10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 or 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Quarter Ended June 30, 2013

OR

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

Commission File Number 1-16681

THE LACLEDE GROUP, INC.

(Exact name of registrant as specified in its charter)

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

Indicate by check mark if the registrant:

(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 [     ]

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

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

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

As of July 26, 2013, there were 32,692,182 shares of the registrant’s Common Stock, par value $1.00 per share, outstanding.

TABLE OF CONTENTS			Page No.
PART I.  FINANCIAL INFORMATION
Item 1	Financial Statements:
		Statements of Consolidated Income	4
		Statements of Consolidated Comprehensive Income	5
		Consolidated Balance Sheets	6
		Statements of Consolidated Cash Flows	8
		Notes to Consolidated Financial Statements	9
Item 2	Management’s Discussion and Analysis of Financial Condition and
		Results of Operations	29
Item 3	Quantitative and Qualitative Disclosures About Market Risk		50
Item 4	Controls and Procedures		50
PART II.  OTHER INFORMATION
Item 1	Legal Proceedings		51
Item 1A	Risk Factors		51
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds		54
Item 6	Exhibits		54
SIGNATURE			55
INDEX TO EXHIBITS			56

2

PART I. FINANCIAL INFORMATION

The interim financial statements included herein have been prepared by The Laclede Group, Inc. (Laclede Group or the Company), without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). These financial statements should be read in conjunction with the financial statements and the notes thereto included in the Company’s Form 10-K for the fiscal year ended September 30, 2012.

3

Item 1. Financial Statements

THE LACLEDE GROUP, INC.

STATEMENTS OF CONSOLIDATED INCOME

(UNAUDITED)

	Three Months Ended					Nine Months Ended
	June 30,					June 30,
(Thousands, Except Per Share Amounts)	2013			2012		2013		2012
Operating Revenues:
Gas Utility	$	131,517		$	116,459	$	735,726	$	665,981
Gas Marketing	33,433			70,014		129,937		288,036
Other	339			376		4,242		1,920
Total Operating Revenues	165,289			186,849		869,905		955,937
Operating Expenses:
Gas Utility
Natural and propane gas	43,233			46,641		410,189		364,556
Other operation and maintenance expenses	42,404			38,351		123,245		125,028
Depreciation and amortization	11,519			10,186		33,742		30,450
Taxes, other than income taxes	12,968			10,842		49,525		45,602
Total Gas Utility Operating Expenses	110,124			106,020		616,701		565,636
Gas Marketing	40,583			65,420		133,959		279,784
Other	2,301			364		13,029		1,784
Total Operating Expenses	153,008			171,804		763,689		847,204
Operating Income	12,281			15,045		106,216		108,733
Other Income and (Income Deductions) – Net	(398		)	451		2,024		3,771
Interest Charges:
Interest on long-term debt	6,266			5,739		17,393		17,218
Other interest charges	594			427		2,197		1,541
Total Interest Charges	6,860			6,166		19,590		18,759
Income Before Income Taxes	5,023			9,330		88,650		93,745
Income Tax (Benefit) Expense	(1,562		)	897		26,256		30,454
Net Income	$	6,585		$	8,433	$	62,394	$	63,291
Weighted Average Number of Common Shares Outstanding:
Basic	26,110			22,282		23,634		22,243
Diluted	26,194			22,357		23,708		22,318
Basic Earnings Per Share of Common Stock	$	0.25		$	0.38	$	2.62	$	2.83
Diluted Earnings Per Share of Common Stock	$	0.25		$	0.38	$	2.62	$	2.82
Dividends Declared Per Share of Common Stock	$	0.425		$	0.415	$	1.275	$	1.245
See Notes to Consolidated Financial Statements.

4

THE LACLEDE GROUP, INC.

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

(UNAUDITED)

	Three Months Ended					Nine Months Ended
	June 30,					June 30,
(Thousands)	2013		2012			2013		2012
Net Income	$	6,585	$	8,433		$	62,394	$	63,291
Other Comprehensive Income (Loss), Before Tax:
Net gains (losses) on cash flow hedging derivative instruments:
Net hedging gain (loss) arising during the period	27,614		(1,733		)	21,414		6,420
Reclassification adjustment for losses (gains) included in
net income	1,318		(6,171		)	3,544		(8,593		)
Net unrealized gains (losses) on cash flow hedging
derivative instruments	28,932		(7,904		)	24,958		(2,173		)
Defined benefit pension and other postretirement plans:
Net actuarial loss arising during the period	—		—			—		(2,366		)
Amortization of actuarial loss included in net periodic
pension and postretirement benefit cost	90		66			271		3,639
Net defined benefit pension and other postretirement plans	90		66			271		1,273
Other Comprehensive Income (Loss), Before Tax	29,022		(7,838		)	25,229		(900		)
Income Tax Expense (Benefit) Related to Items of Other
Comprehensive Income	10,846		(3,028		)	9,429		(348		)
Other Comprehensive Income (Loss), Net of Tax	18,176		(4,810		)	15,800		(552		)
Comprehensive Income	$	24,761	$	3,623		$	78,194	$	62,739
See Notes to Consolidated Financial Statements.

5

THE LACLEDE GROUP, INC.

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	June 30,			Sept. 30,			June 30,
(Thousands)	2013			2012			2012
ASSETS
Utility Plant	$	1,567,296		$	1,497,419		$	1,455,004
Less:  Accumulated depreciation and amortization	484,380			478,120			474,008
Net Utility Plant	1,082,916			1,019,299			980,996
Non-utility property	5,892			6,039			5,899
Other investments	53,337			50,775			55,117
Other Property and Investments	59,229			56,814			61,016
Current Assets:
Cash and cash equivalents	556,489			27,457			21,523
Accounts receivable:
Utility	70,380			64,027			65,762
Non-utility	53,678			51,042			47,335
Other	17,123			26,478			22,927
Allowance for doubtful accounts	(9,024		)	(7,705		)	(8,842		)
Delayed customer billings	11,319			—			—
Inventories:
Natural gas stored underground	59,171			92,729			55,192
Propane gas	8,963			10,200			10,051
Materials and supplies at average cost	4,477			3,543			3,917
Natural gas receivable	24,304			22,377			19,710
Derivative instrument assets	21,279			2,855			3,879
Unamortized purchased gas adjustments	6,230			40,674			9,158
Deferred income taxes	2,888			—			—
Prepayments and other	14,112			9,339			11,079
Total Current Assets	841,389			343,016			261,691
Deferred Charges:
Regulatory assets	432,700			456,047			433,376
Other	5,805			5,086			4,259
Total Deferred Charges	438,505			461,133			437,635
Total Assets	$	2,422,039		$	1,880,262		$	1,741,338

6

THE LACLEDE GROUP, INC.

CONSOLIDATED BALANCE SHEETS (Continued)

(UNAUDITED)

	June 30,.		Sept. 30,.			June 30,
(Thousands, except share amounts)	2013		2012			2012
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock (70,000,000 shares authorized, 32,675,659,     22,539,431, and 22,505,440 shares issued, respectively)	$	32,676	$	22,539		$	22,505
Paid-in capital	592,946		168,607			166,717
Retained earnings	443,691		414,581			424,588
Accumulated other comprehensive income (loss)	11,684		(4,116		)	(2,652		)
Total Common Stock Equity	1,080,997		601,611			611,158
Long-term debt (less current portion)	464,444		339,416			339,401
Total Capitalization	1,545,441		941,027			950,559
Current Liabilities:
Notes payable	—		40,100			—
Accounts payable	104,862		89,503			81,322
Advance customer billings	—		25,146			6,225
Current portion of long-term debt	—		25,000			25,000
Wages and compensation accrued	13,386		13,908			12,653
Dividends payable	14,454		9,831			9,664
Customer deposits	7,828		8,565			9,123
Interest accrued	3,887		8,590			5,405
Taxes accrued	28,522		11,304			13,040
Deferred income taxes	—		6,675			311
Other	9,862		13,502			16,540
Total Current Liabilities	182,801		252,124			179,283
Deferred Credits and Other Liabilities:
Deferred income taxes	377,965		355,509			335,366
Unamortized investment tax credits	2,953		3,113			3,166
Pension and postretirement benefit costs	181,691		196,558			158,011
Asset retirement obligations	42,097		40,368			28,723
Regulatory liabilities	58,382		56,319			53,867
Other	30,709		35,244			32,363
Total Deferred Credits and Other Liabilities	693,797		687,111			611,496
Commitments and Contingencies (Note 12)
Total Capitalization and Liabilities	$	2,422,039	$	1,880,262		$	1,741,338
See Notes to Consolidated Financial Statements.

7

THE LACLEDE GROUP, INC.

STATEMENTS OF CONSOLIDATED CASH FLOWS

(UNAUDITED) 

	Nine Months Ended
	June 30,
(Thousands)	2013			2012
Operating Activities:
Net Income	$	62,394		$	63,291
Adjustments to reconcile net income to net cash provided by (used in)       operating activities:
Depreciation, amortization, and accretion	34,721			30,900
Deferred income taxes and investment tax credits	13,208			22,448
Other – net	1,753			(425		)
Changes in assets and liabilities:
Accounts receivable – net	1,685			(2,699		)
Unamortized purchased gas adjustments	34,444			16,561
Deferred purchased gas costs	12,160			(25,429		)
Accounts payable	21,717			(15,025		)
Delayed customer billings - net	(36,465		)	(9,005		)
Taxes accrued	16,562			568
Natural gas stored underground	33,558			59,978
Other assets and liabilities	(28,693		)	(12,964		)
Net cash provided by operating activities	167,044			128,199
Investing Activities:
Capital expenditures	(96,816		)	(76,780		)
Other investments	(2,558		)	(1,388		)
Net cash used in investing activities	(99,374		)	(78,168		)
Financing Activities:
Issuance of long-term debt	125,000			—
Maturity of first mortgage bonds	(25,000		)	—
Repayment of short-term debt – net	(40,100		)	(46,000		)
Changes in book overdrafts	(1,139		)	223
Issuance of common stock	431,329			3,162
Non-employee directors’ restricted stock awards	—			(565		)
Dividends paid	(28,651		)	(27,599		)
Employees’ taxes paid associated with restricted shares withheld upon vesting	(736		)	(1,171		)
Excess tax benefits from stock-based compensation	1,135			208
Other	(476		)	(43		)
Net cash provided by (used in) financing activities	461,362			(71,785		)
Net Increase (Decrease) in Cash and Cash Equivalents	529,032			(21,754		)
Cash and Cash Equivalents at Beginning of Period	27,457			43,277
Cash and Cash Equivalents at End of Period	$	556,489		$	21,523
Supplemental Disclosure of Cash Paid (Refunded) During the Period for:
Interest	$	22,666		$	21,811
Income taxes	(2,844		)	7,064
See Notes to Consolidated Financial Statements.

8

THE LACLEDE GROUP, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1.        SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

These notes are an integral part of the accompanying unaudited consolidated financial statements of The Laclede Group, Inc. (Laclede Group or the Company) and its subsidiaries. In the opinion of Laclede Group, this interim report includes all adjustments (consisting of only normal recurring accruals) necessary for the fair presentation of the results of operations for the periods presented. This Form 10-Q should be read in conjunction with the Notes to Consolidated Financial Statements contained in the Company’s Fiscal Year 2012 Form 10-K.

The consolidated financial position, results of operations, and cash flows of Laclede Group are comprised primarily from the financial position, results of operations, and cash flowsof Laclede Gas Company (Laclede Gas or the Utility). Laclede Gas is a regulated natural gas distribution utility having a material seasonal cycle. As a result, these interim statements of income for Laclede Group are not necessarily indicative of annual results or representative of succeeding quarters of the fiscal year. Due to the seasonal nature of the business of Laclede Gas, earnings are typically concentrated in the November through April period, which generally corresponds with the heating season. Laclede Energy Resources, Inc. (LER) includes its wholly owned subsidiary, LER Storage Services, Inc., which became operational on January 1, 2012.

REVENUE RECOGNITION - Laclede Gas reads meters and bills its customers on monthly cycles. The Utility records its gas utility revenues from gas sales and transportation services on an accrual basis that includes estimated amounts for gas delivered, but not yet billed. The accruals for unbilled revenues are reversed in the subsequent accounting period when meters are actually read and customers are billed. The amounts of accrued unbilled revenues at June 30, 2013 and 2012, for the Utility, were $8.7 million and $9.0 million, respectively. The amount of accrued unbilled revenue at September 30, 2012 was $11.6 million.

GROSS RECEIPTS TAXES - Gross receipts taxes associated with Laclede Gas’ natural gas utility service are imposed on the Utility and billed to its customers. These amounts are recorded gross in the Statements of Consolidated Income. Amounts recorded in Gas Utility Operating Revenues for the quarters ended June 30, 2013 and 2012 were $7.8 million and $5.7 million, respectively. Amounts recorded in Gas Utility Operating Revenues for the nine months ended June 30, 2013 and 2012 were $35.3 million and $31.4 million, respectively. Gross receipts taxes are expensed by the Utility and included in the Taxes, other than income taxes line.

NEW ACCOUNTING STANDARDS - In June 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-05, “Presentation of Comprehensive Income,” to amend ASC Topic 220, “Comprehensive Income,” by changing certain financial statement presentation requirements. Under the amended guidance, entities may either present a single continuous statement of comprehensive income or, consistent with the Company’s current presentation, provide separate but consecutive statements (a statement of income and a statement of comprehensive income). ASU No. 2011-05 would have required that, regardless of the method chosen, reclassification adjustments from other comprehensive income to net income be presented on the face of the financial statements, displaying the effect on both net income and other comprehensive income. However, in December 2011, the FASB issued ASU No. 2011-12 to defer the effective date of this particular requirement while it reconsiders this provision of the guidance. The amendments in these ASUs do not change the items that are required to be reported in other comprehensive income and, accordingly, did not impact total net income, comprehensive income, or earnings per share upon adoption in the first quarter of fiscal year 2013.

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.

9

2.        PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS

Pension Plans

Laclede Gas 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 for quarters ended June 30, 2013 and 2012 were $4.2 million and $4.1 million, respectively, including amounts charged to construction. Pension costs for nine months ended June 30, 2013 and 2012 were $12.5 million and $15.9 million, respectively, including amounts charged to construction.

The net periodic pension costs include the following components:

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
(Thousands)	2013			2012			2013			2012
Service cost – benefits earned during the period	$	2,311		$	2,295		$	6,933		$	6,908
Interest cost on projected benefit obligation	4,066			4,824			12,198			14,535
Expected return on plan assets	(4,741		)	(4,899		)	(14,223		)	(14,697		)
Amortization of prior service cost	136			148			408			444
Amortization of actuarial loss	2,839			2,252			8,517			6,788
Loss on lump-sum settlement	12,346			—			12,346			3,407
Sub-total	16,957			4,620			26,179			17,385
Regulatory adjustment	(12,780		)	(484		)	(13,647		)	(1,451		)
Net pension cost	$	4,177		$	4,136		$	12,532		$	15,934

Pursuant to the provisions of the Laclede Gas pension plans, pension obligations may be satisfied by lump-sum cash payments. Pursuant to a Missouri Public Service Commission (MoPSC or Commission) 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 were $39.7 million and $6.4 million during the nine months ended June 30, 2013 and June 30, 2012, respectively.

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

The funding policy of Laclede Gas 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. Fiscal year 2013 contributions to the pension plans through June 30, 2013 were $23.4 million to the qualified trusts and approximately $0.4 million to the non-qualified plans. Laclede Gas does not expect to make additional contributions to its qualified, trusteed pension plans during the remaining three months of fiscal year 2013. Contributions to the non-qualified pension plans for the remaining three months of fiscal 2013 are anticipated to be approximately $0.8 million.

Postretirement Benefits

Laclede Gas 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 for both the quarters ended June 30, 2013 and 2012 were $2.4 million, including amounts charged to construction. Postretirement benefit costs for both the nine months ended June 30, 2013 and 2012 were $7.1 million, including amounts charged to construction.

10

Net periodic postretirement benefit costs consisted of the following components:

	Three Months Ended June 30,						Nine Months Ended June 30,
(Thousands)	2013			2012			2013			2012
Service cost – benefits earned during the period	$	2,534		$	2,015		$	7,601		$	6,045
Interest cost on accumulated postretirement benefit obligation	1,278			1,380			3,836			4,140
Expected return on plan assets	(1,082		)	(991		)	(3,244		)	(2,973		)
Amortization of transition obligation	24			34			70			102
Amortization of prior service cost (credit)	—			(518		)	2			(1,554		)
Amortization of actuarial loss	1,325			1,065			3,975			3,195
Sub-total	4,079			2,985			12,240			8,955
Regulatory adjustment	(1,699		)	(604		)	(5,097		)	(1,812		)
Net postretirement benefit cost	$	2,380		$	2,381		$	7,143		$	7,143

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. Laclede Gas established Voluntary Employees’ Beneficiary Association (VEBA) and Rabbi trusts as its external funding mechanisms. VEBA and Rabbi trusts’ assets consist primarily of money market securities and mutual funds invested in stocks and bonds.

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 $9.5 million effective January 1, 2011. The difference between these amounts and postretirement benefit cost based on the above and that otherwise would be included in the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income is deferred as a regulatory asset or regulatory liability.

Laclede Gas’ funding policy is to contribute amounts to the trusts equal to the periodic benefit cost calculated pursuant to GAAP as recovered in rates. Fiscal year 2013 contributions to the postretirement plans through June 30, 2013 were $8.2 million to the qualified trusts and approximately $0.4 million paid directly to participants from Laclede Gas' funds. Contributions to the postretirement plans for the remaining three months of fiscal year 2013 are anticipated to be $8.2 million to the qualified trusts and $0.2 million paid directly to participants from Laclede Gas’ funds.

3.        STOCK-BASED COMPENSATION

Awards of stock-based compensation are made pursuant to The Laclede Group 2006 Equity Incentive Plan (2006 Plan). Refer to Note 3 of the Consolidated Financial Statements included in the Company’s Form 10-K for the fiscal year ended September 30, 2012 for descriptions of the plan.

Restricted Stock Awards

During the nine months ended June 30, 2013, the Company granted 108,419 performance-contingent restricted stock units to executive officers and key employees at a weighted average grant date fair value of $34.48 per share. This number represents the maximum shares that can be earned pursuant to the terms of the awards. Most of these stock units have a performance period ending September 30, 2015. While the participants have no interim voting rights on these stock units, dividends accrue during the performance period and are paid to the participants upon vesting, but are subject to forfeiture if the underlying stock units do not vest. The number of stock units that will ultimately vest is dependent upon the attainment of certain levels of earnings and other strategic goals, as well as the Company’s level of total shareholder return (TSR) during the performance period relative to a comparator group of companies. This TSR provision is considered a market condition under GAAP.

11

Activity of restricted stock and restricted stock units subject to performance and/or market conditions during the nine months ended June 30, 2013 is presented below:

	Restricted Stock/ Stock Units		Weighted Average Grant Date Fair Value
Nonvested at September 30, 2012	232,403		$	30.89
Granted (maximum shares that can be earned)	108,419		$	34.48
Vested	(37,436	)	$	27.02
Forfeited	(48,782	)	$	25.71
Nonvested at June 30, 2013	254,604		$	33.98

During the nine months ended June 30, 2013, the Company granted 58,924 shares of time-vested restricted stock and stock units to executive officers, key employees, and directors at a weighted average grant date fair value of $39.98 per share. Most of these shares were awarded on December 3, 2012 and vest December 3, 2015. In the interim, participants receive full voting rights and dividends, which are not subject to forfeiture.    

Time-vested restricted stock and stock unit activity for the nine months ended June 30, 2013 is presented below:

	Restricted Stock/ Stock Units		Weighted Average Grant Date Fair Value
Nonvested at September 30, 2012	115,115		$	36.54
Granted	58,924		$	39.98
Vested	(20,600	)	$	30.55
Forfeited	(6,500	)	$	38.54
Nonvested at June 30, 2013	146,939		$	38.67

During the nine months ended June 30, 2013, 58,036 shares of restricted stock and stock units (performance-contingent and time-vested), awarded on November 4, 2009, December 1, 2009, January 4, 2010, and May 3, 2010 vested. The Company withheld 18,898 of the vested shares at a weighted average price of $38.96 per share pursuant to elections by employees to satisfy tax withholding obligations.

Stock Option Awards

Stock option activity for the nine months ended June 30, 2013 is presented below:

	Stock Options		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (Years)	Aggregate Intrinsic Value ($000)
Outstanding at September 30, 2012	214,000		$	31.02
Granted	—		$	—
Exercised	(70,500	)	$	29.42
Forfeited	—		$	—
Expired	—		$	—
Outstanding at June 30, 2013	143,500		$	31.81	2.0	$	1,988
Fully Vested and Expected to Vest at June 30, 2013	143,500		$	31.81	2.0	$	1,988
Exercisable at June 30, 2013	143,500		$	31.81	2.0	$	1,988

12

The closing price of the Company’s common stock was $45.66 at June 30, 2013.

Equity Compensation Costs

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

	Three Months Ended June 30,						Nine Months Ended June 30,
(Thousands)	2013			2012			2013			2012
Total equity compensation cost	$	1,654		$	678		$	3,413		$	2,029
Compensation cost capitalized	(536		)	(230		)	(1,075		)	(589		)
Compensation cost recognized in net income, before income taxes	1,118			448			2,338			1,440
Income tax benefit recognized in net income	(428		)	(173		)	(895		)	(556		)
Compensation cost recognized in net income, net of income tax	$	690		$	275		$	1,443		$	884

As of June 30, 2013, there was $6.1 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements. That cost is expected to be recognized over a weighted average period of 2.1 years.

4.        EARNINGS PER COMMON SHARE

	Three Months Ended June 30,				Nine Months Ended June 30,
(Thousands, Except Per Share Amounts)	2013		2012		2013		2012
Basic EPS:
Net Income	$	6,585	$	8,433	$	62,394	$	63,291
Less: Income allocated to participating securities	81		42		389		356
Net Income Available to Common Shareholders	$	6,504	$	8,391	$	62,005	$	62,935
Weighted Average Shares Outstanding	26,110		22,282		23,634		22,243
Earnings Per Share of Common Stock	$	0.25	$	0.38	$	2.62	$	2.83
Diluted EPS:
Net Income	$	6,585	$	8,433	$	62,394	$	63,291
Less: Income allocated to participating securities	81		42		388		355
Net Income Available to Common Shareholders	$	6,504	$	8,391	$	62,006	$	62,936
Weighted Average Shares Outstanding	26,110		22,282		23,634		22,243
Dilutive Effect of Stock Options, Restricted Stock,
and Restricted Stock Units	84		75		74		75
Weighted Average Diluted Shares	26,194		22,357		23,708		22,318
Earnings Per Share of Common Stock	$	0.25	$	0.38	$	2.62	$	2.82
Outstanding Shares Excluded from the
Calculation of Diluted EPS Attributable to:
Restricted stock and stock units subject to
performance and/or market conditions	196		204		196		202

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5.        STOCKHOLDERS' EQUITY

On May 29, 2013, Laclede Group issued 10,005,000 shares of its common stock in a public offering at a price of $44.50 per share. Proceeds from the offering, net of underwriting expenses, were $428.0 million and were recorded as additions to common stock and paid-in capital on the consolidated balance sheets. The Company intends to use the proceeds from the offering to fund a portion of the pending acquisition of MGE, as discussed further in Note 13, Acquisition Agreements.

6.        FAIR VALUE OF FINANCIAL INSTRUMENTS

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

					Classification of Estimated Fair Value
(Thousands)	Carrying Amount		Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
As of June 30, 2013
Cash and cash equivalents	$	556,489	$	556,489	$	421,518	$	134,971	$	—
Short-term debt	—		—		—		—		—
Long-term debt, including current portion	464,444		506,328		—		506,328		—
As of Sept. 30, 2012
Cash and cash equivalents	$	27,457	$	27,457	$	17,380	$	10,077	$	—
Short-term debt	40,100		40,100		—		40,100		—
Long-term debt, including current portion	364,416		452,768		—		452,768		—
As of June 30, 2012
Cash and cash equivalents	$	21,523	$	21,523	$	11,560	$	9,963	$	—
Short-term debt	—		—		—		—		—
Long-term debt, including current portion	364,401		445,961		—		445,961		—

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

14

7.        FAIR VALUE MEASUREMENTS

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

(Thousands)	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Effects of Netting and Cash Margin Receivables /Payables			Total
As of June 30, 2013
Assets
U. S. Stock/Bond Mutual Funds	$	13,980	$	—	$	—	$	—		$	13,980
NYMEX/ICE natural gas contracts	7,066		399		—		(4,635		)	2,830
NYMEX gasoline and heating oil contracts	136		—		—		(136		)	—
Natural gas commodity contracts	—		740		372		(243		)	869
Interest rate swaps	$	—	$	17,689	$	—	$	—		$	17,689
Total	$	21,182	$	18,828	$	372	$	(5,014	)	$	35,368
Liabilities
NYMEX/ICE natural gas contracts	$	3,950	$	329	$	—	$	(4,279	)	$	—
Natural gas commodity contracts	—		1,083		—		(243		)	840
Total	$	3,950	$	1,412	$	—	$	(4,522	)	$	840
As of September 30, 2012
Assets
U. S. Stock/Bond Mutual Funds	$	13,187	$	—	$	—	$	—		$	13,187
NYMEX/ICE natural gas contracts	7,411		994		—		(8,405		)	—
NYMEX gasoline and heating oil contracts	344		—		—		(344		)	—
Natural gas commodity contracts	—		3,060		113		(299		)	2,874
Total	$	20,942	$	4,054	$	113	$	(9,048	)	$	16,061
Liabilities
NYMEX/ICE natural gas contracts	$	12,253	$	1,891	$	—	$	(14,144	)	$	—
Natural gas commodity contracts	—		428		4		(299		)	133
Total	$	12,253	$	2,319	$	4	$	(14,443	)	$	133
As of June 30, 2012
Assets
U. S. Stock/Bond Mutual Funds	$	17,535	$	—	$	—	$	—		$	17,535
NYMEX/ICE natural gas contracts	3,273		1,240		—		(4,513		)	—
NYMEX gasoline and heating oil contracts	107		—		—		(107		)	—
Natural gas commodity contracts	—		4,288		107		(516		)	3,879
Total	$	20,915	$	5,528	$	107	$	(5,136	)	$	21,414
Liabilities
NYMEX/ICE natural gas contracts	$	22,141	$	1,590	$	—	$	(23,731	)	$	—
Natural gas commodity contracts	—		587		—		(516		)	71
Total	$	22,141	$	2,177	$	—	$	(24,247	)	$	71

15

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

	Three Months Ended June 30,						Nine Months Ended June 30,
(Thousands)	2013			2012			2013			2012
Beginning of period	$	93		$	58		$	109		$	13
Net settlements	33			(9		)	4			(16		)
Net losses related to derivatives not held   at end of period	(9		)	(8		)	(99		)	(68		)
Net gains related to derivatives still held   at end of period	255			66			358			178
End of period	$	372		$	107		$	372		$	107

The mutual funds are included in the Other investments line of the Consolidated Balance Sheets. Derivative assets and liabilities, including receivables and payables associated with cash margin requirements, are presented net in the Consolidated Balance Sheets when a legally enforceable netting agreement exists between the Company and the counterparty to a derivative contract. For additional information on derivative instruments, see Note 8, Derivative Instruments and Hedging Activities.

8.        DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Laclede Gas 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 Purchased Gas Adjustment (PGA) Clause, through which the MoPSC allows the Utility to recover gas supply costs, subject to prudence review by the MoPSC. Accordingly, Laclede Gas does not expect any adverse earnings impact as a result of the use of these derivative instruments. The Utility does not designate these instruments as hedging instruments for financial reporting purposes because gains or losses associated with the use of these derivative instruments are deferred and recorded as regulatory assets or regulatory liabilities pursuant to ASC Topic 980, “Regulated Operations,” and, as a result, have no direct impact on the Statements of Consolidated Income. The timing of the operation of the PGA Clause may cause interim variations in short-term cash flows, because the Utility is subject to cash margin requirements associated with changes in the values of these instruments. Nevertheless, carrying costs associated with such requirements are recovered through the PGA Clause.

From time to time, Laclede Gas 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 June 30, 2013, Laclede Gas held 0.4 million gallons of gasoline futures contracts at an average price of $2.25 per gallon. Most of these contracts, the longest of which extends to April 2014, are designated as cash flow hedges of forecasted transactions pursuant to ASC Topic 815. The gains or losses on these derivative instruments are not subject to the Utility’s PGA Clause.

16

In the course of its business, Laclede Group’s gas marketing subsidiary, LER, which includes its wholly owned subsidiary LER Storage Services, Inc., enters into commitments associated with the purchase or sale of natural gas. Certain of LER’s derivative natural gas contracts are designated as normal purchases or normal sales and, as such, are excluded from the scope of ASC Topic 815 and are accounted for as executory contracts on an accrual basis. Any of LER’s derivative natural gas contracts that are not designated as normal purchases or normal sales are accounted for at fair value. At June 30, 2013, the fair values of 57.7 million MMBtu of non-exchange traded natural gas commodity contracts were reflected in the Consolidated Balance Sheet. Of these contracts, 34.3 million MMBtu will settle during fiscal year 2013, 21.6 million MMBtu will settle during fiscal year 2014, while the remaining 1.8 million MMBtu will settle during fiscal year 2015. These contracts have not been designated as hedges; therefore, changes in the fair value of these contracts are reported in earnings each period. Furthermore, LER manages the price risk associated with its fixed-priced commitments by either closely matching the offsetting physical purchase or sale of natural gas at fixed prices or through the use of NYMEX or Ice Clear Europe (ICE) futures, swap, and option contracts to lock in margins. At June 30, 2013, LER’s unmatched fixed-price positions were not material to Laclede Group’s financial position or results of operations. LER’s NYMEX and ICE natural gas futures, swap, and option contracts used to lock in margins may be designated as cash flow hedges of forecasted transactions for financial reporting purposes.

