Spire (SR) 10-K 26 Nov 13 2013 FY Annual report Financial data

Document_And_Entity_Informatio

Document And Entity Information (USD $)	12 Months Ended
	Sep. 30, 2013	Nov. 21, 2013	Mar. 31, 2013
Document and Entity Information [Abstract]	'	'	'
Entity Registrant Name	'LACLEDE GROUP INC	'	'
Entity Central Index Key	'0001126956	'	'
Current Fiscal Year End Date	'--09-30	'	'
Entity Well-known Seasoned Issuer	'Yes	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Filer Category	'Large Accelerated Filer	'	'
Entity Public Float	'	'	$906,985,448
Entity Common Stock, Shares Outstanding	'	32,709,763	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Document Type	'10-K	'	'
Amendment Flag	'false	'	'
Document Period End Date	30-Sep-13	'	'

STATEMENTS_OF_CONSOLIDATED_INC

STATEMENTS OF CONSOLIDATED INCOME (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Operating Revenues:	'	'	'
Gas Utility	$847,224	$763,447	$913,190
Gas Marketing	165,146	358,145	669,375
Other	4,649	3,883	20,742
Total Operating Revenues	1,017,019	1,125,475	1,603,307
Gas Utility	'	'	'
Natural and propane gas	433,442	397,304	549,947
Other operation and maintenance expenses	180,342	167,351	172,938
Depreciation and amortization	48,283	40,739	39,214
Taxes, other than income taxes	60,079	53,672	60,752
Total Gas Utility Operating Expenses	722,146	659,066	822,851
Gas Marketing	176,554	353,283	652,567
Other	21,825	2,524	9,642
Total Operating Expenses	920,525	1,014,873	1,485,060
Operating Income	96,494	110,602	118,247
Other Income and (Income Deductions) – Net	2,444	3,272	177
Interest Charges:	'	'	'
Interest on long-term debt	25,539	22,958	23,161
Other interest charges	3,063	1,987	2,256
Total Interest Charges	28,602	24,945	25,417
Income Before Income Taxes	70,336	88,929	93,007
Income Tax Expense	17,578	26,289	29,182
Net Income	$52,758	$62,640	$63,825
Weighted Average Number of Common Shares Outstanding:	'	'	'
Basic (in shares)	25,875	22,262	22,099
Diluted (in shares)	25,952	22,340	22,171
Basic Earnings Per Share of Common Stock (in dollars per share)	$2.03	$2.80	$2.87
Diluted Earnings Per Share of Common Stock (in dollars per share)	$2.02	$2.79	$2.86

STATEMENTS_OF_CONSOLIDATED_COM

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Statement of Comprehensive Income [Abstract]	'	'	'
Net income	$52,758	$62,640	$63,825
Net gains (losses) on cash flow hedging derivative instruments:	'	'	'
Net hedging gain arising during the period	5,047	4,802	5,581
Reclassification adjustment for (gains) losses included in net income	302	-8,397	1,861
Net unrealized (losses) gains on cash flow hedging derivative instruments	5,349	-3,595	7,442
Defined benefit pension and other postretirement benefit plans:	'	'	'
Net actuarial (loss) gain arising during the period	-120	-3,397	339
Amortization of actuarial loss included in net periodic pension and postretirement benefit cost	195	3,706	426
Net defined benefit pension and other postretirement benefit plans	75	309	765
Other Comprehensive (Loss) Income, Before Tax	5,424	-3,286	8,207
Income Tax (Benefit) Expense Related to Items of Other Comprehensive (Loss) Income	2,094	-1,270	3,170
Other Comprehensive (Loss) Income, Net of Tax	3,329	-2,016	5,037
Comprehensive Income	$56,087	$60,624	$68,862

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Sep. 30, 2013		Sep. 30, 2012
In Thousands, unless otherwise specified
ASSETS	'		'
Utility Plant	$2,271,189		$1,497,419
Less – Accumulated depreciation and amortization	494,559		478,120
Net Utility Plant	1,776,630		1,019,299
Non-utility property (net of accumulated depreciation and amortization, 2013, $5,886; 2012, $10,018)	7,694		6,039
Goodwill	247,078		0
Other investments	58,306		50,775
Other Property and Investments	313,078		56,814
Current Assets:	'		'
Cash and cash equivalents	52,981		27,457
Accounts receivable:	'		'
Utility	101,118		64,027
Non-utility	63,752		51,042
Other	14,451		26,478
Allowance for doubtful accounts	-8,046		-7,705
Inventories:	'		'
Natural gas stored underground	182,035		92,729
Propane gas	8,962		10,200
Materials and supplies at average cost	8,154		3,543
Natural gas receivable	18,782		22,377
Derivative instrument assets	3,291		2,855
Unamortized purchased gas adjustments	17,533		40,674
Prepayments and other	12,867		9,339
Total Current Assets	475,880		343,016
Deferred Charges:	'		'
Regulatory assets	545,947		456,047
Other	13,851		5,086
Total Deferred Charges	559,798		461,133
Total Assets	3,125,386		1,880,262
Capitalization:	'		'
Common stock equity	1,046,282		601,611
Long-term debt (less current portion)	912,712		339,416
Total Capitalization	1,958,994		941,027
Current Liabilities:	'		'
Notes payable	74,000		40,100
Accounts payable	140,234		89,503
Advance customer billings	23,736		25,146
Current portion of long-term debt	0		25,000
Wages and compensation accrued	20,807		13,908
Dividends payable	14,556		9,831
Customer deposits	15,062		8,565
Interest accrued	8,335		8,590
Taxes accrued	32,896		11,304
Deferred income taxes	1,012		6,675
Other	22,540		13,502
Total Current Liabilities	353,178		252,124
Deferred Credits and Other Liabilities:	'		'
Deferred income taxes	379,114	[1]	355,509	[1]
Unamortized investment tax credits	2,900		3,113
Pension and postretirement benefit costs	228,653		196,558
Asset retirement obligations	74,554		40,368
Regulatory liabilities	82,560		56,319
Other	45,433		35,244
Total Deferred Credits and Other Liabilities	813,214		687,111
Commitments and Contingencies	'		'
Total Capitalization and Liabilities	$3,125,386		$1,880,262
[1]	The Company periodically invests in tax credits. As of September 30, 2013, $7.1 million of state tax credits are included in Other and Net deferred tax liability. $4.7 million of state tax credits were classified as current. $2.4 million of state tax credits were classified as non-current.

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Sep. 30, 2013	Sep. 30, 2012
In Thousands, unless otherwise specified
Assets	'	'
Non-utility property (net of accumulated depreciation and amortization)	$5,886	$10,018

STATEMENT_OF_CONSOLIDATED_CAPI

STATEMENT OF CONSOLIDATED CAPITALIZATION (USD $)	Sep. 30, 2013	Sep. 30, 2012
In Thousands, unless otherwise specified
Common Stock Equity:	'	'
Common stock, par value $1 per share: Authorized - 2013 and 2012, 70,000,000 shares Issued - 2013, 32,696,836 shares; and 2012, 22,539,431 shares	$32,697	$22,539
Paid-in capital	594,269	168,607
Retained earnings	420,103	414,581
Accumulated other comprehensive loss	-787	-4,116
Total Common Stock Equity	1,046,282	601,611
Long-Term Debt - Laclede Gas:	'	'
Debt instrument, principal outstanding	915,000	340,000
Unamortized discount, net of premium, on long-term debt	-2,288	-584
Total Long-Term Debt - Laclede Gas	912,712	339,416
Total Capitalization	1,958,994	941,027
Laclede Group [Member] | 3.31% Notes Payable, due December 15, 2022 [Member]	'	'
Long-Term Debt - Laclede Gas:	'	'
Debt instrument, principal outstanding	25,000	0
Laclede Gas [Member] | First Mortage Bonds 5-1/2% Series, due May 1, 2019 [Member]	'	'
Long-Term Debt - Laclede Gas:	'	'
Debt instrument, principal outstanding	50,000	50,000
Laclede Gas [Member] | First Mortage Bonds 7% Series, due June 1, 2029 [Member]	'	'
Long-Term Debt - Laclede Gas:	'	'
Debt instrument, principal outstanding	25,000	25,000
Laclede Gas [Member] | First Mortage Bonds 7.90% Series, due September 15, 2030 [Member]	'	'
Long-Term Debt - Laclede Gas:	'	'
Debt instrument, principal outstanding	30,000	30,000
Laclede Gas [Member] | First Mortage Bonds 6% Series, due May 1, 2034 [Member]	'	'
Long-Term Debt - Laclede Gas:	'	'
Debt instrument, principal outstanding	100,000	100,000
Laclede Gas [Member] | First Mortage Bonds 6.15% Series, due June 1, 2036 [Member]	'	'
Long-Term Debt - Laclede Gas:	'	'
Debt instrument, principal outstanding	55,000	55,000
Laclede Gas [Member] | First Mortage Bonds 6.35% Series, due October 15, 2038 [Member]	'	'
Long-Term Debt - Laclede Gas:	'	'
Debt instrument, principal outstanding	80,000	80,000
Laclede Gas [Member] | First Mortage Bonds 3% Series, due March 15, 2023 [Member]	'	'
Long-Term Debt - Laclede Gas:	'	'
Debt instrument, principal outstanding	55,000	0
Laclede Gas [Member] | First Mortage Bonds 3.40% Series, due March 15, 2028 [Member]	'	'
Long-Term Debt - Laclede Gas:	'	'
Debt instrument, principal outstanding	45,000	0
Laclede Gas [Member] | First Mortage Bonds 2% Series, due August 15, 2018 [Member]	'	'
Long-Term Debt - Laclede Gas:	'	'
Debt instrument, principal outstanding	100,000	0
Laclede Gas [Member] | First Mortage Bonds 3.40% Series, due August 15, 2023 [Member]	'	'
Long-Term Debt - Laclede Gas:	'	'
Debt instrument, principal outstanding	250,000	0
Laclede Gas [Member] | First Mortage Bonds 4.625% Series, due August 15, 2043 [Member]	'	'
Long-Term Debt - Laclede Gas:	'	'
Debt instrument, principal outstanding	$100,000	$0

STATEMENT_OF_CONSOLIDATED_CAPI1

STATEMENT OF CONSOLIDATED CAPITALIZATION (Parenthetical) (USD $)	Sep. 30, 2013	Sep. 30, 2012
Common Stock Equity:	'	'
Common stock, par value (in dollars per share)	$1	$1
Common stock, authorized (in shares)	70,000,000	70,000,000
Common stock, issued (in shares)	32,696,836	22,539,431
Laclede Group [Member] | 3.31% Notes Payable, due December 15, 2022 [Member]	'	'
Long - Term Debt - Laclede Gas:	'	'
Debt instrument, interest rate, stated percentage	3.31%	'
Laclede Gas [Member] | First Mortage Bonds 5-1/2% Series, due May 1, 2019 [Member]	'	'
Long - Term Debt - Laclede Gas:	'	'
Debt instrument, interest rate, stated percentage	5.50%	5.50%
Laclede Gas [Member] | First Mortage Bonds 7% Series, due June 1, 2029 [Member]	'	'
Long - Term Debt - Laclede Gas:	'	'
Debt instrument, interest rate, stated percentage	7.00%	7.00%
Laclede Gas [Member] | First Mortage Bonds 7.90% Series, due September 15, 2030 [Member]	'	'
Long - Term Debt - Laclede Gas:	'	'
Debt instrument, interest rate, stated percentage	7.90%	7.90%
Laclede Gas [Member] | First Mortage Bonds 6% Series, due May 1, 2034 [Member]	'	'
Long - Term Debt - Laclede Gas:	'	'
Debt instrument, interest rate, stated percentage	6.00%	6.00%
Laclede Gas [Member] | First Mortage Bonds 6.15% Series, due June 1, 2036 [Member]	'	'
Long - Term Debt - Laclede Gas:	'	'
Debt instrument, interest rate, stated percentage	6.15%	6.15%
Laclede Gas [Member] | First Mortage Bonds 6.35% Series, due October 15, 2038 [Member]	'	'
Long - Term Debt - Laclede Gas:	'	'
Debt instrument, interest rate, stated percentage	6.35%	6.35%
Laclede Gas [Member] | First Mortage Bonds 3% Series, due March 15, 2023 [Member]	'	'
Long - Term Debt - Laclede Gas:	'	'
Debt instrument, interest rate, stated percentage	3.00%	3.00%
Laclede Gas [Member] | First Mortage Bonds 3.40% Series, due March 15, 2028 [Member]	'	'
Long - Term Debt - Laclede Gas:	'	'
Debt instrument, interest rate, stated percentage	3.40%	3.40%
Laclede Gas [Member] | First Mortage Bonds 2% Series, due August 15, 2018 [Member]	'	'
Long - Term Debt - Laclede Gas:	'	'
Debt instrument, interest rate, stated percentage	2.00%	2.00%
Laclede Gas [Member] | First Mortage Bonds 3.40% Series, due August 15, 2023 [Member]	'	'
Long - Term Debt - Laclede Gas:	'	'
Debt instrument, interest rate, stated percentage	3.40%	3.40%
Laclede Gas [Member] | First Mortage Bonds 4.625% Series, due August 15, 2043 [Member]	'	'
Long - Term Debt - Laclede Gas:	'	'
Debt instrument, interest rate, stated percentage	4.63%	4.63%

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY (USD $)	Total	Common Stock Issued	Paid-in Capital	Retained Earnings	Accum. Other Comp. Income (Loss)
In Thousands, except Share data, unless otherwise specified
BALANCE at Sep. 30, 2010	$535,577	$22,293	$158,698	$361,723	($7,137)
BALANCE (in shares) at Sep. 30, 2010	'	22,292,804	'	'	'
Stockholders' Equity Rollforward	'	'	'	'	'
Net income	63,825	0	0	63,825	0
Dividend reinvestment plan	1,614	43	1,571	0	0
Dividend reinvestment plan (in shares)	'	43,354	'	'	'
Stock-based compensation costs	3,949	0	3,949	0	0
Equity Incentive Plan	935	95	840	0	0
Equity Incentive Plan (in shares)	'	94,576	'	'	'
Employees’ taxes paid associated with restricted shares withheld upon vesting	-1,162	0	-1,162	0	0
Non-employee directors' restricted stock awards	-494	0	-494	0	0
Tax benefit - stock compensation	300	0	300	0	0
Dividends declared:	'	'	'	'	'
Common stock	-36,250	0	0	-36,250	0
Other comprehensive income, net of tax	5,037	0	0	0	5,037
BALANCE at Sep. 30, 2011	573,331	22,431	163,702	389,298	-2,100
BALANCE (in shares) at Sep. 30, 2011	'	22,430,734	'	'	'
Stockholders' Equity Rollforward	'	'	'	'	'
Net income	62,640	0	0	62,640	0
Common stock offering	427,162	10,005	417,157	0	0
Common stock offering (in shares)	'	10,005,000	'	'	'
Dividend reinvestment plan	1,841	46	1,795	0	0
Dividend reinvestment plan (in shares)	46,107	46,107	'	'	'
Stock-based compensation costs	2,702	0	2,702	0	0
Equity Incentive Plan	2,470	62	2,408	0	0
Equity Incentive Plan (in shares)	'	62,590	'	'	'
Employees’ taxes paid associated with restricted shares withheld upon vesting	-1,203	0	-1,203	0	0
Non-employee directors' restricted stock awards	-565	0	-565	0	0
Tax benefit - stock compensation	-232	0	-232	0	0
Dividends declared:	'	'	'	'	'
Common stock	-37,357	0	0	-37,357	0
Other comprehensive income, net of tax	-2,016	0	0	0	-2,016
BALANCE at Sep. 30, 2012	601,611	22,539	168,607	414,581	-4,116
BALANCE (in shares) at Sep. 30, 2012	22,540,000	22,539,431	'	'	'
Stockholders' Equity Rollforward	'	'	'	'	'
Net income	52,758	0	0	52,758	0
Dividend reinvestment plan	1,847	44	1,803	0	0
Dividend reinvestment plan (in shares)	44,074	44,074	'	'	'
Stock-based compensation costs	4,441	0	4,441	0	0
Equity Incentive Plan	2,674	109	2,565	0	0
Equity Incentive Plan (in shares)	'	108,331	'	'	'
Employees’ taxes paid associated with restricted shares withheld upon vesting	-931	0	-931	0	0
Non-employee directors' restricted stock awards	0	0	'	0	0
Tax benefit - stock compensation	627	0	627	0	0
Dividends declared:	'	'	'	'	'
Common stock	-47,236	0	0	-47,236	0
Other comprehensive income, net of tax	3,329	0	0	0	3,329
BALANCE at Sep. 30, 2013	$1,046,282	$32,697	$594,269	$420,103	($787)
BALANCE (in shares) at Sep. 30, 2013	32,700,000	32,696,836	'	'	'

CONSOLIDATED_STATEMENTS_OF_COM1

CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY (Parenthetical) (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Statement of Stockholders' Equity [Abstract]	'	'	'
Dividends Declared, Common stock (in dollars per share)	$1.70	$1.66	$1.62

STATEMENTS_OF_CONSOLIDATED_CAS

STATEMENTS OF CONSOLIDATED CASH FLOWS (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Operating Activities:	'	'	'
Net income	$52,758	$62,640	$63,825
Adjustments to reconcile net income to net cash provided by (used in) operating activities:	'	'	'
Depreciation, amortization and accretion	49,283	41,339	39,764
Deferred income taxes and investment tax credits	22,053	30,554	23,885
Other - net	957	75	3,431
Changes in assets and liabilities:	'	'	'
Accounts receivable – net	-650	-9,359	3,106
Unamortized purchased gas adjustments	23,141	-14,955	-2,001
Deferred purchased gas costs	13,300	11,090	44,565
Accounts payable	35,445	-8,790	-4,860
Advance customer billings – net	-8,248	9,916	-1,579
Taxes accrued	3,666	-1,169	1,387
Natural gas stored underground	-30,626	22,441	-1,594
Other assets and liabilities	2,835	-15,681	-2,742
Net cash provided by operating activities	163,914	128,101	167,187
Investing Activities:	'	'	'
Capital expenditures	-130,788	-108,843	-67,638
Other investments	-2,511	3,439	631
Acquisition of MGE	-975,000	0	0
Net cash used in investing activities	-1,108,299	-105,404	-67,007
Financing Activities:	'	'	'
Issuance of first mortgage bonds	550,000	0	0
Maturity of first mortgage bonds	-25,000	0	-25,000
Issuance (Repayment) of short-term debt - net	33,900	-5,900	-83,650
Notes Payable Issued	25,000	0	0
Change in book overdrafts	-1,255	1,455	-545
Issuance of common stock	431,682	4,311	2,549
Non-employee directors’ restricted stock awards	0	-565	-494
Dividends paid	-42,518	-36,896	-35,821
Employees’ taxes paid associated with restricted shares withheld upon vesting	-931	-1,203	-1,162
Excess tax benefits from stock-based compensation	1,778	338	314
Other	-2,747	-57	-13
Net cash provided by (used in) financing activities	969,909	-38,517	-143,822
Net (Decrease) Increase in Cash and Cash Equivalents	25,524	-15,820	-43,642
Cash and Cash Equivalents at Beginning of Year	27,457	43,277	86,919
Cash and Cash Equivalents at End of Year	52,981	27,457	43,277
Supplemental Disclosure of Cash Paid (Refunded) During the Year for:	'	'	'
Interest	26,304	24,557	25,332
Income taxes	($9,375)	$1,540	$6,860

