherwise, each Base Rate Loan shall bear interest, payable on demand, for each day until paid at a rate per annum equal to two percent (2%) over and above the Adjusted Base Rate.

(b)So long as no Event of Default under this Agreement has occurred and is continuing, each LIBOR Loan shall bear interest on the outstanding principal amount thereof for each Interest Period applicable thereto at a rate per annum equal to the Adjusted LIBOR Rate. Interest shall be payable for each Interest Period on the last day thereof, unless the duration of such Interest Period exceeds three (3) months, in which case such interest shall be payable at the end of the first three (3) months of such Interest Period and on the last day of such Interest Period, and at the maturity of the Loans (whether by reason of acceleration or otherwise); provided, that in the event all LIBOR Loans made pursuant to a single borrowing are repaid or prepaid in full, then accrued interest in respect of such LIBOR Loans shall be payable together with such repayment or prepayment on the date thereof. So long as any Event of Default under this Agreement has occurred and is continuing, each LIBOR Loan shall bear interest on the outstanding principal amount thereof for each Interest Period applicable thereto at a rate per annum equal to two percent (2%) over and above the Adjusted LIBOR Rate and such default interest shall be payable on demand. From and after the maturity of the Loans, whether by reason of acceleration or otherwise, each LIBOR Loan shall bear interest, payable on demand, for each day until paid, at a rate per annum equal to two percent (2%) over and above the Adjusted LIBOR Rate.

(c)So long as no Event of Default under this Agreement has occurred and is continuing, each Swingline Loan shall bear interest as set forth in 2.01(c). So long as any Event of Default under this Agreement has occurred and is continuing, each Swingline Loan shall bear interest on the outstanding principal amount thereof, for each day from the date such Swingline Loan is made until it becomes due, at a rate per annum equal to two percent (2%) over and above the Adjusted Base Rate and such default interest shall be payable on demand. Notwithstanding the provisions of Section 2.05(a), interest on Swingline Loans shall be payable at the earlier of (i) the maturity of the Swingline Loan, (ii) the Swingline Maturity Date, (iii) on the first Business Day of each calendar quarter commencing on the first such date after such Swingline Loan is made, and (iv) at the maturity of the Loans (whether by reason of acceleration or otherwise); provided, that in the event the Loans are repaid or prepaid in full and the Swingline Commitment has been terminated, then accrued interest in respect of all Swingline Loans shall be payable together with such repayment or prepayment on the date thereof. From and after the maturity of the Loans, whether by reason of acceleration or otherwise, each Swingline Loan shall bear interest, payable on demand, for each day until paid at a rate per annum equal to two percent (2%) over and above the Adjusted Base Rate.

(d)The Administrative Agent shall determine each interest rate applicable to the Loans hereunder and its determination thereof shall be conclusive in the absence of manifest error.

(e)So long as any Event of Default under this Agreement has occurred and is continuing, all other overdue Borrower’s Obligations (other than the Borrower’s Obligations

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specified in subsections (a), (b) and (c) above) shall bear interest at a rate per annum equal to two percent (2%) over and above the Adjusted Base Rate and such default interest shall be payable on demand.

(f)Nothing contained in this Agreement or in any other Transaction Document shall be deemed to establish or require the payment of interest to any Bank at a rate in excess of the maximum rate permitted by applicable law. If the amount of interest payable for the account of any Bank on any interest payment date would exceed the maximum amount permitted by applicable law to be charged by such Bank, the amount of interest payable for its account on such interest payment date shall be automatically reduced to such maximum permissible amount. In the event of any such reduction affecting any Bank, if from time to time thereafter the amount of interest payable for the account of such Bank on any interest payment date would be less than the maximum amount permitted by applicable law to be charged by such Bank, then the amount of interest payable for its account on such subsequent interest payment date shall be automatically increased to such maximum permissible amount, provided that at no time shall the aggregate amount by which interest paid for the account of any Bank has been increased pursuant to this sentence exceed the aggregate amount by which interest paid for its account has theretofore been reduced pursuant to the previous sentence.

(g)The Administrative Agent shall promptly notify Borrower and the Banks upon determining the interest rate for each borrowing of LIBOR Loans after its receipt of the relevant Notice of Borrowing or Notice of Election, and upon each change in the Prime Rate; provided, however, that the failure of the Administrative Agent to provide Borrower or the Banks with any such notice shall neither affect any obligations of Borrower or the Banks hereunder nor result in any liability on the part of the Administrative Agent to Borrower or any Bank. Each such determination (including each determination of the Reserve Requirement) shall, absent manifest error, be conclusive and binding on all parties hereto.

2.06Computation of Interest. Interest on Base Rate Loans when the Base Rate is determined by the Prime Rate shall be computed on the basis of a year of 365/366 days and paid for the actual number of days elapsed (including the first day but excluding the last day).All other computations of fees and interest provided hereunder (including computations of the Reserve Requirement) shall be computed on the basis of a year of 360 days and paid for the actual number of days elapsed (including the first day but excluding the last day).

2.07Fees.

(a)From and including the Closing Date, Borrower shall pay to the Administrative Agent for the account of each Bank a commitment fee on such Bank’s Pro Rata Share of the average daily Unutilized Revolving Credit Commitment (disregarding any Swingline Loans) at the Applicable Rate in effect for such fee from time to time payable quarterly in arrears on the first Business Day of each calendar quarter during the Revolving Credit Period, beginning with the first such day to occur after the Closing Date; provided, however, that no commitment fee shall accrue on the Unutilized Revolving Credit Commitment of a Defaulting Bank during any period that such Bank shall be a Defaulting Bank.

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(b)To the Administrative Agent, for the account of each Bank, a letter of credit fee for each calendar quarter (or portion thereof) in respect of all Letters of Credit outstanding during such quarter, at a per annum rate equal to the Applicable Rate in effect from time to time during such quarter for Revolving Loans that are maintained as LIBOR Loans, on such Bank’s Pro Rata Share of the daily average aggregate Stated Amount of such Letters of Credit, payable in arrears (i) on the first Business Day of each calendar quarter during the Revolving Credit Period, beginning with the first such day to occur after the Closing Date, and (ii) on the later of the last day of the Revolving Credit Period and the date of termination of the last outstanding Letter of Credit; provided, however, that any Letter of Credit Fees otherwise payable for the account of a Defaulting Bank with respect to any Letter of Credit as to which such Defaulting Bank has not provided Cash Collateral satisfactory to the Issuing Bank pursuant to Section 3.01(a) shall be payable, to the maximum extent permitted by applicable Law, to the other Banks in accordance with the upward adjustments in their respective Pro Rata Shares of such Letter of Credit pursuant to Section 2.21(a)(iv), with the balance of such fee, if any, payable to the Issuing Bank for its own account;

(c)To each Issuing Bank, for its own account, a facing fee for each calendar quarter (or portion thereof) in respect of all Letters of Credit issued by it outstanding during such quarter on the daily average aggregate Stated Amount of such Letters of Credit, at the per annum rate set forth in the applicable Fee Letter, payable in arrears (i) on the first Business Day of each calendar quarter during the Revolving Credit Period, beginning with the first such day to occur after the Closing Date, and (ii) on the later of the last day of the Revolving Credit Period and the date of termination of the last outstanding Letter of Credit;

(d)To each Issuing Bank, for its own account, such commissions, transfer fees and other fees and charges incurred in connection with the issuance and administration of each Letter of Credit issued by it as are customarily charged from time to time by such Issuing Bank for the performance of such services in connection with similar letters of credit, or as may be otherwise agreed to by such Issuing Bank, but without duplication of amounts payable under Section 2.07(c); and

(e)The Borrower shall pay to the Arrangers and the Administrative Agent for their own respective accounts fees in the amounts and at the times specified in the applicable Fee Letter. The Borrower shall pay to the Banks such fees as shall have been separately agreed upon in writing in the amounts and at the times so specified.

2.08Prepayments.

(a)Borrower may, upon notice to the Administrative Agent, given not later than 11:00 a.m. Charlotte time on the date of such prepayment, specifying that it is paying the Base Rate Loans, pay without penalty or premium the Base Rate Loans in whole at any time or in part in amounts aggregating $500,000 ($100,000 in the case of Swingline Loans) from time to time, by paying the principal amount to be paid. Each such optional payment shall be applied to pay the Base Rate Loans of the several Banks in proportion to their respective Pro Rata Shares.

(b)Borrower may, upon at least three (3) Business Days’ notice to the Administrative Agent, given not later than 11:00 a.m., Charlotte time, specifying that it is paying the LIBOR

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Loans, pay the LIBOR Loans to which a given Interest Period applies, in whole, or in part in amounts aggregating $2,500,000, by paying the principal amount to be paid together with all accrued and unpaid interest thereon to and including the date of payment and any funding losses and other amounts payable under Section 2.10; provided, however, that in no event may Borrower make a partial payment of LIBOR Loans which results in the total outstanding LIBOR Loans with respect to which a given Interest Period applies being less than $2,500,000. Each such optional payment shall be applied to pay the LIBOR Loans of the several Banks in proportion to their respective Pro Rata Shares.

(c)Each notice of prepayment under this Section 2.08 shall specify the proposed date of such prepayment and the aggregate principal amount and Type of the Loans to be prepaid (and, in the case of LIBOR Loans, the applicable Interest Period), and shall be irrevocable and shall bind Borrower to make such prepayment on the terms specified therein. Upon receipt of a notice of payment pursuant to this Section, the Administrative Agent shall promptly notify each Bank of the contents thereof and of such Bank’s Pro Rata Share of such payment and such notice shall not thereafter be revocable by Borrower; provided that if such notice has also been furnished to the Banks, the Administrative Agent shall have no obligation to notify the Banks with respect thereto. Loans prepaid pursuant to this Section 2.08 may be reborrowed, subject to the terms and conditions of this Agreement.

2.09General Provisions as to Payments.

(a)Borrower shall make each payment of principal of, and interest on, the Loans and of fees and all other amounts payable by Borrower under this Agreement, not later than 1:00 p.m. Charlotte time on the date when due and payable, without condition or deduction for any counterclaim, defense, recoupment or setoff, in Dollars in funds immediately available in Charlotte, North Carolina to the Administrative Agent at its address specified in Schedule 9.04. All payments received by the Administrative Agent after 1:00 p.m. Charlotte time shall be deemed to have been received by the Administrative Agent on the next succeeding Business Day. The Administrative Agent will distribute to each Bank in immediately available funds its Pro Rata Share of each such payment received by the Administrative Agent for the account of the Banks by 3:00 p.m. Charlotte time on the day of receipt of such payment by the Administrative Agent if such payment is received by the Administrative Agent from Borrower by 1:00 p.m. Charlotte time on such day or by 1:00 p.m. Charlotte time on the next succeeding Business Day if such payment is received by the Administrative Agent from Borrower after 1:00 p.m. Charlotte time on such day. Any such payment owed by the Administrative Agent to any Bank which is not paid within the applicable time period shall bear interest until paid (payable by the Administrative Agent) at the Fed Funds Rate. Whenever any payment of principal of, or interest on, the Loans or of fees shall be due on a day which is not a Business Day, the date for payment thereof shall be extended to the next succeeding Business Day. If the date for any payment of principal is extended by operation of law or otherwise, interest thereon, at the then applicable rate, shall be payable for such extended time.

(b)Notwithstanding the foregoing or any contrary provision hereof, if any Bank shall fail to make any payment required to be made by it hereunder to the Administrative Agent, any Issuing Bank or the Swingline Bank, then the Administrative Agent may, in its discretion, apply any amounts thereafter received by the Administrative Agent for the account of such Bank to

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satisfy such Bank’s obligations to the Administrative Agent, any Issuing Bank or the Swingline Bank, as the case may be, until all such unsatisfied obligations are fully paid. The Administrative Agent will distribute to such Issuing Bank and Swingline Bank like amounts relating to payments made to the Administrative Agent for the account of such Issuing Bank or Swingline Bank, as the case may be, in the same manner, and subject to the same terms and conditions, as set forth hereinabove with respect to distributions of amounts to the Banks.

(c)Unless the Administrative Agent shall have received notice from Borrower prior to the date on which any payment is due to the Administrative Agent for the account of the Banks or the Issuing Banks hereunder that Borrower will not make such payment, the Administrative Agent may assume that Borrower has made such payment on such date in accordance herewith and may, in reliance upon such assumption, distribute to the Banks or the Issuing Banks, as the case may be, the amount due. In such event, if Borrower has not in fact made such payment, then each of the Banks or the Issuing Banks, as the case may be, severally agrees to repay to the Administrative Agent forthwith on demand the amount so distributed to such Bank or such Issuing Bank, with interest thereon, for each day from and including the date such amount is distributed to it to but excluding the date of payment to the Administrative Agent, at the greater of the Fed Funds Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation.

(d)Notwithstanding any other provision of this Agreement or any other Transaction Document to the contrary, all amounts collected or received by the Administrative Agent or any Bank after acceleration of the Loans pursuant to Section 7 shall be applied by the Administrative Agent as follows:

(i)first, to the payment of all reasonable out-of-pocket costs and expenses (including, without limitation, reasonable attorneys’ and consultants’ fees irrespective of whether such fees are allowed as a claim after the occurrence of an Event of Default under Section 7(g) or Section 7(h)) of the Administrative Agent in connection with enforcing the rights of the Banks under the Transaction Documents;

(ii)second, to the payment of any fees owed to the Administrative Agent hereunder or under any other Transaction Document;

(iii)third, to the payment of all reasonable and documented out-of-pocket costs and expenses (including, without limitation, reasonable attorneys’ and consultants’ fees irrespective of whether such fees are allowed as a claim after the occurrence of an Event of Default under Section 7(g) or (h)) of each of the Banks in connection with enforcing its rights under the Transaction Documents or otherwise with respect to Borrower’s Obligations owing to such Bank;

(iv)fourth, to the payment of all of Borrower’s Obligations consisting of accrued fees and interest (including, without limitation, fees incurred and interest accruing at the then applicable rate after the occurrence of an Event of Default under Section 7(g) or (h) irrespective of whether a claim for such fees incurred and interest accruing is allowed in such proceeding);

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(v)fifth, to the payment of the outstanding principal amount of Borrower’s Obligations (including the payment of any outstanding Reimbursement Obligations and the obligation to cash collateralize Letter of Credit Exposure);

(vi)sixth, to the payment of all other Borrower’s Obligations and other obligations that shall have become due and payable under the Transaction Documents or otherwise and not repaid; and

(vii)seventh, to the payment of the surplus (if any) to whomever may be lawfully entitled to receive such surplus.

In carrying out the foregoing, (A) amounts received shall be applied in the numerical order provided until exhausted prior to application to the next succeeding category, (B) all amounts shall be apportioned ratably among the Banks in proportion to the amounts of such principal, interest, fees or other Borrower’s Obligations owed to them respectively pursuant to clauses (iii) through (vi) above, and (C) to the extent that any amounts available for distribution pursuant to clause (iv) above are attributable to the issued but undrawn amount of outstanding Letters of Credit, such amounts shall be held by the Administrative Agent to cash collateralize Letter of Credit Exposure pursuant to Section 3.08.

2.10Funding Losses. Notwithstanding any provision contained in this Agreement to the contrary, (a) if for any reasons there occurs any payment of principal or conversion with respect to any LIBOR Loan (pursuant to Sections 2 or 7 or otherwise) on any day other than the last day of the Interest Period applicable thereto (including as a consequence of any assignment made pursuant to Section 2.19 or any acceleration of the Loans under Section 7), (b) if Borrower fails to borrow or pay any LIBOR Loan after notice has been given by Borrower to the Administrative Agent in accordance with Section 2.02, 2.04, 2.08 or otherwise, (c) if Borrower fails to make any prepayment of any LIBOR Loan on the date specified in a notice of prepayment given by Borrower, (d) if there is any other failure by Borrower to make any payments with respect to LIBOR Loans when due hereunder or (e) any assignment of a LIBOR Loan on a day other than the last day of the Interest Period therefor as a result of a request by the Borrower pursuant to Section 2.19, Borrower shall reimburse each Bank on demand for any resulting losses and expenses incurred by it, including, without limitation, any losses incurred in obtaining, liquidating or employing deposits from third parties but excluding any loss of margin for the period after any such payment; provided that (i) with respect to losses resulting from the circumstances described in clause (a), Borrower shall not reimburse any Bank if such losses are the result of a default by such Bank and (ii) such Bank shall have delivered to Borrower a certificate setting forth in reasonable detail the calculation of the amount of such losses and expenses, which calculation shall be conclusive in the absence of manifest error.

2.11Basis for Determining Interest Rate Inadequate or Unfair. If with respect to any Interest Period: (a) the Administrative Agent shall have determined that adequate and reasonable means do not exist for ascertaining the applicable LIBOR Rate for such Interest Period or (b) the Administrative Agent shall have received written notice from the Required Banks of their determination that the LIBOR Rate as determined pursuant to the definition thereof will not adequately and fairly reflect the cost to such Banks of maintaining or funding the LIBOR Loans for such Interest Period, the Administrative Agent will forthwith so notify the Banks and

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Borrower which notice shall set forth in detail the basis for such notice, whereupon until the Administrative Agent or the Required Banks, as the case may be, shall have determined that the circumstances giving rise to such suspension no longer exist and the Administrative Agent shall have notified Borrower and the Banks (and the Required Banks, if making such determination, shall have so notified the Administrative Agent) (i) the LIBOR Rate shall not be available to Borrower as an interest rate option on any Loans, (ii) all of the then outstanding LIBOR Loans shall automatically convert to Base Rate Loans on the last day of the then current Interest Period applicable to each such LIBOR Loan and (iii) any Notice of Borrowing or Notice of Election given at any time thereafter with respect to LIBOR Loans shall be deemed to be a request for Base Rate Loans. Interest accrued on each such LIBOR Loan prior to any such conversion shall be due and payable on the date of such conversion.

2.12Illegality. If, after the Closing Date, any Bank shall have determined that a Regulatory Change shall make it unlawful or impossible for such Bank to make, maintain or fund its LIBOR Loans to Borrower, such Bank shall forthwith give notice thereof to the Administrative Agent and Borrower. Upon such notice (a) Borrower shall convert all of its then outstanding LIBOR Loans from such Bank on either (i) the last day of the then current Interest Period applicable to such LIBOR Loan if such Bank may lawfully continue to maintain and fund such LIBOR Loan to such day or (ii) immediately if such Bank may not lawfully continue to fund and maintain such LIBOR Loan to such day, to a Base Rate Loan in an equal principal amount (interest accrued on each such LIBOR Loan prior to any such conversion shall be due and payable on the date of such conversion together with any funding losses and other amounts due under Section 2.10.), (b) the obligation of such Bank to make, to convert Base Rate Loans into, or to continue LIBOR Loans shall be suspended (including pursuant to any borrowing for which the Administrative Agent has received a Notice of Borrowing or Notice of Election but for which the date of such borrowing has not arrived), and (c) any Notice of Borrowing or Notice of Election given at any time thereafter with respect to LIBOR Loans shall, as to such Bank, be deemed to be a request for a Base Rate Loan, in each case until such Bank shall have determined that the circumstances giving rise to such suspension no longer exist and shall have so notified the Administrative Agent, and the Administrative Agent shall have so notified Borrower.

2.13Increased Cost.

(a)If any Regulatory Change: (i) shall subject any Bank to any tax, duty or other charge with respect to this Agreement, any Letter of Credit, any participation in a Letter of Credit or any LIBOR Loans made by it or shall change the basis of taxation of payments to any Bank or any Issuing Bank in respect thereof (of the principal of or interest on its LIBOR Loans or any other amounts due under this Agreement in respect of its LIBOR Loans or its obligation to make LIBOR Loans (except for Indemnified Taxes or Other Taxes covered by Section 2.20 and the imposition of, or any change in the rate of, any Excluded Tax payable by or with respect to amounts payable to such Bank or such Issuing Bank); or (ii) shall impose, modify or deem applicable any reserve, special deposit, capital, compulsory loan, insurance charge or similar requirement against assets of, deposits with or for the account of, or credit extended or committed to be extended or participated in by, any Bank (except the Reserve Requirement reflected in the LIBOR Rate) or any Issuing Bank or (iii) shall, with respect to any Bank, any Issuing Bank or the London interbank market impose, modify or deem applicable any other condition affecting this Agreement or such Bank’s LIBOR Loans or any Letter of Credit or

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participation therein; and the result of any of the foregoing is to increase the cost to (or in the case of Regulation D, to impose a cost on or increase the cost to) such Bank of making or maintaining any LIBOR Loan (or of maintaining its obligation to make any such Loan), or to increase the cost to such Bank or such Issuing Bank of participating in, issuing or maintaining any Letter of Credit (or of maintaining its obligation to participate in or to issue any Letter of Credit), or to reduce the amount of any sum received or receivable by such Bank under this Agreement, then upon notice by such Bank or such Issuing Bank to the Administrative Agent and Borrower, which notice shall set forth such Bank’s supporting calculations and the details of the Requirements of Law, Borrower shall pay such Bank or such Issuing Bank, as the case may be, as additional interest, such additional amount or amounts as will compensate such Bank or such Issuing Bank for such increased cost or reduction. The determination by any Bank under this Section of the additional amount or amounts to be paid to it hereunder shall be conclusive in the absence of manifest error. In determining such amount or amounts, the Banks may use any reasonable averaging and attribution methods.

2.14Base Rate Loans Substituted for Affected LIBOR Loans. If notice has been given by a Bank pursuant to Sections 2.11 or 2.12 or by Borrower pursuant to Section 2.13 requiring LIBOR Loans of any Bank to be repaid, then, unless and until such Bank notifies the Administrative Agent and Borrower that the circumstances giving rise to such repayment no longer apply, all Loans which would otherwise be made by such Bank to Borrower as LIBOR Loans shall be made instead as Base Rate Loans. Such Bank shall promptly notify the Administrative Agent and Borrower if and when the circumstances giving rise to such repayment no longer apply.

2.15Capital Adequacy. If, after the date of this Agreement, any Bank or any Issuing Bank shall have determined in good faith that a Regulatory Change affecting such Bank or such Issuing Bank or any Lending Office of such Bank or such Bank’s or such Issuing Bank’s holding company, if any, regarding capital or liquidity requirements has or would have the effect of reducing the rate of return on such Bank’s or such Issuing Bank’s capital or on the capital of such Bank’s or such Issuing Bank’s holding company, if any, as a consequence of this Agreement, the Revolving Credit Commitments of such Bank or the Loans made by, or participations in Letters of Credit held by, such Bank, or the Letters of Credit issued by such Issuing Bank, to a level below that which such Bank or such Issuing Bank or such Bank’s or such Issuing Bank’s holding company could have achieved but for such Regulatory Change (taking into consideration such Bank’s or such Issuing Bank’s policies and the policies of such Bank’s or such Issuing Bank’s holding company with respect to capital adequacy), then from time to time Borrower will pay to such Bank or such Issuing Bank, as the case may be, such additional amount or amounts as will compensate such Bank or such Issuing Bank or such Bank’s or such Issuing Bank’s holding company for any such reduction suffered. All determinations made in good faith by such Bank or such Issuing Bank of the additional amount or amounts required to compensate such Bank or such Issuing Bank in respect of the foregoing shall be conclusive in the absence of manifest error. In determining such amount or amounts, such Bank or such Issuing Bank may use any reasonable averaging and attribution methods.

2.16Survival of Indemnities. All indemnities and all provisions relating to reimbursement to the Banks of amounts sufficient to protect the yield to the Banks with respect to the Loans, including, without limitation, Sections 2.10, 2.13 and 2.15 hereof, shall survive the

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payment of the Loans, termination of the Revolving Credit Commitments, Letters of Credit and the other Borrower’s Obligations and the expiration or termination of this Agreement. Notwithstanding the foregoing, if any Bank fails to notify Borrower of any funding loss or increased costs or reduction incurred which would entitle such Bank to compensation pursuant to Sections 2.10, 2.13 and/or 2.15 hereof within ninety (90) daysafter such Bank obtains knowledge of such funding loss or increased costs or reduction, then such Bank shall not be entitled to any compensation from Borrower for such funding loss or increased costs or reduction.

2.17Discretion of Banks as to Manner of Funding. Notwithstanding any provision contained in this Agreement to the contrary, each Bank shall be entitled to fund and maintain its funding of all or any part of its LIBOR Loans in any manner it elects, it being understood, however, that for purposes of this Agreement all determinations hereunder (including, without limitation, the determination of each Bank’s funding losses and expenses under Section 2.10) shall be made as if such Bank had actually funded and maintained each LIBOR Loan through the purchase of deposits having a maturity corresponding to the maturity of the applicable Interest Period relating to the applicable LIBOR Loan and bearing an interest rate equal to the applicable LIBOR Base Rate.

2.18Obligations of Banks are Several; Sharing of Payments.

(a)The obligations of the Banks hereunder to make Revolving Loans, to fund participations in Letters of Credit and Swingline Loans and to make payments pursuant to Section 9.03(c) are several and not joint. The failure of any Bank to make any Revolving Loan, to fund any such participation or to make any payment under Section 9.03(c) on any date required hereunder shall not relieve any other Bank of its corresponding obligation to do so on such date, and no Bank shall be responsible for the failure of any other Bank to so make its Revolving Loan, to purchase its participation or to make its payment under Section 9.03(c).

(b)The Banks agree among themselves that, in the event that any Bank shall directly or indirectly obtain any payment (whether voluntary, involuntary, through the exercise of any right of set-off, banker’s lien or counterclaim, through the realization, collection, sale or liquidation of any collateral or otherwise) on account of or in respect of any of the Loans or any of the other Borrower’s Obligations in excess of its Pro Rata Share of all such payments, such Bank shall (a) notify the Administrative Agent of such fact and (b) purchase (for cash at face value) from the other Banks participations in the Loans or other Borrower’s Obligations owed to such other Banks in such amounts, and make such other adjustments from time to time, as shall be equitable to the end that the Banks share such payment ratably in accordance with their respective Pro Rata Shares of the outstanding Loans and other Borrower’s Obligations. The Banks further agree among themselves that (i) if any such excess payment to a Bank shall be rescinded or must otherwise be restored, the other Banks which shall have shared the benefit of such payment shall, by repurchase of participation theretofore sold, or otherwise, return its share of that benefit to the Bank whose payment shall have been rescinded or otherwise restored, without interest and (ii) the provisions of this Section shall not be construed to apply to (x) any payment made by Borrower pursuant to and in accordance with the express terms of this Agreement or (y) any payment obtained by a Bank for participations in Reimbursement Obligations or Swingline Loans to any Assignee or Participant, other than to Borrower or any

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Subsidiary thereof (as to which the provisions of this Section shall apply). Borrower agrees that any Banks so purchasing a participation in the Loans or other Borrower’s Obligations to the other Banks may exercise all rights of set-off, banker’s lien and/or counterclaim as fully as if such Banks were a holder of such Loan or other Borrower’s Obligations in the amount of such participation. If under any applicable bankruptcy, insolvency or other similar law any Bank receives a secured claim in lieu of a set-off to which this Section 2.18 would apply, such Banks shall, to the extent practicable, exercise their rights in respect of such secured claim in a manner consistent with the rights of the Banks entitled under this Section 2.18 to share in the benefits of any recovery of such secured claim.

2.19Substitution of Bank. If (i) the obligation of any Bank to make LIBOR Loans has been suspended pursuant to Section 2.12, (ii) any Bank has demanded compensation under Sections 2.13 and/or 2.15 or payments from Borrower under Section 2.20 or (iii) any Bank becomes a Defaulting Bank (in each case, an “Affected Bank”), Borrower shall have the right, with the assistance of the Administrative Agent, to, without recourse (and in accordance with and subject to the restrictions contained in, and consents required by, Section 9.09), seek a mutually satisfactory substitute bank or banks (which may be one or more of the Banks) (each a “Purchasing Bank”) to purchase the Revolving Credit Note and assume the Revolving Credit Commitment of such Affected Bank. The Affected Bank shall be obligated to sell its Revolving Credit Note and assign its Revolving Credit Commitment and participation in Letters of Credit to such Purchasing Bank or Purchasing Banks within fifteen (15) days after receiving notice from Borrower requiring it to do so, at an aggregate price equal to the outstanding principal amount of such Revolving Credit Note and any funded participations in Letters of Credit not refinanced through the borrowing of Revolving Loans, plus unpaid interest accrued thereon up to but excluding the date of sale plus the amount of any compensation that would be due to the Affected Bank under Section 2.10 if Borrower had prepaid the outstanding LIBOR Loans of the Affected Bank on the date of such sale. In connection with any such sale, and as conditions thereof, (A) Borrower shall pay to the Affected Bank the sum of (y) all fees accrued for its account under this Agreement to but excluding the date of such sale, and (z) any additional compensation accrued for its account under Sections 2.13 and/or 2.15 to but excluding the date of such sale, (B) in the case of such assignment resulting from a request for compensation under Sections 2.13 and/or 2.15 or payment required to be made under Section 2.20, such assignment will result in a reduction of such compensation or payments thereafter and (C) such assignment does not conflict with applicable Requirements of Law. Upon such sale, (1) the Purchasing Bank or Purchasing Banks shall assume the Affected Bank’s Revolving Credit Commitment and participation in Letters of Credit and the Affected Bank shall be released from its obligations under this Agreement to a corresponding extent and (2) the Affected Bank, as assignor, such Purchasing Bank, as assignee, Borrower and the Administrative Agent shall enter into an Assignment and Assumption Agreement in accordance with Section 9.09(c), whereupon such Purchasing Bank shall be a Bank party to this Agreement, shall be deemed to be an Assignee under this Agreement and shall have all the rights and obligations of a Bank with a Revolving Credit Commitment in an amount equal to the Revolving Credit Commitment of the Affected Bank. In connection with any assignment pursuant to this Section, Borrower shall pay to the Administrative Agent the administrative fee of $3,500 for processing such assignment referred to in Section 9.09(c). Upon the consummation of any sale pursuant to this Section 2.19, the Affected Bank, the Administrative Agent and Borrower shall make appropriate arrangements so that, if requested, each Purchasing Bank receives a new Note.

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2.20Taxes.

(a)Any and all payments by Borrower to or for the account of any Bank or the Administrative Agent under any Transaction Document shall be made free and clear of and without reduction or withholding for any Indemnified Taxes or Other Taxes; provided that if Borrower shall be required by applicable law to deduct any Indemnified Taxes (including any Other Taxes) from or in respect of any sum payable under any Transaction Document to any Bank, any Issuing Bank or the Administrative Agent, (i) the sum payable shall be increased as necessary so that after making all required deductions (including deductions applicable to additional sums payable under this Section 2.20(a)) such Bank, such Issuing Bank or the Administrative Agent (as the case may be) receives an amount equal to the sum it would have received had no such deduction for Taxes been made, (ii) Borrower shall make such deductions and (iii) Borrower shall pay the full amount deducted to the relevant Governmental Authority in accordance with applicable law.

(b)Without limiting the provisions of Section 2.20(a), Borrower shall timely pay any Other Taxes to the relevant Governmental Authority in accordance with applicable law.

(c)Borrower agrees to indemnify each Bank, each Issuing Bank and the Administrative Agent for the full amount of any Indemnified Taxes or Other Taxes, respectively (including, without limitation, any Indemnified Taxes or Other Taxes imposed or asserted by any jurisdiction on amounts payable under this Section 2.20), paid by such Bank, such Issuing Bank or the Administrative Agent (as the case may be) and any liability (including penalties, interest and expenses) arising therefrom or with respect thereto, whether or not such Indemnified Taxes or Other Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. This indemnification shall be made within fifteen (15) days from the date such Bank, such Issuing Bank or the Administrative Agent (as the case may be) makes demand therefor, accompanied by a certificate of such Bank, such Issuing Bank or the Administrative Agent (as the case may be) setting forth in reasonable detail its computation of the amount or amounts to be paid to it hereunder.

(d)As soon as practicable after any payment of Indemnified Taxes or Other Taxes by Borrower to a Governmental Authority, Borrower shall furnish to the Administrative Agent (who shall forward the same to the applicable Bank), at its address specified in Schedule 9.04, the original or a certified copy of a receipt issued by such Governmental Authority evidencing such payment, a copy of the return reporting such payment or other evidence of such payment reasonably satisfactory to the Administrative Agent.

(e)Any Foreign Bank that is entitled to an exemption from or reduction of withholding tax under the law of the jurisdiction in which Borrower is resident for tax purposes, or any treaty to which such jurisdiction is a party, with respect to payments hereunder or under any other Transaction Document shall deliver to Borrower (with a copy to the Administrative Agent), at the time or times prescribed by applicable law or reasonably requested by Borrower or the Administrative Agent, such properly completed and executed documentation prescribed by applicable law as will permit such payments to be made without withholding or at a reduced rate of withholding. In addition, any Bank, if requested by Borrower or the Administrative Agent, shall deliver such other documentation prescribed by applicable law or reasonably requested by

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Borrower or the Administrative Agent as will enable Borrower or the Administrative Agent to determine whether or not such Bank is subject to backup withholding or information reporting requirements.

(f)Without limiting the generality of the foregoing, in the event that Borrower is a resident for tax purposes in the United States, any Foreign Bank shall deliver to Borrower and the Administrative Agent (in such number of copies as shall be requested by the recipient) on or prior to the date on which such Foreign Bank becomes a Bank under this Agreement (and from time to time thereafter upon the request of Borrower or the Administrative Agent, but only if such Foreign Bank is legally entitled to do so), whichever of the following is applicable:

(i)duly completed copies of Internal Revenue Service Form W-8BEN claiming eligibility for benefits of an income tax treaty to which the United States is a party,

(ii)duly completed copies of Internal Revenue Service Form W-8ECI,

(iii)in the case of a Foreign Bank claiming the benefits of the exemption for portfolio interest under Section 881(c) of the Code, (x) a certificate to the effect that such Foreign Bank is not (A) a “bank” within the meaning of Section 881(c)(3)(A) of the Code, (B) a “10 percent shareholder” of Borrower within the meaning of Section 881(c)(3)(B) of the Code, or (C) a “controlled foreign corporation” described in Section 881(c)(3)(C) of the Code and (y) duly completed copies of Internal Revenue Service Form W-8BEN,

(iv)if a payment made to a Bank under any Transaction Document would be subject to U.S. Federal withholding Tax imposed by FATCA if such Bank fails to comply with the applicable reporting requirements of FATCA (including those contained in Section 1471(b) or 1472(b) of the Code, as applicable), such Bank shall deliver to the Withholding Agent (as defined below) (A) a certification signed by the chief financial officer, principal accounting officer, treasurer or controller and (B) other documentation reasonably requested by the Withholding Agent sufficient for the Withholding Agent to comply with its obligations under FATCA and to determine that such Bank has complied with such applicable reporting requirements. “Withholding Agent” means Borrower or the Administrative Agent, or

(v)any other form prescribed by applicable law as a basis for claiming exemption from or a reduction in United States federal withholding tax duly completed together with such supplementary documentation as may be prescribed by applicable law to permit Borrower to determine the withholding or deduction required to be made; provided, however, that such Bank shall inform the Borrower at such time as any previously provided tax form pursuant to Section 2.20(e) or (f) expires or becomes obsolete, other than as a result of a change in law.

(g)If the Administrative Agent, any Issuing Bank or any Bank determines, in its sole discretion acting in good faith , that it has received a refund of any Taxes or Other Taxes as to which it has been indemnified by Borrower or with respect to which Borrower has paid

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additional amounts pursuant to this Section, it shall pay to Borrower an amount equal to such refund (but only to the extent of indemnity payments made, or additional amounts paid, by Borrower under this Section with respect to the Taxes or Other Taxes giving rise to such refund), net of all out-of-pocket expenses of such Bank, such Issuing Bank or the Administrative Agent, as the case may be, and without interest (other than any interest paid by the relevant Governmental Authority with respect to such refund), provided that Borrower, upon the request of such Bank, such Issuing Bank, or the Administrative Agent, agrees to repay the amount paid over to Borrower (plus any penalties, interest or other charges imposed by the relevant Governmental Authority) to the Administrative Agent, such Bank or such Issuing Bank in the event the Administrative Agent, such Bank or such Issuing Bank is required to repay such refund to such Governmental Authority. This Section 2.20(g) shall not be construed to require any Bank, any Issuing Bank, or the Administrative Agent to make available its tax returns (or any other information relating to its taxes that it deems confidential) to Borrower or any other Person.

(h)The provisions of this Section 2.20 shall survive any expiration or termination of this Agreement and the payment of the Loans and the other Borrower’s Obligations.

2.21Defaulting Banks.

(a)Notwithstanding anything to the contrary contained in this Agreement, if any Bank becomes a Defaulting Bank, then, until such time as such Bank is no longer a Defaulting Bank, to the extent permitted by applicable law:

(i)Such Defaulting Bank’s right to approve or disapprove any amendment, waiver or consent with respect to this Agreement shall be restricted as set forth in the definition of Required Banks and in Section 9.07.

(ii)Fees shall cease to accrue on such Defaulting Bank’s Pro Rata Share of the average daily Unutilized Revolving Credit Commitment pursuant to Section 2.07(a).

(iii)Any payment of principal, interest, fees (other than any fees described in clause (ii) above) or other amounts received by the Administrative Agent for the account of such Defaulting Bank (whether voluntary or mandatory, at maturity, pursuant to Section 7 or otherwise) shall be applied at such time or times as may be determined by the Administrative Agent as follows: first, to the payment of any amounts owing by such Defaulting Bank to the Administrative Agent hereunder; second, to the payment on a pro rata basis of any amounts owing by such Defaulting Bank to any Issuing Bank or the Swingline Bank hereunder; third, if so determined by the Administrative Agent or requested by any Issuing Bank or the Swingline Bank, to be held as Cash Collateral for future funding obligations of such Defaulting Bank in respect of any participation in any Letter of Credit or Swingline Loan; fourth, as Borrower may request (so long as no Default or Event of Default exists), to the funding of any Loan in respect of which that Defaulting Bank has failed to fund its portion thereof as required by this Agreement, as determined by the Administrative Agent; fifth, if so determined by the Administrative Agent and Borrower, to be held in a non-interest bearing deposit account and released in order to satisfy obligations of such Defaulting Bank to fund Loans under this Agreement; sixth, to the payment of any amounts owing to the Banks, the Issuing Banks or the

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Swingline Bank as a result of any judgment of a court of competent jurisdiction obtained by any Bank, any Issuing Bank or the Swingline Bank against that Defaulting Bank as a result of such Defaulting Bank’s breach of its obligations under this Agreement; seventh, so long as no Default exists, to the payment of any amounts owing to Borrower as a result of any judgment of a court of competent jurisdiction obtained by Borrower against such Defaulting Bank as a result of such Defaulting Bank’s breach of its obligations under this Agreement; and eighth, to such Defaulting Bank or as otherwise directed by a court of competent jurisdiction; provided that if (A) such payment is a payment of the principal amount of any Loans or any Letter of Credit Exposure in respect of which such Defaulting Bank has not fully funded its appropriate share, and (B) such Loans were made or the related Letters of Credit were issued at a time when the conditions set forth in Section 4.02 were satisfied or waived, such payment shall be applied solely to pay the Loans of, and obligations in respect of Letters of Credit owed to, all non-Defaulting Banks on a pro rata basis prior to being applied to the payment of any Loans of, or obligations in respect of Letters of Credit owed to, such Defaulting Bank. Any payments, prepayments or other amounts paid or payable to a Defaulting Bank that are applied (or held) to pay amounts owed by a Defaulting Bank or to post Cash Collateral pursuant to this Section shall be deemed paid to and redirected by such Defaulting Bank, and each Bank irrevocably consents hereto.

(iv)All or any part of such Defaulting Bank’s Letter of Credit Exposure and its Swingline Exposure shall automatically (effective on the day such Bank becomes a Defaulting Bank) be reallocated among the non-Defaulting Banks in accordance with their respective Pro Rata Shares (calculated without regard to such Defaulting Bank’s Revolving Credit Commitment) but only to the extent that (A) no Event of Default shall have occurred and be continuing (and, unless Borrower shall have otherwise notified the Administrative Agent at the time, Borrower shall be deemed to have represented and warranted that such condition is satisfied at such time), and (B) such reallocation does not cause the Revolving Credit Exposure of any non-Defaulting Bank to exceed such non-Defaulting Bank’s Revolving Credit Commitment.

(v)If the reallocation described in clause (iv) above cannot, or can only partially, be effected, Borrower shall, without prejudice to any right or remedy available to it hereunder or under law, within two (2) Business Days following notice by the Administrative Agent, (x) first, prepay Swingline Loans in an amount equal to the Swingline Banks’ Fronting Exposure and (y) second, Cash Collateralize any Issuing Bank’s Fronting Exposure in accordance with the procedures set forth in Section 3.08.

(b)If Borrower, the Administrative Agent, the Issuing Banks and the Swingline Bank agree in writing in their sole discretion that a Defaulting Bank should no longer be deemed to be a Defaulting Bank, the Administrative Agent will so notify the parties hereto, whereupon as of the effective date specified in such notice and subject to any conditions set forth therein (which may include arrangements with respect to any Cash Collateral), that Bank will, to the extent applicable, purchase that portion of outstanding Loans of the other Banks or take such other actions as the Administrative Agent may determine to be necessary to cause the Revolving Loans and funded and unfunded participations in Letters of Credit and Swingline Loans to be held on a pro rata basis by the Banks in accordance with their respective Pro Rata Shares (without giving

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effect to Section 2.21(a)(iii)), whereupon such Bank will cease to be a Defaulting Bank; provided that no adjustments will be made retroactively with respect to fees accrued or payments made by or on behalf of Borrower while that Bank was a Defaulting Bank; and provided, further, that except to the extent otherwise expressly agreed by the affected parties, no change hereunder from Defaulting Bank to Bank will constitute a waiver or release of any claim of any party hereunder arising from that Bank’s having been a Defaulting Bank.

SECTION 3.LETTERS OF CREDIT

3.01Issuance. Subject to and upon the terms and conditions herein set forth, each Issuing Bank agrees, at any time and from time to time on and after the Closing Date and prior to the earlier of (i) the Letter of Credit Maturity Date and (ii) the last day of the Revolving Credit Period, and upon request by Borrower to it in accordance with the provisions of Section 3.02, to issue for the account of Borrower one or more irrevocable standby letters of credit denominated in Dollars and in a form customarily used or otherwise approved by such Issuing Bank (together with all amendments, modifications and supplements thereto, substitutions therefor and renewals and restatements thereof, collectively, the “Letters of Credit”). The Stated Amount of each Letter of Credit shall not be less than $100,000 or such lesser amount as may be acceptable to such Issuing Bank. Notwithstanding the foregoing:

(j)No Letter of Credit shall be issued if, after giving effect to such issuance, (i) the Stated Amount when added to the aggregate Letter of Credit Exposure of the Banks at such time, would exceed the aggregate Letter of Credit Commitment, (ii) with respect to a Letter of Credit with the applicable Issuing Bank, the Stated Amount when added to the aggregate Letter of Credit Exposure of the Banks with respect to Letters of Credit issued by the applicable Issuing Bank at such time, would exceed the Letter of Credit Commitment of such Issuing Bank,(iii) the Stated Amount when added to the aggregate Revolving Credit Exposure, would exceed the aggregate Revolving Credit Commitments at such time, or (iv) any Bank is at that time a Defaulting Bank, unless such Issuing Bank’s Fronting Exposure is 100% covered by the commitments of the non-Defaulting Banks or the applicable Issuing Bank has entered into an arrangement, including the delivery of Cash Collateral, satisfactory to such Issuing Bank (in its sole discretion) with Borrower or such Bank to eliminate such Issuing Bank’s actual Fronting Exposure (after giving effect to Section 2.20(a)(iii)) with respect to the Defaulting Bank arising from either the Letter of Credit then proposed to be issued or that Letter of Credit and all other Letter of Credit Exposure as to which the Issuing Bank has actual Fronting Exposure, as it may elect in its sole discretion;

(k)No Letter of Credit shall be issued that by its terms expires later than the Letter of Credit Maturity Date or, in any event, more than one year after its date of issuance; provided, however, that a Letter of Credit may, if requested by Borrower, provide by its terms, and on terms acceptable to the applicable Issuing Bank, for renewal for successive periods of one year or less (but not beyond the Letter of Credit Maturity Date), unless and until such Issuing Bank shall have delivered a notice of nonrenewal to the beneficiary of such Letter of Credit; and

(l)No Issuing Bank shall be under any obligation to issue any Letter of Credit if, at the time of such proposed issuance, (i) any order, judgment or decree of any Governmental Authority or arbitrator shall purport by its terms to enjoin or restrain such Issuing Bank from

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issuing such Letter of Credit, or any Requirement of Law applicable to such Issuing Bank or any request or directive (whether or not having the force of law) from any Governmental Authority with jurisdiction over such Issuing Bank shall prohibit, or request that such Issuing Bank refrain from, the issuance of letters of credit generally or such Letter of Credit in particular or shall impose upon such Issuing Bank with respect to such Letter of Credit any restriction or reserve or capital requirement (for which such Issuing Bank is not otherwise compensated) not in effect on the Closing Date, or any unreimbursed loss, cost or expense that was not applicable, in effect or known to such Issuing Bank as of the Closing Date and that such Issuing Bank in good faith deems material to it, or (ii) such Issuing Bank shall have actual knowledge, or shall have received notice from any Bank, prior to the issuance of such Letter of Credit that one or more of the conditions specified in Section 4.01 (if applicable) or Section 4.02 are not then satisfied (or have not been waived in writing as required herein) or that the issuance of such Letter of Credit would violate the provisions of Section 3.01(a).

3.02Notices. Whenever Borrower desires the issuance of a Letter of Credit, Borrower will give the applicable Issuing Bank written notice with a copy to the Administrative Agent not later than 11:00 a.m., Charlotte time, three (3) Business Days (or such shorter period as is acceptable to such Issuing Bank in any given case) prior to the requested date of issuance thereof. Each such notice (each, a “Letter of Credit Notice”) shall be irrevocable, shall be given substantially in the form of Exhibit B-4 and shall specify (a) the requested date of issuance, which shall be a Business Day, (b) the requested Stated Amount and expiry date of the Letter of Credit, and (c) the name and address of the requested beneficiary or beneficiaries of the Letter of Credit. Borrower will also complete any application procedures and documents reasonably required by such Issuing Bank in connection with the issuance of any Letter of Credit. Upon its issuance of any Letter of Credit, such Issuing Bank will promptly notify the Administrative Agent of such issuance, and the Administrative Agent will give prompt notice thereof to each Bank. The renewal or extension of any outstanding Letter of Credit shall, for purposes of this Section 3, be treated in all respects as the issuance of a new Letter of Credit.

3.03Participations. Immediately upon the issuance of any Letter of Credit, the applicable Issuing Bank shall be deemed to have sold and transferred to each Bank, and each Bank shall be deemed irrevocably and unconditionally to have purchased and received from such Issuing Bank, without recourse or warranty (except for the absence of Liens thereon created, incurred or suffered to exist by, through or under such Issuing Bank), an undivided interest and participation, pro rata (based on such Bank’s Pro Rata Share), in such Letter of Credit, each drawing made thereunder and the obligations of Borrower under this Agreement with respect thereto and any Collateral or other security therefor or guaranty pertaining thereto; provided, however, that the fee relating to Letters of Credit described in Section 2.07(c) shall be payable directly to such Issuing Bank as provided therein, and the other Banks shall have no right to receive any portion thereof. In consideration and in furtherance of the foregoing, each Bank hereby absolutely and unconditionally agrees to pay to the Administrative Agent, for the account of such Issuing Bank, such Bank’s Pro Rata Share of each Reimbursement Obligation not reimbursed by Borrower on the date due as provided in Section 3.04 or through the borrowing of Revolving Loans as provided in Section 3.05 (because the conditions set forth in Section 4.02 cannot be satisfied, or for any other reason), or of any reimbursement payment required to be refunded to Borrower for any reason. Upon any change in the Revolving Credit Commitments of any of the Banks pursuant to Section 9.09, with respect to all outstanding Letters of Credit and

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Reimbursement Obligations there shall be an automatic adjustment to the participations pursuant to this Section 3.03 to reflect the new Pro Rata Shares of the assigning Bank and the Assignee. Each Bank’s obligation to make payment to such Issuing Bank pursuant to this Section 3.03 shall be absolute and unconditional and shall not be affected by any circumstance whatsoever, including the termination of the Revolving Credit Commitments or the existence of any Default or Event of Default, and each such payment shall be made without any offset, abatement, reduction or withholding whatsoever.

3.04Reimbursement. Borrower hereby agrees to reimburse the applicable Issuing Bank by making payment to the Administrative Agent, for the account of such Issuing Bank, in immediately available funds, for any payment made by such Issuing Bank under any Letter of Credit issued by it (each such amount so paid until reimbursed, together with interest thereon payable as provided hereinbelow, a “Reimbursement Obligation”) immediately upon, and in any event on the same Business Day as, the making of such payment by such Issuing Bank (provided that any such Reimbursement Obligation shall be deemed timely satisfied (but nevertheless subject to the payment of interest thereon as provided hereinbelow) if satisfied pursuant to a borrowing of Revolving Loans made on the date of such payment by such Issuing Bank, as set forth more completely in Section 3.05), together with interest on the amount so paid by such Issuing Bank, to the extent not reimbursed prior to 2:00 p.m., Charlotte time, on the date of such payment or disbursement, for the period from the date of the respective payment to the date the Reimbursement Obligation created thereby is satisfied, at the Adjusted Base Rate applicable to Revolving Loans as in effect from time to time during such period, such interest also to be payable on demand. Each Issuing Bank will provide the Administrative Agent and Borrower with prompt notice of any payment or disbursement made or to be made under any Letter of Credit issued by it, although the failure to give, or any delay in giving, any such notice shall not release, diminish or otherwise affect Borrower’s obligations under this Section 3.04 or any other provision of this Agreement. The Administrative Agent will promptly pay to such Issuing Bank any such amounts received by it under this Section 3.04.

3.05Payment by Revolving Loans. In the event that any Issuing Bank makes any payment under any Letter of Credit and Borrower shall not have timely satisfied in full its Reimbursement Obligation to such Issuing Bank pursuant to Section 3.04, and to the extent that any amounts then held in the Cash Collateral Account established pursuant to Section 3.08 shall be insufficient to satisfy such Reimbursement Obligation in full, such Issuing Bank will promptly notify the Administrative Agent, and the Administrative Agent will promptly notify each Bank, of such failure. If the Administrative Agent gives such notice prior to 12:00 noon, Charlotte time, on any Business Day, each Bank will make available to the Administrative Agent, for the account of such Issuing Bank, its Pro Rata Share of the amount of such payment on such Business Day in immediately available funds. If the Administrative Agent gives such notice after 12:00 noon, Charlotte time, on any Business Day, each such Bank shall make its Pro Rata Share of such amount available to the Administrative Agent on the next succeeding Business Day. If and to the extent any Bank shall not have so made its Pro Rata Share of the amount of such payment available to the Administrative Agent, such Bank agrees to pay to the Administrative Agent, for the account of such Issuing Bank, forthwith on demand such amount, together with interest thereon at the Fed Funds Rate for each day from such date until the date such amount is paid to the Administrative Agent. The failure of any Bank to make available to the Administrative Agent its Pro Rata Share of any payment under any Letter of Credit shall not

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relieve any other Bank of its obligation hereunder to make available to the Administrative Agent its Pro Rata Share of any payment under any Letter of Credit on the date required, as specified above, but no Bank shall be responsible for the failure of any other Bank to make available to the Administrative Agent such other Bank’s Pro Rata Share of any such payment. Each such payment by a Bank under this Section 3.05 of its Pro Rata Share of an amount paid by such Issuing Bank shall constitute a Revolving Loan by such Bank (Borrower being deemed to have given a timely Notice of Borrowing therefor) and shall be treated as such for all purposes of this Agreement; provided that for purposes of determining the aggregate Unutilized Revolving Credit Commitments immediately prior to giving effect to the application of the proceeds of such Revolving Loans, the Reimbursement Obligation being satisfied thereby shall be deemed not to be outstanding at such time. Each Bank’s obligation to make Revolving Loans pursuant to this Section 3.05 shall be absolute and unconditional and shall not be affected by any circumstance whatsoever, including, without limitation, the failure of the amount of such borrowing of Revolving Loans to meet the minimum borrowing amount specified in Section 2.01(a); provided, however, that each Bank’s obligation to make Revolving Loans pursuant to this Section 3.05 is subject to the conditions set forth in Section 4.02 (other than delivery by Borrower of a Notice of Borrowing).

