Edgar Filing: LACLEDE GAS CO

LGC-2013.09.30-10K

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



[ ]	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 1-1822

LACLEDE GAS COMPANY

(Exact name of registrant as specified in its charter)



Missouri (State of Incorporation)	43-0368139 (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) or 12(g) of the Act: None.

Indicate by check mark if the registrant:

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

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

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

As of November 21, 2013, there were 24,549 shares of the registrant’s common stock outstanding.

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

Document Incorporated by Reference: None



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PART I

Forward-Looking Statements		4

Item 1	Business	5
Item 1A	Risk Factors	8
Item 1B	Unresolved Staff Comments	15
Item 2	Properties	15
Item 3	Legal Proceedings	15

Executive Officers of the Registrant (Item 401(b) of Regulation S-K)		16

PART II

Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters	17
Item 6	Selected Financial Data	18
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	33
Item 8	Financial Statements and Supplementary Data	34
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	74
Item 9A	Controls and Procedures	74
Item 9B	Other Information	74

PART III

Item 10	Directors, Executive Officers and Corporate Governance	*
Item 11	Executive Compensation	*
Item 12	Security Ownership of Certain Beneficial Owners and Management
	and Related Stockholder Matters	*
Item 13	Certain Relationships and Related Transactions, and Director Independence	*
Item 14	Principal Accounting Fees and Services	75

PART IV

Item 15	Exhibits, Financial Statement Schedule	76

SIGNATURES		77

FINANCIAL STATEMENT SCHEDULE		78

INDEX TO EXHIBITS		79

* Laclede Gas Company meets all of the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and is filing this Form with reduced disclosure format.

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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 as well as other changes that impact supply for and access to our service area;
•	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

Laclede Gas Company (the Utility) is a wholly owned subsidiary of The Laclede Group, Inc. (Laclede Group). The Utility 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 Gas Utility segment 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. As of September 30, 2013 , the Utility had 2,311 employees, including 15 part-time employees. The Utility has no subsidiaries, but does have certain non-regulated activities, which are presented separately from its regulated utility operations.

Operating Revenues for the last three fiscal years are presented below. For more detailed financial information regarding the Utility’s segments, see Note 12 of the Notes to Financial Statements.



(Thousands)	2013		2012		2011
Utility	$	857,762	$	764,651	$	913,190
Other	1,603		2,976		19,138
Total Operating Revenues	$	859,365	$	767,627	$	932,328

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.LacledeGas.com, in the SEC Filings section under About Laclede Gas 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 Laclede’s 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.

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 Utility for delivery to its service area through the Enable Mississippi River Transmission LLC (MRT) system totaled 55.0 billion cubic feet (Bcf). Laclede Gas also holds firm transportation on several other interstate pipeline systems that provide access to gas supplies upstream of MRT. In addition to deliveries from Enable 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.

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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 26 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 service produces a margin similar to that which the Utility would have received under its regular sales rates.

*****

The Utility is subject to various environmental laws and regulations that, to date, have not materially affected the Utility’s financial position and results of operations. For a detailed discussion of environmental matters, see Note 13 of the Notes to Financial Statements.

*****

Laclede Gas' 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 have 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.

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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:



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
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
Utility Customers (End of Period)
(Thousands)	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.

*****

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.

OTHER

The Other category 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.

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Item 1A. Risk Factors

The Utility'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 Utility considers to be material.

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, beginning on page 26. 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 the Utility 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.

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 us 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 our 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 the the Utility 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.

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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.

The Utility's tariff rate schedules contain Purchased Gas Adjustment (PGA) Clauses that permit the Utility 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, the Utility is allowed to adjust the gas cost component of its 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.

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 to 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.

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

Standard & Poor’s rating group, 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. Credit ratings are an independent assessment of the Utility’s ability to pay its obligations. Consequently, real or anticipated changes in credit ratings will generally affect the market value of the specific debt instruments that are rated.

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

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

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. 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.

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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, rising 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.

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.

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

Over the last several years, the Utility has 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 Utility’s integrated planning, scheduling and dispatching of field resources, and 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 Utility’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.

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Although the Utility 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 Utility is subject to cyber-security risks primarily related to breaches of security pertaining to sensitive customer, employee, and vendor information maintained by the Utility 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 Utility’s reputation, diminish customer confidence, disrupt operations, and subject the Utility to possible financial liability, any of which could have a material affect on the Utility’s financial condition and results of operations. The Utility 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 Utility’s financial condition and results of operations.

Laclede Gas 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.

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 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.

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

The Utility is subject 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 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.

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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.

Among other risks, the increase in indebtedness may:


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


•	limit the Utility’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 cash flows from operations of 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 its ability to borrow additional funds or increase the interest rates applicable to its 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 Utility.

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, the Utility 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 increasing the Utility’s dividend payment obligations and might reduce the reported earnings per share.

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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 the Utility after the acquisitions are ultimately consummated.

The Utility 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.

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. 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.

The Utility 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.

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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, the Utility 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.”

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 13 of the Notes to Financial Statements.

Item 3. Legal Proceedings

For a description of environmental matters, see Note 13, Commitments and Contingencies, of the Notes to Financial Statements. For a description of pending regulatory matters of the Utility, see the Regulatory and Other Matters discussion in the Management’s Discussion and Analysis of Financial Condition and Results of Operations, on page 28.

The Utility is 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 financial position or results of operations reflected in the financial statements presented herein.

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EXECUTIVE OFFICERS OF THE REGISTRANT – Listed below are executive officers of the Utility. Their ages, at September 30, 2013, and positions held at the Utility are listed below along with their business experience during the past five years. Many of the executives currently serve as directors or officers of The Laclede Group or its affiliates.



Name, Age, and Position with the Utility		Appointed (1)

S. Sitherwood, Age 53

	Chairman of the Board and Chief Executive Officer	October 2012
	Chairman of the Board, President and Chief Executive Officer (2)	February 2012

S. L. Lindsey, Age 47

	President (3)	October 2012

S. P. Rasche, Age 53

	Chief Financial Officer	May 2012
	Vice President, Finance (4)	November 2009

M. C. Kullman, Age 53

	Senior Vice President, Assistant Corporate Secretary	October 2013
	Corporate Secretary	May 2012
	Chief Governance Officer and Corporate Secretary	February 2004


(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.

Mr. M. D. Waltermire, the Utility's previous Executive Vice President, retired October 1, 2013.

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Part II

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

The Utility common stock is owned by its parent, The Laclede Group, Inc., and is not traded on any stock exchange.

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



	Fiscal 2013		Fiscal 2012
1st Quarter	$	747.77	$	795.11
2nd Quarter	748.56		794.13
3rd Quarter	1,080.54		793.56
4th Quarter	592.87		793.62

The Utility mortgage contains several restrictions on its ability to pay cash dividends on its common stock, as described in further detail in Note 4, Stockholder’s Equity, of the Notes to Financial Statements.

Laclede Group periodically purchases common stock of the Utility with the price set at the book value of the Utility common stock as of the most recently completed fiscal quarter. The details on sales of common stock of the Utility to Laclede Group during the past three fiscal years are set forth below:



Date of Sale	Aggregate Purchase Price (millions)		Number of Shares
FY 2011
December 13, 2010	$	0.4	10
February 8, 2011	0.4		10
May 12, 2011	0.3		9
August 9, 2011	0.5		14

FY 2012
December 13, 2011	$	0.4	11
February 8, 2012	0.7		18
May 14, 2012	0.9		22
August 14, 2012	0.7		18
September 12, 2012	40.0		1,018

FY 2013
December 13, 2012	$	0.8	21
March 13, 2013	0.9		22
May 10, 2013	0.2		5
August 8, 2013	0.4		9
August 30, 2013	430.0		10,581
September 30, 2013	45.0		1,107

The proceeds from the Utility's sales of stock were used to reduce its short-term borrowings and, in the case of the sale of August 30, 2013, to provide funds for payment of a portion of the purchase price for MGE. Exemption from registration was claimed under Section 4(2) of the Securities Act of 1933.