SUMMARY_OF_SIGNIFICANT_ACCOUNT

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Sep. 30, 2013
Accounting Policies [Abstract]	'
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	'
	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	BASIS OF CONSOLIDATION - The consolidated financial statements include the accounts of Laclede Group and its subsidiary companies, including the recent acquisition of Missouri Gas Energy (MGE). All subsidiaries are wholly owned. Laclede Gas and other subsidiaries of Laclede Group may engage in related party transactions during the ordinary course of business. All material intercompany balances have been eliminated from the consolidated financial statements of Laclede Group. Transactions include sales of natural gas and transportation services between subsidiaries. These revenues are shown on the Intersegment revenues lines in the table included in Note 15, Information by Operating Segment.
	NATURE OF OPERATIONS - The Laclede Group, Inc. (NYSE: LG), headquartered in St. Louis, Missouri, is a public utility holding company. The Gas Utility segment serves St. Louis and eastern Missouri through Laclede Gas and serves Kansas City and western Missouri through Missouri Gas Energy. Together they provide more than 1.13 million residential, commercial and industrial customers with safe and reliable natural gas service. Laclede’s primary non-utility business, Laclede Energy Resources, Inc., included in the Gas Marketing segment, provides non-regulated natural gas services. The activities of other subsidiaries and the non-regulated activities of Laclede Gas are described in Note 15, Information by Operating Segment, and are included in the Other column.
	USE OF ESTIMATES - The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.
	SYSTEM OF ACCOUNTS - The accounts of Laclede Gas are maintained in accordance with the Uniform System of Accounts prescribed by the Missouri Public Service Commission (MoPSC or Commission), which system substantially conforms to that prescribed by the Federal Energy Regulatory Commission (FERC).
	UTILITY PLANT, DEPRECIATION AND AMORTIZATION - Utility plant is stated at original cost. The cost of additions to utility plant includes contracted work, direct labor and materials, allocable overheads, and an allowance for funds used during construction. The costs of units of property retired, replaced, or renewed are removed from utility plant and are charged to accumulated depreciation. Maintenance and repairs of property and replacement and renewal of items determined to be less than units of property are charged to maintenance expenses.
	Utility plant is depreciated on a straight-line basis at rates based on estimated service lives of the various classes of property. In fiscal year 2013, annual depreciation and amortization expense averaged 3.2% of the original cost of depreciable and amortizable property, compared to 3.1% in both fiscal years 2012 and 2011.
	The Utility’s capital expenditures were $128.5 million, $106.7 million, and $67.3 million for fiscal years 2013, 2012, and 2011, respectively. Additionally, the Utility had recorded accruals for capital expenditures totaling $4.7 million at September 30, 2013, $9.7 million at September 30, 2012, and $8.2 million at September 30, 2011. Accrued capital expenditures are excluded from the Statements of Consolidated Cash Flows.
	ASSET RETIREMENT OBLIGATIONS - Laclede Group records legal obligations associated with the retirement of long-lived assets in the period in which the obligations are incurred, if sufficient information exists to reasonably estimate the fair value of the obligations. Obligations are recorded as both a cost of the related long-lived asset and as a corresponding liability. Subsequently, the asset retirement costs are depreciated over the life of the asset and the asset retirement obligations are accreted to the expected settlement amounts. The Company has recorded asset retirement obligations associated with certain safety requirements to purge and seal gas distribution mains upon retirement, the plugging and abandonment of storage wells and other storage facilities, specific service line obligations, and certain removal and disposal obligations related to components of the Utility’s distribution system and general plant. Asset retirement obligations recorded by Laclede Group’s other subsidiaries are not material. As authorized by the MoPSC, the Utility accrues future asset removal costs associated with its property, plant and equipment even if a legal obligation does not exist. Such accruals are provided for through depreciation expense and are recorded with corresponding credits to regulatory liabilities. When the Utility retires depreciable utility plant and equipment, it charges the associated original costs to accumulated depreciation and amortization, and any related removal costs incurred are charged to regulatory liabilities. The difference between removal costs recognized in depreciation rates and the accretion expense and depreciation expense recognized for financial reporting purposes is a timing difference between recovery of these costs in rates and their recognition for financial reporting purposes.
	Accordingly, these differences are deferred as regulatory liabilities. In the rate setting process, the regulatory liability is deducted from the rate base upon which the Utility has the opportunity to earn its allowed rate of return.
	As part of the MGE acquisition, the Utility has estimated the asset retirement obligation of MGE’s long-lived assets as of the acquisition date. This allocation of asset retirement obligations is preliminary and will be finalized upon completion of a detailed fair value analysis that is being performed by the Company in the first quarter of fiscal 2014.
	The following table presents a reconciliation of the beginning and ending balances of asset retirement obligations at September 30 as reported in the Consolidated Balance Sheets:
	(Thousands)	2013			2012
	Asset retirement obligations, beginning of year	$	40,368		$	27,495
	Liabilities incurred during the period	801			851
	Liabilities settled during the period	(1,089		)	(601		)
	Accretion	2,322			1,637
	Revisions in estimated cash flows	—			10,986
	Addition of MGE asset retirement obligation	32,152			—
	Asset retirement obligations, end of year	$	74,554		$	40,368
	REGULATED OPERATIONS - The Utility accounts for its regulated operations in accordance with ASC Topic 980. This Topic sets forth the application of generally accepted accounting principles in the United States of America (GAAP) for those companies whose rates are established by or are subject to approval by an independent third-party regulator. The provisions of this accounting guidance require, among other things, that financial statements of a regulated enterprise reflect the actions of regulators, where appropriate. These actions may result in the recognition of revenues and expenses in time periods that are different than non-regulated enterprises. When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses when those amounts are reflected in rates. Also, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for recovery of costs that are expected to be incurred in the future (regulatory liabilities).
	The following regulatory assets and regulatory liabilities were reflected in the Consolidated Balance Sheets as of September 30:
	(Thousands)	2013			2012
	Regulatory Assets:
	Future income taxes due from customers	$	112,912		$	118,997
	Pension and postretirement benefit costs	381,395			304,446
	Unamortized purchased gas adjustments	17,533			40,674
	Purchased gas costs	18,249			18,386
	Compensated absences	8,004			7,836
	Other	25,387			6,382
	Total Regulatory Assets	$	563,480		$	496,721
	Regulatory Liabilities:
	Unamortized investment tax credits	$	2,900		$	3,113
	Accrued cost of removal	59,066			55,103
	Other	23,494			1,216
	Total Regulatory Liabilities	$	85,460		$	59,432
	The regulatory assets are expected to be recovered in rates charged to customers. A portion of the Company's regulatory assets are not earning a return; however, these regulatory assets are expected to be recovered from customers in future rates. Excluding deferred income taxes and purchased gas adjustment items, as of September 30, 2013 and 2012, approximately $17.2 million and $7.8 million, respectively, of regulatory assets were not earning a rate of return. The Company expects these items to be recovered over a period not to exceed 15 years consistent with precedent set by the MoPSC. The portion of the regulatory asset related to pensions and other postemployment benefits that relates to unfunded differences between the projected benefit obligation and plan assets also does not earn a rate of return.
	As authorized by the MoPSC, the Utility discontinued deferring certain costs for future recovery, as expenses associated with those specific areas were included in approved rates effective December 27, 1999. Previously deferred costs of $10.5 million are being recovered and amortized on a straight-line basis over a fifteen-year period, without return on investment. Amortization of these costs totaled $9.7 million from December 27, 1999 through September 30, 2013.
	NATURAL GAS STORED UNDERGROUND AND PROPANE GAS – For Laclede Gas, inventory of natural gas in storage is priced on a last-in, first-out (LIFO) basis and inventory of propane gas in storage is priced on a first-in, first-out (FIFO) basis. For MGE, inventory of natural gas in storage is priced on a weighted average cost basis. The replacement cost of Laclede Gas' natural gas stored underground for current use at September 30, 2013 and September 30, 2012 was less than the LIFO cost by $13.3 million and $24.3 million, respectively. The carrying value of the Utility inventory is not adjusted to the lower of cost or market prices because, pursuant to both Laclede Gas' and MGE's Purchased Gas Adjustment (PGA) Clauses, actual gas costs are recovered in customer rates. Natural gas and propane gas storage inventory in Laclede Group’s other operating segments is recorded at the lower of average cost or market.
	BUSINESS COMBINATIONS - The Company's acquisition of MGE was accounted for by the Company using business combination accounting. Under this method, the purchase price paid by the acquirer is allocated to the assets acquired and liabilities assumed as of the acquisition date based on their fair value. For additional information on the Company's acquisition of MGE, refer to Note 2, MGE Acquisition.
	GOODWILL - Goodwill is measured as the excess of the acquisition-date fair value of the consideration transferred over the amount of acquisition-date identifiable assets acquired net of assumed liabilities. Laclede Group recorded $247.1 million of goodwill as part of the MGE acquisition.
	REVENUE RECOGNITION - The Utility reads meters and bills its customers on monthly cycles. The Utility records its Gas Utility revenues from gas sales and transportation services on an accrual basis that includes estimated amounts for gas delivered, but not yet billed. The accruals for unbilled revenues are reversed in the subsequent accounting period when meters are actually read and customers are billed. The amounts of accrued unbilled revenues at September 30, 2013 and 2012, for the Utility, were $25.2 million and $11.6 million, respectively.
	Laclede Group’s other subsidiaries, including LER, record revenues when earned, either when the product is delivered or when services are performed.
	In the course of its business, LER enters into commitments associated with the purchase or sale of natural gas. Certain of LER’s derivative natural gas contracts are designated as normal purchases or normal sales, and, as such, are excluded from the scope of ASC Topic 815, “Derivatives and Hedging.” Those contracts are accounted for as executory contracts and recorded on an accrual basis. Revenues and expenses from such contracts are recorded using a gross presentation. Contracts not designated as normal purchases or normal sales are recorded as derivatives with changes in fair value recognized in earnings in the periods prior to physical delivery. For additional information on derivative instruments, refer to Note 11, Derivative Instruments and Hedging Activities. Certain of LER’s wholesale purchase and sale transactions entered on or after January 1, 2012 are classified as trading activities for financial reporting purposes. Under GAAP, revenues and expenses associated with trading activities are presented on a net basis in Gas Marketing Operating Revenues in the Statements of Consolidated Income. This net presentation has no effect on operating income or net income.
	PURCHASED GAS ADJUSTMENTS AND DEFERRED ACCOUNT – As authorized by the MoPSC, the PGA Clause allows Laclede Gas to flow through to customers, subject to prudence review by the MoPSC, the cost of purchased gas supplies. To better match customer billings with market natural gas prices, the Utility is allowed to file to modify, on a periodic basis, the level of gas costs in its PGA. Certain provisions of the PGA Clause are included below:
	•	The Utility has a risk management policy that allows for the purchase of natural gas derivative instruments with the goal of managing price risk associated with purchasing natural gas on behalf of its customers. The MoPSC clarified that costs, cost reductions, and carrying costs associated with the Utility’s use of natural gas derivative instruments are gas costs recoverable through the PGA mechanism.
	•	The tariffs allow the Utility flexibility to make up to three discretionary PGA changes during each year, in addition to its mandatory November PGA change, so long as such changes are separated by at least two months.
	•	The Utility is authorized to recover gas inventory carrying costs through its PGA rates to recover costs it incurs to finance its investment in gas supplies that are purchased during the storage injection season for sale during the heating season. The Utility is also authorized to apply carrying costs to all over- or under-recoveries of gas costs, including costs and cost reductions associated with the use of derivative instruments, including cash payments for margin deposits.
	•	The MoPSC approved a plan applicable to Laclede Gas' gas supply commodity costs under which it retains a portion of cost savings associated with the acquisition of natural gas below an established benchmark level. This gas supply cost management program allows Laclede Gas to retain 10% of cost savings, up to a maximum of $3.0 million annually. Laclede Gas did not record any income under the plan during the three fiscal years reported. Income recorded under the plan, if any, is included in Gas Utility Operating Revenues on the Statements of Consolidated Income.
	Pursuant to the provisions of the PGA Clause, the difference between actual costs incurred and costs recovered through the application of the PGA are reflected as a deferred charge or credit at the end of the fiscal year. These costs include costs and cost reductions associated with the use of derivative instruments and gas inventory carrying costs, amounts due to or from customers related to operation of the gas supply cost management program, refunds received from the Company’s suppliers in connection with gas supply, transportation, and storage services, and carrying costs on such over- or under-recoveries. At that time, the balance is classified as a current asset or current liability and recovered from, or credited to, customers over an annual period commencing in November. The balance in the current account is amortized as amounts are reflected in customer billings. The PGA Clause also provides for the treatment of income from off-system sales and capacity release revenues. Pre-tax income from off-system sales and capacity release revenues is shared with customers, with an estimated amount assumed in PGA rates. The difference between the actual amount allocated to customers for each fiscal year and the estimated amount assumed in PGA rates is recovered from, or credited to, customers over an annual period commencing in the subsequent November. The customer share of such income is determined in accordance with the tables below, which is shown for each legacy company (Laclede Gas and MGE) under which the PGA Clauses were approved by the MoPSC.
	Laclede Gas
	Pre-tax Income	Customer Share	Company Share
	First $2 million	100%	—%
	Next $2 million	80%	20%
	Next $2 million	75%	25%
	Amounts exceeding $6 million	70%	30%
	MGE
	Pre-tax Income	Customer Share	Company Share
	First $1.2 million	85%	15%
	Next $1.2 million	80%	20%
	Next $1.2 million	75%	25%
	Amounts exceeding $3.6 million	70%	30%
	See the Regulatory and Other Matters section on page 36 of this report for additional information on Laclede Gas' off-system sales.
INCOME TAXES - Laclede Group and its subsidiaries have elected, for tax purposes only, various accelerated depreciation provisions of the Internal Revenue Code. In addition, certain other costs are expensed currently for tax purposes while being deferred for book purposes. GAAP permits the benefit from a tax position to be recognized only if, and to the extent that, it is more likely than not that the tax position will be sustained upon examination by the taxing authority, based on the technical merits of the position. Unrecognized tax benefits and related interest and penalties, if any, are recorded as liabilities or as a reduction to deferred tax assets. Laclede Group companies record deferred tax liabilities and assets measured by enacted tax rates for the net tax effect of all temporary differences between the tax basis and the related carrying amounts of assets and liabilities in the financial statements. Changes in enacted tax rates, if any, and certain property basis differences are reflected by entries to regulatory asset or regulatory liability accounts for regulated companies, and are reflected as income or loss for non-regulated companies.
The Utility’s investment tax credits utilized prior to 1986 have been deferred and are being amortized in accordance with regulatory treatment over the useful life of the related property.
CASH AND CASH EQUIVALENTS - All highly liquid debt instruments purchased with original maturities of three months or less are considered to be cash equivalents. Such instruments are carried at cost, which approximates market value.
Outstanding checks on the Company’s controlled disbursement bank accounts in excess of funds on deposit create book overdrafts (which are funded at the time checks are presented for payment) and are classified as Other in the Current Liabilities section of the Consolidated Balance Sheets. Changes in book overdrafts between periods are reflected as Financing Activities in the Statements of Consolidated Cash Flows.
NATURAL GAS RECEIVABLE – LER enters into natural gas transactions with natural gas pipeline companies known as park and loan arrangements. Under the terms of the arrangements, LER purchases natural gas from a third party and delivers that natural gas to the pipeline company for the right to receive the same quantity of natural gas from the pipeline company at the same location in a future period. These arrangements are accounted for as non-monetary transactions under GAAP and are recorded at the carrying amount. As such, natural gas receivables are reflected on the Consolidated Balance Sheets at cost, which includes related pipeline fees associated with the transactions. In the period that the natural gas is returned to LER, concurrent with the sale of the natural gas to a third party, the related natural gas receivable is expensed in the Statements of Consolidated Income. In conjunction with these transactions, LER usually enters into New York Mercantile Exchange (NYMEX) and Ice Clear Europe (ICE) natural gas futures, options, and swap contracts or fixed price sales agreements to protect against market changes in future sales prices.
EARNINGS PER COMMON SHARE - GAAP requires dual presentation of basic and diluted earnings per share (EPS). EPS is computed using the two-class method, which is an earnings allocation method for computing EPS that treats a participating security as having rights to earnings that would otherwise have been available to common shareholders. Certain of the Company’s stock-based compensation awards pay nonforfeitable dividends to the participants during the vesting period and, as such, are deemed participating securities. Basic EPS is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding that are increased for additional shares that would be outstanding if potentially dilutive non-participating securities were converted to common shares, pursuant to the treasury stock method. Shares attributable to non-participating stock options and time-vested restricted stock/units are excluded from the calculation of diluted earnings per share if the effect would be antidilutive. Shares attributable to non-participating performance-contingent restricted stock awards are only included in the calculation of diluted earnings per share to the extent the underlying performance and/or market conditions are satisfied (a) prior to the end of the reporting period or (b) would be satisfied if the end of the reporting period were the end of the related contingency period and the result would be dilutive. The Company’s EPS computations are presented in Note 5, Earnings Per Common Share.
GROSS RECEIPTS AND SALES TAXES - Gross receipts taxes associated with the Utility's natural gas utility service are imposed on the Utility and billed to its customers. These amounts are recorded gross in the Statements of Consolidated Income. Amounts recorded in Gas Utility Operating Revenues were $40.8 million, $35.9 million, and $43.5 million for fiscal years 2013, 2012, and 2011, respectively. Gross receipts taxes are expensed by the Utility and included in the Taxes, other than income taxes line.
Sales taxes imposed on applicable Company sales are billed to customers. These amounts are not recorded in the Statements of Consolidated Income, but are recorded as tax collections payable and included in the Other line of the Current Liabilities section of the Consolidated Balance Sheets.
ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS – Trade accounts receivable are recorded at the amounts due from customers, including unbilled amounts. Estimates of the collectibility of trade accounts receivable are based on historical trends, age of receivables, economic conditions, credit risk of specific customers, and other factors. Accounts receivable are written off against the allowance for doubtful accounts when they are deemed to be uncollectible. The Utility’s provision for uncollectible accounts includes the amortization of previously deferred uncollectible expenses, as approved by the MoPSC.
GROUP MEDICAL AND WORKERS’ COMPENSATION RESERVES - The Company self-insures its group medical and workers’ compensation costs and carries stop-loss coverage in relation to medical claims and workers’ compensation claims. Reserves for amounts incurred but not reported are established based on historical cost levels and lags between occurrences and reporting.
FAIR VALUE MEASUREMENTS – Certain assets and liabilities are recognized or disclosed at fair value, which is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). GAAP establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.
The levels of the hierarchy are described below:
•	Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities.
•	Level 2 – Pricing inputs other than quoted prices included within Level 1, which are either directly or indirectly observable for the asset or liability as of the reporting date. These inputs are derived principally from, or corroborated by, observable market data.
•	Level 3 – Pricing that is based upon inputs that are generally unobservable that are based on the best information available and reflect management’s assumptions about how market participants would price the asset or liability.
Assessment of the significance of a particular input to the fair value measurements may require judgment and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. Additional information about fair value measurements is provided in Note 3, Pension Plans and Other Postretirement Benefits, Note 9, Fair Value of Financial Instruments, and Note 10, Fair Value Measurements.
STOCK-BASED COMPENSATION – The Company measures stock-based compensation awards at fair value at the date of grant and recognizes the compensation cost of the awards over the requisite service period. Forfeitures are estimated at the time of grant and revised, if necessary, in subsequent periods if the actual forfeitures differ from those estimates. Refer to Note 4, Stock-Based Compensation, for further discussion of the accounting for the Company’s stock-based compensation plans.
NEW ACCOUNTING STANDARDS – In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities,” to amend ASC Topic 210, “Balance Sheet,” to require additional disclosures about financial instruments and derivative instruments that have been presented on a net basis (offset) in the balance sheet. Additionally, information about financial instruments and derivative instruments that are subject to enforceable master netting arrangements or similar agreements, irrespective of whether they are presented net in the balance sheet, is required to be disclosed. The ASU impacts disclosures only and will not require any changes to financial statement presentation. The Company will present the new disclosures retrospectively beginning in the first quarter of fiscal year 2014.
In February 2013, the FASB issued ASU No. 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income.” This ASU amends Accounting Standards Codification (ASC) Topic 220, “Comprehensive Income,” by requiring entities to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to provide information on significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income, but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. The Company will present the new disclosures prospectively beginning in the first quarter of fiscal year 2014.

ACQUISITION_OF_MGE

ACQUISITION OF MGE	12 Months Ended
	Sep. 30, 2013
Business Combinations [Abstract]	'
ACQUISITION OF MGE	'
	ACQUISITION OF MGE
	Effective September 1, 2013, Laclede Group completed the purchase of substantially all of the assets and liabilities of Missouri Gas Energy (MGE), a utility engaged in the distribution of natural gas on a regulated basis in western Missouri, from Southern Union Company (SUG), an affiliate of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. The purchase was completed pursuant to the purchase agreement dated December 14, 2012. Under the terms of the purchase agreement, Laclede Group acquired MGE for a purchase price of $975 million. The acquisition was supported through a combination of the issuance of 10.0 million shares of Laclede Group common stock, completed on May 29, 2013, the issuance by Laclede Gas of $450.0 million of first mortgage bonds, completed on August 13, 2013, short-term borrowings, and available cash.
	The acquisition was accounted for under the acquisition method of accounting in accordance with ASC 805 (“Topic 805”), “Business Combinations.” Accordingly, goodwill was measured as the excess of the acquisition-date fair value of the consideration transferred over the amount of acquisition-date identifiable assets acquired net of assumed liabilities. Laclede Group recorded $247.1 million of goodwill as an asset in the consolidated balance sheet, which has been assigned to the Company’s Gas Utility segment.
	As part of the MGE acquisition, Laclede Gas has estimated the asset retirement obligation of MGE’s long-lived assets as of the acquisition date. This allocation of asset retirement obligations is preliminary and will be finalized upon completion of a detailed fair value analysis that is being performed by the Company in the first quarter of fiscal 2014.
	Under Topic 805, merger-related transaction costs (such as advisory, legal, valuation and other professional fees) are not included as components of consideration transferred but are accounted for as expenses in the periods in which the costs are incurred. During the years ended September 30, 2013 and 2012, Laclede Group incurred $17.0 million and $0.2 million, respectively, of third party pre-tax expenses associated with the transaction. These expenses are included in the Statement of Consolidated Income, with $15.1 million included in Other Operating Expenses and $1.9 million included in Interest on Long-term Debt.
	On November 13, 2013, in accordance with Section 3.2 of the purchase agreement for MGE, the Utility provided to SUG a reconciliation of certain balance sheet accounts as of August 31, 2013, the date immediately prior to the closing of the acquisition to the initial valuation date of September 30, 2012. The resulting difference adjusts for changes in the actual net assets transferred to the Utility at closing from the level at September 30, 2012. Section 3.2 also contains a process to resolve any disagreements among the parties, and the Utility plans to adjust cash and goodwill for any change as a result of this process upon final settlement, which is anticipated to be in the first quarter of fiscal 2014.
	The amount of revenue and earnings of MGE included in our Statements of Consolidated Income subsequent to the September 1, 2013 acquisition date are as follows:
	(Thousands, Except Per Share Amounts)	September 1, 2013 - September 30, 2013
	Total net revenues	$	21,985
	Net Income	1,795
	Earnings/(loss) per share:
	Basic	$	0.07
	Diluted	$	0.07
	The following table summarizes the preliminary fair value of assets acquired and liabilities assumed at the date of the acquisition:
	(Thousands)
	Assets:
	Utility plant	$	671,793
	Non-utility property	238
	Other investments	3,096
	Goodwill	247,078
	Other Property and Investments	922,205
	Accounts receivable:
	Utility	19,963
	Other	6,119
	Delayed customer billings	10,701
	Inventories:
	Natural gas stored underground	58,679
	Materials and supplies at average cost	3,988
	Prepayments and other	487
	Total Current Assets	99,937
	Deferred Charges:
	Regulatory assets	84,014
	Other	4,928
	Total Deferred Charges	88,942
	Total Assets Acquired	$	1,111,084
	Liabilities:
	Accounts payable	$	20,154
	Wages and compensation accrued	5,088
	Customer deposits	8,362
	Interest accrued	183
	Taxes accrued	17,197
	Other	12,620
	Total Current Liabilities	63,604
	Pension and postretirement benefit costs	24,466
	Asset retirement obligations	32,056
	Regulatory liabilities	2,249
	Other	13,709
	Total Deferred Credits and Other Liabilities	72,480
	Total Liabilities Assumed	$	136,084
	Net Assets Acquired	$	975,000
	The following unaudited pro forma financial information presents the combined results of operations as if the acquisition had occurred on October 1, 2011. The pro forma financial information does not reflect the costs of any integration activities. The pro forma results include estimates and assumptions, which management believes are reasonable. The unaudited pro forma financial information below is not necessarily indicative of either future results of operations or results that might have been achieved had MGE been part of the Utility as of the beginning of fiscal year 2012.
		Twelve Months Ended September 30,
	(Thousands, Except Per Share Amounts)	2013		2012
	Total net revenues	$	1,518,201	$	1,581,425
	Net Income	83,642		81,722
	Earnings per share:
	Basic	$	2.57	$	2.52
	Diluted	$	2.56	$	2.51