3.06Payment to Banks. Whenever any Issuing Bank receives a payment in respect of a Reimbursement Obligation as to which the Administrative Agent has received, for the account of such Issuing Bank, any payments from the Banks pursuant to Section 3.05, such Issuing Bank will promptly pay to the Administrative Agent, and the Administrative Agent will promptly pay to each Bank that has paid its Pro Rata Share thereof, in immediately available funds, an amount equal to such Bank’s Pro Rate Share of such Reimbursement Obligation.

3.07Obligations Absolute. The Reimbursement Obligations of Borrower shall be irrevocable, shall remain in effect until all Issuing Banks shall have no further obligations to make any payments or disbursements under any circumstances with respect to any Letter of Credit, and shall be absolute and unconditional, shall not be subject to counterclaim, setoff or other defense or any other qualification or exception whatsoever and shall be made in accordance with the terms and conditions of this Agreement under all circumstances, including, without limitation, any of the following circumstances:

(d)Any lack of validity or enforceability of this Agreement, any of the other Transaction Documents or any documents or instruments relating to any Letter of Credit;

(e)Any change in the time, manner or place of payment of, or in any other term of, all or any of Borrower’s Obligations in respect of any Letter of Credit or any other amendment, modification or waiver of or any consent to departure from any Letter of Credit or any documents or instruments relating thereto, in each case whether or not Borrower has notice or knowledge thereof;

(f)The existence of any claim, setoff, defense or other right that Borrower may have at any time against a beneficiary named in a Letter of Credit, any transferee of any Letter of Credit (or any Person for whom any such transferee may be acting), the Administrative Agent, any Issuing Bank, any Bank or other Person, whether in connection with this Agreement, any Letter of Credit, the transactions contemplated hereby or any unrelated transactions (including

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any underlying transaction between Borrower and the beneficiary named in any such Letter of Credit);

(g)Any draft, certificate or any other document presented under the Letter of Credit proving to be forged, fraudulent, invalid or insufficient in any respect or any statement therein being untrue or inaccurate in any respect (provided that such draft, certificate or other document appears on its face to comply with the terms of such Letter of Credit), any errors, omissions, interruptions or delays in transmission or delivery of any messages, by mail, telecopier or otherwise, or any errors in translation or in interpretation of technical terms;

(h)Any defense based upon the failure of any drawing under a Letter of Credit to conform to the terms of the Letter of Credit (provided that any draft, certificate or other document presented pursuant to such Letter of Credit appears on its face to comply with the terms thereof), any nonapplication or misapplication by the beneficiary or any transferee of the proceeds of such drawing or any other act or omission of such beneficiary or transferee in connection with such Letter of Credit;

(i)The exchange, release, surrender or impairment of any collateral or other security for Borrower’s Obligations;

(j)The occurrence of any Default or Event of Default; or

(k)Any other circumstance or event whatsoever, including, without limitation, any other circumstance that might otherwise constitute a defense available to, or a discharge of, Borrower.

Any action taken or omitted to be taken by any Issuing Bank under or in connection with any Letter of Credit issued by it, if taken or omitted in the absence of gross negligence or willful misconduct, shall be binding upon Borrower and each Bank and shall not create or result in any liability of such Issuing Bank to Borrower or any Bank. It is expressly understood and agreed that, for purposes of determining whether a wrongful payment under a Letter of Credit resulted from such Issuing Bank’s gross negligence or willful misconduct, (i) such Issuing Bank’s acceptance of documents that appear on their face to comply with the terms of such Letter of Credit, without responsibility for further investigation, regardless of any notice or information to the contrary, (ii) such Issuing Bank’s exclusive reliance on the documents presented to it under such Letter of Credit as to any and all matters set forth therein, including the amount of any draft presented under such Letter of Credit, whether or not the amount due to the beneficiary thereunder equals the amount of such draft and whether or not any document presented pursuant to such Letter of Credit proves to be insufficient in any respect (so long as such document appears on its face to comply with the terms of such Letter of Credit), and whether or not any other statement or any other document presented pursuant to such Letter of Credit proves to be forged or invalid or any statement therein proves to be inaccurate or untrue in any respect whatsoever, and (iii) any noncompliance in any immaterial respect of the documents presented under such Letter of Credit with the terms thereof shall, in each case, be deemed not to constitute gross negligence or willful misconduct of such Issuing Bank.

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3.08Cash Collateral Account. At any time and from time to time (a) after the occurrence and during the continuance of an Event of Default, the Administrative Agent may, and at the direction or with the consent of the Required Banks shall, require Borrower to deliver to the Administrative Agent such additional amount of cash as is equal to 102% ofthe aggregate Stated Amount of all Letters of Credit at any time outstanding (whether or not any beneficiary under any Letter of Credit shall have drawn or be entitled at such time to draw thereunder) and (b) in the event of a prepayment under Section 2.01(b), the Administrative Agent will retain such amount as may then be required to be retained, such amounts in each case under clauses (a) and (b) above to be held by the Administrative Agent in a cash collateral account (the “Cash Collateral Account”). Borrower hereby grants to the Administrative Agent, for the benefit of the Issuing Banks and the Banks, a Lien upon and security interest in the Cash Collateral Account and all amounts held therein from time to time as security for Letter of Credit Exposure, and for application to Borrower’s Reimbursement Obligations as and when the same shall arise. The Administrative Agent shall have exclusive dominion and control, including the exclusive right of withdrawal, over such account. Amounts in the Cash Collateral Account shall not bear interest. In the event of a drawing, and subsequent payment by any Issuing Bank, under any Letter of Credit at any time during which any amounts are held in the Cash Collateral Account, the Administrative Agent will deliver to such Issuing Bank an amount equal to the Reimbursement Obligation created as a result of such payment (or, if the amounts so held are less than such Reimbursement Obligation, all of such amounts) to reimburse such Issuing Bank therefor. Any amounts remaining in the Cash Collateral Account after the expiration of all Letters of Credit and reimbursement in full of the Issuing Banks for all of its obligations thereunder shall be held by the Administrative Agent, for the benefit of Borrower, to be applied against the Obligations in such order and manner as the Administrative Agent may direct. If Borrower is required to provide cash collateral pursuant to Section 2.01(b), such amount, to the extent not applied as aforesaid, shall be returned to Borrower on demand, provided that after giving effect to such return (i) the aggregate Revolving Credit Exposure would not exceed the aggregate Revolving Credit Commitments at such time and (ii) no Default or Event of Default shall have occurred and be continuing at such time. If Borrower is required to provide cash collateral as a result of an Event of Default, such amount (to the extent not applied as aforesaid) shall be returned to Borrower within three (3) Business Days after all Events of Default have been cured or waived.

3.09The Issuing Banks. Each Issuing Bank shall act on behalf of the Banks with respect to any Letters of Credit issued by it and the documents associated therewith, and each Issuing Bank shall have all of the rights, benefits and immunities (a) provided to the Administrative Agent in Section 8 with respect to any acts taken or omissions suffered by it in connection with Letters of Credit issued by it or proposed to be issued by it and any documents pertaining to such Letters of Credit as fully as if the term “Administrative Agent” as used in Section 8 included each Issuing Bank with respect to such acts or omissions, and (b) as additionally provided herein with respect to each Issuing Bank.

3.10Effectiveness. Notwithstanding any termination of the Revolving Credit Commitments or repayment of the Loans, or both, the obligations of Borrower under this Section 3 shall remain in full force and effect until the Issuing Banks and the Banks shall have no further obligations to make any payments or disbursements under any circumstances with respect to any Letter of Credit.

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SECTION 4.CONDITIONS PRECEDENT.

4.01Conditions to Closing and Initial Loans. Notwithstanding any provision contained in this Agreement to the contrary, no Bank shall have any obligation to make the initial Loan(s) and no Issuing Bank shall have any obligation to issue Letters of Credit under this Agreement unless the Administrative Agent shall have first received:

(a)this Agreement and, as requested by any Bank, Notes, all executed by a duly authorized officer of Borrower;

(b)a certificate of an authorized officer of Borrower, dated as of the Closing Date, in form and substance reasonably satisfactory to the Administrative Agent, certifying and attaching the following:

(i)a copy of resolutions of the Board of Directors of Borrower, duly adopted, which authorize the execution, delivery and performance of this Agreement, the Notes and the other Transaction Documents;

(ii)a copy of the Articles of Incorporation of Borrower, including any amendments thereto;

(iii)a copy of the Bylaws of Borrower, including any amendments thereto;

(iv)an incumbency certificate, executed by the Secretary of Borrower, which shall identify by name and title and bear the signatures of all of the officers of Borrower executing any of the Transaction Documents;

(v)a certificate of corporate good standing of Borrower issued by the Secretary of State of the State of Missouri;

(c)favorable opinions of (i) Mark Darrell, General Counsel of Borrower and (ii) Akin Gump Strauss Hauer & Feld LLP, special counsel to Borrower;

(d)a certificate, signed by an authorized officer of Borrower, dated the Closing Date and in form and substance reasonably satisfactory to the Administrative Agent, certifying that (i) all representations and warranties of Borrower contained in this Agreement and the other Transaction Documents (A) that are qualified by materiality or Material Adverse Effect are true and correct as so qualified and (B) that are not qualified by materiality or Material Adverse Effect are true and correct in all material respects, in each case as of the Closing Date (except to the extent any such representation or warranty is expressly stated to have been made as of a specific date, in which case such representation or warranty shall be true and correct as of such date), (ii) no Default or Event of Default has occurred and is continuing, (iii) no Material Adverse Effect has occurred since September 30, 2012, and there exists no event, condition or state of facts that could reasonably be expected to result in a Material Adverse Effect, and (iv) all conditions to the initial extensions of credit hereunder set forth in this Section 4.01 and in Section 4.02 have been satisfied or waived as required hereunder;

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(e)evidence satisfactory to the Administrative Agent that Borrower has paid (i) to Wells Fargo Securities, U.S. Bank, and JPMorgan, the fees required under the applicable Fee Letters, respectively, to be paid to them on the Closing Date, in the amounts due and payable on the Closing Date, (ii) to the Administrative Agent, the initial payment of the annual administrative fee described in the Wells Fargo Fee Letter, and (iii) all other fees and reasonable expenses of the Arrangers, the Administrative Agent and the Banks required under any other Transaction Document to be paid on or prior to the Closing Date (including, to the extent invoiced prior to the Closing Date, reasonable fees and expenses of counsel) in connection with this Agreement and the other Transaction Documents;

(f)copies of the financial statements referred to in Section 5.09;

(g)all documentation and other information requested by the Administrative Agent that is required to satisfy applicable “know your customer” and anti-money laundering rules and regulations, including without limitation the PATRIOT Act;

(h)an Account Designation Letter, together with written instructions from an Authorized Individual, including wire transfer information, directing the payment of the proceeds of any Loans to be made hereunder;

(i)evidence reasonably satisfactory to the Administrative Agent that the Existing Loan Agreement has been terminated and any existing indebtedness of Borrower thereunder has been paid in full;

(j)evidence reasonably satisfactory to the Administrative Agent that prior to or substantially concurrently with the making of the Loans, the MGE Acquisition shall have been consummated in accordance with the terms of the MGE Acquisition Agreement and all other applicable documentation and in compliance with all applicable laws and regulatory approvals; and

(k)such other agreements, documents, instruments and certificates as the Administrative Agent or any Bank may reasonably request no later than five (5) Business Days prior to the Closing Date.

Without limiting the generality of the provisions of Section 8.04, for purposes of determining compliance with the conditions specified in this Section 4.01, each Bank that has signed this Agreement shall be deemed to have consented to, approved or accepted or to be satisfied with, each document or other matter required hereunder to be consented to or approved by or acceptable or satisfactory to a Bank unless the Administrative Agent shall have received notice from such Bank prior to the proposed Closing Date specifying its objection thereto.

4.02All Extensions of Credit. Notwithstanding any provision contained in this Agreement to the contrary, no Bank shall have any obligation to make any Loan (other than Revolving Loans made for the purpose of repaying Refunded Swingline Loans pursuant to Section 2.02(d) or for the purpose of paying unpaid Reimbursement Obligations pursuant to Section 3.04) and no Issuing Bank shall have any obligation to issue Letters of Credit under this Agreement unless:

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(a)the Administrative Agent shall have received a Notice of Borrowing in accordance with Section 2.02(a), (together with the Swingline Bank) a Notice of Swingline Borrowing in accordance with Section 2.02(c), and/or (together with the applicable Issuing Bank) a Letter of Credit Notice in accordance with Section 3.02;

(b)both immediately before and immediately after giving effect to such Loan or issuing such Letter of Credit, no Default or Event of Default under this Agreement shall have occurred and be continuing; and

(c)all of the representations and warranties of Borrower in this Agreement and/or in any other Transaction Document (except the representations set forth in Section 5.05 (other than clause (ii) thereof) and Section 5.08, each of which shall only be made on the Closing Date) (i) that are qualified by materiality or Material Adverse Effect shall be true and correct as so qualified and (ii) that are not qualified by materiality or Material Adverse Effect shall be true and correct in all material respects; in each case on and as of the date of such Loan or the date of issuance of such Letter of Credit as if made on and as of the date of such Loan or Letter of Credit (except to the extent any such representation or warranty is expressly stated to have been made as of a specific date, in which case such representation or warranty shall be true and correct as of such date).

Each giving of a Notice of Borrowing, a Notice of Swingline Borrowing or a Letter of Credit Notice, and the making of each Loan or issuance of a Letter of Credit, shall be deemed to be a representation and warranty by Borrower on the date of such Loan as to the facts specified in clauses (b) and (c) of this Section 4.02.

SECTION 5.REPRESENTATIONS AND WARRANTIES.

Borrower hereby represents and warrants to the Administrative Agent, each Issuing Bank, the Swingline Bank and each other Bank that:

5.01Corporate Existence and Power. Borrower: (a) is duly incorporated, validly existing and in good standing under the laws of the State of Missouri; (b) has all requisite corporate powers required to carry on its business as now conducted; and (c) is qualified to transact business as a foreign corporation in, and is in good standing under the laws of, all states in which it is required by applicable law to maintain such qualification and good standing except for those states in which the failure to qualify or maintain good standing could not reasonably be expected to have a Material Adverse Effect.

5.02Corporate Authorization. The execution, delivery and performance by Borrower of this Agreement, the Notes and the other Transaction Documents are within the corporate powers of Borrower and have been duly authorized by all necessary corporate and other action on the part of Borrower.

5.03Binding Effect. This Agreement, the Notes and the other Transaction Documents have been duly executed and delivered by Borrower and constitute the legal, valid and binding obligations of Borrower enforceable against Borrower in accordance with their respective terms, except as such enforceability may be limited by bankruptcy, insolvency or other similar laws

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affecting creditors’ rights generally and by general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law).

5.04Governmental and Third-Party Authorization. No consent, approval, authorization or other action by, notice to, or registration or filing with, any Governmental Authority is or will be required as a condition to or otherwise in connection with the due execution, delivery and performance by Borrower of this Agreement or any of the other Transaction Documents to which it is or will be a party or the legality, validity or enforceability hereof or thereof, other than (i) consents, authorizations and filings that have been (or on or prior to the Closing Date will have been) made or obtained and that are (or on the Closing Date will be) in full force and effect, which consents, authorizations and filings are listed on Schedule 5.04 and (ii) consents and filings the failure to obtain or make which, individually or in the aggregate, could not reasonably be expected to have a Material Adverse Effect. Borrower has, and is in good standing with respect to, all governmental approvals, licenses, permits and authorizations necessary to conduct its business as presently conducted and to own or lease and operate its properties, except for those the failure to obtain which, individually or in the aggregate, could not reasonably be expected to have a Material Adverse Effect.

5.05Litigation. Except as disclosed in filings with the Securities and Exchange Commission prior to the Closing Date, there are no actions, investigations, suits or proceedings pending or, to the knowledge of Borrower, threatened, at law, in equity or in arbitration, before any court, other Governmental Authority, arbitrator or other Person, (i) against any of Borrower or any of its properties that, if adversely determined, could reasonably be expected to have a Material Adverse Effect, or (ii) which questions the validity or enforceability of this Agreement, any of the other Transaction Documents or any of the transactions contemplated hereby or thereby.

5.06Taxes. Borrower has filed all United States federal income tax returns and other material tax returns and reports required to be filed by it and has paid all taxes, assessments, fees and other charges levied upon it or upon its properties that are shown thereon as due and payable, other than those that are not yet delinquent or that are being contested in good faith and by proper proceedings and for which adequate reserves have been established in accordance with GAAP.

5.07Subsidiaries. Schedule 5.07 sets forth, as of the Closing Date (i) all of the Material Subsidiaries, if any, of Borrower and (ii) as to each of Borrower and each of its Material Subsidiaries, if any, the number of shares, units or other interests of each class of Capital Stock outstanding, and the number and effect, if exercised, of all outstanding options, warrants, rights of conversion or purchase and similar rights. All outstanding shares of Capital Stock of the Borrower and each of its Material Subsidiaries, if any, are duly and validly issued, fully paid and nonassessable. Except for the shares of Capital Stock and the other equity arrangements expressly indicated on Schedule 5.07, as of the Closing Date there are no shares of Capital Stock, warrants, rights, options or other equity securities, or other Capital Stock of any of Borrower of any of its Material Subsidiaries, if any, outstanding or reserved for any purpose.

5.08No Material Adverse Effect. Except as disclosed in filings with the Securities and Exchange Commission prior to the Closing Date (but excluding any statement therein that is a

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risk factor or cautionary, predictive or forward-looking in nature), as of the Closing Date there has been no Material Adverse Effect since September 30, 2012, and there exists no event, condition or state of facts that could reasonably be expected to result in a Material Adverse Effect.

5.09Financial Statements. Borrower has made available to the Administrative Agent and the Banks the following financial statements: (a) audited consolidated balance sheets and statements of income, retained earnings and cash flows of Borrower and its Subsidiaries as of and for the fiscal year of Borrower ended September 30, 2012, all certified by Borrower’s independent certified public accountants, which financial statements have been prepared in accordance with GAAP consistently applied; and (b) unaudited consolidated balance sheets and statements of income, retained earnings and cash flows of Borrower and its Subsidiaries as of and for the fiscal quarter of Borrower ended June 30, 2013, certified by the chief financial officer of Borrower as being true, correct and complete in all material respects and as being prepared in accordance with GAAP consistently applied. Borrower further represents and warrants to the Administrative Agent and each Bank that the balance sheets provided under clauses (a) and (b) of this Section and their accompanying notes (if any) fairly present in all material respects the financial condition of Borrower and its Subsidiaries as of the dates thereof.

5.10Compliance With Other Instruments; None Burdensome. None of the execution and delivery by Borrower of the Transaction Documents, the performance by Borrower of its obligations under the Transaction Documents or the borrowing and/or repayment of Loans by Borrower under this Agreement will conflict with, or result in a breach of the terms, conditions or provisions of, or constitute a default under or result in any violation of, any law, rule, regulation, order, writ, judgment, injunction, decree or award binding on Borrower, any of the provisions of the Articles of Incorporation or Bylaws of Borrower or any of the provisions of any indenture, agreement, document, instrument or undertaking to which Borrower is a party or subject, or by which Borrower or any property or assets of Borrower is bound, or result in the creation or imposition of any security interest, lien or encumbrance on any of the property or assets of Borrower pursuant to the terms of any such material indenture, agreement, document, instrument or undertaking.

5.11ERISA.

Except as would not result or be reasonably expected to result in a Material Adverse Effect,

(a)Borrower is in compliance with the applicable provisions of ERISA, and each Plan is and has been administered in compliance with all applicable Requirements of Law, including, without limitation, the applicable provisions of ERISA and the Code. Except as set forth on Schedule 5.11(a), no ERISA Event (i) has occurred within the five-year period prior to the Closing Date, (ii) has occurred and is continuing, or (iii) to the knowledge of Borrower, is reasonably expected to occur with respect to any Plan. Except as could not reasonably be expected to have a Material Adverse Effect, no Plan has any Unfunded Pension Liability as of the most recent annual valuation date applicable thereto, and Borrower has not engaged in a transaction that could be subject to Section 4069 or 4212(c) of ERISA.

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(b)Borrower has no outstanding liability on account of a complete or partial withdrawal from any Multiemployer Plan, and Borrower would not become subject to any liability under ERISA if it were to withdraw completely from all Multiemployer Plans as of the most recent valuation date that could reasonably be expected to have a Material Adverse Effect. To the knowledge of the Borrower, no Multiemployer Plan is in “reorganization” or is “insolvent” within the meaning of such terms under ERISA.

5.12Regulation U. Borrower is not engaged principally, or as one of its important activities, in the business of extending credit for the purpose of purchasing or carrying margin stock (within the meaning of Regulation U of The Board of Governors of the Federal Reserve System, as amended) and no part of the proceeds of any Loan will be used (a) to purchase or carry margin stock or to extend credit to others for the purpose of purchasing or carrying margin stock, or to refund or repay indebtedness originally incurred for such purpose, in each case, in a manner that would violate Regulations T, U or X of the Board of Governors of the Federal Reserve System, as in effect from time to time, or (b) for any purpose which entails a violation of, or which is inconsistent with, the provisions of any of the Regulations of The Board of Governors of the Federal Reserve System, including, without limitation, Regulations U, T or X thereof, as amended. If requested by the Administrative Agent or any Bank, Borrower shall furnish to the Administrative Agent and each Bank a statement in conformity with the requirements of Federal Reserve Form U-1 referred to in Regulation U.

5.13Investment Company Act of 1940. Borrower is not an “investment company” as that term is defined in the Investment Company Act of 1940, as amended.

5.14[Reserved].

5.15Labor Relations. Borrower is not engaged in any unfair labor practice within the meaning of the National Labor Relations Act of 1947, as amended, except for any unfair labor practice that has not had or would not reasonably be expected to have a Material Adverse Effect.

5.16Use of Proceeds. The Letters of Credit and the proceeds of the Loans shall be used by Borrower for general corporate purposes not in contravention of any Requirement of Law or of any Transaction Document.

5.17Compliance with Laws. Borrower is in compliance with all laws, rules, regulations, orders and decrees applicable to it or to its properties, except where failure to be in compliance would not have or would not reasonably be expected to have a Material Adverse Effect.

5.18Full Disclosure. All factual information heretofore, contemporaneously or hereafter furnished in writing to the Administrative Agent, the Arrangers or any Bank by or on behalf of Borrower or any of its Subsidiaries for purposes of or in connection with this Agreement and the other Transaction Documents, when taken together with disclosures made in Borrower’s filings with the Securities and Exchange Commission, is or will be true and accurate in all material respects on the date as of which such information is dated or certified (or, if such information has been updated, amended or supplemented, on the date as of which any such update, amendment or supplement is dated or certified) and not made incomplete by omitting to

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state a material fact necessary to make the statements contained herein and therein, in light of the circumstances under which such information was provided, not misleading in any material respect; provided that, with respect to projections, budgets and other estimates, Borrower represents only that such information was prepared in good faith based upon assumptions believed to be reasonable at the time.

5.19OFAC; Anti-Terrorism Laws.

(a)Borrower (i) is not a Sanctioned Person, (ii) has no more than 10% of its assets in Sanctioned Countries, and (iii) does not derive more than 10% of its operating income from investments in, or transactions with, Sanctioned Persons or Sanctioned Countries. No part of the proceeds of any Loan hereunder will be used directly or indirectly to fund any operations in, finance any investments or activities in or make any payments to, a Sanctioned Person or a Sanctioned Country.

(b)The use of the proceeds of the Loans hereunder will not violate the PATRIOT Act, the Trading with the Enemy Act, as amended, or any of the foreign assets control regulations of the United States Treasury Department (31 CFR, Subtitle B, Chapter V, as amended) or any enabling legislation or executive order relating thereto. The Borrower is in compliance in all material respects with the PATRIOT Act.

5.20No Default. No Default or Event of Default under this Agreement has occurred and is continuing.

SECTION 6.COVENANTS.

6.01Affirmative Covenants of Borrower. Borrower covenants and agrees that, so long as (a) any Bank has any obligation to make any Loan under this Agreement, (b) any Issuing Bank has an obligation to issue Letters of Credit under this Agreement and/or (b) any of Borrower’s Obligations remain unpaid (other than (i) contingent indemnification or expense reimbursement obligations to the extent no claim giving rise thereto has been asserted and (ii) Letter of Credit obligations that have been Cash Collateralized in accordance with the terms hereof):

(a)Information. Borrower will make available, deliver or cause to be delivered to the Administrative Agent (who shall forward copies thereof to each Bank):

(i)within ninety (90) days (or such additional extended period as allowed by the Securities and Exchange Commission, not to exceed fifteen (15) days) after the end of each fiscal year of Borrower: an audited consolidated balance sheetof Borrower and its Subsidiaries as of the end of such fiscal year and the related audited consolidated statements of income, retained earnings and cash flows for such fiscal year, including notes thereto, setting forth in each case, in comparative form, the figures for the previous fiscal year, all in reasonable detail and prepared in accordance with GAAP, together with a report and opinion thereon by Deloitte & Touche LLP or any other independent certified public accounting firm of recognized national standing reasonably acceptable to the Administrative Agent prepared in accordance with generally accepted auditing standards that is not subject to any “going concern” or similar qualification or exception

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or any qualification as to the scope of such audit or with respect to accounting principles followed by the Borrower or any of its Subsidiaries not in accordance with GAAP; provided, however, that making available to the Administrative Agent copies of the Annual Report on Form 10-K of Borrower for such fiscal year filed with the Securities and Exchange Commission shall be deemed to satisfy the requirements of this Section 6.01(a)(i);

(ii)within forty-five (45) days (or such additional extended period as allowed by the Securities and Exchange Commission, not to exceed fifteen (15) days) after the end of the first three (3) fiscal quarters of each fiscal year of Borrower, an unaudited consolidated balance sheet of Borrower and its Subsidiaries as of the end of such fiscal quarter and the related unaudited consolidated statements of income, retained earnings and cash flows for such fiscal quarter and for the portion of Borrower’s fiscal year ended at the end of such fiscal quarter, setting forth in each case in comparative form, the figures for the corresponding fiscal quarter and the corresponding portion of Borrower’s previous fiscal year, all in reasonable detail and satisfactory in form to the Required Banks and certified (subject to normal year-end adjustments and absence of footnote disclosures) as to fairness of presentation, consistency and compliance with GAAP by the chief financial officer of Borrower;provided, however, that making available to the Administrative Agent copies of the Quarterly Report on Form 10-Q of Borrower for such fiscal quarter filed with the Securities and Exchange Commission shall be deemed to satisfy the requirements of this Section 6.01(a)(ii);

(iii)within the timeframes outlined in Sections 6.01(a)(i) and (ii) above, as applicable, a certificate of a Financial Officer of Borrower substantially in the form attached hereto as Exhibit C and incorporated herein by reference (A) stating whether there exists on the date of such certificate any Default or Event of Default and, if any Default or Event of Default then exists, setting forth the details thereof and the action which Borrower is taking or proposes to take with respect thereto and (B) certifying that Borrower is in compliance with the financial covenant contained in Section 6.02;

(iv)within forty-five (45) days after the end of the first three (3) fiscal quarters of each fiscal year of Borrower and within ninety (90) days after the end of each fiscal year of Borrower (or such additional extended period as allowed by the Securities and Exchange Commission for filing the corresponding consolidated financial statements, not to exceed fifteen (15) days), an unaudited balance sheet and the related unaudited statement of income for each Material Subsidiary as of the end of such fiscal quarter or such fiscal year, as the case may be; and

(v)with reasonable promptness, such further information regarding the business, affairs and financial condition of Borrower as the Administrative Agent or any Bank may from time to time reasonably request.

Documents required to be delivered pursuant to Section 6.01(a) (to the extent any such documents are included in materials otherwise filed with the Securities and Exchange Commission) may be delivered electronically and if so delivered, shall be deemed to have been delivered on the date (i) Borrower notifies the Administrative Agent that such

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documents have become available on the Security Exchange Commission’s EDGAR Database; (ii) on which Borrower posts such documents, or provides a link thereto on Borrower’s website on the internet at the website address listed in Schedule 9.04; or (iii) on which such documents are posted on the Borrower’s behalf on an Internet or intranet website, if any, to which each Bank and the Administrative Agent have access (whether a commercial, third-party website or whether sponsored by the Administrative Agent); provided that: (i) Borrower shall deliver paper copies of such documents to the Administrative Agent or any Bank that requests the Borrower to deliver such paper copies until a written request to cease delivering paper copies is given by the Administrative Agent or such Bank and (ii) the Borrower shall notify the Administrative Agent and each Bank (by telecopier or electronic mail) of the posting of any such documents. Notwithstanding anything contained herein, in every instance the Borrower shall be required to provide paper copies of the Compliance Certificates to the Administrative Agent. Except for such Compliance Certificates, the Administrative Agent shall have no obligation to request the delivery or to maintain copies of the documents referred to above, and in any event shall have no responsibility to monitor compliance by the Borrower with any such request for delivery, and each Bank shall be solely responsible for requesting delivery to it or maintaining its copies of such documents.

(b)Corporate Existence; Maintenance of Properties; Insurance. Borrower will do all things necessary to (i) preserve and keep in full force and effect at all times its corporate existence and all permits, licenses, franchises and other rights material to its business except to the extent that failure to do so could not reasonably be expected to have a Material Adverse Effect, (ii) be duly qualified to do business and be in good standing in all jurisdictions where the nature of its business or its ownership of property or assets requires such qualification except for those jurisdictions in which the failure to qualify or be in good standing could not reasonably be expected to have a Material Adverse Effect, (iii) keep all material properties in good working order and condition (normal wear and tear and damage by casualty excepted) and from time to time make all necessary repairs to and renewals and replacements of such properties, except to the extent that any of such properties are obsolete or are being replaced or, in the good faith judgment of Borrower, are no longer useful or desirable in the conduct of the business of Borrower and (iv) maintain with financially sound and reputable insurance companies insurance or through its own program of self-insurance with respect to its properties and business against loss or damage of the kinds customarily insured against by Persons engaged in the same or similar business, of such types and in such amounts as are customarily carried under similar circumstances by such other Persons.

(c)Compliance with Laws, Regulations, Etc. Borrower will, and will cause each of its Subsidiaries, to comply with any and all Requirements of Law applicable in respect of the conduct of its business and ownership and operation of its properties and obtain any and all licenses, permits, franchises and other governmental and regulatory authorizations necessary to the ownership of its properties or assets or to the conduct of its business, the violation of which or the failure to comply with or obtain would reasonably be expected to have a Material Adverse Effect.

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(d)Notices. Borrower will notify the Administrative Agent in writing of any of the following within five (5) Business Days (as to Section 6.01(d)(i) below to the extent continuing on the date of such statement) and within fifteen (15) Business Days (as to Sections 6.01(d)(ii), 6.01(d)(iii), and 6.01(d)(iv), below) after any of the Financial Officers of Borrower has actual knowledge thereof, describing the same and, if applicable, the steps being taken by the Person(s) affected with respect thereto:

(i)the occurrence of any Default or Event of Default;

(ii)the entry of any judgment against Borrower or any Subsidiary in an amount of at least $25,000,000 (to the extent not paid or covered by insurance provided by a carrier who has acknowledged coverage);

(iii)any environmental claim or any other action or investigation with respect to the existence or potential existence of any hazardous substances instituted or threatened with respect to Borrower or any Subsidiary or any of the properties or facilities owned, leased or operated by Borrower or any Subsidiary which could reasonably be expected to have a Material Adverse Effect, and any known condition or occurrence on any of the properties or facilities owned, leased or operated by Borrower or any Subsidiary which constitutes a violation of any environmental laws or which gives rise to a reporting obligation or requires removal or remediation under any environmental laws which could reasonably be expected to have a Material Adverse Effect; and

(iv)the occurrence of any ERISA Event that could reasonably be expected to result in a Material Adverse Effect, together with (A) a written statement of a Financial Officer of Borrower specifying the details of such ERISA Event and the action that Borrower has taken and proposes to take with respect thereto, (B) a copy of any notice with respect to such ERISA Event that may be required to be filed with the PBGC and (C) a copy of any notice delivered by the PBGC to Borrower or an ERISA Affiliate with respect to such ERISA Event.

(e)Payment of Obligations. Borrower will, and will cause each of its Subsidiaries to, (i) pay, discharge or otherwise satisfy at or before maturity all liabilities and obligations as and when due (subject to any applicable subordination, grace and notice provisions), except to the extent failure to do so could not reasonably be expected to have a Material Adverse Effect, and (ii) pay and discharge all material taxes, assessments and governmental charges or levies imposed upon it, upon its income or profits or upon any of its properties, prior to the date on which penalties would attach thereto, and all lawful claims that, if unpaid, would become a Lien (other than a Permitted Lien) upon any of Borrower’s properties; provided, however, that Borrower shall not be required to pay any such tax, assessment, charge, levy or claim that is being contested in good faith and by proper proceedings and as to which Borrower is maintaining adequate reserves with respect thereto in accordance with GAAP.

(f)Maintenance of Books and Records; Inspection. Borrower will and will cause each of its Subsidiaries to, (i) maintain complete and adequate books and records of its transactions in accordance with good accounting practices on the basis of GAAP and in compliance with the requirements of any Governmental Authority having jurisdiction over it,

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and (ii) permit employees or agents of the Administrative Agent or any Bank to visit and inspect its properties and examine or audit its books and records and their accounts receivable and inventory and make copies and memoranda of them, and to discuss its affairs, finances and accounts with its officers and employees, in each case, all at the expense of the Administrative Agent or Bank, upon ten (10) Business Days’ prior notice to Borrower and during Borrower’s normal business hours and no more frequently than once during any fiscal year unless an Event of Default has occurred and is continuing; provided, however, that Borrower reserves the right to restrict access to any of its or its Subsidiaries’ facilities in accordance with reasonably adopted procedures relating to safety and security.

(g)Environmental Laws. Borrower will, and will cause each of its Subsidiaries to, (i) comply in all material respects with all applicable Environmental Laws and obtain and comply in all material respects with and maintain any and all licenses, approvals, notifications, registrations or permits required by applicable Environmental Laws, except to the extent that the failure to do so could not reasonably be expected to have a Material Adverse Effect, and (ii)  comply in all material respects with all lawful orders and directives of all Governmental Authorities regarding Environmental Laws, except to the extent that the same are being contested in good faith by appropriate proceedings or to the extent the failure to conduct or complete any of the foregoing could not reasonably be expected to have a Material Adverse Effect.

(h)Further Assurances. Borrower will execute and deliver to the Administrative Agent and each Bank, at any time and from time to time, any and all further agreements, documents and instruments, and take any and all further actions which may be required under applicable law, or which the Administrative Agent or any Bank may from time to time reasonably request, in order to effectuate the transactions contemplated by this Agreement and the other Transaction Documents.

(i)Subsidiaries. If Borrower creates, forms or acquires any Subsidiary which owns more than 10% of the consolidated assets of Borrower and its Subsidiaries on or after the date of this Agreement, Borrower will, contemporaneously with the creation, formation or acquisition of such Subsidiary, cause such Subsidiary to execute a guaranty agreement with respect to Borrower’s Obligations in a form reasonably acceptable to the Administrative Agent, provided that no such Subsidiary shall be required to execute a guaranty agreement so long as prohibited to do so by any regulatory authority having jurisdiction over it.

6.02Maximum Consolidated Capitalization Ratio. Borrower will at all times have a Consolidated Capitalization Ratio of not more than seventy percent (70%)

6.03Negative Covenants of Borrower. Borrower covenants and agrees that, so long as the Administrative Agent and any Bank have any obligation to make any Loan or any Issuing Bank has any obligation to issue Letters of Credit under this Agreement, or any of Borrower’s Obligations remain unpaid, unless the prior written consent of the Required Banks is obtained (other than (i) contingent indemnification or expense reimbursement obligations to the extent no claim giving rise thereto has been asserted and (ii) Letter of Credit obligations that have been Cash Collateralized in accordance with the terms hereof):

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(a)Limitation on Liens. Borrower will not, and will not cause or permit any Subsidiary to, create, incur or assume, or suffer to be incurred or to exist, any Lien on any of its property, whether now owned or hereafter acquired, or upon any income or profits therefrom, except for Permitted Liens.

(b)Consolidation, Merger, Sale of Property, Etc.

(i)Borrower will not, and it will not cause or permit any Subsidiary to, directly or indirectly merge or consolidate with or into any other Person or permit any other Person to merge into or with or consolidate with it, except that, if at the time thereof and immediately after giving effect thereto no Event of Default or Default shall have occurred and be continuing, provided that in any merger or consolidation involving Borrower, (A) Borrower shall be the surviving Person, (B) after giving effect thereto, at least two of Borrower’s Debt Ratings by S&P, Moody’s and Fitch shall be no lower than BBB-, Baa3, BBB-, respectively and (C) such merger or consolidation would not reasonably be expected to materially and adversely affect Borrower’s ability to perform its obligations under this Agreement.

(ii)Borrower will not, and will not cause or permit any Subsidiary to, (A) sell, assign, lease, transfer, abandon or otherwise dispose of any of its property (including, without limitation, any shares of Capital Stock or other equity interests of a Subsidiary owned by Borrower or another Subsidiary) or (B) issue, sell or otherwise dispose of any shares of Capital Stock or other equity interests of any Subsidiary; provided, however, that Borrower and each Subsidiary may sell, assign, lease, transfer, abandon or otherwise dispose of (1) any of its natural gas inventory or past-due accounts receivable in the ordinary course of business, (2) any of its property to Borrower or any Subsidiary, provided that, if at anytime more than ten percent (10%) of the consolidated assets of Borrower and all of its Subsidiaries are transferred from Borrower to a Subsidiary, such Subsidiary shall then execute a Guarantee agreement with respect to Borrower’s Obligations in a form reasonably acceptable to the Administrative Agent and Required Banks, (3) any of the property subject to the Laclede Gas Mortgage and Deed of Trust dated as of February 1, 1945, as amended and supplemented, as may be permitted to be sold, assigned, leased, transferred, abandoned or otherwise disposed of under said Mortgage and Deed of Trust and (4) any of its other property (whether in one transaction or a series of transactions) so long as the value of such property sold, assigned, leased, transferred, abandoned or otherwise disposed of in any fiscal year under this subsection (4) (including in connection with the Permitted Securitization) shall not exceed ten percent (10%) of the consolidated assets of Borrower and all of its Subsidiaries as determined on a consolidated basis as of the last day of the immediately preceding fiscal year; and providedfurther, however, that nothing in this Agreement shall limit or restrict Borrower’s use of financial instruments or natural gas contracts under its gas supply risk management program.

(c)Sale or Discount of Accounts. Borrower will not, and it will not cause or permit any Subsidiary to, sell or discount (other than prompt payment discounts granted in the ordinary course of business) any of its notes or accounts receivable or chattel paper generated from the

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sale of natural gas, except for (i) past due accounts that may be sold to a collection agent and (ii) Permitted Securitizations that comply with clause (4) of Section 6.03(b)(ii).

(d)Transactions with Affiliates. Borrower will not, and it will not cause or permit any Subsidiary to, enter into or be a party to any transaction or arrangement with any Affiliate (including, without limitation, the purchase from, sale to or exchange of property with, or the rendering of any service by or for, any Affiliate), except in the ordinary course of business and pursuant to the reasonable requirements of Borrower’s or such Subsidiary’s business and upon fair and reasonable terms no less favorable to Borrower or such Subsidiary than would be obtained in a comparable arm’s-length transaction with a Person not an Affiliate; provided that the foregoing restrictions shall not apply to: (i) any issuances of stock to Borrower, (ii) payment of any lawful distributions on its issued stock, and (iii) payment or grant of reasonable compensation, benefits and indemnities to any director, officers, employee or agent of the Borrower or any Subsidiary. Notwithstanding the foregoing, nothing in this Section 6.03(d) shall restrict transactions with any Affiliate that have been approved by or are entered into pursuant to any orders or decisions of any Governmental Authority having jurisdiction over Borrower or any of its Subsidiaries, including without limitation the Federal Energy Regulatory Commission or the Missouri Public Service Commission (or any successor commission or organization).

(e)Changes in Nature of Business. Borrower will not, and it will not cause or permit any Subsidiary to, materially alter the general nature of the business of Borrower and its Subsidiaries, considered as a whole, from the general nature of the business and reasonable extensions thereof engaged in by Borrower and its Subsidiaries as of the date of this Agreement.

(f)Permitted Investments; Acquisitions. Borrower will not, and it will not cause or permit any Subsidiary to, directly or indirectly, make any Investments except for Permitted Investments. Borrower will not, and it will not cause or permit any Subsidiary to, directly or indirectly, make any Acquisitions the result of which would be to change substantially the general nature of the business engaged in by Borrower and its Subsidiaries, considered as a whole, as of the date of this Agreement and reasonable extensions thereof.

(g)Limitations on Restrictive Agreements. Except for the Laclede Gas Loan Agreement, Borrower will not, and it will not cause or permit any Subsidiary to, enter into, or permit to exist, any agreement with any Person which prohibits Borrower or such Subsidiary, as the case may be, from performing its contractual obligations under this Agreement; nor enter into any agreement with any Person that would prohibit Borrower or any Subsidiary from creating, incurring, or assuming any Lien in favor of the interests of the Administrative Agent and Banks under this Agreement upon any of its property or revenues whether now owned or hereafter acquired; provided that any agreement between Borrower and a lender which results in the creation of a Permitted Lien may prohibit the creation, incurrence or assumption of Liens in favor of the interests of the Administrative Agent and Banks solely with respect to the assets subject to the Permitted Lien.

6.04Use of Proceeds. Borrower covenants and agrees that the proceeds of the Loans will be used exclusively (i) for the working capital and general corporate purposes of Borrower, (ii) to refinance the Existing Loan Agreement and (iii) to pay or reimburse permitted fees and expenses in connection with this Agreement.

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SECTION 7.EVENTS OF DEFAULT.

If any of the following (each of the following herein sometimes called an “Event of Default”) shall occur and be continuing:

(a)Borrower shall fail to pay any of Borrower’s Obligations constituting principal due under the Loans or any Reimbursement Obligation as and when the same shall become due and payable, whether by reason of demand, maturity, acceleration or otherwise;

(b)Borrower shall fail to pay any of Borrower’s Obligations constituting interest, fees or other amounts (other than any Reimbursement Obligation or principal due under the Loans) within five (5) Business Days after the date the same shall first become due and payable, whether by reason of demand, maturity, acceleration or otherwise;

(c)Any representation or warranty made by Borrower in this Agreement, in any other Transaction Document or in any certificate, agreement, instrument or written statement furnished or made or delivered pursuant hereto or thereto or in connection herewith or therewith, shall prove to have been untrue or incorrect in any material respect on the date as of which it was deemed made;

(d)Borrower shall fail to perform or observe any term, covenant or provision contained in Sections 6.01(d), 6.02, 6.03 or 6.04 above; or Borrower shall fail to perform or observe any term, covenant or provision contained in Sections 2.01(b) or 6.01(a) above and such failure shall continue unremedied for a period of five (5) Business Days after the earlier of any Financial Officer of Borrower obtaining actual knowledge of such failure or written notice thereof given to the Borrower by the Administrative Agent.

(e)Borrower shall fail to perform or observe any other term, covenant or provision contained in this Agreement (other than those specified in Sections 7(a) through 7(d) above) and any such failure shall remain unremedied for thirty (30) days after the earlier of (i) written notice of default is given to Borrower by the Administrative Agent or any Bank or (ii) any Financial Officer of Borrower obtaining actual knowledge of such default;

(f)This Agreement or any of the other Transaction Documents shall at any time for any reason (other than termination of this Agreement or such other Transaction Documents, as the case may be, in accordance with its terms) cease to be in full force and effect or shall be declared to be null and void by a court of competent jurisdiction, or if the validity or enforceability thereof shall be contested or denied by Borrower in writing, or if the transactions completed hereunder or thereunder shall be contested by Borrower or if Borrower shall deny in writing that it has any further liability or obligation hereunder or thereunder;

(g)Borrower or any Material Subsidiary, if any, shall (i) voluntarily commence any proceeding or file any petition seeking relief under Title 11 of the United States Code or any other Federal, state or foreign bankruptcy, insolvency, receivership, liquidation or similar law, (ii) consent to the institution of, or fail to contravene in a timely and appropriate manner, any such proceeding or the filing of any such petition, (iii) apply for or consent to the appointment of a receiver, trustee, custodian, sequestrator or similar official of itself or of a substantial part of its property or assets, (iv) file an answer admitting the material allegations of a petition filed against

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itself in any such proceeding, (v) make a general assignment for the benefit of creditors, (vi) become unable, admit in writing its inability or fail generally to pay its debts as they become due or (vii) take any corporate or other action for the purpose of effecting any of the foregoing;

(h)An involuntary proceeding shall be commenced or an involuntary petition shall be filed in a court of competent jurisdiction seeking (i) relief in respect of Borrower or any Material Subsidiary, if any, or of a substantial part of the property or assets of Borrower, under Title 11 of the United States Code or any other Federal, state or foreign bankruptcy, insolvency, receivership, liquidation or similar law, (ii) the appointment of a receiver, trustee, custodian, sequestrator or similar official of Borrower or any Material Subsidiary, if any, or of a substantial part of the property or assets of Borrower or (iii) the winding-up or liquidation of Borrower or any Material Subsidiary, if any, and such proceeding or petition shall continue undismissed for sixty (60) consecutive days or an order or decree approving or ordering any of the foregoing shall continue unstayed and in effect for sixty (60) consecutive days;

(i)Borrower or any Material Subsidiary, if any, (i) fails to make any payment when due (whether by scheduled maturity, required prepayment, acceleration, demand, or otherwise) in respect of any Debt (other than Debt hereunder and Debt under Swap Contracts) having an aggregate principal amount of more than $25,000,000, or (ii) fails to observe or perform any other agreement or condition relating to any such Debt or contained in any instrument or agreement evidencing, securing or relating thereto, or any other event occurs, the effect of which default or other event is to cause, or to permit the holder or holders of such Debt or the beneficiary or beneficiaries of any Guarantee in respect thereof (or a trustee or agent on behalf of such holder or holders or beneficiary or beneficiaries) to cause, with the giving of notice if required, such Debt to be demanded or to become due or to be repurchased, prepaid, defeased or redeemed (automatically or otherwise), or an offer to repurchase, prepay, defease or redeem such Debt to be made, prior to its stated maturity, or such Guarantee to become payable or cash collateral in respect thereof to be demanded; or (iii) there occurs under any Swap Contract an Early Termination Date (as defined in such Swap Contract) resulting from (A) any event of default under such Swap Contract as to which Borrower or any Material Subsidiary, if any, is the Defaulting Party (as defined in such Swap Contract) or (B) any Additional Termination Event (as so defined) under such Swap Contract as to which Borrower or any Material Subsidiary is the Affected Party (as so defined) and, in either event, the Swap Termination Value owed by Borrower or such Material Subsidiary, if any, as a result thereof is greater than $25,000,000;

(j)Borrower or any Material Subsidiary, if any, shall have a final judgment in an amount in excess of $25,000,000 (to the extent not paid or covered by insurance provided by a carrier who has acknowledged coverage) entered against it by a court having jurisdiction in the premises and such judgment shall continue unsatisfied for sixty (60) days; provided, however, that if such judgment provides for periodic payments over time, then Borrower or such Material Subsidiary, if any, shall have a grace period of thirty (30) days with respect to such periodic payment;

(k)The occurrence of any Change of Control Event; or

(l)Any ERISA Event or any other event or condition shall occur or exist with respect to any Plan or Multiemployer Plan that, when taken together with all other ERISA Events and

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other events or conditions that have occurred or are then existing, has or could reasonably be expected to result in a Material Adverse Effect;

THEN, and in each such event (other than an event described in Sections 7(g) or 7(h)), the Administrative Agent may, with the consent of the Required Banks, or shall, upon the request of the Required Banks, (i) declare that the obligation of the Banks to make Revolving Loans, the obligation of the Swingline Bank to make Swingline Loans and the obligation of any Issuing Bank to issue Letters of Credit under this Agreement have terminated, whereupon such obligations of the Banks shall be immediately and forthwith terminated, (ii) declare the entire outstanding principal balance of and all accrued and unpaid interest on the Loans and all of the other Borrower’s Obligations to be forthwith due and payable, whereupon all of the unpaid principal balance of and all accrued and unpaid interest on the Loans and all of such other Borrower’s Obligations shall become and be immediately due and payable, without presentment, demand, protest or further notice of any kind, all of which are hereby expressly waived by Borrower, (iii) direct Borrower to deposit (and Borrower hereby agrees, forthwith upon receipt of notice of such direction from the Administrative Agent, to deposit) with the Administrative Agent from time to time such additional amount of cash as is equal to 102% of the aggregate Stated Amount of all Letters of Credit then outstanding (whether or not any beneficiary under any Letter of Credit shall have drawn or be entitled at such time to draw thereunder), such amount to be held by the Administrative Agent in the Cash Collateral Account as security for the Letter of Credit Exposure as described in Section 3.08 and (iv) exercise any and all other rights and remedies which they may have under any of the other Transaction Documents or under applicable law; provided, however, that upon the occurrence of any event described in Sections 7(g) or 7(h), the obligation of the Banks to make Revolving Loans, the obligation of the Swingline Bank to make Swingline Loans and the obligation of any Issuing Bank to issue Letters of Credit under this Agreement shall automatically terminate and the entire outstanding principal balance of and all accrued and unpaid interest on the Loans and all of the other Borrower’s Obligations shall automatically become immediately due and payable, without presentment, demand, protest or further notice of any kind, all of which are hereby expressly waived by Borrower, and the Administrative Agent, the Issuing Banks, the Swingline Bank and the Banks may exercise any and all other rights and remedies which they may have under any of the other Transaction Documents or under applicable law.

SECTION 8.ADMINISTRATIVE AGENT

8.01Appointment and Authority. Each of the Banks hereby irrevocably appoints Wells Fargo to act on its behalf as the Administrative Agent hereunder and under the other Transaction Documents and authorizes the Administrative Agent to take such actions on its behalf and to exercise such powers as are delegated to the Administrative Agent by the terms hereof or thereof, together with such actions and powers as are reasonably incidental thereto. Except as set forth in Section 8.06, the provisions of this Section are solely for the benefit of the Administrative Agent and the Banks, and neither Borrower nor any of its Subsidiaries shall have rights as a third party beneficiary of any of such provisions.

8.02Rights as a Bank. The Person serving as the Administrative Agent hereunder shall have the same rights and powers in its capacity as a Bank as any other Bank and may exercise the same as though it were not the Administrative Agent and the term “Bank” or

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“Banks” shall, unless otherwise expressly indicated or unless the context otherwise requires, include the Person serving as the Administrative Agent hereunder in its individual capacity. Such Person and its Affiliates may accept deposits from, lend money to, act as the financial advisor or in any other advisory capacity for and generally engage in any kind of business with Borrower or any Subsidiary or other Affiliate thereof as if such Person were not the Administrative Agent hereunder and without any duty to account therefor to the Banks.

8.03Exculpatory Provisions. The Administrative Agent shall not have any duties or obligations except those expressly set forth herein and in the other Transaction Documents. Without limiting the generality of the foregoing, the Administrative Agent:

(a)shall not be subject to any fiduciary or other implied duties, regardless of whether a Default or Event of Default has occurred and is continuing;

(b)shall not have any duty to take any discretionary action or exercise any discretionary powers, except discretionary rights and powers expressly contemplated hereby or by the other Transaction Documents that the Administrative Agent is required to exercise as directed in writing by the Required Banks (or such other number or percentage of the Banks as shall be expressly provided for herein or in the other Transaction Documents), provided that the Administrative Agent shall not be required to take any action that, in its opinion or the opinion of its counsel, may expose the Administrative Agent to liability or that is contrary to any Transaction Document or applicable law; and

(c)shall not, except as expressly set forth herein and in the other Transaction Documents, have any duty to disclose, and shall not be liable for the failure to disclose, any information relating to Borrower or any of its Affiliates that is communicated to or obtained by the Person serving as the Administrative Agent or any of its Affiliates in any capacity.