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Item 6. Selected Financial Data

The Utility



	Fiscal Years Ended September 30
(Thousands)	2013			2012			2011			2010			2009
Income statement data
Operating Revenues:
Utility	$	857,762		$	764,651		$	913,190		$	864,297		$	1,053,993
Other	1,603			2,976			19,138			10,327			2,246
Total Operating Revenues	859,365			767,627			932,328			874,624			1,056,239
Operating Expenses:
Utility
Natural and propane gas	469,098			414,846			549,947			519,905			699,984
Other operation and maintenance expenses	180,703			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 Utility Operating Expenses	758,163			676,608			822,851			788,123			979,734
Other	13,658			209			7,985			4,343			2,238
Total Operating Expenses	771,821			676,817			830,836			792,466			981,972
Operating Income	87,544			90,810			101,492			82,158			74,267
Other Income and (Income Deductions) – Net	2,009			2,705			825			2,569			3,128
Interest Charges	26,137			25,156			25,544			26,852			30,353
Income Before Income Taxes	63,416			68,359			76,773			57,875			47,042
Income Tax Expense	14,651			18,460			22,996			18,150			13,859
Income Before Income Taxes and Dividends on Redeemable Preferred Stock	48,765			49,899			53,777			39,725			33,183
Dividends on Redeemable Preferred Stock	—			—			—			—			15
Net Income	$	48,765		$	49,899		$	53,777		$	39,725		$	33,168
Common stock data
Dividends Declared – Common Stock	$	46,976		$	37,345		$	36,297		$	35,195		$	34,108
Statements of financial position data
Net Utility Plant	1,776,630			1,019,299			928,683			884,084			855,929
Other Property and Investments	54,016			46,358			46,950			45,864			40,549
Total Assets	2,981,016			1,760,152			1,643,046			1,658,452			1,600,287
Current Liabilities	326,900			242,791			231,462			276,226			251,913
Deferred Credits and Other Liabilities	792,474			686,617			613,270			606,669			556,549
Long-Term Debt (less current portion)	887,712			339,416			364,357			364,298			389,240
Cash flow data
Net cash provided by operating activities	125,486			118,967			156,975			92,580			216,442
Net cash used in investing activities	(1,104,824		)	(103,127		)	(66,562		)	(59,769		)	(51,645		)
Net cash provided by (used in) financing activities	1,000,852			(14,361		)	(90,499		)	(33,204		)	(166,558		)
Consolidated Net Economic Earnings Data (a)
Net Income (GAAP)	$	48,765		$	49,899		$	53,777		$	39,725		$	33,183
Unrealized loss (gain) on energy-related derivative contracts, net of tax	100			(110		)	26			91			(105		)
Acquisition, divestiture and restructuring activities	8,344			—			—			—			—
Net Economic Earnings (Non-GAAP)	$	57,209		$	49,789		$	53,803		$	39,816		$	33,078


(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 22 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 Utility

INTRODUCTION

This section analyzes the financial condition and results of operations of the Utility. 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 Utility’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 Utility’s financial statements and the notes thereto.

RESULTS OF OPERATIONS

Overview

The Utility is a wholly owned subsidiary of The Laclede Group, Inc. (Laclede Group). The Utility is regulated by the Missouri Public Service Commission (MoPSC or Commission) 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.

Based on the nature of the business of the Utility, 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:


•	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; and,


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


•	the ability to integrate the operations of all acquisitions.

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 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 settlement of the Utility’s rate case in July 2013 retained the Utility’s weather mitigation rate design that better ensures the recovery of its fixed costs and margins despite variations in sales volumes due to the impacts of weather and other factors that affect customer usage.

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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%

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 28 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 cost of 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 30 for additional information.

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EARNINGS

2013 vs. 2012

The Utility's net income decreased by $1.1 million for the fiscal year ended September 30, 2013, compared with 2012. The decrease in net income was primarily due to (on a pre-tax basis) higher depreciation and amortization costs totaling $7.5 million and higher other operation and maintenance expenses totaling $13.4 million. These factors were partially offset by higher Gas Utility operating margin (a non-GAAP measure, as discussed below) of $34.1 million and a reduction in other interest charges totaling $0.9 million.

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:



(Millions)		Gas Utility		Other			Total
Year Ended September 30, 2013
	Operating Revenues	$	857.8	$	1.6		$	859.4
	Natural and propane gas expense	469.1		—			469.1
	Gross receipts tax expense	40.2		—			40.2
	Operating margin (non-GAAP)	348.5		1.6			350.1
	Remaining operating expenses	248.9		13.7			262.6
	Operating income (GAAP)	$	99.6	$	(12.1	)	$	87.5

Year Ended September 30, 2012
	Operating revenues	$	764.7	$	2.9		$	767.6
	Natural and propane gas expense	414.8		—			414.8
	Gross receipts tax expense	35.5		—			35.5
	Operating margin (non-GAAP)	314.4		2.9			317.3
	Remaining operating expenses	226.3		0.2			226.5
	Operating income (GAAP)	$	88.1	$	2.7		$	90.8

Year Ended September 30, 2011
	Operating revenues	$	913.2	$	19.1		$	932.3
	Natural and propane gas expense	549.9		—			549.9
	Gross receipts tax expense	42.9		—			42.9
	Operating margin (non-GAAP)	320.4		19.1			339.5
	Remaining operating expenses	230.1		8.0			238.1
	Operating income (GAAP)	$	90.3	$	11.1		$	101.4

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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

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 884.7 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.

Other

Other operating revenues and operating margin in fiscal year 2013 decreased $1.3 million from fiscal year 2012. Beginning July 2013, propane activities are now recorded within the regulated Gas Utility pursuant to the recent rate case filing. Other operating expenses increased $13.5 million primarily due to acquisition-related expenses for MGE.

Other Income and (Income Deductions) - Net

Other Income and (Income Deductions) - Net decreased by $0.7 million primarily due to lower net investment gains, increased charitable donations, and other minor variations.

Interest Charges

Interest charges during fiscal year 2013 increased $1.0 million from the same period last year primarily due to the issuance of long-term debt, partially offset by lower interest rates on long-term debt outstanding. The higher interest on long-term debt reflects the net effect of the March 2013, and August 2013 issuances of additional long-term debt of $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 $63.4 million and $122.0 million for fiscal years 2013 and 2012, respectively.

Income Taxes

Income tax expenses decreased $3.8 million in fiscal year 2013 from fiscal year 2012 primarily due to lower pre-tax income and various property-related deductions.

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2012 vs. 2011

Utility

The Utility's net income decreased by $3.9 million in fiscal year 2012 compared with fiscal year 2011. The decrease in net income was primarily due to (on a pre-tax basis) the effect of income from an April 2011 non-regulated sale of propane inventory totaling $10.0 million, lower system gas sales margins and other variations totaling $7.8 million, increases in pension and group insurance expenses totaling $5.5 million, and increases in charitable contributions totaling $1.9 million. These factors were partially offset by decreases in operation and maintenance expenses, excluding pension and group insurance expenses, totaling $11.1 million, higher Infrastructure System Replacement Surcharge (ISRS) revenues totaling $4.6 million, and higher net investment gains and other variations totaling $3.3 million.

Operating Revenues and Operating Expenses

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 314.5 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 - Remaining operating 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. 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.

Other

Other Operating Revenues and Operating Expenses

Other Operating Revenues decreased $16.2 million in fiscal year 2012 (compared to fiscal year 2011). Other Operating Expenses decreased $7.8 million 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.

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Other Income and (Income Deductions) - Net

Other Income and (Income Deductions) - Net increased $1.9 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 $0.4 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 $122.0 million and $99.2 million for fiscal years 2012 and 2011, respectively.

Income Taxes

Income tax expense decreased $4.5 million in fiscal year 2012 (from fiscal year 2011). This variation was primarily due to changes in pre-tax income.

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CRITICAL ACCOUNTING POLICIES

Our discussion and analysis of our financial condition, results of operations, liquidity, and capital resources is based upon our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP), which require 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 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.

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

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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 Financial Statements for information regarding the regulatory treatment of these costs.

Regulated Operations – 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:

PGA Clause

The Utility’s PGA Clause allows the Utility 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 provides 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.

Taxes

The Utility records deferred tax liabilities and assets measured by enacted tax rates for the net tax effect of all temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes, and the amounts used for income tax purposes. Changes in enacted tax rates, if any, and certain property basis differences will be reflected by entries to regulatory asset or regulatory liability accounts for regulated activities. Pursuant to the direction of the MoPSC, the Utility's provision for income tax expense reflects the regulatory method of excess asset depreciation followed for financial reporting purposes. The Utility's provision for income tax expense also records the income tax effect associated with the difference between overheads capitalized to construction for financial reporting purposes and those recognized for tax purposes without recording an offsetting deferred income tax expense. These two methods are consistent with the regulatory treatment prescribed by the MoPSC.

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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. Accordingly, these differences are deferred as regulatory liabilities.

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.