PENSION_PLANS_AND_OTHER_POSTRE

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS	12 Months Ended
	Sep. 30, 2013
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]	'
PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS	'
	PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS
	This footnote includes all pension plans of the Company whether historical plans or those acquired as part of the purchase of certain assets and liabilities of MGE on September 1, 2013. The net pension and postretirement obligations were remeasured at that time as well as at the fiscal year end.
	Pension Plans
	The Utility has non-contributory, defined benefit, trusteed forms of pension plans covering the majority of its employees. Plan assets consist primarily of corporate and U.S. government obligations and a growth segment consisting of exposure to equity markets, commodities, real estate and inflation-indexed securities, achieved through derivative instruments and investments in diversified mutual funds.
	Pension costs in 2013, 2012, and 2011 amounted to $17.5 million, $20.1 million, and $14.3 million, respectively, including amounts charged to construction.
	The net periodic pension costs include the following components:
	(Thousands)	2013				2012				2011
	Service cost – benefits earned during the period	$	9,209			$	9,203			$	9,553
	Interest cost on projected benefit obligation	16,959				19,358				18,819
	Expected return on plan assets	(19,358		)		(19,595		)		(18,849		)
	Amortization of prior service cost	544				592				642
	Amortization of actuarial loss	10,724				9,040				10,228
	Loss on lump-sum settlements	26,996				20,051				943
	Sub-total	45,074				38,649				21,336
	Regulatory adjustment	(27,532		)		(18,579		)		(7,066		)
	Net pension cost	$	17,542			$	20,070			$	14,270
	Other changes in plan assets and pension benefit obligations recognized in other comprehensive income include the following:
	(Thousands)	2013				2012				2011
	Current year actuarial loss (gain)	$	17,030			$	32,884			$	(13,485	)
	Amortization of actuarial loss	(10,724		)		(29,091		)		(11,171		)
	Acceleration of loss recognized due to settlement	(26,996		)		—				—
	Amortization of prior service cost	(544		)		(592		)		(642		)
	Sub-total	(21,234		)		3,201				(25,298		)
	Regulatory adjustment	21,159				(3,510		)		24,533
	Total recognized in other comprehensive income	$	(75	)		$	(309	)		$	(765	)
	Pursuant to the provisions of the Utility pension plans, pension obligations may be satisfied by lump-sum cash payments. Pursuant to a MoPSC Order, lump-sum payments are recognized as settlements (which can result in gains or losses) only if the total of such payments exceeds 100% of the sum of service and interest costs. Lump-sum payments recognized as settlements during fiscal year 2013, 2012, and 2011 were $79.5 million, $60.1 million, and $2.3 million, respectively.
	Pursuant to a MoPSC Order, the return on plan assets is based on the market-related value of plan assets implemented prospectively over a four-year period. Gains or losses not yet includible in pension cost are amortized only to the extent that such gain or loss exceeds 10% of the greater of the projected benefit obligation or the market-related value of plan assets. Such excess is amortized over the average remaining service life of active participants. The recovery in rates for Laclede Gas' qualified pension plan is based on an annual allowance of $4.8 million effective August 1, 2007 and $15.5 million effective January 1, 2011. The recovery in rates for MGE's qualified pension plan is based on an annual allowance of $10.0 million effective February 20, 2010. The difference between these amounts and pension expense as calculated pursuant to the above and that otherwise would be included in the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income is deferred as a regulatory asset or regulatory liability.
	The following table sets forth the reconciliation of the beginning and ending balances of the pension benefit obligation at September 30:
	(Thousands)	2013				2012
	Benefit obligation, beginning of year	$	412,171			$	384,163
	Service cost	9,209				9,203
	Interest cost	16,959				19,358
	Actuarial (gain) loss	(23,921		)		52,161
	MGE acquisition	151,424				—
	Settlement loss	24,999				14,348
	Gross benefits paid *	(87,023		)		(67,062		)
	Benefit obligation, end of year	$	503,818			$	412,171
	Accumulated benefit obligation, end of year	$	444,129			$	353,061
	*	Includes $79,484 and $60,085 lump-sum payments recognized as settlements in fiscal years 2013 and 2012, respectively.
	The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets at September 30:
	(Thousands)	2013				2012
	Fair value of plan assets, beginning of year	$	274,130			$	247,959
	Actual return on plan assets	3,387				53,220
	Employer contributions	27,991				40,013
	MGE acquisition	126,958				—
	Gross benefits paid *	(87,023		)		(67,062		)
	Fair value of plan assets, end of year	$	345,443			$	274,130
	Funded status of plans, end of year	$	(158,375	)		$	(138,041	)
	*	Includes $79,484 and $60,085 lump-sum payments recognized as settlements in fiscal years 2013 and 2012, respectively.
	The following table sets forth the amounts recognized in the Consolidated Balance Sheets at September 30:
	(Thousands)	2013				2012
	Current liabilities	$	(442	)		$	(468	)
	Noncurrent liabilities	(157,933		)		(137,573		)
	Total	$	(158,375	)		$	(138,041	)
	Pre-tax amounts recognized in accumulated other comprehensive income not yet recognized as components of net periodic pension cost consist of:
	Net actuarial loss	$	115,775			$	136,464
	Prior service costs	4,467				5,011
	Sub-total	120,242				141,475
	Adjustments for amounts included in Regulatory Assets	(116,686		)		(137,845		)
	Total	$	3,556			$	3,630
	At September 30, 2013, the following pre-tax amounts are expected to be amortized from accumulated other comprehensive income into net periodic pension cost during fiscal year 2014:
	(Thousands)	2014
	Amortization of net actuarial loss	$	7,088
Amortization of prior service cost	497
Sub-total	7,585
Regulatory adjustment	(7,196		)
Total	$	389
The assumptions used to calculate net periodic pension costs are as follows:
	2013		2012		2011
Weighted average discount rate*	3.95%		5.10%		4.75%
Weighted average rate of future compensation increase	3.00%		3.00%		3.00%
Expected long-term rate of return on plan assets	7.75%		7.75%		8.00%
*	Weighted average discount rate assumption for the MGE pension plan is 5.05%.
The weighted average discount rate is based on long-term, high quality bond indices at the measurement date. The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Assumed projected rates of return for each asset class were selected after analyzing historical experience and future expectations of the returns. The overall expected rate of return for the portfolio was developed based on the target allocation for each class. The expected return is a long-term assumption that generally does not change annually. However, in 2012 and 2011, the expected return assumption was adjusted to reflect capital market volatility in recent years.
The assumptions used to calculate the benefit obligations are as follows:
	2013		2012
Weighted average discount rate *	4.70%		3.95%
Weighted average rate of future compensation increase	3.00%		3.00%
*	Weighted average discount rate assumption for the MGE pension plan is 5.00%.
Following are the projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for plans that have a projected benefit obligation and an accumulated benefit obligation in excess of plan assets:
(Thousands)	2013				2012
Projected benefit obligation	$	503,818			$	412,171
Accumulated benefit obligation	444,129				353,061
Fair value of plan assets	345,443				274,130
Following are the targeted and actual plan assets by category as of September 30 of each year:
	Target			2013			2012
				Actual			Actual
Growth Strategy
Equity Markets	42.5	%		45.9	%		37.3	%
Commodities	2.5	%		1.6	%		2.2	%
Real Estate	2.5	%		3	%		2.2	%
Inflation-Indexed Securities	2.5	%		1.4	%		2.2	%
Debt Securities	50	%		43.3	%		41.1	%
Other*	—	%		4.8	%		15	%
Total	100	%		100	%		100	%
* Other investments in 2013 consist of cash equivalents. The relatively large cash position at September 30, 2012 was
due to a transition taking place between investment managers and was invested in debt securities in a matter of days.
The Utility's investment policy is designed to maximize, to the extent possible, the funded status of the plan over time, and minimize volatility of funding and costs. The policy seeks to maximize investment returns consistent with these objectives and he Utility’s tolerance for risk. The duration of plan liabilities and the impact of potential changes in asset values on the funded status are fundamental considerations in the selection of plan assets. Outside investment management specialists are utilized in each asset class. Such specialists are provided with guidelines, where appropriate, designed to ensure that the investment portfolio is managed in accordance with the policy. The policy seeks to avoid significant concentrations of risk by investing in a diversified portfolio of assets. Investments in corporate, U.S. government and agencies, and, to a lesser extent, international debt securities seek to provide duration matching with plan liabilities, and typically have investment grade ratings and reflect allocations across various entities and industries. During 2012, exposures to additional asset types were added to the target portfolio: commodities, real estate and inflation-indexed securities. The investment policy permits the use of derivative instruments, which may be used to achieve the desired market exposure of an index, adjust portfolio duration, or rebalance the total portfolio to the target asset allocation. The Growth Strategy utilizes a combination of derivative instruments and debt securities to achieve diversified exposure to equity and other markets while generating returns from the fixed-income investments and providing further duration matching with the liabilities. The assets acquired with the MGE pension plan include diversified funds that are equity-oriented and larger holdings of cash. These are being evaluated along with the liabilities of the MGE plan. Performance and compliance with the guidelines is regularly monitored. The policy calls for increased allocations to debt securities as the funded status improves.
Following are expected pension benefit payments for the succeeding five fiscal years, and in aggregate for the five years thereafter:
					Pensions from
(Millions)	Pensions from				Laclede Gas
	Qualified Trust				Funds
2014	$	22.9			$	0.4
2015	25.3				0.5
2016	27.2				0.5
2017	30.8				0.6
2018	34.2				0.6
2019 – 2023	227.2				4.5
The funding policy of the Utility is to contribute an amount not less than the minimum required by government funding standards, nor more than the maximum deductible amount for federal income tax purposes. Contributions to the pension plans in fiscal year 2014 are anticipated to be $24.0 million into the qualified trusts, and $0.4 million into the non-qualified plans.
Postretirement Benefits
The Utility provides certain life insurance benefits at retirement. Medical insurance is available after early retirement until age 65. The transition obligation not yet includible in postretirement benefit cost is being amortized over 20 years. Postretirement benefit costs in 2013, 2012, and 2011 amounted to $9.5 million, $9.5 million, and $9.1 million, respectively, including amounts charged to construction.
Net periodic postretirement benefit costs consisted of the following components:
(Thousands)	2013				2012				2011
Service cost – benefits earned during the period	$	10,162			$	8,060			$	7,676
Interest cost on accumulated postretirement benefit obligation	5,234				5,521				4,843
Expected return on plan assets	(4,447		)		(3,965		)		(3,646		)
Amortization of transition obligation	93				136				136
Amortization of prior service credit	3				(2,072		)		(2,328		)
Amortization of actuarial loss	5,300				4,261				4,443
Sub-total	16,345				11,941				11,124
Regulatory adjustment	(6,821		)		(2,417		)		(2,071		)
Net postretirement benefit cost	$	9,524			$	9,524			$	9,053
Other changes in plan assets and postretirement benefit obligations recognized in other comprehensive income include the following:
(Thousands)	2013				2012				2011
Current year actuarial loss	$	16,300			$	10,138			$	1,696
Amortization of actuarial loss	(5,300		)		(4,261		)		(4,443		)
Amortization of prior service credit	(3		)		2,072				2,328
Amortization of transition obligation	(93		)		(136		)		(136		)
Sub-total	10,904				7,813				(555		)
Regulatory adjustment	(10,904		)		(7,813		)		555
Total recognized in other comprehensive income	$	—			$	—			$	—
Pursuant to a MoPSC Order, the return on plan assets is based on the market-related value of plan assets implemented prospectively over a four-year period. Gains and losses not yet includible in postretirement benefit cost are amortized only to the extent that such gain or loss exceeds 10% of the greater of the accumulated postretirement benefit obligation or the market-related value of plan assets. Such excess is amortized over the average remaining service life of active participants. The recovery in rates for Laclede Gas' postretirement benefit plans is based on an annual allowance of $7.6 million effective August 1, 2007 and $9.5 million effective January 1, 2011. The difference between these amounts and postretirement benefit cost based on the above and that otherwise would be included in the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income is deferred as a regulatory asset or regulatory liability.
The following table sets forth the reconciliation of the beginning and ending balances of the postretirement benefit obligation at September 30:
(Thousands)	2013				2012
Benefit obligation, beginning of year	$	127,217			$	103,991
Service cost	10,162				8,060
Interest cost	5,234				5,521
Actuarial loss (gain)	17,514				15,895
MGE acquisition	28,444				—
Gross benefits paid	(8,449		)		(6,250		)
Benefit obligation, end of year	$	180,122			$	127,217
The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets at September 30:
(Thousands)	2013				2012
Fair value of plan assets at beginning of year	$	67,442			$	51,744
Actual return on plan assets	5,660				9,722
Employer contributions	16,596				12,226
MGE acquisition	30,396				—
Gross benefits paid	(8,449		)		(6,250		)
Fair value of plan assets, end of year	$	111,645			$	67,442
Funded status of plans, end of year	$	(68,477	)		$	(59,775	)
The following table sets forth the amounts recognized in the Consolidated Balance Sheets at September 30:
(Thousands)	2013				2012
Noncurrent assets	$	2,543			$	—
Current liabilities	(300		)		(790		)
Noncurrent liabilities	(70,720		)		(58,985		)
Total	$	(68,477	)		$	(59,775	)
Pre-tax amounts recognized in accumulated other comprehensive income not yet recognized as components of net periodic postretirement benefit cost consist of:
Net actuarial loss	$	63,573			$	52,573
Prior service credit	(27		)		(24		)
Transition obligation	—				93
Sub-total	63,546				52,642
Adjustments for amounts included in Regulatory Assets	(63,546		)		(52,642		)
Total	$	—			$	—
At September 30, 2013, the following pre-tax amounts are expected to be amortized from accumulated other comprehensive income into net periodic postretirement benefit cost during fiscal year 2014:
(Thousands)
Amortization of net actuarial loss	$	6,021
Amortization of prior service cost	(4		)
Sub-total	6,017
Regulatory adjustment	(6,017		)
Total	$	—
The assumptions used to calculate net periodic postretirement benefit costs are as follows:
	2013			2012			2011
Weighted average discount rate *	3.8	%		5.05	%		4.7	%
Weighted average rate of future compensation increase	3	%		3	%		3	%
Expected long-term rate of return on plan assets **	7.75	%		7.75	%		8	%
*	Weighted average discount rate assumption for the MGE postretirement plan is 5.05%.
**    Expected long-term rate of return on plan assets assumption for the MGE postretirement plan is 5.75%.
The weighted average discount rate is based on long-term, high quality bond indices at the measurement date. The expected long-term rate of return on plan assets is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Assumed projected rates of return for each asset class were selected after analyzing historical experience and future expectations of the returns. The overall expected rate of return for the portfolio was developed based on the target allocation for each class. The expected return is a long-term assumption that generally does not change annually. However, in 2012 and 2011, the expected return assumption was adjusted to reflect capital market volatility in recent years.
The assumptions used to calculate the accumulated postretirement benefit obligations are as follows:
	2013		2012
Weighted average discount rate *	4.60%		3.80%
Weighted average rate of future compensation increase	3.00%		3.00%
*	Weighted average discount rate assumption for the MGE postretirement plan is 4.95%.
The assumed medical cost trend rates at September 30 are as follows:
	2013		2012
Medical cost trend assumed for next year	7.50%		7.00%
Rate to which the medical cost trend rate is assumed to decline (the ultimate medical cost trend rate)	5.00%		5.00%
Year the rate reaches the ultimate trend	2020		2017
The following table presents the effect of an assumed 1% change in the assumed medical cost trend rate:
(Thousands)	1% Increase				1% Decrease
Effect on net periodic postretirement benefit cost	$	1,520			$	(1,390	)
Effect on accumulated postretirement benefit obligation	7,060				(6,580		)
Following are the targeted and actual plan assets by category as of September 30 of each year:
	Target			2013			2012
				Actual			Actual
Equity Securities	60	%		59	%		59	%
Debt Securities	40	%		39	%		39	%
Other	—	%		2	%		2	%
Total	100	%		100	%		100	%
Missouri state law provides for the recovery in rates of costs accrued pursuant to GAAP provided that such costs are funded through an independent, external funding mechanism. The Utility established Voluntary Employees’ Beneficiary Association and Rabbi trusts as its external funding mechanisms. The Utility’s investment policy seeks to maximize investment returns consistent with the Utility's tolerance for risk. Outside investment management specialists are utilized in each asset class. Such specialists are provided with guidelines, where appropriate, designed to ensure that the investment portfolio is managed in accordance with policy. Performance and compliance with the guidelines is regularly monitored. The Utility's current investment policy targets an asset allocation of 60% to equity securities and 40% to debt securities, excluding cash held in short-term debt securities for the purpose of making benefit payments. The Utility currently invests in a mutual fund which is rebalanced on an ongoing basis to the target allocation. The mutual fund is diversified across U.S. stock and bond markets.
Following are expected postretirement benefit payments for the succeeding five fiscal years, and in aggregate for the five years thereafter:
	Benefits Paid				Benefits Paid
(Millions)	from				from Laclede Gas
	Qualified Trust				Funds
2014	$	9.5			$	0.3
2015	9.9				0.3
2016	10.7				0.3
2017	11.7				0.4
2018	12.8				0.4
2019 – 2023	84.1				2.2
The Utility's funding policy is to contribute amounts to the trusts equal to the periodic benefit cost calculated pursuant to GAAP as recovered in rates. Contributions to the postretirement plans in fiscal year 2014 are anticipated to be $19.2 million to the qualified trusts, and $0.3 million paid directly to participants from Laclede Gas funds.
Other Plans
The Utility sponsors 401(k) plans that cover substantially all employees. The plans allow employees to contribute a portion of their base pay in accordance with specific guidelines. The Utility provides a match of such contributions within specific limits. The cost of the defined contribution plans of the Utility amounted to $5.0 million, $3.8 million, and $3.6 million for fiscal years 2013, 2012, and 2011, respectively.
Fair Value Measurements of Pension and Other Postretirement Plan Assets
The table below categorizes the fair value measurements of the Utility's’ pension plan assets:
(Thousands)	Quoted				Significant				Significant			Total
	Prices in				Observable				Unobservable
	Active				Inputs				Inputs
	Markets				(Level 2)				(Level 3)
	(Level 1)
As of September 30, 2013
Cash and cash equivalents	$	18,177			$	—			$	—		$	18,177
Stock/Bond mutual fund	—				115,817				—			115,817
Debt Securities
U.S. bond mutual funds	17,682				—				—			17,682
U.S. government	—				55,743				—			55,743
U.S. corporate	—				110,925				—			110,925
U.S. municipal	—				6,799				—			6,799
International	—				21,594				—			21,594
Derivative instruments (a)	—				(1,294		)		—			(1,294		)
Total	$	35,859			$	309,584			$	—		$	345,443
As of September 30, 2012
Cash and cash equivalents	$	57,614			$	—			$	—		$	57,614
Debt Securities
U.S. bond mutual funds	36,767				—				—			36,767
U.S. government	—				57,925				—			57,925
U.S. corporate	—				93,169				—			93,169
U.S. municipal	—				9,493				—			9,493
International	—				18,885				—			18,885
Derivative instruments (b)	—				277				—			277
Total	$	94,381			$	179,749			$	—		$	274,130
(a)	Derivative assets of $4,186 net of cash margin payable of $5,480.
(b)	Derivative assets of $3,027 net of cash margin payable of $2,750.
The table below categorizes the fair value measurements of The Utility's postretirement plan assets:
(Thousands)	Quoted				Significant				Significant			Total
	Prices in				Observable				Unobservable
	Active				Inputs				Inputs
	Markets				(Level 2)				(Level 3)
	(Level 1)
As of September 30, 2013
Cash and cash equivalents	$	1,411			$	—			$	—		$	1,411
U.S. stock/bond mutual fund	110,234				—				—			110,234
Total	$	111,645			$	—			$	—		$	111,645
As of September 30, 2012
Cash and cash equivalents	$	1,106			$	—			$	—		$	1,106
U.S. stock/bond mutual fund	66,336				—				—			66,336
Total	$	67,442			$	—			$	—		$	67,442
Cash and cash equivalents include money market mutual funds valued based on quoted market prices. Fair values of derivative instruments are calculated by investment managers who use valuation models that incorporate observable market inputs. Debt securities are valued based on broker/dealer quotations or by using observable market inputs. The stock and bond mutual funds are valued at the quoted market price of the identical securities.

STOCKBASED_COMPENSATION

STOCK-BASED COMPENSATION	12 Months Ended
	Sep. 30, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
STOCK-BASED COMPENSATION	'
	STOCK-BASED COMPENSATION
	The Laclede Group 2006 Equity Incentive Plan (the 2006 Plan) was amended and approved at the annual meeting of shareholders of Laclede Group on January 26, 2012, as discussed below. The purpose of the 2006 Plan is to encourage directors, officers, and employees of the Company and its subsidiaries to contribute to the Company’s success and align their interests with that of shareholders. To accomplish this purpose, the Compensation Committee (Committee) of the Board of Directors may grant awards under the 2006 Plan that may be earned by achieving performance objectives and/or other criteria as determined by the Committee. Under the terms of the 2006 Plan, officers and employees of the Company and its subsidiaries, as determined by the Committee, are eligible to be selected for awards. Effective February 1, 2012, members of the Company’s Board of Directors are also eligible to participate in the 2006 Plan and no additional awards will be granted under the Restricted Stock Plan for Non-Employee Directors. The 2006 Plan provides for restricted stock, restricted stock units, qualified and non-qualified stock options, stock appreciation rights, and performance shares payable in stock, cash, or a combination of both. The 2006 Plan generally provides a minimum vesting period of at least three years for each type of award, with pro rata vesting permitted during the minimum three year vesting period. The maximum number of shares reserved for issuance under the 2006 Plan is 1,250,000. The 2006 Plan replaced the Laclede Group Equity Incentive Plan (the 2003 Plan). Shares reserved under the 2003 Plan, other than those needed for currently outstanding awards, were canceled upon shareholder approval of the 2006 Plan.
	The Company issues new shares to satisfy employee restricted stock awards and stock option exercises. Prior to February 1, 2012, shares for non-employee directors were purchased on the open market.
	Restricted Stock Awards
	During fiscal year 2013, the Company granted 108,419 performance-contingent restricted share units to executive officers and key employees at a weighted average grant date fair value of $34.49 per share. This number represents the maximum shares that can be earned pursuant to the terms of the awards. The share units have a performance period ending September 30, 2014. While the participants have no interim voting rights on these share units, dividends accrue during the performance period and are paid to the participants upon vesting, but are subject to forfeiture if the underlying share units do not vest. The number of share units that will ultimately vest is dependent upon the attainment of certain levels of earnings and other strategic goals, as well as the Company’s level of total shareholder return (TSR) during the performance period relative to a comparator group of companies. This TSR provision is considered a market condition under GAAP and is discussed further below.
	The weighted average grant date fair value of performance-contingent restricted shares and share units granted during fiscal years 2012 and 2011 was $36.55 and $30.68 per share, respectively.
	Fiscal year 2013 activity of restricted stock and restricted stock units subject to performance and/or market conditions is presented below:
		Shares/			Weighted
		Units			Average
					Grant Date
					Fair Value
	Nonvested at September 30, 2012	232,403			$	30.89
	Granted (maximum shares that can be earned)	108,419			$	34.49
	Vested	(47,436	)		$	27.61
	Forfeited	(51,118	)		$	26.11
	Nonvested at September 30, 2013	242,268			$	34.15
	During fiscal year 2013, the Company granted 43,924 shares of time-vested restricted stock to executive officers and key employees at a weighted average grant date fair value of $40.03 per share. These shares were awarded on October 1, 2012 and December 3, 2012 and vest October 1, 2014 and December 1, 2015, respectively. In the interim, participants receive full voting rights and dividends, which are not subject to forfeiture. The weighted average grant date fair value of time-vested restricted stock and restricted stock units awarded to employees during fiscal year 2012 and 2011 was $39.72 and $35.93 per share, respectively.
	During fiscal year 2013, the Company granted 15,200 shares of time-vested restricted stock to non-employee directors at a weighted average grant date fair value of $39.92 per share. The weighted average grant date fair value of restricted stock awarded to non-employee directors during fiscal years 2012 and 2011 was $41.36 and $39.48 per share, respectively. These shares were granted under the Restricted Stock Plan for Non-Employee Directors and vest depending on the participant’s age upon entering the plan and years of service as a director. The plan’s trustee acquired the shares for the awards in the open market and holds the shares as trustee for the benefit of the non-employee directors until the restrictions expire. In the interim, the participants receive full dividends and voting rights. As discussed above, effective February 1, 2012, any awards to non-employee directors will be made pursuant under The Laclede Group 2006 Equity Incentive Plan.
	Time-vested restricted stock and stock unit activity for fiscal year 2013 is presented below:
		Shares/			Weighted
		Units			Average
					Grant Date
					Fair Value
	Nonvested at September 30, 2012	115,115			$	36.54
	Granted	59,124			$	40
	Vested	(43,785	)		$	34.95
	Forfeited	(11,050	)		$	38.61
	Nonvested at September 30, 2013	119,404			$	38.64
	During fiscal year 2013, 91,221 shares of restricted stock and stock units (performance-contingent and time-vested), awarded on November 4, 2008, December 1, 2009, January 4, 2010, May 3, 2010, and July 1, 2010 vested. The Company withheld 23,311 of the vested shares at a weighted average price of $39.96 per share pursuant to elections by employees to satisfy tax withholding obligations. During fiscal year 2012, 90,839 shares of restricted stock (performance-contingent and time-vested), awarded on February 14, 2008, November 5, 2008, and March 31, 2009, vested. The Company withheld 30,052 of these vested shares at a weighted average price of $40.02 per share pursuant to elections by employees to satisfy tax withholding obligations. During fiscal year 2011, 94,500 shares of performance-contingent restricted stock, awarded on December 5, 2007, vested. The Company withheld 32,373 of these vested shares at a weighted average price of $35.90 per share pursuant to elections by employees to satisfy tax withholding obligations.
	The total fair value of restricted stock (performance-contingent and time-vested) vested during fiscal years 2013, 2012, and 2011 was $3.8 million, $4.2 million, and $3.6 million, respectively, and the related actual tax benefit realized was $1.4 million, $1.6 million, and $1.4 million, respectively.
	Stock Option Awards
	No stock options were granted during fiscal years 2013, 2012, and 2011. Stock option activity for fiscal year 2013 is presented below:
		Stock			Weighted				Weighted		Aggregate
		Options			Average				Average		Intrinsic
					Exercise				Remaining		Value
					Price				Contractual		$0
									Term
									(Years)
	Outstanding at September 30, 2012	214,000			$	31.02
	Granted	—			$	—
	Exercised	(80,500	)		$	29.61
	Forfeited	—			$	—
	Expired	—			$	—
	Outstanding at September 30, 2013	133,500			$	31.87			2.8		$	1,752
	Fully Vested and Expected to Vest at September 30, 2013	133,500			$	31.87			2.8		$	1,752
	Exercisable at September 30, 2013	133,500			$	31.87			2.8		$	1,752
	Exercise prices of options outstanding at September 30, 2013 range from $28.85 to $34.95. During fiscal year 2013, cash received from the exercise of stock options was $2.7 million, the intrinsic value of the options exercised was $1.0 million and the related actual tax benefit realized was $0.4 million. During fiscal year 2012, cash received from the exercise of stock options was $2.5 million, the intrinsic value of the options exercised was $1.0 million and the related actual tax benefit realized was $0.4 million. During fiscal year 2011, cash received from the exercise of stock options was $0.9 million, the intrinsic value of the options exercised was $0.2 million and the related actual tax benefit realized was $0.1 million.
	The closing price of the Company’s common stock was $45.00 at September 30, 2013.
	Equity Compensation Costs
	Compensation cost for performance-contingent restricted stock and stock unit awards is based upon the probable outcome of the performance conditions. For shares or units that do not vest or that are not expected to vest due to the outcome of the performance conditions (excluding market conditions), no compensation cost is recognized and any previously recognized compensation cost is reversed.
	The fair value of awards of performance-contingent and time-vested restricted stock and restricted stock units, not subject to the TSR provision, is estimated using the closing price of the Company’s stock on the date of the grant. For those awards that do not pay dividends during the vesting period, the estimate of fair value is reduced by the present value of the dividends expected to be paid on the Company’s common stock during the performance period, discounted using an appropriate U.S. Treasury yield. For shares subject to the TSR provision, the estimated impact of this market condition is reflected in the grant date fair value per share of the awards. Accordingly, compensation cost is not reversed to reflect any actual reductions in the awards that may result from the TSR provision. However, if the Company’s TSR during the performance period ranks below the level specified in the award agreements, relative to a comparator group of companies, and the Committee elects not to reduce the award (or reduce by a lesser amount), this election would be accounted for as a modification of the original award and additional compensation cost would be recognized at that time. The grant date fair value of the awards subject to the TSR provision awarded during fiscal years 2013, 2012, and 2011 was valued by a Monte Carlo simulation model that assessed the probabilities of various TSR outcomes. The significant assumptions used in the Monte Carlo simulations are as follows:
		2013			2012			2011
	Risk free interest rate	0.32	%		0.39	%		0.79	%
	Expected dividend yield of stock	—			—			—
	Expected volatility of stock	19.6	%		23.21	%		33.42	%
	Vesting period	2.8 years			2.8 years			2.8 years
	The risk free interest rate was based on the yield on U.S. Treasury securities matching the vesting period. The expected volatility is based on the historical volatility of the Company’s stock. Volatility assumptions were also made for each of the companies included in the comparator group. The vesting period is equal to the performance period set forth in the terms of the award.
	The amounts of compensation cost recognized for share-based compensation arrangements are presented below:
	(Thousands)	2013				2012				2011
	Total equity compensation cost	$	4,453			$	2,707			$	3,980
	Compensation cost capitalized	(1,366		)		(808		)		(924		)
	Compensation cost recognized in net income	3,087				1,899				3,056
	Income tax benefit recognized in net income	(1,182		)		(733		)		(1,179		)
Compensation cost recognized in net income, net of income tax	1,905				1,166				1,877
As of September 30, 2013, there was $4.9 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements. That cost is expected to be recognized over a weighted average period of 2.0 years.