The Administrative Agent shall not be liable for any action taken or not taken by it (i) with the consent or at the request of the Required Banks (or such other number or percentage of the Banks as shall be necessary, or as the Administrative Agent shall believe in good faith shall be necessary, under the circumstances as provided in Section 9.07 and Section 7) or (ii) in the absence of its own gross negligence or willful misconduct. The Administrative Agent shall be deemed not to have knowledge of any Default or Event of Default unless and until notice describing such Default or Event of Default is given to the Administrative Agent by Borrower or a Bank.

The Administrative Agent shall not be responsible for or have any duty to ascertain or inquire into (i) any statement, warranty or representation made in or in connection with this Agreement or any other Transaction Document, (ii) the contents of any certificate, report or other document delivered hereunder or thereunder or in connection herewith or therewith, (iii) the performance or observance of any of the covenants, agreements or other terms or conditions set forth herein or therein or the occurrence of any Default or Event of Default, (iv) the validity, enforceability, effectiveness or genuineness of this Agreement, any other Transaction Document or any other agreement, instrument or document or (v) the satisfaction of any condition set forth in Section 4 or elsewhere herein, other than to confirm receipt of items expressly required to be delivered to the Administrative Agent.

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8.04Reliance by Administrative Agent. The Administrative Agent shall be entitled to rely upon, and shall not incur any liability for relying upon, any notice, request, certificate, consent, statement, instrument, document or other writing (including any electronic message, internet or intranet website posting or other distribution) believed by it to be genuine and to have been signed, sent or otherwise authenticated by the proper Person. The Administrative Agent also may rely upon any statement made to it orally or by telephone and believed by it to have been made by the proper Person, and shall not incur any liability for relying thereon. In determining compliance with any condition hereunder to the making of a Loan, or the issuance of a Letter of Credit, that by its terms must be fulfilled to the satisfaction of a Bank or any Issuing Bank, the Administrative Agent may presume that such condition is satisfactory to such Bank or such Issuing Bank unless the Administrative Agent shall have received notice to the contrary from such Bank or such Issuing Bank prior to the making of such Loan or the issuance of such Letter of Credit. The Administrative Agent may consult with legal counsel (who may be counsel for Borrower), independent accountants and other experts selected by it, and shall not be liable for any action taken or not taken by it in accordance with the advice of any such counsel, accountants or experts.

8.05Delegation of Duties. The Administrative Agent may perform any and all of its duties and exercise its rights and powers hereunder or under any other Transaction Document by or through any one or more sub-agents appointed by the Administrative Agent. The Administrative Agent and any such sub-agent may perform any and all of its duties and exercise its rights and powers by or through their respective Related Parties. The exculpatory provisions of this Article shall apply to any such sub-agent and to the Related Parties of the Administrative Agent and any such sub-agent, and shall apply to their respective activities in connection with the syndication of the credit facilities provided for herein as well as activities as Administrative Agent.

8.06Resignation of Administrative Agent. Subject to the appointment of a successor Administrative Agent, the Administrative Agent may resign as Administrative Agent for the Banks under this Agreement and the other Transaction Documents at any time by giving thirty (30) days’ notice in writing to the Banks and Borrower. Such resignation shall take effect upon appointment of such successor Administrative Agent. Subject to the consent of Borrower (which consent shall not be unreasonably withheld or delayed), the Required Banks shall have the right to appoint a successor Administrative Agent who shall be a Bank and who shall be entitled to all of the rights of, and vested with the same powers as, the original Administrative Agent under this Agreement and the other Transaction Documents. In the event a successor Administrative Agent shall not have been appointed within the thirty (30) day period following the giving of notice by the Administrative Agent, subject to the consent of Borrower (which consent shall not be unreasonably withheld or delayed), the Administrative Agent may appoint its own successor; provided that if the Administrative Agent shall notify Borrower and the Banks that no qualifying Person has accepted such appointment, then such resignation shall nonetheless become effective in accordance with such notice and (1) the retiring Administrative Agent shall be discharged from its duties and obligations hereunder and under the other Transaction Documents (except that in the case of any collateral security, including without limitation Cash Collateral, held by the Administrative Agent on behalf of the Banks under any of the Transaction Documents, the retiring Administrative Agent shall continue to hold such collateral security until such time as a successor Administrative Agent is appointed) and (2) all payments, communications and

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determinations provided to be made by, to or through the Administrative Agent shall instead be made by or to each Bank directly, until such time as the Required Banks appoint a successor Administrative Agent as provided for above in this Section. Upon the acceptance of a successor’s appointment as Administrative Agent hereunder, such successor shall succeed to and become vested with all of the rights, powers, privileges and duties of the retiring (or retired) Administrative Agent, and the retiring Administrative Agent shall be discharged from all of its duties and obligations hereunder or under the other Transaction Documents (if not already discharged therefrom as provided above in this Section). The fees payable by Borrower to a successor Administrative Agent shall be the same as those payable to its predecessor unless otherwise agreed between Borrower and such successor. After the retiring Administrative Agent’s resignation hereunder and under the other Transaction Documents, the provisions of this Section and Section 9.03 shall continue in effect for the benefit of such retiring Administrative Agent, its sub-agents and their respective Related Parties in respect of any actions taken or omitted to be taken by any of them while the retiring Administrative Agent was acting as Administrative Agent.

8.07Non-Reliance on Administrative Agent and Other Banks. Each Bank acknowledges that it has, independently and without reliance upon the Administrative Agent or any other Bank or any of their Related Parties and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement. Each Bank also acknowledges that it will, independently and without reliance upon the Administrative Agent or any other Bank or any of their Related Parties and based on such documents and information as it shall from time to time deem appropriate, continue to make its own decisions in taking or not taking action under or based upon this Agreement, any other Transaction Document or any related agreement or any document furnished hereunder or thereunder.

8.08No Other Duties, Etc. Anything herein to the contrary notwithstanding, none of the Book Runners or Arrangers or other agents listed on the cover page hereof shall have any powers, duties or responsibilities under this Agreement or any of the other Transaction Documents, except in its capacity, as applicable, as the Administrative Agent or a Bank hereunder.

8.09Enforcement. Each Bank hereby agrees that, except as otherwise provided in any Transaction Documents or with the written consent of the Administrative Agent and the Required Banks, it will not take any enforcement action, accelerate obligations under any Transaction Documents, or exercise any right that it might otherwise have under applicable law to credit bid at foreclosure sales, Uniform Commercial Code sales or other similar dispositions of collateral, if any.

8.10Issuing Bank and Swingline Bank. The provisions of this Section 8 (other than Section 8.02) shall apply to each Issuing Bank and the Swingline Bank mutatis mutandis to the same extent as such provisions apply to the Administrative Agent.

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SECTION 9.GENERAL.

9.01No Waiver. No failure or delay by the Administrative Agent or any Bank in exercising any right, remedy, power or privilege under this Agreement or under any other Transaction Document shall operate as a waiver thereof; nor shall any single or partial exercise thereof preclude any other or further exercise thereof or the exercise of any other right, remedy, power or privilege. The rights and remedies provided in this Agreement and in the other Transaction Documents are cumulative and not exclusive of any remedies provided by law. Nothing herein contained shall in any way affect the right of the Administrative Agent or any Bank to exercise any statutory or common law right of banker’s lien or set-off. No course of dealing between Borrower, the Administrative Agent or the Banks or their agents or employees shall be effective to amend, modify or discharge any provision of this Agreement or any other Transaction Document or to constitute a waiver of any Default or Event of Default. No notice to or demand upon Borrower in any case shall entitle Borrower to any other or further notice or demand in similar or other circumstances or constitute a waiver of the right of the Administrative Agent or any Bank to exercise any right or remedy or take any other or further action in any circumstances without notice or demand.

9.02Right of Set-Off. Upon the occurrence and during the continuance of any Event of Default, each Bank and each Issuing Bank and their respective Affiliates is hereby authorized at any time and from time to time, without notice to Borrower (any such notice being expressly waived by Borrower) and to the fullest extent permitted by law, to set-off and apply any and all deposits (general or special, time or demand, provisional or final, but specifically excluding any trust or segregated accounts) at any time held by such Bank and any and all other indebtedness at any time owing by such Bank, such Issuing Bank or any such Affiliate to or for the credit or account of Borrower against any and all of Borrower’s Obligations now or hereafter existing under this Agreement irrespective of whether or not such Bank shall have made any demand under this Agreement or under any of the other Transaction Documents and although such obligations may be contingent or unmatured or are owed to a branch or office of such Bank or such Issuing Bank different from the branch or office holding such deposit or obligated on such indebtedness; provided, that in the event that any Defaulting Bank shall exercise any such right of setoff, (x) all amounts so set off shall be paid over immediately to the Administrative Agent for further application in accordance with the provisions of Section 2.21 and, pending such payment, shall be segregated by such Defaulting Bank from its other funds and deemed held in trust for the benefit of the Administrative Agent, the Issuing Banks and the Banks (including the Swingline Bank), and (y) the Defaulting Bank shall provide promptly to the Administrative Agent a statement describing in reasonable detail the obligations owing to such Defaulting Bank as to which it exercised such right of setoff. Each Bank agrees to promptly notify Borrower after any such set-off and application made by such Bank, provided, however, that the failure to give such notice shall not affect the validity of such set-off and application. The rights of the Banks under this Section 9.02 are in addition to any other rights and remedies (including, without limitation, other rights of set-off) which the Banks may have.

9.03Costs and Expenses; General Indemnity.

(a)Costs and Expenses, Borrower agrees, whether or not any Loan is made or a Letter of Credit issued under this Agreement, to pay or reimburse the Administrative Agent, each

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Bank and each Issuing Bank upon demand for (i) all reasonable documented out-of-pocket costs and expenses (including, without limitation, reasonable attorneys’ fees and expenses) incurred by the Administrative Agent and its Affiliates in connection with the syndication, preparation, documentation, negotiation and/or execution of this Agreement and/or any of the other Transaction Documents, subject to any limitation described in the Commitment Letter and Wells Fargo Fee Letter, (ii) all reasonable documented out-of-pocket expenses incurred by any Issuing Bank in connection with the issuance, amendment, renewal or extension of any Letter of Credit or any demand for payment thereunder, (iii) all recording, filing and search fees and expenses incurred by the Administrative Agent in connection with this Agreement and/or any of the other Transaction Documents, (iv) all reasonable documented out-of-pocket costs and expenses (including, without limitation, reasonable attorneys’ fees and expenses) incurred by the Administrative Agent in connection with the (A) the preparation, documentation, negotiation and execution of any amendment, modification, extension, renewal or restatement of this Agreement and/or any of the other Transaction Documents or (B) the preparation of any waiver or consent under this Agreement or under any of the other Transaction Documents, (v) if an Event of Default occurs, all reasonable documented out-of-pocket costs and expenses (including, without limitation, reasonable attorneys’ fees and expenses) incurred by the Administrative Agent, any Bank or any Issuing Bank in connection with such Event of Default and collection and other enforcement proceedings resulting therefrom and (vi) any civil penalty or fine assessed by OFAC against, and all reasonable documented costs and expenses (including counsel fees and disbursements) incurred in connection with defense thereof by, the Administrative Agent or any Bank as a result of conduct of Borrower that violates a sanction enforced by OFAC. Borrower further agrees to pay or reimburse the Administrative Agent, each Bank and each Issuing Bank upon demand for any stamp or other similar taxes which may be payable with respect to the execution, delivery, recording and/or filing of this Agreement and/or any of the other Transaction Documents. Borrower acknowledges and agrees that such attorneys’ fees and expenses referred to above shall be determined on the basis of rates then generally applicable to the attorneys (and all paralegals, accountants and other staff employed by such attorneys) retained by the Administrative Agent, any Bank or any Issuing Bank. All of the obligations of Borrower under this Section 9.03(a) shall survive the satisfaction and payment of Borrower’s Obligations and the termination of this Agreement.

(b)Indemnity by Borrower. In addition to the payment of expenses pursuant to Section 9.03(a), whether or not the transactions contemplated hereby shall be consummated, Borrower hereby agrees to defend, indemnify, pay and hold the Administrative Agent (and any sub-agent thereof), each Bank, each Issuing Bank, any holders of the Loans, and any Related Party of any of the foregoing Persons (collectively, the “Indemnitees”) harmless from and against any and all other liabilities, obligations, losses, damages, penalties, actions, judgments, suits, claims, disbursements, costs and expenses of any kind or nature whatsoever (including, without limitation, the reasonable fees and disbursements of counsel for such Indemnitees in connection with any investigative, administrative or judicial proceeding commenced or threatened, whether or not such Indemnitees shall be designated a party thereto, provided that the Indemnitees shall share counsel to defend their interests to the extent legally practicable), that may be imposed on, incurred by or asserted against the Indemnitees by any third party or by Borrower, in any manner relating to or arising out of (i) the execution or delivery of this Agreement, any of the other Transaction Documents or any other agreement, document or instrument executed and delivered by Borrower in connection herewith or therewith, the

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statements contained in any commitment letters delivered by the Administrative Agent or any Bank, the agreement of the Banks to make the Loans under this Agreement, (ii) any Loan or Letter of Credit or the use or intended use of the proceeds thereof (including any refusal by any Issuing Bank to honor a demand for payment under a Letter of Credit if the documents presented in connection with such demand do not strictly comply with the terms of such Letter of Credit) (iii) any actual or alleged presence or release of hazardous substances on or from any property owned or operated by Borrower, or any environmental claim related in any way to Borrower or any of its Subsidiaries and (iv) any actual or prospective claim, litigation, investigation or proceeding relating to any of the foregoing, whether based on contract, tort or any other theory, whether brought by a third party or by Borrower, and regardless of whether any Indemnitee is a party thereto (collectively, the “Indemnified Liabilities”); provided that no Indemnitee will have any right to indemnification for any of the foregoing to the extent resulting from such Indemnitee’s own fraud, gross negligence or willful misconduct or a breach in bad faith by such Indemnified Party of its obligations hereunder, in each case as determined by a final non-appealable judgment of a court of competent jurisdiction. To the extent that the undertaking to indemnify, pay and hold harmless set forth in the preceding sentence may be unenforceable because it is violative of any law or public policy, Borrower shall contribute the maximum portion that it is permitted to pay and satisfy under applicable law to the payment and satisfaction of all Indemnified Liabilities incurred by the Indemnitees or any of them. The provisions of the undertakings and indemnification set out in this Section 9.03(a) shall survive satisfaction and payment of Borrower’s Obligations and the termination of this Agreement.

(c)Indemnity by Banks. To the extent that Borrower for any reason fails to indefeasibly pay any amount required under Sections 9.03(a) and (b) to be paid by it to the Administrative Agent (or any sub-agent thereof), any Issuing Bank or any Related Party of any of the foregoing, each Bank severally agrees to pay to the Administrative Agent (or any such sub-agent), such Issuing Bank or such Related Party, as the case may be, such Bank’s proportion (based on the percentages as used in determining the Required Banks as of the time that the applicable unreimbursed expense or indemnity payment is sought) of such unpaid amount, provided that the unreimbursed expense or indemnified loss, claim, damage, liability or related expense, as the case may be, was incurred by or asserted against the Administrative Agent (or any such sub-agent) or such Issuing Bank in its capacity as such, or against any Related Party of any of the foregoing acting for the Administrative Agent (or any such sub-agent) or any Issuing Bank in connection with such capacity. The obligations of the Banks under this Section 9.03(c) are subject to the provisions of Section 2.18(a).

(d)Waiver of Consequential Damages, Etc. To the fullest extent permitted by applicable law, no party hereunder shall assert, and each party hereunder hereby waives, any claim against any other party hereunder, on any theory of liability, for special, indirect, consequential or punitive damages (as opposed to direct or actual damages) arising out of, in connection with, or as a result of, this Agreement, any other Transaction Document or any agreement or instrument contemplated hereby, the transactions contemplated hereby or thereby, any Loan or Letter of Credit or the use of the proceeds thereof; provided however that the obligation of the Borrower to indemnify the Indemnitees as otherwise set forth herein arising from claims brought by third parties shall not be limited by the foregoing. No Indemnitee referred to in clause (b) above shall be liable for any damages arising from the use by unintended recipients of any information or other materials distributed by it through telecommunications,

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electronic or other information transmission systems in connection with this Agreement or the other Loan Documents or the transactions contemplated hereby or thereby; provided, however, that such use was not due to the gross negligence, willful misconduct or breach in bad faith by an Indemnitee referred to in clause (b) above.

9.04Notices.

(a)Notices Generally. Each notice, request, demand, consent, confirmation or other communication under this Agreement shall be in writing and delivered in person or sent by facsimile, recognized overnight courier or registered or certified mail, return receipt requested and postage prepaid, to the applicable party as follows: (a) if to Borrower, the Administrative Agent, any Issuing Bank or the Swingline Bank, to it at the address (or telecopier number) specified for such Person on Schedule 9.04 and (b) if to any Bank, to it at its address (or telecopier number) set forth in its Administrative Questionnaire. Notices sent by hand or overnight courier service, or mailed by certified or registered mail, shall be deemed to have been given when received; notices sent by facsimile, when provided in legible form, shall be deemed to have been given when sent (except that, if not given during normal business hours for the recipient, shall be deemed to have been given at the opening of business on the next business day for the recipient). Notices delivered through electronic communications to the extent provided in paragraph (b) below, shall be effective as provided in said paragraph (b).

(b)Electronic Communications. Notices and other communications to the Banks and the Issuing Banks hereunder may be delivered or furnished by electronic communication (including e-mail and Internet or intranet websites) pursuant to procedures approved by the Administrative Agent, provided that the foregoing shall not apply to notices to any Bank or any Issuing Bank pursuant to Section 2 or 3 if such Bank or such Issuing Bank, as applicable, has notified the Administrative Agent that is incapable of receiving notices under such Section by electronic communication. The Administrative Agent or Borrower may, in its discretion, agree to accept notices and other communications to it hereunder by electronic communications pursuant to procedures approved by it, provided that approval of such procedures may be limited to particular notices or communications. Unless the Administrative Agent otherwise prescribes, (i) notices and other communications sent to an e-mail address shall be deemed received upon the sender’s receipt of an acknowledgement from the intended recipient (such as by the “return receipt requested” function, as available, return e-mail or other written acknowledgement), provided that if such notice or other communication is not sent during the normal business hours of the recipient, such notice or communication shall be deemed to have been sent at the opening of business on the next business day for the recipient, and (ii) notices or communications posted to an Internet or intranet website shall be deemed received upon the deemed receipt by the intended recipient at its e-mail address as described in the foregoing clause (i) of notification that such notice or communication is available and identifying the website address therefor.

9.05Consent to Jurisdiction; Waiver of Jury Trial. EACH PARTY IRREVOCABLY SUBMITS TO THE NONEXCLUSIVE JURISDICTION OF ANY FEDERAL COURT, TO THE EXTENT PERMITTED BY LAW, OF THE UNITED STATES OF AMERICA SITTING IN THE BOROUGH OF MANHATTAN IN NEW YORK CITY OR, IF SUCH FEDERAL COURT IS NOT AVAILABLE DUE TO LACK OF JURISDICTION, ANY NEW YORK STATE COURT SITTING IN THE BOROUGH OF MANHATTAN IN NEW YORK CITY,

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AND ANY APPELLATE COURT FROM ANY THEREOF, AS THE INITIATING PARTY MAY ELECT, IN ANY SUIT, ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT OR ANY OTHER TRANSACTION DOCUMENT. EACH PARTY HEREBY IRREVOCABLY AGREES THAT ALL CLAIMS IN RESPECT TO SUCH SUIT, ACTION OR PROCEEDING MAY BE HEARD AND DETERMINED IN ANY OF SUCH COURTS. EACH PARTY IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY LAW, ANY OBJECTION WHICH SUCH PARTY MAY NOW OR HEREAFTER HAVE TO THE LAYING OF VENUE OF ANY SUCH SUIT, ACTION OR PROCEEDING BROUGHT IN ANY SUCH COURT, AND EACH PARTY FURTHER IRREVOCABLY WAIVES ANY CLAIM THAT SUCH SUIT, ACTION OR PROCEEDING BROUGHT IN ANY SUCH COURT HAS BEEN BROUGHT IN AN INCONVENIENT FORUM. EACH PARTY AUTHORIZES THE SERVICE OF PROCESS UPON BORROWER BY OVERNIGHT COURIER, SIGNATURE REQUIRED SENT TO ITS ADDRESS SPECIFIED IN SCHEDULE 9.04. EACH PARTY HERETO HEREBY IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, THE RIGHT TO TRIAL BY JURY WITH RESPECT TO ANY ACTION RELATING TO OR ARISING OUT OF OR IN CONNECTION WITH THIS AGREEMENT OR ANY OF THE OTHER TRANSACTION DOCUMENTS OR THE TRANSACTIONS CONTEMPLATED HEREBY OR THEREBY (WHETHER BASED ON CONTRACT, TORT OR ANY OTHER THEORY). EACH PARTY HERETO (A) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PERSON HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PERSON WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER AND (B) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AGREEMENT AND THE OTHER TRANSACTION DOCUMENTS BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION.

Nothing in this Agreement or any other Transaction Document shall affect any right that the Administrative Agent, any Bank, or any Issuing Bank may otherwise have to bring any action or proceeding relating to this Agreement or any other Transaction Document against Borrower or any of its Subsidiaries or their properties in courts of any jurisdiction.

9.06Governing Law. This Agreement and the other Transaction Documents shall be governed by and construed in accordance with the substantive laws of the State of New York (including Sections 5-1401 and 5-1402 of the New York General Obligations of Law, but excluding all other choice of law and conflicts of law rules); provided that each Letter of Credit shall be governed by, and construed in accordance with, the laws or rules designated in such Letter of Credit or application therefor or, if no such laws or rules are designated, the International Standby Practices of the International Chamber of Commerce, as in effect from time to time (the “ISP”), and, as to matters not governed by the ISP, the laws of the State of New York (including Sections 5-1401 and 5-1402 of the New York General Obligations Law, but excluding all other choice of law and conflicts of law rules).

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9.07Amendments and Waivers.

(c)Any provision of this Agreement or any of the other Transaction Documents to which Borrower is a party may be amended, modified, discharged, terminated or waived if, but only if, such amendment, modification, waiver, discharge or termination is in writing and is signed by Borrower and the Required Banks (or by the Administrative Agent at the direction or with the consent of the Required Banks); provided, however, that no such amendment, modification, waiver, discharge or termination shall (i) unless signed by each Bank directly affected thereby (A) increase the Revolving Credit Commitment of a Bank (it being understood that a waiver of any condition precedent set forth in Section 4.02 or of any Default or Event of Default, if agreed to by the Required Banks or all Banks (as may be required hereunder with respect to such waiver), shall not constitute such an increase), (B) reduce the principal amount of or rate of interest on any Loan, Reimbursement Obligation or any fees hereunder (provided that only the consent of the Required Banks shall be required to waive the applicability of any post-default increase in interest rates), (C) decrease the Revolving Credit Commitment of any Bank (other than ratable decreases of the Revolving Credit Commitments of each Bank affected in accordance with Section 2.01(d), or (D) waive, extend or postpone the date fixed for any payment of principal of or interest on any Loan or any fees hereunder (other than fees payable to the Administrative Agent, the Arrangers or the Issuing Banks for its own account), waive, extend or postpone the time of payment of any Reimbursement Obligation or any interest thereon, waive, extend or postpone the expiry date of any Letter of Credit beyond the Letter of Credit Maturity Date, or extend the term of the Revolving Credit Period, (ii) unless signed by each Bank, (A) change any provision of this Section or reduce the percentages specified in the definitions of “Required Banks” or change the definition of “Pro Rata Share” or change any other provision hereof specifying the number or percentage of Banks required to amend, waive or otherwise modify any rights hereunder or make any determination or grant any consent hereunder, or (B) amend Section 2.18, and (iii) unless signed by the Issuing Banks, the Swingline Bank or the Administrative Agent in addition to the Banks as provided hereinabove to take such action, affect the respective rights or obligations of the Issuing Banks, the Swingline Bank or the Administrative Agent, as applicable, hereunder or under any of the other Transaction Documents.

(d)Notwithstanding anything to the contrary herein, (i) no Defaulting Bank shall have any right to approve or disapprove any amendment, waiver or consent hereunder (and any amendment, waiver or consent which by its terms requires the consent of all Banks or each affected Bank may be effected with the consent of the applicable Banks other than Defaulting Banks), except that (A) the Revolving Credit Commitment of any Defaulting Bank may not be increased or extended without the consent of such Bank and (B) any waiver, amendment or modification requiring the consent of all Banks or each affected Bank that by its terms affects any Defaulting Bank more adversely than other affected Banks shall require the consent of such Defaulting Bank and (ii) if the Administrative Agent and Borrower shall have jointly identified (each in its sole discretion) an obvious error or omission of a technical or immaterial nature, in each case, in any provision of the Transaction Documents, then the Administrative Agent and Borrower shall be permitted to amend such provision and such amendment shall become effective without any further action or consent of any other party to any Transaction Document if the same is not objected to in writing by the Required Banks within five (5) Business Days following the posting of such amendment to the Banks.

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(e)Notwithstanding the fact that the consent of all Banks is required in certain circumstances as set forth above, each Bank is entitled to vote as such Bank sees fit on any bankruptcy reorganization plan that affects the Loans, and each Bank acknowledges that the provisions of Section 1126(c) of title 11 of the U.S. Code supersedes the unanimous consent provisions set forth herein.

9.08References; Headings for Convenience. Unless otherwise specified herein, all references herein to Section numbers refer to Section numbers of this Agreement, all references herein to Exhibits refer to annexed Exhibits, which are hereby incorporated herein by reference and all references herein to Schedules refer to annexed Schedules, which are hereby incorporated herein by reference. The Section headings are furnished for the convenience of the parties and are not to be considered in the construction or interpretation of this Agreement.

9.09Successors and Assigns.

(a)Subject to paragraphs (b), (c) and (d) of this Section 9.09, the provisions of this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns. Notwithstanding the foregoing, Borrower may not assign or otherwise transfer any of its rights or delegate any of its obligations or duties under this Agreement without the prior written consent of the Administrative Agent and each Bank.

(b)Any Bank may at any time, without the consent of, or notice to, Borrower or the Administrative Agent, sell participations to any Person (other than a natural person or Borrower or any of Borrower’s Affiliates or Subsidiaries) (each, a “Participant”) in its Revolving Credit Commitment, any or all of its Loans and/or any or all of its other rights and/or obligations under this Agreement. In the event of any such grant by a Bank of a participating interest to a Participant, whether or not upon notice to Borrower and the Administrative Agent, such Bank shall remain responsible for the performance of its obligations under this Agreement, and Borrower and the Administrative Agent shall continue to deal solely and directly with such Bank in connection with such Bank’s rights and obligations under this Agreement. Any agreement pursuant to which any Bank may grant such a participating interest shall provide that such Bank shall retain the sole right and responsibility to enforce the obligations of Borrower hereunder including, without limitation, the right to approve any amendment, modification or waiver of any provision of this Agreement; provided that such participation agreement may provide that the applicable Bank will not agree to any amendment, modification or waiver of this Agreement described in clauses (a)(i)(A), (a)(i)(B) or (a)(i)(D) of Section 9.07 without the consent of the Participant. Borrower agrees that each Participant shall, to the extent provided in its participation agreement, be entitled to the benefits of Sections 2.10, 2.11, 2.12, 2.13, 2.14, 2.15, 2.16 and 2.17 of this Agreement with respect to its participating interest, but Borrower’s liability in respect thereof shall not be greater than its liability thereunder to the Bank granting the applicable participation. To the extent permitted by law, each Participant also shall be entitled to the benefits of Section 9.02 as though it were a Bank; provided such Participant agrees to be subject to Section 2.18 as though it were a Bank.

(c)Any Bank may at any time assign to one or more assignees (each, an “Assignee”) all, or a proportionate part of all, of its rights and obligations under this Agreement (including all or a portion of its Revolving Credit Commitments and the Loans (including for purposes of this

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Section 9.09(c), participations in Letters of Credit and Swingline Loans) at the time owing to it) and such Assignee shall assume such rights and obligations, pursuant to an Assignment and Assumption Agreement in substantially the form of Exhibit D attached hereto executed by such Assignee and such transferor Bank, with (and subject to) the subscribed consent of Borrower (provided that Borrower shall be deemed to have given its consent five (5) Business Days after the date written notice thereof has been delivered by the assigning Bank (through the Administrative Agent) unless such consent is expressly refused by Borrower prior to such fifth (5th) Business Day), the Administrative Agent, the Swingline Bank and each Issuing Bank which, in each case, shall not be unreasonably withheld or delayed; provided, however, that (i) the minimum amount of any such assignment shall be (A) $5,000,000 (except in the case of an assignment of the entire remaining amount of the assigning Bank’s Revolving Credit Commitment, in which case no minimum amount need be assigned) or (B) the entire Swingline Commitment and the full amount of the outstanding Swingline Loans, in the case of Swingline Loans, (ii) if any Assignee is an Affiliate of a Bank, an Approved Fund or, immediately prior to such assignment, already a Bank, no consent shall be required and (iii) if any Event of Default under this Agreement has occurred and is continuing no consent of Borrower to such assignment shall be required. Upon execution and delivery of such instrument and payment by such Assignee to such transferor Bank of an amount equal to the purchase price agreed between such transferor Bank and such Assignee, such Assignee shall be a Bank party to this Agreement and shall have all the rights and obligations of a Bank with a Revolving Credit Commitment as set forth in such instrument of assumption, and the transferor Bank shall be released from its obligations hereunder to a corresponding extent, and no further consent or action by any party shall be required but transferor Bank shall continue to be entitled to the benefits of Sections 2.10, 2.13, 2.15, 2.17, 2.20 and 9.03 with respect to facts and circumstances occurring prior to the effective date of such assignment. Upon the consummation of any assignment pursuant to this subsection (c), the transferor Bank, the Administrative Agent and Borrower shall make appropriate arrangements so that, if requested, new Notes are issued to the assignor and/or the Assignee, as applicable. In connection with any such assignment, the transferor Bank shall pay to the Administrative Agent an administrative fee for processing such assignment in the amount of $3,500 and if it is not a Bank, shall deliver to the Administrative Agent an Administrative Questionnaire; provided that in the case of an assignment to a Bank, Approved Fund or Affiliate of a Bank or an Approved Fund, no such fee shall be required.

(d)Any Bank may at any time assign all or any portion of its rights under this Agreement and its Loans to secure its obligations to a Federal Reserve Bank. No such assignment shall release the transferor Bank from any of its obligations hereunder.

(e)No such assignment shall be made to (A) Borrower or any of its respective Affiliates or Subsidiaries or (B) to any Defaulting Bank or any of its Subsidiaries, or any Person who, upon becoming a Bank hereunder, would constitute any of the foregoing Persons described in this clause (B).

(f)No such assignment shall be made to a natural person.

(g)In connection with any assignment of rights and obligations of any Defaulting Bank hereunder, no such assignment shall be effective unless and until, in addition to the other conditions thereto set forth herein, the parties to the assignment shall make such additional

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payments to the Administrative Agent in an aggregate amount sufficient, upon distribution thereof as appropriate (which may be outright payment, purchases by the assignee of participations or sub-participations, or other compensating actions, including funding, with the consent of Borrower and the Administrative Agent, the applicable pro rata share of Loans previously requested but not funded by the Defaulting Bank, to each of which the applicable assignee and assignor hereby irrevocably consent), to (x) pay and satisfy in full all payment liabilities then owed by such Defaulting Bank to the Administrative Agent or any Bank hereunder (and interest accrued thereon), and (y) acquire (and fund as appropriate) its full Pro Rata Share of all Loans and participations in Letters of Credit and Swingline Loans in accordance with its Pro Rata Share. Notwithstanding the foregoing, in the event that any assignment of rights and obligations of any Defaulting Bank hereunder shall become effective under applicable Law without compliance with the provisions of this paragraph, then the assignee of such interest shall be deemed to be a Defaulting Bank for all purposes of this Agreement until such compliance occurs.

(h)The Administrative Agent, acting solely for this purpose as an agent of Borrower, shall maintain at its address for notices specified in Schedule 9.04, a copy of each Assignment and Assumption delivered to it and a register for the recordation of the names and addresses of the Banks, and the Revolving Credit Commitments of, and principal amounts of the Loans owing to, each Bank pursuant to the terms hereof from time to time (the “Register”). The entries in the Register shall be conclusive, and Borrower, the Administrative Agent and the Banks may treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Bank hereunder for all purposes of this Agreement, notwithstanding notice to the contrary. In addition, the Administrative Agent shall maintain on the Register information regarding the designation, revocation of designation, of any Bank as a Defaulting Bank. The Register shall be available for inspection by each of Borrower and each Issuing Bank, at any reasonable time and from time to time upon reasonable prior notice. In addition, at any time that a request for a consent for a material or substantive change to the Transaction Documents is pending, any Bank wishing to consult with other Banks in connection therewith may request and receive from the Administrative Agent a copy of the Register.

(i)Notwithstanding anything to the contrary contained herein, if Wells Fargo assigns all of its Revolving Credit Commitments and Revolving Loans in accordance with this Section 9.09, Wells Fargo may resign as an Issuing Bank and Swingline Bank upon written notice to Borrower and the Banks. Upon any such notice of resignation, Borrower shall have the right to appoint from among the Banks a successor Issuing Bank and Swingline Bank; provided that no failure by Borrower to make such appointment shall affect the resignation of Wells Fargo as an Issuing Bank and Swingline Bank. Wells Fargo shall retain all of the rights and obligations of an Issuing Bank hereunder with respect to all Letters of Credit issued by it and outstanding as of the effective date of its resignation and all obligations of Borrower and the Banks with respect thereto (including the right to require the Banks to make Revolving Loans or fund participation interests pursuant to Section 3) and with respect to all Swingline Loans made by it and outstanding as of the effective date of its resignation and all obligations of Borrower and the Banks with respect thereto (including the right to require the Banks to make Refunded Swingline Loans or fund participation interests pursuant to Section 2.01(e)).

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9.10Entire Agreement. This Agreement embodies the entire agreement and understanding between the parties hereto and supersedes all prior agreements and understandings (oral or written) relating to the subject matter hereof, including the Existing Loan Agreement.

9.11Severability. In the event any one or more of the provisions contained in this Agreement should be invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions contained herein shall not in any way be affected or impaired thereby.

9.12Counterparts. This Agreement may be executed in any number of counterparts (including facsimile counterparts), each of which shall be deemed an original, but all of which together shall constitute one and the same instrument.

9.13Confidentiality. Any Information received by any Bank or any Arranger from Borrower (or from the Administrative Agent on Borrower’s behalf), (i) shall be treated as confidential by such Bank or such Arranger in accordance with its customary practices and procedures and (ii) with respect to any information or materials received prior to the Closing Date, shall be used solely for the purposes of providing the services that are subject to the Commitment Letter and for no other purpose. Notwithstanding such agreement, nothing herein contained shall limit or impair the right or obligation of any Bank or any Arranger to disclose such information: (a) to its auditors, attorneys, trustees, employees, directors, officers, advisors, Affiliates or agents (collectively, the “Representatives”) who are informed of the confidential nature of such information and are or have been advised of their obligation to keep information of this type confidential and, with respect to any information or material received prior to the Closing Date, to use such information solely for the purposes of providing services that are the subject of the Commitment Letter and for no other purpose; provided that such Bank or Arranger shall remain liable for any breach by its Representatives of such confidentiality provisions, (b) when and as required by any law, ordinance, subpoena or governmental order, rule or regulation (in which case, such Bank or Arranger shall promptly notify the Borrower, in advance to the extent permitted by law, and will only disclose that portion of the nonpublic information received by it that such Bank or Arranger is so required to disclose), (c) to the extent requested by any regulatory authority purporting to have jurisdiction over it (including any self-regulatory authority), (d) which is publicly available or readily ascertainable from public sources to the extent any such information becomes publicly available other than by reason of disclosure by such Bank or Arranger, its affiliates or its Representatives in breach of this Section, or which is received by any Bank or Arranger from a third Person which or which is not known by such Bank or Arranger to be bound to keep the same confidential, (e) in connection with any proceeding, case or matter pending (or on its face purported to be pending) before any court, tribunal or any governmental agency, commission, authority, board or similar entity (in which case, such Bank or Arranger shall promptly notify the Borrower, in advance to the extent permitted by law, and will only disclose that portion of the nonpublic information received by it that such Bank or Arranger is so required to disclose), (f) in connection with protection of its interests under this Agreement, the Notes or any of the other Transaction Documents, including, without limitation, the enforcement of the terms and conditions of this Agreement, the Notes and the other Transaction Documents, or (g) to any actual or prospective Participant or Assignee (it being understood and agreed that prior to disclosure of any confidential information to any actual or prospective Participant or Assignee, such actual or prospective Participant or Assignee shall

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have agreed in writing to be bound by the terms and provisions of this Section 9.13). For purposes of this Section, “Information” means all information received from Borrower or any Subsidiary relating to Borrower or any Subsidiary or any of their respective businesses, provided that, in the case of information received from Borrower or any Subsidiary after the date hereof, such information is clearly identified at the time of delivery as confidential.

9.14USA Patriot Act Notice. Each Bank that is subject to the PATRIOT Act and the Administrative Agent (for itself and not on behalf of any Bank) hereby notifies Borrower that pursuant to the requirements of the PATRIOT Act, it is required to obtain, verify and record information that identifies Borrower or any of its Subsidiaries, which information includes the name and address of Borrower and its Subsidiaries and other information that will allow such Bank or the Administrative Agent, as applicable, to identify Borrower and its Subsidiaries in accordance with the PATRIOT Act.

9.15[Reserved]

9.16No Fiduciary Duty. The Borrower agrees that in connection with all aspects of the transactions contemplated hereby and any communications in connection therewith, the Borrower and its Affiliates, on the one hand, and the Administrative Agent, the Arrangers, the Banks, the Issuing Banks and their respective Affiliates, on the other hand, will have a business relationship that does not create, by implication or otherwise, any fiduciary duty on the part of the Administrative Agent, the Arrangers, the Banks, the Issuing Banks or their respective Affiliates and no such duty will be deemed to have arisen in connection with any such transactions or communications.

IN WITNESS WHEREOF, Borrower, the Administrative Agent, the Issuing Banks, the Swingline Bank and the Banks have executed this Agreement as of the day and year first above written.

BORROWER: THELACLEDE GROUP, INC.

By: ___________________________________

Name:    

Title:    

ADMINISTRATIVE AGENT: WELLS FARGO BANK, NATIONAL, ASSOCIATION, as a Bank, an Issuing Bank, the Swingline Bank and Administrative Agent

By:    

Name:    

Title:    

83    

BANK: U.S. BANK NATIONAL ASSOCIATION, as a Bank, and as an Issuing Bank

By:    

Name:    

Title:    

BANK: JPMORGAN CHASE BANK, N.A., as a Bank, and as an Issuing Bank

By:    

Name:    

Title:    

BANK:    BANK OF AMERICA, N.A., as a Bank

By:    

Name:    

Title:    

BANK:    FIFTH THIRD BANK, as a Bank

By:    

Name:    

Title:    

BANK:    MORGAN STANLEY BANK, N.A., as a Bank

By:    

Name:    

Title:    

BANK:    COMMERCE BANK, as a Bank

By:    

Name:    

Title:    

BANK:    UMB BANK, N.A, as a Bank

By:    

Name:    

Title:    

BANK:    STIFEL BANK & TRUST, as a Bank

By:    

Name:    

Title:    

EX-12

Exhibit 12

THE LACLEDE GROUP, INC. AND SUBSIDIARY COMPANIES
SCHEDULE OF COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
	Fiscal Year Ended September 30,
	2013		2012		2011		2010		2009
(Thousands of Dollars)
Income before interest charges and income taxes	$	98,938	$	113,875	$	118,424	$	107,986	$	126,517
Add: One third of applicable rentals charged to operating expense (which approximates the interest factor)	2,009		1,591		1,799		1,825		1,833
Total Earnings	$	100,947	$	115,466	$	120,223	$	109,811	$	128,350
Interest on long-term debt	$	25,539	$	22,958	$	23,161	$	24,583	$	24,583
Other Interest	3,063		1,988		2,256		2,269		5,163
Add: One third of applicable rentals charged to operating expense (which approximates the interest factor)	2,009		1,591		1,799		1,825		1,833
Total Fixed Charges	$	30,611	$	26,537	$	27,216	$	28,677	$	31,579
Ratio of Earnings to Fixed Charges	3.30		4.35		4.42		3.83		4.06

EX-21

Exhibit 21

THE LACLEDE GROUP, INC. AND SUBSIDIARIES
SUBSIDIARIES OF THE REGISTRANT
Subsidiaries of The Laclede Group, Inc. (Parent)	Percent of Voting Stock Owned
Laclede Gas Company	100%
Laclede Pipeline Company	100%
Laclede Investment LLC*	100%
Laclede Development Company**	100%
Laclede Insurance Risk Services, Inc.	100%
*Subsidiary Company of Laclede Investment LLC
Laclede Energy Resources, Inc.	100%
Subsidiary Companies of Laclede Energy Resources, Inc.
Laclede Gas Family Services, Inc.	100%
LER Storage Services, Inc.	100%
**Subsidiary Companies of Laclede Development Company
Laclede Venture Corp.	100%
Laclede Oil Services, LLC	100%
All of the above corporations have been organized under the laws of the State of Missouri except Laclede Insurance Risk Services, Inc., which is organized under the laws of the State of South Carolina.

EX-23

Exhibit 23

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement Nos. 333-190388 and 333-175903 of The Laclede Group, Inc. on Form S-3 and in Registration Statement Nos. 333-90248, 333-90252, 333-90254, and 333-131830 of The Laclede Group, Inc. on Form S-8 of our reports dated November 26, 2013, relating to the consolidated financial statements and financial statement schedule of The Laclede Group, Inc. and subsidiaries, and the effectiveness of The Laclede Group, Inc. and subsidiaries' internal control over financial reporting, appearing in this Annual Report on Form 10-K of The Laclede Group, Inc. for the year ended September 30, 2013.

/s/DELOITTE & TOUCHE LLP

St. Louis, Missouri

November 26, 2013

EX-31

Exhibit 31

CERTIFICATION

I, Suzanne Sitherwood, certify that:

1. I have reviewed this annual report on Form 10-K of The Laclede Group, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 26, 2013	Signature:	/s/ Suzanne Sitherwood
			Suzanne Sitherwood
			President and
			Chief Executive Officer

CERTIFICATION

I, Steven P. Rasche, certify that:

1. I have reviewed this annual report on Form 10-K of The Laclede Group Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	November 26, 2013	Signature:	/s/ Steven P. Rasche
			Steven P. Rasche
			Senior Vice President
			and Chief Financial Officer

EX-32

Exhibit 32

Section 1350 Certification

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, I, Suzanne Sitherwood, President and Chief Executive Officer of The Laclede Group, Inc., hereby certify that

(a) To the best of my knowledge, the accompanying report on Form 10-K for the year ended September 30, 2013 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and

(b) To the best of my knowledge, the information contained in the accompanying report on Form 10-K for the year ended September 30, 2013 fairly presents, in all material respects, the financial condition and results of operations of Laclede Gas Company.

Date:	November 26, 2013	/s/ Suzanne Sitherwood
		Suzanne Sitherwood
		President and
		Chief Executive Officer

Section 1350 Certification

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, I, Steven P. Rasche, Senior Vice President and Chief Financial Officer of The Laclede Group, Inc., hereby certify that

(a) To the best of my knowledge, the accompanying report on Form 10-K for the year ended September 30, 2013 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and

(b) To the best of my knowledge, the information contained in the accompanying report on Form 10-K for the year ended Spetember 30, 2013 fairly presents, in all material respects, the financial condition and results of operations of Laclede Gas Company.

Date:	November 26, 2013	/s/ Steven P. Rasche
		Steven P. Rasche
		Senior Vice President
		and Chief Financial Officer

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CONCENTRATIONS OF CREDIT RISK (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013 counterparty
Concentration Risk [Line Items]
Number of large counterparties for which credit risk is disclosed	5
Energy Producers And Their Affiliates [Member]
Concentration Risk [Line Items]
Accounts receivable	$ 22.8
Utility Companies And Their Affiliates [Member]
Concentration Risk [Line Items]
Accounts receivable	23.5
Net receivable amount	16.6
Largest Counterparties [Member]
Concentration Risk [Line Items]
Accounts receivable	16.6
Net receivable amount	$ 14.5

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OTHER INCOME AND (INCOME DEDUCTIONS) - NET (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Other Nonoperating Income (Expense) [Abstract]
Interest income	$ 1,088	$ 1,309	$ 1,136
Net investment gain	2,857	3,124	185
Other income	377	811	118
Other income deductions	(1,878)	(1,972)	(1,262)
Other Income and (Income Deductions) – Net	$ 2,444	$ 3,272	$ 177

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LONG-TERM DEBT

12 Months Ended

Sep. 30, 2013

Debt Disclosure [Abstract]

LONG-TERM DEBT

LONG-TERM DEBT

Maturities on long-term debt for the five fiscal years subsequent to September 30, 2013 are as follows:

2014	—
2015	—
2016	—
2017	—
2018	$	100	million

On October 15, 2012, the Utility paid at maturity $25 million principal amount of 6 1/2% first mortgage bonds. This maturity was funded through short-term borrowings. Laclede Group issued $25 million of 3.31%10-year unsecured notes in a private placement on December 14, 2012 and the Utility issued $100 million of first mortgage bonds in a private placement on March 15, 2013, that had been committed to in August 2012. Of this $100 million, $55 million were issued at 3.00% for a 10-year term, maturing in March 2023, and $45 million were issued at 3.40% for a 15-year term, maturing in March 2028. The proceeds were used for the repayment of short-term debt and general corporate purposes. The Utility issued $450 million of first mortgage bonds on August 13, 2013. Of this $450 million, $100 million was issued at 2.00% maturing in August 2018, $250 million was issued at 3.40% maturing in August 2023, and $100 million was issued at 4.625% maturing in August 2043. The proceeds were used to fund a portion of the MGE acquisition.

At September 30, 2013, the Company had fixed-rate long-term debt totaling $915 million. While these long-term debt issues are fixed-rate, they are subject to changes in fair value as market interest rates change. Of the Company’s $915 million in long-term debt, $50 million have no call options, $435 million have make-whole call options, $350 million are callable at par three to six months prior to maturity and $80 million are callable at par beginning in October 2013. None of the debt has any put options.

On August 6, 2013, Laclede Group and Laclede Gas filed with the SEC a joint shelf registration statement on Form S-3 for issuance of various types of debt and equity securities, which expires August 5, 2016. Bonds totaling $450 million were issued by Laclede Gas from this registration statement on August 13, 2013. The amount, timing, and type of additional financing to be issued under these shelf registrations will depend on cash requirements and market conditions.

The Utility has authority from the MoPSC to issue up to $518 million in debt securities and preferred stock, including on a private placement basis, as well as to enter into capital leases, issue common stock and receive paid-in capital. This authorization was originally effective through June 30, 2013. In August 2012, the Utility filed a request with the MoPSC to extend this authority for an additional two years, to June 30, 2015. This extension was approved October 24, 2012, to be effective on November 23, 2012. At November 26, 2013, $370.8 million remained under this authorization. The amount, timing, and type of additional financing to be issued will depend on cash requirements and market conditions.

Substantially all of the Utility plant is subject to the liens of its first mortgage bonds. The mortgage contains several restrictions on the Utility's ability to pay cash dividends on its common stock, which are described more fully in Note 6, Stockholders’ Equity.

At September 30, 2013 and 2012, the Utility had authorized 1,480,000 shares of preferred stock, but none were issued and outstanding.

For information on additional financing commitments, refer to Note 16, Commitments and Contingencies.

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 1 (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Pension Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost – benefits earned during the period	$ 9,209	$ 9,203	$ 9,553
Interest cost on projected benefit obligation	16,959	19,358	18,819
Expected return on plan assets	(19,358)	(19,595)	(18,849)
Amortization of prior service cost	544	592	642
Amortization of actuarial loss	10,724	9,040	10,228
Loss on lump-sum settlements	26,996	20,051	943
Sub-total	45,074	38,649	21,336
Regulatory adjustment	(27,532)	(18,579)	(7,066)
Net pension cost	17,542	20,070	14,270
Postretirement Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost – benefits earned during the period	10,162	8,060	7,676
Interest cost on projected benefit obligation	5,234	5,521	4,843
Expected return on plan assets	(4,447)	(3,965)	(3,646)
Amortization of transition obligation	93	136	136
Amortization of prior service cost	3	(2,072)	(2,328)
Amortization of actuarial loss	5,300	4,261	4,443
Sub-total	16,345	11,941	11,124
Regulatory adjustment	(6,821)	(2,417)	(2,071)
Net pension cost	$ 9,524	$ 9,524	$ 9,053

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CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012
ASSETS
Utility Plant	$ 2,271,189		$ 1,497,419
Less – Accumulated depreciation and amortization	494,559		478,120
Net Utility Plant	1,776,630		1,019,299
Non-utility property (net of accumulated depreciation and amortization, 2013, $5,886; 2012, $10,018)	7,694		6,039
Goodwill	247,078		0
Other investments	58,306		50,775
Other Property and Investments	313,078		56,814
Current Assets:
Cash and cash equivalents	52,981		27,457
Accounts receivable:
Utility	101,118		64,027
Non-utility	63,752		51,042
Other	14,451		26,478
Allowance for doubtful accounts	(8,046)		(7,705)
Inventories:
Natural gas stored underground	182,035		92,729
Propane gas	8,962		10,200
Materials and supplies at average cost	8,154		3,543
Natural gas receivable	18,782		22,377
Derivative instrument assets	3,291		2,855
Unamortized purchased gas adjustments	17,533		40,674
Prepayments and other	12,867		9,339
Total Current Assets	475,880		343,016
Deferred Charges:
Regulatory assets	545,947		456,047
Other	13,851		5,086
Total Deferred Charges	559,798		461,133
Total Assets	3,125,386		1,880,262
Capitalization:
Common stock equity	1,046,282		601,611
Long-term debt (less current portion)	912,712		339,416
Total Capitalization	1,958,994		941,027
Current Liabilities:
Notes payable	74,000		40,100
Accounts payable	140,234		89,503
Advance customer billings	23,736		25,146
Current portion of long-term debt	0		25,000
Wages and compensation accrued	20,807		13,908
Dividends payable	14,556		9,831
Customer deposits	15,062		8,565
Interest accrued	8,335		8,590
Taxes accrued	32,896		11,304
Deferred income taxes	1,012		6,675
Other	22,540		13,502
Total Current Liabilities	353,178		252,124
Deferred Credits and Other Liabilities:
Deferred income taxes	379,114	[1]	355,509	[1]
Unamortized investment tax credits	2,900		3,113
Pension and postretirement benefit costs	228,653		196,558
Asset retirement obligations	74,554		40,368
Regulatory liabilities	82,560		56,319
Other	45,433		35,244
Total Deferred Credits and Other Liabilities	813,214		687,111
Commitments and Contingencies
Total Capitalization and Liabilities	$ 3,125,386		$ 1,880,262

[1] The Company periodically invests in tax credits. As of September 30, 2013, $7.1 million of state tax credits are included in Other and Net deferred tax liability. $4.7 million of state tax credits were classified as current. $2.4 million of state tax credits were classified as non-current.