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

REGULATORY AND OTHER MATTERS

The MoPSC Staff previously proposed disallowances related to the Utility's recovery of its purchased gas costs totaling $6.0 million pertaining to the Utility's 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 the Utility alleging that the Utility's affiliate transactions and its Cost Allocation Manual (CAM) violated the MoPSC's affiliate transaction rules. The Utility responded with a counterclaim that the MoPSC Staff had failed to adhere to the affiliate transaction rules and the Utility's CAM. On July 16, 2013, the Utility, 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 the Utility's 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 the Utility alleging that, by stating that it was not in possession of proprietary LER documents, the Utility violated the MoPSC Order authorizing the holding company structure (2001 Order). The Utility counterclaimed stating the Staff failed to adhere to pricing provisions of the MoPSC's affiliate transaction rules and The Utility's 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 the Utility violated the terms of the 2001 Order and authorizing its General Counsel to seek penalties in court against the Utility. On May 19, 2011, the MoPSC's General Counsel filed a petition seeking penalties against the Utility for violation of the 2001 Order. The MoPSC and the Utility 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 the Utility's request to review the opinion of the Western District Court of Appeals. As a result, the Utility 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.

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On December 21, 2012, the Utility 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 Utility 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 the Utility 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.

On June 29, 2010, the Office of Federal Contract Compliance Programs (OFCCP) issued a Notice of Violations to the Utility alleging lapses in certain employment selection procedures during a two-year period ending in February 2006. On July 2, 2013, the Utility executed a Conciliation Agreement with the OFCCP in which the Utility 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 Utility's agreement to provide make whole relief will not have a material effect on the financial position and results of operations, or cash flows of the Utility.

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.

ACCOUNTING PRONOUNCEMENTS

The Utility has evaluated or is in the process of evaluating the impact that recently issued accounting standards will have on the Utility’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 Financial Statements.

The Utility 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 Utility’s financial condition and results of operations.

INFLATION

The accompanying financial statements reflect the historical costs of events and transactions, regardless of the purchasing power of the dollar at the time. Due to the capital-intensive nature of the business of the Company, the most significant impact of inflation is on the depreciation of utility plant. Rate regulation, to which the 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.

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FINANCIAL CONDITION

CASH FLOWS

The Utility'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 Utility’s cash provided by or used in operating activities.

Net cash provided by operating activities for fiscal years 2013, 2012 and 2011 was $125.5 million, $119.0 million and $157.0 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 this year.

Net cash used in investing activities for fiscal years 2013, 2012, and 2011 was $1,104.8 million, $103.1 million, and $66.6 million, respectively. The variations primarily reflect additional capital expenditures for distribution plant and information technology investments and the acquisition of MGE in 2013.

Net cash provided by (used in) financing activities for fiscal years 2013, 2012 and 2011 was $1,000.9 million, $(14.4) million, and $(90.5) million, respectively. The increase in net cash provided by financing activities in fiscal year 2013 from fiscal year 2012 primarily reflects the issuance of first mortgage bonds and the issuance of common stock to Laclede Group. The decrease in net cash used in financing activities in fiscal year 2012 from fiscal year 2011 primarily reflects a net decrease in the repayment of short-term borrowings in 2012 and the effect of the maturity of long-term debt in 2011.

LIQUIDITY AND CAPITAL RESOURCES

Short-term Debt

The Utility’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 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 51% of total capitalization on September 30, 2013.

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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. Information about the Utility’s 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	Borrowings from Laclede Group	Total Short-Term Borrowings
Twelve Months Ended September 30, 2013
Weighted average borrowings outstanding	$34.2 million	$29.2 million	$63.4 million
Weighted average interest rate	0.3%	0.3%	0.3%
Range of borrowings outstanding	$0 – $99.4 million	$0 – $91.7 million	$0 – $160.5 million
As of September 30, 2013
Borrowings outstanding at end of period	$74.0 million	$46.7 million	$120.7 million
Weighted average interest rate	0.3%	0.3%	0.3%
Twelve Months Ended September 30, 2012
Weighted average borrowings outstanding	$43.8 million	$78.2 million	$122.0 million
Weighted average interest rate	0.3%	0.3%	0.3%
Range of borrowings outstanding	$0 – $133.5 million	$13.0 - $107.5 million	$59.6 - $200.1 million
As of September 30, 2012
Borrowings outstanding at end of period	$40.1 million	$37.1 million	$77.2 million
Weighted average interest rate	0.2%	0.2%	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 the Utility’s pre-tax earnings and cash flows by approximately $0.6 million on an annual basis, portions of which may be offset through the application of PGA carrying costs.

Long-term Debt and Equity

On March 15, 2013, the Utility issued $100 million of first mortgage bonds in a private placement 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.

On August 13, 2013, the Utility 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.

On August 30, 2013, the Utility issued 10,581 shares of common stock to Laclede Group for $430 million, and on September 30, 2013, the Utility issued an additional 1,107 shares for $45 million, with the proceeds used to fund a portion of the MGE acquisition. Both the $450 million in bonds and the $475 million in equity were issued under financing authority from the MoPSC in the case giving authority to complete the acquisition of MGE.

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, the Utility filed a request with the MoPSC to extend this authority for an additional two years, to June 30, 2015. 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. For more information on these sales of stock, see Part II., Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities. As of November 26, 2013, $370.8 million remains available under this authorization.

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At September 30, 2013, the Utility had fixed-rate long-term debt totaling $890 million (including current maturities). 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 Utility 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 Utility’s $890 million in long-term debt, $50 million have no call option, $410 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.

Other

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

Utility 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. Utility capital expenditures are expected to be approximately $175 million in fiscal year 2014.

Capitalization at September 30, 2013, consisted of 52.3% common stock equity and 47.7% long-term debt compared to 59.1% common stock equity and 40.9% long-term debt at September 30, 2012.

The Utility's ratio of earnings to fixed charges was 3.3 for fiscal year 2013, 3.6 for fiscal year 2012, and 3.8 for fiscal year 2011.

It is management’s view that the Utility 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.

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CONTRACTUAL OBLIGATIONS

As of September 30, 2013, the Utility 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	$	890.0	$	—	$	—	$	100.0	$	790.0
Interest Payments on Long-Term Debt	687.7		39.7		79.3		79.3		489.4
Capital Leases (a)	0.2		0.1		0.1		—		—
Operating Leases (a)	11.4		5.9		4.9		0.6		—
Purchase Obligations – Natural Gas (b)	792.9		388.5		197.3		143.3		63.8
Purchase Obligations – Other (c)	76.0		25.6		19.1		18.4		12.9
Other Long-Term Liabilities	159.2		15.2		30.9		31.5		81.6
Total (d)	$	2,617.4	$	475.0	$	331.6	$	373.1	$	1,437.7


(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. These amounts reflect fixed obligations as well as obligations to purchase natural gas at future market prices, calculated using September 30, 2013 NYMEX futures prices. The Utility 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 $2.0 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 Utility expects to make contributions to its qualified, trusteed pension plans totaling $24.0 million in fiscal year 2014. The Utility anticipates a $0.4 million contribution relative to its non-qualified pension plans during fiscal year 2014. With regard to the postretirement benefits, the Utility anticipates it 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 Utility’s pension and postretirement benefit plans, refer to Note 3, Pension and Other Postretirement Benefits, of the Notes to Financial Statements.

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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. The Utility 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 9, Derivative Instruments and Hedging Activities, of the Notes to Financial Statements.

Interest Rate Risk

The Utility 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 $0.6 million on an annual basis. Portions of such increases may be offset through the application of PGA carrying costs. At September 30, 2013, the Utility had fixed-rate long-term debt totaling $890 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 Utility 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.

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 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 13, Commitments and Contingencies, of the Notes to Financial Statements.

OFF-BALANCE SHEET ARRANGEMENTS

The Utility has no off-balance sheet arrangements.

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 34 of this report.