EARNINGS_PER_COMMON_SHARE

EARNINGS PER COMMON SHARE	12 Months Ended
	Sep. 30, 2013
Earnings Per Share [Abstract]	'
EARNINGS PER COMMON SHARE	'
	EARNINGS PER COMMON SHARE
	(Thousands, Except Per Share Amounts)	2013		2012		2011
	Basic EPS:
	Net Income	$	52,758	$	62,640	$	63,825
	Less: Income allocated to participating securities	245		340		497
	Net Income Available  to Common Shareholders	$	52,513	$	62,300	$	63,328
	Weighted Average Shares Outstanding	25,875		22,262		22,099
	Earnings Per Share of Common Stock	$	2.03	$	2.8	$	2.87
	Diluted EPS:
	Net Income	$	52,758	$	62,640	$	63,825
	Less: Income allocated to participating securities	245		340		496
	Net Income Available to Common Shareholders	$	52,513	$	62,300	$	63,329
	Weighted Average Shares Outstanding	25,875		22,262		22,099
	Dilutive Effect of Stock Options, Restricted Stock, and Restricted Stock Units	77		78		72
	Weighted Average Diluted Shares	25,952		22,340		22,171
	Earnings Per Share of Common Stock	$	2.02	$	2.79	$	2.86
	Outstanding Shares Excluded from the Calculation of Diluted EPS Attributable to:
	Antidilutive stock options	—		—		—
	Restricted stock and stock units subject to performance and/or market conditions	188		195		203
	Total	188		195		203

STOCKHOLDERS_EQUITY

STOCKHOLDER'S EQUITY	12 Months Ended
	Sep. 30, 2013
Stockholders' Equity Note [Abstract]	'
STOCKHOLDER'S EQUITY	'
	STOCKHOLDER'S EQUITY
	Total shares of common stock outstanding were 32.70 million and 22.54 million at September 30, 2013 and 2012, respectively.
	Common stock and paid-in capital increased $435.8 million in fiscal year 2013. The issuance of 44,074 common shares under the Dividend Reinvestment and Stock Purchase Plan increased common stock and paid-in capital by $1.8 million. The remaining $434.0 million increase was due to the issuance of 10,005,000 shares in May 2013, stock-based compensation costs and the issuance of 108,331 shares of common stock under the Equity Incentive Plan. Common stock and paid-in capital increased $5.0 million in fiscal year 2012. The issuance of 46,107 common shares under the Dividend Reinvestment and Stock Purchase Plan increased common stock and paid-in capital by $1.8 million. The remaining $3.2 million increase was primarily due to stock-based compensation costs and the issuance of 62,590 shares of common stock under the Equity Incentive Plan. Substantially all of the Utility's plant is subject to the liens of its first mortgage bonds. The mortgage contains several restrictions on the Utility's ability to pay cash dividends on its common stock.
	These provisions are applicable regardless of whether the stock is publicly held or, as has been the case since the formation of Laclede Group, held solely by the Utility’s parent company. Under the most restrictive of these provisions, no cash dividend may be declared or paid if, after the dividend, the aggregate net amount spent for all dividends after September 30, 1953, would exceed a maximum amount determined by a formula set out in the mortgage. Under that formula, the maximum amount is the sum of $8 million plus earnings applicable to common stock (adjusted for stock repurchases and issuances) for the period from September 30, 1953, to the last day of the quarter before the declaration or payment date for the dividends. As of September 30, 2013 and 2012, the amount under the mortgage’s formula that was available to pay dividends was $833 million and $355 million, respectively. Thus, all of the Utility’s retained earnings were free from such restrictions as of those dates. The substantial increase in 2013 was primarily due to the issuance of stock to Laclede Group to fund a portion of the MGE acquisition.
	Laclede Group has a registration statement on file on Form S-3 for the issuance and sale of up to 285,222 shares of its common stock under its Dividend Reinvestment and Stock Purchase Program. There were 194,246 and 186,919 shares at September 30, 2013 and November 26, 2013, respectively, remaining available for issuance under this Form S-3. The Company filed this Form S-3 on July 29, 2011.
	On August 6, 2013, Laclede Group and Laclede Gas filed with the SEC a joint shelf registration statement on Form S-3 for issuance of various types of debt and equity securities, which registration statement will expire August 5, 2016. Bonds totaling $450 million were issued by Laclede Gas from this shelf registration statement on August 13, 2013. The amount, timing, and type of additional financing to be issued under this shelf registration statement will depend on cash requirements and market conditions.
	The Utility has authority from the MoPSC to issue up to $518 million in debt securities and preferred stock, including on a private placement basis, as well as to enter into capital leases, issue common stock and receive paid-in capital. This authorization was originally effective through June 30, 2013. In August 2012, the Utility filed a request with the MoPSC to extend this authority for an additional two years, to June 30, 2015. This extension was approved October 24, 2012, to be effective on November 23, 2012. At September 30, 2013, $370.8 million remained under this authorization. The amount, timing, and type of additional financing to be issued will depend on cash requirements and market conditions.
	The components of accumulated other comprehensive income (loss), net of income taxes, recognized in the
	Consolidated Balance Sheets at September 30 were as follows:
	(Thousands)				Defined Benefit Pension and Other			Total
		Net Unrealized Gains (Losses) on Cash Flow Hedges			Postretirement
					Benefit Plans
	Balance at September 30, 2011	$	320		$	(2,420	)	$	(2,100	)
	Current-period change	(2,206		)	190			(2,016		)
	Balance at September 30, 2012	(1,886		)	(2,230		)	(4,116		)
	Current-period change	3,281			48			3,329
	Balance at September 30, 2013	1,395			(2,182		)	(787		)
	Income tax expense (benefit) recorded for items of other comprehensive income reported in the Statements of Consolidated Comprehensive Income is calculated by applying statutory federal, state, and local income tax rates applicable to ordinary income. The tax rates applied to individual items of other comprehensive income are similar within each reporting period.

LONGTERM_DEBT

LONG-TERM DEBT	12 Months Ended
	Sep. 30, 2013
Debt Disclosure [Abstract]	'
LONG-TERM DEBT	'
	LONG-TERM DEBT
	Maturities on long-term debt for the five fiscal years subsequent to September 30, 2013 are as follows:
	2014	—
	2015	—
	2016	—
	2017	—
	2018	$	100	million
	On October 15, 2012, the Utility paid at maturity $25 million principal amount of 6 1/2% first mortgage bonds. This maturity was funded through short-term borrowings. Laclede Group issued $25 million of 3.31% 10-year unsecured notes in a private placement on December 14, 2012 and the Utility issued $100 million of first mortgage bonds in a private placement on March 15, 2013, that had been committed to in August 2012. Of this $100 million, $55 million were issued at 3.00% for a 10-year term, maturing in March 2023, and $45 million were issued at 3.40% for a 15-year term, maturing in March 2028. The proceeds were used for the repayment of short-term debt and general corporate purposes. The Utility issued $450 million of first mortgage bonds on August 13, 2013. Of this $450 million, $100 million was issued at 2.00% maturing in August 2018, $250 million was issued at 3.40% maturing in August 2023, and $100 million was issued at 4.625% maturing in August 2043. The proceeds were used to fund a portion of the MGE acquisition.
	At September 30, 2013, the Company had fixed-rate long-term debt totaling $915 million. While these long-term debt issues are fixed-rate, they are subject to changes in fair value as market interest rates change. Of the Company’s $915 million in long-term debt, $50 million have no call options, $435 million have make-whole call options, $350 million are callable at par three to six months prior to maturity and $80 million are callable at par beginning in October 2013. None of the debt has any put options.
	On August 6, 2013, Laclede Group and Laclede Gas filed with the SEC a joint shelf registration statement on Form S-3 for issuance of various types of debt and equity securities, which expires August 5, 2016. Bonds totaling $450 million were issued by Laclede Gas from this registration statement on August 13, 2013. The amount, timing, and type of additional financing to be issued under these shelf registrations will depend on cash requirements and market conditions.
	The Utility has authority from the MoPSC to issue up to $518 million in debt securities and preferred stock, including on a private placement basis, as well as to enter into capital leases, issue common stock and receive paid-in capital. This authorization was originally effective through June 30, 2013. In August 2012, the Utility filed a request with the MoPSC to extend this authority for an additional two years, to June 30, 2015. This extension was approved October 24, 2012, to be effective on November 23, 2012. At November 26, 2013, $370.8 million remained under this authorization. The amount, timing, and type of additional financing to be issued will depend on cash requirements and market conditions.
	Substantially all of the Utility plant is subject to the liens of its first mortgage bonds. The mortgage contains several restrictions on the Utility's ability to pay cash dividends on its common stock, which are described more fully in Note 6, Stockholders’ Equity.
	At September 30, 2013 and 2012, the Utility had authorized 1,480,000 shares of preferred stock, but none were issued and outstanding.
	For information on additional financing commitments, refer to Note 16, Commitments and Contingencies.

NOTES_PAYABLE_AND_CREDIT_AGREE

NOTES PAYABLE AND CREDIT AGREEMENTS	12 Months Ended
	Sep. 30, 2013
Short-term Debt [Abstract]	'
NOTES PAYABLE AND CREDIT AGREEMENTS	'
	NOTES PAYABLE AND CREDIT AGREEMENTS
	The Company’s short-term borrowing requirements typically peak during the colder months. These short-term cash requirements can be met through the sale of commercial paper supported by lines of credit with banks or through direct use of the lines of credit. On September 3, 2013, the Utility entered into a new syndicated line of credit for $450 million with nine banks, which will expire in September 2018. The largest portion provided by a single bank is 15.6%. The previous syndicated line of credit agreement was terminated at that time.
	The Utility’s line of credit includes a covenant limiting total debt, including short-term debt, to no more than 70% of total capitalization. On September 30, 2013, total debt was 48% of total capitalization.
	Information about the Laclede Group’s short-term borrowings (excluding intercompany borrowings) during the 12 months ended September 30, and as of September 30, is presented below for 2013 and 2012:
		Commercial Paper Borrowings
	Twelve Months Ended September 30, 2013
	Weighted average borrowings outstanding	$34.2 million
	Weighted average interest rate	0.30%
	Range of borrowings outstanding	$0 – $99.4 million
	As of September 30, 2013
	Borrowings outstanding at end of period	$74.0 million
	Weighted average interest rate	0.30%
	Twelve Months Ended September 30, 2012
	Weighted average borrowings outstanding	$43.8 million
	Weighted average interest rate	0.30%
	Range of borrowings outstanding	$0 – $133.5 million
	As of September 30, 2012
	Borrowings outstanding at end of period	$40.1 million
	Weighted average interest rate	0.20%
	Short-term cash requirements outside of the Utility have generally been met with internally-generated funds. On September 3, 2013, Laclede Group entered into a new $150 million in a syndicated line of credit, which expires September 2018. The previous syndicated line of credit agreement was terminated at that time. Laclede Group's line of credit has covenants limiting the total debt of the consolidated Laclede Group to no more than 70% of the Company’s total capitalization. This ratio stood at 49% on September 30, 2013. Occasionally, Laclede Group’s lines may be used to provide for the funding needs of various subsidiaries. There were no borrowings under Laclede Group’s lines during fiscal years 2013 and 2012.

FAIR_VALUE_OF_FINANCIAL_INSTRU

FAIR VALUE OF FINANCIAL INSTRUMENTS	12 Months Ended
	Sep. 30, 2013
Fair Value Disclosures [Abstract]	'
FAIR VALUE OF FINANCIAL INSTRUMENTS	'
	FAIR VALUE OF FINANCIAL INSTRUMENTS
	The carrying amounts and estimated fair values of financial instruments not measured at fair value on a recurring basis at September 30, 2013 and 2012 are as follows:
						Classification of Estimated Fair Value
	(Thousands)	Carrying		Fair		Quoted		Significant Observable Inputs		Significant Unobservable Inputs
		Amount		Value		Prices in Active Markets		(Level 2)		(Level 3)
						(Level 1)
	As of September 30, 2013
	Cash and cash equivalents	$	52,981	$	52,981	$	52,824	$	157	$	—
	Short-term debt	74,000		74,000		—		74,000		—
	Long-term debt, including current portion	912,712		954,126		—		954,126		—
	As of September 30, 2012
	Cash and cash equivalents	$	27,457	$	27,457	$	17,380	$	10,077	$	—
	Short-term debt	40,100		40,100		—		40,100		—
	Long-term debt, including current portion	364,416		452,768		—		452,768		—
	The carrying amounts for cash and cash equivalents and short-term debt approximate fair value due to the short maturity of these instruments. The fair values of long-term debt are estimated based on market prices for similar issues. Refer to Note 10, Fair Value Measurements, for information on financial instruments measured at fair value on a recurring basis.

FAIR_VALUE_MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Sep. 30, 2013
Fair Value Disclosures [Abstract]	'
FAIR VALUE MEASUREMENTS	'
	FAIR VALUE MEASUREMENTS
	The following table categorizes the assets and liabilities in the Consolidated Balance Sheets that are accounted for at fair value on a recurring basis in periods subsequent to initial recognition.
	(Thousands)	Quoted			Significant			Significant		Effects of Netting and Cash Margin Receivables			Total
		Prices in			Observable			Unobservable		/Payables
		Active			Inputs			Inputs
		Markets			(Level 2)			(Level 3)
		(Level 1)
	As of September 30, 2013
	Assets
	U. S. Stock/Bond Mutual Funds	$	14,500		$	—		$	—	$	—		$	14,500
	NYMEX/ICE natural gas contracts	4,333			330			—		(2,145		)	$	2,518
	OTCBB natural gas contracts	—			232			—		(232		)	—
	NYMEX gasoline and heating oil contracts	105			—			—		(105		)	$	—
	Natural gas commodity contracts	—			1,129			150		(495		)	$	784
	Total	$	18,938		$	1,691		$	150	$	(2,977	)	$	17,802
	Liabilities
	NYMEX/ICE natural gas contracts	$	3,687		$	321		$	—	$	(4,008	)	$	—
	OTCBB natural gas contracts	—			5,443			—		(232		)	$	5,211
	NYMEX gasoline and heating oil contracts	—			—			—		—			$	—
	Natural gas commodity contracts	—			1,140			40		(495		)	$	685
	Total	$	3,687		$	6,904		$	40	$	(4,735	)	$	5,896
	As of September 30, 2012
	Assets
	U. S. Stock/Bond Mutual Funds	$	13,187		$	—		$	—	$	—		$	13,187
	NYMEX/ICE natural gas contracts	7,411			994			—		(8,405		)	$	—
	NYMEX gasoline and heating oil contracts	344			—			—		(344		)	$	—
	Natural gas commodity contracts	—			3,060			113		(299		)	$	2,874
	Total	$	20,942		$	4,054		$	113	$	(9,048	)	$	16,061
	Liabilities
	NYMEX/ICE natural gas contracts	$	12,253		$	1,891		$	—	$	(14,144	)	$	—
	NYMEX gasoline and heating oil contracts	—			—			—		—			$	—
	Natural gas commodity contracts	—			428			4		(299		)	$	133
	Total	$	12,253		$	2,319		$	4	$	(14,443	)	$	133
	The mutual funds included in Level 1 are valued based on exchange-quoted market prices of identical securities. Derivative instruments included in Level 1 are valued using quoted market prices on the NYMEX. Derivative instruments classified in Level 2 include physical commodity derivatives that are valued using Over The Counter Bulletin Board (OTCBB), broker, or dealer quotation services whose prices are derived principally from, or are corroborated by, observable market inputs. Also included in Level 2 are certain derivative instruments that have values that are similar to, and correlate with, quoted prices for exchange-traded instruments in active markets. Derivative instruments included in Level 3 are valued using generally unobservable inputs that are based upon the best information available and reflect management’s assumptions about how market participants would price the asset or liability. The Company’s policy is to recognize transfers between the levels of the fair value hierarchy, if any, as of the beginning of the interim reporting period in which circumstances change or events occur to cause the transfer. The following is a reconciliation of the Level 3 beginning and ending net derivative balances:
	(Thousands)	2013			2012
	Beginning of period	$	109		$	13
	Settlements	(269		)	(54		)
	Net losses related to derivatives not held at end of period	(99		)	(68		)
	Net gains related to derivatives still held at end of period	369			218
	End of period	$	110		$	109
	The mutual funds are included in the Other investments line of the Consolidated Balance Sheets. Derivative assets and liabilities, including receivables and payables associated with cash margin requirements, are presented net in the Consolidated Balance Sheets when a legally enforceable netting agreement exists between the Company and the counterparty to a derivative contract. For additional information on derivative instruments, see Note 11, Derivative Instruments and Hedging Activities.