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STATEMENTS OF CONSOLIDATED CASH FLOWS (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Operating Activities:
Net income	$ 52,758	$ 62,640	$ 63,825
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, amortization and accretion	49,283	41,339	39,764
Deferred income taxes and investment tax credits	22,053	30,554	23,885
Other - net	957	75	3,431
Changes in assets and liabilities:
Accounts receivable – net	(650)	(9,359)	3,106
Unamortized purchased gas adjustments	23,141	(14,955)	(2,001)
Deferred purchased gas costs	13,300	11,090	44,565
Accounts payable	35,445	(8,790)	(4,860)
Advance customer billings – net	(8,248)	9,916	(1,579)
Taxes accrued	3,666	(1,169)	1,387
Natural gas stored underground	(30,626)	22,441	(1,594)
Other assets and liabilities	2,835	(15,681)	(2,742)
Net cash provided by operating activities	163,914	128,101	167,187
Investing Activities:
Capital expenditures	(130,788)	(108,843)	(67,638)
Other investments	(2,511)	3,439	631
Acquisition of MGE	(975,000)	0	0
Net cash used in investing activities	(1,108,299)	(105,404)	(67,007)
Financing Activities:
Issuance of first mortgage bonds	550,000	0	0
Maturity of first mortgage bonds	(25,000)	0	(25,000)
Issuance (Repayment) of short-term debt - net	33,900	(5,900)	(83,650)
Notes Payable Issued	25,000	0	0
Change in book overdrafts	(1,255)	1,455	(545)
Issuance of common stock	431,682	4,311	2,549
Non-employee directors’ restricted stock awards	0	(565)	(494)
Dividends paid	(42,518)	(36,896)	(35,821)
Employees’ taxes paid associated with restricted shares withheld upon vesting	(931)	(1,203)	(1,162)
Excess tax benefits from stock-based compensation	1,778	338	314
Other	(2,747)	(57)	(13)
Net cash provided by (used in) financing activities	969,909	(38,517)	(143,822)
Net (Decrease) Increase in Cash and Cash Equivalents	25,524	(15,820)	(43,642)
Cash and Cash Equivalents at Beginning of Year	27,457	43,277	86,919
Cash and Cash Equivalents at End of Year	52,981	27,457	43,277
Supplemental Disclosure of Cash Paid (Refunded) During the Year for:
Interest	26,304	24,557	25,332
Income taxes	$ (9,375)	$ 1,540	$ 6,860

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OTHER INCOME AND (INCOME DEDUCTIONS) - NET

12 Months Ended

Sep. 30, 2013

Other Nonoperating Income (Expense) [Abstract]

OTHER INCOME AND (INCOME DEDUCTIONS) - NET

OTHER INCOME AND (INCOME DEDUCTIONS) – NET

(Thousands)	2013			2012			2011
Interest income	$	1,088		$	1,309		$	1,136
Net investment gain	2,857			3,124			185
Other income	377			811			118
Other income deductions	(1,878		)	(1,972		)	(1,262		)
Other Income and (Income Deductions) – Net	$	2,444		$	3,272		$	177

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EARNINGS PER COMMON SHARE (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended									12 Months Ended
	Sep. 30, 2013		Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Basic EPS:
Net income	$ (9,636)	[1]	$ 6,584	$ 30,242	$ 25,568	$ (651)	$ 8,433	$ 29,684	$ 25,174	$ 52,758	$ 62,640	$ 63,825
Less: Income allocated to participating securities										245	340	497
Net Income Available to Common Shareholders										52,513	62,300	63,328
Weighted Average Shares Outstanding, Basic (in Shares)										25,875	22,262	22,099
Basic Earnings Per Share of Common Stock (in dollars per share)	$ (0.30)	[1]	$ 0.25	$ 1.34	$ 1.14	$ (0.03)	$ 0.38	$ 1.33	$ 1.13	$ 2.03	$ 2.80	$ 2.87
Diluted EPS:
Net Income (Loss)	(9,636)	[1]	6,584	30,242	25,568	(651)	8,433	29,684	25,174	52,758	62,640	63,825
Less: Income allocated to participating securities										(245)	(340)	(496)
Net Income Available to Common Shareholders										$ 52,513	$ 62,300	$ 63,329
Weighted Average Shares Outstanding, Basic (in Shares)										25,875	22,262	22,099
Dilutive Effect of Stock Options, Restricted Stock, and Restricted Stock Units										77	78	72
Weighted Average Diluted Shares (in shares)										25,952	22,340	22,171
Diluted Earnings Per Share of Common Stock (in dollars per share)	$ (0.30)	[1]	$ 0.25	$ 1.34	$ 1.14	$ (0.03)	$ 0.38	$ 1.32	$ 1.12	$ 2.02	$ 2.79	$ 2.86
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Outstanding shares excluded from calculation of diluted EPS (in shares)										188	195	203
Antidilutive Stock Options [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Outstanding shares excluded from calculation of diluted EPS (in shares)										0	0	0
Restricted Stock and Stock Units subject to performance and/or market conditions [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Outstanding shares excluded from calculation of diluted EPS (in shares)										188	195	203

[1] All quarters of 2013 reflect transaction costs incurred associated with the acquisition of MGE. The fourth quarter of 2013 includes one month of activity of the operations of MGE, significant transaction costs incurred in the quarter and the interest impact of the debt issued in the quarter. Total impact of all of these during the quarter was a decrease in net income of $5.5 million.

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 4 (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013		Sep. 30, 2012
Pension Plans [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets, beginning of year	$ 274,130		$ 247,959
Actual return on plan assets	3,387		53,220
Employer contributions	27,991		40,013
MGE acquisition	126,958		0
Gross benefits paid	(87,023)	[1]	(67,062)	[1]
Fair value of plan assets, end of year	345,443		274,130
Funded status of plans, end of year	(158,375)		(138,041)
Postretirement Plans [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets, beginning of year	67,442		51,744
Actual return on plan assets	5,660		9,722
Employer contributions	16,596		12,226
MGE acquisition	30,396		0
Gross benefits paid	(8,449)		(6,250)
Fair value of plan assets, end of year	111,645		67,442
Funded status of plans, end of year	$ (68,477)		$ (59,775)

[1] Includes $79,484 and $60,085 lump-sum payments recognized as settlements in fiscal years 2013 and 2012, respectively.

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NOTES PAYABLE AND CREDIT AGREEMENTS

12 Months Ended

Sep. 30, 2013

Short-term Debt [Abstract]

NOTES PAYABLE AND CREDIT AGREEMENTS

NOTES PAYABLE AND CREDIT AGREEMENTS

The Company’s short-term borrowing requirements typically peak during the colder months. These short-term cash requirements can be met through the sale of commercial paper supported by lines of credit with banks or through direct use of the lines of credit. On September 3, 2013, the Utility entered into a new syndicated line of credit for $450 million with nine banks, which will expire in September 2018. The largest portion provided by a single bank is 15.6%. The previous syndicated line of credit agreement was terminated at that time.

The Utility’s line of credit includes a covenant limiting total debt, including short-term debt, to no more than 70% of total capitalization. On September 30, 2013, total debt was 48% of total capitalization.

Information about the Laclede Group’s short-term borrowings (excluding intercompany borrowings) during the 12 months ended September 30, and as of September 30, is presented below for 2013 and 2012:

	Commercial Paper Borrowings
Twelve Months Ended September 30, 2013
Weighted average borrowings outstanding	$34.2 million
Weighted average interest rate	0.3%
Range of borrowings outstanding	$0 – $99.4 million
As of September 30, 2013
Borrowings outstanding at end of period	$74.0 million
Weighted average interest rate	0.3%
Twelve Months Ended September 30, 2012
Weighted average borrowings outstanding	$43.8 million
Weighted average interest rate	0.3%
Range of borrowings outstanding	$0 – $133.5 million
As of September 30, 2012
Borrowings outstanding at end of period	$40.1 million
Weighted average interest rate	0.2%

Short-term cash requirements outside of the Utility have generally been met with internally-generated funds. On September 3, 2013, Laclede Group entered into a new $150 million in a syndicated line of credit, which expires September 2018. The previous syndicated line of credit agreement was terminated at that time. Laclede Group's line of credit has covenants limiting the total debt of the consolidated Laclede Group to no more than 70% of the Company’s total capitalization. This ratio stood at 49% on September 30, 2013. Occasionally, Laclede Group’s lines may be used to provide for the funding needs of various subsidiaries. There were no borrowings under Laclede Group’s lines during fiscal years 2013 and 2012.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Part 4 (Details) (USD $)	12 Months Ended
	Sep. 30, 2013 change	Sep. 30, 2012	Sep. 30, 2011
Off System Sales [Line Items]
Number of PGA Discretionary Changes	3
Months between PGA Discretionary Changes	2 months
Cost savings retention percentage	10.00%
Maximum amount of cost savings allowable	$ 3,000,000.0
Number of Months of the Original Maturity of Debt Instruments Purchased	3 months
Gross Receipts taxes recorded in regulated gas distribution operating revenues	$ 40,800,000	$ 35,900,000	$ 43,500,000
Laclede Gas [Member] | First $2 million [Member]
Off System Sales [Line Items]
Customer Share	100.00%
Company Share	0.00%
Laclede Gas [Member] | Next $2 million [Member]
Off System Sales [Line Items]
Customer Share	80.00%
Company Share	20.00%
Laclede Gas [Member] | Next $2 million [Member]
Off System Sales [Line Items]
Customer Share	75.00%
Company Share	25.00%
Laclede Gas [Member] | Amounts exceeding $6 million [Member]
Off System Sales [Line Items]
Customer Share	70.00%
Company Share	30.00%
Missouri Gas Energy (MGE) [Member] | First $1.2 million [Member]
Off System Sales [Line Items]
Customer Share	85.00%
Company Share	15.00%
Missouri Gas Energy (MGE) [Member] | Next $1.2 million [Member]
Off System Sales [Line Items]
Customer Share	80.00%
Company Share	20.00%
Missouri Gas Energy (MGE) [Member] | Next $1.2 million [Member]
Off System Sales [Line Items]
Customer Share	75.00%
Company Share	25.00%
Missouri Gas Energy (MGE) [Member] | Amounts exceeding $3.6 million [Member]
Off System Sales [Line Items]
Customer Share	70.00%
Company Share	30.00%

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COMMITMENTS AND CONTINGENCIES (Details) (USD $)	12 Months Ended				36 Months Ended			12 Months Ended			0 Months Ended	12 Months Ended
	Sep. 30, 2014	Sep. 30, 2013 site	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2007	Sep. 30, 2005	Nov. 26, 2013 Subsequent Event [Member]	Sep. 30, 2013 Three-year period ending September 30, 2016 [Member]	Sep. 30, 2013 From October 1, 2016 [Member]	Sep. 30, 2013 MF Global Inc [Member]	Jun. 30, 2010 Laclede Gas [Member]	Sep. 30, 2013 Missouri Gas Energy (MGE) [Member]	Sep. 30, 2013 Vehicles and Power Operated Equipment Leases [Member] Laclede Gas [Member]
Commitments [Abstract]
Estimated capital expenditures, next fiscal year		$ 175,000,000
Approximate contract amount of project		1,500,000
Estimated capital expenditures for non-regulated subsidiaries		10,000,000
Minimum total payments required for natural gas contracts		981,000,000
Leases and Guarantees [Abstract]
Additional years available for lease renewal (in years)		5 years
Office headquarters lease rental aggregate expense		1,000,000	900,000	900,000								600,000
Annual minimum rental payments	1,000,000
Minimum rental costs obligations - current fiscal year													2,700,000
Minimum rental costs obligations - due in two years													1,800,000
Minimum rental costs obligations - due in three years													1,000,000
Minimum rental costs obligations - due in four years													400,000
Minimum rental costs obligations - due in five years													100,000
Outstanding mortgage loans incurred in connection with various real estate ventures with general partners		1,600,000
Contingencies and Indemnifications [Abstract]
Number of former manufactured gas plant (MGP) sites in Missouri		3
Number of former manufactured gas plant (MGP) sites in Shrewsbury, Missouri		1
Number of former manufactured gas plant (MGP) sites in the City of St. Louis		2
Minimum cost estimate for a one-time contractual transfer of risk						5,800,000
Maximum cost estimate for a one-time contractual transfer of risk						36,300,000
Original proposed disallowance amount related to recovery of purchased gas costs					6,000,000
Revenue sharing agreements, Company's net margin amount subject to reduced sharing percentage		2,000,000
Revenue sharing agreements, Company's net margin amount subject to reduced sharing percentage, Company's percentage share		15.00%						0.00%	15.00%
Notice of employment related violations issued to company, applicable period											2 years
Amount remaining on deposit with a brokerage firm for Laclede Gas							200,000
Amount remaining on deposit with a brokerage firm for Laclede Energy Resources, Inc.							100,000
Percentage of deposits recovered from bankrupt entity										$ 0.98

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 5 (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Noncurrent liabilities	$ (228,653)	$ (196,558)
Pension Plans [Member]
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Current liabilities	(442)	(468)
Noncurrent liabilities	(157,933)	(137,573)
Total	158,375	138,041
Pre-tax amounts recognized in accumulated other comprehensive income not yet recognized as components of net periodic pension cost consist of:
Net actuarial loss	115,775	136,464
Prior service costs	4,467	5,011
Sub-total	120,242	141,475
Adjustments for amounts included in Regulatory Assets	(116,686)	(137,845)
Total	3,556	3,630
Postretirement Plans [Member]
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]
Noncurrent assets	2,543	0
Current liabilities	(300)	(790)
Noncurrent liabilities	(70,720)	(58,985)
Total	68,477	59,775
Pre-tax amounts recognized in accumulated other comprehensive income not yet recognized as components of net periodic pension cost consist of:
Net actuarial loss	63,573	52,573
Prior service costs	(27)	(24)
Transition obligation	0	93
Sub-total	63,546	52,642
Adjustments for amounts included in Regulatory Assets	(63,546)	(52,642)
Total	$ 0	$ 0

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FAIR VALUE OF FINANCIAL INSTRUMENTS (Tables)

12 Months Ended

Sep. 30, 2013

Fair Value Disclosures [Abstract]

Fair value - financial instruments

The carrying amounts and estimated fair values of financial instruments not measured at fair value on a recurring basis at September 30, 2013 and 2012 are as follows:

					Classification of Estimated Fair Value
(Thousands)	Carrying Amount		Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
As of September 30, 2013
Cash and cash equivalents	$	52,981	$	52,981	$	52,824	$	157	$	—
Short-term debt	74,000		74,000		—		74,000		—
Long-term debt, including current portion	912,712		954,126		—		954,126		—
As of September 30, 2012
Cash and cash equivalents	$	27,457	$	27,457	$	17,380	$	10,077	$	—
Short-term debt	40,100		40,100		—		40,100		—
Long-term debt, including current portion	364,416		452,768		—		452,768		—

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INTERIM FINANCIAL INFORMATION (UNAUDITED) (Unaudited)

12 Months Ended

Sep. 30, 2013

Quarterly Financial Information Disclosure [Abstract]

INTERIM FINANCIAL INFORMATION (UNAUDITED)

INTERIM FINANCIAL INFORMATION (UNAUDITED)

In the opinion of Laclede Group, the quarterly information presented below for fiscal years 2013 and 2012 includes all adjustments (consisting of only normal recurring accruals) necessary for a fair statement of the results of operations for such periods. Variations in consolidated operations reported on a quarterly basis primarily reflect the seasonal nature of the business of the Utility.

(Thousands, Except Per Share Amounts)
Three Months Ended	Dec. 31		March 31		June 30		Sept. 30
Fiscal Year 2013
Total Operating Revenues	$	307,003	$	397,613	$	165,289	$	147,114
Operating Income (Loss)	42,085		51,849		12,282		(9,722		)
Net Income (Loss)	25,568		30,242		6,584		(9,636		)
Basic Earnings (Loss) Per Share of Common Stock	1.14		1.34		0.25		(0.30		)
Diluted Earnings (Loss) Per Share of Common Stock	1.14		1.34		0.25		(0.30		)
Three Months Ended	Dec. 31		March 31		June 30		Sept. 30
Fiscal Year 2012
Total Operating Revenues	$	410,913	$	358,175	$	186,849	$	169,538
Operating Income	43,105		50,583		15,045		1,869
Net Income (Loss)	25,174		29,684		8,433		(651		)
Basic Earnings (Loss) Per Share of Common Stock	1.13		1.33		0.38		(0.03		)
Diluted Earnings (Loss) Per Share of Common Stock	1.12		1.32		0.38		(0.03		)

All quarters of 2013 reflect transaction costs incurred associated with the acquisition of MGE. The fourth quarter of 2013 includes one month of activity of the operations of MGE, significant transaction costs incurred in the quarter and the interest impact of the debt issued in the quarter. Total impact of all of these during the quarter was a decrease in net income of $5.5 million.

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COMMITMENTS AND CONTINGENCIES

12 Months Ended

Sep. 30, 2013

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES

Commitments

The Utility estimates total Utility capital expenditures for fiscal 2014 at approximately $175 million. In fiscal 2011, the Utility initiated a multi-year project to replace its existing customer relationship and work management, financial, and supply chain software applications to enhance its technology, customer service, and business processes. At September 30, 2013, the Company was contractually committed to costs of approximately $1.5 million related to this project.

Fiscal year 2014 capital expenditures for non-regulated subsidiaries will depend on the nature and magnitude of investments with the current estimate at $10 million. There are no material contractual commitments at September 30, 2013 related to these estimated capital expenditures.

The Utility and LER have entered into various contracts, expiring on dates through 2019, for the storage, transportation, and supply of natural gas. Minimum payments required under the contracts in place at September 30, 2013 are estimated at approximately $981 million. The Utility recovers its costs from customers in accordance with the PGA Clause.

Leases and Guarantees

The lease agreement covering the main office space of the Utility extends through February 2015 with the option to renew for five additional years. The aggregate rental expense for fiscal years 2013, 2012, and 2011 was approximately $1.0 million, $0.9 million, and $0.9 million, respectively. The annual minimum rental payment for fiscal year 2014 is anticipated to be approximately $1.0 million through fiscal year 2015. The annual rental amount for the lease agreement covering MGE's main office space is approximately $0.6 million, and the lease term extends through November 30, 2015.

The Utility has entered into various operating lease agreements for the rental of vehicles and power operated equipment. The rental costs will be approximately $2.7 million in fiscal year 2014, $1.8 million in fiscal year 2015, $1.0 million in fiscal year 2016, and $0.4 million in fiscal year 2017, and $0.1 million in fiscal year 2018. The Utility and LER have other relatively minor rental arrangements that provide for minimum rental payments.

A consolidated subsidiary is a general partner in an unconsolidated partnership that invests in real estate partnerships. The subsidiary and third parties are jointly and severally liable for the payment of mortgage loans in the aggregate outstanding amount of approximately $1.6 million incurred in connection with various real estate ventures. Laclede Group has no reason to believe that the other principal liable parties will not be able to meet their proportionate share of these obligations. Laclede Group further believes that the asset values of the real estate properties are sufficient to support these mortgage loans.

Contingencies

The Utility 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’s or the Utility's financial position and results of operations. As environmental laws, regulations, and their interpretations change, however, the Utility may be required to incur additional costs.

Similar to other natural gas utility companies, Laclede Gas Company faces the risk of incurring environmental liabilities. In the natural gas industry, these are typically associated with sites formerly owned or operated by gas distribution companies like Laclede Gas and MGE or its predecessor companies at which manufactured gas operations took place. At this time, Laclede Gas has identified three former manufactured gas plant (MGP) sites where costs have been incurred and claims have been asserted: one in Shrewsbury, Missouri and two in the City of St. Louis, Missouri. Laclede Gas has enrolled the two sites in the City of St. Louis in the Missouri Department of Natural Resources Brownfields/Voluntary Cleanup Program (BVCP). MGE has enrolled all of its owned former manufactured gas plant sites in the BVCP.

With regard to the former MGP site located in Shrewsbury, Missouri, Laclede Gas and state and federal environmental regulators agreed upon certain remedial actions to a portion of the site in a 1999 Administrative Order on Consent (AOC), which actions have been completed. On September 22, 2008, EPA Region VII issued a letter of Termination and Satisfaction terminating the AOC. However, if after this termination of the AOC, regulators require additional remedial actions, or additional claims are asserted, Laclede Gas may incur additional costs.

One of the sites located in the City of St. Louis is currently owned by a development agency of the City, which, together with other City development agencies, has selected a developer to redevelop the site. In conjunction with this redevelopment effort, Laclede Gas and another former owner of the site entered into an agreement (Remediation Agreement) with the City development agencies, the developer, and an environmental consultant that obligates one of the City agencies and the environmental consultant to remediate the site and obtain a No Further Action letter from the Missouri Department of Natural Resources.

The Remediation Agreement also provides for a release of Laclede Gas and the other former site owner from certain liabilities related to the past and current environmental condition of the site and requires the developer and the environmental consultant to maintain certain insurance coverages, including remediation cost containment, premises pollution liability, and professional liability.

The operative provisions of the Remediation Agreement were triggered on December 20, 2010, on which date Laclede Gas and the other former site owner, as full consideration under the Remediation Agreement, paid a small percentage of the cost of remediation of the site. The amount paid by Laclede Gas did not materially impact the financial condition, results of operations, or cash flows of the Company.

Laclede Gas has not owned the other site located in the City of St. Louis for many years. In a letter dated June 29, 2011, the Attorney General for the State of Missouri informed Laclede Gas that the Missouri Department of Natural Resources had completed an investigation of the site. The Attorney General requested that Laclede Gas participate in the follow up investigations of the site. In a letter dated January 10, 2012, Laclede Gas stated that it would participate in future environmental response activities at the site in conjunction with other potentially responsible parties that are willing to contribute to such efforts in a meaningful and equitable fashion. 

To date, amounts required for remediation at these sites have not been material. However, the amount of costs relative to future remedial actions at these and other sites is unknown and may be material. Laclede Gas has notified its insurers that it seeks reimbursement for costs incurred in the past and future potential liabilities associated with the MGP sites. While some of the insurers have denied coverage and reserved their rights, Laclede Gas continues to discuss potential reimbursements with them. In 2005, the Utility’s outside consultant completed an analysis of the MGP sites to determine cost estimates for a one-time contractual transfer of risk from each of the Utility’s insurers of environmental coverage for the MGP sites. That analysis demonstrated a range of possible future expenditures to investigate, monitor, and remediate these MGP sites from $5.8 million to $36.3 million based upon then currently available facts, technology, and laws and regulations. The actual costs that Laclede Gas may incur could be materially higher or lower depending upon several factors, including whether remedial actions will be required, final selection and regulatory approval of any remedial actions, changing technologies and governmental regulations, the ultimate ability of other potentially responsible parties to pay, the successful completion of remediation efforts required by the Remediation Agreement described above, and any insurance recoveries.

MGE has seven owned MGP sites enrolled in the BVCP, including Joplin MGP #1, St. Joseph MGP #1, Kansas City Coal Gas Station B, Kansas City Station A Railroad, Kansas City Coal Gas Station A North, Kansas City Coal Gas Station A South, and Independence MGP #2. The Missouri Department of Natural Resources awarded a Certificate of Completion to Missouri Gas Energy in 2001 for a site located at 20th and Indiana in Kansas City after an initial site analysis and the property was subsequently sold. Source removal has been conducted at all of the owned sites since 2003 with the exception of Joplin, which is in the early stages of site analysis and characterization. Remediation efforts at these sites are at various stages of completion, ranging from groundwater monitoring and sampling following source removal activities to early site characterization in Joplin. As part of its participation in the BVCP, MGE communicates regularly with the Missouri Department of Natural Resources with respect to its remediation efforts and monitoring activities at these sites.

Costs associated with environmental remediation activities are accrued when such costs are probable and reasonably estimable. The Utility anticipates that any costs it may incur in the future to remediate these sites, less any amounts received as insurance proceeds or as contributions from other potentially responsible parties, would be deferred and recovered in rates through periodic adjustments approved by the MoPSC. Accordingly, any potential liabilities that may arise associated with remediating these sites are not expected to have a material impact on the future financial position and results of operations of the Utility or the Company.

The MoPSC Staff proposed disallowances related to Laclede Gas' recovery of its gas costs totaling $6.0 million pertaining to Laclede Gas' purchase of gas from a marketing affiliate, LER, applicable to fiscal years 2005 through 2007. The MoPSC staff also proposed a number of non-monetary recommendations, based on its review of gas costs for fiscal years 2008 through 2011. In a related matter, on October 6, 2010, the MoPSC Staff filed a complaint against Laclede Gas alleging that Laclede Gas' affiliate transactions and its Cost Allocation Manual (CAM) violated the MoPSC's affiliate transaction rules. Laclede Gas responded with a counterclaim that the MoPSC Staff had failed to adhere to the affiliate transaction rules and the Company's CAM. On July 16, 2013, Laclede Gas, the MoPSC Staff and the Office of the Public Counsel requested MoPSC approval of a unanimous stipulation and agreement resolving the affiliate transaction matters for fiscal years 2005 through 2011, resolving the October 6, 2010 complaint, resolving Laclede Gas' counterclaim, presenting a revised CAM for MoPSC approval, and establishing standards of conduct for gas purchases and sales. While the PSC Staff's disallowances were withdrawn as part of the stipulation, Laclede Gas agreed to a minor adjustment to the off-system sales and capacity release sharing mechanism.

For a three-year period ending September 30, 2016, Laclede Gas' share of the first $2 million in net margin is reduced from 15% to 0%. None of the other sharing percentages are affected, and beginning October 1, 2016, Laclede's sharing percentage of the first $2 million in net margins returns to 15%. The Stipulation and agreement was approved by the MoPSC in an order issued on August 14, 2013.

On July 7, 2010, the MoPSC Staff filed a complaint against Laclede Gas alleging that, by stating that it was not in possession of proprietary LER documents, Laclede Gas violated the MoPSC Order authorizing the holding company structure (2001 Order). Laclede Gas counterclaimed stating the Staff failed to adhere to pricing provisions of the MoPSC's affiliate transaction rules and Laclede Gas' Cost Allocation Manual. By orders dated November 3, 2010 and February4,2011, respectively, the MoPSC dismissed Laclede's counterclaim and granted summary judgment to Staff, finding that Laclede Gas violated the terms of the 2001 Order and authorizing its General Counsel to seek penalties in court against Laclede Gas. On May 19, 2011, the MoPSC's General Counsel filed a petition seeking penalties against Laclede Gas for violation of the 2001 Order. The MoPSC and Laclede Gas agreed to hold the penalty case in abeyance pending the outcome of Laclede's appeal of the November 3, 2010 and February 4, 2011 orders. These Orders were reversed by the Cole County Circuit Court, but later upheld by the Western District Court of Appeals. On March 19, 2013, the Missouri Supreme Court declined Laclede Gas' request to review the opinion of the Western District Court of Appeals. As a result, Laclede Gas produced certain LER documentation that had been requested by the MoPSC Staff and, pursuant to agreement between the MoPSC and Laclede Gas, the MoPSC’s May 2011 penalty case was dismissed.

On June 29, 2010, the Office of Federal Contract Compliance Programs (OFCCP) issued a Notice of Violations to Laclede Gas alleging lapses in certain employment selection procedures during a two-year period ending in February 2006. On July 2, 2013, Laclede Gas executed a Conciliation Agreement with the OFCCP in which the Company did not admit to liability, but agreed to provide make whole relief of back pay and interest to the impacted individuals from 2004-2006. The Company's agreement to provide make whole relief will not have a material effect on the consolidated financial position and results of operations, or cash flows of the Company.

As discussed in Note 11, Derivative Instruments and Hedging Activities, Laclede Gas and LER enter into NYMEX and ICE exchange-traded/cleared derivative instruments. Previously, these instruments were held in accounts at MF Global, Inc. On October 31, 2011, affiliated entities of MF Global filed a Chapter 11 petition at the U.S. Bankruptcy Court in the Southern District of New York. Subsequently, the court-appointed bankruptcy trustee transferred all of the open positions and a significant portion of the margin deposits of Laclede Gas and LER to a new brokerage firm. On June 27, 2013, the bankruptcy Trustee issued a statement projecting that MF Global customers would receive a full payout of their claims. As of November 26, 2013, Laclede Gas and LER had $0.2 million and $0.1 million, respectively, on deposit with MF Global that remain unavailable pending final resolution by the bankruptcy trustee. As the Company has recovered 98% of the amount at issue in the MF Global bankruptcy, the total remaining exposure is not considered material.

On February 19, 2013, Heartland Midwest, LLC, a contractor for Time Warner Cable, hit a MGE natural gas line causing a gas leak while directionally boring during underground cable installation. The natural gas leak resulted in an explosion and fire which killed one person, injured approximately seventeen (including three MGE employees who were at the scene), caused major damage to JJ's restaurant, and caused property damage to adjacent buildings. Several lawsuits have been filed in state court in Jackson County, Missouri, alleging wrongful death, personal injury, property damage, and business interruption. The lawsuits are in the early stages of discovery. While the Company's total exposure is not considered material at this time, management plans to vigorously defend the matter and will continue to evaluate its exposure as discovery proceeds. Management believes, after discussion with counsel, that the final outcome of this matter will not have a material effect on the consolidated financial position, results of operations, or cash flows of the Company.

Laclede Group is involved in other litigation, claims, and investigations arising in the normal course of business. Management, after discussion with counsel, believes that the final outcome will not have a material effect on the consolidated financial position, results of operations, or cash flows of the Company.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Part 2 (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Asset retirement obligations [Roll forward]
Asset retirement obligations, beginning of year	$ 40,368	$ 27,495
Liabilities incurred during the period	801	851
Liabilities settled during the period	(1,089)	(601)
Accretion	2,322	1,637
Revisions in estimated cash flows	0	10,986
Addition of MGE asset retirement obligation	32,152	0
Asset retirement obligations, end of year	$ 74,554	$ 40,368

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EARNINGS PER COMMON SHARE (Tables)

12 Months Ended

Sep. 30, 2013

Earnings Per Share [Abstract]

Earnings Per Common Share

(Thousands, Except Per Share Amounts)	2013		2012		2011
Basic EPS:
Net Income	$	52,758	$	62,640	$	63,825
Less: Income allocated to participating securities	245		340		497
Net Income Available  to Common Shareholders	$	52,513	$	62,300	$	63,328
Weighted Average Shares Outstanding	25,875		22,262		22,099
Earnings Per Share of Common Stock	$	2.03	$	2.80	$	2.87
Diluted EPS:
Net Income	$	52,758	$	62,640	$	63,825
Less: Income allocated to participating securities	245		340		496
Net Income Available to Common Shareholders	$	52,513	$	62,300	$	63,329
Weighted Average Shares Outstanding	25,875		22,262		22,099
Dilutive Effect of Stock Options, Restricted Stock, and Restricted Stock Units	77		78		72
Weighted Average Diluted Shares	25,952		22,340		22,171
Earnings Per Share of Common Stock	$	2.02	$	2.79	$	2.86
Outstanding Shares Excluded from the Calculation of Diluted EPS Attributable to:
Antidilutive stock options	—		—		—
Restricted stock and stock units subject to performance and/or market conditions	188		195		203
Total	188		195		203

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)

12 Months Ended

Sep. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities

The Company’s exchange-traded/cleared derivative instruments consist primarily of NYMEX and ICE positions. The NYMEX is the primary national commodities exchange on which natural gas derivatives are traded. Open NYMEX/ICE and OTCBB natural gas futures and swap positions at September 30, 2013 were as follows:

	Laclede Gas Company			Laclede Energy Resources, Inc.
	MMBtu (millions)	Avg. Price Per MMBtu		MMBtu (millions)	Avg. Price Per MMBtu
NYMEX/ICE open short futures/swap positions
Fiscal 2014	—	$	—	12.91	$	3.98
Fiscal 2015	—	—		0.06	4.21
NYMEX/ICE open long futures/swap positions
Fiscal 2014	7.26	$	3.99	1.71	$	3.94
Fiscal 2015	0.94	3.84		0.19	4.06
Fiscal 2016	—	—		0.02	4.15
OTCBB open long futures
Fiscal 2014	16.81	$	3.97	—	$	—
Fiscal 2015	7.58	4.22		—	—

The Effect of Derivative Instruments on the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income

The Effect of Derivative Instruments on the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income
	Location of Gain (Loss)
(Thousands)	Recorded in Income	2013			2012			2011
Derivatives in Cash Flow Hedging Relationships
Effective portion of gain (loss) recognized in OCI on derivatives:
NYMEX/ICE natural gas contracts		$	4,923		$	4,505		$	5,226
NYMEX gasoline and heating oil contracts		123			297			355
Total		$	5,046		$	4,802		$	5,581
Effective portion of gain (loss) reclassified from AOCI to income:
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	$	(4	)	$	18,929		$	7,443
	Gas Marketing Operating Expenses	(509		)	(10,532		)	(9,770		)
Sub-total		$	(513	)	$	8,397		$	(2,327	)
NYMEX gasoline and heating oil contracts	Gas Utility Other Operation Expenses	211			—			466
Total		$	(302	)	$	8,397		$	(1,861	)
Ineffective portion of gain (loss) on derivatives     recognized in income:
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	$	(420	)	$	(36	)	$	966
	Gas Marketing Operating Expenses	(239		)	(263		)	(1,322		)
Sub-total		$	(659	)	$	(299	)	$	(356	)
NYMEX gasoline and heating oil contracts	Gas Utility Other Operation Expenses	(127		)	175			12
Total		$	(786	)	$	(124	)	$	(344	)
Derivatives Not Designated as Hedging Instruments*
Gain (loss) recognized in income on derivatives:
Natural gas commodity contracts	Gas Marketing Operating Revenues	$	(78	)	$	3,782		$	(660	)
	Gas Marketing Operating Expenses	—			687			4,229
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	(778		)	(615		)	(115		)
	Gas Marketing Operating Expenses	—			(625		)	(3		)
NYMEX gasoline and heating oil contracts	Other Income and (Income Deductions) - Net	41			19			37
Total		$	(815	)	$	3,248		$	3,488

* Gains and losses on the Utility’s natural gas derivative instruments, which are not designated as hedging instruments for financial reporting purposes, are deferred pursuant to the Utility’s PGA Clause and initially recorded as regulatory assets or regulatory liabilities. These gains and losses are excluded from the table above because they have no direct impact on the Statements of Consolidated Income. Such amounts are recognized in the Statements of Consolidated Income as a component of Regulated Gas Distribution Natural and Propane Gas operating expenses when they are recovered through the PGA Clause and reflected in customer billings.

Fair Value of Derivative Instruments in the Consolidated Balance Sheet

Fair Value of Derivative Instruments in the Consolidated Balance Sheet at September 30, 2013
	Asset Derivatives*				Liability Derivatives*
(Thousands)	Balance Sheet Location	Fair Value			Balance Sheet Location	Fair  Value
Derivatives designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets	$	2,222		Derivative Instrument Assets	$	440
	Other Deferred Charges	22			Other Deferred Charges	11
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	105			Accounts Receivable - Other	—
Sub-total		2,349				451
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets	950			Derivative Instrument Assets	100
	Accounts Receivable - Other	1,434			Accounts Receivable - Other	3,455
	Other Deferred Charges	32			Other Deferred Charges	—
OTCBB natural gas contracts	Other Current Liabilities	228			Other Current Liabilities	4,045
	Other Deferred Credits	4			Other Deferred Credits	1,398
Natural gas commodity contracts	Derivative Instrument Assets	991			Derivative Instrument Assets	90
	Other Deferred Charges	20			Other Deferred Charges	137
	Other Current Liabilities	247			Other Current Liabilities	830
	Other Deferred Credits	21			Other Deferred Credits	123
Sub-total		3,927				10,178
Total derivatives		$	6,276			$	10,629
Fair Value of Derivative Instruments in the Consolidated Balance Sheet at September 30, 2012
	Asset Derivatives				Liability Derivatives
(Thousands)	Balance Sheet Location	Fair Value		*	Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments
NYMEX/ICE natural gas contracts	Accounts Receivable - Other	$	405		Accounts Receivable - Other	$	3,413
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	334			Accounts Receivable - Other	—
Sub-total		739				3,413
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Accounts Receivable - Other	8,000			Accounts Receivable - Other	10,731
	Other Deferred Charges	—			Other Deferred Charges	—
Natural gas commodity contracts	Derivative Instrument Assets	3,150			Derivative Instrument Assets	295
	Other Current Liabilities	4			Other Current Liabilities	137
	Other Deferred Charges	19			Other Deferred Charges	—
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	10			Accounts Receivable - Other	—
Sub-total		11,183				11,163
Total derivatives		$	11,922			$	14,576

* The fair values of Asset Derivatives and Liability Derivatives exclude the fair value of cash margin receivables or payables with counterparties subject to netting arrangements. Fair value amounts of derivative contracts (including the fair value amounts of cash margin receivables and payables) for which there is a legal right to set off are presented net on the Consolidated Balance Sheets. As such, the gross balances presented in the table above are not indicative of the Company’s net economic exposure. Refer to Note 10, Fair Value Measurements, for information on the valuation of derivative instruments.

Derivative instrument Reconciliation

Following is a reconciliation of the amounts in the tables above to the amounts presented in the Consolidated Balance Sheets:

(Thousands)	2013			2012
Fair value of asset derivatives presented above	6,276			11,922
Fair value of cash margin receivables offset with derivatives	1,765			5,478
Netting of assets and liabilities with the same counterparty	(4,739		)	(14,526		)
Total	3,302			2,874
Derivative Instrument Assets, per Consolidated Balance Sheets:
Derivative instrument assets	3,291			2,855
Other deferred charges	11			19
Total	3,302			2,874
Fair value of liability derivatives presented above	10,629			14,576
Fair value of cash margin payables offset with derivatives	6			83
Netting of assets and liabilities with the same counterparty	(4,739		)	(14,526		)
Derivative instrument liabilities, per Consolidated Balance Sheets	5,896			133
Derivative Instrument Liabilities, per Consolidated Balance Sheets:
Other current liabilities	$	4,400		$	133
Other deferred credits	1,496			—
Total	$	5,896		$	133

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ACQUISITION OF MGE Part 1 - Narrative (Details) (USD $)	12 Months Ended					0 Months Ended			0 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2013 Other Operating Expense [Member]	Sep. 30, 2013 Interest on Long-term Debt [Member]	Aug. 13, 2013 Laclede Gas [Member]	Sep. 01, 2013 Missouri Gas Energy (MGE) [Member]	Sep. 01, 2013 Missouri Gas Energy (MGE) [Member] Gas Utility [Member]	May 29, 2013 Missouri Gas Energy (MGE) [Member] Common Stock Issued	Aug. 13, 2013 Missouri Gas Energy (MGE) [Member] Laclede Gas [Member]
Business Acquisition [Line Items]
Acquisition purchase price	$ 975,000,000	$ 0	$ 0				$ 975,000,000
Stock issued to finance acquisition									10,000,000
First mortgage bonds issued to finance acquisition	550,000,000	0	0			450,000,000				450,000,000
Goodwill	247,078,000	0					247,078,000	247,100,000
Merger-related transaction costs	$ 17,000,000	$ 200,000		$ 15,100,000	$ 1,900,000

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ACQUISITION OF MGE (Tables)

12 Months Ended

Sep. 30, 2013

Business Acquisition [Line Items]

Schedule of Pro Forma Information

The amount of revenue and earnings of MGE included in our Statements of Consolidated Income subsequent to the September 1, 2013 acquisition date are as follows:

(Thousands, Except Per Share Amounts)	September 1, 2013 - September 30, 2013
Total net revenues	$	21,985
Net Income	1,795
Earnings/(loss) per share:
Basic	$	0.07
Diluted	$	0.07

The following unaudited pro forma financial information presents the combined results of operations as if the acquisition had occurred on October 1, 2011. The pro forma financial information does not reflect the costs of any integration activities. The pro forma results include estimates and assumptions, which management believes are reasonable. The unaudited pro forma financial information below is not necessarily indicative of either future results of operations or results that might have been achieved had MGE been part of the Utility as of the beginning of fiscal year 2012.

	Twelve Months Ended September 30,
(Thousands, Except Per Share Amounts)	2013		2012
Total net revenues	$	1,518,201	$	1,581,425
Net Income	83,642		81,722
Earnings per share:
Basic	$	2.57	$	2.52
Diluted	$	2.56	$	2.51

Missouri Gas Energy (MGE) [Member]

Business Acquisition [Line Items]

Schedule of preliminary fair value of assets acquired and liabilities assumed

The following table summarizes the preliminary fair value of assets acquired and liabilities assumed at the date of the acquisition:

(Thousands)
Assets:
Utility plant	$	671,793
Non-utility property	238
Other investments	3,096
Goodwill	247,078
Other Property and Investments	922,205
Accounts receivable:
Utility	19,963
Other	6,119
Delayed customer billings	10,701
Inventories:
Natural gas stored underground	58,679
Materials and supplies at average cost	3,988
Prepayments and other	487
Total Current Assets	99,937
Deferred Charges:
Regulatory assets	84,014
Other	4,928
Total Deferred Charges	88,942
Total Assets Acquired	$	1,111,084
Liabilities:
Accounts payable	$	20,154
Wages and compensation accrued	5,088
Customer deposits	8,362
Interest accrued	183
Taxes accrued	17,197
Other	12,620
Total Current Liabilities	63,604
Pension and postretirement benefit costs	24,466
Asset retirement obligations	32,056
Regulatory liabilities	2,249
Other	13,709
Total Deferred Credits and Other Liabilities	72,480
Total Liabilities Assumed	$	136,084
Net Assets Acquired	$	975,000

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 12 (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2011
Pension Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	$ 345,443		$ 274,130		$ 247,959
Derivative Assets, fair value measurements	4,186		3,027
Cash margin payable	5,480		2,750
Pension Plans [Member] | Cash and cash equivalents [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	18,177		57,614
Pension Plans [Member] | Stock/Bond mutual fund [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	115,817
Pension Plans [Member] | U.S. bond mutual funds [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	17,682		36,767
Pension Plans [Member] | U.S. government [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	55,743		57,925
Pension Plans [Member] | U.S. corporate [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	110,925		93,169
Pension Plans [Member] | U.S. municipal [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	6,799		9,493
Pension Plans [Member] | International [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	21,594		18,885
Pension Plans [Member] | Derivative instrument [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	(1,294)	[1]	277	[2]
Pension Plans [Member] | Quoted Prices in Active Markets (Level 1) [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	35,859		94,381
Pension Plans [Member] | Quoted Prices in Active Markets (Level 1) [Member] | Cash and cash equivalents [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	18,177		57,614
Pension Plans [Member] | Quoted Prices in Active Markets (Level 1) [Member] | U.S. bond mutual funds [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	17,682		36,767
Pension Plans [Member] | Significant Observable Inputs (Level 2) [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	309,584		179,749
Pension Plans [Member] | Significant Observable Inputs (Level 2) [Member] | Stock/Bond mutual fund [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	115,817
Pension Plans [Member] | Significant Observable Inputs (Level 2) [Member] | U.S. government [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	55,743		57,925
Pension Plans [Member] | Significant Observable Inputs (Level 2) [Member] | U.S. corporate [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	110,925		93,169
Pension Plans [Member] | Significant Observable Inputs (Level 2) [Member] | U.S. municipal [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	6,799		9,493
Pension Plans [Member] | Significant Observable Inputs (Level 2) [Member] | International [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	21,594		18,885
Pension Plans [Member] | Significant Observable Inputs (Level 2) [Member] | Derivative instrument [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	(1,294)	[1]	277	[2]
Postretirement Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	111,645		67,442		51,744
Postretirement Plans [Member] | Cash and cash equivalents [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	1,411		1,106
Postretirement Plans [Member] | Stock/Bond mutual fund [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	110,234		66,336
Postretirement Plans [Member] | Quoted Prices in Active Markets (Level 1) [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	111,645		67,442
Postretirement Plans [Member] | Quoted Prices in Active Markets (Level 1) [Member] | Cash and cash equivalents [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	1,411		1,106
Postretirement Plans [Member] | Quoted Prices in Active Markets (Level 1) [Member] | Stock/Bond mutual fund [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Fair value measurements of plan assets	$ 110,234		$ 66,336

[1] Derivative assets of $4,186 net of cash margin payable of $5,480.

[2] Derivative assets of $3,027 net of cash margin payable of $2,750.

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FAIR VALUE OF FINANCIAL INSTRUMENTS (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2010
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	$ 52,981	$ 27,457	$ 43,277	$ 86,919
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	52,981	27,457
Short-term debt	74,000	40,100
Long-term debt, including current portion	912,712	364,416
Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	52,981	27,457
Short-term debt	74,000	40,100
Long-term debt, including current portion	954,126	452,768
Quoted Prices in Active Markets (Level 1) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	52,824	17,380
Short-term debt	0	0
Long-term debt, including current portion	0	0
Significant Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	157	10,077
Short-term debt	74,000	40,100
Long-term debt, including current portion	954,126	452,768
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	0	0
Short-term debt	0	0
Long-term debt, including current portion	$ 0	$ 0

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 11 (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Medical cost trend assumed for next year	7.50%	7.00%
Rate to which the medical cost trend rate is assumed to decline (the ultimate medical cost trend rate)	5.00%	5.00%
Year the rate reaches the ultimate trend	2020	2017
Assumed 1% change in the assumed medical cost trend rate [Abstract]
Effect of 1% increase on net periodic postretirement benefit cost	$ 1,520
Effect of 1% decrease on net periodic postretirement benefit cost	(1,390)
Effect of 1% increase on accumulated postretirement benefit obligation	7,060
Effect of 1% decrease on accumulated postretirement benefit obligation	$ (6,580)

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INFORMATION BY OPERATING SEGMENT (Tables)

12 Months Ended

Sep. 30, 2013

Segment Reporting [Abstract]

Schedule of operating segment information

	Gas Utility		Gas Marketing			Other				Eliminations			Consolidated
(Thousands)
Fiscal 2013
Revenues from external customers	$	847,224	$	165,146		$	4,649			$	—		$	1,017,019
Intersegment revenues	10,538		24,185			1,625				(36,348		)	—
Total Operating Revenues	857,762		189,331			6,274				(36,348		)	1,017,019
Operating Expenses
Gas Utility
Natural and Propane Gas	469,098		—			—				(35,656		)	433,442
Other Operation and Maintenance	180,702		—			—				(360		)	180,342
Depreciation and Amortization	48,283		—			—				—			48,283
Taxes, Other than Income Taxes	60,079		—			—				—			60,079
Total Gas Utility Operating Expenses	758,162		—			—				(36,016		)	722,146
Gas Marketing	—		176,554		(a)	—				—			176,554
Other	—		—			22,157			(b)	(332		)	21,825
Total Operating Expenses	758,162		176,554			22,157				(36,348		)	920,525
Operating Income	99,599		12,777			(15,882		)		—			96,494
Interest income	947		103			343				(305		)	1,088
Interest charges	26,137		135			2,635				(305		)	28,602
Income tax expense	19,243		5,162			(6,827		)		—			17,578
Net economic earnings	56,635		8,936			(559		)		—			65,012
Total assets	2,981,016		163,944			115,560				(135,134		)	3,125,386
Capital expenditures	128,496		44			2,248				—			130,788
Fiscal 2012
Revenues from external customers	$	763,447	$	358,145		$	3,883			$	—		$	1,125,475
Intersegment revenues	1,204		15,330			1,042				(17,576		)	—
Total Operating Revenues	764,651		373,475			4,925				(17,576		)	1,125,475
Operating Expenses
Gas Utility
Natural and Propane Gas	414,846		—			—				(17,542		)	397,304
Other Operation and Maintenance	167,351		—			—				—			167,351
Depreciation and Amortization	40,739		—			—				—			40,739
Taxes, Other than Income Taxes	53,672		—			—				—			$	53,672
Total Gas Utility Operating Expenses	676,608		—			—				(17,542		)	659,066
Gas Marketing	—		353,286		(a)	—				(3		)	353,283
Other	—		—			2,555			(b)	(31		)	2,524
Total Operating Expenses	676,608		353,286			2,555				(17,576		)	1,014,873
Operating Income	88,043		20,189			2,370				—			110,602
Interest income	1,230		175			371				(467		)	1,309
Interest charges	25,156		81			175				(467		)	24,945
Income tax expense	17,393		7,966			930				—			26,289
Net economic earnings	48,089		12,273			2,250				—			62,612
Total assets	1,758,952		190,709			102,241				(171,640		)	1,880,262
Capital expenditures	106,734		140			1,969				—			108,843

Fiscal 2011
Revenues from external customers	$	911,614	$	645,042		$	19,704		$	—		1,576,360
Intersegment revenues	1,576		24,333			1,038			—			26,947
Total Operating Revenues	913,190		669,375			20,742			—			1,603,307
Operating Expenses
Gas Utility
Natural and Propane Gas	549,947		—			—			—			549,947
Other Operation and Maintenance	172,938		—			—			—			172,938
Depreciation and Amortization	39,214		—			—			—			$	39,214
Taxes, Other than Income Taxes	60,752		—			—			—			60,752
Total Gas Utility Operating Expenses	822,851		—			—			—			$	822,851
Gas Marketing	—		652,567		(a)	—			—			652,567
Other	—		—			9,642		(b)	—			9,642
Total Operating Expenses	822,851		652,567			9,642			—			1,485,060
Operating Income	90,339		16,808			11,100			—			118,247
Interest income	1,057		165			217			(303		)	1,136
Interest charges	25,544		14			162			(303		)	25,417
Income tax expense	18,694		6,570			3,918			—			29,182
Net economic earnings	46,952		8,962			6,496		(c)	—			62,410
Total assets	1,641,386		175,352			129,176			(162,832		)	1,783,082
Capital expenditures	67,304		215			119			—			67,638

(a) Depreciation and amortization for Gas Marketing is included in Gas Marketing Expenses on the Statements of Consolidated Income ($0.3 million for fiscal year 2013, $0.3 million for fiscal year 2012, and $0.1 million for fiscal year 2011).

(b) Depreciation, amortization, and accretion for Other is included in the Other Operating Expenses on the Statements of Consolidated Income ($0.6 million for fiscal year 2013, $0.3 million for fiscal year 2012 and $0.2 million for fiscal year 2011).

(c) Net economic earnings include income realized by the Utility from separate non-regulated sales of propane inventory no longer needed to serve utility customers, of which occurred in fiscal year 2011. This transaction resulted in after-tax earnings totaling $6.1 million.

Schedule of the reconciliation of consolidated net economic earnings to consolidated net income

Reconciliation of Consolidated Net Income to Consolidated Net Economic Earnings
(Thousands)	2013			2012			2011
Net Income (GAAP)	$	52,758		$	62,640		$	63,825
Unrealized loss (gain) on energy-related      derivatives	614			(314		)	(1,415		)
Lower of cost or market inventory adjustments	868			—			—
Realized (gain) loss on economic hedges prior      to the sale of the physical commodity	(25		)	163			—
Acquisition, divestiture and restructuring activities	10,797			123			—
Net Economic Earnings (Non-GAAP)	$	65,012		$	62,612		$	62,410

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LONG-TERM DEBT Part 1 - Maturities of Long-term Debt (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013
Maturities on long-term debt [Abstract]
2014	$ 0
2015	0
2016	0
2017	0
2018	$ 100

XML

INFORMATION BY OPERATING SEGMENT

12 Months Ended

Sep. 30, 2013

Segment Reporting [Abstract]

INFORMATION BY OPERATING SEGMENT

INFORMATION BY OPERATING SEGMENT

All of Laclede Group’s subsidiaries are wholly owned. In the first quarter of fiscal year 2013, the Company retitled its segment names. The Gas Utility segment, previously titled Regulated Gas Distribution, consists of the regulated operations of the Utility and is the core business segment of Laclede Group. The Utility is a public utility engaged in the retail distribution and sale of natural gas serving an area in eastern Missouri, including the City of St. Louis, through Laclede Gas and an area in western Missouri, including Kansas City, through MGE. The Gas Marketing segment, previously titled Non-Regulated Gas Marketing, includes the results of LER, a subsidiary engaged in the non-regulated marketing of natural gas and related activities, and LER Storage Services, Inc., which became operational in January 2012 and utilizes natural gas storage contracts for providing natural gas sales. Other includes Laclede Pipeline Company’s transportation of liquid propane regulated by the Federal Energy Regulatory Commission (FERC) as well as non-regulated activities, including, among other activities, real estate development, the compression of natural gas, and financial investments in other enterprises. These operations are conducted through seven subsidiaries. Other also includes the Utility’s non-regulated business activities, which are comprised of its propane storage and related services. Beginning July 1, 2013, propane-related services were included within Gas Utility operations pursuant to Laclede Gas' most recent rate case. Accounting policies are described in Note 1, Summary of Significant Accounting Policies. Intersegment transactions include sales of natural gas from the Utility to LER, propane storage services provided by the Utility to Laclede Pipeline Company, sales of natural gas from LER to the Utility, and propane transportation services provided by Laclede Pipeline Company to the Utility.