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

	Laclede Gas Company			Laclede Energy Resources, Inc.
	MMBtu (millions)	Avg. Price Per MMBtu		MMBtu (millions)	Avg. Price Per MMBtu
Open short futures positions
Fiscal 2013	—	$	—	5.00	$	4.03
Fiscal 2014	—	—		6.04	3.84
Fiscal 2015	—	—		0.28	4.18
Open long futures positions
Fiscal 2013	3.42	$	3.42	0.63	$	3.82
Fiscal 2014	4.87	3.97		0.01	4.03
Fiscal 2015	—	—		2.42	3.91

At June 30, 2013, Laclede Gas had 17.0 million MMBtu of other price mitigation in place through the use of NYMEX natural gas option-based strategies while LER had none.

In February 2013, Laclede Group entered into certain interest rate swap agreements to effectively lock in interest rates on a portion of the long-term debt it anticipates issuing to finance its pending acquisition of Missouri Gas Energy (MGE). These derivative instruments have been designated as cash flow hedges of forecasted transactions. These forward starting swaps involve the payment of a fixed interest rate and the receipt of a floating interest rate (the London Interbank Offered Rate, also known as LIBOR) over the terms specified in the contracts. At June 30, 2013, the notional amount of interest rate swaps outstanding was $355 million with stated maturities ranging from 2018 to 2043 and fixed interest rates ranging between 1.28% and 3.14%.

Derivative instruments designated as cash flow hedges of forecasted transactions are recognized on the Consolidated Balance Sheets at fair value and the change in the fair value of the effective portion of these hedge instruments is recorded, net of tax, in other comprehensive income (OCI). Accumulated other comprehensive income (AOCI) is a component of Total Common Stock Equity. Amounts are reclassified from AOCI into earnings when the hedged items affect net income, using the same revenue or expense category that the hedged item impacts. Based on market prices at June 30, 2013, it is expected that approximately $5.3 million of pre-tax unrealized gains will be reclassified into the Statements of Consolidated Income during the next twelve months. Cash flows from hedging transactions are classified in the same category as the cash flows from the items that are being hedged in the Statements of Consolidated Cash Flows.

17

The Effect of Derivative Instruments on the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income
		Three Months Ended						Nine Months Ended
	Location of Gain (Loss)	June 30,						June 30,
(Thousands)	Recorded in Income	2013			2012			2013			2012
Derivatives in Cash Flow Hedging Relationships
Effective portion of gain (loss) recognized in OCI on derivatives:
NYMEX/ICE natural gas contracts		$	5,501		$	(1,802	)	$	3,646		$	6,218
NYMEX gasoline and heating oil contracts		(125		)	69			79			202
Interest rate swaps		22,238			—			17,689			—
Total		$	27,614		$	(1,733	)	$	21,414		$	6,420
Effective portion of gain (loss) reclassified from AOCI to income:
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	$	(1,570	)	$	7,646		$	(3,229	)	$	18,434
	Gas Marketing Operating Expenses	199			(1,492		)	(453		)	(9,861		)
Sub-total		(1,371		)	6,154			(3,682		)	8,573
NYMEX gasoline and heating oil contracts	Gas Utility Other Operations and Maintenance Expenses	53			17			138			20
Total		$	(1,318	)	$	6,171		$	(3,544	)	$	8,593
Ineffective portion of gain (loss) on derivatives recognized in income:
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	$	16		$	(84	)	$	(396	)	$	(15	)
	Gas Marketing Operating Expenses	(22		)	(95		)	(151		)	(291		)
Sub-total		(6		)	(179		)	(547		)	(306		)
NYMEX gasoline and heating oil contracts	Gas Utility Other Operations and Maintenance Expenses	5			(46		)	(127		)	(12		)
Total		$	(1	)	$	(225	)	$	(674	)	$	(318	)
Derivatives Not Designated as Hedging Instruments *
Gain (loss) recognized in income on derivatives:
Natural gas commodity contracts	Gas Marketing Operating Revenues	$	(993	)	$	2,641		$	(218	)	$	3,431
	Gas Marketing Operating Expenses	—			—			—			687
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	1,163			(1,123		)	551			425
	Gas Marketing Operating Expenses	—			(655		)	—			(625		)
NYMEX gasoline and heating oil contracts	Other Income and (Income Deductions) - Net	(5		)	(11		)	41			2
Total		$	165		$	852		$	374		$	3,920

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

18

Fair Value of Derivative Instruments in the Consolidated Balance Sheet at June 30, 2013
	Asset Derivatives				Liability Derivatives
(Thousands)	Balance Sheet Location	Fair Value		*	Balance Sheet Location	Fair  Value		*
Derivatives designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets	$	4,574		Derivative Instrument Assets	$	437
NYMEX/ICE natural gas contracts	Other Deferred Charges	77			Other Deferred Charges	9
NYMEX gasoline and heating oil contracts	Accounts Receivable – Other	136			Accounts Receivable – Other	—
Interest rate swaps	Derivative Instrument Assets	17,689			Derivative Instrument Assets	—
Sub-total		22,476				446
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets	859			Derivative Instrument Assets	146
	Accounts Receivable – Other	1,956			Accounts Receivable – Other	3,688
Natural gas commodity contracts	Derivative Instrument Assets	944			Derivative Instrument Assets	89
	Other Deferred Charges	14			Other Deferred Charges	—
	Other Current Liabilities	122			Other Current Liabilities	836
	Other Deferred Credits	33			Other Deferred Credits	159
Sub-total		3,928				4,918
Total derivatives		$	26,404			$	5,364
Fair Value of Derivative Instruments in the Consolidated Balance Sheet at September 30, 2012
	Asset Derivatives				Liability Derivatives
(Thousands)	Balance Sheet Location	Fair Value		*	Balance Sheet Location	Fair Value		*
Derivatives designated as hedging instruments
NYMEX/ICE natural gas contracts	Accounts Receivable - Other	$	405		Accounts Receivable - Other	$	3,413
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	334			Accounts Receivable - Other	—
Sub-total		739				3,413
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Accounts Receivable - Other	8,000			Accounts Receivable - Other	10,731
Natural gas commodity contracts	Derivative Instrument Assets	3,150			Derivative Instrument Assets	295
	Other Current Liabilities	4			Other Current Liabilities	137
	Other Deferred Charges	19			Other Deferred Charges	—
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	10			Accounts Receivable - Other	—
Sub-total		11,183				11,163
Total derivatives		$	11,922			$	14,576

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Fair Value of Derivative Instruments in the Consolidated Balance Sheet at June 30, 2012
	Asset Derivatives				Liability Derivatives
(Thousands)	Balance Sheet Location	Fair Value		*	Balance Sheet Location	Fair Value		*
Derivatives designated as hedging instruments
NYMEX/ICE natural gas contracts	Accounts Receivable - Other	$	1,064		Accounts Receivable - Other	$	2,529
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	106			Accounts Receivable - Other	—
Sub-total		1,170				2,529
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Accounts Receivable - Other	3,449			Accounts Receivable - Other	21,202
Natural gas commodity contracts	Derivative Instrument Assets	4,356			Derivative Instrument Assets	478
	Other Current Liabilities	39			Other Current Liabilities	109
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	1			Accounts Receivable - Other	—
Sub-total		7,845				21,789
Total derivatives		$	9,015			$	24,318

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

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

(Thousands)	June 30, 2013			Sept. 30, 2012			June 30, 2012
Fair value of asset derivatives presented above	$	26,404		$	11,922		$	9,015
Fair value of cash margin receivables offset with derivatives	1,596			5,478			19,111
Netting of assets and liabilities with the same counterparty	(6,612		)	(14,526		)	(24,247		)
Total	$	21,388		$	2,874		$	3,879
Derivative Instrument Assets, per Consolidated Balance Sheets:
Derivative instrument assets	$	21,279		$	2,855		$	3,879
Other deferred charges	109			19			—
Total	$	21,388		$	2,874		$	3,879
Fair value of liability derivatives presented above	$	5,364		$	14,576		$	24,318
Fair value of cash margin payables offset with derivatives	2,088			83			—
Netting of assets and liabilities with the same counterparty	(6,612		)	(14,526		)	(24,247		)
Total	$	840		$	133		$	71
Derivative Instrument Liabilities, per Consolidated Balance Sheets:
Other Current Liabilities	$	727		$	133		$	71
Other Deferred Credits	113			—			—
Total	$	840		$	133		$	71

Additionally, at June 30, 2013, September 30, 2012, and June 30, 2012, the Company had $3.6 million, $10.0 million, and $10.6 million, respectively, in cash margin receivables not offset with derivatives, that are presented in Accounts Receivable - Other.     

20

9.        CONCENTRATIONS OF CREDIT RISK

A significant portion of LER’s transactions are with (or are associated with) energy producers, utility companies, and pipelines. These concentrations of transactions with these counterparties have the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that each of these three groups may be affected similarly by changes in economic, industry, or other conditions. To manage this risk, as well as credit risk from significant counterparties in these and other industries, LER has established procedures to determine the creditworthiness of its counterparties. These procedures include obtaining credit ratings and credit reports, analyzing counterparty financial statements to assess financial condition, and considering the industry environment in which the counterparty operates. This information is monitored on an ongoing basis. In some instances, LER may require credit assurances such as prepayments, letters of credit, or parental guarantees. In addition, LER may enter into netting arrangements to mitigate credit risk with counterparties in the energy industry from which LER both sells and purchases natural gas. Sales are typically made on an unsecured credit basis with payment due the month following delivery. Accounts receivable amounts are closely monitored and provisions for uncollectible amounts are accrued when losses are probable. To date, losses have not been significant. LER records accounts receivable, accounts payable, and prepayments for physical sales and purchases of natural gas on a gross basis. The amount included in accounts receivable attributable to energy producers and their marketing affiliates amounted to $22.2 million at June 30, 2013. Net receivable amounts from these customers on the same date, reflecting netting arrangements, were $12.0 million Accounts receivable attributable to utility companies and their marketing affiliates comprised $18.6 million of total accounts receivable at June 30, 2013, while net receivable amounts from these customers, reflecting netting arrangements, were $11.3 million. LER also has concentrations of credit risk with certain individually significant counterparties. At June 30, 2013, the amounts included in accounts receivable from LER’s five largest counterparties (in terms of net accounts receivable exposure), were $25.7 million. These five counterparties are either investment-grade rated or owned by investment-grade rated companies. Net receivable amounts from these customers on the same date, reflecting netting arrangements, were $17.0 million. Additionally, LER has concentrations of credit risk with pipeline companies associated with its natural gas receivable amounts.

10.        OTHER INCOME AND (INCOME DEDUCTIONS) - NET

	Three Months Ended June 30,						Nine Months Ended June 30,
(Thousands)	2013			2012			2013			2012
Interest income	$	164		$	337		$	827		$	1,001
Net investment gain	24			264			1,127			2,458
Other income	156			(15		)	233			(4		)
Other income deductions	(742		)	(135		)	(163		)	316
Other Income and (Income Deductions) – Net	$	(398	)	$	451		$	2,024		$	3,771

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11.        INFORMATION BY OPERATING SEGMENT

All of Laclede Group’s subsidiaries are wholly owned. In the first quarter of fiscal year 2013, the Company retitled its segment names. The Gas Utility segment, previously titled Regulated Gas Distribution, consists of the regulated operations of Laclede Gas and is the core business segment of Laclede Group. Laclede Gas is a public utility engaged in the retail distribution and sale of natural gas serving an area in eastern Missouri, with a population of approximately 2.2 million, including the City of St. Louis and parts of ten counties in eastern Missouri. The Gas Marketing segment, previously titled Non-Regulated Gas Marketing, includes the results of LER, a subsidiary engaged in the non-regulated marketing of natural gas and related activities, and LER Storage Services, Inc., which became operational in January 2012 and utilizes natural gas storage contracts for providing natural gas sales. Other includes Laclede Pipeline Company’s transportation of liquid propane regulated by the Federal Energy Regulatory Commission (FERC) as well as non-regulated activities, including, among other activities, real estate development, the compression of natural gas, and financial investments in other enterprises. These operations are conducted through seven subsidiaries. Other also includes Laclede Gas’ non-regulated business activities, which are comprised of its propane storage and related services. Accounting policies are described in Note 1. Intersegment transactions include sales of natural gas from Laclede Gas to LER, propane storage services provided by Laclede Gas to Laclede Pipeline Company, sales of natural gas from LER to Laclede Gas, and propane transportation services provided by Laclede Pipeline Company to Laclede Gas.

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

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			Gas
(Thousands)	Gas Utility		Marketing		Other			Eliminations			Consolidated
Three Months Ended June 30, 2013
Revenues from external customers	$	131,517	$	33,433	$	339		$	—		$	165,289
Intersegment revenues	23		9,354		546			(9,923		)	—
Total Operating Revenues	131,540		42,787		885			(9,923		)	165,289
Operating Expenses
Gas Utility
Natural and Propane Gas	52,847		—		—			(9,614		)	43,233
Other Operation and Maintenance Expenses	42,090		—		—			314			42,404
Depreciation and Amortization	11,519		—		—			—			11,519
Taxes, Other than Income Taxes	12,968		—		—			—			12,968
Total Gas Utility Operating Expenses	119,424		—		—			(9,300		)	110,124
Gas Marketing	—		40,583		—			—			40,583
Other	—		—		2,924			(623		)	2,301
Total Operating Expenses	119,424		40,583		2,924			(9,923		)	153,008
Operating Income	12,116		2,204		(2,039		)	—			12,281
Net Economic Earnings (Losses)	6,834		1,632		(302		)	—			8,164
Total assets	1,766,198		220,162		584,488			(148,809		)	2,422,039
Three Months Ended June 30, 2012
Revenues from external customers	$	116,459	$	70,014	$	376		$	—		$	186,849
Intersegment revenues	1,175		587		259			(2,021		)	—
Total Operating Revenues	117,634		70,601		635			(2,021		)	186,849
Operating Expenses
Gas Utility
Natural and Propane Gas	48,662		—		—			(2,021		)	46,641
Other Operation and Maintenance Expenses	38,351		—		—			—			38,351
Depreciation and Amortization	10,186		—		—			—			10,186
Taxes, Other than Income Taxes	10,842		—		—			—			10,842
Total Gas Utility Operating Expenses	108,041		—		—			(2,021		)	106,020
Gas Marketing	—		65,420		—			—			65,420
Other	—		—		364			—			364
Total Operating Expenses	108,041		65,420		364			(2,021		)	171,804
Operating Income	9,593		5,181		271			—			15,045
Net Economic Earnings	4,597		3,605		694			—			8,896
Total assets	1,640,101		186,394		150,117			(235,274		)	1,741,338

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			Gas
(Thousands)	Gas Utility		Marketing		Other			Eliminations			Consolidated
Nine Months Ended June 30, 2013
Revenues from external customers	$	735,726	$	129,937	$	4,242		$	—		$	869,905
Intersegment revenues	10,517		13,928		1,124			(25,569		)	—
Total Operating Revenues	746,243		143,865		5,366			(25,569		)	869,905
Operating Expenses
Gas Utility
Natural and Propane Gas	435,329		—		—			(25,140		)	410,189
Other Operation and Maintenance Expenses	122,936		—		—			309			123,245
Depreciation and Amortization	33,742		—		—			—			33,742
Taxes, Other than Income Taxes	49,525		—		—			—			49,525
Total Gas Utility Operating Expenses	641,532		—		—			(24,831		)	616,701
Gas Marketing	—		133,959		—			—			133,959
Other	—		—		13,767			(738		)	13,029
Total Operating Expenses	641,532		133,959		13,767			(25,569		)	763,689
Operating Income	104,711		9,906		(8,401		)	—			106,216
Net Economic Earnings (Losses)	62,372		7,281		(742		)	—			68,911
Total assets	1,766,198		220,162		584,488			(148,809		)	2,422,039
Nine Months Ended June 30, 2012
Revenues from external customers	$	665,981	$	288,036	$	1,920		$	—		$	955,937
Intersegment revenues	1,178		9,125		778			(11,081		)	—
Total Operating Revenues	667,159		297,161		2,698			(11,081		)	955,937
Operating Expenses
Gas Utility
Natural and Propane Gas	375,634		—		—			(11,078		)	364,556
Other Operation and Maintenance Expenses	125,028		—		—			—			125,028
Depreciation and Amortization	30,450		—		—			—			30,450
Taxes, Other than Income Taxes	45,602		—		—			—			45,602
Total Gas Utility Operating Expenses	576,714		—		—			(11,078		)	565,636
Gas Marketing	—		279,787		—			(3		)	279,784
Other	—		—		1,784			—			1,784
Total Operating Expenses	576,714		279,787		1,784			(11,081		)	847,204
Operating Income	90,445		17,374		914			—			108,733
Net Economic Earnings	51,448		9,589		1,179			—			62,216
Total assets	1,640,101		186,394		150,117			(235,274		)	1,741,338

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Reconciliation of Consolidated Net Economic Earnings to Consolidated Net Income
	Three Months Ended						Nine Months Ended
	June 30,						June 30,
(Thousands)	2013			2012			2013			2012
Total Net Economic Earnings above	$	8,164		$	8,896		$	68,911		$	62,216
Add: Unrealized gain (loss) on energy-related derivative
contracts, net of tax	304			(963		)	(722		)	1,281
Add:  Lower of cost or market inventory
adjustments, net of tax	(559		)	494			(559		)	(68		)
Add:  Realized gain (loss) on economic hedges prior to sale of
the physical commodity, net of tax	3			6			25			(138		)
Add:  Acquisition, divestiture, and restructuring activities,
net of tax	(1,327		)	—			(5,261		)	—
Net Income	$	6,585		$	8,433		$	62,394		$	63,291

12.        COMMITMENTS AND CONTINGENCIES

Commitments

Laclede Gas and LER have entered into various contracts, expiring on dates through fiscal year 2018, for the storage, transportation, and supply of natural gas. Minimum payments required under the contracts in place at June 30, 2013 are estimated at approximately $321 million. Additional contracts are generally entered into prior to or during the heating season. Laclede Gas recovers its costs from customers in accordance with the PGA Clause.

During 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 June 30, 2013, the Company was contractually committed to costs of approximately $1.5 million related to this project. The final phase of the project was implemented in July 2013.

Refer to Note 13, Acquisition Agreements, for information about Laclede Group's commitments associated with the pending acquisitions of substantially all of the assets and liabilities of Missouri Gas Energy (MGE) and New England Gas Company (NEG) and the subsequent agreement with Algonquin Power & Utilities Corp. (APUC) that will allow an APUC subsidiary to acquire the Company's rights to purchase the assets of NEG.

Contingencies

Laclede Gas owns and operates natural gas distribution, transmission, and storage facilities, the operations of which are subject to various environmental laws, regulations, and interpretations. While environmental issues resulting from such operations arise in the ordinary course of business, such issues have not materially affected the Company’s or Laclede Gas’ financial position and results of operations. As environmental laws, regulations, and their interpretations change, however, Laclede Gas may be required to incur additional costs.

Similar to other natural gas utility companies, Laclede Gas 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/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.

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

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One of the sites located in the City of St. Louis is currently owned by a development agency of the City, which, together with other City development agencies, has selected a developer to redevelop the site. In conjunction with this redevelopment effort, Laclede Gas and another former owner of the site entered into an agreement (Remediation Agreement) with the City development agencies, the developer, and an environmental consultant that obligates one of the City agencies and the environmental consultant to remediate the site and obtain a No Further Action letter from the Missouri Department of Natural Resources. The Remediation Agreement also provides for a release of Laclede Gas and the other former site owner from certain liabilities related to the past and current environmental condition of the site and requires the developer and the environmental consultant to maintain certain insurance coverages, including remediation cost containment, premises pollution liability, and professional liability. The operative provisions of the Remediation Agreement were triggered on December 20, 2010, on which date Laclede Gas and the other former site owner, as full consideration under the Remediation Agreement, paid a small percentage of the cost of remediation of the site. The amount paid by Laclede Gas did not materially impact the financial condition, results of operations, or cash flows of the Company.

Laclede Gas has not owned the other site located in the City of St. Louis for many years. In a letter dated June 29, 2011, the Attorney General for the State of Missouri informed Laclede Gas that the Missouri Department of Natural Resources had completed an investigation of the site. The Attorney General requested that Laclede Gas participate in the follow up investigations of the site. In a letter dated January 10, 2012, the Company 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. Further correspondence from the Missouri Attorney General dated April 12, 2012, and November 28, 2012, encouraged Laclede Gas and other present and former owners of the site to move forward with further site investigation for possible remediation via enrollment in the Missouri Department of Natural Resources Brownfields/Voluntary Cleanup Program (BVCP) in lieu of being subjected to enforcement action by the United States Environmental Protection Agency, Region VII. Accordingly, Laclede Gas and the other former and current owners of the site each have entered into, or are in the process of entering into, Provisional Cost Sharing and Environmental Response Agreements enabling Laclede Gas to enroll the property in the BVCP and to fund and conduct additional investigation of the property. Laclede Gas enrolled the site in the BVCP as of April 1, 2013.

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. Costs associated with environmental remediation activities are accrued when such costs are probable and reasonably estimable.

Laclede Gas 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 Laclede Gas or the Company.

The MoPSC Staff previously proposed disallowances related to Laclede Gas' recovery of its purchased gas costs totaling $6.0 million pertaining to Laclede Gas' purchase of gas from a marketing affiliate, LER, applicable to fiscal years 2005 through 2007. The MoPSC Staff also proposed a number of non-monetary recommendations, based on its review of gas costs for fiscal years 2008 through 2011. Laclede Gas believes that the proposed disallowances lack merit and is vigorously opposing these adjustments. In a related matter, on October 6, 2010, the MoPSC Staff filed a complaint against Laclede Gas alleging that Laclede Gas' affiliate transactions and its Cost Allocation Manual (CAM) violated the MoPSC's affiliate transaction rules. Laclede Gas responded with a counterclaim that the MoPSC Staff had failed to adhere to the affiliate transaction rules and the Company's CAM. On July 16, 2013, Laclede Gas, the MoPSC Staff and the Office of the Public Counsel requested MoPSC approval of a unanimous stipulation and agreement resolving the affiliate transaction matters for fiscal years 2005 through 2011, resolving the October 6, 2010 complaint, resolving Laclede Gas' counterclaim, presenting a revised CAM for MoPSC approval, and establishing standards of conduct for gas purchases and sales. The parties' request is pending before the MoPSC. Management, after discussion with counsel, continues to believe the final outcome of these matters will not have a material effect on the Company's financial position, results of operations, or cash flows.

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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. In light of such document production, Laclede Gas is currently in discussions with the MoPSC to resolve the penalty case. Management, after discussion with counsel, continues to believe the final outcome of these matters will not have a material effect on the Company's financial position, results of operations, or cash flows.

On June 29, 2010, the Office of Federal Contract Compliance Programs issued a Notice of Violations to Laclede Gas alleging lapses in certain employment selection procedures during a two-year period ending in February 2006. On July 2, 2013, Laclede Gas executed a Conciliation Agreement with the OFCCP in which the Company did not admit to liability, but agreed to provide make whole relief of back pay and interest to the impacted parties from 2004-2006. The OFCCP, as of the date of this report, has not yet executed the Conciliation Agreement. 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 8, Derivative Instruments and Hedging Activities, Laclede Gas and LER enter into NYMEX and ICE exchange-traded/cleared derivative instruments. Previously, these instruments were held in accounts at MF Global, Inc. On October 31, 2011, affiliated entities of MF Global filed a Chapter 11 petition at the U.S. Bankruptcy Court in the Southern District of New York. Subsequently, the court-appointed bankruptcy trustee transferred all of the open positions and a significant portion of the margin deposits of Laclede Gas and LER to a new brokerage firm. On June 27, 2013, the bankruptcy Trustee issued a statement projecting that MF Global customers would receive a full payout of their claims. As of July 30, 2013, Laclede Gas and LER had $0.9 million and $0.2 million, respectively, on deposit with MF Global.

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

13.    ACQUISITION AGREEMENTS

On December 14, 2012, Laclede Group entered into purchase and sale agreements, subject to customary closing adjustments, to acquire for $1.035 billion (collectively, the Transaction) from Southern Union Company (SUG), an affiliate of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P., substantially all of the assets and liabilities of SUG's MGE and NEG divisions (collectively, the Utilities). The Utilities are engaged in the distribution of natural gas on a regulated basis in western Missouri and in southeastern Massachusetts.

The Transaction is targeted to close before the end of fiscal year 2013, subject to customary closing conditions, including regulatory approvals from the MoPSC, which were obtained July 17, 2013, and the Massachusetts Department of Public Utilities (MDPU), which are pending. On January 22, 2013, the Federal Trade Commission notified the Company of the early termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. No shareholder approval is required to complete the Transaction, and each of the entities has received all necessary approvals from their boards of directors.

The purchase and sale agreements contain 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). In the event that SUG terminates the MGE acquisition agreement as a result of the failure of Laclede Group to obtain financing, the Company may be required to pay SUG a "reverse break up" fee of $73.1 million, which amount will operate as liquidated damages and a cap on such liability for such breach.

Laclede Group's agreement to acquire MGE for $975 million, via the newly formed wholly owned subsidiary Plaza Missouri Acquisition, Inc., was assigned by Laclede Group to Laclede Gas on January 11, 2013. Subsequently, on January 14, 2013, the Company filed an application with the MoPSC for approval to acquire the assets of MGE from SUG. On July 2, 2013, the Utility and other parties to the case filed a Unanimous Stipulation and Agreement with the MoPSC, which was approved on July 17, 2013, authorizing Laclede Gas' to acquire MGE, subject to certain conditions.

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Similarly, the agreement to acquire NEG for $60 million, including approximately $19.5 million of assumed NEG debt, is contracted through a second newly formed wholly owned subsidiary of Laclede Group, Plaza Massachusetts Acquisition, Inc. (Plaza Massachusetts). On February 11, 2013, the Company announced that it 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 rights to purchase the assets of NEG, subject to certain approvals and conditions. Under the terms of this agreement, the Company will receive $11 million from APUC at closing. Further, APUC has deposited $3.0 million in an escrow account that will be paid to SUG at closing. The sale of NEG to APUC is subject to approval from the MDPU, and a filing that was made by the Company and SUG with the MDPU on January 24, 2013, for approval of the acquisition of NEG, was amended on February 19, 2013 to include APUC. An evidentiary hearing was held on this matter during the last week of June 2013. Laclede Group remains obligated to acquire NEG in the event that APUC is not able to satisfy all conditions for closing on or before October 14, 2013, although the Company believes this scenario would be unlikely. The Company's agreement with APUC is not anticipated to impact the MGE transaction.

The Transaction is supported by existing company cash, including the proceeds received from Laclede Group's May 2013 public offering of common stock, and Laclede Group's fully committed bridge facility with Wells Fargo Bank, National Association. That bridge facility was syndicated to a group of nine financial institutions in January 2013. As a result of the Company's May 2013 equity offering and an amendment to the bridge facility in June 2013, the commitment under the facility was reduced from $1.020 billion to $525 million during the third quarter of fiscal year 2013. The Company anticipates permanent financing to be a combination of long-term debt and equity.

The Company continues to incur costs associated with the evaluation, approval and financing of the Transaction. During the three and nine months ended June 30, 2013, Laclede Group recorded $1.4 million and $5.3 million, respectively, net of tax, of third-party expenses associated with the Transaction.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

This management’s discussion analyzes the financial condition and results of operations of The Laclede Group, Inc. (Laclede Group or the Company) and its subsidiaries. It includes management’s view of factors that affect its business, explanations of past financial results including changes in earnings and costs from the prior year periods, and their effects on overall financial condition and liquidity.

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

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

• volatility in gas prices, particularly sudden and sustained changes in natural gas prices, including the related impact on margin deposits associated with the use of natural gas derivative instruments;

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

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

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

• allowed rates of return

• incentive regulation

• industry structure

• purchased gas adjustment provisions

• rate design structure and implementation

• regulatory assets

• non-regulated and affiliate transactions

• franchise renewals

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

• taxes

• pension and other postretirement benefit liabilities and funding obligations

• accounting standards, including the effect of potential changes relative to adoption of or convergence with international 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.

In addition, actual results may differ materially from those contemplated in any forward-looking statement due to the timing and likelihood of the closing of i) the purchase of substantially all of the assets and liabilities of Missouri Gas Energy (MGE) from Southern Union Company (SUG), ii) the Company's agreement with Algonquin Power & Utilities Corp. (APUC) to allow an APUC subsidiary to acquire the Company's rights to purchase the assets of New England Gas Company (NEG), and iii) the other factors discussed in "Risks Related To The Company's Acquisition Agreements With Southern Union Company And Algonquin Power & Utilities Corp." under Part II. Item 1A on page 51 of this Report. Refer to Acquisition Agreements on page 30 for additional information.

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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.

The Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the Company’s Consolidated Financial Statements and the Notes thereto.

ACQUISITION AGREEMENTS

In December 2012, Laclede Group, through two newly formed wholly owned subsidiaries, Plaza Missouri Acquisition, Inc. and Plaza Massachusetts Acquisition, Inc., entered into definitive purchase and sale agreements with SUG to acquire substantially all of the assets of MGE and NEG. On February 11, 2013, the Company announced that it entered into an agreement with APUC that will allow an APUC subsidiary to acquire the Company's rights to purchase the assets of NEG, subject to certain approvals and conditions. The Company's agreement with APUC is not expected to impact the MGE transaction. These transactions are targeted to be completed before the end of fiscal year 2013. The strategic rationale for Laclede Group is described below:

• With a larger market capitalization and enterprise value, the Company expects to have improved trading liquidity and better access to the capital markets. It plans to be able to support growth initiatives in new markets with new customers.

• Laclede Group will serve Missouri's two largest metropolitan areas in a state where it already has a working relationship with regulators.

• The acquisition of MGE is expected to be accretive to the Gas Utility Segment's net economic earnings in fiscal year 2014 and thereafter. The acquisition of MGE is expected to be immediately accretive to cash flow.