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Item 8. Financial Statements and Supplementary Data
		2013 10-K Page

	Management Report on Internal Control Over Financial Reporting	35
	Reports of Independent Registered Public Accounting Firm	36

	Financial Statements:

	For Years Ended September 30, 2013, 2012, and 2011:
	Statements of Income	38
	Statements of Comprehensive Income	39
	Statements of Common Shareholder’s Equity	43
	Statements of Cash Flows	44
	As of September 30, 2013 and 2012:
	Balance Sheets	40
	Statements of Capitalization	42
	Notes to Financial Statements:
	Note 1 Summary of Significant Accounting Policies	45
	Note 2 MGE Acquisition	51
	Note 3 Pension Plans and Other Postretirement Benefits	53
	Note 4 Stockholder’s Equity	61
	Note 5 Long-Term Debt	62
	Note 6 Notes Payable and Credit Agreements	62
	Note 7 Fair Value of Financial Instruments	63
	Note 8 Fair Value Measurements	64
	Note 9 Derivative Instruments and Hedging Activities	64
	Note 10 Income Taxes	67
	Note 11 Other Income and (Income Deductions) – Net	68
	Note 12 Information By Operating Segment	68
	Note 13 Commitments and Contingencies	70
	Note 14 Interim Financial Information (Unaudited)	72

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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 53 percent and 38 percent of net and total assets, respectively, 3 percent of revenues, and 4 percent of net income, of the financial statement amounts as of and for the year ended September 30, 2013. Refer to Note 2, Acquisition of MGE in the Notes to 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.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Laclede Gas Company

St. Louis, Missouri

We have audited the internal control over financial reporting of Laclede Gas Company (a wholly owned subsidiary of The Laclede Group, Inc.) (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 53 percent and 38 percent of net and total assets, respectively, three percent of total revenues, and four 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 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 financial statements and financial statement schedule.

/s/ DELOITTE & TOUCHE LLP

St. Louis, Missouri

November 26, 2013

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Laclede Gas Company

St. Louis, Missouri

We have audited the accompanying balance sheets and statements of capitalization of Laclede Gas Company (a wholly owned subsidiary of The Laclede Group, Inc.) (the “Company”) as of September 30, 2013 and 2012, and the related statements of income, comprehensive income, common shareholder’s 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 financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the 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 financial statements present fairly, in all material respects, the financial position of Laclede Gas Company as of September 30, 2013 and 2012, and the results of its operations and its 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 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

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LACLEDE GAS COMPANY
STATEMENTS OF INCOME
(Thousands)
Years Ended September 30	2013		2012		2011
Operating Revenues:
Utility	$	857,762	$	764,651	$	913,190
Other	1,603		2,976		19,138
Total Operating Revenues	859,365		767,627		932,328
Operating Expenses:
Utility
Natural and propane gas	469,098		414,846		549,947
Other operation and maintenance expenses	180,703		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 Utility Operating Expenses	758,163		676,608		822,851
Other	13,658		209		7,985
Total Operating Expenses	771,821		676,817		830,836
Operating Income	87,544		90,810		101,492
Other Income and (Income Deductions) - Net	2,009		2,705		825
Interest Charges:
Interest on long-term debt	24,884		22,958		23,161
Other interest charges	1,253		2,198		2,383
Total Interest Charges	26,137		25,156		25,544
Income Before Income Taxes	63,416		68,359		76,773
Income Tax Expense	14,651		18,460		22,996
Net Income	$	48,765	$	49,899	$	53,777

See the accompanying Notes to Financial Statements.

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LACLEDE GAS COMPANY
STATEMENTS OF COMPREHENSIVE INCOME
(Thousands)
Years Ended September 30	2013			2012			2011
Net Income	$	48,765		$	49,899		$	53,777
Other Comprehensive Income (Loss) Before Tax:
Net gains (losses) on cash flow hedging derivative instruments:
Net hedging gains arising during the period	123			297			355
Reclassification adjustment for gains included in net income	(211		)	—			(466		)
Net unrealized gains (losses) on cash flow hedging derivative instruments	(88		)	297			(111		)
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 other postretirement benefit cost	195			3,706			426
Net defined benefit pension and other postretirement benefit plans	75			309			765
Other Comprehensive Income (Loss), Before Tax	(13		)	606			654
Income Tax Expense (Benefit) Related to Items of Other Comprehensive Income (Loss)	(8		)	234			252
Other Comprehensive Income (Loss), Net of Tax	(5		)	372			402
Comprehensive Income	$	48,760		$	50,271		$	54,179

See the accompanying Notes to Financial Statements.

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LACLEDE GAS COMPANY
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
Goodwill	247,078			—
Other Property and Investments	54,016			46,358
Current Assets:
Cash and cash equivalents	23,916			2,402
Accounts receivable:
Utility	101,118			64,027
Non-utility	967			1,244
Associated companies	1,111			4,315
Other	14,148			17,288
Allowance for doubtful accounts	(7,942		)	(7,601		)
Inventories:
Natural gas stored underground	164,740			89,852
Propane gas at FIFO cost	8,962			8,963
Materials and supplies at average cost	8,027			3,418
Unamortized purchased gas adjustments	17,533			40,674
Prepayments and other	11,255			9,011
Total Current Assets	343,835			233,593
Deferred Charges:
Regulatory assets	545,937			456,047
Other	13,520			4,855
Total Deferred Charges	559,457			460,902
Total Assets	$	2,981,016		$	1,760,152

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LACLEDE GAS COMPANY
BALANCE SHEETS (continued)
(Thousands)
September 30	2013		2012
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock equity	$	973,930	$	491,328
Long-term debt (less current portion)	887,712		339,416
Total Capitalization	1,861,642		830,744
Current Liabilities:
Notes payable	74,000		40,100
Notes payable – associated companies	46,729		37,125
Accounts payable	66,582		38,391
Accounts payable – associated companies	6,081		2,576
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	13,912		9,354
Customer deposits	15,062		8,565
Interest accrued	8,096		8,590
Taxes accrued	32,592		13,822
Deferred income taxes	1,692		10,146
Other	17,611		10,068
Total Current Liabilities	326,900		242,791
Deferred Credits and Other Liabilities:
Deferred income taxes	380,113		355,458
Unamortized investment tax credits	2,900		3,113
Pension and postretirement benefit costs	228,653		196,558
Asset retirement obligations	74,302		40,126
Regulatory liabilities	61,943		56,319
Other	44,563		35,043
Total Deferred Credits and Other Liabilities	792,474		686,617
Commitments and Contingencies (Note 13)
Total Capitalization and Liabilities	$	2,981,016	$	1,760,152

See the accompanying Notes to Financial Statements.

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LACLEDE GAS COMPANY
STATEMENTS OF CAPITALIZATION
(Thousands, Except for Shares and Per Share Amounts)
September 30	2013			2012
Common Stock Equity:
Common stock, par value $1 per share and Paid-in Capital:
Authorized – 2013 and 2012, 50,000,000 shares
Issued – 2013, 24,549 shares; and 2012, 12,804 shares	$	738,233		$	257,415
Retained earnings	237,803			236,014
Accumulated other comprehensive loss	(2,106		)	(2,101		)
Total Common Stock Equity	973,930			491,328
Long-Term Debt:
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	890,000			340,000
Unamortized discount, net of premium, on long-term debt	(2,288		)	(584		)
Total Long-Term Debt	887,712			339,416
Total Capitalization	$	1,861,642		$	830,744

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

See the accompanying Notes to Financial Statements.

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LACLEDE GAS COMPANY
STATEMENTS OF COMMON SHAREHOLDER’S EQUITY
	Common Stock Issued			Paid-in			Retained			Accum. Other Comp.
(Thousands, Except for Shares)	Shares	Amount		Capital			Earnings			Income (Loss)			Total
BALANCE OCTOBER 1, 2010	11,674	$	12	$	208,142		$	205,980		$	(2,875	)	$	411,259
Net income	—	—		—			53,777			—			53,777
Dividends declared:
Common stock	—	—		—			(36,297		)	—			(36,297		)
Stock-based compensation costs	—	—		2,946			—			—			2,946
Tax benefit – stock compensation	—	—		278			—			—			278
Other comprehensive loss, net of tax	—	—		—			—			402			402
Issuance of common stock to Laclede Group	43	—		1,592			—			—			1,592
BALANCE SEPTEMBER 30, 2011	11,717	12		212,958			223,460			(2,473		)	433,957
Net income	—	—		—			49,899			—			49,899
Dividends declared:
Common stock	—	—		—			(37,345		)	—			(37,345		)
Stock-based compensation costs	—	—		1,972			—			—			1,972
Tax benefit – stock compensation	—	—		(199		)	—			—			(199		)
Other comprehensive income, net of tax	—	—		—			—			372			372
Issuance of common stock to Laclede Group	1,087	1		42,671			—			—			42,672
BALANCE SEPTEMBER 30, 2012	12,804	13		257,402			236,014			(2,101		)	491,328
Net income	—	—		—			48,765			—			48,765
Dividends declared:
Common stock	—	—		—			(46,976		)	—			(46,976		)
Stock-based compensation costs	—	—		3,055			—			—			3,055
Tax benefit – stock compensation	—	—		549			—			—			549
Other comprehensive income, net of tax	—	—		—			—			(5		)	(5		)
Issuance of common stock to Laclede Group	11,745	12		477,202			—			—			477,214
BALANCE SEPTEMBER 30, 2013	24,549	$	25	$	738,208		$	237,803		$	(2,106	)	$	973,930

See the accompanying Notes to Financial Statements.