Management evaluates the performance of the operating segments based on the computation of net economic earnings. Net economic earnings exclude from reported net income the after-tax impacts of net unrealized gains and losses and other timing differences associated with energy-related transactions. Net economic earnings also excludes the after-tax impacts related to acquisition, divestiture, and restructuring activities.

	Gas Utility		Gas Marketing			Other				Eliminations			Consolidated
(Thousands)
Fiscal 2013
Revenues from external customers	$	847,224	$	165,146		$	4,649			$	—		$	1,017,019
Intersegment revenues	10,538		24,185			1,625				(36,348		)	—
Total Operating Revenues	857,762		189,331			6,274				(36,348		)	1,017,019
Operating Expenses
Gas Utility
Natural and Propane Gas	469,098		—			—				(35,656		)	433,442
Other Operation and Maintenance	180,702		—			—				(360		)	180,342
Depreciation and Amortization	48,283		—			—				—			48,283
Taxes, Other than Income Taxes	60,079		—			—				—			60,079
Total Gas Utility Operating Expenses	758,162		—			—				(36,016		)	722,146
Gas Marketing	—		176,554		(a)	—				—			176,554
Other	—		—			22,157			(b)	(332		)	21,825
Total Operating Expenses	758,162		176,554			22,157				(36,348		)	920,525
Operating Income	99,599		12,777			(15,882		)		—			96,494
Interest income	947		103			343				(305		)	1,088
Interest charges	26,137		135			2,635				(305		)	28,602
Income tax expense	19,243		5,162			(6,827		)		—			17,578
Net economic earnings	56,635		8,936			(559		)		—			65,012
Total assets	2,981,016		163,944			115,560				(135,134		)	3,125,386
Capital expenditures	128,496		44			2,248				—			130,788
Fiscal 2012
Revenues from external customers	$	763,447	$	358,145		$	3,883			$	—		$	1,125,475
Intersegment revenues	1,204		15,330			1,042				(17,576		)	—
Total Operating Revenues	764,651		373,475			4,925				(17,576		)	1,125,475
Operating Expenses
Gas Utility
Natural and Propane Gas	414,846		—			—				(17,542		)	397,304
Other Operation and Maintenance	167,351		—			—				—			167,351
Depreciation and Amortization	40,739		—			—				—			40,739
Taxes, Other than Income Taxes	53,672		—			—				—			$	53,672
Total Gas Utility Operating Expenses	676,608		—			—				(17,542		)	659,066
Gas Marketing	—		353,286		(a)	—				(3		)	353,283
Other	—		—			2,555			(b)	(31		)	2,524
Total Operating Expenses	676,608		353,286			2,555				(17,576		)	1,014,873
Operating Income	88,043		20,189			2,370				—			110,602
Interest income	1,230		175			371				(467		)	1,309
Interest charges	25,156		81			175				(467		)	24,945
Income tax expense	17,393		7,966			930				—			26,289
Net economic earnings	48,089		12,273			2,250				—			62,612
Total assets	1,758,952		190,709			102,241				(171,640		)	1,880,262
Capital expenditures	106,734		140			1,969				—			108,843

Fiscal 2011
Revenues from external customers	$	911,614	$	645,042		$	19,704		$	—		1,576,360
Intersegment revenues	1,576		24,333			1,038			—			26,947
Total Operating Revenues	913,190		669,375			20,742			—			1,603,307
Operating Expenses
Gas Utility
Natural and Propane Gas	549,947		—			—			—			549,947
Other Operation and Maintenance	172,938		—			—			—			172,938
Depreciation and Amortization	39,214		—			—			—			$	39,214
Taxes, Other than Income Taxes	60,752		—			—			—			60,752
Total Gas Utility Operating Expenses	822,851		—			—			—			$	822,851
Gas Marketing	—		652,567		(a)	—			—			652,567
Other	—		—			9,642		(b)	—			9,642
Total Operating Expenses	822,851		652,567			9,642			—			1,485,060
Operating Income	90,339		16,808			11,100			—			118,247
Interest income	1,057		165			217			(303		)	1,136
Interest charges	25,544		14			162			(303		)	25,417
Income tax expense	18,694		6,570			3,918			—			29,182
Net economic earnings	46,952		8,962			6,496		(c)	—			62,410
Total assets	1,641,386		175,352			129,176			(162,832		)	1,783,082
Capital expenditures	67,304		215			119			—			67,638

(a) Depreciation and amortization for Gas Marketing is included in Gas Marketing Expenses on the Statements of Consolidated Income ($0.3 million for fiscal year 2013, $0.3 million for fiscal year 2012, and $0.1 million for fiscal year 2011).

(b) Depreciation, amortization, and accretion for Other is included in the Other Operating Expenses on the Statements of Consolidated Income ($0.6 million for fiscal year 2013, $0.3 million for fiscal year 2012 and $0.2 million for fiscal year 2011).

(c) Net economic earnings include income realized by the Utility from separate non-regulated sales of propane inventory no longer needed to serve utility customers, of which occurred in fiscal year 2011. This transaction resulted in after-tax earnings totaling $6.1 million.

Reconciliation of Consolidated Net Income to Consolidated Net Economic Earnings
(Thousands)	2013			2012			2011
Net Income (GAAP)	$	52,758		$	62,640		$	63,825
Unrealized loss (gain) on energy-related      derivatives	614			(314		)	(1,415		)
Lower of cost or market inventory adjustments	868			—			—
Realized (gain) loss on economic hedges prior      to the sale of the physical commodity	(25		)	163			—
Acquisition, divestiture and restructuring activities	10,797			123			—
Net Economic Earnings (Non-GAAP)	$	65,012		$	62,612		$	62,410

XML

STATEMENT OF CONSOLIDATED CAPITALIZATION (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Common Stock Equity:
Common stock, par value $1 per share: Authorized - 2013 and 2012, 70,000,000 shares Issued - 2013, 32,696,836 shares; and 2012, 22,539,431 shares	$ 32,697	$ 22,539
Paid-in capital	594,269	168,607
Retained earnings	420,103	414,581
Accumulated other comprehensive loss	(787)	(4,116)
Total Common Stock Equity	1,046,282	601,611
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	915,000	340,000
Unamortized discount, net of premium, on long-term debt	(2,288)	(584)
Total Long-Term Debt - Laclede Gas	912,712	339,416
Total Capitalization	1,958,994	941,027
Laclede Group [Member] | 3.31% Notes Payable, due December 15, 2022 [Member]
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	25,000	0
Laclede Gas [Member] | First Mortage Bonds 5-1/2% Series, due May 1, 2019 [Member]
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	50,000	50,000
Laclede Gas [Member] | First Mortage Bonds 7% Series, due June 1, 2029 [Member]
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	25,000	25,000
Laclede Gas [Member] | First Mortage Bonds 7.90% Series, due September 15, 2030 [Member]
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	30,000	30,000
Laclede Gas [Member] | First Mortage Bonds 6% Series, due May 1, 2034 [Member]
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	100,000	100,000
Laclede Gas [Member] | First Mortage Bonds 6.15% Series, due June 1, 2036 [Member]
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	55,000	55,000
Laclede Gas [Member] | First Mortage Bonds 6.35% Series, due October 15, 2038 [Member]
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	80,000	80,000
Laclede Gas [Member] | First Mortage Bonds 3% Series, due March 15, 2023 [Member]
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	55,000	0
Laclede Gas [Member] | First Mortage Bonds 3.40% Series, due March 15, 2028 [Member]
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	45,000	0
Laclede Gas [Member] | First Mortage Bonds 2% Series, due August 15, 2018 [Member]
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	100,000	0
Laclede Gas [Member] | First Mortage Bonds 3.40% Series, due August 15, 2023 [Member]
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	250,000	0
Laclede Gas [Member] | First Mortage Bonds 4.625% Series, due August 15, 2043 [Member]
Long-Term Debt - Laclede Gas:
Debt instrument, principal outstanding	$ 100,000	$ 0

XML

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY (USD $) In Thousands, except Share data, unless otherwise specified	Total	Common Stock Issued	Paid-in Capital	Retained Earnings	Accum. Other Comp. Income (Loss)
BALANCE at Sep. 30, 2010	$ 535,577	$ 22,293	$ 158,698	$ 361,723	$ (7,137)
BALANCE (in shares) at Sep. 30, 2010		22,292,804
Stockholders' Equity Rollforward
Net income	63,825	0	0	63,825	0
Dividend reinvestment plan	1,614	43	1,571	0	0
Dividend reinvestment plan (in shares)		43,354
Stock-based compensation costs	3,949	0	3,949	0	0
Equity Incentive Plan	935	95	840	0	0
Equity Incentive Plan (in shares)		94,576
Employees’ taxes paid associated with restricted shares withheld upon vesting	(1,162)	0	(1,162)	0	0
Non-employee directors' restricted stock awards	(494)	0	(494)	0	0
Tax benefit - stock compensation	300	0	300	0	0
Dividends declared:
Common stock	(36,250)	0	0	(36,250)	0
Other comprehensive income, net of tax	5,037	0	0	0	5,037
BALANCE at Sep. 30, 2011	573,331	22,431	163,702	389,298	(2,100)
BALANCE (in shares) at Sep. 30, 2011		22,430,734
Stockholders' Equity Rollforward
Net income	62,640	0	0	62,640	0
Common stock offering	427,162	10,005	417,157	0	0
Common stock offering (in shares)		10,005,000
Dividend reinvestment plan	1,841	46	1,795	0	0
Dividend reinvestment plan (in shares)	46,107	46,107
Stock-based compensation costs	2,702	0	2,702	0	0
Equity Incentive Plan	2,470	62	2,408	0	0
Equity Incentive Plan (in shares)		62,590
Employees’ taxes paid associated with restricted shares withheld upon vesting	(1,203)	0	(1,203)	0	0
Non-employee directors' restricted stock awards	(565)	0	(565)	0	0
Tax benefit - stock compensation	(232)	0	(232)	0	0
Dividends declared:
Common stock	(37,357)	0	0	(37,357)	0
Other comprehensive income, net of tax	(2,016)	0	0	0	(2,016)
BALANCE at Sep. 30, 2012	601,611	22,539	168,607	414,581	(4,116)
BALANCE (in shares) at Sep. 30, 2012	22,540,000	22,539,431
Stockholders' Equity Rollforward
Net income	52,758	0	0	52,758	0
Dividend reinvestment plan	1,847	44	1,803	0	0
Dividend reinvestment plan (in shares)	44,074	44,074
Stock-based compensation costs	4,441	0	4,441	0	0
Equity Incentive Plan	2,674	109	2,565	0	0
Equity Incentive Plan (in shares)		108,331
Employees’ taxes paid associated with restricted shares withheld upon vesting	(931)	0	(931)	0	0
Non-employee directors' restricted stock awards	0	0		0	0
Tax benefit - stock compensation	627	0	627	0	0
Dividends declared:
Common stock	(47,236)	0	0	(47,236)	0
Other comprehensive income, net of tax	3,329	0	0	0	3,329
BALANCE at Sep. 30, 2013	$ 1,046,282	$ 32,697	$ 594,269	$ 420,103	$ (787)
BALANCE (in shares) at Sep. 30, 2013	32,700,000	32,696,836

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

12 Months Ended

Sep. 30, 2013

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

BASIS OF CONSOLIDATION - The consolidated financial statements include the accounts of Laclede Group and its subsidiary companies, including the recent acquisition of Missouri Gas Energy (MGE). All subsidiaries are wholly owned. Laclede Gas and other subsidiaries of Laclede Group may engage in related party transactions during the ordinary course of business. All material intercompany balances have been eliminated from the consolidated financial statements of Laclede Group. Transactions include sales of natural gas and transportation services between subsidiaries. These revenues are shown on the Intersegment revenues lines in the table included in Note 15, Information by Operating Segment.

NATURE OF OPERATIONS - The Laclede Group, Inc. (NYSE: LG), headquartered in St. Louis, Missouri, is a public utility holding company. The Gas Utility segment serves St. Louis and eastern Missouri through Laclede Gas and serves Kansas City and western Missouri through Missouri Gas Energy. Together they provide more than 1.13 million residential, commercial and industrial customers with safe and reliable natural gas service. Laclede’s primary non-utility business, Laclede Energy Resources, Inc., included in the Gas Marketing segment, provides non-regulated natural gas services. The activities of other subsidiaries and the non-regulated activities of Laclede Gas are described in Note 15, Information by Operating Segment, and are included in the Other column.

USE OF ESTIMATES - The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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.

SYSTEM OF ACCOUNTS - The accounts of Laclede Gas are maintained in accordance with the Uniform System of Accounts prescribed by the Missouri Public Service Commission (MoPSC or Commission), which system substantially conforms to that prescribed by the Federal Energy Regulatory Commission (FERC).

UTILITY PLANT, DEPRECIATION AND AMORTIZATION - 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.

Utility plant is depreciated on a straight-line basis at rates based on estimated service lives of the various classes of property. In fiscal year 2013, annual depreciation and amortization expense averaged 3.2% of the original cost of depreciable and amortizable property, compared to 3.1% in both fiscal years 2012 and 2011.

The Utility’s capital expenditures were $128.5 million, $106.7 million, and $67.3 million for fiscal years 2013, 2012, and 2011, respectively. Additionally, the Utility had recorded accruals for capital expenditures totaling $4.7 million at September 30, 2013, $9.7 million at September 30, 2012, and $8.2 million at September 30, 2011. Accrued capital expenditures are excluded from the Statements of Consolidated Cash Flows.

ASSET RETIREMENT OBLIGATIONS - Laclede Group 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 has recorded 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 Utility’s distribution system and general plant. Asset retirement obligations recorded by Laclede Group’s other subsidiaries are not material. As authorized by the MoPSC, the Utility accrues future asset removal costs associated with its property, plant and equipment even if a legal obligation does not exist. Such accruals are provided for through depreciation expense and are recorded with corresponding credits to regulatory liabilities. When the Utility retires depreciable utility plant and equipment, it charges the associated original costs to accumulated depreciation and amortization, and any related removal costs incurred are charged to regulatory liabilities. The difference between removal costs recognized in depreciation rates and the accretion expense and depreciation expense recognized for financial reporting purposes is a timing difference between recovery of these costs in rates and their recognition for financial reporting purposes.

Accordingly, these differences are deferred as regulatory liabilities. In the rate setting process, the regulatory liability is deducted from the rate base upon which the Utility has the opportunity to earn its allowed rate of return.

As part of the MGE acquisition, the Utility has estimated the asset retirement obligation of MGE’s long-lived assets as of the acquisition date. This allocation of asset retirement obligations is preliminary and will be finalized upon completion of a detailed fair value analysis that is being performed by the Company in the first quarter of fiscal 2014.

The following table presents a reconciliation of the beginning and ending balances of asset retirement obligations at September 30 as reported in the Consolidated Balance Sheets:

(Thousands)	2013			2012
Asset retirement obligations, beginning of year	$	40,368		$	27,495
Liabilities incurred during the period	801			851
Liabilities settled during the period	(1,089		)	(601		)
Accretion	2,322			1,637
Revisions in estimated cash flows	—			10,986
Addition of MGE asset retirement obligation	32,152			—
Asset retirement obligations, end of year	$	74,554		$	40,368

REGULATED OPERATIONS - The Utility accounts for its regulated operations in accordance with ASC Topic 980. This Topic sets forth the application of generally accepted accounting principles in the United States of America (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 Consolidated Balance Sheets as of September 30:

(Thousands)	2013		2012
Regulatory Assets:
Future income taxes due from customers	$	112,912	$	118,997
Pension and postretirement benefit costs	381,395		304,446
Unamortized purchased gas adjustments	17,533		40,674
Purchased gas costs	18,249		18,386
Compensated absences	8,004		7,836
Other	25,387		6,382
Total Regulatory Assets	$	563,480	$	496,721
Regulatory Liabilities:
Unamortized investment tax credits	$	2,900	$	3,113
Accrued cost of removal	59,066		55,103
Other	23,494		1,216
Total Regulatory Liabilities	$	85,460	$	59,432

The regulatory assets are expected to be recovered in rates charged to customers. A portion of the Company's regulatory assets are not earning a return; however, these regulatory assets are expected to be recovered from customers in future rates. Excluding deferred income taxes and purchased gas adjustment items, as of September 30, 2013 and 2012, approximately $17.2 million and $7.8 million, respectively, of regulatory assets were not earning a rate of return. The Company expects these items to be recovered over a period not to exceed 15 years consistent with precedent set by the MoPSC. The portion of the regulatory asset related to pensions and other postemployment benefits that relates to unfunded differences between the projected benefit obligation and plan assets also does not earn a rate of return.

As authorized by the MoPSC, the Utility discontinued deferring certain costs for future recovery, as expenses associated with those specific areas were included in approved rates effective December 27, 1999. Previously deferred costs of $10.5 million are being recovered and amortized on a straight-line basis over a fifteen-year period, without return on investment. Amortization of these costs totaled $9.7 million from December 27, 1999 through September 30, 2013.

NATURAL GAS STORED UNDERGROUND AND PROPANE GAS – For Laclede Gas, inventory of natural gas in storage is priced on a last-in, first-out (LIFO) basis and inventory of propane gas in storage is priced on a first-in, first-out (FIFO) basis. For MGE, inventory of natural gas in storage is priced on a weighted average cost basis. The replacement cost of Laclede Gas' natural gas stored underground for current use at September 30, 2013 and September 30, 2012 was less than the LIFO cost by $13.3 million and $24.3 million, respectively. The carrying value of the Utility inventory is not adjusted to the lower of cost or market prices because, pursuant to both Laclede Gas' and MGE's Purchased Gas Adjustment (PGA) Clauses, actual gas costs are recovered in customer rates. Natural gas and propane gas storage inventory in Laclede Group’s other operating segments is recorded at the lower of average cost or market.

BUSINESS COMBINATIONS - The Company's acquisition of MGE was accounted for by the Company using business combination accounting. Under this method, the purchase price paid by the acquirer is allocated to the assets acquired and liabilities assumed as of the acquisition date based on their fair value. For additional information on the Company's acquisition of MGE, refer to Note 2, MGE Acquisition.

GOODWILL - Goodwill is measured as the excess of the acquisition-date fair value of the consideration transferred over the amount of acquisition-date identifiable assets acquired net of assumed liabilities. Laclede Group recorded $247.1 million of goodwill as part of the MGE acquisition.

REVENUE RECOGNITION - The Utility reads meters and bills its customers on monthly cycles. The Utility records its Gas Utility revenues from gas sales and transportation services on an accrual basis that includes estimated amounts for gas delivered, but not yet billed. The accruals for unbilled revenues are reversed in the subsequent accounting period when meters are actually read and customers are billed. The amounts of accrued unbilled revenues at September 30, 2013 and 2012, for the Utility, were $25.2 million and $11.6 million, respectively.

Laclede Group’s other subsidiaries, including LER, record revenues when earned, either when the product is delivered or when services are performed.

In the course of its business, LER enters into commitments associated with the purchase or sale of natural gas. Certain of LER’s derivative natural gas contracts are designated as normal purchases or normal sales, and, as such, are excluded from the scope of ASC Topic 815, “Derivatives and Hedging.” Those contracts are accounted for as executory contracts and recorded on an accrual basis. Revenues and expenses from such contracts are recorded using a gross presentation. Contracts not designated as normal purchases or normal sales are recorded as derivatives with changes in fair value recognized in earnings in the periods prior to physical delivery. For additional information on derivative instruments, refer to Note 11, Derivative Instruments and Hedging Activities. Certain of LER’s wholesale purchase and sale transactions entered on or after January 1, 2012 are classified as trading activities for financial reporting purposes. Under GAAP, revenues and expenses associated with trading activities are presented on a net basis in Gas Marketing Operating Revenues in the Statements of Consolidated Income. This net presentation has no effect on operating income or net income.

PURCHASED GAS ADJUSTMENTS AND DEFERRED ACCOUNT – As authorized by the MoPSC, the PGA Clause allows Laclede Gas to flow through to customers, subject to prudence review by the MoPSC, the cost of purchased gas supplies. To better match customer billings with market natural gas prices, the Utility is allowed to file to modify, on a periodic basis, the level of gas costs in its PGA. Certain provisions of the PGA Clause are included below:

• The Utility has a risk management policy that allows for the purchase of natural gas derivative instruments with the goal of managing price risk associated with purchasing natural gas on behalf of its customers. The MoPSC clarified that costs, cost reductions, and carrying costs associated with the Utility’s use of natural gas derivative instruments are gas costs recoverable through the PGA mechanism.

• The tariffs allow the Utility flexibility to make up to three discretionary PGA changes during each year, in addition to its mandatory November PGA change, so long as such changes are separated by at least two months.

• The Utility is authorized to recover gas inventory carrying costs through its PGA rates to recover costs it incurs to finance its investment in gas supplies that are purchased during the storage injection season for sale during the heating season. The Utility is also authorized to apply carrying costs to all over- or under-recoveries of gas costs, including costs and cost reductions associated with the use of derivative instruments, including cash payments for margin deposits.

• The MoPSC approved a plan applicable to Laclede Gas' gas supply commodity costs under which it retains a portion of cost savings associated with the acquisition of natural gas below an established benchmark level. This gas supply cost management program allows Laclede Gas to retain 10% of cost savings, up to a maximum of $3.0 million annually. Laclede Gas did not record any income under the plan during the three fiscal years reported. Income recorded under the plan, if any, is included in Gas Utility Operating Revenues on the Statements of Consolidated Income.

Pursuant to the provisions of the PGA Clause, the difference between actual costs incurred and costs recovered through the application of the PGA are reflected as a deferred charge or credit at the end of the fiscal year. These costs include costs and cost reductions associated with the use of derivative instruments and gas inventory carrying costs, amounts due to or from customers related to operation of the gas supply cost management program, refunds received from the Company’s suppliers in connection with gas supply, transportation, and storage services, and carrying costs on such over- or under-recoveries. At that time, the balance is classified as a current asset or current liability and recovered from, or credited to, customers over an annual period commencing in November. The balance in the current account is amortized as amounts are reflected in customer billings. The PGA Clause also provides for the treatment of income from off-system sales and capacity release revenues. Pre-tax income from off-system sales and capacity release revenues is shared with customers, with an estimated amount assumed in PGA rates. The difference between the actual amount allocated to customers for each fiscal year and the estimated amount assumed in PGA rates is recovered from, or credited to, customers over an annual period commencing in the subsequent November. The customer share of such income is determined in accordance with the tables below, which is shown for each legacy company (Laclede Gas and MGE) under which the PGA Clauses were approved by the MoPSC.

Laclede Gas
Pre-tax Income	Customer Share	Company Share
First $2 million	100%	—%
Next $2 million	80%	20%
Next $2 million	75%	25%
Amounts exceeding $6 million	70%	30%
MGE
Pre-tax Income	Customer Share	Company Share
First $1.2 million	85%	15%
Next $1.2 million	80%	20%
Next $1.2 million	75%	25%
Amounts exceeding $3.6 million	70%	30%

See the Regulatory and Other Matters section on page 36 of this report for additional information on Laclede Gas' off-system sales.

INCOME TAXES - Laclede Group and its subsidiaries have elected, for tax purposes only, various accelerated depreciation provisions of the Internal Revenue Code. In addition, certain other costs are expensed currently for tax purposes while being deferred for book purposes. GAAP permits the benefit from a tax position to be recognized only if, and to the extent that, it is more likely than not that the tax position will be sustained upon examination by the taxing authority, based on the technical merits of the position. Unrecognized tax benefits and related interest and penalties, if any, are recorded as liabilities or as a reduction to deferred tax assets. Laclede Group companies record deferred tax liabilities and assets measured by enacted tax rates for the net tax effect of all temporary differences between the tax basis and the related carrying amounts of assets and liabilities in the financial statements. Changes in enacted tax rates, if any, and certain property basis differences are reflected by entries to regulatory asset or regulatory liability accounts for regulated companies, and are reflected as income or loss for non-regulated companies.

The Utility’s investment tax credits utilized prior to 1986 have been deferred and are being amortized in accordance with regulatory treatment over the useful life of the related property.

CASH AND CASH EQUIVALENTS - All highly liquid debt instruments purchased with original maturities of three months or less are considered to be cash equivalents. Such instruments are carried at cost, which approximates market value.

Outstanding checks on the Company’s controlled disbursement bank accounts in excess of funds on deposit create book overdrafts (which are funded at the time checks are presented for payment) and are classified as Other in the Current Liabilities section of the Consolidated Balance Sheets. Changes in book overdrafts between periods are reflected as Financing Activities in the Statements of Consolidated Cash Flows.

NATURAL GAS RECEIVABLE – LER enters into natural gas transactions with natural gas pipeline companies known as park and loan arrangements. Under the terms of the arrangements, LER purchases natural gas from a third party and delivers that natural gas to the pipeline company for the right to receive the same quantity of natural gas from the pipeline company at the same location in a future period. These arrangements are accounted for as non-monetary transactions under GAAP and are recorded at the carrying amount. As such, natural gas receivables are reflected on the Consolidated Balance Sheets at cost, which includes related pipeline fees associated with the transactions. In the period that the natural gas is returned to LER, concurrent with the sale of the natural gas to a third party, the related natural gas receivable is expensed in the Statements of Consolidated Income. In conjunction with these transactions, LER usually enters into New York Mercantile Exchange (NYMEX) and Ice Clear Europe (ICE) natural gas futures, options, and swap contracts or fixed price sales agreements to protect against market changes in future sales prices.

EARNINGS PER COMMON SHARE - GAAP requires dual presentation of basic and diluted earnings per share (EPS). EPS is computed using the two-class method, which is an earnings allocation method for computing EPS that treats a participating security as having rights to earnings that would otherwise have been available to common shareholders. Certain of the Company’s stock-based compensation awards pay nonforfeitable dividends to the participants during the vesting period and, as such, are deemed participating securities. Basic EPS is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding that are increased for additional shares that would be outstanding if potentially dilutive non-participating securities were converted to common shares, pursuant to the treasury stock method. Shares attributable to non-participating stock options and time-vested restricted stock/units are excluded from the calculation of diluted earnings per share if the effect would be antidilutive. Shares attributable to non-participating performance-contingent restricted stock awards are only included in the calculation of diluted earnings per share to the extent the underlying performance and/or market conditions are satisfied (a) prior to the end of the reporting period or (b) would be satisfied if the end of the reporting period were the end of the related contingency period and the result would be dilutive. The Company’s EPS computations are presented in Note 5, Earnings Per Common Share.

GROSS RECEIPTS AND SALES TAXES - Gross receipts taxes associated with the Utility's natural gas utility service are imposed on the Utility and billed to its customers. These amounts are recorded gross in the Statements of Consolidated Income. Amounts recorded in Gas Utility Operating Revenues were $40.8 million, $35.9 million, and $43.5 million for fiscal years 2013, 2012, and 2011, respectively. Gross receipts taxes are expensed by the Utility and included in the Taxes, other than income taxes line.

Sales taxes imposed on applicable Company sales are billed to customers. These amounts are not recorded in the Statements of Consolidated Income, but are recorded as tax collections payable and included in the Other line of the Current Liabilities section of the Consolidated 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 collectibility 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. The Utility’s provision for uncollectible accounts includes the amortization of previously deferred uncollectible expenses, as approved by the MoPSC.

GROUP MEDICAL AND WORKERS’ COMPENSATION RESERVES - The Company self-insures its group medical and workers’ compensation costs and carries stop-loss coverage in relation to medical claims 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 3, Pension Plans and Other Postretirement Benefits, Note 9, Fair Value of Financial Instruments, and Note 10, Fair Value Measurements.

STOCK-BASED COMPENSATION – The Company measures stock-based compensation awards at fair value at the date of grant and recognizes the compensation cost of the awards over the requisite service period. Forfeitures are estimated at the time of grant and revised, if necessary, in subsequent periods if the actual forfeitures differ from those estimates. Refer to Note 4, Stock-Based Compensation, for further discussion of the accounting for the Company’s stock-based compensation plans.

NEW ACCOUNTING STANDARDS – In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities,” to amend ASC Topic 210, “Balance Sheet,” to require additional disclosures about financial instruments and derivative instruments that have been presented on a net basis (offset) in the balance sheet. Additionally, information about financial instruments and derivative instruments that are subject to enforceable master netting arrangements or similar agreements, irrespective of whether they are presented net in the balance sheet, is required to be disclosed. The ASU impacts disclosures only and will not require any changes to financial statement presentation. The Company will present the new disclosures retrospectively beginning in the first quarter of fiscal year 2014.

In February 2013, the FASB issued ASU No. 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income.” This ASU amends Accounting Standards Codification (ASC) Topic 220, “Comprehensive Income,” by requiring entities to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to provide information on significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income, but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. The Company will present the new disclosures prospectively beginning in the first quarter of fiscal year 2014.

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FAIR VALUE MEASUREMENTS (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Beginning of period	$ 109	$ 13
Settlements	(269)	(54)
Net losses related to derivatives not held at end of period	(99)	(68)
Net gains related to derivatives still held at end of period	369	218
End of period	110	109
Fair Value, Measurements, Recurring [Member]
Assets
U. S. Stock/Bond Mutual Funds	14,500	13,187
NYMEX/ICE natural gas contracts	2,518	0
OTCBB natural gas contracts	0
NYMEX gasoline and heating oil contracts	0	0
Natural gas commodity contracts	784	2,874
Total	17,802	16,061
Liabilities
NYMEX/ICE natural gas contracts	0	0
OTCBB natural gas contracts	5,211
NYMEX gasoline and heating oil contracts	0	0
Natural gas commodity contracts	685	133
Total	5,896	133
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets (Level 1) [Member]
Assets
U. S. Stock/Bond Mutual Funds	14,500	13,187
NYMEX/ICE natural gas contracts	4,333	7,411
OTCBB natural gas contracts	0
NYMEX gasoline and heating oil contracts	105	344
Natural gas commodity contracts	0	0
Total	18,938	20,942
Liabilities
NYMEX/ICE natural gas contracts	3,687	12,253
OTCBB natural gas contracts	0
NYMEX gasoline and heating oil contracts	0	0
Natural gas commodity contracts	0	0
Total	3,687	12,253
Fair Value, Measurements, Recurring [Member] | Significant Observable Inputs (Level 2) [Member]
Assets
U. S. Stock/Bond Mutual Funds	0	0
NYMEX/ICE natural gas contracts	330	994
OTCBB natural gas contracts	232
NYMEX gasoline and heating oil contracts	0	0
Natural gas commodity contracts	1,129	3,060
Total	1,691	4,054
Liabilities
NYMEX/ICE natural gas contracts	321	1,891
OTCBB natural gas contracts	5,443
NYMEX gasoline and heating oil contracts	0	0
Natural gas commodity contracts	1,140	428
Total	6,904	2,319
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]
Assets
U. S. Stock/Bond Mutual Funds	0	0
NYMEX/ICE natural gas contracts	0	0
OTCBB natural gas contracts	0
NYMEX gasoline and heating oil contracts	0	0
Natural gas commodity contracts	150	113
Total	150	113
Liabilities
NYMEX/ICE natural gas contracts	0	0
OTCBB natural gas contracts	0
NYMEX gasoline and heating oil contracts	0	0
Natural gas commodity contracts	40	4
Total	40	4
Fair Value, Measurements, Recurring [Member] | Effects of Netting and Cash Margin Receivables /Payables
Assets
U. S. Stock/Bond Mutual Funds	0	0
NYMEX/ICE natural gas contracts	(2,145)	(8,405)
OTCBB natural gas contracts	(232)
NYMEX gasoline and heating oil contracts	(105)	(344)
Natural gas commodity contracts	(495)	(299)
Total	(2,977)	(9,048)
Liabilities
NYMEX/ICE natural gas contracts	(4,008)	(14,144)
OTCBB natural gas contracts	(232)
NYMEX gasoline and heating oil contracts	0	0
Natural gas commodity contracts	(495)	(299)
Total	$ (4,735)	$ (14,443)

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CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY (Parenthetical) (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Statement of Stockholders' Equity [Abstract]
Dividends Declared, Common stock (in dollars per share)	$ 1.70	$ 1.66	$ 1.62

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INCOME TAXES (Tables)

12 Months Ended

Sep. 30, 2013

Income Tax Disclosure [Abstract]

Net Provision For Income Tax

The net provisions for income taxes charged during the fiscal years ended September 30, 2013, 2012, and 2011 are as follows:

(Thousands)	2013			2012			2011
Included in Statements of Consolidated Income:
Federal
Current	$	(4,173	)	$	(3,835	)	$	4,724
Deferred	19,925			26,365			20,602
Investment tax credits	(213		)	(213		)	(213		)
State and local
Current	(301		)	(430		)	573
Deferred	2,340			4,402			3,496
Total Income Tax Expense	$	17,578		$	26,289		$	29,182

Effective income tax rate variation from stated tax rate

The effective income tax rate varied from the federal statutory income tax rate for each year due to the following:

	2013		2012		2011
Federal income tax statutory rate	35.0	%	35.0	%	35.0	%
State and local income taxes, net of federal income tax benefits	3.5		2.9		2.8
Certain expenses capitalized on books and deducted on tax return	(9.7	)	(6.9	)	(5.0	)
Taxes related to prior years	(1.6	)	(0.8	)	(0.7	)
Other items – net	(2.2	)	(0.6	)	(0.7	)
Effective income tax rate	25.0	%	29.6	%	31.4	%

Significant Items in Net Deferred Tax Liability

The significant items comprising the net deferred tax liability recognized in the Consolidated Balance Sheets as of September 30 are as follows:

(Thousands)	2013			2012
Deferred tax assets:
Reserves not currently deductible	$	13,933		$	16,400
Pension and other postretirement benefits	71,367			73,480
Unamortized investment tax credits	1,799			1,955
Other*	12,522			18,224
Total deferred tax assets	99,621			110,059
Deferred tax liabilities:
Relating to property	341,975			303,474
Regulatory pension and other postretirement benefits	124,871			121,554
Deferred gas costs	7,112			20,652
Other	5,789			26,563
Total deferred tax liabilities	479,747			472,243
Net deferred tax liability	380,126			362,184
Net deferred tax liability – current*	(1,012		)	(6,675		)
Net deferred tax liability – non-current*	$	379,114		$	355,509

* The Company periodically invests in tax credits. As of September 30, 2013, $7.1 million of state tax credits are included in Other and Net deferred tax liability. $4.7 million of state tax credits were classified as current. $2.4 million of state tax credits were classified as non-current.

Unrecognized Tax Benefit Reconciliation

The following table presents a reconciliation of the beginning and ending balances of unrecognized tax benefits at September 30 as reported in the Consolidated Balance Sheets:

(Thousands)	2013			2012
Unrecognized tax benefits, beginning of year	$	5,810		$	5,596
Increases related to prior year tax positions	145			78
Increases related to tax positions taken in current year	1,450			547
Reductions due to lapse of applicable statute of limitations	(5,018		)	(411		)
Unrecognized tax benefits, end of year	$	2,387		$	5,810

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SCHEDULE II

12 Months Ended

Sep. 30, 2013

Valuation and Qualifying Accounts [Abstract]

SCHEDULE II

SCHEDULE II

THE LACLEDE GROUP, INC. AND SUBSIDIARY COMPANIES

RESERVES

FOR THE YEARS ENDED SEPTEMBER 30, 2013, 2012, AND 2011

COLUMN A	COLUMN B		COLUMN C						COLUMN D			COLUMN E
	BALANCE AT		ADDITIONS			CHARGED			DEDUCTIONS			BALANCE
	BEGINNING		TO			TO OTHER			FROM			AT CLOSE
DESCRIPTION	OF PERIOD		INCOME			ACCOUNTS			RESERVES			OF PERIOD
(Thousands of Dollars)
YEAR ENDED SEPTEMBER 30, 2013:
DOUBTFUL ACCOUNTS	$	7,705	$	5,584		$	8,234	(b)	$	13,477	(c)	$	8,046
MISCELLANEOUS:
Injuries and property damage	$	4,540	$	1,934		$	—		$	2,135	(d)	$	4,339
Deferred compensation	14,205		1,781			—			1,306			14,680
Group medical claims incurred but not reported	1,560		17,205			—			16,116		(d)	2,649
TOTAL	$	20,305	$	20,920	(a)	$	—	(a)	$	19,557	(a)	$	21,668
YEAR ENDED SEPTEMBER 30, 2012:
DOUBTFUL ACCOUNTS	$	10,073	$	6,011		$	10,145	(b)	$	18,524	(c)	$	7,705
MISCELLANEOUS:
Injuries and property damage	$	3,603	$	3,150		$	—		$	2,213	(d)	$	4,540
Deferred compensation	13,474		1,756			—			1,025			14,205
Group medical claims incurred but not reported	1,300		15,381			—			15,121		(d)	1,560
TOTAL	$	18,377	$	20,287		$	—		$	18,359		$	20,305
YEAR ENDED SEPTEMBER 30, 2011:
DOUBTFUL ACCOUNTS	$	10,295	$	7,242		$	11,340	(b)	$	18,804	(c)	$	10,073
MISCELLANEOUS:
Injuries and property damage	$	3,228	$	2,416		$	—		$	2,041	(d)	$	3,603
Deferred compensation	12,571		1,893			—			990			13,474
Group medical claims incurred but not reported	1,450		14,171			—			14,321		(d)	1,300
TOTAL	$	17,249	$	18,480		$	—		$	17,352		$	18,377

(a) Totals for the year ended September 30, 2013 includes one month of MGE activity.

(b) Accounts reinstated, cash recoveries, etc.

(c) Accounts written off.

(d) Claims settled, less reimbursements from insurance companies.

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS (Tables)

12 Months Ended

Sep. 30, 2013

Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]

Net Periodic Cost

Net periodic postretirement benefit costs consisted of the following components:

(Thousands)	2013			2012			2011
Service cost – benefits earned during the period	$	10,162		$	8,060		$	7,676
Interest cost on accumulated postretirement benefit obligation	5,234			5,521			4,843
Expected return on plan assets	(4,447		)	(3,965		)	(3,646		)
Amortization of transition obligation	93			136			136
Amortization of prior service credit	3			(2,072		)	(2,328		)
Amortization of actuarial loss	5,300			4,261			4,443
Sub-total	16,345			11,941			11,124
Regulatory adjustment	(6,821		)	(2,417		)	(2,071		)
Net postretirement benefit cost	$	9,524		$	9,524		$	9,053

The net periodic pension costs include the following components:

(Thousands)	2013			2012			2011
Service cost – benefits earned during the period	$	9,209		$	9,203		$	9,553
Interest cost on projected benefit obligation	16,959			19,358			18,819
Expected return on plan assets	(19,358		)	(19,595		)	(18,849		)
Amortization of prior service cost	544			592			642
Amortization of actuarial loss	10,724			9,040			10,228
Loss on lump-sum settlements	26,996			20,051			943
Sub-total	45,074			38,649			21,336
Regulatory adjustment	(27,532		)	(18,579		)	(7,066		)
Net pension cost	$	17,542		$	20,070		$	14,270

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

Other changes in plan assets and postretirement benefit obligations recognized in other comprehensive income include the following:

(Thousands)	2013			2012			2011
Current year actuarial loss	$	16,300		$	10,138		$	1,696
Amortization of actuarial loss	(5,300		)	(4,261		)	(4,443		)
Amortization of prior service credit	(3		)	2,072			2,328
Amortization of transition obligation	(93		)	(136		)	(136		)
Sub-total	10,904			7,813			(555		)
Regulatory adjustment	(10,904		)	(7,813		)	555
Total recognized in other comprehensive income	$	—		$	—		$	—

Other changes in plan assets and pension benefit obligations recognized in other comprehensive income include the following:

(Thousands)	2013			2012			2011
Current year actuarial loss (gain)	$	17,030		$	32,884		$	(13,485	)
Amortization of actuarial loss	(10,724		)	(29,091		)	(11,171		)
Acceleration of loss recognized due to settlement	(26,996		)	—			—
Amortization of prior service cost	(544		)	(592		)	(642		)
Sub-total	(21,234		)	3,201			(25,298		)
Regulatory adjustment	21,159			(3,510		)	24,533
Total recognized in other comprehensive income	$	(75	)	$	(309	)	$	(765	)

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 postretirement benefit obligation at September 30:

(Thousands)	2013			2012
Benefit obligation, beginning of year	$	127,217		$	103,991
Service cost	10,162			8,060
Interest cost	5,234			5,521
Actuarial loss (gain)	17,514			15,895
MGE acquisition	28,444			—
Gross benefits paid	(8,449		)	(6,250		)
Benefit obligation, end of year	$	180,122		$	127,217

The following table sets forth the reconciliation of the beginning and ending balances of the pension benefit obligation at September 30:

(Thousands)	2013			2012
Benefit obligation, beginning of year	$	412,171		$	384,163
Service cost	9,209			9,203
Interest cost	16,959			19,358
Actuarial (gain) loss	(23,921		)	52,161
MGE acquisition	151,424			—
Settlement loss	24,999			14,348
Gross benefits paid *	(87,023		)	(67,062		)
Benefit obligation, end of year	$	503,818		$	412,171
Accumulated benefit obligation, end of year	$	444,129		$	353,061

* Includes $79,484 and $60,085 lump-sum payments recognized as settlements in fiscal years 2013 and 2012, respectively.

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 at September 30:

(Thousands)	2013			2012
Fair value of plan assets at beginning of year	$	67,442		$	51,744
Actual return on plan assets	5,660			9,722
Employer contributions	16,596			12,226
MGE acquisition	30,396			—
Gross benefits paid	(8,449		)	(6,250		)
Fair value of plan assets, end of year	$	111,645		$	67,442
Funded status of plans, end of year	$	(68,477	)	$	(59,775	)

The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets at September 30:

(Thousands)	2013			2012
Fair value of plan assets, beginning of year	$	274,130		$	247,959
Actual return on plan assets	3,387			53,220
Employer contributions	27,991			40,013
MGE acquisition	126,958			—
Gross benefits paid *	(87,023		)	(67,062		)
Fair value of plan assets, end of year	$	345,443		$	274,130
Funded status of plans, end of year	$	(158,375	)	$	(138,041	)

*  Includes $79,484 and $60,085 lump-sum payments recognized as settlements in fiscal years 2013 and 2012, respectively.

Amounts recognized in consolidated balance sheet

The following table sets forth the amounts recognized in the Consolidated Balance Sheets at September 30:

(Thousands)	2013			2012
Current liabilities	$	(442	)	$	(468	)
Noncurrent liabilities	(157,933		)	(137,573		)
Total	$	(158,375	)	$	(138,041	)
Pre-tax amounts recognized in accumulated other comprehensive income not yet recognized as components of net periodic pension cost consist of:
Net actuarial loss	$	115,775		$	136,464
Prior service costs	4,467			5,011
Sub-total	120,242			141,475
Adjustments for amounts included in Regulatory Assets	(116,686		)	(137,845		)
Total	$	3,556		$	3,630

The following table sets forth the amounts recognized in the Consolidated Balance Sheets at September 30:

(Thousands)	2013			2012
Noncurrent assets	$	2,543		$	—
Current liabilities	(300		)	(790		)
Noncurrent liabilities	(70,720		)	(58,985		)
Total	$	(68,477	)	$	(59,775	)
Pre-tax amounts recognized in accumulated other comprehensive income not yet recognized as components of net periodic postretirement benefit cost consist of:
Net actuarial loss	$	63,573		$	52,573
Prior service credit	(27		)	(24		)
Transition obligation	—			93
Sub-total	63,546			52,642
Adjustments for amounts included in Regulatory Assets	(63,546		)	(52,642		)
Total	$	—		$	—

Pre-tax amounts amortized from accumulated other comprehensive income into net periodic cost

At September 30, 2013, the following pre-tax amounts are expected to be amortized from accumulated other comprehensive income into net periodic postretirement benefit cost during fiscal year 2014:

(Thousands)
Amortization of net actuarial loss	$	6,021
Amortization of prior service cost	(4		)
Sub-total	6,017
Regulatory adjustment	(6,017		)
Total	$	—

At September 30, 2013, the following pre-tax amounts are expected to be amortized from accumulated other comprehensive income into net periodic pension cost during fiscal year 2014:

(Thousands)	2014
Amortization of net actuarial loss	$	7,088
Amortization of prior service cost	497
Sub-total	7,585
Regulatory adjustment	(7,196		)
Total	$	389

Assumptions used to calculate net periodic cost and benefit obligations.

The assumptions used to calculate the accumulated postretirement benefit obligations are as follows:

	2013	2012
Weighted average discount rate *	4.60%	3.80%
Weighted average rate of future compensation increase	3.00%	3.00%

The assumptions used to calculate the benefit obligations are as follows:

	2013	2012
Weighted average discount rate *	4.70%	3.95%
Weighted average rate of future compensation increase	3.00%	3.00%

* Weighted average discount rate assumption for the MGE pension plan is 5.00%.

The assumptions used to calculate net periodic pension costs are as follows:

	2013	2012	2011
Weighted average discount rate*	3.95%	5.10%	4.75%
Weighted average rate of future compensation increase	3.00%	3.00%	3.00%
Expected long-term rate of return on plan assets	7.75%	7.75%	8.00%

* Weighted average discount rate assumption for the MGE pension plan is 5.05%.

The assumptions used to calculate net periodic postretirement benefit costs are as follows:

	2013		2012		2011
Weighted average discount rate *	3.80	%	5.05	%	4.70	%
Weighted average rate of future compensation increase	3.00	%	3.00	%	3.00	%
Expected long-term rate of return on plan assets **	7.75	%	7.75	%	8.00	%

* Weighted average discount rate assumption for the MGE postretirement plan is 5.05%.

**    Expected long-term rate of return on plan assets assumption for the MGE postretirement plan is 5.75%.

Projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for plans that have projected benefit obligation and accumulated benefit obligation in excess of plan assets

Following are the projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for plans that have a projected benefit obligation and an accumulated benefit obligation in excess of plan assets:

(Thousands)	2013		2012
Projected benefit obligation	$	503,818	$	412,171
Accumulated benefit obligation	444,129		353,061
Fair value of plan assets	345,443		274,130

Targeted and actual plan assets by category

Following are the targeted and actual plan assets by category as of September 30 of each year:

	Target		2013 Actual		2012 Actual
Growth Strategy
Equity Markets	42.5	%	45.9	%	37.3	%
Commodities	2.5	%	1.6	%	2.2	%
Real Estate	2.5	%	3.0	%	2.2	%
Inflation-Indexed Securities	2.5	%	1.4	%	2.2	%
Debt Securities	50.0	%	43.3	%	41.1	%
Other*	—	%	4.8	%	15.0	%
Total	100.0	%	100.0	%	100.0	%

* Other investments in 2013 consist of cash equivalents. The relatively large cash position at September 30, 2012 was

due to a transition taking place between investment managers and was invested in debt securities in a matter of days.

Following are the targeted and actual plan assets by category as of September 30 of each year:

	Target		2013 Actual		2012 Actual
Equity Securities	60.0	%	59.0	%	59.0	%
Debt Securities	40.0	%	39.0	%	39.0	%
Other	—	%	2.0	%	2.0	%
Total	100.0	%	100.0	%	100.0	%

Expected benefit payments for the succeeding five fiscal years

Following are expected pension benefit payments for the succeeding five fiscal years, and in aggregate for the five years thereafter:

(Millions)	Pensions from Qualified Trust		Pensions from Laclede Gas Funds
2014	$	22.9	$	0.4
2015	25.3		0.5
2016	27.2		0.5
2017	30.8		0.6
2018	34.2		0.6
2019 – 2023	227.2		4.5

Following are expected postretirement benefit payments for the succeeding five fiscal years, and in aggregate for the five years thereafter:

(Millions)	Benefits Paid from Qualified Trust		Benefits Paid from Laclede Gas Funds
2014	$	9.5	$	0.3
2015	9.9		0.3
2016	10.7		0.3
2017	11.7		0.4
2018	12.8		0.4
2019 – 2023	84.1		2.2

Assumed medical cost trend rates and effect of an assumed 1% changed in assumed medical cost trend.

The assumed medical cost trend rates at September 30 are as follows:

	2013	2012
Medical cost trend assumed for next year	7.50%	7.00%
Rate to which the medical cost trend rate is assumed to decline (the ultimate medical cost trend rate)	5.00%	5.00%
Year the rate reaches the ultimate trend	2020	2017

The following table presents the effect of an assumed 1% change in the assumed medical cost trend rate:

(Thousands)	1% Increase		1% Decrease
Effect on net periodic postretirement benefit cost	$	1,520	$	(1,390	)
Effect on accumulated postretirement benefit obligation	7,060		(6,580		)

Fair value measurements of plan assets

The table below categorizes the fair value measurements of the Utility's’ pension plan assets:

(Thousands)	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total
As of September 30, 2013
Cash and cash equivalents	$	18,177	$	—		$	—	$	18,177
Stock/Bond mutual fund	—		115,817			—		115,817
Debt Securities
U.S. bond mutual funds	17,682		—			—		17,682
U.S. government	—		55,743			—		55,743
U.S. corporate	—		110,925			—		110,925
U.S. municipal	—		6,799			—		6,799
International	—		21,594			—		21,594
Derivative instruments (a)	—		(1,294		)	—		(1,294		)
Total	$	35,859	$	309,584		$	—	$	345,443
As of September 30, 2012
Cash and cash equivalents	$	57,614	$	—		$	—	$	57,614
Debt Securities
U.S. bond mutual funds	36,767		—			—		36,767
U.S. government	—		57,925			—		57,925
U.S. corporate	—		93,169			—		93,169
U.S. municipal	—		9,493			—		9,493
International	—		18,885			—		18,885
Derivative instruments (b)	—		277			—		277
Total	$	94,381	$	179,749		$	—	$	274,130

(a) Derivative assets of $4,186 net of cash margin payable of $5,480.

(b) Derivative assets of $3,027 net of cash margin payable of $2,750.