Completion of the pending transactions, including the agreement with APUC relative to NEG, is subject to customary closing conditions and regulatory approvals from the Massachusetts Department of Public Utilities. As discussed further in Regulatory and Other Matters, on July 2, 2013, the Company and other parties to the proceeding filed a Unanimous Stipulation and Agreement with the MoPSC which was approved on July 17, 2013 authorizing Laclede Gas to acquire MGE. No shareholder approval is required to complete the transaction, and each of the entities has received all necessary approvals from their boards of directors. On January 22, 2013, the Federal Trade Commission notified the Company of the early termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended.

The purchase and sale agreements contain certain termination rights for both Laclede Group and SUG, and further provide for the payment of fees and expenses upon termination under specified circumstances. For additional information relating to the pending acquisitions, see Note 13, Acquisition Agreements, of the Notes of the Consolidated Financial Statements. Also refer to the Company's Current Report on Form 8-K filed on December 17, 2012, January 18, 2013, January 24, 2013, July 18, 2013 and Exhibit 2.1 of Laclede Group's Form 10-Q for the quarter ended December 31, 2012. Subsequently, on January 11, 2013, the Company entered into an agreement to assign the MGE agreement to Laclede Group's Utility subsidiary, Laclede Gas, as described more fully in the Company's Form 8-K filed on January 14, 2013.

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RESULTS OF OPERATIONS

Overview

Laclede Group’s earnings are primarily derived from its Gas Utility segment, which reflects the regulated activities of its largest subsidiary, Laclede Gas, Missouri’s largest natural gas distribution company. Laclede Gas is regulated by the MoPSC and serves the City of St. Louis and parts of ten counties in eastern Missouri. Laclede Gas 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 lessens the impact of weather volatility on Laclede Gas’ 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 Laclede Gas, Laclede Group’s earnings are typically concentrated in the November through April period, which generally corresponds with the heating season.

Laclede Energy Resources, Inc. (LER), which includes its wholly owned subsidiary LER Storage Services, Inc. (LSS), is engaged in the marketing of natural gas and related activities on a non-regulated basis and is reported in the Gas Marketing segment. LER markets natural gas to both on-system Utility transportation customers and customers outside of Laclede Gas’ traditional service territory, including large retail and wholesale customers. LER’s operations and customer base are more subject to fluctuations in market conditions than the Utility. LSS has contracted storage capacity for 1 Bcf of natural gas through January 2014. Further, and separately, LSS has entered into a precedent agreement with a natural gas storage facility operator that is expected to provide 1 Bcf of natural gas storage beginning August 1, 2013.

Other subsidiaries provide less than 10% of consolidated revenues.

On July 3, 2013, the Company announced that Mark D. Waltermire, Laclede Group's Executive Vice President and Chief Financial Officer, will retire effective September 30, 2013, the end of the current fiscal year. On July 9, 2013, the Company announced that the board of directors named Steven P. Rasche, currently Senior Vice President of Finance and Accounting, as Laclede Group's Senior Vice President and Chief Financial Officer effective October 1, 2013.

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

Gas Utility Segment:

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

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

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

• 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.

Gas Marketing Segment:

• the risks of competition;

• fluctuations in natural gas prices;

• new national pipeline infrastructure projects;

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

• credit and/or capital market access;

• counterparty risks;

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

• additional growth.

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

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Laclede Gas continues to provide reliable natural gas service at a reasonable cost, while maintaining and building a secure and dependable infrastructure. The Utility’s strategy focuses on improving performance and mitigating the impact of weather fluctuations on Laclede Gas’ customers while improving 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 16,000 miles of mains and services comprising its natural gas distribution system and related storage facilities. The Utility’s distribution costs include wages and employee benefit costs, depreciation and maintenance expenses, and other regulated utility operating expenses, excluding natural and propane gas expense. Distribution costs are considered in the ratemaking process, and recovery of these types of costs is included in revenues generated through the Utility’s tariff rates, as approved by the Missouri Public Service Commission (MoPSC or Commission). The settlement of the Utility’s rate case in 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.

The Utility’s income from off-system sales and capacity release remains subject to fluctuations in market conditions. 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. 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 Laclede Gas’ 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 and there may be a demand for such supply in other markets. See the Regulatory and Other Matters section on page 42 of this report for additional information on regulatory issues relative to the Utility.

Laclede Gas 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 Laclede Gas to flow through to customers, subject to prudence review by the MoPSC, the cost of purchased gas supplies, including costs, cost reductions, and related carrying costs associated with the use of derivative instruments to hedge the purchase price of natural gas, as well as gas inventory carrying costs. The Utility believes it will continue to be able to obtain sufficient gas supply. The price of natural gas supplies and other economic conditions may affect sales volumes, due to the conservation efforts of customers, and cash flows associated with the timing of collection of gas costs and related accounts receivable from customers.

The Utility relies on both short-term credit and long-term capital markets, as well as cash flows from operations, to satisfy its seasonal cash requirements and fund its capital expenditures. Laclede Gas’ 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 44 for additional information.

LER provides both on-system Utility transportation customers and customers outside of Laclede Gas’ traditional service area with another choice in non-regulated natural gas suppliers. LER utilizes its natural gas supply agreements, transportation agreements, park and loan agreements, storage agreements, and other executory contracts to support a variety of services to its customers at competitive prices. It closely monitors and manages the natural gas commodity price and volatility risks associated with providing such services to its customers through the use of a variety of risk management activities, including the use of exchange-traded/cleared derivative instruments and other contractual arrangements. LER is committed to managing commodity price risk, while it seeks to expand the services that it now provides. Nevertheless, income from LER’s operations is more subject to fluctuations in market conditions than the Utility’s operations. LER’s business is directly impacted by the effects of competition in the marketplace, the impacts of new pipeline infrastructure and surplus natural gas supplies on natural gas commodity prices. Management expects that LER's net economic earnings (a non-GAAP measure, as discussed below) will continue to be negatively impacted by the expiration of favorable long-term natural gas supply contracts with the last such contract expiring on September 30, 2013. However, this impact is expected to be somewhat offset by the reduction in other fixed costs, including pipeline transportation charges. As a result of these changes, management anticipates that LER's net economic earnings will be approximately 40% lower in fiscal year 2014 compared to fiscal year 2013.

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

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

In response to new pipeline infrastructure and more abundant natural gas supplies, LER may have the opportunity to enter into subsequent offsetting purchase or sale transactions at the same location in order to satisfy its commitments without incurring fuel cost to transport natural gas to a different location. Thus, LER cannot be certain that all of its wholesale purchase and sale transactions will settle physically. As such, certain transactions entered into on or after January 1, 2012 are designated as trading activities for financial reporting purposes, due to their settlement characteristics, rather than elected for normal purchases or normal sales designations under generally accepted accounting principles (GAAP). Results of operations from trading activities are reported on a net basis (instead of a gross basis) in Gas Marketing Operating Revenues, which may cause reductions in and/or volatility in the Company’s operating revenues, but has no effect on operating income or net income.

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

EARNINGS

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

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

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

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

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

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

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

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

QUARTER ENDED JUNE 30, 2013

Net Income and Net Economic Earnings

Reconciliation of Consolidated Net Economic Earnings (Non-GAAP) to Consolidated Net Income (GAAP)
(Millions, except per share amounts)		Gas Utility		Gas Marketing			Other			Total			Per Share Amounts**
Quarter Ended June 30, 2013
	Net Income (Loss) (GAAP)	$	6.8	$	1.4		$	(1.6	)	$	6.6		$	0.25
	Unrealized (gain) loss on energy-related      derivatives*	—		(0.3		)	—			(0.3		)	(0.01		)
	Lower of cost or market inventory adjustments*	—		0.5			—			0.5			0.02
	Realized (gain) loss on economic hedges prior      to the sale of the physical commodity*	—		—			—			—			—
	Acquisition, divestiture and restructuring activities*	—		—			1.4			1.4			0.05
	Weighted Average Shares Adjustment**	—		—			—			—			0.05
	Net Economic Earnings (Losses) (Non-GAAP)	$	6.8	$	1.6		$	(0.2	)	$	8.2		0.36
Quarter Ended June 30, 2012
	Net Income (Loss) (GAAP)	$	4.6	$	3.2		$	0.6		$	8.4		0.38
	Unrealized (gain) loss on energy-related      derivatives*	0.1		0.9			—			1.0			0.04
	Lower of cost or market inventory adjustments*	—		(0.5		)	—			(0.5		)	(0.02		)
	Realized gain (loss) on economic hedges prior      to the sale of the physical commodity*	—		—			—			—			—
	Net Economic Earnings (Losses) (Non-GAAP)	$	4.7	$	3.6		$	0.6		$	8.9		0.40

* Amounts presented net of income taxes. Income taxes are calculated by applying federal, state, and local income tax rates applicable to ordinary income to the amounts of the pre-tax reconciling items. For the quarters ended June 30, 2013 and 2012, the total net amount of income tax (benefit) expense included in the reconciling items above is ($1.0) million and $(0.3) million, respectively.

** Net economic earnings per share is calculated by replacing consolidated net income with consolidated net economic earnings in the GAAP diluted earnings per share calculation. Also, net economic earnings per share exclude the impact of the May 2013 equity offering to fund the pending acquisition of MGE. The weighted-average diluted shares used in the net economic earnings per share calculation for the quarter ended June 30, 2013 was 22.5 million compared to 26.2 million in the GAAP EPS calculation.

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Laclede Group’s net income was $6.6 million for the quarter ended June 30, 2013, compared with $8.4 million for the quarter ended June 30, 2012. Basic and diluted earnings per share for the quarter ended June 30, 2013 were $0.25, compared with basic and diluted earnings per share of $0.38 for the quarter ended June 30, 2012. Earnings per share decreased compared to last year primarily due to lower net income reported by the Gas Marketing Segment, acquisition costs incurred this quarter totaling $1.4 million, net of tax, or $0.05 per share, associated with agreements to acquire certain assets and liabilities from SUG, as described previously, and the effect of higher weighted average shares outstanding attributable to the Company's May 2013 equity offering. These factors were partially offset by improved results reported by the Gas Utility Segment. Acquisition-related costs, among other items, are excluded from net economic earnings, which were $8.2 million for the quarter ended June 30, 2013, compared with $8.9 million for the same quarter last year. Net economic earnings per share were $0.36 for the quarter ended June 30, 2013, compared with $0.40 for the quarter ended June 30, 2012.

Gas Utility

Gas Utility net income and net economic earnings increased by $2.2 million and $2.1 million, respectively, for the quarter ended June 30, 2013, compared with the quarter ended June 30, 2012. The increase was primarily due to (on a pre-tax basis) higher operating margin (a non-GAAP measure, as discussed below) of $7.8 million and a reduction in interest charges related to the recognition of previously unrecognized tax benefits, totaling $0.6 million. These benefits were partially offset by higher operation and maintenance expenses totaling $3.7 million, and higher depreciation and amortization expenses totaling $1.3 million.

Gas Marketing

The Gas Marketing segment reported GAAP earnings totaling $1.4 million, a decrease of $1.8 million compared with the same quarter last year. Net economic earnings for the quarter ended June 30, 2013 decreased $2.0 million from the quarter ended June 30, 2012. The decreases in net income and net economic earnings were primarily attributable to decreases in operating margin, as discussed below. On a GAAP basis, LER's results reflect the effect of higher net unrealized gains from certain of LER's energy-related derivative contracts, largely offset by the impact of lower of cost or market inventory adjustments.

Other

Other net income and net economic earnings decreased $2.2 million and $0.8 million, respectively, compared with the same period last year. The decrease in net income is primarily due to expenses during the quarter ended June 30, 2013, attributable to the pending acquisition of MGE and NEG from SUG totaling $1.4 million, net of tax.

Operating Revenues and Operating Expenses

Laclede Group reported operating revenues of $165.3 million for the quarter ended June 30, 2013 compared with $186.8 million for the same period last year. Operating expenses were $153.0 million for the quarter, compared with $171.8 million last year. The decreases were primarily due to lower Gas Marketing operating revenues and expenses, partially offset by increased Gas Utility operating revenues and expenses, as discussed further below.

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. Operating margin is a non-GAAP financial measure defined as operating revenues less natural and propane gas expenses and associated gross receipts taxes that are billed to customers and expensed by the Company. This measure may not be comparable to the definition of operating margin used by others in the natural gas distribution business or other industries. Management believes that operating margin provides a meaningful basis for evaluating operating performance since the Utility's natural and propane gas costs and gross receipts tax expenses are included in operating revenues and passed through to customers and, therefore, have no effect on operating margin. Reconciliations of operating margin to the most directly comparable GAAP measure are shown below.

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(Millions)		Gas Utility			Gas Marketing			Other			Eliminations			Total
Quarter Ended June 30, 2013
	Operating Revenues	$	131.5		$	42.8		$	0.9		$	(9.9	)	$	165.3
	Natural and propane gas expense	52.8			39.7			—			(9.6		)	82.9
	Gross receipts tax expenses	8.2			—			—			—			8.2
	Operating margin (non-GAAP)	70.5			3.1			0.9			(0.3		)	74.2
	Add: Natural and propane gas expense	52.8			39.7			—			(9.6		)	82.9
	Add: Gross receipts tax expenses	8.2			—			—			—			8.2
	Less: Total Operating Expenses	(119.4		)	(40.6		)	(2.9		)	9.9			(153.0		)
	Operating income (GAAP)	$	12.1		$	2.2		$	(2.0	)	$	—		$	12.3
Quarter Ended June 30, 2012
	Operating Revenues	$	117.6		$	70.6		$	0.6		$	(2.0	)	$	186.8
	Natural and propane gas expense	48.7			64.2			—			(2.0		)	110.9
	Gross receipts tax expenses	6.2			—			—			—			6.2
	Operating margin (non-GAAP)	62.7			6.4			0.6			—			69.7
	Add: Natural and propane gas expense	48.7			64.2			—			(2.0		)	110.9
	Add: Gross receipts tax expenses	6.2			—			—			—			6.2
	Less: Total Operating Expenses	(108.0		)	(65.4		)	(0.4		)	2.0			(171.8		)
	Operating income (GAAP)	$	9.6		$	5.2		$	0.2		$	—		$	15.0

Laclede Group's operating margin increased $4.5 million for the quarter ended June 30, 2013, compared to the same period last year primarily due to higher Gas Utility operating margin, partially offset by lower operating margin reported by the Gas Marketing segment as discussed below.

Gas Utility

Laclede Gas passes on to Utility customers (subject to prudence review by the MoPSC) increases and decreases in the wholesale cost of natural gas in accordance with its PGA Clause. 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 margin and net income.

Operating Revenues - Gas Utility operating revenues for the quarter ended June 30, 2013 were $131.5 million, or $13.9 million more than the same period last year. Temperatures experienced in the Utility’s service area during the quarter ended June 30, 2013 were 101.9% colder than the same quarter last year and 22.2% colder than normal. Total system therms sold and transported were 122.7 million for the quarter ended June 30, 2013, compared with 97.1 million for the same period last year. Total off-system therms sold and transported were 18.2 million for the quarter ended June 30, 2013, compared with 51.4 million for the same period last year. The increase in Gas Utility operating revenues was primarily attributable to the following factors:

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(Millions)
Higher system sales volumes and other variations	$	23.0
Lower wholesale gas costs passed on to Utility customers (subject to prudence review by the MoPSC)	(7.5		)
Lower off-system sales volumes (reflecting less favorable market conditions as described in greater      detail in the Results of Operations - Overview)	(7.5		)
Higher prices charged for off-system sales	3.9
Higher ISRS revenues	2.0
Total Variation	$	13.9

Operating Expenses - Gas Utility operating expenses for the quarter ended June 30, 2013 increased $11.4 million from the same quarter last year. Natural and propane gas expense increased $4.1 million, or 8.6%, from last year’s level, primarily attributable to increased system volumes purchased for sendout, partially offset by lower prices charged by suppliers and lower off-system gas expense. Other operation and maintenance expense increased $3.7 million, or 9.7%, primarily due to increased charges for outside services, increased compensation expenses, higher employee benefit expenses, and other minor variations, partially offset by a lower provision for uncollectible accounts. Depreciation and amortization expense increased $1.3 million, or 13.1%, primarily due to additional depreciable property. Taxes, other than income taxes, increased $2.1 million, or 19.6%, primarily due to increased gross receipts taxes (attributable to increased system sales revenues).

Operating Margin - Gas Utility operating margin was $70.5 million for quarter ended June 30, 2013, a $7.8 million increase over the same period last year. The increase is primarily due to increased sales margins reflecting colder weather this year totaling $5.3 million, higher Infrastructure System Replacement Surcharge (ISRS) revenues totaling $2.0 million, and other minor variations of $0.5 million.

Gas Marketing

Operating Revenues and Operating Expenses - Gas Marketing operating revenues and operating expenses decreased $27.8 million and $24.8 million, respectively, primarily due to the effect of recording certain transactions on a net basis (instead of a gross basis) which had no effect on earnings, as described in greater detail in Results of Operations – Overview. The decreases were partially offset by higher per unit gas prices. Volumes purchased and sold were essentially unchanged from last year.

Operating Margin - Gas Marketing operating margin was $3.1 million for the quarter ended June 30, 2013, a $3.3 million decrease compared to the same period last year. The decrease in operating margin was primarily attributable to reduced sales margins, reflecting low price volatility and basis differentials in the current natural gas market, the expiration of a favorable supply contract, and lower of cost or market inventory adjustments. These decreases were partially offset by the effect of higher net unrealized gains from certain LER's energy-related derivative contracts of $1.2 million. As discussed in Results of Operations-Overview above, LER's future results are expected to continue to be impacted by the effects of the expiration of natural gas supply contracts.

Other

Other operating revenues and operating margin increased by $0.3 million during the quarter ended June 30, 2013. The increase in Other operating expenses, totaling $2.5 million, was primarily due to the acquisition expenses discussed above. Additional acquisition expenses are expected to be incurred prior to the closing of the Transaction.

Other Income and (Income Deductions) - Net

Other Income and (Income Deductions) - Net decreased $0.8 million primarily due to increased charitable donations, lower net investment gains, and other minor variations.

Interest Charges

Interest charges during the quarter ended June 30, 2013 increased $0.7 million from the same period last year primarily due to expenses associated with the Company's bridge loan facility and higher interest on long-term debt, partially offset by a reduction in interest charges related to the recognition of previously unrecognized tax benefits. The higher interest on long-term debt reflects the net effect of the December 2012 and March 2013 issuances of additional long-term debt of $25 million and $100 million, respectively, and the October 2012 maturity of $25 million of 6 1/2% first mortgage bonds. There were no short-term borrowings during the quarter ended June 30, 2013. Average short-term borrowings were $7.5 million for the quarter ended June 30, 2012 with an average interest rate of 0.3%.

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Income Taxes

The $2.5 million decrease in income taxes was primarily due to lower pre-tax income and various property-related deductions.

NINE MONTHS ENDEDJUNE 30, 2013

Net Income and Net Economic Earnings

Reconciliation of Consolidated Net Economic Earnings (Non-GAAP) to Consolidated Net Income (GAAP)
(Millions, except per share amounts)		Gas Utility		Gas Marketing			Unallocated & Other			Total			Per Share Amounts**
Nine Months Ended June 30, 2013
	Net Income (Loss) (GAAP)	$	62.3	$	6.1		$	(6.0	)	$	62.4		$	2.62
	Unrealized (gain) loss on energy-related      derivatives*	—		0.6			—			0.6			0.02
	Lower of cost or market inventory adjustments*	—		0.6			—			0.6			0.02
	Acquisition, divestiture and restructuring activities*	—		—			5.3			5.3			0.23
	Weighted Average Shares Adjustment**	—		—			—			—			0.15
	Net Economic Earnings (Losses) (Non-GAAP)	$	62.3	$	7.3		$	(0.7	)	$	68.9		$	3.04
Nine Months Ended June 30, 2012
	Net Income (Loss) (GAAP)	$	51.4	$	10.7		$	1.2		$	63.3		$	2.82
	Unrealized (gain) loss on energy-related      derivatives*	—		(1.3		)	—			(1.3		)	(0.06		)
	Lower of cost or market inventory adjustments*	—		0.1			—			0.1			—
	Realized gain (loss) on economic hedges prior      to the sale of the physical commodity*	—		0.1			—			0.1			0.01
	Net Economic Earnings (Losses) (Non-GAAP)	$	51.4	$	9.6		$	1.2		$	62.2		$	2.77

* Amounts presented net of income taxes. Income taxes are calculated by applying federal, state, and local income tax rates applicable to ordinary income to the amounts of the pre-tax reconciling items. For the nine months ended June 30, 2013 and 2012, the total net amount of income tax (benefit) expense included in the reconciling items above is ($4.0) million and $0.7 million, respectively.

** Net economic earnings per share is calculated by replacing consolidated net income with consolidated net economic earnings in the GAAP diluted earnings per share calculation. Also, net economic earnings per share exclude the impact of the May 2013 equity offering to fund the pending acquisition of MGE. The weighted-average diluted shares used in the net economic earnings per share calculation for the nine months ended June 30, 2013 was 22.5 million compared to 23.7 million in the GAAP EPS calculation.

Laclede Group’s net income was $62.4 million for the nine months ended June 30, 2013, compared with $63.3 million for the nine months ended June 30, 2012. Basic and diluted earnings per share for the nine months ended June 30, 2013 were $2.62, compared with basic and diluted earnings per share of $2.83 and $2.82, respectively, for the nine months ended June 30, 2012. Earnings increased compared to last year primarily due to improved results reported by Laclede Group's Gas Utility Segment, partially offset by acquisition costs incurred during the period totaling $5.3 million, net of tax, or $0.23 per share, associated with agreements to acquire certain assets and liabilities from SUG, as described previously. Additionally, earnings were impacted by decreased income from the Gas Marketing Segment. Acquisition-related costs, among other items, are excluded from net economic earnings, which were $68.9 million for the nine months ended June 30, 2013, compared with $62.2 million for the same period last year. Net economic earnings per share were $3.04 for the nine months ended June 30, 2013, compared with $2.77 for the nine months ended June 30, 2012.

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Gas Utility

Gas Utility net income and net economic earnings both increased by $10.9 million, respectively for the nine months ended June 30, 2013, compared with the nine months ended June 30, 2013. The increase was primarily due to (on a pre-tax basis) higher operating margin (a non-GAAP measure, as discussed below) of $15.7 million, a lower provision for uncollectible accounts totaling $3.2 million, and decreases in employee benefit expenses totaling $2.1 million. These benefits were partially offset by higher depreciation and amortization expenses totaling $3.3 million.

Gas Marketing

The Gas Marketing segment reported GAAP earnings totaling $6.1 million, a decrease of $4.6 million compared with the same period last year. Net economic earnings for the nine months ended June 30, 2013 decreased $2.3 million from the nine months ended June 30, 2012. The decreases in net income and net economic earnings was primarily attributable to decreases in operating margin, as discussed below. On a GAAP basis, LER's results were further impacted by the effect of higher net unrealized losses from certain of LER's energy-related derivative contracts and the impact of lower of cost or market inventory adjustments.

Other

Other net income and other net economic earnings decreased $7.2 million and $1.9 million, respectively, compared with the same period last year. The decrease in net income is primarily due to expenses during the nine months ended June 30, 2013, attributable to the pending acquisition of MGE and NEG from SUG totaling $5.3 million, net of tax, and other minor variations.

Operating Revenues and Operating Expenses

Laclede Group reported operating revenues of $869.9 million for the nine months ended June 30, 2013 compared with $955.9 million for the same period last year. Operating expenses were $763.7 million for the nine months end June 30, 2013, compared with $847.2 million last year. The decreases were primarily due to lower Gas Marketing operating revenues and expenses, partially offset by increased Gas Utility operating revenues and expenses, as discussed further below.

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 and discussed above. Reconciliations of operating margin to the most directly comparable GAAP measure are shown below.

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(Millions)		Gas Utility			Gas Marketing			Other			Eliminations			Total
Nine Months Ended June 30, 2013
	Operating Revenues	$	746.2		$	143.9		$	5.4		$	(25.6	)	$	869.9
	Natural and propane gas expense	435.3			130.3			1.4			(25.3		)	541.7
	Gross receipts tax expense	34.7			0.1			—			—			34.8
	Operating margin (non-GAAP)	276.2			13.5			4.0			(0.3		)	293.4
	Add: Natural and propane gas expense	435.3			130.3			1.4			(25.3		)	541.7
	Add: Gross receipts tax expense	34.7			0.1			—			—			34.8
	Less: Total Operating Expenses	(641.5		)	(134.0		)	(13.8		)	25.6			(763.7		)
	Operating income (GAAP)	$	104.7		$	9.9		$	(8.4	)	$	—		$	106.2
Nine Months Ended June 30, 2012
	Operating revenues	$	667.2		$	297.2		$	2.6		$	(11.1	)	$	955.9
	Natural and propane gas expense	375.6			276.2			—			(11.1		)	640.7
	Gross receipts tax expense	31.1			0.1			—			—			31.2
	Operating margin (non-GAAP)	260.5			20.9			2.6			—			284.0
	Add: Natural and propane gas expense	375.6			276.2			—			(11.1		)	640.7
	Add: Gross receipts tax expense	31.1			0.1			—			—			31.2
	Less: Total operating expenses	(576.7		)	(279.8		)	(1.8		)	11.1			(847.2		)
	Operating income (GAAP)	$	90.5		$	17.4		$	0.8		$	—		$	108.7

Laclede Group's operating margin increased $9.4 million for the nine months ended June 30, 2013, compared to the same period last year primarily due, to higher Gas Utility operating margin, partially offset by lower operating margin reported by the Gas Marketing segment as discussed below.

Gas Utility

Laclede Gas passes on to Utility customers (subject to prudence review by the MoPSC) increases and decreases in the wholesale cost of natural gas in accordance with its PGA Clause. 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 margin and net income.

Operating Revenues - Gas Utility operating revenues for the nine months ended June 30, 2013 were $746.2 million, or $79.0 million more than the same period last year. Temperatures experienced in the Utility’s service area during the nine months ended June 30, 2013 were 37.0% colder than the same period last year, and 0.2% colder than normal. Last year's temperatures were the warmest on record. Total system therms sold and transported were 796.8 million for the nine months ended June 30, 2013, compared with 640.8 million for the same period last year. Total off-system therms sold and transported were 229.4 million for the nine months ended June 30, 2013, compared with 279.7 million for the same period last year. The increase in Gas Utility operating revenues was primarily attributable to the following factors:

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(Millions)
Higher system sales volumes and other variations	$	97.3
Lower wholesale gas costs passed on to Utility customers (subject to prudence review by the MoPSC)	(28.6		)
Higher prices charged for off-system sales	20.1
Lower off-system sales volumes (reflecting less favorable market conditions as described in greater      detail in the Results of Operations - Overview)	(14.2		)
Higher ISRS revenues	4.4
Total Variation	$	79.0

Operating Expenses - Gas Utility operating expenses for the nine months ended June 30, 2013 increased $64.8 million from the same period last year. Natural and propane gas expense increased $59.7 million or 15.9%, from last year’s level, primarily attributable to increased system volumes purchased for sendout and higher off-system gas expense, partially offset by lower rates charged by our suppliers. Other operation and maintenance expenses decreased $2.1 million, or 1.7%, primarily due to a lower provision for uncollectible accounts, lower employee benefit expenses, a higher rate of overheads capitalized, and reduced customer accounts expenses, partially offset by increased charges for outside services. Depreciation and amortization expense increased $3.3 million, or 10.8%, primarily due to additional depreciable property. Taxes, other than income taxes, increased $3.9 million, or 8.6%, primarily due to increased gross receipts taxes (attributable to increased system sales revenues).

Operating Margin - Gas Utility operating margin was $276.2 million for the nine months ended June 30, 2013, a $15.7 million increase over the same period last year. The increase is primarily due to increased sales margins reflecting colder weather this year totaling $10.5 million, higher Infrastructure System Replacement Surcharge (ISRS) revenues totaling $4.4 million, and other minor variations of $0.8 million.

Gas Marketing

Operating Revenues and Operating Expenses - Gas Marketing operating revenues and operating expenses decreased $153.3 million and $145.8 million, respectively, primarily due to the effect of recording certain transactions on a net basis (instead of a gross basis) which had no effect on earnings, as described in greater detail in Results of Operations – Overview. The decreases were partially offset by higher per unit gas prices and increases in volumes purchased and sold.

Operating Margin - Gas Marketing operating margin was $13.5 million for the quarter ended June 30, 2013, a $7.4 million decrease compared to the same period last year. The decrease in operating margin was primarily attributable to reduced sales margins, reflecting low price volatility and basis differentials in the current natural gas market, the expiration of a favorable supply contract, higher net unrealized losses from certain LER's energy-related derivative contracts, and lower of cost or market inventory adjustments. These factors were partially offset by the effect of higher volumes purchased and sold. As discussed in Results of Operations-Overview above, LER's future results are expected to continue to be impacted by the effects of the expiration of natural gas supply contracts.

Other

Other operating revenues and operating margin increased by $2.8 million and $1.4 million, respectively, primarily due to a sale of propane inventory by Laclede Pipeline Company during the nine months ended June 30, 2013. The increase in Other operating expenses, totaling $12.0 million, was primarily due to the acquisition-related expenses discussed above and expenses associated with the aforementioned propane sale. Additional acquisition expenses are expected to be incurred prior to the closing of the Transaction.

Other Income and (Income Deductions) - Net

Other Income and (Income Deductions) - Net decreased $1.7 million primarily due to lower net investment gains, increased charitable donations, and other minor variations.

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Interest Charges

Interest charges during the nine months ended June 30, 2013 increased $0.8 million from the same period last year primarily due to expenses associated with the Company's bridge loan facility and higher interest on long-term debt, partially offset by a reduction in interest charges related to the recognition of previously unrecognized tax benefits. The higher interest on long-term debt reflects the net effect of the December 2012 and March 2013 issuances of additional long-term debt of $25 million and $100 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 the nine months ended June 30, 2013 and 2012. Average short-term borrowings were $40.6 million for the nine months ended June 30, 2013, compared with $52.6 million for the nine months ended June 30, 2012.

Income Taxes

The $4.2 million decrease in income taxes was primarily due to lower pre-tax income and various property-related deductions.