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LACLEDE GAS COMPANY
STATEMENTS OF CASH FLOWS
(Thousands)
Years Ended September 30	2013			2012			2011
Operating Activities:
Net Income	$	48,765		$	49,899		$	53,777
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, amortization, and accretion	48,299			40,784			39,234
Deferred income taxes and investment tax credits	22,174			31,573			23,015
Other – net	(411		)	(582		)	1,992
Changes in assets and liabilities:
Accounts receivable – net	6,654			(9,444		)	(1,517		)
Unamortized purchased gas adjustments	23,141			(14,955		)	(2,001		)
Deferred purchased gas costs	13,300			11,090			44,565
Accounts payable	16,410			(8,130		)	4,182
Advance customer billings – net	(8,248		)	9,916			(1,579		)
Taxes accrued	999			3,286			1,347
Natural gas stored underground	(16,209		)	25,318			(1,594		)
Other assets and liabilities	(29,388		)	(19,788		)	(4,446		)
Net cash provided by operating activities	125,486			118,967			156,975
Investing Activities:
Capital expenditures	(128,496		)	(106,734		)	(67,304		)
Other investments	(1,328		)	3,607			742
Acquisition of MGE, net	(975,000		)	—			—
Net cash used in investing activities	(1,104,824		)	(103,127		)	(66,562		)
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		)
Borrowings from Laclede Group	171,958			203,955			252,530
Repayment of borrowings from Laclede Group	(162,355		)	(219,709		)	(199,651		)
Changes in book overdrafts	(1,255		)	1,455			(545		)
Dividends paid	(42,420		)	(37,076		)	(36,018		)
Issuance of common stock to Laclede Group	477,225			42,672			1,592
Excess tax benefits from stock-based compensation	1,545			299			291
Other	(2,746		)	(57		)	(48		)
Net cash provided by (used in) financing activities	1,000,852			(14,361		)	(90,499		)
Net Increase (Decrease) in Cash and Cash Equivalents	21,514			1,479			(86		)
Cash and Cash Equivalents at Beginning of Year	2,402			923			1,009
Cash and Cash Equivalents at End of Year	$	23,916		$	2,402		$	923
Supplemental Disclosure of Cash Paid (Refunded) During the Year for:
Interest	$	25,743		$	24,768		$	25,460
Income taxes	(7,573		)	(6,588		)	(846		)

See the accompanying Notes to Financial Statements.

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LACLEDE GAS COMPANY

NOTES TO FINANCIAL STATEMENTS


1.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

BASIS OF PRESENTATION - In compliance with generally accepted accounting principles (GAAP), transactions between the Utility and its affiliates as well as intercompany balances on the Utility's Balance Sheets have not been eliminated from the Utility financial statements. Transactions with associated companies include sales of natural gas from the Utility to Laclede Energy Resources, Inc. (LER), sales of natural gas from LER to the Utility, and transportation services provided by Laclede Pipeline Company to the Utility. For fiscal years 2013, 2012, and 2011, sales of natural gas from the Utility to LER were $10.5 million, $1.2 million, and $1.6 million, respectively. Sales of natural gas from LER to the Utility during fiscal years 2013, 2012, and 2011 were $24.2 million, $16.5 million, and $24.3 million, respectively. Other services provided by Laclede Group's other subsidiaries to the Utility during fiscal years 2013, 2012, and 2011 were $1.6 million, $1.0 million, $1.0 million, respectively.

The Utility provides administrative and general support to affiliates. All such costs, which are not material, are billed to the appropriate affiliates. Also, Laclede Group may charge or reimburse the Utility for certain tax-related amounts. Unpaid balances relating to these activities are reflected in the Utility Balance Sheets as Accounts receivable-Associated companies or as Accounts payable-associated companies. Additionally, the Utility may borrow funds from Laclede Group. Unpaid balances relating to this arrangement, if any, are reflected in Notes payable-associated companies. The Utility had outstanding borrowings from Laclede Group under a revolving credit note of $46.7 million and $37.1 million, at September 30, 2013 and 2012, respectively. The interest rate on these borrowings was 0.3% and 0.2% at September 30, 2013 and 2012, respectively. Advances under this note are due and payable on demand.

NATURE OF OPERATIONS - The Utility 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. As an adjunct to its gas distribution business, the Utility operates an underground natural gas storage field. The non-regulated activities of the Utility are described in Note 12, 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 the Utility 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 Cash Flows.

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ASSET RETIREMENT OBLIGATIONS - The Utility 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 Utility 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. 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 of September 1, 2013. This estimate 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 Balance Sheets:



(Thousands)	2013			2012
Asset retirement obligations, beginning of year	$	40,126		$	27,486
Liabilities incurred during the period	801			619
Liabilities settled during the period	(1,089		)	(601		)
Accretion	2,312			1,636
Revisions in estimated cash flows	—			10,986
MGE's asset retirement obligation	32,152			—
Asset retirement obligations, end of year	$	74,302		$	40,126

REGULATED OPERATIONS - 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).

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The following regulatory assets and regulatory liabilities were reflected in the Balance Sheets as of September 30:



(Thousands)	2013		2012
Regulatory Assets:
Future income taxes due from customers	$	112,902	$	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
Cold weather rule	—		—
Other	25,387		6,382
Total Regulatory Assets	$	563,470	$	496,721
Regulatory Liabilities:
Unamortized investment tax credits	$	2,900	$	3,113
Accrued cost of removal	59,066		55,103
Other	2,877		1,216
Total Regulatory Liabilities	$	64,843	$	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 Commission. 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 - 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 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.

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, Acquisition of MGE.

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. which has been assigned to the Utility within the company’s Gas Utility segment.

REVENUE RECOGNITION - The Utility reads meters and bills its customers on monthly cycles. The Utility records its utility operating 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.

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PURCHASED GAS ADJUSTMENTS AND DEFERRED ACCOUNT – As authorized by the MoPSC, the PGA Clause allows the Utility 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 Utility Operating Revenues on the Statements of 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 Utility’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 (the Utility 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 28 of this report for additional information on Laclede Gas' off-system sales.

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INCOME TAXES - The Utility has 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. The Utility records 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.

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.

Laclede Group files a consolidated federal income tax return and allocates income taxes to the Utility and its other subsidiaries as if each entity were a separate taxpayer.

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 Utility’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 Balance Sheets. Changes in book overdrafts between periods are reflected as Financing Activities in the Statements of Cash Flows.

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 Income. Amounts recorded in 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 Utility sales are billed to customers. These amounts are not recorded in the Statements of Income, but are recorded as tax collections payable and included in the Other line of the Current Liabilities section of the Balance Sheets.

ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS – Trade accounts receivable are recorded at the amounts due from customers, including unbilled amounts. Estimates of the 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 Utility 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.

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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 7, Fair Value of Financial Instruments, and Note 8, Fair Value Measurements.

STOCK-BASED COMPENSATION - Officers and employees of the Utility, as determined by the Compensation Committee of Laclede Group’s Board of Directors, are eligible to be selected for awards under the Laclede Group 2006 Equity Incentive Plan (2006 Plan). Grants of awards may be earned by achieving performance objectives and/or other criteria as determined by the Compensation Committee. Awards may include 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.

For Laclede Group’s non-employee directors, shares were awarded under the Restricted Stock Plan for Non-Employee Directors (Plan) prior to February 1, 2012, but any future awards will be granted under the 2006 Plan, as a result of plan amendments approved by Laclede Group’s shareholders. Awards previously granted under the Plan vest depending upon the participant’s age upon entering the plan and years of service as a director. Shares of the Utility common stock, which are 100% owned by Laclede Group, are not transacted under the plans.

Laclede Group accounts for awards under these plans in accordance with GAAP, and allocates applicable compensation costs to its subsidiaries. For awards made to its employees, the Utility records its allocation of compensation cost from Laclede Group with a corresponding increase to additional paid-in capital.