DERIVATIVE_INSTRUMENTS_AND_HED

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES	12 Months Ended
	Sep. 30, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES	'
	DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
	The Utility has a risk management policy that allows for the purchase of natural gas derivative instruments with the goal of managing price risk associated with purchasing natural gas on behalf of its customers. This policy prohibits speculation and permits the Utility to hedge up to 70% of its normal volumes purchased for up to a 36-month period. Costs and cost reductions, including carrying costs, associated with the Utility’s use of natural gas derivative instruments are allowed to be passed on to the Utility’s customers through the operation of its PGA Clause, through which the MoPSC allows the Utility to recover gas supply costs, subject to prudence review by the MoPSC. Accordingly, the Utility does not expect any adverse earnings impact as a result of the use of these derivative instruments. The Utility does not designate these instruments as hedging instruments for financial reporting purposes because gains or losses associated with the use of these derivative instruments are deferred and recorded as regulatory assets or regulatory liabilities pursuant to ASC Topic 980, “Regulated Operations,” and, as a result, have no direct impact on the Statements of Consolidated Income. The timing of the operation of the PGA Clause may cause interim variations in short-term cash flows, because the Utility is subject to cash margin requirements associated with changes in the values of these instruments. Nevertheless, carrying costs associated with such requirements are recovered through the PGA Clause.
	From time to time, the Utility purchases NYMEX futures and options contracts to help stabilize operating costs associated with forecasted purchases of gasoline and diesel fuels used to power vehicles and equipment used in the course of its business. At September 30, 2013, Laclede Gas held 0.3 million gallons of gasoline futures contracts at an average price of $2.23 per gallon. Most of these contracts, the longest of which extends to April 2014, are designated as cash flow hedges of forecasted transactions pursuant to ASC Topic 815. The gains or losses on these derivative instruments are not subject to the Utility’s PGA Clause.
	In the course of its business, Laclede Group’s non-regulated gas marketing subsidiary, LER, which includes its wholly owned subsidiary LER Storage Services, Inc., enters into commitments associated with the purchase or sale of natural gas. Certain of LER’s derivative natural gas contracts are designated as normal purchases or normal sales and, as such, are excluded from the scope of ASC Topic 815 and are accounted for as executory contracts on an accrual basis. Any of LER’s derivative natural gas contracts that are not designated as normal purchases or normal sales are accounted for at fair value. At September 30, 2013, the fair values of 67.4 million MMBtu of non-exchange traded natural gas commodity contracts were reflected in the Consolidated Balance Sheet. Of these contracts, 58.5 million MMBtu will settle during fiscal year 2014, 8.1 million MMBtu will settle during fiscal year 2015, while the remaining 0.8 million MMBtu will settle during fiscal year 2016. These contracts have not been designated as hedges; therefore, changes in the fair value of these contracts are reported in earnings each period. Furthermore, LER manages the price risk associated with its fixed-priced commitments by either closely matching the offsetting physical purchase or sale of natural gas at fixed prices or through the use of NYMEX or ICE futures, swap, and option contracts to lock in margins. At September 30, 2013, LER’s unmatched fixed-price positions were not material to Laclede Group’s financial position or results of operations. LER’s NYMEX and ICE natural gas futures, swap, and option contracts used to lock in margins may be designated as cash flow hedges of forecasted transactions for financial reporting purposes.
	Derivative instruments designated as cash flow hedges of forecasted transactions are recognized on the Consolidated Balance Sheets at fair value and the change in the fair value of the effective portion of these hedge instruments is recorded, net of tax, in other comprehensive income (OCI). Accumulated other comprehensive income (AOCI) is a component of Total Common Stock Equity. Amounts are reclassified from AOCI into earnings when the hedged items affect net income, using the same revenue or expense category that the hedged item impacts. Based on market prices at September 30, 2013, it is expected that approximately $2.3 million of pretax losses will be reclassified into the Statements of Consolidated Income during fiscal year 2014. Cash flows from hedging transactions are classified in the same category as the cash flows from the items that are being hedged in the Statements of Consolidated Cash Flows.
	The Company’s exchange-traded/cleared derivative instruments consist primarily of NYMEX and ICE positions. The NYMEX is the primary national commodities exchange on which natural gas derivatives are traded. Open NYMEX/ICE and OTCBB natural gas futures and swap positions at September 30, 2013 were as follows:
		Laclede Gas Company							Laclede Energy
									Resources, Inc.
		MMBtu			Avg. Price				MMBtu		Avg. Price
		(millions)			Per				(millions)		Per
					MMBtu						MMBtu
	NYMEX/ICE open short futures/swap positions
	Fiscal 2014	—			$	—			12.91		$	3.98
	Fiscal 2015	—			—				0.06		4.21
	NYMEX/ICE open long futures/swap positions
	Fiscal 2014	7.26			$	3.99			1.71		$	3.94
	Fiscal 2015	0.94			3.84				0.19		4.06
	Fiscal 2016	—			—				0.02		4.15
	OTCBB open long futures
	Fiscal 2014	16.81			$	3.97			—		$	—
	Fiscal 2015	7.58			4.22				—		—
	At September 30, 2013, the Utility and LER also had 23.6 million MMBtu and 0.0 million MMBtu, respectively, of other price mitigation in place through the use of NYMEX and OTCBB natural gas option-based strategies.
	In February 2013, Laclede Group entered into certain interest rate swap agreements, with a notional amount of $355 million, to effectively lock in interest rates on a portion of the long-term debt it anticipated issuing to finance its acquisition of Missouri Gas Energy (MGE). These derivative instruments had been designated as cash flow hedges of forecasted transactions. These forward starting swaps involve the payment of a fixed interest rate and the receipt of a floating interest rate (the London Interbank Offered Rate, also known as LIBOR) over the terms specified in the contracts. On August 6, 2013, the interest rate swap agreements were terminated and the settlement resulted in a $20.8 million gain by Laclede Group. The Company assigned the gain as a regulatory liability since the interest rate swaps were entered into to hedge the interest payments on the $450 million of long-term debt issued on August 13, 2013 by Laclede Gas.
	The Effect of Derivative Instruments on the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income
		Location of Gain (Loss)
	(Thousands)	Recorded in Income	2013				2012			2011
	Derivatives in Cash Flow Hedging Relationships
	Effective portion of gain (loss) recognized in OCI on derivatives:
	NYMEX/ICE natural gas contracts		$	4,923			$	4,505		$	5,226
	NYMEX gasoline and heating oil contracts		123				297			355
	Total		$	5,046			$	4,802		$	5,581
	Effective portion of gain (loss) reclassified from AOCI to income:
	NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	$	(4	)		$	18,929		$	7,443
		Gas Marketing Operating Expenses	(509		)		(10,532		)	(9,770		)
	Sub-total		$	(513	)		$	8,397		$	(2,327	)
	NYMEX gasoline and heating oil contracts	Gas Utility Other Operation Expenses	211				—			466
	Total		$	(302	)		$	8,397		$	(1,861	)
	Ineffective portion of gain (loss) on derivatives
	recognized in income:
	NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	$	(420	)		$	(36	)	$	966
		Gas Marketing Operating Expenses	(239		)		(263		)	(1,322		)
	Sub-total		$	(659	)		$	(299	)	$	(356	)
	NYMEX gasoline and heating oil contracts	Gas Utility Other Operation Expenses	(127		)		175			12
	Total		$	(786	)		$	(124	)	$	(344	)
	Derivatives Not Designated as Hedging Instruments*
	Gain (loss) recognized in income on derivatives:
	Natural gas commodity contracts	Gas Marketing Operating Revenues	$	(78	)		$	3,782		$	(660	)
		Gas Marketing Operating Expenses	—				687			4,229
	NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	(778		)		(615		)	(115		)
		Gas Marketing Operating Expenses	—				(625		)	(3		)
	NYMEX gasoline and heating oil contracts	Other Income and (Income Deductions) - Net	41				19			37
	Total		$	(815	)		$	3,248		$	3,488
	*	Gains and losses on the Utility’s natural gas derivative instruments, which are not designated as hedging instruments for financial reporting purposes, are deferred pursuant to the Utility’s PGA Clause and initially recorded as regulatory assets or regulatory liabilities. These gains and losses are excluded from the table above because they have no direct impact on the Statements of Consolidated Income. Such amounts are recognized in the Statements of Consolidated Income as a component of Regulated Gas Distribution Natural and Propane Gas operating expenses when they are recovered through the PGA Clause and reflected in customer billings.
	Fair Value of Derivative Instruments in the Consolidated Balance Sheet at September 30, 2013
		Asset Derivatives*					Liability Derivatives*
	(Thousands)	Balance Sheet Location	Fair Value				Balance Sheet Location	Fair  Value
	Derivatives designated as hedging instruments
	NYMEX/ICE natural gas contracts	Derivative Instrument Assets	$	2,222			Derivative Instrument Assets	$	440
		Other Deferred Charges	22				Other Deferred Charges	11
	NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	105				Accounts Receivable - Other	—
	Sub-total		2,349					451
	Derivatives not designated as hedging instruments
	NYMEX/ICE natural gas contracts	Derivative Instrument Assets	950				Derivative Instrument Assets	100
	Accounts Receivable - Other	1,434				Accounts Receivable - Other	3,455
	Other Deferred Charges	32				Other Deferred Charges	—
OTCBB natural gas contracts	Other Current Liabilities	228				Other Current Liabilities	4,045
	Other Deferred Credits	4				Other Deferred Credits	1,398
Natural gas commodity contracts	Derivative Instrument Assets	991				Derivative Instrument Assets	90
	Other Deferred Charges	20				Other Deferred Charges	137
	Other Current Liabilities	247				Other Current Liabilities	830
	Other Deferred Credits	21				Other Deferred Credits	123
Sub-total		3,927					10,178
Total derivatives		$	6,276				$	10,629
Fair Value of Derivative Instruments in the Consolidated Balance Sheet at September 30, 2012
	Asset Derivatives					Liability Derivatives
(Thousands)	Balance Sheet Location	Fair Value			*	Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments
NYMEX/ICE natural gas contracts	Accounts Receivable - Other	$	405			Accounts Receivable - Other	$	3,413
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	334				Accounts Receivable - Other	—
Sub-total		739					3,413
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Accounts Receivable - Other	8,000				Accounts Receivable - Other	10,731
	Other Deferred Charges	—				Other Deferred Charges	—
Natural gas commodity contracts	Derivative Instrument Assets	3,150				Derivative Instrument Assets	295
	Other Current Liabilities	4				Other Current Liabilities	137
	Other Deferred Charges	19				Other Deferred Charges	—
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	10				Accounts Receivable - Other	—
Sub-total		11,183					11,163
Total derivatives		$	11,922				$	14,576
*	The fair values of Asset Derivatives and Liability Derivatives exclude the fair value of cash margin receivables or payables with counterparties subject to netting arrangements. Fair value amounts of derivative contracts (including the fair value amounts of cash margin receivables and payables) for which there is a legal right to set off are presented net on the Consolidated Balance Sheets. As such, the gross balances presented in the table above are not indicative of the Company’s net economic exposure. Refer to Note 10, Fair Value Measurements, for information on the valuation of derivative instruments.
Following is a reconciliation of the amounts in the tables above to the amounts presented in the Consolidated Balance Sheets:
(Thousands)	2013				2012
Fair value of asset derivatives presented above	6,276				11,922
Fair value of cash margin receivables offset with derivatives	1,765				5,478
Netting of assets and liabilities with the same counterparty	(4,739		)		(14,526		)
Total	3,302				2,874
Derivative Instrument Assets, per Consolidated Balance Sheets:
Derivative instrument assets	3,291				2,855
Other deferred charges	11				19
Total	3,302				2,874
Fair value of liability derivatives presented above	10,629				14,576
Fair value of cash margin payables offset with derivatives	6				83
Netting of assets and liabilities with the same counterparty	(4,739		)		(14,526		)
Derivative instrument liabilities, per Consolidated Balance Sheets	5,896				133
Derivative Instrument Liabilities, per Consolidated Balance Sheets:
Other current liabilities	$	4,400			$	133
Other deferred credits	1,496				—
Total	$	5,896			$	133
Additionally, at September 30, 2013 and 2012, the Company had $3.2 million and $10.0 million, respectively, in cash margin receivables not offset with derivatives, that are presented in Accounts Receivable – Other.

CONCENTRATIONS_OF_CREDIT_RISK

CONCENTRATIONS OF CREDIT RISK	12 Months Ended
	Sep. 30, 2013
Risks and Uncertainties [Abstract]	'
CONCENTRATIONS OF CREDIT RISK	'
	CONCENTRATION OF CREDIT RISK
	A significant portion of LER’s transactions are with (or are associated with) energy producers, utility companies, and pipelines. These concentrations of transactions with these counterparties have the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that each of these three groups may be affected similarly by changes in economic, industry, or other conditions. To manage this risk, as well as credit risk from significant counterparties in these and other industries, LER has established procedures to determine the creditworthiness of its counterparties. These procedures include obtaining credit ratings and credit reports, analyzing counterparty financial statements to assess financial condition, and considering the industry environment in which the counterparty operates. This information is monitored on an ongoing basis. In some instances, LER may require credit assurances such as prepayments, letters of credit, or parental guarantees. In addition, LER may enter into netting arrangements to mitigate credit risk with counterparties in the energy industry from which LER both sells and purchases natural gas. Sales are typically made on an unsecured credit basis with payment due the month following delivery. Accounts receivable amounts are closely monitored and provisions for uncollectible amounts are accrued when losses are probable. To date, losses have not been significant. LER records accounts receivable, accounts payable, and prepayments for physical sales and purchases of natural gas on a gross basis. The amount included in accounts receivable attributable to energy producers and their marketing affiliates amounted to $22.8 million at September 30, 2013. However, due to netting arrangements, there were no net receivable amounts from these customers on that same date. Accounts receivable attributable to utility companies and their marketing affiliates comprised $23.5 million of total accounts receivable at September 30, 2013, while net receivable amounts from these customers, reflecting netting arrangements, were $16.6 million. LER also has concentrations of credit risk with certain individually significant counterparties. At September 30, 2013, the amounts included in accounts receivable from LER’s five largest counterparties (in terms of net accounts receivable exposure), were $16.6 million. These five counterparties are either investment-grade rated or owned by investment-grade rated companies. Net receivable amounts from these customers on the same date, reflecting netting arrangements, were $14.5 million. Additionally, LER has concentrations of credit risk with pipeline companies associated with its natural gas receivable amounts.

INCOME_TAXES

INCOME TAXES	12 Months Ended
	Sep. 30, 2013
Income Tax Disclosure [Abstract]	'
INCOME TAXES	'
	INCOME TAXES
	The net provisions for income taxes charged during the fiscal years ended September 30, 2013, 2012, and 2011 are as follows:
	(Thousands)	2013				2012				2011
	Included in Statements of Consolidated Income:
	Federal
	Current	$	(4,173	)		$	(3,835	)		$	4,724
	Deferred	19,925				26,365				20,602
	Investment tax credits	(213		)		(213		)		(213		)
	State and local
	Current	(301		)		(430		)		573
	Deferred	2,340				4,402				3,496
	Total Income Tax Expense	$	17,578			$	26,289			$	29,182
	The effective income tax rate varied from the federal statutory income tax rate for each year due to the following:
		2013			2012			2011
	Federal income tax statutory rate	35	%		35	%		35	%
	State and local income taxes, net of federal income tax benefits	3.5			2.9			2.8
	Certain expenses capitalized on books and deducted on tax return	(9.7	)		(6.9	)		(5.0	)
	Taxes related to prior years	(1.6	)		(0.8	)		(0.7	)
	Other items – net	(2.2	)		(0.6	)		(0.7	)
	Effective income tax rate	25	%		29.6	%		31.4	%
	The significant items comprising the net deferred tax liability recognized in the Consolidated Balance Sheets as of September 30 are as follows:
	(Thousands)	2013				2012
	Deferred tax assets:
	Reserves not currently deductible	$	13,933			$	16,400
	Pension and other postretirement benefits	71,367				73,480
	Unamortized investment tax credits	1,799				1,955
	Other*	12,522				18,224
	Total deferred tax assets	99,621				110,059
	Deferred tax liabilities:
	Relating to property	341,975				303,474
	Regulatory pension and other postretirement benefits	124,871				121,554
	Deferred gas costs	7,112				20,652
	Other	5,789				26,563
	Total deferred tax liabilities	479,747				472,243
	Net deferred tax liability	380,126				362,184
	Net deferred tax liability – current*	(1,012		)		(6,675		)
	Net deferred tax liability – non-current*	$	379,114			$	355,509
	* The Company periodically invests in tax credits. As of September 30, 2013, $7.1 million of state tax credits are included in Other and Net deferred tax liability. $4.7 million of state tax credits were classified as current. $2.4 million of state tax credits were classified as non-current.
	Pursuant to GAAP, the Company may recognize the tax benefit from a tax position only if it is at least more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The Company records potential interest and penalties related to its uncertain tax positions as interest expense and other income deductions, respectively. Unrecognized tax benefits, accrued interest payable, and accrued penalties payable are included in the Other line of the Deferred Credits and Other Liabilities section of the Consolidated Balance Sheets.
	The following table presents a reconciliation of the beginning and ending balances of unrecognized tax benefits at September 30 as reported in the Consolidated Balance Sheets:
	(Thousands)	2013				2012
	Unrecognized tax benefits, beginning of year	$	5,810			$	5,596
	Increases related to prior year tax positions	145				78
	Increases related to tax positions taken in current year	1,450				547
	Reductions due to lapse of applicable statute of limitations	(5,018		)		(411		)
	Unrecognized tax benefits, end of year	$	2,387			$	5,810
	The amount of unrecognized tax benefits which, if recognized, would affect the Company’s effective tax rate were $1.9 million and $1.4 million as of September 30, 2013 and 2012, respectively. It is reasonably possible that events will occur in the next 12 months that could increase or decrease the amount of the Company’s unrecognized tax benefits. The Company does not expect that any such change will be significant to the Consolidated Balance Sheets.
	Interest accrued associated with the Company’s uncertain tax positions as of September 30, 2013 and 2012 were $0.1 million and $0.6 million, respectively, and an immaterial amount of penalties were accrued as of September 30, 2013. Interest expense accrued during fiscal year 2013 was $0.1 million, $0.2 million for fiscal year 2012, and $0.2 million for fiscal year 2011. During fiscal year 2013, the Company reversed $0.6 million of accrued interest expense in the Consolidated Statements of Income.
	The Company is subject to U.S. federal income tax as well as income tax of state and local jurisdictions. The Company is no longer subject to examination for fiscal years prior to 2010.
	In September 2013, the Internal Revenue Service and U.S. Treasury Department released final regulations on the deduction and capitalization of expenditures related to tangible property. The regulations do not address the tax treatment for network assets such as natural gas pipelines. These regulations apply to tax years beginning on or after January 1, 2014. Laclede is evaluating the effects of the regulations, but does not believe that they will have a significant impact on its consolidated financial statements.

OTHER_INCOME_AND_INCOME_DEDUCT

OTHER INCOME AND (INCOME DEDUCTIONS) - NET	12 Months Ended
	Sep. 30, 2013
Other Nonoperating Income (Expense) [Abstract]	'
OTHER INCOME AND (INCOME DEDUCTIONS) - NET	'
	OTHER INCOME AND (INCOME DEDUCTIONS) – NET
	(Thousands)	2013			2012			2011
	Interest income	$	1,088		$	1,309		$	1,136
	Net investment gain	2,857			3,124			185
	Other income	377			811			118
	Other income deductions	(1,878		)	(1,972		)	(1,262		)
	Other Income and (Income Deductions) – Net	$	2,444		$	3,272		$	177

INFORMATION_BY_OPERATING_SEGME

INFORMATION BY OPERATING SEGMENT	12 Months Ended
	Sep. 30, 2013
Segment Reporting [Abstract]	'
INFORMATION BY OPERATING SEGMENT	'
	INFORMATION BY OPERATING SEGMENT
	All of Laclede Group’s subsidiaries are wholly owned. In the first quarter of fiscal year 2013, the Company retitled its segment names. The Gas Utility segment, previously titled Regulated Gas Distribution, consists of the regulated operations of the Utility and is the core business segment of Laclede Group. The Utility is a public utility engaged in the retail distribution and sale of natural gas serving an area in eastern Missouri, including the City of St. Louis, through Laclede Gas and an area in western Missouri, including Kansas City, through MGE. The Gas Marketing segment, previously titled Non-Regulated Gas Marketing, includes the results of LER, a subsidiary engaged in the non-regulated marketing of natural gas and related activities, and LER Storage Services, Inc., which became operational in January 2012 and utilizes natural gas storage contracts for providing natural gas sales. Other includes Laclede Pipeline Company’s transportation of liquid propane regulated by the Federal Energy Regulatory Commission (FERC) as well as non-regulated activities, including, among other activities, real estate development, the compression of natural gas, and financial investments in other enterprises. These operations are conducted through seven subsidiaries. Other also includes the Utility’s non-regulated business activities, which are comprised of its propane storage and related services. Beginning July 1, 2013, propane-related services were included within Gas Utility operations pursuant to Laclede Gas' most recent rate case. Accounting policies are described in Note 1, Summary of Significant Accounting Policies. Intersegment transactions include sales of natural gas from the Utility to LER, propane storage services provided by the Utility to Laclede Pipeline Company, sales of natural gas from LER to the Utility, and propane transportation services provided by Laclede Pipeline Company to the Utility.
	Management evaluates the performance of the operating segments based on the computation of net economic earnings. Net economic earnings exclude from reported net income the after-tax impacts of net unrealized gains and losses and other timing differences associated with energy-related transactions. Net economic earnings also excludes the after-tax impacts related to acquisition, divestiture, and restructuring activities.
		Gas Utility			Gas Marketing				Other				Eliminations			Consolidated
	(Thousands)
	Fiscal 2013
	Revenues from external customers	$	847,224		$	165,146			$	4,649			$	—		$	1,017,019
	Intersegment revenues	10,538			24,185				1,625				(36,348		)	—
	Total Operating Revenues	857,762			189,331				6,274				(36,348		)	1,017,019
	Operating Expenses
	Gas Utility
	Natural and Propane Gas	469,098			—				—				(35,656		)	433,442
	Other Operation and Maintenance	180,702			—				—				(360		)	180,342
	Depreciation and Amortization	48,283			—				—				—			48,283
	Taxes, Other than Income Taxes	60,079			—				—				—			60,079
	Total Gas Utility Operating Expenses	758,162			—				—				(36,016		)	722,146
	Gas Marketing	—			176,554			(a)	—				—			176,554
	Other	—			—				22,157			(b)	(332		)	21,825
	Total Operating Expenses	758,162			176,554				22,157				(36,348		)	920,525
	Operating Income	99,599			12,777				(15,882		)		—			96,494
	Interest income	947			103				343				(305		)	1,088
	Interest charges	26,137			135				2,635				(305		)	28,602
	Income tax expense	19,243			5,162				(6,827		)		—			17,578
	Net economic earnings	56,635			8,936				(559		)		—			65,012
	Total assets	2,981,016			163,944				115,560				(135,134		)	3,125,386
	Capital expenditures	128,496			44				2,248				—			130,788
	Fiscal 2012
	Revenues from external customers	$	763,447		$	358,145			$	3,883			$	—		$	1,125,475
	Intersegment revenues	1,204			15,330				1,042				(17,576		)	—
	Total Operating Revenues	764,651			373,475				4,925				(17,576		)	1,125,475
	Operating Expenses
	Gas Utility
	Natural and Propane Gas	414,846			—				—				(17,542		)	397,304
	Other Operation and Maintenance	167,351			—				—				—			167,351
	Depreciation and Amortization	40,739			—				—				—			40,739
	Taxes, Other than Income Taxes	53,672			—				—				—			$	53,672
	Total Gas Utility Operating Expenses	676,608			—				—				(17,542		)	659,066
	Gas Marketing	—			353,286			(a)	—				(3		)	353,283
	Other	—			—				2,555			(b)	(31		)	2,524
	Total Operating Expenses	676,608			353,286				2,555				(17,576		)	1,014,873
	Operating Income	88,043			20,189				2,370				—			110,602
	Interest income	1,230			175				371				(467		)	1,309
	Interest charges	25,156			81				175				(467		)	24,945
	Income tax expense	17,393			7,966				930				—			26,289
	Net economic earnings	48,089			12,273				2,250				—			62,612
	Total assets	1,758,952			190,709				102,241				(171,640		)	1,880,262
	Capital expenditures	106,734			140				1,969				—			108,843
	Fiscal 2011
	Revenues from external customers	$	911,614		$	645,042			$	19,704			$	—		1,576,360
	Intersegment revenues	1,576			24,333				1,038				—			26,947
	Total Operating Revenues	913,190			669,375				20,742				—			1,603,307
	Operating Expenses
	Gas Utility
	Natural and Propane Gas	549,947			—				—				—			549,947
	Other Operation and Maintenance	172,938			—				—				—			172,938
	Depreciation and Amortization	39,214			—				—				—			$	39,214
	Taxes, Other than Income Taxes	60,752			—				—				—			60,752
	Total Gas Utility Operating Expenses	822,851			—				—				—			$	822,851
	Gas Marketing	—			652,567			(a)	—				—			652,567
	Other	—			—				9,642			(b)	—			9,642
	Total Operating Expenses	822,851			652,567				9,642				—			1,485,060
	Operating Income	90,339			16,808				11,100				—			118,247
	Interest income	1,057			165				217				(303		)	1,136
Interest charges	25,544			14				162				(303		)	25,417
Income tax expense	18,694			6,570				3,918				—			29,182
Net economic earnings	46,952			8,962				6,496			(c)	—			62,410
Total assets	1,641,386			175,352				129,176				(162,832		)	1,783,082
Capital expenditures	67,304			215				119				—			67,638
(a)	Depreciation and amortization for Gas Marketing is included in Gas Marketing Expenses on the Statements of Consolidated Income ($0.3 million for fiscal year 2013, $0.3 million for fiscal year 2012, and $0.1 million for fiscal year 2011).
(b)	Depreciation, amortization, and accretion for Other is included in the Other Operating Expenses on the Statements of Consolidated Income ($0.6 million for fiscal year 2013, $0.3 million for fiscal year 2012 and $0.2 million for fiscal year 2011).
(c)	Net economic earnings include income realized by the Utility from separate non-regulated sales of propane inventory no longer needed to serve utility customers, of which occurred in fiscal year 2011. This transaction resulted in after-tax earnings totaling $6.1 million.
Reconciliation of Consolidated Net Income to Consolidated Net Economic Earnings
(Thousands)	2013			2012				2011
Net Income (GAAP)	$	52,758		$	62,640			$	63,825
Unrealized loss (gain) on energy-related	614			(314		)		(1,415		)
derivatives
Lower of cost or market inventory adjustments	868			—				—
Realized (gain) loss on economic hedges prior	(25		)	163				—
to the sale of the physical commodity
Acquisition, divestiture and restructuring activities	10,797			123				—
Net Economic Earnings (Non-GAAP)	$	65,012		$	62,612			$	62,410