REGULATORY AND OTHER MATTERS

The MoPSC Staff previously proposed disallowances related to Laclede Gas' recovery of its purchased gas costs totaling $6.0 million pertaining to Laclede Gas' purchase of gas from a marketing affiliate, LER, applicable to fiscal years 2005 through 2007. The MoPSC Staff also proposed a number of non-monetary recommendations, based on its review of gas costs for fiscal years 2008 through 2011. Laclede Gas believes that the proposed disallowances lack merit and is vigorously opposing these adjustments. In a related matter, on October 6, 2010, the MoPSC Staff filed a complaint against Laclede Gas alleging that Laclede Gas' affiliate transactions and its Cost Allocation Manual (CAM) violated the MoPSC's affiliate transaction rules. Laclede Gas responded with a counterclaim that the MoPSC Staff had failed to adhere to the affiliate transaction rules and the Company's CAM. On July 16, 2013, Laclede Gas, the MoPSC Staff and the Office of the Public Counsel requested MoPSC approval of a unanimous stipulation and agreement resolving the affiliate transaction matters for fiscal years 2005 through 2011, resolving the October 6, 2010 complaint, resolving Laclede Gas' counterclaim, presenting a revised CAM for MoPSC approval, and establishing standards of conduct for gas purchases and sales. The parties' request is pending before the MoPSC. Management, after discussion with counsel, continues to believe the final outcome of these matters will not have a material effect on the Company's financial position, results of operations, or cash flows.

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. In light of such document production, Laclede Gas is currently in discussions with the MoPSC to resolve the penalty case. Management, after discussion with counsel, continues to believe the final outcome of these matters will not have a material effect on the Company's financial position, results of operations, or cash flows.

On December 21, 2012, Laclede Gas filed tariff sheets in a new general rate case proceeding that were designed to increase the Utility's total revenues by $58.4 million, less the current annualized ISRS revenues of $10 million that were already being recovered from customers. On December 27, 2012, the MoPSC suspended implementation of the Utility's proposed rates and set the case for hearing in August 2013. However, on June 26, 2013, the MoPSC approved a Unanimous Stipulation and Agreement in which the Utility will incorporate its current annualized ISRS revenues of $14.8 million into its base rates, effective September 1, 2013. At that time, the ISRS charge will be reset to zero, and the Utility will be permitted to make future ISRS filings for any qualifying expenditures incurred by the Utility after January 31, 2013.

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On January 14, 2013, the Company filed an application with the MoPSC for approval to acquire the assets of MGE from SUG as reported in the Acquisition Agreements section on page 30. On July 2, 2013, the Utility and other parties to the proceeding filed a Unanimous Stipulation and Agreement (Agreement) with the MoPSC resolving all matters in the case, which was approved by the Commission on July 17, 2013. The Agreement authorizes Laclede Gas to acquire MGE and obtain the necessary financing, subject to various conditions set forth in the Agreement. Under the Agreement, Laclede Gas would generally be precluded from filing a general rate case for either its Laclede or MGE Divisions prior to October 1, 2015, except that a general rate case for the MGE service territory may be filed no later than September 18, 2013. ISRS filings and the collection of gas costs under the PGA Clause would not be impacted. The Agreement also allows for the deferral for future recovery of a portion of one-time costs incurred associated with the integration of MGE. The Agreement sets forth a number of other conditions including those related to credit ratings, gas supply, service quality, gas safety, and reporting requirements.

A filing was made with the Massachusetts Department of Public Utilities (MDPU) on January 24, 2013 for approval of the acquisition of NEG. An evidentiary hearing was held on this matter during the last week of June 2013.

On January 14, 2013, the Utility made an ISRS filing with the Commission and an increase of $4.8 million was approved by the MoPSC effective March 15, 2013.

On June 29, 2010, the Office of Federal Contract Compliance Programs issued a Notice of Violations to Laclede Gas alleging lapses in certain employment selection procedures during a two-year period ending in February 2006. On July 2, 2013, Laclede Gas executed a Conciliation Agreement with the OFCCP in which the Company did not admit to liability, but agreed to provide make whole relief of back pay and interest to the impacted parties from 2004-2006. The OFCCP, as of the date of this report, has not yet executed the Conciliation Agreement. 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.

CRITICAL ACCOUNTING POLICIES

Our discussion and analysis of our financial condition, results of operations, liquidity, and capital resources is based upon our consolidated financial statements, which have been prepared in accordance with GAAP. GAAP requires that we make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We evaluate our estimates on an ongoing basis. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates. Our critical accounting policies used in the preparation of our Consolidated Financial Statements are described in Item 7 of our Annual Report on Form 10-K for the fiscal year ended September 30, 2012 and include the following:

• Accounts receivable and allowance for doubtful accounts

• Employee benefits and postretirement obligations

• Regulated operations

• Non-Regulated Gas Marketing Energy Contracts

There were no significant changes to these critical accounting policies during the nine months ended June 30, 2013.

For discussion of other significant accounting policies, see Note 1 of the Notes to Consolidated Financial Statements included in the Company’s Form 10-K for the fiscal year ended September 30, 2012.

ACCOUNTING PRONOUNCEMENTS

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

The Company continues to monitor the developments of the Financial Accounting Standards Board (FASB) relative to possible changes in accounting standards. Currently, the FASB is considering various changes to U. S. GAAP, some of which may be significant, as part of a joint effort with the International Accounting Standards Board to converge accounting standards.

Future developments, depending on the outcome, have the potential to impact the Company’s financial condition and results of operations.

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FINANCIAL CONDITION

CASH FLOWS

The Company’s short-term borrowing requirements typically peak during colder months when Laclede Gas 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 can cause significant variations in the Utility’s cash provided by or used in operating activities.

Net cash provided by operating activities was $167.0 million for the nine months ended June 30, 2013, compared with $128.2 million for the same period last year. The variation is primarily associated with the timing of collections of gas cost under the Utility’s PGA Clause, primarily due to reduced 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 advance customer billings.

Net cash used in investing activities for the nine months ended June 30, 2013 was $99.4 million, compared with $78.2 million for the nine months ended June 30, 2012. The variation primarily reflects additional capital expenditures this year for distribution plant and information technology investments.

Net cash provided by financing activities was $461.4 million for the nine months ended June 30, 2013, compared with net cash used in financing activities of $71.8 million for the nine months ended June 30, 2012. The variation primarily reflects the May 2013 common stock offering and the issuance of additional long-term debt this year, partially offset by the maturity of long-term debt and increased repayments of short-term borrowings.

LIQUIDITY AND CAPITAL RESOURCES

Cash and Cash Equivalents

Laclede Group had temporary cash investments totaling $546.8 million at June 30, 2013, earning an average interest rate of 0.1%. This includes $27.4 million held by Laclede Gas, also at an average interest rate of 0.1%. These investments, which are presented in the Cash and cash equivalents line of the Consolidated Balance Sheets, were diversified among money market funds, commercial paper, and interest-bearing deposits at highly-rated commercial banks. The money market funds are accessible by the Company on demand. The bank deposits are also generally available on demand, though the banks reserve the right to require seven days’ notice for a withdrawal. The commercial paper has a maximum remaining maturity of one month. These funds are used to support the working capital needs of the Company’s subsidiaries. The balance of short-term investments ranged between $10.4 million and $583.5 million during the nine months ended June 30, 2013. Due to lower yields available to Laclede Group on its short-term investments, Laclede Group elected to provide a portion of Laclede Gas’ short-term funding through intercompany lending during the nine months ended June 30, 2013, but there were no such borrowings at June 30, 2013.

Short-term Debt

As indicated in the discussion of cash flows above, the Company’s short-term borrowing requirements typically peak during the colder months. These short-term cash requirements can be met through the sale of commercial paper supported by lines of credit with banks or through direct use of the lines of credit. At June 30, 2013, Laclede Gas had a syndicated line of credit in place of $300 million from seven banks, $257.1 million of which is scheduled to expire in July 2017 and $42.9 million of which is scheduled to expire in July 2016. The largest portion provided by a single bank is 17.9%. Laclede Gas’ line of credit includes a covenant limiting total debt, including short-term debt, to no more than 70% of total capitalization. As a result of certain amendments made on January 16, 2013, this maximum percentage will temporarily increase to 72.5% if the MGE acquisition is consummated. Such temporary increase would be effective from the date of consummation through September 30, 2014. As defined in the line of credit, total debt was 46% of total capitalization on June 30, 2013.

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Short-term cash requirements outside of Laclede Gas have generally been met with internally generated funds. However, Laclede Group has $50 million in a syndicated line of credit, $42.9 million of which expires in July 2017 and $7.1 million of which expires in July 2016, to meet short-term liquidity needs of its subsidiaries. The line of credit has a covenant limiting the total debt of the consolidated Laclede Group to no more than 70% of the Company’s total capitalization. As a result of certain amendments made on January 16, 2013, this maximum percentage will temporarily increase to 72.5% if the MGE acquisition is consummated. Such temporary increase would be effective from the date of consummation through September 30, 2014. As defined in the line of credit, this ratio stood at 30% on June 30, 2013. Occasionally, Laclede Group’s lines may be used to provide for the funding needs of various subsidiaries. There were no borrowings under Laclede Group’s lines during the nine months ended June 30, 2013.

To support the liquidity needs of the Company following the MGE acquisition, Laclede Group and Laclede Gas plan to enter into new expanded credit facilities at or just prior to the closing of the MGE acquisition.

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

	Commercial Paper Borrowings
Nine Months Ended June 30, 2013
Weighted average borrowings outstanding	$40.6 million
Weighted average interest rate	0.3%
Range of borrowings outstanding	$0.0 - $99.4 million
As of June 30, 2013
Borrowings outstanding at end of period	None
Weighted average interest rate	N/A

Based on average short-term borrowings for the nine months ended June 30, 2013, an increase in the average interest rate of 100 basis points would decrease Laclede Group’s pre-tax earnings and cash flows by approximately $0.4 million on an annual basis, portions of which may be offset through the application of PGA carrying costs.

Long-term Debt, Equity, and Shelf Registrations

On March 15, 2013, Laclede Gas 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. Laclede Group issued $25 million of 3.31% 10-year unsecured notes in a private placement on December 14, 2012, which had also been committed to in August 2012. The proceeds were used for the repayment of short-term debt and general corporate purposes.

On May 29, 2013 the Laclede Group received cash of approximately $428 million from the issuance of 10,005,000 common shares to fund a portion of the purchase of MGE. These funds have been invested in high-quality, short-term instruments until the acquisition closes.

Laclede Gas had on file with the SEC an effective shelf registration on Form S-3 for issuance of $350 million of first mortgage bonds, unsecured debt, and preferred stock, that expired May 28, 2013.

The Utility has MoPSC authority to issue debt securities and preferred stock, including on a private placement basis, as well as to issue common stock, receive paid-in capital, and enter into capital lease agreements, all for a total of up to $518 million. This authorization was originally effective through June 30, 2013. In August 2012, Laclede Gas filed a request with the MoPSC to extend this authority for an additional two years, to June 30, 2015. This extension became effective on November 23, 2012. During the nine months ended June 30, 2013, pursuant to this authority, the Utility sold 48 shares of its common stock to Laclede Group for $1.9 million. As of July 26, 2013, $371.1 million remains available under this authorization. As part of the MoPSC's approval of the acquisition of MGE on July 17, 2013, Laclede Gas was granted authorization to issue debt and equity securities of up to $1.020 billion to finance the MGE Acquisition at any time beginning July 31, 2013 and ending one year after closing of the transaction. The amount, timing, and type of additional financing to be issued, including in connection with the MGE and NEG acquisitions as described below, will depend on cash requirements and market conditions, as well as future MoPSC authorizations.

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On October 15, 2012, Laclede Gas paid at maturity $25 million principal amount of 6 1/2% first mortgage bonds. At June 30, 2013, Laclede Gas had fixed-rate long-term debt totaling $440 million. 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 Laclede Gas were to reacquire any of these issues in the open market prior to maturity. Under GAAP applicable to Laclede Gas’ 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 $440 million in long-term debt, $25 million have no call option, $335 million have make-whole call options, and $80 million are callable at par on or after October 15, 2013. None of the debt has any put options.

Additionally, as of June 30, 2013, Laclede Group had fixed-rate long-term debt totaling $25 million, which is subject to changes in its fair value as market interest rates change. However, increases or decreases in fair value would impact earnings and cash flows only if Laclede Group were to reacquire any of these issues in the open market prior to maturity. This debt has a make-whole call option.

Laclede Group has a registration statement on file on Form S-3 for the issuance and sale of up to 285,222 shares of its common stock under its Dividend Reinvestment and Stock Purchase Program. There were 201,907 and 195,076 shares at June 30, 2013 and July 25, 2013, respectively, remaining available for issuance under its Form S-3. Laclede Group also has an automatic shelf registration statement on Form S-3 for the issuance of equity and debt securities. No securities have been issued under that S-3. The amount, timing, and type of financing to be issued under this shelf registration will depend on cash requirements and market conditions.

In December 2012, Laclede Group announced agreements to acquire the assets of MGE and NEG for $1.015 billion, net of $19.5 million in assumed debt. Simultaneously, Laclede Group entered into a fully committed bridge facility for $1.020 billion with Wells Fargo Bank, National Association in order to fund these acquisitions. The bridge facility was syndicated by Wells Fargo Securities, LLC, to a group of nine banks, effective on January 16, 2013. As described in further in Acquisition Agreements, on February 11, 2013, the Company announced that it entered into an agreement with APUC that will allow an APUC subsidiary to acquire the Company's rights to purchase the assets of NEG. On May 29, 2013, in order to finance a portion of the acquisition, Laclede Group issued 10,005,000 shares of common stock for net proceeds of approximately $428 million. As a result of the equity offering and an amendment made to the bridge facility in June 2013, the commitment under the bridge facility was reduced to $525 million during the quarter ended June 30, 2013. The remainder of the purchase price is expected to be funded with long-term debt of Laclede Gas and/or Laclede Group, short-term debt, and cash on hand. Laclede Group has entered into interest rate hedges for approximately 79% of the expected long-term debt issuance to protect against the impacts of adverse movements in rates. Additional interest rate hedging may be done either by Laclede Gas or Laclede Group prior to completing the debt financing.

Other

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

Utility capital expenditures were $96.0 million for the nine months ended June 30, 2013, compared with $75.0 million for the same period last year. The increase in capital expenditures, compared with the prior period, is primarily attributable to additional expenditures for distribution plant and information technology investments. During fiscal 2011, Laclede Gas began a multi-year project to enhance its technology, customer service, and business processes by replacing its existing customer relationship and work management, financial, and supply chain software applications. The final phase of the project was implemented in July 2013. Non-utility capital expenditures were $0.9 million and $1.8 million during the nine months ended June 30, 2013 and 2012.

Consolidated capitalization at June 30, 2013 consisted of 70.0% common stock equity and 30.0% long-term debt.

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

The seasonal nature of Laclede Gas’ sales affects the comparison of certain balance sheet items at June 30, 2013 and at September 30, 2012, such as Accounts receivable - net, Gas stored underground, Notes payable, Accounts payable, Regulatory assets and Regulatory liabilities, and Delayed and Advance customer billings. The Consolidated Balance Sheet at June 30, 2012 is presented to facilitate comparison of these items with the corresponding interim period of the preceding fiscal year.

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CONTRACTUAL OBLIGATIONS

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

			Payments due by period
Contractual Obligations	Total		Remaining Fiscal Year 2013		Fiscal Years 2014-2015		Fiscal Years 2016-2017		Fiscal Years 2018 and thereafter
Principal Payments on Long-Term Debt	$	465.0	$	—	$	—	$	—	$	465.0
Interest Payments on Long-Term Debt	465.7		4.0		50.7		50.6		360.4
Capital Leases (a)	0.2		0.1		0.1		—		—
Operating Leases (a)	10.6		1.2		7.5		1.8		0.1
Purchase Obligations – Natural Gas (b)	321.3		135.4		161.7		20.7		3.5
Purchase Obligations – Other (c)	80.7		15.4		26.3		18.5		20.5
Total (d) (e)	$	1,343.5	$	156.1	$	246.3	$	91.6	$	849.5

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

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

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

(d) The category of Other Long-Term Liabilities has been excluded from the table above because there are no material amounts of contractual obligations under this category. Long-term liabilities associated with unrecognized tax benefits, totaling $2.9 million, have been excluded from the table above because the timing of future cash outflows, if any, cannot be reasonably estimated. Also, commitments related to pension and postretirement benefit plans have been excluded from the table above. The Company does not expect to make any contributions to its qualified trusteed pension plans during the remaining three months of fiscal year 2013. Laclede Gas anticipates a $0.8 million contribution relative to its non-qualified pension plans during the remaining three months of fiscal year 2013. With regard to the postretirement benefits, the Company anticipates Laclede Gas will contribute $8.2 million to the qualified trusts and $0.2 million directly to participants from Laclede Gas’ funds during the remaining three months of fiscal year 2013. For further discussion of the Company’s pension and postretirement benefit plans, refer to Note 2, Pension Plans and Other Postretirement Benefits, of the Notes to Consolidated Financial Statements.

(e) The table above does not include the Company's potential payment of a "reverse break up" fee of $73.1 million that would be due in the event that SUG terminates the MGE acquisition agreement as a result of the failure of Laclede Group to obtain financing. See Note 13, Acquisition Agreements, of the Notes to Consolidated Financial Statements for further details. Also, the table does not include any anticipated additional long-term debt to finance the acquisitions.

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MARKET RISK

Commodity Price Risk

Laclede Gas’ commodity price risk, which arises from market fluctuations in the price of natural gas, is primarily managed through the operation of its PGA Clause. The PGA Clause allows Laclede Gas to flow through to customers, subject to prudence review by the MoPSC, the cost of purchased gas supplies. The Utility is allowed the flexibility to make up to three discretionary PGA changes during each year, in addition to its mandatory November PGA change, so long as such changes are separated by at least two months. The Utility is able to mitigate, to some extent, changes in commodity prices through the use of physical storage supplies and regional supply diversity. Laclede Gas also has a risk management policy that allows 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. This policy prohibits 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, Laclede Gas 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 8, Derivative Instruments and Hedging Activities, of the Notes to Consolidated Financial Statements.

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

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

(Thousands)	Derivative Fair Values			Cash Margin			Derivatives and Cash Margin
Net balance of derivative (liabilities) assets at September 30, 2012	$	(3,515	)	$	5,489		$	1,974
Changes in fair value	3,651			—			3,651
Settlements/purchases - net	4,782			—			4,782
Changes in cash margin	—			(7,577		)	(7,577		)
Net balance of derivative assets (liabilities) at June 30, 2013	$	4,918		$	(2,088	)	$	2,830

	At June 30, 2013
	Maturity by Fiscal Year
(Thousands)	Total			2013			2014			2015
Fair values of exchange-traded/cleared natural gas derivatives - net	$	4,918		$	2,629		$	2,275		$	14
MMBtu – net (short) long futures/swap/option positions	(11,893		)	(5,363		)	(6,495		)	(35		)

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Certain of LER’s physical natural gas derivative contracts are designated as normal purchases or normal sales, as permitted by GAAP. This election permits the Company to account for the contract in the period the natural gas is delivered. Contracts not designated as normal purchases or normal sales, including those designated as trading activities, are accounted for as derivatives with changes in fair value recognized in earnings in the periods prior to settlement. Below is a reconciliation of the beginning and ending balances for physical natural gas contracts accounted for as derivatives, none of which will settle beyond fiscal year 2015:

(Thousands)
Net balance of derivative assets at September 30, 2012	$	2,741
Changes in fair value	(556		)
Settlements	(2,156		)
Net balance of derivative assets at June 30, 2013	$	29

For further details related to LER’s derivatives and hedging activities, see Note 8, Derivative Instruments and Hedging Activities, of the Notes to Consolidated Financial Statements.

Counterparty Credit Risk

LER has concentrations of counterparty credit risk in that a significant portion of its transactions are with (or are associated with) energy producers, utility companies, and pipelines. These concentrations of counterparties have the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that each of these three groups may be affected similarly by changes in economic, industry, or other conditions. LER also has concentrations of credit risk with certain individually significant counterparties. To the extent possible, LER enters into netting arrangements with its counterparties to mitigate exposure to credit risk. Although not recorded on the consolidated balance sheets, LER is also exposed to credit risk associated with its derivative contracts designated as normal purchases and normal sales. LER closely monitors its credit exposure and, although uncollectible amounts have not been significant, increased counterparty defaults are possible and may result in financial losses and/or capital limitations. For more information on these concentrations of credit risk, including how LER manages these risks, see Note 9, Concentrations of Credit Risk, of the Notes to Consolidated Financial Statements.

Interest Rate Risk

The Company is subject to interest rate risk associated with its long-term and short-term debt issuances. Based on average short-term borrowings during the nine months ended June 30, 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 $0.4 million on an annual basis. Portions of such increases may be offset through the application of PGA carrying costs. At June 30, 2013, Laclede Gas had fixed-rate long-term debt totaling $440 million. Additionally, Laclede Group had fixed-rate long-term debt totaling $25 million. While these long-term debt issues are fixed-rate, they are subject to changes in fair value as market interest rates change. However, increases or decreases in fair value would impact earnings and cash flows only if the Company were to reacquire any of these issues in the open market prior to maturity. Under GAAP applicable to Laclede Gas’ regulated operations, losses or gains on early redemptions of its long-term debt would typically be deferred as regulatory assets or regulatory liabilities and amortized over a future period.

The Company has entered into certain interest rate swap transactions to protect itself against adverse movements in interest rates associated with its anticipated issuance of long-term debt to fund the acquisition of MGE. Refer to Note 8, Derivative Instruments and Hedging Activities, of the Notes to Consolidated Financial Statements for additional details on these interest rate swap transactions.

ENVIRONMENTAL MATTERS

Laclede Gas owns and operates natural gas distribution, transmission and storage facilities, the operations of which are subject to various environmental laws, regulations and interpretations. While environmental issues resulting from such operations arise in the ordinary course of business, such issues have not materially affected the Company’s or Laclede Gas’ financial position and results of operations. As environmental laws, regulations, and their interpretations change, however, Laclede Gas may be required to incur additional costs. For information relative to environmental matters, see Note 12, Commitments and Contingencies, of the Notes to Consolidated Financial Statements.

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OFF-BALANCE SHEET ARRANGEMENTS

Laclede Group has no off-balance sheet arrangements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

For this discussion, see Part I., Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Risk, on page 48 of this report.

Item 4. 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 our 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.

There have been no changes in our internal control over financial reporting that occurred during our third fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. However, as management has not yet completed all of its testing of the operating effectiveness of all controls related to a significant system implementation that occurred earlier in the year, it will continue to evaluate the operating effectiveness of key controls during subsequent periods.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For a description of environmental matters and legal proceedings, see Note 12, Commitments and Contingencies, of the Notes to Consolidated Financial Statements. For a description of pending regulatory matters of Laclede Gas, see Part I., Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Regulatory and Other Matters, on page 42 of this report.

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

Item 1A. Risk Factors

The following paragraphs should be read in conjunction with the risk factors included in Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended September 30, 2012.

RISKS RELATED TO THE COMPANY'S ACQUISITION AGREEMENTS WITH SOUTHERN UNION COMPANY AND ALGONQUIN POWER & UTILITIES CORP.

The transactions 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 two newly formed wholly owned subsidiaries, Plaza Missouri Acquisition, Inc. (Plaza Missouri) and Plaza Massachusetts Acquisition, Inc. (Plaza Massachusetts), entered into acquisition agreements to acquire from Southern Union Company (SUG) substantially all of the assets and liabilities of Missouri Gas Energy (MGE) and New England Gas Company (NEG). Subsequently, on January 11, 2013, the Company and Plaza Missouri, with consent of SUG, entered into an agreement with Laclede Gas to assign the MGE agreement to Laclede Gas. On February 11, 2013, the Company announced that it 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. However, the Company remains obligated to acquire NEG in the event that APUC is not able to satisfy all conditions to closing on or before October 14, 2013, although the Company believes this scenario would be unlikely. The Company's agreement with APUC is not expected to impact the MGE transaction. Nonetheless, there can be no assurance that APUC will be able to satisfy all of the required conditions on or before this date.

On July 2, 2013, the Utility and other parties to the case filed a Unanimous Stipulation and Agreement with the Missouri Public Service Commission (MoPSC) that authorizes Laclede Gas to complete the acquisition of MGE, subject to certain conditions, including restrictions relative to the timing of filing for general rate increases. This Unanimous Stipulation and Agreement was approved by the MoPSC on July 17, 2013. Although the MoPSC approval satisfies one of the closing conditions under the MGE acquisition agreement, the closing remains subject to the satisfaction or waiver of all conditions precedent as described in the MGE acquisition agreement, including the ability to close the NEG transaction concurrently with the MGE acquisition. 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. If the NEG transaction is not closed or capable of closing or SUG does not waive such condition, the closing of the MGE acquisition would be delayed until the conditions precedent to the NEG transaction are satisfied, including the condition of MDPU approval. There can be no assurance as to the receipt or timing of the necessary MDPU approvals or any waivers from SUG.

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In addition, the acquisition agreements contain other customary closing conditions which may not be satisfied or waived or may take longer than anticipated to satisfy. The pending transaction subjects Laclede Group to a number of additional risks, including the following:

• the Company's estimate of the costs to complete the acquisitions and the operating performance after the acquisitions close may vary significantly from actual results;

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

• the potential loss of key employees of the Company or of MGE or NEG who may be uncertain about their future roles if and when the acquisitions are 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 acquisition agreements contain certain termination rights for both the Company and SUG, including, among others, the right to terminate if the transactions are not completed by October 14, 2013 (subject to up to four 30-day extensions under certain circumstances related to obtaining required regulatory approvals). In the event that SUG terminates the MGE acquisition agreement as a result of the failure of Laclede Group to obtain financing, the Company may be required to pay SUG a "reverse break up" fee of $73.1 million, which amount will operate as liquidated damages and a cap on such liability for such breach.

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.

In addition to its equity offering completed on May 29, 2013, Laclede Group expects to issue significant debt in order to provide permanent financing for the acquisition of MGE in lieu of and/or to refund borrowings under the bridge loan facility, and, as a result, the Company is subject to market risks including market demand for debt offerings, interest rate volatility, and adverse impacts on its credit ratings.

In connection with the acquisition agreements, Laclede Group has obtained a commitment from Wells Fargo Bank, National Association and various other banks for a syndicated bridge loan facility, which may be used to finance a significant portion of the acquisitions and pay related fees and expenses in the event that permanent financing is not completed at the time of the closing of the acquisitions. The equity portion of the permanent financing was completed on May 29, 2013 when Laclede Group completed a public offering of 10,005,000 shares of its common stock, which generated net proceeds of $428.0 million. As a result of the equity offering and an amendment made to the bridge facility in June 2013, the commitment under the bridge facility was reduced from $1.020 billion to $525 million during the third quarter of fiscal year 2013. The permanent financing is anticipated to also include a mix of long-term debt of Laclede Group and/or Laclede Gas , and, depending on market conditions, may include other instruments such as convertible debt, preferred shares, or term loans.

Although the Company and its advisers believe they have taken prudent steps to position the Company and its subsidiaries for successful capital raises, there can be no assurance as to the ultimate cost or availability of funds to complete the permanent financing.

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Among other risks, the planned increase in indebtedness may:

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

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

• require an increased portion of the Company's cash flows from operations of Laclede Group and Laclede Gas 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 Laclede Gas' indebtedness, which could limit their ability to borrow additional funds or increase the interest rates applicable to their indebtedness;

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

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

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

In addition, in order to maintain investment-grade credit ratings, Laclede Group may consider it appropriate to reduce the amount of indebtedness outstanding following the acquisitions. This may be accomplished in several ways, including issuing additional shares of common stock or securities convertible into shares of common stock, reducing discretionary uses of cash or a combination of these and other measures. The specific measures that management may ultimately decide to use to maintain or improve its credit ratings and their timing, will depend upon a number of factors, including market conditions and forecasts at the time those decisions are made.

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 Gas Utility Segment'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 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. The diversion of management's attention and any delays or difficulties encountered in connection with the transaction and the integration of the companies' operations could have an adverse effect on the business, results of operations, financial condition or prospects of Laclede Group after the acquisitions are ultimately consummated.

The Company expects to incur costs associated with combining the operations of the companies, as well as transaction fees and other costs related to the transaction. The Company also will incur integration costs in connection with the acquisitions and management is in the early stages of assessing the magnitude of these costs and additional unanticipated costs may be incurred in the integration of the businesses.

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

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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

During the quarter ended June 30, 2013, the only repurchases of our common stock were pursuant to elections by employees to have shares of stock withheld to cover employee tax withholding obligations upon the vesting of performance-based and time-vested restricted stock and stock units. The following table provides information on those repurchases.