The amounts of compensation cost allocated to the Utility for share-based compensation arrangements are presented below:



(Thousands)	2013			2012			2011

Total equity compensation cost	$	3,843		$	2,303		$	3,383
Compensation cost capitalized	(1,366		)	(808		)	(924		)
Compensation cost recognized in net income	2,477			1,495			2,459
Income tax benefit recognized in net income	(948		)	(577		)	(948		)
Compensation cost recognized in net income, net of income tax	$	1,529		$	918		$	1,511

As of September 30, 2013, there was $4.2 million in unrecognized compensation cost related to nonvested share-based compensation arrangements that is expected to be allocated to the Utility over a weighted average period of 2.0 years.

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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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 Utility within the Company’s Gas Utility segment.

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.

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)	September 1, 2013 - September 30, 2013
Total net revenues	$	21,985
Net Income	1,795

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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

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.

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	Twelve Months Ended September 30,
(Thousands)	2013		2012
Total net revenues	$	1,518,201	$	1,581,425
Net Income	83,642		81,722


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 substantially all 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.

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.

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

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(Thousands)
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:



	2014		2013		2012
	Target		Actual		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.

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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 the 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. 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

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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 the Utility’s 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 Income and Statements of 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 at 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 at 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 at end of year	$	111,645		$	67,442
Funded status of plans, end of year	$	(68,477	)	$	(59,775	)

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The following table sets forth the amounts recognized in the 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 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%.

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The assumed medical cost trend rates at September 30 for the Utility's postretirement plans 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:



	2014 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 2013 are anticipated to be $19.2 million to the qualified trusts, and $0.3 million paid directly to participants from the Utility 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 receivable 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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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.	STOCKHOLDER’S EQUITY

Total shares of common stock outstanding were 24,549 and 12,804 at September 30, 2013 and 2012, respectively. Common stock and paid-in capital increased $480.8 million and $44.4 million in 2013 and 2012, respectively. These increases were primarily due to the issuance of common stock to Laclede Group and stock-based compensation costs allocated to the Utility from Laclede Group in both periods.

The Utility periodically sold shares of its stock to Laclede Group at prices per share equal to book value on the last day of the quarter preceding each sale. The Utility sold 11,745 shares to Laclede Group for $476.5 million during fiscal 2013 and 1,087 shares to Laclede Group for $42.7 million during fiscal 2012. During fiscal 2013, $475 million of the stock sale proceeds were used to fund a portion of the MGE acquisition. The proceeds from other sales were used to reduce short-term borrowings. Exemption from registration for all of the sales was claimed under Section 4(2) of the Securities Act of 1933.

Substantially all of the utility plant of the Utility 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.

The components of accumulated other comprehensive income (loss), net of income taxes, recognized in the 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, September 30, 2011	$	(53	)	$	(2,420	)	$	(2,473	)
Current-period change	182			190			372
Balance, September 30, 2012	129			(2,230		)	(2,101		)
Current-period change	(53		)	48			(5		)
Balance, September 30, 2013	$	76		$	(2,182	)	$	(2,106	)

Income tax expense (benefit) recorded for items of other comprehensive income reported in the Statements of 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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5. 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. 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 Utility had fixed-rate long-term debt, including the current portion, totaling $890 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 Utility’s $890 million in long-term debt, $50 million have no call options, $410 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 the Utility filed with the SEC a joint shelf registration statement on Form S-3 for issuance of first mortgage bonds, unsecured debt, and preferred stock, which expires August 5, 2016. Bonds totaling $450 million were issued by the Utility from this registration statement on August 13, 2013. The amount, timing, and type of additional financing to be issued under this shelf registration 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 4, 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 13, Commitments and Contingencies.


6.	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 51% of total capitalization.

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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 the fiscal year. Information about the Utility’s internal and external short-term borrowings during the 12 months ended September 30, and as of September 30, is presented below for 2013 and 2012:



	Commercial Paper Borrowings	Borrowings from Laclede Group	Total Short-Term Borrowings

Twelve Months Ended September 30, 2013
Weighted average borrowings outstanding	$34.2 million	$29.2 million	$63.4 million
Weighted average interest rate	0.3%	0.3%	0.3%
Range of borrowings outstanding	$0 – $99.4 million	$0 – $91.7 million	$0 – $160.5 million

As of September 30, 2013
Borrowings outstanding at end of period	$74.0 million	$46.7 million	$120.7 million
Weighted average interest rate	0.3%	0.3%	0.3%

Twelve Months Ended September 30, 2012
Weighted average borrowings outstanding	$43.8 million	$78.2 million	$122.0 million
Weighted average interest rate	0.3%	0.3%	0.3%
Range of borrowings outstanding	$0 – $133.5 million	$13.0 - $107.5 million	$59.6 - $200.1 million

As of September 30, 2012
Borrowings outstanding at end of period	$40.1 million	$37.1 million	$77.2 million
Weighted average interest rate	0.2%	0.2%	0.2%


7.	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 (a)
(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	$	23,916	$	23,916	$	23,892	$	24	$	—
Short-term debt	120,729		120,729		—		120,729		—
Long-term debt, including current portion	887,712		930,369		—		930,369		—

As of September 30, 2012
Cash and cash equivalents	$	2,402	$	2,402	$	2,378	$	24	$	—
Short-term debt	77,225		77,225		—		77,225		—
Long-term debt	364,416		452,768		—		452,768		—

(a) The Utility adopted the provisions of ASU 2011-04 (ASC Topic 820) in the second quarter of fiscal year 2012 on a prospective basis. Accordingly, disclosures for prior periods are not required to be presented.

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 8, Fair Value Measurements, for information on financial instruments measured at fair value on a recurring basis.

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8.	FAIR VALUE MEASUREMENTS

The following table categorizes the assets and liabilities in the 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 natural gas contracts	1,466		—		—		(1,466		)	—
OTCBB natural gas contracts	—		232		—		(232		)	—
NYMEX gasoline and heating oil contracts	105		—		—		(105		)	—
Total	$	16,071	$	232	$	—	$	(1,803	)	$	14,500
Liabilities
NYMEX natural gas contracts	$	3,455	$	—	$	—	$	(3,455	)	$	—
OTCBB natural gas contracts	$	—	$	5,443	$	—	$	(232	)	$	5,211

As of September 30, 2012
U. S. Stock/Bond Mutual Funds	$	13,187	$	—	$	—	$	—		$	13,187
NYMEX natural gas contracts	7,338		—		—		(7,338		)	—
NYMEX gasoline and heating oil contracts	344		—		—		(344		)	—
Total	$	20,869	$	—	$	—	$	(7,682	)	$	13,187
Liabilities
NYMEX natural gas contracts	$	9,563	$	—	$	—	$	(9,563	)	$	—

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 New York Mercantile Exchange (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. The Utility’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 mutual funds are included in the Other Property and Investments line of the Balance Sheets. Derivative assets and liabilities, including receivables and payables associated with cash margin requirements, are presented net in the Balance Sheets when a legally enforceable netting agreement exists between the Utility and the counterparty to a derivative contract. For additional information on derivative instruments, see Note 9, Derivative Instruments and Hedging Activities.


9.	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 Income.

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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, the Utility 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, “Derivatives and Hedging.” The gains or losses on these derivative instruments are not subject to the Utility’s PGA Clause.

Derivative instruments designated as cash flow hedges of forecasted transactions are recognized on the 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 $0.1 million in pre-tax gains will be reclassified into the Statements of 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 Cash Flows.