COMMITMENTS_AND_CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Sep. 30, 2013
Commitments and Contingencies Disclosure [Abstract]	'
COMMITMENTS AND CONTINGENCIES	'
	COMMITMENTS AND CONTINGENCIES
	Commitments
	The Utility estimates total Utility capital expenditures for fiscal 2014 at approximately $175 million. In fiscal 2011, the Utility initiated a multi-year project to replace its existing customer relationship and work management, financial, and supply chain software applications to enhance its technology, customer service, and business processes. At September 30, 2013, the Company was contractually committed to costs of approximately $1.5 million related to this project.
	Fiscal year 2014 capital expenditures for non-regulated subsidiaries will depend on the nature and magnitude of investments with the current estimate at $10 million. There are no material contractual commitments at September 30, 2013 related to these estimated capital expenditures.
	The Utility and LER have entered into various contracts, expiring on dates through 2019, for the storage, transportation, and supply of natural gas. Minimum payments required under the contracts in place at September 30, 2013 are estimated at approximately $981 million. The Utility recovers its costs from customers in accordance with the PGA Clause.
	Leases and Guarantees
	The lease agreement covering the main office space of the Utility extends through February 2015 with the option to renew for five additional years. The aggregate rental expense for fiscal years 2013, 2012, and 2011 was approximately $1.0 million, $0.9 million, and $0.9 million, respectively. The annual minimum rental payment for fiscal year 2014 is anticipated to be approximately $1.0 million through fiscal year 2015. The annual rental amount for the lease agreement covering MGE's main office space is approximately $0.6 million, and the lease term extends through November 30, 2015.
	The Utility has entered into various operating lease agreements for the rental of vehicles and power operated equipment. The rental costs will be approximately $2.7 million in fiscal year 2014, $1.8 million in fiscal year 2015, $1.0 million in fiscal year 2016, and $0.4 million in fiscal year 2017, and $0.1 million in fiscal year 2018. The Utility and LER have other relatively minor rental arrangements that provide for minimum rental payments.
	A consolidated subsidiary is a general partner in an unconsolidated partnership that invests in real estate partnerships. The subsidiary and third parties are jointly and severally liable for the payment of mortgage loans in the aggregate outstanding amount of approximately $1.6 million incurred in connection with various real estate ventures. Laclede Group has no reason to believe that the other principal liable parties will not be able to meet their proportionate share of these obligations. Laclede Group further believes that the asset values of the real estate properties are sufficient to support these mortgage loans.
	Contingencies
	The Utility owns and operates natural gas distribution, transmission, and storage facilities, the operations of which are subject to various environmental laws, regulations, and interpretations. While environmental issues resulting from such operations arise in the ordinary course of business, such issues have not materially affected the Company’s or the Utility's financial position and results of operations. As environmental laws, regulations, and their interpretations change, however, the Utility may be required to incur additional costs.
	Similar to other natural gas utility companies, Laclede Gas Company faces the risk of incurring environmental liabilities. In the natural gas industry, these are typically associated with sites formerly owned or operated by gas distribution companies like Laclede Gas and MGE or its predecessor companies at which manufactured gas operations took place. At this time, Laclede Gas has identified three former manufactured gas plant (MGP) sites where costs have been incurred and claims have been asserted: one in Shrewsbury, Missouri and two in the City of St. Louis, Missouri. Laclede Gas has enrolled the two sites in the City of St. Louis in the Missouri Department of Natural Resources Brownfields/Voluntary Cleanup Program (BVCP). MGE has enrolled all of its owned former manufactured gas plant sites in the BVCP.
	With regard to the former MGP site located in Shrewsbury, Missouri, Laclede Gas and state and federal environmental regulators agreed upon certain remedial actions to a portion of the site in a 1999 Administrative Order on Consent (AOC), which actions have been completed. On September 22, 2008, EPA Region VII issued a letter of Termination and Satisfaction terminating the AOC. However, if after this termination of the AOC, regulators require additional remedial actions, or additional claims are asserted, Laclede Gas may incur additional costs.
	One of the sites located in the City of St. Louis is currently owned by a development agency of the City, which, together with other City development agencies, has selected a developer to redevelop the site. In conjunction with this redevelopment effort, Laclede Gas and another former owner of the site entered into an agreement (Remediation Agreement) with the City development agencies, the developer, and an environmental consultant that obligates one of the City agencies and the environmental consultant to remediate the site and obtain a No Further Action letter from the Missouri Department of Natural Resources.
	The Remediation Agreement also provides for a release of Laclede Gas and the other former site owner from certain liabilities related to the past and current environmental condition of the site and requires the developer and the environmental consultant to maintain certain insurance coverages, including remediation cost containment, premises pollution liability, and professional liability.
	The operative provisions of the Remediation Agreement were triggered on December 20, 2010, on which date Laclede Gas and the other former site owner, as full consideration under the Remediation Agreement, paid a small percentage of the cost of remediation of the site. The amount paid by Laclede Gas did not materially impact the financial condition, results of operations, or cash flows of the Company.
	Laclede Gas has not owned the other site located in the City of St. Louis for many years. In a letter dated June 29, 2011, the Attorney General for the State of Missouri informed Laclede Gas that the Missouri Department of Natural Resources had completed an investigation of the site. The Attorney General requested that Laclede Gas participate in the follow up investigations of the site. In a letter dated January 10, 2012, Laclede Gas stated that it would participate in future environmental response activities at the site in conjunction with other potentially responsible parties that are willing to contribute to such efforts in a meaningful and equitable fashion.
	To date, amounts required for remediation at these sites have not been material. However, the amount of costs relative to future remedial actions at these and other sites is unknown and may be material. Laclede Gas has notified its insurers that it seeks reimbursement for costs incurred in the past and future potential liabilities associated with the MGP sites. While some of the insurers have denied coverage and reserved their rights, Laclede Gas continues to discuss potential reimbursements with them. In 2005, the Utility’s outside consultant completed an analysis of the MGP sites to determine cost estimates for a one-time contractual transfer of risk from each of the Utility’s insurers of environmental coverage for the MGP sites. That analysis demonstrated a range of possible future expenditures to investigate, monitor, and remediate these MGP sites from $5.8 million to $36.3 million based upon then currently available facts, technology, and laws and regulations. The actual costs that Laclede Gas may incur could be materially higher or lower depending upon several factors, including whether remedial actions will be required, final selection and regulatory approval of any remedial actions, changing technologies and governmental regulations, the ultimate ability of other potentially responsible parties to pay, the successful completion of remediation efforts required by the Remediation Agreement described above, and any insurance recoveries.
	MGE has seven owned MGP sites enrolled in the BVCP, including Joplin MGP #1, St. Joseph MGP #1, Kansas City Coal Gas Station B, Kansas City Station A Railroad, Kansas City Coal Gas Station A North, Kansas City Coal Gas Station A South, and Independence MGP #2. The Missouri Department of Natural Resources awarded a Certificate of Completion to Missouri Gas Energy in 2001 for a site located at 20th and Indiana in Kansas City after an initial site analysis and the property was subsequently sold. Source removal has been conducted at all of the owned sites since 2003 with the exception of Joplin, which is in the early stages of site analysis and characterization. Remediation efforts at these sites are at various stages of completion, ranging from groundwater monitoring and sampling following source removal activities to early site characterization in Joplin. As part of its participation in the BVCP, MGE communicates regularly with the Missouri Department of Natural Resources with respect to its remediation efforts and monitoring activities at these sites.
	Costs associated with environmental remediation activities are accrued when such costs are probable and reasonably estimable. The Utility anticipates that any costs it may incur in the future to remediate these sites, less any amounts received as insurance proceeds or as contributions from other potentially responsible parties, would be deferred and recovered in rates through periodic adjustments approved by the MoPSC. Accordingly, any potential liabilities that may arise associated with remediating these sites are not expected to have a material impact on the future financial position and results of operations of the Utility or the Company.
	The MoPSC Staff proposed disallowances related to Laclede Gas' recovery of its gas costs totaling $6.0 million pertaining to Laclede Gas' purchase of gas from a marketing affiliate, LER, applicable to fiscal years 2005 through 2007. The MoPSC staff also proposed a number of non-monetary recommendations, based on its review of gas costs for fiscal years 2008 through 2011. In a related matter, on October 6, 2010, the MoPSC Staff filed a complaint against Laclede Gas alleging that Laclede Gas' affiliate transactions and its Cost Allocation Manual (CAM) violated the MoPSC's affiliate transaction rules. Laclede Gas responded with a counterclaim that the MoPSC Staff had failed to adhere to the affiliate transaction rules and the Company's CAM. On July 16, 2013, Laclede Gas, the MoPSC Staff and the Office of the Public Counsel requested MoPSC approval of a unanimous stipulation and agreement resolving the affiliate transaction matters for fiscal years 2005 through 2011, resolving the October 6, 2010 complaint, resolving Laclede Gas' counterclaim, presenting a revised CAM for MoPSC approval, and establishing standards of conduct for gas purchases and sales. While the PSC Staff's disallowances were withdrawn as part of the stipulation, Laclede Gas agreed to a minor adjustment to the off-system sales and capacity release sharing mechanism.
	For a three-year period ending September 30, 2016, Laclede Gas' share of the first $2 million in net margin is reduced from 15% to 0%. None of the other sharing percentages are affected, and beginning October 1, 2016, Laclede's sharing percentage of the first $2 million in net margins returns to 15%. The Stipulation and agreement was approved by the MoPSC in an order issued on August 14, 2013.
	On July 7, 2010, the MoPSC Staff filed a complaint against Laclede Gas alleging that, by stating that it was not in possession of proprietary LER documents, Laclede Gas violated the MoPSC Order authorizing the holding company structure (2001 Order). Laclede Gas counterclaimed stating the Staff failed to adhere to pricing provisions of the MoPSC's affiliate transaction rules and Laclede Gas' Cost Allocation Manual. By orders dated November 3, 2010 and February 4, 2011, respectively, the MoPSC dismissed Laclede's counterclaim and granted summary judgment to Staff, finding that Laclede Gas violated the terms of the 2001 Order and authorizing its General Counsel to seek penalties in court against Laclede Gas. On May 19, 2011, the MoPSC's General Counsel filed a petition seeking penalties against Laclede Gas for violation of the 2001 Order. The MoPSC and Laclede Gas agreed to hold the penalty case in abeyance pending the outcome of Laclede's appeal of the November 3, 2010 and February 4, 2011 orders. These Orders were reversed by the Cole County Circuit Court, but later upheld by the Western District Court of Appeals. On March 19, 2013, the Missouri Supreme Court declined Laclede Gas' request to review the opinion of the Western District Court of Appeals. As a result, Laclede Gas produced certain LER documentation that had been requested by the MoPSC Staff and, pursuant to agreement between the MoPSC and Laclede Gas, the MoPSC’s May 2011 penalty case was dismissed.
	On June 29, 2010, the Office of Federal Contract Compliance Programs (OFCCP) issued a Notice of Violations to Laclede Gas alleging lapses in certain employment selection procedures during a two-year period ending in February 2006. On July 2, 2013, Laclede Gas executed a Conciliation Agreement with the OFCCP in which the Company did not admit to liability, but agreed to provide make whole relief of back pay and interest to the impacted individuals from 2004-2006. The Company's agreement to provide make whole relief will not have a material effect on the consolidated financial position and results of operations, or cash flows of the Company.
	As discussed in Note 11, Derivative Instruments and Hedging Activities, Laclede Gas and LER enter into NYMEX and ICE exchange-traded/cleared derivative instruments. Previously, these instruments were held in accounts at MF Global, Inc. On October 31, 2011, affiliated entities of MF Global filed a Chapter 11 petition at the U.S. Bankruptcy Court in the Southern District of New York. Subsequently, the court-appointed bankruptcy trustee transferred all of the open positions and a significant portion of the margin deposits of Laclede Gas and LER to a new brokerage firm. On June 27, 2013, the bankruptcy Trustee issued a statement projecting that MF Global customers would receive a full payout of their claims. As of November 26, 2013, Laclede Gas and LER had $0.2 million and $0.1 million, respectively, on deposit with MF Global that remain unavailable pending final resolution by the bankruptcy trustee. As the Company has recovered 98% of the amount at issue in the MF Global bankruptcy, the total remaining exposure is not considered material.
	On February 19, 2013, Heartland Midwest, LLC, a contractor for Time Warner Cable, hit a MGE natural gas line causing a gas leak while directionally boring during underground cable installation. The natural gas leak resulted in an explosion and fire which killed one person, injured approximately seventeen (including three MGE employees who were at the scene), caused major damage to JJ's restaurant, and caused property damage to adjacent buildings. Several lawsuits have been filed in state court in Jackson County, Missouri, alleging wrongful death, personal injury, property damage, and business interruption. The lawsuits are in the early stages of discovery. While the Company's total exposure is not considered material at this time, management plans to vigorously defend the matter and will continue to evaluate its exposure as discovery proceeds. Management believes, after discussion with counsel, that the final outcome of this matter will not have a material effect on the consolidated financial position, results of operations, or cash flows of the Company.
	Laclede Group is involved in other litigation, claims, and investigations arising in the normal course of business. Management, after discussion with counsel, believes that the final outcome will not have a material effect on the consolidated financial position, results of operations, or cash flows of the Company.

INTERIM_FINANCIAL_INFORMATION_

INTERIM FINANCIAL INFORMATION (UNAUDITED) (Unaudited)	12 Months Ended
	Sep. 30, 2013
Quarterly Financial Information Disclosure [Abstract]	'
INTERIM FINANCIAL INFORMATION (UNAUDITED)	'
	INTERIM FINANCIAL INFORMATION (UNAUDITED)
	In the opinion of Laclede Group, the quarterly information presented below for fiscal years 2013 and 2012 includes all adjustments (consisting of only normal recurring accruals) necessary for a fair statement of the results of operations for such periods. Variations in consolidated operations reported on a quarterly basis primarily reflect the seasonal nature of the business of the Utility.
	(Thousands, Except Per Share Amounts)
	Three Months Ended	Dec. 31		31-Mar		30-Jun		Sept. 30
	Fiscal Year 2013
	Total Operating Revenues	$	307,003	$	397,613	$	165,289	$	147,114
	Operating Income (Loss)	42,085		51,849		12,282		(9,722		)
	Net Income (Loss)	25,568		30,242		6,584		(9,636		)
	Basic Earnings (Loss) Per Share of Common Stock	1.14		1.34		0.25		(0.30		)
	Diluted Earnings (Loss) Per Share of Common Stock	1.14		1.34		0.25		(0.30		)
	Three Months Ended	Dec. 31		31-Mar		30-Jun		Sept. 30
	Fiscal Year 2012
	Total Operating Revenues	$	410,913	$	358,175	$	186,849	$	169,538
	Operating Income	43,105		50,583		15,045		1,869
	Net Income (Loss)	25,174		29,684		8,433		(651		)
	Basic Earnings (Loss) Per Share of Common Stock	1.13		1.33		0.38		(0.03		)
	Diluted Earnings (Loss) Per Share of Common Stock	1.12		1.32		0.38		(0.03		)
	All quarters of 2013 reflect transaction costs incurred associated with the acquisition of MGE. The fourth quarter of 2013 includes one month of activity of the operations of MGE, significant transaction costs incurred in the quarter and the interest impact of the debt issued in the quarter. Total impact of all of these during the quarter was a decrease in net income of $5.5 million.

SCHEDULE_II

SCHEDULE II	12 Months Ended
	Sep. 30, 2013
Valuation and Qualifying Accounts [Abstract]	'
SCHEDULE II	'
	SCHEDULE II
	THE LACLEDE GROUP, INC. AND SUBSIDIARY COMPANIES
	RESERVES
	FOR THE YEARS ENDED SEPTEMBER 30, 2013, 2012, AND 2011
	COLUMN A	COLUMN B		COLUMN C						COLUMN D			COLUMN E
		BALANCE AT		ADDITIONS			CHARGED			DEDUCTIONS			BALANCE
		BEGINNING		TO			TO OTHER			FROM			AT CLOSE
	DESCRIPTION	OF PERIOD		INCOME			ACCOUNTS			RESERVES			OF PERIOD
	(Thousands of Dollars)
	YEAR ENDED SEPTEMBER 30, 2013:
	DOUBTFUL ACCOUNTS	$	7,705	$	5,584		$	8,234	(b)	$	13,477	(c)	$	8,046
	MISCELLANEOUS:
	Injuries and property damage	$	4,540	$	1,934		$	—		$	2,135	(d)	$	4,339
	Deferred compensation	14,205		1,781			—			1,306			14,680
	Group medical claims incurred but not reported	1,560		17,205			—			16,116		(d)	2,649
	TOTAL	$	20,305	$	20,920	(a)	$	—	(a)	$	19,557	(a)	$	21,668
	YEAR ENDED SEPTEMBER 30, 2012:
	DOUBTFUL ACCOUNTS	$	10,073	$	6,011		$	10,145	(b)	$	18,524	(c)	$	7,705
	MISCELLANEOUS:
	Injuries and property damage	$	3,603	$	3,150		$	—		$	2,213	(d)	$	4,540
	Deferred compensation	13,474		1,756			—			1,025			14,205
	Group medical claims incurred but not reported	1,300		15,381			—			15,121		(d)	1,560
	TOTAL	$	18,377	$	20,287		$	—		$	18,359		$	20,305
	YEAR ENDED SEPTEMBER 30, 2011:
	DOUBTFUL ACCOUNTS	$	10,295	$	7,242		$	11,340	(b)	$	18,804	(c)	$	10,073
	MISCELLANEOUS:
	Injuries and property damage	$	3,228	$	2,416		$	—		$	2,041	(d)	$	3,603
	Deferred compensation	12,571		1,893			—			990			13,474
	Group medical claims incurred but not reported	1,450		14,171			—			14,321		(d)	1,300
	TOTAL	$	17,249	$	18,480		$	—		$	17,352		$	18,377
	(a)	Totals for the year ended September 30, 2013 includes one month of MGE activity.
	(b)	Accounts reinstated, cash recoveries, etc.
	(c)	Accounts written off.
	(d)	Claims settled, less reimbursements from insurance companies.