Period	Total No. of Shares Purchases	Average Price Paid Per Share	Total No. of Shares Purchased as Part of Publicly Announced Plans	Maximum No. of Shares that May Yet be Purchased Under the Plans
April 1, 2013 – April 30, 2013	—	—	—	—
May 1, 2013 – May 31, 2013	154	$46.38	—	—
June 1, 2013 – June 30, 2013	—	—	—	—
Total	154	—	—	—

Item 6. Exhibits

(a) See Exhibit Index

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		The Laclede Group, Inc.
Dated:	July 30, 2013	By:	/s/ Steven P. Rasche
			Steven P. Rasche
			Senior Vice President, Finance and Accounting
			(Authorized Signatory and Principal Accounting Officer)

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INDEX TO EXHIBITS

Exhibit No.
10.1	-	1st Amendment to Commitment Letter dated June 24, 2013, filed as exhibit 99.1 to Laclede Group's Form 8-K dated June 27, 2013 and incorporated herein by reference (File No. 1-16681)
12	-	Ratio of Earnings to Fixed Charges.
31	-	CEO and CFO Certifications under Exchange Act Rule 13a – 14(a).
32	-	CEO and CFO Section 1350 Certifications.
99.1	-	Audited Financial Statements of Missouri Gas Energy as of December 31, 2012 and 2011 and for the years ended December 31, 2012, 2011, and 2010, filed as exhibit 99.1 to Laclede Group's Form 8-K dated May 20, 2013 and incorporated herein by reference (File No. 1-16681)
99.2	-	Unaudited Interim Financial Statements of Missouri Gas Energy as of March 31, 2013 and for the three months ended March 31, 2013 and 2012, filed as exhibit 99.1 to Laclede Group's Form 8-K dated May 20, 2013 and incorporated herein by reference (File No. 1-16681)
99.3	-	Unaudited Pro Forma Combined Condensed Statements of Income for the six months ended March 31, 2013 and for the year ended September 30, 2012 and Unaudited Pro Forma Combined Condensed Balance Sheets as of March 31, 2013 and September 30, 2012, of The Laclede Group, Inc. and Missouri Gas Energy, filed as exhibit 99.1 to Laclede Group's Form 8-K dated May 20, 2013 and incorporated herein by reference (File No. 1-16681)
101.INS	-	XBRL Instance Document. (1)
101.SCH	-	XBRL Taxonomy Extension Schema. (1)
101.CAL	-	XBRL Taxonomy Extension Calculation Linkbase. (1)
101.DEF	-	XBRL Taxonomy Definition Linkbase. (1)
101.LAB	-	XBRL Taxonomy Extension Labels Linkbase. (1)
101.PRE	-	XBRL Taxonomy Extension Presentation Linkbase. (1)

(1) Attached as Exhibit 101 to this Quarterly Report are the following documents formatted in extensible business reporting language (XBRL): (i) Document and Entity Information; (ii) unaudited Statements of Consolidated Income for the three and nine months ended June 30, 2013 and 2012; (iii) unaudited Statements of Consolidated Comprehensive Income for the three and nine months ended June 30, 2013 and 2012; (iv) unaudited Consolidated Balance Sheets at June 30, 2013, September 30, 2012 and June 30, 2012; (v) unaudited Statements of Consolidated Cash Flows for the three and nine months ended June 30, 2013 and 2012, and (vi) Notes to the unaudited Consolidated Financial Statements. We also make available on our website the Interactive Data Files submitted as Exhibit 101 to this Quarterly Report. 

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EX-12

Exhibit 12

THE LACLEDE GROUP, INC. AND SUBSIDIARY COMPANIES

SCHEDULE OF COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

	Twelve Months Ended
	June 30,		September 30,
(Thousands of Dollars)	2013		2012		2011		2010		2009		2008
Income from continuing      operations before interest
charges and income taxes	$	109,611	$	113,875	$	118,424	$	107,986	$	126,517	$	113,228
Add: One third of applicable
rentals charged to operating
expense (which approximates
the interest factor)	1,827		1,591		1,799		1,825		1,833		1,691
Total Earnings	$	111,438	$	115,466	$	120,223	$	109,811	$	128,350	$	114,919
Interest on long-term debt	$	23,132	$	22,958	$	23,161	$	24,583	$	24,583	$	19,851
Other interest	2,645		1,988		2,256		2,269		5,163		9,626
Add: One third of applicable
rentals charged to operating
expense (which approximates
the interest factor)	1,827		1,591		1,799		1,825		1,833		1,691
Total Fixed Charges	$	27,604	$	26,537	$	27,216	$	28,677	$	31,579	$	31,168
Ratio of Earnings to Fixed
Charges	4.04		4.35		4.42		3.83		4.06		3.69

EX-31

Exhibit 31

CERTIFICATION

I, Suzanne Sitherwood, certify that:

1. I have reviewed this quarterly report on Form 10-Q of The Laclede Group, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	July 30, 2013	Signature:	/s/ Suzanne Sitherwood
			Suzanne Sitherwood
			President and Chief Executive Officer

CERTIFICATION

I, Mark D. Waltermire, certify that:

1. I have reviewed this quarterly report on Form 10-Q of The Laclede Group, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	July 30, 2013	Signature:	/s/ Mark D. Waltermire
			Mark D. Waltermire
			Executive Vice President, Chief Financial Officer

EX-32

Exhibit 32

Section 1350 Certification

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, I, Suzanne Sitherwood, President and Chief Executive Officer of The Laclede Group, Inc., hereby certify that

(a) To the best of my knowledge, the accompanying report on Form 10-Q for the quarter ended June 30, 2013 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and

(b) To the best of my knowledge, the information contained in the accompanying report on Form 10-Q for the quarter ended June 30, 2013 fairly presents, in all material respects, the financial condition and results of operations of The Laclede Group, Inc.

Date:	July 30, 2013	/s/ Suzanne Sitherwood
		Suzanne Sitherwood
		President and Chief Executive Officer

Section 1350 Certification

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, I, Mark D. Waltermire, Executive Vice President, Chief Financial Officer of The Laclede Group, Inc., hereby certify that

a. To the best of my knowledge, the accompanying report on Form 10-Q for the quarter ended June 30, 2013 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and

b. To the best of my knowledge, the information contained in the accompanying report on Form 10-Q for the quarter ended June 30, 2013 fairly presents, in all material respects, the financial condition and results of operations of The Laclede Group, Inc.

Date:	July 30, 2013	/s/ Mark D. Waltermire
		Mark D. Waltermire
		Executive Vice President, Chief Financial Officer

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INFORMATION BY OPERATING SEGMENT

9 Months Ended

Jun. 30, 2013

Segment Reporting [Abstract]

INFORMATION BY OPERATING SEGMENT

11.        INFORMATION BY OPERATING SEGMENT

All of Laclede Group’s subsidiaries are wholly owned. In the first quarter of fiscal year 2013, the Company retitled its segment names. The Gas Utility segment, previously titled Regulated Gas Distribution, consists of the regulated operations of Laclede Gas and is the core business segment of Laclede Group. Laclede Gas is a public utility engaged in the retail distribution and sale of natural gas serving an area in eastern Missouri, with a population of approximately 2.2 million, including the City of St. Louis and parts of ten counties in eastern Missouri. The Gas Marketing segment, previously titled Non-Regulated Gas Marketing, includes the results of LER, a subsidiary engaged in the non-regulated marketing of natural gas and related activities, and LER Storage Services, Inc., which became operational in January 2012 and utilizes natural gas storage contracts for providing natural gas sales. Other includes Laclede Pipeline Company’s transportation of liquid propane regulated by the Federal Energy Regulatory Commission (FERC) as well as non-regulated activities, including, among other activities, real estate development, the compression of natural gas, and financial investments in other enterprises. These operations are conducted through seven subsidiaries. Other also includes Laclede Gas’ non-regulated business activities, which are comprised of its propane storage and related services. Accounting policies are described in Note 1. Intersegment transactions include sales of natural gas from Laclede Gas to LER, propane storage services provided by Laclede Gas to Laclede Pipeline Company, sales of natural gas from LER to Laclede Gas, and propane transportation services provided by Laclede Pipeline Company to Laclede Gas.

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

			Gas
(Thousands)	Gas Utility		Marketing		Other			Eliminations			Consolidated
Three Months Ended June 30, 2013
Revenues from external customers	$	131,517	$	33,433	$	339		$	—		$	165,289
Intersegment revenues	23		9,354		546			(9,923		)	—
Total Operating Revenues	131,540		42,787		885			(9,923		)	165,289
Operating Expenses
Gas Utility
Natural and Propane Gas	52,847		—		—			(9,614		)	43,233
Other Operation and Maintenance Expenses	42,090		—		—			314			42,404
Depreciation and Amortization	11,519		—		—			—			11,519
Taxes, Other than Income Taxes	12,968		—		—			—			12,968
Total Gas Utility Operating Expenses	119,424		—		—			(9,300		)	110,124
Gas Marketing	—		40,583		—			—			40,583
Other	—		—		2,924			(623		)	2,301
Total Operating Expenses	119,424		40,583		2,924			(9,923		)	153,008
Operating Income	12,116		2,204		(2,039		)	—			12,281
Net Economic Earnings (Losses)	6,834		1,632		(302		)	—			8,164
Total assets	1,766,198		220,162		584,488			(148,809		)	2,422,039
Three Months Ended June 30, 2012
Revenues from external customers	$	116,459	$	70,014	$	376		$	—		$	186,849
Intersegment revenues	1,175		587		259			(2,021		)	—
Total Operating Revenues	117,634		70,601		635			(2,021		)	186,849
Operating Expenses
Gas Utility
Natural and Propane Gas	48,662		—		—			(2,021		)	46,641
Other Operation and Maintenance Expenses	38,351		—		—			—			38,351
Depreciation and Amortization	10,186		—		—			—			10,186
Taxes, Other than Income Taxes	10,842		—		—			—			10,842
Total Gas Utility Operating Expenses	108,041		—		—			(2,021		)	106,020
Gas Marketing	—		65,420		—			—			65,420
Other	—		—		364			—			364
Total Operating Expenses	108,041		65,420		364			(2,021		)	171,804
Operating Income	9,593		5,181		271			—			15,045
Net Economic Earnings	4,597		3,605		694			—			8,896
Total assets	1,640,101		186,394		150,117			(235,274		)	1,741,338

			Gas
(Thousands)	Gas Utility		Marketing		Other			Eliminations			Consolidated
Nine Months Ended June 30, 2013
Revenues from external customers	$	735,726	$	129,937	$	4,242		$	—		$	869,905
Intersegment revenues	10,517		13,928		1,124			(25,569		)	—
Total Operating Revenues	746,243		143,865		5,366			(25,569		)	869,905
Operating Expenses
Gas Utility
Natural and Propane Gas	435,329		—		—			(25,140		)	410,189
Other Operation and Maintenance Expenses	122,936		—		—			309			123,245
Depreciation and Amortization	33,742		—		—			—			33,742
Taxes, Other than Income Taxes	49,525		—		—			—			49,525
Total Gas Utility Operating Expenses	641,532		—		—			(24,831		)	616,701
Gas Marketing	—		133,959		—			—			133,959
Other	—		—		13,767			(738		)	13,029
Total Operating Expenses	641,532		133,959		13,767			(25,569		)	763,689
Operating Income	104,711		9,906		(8,401		)	—			106,216
Net Economic Earnings (Losses)	62,372		7,281		(742		)	—			68,911
Total assets	1,766,198		220,162		584,488			(148,809		)	2,422,039
Nine Months Ended June 30, 2012
Revenues from external customers	$	665,981	$	288,036	$	1,920		$	—		$	955,937
Intersegment revenues	1,178		9,125		778			(11,081		)	—
Total Operating Revenues	667,159		297,161		2,698			(11,081		)	955,937
Operating Expenses
Gas Utility
Natural and Propane Gas	375,634		—		—			(11,078		)	364,556
Other Operation and Maintenance Expenses	125,028		—		—			—			125,028
Depreciation and Amortization	30,450		—		—			—			30,450
Taxes, Other than Income Taxes	45,602		—		—			—			45,602
Total Gas Utility Operating Expenses	576,714		—		—			(11,078		)	565,636
Gas Marketing	—		279,787		—			(3		)	279,784
Other	—		—		1,784			—			1,784
Total Operating Expenses	576,714		279,787		1,784			(11,081		)	847,204
Operating Income	90,445		17,374		914			—			108,733
Net Economic Earnings	51,448		9,589		1,179			—			62,216
Total assets	1,640,101		186,394		150,117			(235,274		)	1,741,338

Reconciliation of Consolidated Net Economic Earnings to Consolidated Net Income
	Three Months Ended						Nine Months Ended
	June 30,						June 30,
(Thousands)	2013			2012			2013			2012
Total Net Economic Earnings above	$	8,164		$	8,896		$	68,911		$	62,216
Add: Unrealized gain (loss) on energy-related derivative
contracts, net of tax	304			(963		)	(722		)	1,281
Add:  Lower of cost or market inventory
adjustments, net of tax	(559		)	494			(559		)	(68		)
Add:  Realized gain (loss) on economic hedges prior to sale of
the physical commodity, net of tax	3			6			25			(138		)
Add:  Acquisition, divestiture, and restructuring activities,
net of tax	(1,327		)	—			(5,261		)	—
Net Income	$	6,585		$	8,433		$	62,394		$	63,291

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CONSOLIDATED BALANCE SHEETS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Sep. 30, 2012	Jun. 30, 2012
ASSETS
Utility Plant	$ 1,567,296	$ 1,497,419	$ 1,455,004
Less: Accumulated depreciation and amortization	484,380	478,120	474,008
Net Utility Plant	1,082,916	1,019,299	980,996
Non-utility property	5,892	6,039	5,899
Other investments	53,337	50,775	55,117
Other Property and Investments	59,229	56,814	61,016
Current Assets:
Cash and cash equivalents	556,489	27,457	21,523
Accounts receivable:
Utility	70,380	64,027	65,762
Non-utility	53,678	51,042	47,335
Other	17,123	26,478	22,927
Allowance for doubtful accounts	(9,024)	(7,705)	(8,842)
Delayed customer billings	11,319	0	0
Inventories:
Natural gas stored underground	59,171	92,729	55,192
Propane gas	8,963	10,200	10,051
Materials and supplies at average cost	4,477	3,543	3,917
Natural gas receivable	24,304	22,377	19,710
Derivative instrument assets	21,279	2,855	3,879
Unamortized purchased gas adjustments	6,230	40,674	9,158
Deferred income taxes	2,888	0	0
Prepayments and other	14,112	9,339	11,079
Total Current Assets	841,389	343,016	261,691
Deferred Charges:
Regulatory assets	432,700	456,047	433,376
Other	5,805	5,086	4,259
Total Deferred Charges	438,505	461,133	437,635
Total Assets	2,422,039	1,880,262	1,741,338
Capitalization:
Common stock (70,000,000 shares authorized, 32,675,659, 22,539,431, and 22,505,440 shares issued, respectively)	32,676	22,539	22,505
Paid-in capital	592,946	168,607	166,717
Retained earnings	443,691	414,581	424,588
Accumulated other comprehensive loss	11,684	(4,116)	(2,652)
Total Common Stock Equity	1,080,997	601,611	611,158
Long-term debt (less current portion)	464,444	339,416	339,401
Total Capitalization	1,545,441	941,027	950,559
Current Liabilities:
Notes payable	0	40,100	0
Accounts payable	104,862	89,503	81,322
Advance customer billings	0	25,146	6,225
Current portion of long-term debt	0	25,000	25,000
Wages and compensation accrued	13,386	13,908	12,653
Dividends payable	14,454	9,831	9,664
Customer deposits	7,828	8,565	9,123
Interest accrued	3,887	8,590	5,405
Taxes accrued	28,522	11,304	13,040
Deferred income taxes	0	6,675	311
Other	9,862	13,502	16,540
Total Current Liabilities	182,801	252,124	179,283
Deferred Credits and Other Liabilities:
Deferred income taxes	377,965	355,509	335,366
Unamortized investment tax credits	2,953	3,113	3,166
Pension and postretirement benefit costs	181,691	196,558	158,011
Asset retirement obligations	42,097	40,368	28,723
Regulatory liabilities	58,382	56,319	53,867
Other	30,709	35,244	32,363
Total Deferred Credits and Other Liabilities	693,797	687,111	611,496
Commitments and Contingencies (Note 12)
Total Capitalization and Liabilities	$ 2,422,039	$ 1,880,262	$ 1,741,338

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EARNINGS PER COMMON SHARE

9 Months Ended

Jun. 30, 2013

Earnings Per Share [Abstract]

EARNINGS PER COMMON SHARE

4.        EARNINGS PER COMMON SHARE

	Three Months Ended June 30,				Nine Months Ended June 30,
(Thousands, Except Per Share Amounts)	2013		2012		2013		2012
Basic EPS:
Net Income	$	6,585	$	8,433	$	62,394	$	63,291
Less: Income allocated to participating securities	81		42		389		356
Net Income Available to Common Shareholders	$	6,504	$	8,391	$	62,005	$	62,935
Weighted Average Shares Outstanding	26,110		22,282		23,634		22,243
Earnings Per Share of Common Stock	$	0.25	$	0.38	$	2.62	$	2.83
Diluted EPS:
Net Income	$	6,585	$	8,433	$	62,394	$	63,291
Less: Income allocated to participating securities	81		42		388		355
Net Income Available to Common Shareholders	$	6,504	$	8,391	$	62,006	$	62,936
Weighted Average Shares Outstanding	26,110		22,282		23,634		22,243
Dilutive Effect of Stock Options, Restricted Stock,
and Restricted Stock Units	84		75		74		75
Weighted Average Diluted Shares	26,194		22,357		23,708		22,318
Earnings Per Share of Common Stock	$	0.25	$	0.38	$	2.62	$	2.82
Outstanding Shares Excluded from the
Calculation of Diluted EPS Attributable to:
Restricted stock and stock units subject to
performance and/or market conditions	196		204		196		202

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FAIR VALUE OF FINANCIAL INSTRUMENTS (Tables)

9 Months Ended

Jun. 30, 2013

Financial Instruments, Owned, at Fair Value [Abstract]

Fair value - financial instruments

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

					Classification of Estimated Fair Value
(Thousands)	Carrying Amount		Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
As of June 30, 2013
Cash and cash equivalents	$	556,489	$	556,489	$	421,518	$	134,971	$	—
Short-term debt	—		—		—		—		—
Long-term debt, including current portion	464,444		506,328		—		506,328		—
As of Sept. 30, 2012
Cash and cash equivalents	$	27,457	$	27,457	$	17,380	$	10,077	$	—
Short-term debt	40,100		40,100		—		40,100		—
Long-term debt, including current portion	364,416		452,768		—		452,768		—
As of June 30, 2012
Cash and cash equivalents	$	21,523	$	21,523	$	11,560	$	9,963	$	—
Short-term debt	—		—		—		—		—
Long-term debt, including current portion	364,401		445,961		—		445,961		—

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COMMITMENTS AND CONTINGENCIES

9 Months Ended

Jun. 30, 2013

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

12.        COMMITMENTS AND CONTINGENCIES

Commitments

Laclede Gas and LER have entered into various contracts, expiring on dates through fiscal year 2018, for the storage, transportation, and supply of natural gas. Minimum payments required under the contracts in place at June 30, 2013 are estimated at approximately $321 million. Additional contracts are generally entered into prior to or during the heating season. Laclede Gas recovers its costs from customers in accordance with the PGA Clause.

During 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 June 30, 2013, the Company was contractually committed to costs of approximately $1.5 million related to this project. The final phase of the project was implemented in July 2013.

Refer to Note 13, Acquisition Agreements, for information about Laclede Group's commitments associated with the pending acquisitions of substantially all of the assets and liabilities of Missouri Gas Energy (MGE) and New England Gas Company (NEG) and the subsequent agreement with Algonquin Power & Utilities Corp. (APUC) that will allow an APUC subsidiary to acquire the Company's rights to purchase the assets of NEG.

Contingencies

Laclede Gas owns and operates natural gas distribution, transmission, and storage facilities, the operations of which are subject to various environmental laws, regulations, and interpretations. While environmental issues resulting from such operations arise in the ordinary course of business, such issues have not materially affected the Company’s or Laclede Gas’ financial position and results of operations. As environmental laws, regulations, and their interpretations change, however, Laclede Gas may be required to incur additional costs.

Similar to other natural gas utility companies, Laclede Gas 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/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.

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

One of the sites located in the City of St. Louis is currently owned by a development agency of the City, which, together with other City development agencies, has selected a developer to redevelop the site. In conjunction with this redevelopment effort, Laclede Gas and another former owner of the site entered into an agreement (Remediation Agreement) with the City development agencies, the developer, and an environmental consultant that obligates one of the City agencies and the environmental consultant to remediate the site and obtain a No Further Action letter from the Missouri Department of Natural Resources. The Remediation Agreement also provides for a release of Laclede Gas and the other former site owner from certain liabilities related to the past and current environmental condition of the site and requires the developer and the environmental consultant to maintain certain insurance coverages, including remediation cost containment, premises pollution liability, and professional liability. The operative provisions of the Remediation Agreement were triggered on December 20, 2010, on which date Laclede Gas and the other former site owner, as full consideration under the Remediation Agreement, paid a small percentage of the cost of remediation of the site. The amount paid by Laclede Gas did not materially impact the financial condition, results of operations, or cash flows of the Company.

Laclede Gas has not owned the other site located in the City of St. Louis for many years. In a letter dated June 29, 2011, the Attorney General for the State of Missouri informed Laclede Gas that the Missouri Department of Natural Resources had completed an investigation of the site. The Attorney General requested that Laclede Gas participate in the follow up investigations of the site. In a letter dated January 10, 2012, the Company 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. Further correspondence from the Missouri Attorney General dated April 12, 2012, and November 28, 2012, encouraged Laclede Gas and other present and former owners of the site to move forward with further site investigation for possible remediation via enrollment in the Missouri Department of Natural Resources Brownfields/Voluntary Cleanup Program (BVCP) in lieu of being subjected to enforcement action by the United States Environmental Protection Agency, Region VII. Accordingly, Laclede Gas and the other former and current owners of the site each have entered into, or are in the process of entering into, Provisional Cost Sharing and Environmental Response Agreements enabling Laclede Gas to enroll the property in the BVCP and to fund and conduct additional investigation of the property. Laclede Gas enrolled the site in the BVCP as of April 1, 2013.

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. Costs associated with environmental remediation activities are accrued when such costs are probable and reasonably estimable.

Laclede Gas 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 Laclede Gas or the Company.

The MoPSC Staff previously proposed disallowances related to Laclede Gas' recovery of its purchased gas costs totaling $6.0 million pertaining to Laclede Gas' purchase of gas from a marketing affiliate, LER, applicable to fiscal years 2005 through 2007. The MoPSC Staff also proposed a number of non-monetary recommendations, based on its review of gas costs for fiscal years 2008 through 2011. Laclede Gas believes that the proposed disallowances lack merit and is vigorously opposing these adjustments. In a related matter, on October 6, 2010, the MoPSC Staff filed a complaint against Laclede Gas alleging that Laclede Gas' affiliate transactions and its Cost Allocation Manual (CAM) violated the MoPSC's affiliate transaction rules. Laclede Gas responded with a counterclaim that the MoPSC Staff had failed to adhere to the affiliate transaction rules and the Company's CAM. On July 16, 2013, Laclede Gas, the MoPSC Staff and the Office of the Public Counsel requested MoPSC approval of a unanimous stipulation and agreement resolving the affiliate transaction matters for fiscal years 2005 through 2011, resolving the October 6, 2010 complaint, resolving Laclede Gas' counterclaim, presenting a revised CAM for MoPSC approval, and establishing standards of conduct for gas purchases and sales. The parties' request is pending before the MoPSC. Management, after discussion with counsel, continues to believe the final outcome of these matters will not have a material effect on the Company's financial position, results of operations, or cash flows.

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. In light of such document production, Laclede Gas is currently in discussions with the MoPSC to resolve the penalty case. Management, after discussion with counsel, continues to believe the final outcome of these matters will not have a material effect on the Company's financial position, results of operations, or cash flows.

On June 29, 2010, the Office of Federal Contract Compliance Programs issued a Notice of Violations to Laclede Gas alleging lapses in certain employment selection procedures during a two-year period ending in February 2006. On July 2, 2013, Laclede Gas executed a Conciliation Agreement with the OFCCP in which the Company did not admit to liability, but agreed to provide make whole relief of back pay and interest to the impacted parties from 2004-2006. The OFCCP, as of the date of this report, has not yet executed the Conciliation Agreement. 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 8, Derivative Instruments and Hedging Activities, Laclede Gas and LER enter into NYMEX and ICE exchange-traded/cleared derivative instruments. Previously, these instruments were held in accounts at MF Global, Inc. On October 31, 2011, affiliated entities of MF Global filed a Chapter 11 petition at the U.S. Bankruptcy Court in the Southern District of New York. Subsequently, the court-appointed bankruptcy trustee transferred all of the open positions and a significant portion of the margin deposits of Laclede Gas and LER to a new brokerage firm. On June 27, 2013, the bankruptcy Trustee issued a statement projecting that MF Global customers would receive a full payout of their claims. As of July 30, 2013, Laclede Gas and LER had $0.9 million and $0.2 million, respectively, on deposit with MF Global.

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

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Part 1) (Details) (USD $)	9 Months Ended
	Jun. 30, 2013 MMBTU gal	Sep. 30, 2012	Jun. 30, 2012
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Maximum percentage of normal volumes hedged	70.00%
Maximum number of months normal volumes can be hedged (in months)	36-month
Derivative [Line Items]
Gasoline futures contracts notional amount (in gallons)	400,000
Average price of gasoline futures contracts (dollars per gallon)	$ 2.25
Notional amount of non-exchange traded natural gas commodity contracts (in MMBtu)	57,700,000
Notional amount of non-exchange traded natural gas commodity contracts to be settled during fiscal 2015 (in MMBtu)	1,800,000
Notional amount of non-exchange traded natural gas commodity contracts to be settled during fiscal 2014 (in MMBtu)	21,600,000
Notional amount of non-exchange traded natural gas commodity contracts to be settled during fiscal 2013 (in MMBtu)	34,300,000
Notional Amount of Interest Rate Swap Derivatives	355,000,000
Derivative, Lower Fixed Interest Rate Range	1.28%
Derivative, Higher Fixed Interest Rate Range	3.14%
Expected pre-tax unrealized gain (loss) reclassifications into the Statements of Consolidated Income during the twelve months	5,300,000
Derivative instrument reconciliation [Abstract]
Fair value of asset derivatives presented above	26,404,000	11,922,000	9,015,000
Fair value of cash margin receivables offset with derivatives	1,596,000	5,478,000	19,111,000
Cash margin receivables not offset with derivatives	3,600,000	10,000,000	10,600,000
Netting of assets and liabilities with the same counterparty	(6,612,000)	(14,526,000)	(24,247,000)
Derivative Assets	21,388,000	2,874,000	3,879,000
Derivative Liabilities	840,000	133,000	71,000
Fair value of liability derivatives presented above	5,364,000	14,576,000	24,318,000
Fair value of cash margin payables offset with derivatives	2,088,000	83,000	0
Derivative Instrument, per Consolidated Balance Sheets: [Abstract]
Derivative instrument assets	21,279,000	2,855,000	3,879,000
Other deferred charges derivative instruments	109,000	19,000	0
Derivative Assets	21,388,000	2,874,000	3,879,000
Other Current Liabilities	727,000	133,000	71,000
Netting of assets and liabilities with the same counterparty	(6,612,000)	(14,526,000)	(24,247,000)
Other Deferred Credits, Current	113,000	0	0
Derivative Liabilities	840,000	133,000	71,000
Laclede Gas Company [Member]
Derivative [Line Items]
Nonmonetary Notional Amount Of Option Based Price Risk Derivatives	17,000,000
Laclede Gas Company [Member] | Fiscal 2013 [Member] | Open Short Futures Positions [Member]
Derivative [Line Items]
MMBtu	0
Avg. Price Per MMBtu	0.00
Laclede Gas Company [Member] | Fiscal 2013 [Member] | Open Long Futures Positions [Member]
Derivative [Line Items]
MMBtu	3,420,000
Avg. Price Per MMBtu	3.42
Laclede Gas Company [Member] | Fiscal 2014 [Member] | Open Short Futures Positions [Member]
Derivative [Line Items]
MMBtu	0
Avg. Price Per MMBtu	0.00
Laclede Gas Company [Member] | Fiscal 2014 [Member] | Open Long Futures Positions [Member]
Derivative [Line Items]
MMBtu	4,870,000
Avg. Price Per MMBtu	3.97
Laclede Gas Company [Member] | Fiscal 2015 [Member] | Open Short Futures Positions [Member]
Derivative [Line Items]
MMBtu	0
Avg. Price Per MMBtu	0.00
Laclede Gas Company [Member] | Fiscal 2015 [Member] | Open Long Futures Positions [Member]
Derivative [Line Items]
MMBtu	0
Avg. Price Per MMBtu	0.00
Laclede Energy Resources [Member] | Fiscal 2013 [Member] | Open Short Futures Positions [Member]
Derivative [Line Items]
MMBtu	5,000,000
Avg. Price Per MMBtu	4.03
Laclede Energy Resources [Member] | Fiscal 2013 [Member] | Open Long Futures Positions [Member]
Derivative [Line Items]
MMBtu	630,000
Avg. Price Per MMBtu	3.82
Laclede Energy Resources [Member] | Fiscal 2014 [Member] | Open Short Futures Positions [Member]
Derivative [Line Items]
MMBtu	6,040,000
Avg. Price Per MMBtu	3.84
Laclede Energy Resources [Member] | Fiscal 2014 [Member] | Open Long Futures Positions [Member]
Derivative [Line Items]
MMBtu	10,000
Avg. Price Per MMBtu	4.03
Laclede Energy Resources [Member] | Fiscal 2015 [Member] | Open Short Futures Positions [Member]
Derivative [Line Items]
MMBtu	280,000
Avg. Price Per MMBtu	4.18
Laclede Energy Resources [Member] | Fiscal 2015 [Member] | Open Long Futures Positions [Member]
Derivative [Line Items]
MMBtu	2,420,000
Avg. Price Per MMBtu	3.91
Other Deferred Charges [Member] | Natural Gas Commodity Contracts [Member] | Not Designated as Hedging Instrument [Member]
Derivative instrument reconciliation [Abstract]
Fair value of asset derivatives presented above	14,000	19,000
Fair value of liability derivatives presented above	0	0
Derivative Instruments Assets [Member] | Natural Gas Commodity Contracts [Member] | Not Designated as Hedging Instrument [Member]
Derivative instrument reconciliation [Abstract]
Fair value of asset derivatives presented above	944,000	3,150,000	4,356,000
Fair value of liability derivatives presented above	$ 89,000	$ 295,000	$ 478,000

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OTHER INCOME AND (INCOME DEDUCTIONS) - NET (Tables)

9 Months Ended

Jun. 30, 2013

Other Nonoperating Income (Expense) [Abstract]

Other Income and (Income Deductions) by Component

	Three Months Ended June 30,						Nine Months Ended June 30,
(Thousands)	2013			2012			2013			2012
Interest income	$	164		$	337		$	827		$	1,001
Net investment gain	24			264			1,127			2,458
Other income	156			(15		)	233			(4		)
Other income deductions	(742		)	(135		)	(163		)	316
Other Income and (Income Deductions) – Net	$	(398	)	$	451		$	2,024		$	3,771