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



	MMBtu (millions)	Avg. Price Per MMBtu
NYMEX open long futures positions
Fiscal 2014	7.26	$	3.99
Fiscal 2015	0.94	3.84
OTCBB open long futures positions
Fiscal 2014	16.81	3.97
Fiscal 2015	7.58	4.22

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



The Effect of Derivative Instruments on the Statements of Income and Statements of Comprehensive Income
	Location of Gain (Loss)
(Thousands)	Recorded in Income	2013			2012		2011
Derivatives in Cash Flow Hedging Relationships
NYMEX gasoline and heating oil contracts:
Effective portion of gain recognized in OCI on derivatives		$	123		$	297	$	355
Effective portion of gain reclassified from AOCI to income	Utility – Other Operation Expenses	211			—		466
Ineffective portion of gain (loss) on derivatives recognized in income	Utility – Other Operation Expenses	(127		)	175		12
Derivatives Not Designated as Hedging Instruments *
NYMEX gasoline and heating oil contracts:
Gain (loss) recognized in income on derivative	Other Income and (Income Deductions) - Net	$	41		$	19	$	37

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 Income. Such amounts are recognized in the Statements of Income as a component of Utility 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 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 gasoline and heating oil contracts	Accounts Receivable - Other	$	105	Accounts Receivable - Other	$	—
Derivatives not designated as hedging instruments
NYMEX natural gas contracts	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		Current Liabilities - Other	4,045
	Other Deferred Credits	4		Deferred Credits - Other	1,398
Sub-total		1,698			8,898
Total derivatives		$	1,803		$	8,898
Fair Value of Derivative Instruments in the 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 gasoline and heating oil contracts	Accounts Receivable - Other	$	334	Accounts Receivable - Other	$	—
Derivatives not designated as hedging instruments
NYMEX natural gas contracts	Accounts Receivable - Other	7,338		Accounts Receivable - Other	9,563
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	10		Accounts Receivable - Other	—
Sub-total		7,348			9,563
Total derivatives		$	7,682		$	9,563

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 Balance Sheets. As such, the gross balances presented in the table above are not indicative of the Utility’s net economic exposure. Refer to Note 8, 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 Balance Sheets:



(Thousands)	2013			2012
Fair value of asset derivatives presented above	1,803			7,682
Fair value of cash margin receivables offset with derivatives	1,890			1,964
Netting of assets and liabilities with the same counterparty	(3,693		)	(9,646		)
Total	$	—		$	—
Derivative Instrument Assets, per Balance Sheets:
Derivative instrument assets	—			—
Other deferred charges	—			—
Total	$	—		$	—
Fair value of liability derivatives presented above	8,898			9,563
Fair Value of cash margin payables offset with derivatives	6			83
Netting of assets and liabilities with the same counterparty	(3,693		)	(9,646		)
Derivative instrument liabilities, per Balance Sheets*	$	5,211		$	—
Derivative Instrument Assets, per Balance Sheets:
Other current liabilities	3,817			—
Other deferred credits	1,394			—
Total	$	5,211		$	—

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Additionally, at September 30, 2013 and September 30, 2012, the Utility had $2.9 million and $8.0 million, respectively, in cash margin receivables not offset with derivatives, that are presented in Accounts Receivable – Other. There was no such amount at September 30, 2011.

10. 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 Income:
Federal
Current	$	(6,539	)	$	(11,288	)	$	133
Deferred	20,103			27,186			19,848
Investment tax credits	(213		)	(213		)	(213		)
State and local
Current	(984		)	(1,825		)	(152		)
Deferred	2,284			4,600			3,380
Total Income Tax Expense	$	14,651		$	18,460		$	22,996

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	3.3		2.6		2.7
Certain expenses capitalized on books and
deducted on tax return	(10.8	)	(8.9	)	(6.1	)
Taxes related to prior years	(1.6	)	(0.6	)	(0.8	)
Other items – net	(2.8	)	(1.1	)	(0.8	)
Effective income tax rate	23.1	%	27.0	%	30.0	%

The significant items comprising the net deferred tax liability recognized in the 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*	10,450			14,513
Total deferred tax assets	97,549			106,348
Deferred tax liabilities:
Relating to utility property	341,975			303,332
Regulatory pension and other postretirement benefits	124,871			121,554
Deferred gas costs	7,112			20,652
Other	5,396			26,414
Total deferred tax liabilities	479,354			471,952
Net deferred tax liability	381,805			365,604
Net deferred tax liability – current*	(1,692		)	(10,146		)
Net deferred tax liability – non-current*	$	380,113		$	355,458

* The Utility periodically invests in tax credits. As of September 30, 2013, $6.6 million of state tax credits are included in Other and Net deferred tax liability. $4.3 million of state tax credits were classified as current. $2.3 million of state tax credits were classified as non-current.

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Laclede Group files a consolidated federal and state income tax return and allocates income taxes to the Utility and its other subsidiaries as if each entity were a separate taxpayer. Pursuant to GAAP, the Utility 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 Utility 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 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 Balance Sheets:



(Thousands)	2013			2012
Unrecognized tax benefits, beginning of year	$	5,615		$	5,536
Increases related to tax positions taken in current year	1,420			490
Reductions due to lapse of applicable statute of limitations	(5,018		)	(411		)
Unrecognized tax benefits, end of year	$	2,017		$	5,615

The amount of unrecognized tax benefits, which, if recognized, would affect the Utility’s effective tax rate were $1.5 million and $1.2 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 Utility’s unrecognized tax benefits. The Utility does not expect that any such change will be significant to the Utility's Balance Sheets.

Interest accrued associated with the Utility’s uncertain tax positions as of September 30, 2013 and 2012 were $0.1 million and $0.5 million, respectively, and no penalties were accrued as of those dates. 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 Utility reversed $0.6 million of accrued interest expense in the Statements of Income.

Laclede Group and/or the Utility are subject to U.S. federal income tax as well as income tax of state and local jurisdictions. These companies are 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.


11.	OTHER INCOME AND (INCOME DEDUCTIONS) – NET



(Thousands)	2013			2012			2011
Interest income	$	947		$	1,230		$	1,057
Net investment gain (loss)	2,544			2,626			(73		)
Other income	377			804			53
Other income deductions	(1,859		)	(1,955		)	(212		)
Other Income and (Income Deductions) – Net	$	2,009		$	2,705		$	825


12.	INFORMATION BY OPERATING SEGMENT

The Gas Utility segment consists of the regulated operations of the Utility. 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.

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The Other segment includes the Utility's non-regulated business activities, which are comprised of its non-regulated propane sales transactions and its propane storage and related services. Accounting policies are described in Note 1. There are no material intersegment revenues.

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 will also exclude, if applicable, the after-tax impact of costs related to acquisition, divestiture, and restructuring activities.



						Adjustments &
(Thousands)	Gas Utility		Other			Eliminations		Total
FISCAL 2013
Operating revenues	$	857,762	$	1,603		$	—	$	859,365
Depreciation and amortization	48,283		—			—		48,283
Interest income	947		—			—		947
Interest charges	26,137		—			—		26,137
Income tax expense	19,243		(4,592		)	—		14,651
Net economic earnings	56,635		574			—		57,209
Total assets	2,981,016		—			—		2,981,016
Capital expenditures	128,496		—			—		128,496

FISCAL 2012
Operating revenues	$	764,651	$	2,976		$	—	$	767,627
Depreciation and amortization	40,739		—			—		40,739
Interest income	1,230		—			—		1,230
Interest charges	25,156		—			—		25,156
Income tax expense	17,393		1,067			—		18,460
Net economic earnings	48,089		1,700			—		49,789
Total assets	1,758,952		1,200			—		1,760,152
Capital expenditures	106,734		—			—		106,734

FISCAL 2011
Operating revenues	$	913,190	$	19,138		$	—	$	932,328
Depreciation and amortization	39,214		—			—		39,214
Interest income	1,057		—			—		1,057
Interest charges	25,544		—			—		25,544
Income tax expense	18,694		4,302			—		22,996
Net economic earnings	46,952		6,851		*	—		53,803
Total assets	1,641,386		1,660			—		1,643,046
Capital expenditures	67,304		—			—		67,304


*	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. These transactions resulted in after-tax earnings totaling $6.1 million.



Reconciliation of Net Income to Net Economic Earnings
(Thousands)	2013		2012			2011
Net Income (GAAP)	$	48,765	$	49,899		$	53,777
Unrealized loss (gain) on energy-related derivative contracts, net of tax	100		(110		)	26
Acquisition, divestiture and restructuring activities	8,344		—			—
Net Economic Earnings (Non-GAAP)	$	57,209	$	49,789		$	53,803

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13. 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 Utility was contractually committed to costs of approximately $1.5 million related to this project, with additional expenditures to be incurred throughout the project’s life.

The Utility has 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 $793 million. The Utility recovers its costs from customers in accordance with the PGA Clause.

Laclede Pipeline Company (Pipeline), a wholly owned subsidiary of Laclede Group, is providing liquid propane transportation service to the Utility pursuant to an approved FERC tariff and a contractual arrangement between Pipeline and the Utility. In accordance with the terms of that agreement, the Utility is obligated to pay Pipeline approximately $1.0 million annually, at current rates. The agreement renews at the end of each contract year, unless terminated by either party upon provision of at least six months’ notice.

Leases

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, $0.4 million in fiscal year 2017, and $0.1 million in fiscal year 2018. The Utility has other relatively minor rental arrangements that provide for minimum rental payments.

Contingencies

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 former manufactured gas plant sites in the BVCP.

With regard to the former MGP site located in Shrewsbury, Missouri, the Utility 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, the Utility 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.