SUMMARY_OF_SIGNIFICANT_ACCOUNT1

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Sep. 30, 2013
Accounting Policies [Abstract]	'
BASIS OF CONSOLIDATION	'
	BASIS OF CONSOLIDATION - The consolidated financial statements include the accounts of Laclede Group and its subsidiary companies, including the recent acquisition of Missouri Gas Energy (MGE). All subsidiaries are wholly owned. Laclede Gas and other subsidiaries of Laclede Group may engage in related party transactions during the ordinary course of business. All material intercompany balances have been eliminated from the consolidated financial statements of Laclede Group. Transactions include sales of natural gas and transportation services between subsidiaries. These revenues are shown on the Intersegment revenues lines in the table included in Note 15, Information by Operating Segment.
USE OF ESTIMATES	'
	USE OF ESTIMATES - The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.
SYSTEM OF ACCOUNTS	'
	SYSTEM OF ACCOUNTS - The accounts of Laclede Gas are maintained in accordance with the Uniform System of Accounts prescribed by the Missouri Public Service Commission (MoPSC or Commission), which system substantially conforms to that prescribed by the Federal Energy Regulatory Commission (FERC).
UTILITY PLANT, DEPRECIATION AND AMORTIZATION	'
	UTILITY PLANT, DEPRECIATION AND AMORTIZATION - Utility plant is stated at original cost. The cost of additions to utility plant includes contracted work, direct labor and materials, allocable overheads, and an allowance for funds used during construction. The costs of units of property retired, replaced, or renewed are removed from utility plant and are charged to accumulated depreciation. Maintenance and repairs of property and replacement and renewal of items determined to be less than units of property are charged to maintenance expenses.
	Utility plant is depreciated on a straight-line basis at rates based on estimated service lives of the various classes of property. In fiscal year 2013, annual depreciation and amortization expense averaged 3.2% of the original cost of depreciable and amortizable property, compared to 3.1% in both fiscal years 2012 and 2011.
	The Utility’s capital expenditures were $128.5 million, $106.7 million, and $67.3 million for fiscal years 2013, 2012, and 2011, respectively. Additionally, the Utility had recorded accruals for capital expenditures totaling $4.7 million at September 30, 2013, $9.7 million at September 30, 2012, and $8.2 million at September 30, 2011. Accrued capital expenditures are excluded from the Statements of Consolidated Cash Flows.
ASSET RETIREMENT OBLIGATIONS	'
	ASSET RETIREMENT OBLIGATIONS - Laclede Group records legal obligations associated with the retirement of long-lived assets in the period in which the obligations are incurred, if sufficient information exists to reasonably estimate the fair value of the obligations. Obligations are recorded as both a cost of the related long-lived asset and as a corresponding liability. Subsequently, the asset retirement costs are depreciated over the life of the asset and the asset retirement obligations are accreted to the expected settlement amounts. The Company has recorded asset retirement obligations associated with certain safety requirements to purge and seal gas distribution mains upon retirement, the plugging and abandonment of storage wells and other storage facilities, specific service line obligations, and certain removal and disposal obligations related to components of the Utility’s distribution system and general plant. Asset retirement obligations recorded by Laclede Group’s other subsidiaries are not material. As authorized by the MoPSC, the Utility accrues future asset removal costs associated with its property, plant and equipment even if a legal obligation does not exist. Such accruals are provided for through depreciation expense and are recorded with corresponding credits to regulatory liabilities. When the Utility retires depreciable utility plant and equipment, it charges the associated original costs to accumulated depreciation and amortization, and any related removal costs incurred are charged to regulatory liabilities. The difference between removal costs recognized in depreciation rates and the accretion expense and depreciation expense recognized for financial reporting purposes is a timing difference between recovery of these costs in rates and their recognition for financial reporting purposes.
	Accordingly, these differences are deferred as regulatory liabilities. In the rate setting process, the regulatory liability is deducted from the rate base upon which the Utility has the opportunity to earn its allowed rate of return.
	As part of the MGE acquisition, the Utility has estimated the asset retirement obligation of MGE’s long-lived assets as of the acquisition date. This allocation of asset retirement obligations is preliminary and will be finalized upon completion of a detailed fair value analysis that is being performed by the Company in the first quarter of fiscal 2014.
REGULATED OPERATIONS	'
	REGULATED OPERATIONS - The Utility accounts for its regulated operations in accordance with ASC Topic 980. This Topic sets forth the application of generally accepted accounting principles in the United States of America (GAAP) for those companies whose rates are established by or are subject to approval by an independent third-party regulator. The provisions of this accounting guidance require, among other things, that financial statements of a regulated enterprise reflect the actions of regulators, where appropriate. These actions may result in the recognition of revenues and expenses in time periods that are different than non-regulated enterprises. When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses when those amounts are reflected in rates. Also, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for recovery of costs that are expected to be incurred in the future (regulatory liabilities).
	The following regulatory assets and regulatory liabilities were reflected in the Consolidated Balance Sheets as of September 30:
	(Thousands)	2013		2012
	Regulatory Assets:
	Future income taxes due from customers	$	112,912	$	118,997
	Pension and postretirement benefit costs	381,395		304,446
	Unamortized purchased gas adjustments	17,533		40,674
	Purchased gas costs	18,249		18,386
	Compensated absences	8,004		7,836
	Other	25,387		6,382
	Total Regulatory Assets	$	563,480	$	496,721
	Regulatory Liabilities:
	Unamortized investment tax credits	$	2,900	$	3,113
	Accrued cost of removal	59,066		55,103
	Other	23,494		1,216
	Total Regulatory Liabilities	$	85,460	$	59,432
	The regulatory assets are expected to be recovered in rates charged to customers. A portion of the Company's regulatory assets are not earning a return; however, these regulatory assets are expected to be recovered from customers in future rates. Excluding deferred income taxes and purchased gas adjustment items, as of September 30, 2013 and 2012, approximately $17.2 million and $7.8 million, respectively, of regulatory assets were not earning a rate of return. The Company expects these items to be recovered over a period not to exceed 15 years consistent with precedent set by the MoPSC. The portion of the regulatory asset related to pensions and other postemployment benefits that relates to unfunded differences between the projected benefit obligation and plan assets also does not earn a rate of return.
	As authorized by the MoPSC, the Utility discontinued deferring certain costs for future recovery, as expenses associated with those specific areas were included in approved rates effective December 27, 1999. Previously deferred costs of $10.5 million are being recovered and amortized on a straight-line basis over a fifteen-year period, without return on investment. Amortization of these costs totaled $9.7 million from December 27, 1999 through September 30, 2013.
NATURAL GAS STORED UNDERGROUND AND PROPANE GAS	'
	NATURAL GAS STORED UNDERGROUND AND PROPANE GAS – For Laclede Gas, inventory of natural gas in storage is priced on a last-in, first-out (LIFO) basis and inventory of propane gas in storage is priced on a first-in, first-out (FIFO) basis. For MGE, inventory of natural gas in storage is priced on a weighted average cost basis. The replacement cost of Laclede Gas' natural gas stored underground for current use at September 30, 2013 and September 30, 2012 was less than the LIFO cost by $13.3 million and $24.3 million, respectively. The carrying value of the Utility inventory is not adjusted to the lower of cost or market prices because, pursuant to both Laclede Gas' and MGE's Purchased Gas Adjustment (PGA) Clauses, actual gas costs are recovered in customer rates. Natural gas and propane gas storage inventory in Laclede Group’s other operating segments is recorded at the lower of average cost or market.
BUSINESS COMBINATIONS	'
	BUSINESS COMBINATIONS - The Company's acquisition of MGE was accounted for by the Company using business combination accounting. Under this method, the purchase price paid by the acquirer is allocated to the assets acquired and liabilities assumed as of the acquisition date based on their fair value. For additional information on the Company's acquisition of MGE, refer to Note 2, MGE Acquisition.
GOODWILL	'
	GOODWILL - Goodwill is measured as the excess of the acquisition-date fair value of the consideration transferred over the amount of acquisition-date identifiable assets acquired net of assumed liabilities. Laclede Group recorded $247.1 million of goodwill as part of the MGE acquisition.
REVENUE RECOGNITION	'
	REVENUE RECOGNITION - The Utility reads meters and bills its customers on monthly cycles. The Utility records its Gas Utility revenues from gas sales and transportation services on an accrual basis that includes estimated amounts for gas delivered, but not yet billed. The accruals for unbilled revenues are reversed in the subsequent accounting period when meters are actually read and customers are billed. The amounts of accrued unbilled revenues at September 30, 2013 and 2012, for the Utility, were $25.2 million and $11.6 million, respectively.
	Laclede Group’s other subsidiaries, including LER, record revenues when earned, either when the product is delivered or when services are performed.
	In the course of its business, LER enters into commitments associated with the purchase or sale of natural gas. Certain of LER’s derivative natural gas contracts are designated as normal purchases or normal sales, and, as such, are excluded from the scope of ASC Topic 815, “Derivatives and Hedging.” Those contracts are accounted for as executory contracts and recorded on an accrual basis. Revenues and expenses from such contracts are recorded using a gross presentation. Contracts not designated as normal purchases or normal sales are recorded as derivatives with changes in fair value recognized in earnings in the periods prior to physical delivery. For additional information on derivative instruments, refer to Note 11, Derivative Instruments and Hedging Activities. Certain of LER’s wholesale purchase and sale transactions entered on or after January 1, 2012 are classified as trading activities for financial reporting purposes. Under GAAP, revenues and expenses associated with trading activities are presented on a net basis in Gas Marketing Operating Revenues in the Statements of Consolidated Income. This net presentation has no effect on operating income or net income.
PURCHASED GAS ADJUSTMENTS AND DEFERRED ACCOUNT	'
	PURCHASED GAS ADJUSTMENTS AND DEFERRED ACCOUNT – As authorized by the MoPSC, the PGA Clause allows Laclede Gas to flow through to customers, subject to prudence review by the MoPSC, the cost of purchased gas supplies. To better match customer billings with market natural gas prices, the Utility is allowed to file to modify, on a periodic basis, the level of gas costs in its PGA. Certain provisions of the PGA Clause are included below:
	•	The Utility has a risk management policy that allows for the purchase of natural gas derivative instruments with the goal of managing price risk associated with purchasing natural gas on behalf of its customers. The MoPSC clarified that costs, cost reductions, and carrying costs associated with the Utility’s use of natural gas derivative instruments are gas costs recoverable through the PGA mechanism.
	•	The tariffs allow the Utility flexibility to make up to three discretionary PGA changes during each year, in addition to its mandatory November PGA change, so long as such changes are separated by at least two months.
	•	The Utility is authorized to recover gas inventory carrying costs through its PGA rates to recover costs it incurs to finance its investment in gas supplies that are purchased during the storage injection season for sale during the heating season. The Utility is also authorized to apply carrying costs to all over- or under-recoveries of gas costs, including costs and cost reductions associated with the use of derivative instruments, including cash payments for margin deposits.
	•	The MoPSC approved a plan applicable to Laclede Gas' gas supply commodity costs under which it retains a portion of cost savings associated with the acquisition of natural gas below an established benchmark level. This gas supply cost management program allows Laclede Gas to retain 10% of cost savings, up to a maximum of $3.0 million annually. Laclede Gas did not record any income under the plan during the three fiscal years reported. Income recorded under the plan, if any, is included in Gas Utility Operating Revenues on the Statements of Consolidated Income.
	Pursuant to the provisions of the PGA Clause, the difference between actual costs incurred and costs recovered through the application of the PGA are reflected as a deferred charge or credit at the end of the fiscal year. These costs include costs and cost reductions associated with the use of derivative instruments and gas inventory carrying costs, amounts due to or from customers related to operation of the gas supply cost management program, refunds received from the Company’s suppliers in connection with gas supply, transportation, and storage services, and carrying costs on such over- or under-recoveries. At that time, the balance is classified as a current asset or current liability and recovered from, or credited to, customers over an annual period commencing in November. The balance in the current account is amortized as amounts are reflected in customer billings. The PGA Clause also provides for the treatment of income from off-system sales and capacity release revenues. Pre-tax income from off-system sales and capacity release revenues is shared with customers, with an estimated amount assumed in PGA rates. The difference between the actual amount allocated to customers for each fiscal year and the estimated amount assumed in PGA rates is recovered from, or credited to, customers over an annual period commencing in the subsequent November. The customer share of such income is determined in accordance with the tables below, which is shown for each legacy company (Laclede Gas and MGE) under which the PGA Clauses were approved by the MoPSC.
	Laclede Gas
	Pre-tax Income	Customer Share	Company Share
	First $2 million	100%	—%
	Next $2 million	80%	20%
	Next $2 million	75%	25%
	Amounts exceeding $6 million	70%	30%
	MGE
	Pre-tax Income	Customer Share	Company Share
	First $1.2 million	85%	15%
	Next $1.2 million	80%	20%
	Next $1.2 million	75%	25%
	Amounts exceeding $3.6 million	70%	30%
INCOME TAXES	'
	INCOME TAXES - Laclede Group and its subsidiaries have elected, for tax purposes only, various accelerated depreciation provisions of the Internal Revenue Code. In addition, certain other costs are expensed currently for tax purposes while being deferred for book purposes. GAAP permits the benefit from a tax position to be recognized only if, and to the extent that, it is more likely than not that the tax position will be sustained upon examination by the taxing authority, based on the technical merits of the position. Unrecognized tax benefits and related interest and penalties, if any, are recorded as liabilities or as a reduction to deferred tax assets. Laclede Group companies record deferred tax liabilities and assets measured by enacted tax rates for the net tax effect of all temporary differences between the tax basis and the related carrying amounts of assets and liabilities in the financial statements. Changes in enacted tax rates, if any, and certain property basis differences are reflected by entries to regulatory asset or regulatory liability accounts for regulated companies, and are reflected as income or loss for non-regulated companies.
	The Utility’s investment tax credits utilized prior to 1986 have been deferred and are being amortized in accordance with regulatory treatment over the useful life of the related property.
CASH AND CASH EQUIVALENTS	'
	CASH AND CASH EQUIVALENTS - All highly liquid debt instruments purchased with original maturities of three months or less are considered to be cash equivalents. Such instruments are carried at cost, which approximates market value.
	Outstanding checks on the Company’s controlled disbursement bank accounts in excess of funds on deposit create book overdrafts (which are funded at the time checks are presented for payment) and are classified as Other in the Current Liabilities section of the Consolidated Balance Sheets. Changes in book overdrafts between periods are reflected as Financing Activities in the Statements of Consolidated Cash Flows.
NATURAL GAS RECEIVABLE	'
	NATURAL GAS RECEIVABLE – LER enters into natural gas transactions with natural gas pipeline companies known as park and loan arrangements. Under the terms of the arrangements, LER purchases natural gas from a third party and delivers that natural gas to the pipeline company for the right to receive the same quantity of natural gas from the pipeline company at the same location in a future period. These arrangements are accounted for as non-monetary transactions under GAAP and are recorded at the carrying amount. As such, natural gas receivables are reflected on the Consolidated Balance Sheets at cost, which includes related pipeline fees associated with the transactions. In the period that the natural gas is returned to LER, concurrent with the sale of the natural gas to a third party, the related natural gas receivable is expensed in the Statements of Consolidated Income. In conjunction with these transactions, LER usually enters into New York Mercantile Exchange (NYMEX) and Ice Clear Europe (ICE) natural gas futures, options, and swap contracts or fixed price sales agreements to protect against market changes in future sales prices.
EARNINGS PER COMMON SHARE	'
	EARNINGS PER COMMON SHARE - GAAP requires dual presentation of basic and diluted earnings per share (EPS). EPS is computed using the two-class method, which is an earnings allocation method for computing EPS that treats a participating security as having rights to earnings that would otherwise have been available to common shareholders. Certain of the Company’s stock-based compensation awards pay nonforfeitable dividends to the participants during the vesting period and, as such, are deemed participating securities. Basic EPS is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding that are increased for additional shares that would be outstanding if potentially dilutive non-participating securities were converted to common shares, pursuant to the treasury stock method. Shares attributable to non-participating stock options and time-vested restricted stock/units are excluded from the calculation of diluted earnings per share if the effect would be antidilutive. Shares attributable to non-participating performance-contingent restricted stock awards are only included in the calculation of diluted earnings per share to the extent the underlying performance and/or market conditions are satisfied (a) prior to the end of the reporting period or (b) would be satisfied if the end of the reporting period were the end of the related contingency period and the result would be dilutive. The Company’s EPS computations are presented in Note 5, Earnings Per Common Share.
GROSS RECEIPTS AND SALES TAXES	'
	GROSS RECEIPTS AND SALES TAXES - Gross receipts taxes associated with the Utility's natural gas utility service are imposed on the Utility and billed to its customers. These amounts are recorded gross in the Statements of Consolidated Income. Amounts recorded in Gas Utility Operating Revenues were $40.8 million, $35.9 million, and $43.5 million for fiscal years 2013, 2012, and 2011, respectively. Gross receipts taxes are expensed by the Utility and included in the Taxes, other than income taxes line.
	Sales taxes imposed on applicable Company sales are billed to customers. These amounts are not recorded in the Statements of Consolidated Income, but are recorded as tax collections payable and included in the Other line of the Current Liabilities section of the Consolidated Balance Sheets.
ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS	'
	ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS – Trade accounts receivable are recorded at the amounts due from customers, including unbilled amounts. Estimates of the collectibility of trade accounts receivable are based on historical trends, age of receivables, economic conditions, credit risk of specific customers, and other factors. Accounts receivable are written off against the allowance for doubtful accounts when they are deemed to be uncollectible. The Utility’s provision for uncollectible accounts includes the amortization of previously deferred uncollectible expenses, as approved by the MoPSC.
GROUP MEDICAL AND WORKERS' COMPENSATION RESERVES	'
	GROUP MEDICAL AND WORKERS’ COMPENSATION RESERVES - The Company self-insures its group medical and workers’ compensation costs and carries stop-loss coverage in relation to medical claims and workers’ compensation claims. Reserves for amounts incurred but not reported are established based on historical cost levels and lags between occurrences and reporting.
FAIR VALUE MEASUREMENTS	'
	FAIR VALUE MEASUREMENTS – Certain assets and liabilities are recognized or disclosed at fair value, which is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). GAAP establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.
	The levels of the hierarchy are described below:
	•	Level 1 – Unadjusted quoted prices in active markets for identical assets or liabilities.
	•	Level 2 – Pricing inputs other than quoted prices included within Level 1, which are either directly or indirectly observable for the asset or liability as of the reporting date. These inputs are derived principally from, or corroborated by, observable market data.
	•	Level 3 – Pricing that is based upon inputs that are generally unobservable that are based on the best information available and reflect management’s assumptions about how market participants would price the asset or liability.
	Assessment of the significance of a particular input to the fair value measurements may require judgment and may affect the valuation of the asset or liability and its placement within the fair value hierarchy. Additional information about fair value measurements is provided in Note 3, Pension Plans and Other Postretirement Benefits, Note 9, Fair Value of Financial Instruments, and Note 10, Fair Value Measurements.
STOCK-BASED COMPENSATION	'
	STOCK-BASED COMPENSATION – The Company measures stock-based compensation awards at fair value at the date of grant and recognizes the compensation cost of the awards over the requisite service period. Forfeitures are estimated at the time of grant and revised, if necessary, in subsequent periods if the actual forfeitures differ from those estimates. Refer to Note 4, Stock-Based Compensation, for further discussion of the accounting for the Company’s stock-based compensation plans.
NEW ACCOUNTING STANDARDS	'
	NEW ACCOUNTING STANDARDS – In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities,” to amend ASC Topic 210, “Balance Sheet,” to require additional disclosures about financial instruments and derivative instruments that have been presented on a net basis (offset) in the balance sheet. Additionally, information about financial instruments and derivative instruments that are subject to enforceable master netting arrangements or similar agreements, irrespective of whether they are presented net in the balance sheet, is required to be disclosed. The ASU impacts disclosures only and will not require any changes to financial statement presentation. The Company will present the new disclosures retrospectively beginning in the first quarter of fiscal year 2014.
	In February 2013, the FASB issued ASU No. 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income.” This ASU amends Accounting Standards Codification (ASC) Topic 220, “Comprehensive Income,” by requiring entities to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to provide information on significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income, but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. The Company will present the new disclosures prospectively beginning in the first quarter of fiscal year 2014.

SUMMARY_OF_SIGNIFICANT_ACCOUNT2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Sep. 30, 2013
Accounting Policies [Abstract]	'
Asset Retirement Obligations	'
	The following table presents a reconciliation of the beginning and ending balances of asset retirement obligations at September 30 as reported in the Consolidated Balance Sheets:
	(Thousands)	2013			2012
	Asset retirement obligations, beginning of year	$	40,368		$	27,495
	Liabilities incurred during the period	801			851
	Liabilities settled during the period	(1,089		)	(601		)
	Accretion	2,322			1,637
	Revisions in estimated cash flows	—			10,986
	Addition of MGE asset retirement obligation	32,152			—
	Asset retirement obligations, end of year	$	74,554		$	40,368
Regulatory Assets and Liabilities	'
	The following regulatory assets and regulatory liabilities were reflected in the Consolidated Balance Sheets as of September 30:
	(Thousands)	2013			2012
	Regulatory Assets:
	Future income taxes due from customers	$	112,912		$	118,997
	Pension and postretirement benefit costs	381,395			304,446
	Unamortized purchased gas adjustments	17,533			40,674
	Purchased gas costs	18,249			18,386
	Compensated absences	8,004			7,836
	Other	25,387			6,382
	Total Regulatory Assets	$	563,480		$	496,721
	Regulatory Liabilities:
	Unamortized investment tax credits	$	2,900		$	3,113
	Accrued cost of removal	59,066			55,103
	Other	23,494			1,216
	Total Regulatory Liabilities	$	85,460		$	59,432
Off-System Sales	'
	Laclede Gas
	Pre-tax Income	Customer Share	Company Share
	First $2 million	100%	—%
	Next $2 million	80%	20%
	Next $2 million	75%	25%
	Amounts exceeding $6 million	70%	30%
	MGE
	Pre-tax Income	Customer Share	Company Share
	First $1.2 million	85%	15%
	Next $1.2 million	80%	20%
	Next $1.2 million	75%	25%
	Amounts exceeding $3.6 million	70%	30%

ACQUISITION_OF_MGE_Tables

ACQUISITION OF MGE (Tables)	12 Months Ended
	Sep. 30, 2013
Business Acquisition [Line Items]	'
Schedule of Pro Forma Information	'
	The amount of revenue and earnings of MGE included in our Statements of Consolidated Income subsequent to the September 1, 2013 acquisition date are as follows:
	(Thousands, Except Per Share Amounts)	September 1, 2013 - September 30, 2013
	Total net revenues	$	21,985
	Net Income	1,795
	Earnings/(loss) per share:
	Basic	$	0.07
	Diluted	$	0.07
	The following unaudited pro forma financial information presents the combined results of operations as if the acquisition had occurred on October 1, 2011. The pro forma financial information does not reflect the costs of any integration activities. The pro forma results include estimates and assumptions, which management believes are reasonable. The unaudited pro forma financial information below is not necessarily indicative of either future results of operations or results that might have been achieved had MGE been part of the Utility as of the beginning of fiscal year 2012.
		Twelve Months Ended September 30,
	(Thousands, Except Per Share Amounts)	2013		2012
	Total net revenues	$	1,518,201	$	1,581,425
	Net Income	83,642		81,722
	Earnings per share:
	Basic	$	2.57	$	2.52
	Diluted	$	2.56	$	2.51
Missouri Gas Energy (MGE) [Member]	'
Business Acquisition [Line Items]	'
Schedule of preliminary fair value of assets acquired and liabilities assumed	'
	The following table summarizes the preliminary fair value of assets acquired and liabilities assumed at the date of the acquisition:
	(Thousands)
	Assets:
	Utility plant	$	671,793
	Non-utility property	238
	Other investments	3,096
	Goodwill	247,078
	Other Property and Investments	922,205
	Accounts receivable:
	Utility	19,963
	Other	6,119
	Delayed customer billings	10,701
	Inventories:
	Natural gas stored underground	58,679
	Materials and supplies at average cost	3,988
	Prepayments and other	487
	Total Current Assets	99,937
	Deferred Charges:
	Regulatory assets	84,014
	Other	4,928
	Total Deferred Charges	88,942
	Total Assets Acquired	$	1,111,084
	Liabilities:
	Accounts payable	$	20,154
	Wages and compensation accrued	5,088
	Customer deposits	8,362
	Interest accrued	183
	Taxes accrued	17,197
	Other	12,620
	Total Current Liabilities	63,604
	Pension and postretirement benefit costs	24,466
	Asset retirement obligations	32,056
	Regulatory liabilities	2,249
	Other	13,709
	Total Deferred Credits and Other Liabilities	72,480
	Total Liabilities Assumed	$	136,084
	Net Assets Acquired	$	975,000