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)

9 Months Ended

Jun. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities

Open NYMEX/ICE natural gas futures and swap positions at June 30, 2013 were as follows:

	Laclede Gas Company			Laclede Energy Resources, Inc.
	MMBtu (millions)	Avg. Price Per MMBtu		MMBtu (millions)	Avg. Price Per MMBtu
Open short futures positions
Fiscal 2013	—	$	—	5.00	$	4.03
Fiscal 2014	—	—		6.04	3.84
Fiscal 2015	—	—		0.28	4.18
Open long futures positions
Fiscal 2013	3.42	$	3.42	0.63	$	3.82
Fiscal 2014	4.87	3.97		0.01	4.03
Fiscal 2015	—	—		2.42	3.91

The Effect of Derivative Instruments on the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income

The Effect of Derivative Instruments on the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income
		Three Months Ended						Nine Months Ended
	Location of Gain (Loss)	June 30,						June 30,
(Thousands)	Recorded in Income	2013			2012			2013			2012
Derivatives in Cash Flow Hedging Relationships
Effective portion of gain (loss) recognized in OCI on derivatives:
NYMEX/ICE natural gas contracts		$	5,501		$	(1,802	)	$	3,646		$	6,218
NYMEX gasoline and heating oil contracts		(125		)	69			79			202
Interest rate swaps		22,238			—			17,689			—
Total		$	27,614		$	(1,733	)	$	21,414		$	6,420
Effective portion of gain (loss) reclassified from AOCI to income:
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	$	(1,570	)	$	7,646		$	(3,229	)	$	18,434
	Gas Marketing Operating Expenses	199			(1,492		)	(453		)	(9,861		)
Sub-total		(1,371		)	6,154			(3,682		)	8,573
NYMEX gasoline and heating oil contracts	Gas Utility Other Operations and Maintenance Expenses	53			17			138			20
Total		$	(1,318	)	$	6,171		$	(3,544	)	$	8,593
Ineffective portion of gain (loss) on derivatives recognized in income:
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	$	16		$	(84	)	$	(396	)	$	(15	)
	Gas Marketing Operating Expenses	(22		)	(95		)	(151		)	(291		)
Sub-total		(6		)	(179		)	(547		)	(306		)
NYMEX gasoline and heating oil contracts	Gas Utility Other Operations and Maintenance Expenses	5			(46		)	(127		)	(12		)
Total		$	(1	)	$	(225	)	$	(674	)	$	(318	)
Derivatives Not Designated as Hedging Instruments *
Gain (loss) recognized in income on derivatives:
Natural gas commodity contracts	Gas Marketing Operating Revenues	$	(993	)	$	2,641		$	(218	)	$	3,431
	Gas Marketing Operating Expenses	—			—			—			687
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	1,163			(1,123		)	551			425
	Gas Marketing Operating Expenses	—			(655		)	—			(625		)
NYMEX gasoline and heating oil contracts	Other Income and (Income Deductions) - Net	(5		)	(11		)	41			2
Total		$	165		$	852		$	374		$	3,920

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

Fair Value of Derivative Instruments in the Consolidated Balance Sheet

Fair Value of Derivative Instruments in the Consolidated Balance Sheet at June 30, 2013
	Asset Derivatives				Liability Derivatives
(Thousands)	Balance Sheet Location	Fair Value		*	Balance Sheet Location	Fair  Value		*
Derivatives designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets	$	4,574		Derivative Instrument Assets	$	437
NYMEX/ICE natural gas contracts	Other Deferred Charges	77			Other Deferred Charges	9
NYMEX gasoline and heating oil contracts	Accounts Receivable – Other	136			Accounts Receivable – Other	—
Interest rate swaps	Derivative Instrument Assets	17,689			Derivative Instrument Assets	—
Sub-total		22,476				446
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets	859			Derivative Instrument Assets	146
	Accounts Receivable – Other	1,956			Accounts Receivable – Other	3,688
Natural gas commodity contracts	Derivative Instrument Assets	944			Derivative Instrument Assets	89
	Other Deferred Charges	14			Other Deferred Charges	—
	Other Current Liabilities	122			Other Current Liabilities	836
	Other Deferred Credits	33			Other Deferred Credits	159
Sub-total		3,928				4,918
Total derivatives		$	26,404			$	5,364
Fair Value of Derivative Instruments in the Consolidated Balance Sheet at September 30, 2012
	Asset Derivatives				Liability Derivatives
(Thousands)	Balance Sheet Location	Fair Value		*	Balance Sheet Location	Fair Value		*
Derivatives designated as hedging instruments
NYMEX/ICE natural gas contracts	Accounts Receivable - Other	$	405		Accounts Receivable - Other	$	3,413
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	334			Accounts Receivable - Other	—
Sub-total		739				3,413
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Accounts Receivable - Other	8,000			Accounts Receivable - Other	10,731
Natural gas commodity contracts	Derivative Instrument Assets	3,150			Derivative Instrument Assets	295
	Other Current Liabilities	4			Other Current Liabilities	137
	Other Deferred Charges	19			Other Deferred Charges	—
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	10			Accounts Receivable - Other	—
Sub-total		11,183				11,163
Total derivatives		$	11,922			$	14,576

Fair Value of Derivative Instruments in the Consolidated Balance Sheet at June 30, 2012
	Asset Derivatives				Liability Derivatives
(Thousands)	Balance Sheet Location	Fair Value		*	Balance Sheet Location	Fair Value		*
Derivatives designated as hedging instruments
NYMEX/ICE natural gas contracts	Accounts Receivable - Other	$	1,064		Accounts Receivable - Other	$	2,529
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	106			Accounts Receivable - Other	—
Sub-total		1,170				2,529
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Accounts Receivable - Other	3,449			Accounts Receivable - Other	21,202
Natural gas commodity contracts	Derivative Instrument Assets	4,356			Derivative Instrument Assets	478
	Other Current Liabilities	39			Other Current Liabilities	109
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	1			Accounts Receivable - Other	—
Sub-total		7,845				21,789
Total derivatives		$	9,015			$	24,318

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

Derivative instrument Reconciliation

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

(Thousands)	June 30, 2013			Sept. 30, 2012			June 30, 2012
Fair value of asset derivatives presented above	$	26,404		$	11,922		$	9,015
Fair value of cash margin receivables offset with derivatives	1,596			5,478			19,111
Netting of assets and liabilities with the same counterparty	(6,612		)	(14,526		)	(24,247		)
Total	$	21,388		$	2,874		$	3,879
Derivative Instrument Assets, per Consolidated Balance Sheets:
Derivative instrument assets	$	21,279		$	2,855		$	3,879
Other deferred charges	109			19			—
Total	$	21,388		$	2,874		$	3,879
Fair value of liability derivatives presented above	$	5,364		$	14,576		$	24,318
Fair value of cash margin payables offset with derivatives	2,088			83			—
Netting of assets and liabilities with the same counterparty	(6,612		)	(14,526		)	(24,247		)
Total	$	840		$	133		$	71
Derivative Instrument Liabilities, per Consolidated Balance Sheets:
Other Current Liabilities	$	727		$	133		$	71
Other Deferred Credits	113			—			—
Total	$	840		$	133		$	71

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EARNINGS PER COMMON SHARE (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Basic EPS [Abstract]
Net Income	$ 6,585	$ 8,433	$ 62,394	$ 63,291
Less: Income allocated to participating securities	81	42	389	356
Net Income Available to Common Shareholders, Basic	6,504	8,391	62,005	62,935
Weighted Average Shares Outstanding, Basic	26,110	22,282	23,634	22,243
Earnings Per Share of Common Stock, Basic (Per Share)	$ 0.25	$ 0.38	$ 2.62	$ 2.83
Diluted EPS [Abstract]
Net Income	6,585	8,433	62,394	63,291
Less: Income allocated to participating securities	81	42	388	355
Net Income Available to Common Stockholders, Diluted	$ 6,504	$ 8,391	$ 62,006	$ 62,936
Weighted Average Shares Outstanding, Basic	26,110	22,282	23,634	22,243
Dilutive Effect of Stock Options, Restricted Stock, and Restricted Stock Units	84	75	74	75
Weighted Average Diluted Shares	26,194	22,357	23,708	22,318
Earnings Per Share of Common Stock, Diluted (Per share)	$ 0.25	$ 0.38	$ 2.62	$ 2.82
Restricted Stock and Stock Units Subject to Performance and/or Market Conditions [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Outstanding shares excluded from the calculation of diluted EPS	196	204	196	202

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Part 3) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Cash Flow Hedging [Member] | NYMEX Natural Gas Contracts [Member] | Gas Marketing Operating Expenses [Member]
Derivatives in Cash Flow Hedging Relationships [Abstract]
Ineffective portion of gain (loss) on derivatives recognized in income	$ (22)	$ (95)	$ (151)	$ (291)
Effective portion of gain (loss) reclassiffied from AOCI to income	199	(1,492)	(453)	(9,861)
Cash Flow Hedging [Member] | NYMEX Natural Gas Contracts [Member] | Other Comprehensive Income (Loss) [Member]
Derivatives in Cash Flow Hedging Relationships [Abstract]
Effective portion of gain (loss) recognized in OCI on derivatives	5,501	(1,802)	3,646	6,218
Cash Flow Hedging [Member] | NYMEX Natural Gas Contracts [Member] | Gas Marketing Operating Revenue [Member]
Derivatives in Cash Flow Hedging Relationships [Abstract]
Ineffective portion of gain (loss) on derivatives recognized in income	16	(84)	(396)	(15)
Effective portion of gain (loss) reclassiffied from AOCI to income	(1,570)	7,646	(3,229)	18,434
Cash Flow Hedging [Member] | NYMEX Gasoline and Heating Oil Contracts [Member] | Other Comprehensive Income (Loss) [Member]
Derivatives in Cash Flow Hedging Relationships [Abstract]
Effective portion of gain (loss) recognized in OCI on derivatives	(125)	69	79	202
Cash Flow Hedging [Member] | NYMEX Gasoline and Heating Oil Contracts [Member] | Other Gas Utility Operating Expenses [Member]
Derivatives in Cash Flow Hedging Relationships [Abstract]
Ineffective portion of gain (loss) on derivatives recognized in income	5	(46)	(127)	(12)
Effective portion of gain (loss) reclassiffied from AOCI to income	53	17	138	20
Cash Flow Hedging [Member] | Interest Rate Swap [Member] | Other Comprehensive Income (Loss) [Member]
Derivatives in Cash Flow Hedging Relationships [Abstract]
Effective portion of gain (loss) recognized in OCI on derivatives	22,238	0	17,689	0
Not Designated as Hedging Instrument [Member] | NYMEX Natural Gas Contracts [Member] | Gas Marketing Operating Expenses [Member]
Derivatives Not Designated as Hedging Instruments [Abstract]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	(655)	0	(625)
Not Designated as Hedging Instrument [Member] | NYMEX Natural Gas Contracts [Member] | Gas Marketing Operating Revenue [Member]
Derivatives Not Designated as Hedging Instruments [Abstract]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	1,163	(1,123)	551	425
Not Designated as Hedging Instrument [Member] | NYMEX Gasoline and Heating Oil Contracts [Member] | Other Income and (Income Deductions) - Net [Member]
Derivatives Not Designated as Hedging Instruments [Abstract]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	(5)	(11)	41	2
Not Designated as Hedging Instrument [Member] | Natural Gas Commodity Contracts [Member] | Gas Marketing Operating Expenses [Member]
Derivatives Not Designated as Hedging Instruments [Abstract]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	0	0	687
Not Designated as Hedging Instrument [Member] | Natural Gas Commodity Contracts [Member] | Gas Marketing Operating Revenue [Member]
Derivatives Not Designated as Hedging Instruments [Abstract]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ (993)	$ 2,641	$ (218)	$ 3,431

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 1 (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Pension Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost - benefits earned during the period	$ 2,311	$ 2,295	$ 6,933	$ 6,908
Interest Cost	4,066	4,824	12,198	14,535
Expected return on plan assets	(4,741)	(4,899)	(14,223)	(14,697)
Amortization of prior service cost (credit)	136	148	408	444
Amortization of actuarial loss	2,839	2,252	8,517	6,788
Loss on lump-sum settlement	12,346	0	12,346	3,407
Sub-total	16,957	4,620	26,179	17,385
Regulatory adjustment	(12,780)	(484)	(13,647)	(1,451)
Net benefit cost	4,177	4,136	12,532	15,934
Postretirement Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost - benefits earned during the period	2,534	2,015	7,601	6,045
Interest Cost	1,278	1,380	3,836	4,140
Expected return on plan assets	(1,082)	(991)	(3,244)	(2,973)
Amortization of transition obligation	24	34	70	102
Amortization of prior service cost (credit)	0	(518)	2	(1,554)
Amortization of actuarial loss	1,325	1,065	3,975	3,195
Sub-total	4,079	2,985	12,240	8,955
Regulatory adjustment	(1,699)	(604)	(5,097)	(1,812)
Net benefit cost	$ 2,380	$ 2,381	$ 7,143	$ 7,143

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INFORMATION BY OPERATING SEGMENT (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012	Sep. 30, 2012
Segment Reporting [Abstract]
Gas Utility segment, population of service area	2,200,000		2,200,000
Number of service area counties			ten
Number of entity subsidiaries			seven
Operating Segment Information [Abstract]
Total Operating Revenues	$ 165,289	$ 186,849	$ 869,905	$ 955,937
Operating Expenses [Abstract]
Natural and propane gas	43,233	46,641	410,189	364,556
Other Operation and Maintenance	42,404	38,351	123,245	125,028
Depreciation and amortization	11,519	10,186	33,742	30,450
Taxes, other than income taxes	12,968	10,842	49,525	45,602
Total Gas Utility Operating Expenses	110,124	106,020	616,701	565,636
Gas Marketing	40,583	65,420	133,959	279,784
Other Cost and Expense, Operating	2,301	364	13,029	1,784
Total Operating Expenses	153,008	171,804	763,689	847,204
Operating Income (Loss)	12,281	15,045	106,216	108,733
Net Economic Earnings (Losses)	8,164	8,896	68,911	62,216
Total assets	2,422,039	1,741,338	2,422,039	1,741,338	1,880,262
Reconciliation of Consolidated Net Economic Earnings to Consolidated Net Income [Abstract]
Total Net Economic Earnings above	8,164	8,896	68,911	62,216
Add: Unrealized gain (loss) on energy-related derivative contracts, net of tax	304	(963)	(722)	1,281
Add: Realized gain (loss) on economic hedges prior to sale of the physical commodity, net of tax	3	6	25	(138)
Add: Acquisition, divestiture, and restructuring activities, net of tax	(1,327)	0	(5,261)	0
Add: Lower of cost or market inventory adjustments, net of tax	(559)	494	(559)	(68)
Net Income	6,585	8,433	62,394	63,291
Gas Utility [Member]
Operating Segment Information [Abstract]
Revenues from external customers	131,517	116,459	735,726	665,981
Intersegment revenues	23	1,175	10,517	1,178
Total Operating Revenues	131,540	117,634	746,243	667,159
Operating Expenses [Abstract]
Natural and propane gas	52,847	48,662	435,329	375,634
Other Operation and Maintenance	42,090	38,351	122,936	125,028
Depreciation and amortization	11,519	10,186	33,742	30,450
Taxes, other than income taxes	12,968	10,842	49,525	45,602
Total Gas Utility Operating Expenses	119,424	108,041	641,532	576,714
Gas Marketing	0	0	0	0
Other Cost and Expense, Operating	0	0	0	0
Total Operating Expenses	119,424	108,041	641,532	576,714
Operating Income (Loss)	12,116	9,593	104,711	90,445
Net Economic Earnings (Losses)	6,834	4,597	62,372	51,448
Total assets	1,766,198	1,640,101	1,766,198	1,640,101
Reconciliation of Consolidated Net Economic Earnings to Consolidated Net Income [Abstract]
Total Net Economic Earnings above	6,834	4,597	62,372	51,448
Gas Marketing [Member]
Operating Segment Information [Abstract]
Revenues from external customers	33,433	70,014	129,937	288,036
Intersegment revenues	9,354	587	13,928	9,125
Total Operating Revenues	42,787	70,601	143,865	297,161
Operating Expenses [Abstract]
Natural and propane gas	0	0	0	0
Other Operation and Maintenance	0	0	0	0
Depreciation and amortization	0	0	0	0
Taxes, other than income taxes	0	0	0	0
Total Gas Utility Operating Expenses	0	0	0	0
Gas Marketing	40,583	65,420	133,959	279,787
Other Cost and Expense, Operating	0	0	0	0
Total Operating Expenses	40,583	65,420	133,959	279,787
Operating Income (Loss)	2,204	5,181	9,906	17,374
Net Economic Earnings (Losses)	1,632	3,605	7,281	9,589
Total assets	220,162	186,394	220,162	186,394
Reconciliation of Consolidated Net Economic Earnings to Consolidated Net Income [Abstract]
Total Net Economic Earnings above	1,632	3,605	7,281	9,589
Other [Member]
Operating Segment Information [Abstract]
Revenues from external customers	339	376	4,242	1,920
Intersegment revenues	546	259	1,124	778
Total Operating Revenues	885	635	5,366	2,698
Operating Expenses [Abstract]
Natural and propane gas	0	0	0	0
Other Operation and Maintenance	0	0	0	0
Depreciation and amortization	0	0	0	0
Taxes, other than income taxes	0	0	0	0
Total Gas Utility Operating Expenses	0	0	0	0
Gas Marketing	0	0	0	0
Other Cost and Expense, Operating	2,924	364	13,767	1,784
Total Operating Expenses	2,924	364	13,767	1,784
Operating Income (Loss)	(2,039)	271	(8,401)	914
Net Economic Earnings (Losses)	(302)	694	(742)	1,179
Total assets	584,488	150,117	584,488	150,117
Reconciliation of Consolidated Net Economic Earnings to Consolidated Net Income [Abstract]
Total Net Economic Earnings above	(302)	694	(742)	1,179
Unallocated and Eliminations [Member]
Operating Segment Information [Abstract]
Revenues from external customers	0	0	0	0
Intersegment revenues	(9,923)	(2,021)	(25,569)	(11,081)
Total Operating Revenues	(9,923)	(2,021)	(25,569)	(11,081)
Operating Expenses [Abstract]
Natural and propane gas	(9,614)	(2,021)	(25,140)	(11,078)
Other Operation and Maintenance	314	0	309	0
Depreciation and amortization	0	0	0	0
Taxes, other than income taxes	0	0	0	0
Total Gas Utility Operating Expenses	(9,300)	(2,021)	(24,831)	(11,078)
Gas Marketing	0	0	0	(3)
Other Cost and Expense, Operating	(623)	0	(738)	0
Total Operating Expenses	(9,923)	(2,021)	(25,569)	(11,081)
Operating Income (Loss)	0	0	0	0
Net Economic Earnings (Losses)	0	0	0	0
Total assets	(148,809)	(235,274)	(148,809)	(235,274)
Reconciliation of Consolidated Net Economic Earnings to Consolidated Net Income [Abstract]
Total Net Economic Earnings above	$ 0	$ 0	$ 0	$ 0

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FAIR VALUE MEASUREMENTS (Tables)

9 Months Ended

Jun. 30, 2013

Fair Value Disclosures [Abstract]

Fair Value Measurements, Measured on Recurring Basis

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

(Thousands)	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Effects of Netting and Cash Margin Receivables /Payables			Total
As of June 30, 2013
Assets
U. S. Stock/Bond Mutual Funds	$	13,980	$	—	$	—	$	—		$	13,980
NYMEX/ICE natural gas contracts	7,066		399		—		(4,635		)	2,830
NYMEX gasoline and heating oil contracts	136		—		—		(136		)	—
Natural gas commodity contracts	—		740		372		(243		)	869
Interest rate swaps	$	—	$	17,689	$	—	$	—		$	17,689
Total	$	21,182	$	18,828	$	372	$	(5,014	)	$	35,368
Liabilities
NYMEX/ICE natural gas contracts	$	3,950	$	329	$	—	$	(4,279	)	$	—
Natural gas commodity contracts	—		1,083		—		(243		)	840
Total	$	3,950	$	1,412	$	—	$	(4,522	)	$	840
As of September 30, 2012
Assets
U. S. Stock/Bond Mutual Funds	$	13,187	$	—	$	—	$	—		$	13,187
NYMEX/ICE natural gas contracts	7,411		994		—		(8,405		)	—
NYMEX gasoline and heating oil contracts	344		—		—		(344		)	—
Natural gas commodity contracts	—		3,060		113		(299		)	2,874
Total	$	20,942	$	4,054	$	113	$	(9,048	)	$	16,061
Liabilities
NYMEX/ICE natural gas contracts	$	12,253	$	1,891	$	—	$	(14,144	)	$	—
Natural gas commodity contracts	—		428		4		(299		)	133
Total	$	12,253	$	2,319	$	4	$	(14,443	)	$	133
As of June 30, 2012
Assets
U. S. Stock/Bond Mutual Funds	$	17,535	$	—	$	—	$	—		$	17,535
NYMEX/ICE natural gas contracts	3,273		1,240		—		(4,513		)	—
NYMEX gasoline and heating oil contracts	107		—		—		(107		)	—
Natural gas commodity contracts	—		4,288		107		(516		)	3,879
Total	$	20,915	$	5,528	$	107	$	(5,136	)	$	21,414
Liabilities
NYMEX/ICE natural gas contracts	$	22,141	$	1,590	$	—	$	(23,731	)	$	—
Natural gas commodity contracts	—		587		—		(516		)	71
Total	$	22,141	$	2,177	$	—	$	(24,247	)	$	71

Reconciliation of the Level 3 beginning and ending net derivative balances

The following is a reconciliation of the Level 3 beginning and ending net derivative balances:

	Three Months Ended June 30,						Nine Months Ended June 30,
(Thousands)	2013			2012			2013			2012
Beginning of period	$	93		$	58		$	109		$	13
Net settlements	33			(9		)	4			(16		)
Net losses related to derivatives not held   at end of period	(9		)	(8		)	(99		)	(68		)
Net gains related to derivatives still held   at end of period	255			66			358			178
End of period	$	372		$	107		$	372		$	107

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STATEMENTS OF CONSOLIDATED CASH FLOWS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012
Operating Activities:
Net Income	$ 62,394	$ 63,291
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, amortization, and accretion	34,721	30,900
Deferred income taxes and investment tax credits	13,208	22,448
Other - net	1,753	(425)
Changes in assets and liabilities:
Accounts receivable - net	1,685	(2,699)
Unamortized purchased gas adjustments	34,444	16,561
Deferred purchased gas costs	12,160	(25,429)
Accounts payable	21,717	(15,025)
Delayed customer billings - net	(36,465)	(9,005)
Taxes accrued	16,562	568
Natural gas stored underground	33,558	59,978
Other assets and liabilities	(28,693)	(12,964)
Net cash provided by (used in) operating activities	167,044	128,199
Investing Activities:
Capital expenditures	(96,816)	(76,780)
Other investments	(2,558)	(1,388)
Net cash used in investing activities	(99,374)	(78,168)
Financing Activities:
Issuance of long-term debt	125,000	0
Maturity of first mortgage bonds	(25,000)	0
Repayment of short-term debt - net	(40,100)	(46,000)
Non-employee directors' restricted stock awards	0	(565)
Changes in book overdrafts	(1,139)	223
Issuance of common stock	431,329	3,162
Dividends paid	(28,651)	(27,599)
Employees' taxes paid associated with restricted shares withheld upon vesting	(736)	(1,171)
Excess tax benefits from stock-based compensation	1,135	208
Other	(476)	(43)
Net cash provided by financing activities	461,362	(71,785)
Net Increase (Decrease) in Cash and Cash Equivalents	529,032	(21,754)
Cash and Cash Equivalents at Beginning of Period	27,457	43,277
Cash and Cash Equivalents at End of Period	556,489	21,523
Supplemental Disclosure of Cash Paid (Refunded) During the Period for:
Interest	22,666	21,811
Income taxes	$ (2,844)	$ 7,064

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS

9 Months Ended

Jun. 30, 2013

Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS

2.        PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS

Pension Plans

Laclede Gas 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 for quarters ended June 30, 2013 and 2012 were $4.2 million and $4.1 million, respectively, including amounts charged to construction. Pension costs for nine months ended June 30, 2013 and 2012 were $12.5 million and $15.9 million, respectively, including amounts charged to construction.

The net periodic pension costs include the following components:

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
(Thousands)	2013			2012			2013			2012
Service cost – benefits earned during the period	$	2,311		$	2,295		$	6,933		$	6,908
Interest cost on projected benefit obligation	4,066			4,824			12,198			14,535
Expected return on plan assets	(4,741		)	(4,899		)	(14,223		)	(14,697		)
Amortization of prior service cost	136			148			408			444
Amortization of actuarial loss	2,839			2,252			8,517			6,788
Loss on lump-sum settlement	12,346			—			12,346			3,407
Sub-total	16,957			4,620			26,179			17,385
Regulatory adjustment	(12,780		)	(484		)	(13,647		)	(1,451		)
Net pension cost	$	4,177		$	4,136		$	12,532		$	15,934

Pursuant to the provisions of the Laclede Gas pension plans, pension obligations may be satisfied by lump-sum cash payments. Pursuant to a Missouri Public Service Commission (MoPSC or Commission) 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 were $39.7 million and $6.4 million during the nine months ended June 30, 2013 and June 30, 2012, respectively.

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

The funding policy of Laclede Gas 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. Fiscal year 2013 contributions to the pension plans through June 30, 2013 were $23.4 million to the qualified trusts and approximately $0.4 million to the non-qualified plans. Laclede Gas does not expect to make additional contributions to its qualified, trusteed pension plans during the remaining three months of fiscal year 2013. Contributions to the non-qualified pension plans for the remaining three months of fiscal 2013 are anticipated to be approximately $0.8 million.

Postretirement Benefits

Laclede Gas 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 for both the quarters ended June 30, 2013 and 2012 were $2.4 million, including amounts charged to construction. Postretirement benefit costs for both the nine months ended June 30, 2013 and 2012 were $7.1 million, including amounts charged to construction.

Net periodic postretirement benefit costs consisted of the following components:

	Three Months Ended June 30,						Nine Months Ended June 30,
(Thousands)	2013			2012			2013			2012
Service cost – benefits earned during the period	$	2,534		$	2,015		$	7,601		$	6,045
Interest cost on accumulated postretirement benefit obligation	1,278			1,380			3,836			4,140
Expected return on plan assets	(1,082		)	(991		)	(3,244		)	(2,973		)
Amortization of transition obligation	24			34			70			102
Amortization of prior service cost (credit)	—			(518		)	2			(1,554		)
Amortization of actuarial loss	1,325			1,065			3,975			3,195
Sub-total	4,079			2,985			12,240			8,955
Regulatory adjustment	(1,699		)	(604		)	(5,097		)	(1,812		)
Net postretirement benefit cost	$	2,380		$	2,381		$	7,143		$	7,143

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. Laclede Gas established Voluntary Employees’ Beneficiary Association (VEBA) and Rabbi trusts as its external funding mechanisms. VEBA and Rabbi trusts’ assets consist primarily of money market securities and mutual funds invested in stocks and bonds.

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 $9.5 million effective January 1, 2011. The difference between these amounts and postretirement benefit cost based on the above and that otherwise would be included in the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income is deferred as a regulatory asset or regulatory liability.

Laclede Gas’ funding policy is to contribute amounts to the trusts equal to the periodic benefit cost calculated pursuant to GAAP as recovered in rates. Fiscal year 2013 contributions to the postretirement plans through June 30, 2013 were $8.2 million to the qualified trusts and approximately $0.4 million paid directly to participants from Laclede Gas' funds. Contributions to the postretirement plans for the remaining three months of fiscal year 2013 are anticipated to be $8.2 million to the qualified trusts and $0.2 million paid directly to participants from Laclede Gas’ funds.

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STOCKHOLDERS' EQUITY

9 Months Ended

Jun. 30, 2013

Stockholders' Equity Note [Abstract]

STOCKHOLDERS' EQUITY

5.        STOCKHOLDERS' EQUITY

On May 29, 2013, Laclede Group issued 10,005,000 shares of its common stock in a public offering at a price of $44.50 per share. Proceeds from the offering, net of underwriting expenses, were $428.0 million and were recorded as additions to common stock and paid-in capital on the consolidated balance sheets. The Company intends to use the proceeds from the offering to fund a portion of the pending acquisition of MGE, as discussed further in Note 13, Acquisition Agreements.

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STOCK-BASED COMPENSATION

9 Months Ended

Jun. 30, 2013

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

STOCK-BASED COMPENSATION

3.        STOCK-BASED COMPENSATION

Awards of stock-based compensation are made pursuant to The Laclede Group 2006 Equity Incentive Plan (2006 Plan). Refer to Note 3 of the Consolidated Financial Statements included in the Company’s Form 10-K for the fiscal year ended September 30, 2012 for descriptions of the plan.

Restricted Stock Awards

During the nine months ended June 30, 2013, the Company granted 108,419 performance-contingent restricted stock units to executive officers and key employees at a weighted average grant date fair value of $34.48 per share. This number represents the maximum shares that can be earned pursuant to the terms of the awards. Most of these stock units have a performance period ending September 30, 2015. While the participants have no interim voting rights on these stock units, dividends accrue during the performance period and are paid to the participants upon vesting, but are subject to forfeiture if the underlying stock units do not vest. The number of stock units that will ultimately vest is dependent upon the attainment of certain levels of earnings and other strategic goals, as well as the Company’s level of total shareholder return (TSR) during the performance period relative to a comparator group of companies. This TSR provision is considered a market condition under GAAP.