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In conjunction with this redevelopment effort, the Utility 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 the Utility 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 the Utility 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 the Utility did not materially impact its financial condition, results of operations, or cash flows.

The Utility 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 the Utility that the Missouri Department of Natural Resources had completed an investigation of the site. The Attorney General requested that the Utility participate in the follow up investigations of the site. In a letter dated January 10, 2012, the Utility 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.

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.

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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 purchase 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 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 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 9, Derivative Instruments and Hedging Activities, the Utility enters into NYMEX exchange-traded 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 the Utility 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, the Utility had $0.2 million on deposit with MF Global that remains unavailable to the Utility 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.

The Utility 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 financial position, results of operations, or cash flows of the Utility.

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14.	INTERIM FINANCIAL INFORMATION (UNAUDITED)

In the opinion of the Utility, 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 operations reported on a quarterly basis primarily reflect the seasonal nature of the business of the Utility.



(Thousands)
Three Months Ended	Dec. 31		March 31		June 30		Sept. 30

Fiscal Year 2013
Total Operating Revenues	$	251,934	$	364,145	$	131,757	$	111,529
Operating Income (Loss)	42,052		50,691		7,154		(12,353		)
Net Income (Loss)	25,743		29,775		3,765		(10,518		)

Three Months Ended	Dec. 31		March 31		June 30		Sept. 30
Fiscal Year 2012
Total Operating Revenues	$	251,983	$	298,897	$	117,771	$	98,976
Operating Income (Loss)	37,522		44,553		9,708		(973		)
Net Income (Loss)	21,697		25,925		4,630		(2,353		)

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 36 through 38.

Item 9B. Other Information

None.

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Part III

Item 14. Principal Accounting Fees and Services

The following table displays the aggregate fees for professional audit services for the audit of the financial statements of The Laclede Group, Inc. and the Utility for the fiscal years ended September 30, 2012 and 2011 and fees billed for other services during those periods by the Company’s independent registered public accounting firm, Deloitte & Touche LLP. Approximately 82% of the fees listed below were allocated to the Utility in both fiscal years 2013 and 2012, respectively.



	2013		2012
Audit fees	$	1,163,000	$	650,000
Audit related fees (1)	943,372		27,000
Tax fees (2)	27,200		26,800
All other fees (3)	2,200		2,200
Total	$	2,135,772	$	706,000


(1)	Audit related fees consisted of comfort letters, consents for registration statements and work paper reviews.


(2)	Tax fees consisted primarily of assistance with tax planning, compliance and reporting.


(3)	All other fees consisted of an annual subscription for the accounting technical library.

The Laclede Group, Inc.’s Audit Committee (Committee) pre-approved all of the fees disclosed for fiscal years 2013 and 2012. Consistent with Securities and Exchange Commission requirements regarding accountant independence, Laclede Group’s Audit Committee recognizes the importance of maintaining the independence, in fact and appearance, of our independent registered public accountant. To this end, the Audit Committee adopted a policy to pre-approve all audit and permissible non-audit services provided by the independent accountant. Under the policy, the Committee or its designated member must pre-approve services prior to commencement of the specified service, provided that all fees relative to compliance with Section 404 of the Sarbanes-Oxley Act may only be pre-approved by the Committee. Any pre-approvals by the designated member between meetings will be reported to the Audit Committee at its next meeting. The requests for pre-approval are submitted to the Audit Committee or its designated member, as applicable, by both the independent accountant and Laclede Group’s Chief Financial Officer with a joint statement as to whether in their view the request is consistent with the Securities and Exchange Commission’s rules on accountant independence. At each Committee meeting, the Audit Committee reviews a report summarizing the services, including fees, provided by the independent accountant, a listing of pre-approved services provided since its last meeting, and a current projection of the estimated annual fees to be paid to the independent accountant.

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Part IV



Item 15. Exhibits, Financial Statement Schedule
			2012 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	78

		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

		Incorporated herein by reference to Index to Exhibits, page 80.

Item 15(a)(3) See the marked exhibits in the Index to Exhibits, page 80.

(b) Incorporated herein by reference to Index to Exhibits, page 80.

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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.



			LACLEDE GAS COMPANY

Dated:	November 26, 2013	By /s/	Steven P. Rasche
			Steven P. Rasche
			Chief Financial Officer

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



Date	Signature		Title

November 26, 2013	/s/	Suzanne Sitherwood	Chairman of the Board and
		Suzanne Sitherwood	Chief Executive Officer
			(Principal Executive Officer)

November 26, 2013	/s/	Steven P. Rasche	Director and Chief Financial Officer
		Steven P. Rasche	(Principal Financial and Accounting Officer)

November 26, 2013	/s/	Steven L. Lindsey	Director and President
		Steven L. Lindsey

November 26, 2013	/s/	Mary C. Kullman	Director and Senior Vice President and
		Mary C. Kullman	Assistant Corporate Secretary

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SCHEDULE II

LACLEDE GAS COMPANY

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	$	7,601	$	5,584		$	8,234	(b)	$	13,477	(c)	$	7,942
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	$	9,969	$	6,011		$	10,145	(b)	$	18,524	(c)	$	7,601
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	$	10,176	$	7,257		$	11,340	(b)	$	18,804	(c)	$	9,969
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.
3.01(i)*	-	Laclede’s Restated Articles of Incorporation as amended March 8, 2013; filed as Exhibit 3.1 to Form 10-Q/A for the quarter ended March 31, 2013.
3.01(ii)*	-	Bylaws of Laclede effective January 18, 2002; filed as Exhibit 3.4 to Laclede’s Form 8-K filed May 29, 2002.
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 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 Exhibit 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 August 2, 2013 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 August 2, 2013 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*	-	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.
10.07a*	-	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.
10.08*	-	Form of Indemnification Agreement between Laclede and its Directors and Officers; filed as Exhibit 10.13 to the Company’s 1990 10-K.
10.09*	-	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.

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INDEX TO EXHIBITS

Exhibit
No.
10.09a*	-	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.
10.10*	-	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.
10.11*	-	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.
10.12	-	Loan agreement with Laclede Gas Company 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.
10.13*	-	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.
10.13a*	-	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.
10.13b*	-	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.
10.14*	-	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.
10.15*	-	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.
10.15a*	-	The Laclede Group, Inc. Annual Incentive Plan; filed as Appendix 1 to the Company’s proxy statement filed December 17, 2010.
10.15b*	-	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.
10.16*	-	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.
10.16a*	-	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.
10.16b*	-	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.
10.16c*	-	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.
10.17*	-	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.
10.17a*	-	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.
10.19*	-	Laclede Gas Company Cash Balance Supplemental Retirement Benefit Plan, effective as of January 1, 2009; filed as Exhibit 10.19 to the Company's Form 10-K for the fiscal year ended September 30, 2012.
10.20*	-	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.
10.21*	-	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.
10.22*	-	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.

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INDEX TO EXHIBITS

Exhibit
No.
10.23*	-	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.
12	-	Ratio of Earnings to Fixed Charges.
23	-	Consent of Independent Registered Public Accounting Firm.
31	-	Certificates under Rule 13a-14(a) of the CEO and CFO of Laclede Gas Company.
32	-	Section 1350 Certifications under Rule 13a-14(b) of the CEO and CFO of Laclede Gas Company.

*Incorporated herein by reference and made a part hereof. Laclede’s File No. 1-1822.

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



INDEX TO EXHIBITS

Exhibit
No.

101.INS	-	XBRL Instance Document. (1)
101.SCH	-	XBRL Taxonomy Extension Schema. (1)
101.CAL	-	XBRL Taxonomy Extension Calculation Linkbase. (1)
101.DEF	-	XBRL Taxonomy Definition Linkbase. (1)
101.LAB	-	XBRL Taxonomy Extension Labels Linkbase. (1)
101.PRE	-	XBRL Taxonomy Extension Presentation Linkbase. (1)


(1)	Furnished, not filed

Attached as Exhibit 101 to this Annual Report are the following documents formatted in extensible business reporting language (XBRL): (i) Document and Entity Information; (ii) Statements of Income for the years ended September 30, 2013, 2012, and 2011; (iii) Statements of Comprehensive Income for the years ended September 30, 2013, 2012, and 2011; (iv) Statements of Common Shareholder’s Equity for the years ended September 30, 2013, 2012, and 2011; (v) Statements of Cash Flows for the years ended September 30, 2013, 2012, and 2011; (vi) Balance Sheets at September 30, 2013 and 2012; (vii) Statements of Capitalization at September 30, 2013 and 2012; (viii) Notes to the Financial Statements.