The table below categorizes the fair value measurements of The Utility's postretirement plan assets:

(Thousands)	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
As of September 30, 2013
Cash and cash equivalents	$	1,411	$	—	$	—	$	1,411
U.S. stock/bond mutual fund	110,234		—		—		110,234
Total	$	111,645	$	—	$	—	$	111,645
As of September 30, 2012
Cash and cash equivalents	$	1,106	$	—	$	—	$	1,106
U.S. stock/bond mutual fund	66,336		—		—		66,336
Total	$	67,442	$	—	$	—	$	67,442

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NOTES PAYABLE AND CREDIT AGREEMENTS (Details) (USD $)							12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013 Laclede Gas [Member] Line of Credit [Member]	Sep. 03, 2013 Laclede Gas [Member] Line of Credit [Member] bank	Sep. 30, 2013 Laclede Group [Member] Line of Credit [Member]	Sep. 03, 2013 Laclede Group [Member] Line of Credit [Member]	Sep. 30, 2013 Laclede Group [Member] Commercial Paper [Member]	Sep. 30, 2012 Laclede Group [Member] Commercial Paper [Member]
Line of Credit Facility [Line Items]
Line of credit facility borrowing capacity				$ 450,000,000		$ 150,000,000
Banks in syndicated line of credit facility				9
Banks in syndicated line of credit facility, largest borrowing portion provided by a single bank				15.60%
Minimum required ratio of earnings before interest, taxes, depreciation, and amortization (EBITDA) times interest expense as required by the line of credit covenant.				70.00%		70.00%
Debt to total capitalization ratio			48.00%		49.00%
Weighted average borrowings outstanding							34,200,000	43,800,000
Weighted average interest rate							0.30%	0.30%
Short term borrowings outstanding in the period - minimum							0	0
Short term borrowings outstanding in the period - maximum							99,400,000	133,500,000
Borrowings outstanding at end of period	$ 74,000,000	$ 40,100,000					$ 74,000,000	$ 40,100,000
Weighted average interest rate at period end							0.30%	0.20%

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NOTES PAYABLE AND CREDIT AGREEMENTS (Tables)

12 Months Ended

Sep. 30, 2013

Short-term Debt [Abstract]

Short-term borrowings

Information about the Laclede Group’s short-term borrowings (excluding intercompany borrowings) during the 12 months ended September 30, and as of September 30, is presented below for 2013 and 2012:

	Commercial Paper Borrowings
Twelve Months Ended September 30, 2013
Weighted average borrowings outstanding	$34.2 million
Weighted average interest rate	0.3%
Range of borrowings outstanding	$0 – $99.4 million
As of September 30, 2013
Borrowings outstanding at end of period	$74.0 million
Weighted average interest rate	0.3%
Twelve Months Ended September 30, 2012
Weighted average borrowings outstanding	$43.8 million
Weighted average interest rate	0.3%
Range of borrowings outstanding	$0 – $133.5 million
As of September 30, 2012
Borrowings outstanding at end of period	$40.1 million
Weighted average interest rate	0.2%

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LONG-TERM DEBT Part 2 - Narrative (Details) (USD $)	12 Months Ended								12 Months Ended					0 Months Ended				0 Months Ended			0 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011	Jun. 30, 2013	Sep. 30, 2013 No Call Options [Member]	Sep. 30, 2013 Make Whole Call Options [Member]	Sep. 30, 2013 Callable at par in 2013 [Member] Three to six months prior to maturity [Member]	Sep. 30, 2013 Callable at par in 2013 [Member] Beginning October 2013 [Member]	Sep. 30, 2013 Laclede Gas [Member]	Sep. 30, 2012 Laclede Gas [Member]	Nov. 26, 2013 Laclede Gas [Member] Subsequent Event [Member]	Aug. 13, 2013 First Mortgage [Member] Laclede Gas [Member]	Mar. 15, 2013 First Mortgage [Member] Laclede Gas [Member]	Oct. 15, 2012 First Mortgage Bonds 6.5% Series, due October 15, 2012 [Member] First Mortgage [Member] Laclede Gas [Member]	Dec. 14, 2012 3.31% Notes Payable, due December 15, 2022 [Member] Unsecured Debt [Member]	Sep. 30, 2013 First Mortage Bonds 3% Series, due March 15, 2023 [Member] Laclede Gas [Member]	Sep. 30, 2012 First Mortage Bonds 3% Series, due March 15, 2023 [Member] Laclede Gas [Member]	Mar. 15, 2013 First Mortage Bonds 3% Series, due March 15, 2023 [Member] First Mortgage [Member] Laclede Gas [Member]	Sep. 30, 2013 First Mortage Bonds 3.40% Series, due March 15, 2028 [Member] Laclede Gas [Member]	Sep. 30, 2012 First Mortage Bonds 3.40% Series, due March 15, 2028 [Member] Laclede Gas [Member]	Mar. 15, 2013 First Mortage Bonds 3.40% Series, due March 15, 2028 [Member] First Mortgage [Member] Laclede Gas [Member]	Sep. 30, 2013 First Mortage Bonds 2% Series, due August 15, 2018 [Member] Laclede Gas [Member]	Sep. 30, 2012 First Mortage Bonds 2% Series, due August 15, 2018 [Member] Laclede Gas [Member]	Aug. 13, 2013 First Mortage Bonds 2% Series, due August 15, 2018 [Member] First Mortgage [Member] Laclede Gas [Member]	Sep. 30, 2013 First Mortage Bonds 3.40% Series, due August 15, 2023 [Member] Laclede Gas [Member]	Sep. 30, 2012 First Mortage Bonds 3.40% Series, due August 15, 2023 [Member] Laclede Gas [Member]	Aug. 13, 2013 First Mortage Bonds 3.40% Series, due August 15, 2023 [Member] First Mortgage [Member] Laclede Gas [Member]	Sep. 30, 2013 First Mortage Bonds 4.625% Series, due August 15, 2043 [Member] Laclede Gas [Member]	Sep. 30, 2012 First Mortage Bonds 4.625% Series, due August 15, 2043 [Member] Laclede Gas [Member]	Aug. 13, 2013 First Mortage Bonds 4.625% Series, due August 15, 2043 [Member] First Mortgage [Member] Laclede Gas [Member]
Debt Instrument [Line Items]
Maturity of first mortgage bonds	$ 25,000,000	$ 0	$ 25,000,000											$ 25,000,000
Stated interest rate on debt issued														6.50%	3.31%	3.00%	3.00%	3.00%	3.40%	3.40%	3.40%	2.00%	2.00%	2.00%	3.40%	3.40%	3.40%	4.625%	4.625%	4.625%
Debt issued, maturity term															10 years			10 years			15 years
Issuance of debt												450,000,000	100,000,000		25,000,000			55,000,000			45,000,000			100,000,000			250,000,000			100,000,000
Fixed-rate long-term debt amount	915,000,000				50,000,000	435,000,000	350,000,000	80,000,000
MoPSC authorized debt issuance through June 30, 2013 - maximum available				518,000,000					518,000,000
Extension period for debt securities and preferred stock issuance authority	2 years								2 years
MoPSC authorized debt issuance - remaining available	$ 370,800,000										$ 370,800,000
Preferred stock shares authorized (in shares)									1,480,000	1,480,000

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 3 (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2011
Pension Plans [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation, beginning of year	$ 412,171		$ 384,163
Service cost	9,209		9,203		9,553
Interest cost	16,959		19,358		18,819
Actuarial (gain) loss	(23,921)		52,161
MGE acquisition	151,424		0
Settlement loss	24,999		14,348
Gross benefits paid	(87,023)	[1]	(67,062)	[1]
Benefit obligation, end of year	503,818		412,171		384,163
Accumulated benefit obligation, end of year	444,129		353,061
Postretirement Plans [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation, beginning of year	127,217		103,991
Service cost	10,162		8,060		7,676
Interest cost	5,234		5,521		4,843
Actuarial (gain) loss	(17,514)		(15,895)
MGE acquisition	28,444		0
Gross benefits paid	(8,449)		(6,250)
Benefit obligation, end of year	$ 180,122		$ 127,217		$ 103,991

[1] Includes $79,484 and $60,085 lump-sum payments recognized as settlements in fiscal years 2013 and 2012, respectively.

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ACQUISITION OF MGE Part 2 - Pro Forma Information, Revenues and Earnings of Acquiree (Details) (Missouri Gas Energy (MGE) [Member], USD $) In Thousands, except Per Share data, unless otherwise specified	1 Months Ended
	Sep. 30, 2013
Missouri Gas Energy (MGE) [Member]
Pro Forma Information of Acquiree since Acquisition Date
Total net revenues	$ 21,985
Net Income	$ 1,795
Earnings/(loss) per share:
Basic (in dollars per share)	$ 0.07
Diluted (in dollars per share)	$ 0.07

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Part 1 (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Sep. 30, 2013 customer	Sep. 30, 2012	Sep. 30, 2011
Nature of operations [Abstract]
Population of service area (more than)	1,130,000
Utility Plant, Depreciation and Amortization [Abstract]
Average annual depreciation and amortization expense percentage	3.20%	3.10%	3.10%
Annual capital expenditures	$ 128.5	$ 106.7	$ 67.3
Accruals for capital expenditures	$ 4.7	$ 9.7	$ 8.2

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STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Statement of Comprehensive Income [Abstract]
Net income	$ 52,758	$ 62,640	$ 63,825
Net gains (losses) on cash flow hedging derivative instruments:
Net hedging gain arising during the period	5,047	4,802	5,581
Reclassification adjustment for (gains) losses included in net income	302	(8,397)	1,861
Net unrealized (losses) gains on cash flow hedging derivative instruments	5,349	(3,595)	7,442
Defined benefit pension and other postretirement benefit plans:
Net actuarial (loss) gain arising during the period	(120)	(3,397)	339
Amortization of actuarial loss included in net periodic pension and postretirement benefit cost	195	3,706	426
Net defined benefit pension and other postretirement benefit plans	75	309	765
Other Comprehensive (Loss) Income, Before Tax	5,424	(3,286)	8,207
Income Tax (Benefit) Expense Related to Items of Other Comprehensive (Loss) Income	2,094	(1,270)	3,170
Other Comprehensive (Loss) Income, Net of Tax	3,329	(2,016)	5,037
Comprehensive Income	$ 56,087	$ 60,624	$ 68,862

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STOCK-BASED COMPENSATION

12 Months Ended

Sep. 30, 2013

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

STOCK-BASED COMPENSATION

STOCK-BASED COMPENSATION

The Laclede Group 2006 Equity Incentive Plan (the 2006 Plan) was amended and approved at the annual meeting of shareholders of Laclede Group on January 26, 2012, as discussed below. The purpose of the 2006 Plan is to encourage directors, officers, and employees of the Company and its subsidiaries to contribute to the Company’s success and align their interests with that of shareholders. To accomplish this purpose, the Compensation Committee (Committee) of the Board of Directors may grant awards under the 2006 Plan that may be earned by achieving performance objectives and/or other criteria as determined by the Committee. Under the terms of the 2006 Plan, officers and employees of the Company and its subsidiaries, as determined by the Committee, are eligible to be selected for awards. Effective February 1, 2012, members of the Company’s Board of Directors are also eligible to participate in the 2006 Plan and no additional awards will be granted under the Restricted Stock Plan for Non-Employee Directors. The 2006 Plan provides for restricted stock, restricted stock units, qualified and non-qualified stock options, stock appreciation rights, and performance shares payable in stock, cash, or a combination of both. The 2006 Plan generally provides a minimum vesting period of at least three years for each type of award, with pro rata vesting permitted during the minimum three year vesting period. The maximum number of shares reserved for issuance under the 2006 Plan is 1,250,000. The 2006 Plan replaced the Laclede Group Equity Incentive Plan (the 2003 Plan). Shares reserved under the 2003 Plan, other than those needed for currently outstanding awards, were canceled upon shareholder approval of the 2006 Plan.

The Company issues new shares to satisfy employee restricted stock awards and stock option exercises. Prior to February 1, 2012, shares for non-employee directors were purchased on the open market.

Restricted Stock Awards

During fiscal year 2013, the Company granted 108,419 performance-contingent restricted share units to executive officers and key employees at a weighted average grant date fair value of $34.49 per share. This number represents the maximum shares that can be earned pursuant to the terms of the awards. The share units have a performance period ending September 30, 2014. While the participants have no interim voting rights on these share units, dividends accrue during the performance period and are paid to the participants upon vesting, but are subject to forfeiture if the underlying share units do not vest. The number of share units that will ultimately vest is dependent upon the attainment of certain levels of earnings and other strategic goals, as well as the Company’s level of total shareholder return (TSR) during the performance period relative to a comparator group of companies. This TSR provision is considered a market condition under GAAP and is discussed further below.

The weighted average grant date fair value of performance-contingent restricted shares and share units granted during fiscal years 2012 and 2011 was $36.55 and $30.68 per share, respectively.

Fiscal year 2013 activity of restricted stock and restricted stock units subject to performance and/or market conditions is presented below:

	Shares/ Units		Weighted Average Grant Date Fair Value
Nonvested at September 30, 2012	232,403		$	30.89
Granted (maximum shares that can be earned)	108,419		$	34.49
Vested	(47,436	)	$	27.61
Forfeited	(51,118	)	$	26.11
Nonvested at September 30, 2013	242,268		$	34.15

During fiscal year 2013, the Company granted 43,924 shares of time-vested restricted stock to executive officers and key employees at a weighted average grant date fair value of $40.03 per share. These shares were awarded on October 1, 2012 and December 3, 2012 and vest October 1, 2014 and December 1, 2015, respectively. In the interim, participants receive full voting rights and dividends, which are not subject to forfeiture. The weighted average grant date fair value of time-vested restricted stock and restricted stock units awarded to employees during fiscal year 2012 and 2011 was $39.72 and $35.93 per share, respectively.

During fiscal year 2013, the Company granted 15,200 shares of time-vested restricted stock to non-employee directors at a weighted average grant date fair value of $39.92 per share. The weighted average grant date fair value of restricted stock awarded to non-employee directors during fiscal years 2012 and 2011 was $41.36 and $39.48 per share, respectively. These shares were granted under the Restricted Stock Plan for Non-Employee Directors and vest depending on the participant’s age upon entering the plan and years of service as a director. The plan’s trustee acquired the shares for the awards in the open market and holds the shares as trustee for the benefit of the non-employee directors until the restrictions expire. In the interim, the participants receive full dividends and voting rights. As discussed above, effective February 1, 2012, any awards to non-employee directors will be made pursuant under The Laclede Group 2006 Equity Incentive Plan.

Time-vested restricted stock and stock unit activity for fiscal year 2013 is presented below:

	Shares/ Units		Weighted Average Grant Date Fair Value
Nonvested at September 30, 2012	115,115		$	36.54
Granted	59,124		$	40.00
Vested	(43,785	)	$	34.95
Forfeited	(11,050	)	$	38.61
Nonvested at September 30, 2013	119,404		$	38.64

During fiscal year 2013, 91,221 shares of restricted stock and stock units (performance-contingent and time-vested), awarded on November 4, 2008, December 1, 2009, January 4, 2010, May 3, 2010, and July 1, 2010 vested. The Company withheld 23,311 of the vested shares at a weighted average price of $39.96 per share pursuant to elections by employees to satisfy tax withholding obligations. During fiscal year 2012, 90,839 shares of restricted stock (performance-contingent and time-vested), awarded on February 14, 2008, November 5, 2008, and March 31, 2009, vested. The Company withheld 30,052 of these vested shares at a weighted average price of $40.02 per share pursuant to elections by employees to satisfy tax withholding obligations. During fiscal year 2011, 94,500 shares of performance-contingent restricted stock, awarded on December 5, 2007, vested. The Company withheld 32,373 of these vested shares at a weighted average price of $35.90 per share pursuant to elections by employees to satisfy tax withholding obligations.

The total fair value of restricted stock (performance-contingent and time-vested) vested during fiscal years 2013, 2012, and 2011 was $3.8 million, $4.2 million, and $3.6 million, respectively, and the related actual tax benefit realized was $1.4 million, $1.6 million, and $1.4 million, respectively.

Stock Option Awards

No stock options were granted during fiscal years 2013, 2012, and 2011. Stock option activity for fiscal year 2013 is presented below:

	Stock Options		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (Years)	Aggregate Intrinsic Value ($000)
Outstanding at September 30, 2012	214,000		$	31.02
Granted	—		$	—
Exercised	(80,500	)	$	29.61
Forfeited	—		$	—
Expired	—		$	—
Outstanding at September 30, 2013	133,500		$	31.87	2.8	$	1,752
Fully Vested and Expected to Vest at September 30, 2013	133,500		$	31.87	2.8	$	1,752
Exercisable at September 30, 2013	133,500		$	31.87	2.8	$	1,752

Exercise prices of options outstanding at September 30, 2013 range from $28.85 to $34.95. During fiscal year 2013, cash received from the exercise of stock options was $2.7 million, the intrinsic value of the options exercised was $1.0 million and the related actual tax benefit realized was $0.4 million. During fiscal year 2012, cash received from the exercise of stock options was $2.5 million, the intrinsic value of the options exercised was $1.0 million and the related actual tax benefit realized was $0.4 million. During fiscal year 2011, cash received from the exercise of stock options was $0.9 million, the intrinsic value of the options exercised was $0.2 million and the related actual tax benefit realized was $0.1 million.

The closing price of the Company’s common stock was $45.00 at September 30, 2013.

Equity Compensation Costs

Compensation cost for performance-contingent restricted stock and stock unit awards is based upon the probable outcome of the performance conditions. For shares or units that do not vest or that are not expected to vest due to the outcome of the performance conditions (excluding market conditions), no compensation cost is recognized and any previously recognized compensation cost is reversed.

The fair value of awards of performance-contingent and time-vested restricted stock and restricted stock units, not subject to the TSR provision, is estimated using the closing price of the Company’s stock on the date of the grant. For those awards that do not pay dividends during the vesting period, the estimate of fair value is reduced by the present value of the dividends expected to be paid on the Company’s common stock during the performance period, discounted using an appropriate U.S. Treasury yield. For shares subject to the TSR provision, the estimated impact of this market condition is reflected in the grant date fair value per share of the awards. Accordingly, compensation cost is not reversed to reflect any actual reductions in the awards that may result from the TSR provision. However, if the Company’s TSR during the performance period ranks below the level specified in the award agreements, relative to a comparator group of companies, and the Committee elects not to reduce the award (or reduce by a lesser amount), this election would be accounted for as a modification of the original award and additional compensation cost would be recognized at that time. The grant date fair value of the awards subject to the TSR provision awarded during fiscal years 2013, 2012, and 2011 was valued by a Monte Carlo simulation model that assessed the probabilities of various TSR outcomes. The significant assumptions used in the Monte Carlo simulations are as follows:

	2013		2012		2011
Risk free interest rate	0.32	%	0.39	%	0.79	%
Expected dividend yield of stock	—		—		—
Expected volatility of stock	19.60	%	23.21	%	33.42	%
Vesting period	2.8 years		2.8 years		2.8 years

The risk free interest rate was based on the yield on U.S. Treasury securities matching the vesting period. The expected volatility is based on the historical volatility of the Company’s stock. Volatility assumptions were also made for each of the companies included in the comparator group. The vesting period is equal to the performance period set forth in the terms of the award.

The amounts of compensation cost recognized for share-based compensation arrangements are presented below:

(Thousands)	2013			2012			2011
Total equity compensation cost	$	4,453		$	2,707		$	3,980
Compensation cost capitalized	(1,366		)	(808		)	(924		)
Compensation cost recognized in net income	3,087			1,899			3,056
Income tax benefit recognized in net income	(1,182		)	(733		)	(1,179		)
Compensation cost recognized in net income, net of income tax	1,905			1,166			1,877

As of September 30, 2013, there was $4.9 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements. That cost is expected to be recognized over a weighted average period of 2.0 years.

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Assets
Non-utility property (net of accumulated depreciation and amortization)	$ 5,886	$ 10,018

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 6 (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013
Pension Plans [Member]
Pre-tax amounts are expected to be amortized from accumulated other comprehensive income [Abstract]
Amortization of net actuarial loss	$ 7,088
Amortization of prior service cost	497
Sub-total	7,585
Regulatory adjustment	(7,196)
Total Expected to be Amortized	389
Postretirement Plans [Member]
Pre-tax amounts are expected to be amortized from accumulated other comprehensive income [Abstract]
Amortization of net actuarial loss	6,021
Amortization of prior service cost	(4)
Sub-total	6,017
Regulatory adjustment	(6,017)
Total Expected to be Amortized	$ 0

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STATEMENTS OF CONSOLIDATED INCOME (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Operating Revenues:
Gas Utility	$ 847,224	$ 763,447	$ 913,190
Gas Marketing	165,146	358,145	669,375
Other	4,649	3,883	20,742
Total Operating Revenues	1,017,019	1,125,475	1,603,307
Gas Utility
Natural and propane gas	433,442	397,304	549,947
Other operation and maintenance expenses	180,342	167,351	172,938
Depreciation and amortization	48,283	40,739	39,214
Taxes, other than income taxes	60,079	53,672	60,752
Total Gas Utility Operating Expenses	722,146	659,066	822,851
Gas Marketing	176,554	353,283	652,567
Other	21,825	2,524	9,642
Total Operating Expenses	920,525	1,014,873	1,485,060
Operating Income	96,494	110,602	118,247
Other Income and (Income Deductions) – Net	2,444	3,272	177
Interest Charges:
Interest on long-term debt	25,539	22,958	23,161
Other interest charges	3,063	1,987	2,256
Total Interest Charges	28,602	24,945	25,417
Income Before Income Taxes	70,336	88,929	93,007
Income Tax Expense	17,578	26,289	29,182
Net Income	$ 52,758	$ 62,640	$ 63,825
Weighted Average Number of Common Shares Outstanding:
Basic (in shares)	25,875	22,262	22,099
Diluted (in shares)	25,952	22,340	22,171
Basic Earnings Per Share of Common Stock (in dollars per share)	$ 2.03	$ 2.80	$ 2.87
Diluted Earnings Per Share of Common Stock (in dollars per share)	$ 2.02	$ 2.79	$ 2.86

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ACQUISITION OF MGE Part 3 - Preliminary Fair Value of Assets Acquired and Liabilities Assumed (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 01, 2013 Missouri Gas Energy (MGE) [Member]
Assets:
Utility plant			$ 671,793
Non-utility property			238
Other investments			3,096
Goodwill	247,078	0	247,078
Other Property and Investments			922,205
Accounts receivable:
Utility			19,963
Other			6,119
Delayed customer billings			10,701
Inventories:
Natural gas stored underground			58,679
Materials and supplies at average cost			3,988
Prepayments and other			487
Total Current Assets			99,937
Deferred Charges:
Regulatory assets			84,014
Other			4,928
Total Deferred Charges			88,942
Total Assets Acquired			1,111,084
Liabilities:
Accounts payable			20,154
Wages and compensation accrued			5,088
Customer deposits			8,362
Interest accrued			183
Taxes accrued			17,197
Other			12,620
Total Current Liabilities			63,604
Pension and postretirement benefit costs			24,466
Asset retirement obligations			32,056
Regulatory liabilities			2,249
Regulatory liabilities			13,709
Total Deferred Credits and Other Liabilities			72,480
Total Liabilities Assumed			136,084
Net Assets Acquired			$ 975,000

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INFORMATION BY OPERATING SEGMENT (Details) (USD $)	3 Months Ended									12 Months Ended
	Sep. 30, 2013 subsidiary		Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2013 subsidiary		Sep. 30, 2012		Sep. 30, 2011
Segment Reporting [Abstract]
Number of entity subsidiaries	7									7
Amount of depreciation and amortization for Non-Regulated Gas Marketing included in Non-Regulated Gas Marketing Expenses on the Statements of Consolidated Income										$ 300,000		$ 300,000		$ 100,000
Amount of depreciation, amortization, and accretion for Other included in Other Operating Expenses on the Statements of Consolidated Income										600,000		300,000		200,000
After-tax earnings resulting from the non-regulated sale of propane inventory														6,100,000
Reconciliation of Consolidated Net Income to Consolidated Net Economic Earnings
Net income	(9,636,000)	[1]	6,584,000	30,242,000	25,568,000	(651,000)	8,433,000	29,684,000	25,174,000	52,758,000		62,640,000		63,825,000
Unrealized loss (gain) on energy-related derivatives										614,000		(314,000)		(1,415,000)
Lower of cost or market inventory adjustments										868,000		0		0
Realized (gain) loss on economic hedges prior to the sale of the physical commodity										(25,000)		163,000		0
Acquisition, divestiture and restructuring activities										10,797,000		123,000		0
Net Economic Earnings (Non-GAAP)										65,012,000		62,612,000		62,410,000
Operating Segment Information [Abstract]
Total revenues including intersegment revenues										1,017,019,000		1,125,475,000		1,576,360,000
Total Operating Revenues	147,114,000	[1]	165,289,000	397,613,000	307,003,000	169,538,000	186,849,000	358,175,000	410,913,000	1,017,019,000		1,125,475,000		1,603,307,000
Gas Utility
Natural and propane gas										433,442,000		397,304,000		549,947,000
Other operation and maintenance expenses										180,342,000		167,351,000		172,938,000
Depreciation & amortization										48,283,000		40,739,000		39,214,000
Taxes, other than income taxes										60,079,000		53,672,000		60,752,000
Total Gas Utility Operating Expenses										722,146,000		659,066,000		822,851,000
Gas Marketing										176,554,000		353,283,000		652,567,000
Other										21,825,000		2,524,000		9,642,000
Costs and Expenses										920,525,000		1,014,873,000		1,485,060,000
Operating Income	(9,722,000)	[1]	12,282,000	51,849,000	42,085,000	1,869,000	15,045,000	50,583,000	43,105,000	96,494,000		110,602,000		118,247,000
Interest income										1,088,000		1,309,000		1,136,000
Interest charges										28,602,000		24,945,000		25,417,000
Income Tax Expense										17,578,000		26,289,000		29,182,000
Net Economic Earnings (Non-GAAP)										65,012,000		62,612,000		62,410,000
Total assets	3,125,386,000					1,880,262,000				3,125,386,000		1,880,262,000		1,783,082,000
Capital expenditures										130,788,000		108,843,000		67,638,000
Intersegment Revenues [Member]
Operating Segment Information [Abstract]
Total revenues including intersegment revenues										0		0		26,947,000
Gas Utility [Member]
Reconciliation of Consolidated Net Income to Consolidated Net Economic Earnings
Net Economic Earnings (Non-GAAP)										56,635,000		48,089,000		46,952,000
Operating Segment Information [Abstract]
Total revenues including intersegment revenues										847,224,000		763,447,000		911,614,000
Total Operating Revenues										857,762,000		764,651,000		913,190,000
Gas Utility
Natural and propane gas										469,098,000		414,846,000		549,947,000
Other operation and maintenance expenses										180,702,000		167,351,000		172,938,000
Depreciation & amortization										48,283,000		40,739,000		39,214,000
Taxes, other than income taxes										60,079,000		53,672,000		60,752,000
Total Gas Utility Operating Expenses										758,162,000		676,608,000		822,851,000
Gas Marketing										0		0		0
Other										0		0		0
Costs and Expenses										758,162,000		676,608,000		822,851,000
Operating Income										99,599,000		88,043,000		90,339,000
Interest income										947,000		1,230,000		1,057,000
Interest charges										26,137,000		25,156,000		25,544,000
Income Tax Expense										19,243,000		17,393,000		18,694,000
Net Economic Earnings (Non-GAAP)										56,635,000		48,089,000		46,952,000
Total assets	2,981,016,000					1,758,952,000				2,981,016,000		1,758,952,000		1,641,386,000
Capital expenditures										128,496,000		106,734,000		67,304,000
Gas Utility [Member] | Intersegment Revenues [Member]
Operating Segment Information [Abstract]
Total revenues including intersegment revenues										10,538,000		1,204,000		1,576,000
Gas Marketing [Member]
Reconciliation of Consolidated Net Income to Consolidated Net Economic Earnings
Net Economic Earnings (Non-GAAP)										8,936,000		12,273,000		8,962,000
Operating Segment Information [Abstract]
Total revenues including intersegment revenues										165,146,000		358,145,000		645,042,000
Total Operating Revenues										189,331,000		373,475,000		669,375,000
Gas Utility
Natural and propane gas										0		0		0
Other operation and maintenance expenses										0		0		0
Depreciation & amortization										0		0		0
Taxes, other than income taxes										0		0		0
Total Gas Utility Operating Expenses										0		0		0
Gas Marketing										176,554,000	[2]	353,286,000	[2]	652,567,000	[2]
Other										0		0		0
Costs and Expenses										176,554,000		353,286,000		652,567,000
Operating Income										12,777,000		20,189,000		16,808,000
Interest income										103,000		175,000		165,000
Interest charges										135,000		81,000		14,000
Income Tax Expense										5,162,000		7,966,000		6,570,000
Net Economic Earnings (Non-GAAP)										8,936,000		12,273,000		8,962,000
Total assets	163,944,000					190,709,000				163,944,000		190,709,000		175,352,000
Capital expenditures										44,000		140,000		215,000
Gas Marketing [Member] | Intersegment Revenues [Member]
Operating Segment Information [Abstract]
Total revenues including intersegment revenues										24,185,000		15,330,000		24,333,000
Other [Member]
Reconciliation of Consolidated Net Income to Consolidated Net Economic Earnings
Net Economic Earnings (Non-GAAP)										(559,000)		2,250,000		6,496,000	[3]
Operating Segment Information [Abstract]
Total revenues including intersegment revenues										4,649,000		3,883,000		19,704,000
Total Operating Revenues										6,274,000		4,925,000		20,742,000
Gas Utility
Natural and propane gas										0		0		0
Other operation and maintenance expenses										0		0		0
Depreciation & amortization										0		0		0
Taxes, other than income taxes										0		0		0
Total Gas Utility Operating Expenses										0		0		0
Gas Marketing										0		0		0
Other										22,157,000	[4]	2,555,000	[4]	9,642,000	[4]
Costs and Expenses										22,157,000		2,555,000		9,642,000
Operating Income										(15,882,000)		2,370,000		11,100,000
Interest income										343,000		371,000		217,000
Interest charges										2,635,000		175,000		162,000
Income Tax Expense										(6,827,000)		930,000		3,918,000
Net Economic Earnings (Non-GAAP)										(559,000)		2,250,000		6,496,000	[3]
Total assets	115,560,000					102,241,000				115,560,000		102,241,000		129,176,000
Capital expenditures										2,248,000		1,969,000		119,000
Other [Member] | Intersegment Revenues [Member]
Operating Segment Information [Abstract]
Total revenues including intersegment revenues										1,625,000		1,042,000		1,038,000
Eliminations [Member]
Reconciliation of Consolidated Net Income to Consolidated Net Economic Earnings
Net Economic Earnings (Non-GAAP)										0		0		0
Operating Segment Information [Abstract]
Total revenues including intersegment revenues										0		0		0
Total Operating Revenues										(36,348,000)		(17,576,000)		0
Gas Utility
Natural and propane gas										(35,656,000)		(17,542,000)		0
Other operation and maintenance expenses										(360,000)		0		0
Depreciation & amortization										0		0		0
Taxes, other than income taxes										0		0		0
Total Gas Utility Operating Expenses										(36,016,000)		(17,542,000)		0
Gas Marketing										0		(3,000)		0
Other										(332,000)		(31,000)		0
Costs and Expenses										(36,348,000)		(17,576,000)		0
Operating Income										0		0		0
Interest income										(305,000)		(467,000)		(303,000)
Interest charges										(305,000)		(467,000)		(303,000)
Income Tax Expense										0		0		0
Net Economic Earnings (Non-GAAP)										0		0		0
Total assets	(135,134,000)					(171,640,000)				(135,134,000)		(171,640,000)		(162,832,000)
Capital expenditures										0		0		0
Eliminations [Member] | Intersegment Revenues [Member]
Operating Segment Information [Abstract]
Total revenues including intersegment revenues										$ (36,348,000)		$ (17,576,000)		$ 0

[1] All quarters of 2013 reflect transaction costs incurred associated with the acquisition of MGE. The fourth quarter of 2013 includes one month of activity of the operations of MGE, significant transaction costs incurred in the quarter and the interest impact of the debt issued in the quarter. Total impact of all of these during the quarter was a decrease in net income of $5.5 million.

[2] Depreciation and amortization for Gas Marketing is included in Gas Marketing Expenses on the Statements of Consolidated Income ($0.3 million for fiscal year 2013, $0.3 million for fiscal year 2012, and $0.1 million for fiscal year 2011).

[3] Net economic earnings include income realized by the Utility from separate non-regulated sales of propane inventory no longer needed to serve utility customers, of which occurred in fiscal year 2011. This transaction resulted in after-tax earnings totaling $6.1 million.

[4] Depreciation, amortization, and accretion for Other is included in the Other Operating Expenses on the Statements of Consolidated Income ($0.6 million for fiscal year 2013, $0.3 million for fiscal year 2012 and $0.2 million for fiscal year 2011).

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES Part 2 (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2011
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Derivatives in Cash Flow Hedging Relationships [Abstract]
Effective portion of gain (loss) reclassified from AOCI to income	$ (302)		$ 8,397		$ (1,861)
Ineffective portion of gain (loss) on derivatives recognized in income	(786)		(124)		(344)
Designated as Hedging Instrument [Member] | NYMEX Natural Gas Contracts [Member] | Cash Flow Hedging [Member]
Derivatives in Cash Flow Hedging Relationships [Abstract]
Effective portion of gain (loss) reclassified from AOCI to income	(513)		8,397		(2,327)
Ineffective portion of gain (loss) on derivatives recognized in income	(659)		(299)		(356)
Designated as Hedging Instrument [Member] | NYMEX Natural Gas Contracts [Member] | Other Comprehensive Income (Loss) [Member] | Cash Flow Hedging [Member]
Derivatives in Cash Flow Hedging Relationships [Abstract]
Effective portion of gain (loss) recognized in OCI on derivatives	4,923		4,505		5,226
Designated as Hedging Instrument [Member] | NYMEX Natural Gas Contracts [Member] | Non-Regulated Gas Marketing Operating Revenue [Member] | Cash Flow Hedging [Member]
Derivatives in Cash Flow Hedging Relationships [Abstract]
Effective portion of gain (loss) reclassified from AOCI to income	(4)		18,929		7,443
Ineffective portion of gain (loss) on derivatives recognized in income	(420)		(36)		966
Designated as Hedging Instrument [Member] | NYMEX Natural Gas Contracts [Member] | Non-Regulated Gas Marketing Operating Expenses [Member] | Cash Flow Hedging [Member]
Derivatives in Cash Flow Hedging Relationships [Abstract]
Effective portion of gain (loss) reclassified from AOCI to income	(509)		(10,532)		(9,770)
Ineffective portion of gain (loss) on derivatives recognized in income	(239)		(263)		(1,322)
Designated as Hedging Instrument [Member] | NYMEX Gasoline and Heating Oil Contracts [Member] | Cash Flow Hedging [Member]
Derivatives in Cash Flow Hedging Relationships [Abstract]
Effective portion of gain (loss) recognized in OCI on derivatives	5,046		4,802		5,581
Designated as Hedging Instrument [Member] | NYMEX Gasoline and Heating Oil Contracts [Member] | Other Comprehensive Income (Loss) [Member] | Cash Flow Hedging [Member]
Derivatives in Cash Flow Hedging Relationships [Abstract]
Effective portion of gain (loss) recognized in OCI on derivatives	123		297		355
Designated as Hedging Instrument [Member] | NYMEX Gasoline and Heating Oil Contracts [Member] | Regulated Gas Distribution Other Operation Expenses [Member] | Cash Flow Hedging [Member]
Derivatives in Cash Flow Hedging Relationships [Abstract]
Effective portion of gain (loss) reclassified from AOCI to income	211		0		466
Ineffective portion of gain (loss) on derivatives recognized in income	(127)		175		12
Not Designated as Hedging Instrument [Member] | NYMEX Natural Gas Contracts [Member] | Non-Regulated Gas Marketing Operating Revenue [Member]
Derivatives Not Designated as Hedging Instruments [Abstract]
Gain (loss) recognized in income on derivatives	(778)	[1]	(615)	[1]	(115)	[1]
Not Designated as Hedging Instrument [Member] | NYMEX Natural Gas Contracts [Member] | Non-Regulated Gas Marketing Operating Expenses [Member]
Derivatives Not Designated as Hedging Instruments [Abstract]
Gain (loss) recognized in income on derivatives	0	[1]	(625)	[1]	(3)	[1]
Not Designated as Hedging Instrument [Member] | NYMEX Gasoline and Heating Oil Contracts [Member]
Derivatives Not Designated as Hedging Instruments [Abstract]
Gain (loss) recognized in income on derivatives	(815)	[1]	3,248	[1]	3,488	[1]
Not Designated as Hedging Instrument [Member] | NYMEX Gasoline and Heating Oil Contracts [Member] | Other Income and (Income Deduction) - Net [Member]
Derivatives Not Designated as Hedging Instruments [Abstract]
Gain (loss) recognized in income on derivatives	41	[1]	19	[1]	37	[1]
Not Designated as Hedging Instrument [Member] | Natural Gas Commodity Contracts [Member] | Non-Regulated Gas Marketing Operating Revenue [Member]
Derivatives Not Designated as Hedging Instruments [Abstract]
Gain (loss) recognized in income on derivatives	(78)	[1]	3,782	[1]	(660)	[1]
Not Designated as Hedging Instrument [Member] | Natural Gas Commodity Contracts [Member] | Non-Regulated Gas Marketing Operating Expenses [Member]
Derivatives Not Designated as Hedging Instruments [Abstract]
Gain (loss) recognized in income on derivatives	$ 0	[1]	$ 687	[1]	$ 4,229	[1]

[1] Gains and losses on the Utility’s natural gas derivative instruments, which are not designated as hedging instruments for financial reporting purposes, are deferred pursuant to the Utility’s PGA Clause and initially recorded as regulatory assets or regulatory liabilities. These gains and losses are excluded from the table above because they have no direct impact on the Statements of Consolidated Income. Such amounts are recognized in the Statements of Consolidated Income as a component of Regulated Gas Distribution Natural and Propane Gas operating expenses when they are recovered through the PGA Clause and reflected in customer billings.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

12 Months Ended

Sep. 30, 2013

Accounting Policies [Abstract]

BASIS OF CONSOLIDATION

BASIS OF CONSOLIDATION - The consolidated financial statements include the accounts of Laclede Group and its subsidiary companies, including the recent acquisition of Missouri Gas Energy (MGE). All subsidiaries are wholly owned. Laclede Gas and other subsidiaries of Laclede Group may engage in related party transactions during the ordinary course of business. All material intercompany balances have been eliminated from the consolidated financial statements of Laclede Group. Transactions include sales of natural gas and transportation services between subsidiaries. These revenues are shown on the Intersegment revenues lines in the table included in Note 15, Information by Operating Segment.

USE OF ESTIMATES

USE OF ESTIMATES - The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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.

SYSTEM OF ACCOUNTS

SYSTEM OF ACCOUNTS - The accounts of Laclede Gas are maintained in accordance with the Uniform System of Accounts prescribed by the Missouri Public Service Commission (MoPSC or Commission), which system substantially conforms to that prescribed by the Federal Energy Regulatory Commission (FERC).

UTILITY PLANT, DEPRECIATION AND AMORTIZATION

UTILITY PLANT, DEPRECIATION AND AMORTIZATION - 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.

Utility plant is depreciated on a straight-line basis at rates based on estimated service lives of the various classes of property. In fiscal year 2013, annual depreciation and amortization expense averaged 3.2% of the original cost of depreciable and amortizable property, compared to 3.1% in both fiscal years 2012 and 2011.

The Utility’s capital expenditures were $128.5 million, $106.7 million, and $67.3 million for fiscal years 2013, 2012, and 2011, respectively. Additionally, the Utility had recorded accruals for capital expenditures totaling $4.7 million at September 30, 2013, $9.7 million at September 30, 2012, and $8.2 million at September 30, 2011. Accrued capital expenditures are excluded from the Statements of Consolidated Cash Flows.

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS - Laclede Group 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 has recorded 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 Utility’s distribution system and general plant. Asset retirement obligations recorded by Laclede Group’s other subsidiaries are not material. As authorized by the MoPSC, the Utility accrues future asset removal costs associated with its property, plant and equipment even if a legal obligation does not exist. Such accruals are provided for through depreciation expense and are recorded with corresponding credits to regulatory liabilities. When the Utility retires depreciable utility plant and equipment, it charges the associated original costs to accumulated depreciation and amortization, and any related removal costs incurred are charged to regulatory liabilities. The difference between removal costs recognized in depreciation rates and the accretion expense and depreciation expense recognized for financial reporting purposes is a timing difference between recovery of these costs in rates and their recognition for financial reporting purposes.

Accordingly, these differences are deferred as regulatory liabilities. In the rate setting process, the regulatory liability is deducted from the rate base upon which the Utility has the opportunity to earn its allowed rate of return.

As part of the MGE acquisition, the Utility has estimated the asset retirement obligation of MGE’s long-lived assets as of the acquisition date. This allocation of asset retirement obligations is preliminary and will be finalized upon completion of a detailed fair value analysis that is being performed by the Company in the first quarter of fiscal 2014.

REGULATED OPERATIONS

REGULATED OPERATIONS - The Utility accounts for its regulated operations in accordance with ASC Topic 980. This Topic sets forth the application of generally accepted accounting principles in the United States of America (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 Consolidated Balance Sheets as of September 30:

(Thousands)	2013		2012
Regulatory Assets:
Future income taxes due from customers	$	112,912	$	118,997
Pension and postretirement benefit costs	381,395		304,446
Unamortized purchased gas adjustments	17,533		40,674
Purchased gas costs	18,249		18,386
Compensated absences	8,004		7,836
Other	25,387		6,382
Total Regulatory Assets	$	563,480	$	496,721
Regulatory Liabilities:
Unamortized investment tax credits	$	2,900	$	3,113
Accrued cost of removal	59,066		55,103
Other	23,494		1,216
Total Regulatory Liabilities	$	85,460	$	59,432

The regulatory assets are expected to be recovered in rates charged to customers. A portion of the Company's regulatory assets are not earning a return; however, these regulatory assets are expected to be recovered from customers in future rates. Excluding deferred income taxes and purchased gas adjustment items, as of September 30, 2013 and 2012, approximately $17.2 million and $7.8 million, respectively, of regulatory assets were not earning a rate of return. The Company expects these items to be recovered over a period not to exceed 15 years consistent with precedent set by the MoPSC. The portion of the regulatory asset related to pensions and other postemployment benefits that relates to unfunded differences between the projected benefit obligation and plan assets also does not earn a rate of return.

As authorized by the MoPSC, the Utility discontinued deferring certain costs for future recovery, as expenses associated with those specific areas were included in approved rates effective December 27, 1999. Previously deferred costs of $10.5 million are being recovered and amortized on a straight-line basis over a fifteen-year period, without return on investment. Amortization of these costs totaled $9.7 million from December 27, 1999 through September 30, 2013.

NATURAL GAS STORED UNDERGROUND AND PROPANE GAS

NATURAL GAS STORED UNDERGROUND AND PROPANE GAS – For Laclede Gas, inventory of natural gas in storage is priced on a last-in, first-out (LIFO) basis and inventory of propane gas in storage is priced on a first-in, first-out (FIFO) basis. For MGE, inventory of natural gas in storage is priced on a weighted average cost basis. The replacement cost of Laclede Gas' natural gas stored underground for current use at September 30, 2013 and September 30, 2012 was less than the LIFO cost by $13.3 million and $24.3 million, respectively. The carrying value of the Utility inventory is not adjusted to the lower of cost or market prices because, pursuant to both Laclede Gas' and MGE's Purchased Gas Adjustment (PGA) Clauses, actual gas costs are recovered in customer rates. Natural gas and propane gas storage inventory in Laclede Group’s other operating segments is recorded at the lower of average cost or market.

BUSINESS COMBINATIONS

BUSINESS COMBINATIONS - The Company's acquisition of MGE was accounted for by the Company using business combination accounting. Under this method, the purchase price paid by the acquirer is allocated to the assets acquired and liabilities assumed as of the acquisition date based on their fair value. For additional information on the Company's acquisition of MGE, refer to Note 2, MGE Acquisition.

GOODWILL

GOODWILL - Goodwill is measured as the excess of the acquisition-date fair value of the consideration transferred over the amount of acquisition-date identifiable assets acquired net of assumed liabilities. Laclede Group recorded $247.1 million of goodwill as part of the MGE acquisition.

REVENUE RECOGNITION

REVENUE RECOGNITION - The Utility reads meters and bills its customers on monthly cycles. The Utility records its Gas Utility revenues from gas sales and transportation services on an accrual basis that includes estimated amounts for gas delivered, but not yet billed. The accruals for unbilled revenues are reversed in the subsequent accounting period when meters are actually read and customers are billed. The amounts of accrued unbilled revenues at September 30, 2013 and 2012, for the Utility, were $25.2 million and $11.6 million, respectively.

Laclede Group’s other subsidiaries, including LER, record revenues when earned, either when the product is delivered or when services are performed.

In the course of its business, LER enters into commitments associated with the purchase or sale of natural gas. Certain of LER’s derivative natural gas contracts are designated as normal purchases or normal sales, and, as such, are excluded from the scope of ASC Topic 815, “Derivatives and Hedging.” Those contracts are accounted for as executory contracts and recorded on an accrual basis. Revenues and expenses from such contracts are recorded using a gross presentation. Contracts not designated as normal purchases or normal sales are recorded as derivatives with changes in fair value recognized in earnings in the periods prior to physical delivery. For additional information on derivative instruments, refer to Note 11, Derivative Instruments and Hedging Activities. Certain of LER’s wholesale purchase and sale transactions entered on or after January 1, 2012 are classified as trading activities for financial reporting purposes. Under GAAP, revenues and expenses associated with trading activities are presented on a net basis in Gas Marketing Operating Revenues in the Statements of Consolidated Income. This net presentation has no effect on operating income or net income.

PURCHASED GAS ADJUSTMENTS AND DEFERRED ACCOUNT

PURCHASED GAS ADJUSTMENTS AND DEFERRED ACCOUNT – As authorized by the MoPSC, the PGA Clause allows Laclede Gas to flow through to customers, subject to prudence review by the MoPSC, the cost of purchased gas supplies. To better match customer billings with market natural gas prices, the Utility is allowed to file to modify, on a periodic basis, the level of gas costs in its PGA. Certain provisions of the PGA Clause are included below:

• The Utility has a risk management policy that allows for the purchase of natural gas derivative instruments with the goal of managing price risk associated with purchasing natural gas on behalf of its customers. The MoPSC clarified that costs, cost reductions, and carrying costs associated with the Utility’s use of natural gas derivative instruments are gas costs recoverable through the PGA mechanism.

• The tariffs allow the Utility flexibility to make up to three discretionary PGA changes during each year, in addition to its mandatory November PGA change, so long as such changes are separated by at least two months.

• The Utility is authorized to recover gas inventory carrying costs through its PGA rates to recover costs it incurs to finance its investment in gas supplies that are purchased during the storage injection season for sale during the heating season. The Utility is also authorized to apply carrying costs to all over- or under-recoveries of gas costs, including costs and cost reductions associated with the use of derivative instruments, including cash payments for margin deposits.

• The MoPSC approved a plan applicable to Laclede Gas' gas supply commodity costs under which it retains a portion of cost savings associated with the acquisition of natural gas below an established benchmark level. This gas supply cost management program allows Laclede Gas to retain 10% of cost savings, up to a maximum of $3.0 million annually. Laclede Gas did not record any income under the plan during the three fiscal years reported. Income recorded under the plan, if any, is included in Gas Utility Operating Revenues on the Statements of Consolidated Income.

Pursuant to the provisions of the PGA Clause, the difference between actual costs incurred and costs recovered through the application of the PGA are reflected as a deferred charge or credit at the end of the fiscal year. These costs include costs and cost reductions associated with the use of derivative instruments and gas inventory carrying costs, amounts due to or from customers related to operation of the gas supply cost management program, refunds received from the Company’s suppliers in connection with gas supply, transportation, and storage services, and carrying costs on such over- or under-recoveries. At that time, the balance is classified as a current asset or current liability and recovered from, or credited to, customers over an annual period commencing in November. The balance in the current account is amortized as amounts are reflected in customer billings. The PGA Clause also provides for the treatment of income from off-system sales and capacity release revenues. Pre-tax income from off-system sales and capacity release revenues is shared with customers, with an estimated amount assumed in PGA rates. The difference between the actual amount allocated to customers for each fiscal year and the estimated amount assumed in PGA rates is recovered from, or credited to, customers over an annual period commencing in the subsequent November. The customer share of such income is determined in accordance with the tables below, which is shown for each legacy company (Laclede Gas and MGE) under which the PGA Clauses were approved by the MoPSC.

Laclede Gas
Pre-tax Income	Customer Share	Company Share
First $2 million	100%	—%
Next $2 million	80%	20%
Next $2 million	75%	25%
Amounts exceeding $6 million	70%	30%
MGE
Pre-tax Income	Customer Share	Company Share
First $1.2 million	85%	15%
Next $1.2 million	80%	20%
Next $1.2 million	75%	25%
Amounts exceeding $3.6 million	70%	30%

INCOME TAXES

INCOME TAXES - Laclede Group and its subsidiaries have elected, for tax purposes only, various accelerated depreciation provisions of the Internal Revenue Code. In addition, certain other costs are expensed currently for tax purposes while being deferred for book purposes. GAAP permits the benefit from a tax position to be recognized only if, and to the extent that, it is more likely than not that the tax position will be sustained upon examination by the taxing authority, based on the technical merits of the position. Unrecognized tax benefits and related interest and penalties, if any, are recorded as liabilities or as a reduction to deferred tax assets. Laclede Group companies record deferred tax liabilities and assets measured by enacted tax rates for the net tax effect of all temporary differences between the tax basis and the related carrying amounts of assets and liabilities in the financial statements. Changes in enacted tax rates, if any, and certain property basis differences are reflected by entries to regulatory asset or regulatory liability accounts for regulated companies, and are reflected as income or loss for non-regulated companies.

The Utility’s investment tax credits utilized prior to 1986 have been deferred and are being amortized in accordance with regulatory treatment over the useful life of the related property.

CASH AND CASH EQUIVALENTS

CASH AND CASH EQUIVALENTS - All highly liquid debt instruments purchased with original maturities of three months or less are considered to be cash equivalents. Such instruments are carried at cost, which approximates market value.

Outstanding checks on the Company’s controlled disbursement bank accounts in excess of funds on deposit create book overdrafts (which are funded at the time checks are presented for payment) and are classified as Other in the Current Liabilities section of the Consolidated Balance Sheets. Changes in book overdrafts between periods are reflected as Financing Activities in the Statements of Consolidated Cash Flows.

NATURAL GAS RECEIVABLE

NATURAL GAS RECEIVABLE – LER enters into natural gas transactions with natural gas pipeline companies known as park and loan arrangements. Under the terms of the arrangements, LER purchases natural gas from a third party and delivers that natural gas to the pipeline company for the right to receive the same quantity of natural gas from the pipeline company at the same location in a future period. These arrangements are accounted for as non-monetary transactions under GAAP and are recorded at the carrying amount. As such, natural gas receivables are reflected on the Consolidated Balance Sheets at cost, which includes related pipeline fees associated with the transactions. In the period that the natural gas is returned to LER, concurrent with the sale of the natural gas to a third party, the related natural gas receivable is expensed in the Statements of Consolidated Income. In conjunction with these transactions, LER usually enters into New York Mercantile Exchange (NYMEX) and Ice Clear Europe (ICE) natural gas futures, options, and swap contracts or fixed price sales agreements to protect against market changes in future sales prices.

EARNINGS PER COMMON SHARE

EARNINGS PER COMMON SHARE - GAAP requires dual presentation of basic and diluted earnings per share (EPS). EPS is computed using the two-class method, which is an earnings allocation method for computing EPS that treats a participating security as having rights to earnings that would otherwise have been available to common shareholders. Certain of the Company’s stock-based compensation awards pay nonforfeitable dividends to the participants during the vesting period and, as such, are deemed participating securities. Basic EPS is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding that are increased for additional shares that would be outstanding if potentially dilutive non-participating securities were converted to common shares, pursuant to the treasury stock method. Shares attributable to non-participating stock options and time-vested restricted stock/units are excluded from the calculation of diluted earnings per share if the effect would be antidilutive. Shares attributable to non-participating performance-contingent restricted stock awards are only included in the calculation of diluted earnings per share to the extent the underlying performance and/or market conditions are satisfied (a) prior to the end of the reporting period or (b) would be satisfied if the end of the reporting period were the end of the related contingency period and the result would be dilutive. The Company’s EPS computations are presented in Note 5, Earnings Per Common Share.

GROSS RECEIPTS AND SALES TAXES

GROSS RECEIPTS AND SALES TAXES - Gross receipts taxes associated with the Utility's natural gas utility service are imposed on the Utility and billed to its customers. These amounts are recorded gross in the Statements of Consolidated Income. Amounts recorded in Gas Utility Operating Revenues were $40.8 million, $35.9 million, and $43.5 million for fiscal years 2013, 2012, and 2011, respectively. Gross receipts taxes are expensed by the Utility and included in the Taxes, other than income taxes line.

Sales taxes imposed on applicable Company sales are billed to customers. These amounts are not recorded in the Statements of Consolidated Income, but are recorded as tax collections payable and included in the Other line of the Current Liabilities section of the Consolidated 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 collectibility 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. The Utility’s provision for uncollectible accounts includes the amortization of previously deferred uncollectible expenses, as approved by the MoPSC.