Activity of restricted stock and restricted stock units subject to performance and/or market conditions during the nine months ended June 30, 2013 is presented below:

	Restricted Stock/ Stock Units		Weighted Average Grant Date Fair Value
Nonvested at September 30, 2012	232,403		$	30.89
Granted (maximum shares that can be earned)	108,419		$	34.48
Vested	(37,436	)	$	27.02
Forfeited	(48,782	)	$	25.71
Nonvested at June 30, 2013	254,604		$	33.98

During the nine months ended June 30, 2013, the Company granted 58,924 shares of time-vested restricted stock and stock units to executive officers, key employees, and directors at a weighted average grant date fair value of $39.98 per share. Most of these shares were awarded on December 3, 2012 and vest December 3, 2015. In the interim, participants receive full voting rights and dividends, which are not subject to forfeiture.    

Time-vested restricted stock and stock unit activity for the nine months ended June 30, 2013 is presented below:

	Restricted Stock/ Stock Units		Weighted Average Grant Date Fair Value
Nonvested at September 30, 2012	115,115		$	36.54
Granted	58,924		$	39.98
Vested	(20,600	)	$	30.55
Forfeited	(6,500	)	$	38.54
Nonvested at June 30, 2013	146,939		$	38.67

During the nine months ended June 30, 2013, 58,036 shares of restricted stock and stock units (performance-contingent and time-vested), awarded on November 4, 2009, December 1, 2009, January 4, 2010, and May 3, 2010 vested. The Company withheld 18,898 of the vested shares at a weighted average price of $38.96 per share pursuant to elections by employees to satisfy tax withholding obligations.

Stock Option Awards

Stock option activity for the nine months ended June 30, 2013 is presented below:

	Stock Options		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (Years)	Aggregate Intrinsic Value ($000)
Outstanding at September 30, 2012	214,000		$	31.02
Granted	—		$	—
Exercised	(70,500	)	$	29.42
Forfeited	—		$	—
Expired	—		$	—
Outstanding at June 30, 2013	143,500		$	31.81	2.0	$	1,988
Fully Vested and Expected to Vest at June 30, 2013	143,500		$	31.81	2.0	$	1,988
Exercisable at June 30, 2013	143,500		$	31.81	2.0	$	1,988

The closing price of the Company’s common stock was $45.66 at June 30, 2013.

Equity Compensation Costs

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

	Three Months Ended June 30,						Nine Months Ended June 30,
(Thousands)	2013			2012			2013			2012
Total equity compensation cost	$	1,654		$	678		$	3,413		$	2,029
Compensation cost capitalized	(536		)	(230		)	(1,075		)	(589		)
Compensation cost recognized in net income, before income taxes	1,118			448			2,338			1,440
Income tax benefit recognized in net income	(428		)	(173		)	(895		)	(556		)
Compensation cost recognized in net income, net of income tax	$	690		$	275		$	1,443		$	884

As of June 30, 2013, there was $6.1 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements. That cost is expected to be recognized over a weighted average period of 2.1 years.

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CONCENTRATIONS OF CREDIT RISK (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Jun. 30, 2013
Concentration Risk [Line Items]
Number of large counterparties for which credit risk is disclosed	5
Number of investment-grade rated counterparties for which credit risk is disclosed, in terms of net accounts receivable exposure	5
Energy Producers And Their Affiliates [Member]
Concentration Risk [Line Items]
Accounts receivable	$ 22.2
Net receivable amount	12.0
Utility Companies And Their Affiliates [Member]
Concentration Risk [Line Items]
Accounts receivable	18.6
Net receivable amount	11.3
Largest Counterparties [Member]
Concentration Risk [Line Items]
Accounts receivable	25.7
Net receivable amount	$ 17.0

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INFORMATION BY OPERATING SEGMENT (Tables)

9 Months Ended

Jun. 30, 2013

Segment Reporting [Abstract]

Schedule of operating segment information

			Gas
(Thousands)	Gas Utility		Marketing		Other			Eliminations			Consolidated
Three Months Ended June 30, 2013
Revenues from external customers	$	131,517	$	33,433	$	339		$	—		$	165,289
Intersegment revenues	23		9,354		546			(9,923		)	—
Total Operating Revenues	131,540		42,787		885			(9,923		)	165,289
Operating Expenses
Gas Utility
Natural and Propane Gas	52,847		—		—			(9,614		)	43,233
Other Operation and Maintenance Expenses	42,090		—		—			314			42,404
Depreciation and Amortization	11,519		—		—			—			11,519
Taxes, Other than Income Taxes	12,968		—		—			—			12,968
Total Gas Utility Operating Expenses	119,424		—		—			(9,300		)	110,124
Gas Marketing	—		40,583		—			—			40,583
Other	—		—		2,924			(623		)	2,301
Total Operating Expenses	119,424		40,583		2,924			(9,923		)	153,008
Operating Income	12,116		2,204		(2,039		)	—			12,281
Net Economic Earnings (Losses)	6,834		1,632		(302		)	—			8,164
Total assets	1,766,198		220,162		584,488			(148,809		)	2,422,039
Three Months Ended June 30, 2012
Revenues from external customers	$	116,459	$	70,014	$	376		$	—		$	186,849
Intersegment revenues	1,175		587		259			(2,021		)	—
Total Operating Revenues	117,634		70,601		635			(2,021		)	186,849
Operating Expenses
Gas Utility
Natural and Propane Gas	48,662		—		—			(2,021		)	46,641
Other Operation and Maintenance Expenses	38,351		—		—			—			38,351
Depreciation and Amortization	10,186		—		—			—			10,186
Taxes, Other than Income Taxes	10,842		—		—			—			10,842
Total Gas Utility Operating Expenses	108,041		—		—			(2,021		)	106,020
Gas Marketing	—		65,420		—			—			65,420
Other	—		—		364			—			364
Total Operating Expenses	108,041		65,420		364			(2,021		)	171,804
Operating Income	9,593		5,181		271			—			15,045
Net Economic Earnings	4,597		3,605		694			—			8,896
Total assets	1,640,101		186,394		150,117			(235,274		)	1,741,338

			Gas
(Thousands)	Gas Utility		Marketing		Other			Eliminations			Consolidated
Nine Months Ended June 30, 2013
Revenues from external customers	$	735,726	$	129,937	$	4,242		$	—		$	869,905
Intersegment revenues	10,517		13,928		1,124			(25,569		)	—
Total Operating Revenues	746,243		143,865		5,366			(25,569		)	869,905
Operating Expenses
Gas Utility
Natural and Propane Gas	435,329		—		—			(25,140		)	410,189
Other Operation and Maintenance Expenses	122,936		—		—			309			123,245
Depreciation and Amortization	33,742		—		—			—			33,742
Taxes, Other than Income Taxes	49,525		—		—			—			49,525
Total Gas Utility Operating Expenses	641,532		—		—			(24,831		)	616,701
Gas Marketing	—		133,959		—			—			133,959
Other	—		—		13,767			(738		)	13,029
Total Operating Expenses	641,532		133,959		13,767			(25,569		)	763,689
Operating Income	104,711		9,906		(8,401		)	—			106,216
Net Economic Earnings (Losses)	62,372		7,281		(742		)	—			68,911
Total assets	1,766,198		220,162		584,488			(148,809		)	2,422,039
Nine Months Ended June 30, 2012
Revenues from external customers	$	665,981	$	288,036	$	1,920		$	—		$	955,937
Intersegment revenues	1,178		9,125		778			(11,081		)	—
Total Operating Revenues	667,159		297,161		2,698			(11,081		)	955,937
Operating Expenses
Gas Utility
Natural and Propane Gas	375,634		—		—			(11,078		)	364,556
Other Operation and Maintenance Expenses	125,028		—		—			—			125,028
Depreciation and Amortization	30,450		—		—			—			30,450
Taxes, Other than Income Taxes	45,602		—		—			—			45,602
Total Gas Utility Operating Expenses	576,714		—		—			(11,078		)	565,636
Gas Marketing	—		279,787		—			(3		)	279,784
Other	—		—		1,784			—			1,784
Total Operating Expenses	576,714		279,787		1,784			(11,081		)	847,204
Operating Income	90,445		17,374		914			—			108,733
Net Economic Earnings	51,448		9,589		1,179			—			62,216
Total assets	1,640,101		186,394		150,117			(235,274		)	1,741,338

Schedule of the reconciliation of consolidated net economic earnings to consolidated net income

Reconciliation of Consolidated Net Economic Earnings to Consolidated Net Income
	Three Months Ended						Nine Months Ended
	June 30,						June 30,
(Thousands)	2013			2012			2013			2012
Total Net Economic Earnings above	$	8,164		$	8,896		$	68,911		$	62,216
Add: Unrealized gain (loss) on energy-related derivative
contracts, net of tax	304			(963		)	(722		)	1,281
Add:  Lower of cost or market inventory
adjustments, net of tax	(559		)	494			(559		)	(68		)
Add:  Realized gain (loss) on economic hedges prior to sale of
the physical commodity, net of tax	3			6			25			(138		)
Add:  Acquisition, divestiture, and restructuring activities,
net of tax	(1,327		)	—			(5,261		)	—
Net Income	$	6,585		$	8,433		$	62,394		$	63,291

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 2 (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Dec. 31, 2010
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]
Extent of Lump-sum payments recognized, percentage	100%
Lump-sum payments recognized as settlements	$ 39.7	$ 6.4
Implementation period used to calculate return on plan assets (in years)	four-year
Gains or losses includible in cost amortized to extent exceeds benefit obligations or market-related value of plan assets, percentage	10.00%
Recovery in rates for the qualified pension plans base allowance			15.5
Recovery in rates for postretirement benefit			9.5
Defined Benefit Plan, Pension Plans, Qualified Trusts, Contributions by Employer, Fiscal Year To Date	23.4
Defined Benefit Plan, Pension Plans, Non-Qualified Plans, Contributions by Employer, Fiscal Year To Date	0.4
Defined Benefit Plan, Pension Plans, Non-Qualified Trusts, Estimated Future Employer Contributions Remaining For Current Fiscal Year, Description	0.8
Medical insurance available until age is reached after early retirement	65
Amortization period for transition obligation excluded from postretirement benefit cost (in years)	20 years
Defined Benefit Plan, Other Postretirement Benefit Plans, Non-Qualified Plans, Contributions by Employer, Fiscal Year To Date	0.4
Defined Benefit Plan, Other Postretirement Benefit Plans, Qualified Trusts, Contributions by Employer, Fiscal Year to Date	8.2
Defined Benefit Plan, Other Postretirement Benefit Plans, Qualified Trusts, Estimated Future Employer Contributions Remaining For Current Fiscal Year, Description	8.2
Defined Benefit Plan, Other Postretirement Benefit Plans, Estimated Future Payment Directly Participants, Description	$ 0.2

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FAIR VALUE MEASUREMENTS (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013 Fair Value, Measurements, Recurring [Member] Quoted Prices in Active Markets (Level 1) [Member]	Sep. 30, 2012 Fair Value, Measurements, Recurring [Member] Quoted Prices in Active Markets (Level 1) [Member]	Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Quoted Prices in Active Markets (Level 1) [Member]	Jun. 30, 2013 Fair Value, Measurements, Recurring [Member] Significant Observable Inputs (Level 2) [Member]	Sep. 30, 2012 Fair Value, Measurements, Recurring [Member] Significant Observable Inputs (Level 2) [Member]	Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Significant Observable Inputs (Level 2) [Member]	Jun. 30, 2013 Fair Value, Measurements, Recurring [Member] Significant Unobservable Inputs (Level 3) [Member]	Sep. 30, 2012 Fair Value, Measurements, Recurring [Member] Significant Unobservable Inputs (Level 3) [Member]	Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Significant Unobservable Inputs (Level 3) [Member]	Jun. 30, 2013 Fair Value, Measurements, Recurring [Member] Effects of Netting and Cash Margin Receivables Payables [Member]	Sep. 30, 2012 Fair Value, Measurements, Recurring [Member] Effects of Netting and Cash Margin Receivables Payables [Member]	Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Effects of Netting and Cash Margin Receivables Payables [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
U. S. Stock/Bond Mutual Funds					$ 13,980	$ 13,187	$ 17,535	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0
NYMEX/ICE natural gas contracts- Asset					7,066	7,411	3,273	399	994	1,240	0	0	0	(4,635)	(8,405)	(4,513)
NYMEX gasoline and heating oil contracts- Asset					136	344	107	0	0	0	0	0	0	(136)	(344)	(107)
Natural gas commodity contracts- Asset					0	0	0	740	3,060	4,288	372	113	107	(243)	(299)	(516)
Interest Rate Swaps Asset at Fair Value					0			17,689			0			0
Total Assets					21,182	20,942	20,915	18,828	4,054	5,528	372	113	107	(5,014)	(9,048)	(5,136)
NYMEX/ICE natural gas contracts- Liabilities					3,950	12,253	22,141	329	1,891	1,590	0	0	0	(4,279)	(14,144)	(23,731)
Natural gas commodity contracts- Liabilities					0	0	0	1,083	428	587	0	4	0	(243)	(299)	(516)
Total Liabilities					3,950	12,253	22,141	1,412	2,319	2,177	0	4	0	(4,522)	(14,443)	(24,247)
Beginning of period	93	58	109	13
Settlements	33	(9)	4	(16)
Net Gain Loss From Derivatives Not Held At End Of Period	(9)	(8)	(99)	(68)
Net gains related to derivatives still held at end of period	255	66	358	178
End of period	$ 372	$ 107	$ 372	$ 107

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ACQUISITION AGREEMENTS (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	9 Months Ended
	Jun. 30, 2013	Jun. 30, 2013	Mar. 31, 2013
Business Combinations [Line Items]
Pending Business Acquisition, Stated Purchase Price, Total	$ 1,035	$ 1,035
Acquisition Related Costs	1.4	5.3
Reverse break up fee	73.1	73.1
Number of Banks	9	9
Bridge Facility	525	525	1,020
Missouri Gas Energy (MGE) [Member]
Business Combinations [Line Items]
Pending Business Acquisition, Stated Purchase Price, Total	975	975
New England Gas Company (NEG) [Member]
Business Combinations [Line Items]
Pending Business Acquisition, Stated Purchase Price, Total	60	60
Pending Business Acquisition, Debt to be Assumed	19.5	19.5
Pending Business Acquisition, Cash Deposited	3.0	3.0
Pending Business Acquisition, Cash to be Received	$ 11	$ 11

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STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (UNAUDITED) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Statement of Other Comprehensive Income [Abstract]
Net Income	$ 6,585	$ 8,433	$ 62,394	$ 63,291
Net gains (losses) on cash flow hedging derivative instruments:
Net hedging gain (loss) arising during the period	27,614	(1,733)	21,414	6,420
Reclassification adjustment for losses (gains) included in net income	1,318	(6,171)	3,544	(8,593)
Net unrealized gain (loss) on cash flow hedging derivative instruments	28,932	(7,904)	24,958	(2,173)
Defined benefit pension and other postretirement benefit plans:
Net actuarial loss arising during the period	0	0	0	(2,366)
Amortization of actuarial loss included in net periodic pension and postretirement benefit cost	90	66	271	3,639
Net defined benefit pension and other postretirement plans	90	66	271	1,273
Other Comprehensive Income (Loss), Before Tax	29,022	(7,838)	25,229	(900)
Income Tax (Benefit) Expense Related to Items of Other Comprehensive Income	10,846	(3,028)	9,429	(348)
Other Comprehensive Income (Loss), Net of Tax	18,176	(4,810)	15,800	(552)
Comprehensive Income	$ 24,761	$ 3,623	$ 78,194	$ 62,739

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

9 Months Ended

Jun. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

8.        DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Laclede Gas 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 Purchased Gas Adjustment (PGA) Clause, through which the MoPSC allows the Utility to recover gas supply costs, subject to prudence review by the MoPSC. Accordingly, Laclede Gas does not expect any adverse earnings impact as a result of the use of these derivative instruments. The Utility does not designate these instruments as hedging instruments for financial reporting purposes because gains or losses associated with the use of these derivative instruments are deferred and recorded as regulatory assets or regulatory liabilities pursuant to ASC Topic 980, “Regulated Operations,” and, as a result, have no direct impact on the Statements of Consolidated Income. The timing of the operation of the PGA Clause may cause interim variations in short-term cash flows, because the Utility is subject to cash margin requirements associated with changes in the values of these instruments. Nevertheless, carrying costs associated with such requirements are recovered through the PGA Clause.

From time to time, Laclede Gas 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 June 30, 2013, Laclede Gas held 0.4 million gallons of gasoline futures contracts at an average price of $2.25 per gallon. Most of these contracts, the longest of which extends to April 2014, are designated as cash flow hedges of forecasted transactions pursuant to ASC Topic 815. The gains or losses on these derivative instruments are not subject to the Utility’s PGA Clause.

In the course of its business, Laclede Group’s gas marketing subsidiary, LER, which includes its wholly owned subsidiary LER Storage Services, Inc., enters into commitments associated with the purchase or sale of natural gas. Certain of LER’s derivative natural gas contracts are designated as normal purchases or normal sales and, as such, are excluded from the scope of ASC Topic 815 and are accounted for as executory contracts on an accrual basis. Any of LER’s derivative natural gas contracts that are not designated as normal purchases or normal sales are accounted for at fair value. At June 30, 2013, the fair values of 57.7 million MMBtu of non-exchange traded natural gas commodity contracts were reflected in the Consolidated Balance Sheet. Of these contracts, 34.3 million MMBtu will settle during fiscal year 2013, 21.6 million MMBtu will settle during fiscal year 2014, while the remaining 1.8 million MMBtu will settle during fiscal year 2015. These contracts have not been designated as hedges; therefore, changes in the fair value of these contracts are reported in earnings each period. Furthermore, LER manages the price risk associated with its fixed-priced commitments by either closely matching the offsetting physical purchase or sale of natural gas at fixed prices or through the use of NYMEX or Ice Clear Europe (ICE) futures, swap, and option contracts to lock in margins. At June 30, 2013, LER’s unmatched fixed-price positions were not material to Laclede Group’s financial position or results of operations. LER’s NYMEX and ICE natural gas futures, swap, and option contracts used to lock in margins may be designated as cash flow hedges of forecasted transactions for financial reporting purposes.

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

	Laclede Gas Company			Laclede Energy Resources, Inc.
	MMBtu (millions)	Avg. Price Per MMBtu		MMBtu (millions)	Avg. Price Per MMBtu
Open short futures positions
Fiscal 2013	—	$	—	5.00	$	4.03
Fiscal 2014	—	—		6.04	3.84
Fiscal 2015	—	—		0.28	4.18
Open long futures positions
Fiscal 2013	3.42	$	3.42	0.63	$	3.82
Fiscal 2014	4.87	3.97		0.01	4.03
Fiscal 2015	—	—		2.42	3.91

At June 30, 2013, Laclede Gas had 17.0 million MMBtu of other price mitigation in place through the use of NYMEX natural gas option-based strategies while LER had none.

In February 2013, Laclede Group entered into certain interest rate swap agreements to effectively lock in interest rates on a portion of the long-term debt it anticipates issuing to finance its pending acquisition of Missouri Gas Energy (MGE). These derivative instruments have been designated as cash flow hedges of forecasted transactions. These forward starting swaps involve the payment of a fixed interest rate and the receipt of a floating interest rate (the London Interbank Offered Rate, also known as LIBOR) over the terms specified in the contracts. At June 30, 2013, the notional amount of interest rate swaps outstanding was $355 million with stated maturities ranging from 2018 to 2043 and fixed interest rates ranging between 1.28% and 3.14%.

Derivative instruments designated as cash flow hedges of forecasted transactions are recognized on the Consolidated Balance Sheets at fair value and the change in the fair value of the effective portion of these hedge instruments is recorded, net of tax, in other comprehensive income (OCI). Accumulated other comprehensive income (AOCI) is a component of Total Common Stock Equity. Amounts are reclassified from AOCI into earnings when the hedged items affect net income, using the same revenue or expense category that the hedged item impacts. Based on market prices at June 30, 2013, it is expected that approximately $5.3 million of pre-tax unrealized gains will be reclassified into the Statements of Consolidated Income during the next twelve months. Cash flows from hedging transactions are classified in the same category as the cash flows from the items that are being hedged in the Statements of Consolidated Cash Flows.

The Effect of Derivative Instruments on the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income
		Three Months Ended						Nine Months Ended
	Location of Gain (Loss)	June 30,						June 30,
(Thousands)	Recorded in Income	2013			2012			2013			2012
Derivatives in Cash Flow Hedging Relationships
Effective portion of gain (loss) recognized in OCI on derivatives:
NYMEX/ICE natural gas contracts		$	5,501		$	(1,802	)	$	3,646		$	6,218
NYMEX gasoline and heating oil contracts		(125		)	69			79			202
Interest rate swaps		22,238			—			17,689			—
Total		$	27,614		$	(1,733	)	$	21,414		$	6,420
Effective portion of gain (loss) reclassified from AOCI to income:
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	$	(1,570	)	$	7,646		$	(3,229	)	$	18,434
	Gas Marketing Operating Expenses	199			(1,492		)	(453		)	(9,861		)
Sub-total		(1,371		)	6,154			(3,682		)	8,573
NYMEX gasoline and heating oil contracts	Gas Utility Other Operations and Maintenance Expenses	53			17			138			20
Total		$	(1,318	)	$	6,171		$	(3,544	)	$	8,593
Ineffective portion of gain (loss) on derivatives recognized in income:
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	$	16		$	(84	)	$	(396	)	$	(15	)
	Gas Marketing Operating Expenses	(22		)	(95		)	(151		)	(291		)
Sub-total		(6		)	(179		)	(547		)	(306		)
NYMEX gasoline and heating oil contracts	Gas Utility Other Operations and Maintenance Expenses	5			(46		)	(127		)	(12		)
Total		$	(1	)	$	(225	)	$	(674	)	$	(318	)
Derivatives Not Designated as Hedging Instruments *
Gain (loss) recognized in income on derivatives:
Natural gas commodity contracts	Gas Marketing Operating Revenues	$	(993	)	$	2,641		$	(218	)	$	3,431
	Gas Marketing Operating Expenses	—			—			—			687
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	1,163			(1,123		)	551			425
	Gas Marketing Operating Expenses	—			(655		)	—			(625		)
NYMEX gasoline and heating oil contracts	Other Income and (Income Deductions) - Net	(5		)	(11		)	41			2
Total		$	165		$	852		$	374		$	3,920

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

Fair Value of Derivative Instruments in the Consolidated Balance Sheet at June 30, 2013
	Asset Derivatives				Liability Derivatives
(Thousands)	Balance Sheet Location	Fair Value		*	Balance Sheet Location	Fair  Value		*
Derivatives designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets	$	4,574		Derivative Instrument Assets	$	437
NYMEX/ICE natural gas contracts	Other Deferred Charges	77			Other Deferred Charges	9
NYMEX gasoline and heating oil contracts	Accounts Receivable – Other	136			Accounts Receivable – Other	—
Interest rate swaps	Derivative Instrument Assets	17,689			Derivative Instrument Assets	—
Sub-total		22,476				446
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets	859			Derivative Instrument Assets	146
	Accounts Receivable – Other	1,956			Accounts Receivable – Other	3,688
Natural gas commodity contracts	Derivative Instrument Assets	944			Derivative Instrument Assets	89
	Other Deferred Charges	14			Other Deferred Charges	—
	Other Current Liabilities	122			Other Current Liabilities	836
	Other Deferred Credits	33			Other Deferred Credits	159
Sub-total		3,928				4,918
Total derivatives		$	26,404			$	5,364
Fair Value of Derivative Instruments in the Consolidated Balance Sheet at September 30, 2012
	Asset Derivatives				Liability Derivatives
(Thousands)	Balance Sheet Location	Fair Value		*	Balance Sheet Location	Fair Value		*
Derivatives designated as hedging instruments
NYMEX/ICE natural gas contracts	Accounts Receivable - Other	$	405		Accounts Receivable - Other	$	3,413
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	334			Accounts Receivable - Other	—
Sub-total		739				3,413
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Accounts Receivable - Other	8,000			Accounts Receivable - Other	10,731
Natural gas commodity contracts	Derivative Instrument Assets	3,150			Derivative Instrument Assets	295
	Other Current Liabilities	4			Other Current Liabilities	137
	Other Deferred Charges	19			Other Deferred Charges	—
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	10			Accounts Receivable - Other	—
Sub-total		11,183				11,163
Total derivatives		$	11,922			$	14,576

Fair Value of Derivative Instruments in the Consolidated Balance Sheet at June 30, 2012
	Asset Derivatives				Liability Derivatives
(Thousands)	Balance Sheet Location	Fair Value		*	Balance Sheet Location	Fair Value		*
Derivatives designated as hedging instruments
NYMEX/ICE natural gas contracts	Accounts Receivable - Other	$	1,064		Accounts Receivable - Other	$	2,529
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	106			Accounts Receivable - Other	—
Sub-total		1,170				2,529
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Accounts Receivable - Other	3,449			Accounts Receivable - Other	21,202
Natural gas commodity contracts	Derivative Instrument Assets	4,356			Derivative Instrument Assets	478
	Other Current Liabilities	39			Other Current Liabilities	109
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	1			Accounts Receivable - Other	—
Sub-total		7,845				21,789
Total derivatives		$	9,015			$	24,318

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

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

(Thousands)	June 30, 2013			Sept. 30, 2012			June 30, 2012
Fair value of asset derivatives presented above	$	26,404		$	11,922		$	9,015
Fair value of cash margin receivables offset with derivatives	1,596			5,478			19,111
Netting of assets and liabilities with the same counterparty	(6,612		)	(14,526		)	(24,247		)
Total	$	21,388		$	2,874		$	3,879
Derivative Instrument Assets, per Consolidated Balance Sheets:
Derivative instrument assets	$	21,279		$	2,855		$	3,879
Other deferred charges	109			19			—
Total	$	21,388		$	2,874		$	3,879
Fair value of liability derivatives presented above	$	5,364		$	14,576		$	24,318
Fair value of cash margin payables offset with derivatives	2,088			83			—
Netting of assets and liabilities with the same counterparty	(6,612		)	(14,526		)	(24,247		)
Total	$	840		$	133		$	71
Derivative Instrument Liabilities, per Consolidated Balance Sheets:
Other Current Liabilities	$	727		$	133		$	71
Other Deferred Credits	113			—			—
Total	$	840		$	133		$	71

Additionally, at June 30, 2013, September 30, 2012, and June 30, 2012, the Company had $3.6 million, $10.0 million, and $10.6 million, respectively, in cash margin receivables not offset with derivatives, that are presented in Accounts Receivable - Other.

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CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical)	Jun. 30, 2013	Sep. 30, 2012	Jun. 30, 2012
Capitalization:
Common Stock Shares Authorized (in shares)	70,000,000	70,000,000	70,000,000
Common Stock Shares Issued (in shares)	32,675,659	22,539,431	22,505,440

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STATEMENTS OF CONSOLIDATED INCOME (UNAUDITED) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Operating Revenues:
Gas Utility	$ 131,517	$ 116,459	$ 735,726	$ 665,981
Gas Marketing	33,433	70,014	129,937	288,036
Other	339	376	4,242	1,920
Total Operating Revenues	165,289	186,849	869,905	955,937
Gas Utility
Natural and propane gas	43,233	46,641	410,189	364,556
Other operation and maintenance expense	42,404	38,351	123,245	125,028
Depreciation and amortization	11,519	10,186	33,742	30,450
Taxes, other than income taxes	12,968	10,842	49,525	45,602
Total Gas Utility Operating Expenses	110,124	106,020	616,701	565,636
Gas Marketing	40,583	65,420	133,959	279,784
Other	2,301	364	13,029	1,784
Total Operating Expenses	153,008	171,804	763,689	847,204
Operating Income	12,281	15,045	106,216	108,733
Other (Income Deductions) and Income - Net	(398)	451	2,024	3,771
Interest Charges:
Interest on long-term debt	6,266	5,739	17,393	17,218
Other interest charges	594	427	2,197	1,541
Total Interest Charges	6,860	6,166	19,590	18,759
Income Before Income Taxes	5,023	9,330	88,650	93,745
Income Tax (Benefit) Expense	(1,562)	897	26,256	30,454
Net Income	$ 6,585	$ 8,433	$ 62,394	$ 63,291
Weighted Average Number of Common Shares Outstanding:
Basic	26,110	22,282	23,634	22,243
Diluted	26,194	22,357	23,708	22,318
Basic Earnings Per Share of Common Stock:
Basic Earnings Per Share of Common Stock	$ 0.25	$ 0.38	$ 2.62	$ 2.83
Diluted Earnings Per Share of Common Stock:
Diluted Earnings Per Share of Common Stock	$ 0.25	$ 0.38	$ 2.62	$ 2.82
Dividends Declared Per Share of Common Stock	$ 0.425	$ 0.415	$ 1.275	$ 1.245

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Part 1 (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2013	Sep. 30, 2012	Jun. 30, 2012
Accounting Policies [Abstract]
Accrued Unbilled Revenue	$ 8.7	$ 11.6	$ 9.0

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EARNINGS PER COMMON SHARE (Tables)

9 Months Ended

Jun. 30, 2013

Earnings Per Share [Abstract]

Earnings Per Common Share

	Three Months Ended June 30,				Nine Months Ended June 30,
(Thousands, Except Per Share Amounts)	2013		2012		2013		2012
Basic EPS:
Net Income	$	6,585	$	8,433	$	62,394	$	63,291
Less: Income allocated to participating securities	81		42		389		356
Net Income Available to Common Shareholders	$	6,504	$	8,391	$	62,005	$	62,935
Weighted Average Shares Outstanding	26,110		22,282		23,634		22,243
Earnings Per Share of Common Stock	$	0.25	$	0.38	$	2.62	$	2.83
Diluted EPS:
Net Income	$	6,585	$	8,433	$	62,394	$	63,291
Less: Income allocated to participating securities	81		42		388		355
Net Income Available to Common Shareholders	$	6,504	$	8,391	$	62,006	$	62,936
Weighted Average Shares Outstanding	26,110		22,282		23,634		22,243
Dilutive Effect of Stock Options, Restricted Stock,
and Restricted Stock Units	84		75		74		75
Weighted Average Diluted Shares	26,194		22,357		23,708		22,318
Earnings Per Share of Common Stock	$	0.25	$	0.38	$	2.62	$	2.82
Outstanding Shares Excluded from the
Calculation of Diluted EPS Attributable to:
Restricted stock and stock units subject to
performance and/or market conditions	196		204		196		202

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COMMITMENTS AND CONTINGENCIES (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Jun. 30, 2013	Jul. 30, 2013 Laclede Gas [Member]	Jul. 30, 2013 LER [Member]
Commitments [Abstract]
Minimum total payments required for natural gas contracts	$ 321
Approximate contract amount of project	1.5
Contingencies and Indemnifications [Abstract]
Number Of Former Manufactured Gas Plant Sites In Missouri	3
Number of former manufactured gas plant (MGP) sites in Shrewsbury, Missouri	1
Number of former manufactured gas plant (MGP) sites in the City of St. Louis	2
Minimum cost estimate for a one-time contractual transfer of risk	5.8
Maximum cost estimate for a one-time contractual transfer of risk	36.3
Proposed disallowance amount related to purchase gas costs	6.0
Amount Remaining On Deposit With Brokerage Firm		$ 0.9	$ 0.2

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Part 2) (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Sep. 30, 2012	Jun. 30, 2012
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 26,404	$ 11,922	$ 9,015
Derivative Liability, Fair Value, Gross Liability	5,364	14,576	24,318
NYMEX Natural Gas Contracts [Member] | Designated as Hedging Instrument [Member] | Derivative Instruments Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	4,574
Derivative Liability, Fair Value, Gross Liability	437
NYMEX Natural Gas Contracts [Member] | Designated as Hedging Instrument [Member] | Other Deferred Charges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	77
Derivative Liability, Fair Value, Gross Liability	9
NYMEX Natural Gas Contracts [Member] | Designated as Hedging Instrument [Member] | Accounts Receivable Other [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		405	1,064
Derivative Liability, Fair Value, Gross Liability		3,413	2,529
NYMEX Natural Gas Contracts [Member] | Not Designated as Hedging Instrument [Member] | Derivative Instruments Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	859
Derivative Liability, Fair Value, Gross Liability	146
NYMEX Natural Gas Contracts [Member] | Not Designated as Hedging Instrument [Member] | Accounts Receivable Other [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	1,956	8,000	3,449
Derivative Liability, Fair Value, Gross Liability	3,688	10,731	21,202
Natural Gas Commodity Contracts [Member] | Not Designated as Hedging Instrument [Member] | Derivative Instruments Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	944	3,150	4,356
Derivative Liability, Fair Value, Gross Liability	89	295	478
Natural Gas Commodity Contracts [Member] | Not Designated as Hedging Instrument [Member] | Other Deferred Credits [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	33
Derivative Liability, Fair Value, Gross Liability	159
Natural Gas Commodity Contracts [Member] | Not Designated as Hedging Instrument [Member] | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	122	4	39
Derivative Liability, Fair Value, Gross Liability	836	137	109
Natural Gas Commodity Contracts [Member] | Not Designated as Hedging Instrument [Member] | Other Deferred Charges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	14	19
Derivative Liability, Fair Value, Gross Liability	0	0
NYMEX Gasoline and Heating Oil Contracts [Member] | Designated as Hedging Instrument [Member] | Accounts Receivable Other [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	136	334	106
Derivative Liability, Fair Value, Gross Liability	0	0	0
NYMEX Gasoline and Heating Oil Contracts [Member] | Not Designated as Hedging Instrument [Member] | Accounts Receivable Other [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		10	1
Derivative Liability, Fair Value, Gross Liability		0	0
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Derivative Instruments Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	17,689
Derivative Liability, Fair Value, Gross Liability	$ 0

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STOCKHOLDERS' EQUITY STOCKHOLDERS' EQUITY (Details) (USD $) In Millions, except Share data, unless otherwise specified	9 Months Ended
	Jun. 30, 2013	May 29, 2013
Stockholders' Equity Note [Abstract]
Common Stock Issuance Date	May 29, 2013
Number of Common Stock Shares Issued	10,005,000
Share Price		$ 44.50
Proceeds from Common Stock Issuance, Net	$ 428.0

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FAIR VALUE OF FINANCIAL INSTRUMENTS (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2013	Sep. 30, 2012	Jun. 30, 2012	Sep. 30, 2011
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	$ 556,489	$ 27,457	$ 21,523	$ 43,277
Carrying (Reported) Amount, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	556,489	27,457	21,523
Short-term debt	0	40,100	0
Long-term debt, including current portion	464,444	364,416	364,401
Estimate of Fair Value, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	556,489	27,457	21,523
Short-term debt	0	40,100	0
Long-term debt, including current portion	506,328	452,768	445,961
Quoted Prices in Active Markets (Level 1) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	421,518	17,380	11,560
Short-term debt	0	0
Long-term debt, including current portion	0	0	0
Significant Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	134,971	10,077	9,963
Short-term debt	0	40,100	0
Long-term debt, including current portion	506,328	452,768	445,961
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	0	0	0
Short-term debt	0	0	0
Long-term debt, including current portion	$ 0	$ 0	$ 0

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FAIR VALUE MEASUREMENTS

9 Months Ended

Jun. 30, 2013

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

7.        FAIR VALUE MEASUREMENTS

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

(Thousands)	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Effects of Netting and Cash Margin Receivables /Payables			Total
As of June 30, 2013
Assets
U. S. Stock/Bond Mutual Funds	$	13,980	$	—	$	—	$	—		$	13,980
NYMEX/ICE natural gas contracts	7,066		399		—		(4,635		)	2,830
NYMEX gasoline and heating oil contracts	136		—		—		(136		)	—
Natural gas commodity contracts	—		740		372		(243		)	869
Interest rate swaps	$	—	$	17,689	$	—	$	—		$	17,689
Total	$	21,182	$	18,828	$	372	$	(5,014	)	$	35,368
Liabilities
NYMEX/ICE natural gas contracts	$	3,950	$	329	$	—	$	(4,279	)	$	—
Natural gas commodity contracts	—		1,083		—		(243		)	840
Total	$	3,950	$	1,412	$	—	$	(4,522	)	$	840
As of September 30, 2012
Assets
U. S. Stock/Bond Mutual Funds	$	13,187	$	—	$	—	$	—		$	13,187
NYMEX/ICE natural gas contracts	7,411		994		—		(8,405		)	—
NYMEX gasoline and heating oil contracts	344		—		—		(344		)	—
Natural gas commodity contracts	—		3,060		113		(299		)	2,874
Total	$	20,942	$	4,054	$	113	$	(9,048	)	$	16,061
Liabilities
NYMEX/ICE natural gas contracts	$	12,253	$	1,891	$	—	$	(14,144	)	$	—
Natural gas commodity contracts	—		428		4		(299		)	133
Total	$	12,253	$	2,319	$	4	$	(14,443	)	$	133
As of June 30, 2012
Assets
U. S. Stock/Bond Mutual Funds	$	17,535	$	—	$	—	$	—		$	17,535
NYMEX/ICE natural gas contracts	3,273		1,240		—		(4,513		)	—
NYMEX gasoline and heating oil contracts	107		—		—		(107		)	—
Natural gas commodity contracts	—		4,288		107		(516		)	3,879
Total	$	20,915	$	5,528	$	107	$	(5,136	)	$	21,414
Liabilities
NYMEX/ICE natural gas contracts	$	22,141	$	1,590	$	—	$	(23,731	)	$	—
Natural gas commodity contracts	—		587		—		(516		)	71
Total	$	22,141	$	2,177	$	—	$	(24,247	)	$	71

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

	Three Months Ended June 30,						Nine Months Ended June 30,
(Thousands)	2013			2012			2013			2012
Beginning of period	$	93		$	58		$	109		$	13
Net settlements	33			(9		)	4			(16		)
Net losses related to derivatives not held   at end of period	(9		)	(8		)	(99		)	(68		)
Net gains related to derivatives still held   at end of period	255			66			358			178
End of period	$	372		$	107		$	372		$	107

The mutual funds are included in the Other investments line of the Consolidated Balance Sheets. Derivative assets and liabilities, including receivables and payables associated with cash margin requirements, are presented net in the Consolidated Balance Sheets when a legally enforceable netting agreement exists between the Company and the counterparty to a derivative contract. For additional information on derivative instruments, see Note 8, Derivative Instruments and Hedging Activities.

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Part 2 (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Accounting Policies [Abstract]
Gross Receipts taxes recorded in gas utility operating revenues	$ 7.8	$ 5.7	$ 35.3	$ 31.4

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OTHER INCOME AND (INCOME DEDUCTIONS) - NET (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Other Nonoperating Income (Expense) [Abstract]
Interest income	$ 164	$ 337	$ 827	$ 1,001
Net investment gain	24	264	1,127	2,458
Other income	156	(15)	233	(4)
Other income deductions	(742)	(135)	(163)	316
Other (Income Deductions) and Income - Net	$ (398)	$ 451	$ 2,024	$ 3,771

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OTHER INCOME AND (INCOME DEDUCTIONS) - NET

9 Months Ended

Jun. 30, 2013

Other Nonoperating Income (Expense) [Abstract]

OTHER INCOME AND (INCOME DEDUCTIONS) - NET

10.        OTHER INCOME AND (INCOME DEDUCTIONS) - NET

	Three Months Ended June 30,						Nine Months Ended June 30,
(Thousands)	2013			2012			2013			2012
Interest income	$	164		$	337		$	827		$	1,001
Net investment gain	24			264			1,127			2,458
Other income	156			(15		)	233			(4		)
Other income deductions	(742		)	(135		)	(163		)	316
Other Income and (Income Deductions) – Net	$	(398	)	$	451		$	2,024		$	3,771

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FAIR VALUE OF FINANCIAL INSTRUMENTS

9 Months Ended

Jun. 30, 2013

Financial Instruments, Owned, at Fair Value [Abstract]

FAIR VALUE OF FINANCIAL INSTRUMENTS

6.        FAIR VALUE OF FINANCIAL INSTRUMENTS

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

					Classification of Estimated Fair Value
(Thousands)	Carrying Amount		Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
As of June 30, 2013
Cash and cash equivalents	$	556,489	$	556,489	$	421,518	$	134,971	$	—
Short-term debt	—		—		—		—		—
Long-term debt, including current portion	464,444		506,328		—		506,328		—
As of Sept. 30, 2012
Cash and cash equivalents	$	27,457	$	27,457	$	17,380	$	10,077	$	—
Short-term debt	40,100		40,100		—		40,100		—
Long-term debt, including current portion	364,416		452,768		—		452,768		—
As of June 30, 2012
Cash and cash equivalents	$	21,523	$	21,523	$	11,560	$	9,963	$	—
Short-term debt	—		—		—		—		—
Long-term debt, including current portion	364,401		445,961		—		445,961		—

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

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

9 Months Ended

Jun. 30, 2013

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

1.        SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

These notes are an integral part of the accompanying unaudited consolidated financial statements of The Laclede Group, Inc. (Laclede Group or the Company) and its subsidiaries. In the opinion of Laclede Group, this interim report includes all adjustments (consisting of only normal recurring accruals) necessary for the fair presentation of the results of operations for the periods presented. This Form 10-Q should be read in conjunction with the Notes to Consolidated Financial Statements contained in the Company’s Fiscal Year 2012 Form 10-K.

The consolidated financial position, results of operations, and cash flows of Laclede Group are comprised primarily from the financial position, results of operations, and cash flowsof Laclede Gas Company (Laclede Gas or the Utility). Laclede Gas is a regulated natural gas distribution utility having a material seasonal cycle. As a result, these interim statements of income for Laclede Group are not necessarily indicative of annual results or representative of succeeding quarters of the fiscal year. Due to the seasonal nature of the business of Laclede Gas, earnings are typically concentrated in the November through April period, which generally corresponds with the heating season. Laclede Energy Resources, Inc. (LER) includes its wholly owned subsidiary, LER Storage Services, Inc., which became operational on January 1, 2012.

REVENUE RECOGNITION - Laclede Gas reads meters and bills its customers on monthly cycles. The Utility records its gas utility revenues from gas sales and transportation services on an accrual basis that includes estimated amounts for gas delivered, but not yet billed. The accruals for unbilled revenues are reversed in the subsequent accounting period when meters are actually read and customers are billed. The amounts of accrued unbilled revenues at June 30, 2013 and 2012, for the Utility, were $8.7 million and $9.0 million, respectively. The amount of accrued unbilled revenue at September 30, 2012 was $11.6 million.

GROSS RECEIPTS TAXES - Gross receipts taxes associated with Laclede Gas’ natural gas utility service are imposed on the Utility and billed to its customers. These amounts are recorded gross in the Statements of Consolidated Income. Amounts recorded in Gas Utility Operating Revenues for the quarters ended June 30, 2013 and 2012 were $7.8 million and $5.7 million, respectively. Amounts recorded in Gas Utility Operating Revenues for the nine months ended June 30, 2013 and 2012 were $35.3 million and $31.4 million, respectively. Gross receipts taxes are expensed by the Utility and included in the Taxes, other than income taxes line.

NEW ACCOUNTING STANDARDS - In June 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-05, “Presentation of Comprehensive Income,” to amend ASC Topic 220, “Comprehensive Income,” by changing certain financial statement presentation requirements. Under the amended guidance, entities may either present a single continuous statement of comprehensive income or, consistent with the Company’s current presentation, provide separate but consecutive statements (a statement of income and a statement of comprehensive income). ASU No. 2011-05 would have required that, regardless of the method chosen, reclassification adjustments from other comprehensive income to net income be presented on the face of the financial statements, displaying the effect on both net income and other comprehensive income. However, in December 2011, the FASB issued ASU No. 2011-12 to defer the effective date of this particular requirement while it reconsiders this provision of the guidance. The amendments in these ASUs do not change the items that are required to be reported in other comprehensive income and, accordingly, did not impact total net income, comprehensive income, or earnings per share upon adoption in the first quarter of fiscal year 2013.

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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STOCK-BASED COMPENSATION (Details) (USD $)	3 Months Ended		9 Months Ended
	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013 Restricted Stock Awards [Member]	Jun. 30, 2013 Restricted Stock Awards [Member] Time Vested Restricted Stock and Time Vested Restricted Stock Units [Member]	Jun. 30, 2013 Restricted Stock Awards [Member] Executive Officers and Key Employees [Member] Performance Contingent Restricted Stock and Stock Units [Member]	Jun. 30, 2013 Stock Options Awards [Member]	Sep. 30, 2012 Stock Options Awards [Member]
Restricted Stock Awards [Abstract]
Granted (in shares)						58,924	108,419
Granted, weighted average grant date fair value (per share)						$ 39.98	$ 34.48
Vested restricted stock withheld for tax withholding obligations (in shares)					18,898
Vested restricted stock withheld for tax withholding obligations, weighted average price (in dollars per share)					$ 38.96
Restricted stock/stock units activity [Roll-Forward]
Nonvested, beginning of period (in shares)						115,115	232,403
Granted (in shares)						58,924	108,419
Vested (in shares)					(58,036)	(20,600)	(37,436)
Forfeited (in shares)						(6,500)	(48,782)
Nonvested, end of period (in shares)						146,939	254,604
Weighted average Grant Date Fair Value [Abstract]
Nonvested Beginning Balance, weighted average grant date fair value (per share)						$ 36.54	$ 30.89
Granted, weighted average grant date fair value (per share)						$ 39.98	$ 34.48
Vested, weighted average grant date fair value (per share)						$ 30.55	$ 27.02
Forfeited, weighted average grant date fair value (per share)						$ 38.54	$ 25.71
Nonvested Ending Balance, weighted average grant date fair value (per share)						$ 38.67	$ 33.98
Stock Options - Shares [Roll Forward]
Outstanding Balance - stock options								143,500	214,000
Fully Vested and Expected to Vest, end of period (in shares)								143,500
Exercisable, end of period (in shares)								143,500
Granted - stock options (in shares)								0
Exercised - stock options (in shares)								(70,500)
Forfeited - stock options (in shares)								0
Expired - stock options (in shares)								0
Stock Options - Shares Weighted Average Exercise Price [Abstract]
Outstanding Beginning Balance, weighted average exercise price - stock options (per share)								$ 31.81	$ 31.02
Granted, weighted average exercise price - stock options (per share)								$ 0.00
Exercised, weighted average exercise price - stock options (per share)								$ 29.42
Forfeited, weighted average exercise price - stock options (per share)								$ 0.00
Expired, weighted average exercise price - stock options (per share)								$ 0.00
Outstanding Ending Balance, weighted average exercise price - stock options (per share)								$ 31.81	$ 31.02
Fully Vested and Expected to Vest at End of Period, weighted average exercise price - stock options (per share)								$ 31.81
Exercisable at End of Period, weighted average exercise price - stock options (per share)								$ 31.81
Outstanding Ending Balance, weighted average remaining contractual term - stock options (in years)								2 years
Fully Vested and Expected to Vest at End of Period, weighted average remaining contractual term - stock options (in years)								2 years
Exercisable at End of Period, weighted average remaining contractual term - stock options (in years)								2 years
Outstanding Ending Balance, aggregate intrinsic value - stock options								$ 1,988,000
Fully Vested and Expected to Vest at End of Period, aggregate intrinsic value - stock options								1,988,000
Exercisable at End of Period, aggregate intrinsic value - stock options								1,988,000
Stock Option Awards [Abstract]
Common stock closing price (per share)								$ 45.66
Equity Compensation Cost [Abstract]
Total equity compensation cost	1,654,000	678,000	3,413,000	2,029,000
Compensation cost capitalized	(536,000)	(230,000)	(1,075,000)	(589,000)
Compensation cost recognized in net income	1,118,000	448,000	2,338,000	1,440,000
Income tax benefit recognized in net income	(428,000)	(173,000)	(895,000)	(556,000)
Compensation cost recognized in net income, net of income tax	690,000	275,000	1,443,000	884,000
Total unrecognized compensation cost	$ 6,100,000		$ 6,100,000
Weighted average period cost to be recognized (in years)	2 years 1 month 6 days

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ACQUISITION AGREEMENTS

9 Months Ended

Jun. 30, 2013

Business Combinations [Abstract]

ACQUISITION AGREEMENTS

13.    ACQUISITION AGREEMENTS

On December 14, 2012, Laclede Group entered into purchase and sale agreements, subject to customary closing adjustments, to acquire for $1.035 billion (collectively, the Transaction) from Southern Union Company (SUG), an affiliate of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P., substantially all of the assets and liabilities of SUG's MGE and NEG divisions (collectively, the Utilities). The Utilities are engaged in the distribution of natural gas on a regulated basis in western Missouri and in southeastern Massachusetts.

The Transaction is targeted to close before the end of fiscal year 2013, subject to customary closing conditions, including regulatory approvals from the MoPSC, which were obtained July 17, 2013, and the Massachusetts Department of Public Utilities (MDPU), which are pending. On January 22, 2013, the Federal Trade Commission notified the Company of the early termination of the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. No shareholder approval is required to complete the Transaction, and each of the entities has received all necessary approvals from their boards of directors.

The purchase and sale agreements contain 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). In the event that SUG terminates the MGE acquisition agreement as a result of the failure of Laclede Group to obtain financing, the Company may be required to pay SUG a "reverse break up" fee of $73.1 million, which amount will operate as liquidated damages and a cap on such liability for such breach.

Laclede Group's agreement to acquire MGE for $975 million, via the newly formed wholly owned subsidiary Plaza Missouri Acquisition, Inc., was assigned by Laclede Group to Laclede Gas on January 11, 2013. Subsequently, on January 14, 2013, the Company filed an application with the MoPSC for approval to acquire the assets of MGE from SUG. On July 2, 2013, the Utility and other parties to the case filed a Unanimous Stipulation and Agreement with the MoPSC, which was approved on July 17, 2013, authorizing Laclede Gas' to acquire MGE, subject to certain conditions.

Similarly, the agreement to acquire NEG for $60 million, including approximately $19.5 million of assumed NEG debt, is contracted through a second newly formed wholly owned subsidiary of Laclede Group, Plaza Massachusetts Acquisition, Inc. (Plaza Massachusetts). On February 11, 2013, the Company announced that it 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 rights to purchase the assets of NEG, subject to certain approvals and conditions. Under the terms of this agreement, the Company will receive $11 million from APUC at closing. Further, APUC has deposited $3.0 million in an escrow account that will be paid to SUG at closing. The sale of NEG to APUC is subject to approval from the MDPU, and a filing that was made by the Company and SUG with the MDPU on January 24, 2013, for approval of the acquisition of NEG, was amended on February 19, 2013 to include APUC. An evidentiary hearing was held on this matter during the last week of June 2013. Laclede Group remains obligated to acquire NEG in the event that APUC is not able to satisfy all conditions for closing on or before October 14, 2013, although the Company believes this scenario would be unlikely. The Company's agreement with APUC is not anticipated to impact the MGE transaction.

The Transaction is supported by existing company cash, including the proceeds received from Laclede Group's May 2013 public offering of common stock, and Laclede Group's fully committed bridge facility with Wells Fargo Bank, National Association. That bridge facility was syndicated to a group of nine financial institutions in January 2013. As a result of the Company's May 2013 equity offering and an amendment to the bridge facility in June 2013, the commitment under the facility was reduced from $1.020 billion to $525 million during the third quarter of fiscal year 2013. The Company anticipates permanent financing to be a combination of long-term debt and equity.

The Company continues to incur costs associated with the evaluation, approval and financing of the Transaction. During the three and nine months ended June 30, 2013, Laclede Group recorded $1.4 million and $5.3 million, respectively, net of tax, of third-party expenses associated with the Transaction.

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CONCENTRATIONS OF CREDIT RISK

9 Months Ended

Jun. 30, 2013

Risks and Uncertainties [Abstract]

CONCENTRATIONS OF CREDIT RISK

9.        CONCENTRATIONS OF CREDIT RISK

A significant portion of LER’s transactions are with (or are associated with) energy producers, utility companies, and pipelines. These concentrations of transactions with these counterparties have the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that each of these three groups may be affected similarly by changes in economic, industry, or other conditions. To manage this risk, as well as credit risk from significant counterparties in these and other industries, LER has established procedures to determine the creditworthiness of its counterparties. These procedures include obtaining credit ratings and credit reports, analyzing counterparty financial statements to assess financial condition, and considering the industry environment in which the counterparty operates. This information is monitored on an ongoing basis. In some instances, LER may require credit assurances such as prepayments, letters of credit, or parental guarantees. In addition, LER may enter into netting arrangements to mitigate credit risk with counterparties in the energy industry from which LER both sells and purchases natural gas. Sales are typically made on an unsecured credit basis with payment due the month following delivery. Accounts receivable amounts are closely monitored and provisions for uncollectible amounts are accrued when losses are probable. To date, losses have not been significant. LER records accounts receivable, accounts payable, and prepayments for physical sales and purchases of natural gas on a gross basis. The amount included in accounts receivable attributable to energy producers and their marketing affiliates amounted to $22.2 million at June 30, 2013. Net receivable amounts from these customers on the same date, reflecting netting arrangements, were $12.0 million Accounts receivable attributable to utility companies and their marketing affiliates comprised $18.6 million of total accounts receivable at June 30, 2013, while net receivable amounts from these customers, reflecting netting arrangements, were $11.3 million. LER also has concentrations of credit risk with certain individually significant counterparties. At June 30, 2013, the amounts included in accounts receivable from LER’s five largest counterparties (in terms of net accounts receivable exposure), were $25.7 million. These five counterparties are either investment-grade rated or owned by investment-grade rated companies. Net receivable amounts from these customers on the same date, reflecting netting arrangements, were $17.0 million. Additionally, LER has concentrations of credit risk with pipeline companies associated with its natural gas receivable amounts.

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STOCK-BASED COMPENSATION (Tables)

9 Months Ended

Jun. 30, 2013

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Restricted stock and restricted stock unit activity

Time-vested restricted stock and stock unit activity for the nine months ended June 30, 2013 is presented below:

	Restricted Stock/ Stock Units		Weighted Average Grant Date Fair Value
Nonvested at September 30, 2012	115,115		$	36.54
Granted	58,924		$	39.98
Vested	(20,600	)	$	30.55
Forfeited	(6,500	)	$	38.54
Nonvested at June 30, 2013	146,939		$	38.67

Activity of restricted stock and restricted stock units subject to performance and/or market conditions during the nine months ended June 30, 2013 is presented below:

	Restricted Stock/ Stock Units		Weighted Average Grant Date Fair Value
Nonvested at September 30, 2012	232,403		$	30.89
Granted (maximum shares that can be earned)	108,419		$	34.48
Vested	(37,436	)	$	27.02
Forfeited	(48,782	)	$	25.71
Nonvested at June 30, 2013	254,604		$	33.98

Stock option awards activity

Stock option activity for the nine months ended June 30, 2013 is presented below:

	Stock Options		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (Years)	Aggregate Intrinsic Value ($000)
Outstanding at September 30, 2012	214,000		$	31.02
Granted	—		$	—
Exercised	(70,500	)	$	29.42
Forfeited	—		$	—
Expired	—		$	—
Outstanding at June 30, 2013	143,500		$	31.81	2.0	$	1,988
Fully Vested and Expected to Vest at June 30, 2013	143,500		$	31.81	2.0	$	1,988
Exercisable at June 30, 2013	143,500		$	31.81	2.0	$	1,988

Compensation cost recognized for share-based compensation arrangements

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

	Three Months Ended June 30,						Nine Months Ended June 30,
(Thousands)	2013			2012			2013			2012
Total equity compensation cost	$	1,654		$	678		$	3,413		$	2,029
Compensation cost capitalized	(536		)	(230		)	(1,075		)	(589		)
Compensation cost recognized in net income, before income taxes	1,118			448			2,338			1,440
Income tax benefit recognized in net income	(428		)	(173		)	(895		)	(556		)
Compensation cost recognized in net income, net of income tax	$	690		$	275		$	1,443		$	884

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

9 Months Ended

Jun. 30, 2013

Accounting Policies [Abstract]

REVENUE RECOGNITION

REVENUE RECOGNITION - Laclede Gas reads meters and bills its customers on monthly cycles. The Utility records its gas utility revenues from gas sales and transportation services on an accrual basis that includes estimated amounts for gas delivered, but not yet billed. The accruals for unbilled revenues are reversed in the subsequent accounting period when meters are actually read and customers are billed. The amounts of accrued unbilled revenues at June 30, 2013 and 2012, for the Utility, were $8.7 million and $9.0 million, respectively. The amount of accrued unbilled revenue at September 30, 2012 was $11.6 million.

GROSS RECEIPTS TAXES

GROSS RECEIPTS TAXES - Gross receipts taxes associated with Laclede Gas’ natural gas utility service are imposed on the Utility and billed to its customers. These amounts are recorded gross in the Statements of Consolidated Income. Amounts recorded in Gas Utility Operating Revenues for the quarters ended June 30, 2013 and 2012 were $7.8 million and $5.7 million, respectively. Amounts recorded in Gas Utility Operating Revenues for the nine months ended June 30, 2013 and 2012 were $35.3 million and $31.4 million, respectively. Gross receipts taxes are expensed by the Utility and included in the Taxes, other than income taxes line.

NEW ACCOUNTING STANDARDS

NEW ACCOUNTING STANDARDS - In June 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-05, “Presentation of Comprehensive Income,” to amend ASC Topic 220, “Comprehensive Income,” by changing certain financial statement presentation requirements. Under the amended guidance, entities may either present a single continuous statement of comprehensive income or, consistent with the Company’s current presentation, provide separate but consecutive statements (a statement of income and a statement of comprehensive income). ASU No. 2011-05 would have required that, regardless of the method chosen, reclassification adjustments from other comprehensive income to net income be presented on the face of the financial statements, displaying the effect on both net income and other comprehensive income. However, in December 2011, the FASB issued ASU No. 2011-12 to defer the effective date of this particular requirement while it reconsiders this provision of the guidance. The amendments in these ASUs do not change the items that are required to be reported in other comprehensive income and, accordingly, did not impact total net income, comprehensive income, or earnings per share upon adoption in the first quarter of fiscal year 2013.

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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Document and Entity Information (USD $)	9 Months Ended
	Jun. 30, 2013	Jul. 26, 2013	Mar. 31, 2012
Document and Entity Information [Abstract]
Entity Registrant Name	Laclede Group Inc.
Entity Central Index Key	0001126956
Current Fiscal Year End Date	--09-30
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 814,739,902
Entity Common Stock, Shares Outstanding		32,692,182
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2013

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS (Tables)

9 Months Ended

Jun. 30, 2013

Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]

Net Periodic Cost

Net periodic postretirement benefit costs consisted of the following components:

	Three Months Ended June 30,						Nine Months Ended June 30,
(Thousands)	2013			2012			2013			2012
Service cost – benefits earned during the period	$	2,534		$	2,015		$	7,601		$	6,045
Interest cost on accumulated postretirement benefit obligation	1,278			1,380			3,836			4,140
Expected return on plan assets	(1,082		)	(991		)	(3,244		)	(2,973		)
Amortization of transition obligation	24			34			70			102
Amortization of prior service cost (credit)	—			(518		)	2			(1,554		)
Amortization of actuarial loss	1,325			1,065			3,975			3,195
Sub-total	4,079			2,985			12,240			8,955
Regulatory adjustment	(1,699		)	(604		)	(5,097		)	(1,812		)
Net postretirement benefit cost	$	2,380		$	2,381		$	7,143		$	7,143

The net periodic pension costs include the following components:

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
(Thousands)	2013			2012			2013			2012
Service cost – benefits earned during the period	$	2,311		$	2,295		$	6,933		$	6,908
Interest cost on projected benefit obligation	4,066			4,824			12,198			14,535
Expected return on plan assets	(4,741		)	(4,899		)	(14,223		)	(14,697		)
Amortization of prior service cost	136			148			408			444
Amortization of actuarial loss	2,839			2,252			8,517			6,788
Loss on lump-sum settlement	12,346			—			12,346			3,407
Sub-total	16,957			4,620			26,179			17,385
Regulatory adjustment	(12,780		)	(484		)	(13,647		)	(1,451		)
Net pension cost	$	4,177		$	4,136		$	12,532		$	15,934