GROUP MEDICAL AND WORKERS' COMPENSATION RESERVES

GROUP MEDICAL AND WORKERS’ COMPENSATION RESERVES - The Company self-insures its group medical and workers’ compensation costs and carries stop-loss coverage in relation to medical claims 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. Additional information about fair value measurements is provided in Note 3, Pension Plans and Other Postretirement Benefits, Note 9, Fair Value of Financial Instruments, and Note 10, Fair Value Measurements.

STOCK-BASED COMPENSATION

STOCK-BASED COMPENSATION – The Company measures stock-based compensation awards at fair value at the date of grant and recognizes the compensation cost of the awards over the requisite service period. Forfeitures are estimated at the time of grant and revised, if necessary, in subsequent periods if the actual forfeitures differ from those estimates. Refer to Note 4, Stock-Based Compensation, for further discussion of the accounting for the Company’s stock-based compensation plans.

NEW ACCOUNTING STANDARDS

NEW ACCOUNTING STANDARDS – In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities,” to amend ASC Topic 210, “Balance Sheet,” to require additional disclosures about financial instruments and derivative instruments that have been presented on a net basis (offset) in the balance sheet. Additionally, information about financial instruments and derivative instruments that are subject to enforceable master netting arrangements or similar agreements, irrespective of whether they are presented net in the balance sheet, is required to be disclosed. The ASU impacts disclosures only and will not require any changes to financial statement presentation. The Company will present the new disclosures retrospectively beginning in the first quarter of fiscal year 2014.

In February 2013, the FASB issued ASU No. 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income.” This ASU amends Accounting Standards Codification (ASC) Topic 220, “Comprehensive Income,” by requiring entities to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to provide information on significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income, but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. The Company will present the new disclosures prospectively beginning in the first quarter of fiscal year 2014.

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INCOME TAXES

12 Months Ended

Sep. 30, 2013

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

The net provisions for income taxes charged during the fiscal years ended September 30, 2013, 2012, and 2011 are as follows:

(Thousands)	2013			2012			2011
Included in Statements of Consolidated Income:
Federal
Current	$	(4,173	)	$	(3,835	)	$	4,724
Deferred	19,925			26,365			20,602
Investment tax credits	(213		)	(213		)	(213		)
State and local
Current	(301		)	(430		)	573
Deferred	2,340			4,402			3,496
Total Income Tax Expense	$	17,578		$	26,289		$	29,182

The effective income tax rate varied from the federal statutory income tax rate for each year due to the following:

	2013		2012		2011
Federal income tax statutory rate	35.0	%	35.0	%	35.0	%
State and local income taxes, net of federal income tax benefits	3.5		2.9		2.8
Certain expenses capitalized on books and deducted on tax return	(9.7	)	(6.9	)	(5.0	)
Taxes related to prior years	(1.6	)	(0.8	)	(0.7	)
Other items – net	(2.2	)	(0.6	)	(0.7	)
Effective income tax rate	25.0	%	29.6	%	31.4	%

The significant items comprising the net deferred tax liability recognized in the Consolidated Balance Sheets as of September 30 are as follows:

(Thousands)	2013			2012
Deferred tax assets:
Reserves not currently deductible	$	13,933		$	16,400
Pension and other postretirement benefits	71,367			73,480
Unamortized investment tax credits	1,799			1,955
Other*	12,522			18,224
Total deferred tax assets	99,621			110,059
Deferred tax liabilities:
Relating to property	341,975			303,474
Regulatory pension and other postretirement benefits	124,871			121,554
Deferred gas costs	7,112			20,652
Other	5,789			26,563
Total deferred tax liabilities	479,747			472,243
Net deferred tax liability	380,126			362,184
Net deferred tax liability – current*	(1,012		)	(6,675		)
Net deferred tax liability – non-current*	$	379,114		$	355,509

* The Company periodically invests in tax credits. As of September 30, 2013, $7.1 million of state tax credits are included in Other and Net deferred tax liability. $4.7 million of state tax credits were classified as current. $2.4 million of state tax credits were classified as non-current.

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 interest expense and other income deductions, respectively. 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 Consolidated Balance Sheets.

The following table presents a reconciliation of the beginning and ending balances of unrecognized tax benefits at September 30 as reported in the Consolidated Balance Sheets:

(Thousands)	2013			2012
Unrecognized tax benefits, beginning of year	$	5,810		$	5,596
Increases related to prior year tax positions	145			78
Increases related to tax positions taken in current year	1,450			547
Reductions due to lapse of applicable statute of limitations	(5,018		)	(411		)
Unrecognized tax benefits, end of year	$	2,387		$	5,810

The amount of unrecognized tax benefits which, if recognized, would affect the Company’s effective tax rate were $1.9 million and $1.4 million as of September 30, 2013 and 2012, respectively. It is reasonably possible that events will occur in the next 12 months that could increase or decrease the amount of the Company’s unrecognized tax benefits. The Company does not expect that any such change will be significant to the Consolidated Balance Sheets.

Interest accrued associated with the Company’s uncertain tax positions as of September 30, 2013 and 2012 were $0.1 million and $0.6 million, respectively, and an immaterial amount of penalties were accrued as of September 30, 2013. Interest expense accrued during fiscal year 2013 was $0.1 million, $0.2 million for fiscal year 2012, and $0.2 million for fiscal year 2011. During fiscal year 2013, the Company reversed $0.6 million of accrued interest expense in the Consolidated Statements of Income.

The Company is subject to U.S. federal income tax as well as income tax of state and local jurisdictions. The Company is no longer subject to examination for fiscal years prior to 2010.

In September 2013, the Internal Revenue Service and U.S. 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. Laclede is evaluating the effects of the regulations, but does not believe that they will have a significant impact on its consolidated financial statements.

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INTERIM FINANCIAL INFORMATION (UNAUDITED) (Unaudited) (Tables)

12 Months Ended

Sep. 30, 2013

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information Table

(Thousands, Except Per Share Amounts)
Three Months Ended	Dec. 31		March 31		June 30		Sept. 30
Fiscal Year 2013
Total Operating Revenues	$	307,003	$	397,613	$	165,289	$	147,114
Operating Income (Loss)	42,085		51,849		12,282		(9,722		)
Net Income (Loss)	25,568		30,242		6,584		(9,636		)
Basic Earnings (Loss) Per Share of Common Stock	1.14		1.34		0.25		(0.30		)
Diluted Earnings (Loss) Per Share of Common Stock	1.14		1.34		0.25		(0.30		)
Three Months Ended	Dec. 31		March 31		June 30		Sept. 30
Fiscal Year 2012
Total Operating Revenues	$	410,913	$	358,175	$	186,849	$	169,538
Operating Income	43,105		50,583		15,045		1,869
Net Income (Loss)	25,174		29,684		8,433		(651		)
Basic Earnings (Loss) Per Share of Common Stock	1.13		1.33		0.38		(0.03		)
Diluted Earnings (Loss) Per Share of Common Stock	1.12		1.32		0.38		(0.03		)

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INCOME TAXES (Details) (USD $)	12 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2011	Sep. 30, 2013 State	Sep. 03, 2013 State
Federal
Current	$ (4,173,000)		$ (3,835,000)		$ 4,724,000
Deferred	19,925,000		26,365,000		20,602,000
Investment tax credits	(213,000)		(213,000)		(213,000)
State and local
Current	(301,000)		(430,000)		573,000
Deferred	2,340,000		4,402,000		3,496,000
Total Income Tax Expense	17,578,000		26,289,000		29,182,000
Effective income tax rate variance from federal statutory rate [Abstract]
Federal income tax statutory rate	35.00%		35.00%		35.00%
State and local income taxes, net of federal income tax benefits	3.50%		2.90%		2.80%
Certain expenses capitalized on books and deducted on tax return	(9.70%)		(6.90%)		(5.00%)
Taxes related to prior years	(1.60%)		(0.80%)		(0.70%)
Other items – net	(2.20%)		(0.60%)		(0.70%)
Effective income tax rate	25.00%		29.60%		31.40%
Deferred tax assets:
Reserves not currently deductible	13,933,000		16,400,000
Pension and other postretirement benefits	71,367,000		73,480,000
Unamortized investment tax credits	1,799,000		1,955,000
Other	12,522,000	[1]	18,224,000	[1]
Total deferred tax assets	99,621,000		110,059,000
Deferred tax liabilities:
Relating to property	341,975,000		303,474,000
Regulatory pension and other postretirement benefits	124,871,000		121,554,000
Deferred gas costs	7,112,000		20,652,000
Other	5,789,000		26,563,000
Total deferred tax liabilities	479,747,000		472,243,000
Total deferred tax liabilities	380,126,000		362,184,000
Net deferred tax liability - current	(1,012,000)	[1]	(6,675,000)	[1]
Net deferred tax liability - non-current	379,114,000	[1]	355,509,000	[1]
Unrecognized tax benefits [Roll Forward]
Unrecognized tax benefits, beginning of year	5,810,000		5,596,000
Increases related to prior year tax positions	145,000		78,000
Increases related to tax positions taken in current year	1,450,000		547,000
Reductions due to lapse of applicable statute of limitations	(5,018,000)		(411,000)
Unrecognized tax benefits, end of year	2,387,000		5,810,000		5,596,000
Tax credits included in net deferred tax liability							7,100,000
Tax credits classified as current						4,700,000
Tax credits classified as noncurrent						2,400,000
Unrecognized tax benefits affect on the Company's effective tax rate	1,900,000		1,400,000
Interest accrued associated with uncertain tax positions	100,000		600,000
Interest expense accrued during fiscal year	100,000		200,000		200,000
Reversal of accrued penalties	$ 600,000

[1] The Company periodically invests in tax credits. As of September 30, 2013, $7.1 million of state tax credits are included in Other and Net deferred tax liability. $4.7 million of state tax credits were classified as current. $2.4 million of state tax credits were classified as non-current.

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 2 (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Pension Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Current year actuarial loss (gain)	$ 17,030	$ 32,884	$ (13,485)
Amortization of actuarial loss	(10,724)	(29,091)	(11,171)
Acceleration of loss recognized due to settlement	26,996	0	0
Amortization of prior service cost	(544)	(592)	(642)
Sub-total	(21,234)	3,201	(25,298)
Regulatory adjustment	21,159	(3,510)	24,533
Total recognized in other comprehensive income	(75)	(309)	(765)
Postretirement Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Current year actuarial loss (gain)	16,300	10,138	1,696
Amortization of actuarial loss	(5,300)	(4,261)	(4,443)
Amortization of prior service cost	(3)	2,072	2,328
Amortization of transition obligation	(93)	(136)	(136)
Sub-total	10,904	7,813	(555)
Regulatory adjustment	(10,904)	(7,813)	555
Total recognized in other comprehensive income	$ 0	$ 0	$ 0

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 13 (Details) (USD $)	12 Months Ended								12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2010	Aug. 01, 2007	Dec. 31, 2010 Laclede Gas [Member]	Aug. 01, 2007 Laclede Gas [Member]	Feb. 20, 2010 Missouri Gas Energy (MGE) [Member]	Sep. 30, 2013 Postretirement Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Extent of Lump-sum payments recognized, percentage	100.00%
Lump-sum payments recognized as settlements	$ 79,484,000	$ 60,085,000	$ 2,300,000
Implementation period used to calculate return on plan assets (in years)	4 years
Gains or losses includible in cost amortized to extent exceeds benefit obligations or market-related value of plan assets, percentage.	10.00%
Recovery in rates for the qualified pension plans base allowance						15,500,000	4,800,000	10,000,000
Recovery in rates for postretirement benefit				9,500,000	7,600,000
Anticipated Contributions to pension plans for qualified trust	24,000,000
Anticipated contributions to pension plans for non-qualified plans	400,000
Medical insurance available until age is reached after early retirement	65 years
Amortization period for transition obligation excluded from postretirement benefit cost (in years)	20 years
Anticipated contributions to the postretirement plans for qualified trusts									19,200,000
Anticipated payment directly to participants in postretirement plan									300,000
Current investment policy targets an asset allocation to equity securities									60.00%
Investment policy targets asset allocation to debt securities									40.00%
Other Plans [Abstract]
401(K) plans, cost of defined contributions	$ 5,000,000	$ 3,800,000	$ 3,600,000

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FAIR VALUE MEASUREMENTS (Tables)

12 Months Ended

Sep. 30, 2013

Fair Value Disclosures [Abstract]

Fair Value Measurements, Measured on Recurring Basis

The following table categorizes the assets and liabilities in the Consolidated Balance Sheets that are accounted for at fair value on a recurring basis in periods subsequent to initial recognition.

(Thousands)	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Effects of Netting and Cash Margin Receivables /Payables			Total
As of September 30, 2013
Assets
U. S. Stock/Bond Mutual Funds	$	14,500	$	—	$	—	$	—		$	14,500
NYMEX/ICE natural gas contracts	4,333		330		—		(2,145		)	$	2,518
OTCBB natural gas contracts	—		232		—		(232		)	—
NYMEX gasoline and heating oil contracts	105		—		—		(105		)	$	—
Natural gas commodity contracts	—		1,129		150		(495		)	$	784
Total	$	18,938	$	1,691	$	150	$	(2,977	)	$	17,802
Liabilities
NYMEX/ICE natural gas contracts	$	3,687	$	321	$	—	$	(4,008	)	$	—
OTCBB natural gas contracts	—		5,443		—		(232		)	$	5,211
NYMEX gasoline and heating oil contracts	—		—		—		—			$	—
Natural gas commodity contracts	—		1,140		40		(495		)	$	685
Total	$	3,687	$	6,904	$	40	$	(4,735	)	$	5,896
As of September 30, 2012
Assets
U. S. Stock/Bond Mutual Funds	$	13,187	$	—	$	—	$	—		$	13,187
NYMEX/ICE natural gas contracts	7,411		994		—		(8,405		)	$	—
NYMEX gasoline and heating oil contracts	344		—		—		(344		)	$	—
Natural gas commodity contracts	—		3,060		113		(299		)	$	2,874
Total	$	20,942	$	4,054	$	113	$	(9,048	)	$	16,061
Liabilities
NYMEX/ICE natural gas contracts	$	12,253	$	1,891	$	—	$	(14,144	)	$	—
NYMEX gasoline and heating oil contracts	—		—		—		—			$	—
Natural gas commodity contracts	—		428		4		(299		)	$	133
Total	$	12,253	$	2,319	$	4	$	(14,443	)	$	133

Reconciliation of the Level 3 beginning and ending net derivative balances

The following is a reconciliation of the Level 3 beginning and ending net derivative balances:

(Thousands)	2013			2012
Beginning of period	$	109		$	13
Settlements	(269		)	(54		)
Net losses related to derivatives not held at end of period	(99		)	(68		)
Net gains related to derivatives still held at end of period	369			218
End of period	$	110		$	109

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STOCKHOLDER'S EQUITY (Tables)

12 Months Ended

Sep. 30, 2013

Stockholders' Equity Note [Abstract]

Accumulated other comprehensive income (loss), net of taxes

The components of accumulated other comprehensive income (loss), net of income taxes, recognized in the

Consolidated Balance Sheets at September 30 were as follows:

(Thousands)	Net Unrealized Gains (Losses) on Cash Flow Hedges			Defined Benefit Pension and Other Postretirement Benefit Plans			Total
Balance at September 30, 2011	$	320		$	(2,420	)	$	(2,100	)
Current-period change	(2,206		)	190			(2,016		)
Balance at September 30, 2012	(1,886		)	(2,230		)	(4,116		)
Current-period change	3,281			48			3,329
Balance at September 30, 2013	1,395			(2,182		)	(787		)

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LONG-TERM DEBT (Tables)

12 Months Ended

Sep. 30, 2013

Debt Disclosure [Abstract]

Schedule of Maturities of long-term debt by fiscal year

Maturities on long-term debt for the five fiscal years subsequent to September 30, 2013 are as follows:

2014	—
2015	—
2016	—
2017	—
2018	$	100	million

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS

12 Months Ended

Sep. 30, 2013

Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS

This footnote includes all pension plans of the Company whether historical plans or those acquired as part of the purchase of certain assets and liabilities of MGE on September 1, 2013. The net pension and postretirement obligations were remeasured at that time as well as at the fiscal year end.

Pension Plans

The Utility has non-contributory, defined benefit, trusteed forms of pension plans covering the majority of its employees. Plan assets consist primarily of corporate and U.S. government obligations and a growth segment consisting of exposure to equity markets, commodities, real estate and inflation-indexed securities, achieved through derivative instruments and investments in diversified mutual funds.

Pension costs in 2013, 2012, and 2011 amounted to $17.5 million, $20.1 million, and $14.3 million, respectively, including amounts charged to construction.

The net periodic pension costs include the following components:

(Thousands)	2013			2012			2011
Service cost – benefits earned during the period	$	9,209		$	9,203		$	9,553
Interest cost on projected benefit obligation	16,959			19,358			18,819
Expected return on plan assets	(19,358		)	(19,595		)	(18,849		)
Amortization of prior service cost	544			592			642
Amortization of actuarial loss	10,724			9,040			10,228
Loss on lump-sum settlements	26,996			20,051			943
Sub-total	45,074			38,649			21,336
Regulatory adjustment	(27,532		)	(18,579		)	(7,066		)
Net pension cost	$	17,542		$	20,070		$	14,270

Other changes in plan assets and pension benefit obligations recognized in other comprehensive income include the following:

(Thousands)	2013			2012			2011
Current year actuarial loss (gain)	$	17,030		$	32,884		$	(13,485	)
Amortization of actuarial loss	(10,724		)	(29,091		)	(11,171		)
Acceleration of loss recognized due to settlement	(26,996		)	—			—
Amortization of prior service cost	(544		)	(592		)	(642		)
Sub-total	(21,234		)	3,201			(25,298		)
Regulatory adjustment	21,159			(3,510		)	24,533
Total recognized in other comprehensive income	$	(75	)	$	(309	)	$	(765	)

Pursuant to the provisions of the Utility pension plans, pension obligations may be satisfied by lump-sum cash payments. Pursuant to a MoPSC Order, lump-sum payments are recognized as settlements (which can result in gains or losses) only if the total of such payments exceeds 100% of the sum of service and interest costs. Lump-sum payments recognized as settlements during fiscal year 2013, 2012, and 2011 were $79.5 million, $60.1 million, and $2.3 million, respectively.

Pursuant to a MoPSC Order, the return on plan assets is based on the market-related value of plan assets implemented prospectively over a four-year period. Gains or losses not yet includible in pension cost are amortized only to the extent that such gain or loss exceeds 10% of the greater of the projected benefit obligation or the market-related value of plan assets. Such excess is amortized over the average remaining service life of active participants. The recovery in rates for Laclede Gas' qualified pension plan is based on an annual allowance of $4.8 million effective August 1, 2007 and $15.5 million effective January 1, 2011. The recovery in rates for MGE's qualified pension plan is based on an annual allowance of $10.0 million effective February 20, 2010. The difference between these amounts and pension expense as calculated pursuant to the above and that otherwise would be included in the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income is deferred as a regulatory asset or regulatory liability.

The following table sets forth the reconciliation of the beginning and ending balances of the pension benefit obligation at September 30:

(Thousands)	2013			2012
Benefit obligation, beginning of year	$	412,171		$	384,163
Service cost	9,209			9,203
Interest cost	16,959			19,358
Actuarial (gain) loss	(23,921		)	52,161
MGE acquisition	151,424			—
Settlement loss	24,999			14,348
Gross benefits paid *	(87,023		)	(67,062		)
Benefit obligation, end of year	$	503,818		$	412,171
Accumulated benefit obligation, end of year	$	444,129		$	353,061

* Includes $79,484 and $60,085 lump-sum payments recognized as settlements in fiscal years 2013 and 2012, respectively.

The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets at September 30:

(Thousands)	2013			2012
Fair value of plan assets, beginning of year	$	274,130		$	247,959
Actual return on plan assets	3,387			53,220
Employer contributions	27,991			40,013
MGE acquisition	126,958			—
Gross benefits paid *	(87,023		)	(67,062		)
Fair value of plan assets, end of year	$	345,443		$	274,130
Funded status of plans, end of year	$	(158,375	)	$	(138,041	)

*  Includes $79,484 and $60,085 lump-sum payments recognized as settlements in fiscal years 2013 and 2012, respectively.

The following table sets forth the amounts recognized in the Consolidated Balance Sheets at September 30:

(Thousands)	2013			2012
Current liabilities	$	(442	)	$	(468	)
Noncurrent liabilities	(157,933		)	(137,573		)
Total	$	(158,375	)	$	(138,041	)
Pre-tax amounts recognized in accumulated other comprehensive income not yet recognized as components of net periodic pension cost consist of:
Net actuarial loss	$	115,775		$	136,464
Prior service costs	4,467			5,011
Sub-total	120,242			141,475
Adjustments for amounts included in Regulatory Assets	(116,686		)	(137,845		)
Total	$	3,556		$	3,630

At September 30, 2013, the following pre-tax amounts are expected to be amortized from accumulated other comprehensive income into net periodic pension cost during fiscal year 2014:

(Thousands)	2014
Amortization of net actuarial loss	$	7,088
Amortization of prior service cost	497
Sub-total	7,585
Regulatory adjustment	(7,196		)
Total	$	389

The assumptions used to calculate net periodic pension costs are as follows:

	2013	2012	2011
Weighted average discount rate*	3.95%	5.10%	4.75%
Weighted average rate of future compensation increase	3.00%	3.00%	3.00%
Expected long-term rate of return on plan assets	7.75%	7.75%	8.00%

* Weighted average discount rate assumption for the MGE pension plan is 5.05%.

The weighted average discount rate is based on long-term, high quality bond indices at the measurement date. The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Assumed projected rates of return for each asset class were selected after analyzing historical experience and future expectations of the returns. The overall expected rate of return for the portfolio was developed based on the target allocation for each class. The expected return is a long-term assumption that generally does not change annually. However, in 2012 and 2011, the expected return assumption was adjusted to reflect capital market volatility in recent years.

The assumptions used to calculate the benefit obligations are as follows:

	2013	2012
Weighted average discount rate *	4.70%	3.95%
Weighted average rate of future compensation increase	3.00%	3.00%

* Weighted average discount rate assumption for the MGE pension plan is 5.00%.

Following are the projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for plans that have a projected benefit obligation and an accumulated benefit obligation in excess of plan assets:

(Thousands)	2013		2012
Projected benefit obligation	$	503,818	$	412,171
Accumulated benefit obligation	444,129		353,061
Fair value of plan assets	345,443		274,130

Following are the targeted and actual plan assets by category as of September 30 of each year:

	Target		2013 Actual		2012 Actual
Growth Strategy
Equity Markets	42.5	%	45.9	%	37.3	%
Commodities	2.5	%	1.6	%	2.2	%
Real Estate	2.5	%	3.0	%	2.2	%
Inflation-Indexed Securities	2.5	%	1.4	%	2.2	%
Debt Securities	50.0	%	43.3	%	41.1	%
Other*	—	%	4.8	%	15.0	%
Total	100.0	%	100.0	%	100.0	%

* Other investments in 2013 consist of cash equivalents. The relatively large cash position at September 30, 2012 was

due to a transition taking place between investment managers and was invested in debt securities in a matter of days.

The Utility's investment policy is designed to maximize, to the extent possible, the funded status of the plan over time, and minimize volatility of funding and costs. The policy seeks to maximize investment returns consistent with these objectives and he Utility’s tolerance for risk. The duration of plan liabilities and the impact of potential changes in asset values on the funded status are fundamental considerations in the selection of plan assets. Outside investment management specialists are utilized in each asset class. Such specialists are provided with guidelines, where appropriate, designed to ensure that the investment portfolio is managed in accordance with the policy. The policy seeks to avoid significant concentrations of risk by investing in a diversified portfolio of assets. Investments in corporate, U.S. government and agencies, and, to a lesser extent, international debt securities seek to provide duration matching with plan liabilities, and typically have investment grade ratings and reflect allocations across various entities and industries. During 2012, exposures to additional asset types were added to the target portfolio: commodities, real estate and inflation-indexed securities. The investment policy permits the use of derivative instruments, which may be used to achieve the desired market exposure of an index, adjust portfolio duration, or rebalance the total portfolio to the target asset allocation. The Growth Strategy utilizes a combination of derivative instruments and debt securities to achieve diversified exposure to equity and other markets while generating returns from the fixed-income investments and providing further duration matching with the liabilities. The assets acquired with the MGE pension plan include diversified funds that are equity-oriented and larger holdings of cash. These are being evaluated along with the liabilities of the MGE plan. Performance and compliance with the guidelines is regularly monitored. The policy calls for increased allocations to debt securities as the funded status improves.

Following are expected pension benefit payments for the succeeding five fiscal years, and in aggregate for the five years thereafter:

(Millions)	Pensions from Qualified Trust		Pensions from Laclede Gas Funds
2014	$	22.9	$	0.4
2015	25.3		0.5
2016	27.2		0.5
2017	30.8		0.6
2018	34.2		0.6
2019 – 2023	227.2		4.5

The funding policy of the Utility is to contribute an amount not less than the minimum required by government funding standards, nor more than the maximum deductible amount for federal income tax purposes. Contributions to the pension plans in fiscal year 2014 are anticipated to be $24.0 million into the qualified trusts, and $0.4 million into the non-qualified plans.

Postretirement Benefits

The Utility provides certain life insurance benefits at retirement. Medical insurance is available after early retirement until age 65. The transition obligation not yet includible in postretirement benefit cost is being amortized over 20 years. Postretirement benefit costs in 2013, 2012, and 2011 amounted to $9.5 million, $9.5 million, and $9.1 million, respectively, including amounts charged to construction.

Net periodic postretirement benefit costs consisted of the following components:

(Thousands)	2013			2012			2011
Service cost – benefits earned during the period	$	10,162		$	8,060		$	7,676
Interest cost on accumulated postretirement benefit obligation	5,234			5,521			4,843
Expected return on plan assets	(4,447		)	(3,965		)	(3,646		)
Amortization of transition obligation	93			136			136
Amortization of prior service credit	3			(2,072		)	(2,328		)
Amortization of actuarial loss	5,300			4,261			4,443
Sub-total	16,345			11,941			11,124
Regulatory adjustment	(6,821		)	(2,417		)	(2,071		)
Net postretirement benefit cost	$	9,524		$	9,524		$	9,053

Other changes in plan assets and postretirement benefit obligations recognized in other comprehensive income include the following:

(Thousands)	2013			2012			2011
Current year actuarial loss	$	16,300		$	10,138		$	1,696
Amortization of actuarial loss	(5,300		)	(4,261		)	(4,443		)
Amortization of prior service credit	(3		)	2,072			2,328
Amortization of transition obligation	(93		)	(136		)	(136		)
Sub-total	10,904			7,813			(555		)
Regulatory adjustment	(10,904		)	(7,813		)	555
Total recognized in other comprehensive income	$	—		$	—		$	—

Pursuant to a MoPSC Order, the return on plan assets is based on the market-related value of plan assets implemented prospectively over a four-year period. Gains and losses not yet includible in postretirement benefit cost are amortized only to the extent that such gain or loss exceeds 10% of the greater of the accumulated postretirement benefit obligation or the market-related value of plan assets. Such excess is amortized over the average remaining service life of active participants. The recovery in rates for Laclede Gas' postretirement benefit plans is based on an annual allowance of $7.6 million effective August 1, 2007 and $9.5 million effective January 1, 2011. The difference between these amounts and postretirement benefit cost based on the above and that otherwise would be included in the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income is deferred as a regulatory asset or regulatory liability.

The following table sets forth the reconciliation of the beginning and ending balances of the postretirement benefit obligation at September 30:

(Thousands)	2013			2012
Benefit obligation, beginning of year	$	127,217		$	103,991
Service cost	10,162			8,060
Interest cost	5,234			5,521
Actuarial loss (gain)	17,514			15,895
MGE acquisition	28,444			—
Gross benefits paid	(8,449		)	(6,250		)
Benefit obligation, end of year	$	180,122		$	127,217

The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets at September 30:

(Thousands)	2013			2012
Fair value of plan assets at beginning of year	$	67,442		$	51,744
Actual return on plan assets	5,660			9,722
Employer contributions	16,596			12,226
MGE acquisition	30,396			—
Gross benefits paid	(8,449		)	(6,250		)
Fair value of plan assets, end of year	$	111,645		$	67,442
Funded status of plans, end of year	$	(68,477	)	$	(59,775	)

The following table sets forth the amounts recognized in the Consolidated Balance Sheets at September 30:

(Thousands)	2013			2012
Noncurrent assets	$	2,543		$	—
Current liabilities	(300		)	(790		)
Noncurrent liabilities	(70,720		)	(58,985		)
Total	$	(68,477	)	$	(59,775	)
Pre-tax amounts recognized in accumulated other comprehensive income not yet recognized as components of net periodic postretirement benefit cost consist of:
Net actuarial loss	$	63,573		$	52,573
Prior service credit	(27		)	(24		)
Transition obligation	—			93
Sub-total	63,546			52,642
Adjustments for amounts included in Regulatory Assets	(63,546		)	(52,642		)
Total	$	—		$	—

At September 30, 2013, the following pre-tax amounts are expected to be amortized from accumulated other comprehensive income into net periodic postretirement benefit cost during fiscal year 2014:

(Thousands)
Amortization of net actuarial loss	$	6,021
Amortization of prior service cost	(4		)
Sub-total	6,017
Regulatory adjustment	(6,017		)
Total	$	—

The assumptions used to calculate net periodic postretirement benefit costs are as follows:

	2013		2012		2011
Weighted average discount rate *	3.80	%	5.05	%	4.70	%
Weighted average rate of future compensation increase	3.00	%	3.00	%	3.00	%
Expected long-term rate of return on plan assets **	7.75	%	7.75	%	8.00	%

* Weighted average discount rate assumption for the MGE postretirement plan is 5.05%.

**    Expected long-term rate of return on plan assets assumption for the MGE postretirement plan is 5.75%.

The weighted average discount rate is based on long-term, high quality bond indices at the measurement date. The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Assumed projected rates of return for each asset class were selected after analyzing historical experience and future expectations of the returns. The overall expected rate of return for the portfolio was developed based on the target allocation for each class. The expected return is a long-term assumption that generally does not change annually. However, in 2012 and 2011, the expected return assumption was adjusted to reflect capital market volatility in recent years.

The assumptions used to calculate the accumulated postretirement benefit obligations are as follows:

	2013	2012
Weighted average discount rate *	4.60%	3.80%
Weighted average rate of future compensation increase	3.00%	3.00%

* Weighted average discount rate assumption for the MGE postretirement plan is 4.95%.

The assumed medical cost trend rates at September 30 are as follows:

	2013	2012
Medical cost trend assumed for next year	7.50%	7.00%
Rate to which the medical cost trend rate is assumed to decline (the ultimate medical cost trend rate)	5.00%	5.00%
Year the rate reaches the ultimate trend	2020	2017

The following table presents the effect of an assumed 1% change in the assumed medical cost trend rate:

(Thousands)	1% Increase		1% Decrease
Effect on net periodic postretirement benefit cost	$	1,520	$	(1,390	)
Effect on accumulated postretirement benefit obligation	7,060		(6,580		)

Following are the targeted and actual plan assets by category as of September 30 of each year:

	Target		2013 Actual		2012 Actual
Equity Securities	60.0	%	59.0	%	59.0	%
Debt Securities	40.0	%	39.0	%	39.0	%
Other	—	%	2.0	%	2.0	%
Total	100.0	%	100.0	%	100.0	%

Missouri state law provides for the recovery in rates of costs accrued pursuant to GAAP provided that such costs are funded through an independent, external funding mechanism. The Utility established Voluntary Employees’ Beneficiary Association and Rabbi trusts as its external funding mechanisms. The Utility’s investment policy seeks to maximize investment returns consistent with the Utility's tolerance for risk. Outside investment management specialists are utilized in each asset class. Such specialists are provided with guidelines, where appropriate, designed to ensure that the investment portfolio is managed in accordance with policy. Performance and compliance with the guidelines is regularly monitored. The Utility's current investment policy targets an asset allocation of 60% to equity securities and 40% to debt securities, excluding cash held in short-term debt securities for the purpose of making benefit payments. The Utility currently invests in a mutual fund which is rebalanced on an ongoing basis to the target allocation. The mutual fund is diversified across U.S. stock and bond markets.

Following are expected postretirement benefit payments for the succeeding five fiscal years, and in aggregate for the five years thereafter:

(Millions)	Benefits Paid from Qualified Trust		Benefits Paid from Laclede Gas Funds
2014	$	9.5	$	0.3
2015	9.9		0.3
2016	10.7		0.3
2017	11.7		0.4
2018	12.8		0.4
2019 – 2023	84.1		2.2

The Utility's funding policy is to contribute amounts to the trusts equal to the periodic benefit cost calculated pursuant to GAAP as recovered in rates. Contributions to the postretirement plans in fiscal year 2014 are anticipated to be $19.2 million to the qualified trusts, and $0.3 million paid directly to participants from Laclede Gas funds.

Other Plans

The Utility sponsors 401(k) plans that cover substantially all employees. The plans allow employees to contribute a portion of their base pay in accordance with specific guidelines. The Utility provides a match of such contributions within specific limits. The cost of the defined contribution plans of the Utility amounted to $5.0 million, $3.8 million, and $3.6 million for fiscal years 2013, 2012, and 2011, respectively.

Fair Value Measurements of Pension and Other Postretirement Plan Assets

The table below categorizes the fair value measurements of the Utility's’ pension plan assets:

(Thousands)	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total
As of September 30, 2013
Cash and cash equivalents	$	18,177	$	—		$	—	$	18,177
Stock/Bond mutual fund	—		115,817			—		115,817
Debt Securities
U.S. bond mutual funds	17,682		—			—		17,682
U.S. government	—		55,743			—		55,743
U.S. corporate	—		110,925			—		110,925
U.S. municipal	—		6,799			—		6,799
International	—		21,594			—		21,594
Derivative instruments (a)	—		(1,294		)	—		(1,294		)
Total	$	35,859	$	309,584		$	—	$	345,443
As of September 30, 2012
Cash and cash equivalents	$	57,614	$	—		$	—	$	57,614
Debt Securities
U.S. bond mutual funds	36,767		—			—		36,767
U.S. government	—		57,925			—		57,925
U.S. corporate	—		93,169			—		93,169
U.S. municipal	—		9,493			—		9,493
International	—		18,885			—		18,885
Derivative instruments (b)	—		277			—		277
Total	$	94,381	$	179,749		$	—	$	274,130

(a) Derivative assets of $4,186 net of cash margin payable of $5,480.

(b) Derivative assets of $3,027 net of cash margin payable of $2,750.

The table below categorizes the fair value measurements of The Utility's postretirement plan assets:

(Thousands)	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
As of September 30, 2013
Cash and cash equivalents	$	1,411	$	—	$	—	$	1,411
U.S. stock/bond mutual fund	110,234		—		—		110,234
Total	$	111,645	$	—	$	—	$	111,645
As of September 30, 2012
Cash and cash equivalents	$	1,106	$	—	$	—	$	1,106
U.S. stock/bond mutual fund	66,336		—		—		66,336
Total	$	67,442	$	—	$	—	$	67,442

Cash and cash equivalents include money market mutual funds valued based on quoted market prices. Fair values of derivative instruments are calculated by investment managers who use valuation models that incorporate observable market inputs. Debt securities are valued based on broker/dealer quotations or by using observable market inputs. The stock and bond mutual funds are valued at the quoted market price of the identical securities.

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 10 (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013
Pension Plans [Member] | Paid From Qualified Trust [Member]
Expected benefit payments [Abstract]
2014	$ 22.9
2015	25.3
2016	27.2
2017	30.8
2018	34.2
2019 - 2023	227.2
Pension Plans [Member] | Paid From Laclede Gas Funds [Member]
Expected benefit payments [Abstract]
2014	0.4
2015	0.5
2016	0.5
2017	0.6
2018	0.6
2019 - 2023	4.5
Postretirement Plans [Member] | Paid From Qualified Trust [Member]
Expected benefit payments [Abstract]
2014	9.5
2015	9.9
2016	10.7
2017	11.7
2018	12.8
2019 - 2023	84.1
Postretirement Plans [Member] | Paid From Laclede Gas Funds [Member]
Expected benefit payments [Abstract]
2014	0.3
2015	0.3
2016	0.3
2017	0.4
2018	0.4
2019 - 2023	$ 2.2

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)

12 Months Ended

Sep. 30, 2013

Accounting Policies [Abstract]

Asset Retirement Obligations

The following table presents a reconciliation of the beginning and ending balances of asset retirement obligations at September 30 as reported in the Consolidated Balance Sheets:

(Thousands)	2013			2012
Asset retirement obligations, beginning of year	$	40,368		$	27,495
Liabilities incurred during the period	801			851
Liabilities settled during the period	(1,089		)	(601		)
Accretion	2,322			1,637
Revisions in estimated cash flows	—			10,986
Addition of MGE asset retirement obligation	32,152			—
Asset retirement obligations, end of year	$	74,554		$	40,368

Regulatory Assets and Liabilities

The following regulatory assets and regulatory liabilities were reflected in the Consolidated Balance Sheets as of September 30:

(Thousands)	2013		2012
Regulatory Assets:
Future income taxes due from customers	$	112,912	$	118,997
Pension and postretirement benefit costs	381,395		304,446
Unamortized purchased gas adjustments	17,533		40,674
Purchased gas costs	18,249		18,386
Compensated absences	8,004		7,836
Other	25,387		6,382
Total Regulatory Assets	$	563,480	$	496,721
Regulatory Liabilities:
Unamortized investment tax credits	$	2,900	$	3,113
Accrued cost of removal	59,066		55,103
Other	23,494		1,216
Total Regulatory Liabilities	$	85,460	$	59,432

Off-System Sales

Laclede Gas
Pre-tax Income	Customer Share	Company Share
First $2 million	100%	—%
Next $2 million	80%	20%
Next $2 million	75%	25%
Amounts exceeding $6 million	70%	30%
MGE
Pre-tax Income	Customer Share	Company Share
First $1.2 million	85%	15%
Next $1.2 million	80%	20%
Next $1.2 million	75%	25%
Amounts exceeding $3.6 million	70%	30%

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OTHER INCOME AND (INCOME DEDUCTIONS) - NET (Tables)

12 Months Ended

Sep. 30, 2013

Other Nonoperating Income (Expense) [Abstract]

Other Income and (Income Deductions) by Component

(Thousands)	2013			2012			2011
Interest income	$	1,088		$	1,309		$	1,136
Net investment gain	2,857			3,124			185
Other income	377			811			118
Other income deductions	(1,878		)	(1,972		)	(1,262		)
Other Income and (Income Deductions) – Net	$	2,444		$	3,272		$	177

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STOCKHOLDER'S EQUITY

12 Months Ended

Sep. 30, 2013

Stockholders' Equity Note [Abstract]

STOCKHOLDER'S EQUITY

STOCKHOLDER'S EQUITY

Total shares of common stock outstanding were 32.70 million and 22.54 million at September 30, 2013 and 2012, respectively.

Common stock and paid-in capital increased $435.8 million in fiscal year 2013. The issuance of 44,074 common shares under the Dividend Reinvestment and Stock Purchase Plan increased common stock and paid-in capital by $1.8 million. The remaining $434.0 million increase was due to the issuance of 10,005,000 shares in May 2013, stock-based compensation costs and the issuance of 108,331 shares of common stock under the Equity Incentive Plan. Common stock and paid-in capital increased $5.0 million in fiscal year 2012. The issuance of 46,107 common shares under the Dividend Reinvestment and Stock Purchase Plan increased common stock and paid-in capital by $1.8 million. The remaining $3.2 million increase was primarily due to stock-based compensation costs and the issuance of 62,590 shares of common stock under the Equity Incentive Plan. Substantially all of the Utility's plant is subject to the liens of its first mortgage bonds. The mortgage contains several restrictions on the Utility's ability to pay cash dividends on its common stock.

These provisions are applicable regardless of whether the stock is publicly held or, as has been the case since the formation of Laclede Group, held solely by the Utility’s parent company. Under the most restrictive of these provisions, no cash dividend may be declared or paid if, after the dividend, the aggregate net amount spent for all dividends after September 30, 1953, would exceed a maximum amount determined by a formula set out in the mortgage. Under that formula, the maximum amount is the sum of $8 million plus earnings applicable to common stock (adjusted for stock repurchases and issuances) for the period from September 30, 1953, to the last day of the quarter before the declaration or payment date for the dividends. As of September 30, 2013 and 2012, the amount under the mortgage’s formula that was available to pay dividends was $833 million and $355 million, respectively. Thus, all of the Utility’s retained earnings were free from such restrictions as of those dates. The substantial increase in 2013 was primarily due to the issuance of stock to Laclede Group to fund a portion of the MGE acquisition.

Laclede Group has a registration statement on file on Form S-3 for the issuance and sale of up to 285,222 shares of its common stock under its Dividend Reinvestment and Stock Purchase Program. There were 194,246 and 186,919 shares at September 30, 2013 and November 26, 2013, respectively, remaining available for issuance under this Form S-3. The Company filed this Form S-3 on July 29, 2011.

On August 6, 2013, Laclede Group and Laclede Gas filed with the SEC a joint shelf registration statement on Form S-3 for issuance of various types of debt and equity securities, which registration statement will expire August 5, 2016. Bonds totaling $450 million were issued by Laclede Gas from this shelf registration statement on August 13, 2013. The amount, timing, and type of additional financing to be issued under this shelf registration statement will depend on cash requirements and market conditions.

The Utility has authority from the MoPSC to issue up to $518 million in debt securities and preferred stock, including on a private placement basis, as well as to enter into capital leases, issue common stock and receive paid-in capital. This authorization was originally effective through June 30, 2013. In August 2012, the Utility filed a request with the MoPSC to extend this authority for an additional two years, to June 30, 2015. This extension was approved October 24, 2012, to be effective on November 23, 2012. At September 30, 2013, $370.8 million remained under this authorization. The amount, timing, and type of additional financing to be issued will depend on cash requirements and market conditions.

The components of accumulated other comprehensive income (loss), net of income taxes, recognized in the

Consolidated Balance Sheets at September 30 were as follows:

(Thousands)	Net Unrealized Gains (Losses) on Cash Flow Hedges			Defined Benefit Pension and Other Postretirement Benefit Plans			Total
Balance at September 30, 2011	$	320		$	(2,420	)	$	(2,100	)
Current-period change	(2,206		)	190			(2,016		)
Balance at September 30, 2012	(1,886		)	(2,230		)	(4,116		)
Current-period change	3,281			48			3,329
Balance at September 30, 2013	1,395			(2,182		)	(787		)

Income tax expense (benefit) recorded for items of other comprehensive income reported in the Statements of Consolidated Comprehensive Income is calculated by applying statutory federal, state, and local income tax rates applicable to ordinary income. The tax rates applied to individual items of other comprehensive income are similar within each reporting period.

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES Part 1 (Details) (USD $)	12 Months Ended																																																					0 Months Ended																	0 Months Ended
	Sep. 30, 2013 gal MMBTU		Sep. 30, 2012		Sep. 30, 2011	Sep. 30, 2013 Designated as Hedging Instrument [Member]		Sep. 30, 2012 Designated as Hedging Instrument [Member]		Sep. 30, 2013 Not Designated as Hedging Instrument [Member]		Sep. 30, 2012 Not Designated as Hedging Instrument [Member]		Sep. 30, 2013 NYMEX Natural Gas Contracts [Member] Designated as Hedging Instrument [Member] Derivative Instruments Assets [Member]		Sep. 30, 2013 NYMEX Natural Gas Contracts [Member] Designated as Hedging Instrument [Member] Other Deferred Charges [Member]		Sep. 30, 2012 NYMEX Natural Gas Contracts [Member] Designated as Hedging Instrument [Member] Accounts Receivable Other [Member]		Sep. 30, 2013 NYMEX Natural Gas Contracts [Member] Not Designated as Hedging Instrument [Member] Derivative Instruments Assets [Member]		Sep. 30, 2013 NYMEX Natural Gas Contracts [Member] Not Designated as Hedging Instrument [Member] Other Deferred Charges [Member]		Sep. 30, 2012 NYMEX Natural Gas Contracts [Member] Not Designated as Hedging Instrument [Member] Other Deferred Charges [Member]		Sep. 30, 2013 NYMEX Natural Gas Contracts [Member] Not Designated as Hedging Instrument [Member] Accounts Receivable Other [Member]		Sep. 30, 2012 NYMEX Natural Gas Contracts [Member] Not Designated as Hedging Instrument [Member] Accounts Receivable Other [Member]		Sep. 30, 2013 Natural Gas Commodity Contracts [Member] Not Designated as Hedging Instrument [Member] Derivative Instruments Assets [Member]		Sep. 30, 2012 Natural Gas Commodity Contracts [Member] Not Designated as Hedging Instrument [Member] Derivative Instruments Assets [Member]		Sep. 30, 2013 Natural Gas Commodity Contracts [Member] Not Designated as Hedging Instrument [Member] Other Deferred Charges [Member]		Sep. 30, 2012 Natural Gas Commodity Contracts [Member] Not Designated as Hedging Instrument [Member] Other Deferred Charges [Member]		Sep. 30, 2013 Natural Gas Commodity Contracts [Member] Not Designated as Hedging Instrument [Member] Other Current Liabilities [Member]		Sep. 30, 2012 Natural Gas Commodity Contracts [Member] Not Designated as Hedging Instrument [Member] Other Current Liabilities [Member]		Sep. 30, 2013 Natural Gas Commodity Contracts [Member] Not Designated as Hedging Instrument [Member] Other Deferred Credits [Member]		Sep. 30, 2013 OTCBB Natural Gas Contracts [Member] Not Designated as Hedging Instrument [Member] Other Current Liabilities [Member]		Sep. 30, 2013 OTCBB Natural Gas Contracts [Member] Not Designated as Hedging Instrument [Member] Other Deferred Credits [Member]		Sep. 30, 2013 NYMEX Gasoline and Heating Oil Contracts [Member] Designated as Hedging Instrument [Member] Accounts Receivable Other [Member]		Sep. 30, 2012 NYMEX Gasoline and Heating Oil Contracts [Member] Designated as Hedging Instrument [Member] Accounts Receivable Other [Member]		Sep. 30, 2012 NYMEX Gasoline and Heating Oil Contracts [Member] Not Designated as Hedging Instrument [Member] Accounts Receivable Other [Member]		Aug. 06, 2013 Cash Flow Hedging [Member] Interest Rate Swap [Member]	Feb. 28, 2013 Cash Flow Hedging [Member] Interest Rate Swap [Member]	Sep. 30, 2013 Laclede Gas Company [Member] MMBTU	Sep. 30, 2013 Laclede Gas Company [Member] Fiscal 2014 [Member] Open Short Futures Positions [Member] MMBTU	Sep. 30, 2013 Laclede Gas Company [Member] Fiscal 2014 [Member] NYMEX Natural Gas Contracts [Member] Open Long Futures Positions [Member] MMBTU	Sep. 30, 2013 Laclede Gas Company [Member] Fiscal 2014 [Member] OTCBB Natural Gas Contracts [Member] Open Long Futures Positions [Member] MMBTU	Sep. 30, 2013 Laclede Gas Company [Member] Fiscal 2015 [Member] Open Short Futures Positions [Member] MMBTU	Sep. 30, 2013 Laclede Gas Company [Member] Fiscal 2015 [Member] NYMEX Natural Gas Contracts [Member] Open Long Futures Positions [Member] MMBTU	Sep. 30, 2013 Laclede Gas Company [Member] Fiscal 2015 [Member] OTCBB Natural Gas Contracts [Member] Open Long Futures Positions [Member] MMBTU	Sep. 30, 2013 Laclede Energy Resources [Member] MMBTU	Sep. 30, 2013 Laclede Energy Resources [Member] Fiscal 2014 [Member] Open Short Futures Positions [Member] MMBTU	Sep. 30, 2013 Laclede Energy Resources [Member] Fiscal 2014 [Member] Open Long Futures Positions [Member] MMBTU	Sep. 30, 2013 Laclede Energy Resources [Member] Fiscal 2014 [Member] NYMEX Natural Gas Contracts [Member] Open Long Futures Positions [Member] MMBTU	Sep. 30, 2013 Laclede Energy Resources [Member] Fiscal 2015 [Member] Open Short Futures Positions [Member] MMBTU	Sep. 30, 2013 Laclede Energy Resources [Member] Fiscal 2015 [Member] Open Long Futures Positions [Member] MMBTU	Sep. 30, 2013 Laclede Energy Resources [Member] Fiscal 2015 [Member] NYMEX Natural Gas Contracts [Member] Open Long Futures Positions [Member] MMBTU	Sep. 30, 2013 Laclede Energy Resources [Member] Fiscal 2016 [Member] Open Long Futures Positions [Member] MMBTU	Aug. 13, 2013 Laclede Gas [Member]
Derivative [Line Items]
Maximum percentage of normal volumes hedged	70.00%
Maximum number of months normal volumes can be hedged (in months)	36 months
Gasoline futures contracts notional amount (in gallons)	300,000
Average price of gasoline futures contracts (dollars per gallon)	$ 2.23
Notional amount of non-exchange traded natural gas commodity contracts (in MMBtu)	67,400,000
Notional amount of non-exchange traded natural gas commodity contracts to be settled during fiscal 2014	58,500,000
Notional amount of non-exchange traded natural gas commodity contracts to be settled during fiscal 2015	8,100,000
Notional amount of non-exchange traded natural gas commodity contracts to be settled during fiscal 2016	800,000
Expected pre-tax unrealized gain (loss) reclassifications into the Statements of Consolidated Income during the next twelve months	(2,300,000)
MMBtu																																																									0	7,260,000	16,810,000	0	940,000	7,580,000		12,910,000	0	1,710,000	60,000	0	190,000	0
Avg. Price Per MMBtu																																																									0.00	3.99	3.97	0.00	3.84	4.22		3.98	0.00	3.94	4.21	0.00	4.06	4.15
Contract volumes of NYMEX natural gas option used to mitigate price risk (in MMBtu)																																																								23,600,000							0
Derivative notional amount																																																							355,000,000
Gain (Loss) on Derivative Instruments, Net, Pretax																																																						20,800,000
Issuance of first mortgage bonds	550,000,000		0		0																																																																		450,000,000
Derivatives, Fair Value [Line Items]
Asset Derivatives	6,276,000	[1]	11,922,000	[1]		2,349,000	[1]	739,000	[1]	3,927,000	[1]	11,183,000	[1]	2,222,000	[1]	22,000	[1]	405,000	[1]	950,000	[1]	32,000	[1]	0	[1]	1,434,000	[1]	8,000,000	[1]	991,000	[1]	3,150,000	[1]	20,000	[1]	19,000	[1]	247,000	[1]	4,000	[1]	21,000	[1]	228,000	[1]	4,000	[1]	105,000	[1]	334,000	[1]	10,000	[1]
Liability Derivatives	10,629,000	[1]	14,576,000			451,000	[1]	3,413,000		10,178,000	[1]	11,163,000		440,000	[1]	11,000	[1]	3,413,000		100,000	[1]	0	[1]	0		3,455,000	[1]	10,731,000		90,000	[1]	295,000		137,000	[1]	0		830,000	[1]	137,000		123,000	[1]	4,045,000	[1]	1,398,000	[1]	0	[1]	0		0
Derivative instrument assets reconciliation [Abstract]
Fair value of asset derivatives presented above	6,276,000	[1]	11,922,000	[1]		2,349,000	[1]	739,000	[1]	3,927,000	[1]	11,183,000	[1]	2,222,000	[1]	22,000	[1]	405,000	[1]	950,000	[1]	32,000	[1]	0	[1]	1,434,000	[1]	8,000,000	[1]	991,000	[1]	3,150,000	[1]	20,000	[1]	19,000	[1]	247,000	[1]	4,000	[1]	21,000	[1]	228,000	[1]	4,000	[1]	105,000	[1]	334,000	[1]	10,000	[1]
Fair value of cash margin receivables offset with derivatives	1,765,000		5,478,000
Netting of assets and liabilities with the same counterparty	(4,739,000)		(14,526,000)
Total	3,302,000		2,874,000
Derivative Instrument Assets, per Consolidated Balance Sheets:
Derivative instrument assets	3,291,000		2,855,000
Other deferred charges	11,000		19,000
Total	3,302,000		2,874,000
Fair value of liability derivatives presented above	10,629,000	[1]	14,576,000			451,000	[1]	3,413,000		10,178,000	[1]	11,163,000		440,000	[1]	11,000	[1]	3,413,000		100,000	[1]	0	[1]	0		3,455,000	[1]	10,731,000		90,000	[1]	295,000		137,000	[1]	0		830,000	[1]	137,000		123,000	[1]	4,045,000	[1]	1,398,000	[1]	0	[1]	0		0
Fair value of cash margin payables offset with derivatives	6,000		83,000
Netting of assets and liabilities with the same counterparty	(4,739,000)		(14,526,000)
Derivative instrument liabilities, per Consolidated Balance Sheets	5,896,000	[2]	133,000	[2]
Other current liabilities	4,400,000		133,000
Other deferred credits	1,496,000		0
Other Receivables from Broker-Dealers and Clearing Organizations	$ 3,200,000		$ 10,000,000

[1] The fair values of Asset Derivatives and Liability Derivatives exclude the fair value of cash margin receivables or payables with counterparties subject to netting arrangements. Fair value amounts of derivative contracts (including the fair value amounts of cash margin receivables and payables) for which there is a legal right to set off are presented net on the Consolidated Balance Sheets. As such, the gross balances presented in the table above are not indicative of the Company’s net economic exposure. Refer to Note 10, Fair Value Measurements, for information on the valuation of derivative instruments.

[2]

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ACQUISITION OF MGE

12 Months Ended

Sep. 30, 2013

Business Combinations [Abstract]

ACQUISITION OF MGE

ACQUISITION OF MGE

Effective September 1, 2013, Laclede Group completed the purchase of substantially all of the assets and liabilities of Missouri Gas Energy (MGE), a utility engaged in the distribution of natural gas on a regulated basis in western Missouri, from Southern Union Company (SUG), an affiliate of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. The purchase was completed pursuant to the purchase agreement dated December 14, 2012. Under the terms of the purchase agreement, Laclede Group acquired MGE for a purchase price of $975 million. The acquisition was supported through a combination of the issuance of 10.0 million shares of Laclede Group common stock, completed on May 29, 2013, the issuance by Laclede Gas of $450.0 million of first mortgage bonds, completed on August 13, 2013, short-term borrowings, and available cash.

The acquisition was accounted for under the acquisition method of accounting in accordance with ASC 805 (“Topic 805”), “Business Combinations.” Accordingly, goodwill was measured as the excess of the acquisition-date fair value of the consideration transferred over the amount of acquisition-date identifiable assets acquired net of assumed liabilities. Laclede Group recorded $247.1 million of goodwill as an asset in the consolidated balance sheet, which has been assigned to the Company’s Gas Utility segment.

As part of the MGE acquisition, Laclede Gas has estimated the asset retirement obligation of MGE’s long-lived assets as of the acquisition date. This allocation of asset retirement obligations is preliminary and will be finalized upon completion of a detailed fair value analysis that is being performed by the Company in the first quarter of fiscal 2014.

Under Topic 805, merger-related transaction costs (such as advisory, legal, valuation and other professional fees) are not included as components of consideration transferred but are accounted for as expenses in the periods in which the costs are incurred. During the years ended September 30, 2013 and 2012, Laclede Group incurred $17.0 million and $0.2 million, respectively, of third party pre-tax expenses associated with the transaction. These expenses are included in the Statement of Consolidated Income, with $15.1 million included in Other Operating Expenses and $1.9 million included in Interest on Long-term Debt.

On November 13, 2013, in accordance with Section 3.2 of the purchase agreement for MGE, the Utility provided to SUG a reconciliation of certain balance sheet accounts as of August 31, 2013, the date immediately prior to the closing of the acquisition to the initial valuation date of September 30, 2012. The resulting difference adjusts for changes in the actual net assets transferred to the Utility at closing from the level at September 30, 2012. Section 3.2 also contains a process to resolve any disagreements among the parties, and the Utility plans to adjust cash and goodwill for any change as a result of this process upon final settlement, which is anticipated to be in the first quarter of fiscal 2014.

The amount of revenue and earnings of MGE included in our Statements of Consolidated Income subsequent to the September 1, 2013 acquisition date are as follows:

(Thousands, Except Per Share Amounts)	September 1, 2013 - September 30, 2013
Total net revenues	$	21,985
Net Income	1,795
Earnings/(loss) per share:
Basic	$	0.07
Diluted	$	0.07

The following table summarizes the preliminary fair value of assets acquired and liabilities assumed at the date of the acquisition:

(Thousands)
Assets:
Utility plant	$	671,793
Non-utility property	238
Other investments	3,096
Goodwill	247,078
Other Property and Investments	922,205
Accounts receivable:
Utility	19,963
Other	6,119
Delayed customer billings	10,701
Inventories:
Natural gas stored underground	58,679
Materials and supplies at average cost	3,988
Prepayments and other	487
Total Current Assets	99,937
Deferred Charges:
Regulatory assets	84,014
Other	4,928
Total Deferred Charges	88,942
Total Assets Acquired	$	1,111,084
Liabilities:
Accounts payable	$	20,154
Wages and compensation accrued	5,088
Customer deposits	8,362
Interest accrued	183
Taxes accrued	17,197
Other	12,620
Total Current Liabilities	63,604
Pension and postretirement benefit costs	24,466
Asset retirement obligations	32,056
Regulatory liabilities	2,249
Other	13,709
Total Deferred Credits and Other Liabilities	72,480
Total Liabilities Assumed	$	136,084
Net Assets Acquired	$	975,000

The following unaudited pro forma financial information presents the combined results of operations as if the acquisition had occurred on October 1, 2011. The pro forma financial information does not reflect the costs of any integration activities. The pro forma results include estimates and assumptions, which management believes are reasonable. The unaudited pro forma financial information below is not necessarily indicative of either future results of operations or results that might have been achieved had MGE been part of the Utility as of the beginning of fiscal year 2012.

	Twelve Months Ended September 30,
(Thousands, Except Per Share Amounts)	2013		2012
Total net revenues	$	1,518,201	$	1,581,425
Net Income	83,642		81,722
Earnings per share:
Basic	$	2.57	$	2.52
Diluted	$	2.56	$	2.51

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STATEMENT OF CONSOLIDATED CAPITALIZATION (Parenthetical) (USD $)	Sep. 30, 2013	Sep. 30, 2012
Common Stock Equity:
Common stock, par value (in dollars per share)	$ 1	$ 1
Common stock, authorized (in shares)	70,000,000	70,000,000
Common stock, issued (in shares)	32,696,836	22,539,431
Laclede Group [Member] | 3.31% Notes Payable, due December 15, 2022 [Member]
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	3.31%
Laclede Gas [Member] | First Mortage Bonds 5-1/2% Series, due May 1, 2019 [Member]
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	5.50%	5.50%
Laclede Gas [Member] | First Mortage Bonds 7% Series, due June 1, 2029 [Member]
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	7.00%	7.00%
Laclede Gas [Member] | First Mortage Bonds 7.90% Series, due September 15, 2030 [Member]
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	7.90%	7.90%
Laclede Gas [Member] | First Mortage Bonds 6% Series, due May 1, 2034 [Member]
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	6.00%	6.00%
Laclede Gas [Member] | First Mortage Bonds 6.15% Series, due June 1, 2036 [Member]
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	6.15%	6.15%
Laclede Gas [Member] | First Mortage Bonds 6.35% Series, due October 15, 2038 [Member]
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	6.35%	6.35%
Laclede Gas [Member] | First Mortage Bonds 3% Series, due March 15, 2023 [Member]
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	3.00%	3.00%
Laclede Gas [Member] | First Mortage Bonds 3.40% Series, due March 15, 2028 [Member]
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	3.40%	3.40%
Laclede Gas [Member] | First Mortage Bonds 2% Series, due August 15, 2018 [Member]
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	2.00%	2.00%
Laclede Gas [Member] | First Mortage Bonds 3.40% Series, due August 15, 2023 [Member]
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	3.40%	3.40%
Laclede Gas [Member] | First Mortage Bonds 4.625% Series, due August 15, 2043 [Member]
Long - Term Debt - Laclede Gas:
Debt instrument, interest rate, stated percentage	4.625%	4.625%

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ACQUISITION OF MGE Part 4 - Pro Forma Information (Details) (Missouri Gas Energy (MGE) [Member], USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Missouri Gas Energy (MGE) [Member]
Business Acquisition, Pro Forma Information [Abstract]
Total net revenues	$ 1,518,201	$ 1,581,425
Net Income	$ 83,642	$ 81,722
Earnings per share:
Basic (in dollars per share)	$ 2.57	$ 2.52
Diluted (in dollars per share)	$ 2.56	$ 2.51

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Part 3 (Details) (USD $)	12 Months Ended																				12 Months Ended	165 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013 Unamortized investment tax credits [Member]	Sep. 30, 2012 Unamortized investment tax credits [Member]	Sep. 30, 2013 Accrued cost of removal [Member]	Sep. 30, 2012 Accrued cost of removal [Member]	Sep. 30, 2013 Other Regulatory Liabilities [Member]	Sep. 30, 2012 Other Regulatory Liabilities [Member]	Sep. 30, 2013 Future income taxes due from customers [Member]	Sep. 30, 2012 Future income taxes due from customers [Member]	Sep. 30, 2013 Pension and postretirement benefit costs [Member]	Sep. 30, 2012 Pension and postretirement benefit costs [Member]	Sep. 30, 2013 Unamortized purchased gas adjustments [Member]	Sep. 30, 2012 Unamortized purchased gas adjustments [Member]	Sep. 30, 2013 Purchased gas costs [Member]	Sep. 30, 2012 Purchased gas costs [Member]	Sep. 30, 2013 Compensated absences [Member]	Sep. 30, 2012 Compensated absences [Member]	Sep. 30, 2013 Other [Member]	Sep. 30, 2012 Other [Member]	Sep. 30, 2013 Deferred Costs Incurred Prior to YE 1999 [Member]	Sep. 30, 2013 Deferred Costs Incurred Prior to YE 1999 [Member]	Sep. 01, 2013 Missouri Gas Energy (MGE) [Member]	Sep. 01, 2013 Laclede Group [Member] Missouri Gas Energy (MGE) [Member]
Schedule of Regulatory Assets and Liabilities[Line Items]
Regulatory Assets	$ 563,480,000	$ 496,721,000							$ 112,912,000	$ 118,997,000	$ 381,395,000	$ 304,446,000	$ 17,533,000	$ 40,674,000	$ 18,249,000	$ 18,386,000	$ 8,004,000	$ 7,836,000	$ 25,387,000	$ 6,382,000
Regulatory Liabilities	85,460,000	59,432,000	2,900,000	3,113,000	59,066,000	55,103,000	23,494,000	1,216,000
Regulated Operations [Abstract]
Regulatory assets not earning a rate of return	17,200,000	7,800,000
Regulatory assets not earning a rate of return, recovery period	15 years
Regulatory Assets - Non-current	545,947,000	456,047,000																			10,500,000	10,500,000
Amortization period of deferred costs (in years)																					15 years
Amortization of deferred costs recognized to date - total																						9,700,000
The amount by which the replacement cost exceeds (less than) the cost basis value of stored gas inventories	13,300,000	24,300,000
Goodwill [Abstract]
Goodwill acquired during period	247,078,000	0																					247,078,000	247,100,000
Revenue Recognition [Abstract]
Accrued Unbilled Revenue	$ 25,200,000	$ 11,600,000

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SCHEDULE II (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2011
DOUBTFUL ACCOUNTS [Member]
CHANGES IN RESERVES [Roll Forward]
BALANCE AT BEGINNING OF PERIOD	$ 7,705		$ 10,073		$ 10,295
ADDITIONS TO INCOME	5,584		6,011		7,242
CHARGED TO OTHER ACCOUNTS	8,234	[1]	10,145	[1]	11,340	[1]
DEDUCTIONS FROM RESERVES	13,477	[2]	18,524	[2]	18,804	[2]
BALANCE AT END OF PERIOD	8,046		7,705		10,073
MISCELLANEOUS: Injuries and property damage [Member]
CHANGES IN RESERVES [Roll Forward]
BALANCE AT BEGINNING OF PERIOD	4,540		3,603		3,228
ADDITIONS TO INCOME	1,934		3,150		2,416
CHARGED TO OTHER ACCOUNTS	0		0		0
DEDUCTIONS FROM RESERVES	2,135	[3]	2,213	[3]	2,041	[3]
BALANCE AT END OF PERIOD	4,339		4,540		3,603
MISCELLANEOUS: deferred compensation [Member]
CHANGES IN RESERVES [Roll Forward]
BALANCE AT BEGINNING OF PERIOD	14,205		13,474		12,571
ADDITIONS TO INCOME	1,781		1,756		1,893
CHARGED TO OTHER ACCOUNTS	0		0		0
DEDUCTIONS FROM RESERVES	1,306		1,025		990
BALANCE AT END OF PERIOD	14,680		14,205		13,474
MISCELLANEOUS: group medical claims incurred but not reported [Member]
CHANGES IN RESERVES [Roll Forward]
BALANCE AT BEGINNING OF PERIOD	1,560		1,300		1,450
ADDITIONS TO INCOME	17,205		15,381		14,171
CHARGED TO OTHER ACCOUNTS	0		0		0
DEDUCTIONS FROM RESERVES	16,116	[3]	15,121	[3]	14,321	[3]
BALANCE AT END OF PERIOD	2,649		1,560		1,300
Total MISCELLANEOUS [Member]
CHANGES IN RESERVES [Roll Forward]
BALANCE AT BEGINNING OF PERIOD	20,305		18,377		17,249
ADDITIONS TO INCOME	20,920	[4]	20,287		18,480
CHARGED TO OTHER ACCOUNTS	0	[4]	0		0
DEDUCTIONS FROM RESERVES	19,557	[4]	18,359		17,352
BALANCE AT END OF PERIOD	$ 21,668		$ 20,305		$ 18,377

[1] Accounts reinstated, cash recoveries, etc.

[2] Accounts written off.

[3] Claims settled, less reimbursements from insurance companies.

[4] Totals for the year ended September 30, 2013 includes one month of MGE activity.

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STOCK-BASED COMPENSATION (Tables)

12 Months Ended

Sep. 30, 2013

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Restricted stock and restricted stock unit activity

Time-vested restricted stock and stock unit activity for fiscal year 2013 is presented below:

	Shares/ Units		Weighted Average Grant Date Fair Value
Nonvested at September 30, 2012	115,115		$	36.54
Granted	59,124		$	40.00
Vested	(43,785	)	$	34.95
Forfeited	(11,050	)	$	38.61
Nonvested at September 30, 2013	119,404		$	38.64

Fiscal year 2013 activity of restricted stock and restricted stock units subject to performance and/or market conditions is presented below:

	Shares/ Units		Weighted Average Grant Date Fair Value
Nonvested at September 30, 2012	232,403		$	30.89
Granted (maximum shares that can be earned)	108,419		$	34.49
Vested	(47,436	)	$	27.61
Forfeited	(51,118	)	$	26.11
Nonvested at September 30, 2013	242,268		$	34.15

Stock option awards activity

No stock options were granted during fiscal years 2013, 2012, and 2011. Stock option activity for fiscal year 2013 is presented below:

	Stock Options		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (Years)	Aggregate Intrinsic Value ($000)
Outstanding at September 30, 2012	214,000		$	31.02
Granted	—		$	—
Exercised	(80,500	)	$	29.61
Forfeited	—		$	—
Expired	—		$	—
Outstanding at September 30, 2013	133,500		$	31.87	2.8	$	1,752
Fully Vested and Expected to Vest at September 30, 2013	133,500		$	31.87	2.8	$	1,752
Exercisable at September 30, 2013	133,500		$	31.87	2.8	$	1,752

Significant assumptions used in the Monte Carlo simulations

The significant assumptions used in the Monte Carlo simulations are as follows:

	2013		2012		2011
Risk free interest rate	0.32	%	0.39	%	0.79	%
Expected dividend yield of stock	—		—		—
Expected volatility of stock	19.60	%	23.21	%	33.42	%
Vesting period	2.8 years		2.8 years		2.8 years

Compensation cost recognized for share-based compensation arrangements

The amounts of compensation cost recognized for share-based compensation arrangements are presented below:

(Thousands)	2013			2012			2011
Total equity compensation cost	$	4,453		$	2,707		$	3,980
Compensation cost capitalized	(1,366		)	(808		)	(924		)
Compensation cost recognized in net income	3,087			1,899			3,056
Income tax benefit recognized in net income	(1,182		)	(733		)	(1,179		)
Compensation cost recognized in net income, net of income tax	1,905			1,166			1,877

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INTERIM FINANCIAL INFORMATION (UNAUDITED) (Unaudited) (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended									12 Months Ended
	Sep. 30, 2013		Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Quarterly Financial Information Disclosure [Abstract]
Total Operating Revenues	$ 147,114	[1]	$ 165,289	$ 397,613	$ 307,003	$ 169,538	$ 186,849	$ 358,175	$ 410,913	$ 1,017,019	$ 1,125,475	$ 1,603,307
Operating Income (Loss)	(9,722)	[1]	12,282	51,849	42,085	1,869	15,045	50,583	43,105	96,494	110,602	118,247
Net Income (Loss)	$ (9,636)	[1]	$ 6,584	$ 30,242	$ 25,568	$ (651)	$ 8,433	$ 29,684	$ 25,174	$ 52,758	$ 62,640	$ 63,825
Basic Earnings (Loss) Per Share of Common Stock (in dollars per share)	$ (0.30)	[1]	$ 0.25	$ 1.34	$ 1.14	$ (0.03)	$ 0.38	$ 1.33	$ 1.13	$ 2.03	$ 2.80	$ 2.87
Diluted Earnings (Loss) Per Share of Common Stock (in dollars per share)	$ (0.30)	[1]	$ 0.25	$ 1.34	$ 1.14	$ (0.03)	$ 0.38	$ 1.32	$ 1.12	$ 2.02	$ 2.79	$ 2.86

[1] All quarters of 2013 reflect transaction costs incurred associated with the acquisition of MGE. The fourth quarter of 2013 includes one month of activity of the operations of MGE, significant transaction costs incurred in the quarter and the interest impact of the debt issued in the quarter. Total impact of all of these during the quarter was a decrease in net income of $5.5 million.

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STOCK-BASED COMPENSATION (Details) (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares of common stock that may be issued (in shares)	1,250,000
Stock Option Awards [Abstract]
Common stock closing price (per share)	$ 45.00
Fair Value Assumptions and Methodology [Abstract]
Risk free interest rate	0.32%	0.39%	0.79%
Expected dividend yield of stock	0.00%	0.00%	0.00%
Expected volatility of stock	19.60%	23.21%	33.42%
Vesting period	2 years 9 months 18 days	2 years 9 months 18 days	2 years 9 months 18 days
Total equity compensation cost	$ 4,453,000	$ 2,707,000	$ 3,980,000
Compensation cost capitalized	(1,366,000)	(808,000)	(924,000)
Compensation cost recognized in net income	3,087,000	1,899,000	3,056,000
Income tax benefit recognized in net income	(1,182,000)	(733,000)	(1,179,000)
Compensation cost recognized in net income, net of income tax	1,905,000	1,166,000	1,877,000
Total unrecognized compensation cost	4,900,000
Weighted average period cost to be recognized (in years)	2 years
Restricted Stock Awards [Member]
Restricted Stock Awards [Abstract]
Vested (in shares)	91,221	90,839	94,500
Vested restricted stock withheld for tax withholding obligations (in shares)	23,311	30,052	32,373
Vested restricted stock withheld for tax withholding obligations, weighted average price (in dollars per share)	$ 39.96	$ 40.02	$ 35.90
Fair value, restricted stock	3,800,000	4,200,000	3,600,000
Actual tax benefit realized	1,400,000	1,600,000	1,400,000
Shares/ Units
Vested (in shares)	(91,221)	(90,839)	(94,500)
Stock Option Awards [Abstract]
Actual tax benefit realized	1,400,000	1,600,000	1,400,000
Restricted Stock Awards [Member] | Time Vested Restricted Stock and Time Vested Restricted Stock Units [Member]
Restricted Stock Awards [Abstract]
Granted (in shares)	59,124
Granted, weighted average grant date fair value (per share)	$ 40.00
Vested (in shares)	43,785
Shares/ Units
Nonvested at September 30, 2012 (in shares)	115,115
Granted (in shares)	59,124
Vested (in shares)	(43,785)
Forfeited (in shares)	(11,050)
Nonvested at September 30, 2013 (in shares)	119,404
Weighted Average Grant Date Fair Value
Nonvested at September 30, 2012 (in dollars per share)	$ 36.54
Granted (in dollars per share)	$ 40.00
Vested (in dollars per share)	$ 34.95
Forfeited (in dollars per share)	$ 38.61
Nonvested at September 30, 2013 (in dollars per share)	$ 38.64
Restricted Stock Awards [Member] | Non Employee Directors [Member] | Time Vested Restricted Stock and Time Vested Restricted Stock Units [Member]
Restricted Stock Awards [Abstract]
Granted (in shares)	15,200
Granted, weighted average grant date fair value (per share)	$ 39.92	$ 41.36	$ 39.48
Shares/ Units
Granted (in shares)	15,200
Weighted Average Grant Date Fair Value
Granted (in dollars per share)	$ 39.92	$ 41.36	$ 39.48
Restricted Stock Awards [Member] | Executive Officers and Key Employees [Member] | Performance Contingent Restricted Stock and Stock Units [Member]
Restricted Stock Awards [Abstract]
Granted (in shares)	108,419
Granted, weighted average grant date fair value (per share)	$ 34.49	$ 36.55	$ 30.68
Vested (in shares)	47,436
Shares/ Units
Nonvested at September 30, 2012 (in shares)	232,403
Granted (in shares)	108,419
Vested (in shares)	(47,436)
Forfeited (in shares)	(51,118)
Nonvested at September 30, 2013 (in shares)	242,268	232,403
Weighted Average Grant Date Fair Value
Nonvested at September 30, 2012 (in dollars per share)	$ 30.89
Granted (in dollars per share)	$ 34.49	$ 36.55	$ 30.68
Vested (in dollars per share)	$ 27.61
Forfeited (in dollars per share)	$ 26.11
Nonvested at September 30, 2013 (in dollars per share)	$ 34.15	$ 30.89
Restricted Stock Awards [Member] | Executive Officers and Key Employees [Member] | Time Vested Restricted Stock and Time Vested Restricted Stock Units [Member]
Restricted Stock Awards [Abstract]
Granted (in shares)	43,924
Granted, weighted average grant date fair value (per share)	$ 40.03	$ 39.72	$ 35.93
Shares/ Units
Granted (in shares)	43,924
Weighted Average Grant Date Fair Value
Granted (in dollars per share)	$ 40.03	$ 39.72	$ 35.93
Stock Option Awards [Member]
Restricted Stock Awards [Abstract]
Actual tax benefit realized	400,000	400,000	100,000
Stock Options
Outstanding at September 30, 2012 (in shares)	214,000
Granted (in shares)	0
Exercised (in shares)	(80,500)
Forfeited (in shares)	0
Expired (in shares)	0
Outstanding at September 30, 2013 (in shares)	133,500	214,000
Fully Vested and Expected to Vest at September 30, 2013 (in shares)	133,500
Exercisable at September 30, 2013 (in shares)	133,500
Weighted Average Exercise Price
Outstanding at September 30, 2012 (in dollars per share)	$ 31.02
Granted (in dollars per share)	$ 0.00
Exercised (in dollars per share)	$ 29.61
Forfeited (in dollars per share)	$ 0.00
Expired (in dollars per share)	$ 0.00
Outstanding at September 30, 2013 (in dollars per share)	$ 31.87	$ 31.02
Fully Vested and Expected to Vest at September 30, 2013 (in dollars per share)	$ 31.87
Exercisable at September 30, 2013 (in dollars per share)	$ 31.87
Stock Options (Additional Information)
Outstanding at End of Period, weighted average remaining contractual term - stock options (in years)	2 years 9 months 18 days
Fully Vested and Expected to Vest at End of Period, weighted average remaining contractual term - stock options (in years)	2 years 9 months 18 days
Exercisable at End of Period, weighted average remaining contractual term - stock options (in years)	2 years 9 months 18 days
Outstanding Ending Balance, aggregate intrinsic value - stock options	1,752,000
Fully Vested and Expected to Vest at End of Period, aggregate intrinsic value - stock options	1,752,000
Exercisable at End of Period, aggregate intrinsic value - stock options	1,752,000
Stock Option Awards [Abstract]
Exercise price range , minimum (in dollars per share)	$ 28.85
Exercise price range , maximum (in dollars per share)	$ 34.95
Cash received from the exercise of stock options	2,700,000	2,500,000	900,000
Intrinsic value of exercised	1,000,000	1,000,000	200,000
Actual tax benefit realized	$ 400,000	$ 400,000	$ 100,000
Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period, minimum (in years)	3 years

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 7 (Details)	12 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2011
Pension Plans [Member]
Assumptions used to calculate net periodic cost [Abstract]
Weighted average discount rate	3.95%	[1]	5.10%	[1]	4.75%	[1]
Weighted average rate of future compensation increase	3.00%		3.00%		3.00%
Expected long-term rate of return on plan assets	7.75%		7.75%		8.00%
Assumptions used to calculate benefit obligations [Abstract]
Weighted average discount rate	4.70%	[2]	3.95%	[2]
Weighted average rate of future compensation increase	3.00%		3.00%
Pension Plans [Member] | Missouri Gas Energy (MGE) [Member]
Assumptions used to calculate net periodic cost [Abstract]
Weighted average discount rate	5.05%
Assumptions used to calculate benefit obligations [Abstract]
Weighted average discount rate	5.00%
Postretirement Plans [Member]
Assumptions used to calculate net periodic cost [Abstract]
Weighted average discount rate	3.80%	[3]	5.05%	[3]	4.70%	[3]
Weighted average rate of future compensation increase	3.00%		3.00%		3.00%
Expected long-term rate of return on plan assets	7.75%	[4]	7.75%	[4]	8.00%	[4]
Assumptions used to calculate benefit obligations [Abstract]
Weighted average discount rate	4.60%	[5]	3.80%	[5]
Weighted average rate of future compensation increase	3.00%		3.00%
Postretirement Plans [Member] | Missouri Gas Energy (MGE) [Member]
Assumptions used to calculate net periodic cost [Abstract]
Weighted average discount rate	5.05%	[3]
Expected long-term rate of return on plan assets	5.75%	[4]
Assumptions used to calculate benefit obligations [Abstract]
Weighted average discount rate	4.95%	[3]

[1] Weighted average discount rate assumption for the MGE pension plan is 5.05%.

[2] Derivative assets of $3,027 net of cash margin payable of $2,750.

[3] Weighted average discount rate assumption for the MGE postretirement plan is 5.05%.

[4] Expected long-term rate of return on plan assets assumption for the MGE postretirement plan is

[5] Weighted average discount rate assumption for the MGE postretirement plan is 4.95%.

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FAIR VALUE OF FINANCIAL INSTRUMENTS

12 Months Ended

Sep. 30, 2013

Fair Value Disclosures [Abstract]

FAIR VALUE OF FINANCIAL INSTRUMENTS

FAIR VALUE OF FINANCIAL INSTRUMENTS

The carrying amounts and estimated fair values of financial instruments not measured at fair value on a recurring basis at September 30, 2013 and 2012 are as follows:

					Classification of Estimated Fair Value
(Thousands)	Carrying Amount		Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
As of September 30, 2013
Cash and cash equivalents	$	52,981	$	52,981	$	52,824	$	157	$	—
Short-term debt	74,000		74,000		—		74,000		—
Long-term debt, including current portion	912,712		954,126		—		954,126		—
As of September 30, 2012
Cash and cash equivalents	$	27,457	$	27,457	$	17,380	$	10,077	$	—
Short-term debt	40,100		40,100		—		40,100		—
Long-term debt, including current portion	364,416		452,768		—		452,768		—

The carrying amounts for cash and cash equivalents and short-term debt approximate fair value due to the short maturity of these instruments. The fair values of long-term debt are estimated based on market prices for similar issues. Refer to Note 10, Fair Value Measurements, for information on financial instruments measured at fair value on a recurring basis.

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EARNINGS PER COMMON SHARE

12 Months Ended

Sep. 30, 2013

Earnings Per Share [Abstract]

EARNINGS PER COMMON SHARE

EARNINGS PER COMMON SHARE    

(Thousands, Except Per Share Amounts)	2013		2012		2011
Basic EPS:
Net Income	$	52,758	$	62,640	$	63,825
Less: Income allocated to participating securities	245		340		497
Net Income Available  to Common Shareholders	$	52,513	$	62,300	$	63,328
Weighted Average Shares Outstanding	25,875		22,262		22,099
Earnings Per Share of Common Stock	$	2.03	$	2.80	$	2.87
Diluted EPS:
Net Income	$	52,758	$	62,640	$	63,825
Less: Income allocated to participating securities	245		340		496
Net Income Available to Common Shareholders	$	52,513	$	62,300	$	63,329
Weighted Average Shares Outstanding	25,875		22,262		22,099
Dilutive Effect of Stock Options, Restricted Stock, and Restricted Stock Units	77		78		72
Weighted Average Diluted Shares	25,952		22,340		22,171
Earnings Per Share of Common Stock	$	2.02	$	2.79	$	2.86
Outstanding Shares Excluded from the Calculation of Diluted EPS Attributable to:
Antidilutive stock options	—		—		—
Restricted stock and stock units subject to performance and/or market conditions	188		195		203
Total	188		195		203

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STOCKHOLDER'S EQUITY (Details) (USD $)	1 Months Ended	12 Months Ended				12 Months Ended					0 Months Ended	12 Months Ended
	May 31, 2013	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011	Jun. 30, 2013	Sep. 30, 2013 Net Unrealized Gains (Losses) on Cash Flow Hedges [Member]	Sep. 30, 2012 Net Unrealized Gains (Losses) on Cash Flow Hedges [Member]	Sep. 30, 2013 Defined Benefit Pension and Other Postretirement Benefit Plans [Member]	Sep. 30, 2012 Defined Benefit Pension and Other Postretirement Benefit Plans [Member]	Nov. 26, 2013 Subsequent Event [Member]	Aug. 13, 2013 Laclede Gas [Member]	Sep. 30, 2013 Laclede Gas [Member]	Nov. 26, 2013 Laclede Gas [Member] Subsequent Event [Member]
Accumulated other comprehensive income (loss), net of income taxes [Line Items]
Common stock, issued (in shares)		32,700,000	22,540,000
Increase in common stock and paid-in capital		$ 435,800,000	$ 5,000,000
Shares issued - dividend reinvestment plan and stock purchase plan (in shares)		44,074	46,107
Shares issued - dividend reinvestment plan and stock purchase plan		1,847,000	1,841,000	1,614,000
Shares issued - Equity plan and stock-based compensation costs		434,000,000	3,200,000
Stock Issued During Period, Shares, Share-based Compensation, Gross	10,005,000
Shares issued - Equity plan and stock-based compensation costs (in shares)		108,331	62,590
Dividend payment restriction formula component - fixed amount		8,000,000
Dividend payment restriction formula resulting calculation - available to pay dividends in period		833,000,000	355,000,000
SEC effective shelf registration Form S-3 sale and issuance authorization under the dividend reinvestment and stock purchase program (in shares)		285,222
SEC effective shelf registration Form S-3 remaining and available for issuance under the dividend reinvestment and stock purchase program (in shares)		194,246								186,919
Issuance of first mortgage bonds		550,000,000	0	0							450,000,000
MoPSC authorized debt issuance through June 30, 2013 - maximum available					518,000,000							518,000,000
Extension period for debt securities and preferred stock issuance authority		2 years										2 years
MoPSC authorized debt issuance - remaining available		370,800,000											370,800,000
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Balance, beginning balance		(4,116,000)	(2,100,000)			(1,886,000)	320,000	(2,230,000)	(2,420,000)
Current-period change		3,329,000	(2,016,000)	5,037,000		3,281,000	(2,206,000)	48,000	190,000
Balance, ending balance		$ (787,000)	$ (4,116,000)	$ (2,100,000)		$ 1,395,000	$ (1,886,000)	$ (2,182,000)	$ (2,230,000)

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CONCENTRATIONS OF CREDIT RISK

12 Months Ended

Sep. 30, 2013

Risks and Uncertainties [Abstract]

CONCENTRATIONS OF CREDIT RISK

CONCENTRATION OF CREDIT RISK

A significant portion of LER’s transactions are with (or are associated with) energy producers, utility companies, and pipelines. These concentrations of transactions with these counterparties have the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that each of these three groups may be affected similarly by changes in economic, industry, or other conditions. To manage this risk, as well as credit risk from significant counterparties in these and other industries, LER has established procedures to determine the creditworthiness of its counterparties. These procedures include obtaining credit ratings and credit reports, analyzing counterparty financial statements to assess financial condition, and considering the industry environment in which the counterparty operates. This information is monitored on an ongoing basis. In some instances, LER may require credit assurances such as prepayments, letters of credit, or parental guarantees. In addition, LER may enter into netting arrangements to mitigate credit risk with counterparties in the energy industry from which LER both sells and purchases natural gas. Sales are typically made on an unsecured credit basis with payment due the month following delivery. Accounts receivable amounts are closely monitored and provisions for uncollectible amounts are accrued when losses are probable. To date, losses have not been significant. LER records accounts receivable, accounts payable, and prepayments for physical sales and purchases of natural gas on a gross basis. The amount included in accounts receivable attributable to energy producers and their marketing affiliates amounted to $22.8 million at September 30, 2013. However, due to netting arrangements, there were no net receivable amounts from these customers on that same date. Accounts receivable attributable to utility companies and their marketing affiliates comprised $23.5 million of total accounts receivable at September 30, 2013, while net receivable amounts from these customers, reflecting netting arrangements, were $16.6 million. LER also has concentrations of credit risk with certain individually significant counterparties. At September 30, 2013, the amounts included in accounts receivable from LER’s five largest counterparties (in terms of net accounts receivable exposure), were $16.6 million. These five counterparties are either investment-grade rated or owned by investment-grade rated companies. Net receivable amounts from these customers on the same date, reflecting netting arrangements, were $14.5 million. Additionally, LER has concentrations of credit risk with pipeline companies associated with its natural gas receivable amounts.

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FAIR VALUE MEASUREMENTS

12 Months Ended

Sep. 30, 2013

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

The following table categorizes the assets and liabilities in the Consolidated Balance Sheets that are accounted for at fair value on a recurring basis in periods subsequent to initial recognition.

(Thousands)	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Effects of Netting and Cash Margin Receivables /Payables			Total
As of September 30, 2013
Assets
U. S. Stock/Bond Mutual Funds	$	14,500	$	—	$	—	$	—		$	14,500
NYMEX/ICE natural gas contracts	4,333		330		—		(2,145		)	$	2,518
OTCBB natural gas contracts	—		232		—		(232		)	—
NYMEX gasoline and heating oil contracts	105		—		—		(105		)	$	—
Natural gas commodity contracts	—		1,129		150		(495		)	$	784
Total	$	18,938	$	1,691	$	150	$	(2,977	)	$	17,802
Liabilities
NYMEX/ICE natural gas contracts	$	3,687	$	321	$	—	$	(4,008	)	$	—
OTCBB natural gas contracts	—		5,443		—		(232		)	$	5,211
NYMEX gasoline and heating oil contracts	—		—		—		—			$	—
Natural gas commodity contracts	—		1,140		40		(495		)	$	685
Total	$	3,687	$	6,904	$	40	$	(4,735	)	$	5,896
As of September 30, 2012
Assets
U. S. Stock/Bond Mutual Funds	$	13,187	$	—	$	—	$	—		$	13,187
NYMEX/ICE natural gas contracts	7,411		994		—		(8,405		)	$	—
NYMEX gasoline and heating oil contracts	344		—		—		(344		)	$	—
Natural gas commodity contracts	—		3,060		113		(299		)	$	2,874
Total	$	20,942	$	4,054	$	113	$	(9,048	)	$	16,061
Liabilities
NYMEX/ICE natural gas contracts	$	12,253	$	1,891	$	—	$	(14,144	)	$	—
NYMEX gasoline and heating oil contracts	—		—		—		—			$	—
Natural gas commodity contracts	—		428		4		(299		)	$	133
Total	$	12,253	$	2,319	$	4	$	(14,443	)	$	133

The mutual funds included in Level 1 are valued based on exchange-quoted market prices of identical securities. Derivative instruments included in Level 1 are valued using quoted market prices on the NYMEX. Derivative instruments classified in Level 2 include physical commodity derivatives that are valued using Over The Counter Bulletin Board (OTCBB), broker, or dealer quotation services whose prices are derived principally from, or are corroborated by, observable market inputs. Also included in Level 2 are certain derivative instruments that have values that are similar to, and correlate with, quoted prices for exchange-traded instruments in active markets. Derivative instruments included in Level 3 are valued using generally unobservable inputs that are based upon the best information available and reflect management’s assumptions about how market participants would price the asset or liability. The Company’s policy is to recognize transfers between the levels of the fair value hierarchy, if any, as of the beginning of the interim reporting period in which circumstances change or events occur to cause the transfer. The following is a reconciliation of the Level 3 beginning and ending net derivative balances:

(Thousands)	2013			2012
Beginning of period	$	109		$	13
Settlements	(269		)	(54		)
Net losses related to derivatives not held at end of period	(99		)	(68		)
Net gains related to derivatives still held at end of period	369			218
End of period	$	110		$	109

The mutual funds are included in the Other investments line of the Consolidated Balance Sheets. Derivative assets and liabilities, including receivables and payables associated with cash margin requirements, are presented net in the Consolidated Balance Sheets when a legally enforceable netting agreement exists between the Company and the counterparty to a derivative contract. For additional information on derivative instruments, see Note 11, Derivative Instruments and Hedging Activities.

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Document And Entity Information (USD $)	12 Months Ended
	Sep. 30, 2013	Nov. 21, 2013	Mar. 31, 2013
Document and Entity Information [Abstract]
Entity Registrant Name	LACLEDE GROUP INC
Entity Central Index Key	0001126956
Current Fiscal Year End Date	--09-30
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 906,985,448
Entity Common Stock, Shares Outstanding		32,709,763
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY
Document Type	10-K
Amendment Flag	false
Document Period End Date	Sep. 30, 2013

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

12 Months Ended

Sep. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

The Utility has a risk management policy that allows for the purchase of natural gas derivative instruments with the goal of managing price risk associated with purchasing natural gas on behalf of its customers. This policy prohibits speculation and permits the Utility to hedge up to 70% of its normal volumes purchased for up to a 36-month period. Costs and cost reductions, including carrying costs, associated with the Utility’s use of natural gas derivative instruments are allowed to be passed on to the Utility’s customers through the operation of its PGA Clause, through which the MoPSC allows the Utility to recover gas supply costs, subject to prudence review by the MoPSC. Accordingly, the Utility does not expect any adverse earnings impact as a result of the use of these derivative instruments. The Utility does not designate these instruments as hedging instruments for financial reporting purposes because gains or losses associated with the use of these derivative instruments are deferred and recorded as regulatory assets or regulatory liabilities pursuant to ASC Topic 980, “Regulated Operations,” and, as a result, have no direct impact on the Statements of Consolidated Income. The timing of the operation of the PGA Clause may cause interim variations in short-term cash flows, because the Utility is subject to cash margin requirements associated with changes in the values of these instruments. Nevertheless, carrying costs associated with such requirements are recovered through the PGA Clause.

From time to time, the Utility purchases NYMEX futures and options contracts to help stabilize operating costs associated with forecasted purchases of gasoline and diesel fuels used to power vehicles and equipment used in the course of its business. At September 30, 2013, Laclede Gas held 0.3 million gallons of gasoline futures contracts at an average price of $2.23 per gallon. Most of these contracts, the longest of which extends to April 2014, are designated as cash flow hedges of forecasted transactions pursuant to ASC Topic 815. The gains or losses on these derivative instruments are not subject to the Utility’s PGA Clause.

In the course of its business, Laclede Group’s non-regulated gas marketing subsidiary, LER, which includes its wholly owned subsidiary LER Storage Services, Inc., enters into commitments associated with the purchase or sale of natural gas. Certain of LER’s derivative natural gas contracts are designated as normal purchases or normal sales and, as such, are excluded from the scope of ASC Topic 815 and are accounted for as executory contracts on an accrual basis. Any of LER’s derivative natural gas contracts that are not designated as normal purchases or normal sales are accounted for at fair value. At September 30, 2013, the fair values of 67.4 million MMBtu of non-exchange traded natural gas commodity contracts were reflected in the Consolidated Balance Sheet. Of these contracts, 58.5 million MMBtu will settle during fiscal year 2014, 8.1 million MMBtu will settle during fiscal year 2015, while the remaining 0.8 million MMBtu will settle during fiscal year 2016. These contracts have not been designated as hedges; therefore, changes in the fair value of these contracts are reported in earnings each period. Furthermore, LER manages the price risk associated with its fixed-priced commitments by either closely matching the offsetting physical purchase or sale of natural gas at fixed prices or through the use of NYMEX or ICE futures, swap, and option contracts to lock in margins. At September 30, 2013, LER’s unmatched fixed-price positions were not material to Laclede Group’s financial position or results of operations. LER’s NYMEX and ICE natural gas futures, swap, and option contracts used to lock in margins may be designated as cash flow hedges of forecasted transactions for financial reporting purposes.

Derivative instruments designated as cash flow hedges of forecasted transactions are recognized on the Consolidated Balance Sheets at fair value and the change in the fair value of the effective portion of these hedge instruments is recorded, net of tax, in other comprehensive income (OCI). Accumulated other comprehensive income (AOCI) is a component of Total Common Stock Equity. Amounts are reclassified from AOCI into earnings when the hedged items affect net income, using the same revenue or expense category that the hedged item impacts. Based on market prices at September 30, 2013, it is expected that approximately $2.3 million of pretax losses will be reclassified into the Statements of Consolidated Income during fiscal year 2014. Cash flows from hedging transactions are classified in the same category as the cash flows from the items that are being hedged in the Statements of Consolidated Cash Flows.

The Company’s exchange-traded/cleared derivative instruments consist primarily of NYMEX and ICE positions. The NYMEX is the primary national commodities exchange on which natural gas derivatives are traded. Open NYMEX/ICE and OTCBB natural gas futures and swap positions at September 30, 2013 were as follows:

	Laclede Gas Company			Laclede Energy Resources, Inc.
	MMBtu (millions)	Avg. Price Per MMBtu		MMBtu (millions)	Avg. Price Per MMBtu
NYMEX/ICE open short futures/swap positions
Fiscal 2014	—	$	—	12.91	$	3.98
Fiscal 2015	—	—		0.06	4.21
NYMEX/ICE open long futures/swap positions
Fiscal 2014	7.26	$	3.99	1.71	$	3.94
Fiscal 2015	0.94	3.84		0.19	4.06
Fiscal 2016	—	—		0.02	4.15
OTCBB open long futures
Fiscal 2014	16.81	$	3.97	—	$	—
Fiscal 2015	7.58	4.22		—	—

At September 30, 2013, the Utility and LER also had 23.6 million MMBtu and 0.0 million MMBtu, respectively, of other price mitigation in place through the use of NYMEX and OTCBB natural gas option-based strategies.

In February 2013, Laclede Group entered into certain interest rate swap agreements, with a notional amount of $355 million, to effectively lock in interest rates on a portion of the long-term debt it anticipated issuing to finance its acquisition of Missouri Gas Energy (MGE). These derivative instruments had been designated as cash flow hedges of forecasted transactions. These forward starting swaps involve the payment of a fixed interest rate and the receipt of a floating interest rate (the London Interbank Offered Rate, also known as LIBOR) over the terms specified in the contracts. On August 6, 2013, the interest rate swap agreements were terminated and the settlement resulted in a $20.8 million gain by Laclede Group. The Company assigned the gain as a regulatory liability since the interest rate swaps were entered into to hedge the interest payments on the $450 million of long-term debt issued on August 13, 2013 by Laclede Gas.

The Effect of Derivative Instruments on the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income
	Location of Gain (Loss)
(Thousands)	Recorded in Income	2013			2012			2011
Derivatives in Cash Flow Hedging Relationships
Effective portion of gain (loss) recognized in OCI on derivatives:
NYMEX/ICE natural gas contracts		$	4,923		$	4,505		$	5,226
NYMEX gasoline and heating oil contracts		123			297			355
Total		$	5,046		$	4,802		$	5,581
Effective portion of gain (loss) reclassified from AOCI to income:
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	$	(4	)	$	18,929		$	7,443
	Gas Marketing Operating Expenses	(509		)	(10,532		)	(9,770		)
Sub-total		$	(513	)	$	8,397		$	(2,327	)
NYMEX gasoline and heating oil contracts	Gas Utility Other Operation Expenses	211			—			466
Total		$	(302	)	$	8,397		$	(1,861	)
Ineffective portion of gain (loss) on derivatives     recognized in income:
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	$	(420	)	$	(36	)	$	966
	Gas Marketing Operating Expenses	(239		)	(263		)	(1,322		)
Sub-total		$	(659	)	$	(299	)	$	(356	)
NYMEX gasoline and heating oil contracts	Gas Utility Other Operation Expenses	(127		)	175			12
Total		$	(786	)	$	(124	)	$	(344	)
Derivatives Not Designated as Hedging Instruments*
Gain (loss) recognized in income on derivatives:
Natural gas commodity contracts	Gas Marketing Operating Revenues	$	(78	)	$	3,782		$	(660	)
	Gas Marketing Operating Expenses	—			687			4,229
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	(778		)	(615		)	(115		)
	Gas Marketing Operating Expenses	—			(625		)	(3		)
NYMEX gasoline and heating oil contracts	Other Income and (Income Deductions) - Net	41			19			37
Total		$	(815	)	$	3,248		$	3,488

* Gains and losses on the Utility’s natural gas derivative instruments, which are not designated as hedging instruments for financial reporting purposes, are deferred pursuant to the Utility’s PGA Clause and initially recorded as regulatory assets or regulatory liabilities. These gains and losses are excluded from the table above because they have no direct impact on the Statements of Consolidated Income. Such amounts are recognized in the Statements of Consolidated Income as a component of Regulated Gas Distribution Natural and Propane Gas operating expenses when they are recovered through the PGA Clause and reflected in customer billings.

Fair Value of Derivative Instruments in the Consolidated Balance Sheet at September 30, 2013
	Asset Derivatives*				Liability Derivatives*
(Thousands)	Balance Sheet Location	Fair Value			Balance Sheet Location	Fair  Value
Derivatives designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets	$	2,222		Derivative Instrument Assets	$	440
	Other Deferred Charges	22			Other Deferred Charges	11
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	105			Accounts Receivable - Other	—
Sub-total		2,349				451
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets	950			Derivative Instrument Assets	100
	Accounts Receivable - Other	1,434			Accounts Receivable - Other	3,455
	Other Deferred Charges	32			Other Deferred Charges	—
OTCBB natural gas contracts	Other Current Liabilities	228			Other Current Liabilities	4,045
	Other Deferred Credits	4			Other Deferred Credits	1,398
Natural gas commodity contracts	Derivative Instrument Assets	991			Derivative Instrument Assets	90
	Other Deferred Charges	20			Other Deferred Charges	137
	Other Current Liabilities	247			Other Current Liabilities	830
	Other Deferred Credits	21			Other Deferred Credits	123
Sub-total		3,927				10,178
Total derivatives		$	6,276			$	10,629
Fair Value of Derivative Instruments in the Consolidated Balance Sheet at September 30, 2012
	Asset Derivatives				Liability Derivatives
(Thousands)	Balance Sheet Location	Fair Value		*	Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments
NYMEX/ICE natural gas contracts	Accounts Receivable - Other	$	405		Accounts Receivable - Other	$	3,413
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	334			Accounts Receivable - Other	—
Sub-total		739				3,413
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Accounts Receivable - Other	8,000			Accounts Receivable - Other	10,731
	Other Deferred Charges	—			Other Deferred Charges	—
Natural gas commodity contracts	Derivative Instrument Assets	3,150			Derivative Instrument Assets	295
	Other Current Liabilities	4			Other Current Liabilities	137
	Other Deferred Charges	19			Other Deferred Charges	—
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	10			Accounts Receivable - Other	—
Sub-total		11,183				11,163
Total derivatives		$	11,922			$	14,576

* The fair values of Asset Derivatives and Liability Derivatives exclude the fair value of cash margin receivables or payables with counterparties subject to netting arrangements. Fair value amounts of derivative contracts (including the fair value amounts of cash margin receivables and payables) for which there is a legal right to set off are presented net on the Consolidated Balance Sheets. As such, the gross balances presented in the table above are not indicative of the Company’s net economic exposure. Refer to Note 10, Fair Value Measurements, for information on the valuation of derivative instruments.

Following is a reconciliation of the amounts in the tables above to the amounts presented in the Consolidated Balance Sheets:

(Thousands)	2013			2012
Fair value of asset derivatives presented above	6,276			11,922
Fair value of cash margin receivables offset with derivatives	1,765			5,478
Netting of assets and liabilities with the same counterparty	(4,739		)	(14,526		)
Total	3,302			2,874
Derivative Instrument Assets, per Consolidated Balance Sheets:
Derivative instrument assets	3,291			2,855
Other deferred charges	11			19
Total	3,302			2,874
Fair value of liability derivatives presented above	10,629			14,576
Fair value of cash margin payables offset with derivatives	6			83
Netting of assets and liabilities with the same counterparty	(4,739		)	(14,526		)
Derivative instrument liabilities, per Consolidated Balance Sheets	5,896			133
Derivative Instrument Liabilities, per Consolidated Balance Sheets:
Other current liabilities	$	4,400		$	133
Other deferred credits	1,496			—
Total	$	5,896		$	133

Additionally, at September 30, 2013 and 2012, the Company had $3.2 million and $10.0 million, respectively, in cash margin receivables not offset with derivatives, that are presented in Accounts Receivable – Other.

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 9 (Details)	12 Months Ended
	Sep. 30, 2013		Sep. 30, 2012
Pension Plans [Member]
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 [Member] | Equity Markets [Member]
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	42.50%
Actual allocation of plan assets	45.90%		37.30%
Pension Plans [Member] | Commodities [Member]
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	2.50%
Actual allocation of plan assets	1.60%		2.20%
Pension Plans [Member] | Real Estate [Member]
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	2.50%
Actual allocation of plan assets	3.00%		2.20%
Pension Plans [Member] | Inflation-Indexed Securities [Member]
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	2.50%
Actual allocation of plan assets	1.40%		2.20%
Pension Plans [Member] | Debt Securities [Member]
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	50.00%
Actual allocation of plan assets	43.30%		41.10%
Pension Plans [Member] | Other
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	0.00%	[1]
Actual allocation of plan assets	4.80%	[1]	15.00%	[1]
Postretirement Plans [Member]
Targeted and actual plan assets by category [Abstract]
Investment policy targets asset allocation to debt securities	40.00%
Current investment policy targets an asset allocation to equity securities	60.00%
Postretirement Plans [Member] | Equity Markets [Member]
Targeted and actual plan assets by category [Abstract]
Actual allocation of plan assets	59.00%		59.00%
Postretirement Plans [Member] | Debt Securities [Member]
Targeted and actual plan assets by category [Abstract]
Actual allocation of plan assets	39.00%		39.00%
Postretirement Plans [Member] | Other
Targeted and actual plan assets by category [Abstract]
Targeted allocation of plan assets	0.00%
Actual allocation of plan assets	2.00%		2.00%

[1] Other investments in 2013 consist of cash equivalents. The relatively large cash position at September 30, 2012 was due to a transition taking place between investment managers and was invested in debt securities in a matter of days.

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 8 (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Projected benefit obligation	$ 503,818	$ 412,171
Accumulated benefit obligation	444,129	353,061
Fair value of plan assets, plans with benefit obligations in excess of plan assets	345,443	274,130
Fair value of plan assets, plans with accumulated benefit obligations in excess of plan assets	$ 345,443	$ 274,130