PENSION_PLANS_AND_OTHER_POSTRE1

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS (Tables)	12 Months Ended
	Sep. 30, 2013
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]	'
Net Periodic Cost	'
	Net periodic postretirement benefit costs consisted of the following components:
	(Thousands)	2013				2012				2011
	Service cost – benefits earned during the period	$	10,162			$	8,060			$	7,676
	Interest cost on accumulated postretirement benefit obligation	5,234				5,521				4,843
	Expected return on plan assets	(4,447		)		(3,965		)		(3,646		)
	Amortization of transition obligation	93				136				136
	Amortization of prior service credit	3				(2,072		)		(2,328		)
	Amortization of actuarial loss	5,300				4,261				4,443
	Sub-total	16,345				11,941				11,124
	Regulatory adjustment	(6,821		)		(2,417		)		(2,071		)
	Net postretirement benefit cost	$	9,524			$	9,524			$	9,053
	The net periodic pension costs include the following components:
	(Thousands)	2013				2012				2011
	Service cost – benefits earned during the period	$	9,209			$	9,203			$	9,553
	Interest cost on projected benefit obligation	16,959				19,358				18,819
	Expected return on plan assets	(19,358		)		(19,595		)		(18,849		)
	Amortization of prior service cost	544				592				642
	Amortization of actuarial loss	10,724				9,040				10,228
	Loss on lump-sum settlements	26,996				20,051				943
	Sub-total	45,074				38,649				21,336
	Regulatory adjustment	(27,532		)		(18,579		)		(7,066		)
	Net pension cost	$	17,542			$	20,070			$	14,270
Other changes in plan assets and benefit obligations recognized in other comprehensive income	'
	Other changes in plan assets and postretirement benefit obligations recognized in other comprehensive income include the following:
	(Thousands)	2013				2012				2011
	Current year actuarial loss	$	16,300			$	10,138			$	1,696
	Amortization of actuarial loss	(5,300		)		(4,261		)		(4,443		)
	Amortization of prior service credit	(3		)		2,072				2,328
	Amortization of transition obligation	(93		)		(136		)		(136		)
	Sub-total	10,904				7,813				(555		)
	Regulatory adjustment	(10,904		)		(7,813		)		555
	Total recognized in other comprehensive income	$	—			$	—			$	—
	Other changes in plan assets and pension benefit obligations recognized in other comprehensive income include the following:
	(Thousands)	2013				2012				2011
	Current year actuarial loss (gain)	$	17,030			$	32,884			$	(13,485	)
	Amortization of actuarial loss	(10,724		)		(29,091		)		(11,171		)
	Acceleration of loss recognized due to settlement	(26,996		)		—				—
	Amortization of prior service cost	(544		)		(592		)		(642		)
	Sub-total	(21,234		)		3,201				(25,298		)
	Regulatory adjustment	21,159				(3,510		)		24,533
	Total recognized in other comprehensive income	$	(75	)		$	(309	)		$	(765	)
Reconciliation of the beginning and Ending Balances of Benefit Obligation	'
	The following table sets forth the reconciliation of the beginning and ending balances of the postretirement benefit obligation at September 30:
	(Thousands)	2013				2012
	Benefit obligation, beginning of year	$	127,217			$	103,991
	Service cost	10,162				8,060
	Interest cost	5,234				5,521
	Actuarial loss (gain)	17,514				15,895
	MGE acquisition	28,444				—
	Gross benefits paid	(8,449		)		(6,250		)
	Benefit obligation, end of year	$	180,122			$	127,217
	The following table sets forth the reconciliation of the beginning and ending balances of the pension benefit obligation at September 30:
	(Thousands)	2013				2012
	Benefit obligation, beginning of year	$	412,171			$	384,163
	Service cost	9,209				9,203
	Interest cost	16,959				19,358
	Actuarial (gain) loss	(23,921		)		52,161
	MGE acquisition	151,424				—
	Settlement loss	24,999				14,348
	Gross benefits paid *	(87,023		)		(67,062		)
	Benefit obligation, end of year	$	503,818			$	412,171
	Accumulated benefit obligation, end of year	$	444,129			$	353,061
	*	Includes $79,484 and $60,085 lump-sum payments recognized as settlements in fiscal years 2013 and 2012, respectively.
Fair Value of Plan Assets	'
	The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets at September 30:
	(Thousands)	2013				2012
	Fair value of plan assets at beginning of year	$	67,442			$	51,744
	Actual return on plan assets	5,660				9,722
	Employer contributions	16,596				12,226
	MGE acquisition	30,396				—
	Gross benefits paid	(8,449		)		(6,250		)
	Fair value of plan assets, end of year	$	111,645			$	67,442
	Funded status of plans, end of year	$	(68,477	)		$	(59,775	)
	The following table sets forth the reconciliation of the beginning and ending balances of the fair value of plan assets at September 30:
	(Thousands)	2013				2012
	Fair value of plan assets, beginning of year	$	274,130			$	247,959
	Actual return on plan assets	3,387				53,220
	Employer contributions	27,991				40,013
	MGE acquisition	126,958				—
	Gross benefits paid *	(87,023		)		(67,062		)
	Fair value of plan assets, end of year	$	345,443			$	274,130
	Funded status of plans, end of year	$	(158,375	)		$	(138,041	)
	*	Includes $79,484 and $60,085 lump-sum payments recognized as settlements in fiscal years 2013 and 2012, respectively.
Amounts recognized in consolidated balance sheet	'
	The following table sets forth the amounts recognized in the Consolidated Balance Sheets at September 30:
	(Thousands)	2013				2012
	Current liabilities	$	(442	)		$	(468	)
	Noncurrent liabilities	(157,933		)		(137,573		)
	Total	$	(158,375	)		$	(138,041	)
	Pre-tax amounts recognized in accumulated other comprehensive income not yet recognized as components of net periodic pension cost consist of:
	Net actuarial loss	$	115,775			$	136,464
	Prior service costs	4,467				5,011
	Sub-total	120,242				141,475
	Adjustments for amounts included in Regulatory Assets	(116,686		)		(137,845		)
	Total	$	3,556			$	3,630
	The following table sets forth the amounts recognized in the Consolidated Balance Sheets at September 30:
	(Thousands)	2013				2012
	Noncurrent assets	$	2,543			$	—
	Current liabilities	(300		)		(790		)
	Noncurrent liabilities	(70,720		)		(58,985		)
	Total	$	(68,477	)		$	(59,775	)
	Pre-tax amounts recognized in accumulated other comprehensive income not yet recognized as components of net periodic postretirement benefit cost consist of:
	Net actuarial loss	$	63,573			$	52,573
	Prior service credit	(27		)		(24		)
	Transition obligation	—				93
	Sub-total	63,546				52,642
	Adjustments for amounts included in Regulatory Assets	(63,546		)		(52,642		)
	Total	$	—			$	—
Pre-tax amounts amortized from accumulated other comprehensive income into net periodic cost	'
	At September 30, 2013, the following pre-tax amounts are expected to be amortized from accumulated other comprehensive income into net periodic postretirement benefit cost during fiscal year 2014:
	(Thousands)
	Amortization of net actuarial loss	$	6,021
	Amortization of prior service cost	(4		)
	Sub-total	6,017
	Regulatory adjustment	(6,017		)
	Total	$	—
	At September 30, 2013, the following pre-tax amounts are expected to be amortized from accumulated other comprehensive income into net periodic pension cost during fiscal year 2014:
	(Thousands)	2014
	Amortization of net actuarial loss	$	7,088
	Amortization of prior service cost	497
	Sub-total	7,585
	Regulatory adjustment	(7,196		)
	Total	$	389
Assumptions used to calculate net periodic cost and benefit obligations.	'
	The assumptions used to calculate the accumulated postretirement benefit obligations are as follows:
		2013		2012
	Weighted average discount rate *	4.60%		3.80%
	Weighted average rate of future compensation increase	3.00%		3.00%
	The assumptions used to calculate the benefit obligations are as follows:
		2013		2012
	Weighted average discount rate *	4.70%		3.95%
	Weighted average rate of future compensation increase	3.00%		3.00%
	*	Weighted average discount rate assumption for the MGE pension plan is 5.00%.
	The assumptions used to calculate net periodic pension costs are as follows:
		2013		2012		2011
	Weighted average discount rate*	3.95%		5.10%		4.75%
	Weighted average rate of future compensation increase	3.00%		3.00%		3.00%
	Expected long-term rate of return on plan assets	7.75%		7.75%		8.00%
	*	Weighted average discount rate assumption for the MGE pension plan is 5.05%.
	The assumptions used to calculate net periodic postretirement benefit costs are as follows:
		2013			2012			2011
	Weighted average discount rate *	3.8	%		5.05	%		4.7	%
	Weighted average rate of future compensation increase	3	%		3	%		3	%
	Expected long-term rate of return on plan assets **	7.75	%		7.75	%		8	%
	*	Weighted average discount rate assumption for the MGE postretirement plan is 5.05%.
	**    Expected long-term rate of return on plan assets assumption for the MGE postretirement plan is 5.75%.
Projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for plans that have projected benefit obligation and accumulated benefit obligation in excess of plan assets	'
	Following are the projected benefit obligation, accumulated benefit obligation, and fair value of plan assets for plans that have a projected benefit obligation and an accumulated benefit obligation in excess of plan assets:
	(Thousands)	2013				2012
	Projected benefit obligation	$	503,818			$	412,171
	Accumulated benefit obligation	444,129				353,061
	Fair value of plan assets	345,443				274,130
Targeted and actual plan assets by category	'
	Following are the targeted and actual plan assets by category as of September 30 of each year:
		Target			2013			2012
					Actual			Actual
	Growth Strategy
	Equity Markets	42.5	%		45.9	%		37.3	%
	Commodities	2.5	%		1.6	%		2.2	%
	Real Estate	2.5	%		3	%		2.2	%
	Inflation-Indexed Securities	2.5	%		1.4	%		2.2	%
	Debt Securities	50	%		43.3	%		41.1	%
	Other*	—	%		4.8	%		15	%
	Total	100	%		100	%		100	%
	* Other investments in 2013 consist of cash equivalents. The relatively large cash position at September 30, 2012 was
	due to a transition taking place between investment managers and was invested in debt securities in a matter of days.
	Following are the targeted and actual plan assets by category as of September 30 of each year:
		Target			2013			2012
					Actual			Actual
	Equity Securities	60	%		59	%		59	%
	Debt Securities	40	%		39	%		39	%
	Other	—	%		2	%		2	%
	Total	100	%		100	%		100	%
Expected benefit payments for the succeeding five fiscal years	'
	Following are expected pension benefit payments for the succeeding five fiscal years, and in aggregate for the five years thereafter:
						Pensions from
	(Millions)	Pensions from				Laclede Gas
		Qualified Trust				Funds
	2014	$	22.9			$	0.4
	2015	25.3				0.5
	2016	27.2				0.5
	2017	30.8				0.6
	2018	34.2				0.6
	2019 – 2023	227.2				4.5
	Following are expected postretirement benefit payments for the succeeding five fiscal years, and in aggregate for the five years thereafter:
		Benefits Paid				Benefits Paid
	(Millions)	from				from Laclede Gas
		Qualified Trust				Funds
	2014	$	9.5			$	0.3
	2015	9.9				0.3
	2016	10.7				0.3
	2017	11.7				0.4
	2018	12.8				0.4
	2019 – 2023	84.1				2.2
Assumed medical cost trend rates and effect of an assumed 1% changed in assumed medical cost trend.	'
	The assumed medical cost trend rates at September 30 are as follows:
		2013		2012
	Medical cost trend assumed for next year	7.50%		7.00%
	Rate to which the medical cost trend rate is assumed to decline (the ultimate medical cost trend rate)	5.00%		5.00%
	Year the rate reaches the ultimate trend	2020		2017
	The following table presents the effect of an assumed 1% change in the assumed medical cost trend rate:
	(Thousands)	1% Increase				1% Decrease
	Effect on net periodic postretirement benefit cost	$	1,520			$	(1,390	)
	Effect on accumulated postretirement benefit obligation	7,060				(6,580		)
Fair value measurements of plan assets	'
	The table below categorizes the fair value measurements of the Utility's’ pension plan assets:
	(Thousands)	Quoted				Significant				Significant			Total
		Prices in				Observable				Unobservable
		Active				Inputs				Inputs
		Markets				(Level 2)				(Level 3)
		(Level 1)
	As of September 30, 2013
	Cash and cash equivalents	$	18,177			$	—			$	—		$	18,177
	Stock/Bond mutual fund	—				115,817				—			115,817
	Debt Securities
	U.S. bond mutual funds	17,682				—				—			17,682
	U.S. government	—				55,743				—			55,743
	U.S. corporate	—				110,925				—			110,925
	U.S. municipal	—				6,799				—			6,799
	International	—				21,594				—			21,594
	Derivative instruments (a)	—				(1,294		)		—			(1,294		)
	Total	$	35,859			$	309,584			$	—		$	345,443
	As of September 30, 2012
	Cash and cash equivalents	$	57,614			$	—			$	—		$	57,614
	Debt Securities
	U.S. bond mutual funds	36,767				—				—			36,767
	U.S. government	—				57,925				—			57,925
	U.S. corporate	—				93,169				—			93,169
	U.S. municipal	—				9,493				—			9,493
	International	—				18,885				—			18,885
	Derivative instruments (b)	—				277				—			277
	Total	$	94,381			$	179,749			$	—		$	274,130
	(a)	Derivative assets of $4,186 net of cash margin payable of $5,480.
	(b)	Derivative assets of $3,027 net of cash margin payable of $2,750.
	The table below categorizes the fair value measurements of The Utility's postretirement plan assets:
	(Thousands)	Quoted				Significant				Significant			Total
		Prices in				Observable				Unobservable
		Active				Inputs				Inputs
		Markets				(Level 2)				(Level 3)
		(Level 1)
	As of September 30, 2013
	Cash and cash equivalents	$	1,411			$	—			$	—		$	1,411
	U.S. stock/bond mutual fund	110,234				—				—			110,234
	Total	$	111,645			$	—			$	—		$	111,645
	As of September 30, 2012
	Cash and cash equivalents	$	1,106			$	—			$	—		$	1,106
	U.S. stock/bond mutual fund	66,336				—				—			66,336
	Total	$	67,442			$	—			$	—		$	67,442

STOCKBASED_COMPENSATION_Tables

STOCK-BASED COMPENSATION (Tables)	12 Months Ended
	Sep. 30, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Restricted stock and restricted stock unit activity	'
	Time-vested restricted stock and stock unit activity for fiscal year 2013 is presented below:
		Shares/			Weighted
		Units			Average
					Grant Date
					Fair Value
	Nonvested at September 30, 2012	115,115			$	36.54
	Granted	59,124			$	40
	Vested	(43,785	)		$	34.95
	Forfeited	(11,050	)		$	38.61
	Nonvested at September 30, 2013	119,404			$	38.64
	Fiscal year 2013 activity of restricted stock and restricted stock units subject to performance and/or market conditions is presented below:
		Shares/			Weighted
		Units			Average
					Grant Date
					Fair Value
	Nonvested at September 30, 2012	232,403			$	30.89
	Granted (maximum shares that can be earned)	108,419			$	34.49
	Vested	(47,436	)		$	27.61
	Forfeited	(51,118	)		$	26.11
	Nonvested at September 30, 2013	242,268			$	34.15
Stock option awards activity	'
	No stock options were granted during fiscal years 2013, 2012, and 2011. Stock option activity for fiscal year 2013 is presented below:
		Stock			Weighted				Weighted		Aggregate
		Options			Average				Average		Intrinsic
					Exercise				Remaining		Value
					Price				Contractual		$0
									Term
									(Years)
	Outstanding at September 30, 2012	214,000			$	31.02
	Granted	—			$	—
	Exercised	(80,500	)		$	29.61
	Forfeited	—			$	—
	Expired	—			$	—
	Outstanding at September 30, 2013	133,500			$	31.87			2.8		$	1,752
	Fully Vested and Expected to Vest at September 30, 2013	133,500			$	31.87			2.8		$	1,752
	Exercisable at September 30, 2013	133,500			$	31.87			2.8		$	1,752
Significant assumptions used in the Monte Carlo simulations	'
	The significant assumptions used in the Monte Carlo simulations are as follows:
		2013			2012			2011
	Risk free interest rate	0.32	%		0.39	%		0.79	%
	Expected dividend yield of stock	—			—			—
	Expected volatility of stock	19.6	%		23.21	%		33.42	%
	Vesting period	2.8 years			2.8 years			2.8 years
Compensation cost recognized for share-based compensation arrangements	'
	The amounts of compensation cost recognized for share-based compensation arrangements are presented below:
	(Thousands)	2013				2012				2011
	Total equity compensation cost	$	4,453			$	2,707			$	3,980
	Compensation cost capitalized	(1,366		)		(808		)		(924		)
	Compensation cost recognized in net income	3,087				1,899				3,056
	Income tax benefit recognized in net income	(1,182		)		(733		)		(1,179		)
	Compensation cost recognized in net income, net of income tax	1,905				1,166				1,877

EARNINGS_PER_COMMON_SHARE_Tabl

EARNINGS PER COMMON SHARE (Tables)	12 Months Ended
	Sep. 30, 2013
Earnings Per Share [Abstract]	'
Earnings Per Common Share	'
	(Thousands, Except Per Share Amounts)	2013		2012		2011
	Basic EPS:
	Net Income	$	52,758	$	62,640	$	63,825
	Less: Income allocated to participating securities	245		340		497
	Net Income Available  to Common Shareholders	$	52,513	$	62,300	$	63,328
	Weighted Average Shares Outstanding	25,875		22,262		22,099
	Earnings Per Share of Common Stock	$	2.03	$	2.8	$	2.87
	Diluted EPS:
	Net Income	$	52,758	$	62,640	$	63,825
	Less: Income allocated to participating securities	245		340		496
	Net Income Available to Common Shareholders	$	52,513	$	62,300	$	63,329
	Weighted Average Shares Outstanding	25,875		22,262		22,099
	Dilutive Effect of Stock Options, Restricted Stock, and Restricted Stock Units	77		78		72
	Weighted Average Diluted Shares	25,952		22,340		22,171
	Earnings Per Share of Common Stock	$	2.02	$	2.79	$	2.86
	Outstanding Shares Excluded from the Calculation of Diluted EPS Attributable to:
	Antidilutive stock options	—		—		—
	Restricted stock and stock units subject to performance and/or market conditions	188		195		203
	Total	188		195		203

STOCKHOLDERS_EQUITY_Tables

STOCKHOLDER'S EQUITY (Tables)	12 Months Ended
	Sep. 30, 2013
Stockholders' Equity Note [Abstract]	'
Accumulated other comprehensive income (loss), net of taxes	'
	The components of accumulated other comprehensive income (loss), net of income taxes, recognized in the
	Consolidated Balance Sheets at September 30 were as follows:
	(Thousands)				Defined Benefit Pension and Other			Total
		Net Unrealized Gains (Losses) on Cash Flow Hedges			Postretirement
					Benefit Plans
	Balance at September 30, 2011	$	320		$	(2,420	)	$	(2,100	)
	Current-period change	(2,206		)	190			(2,016		)
	Balance at September 30, 2012	(1,886		)	(2,230		)	(4,116		)
	Current-period change	3,281			48			3,329
	Balance at September 30, 2013	1,395			(2,182		)	(787		)

LONGTERM_DEBT_Tables

LONG-TERM DEBT (Tables)	12 Months Ended
	Sep. 30, 2013
Debt Disclosure [Abstract]	'
Schedule of Maturities of long-term debt by fiscal year	'
	Maturities on long-term debt for the five fiscal years subsequent to September 30, 2013 are as follows:
	2014	—
	2015	—
	2016	—
	2017	—
	2018	$	100	million

NOTES_PAYABLE_AND_CREDIT_AGREE1

NOTES PAYABLE AND CREDIT AGREEMENTS (Tables)	12 Months Ended
	Sep. 30, 2013
Short-term Debt [Abstract]	'
Short-term borrowings	'
	Information about the Laclede Group’s short-term borrowings (excluding intercompany borrowings) during the 12 months ended September 30, and as of September 30, is presented below for 2013 and 2012:
		Commercial Paper Borrowings
	Twelve Months Ended September 30, 2013
	Weighted average borrowings outstanding	$34.2 million
	Weighted average interest rate	0.30%
	Range of borrowings outstanding	$0 – $99.4 million
	As of September 30, 2013
	Borrowings outstanding at end of period	$74.0 million
	Weighted average interest rate	0.30%
	Twelve Months Ended September 30, 2012
	Weighted average borrowings outstanding	$43.8 million
	Weighted average interest rate	0.30%
	Range of borrowings outstanding	$0 – $133.5 million
	As of September 30, 2012
	Borrowings outstanding at end of period	$40.1 million
	Weighted average interest rate	0.20%

FAIR_VALUE_OF_FINANCIAL_INSTRU1

FAIR VALUE OF FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Sep. 30, 2013
Fair Value Disclosures [Abstract]	'
Fair value - financial instruments	'
	The carrying amounts and estimated fair values of financial instruments not measured at fair value on a recurring basis at September 30, 2013 and 2012 are as follows:
						Classification of Estimated Fair Value
	(Thousands)	Carrying		Fair		Quoted		Significant Observable Inputs		Significant Unobservable Inputs
		Amount		Value		Prices in Active Markets		(Level 2)		(Level 3)
						(Level 1)
	As of September 30, 2013
	Cash and cash equivalents	$	52,981	$	52,981	$	52,824	$	157	$	—
	Short-term debt	74,000		74,000		—		74,000		—
	Long-term debt, including current portion	912,712		954,126		—		954,126		—
	As of September 30, 2012
	Cash and cash equivalents	$	27,457	$	27,457	$	17,380	$	10,077	$	—
	Short-term debt	40,100		40,100		—		40,100		—
	Long-term debt, including current portion	364,416		452,768		—		452,768		—

FAIR_VALUE_MEASUREMENTS_Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Sep. 30, 2013
Fair Value Disclosures [Abstract]	'
Fair Value Measurements, Measured on Recurring Basis	'
	The following table categorizes the assets and liabilities in the Consolidated Balance Sheets that are accounted for at fair value on a recurring basis in periods subsequent to initial recognition.
	(Thousands)	Quoted			Significant			Significant		Effects of Netting and Cash Margin Receivables			Total
		Prices in			Observable			Unobservable		/Payables
		Active			Inputs			Inputs
		Markets			(Level 2)			(Level 3)
		(Level 1)
	As of September 30, 2013
	Assets
	U. S. Stock/Bond Mutual Funds	$	14,500		$	—		$	—	$	—		$	14,500
	NYMEX/ICE natural gas contracts	4,333			330			—		(2,145		)	$	2,518
	OTCBB natural gas contracts	—			232			—		(232		)	—
	NYMEX gasoline and heating oil contracts	105			—			—		(105		)	$	—
	Natural gas commodity contracts	—			1,129			150		(495		)	$	784
	Total	$	18,938		$	1,691		$	150	$	(2,977	)	$	17,802
	Liabilities
	NYMEX/ICE natural gas contracts	$	3,687		$	321		$	—	$	(4,008	)	$	—
	OTCBB natural gas contracts	—			5,443			—		(232		)	$	5,211
	NYMEX gasoline and heating oil contracts	—			—			—		—			$	—
	Natural gas commodity contracts	—			1,140			40		(495		)	$	685
	Total	$	3,687		$	6,904		$	40	$	(4,735	)	$	5,896
	As of September 30, 2012
	Assets
	U. S. Stock/Bond Mutual Funds	$	13,187		$	—		$	—	$	—		$	13,187
	NYMEX/ICE natural gas contracts	7,411			994			—		(8,405		)	$	—
	NYMEX gasoline and heating oil contracts	344			—			—		(344		)	$	—
	Natural gas commodity contracts	—			3,060			113		(299		)	$	2,874
	Total	$	20,942		$	4,054		$	113	$	(9,048	)	$	16,061
	Liabilities
	NYMEX/ICE natural gas contracts	$	12,253		$	1,891		$	—	$	(14,144	)	$	—
	NYMEX gasoline and heating oil contracts	—			—			—		—			$	—
	Natural gas commodity contracts	—			428			4		(299		)	$	133
	Total	$	12,253		$	2,319		$	4	$	(14,443	)	$	133
Reconciliation of the Level 3 beginning and ending net derivative balances	'
	The following is a reconciliation of the Level 3 beginning and ending net derivative balances:
	(Thousands)	2013			2012
	Beginning of period	$	109		$	13
	Settlements	(269		)	(54		)
	Net losses related to derivatives not held at end of period	(99		)	(68		)
	Net gains related to derivatives still held at end of period	369			218
	End of period	$	110		$	109

DERIVATIVE_INSTRUMENTS_AND_HED1

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)	12 Months Ended
	Sep. 30, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Derivative Instruments and Hedging Activities	'
	The Company’s exchange-traded/cleared derivative instruments consist primarily of NYMEX and ICE positions. The NYMEX is the primary national commodities exchange on which natural gas derivatives are traded. Open NYMEX/ICE and OTCBB natural gas futures and swap positions at September 30, 2013 were as follows:
		Laclede Gas Company							Laclede Energy
									Resources, Inc.
		MMBtu			Avg. Price				MMBtu		Avg. Price
		(millions)			Per				(millions)		Per
					MMBtu						MMBtu
	NYMEX/ICE open short futures/swap positions
	Fiscal 2014	—			$	—			12.91		$	3.98
	Fiscal 2015	—			—				0.06		4.21
	NYMEX/ICE open long futures/swap positions
	Fiscal 2014	7.26			$	3.99			1.71		$	3.94
	Fiscal 2015	0.94			3.84				0.19		4.06
	Fiscal 2016	—			—				0.02		4.15
	OTCBB open long futures
	Fiscal 2014	16.81			$	3.97			—		$	—
	Fiscal 2015	7.58			4.22				—		—
The Effect of Derivative Instruments on the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income	'
	The Effect of Derivative Instruments on the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income
		Location of Gain (Loss)
	(Thousands)	Recorded in Income	2013				2012			2011
	Derivatives in Cash Flow Hedging Relationships
	Effective portion of gain (loss) recognized in OCI on derivatives:
	NYMEX/ICE natural gas contracts		$	4,923			$	4,505		$	5,226
	NYMEX gasoline and heating oil contracts		123				297			355
	Total		$	5,046			$	4,802		$	5,581
	Effective portion of gain (loss) reclassified from AOCI to income:
	NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	$	(4	)		$	18,929		$	7,443
		Gas Marketing Operating Expenses	(509		)		(10,532		)	(9,770		)
	Sub-total		$	(513	)		$	8,397		$	(2,327	)
	NYMEX gasoline and heating oil contracts	Gas Utility Other Operation Expenses	211				—			466
	Total		$	(302	)		$	8,397		$	(1,861	)
	Ineffective portion of gain (loss) on derivatives
	recognized in income:
	NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	$	(420	)		$	(36	)	$	966
		Gas Marketing Operating Expenses	(239		)		(263		)	(1,322		)
	Sub-total		$	(659	)		$	(299	)	$	(356	)
	NYMEX gasoline and heating oil contracts	Gas Utility Other Operation Expenses	(127		)		175			12
	Total		$	(786	)		$	(124	)	$	(344	)
	Derivatives Not Designated as Hedging Instruments*
	Gain (loss) recognized in income on derivatives:
	Natural gas commodity contracts	Gas Marketing Operating Revenues	$	(78	)		$	3,782		$	(660	)
		Gas Marketing Operating Expenses	—				687			4,229
	NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	(778		)		(615		)	(115		)
		Gas Marketing Operating Expenses	—				(625		)	(3		)
	NYMEX gasoline and heating oil contracts	Other Income and (Income Deductions) - Net	41				19			37
	Total		$	(815	)		$	3,248		$	3,488
	*	Gains and losses on the Utility’s natural gas derivative instruments, which are not designated as hedging instruments for financial reporting purposes, are deferred pursuant to the Utility’s PGA Clause and initially recorded as regulatory assets or regulatory liabilities. These gains and losses are excluded from the table above because they have no direct impact on the Statements of Consolidated Income. Such amounts are recognized in the Statements of Consolidated Income as a component of Regulated Gas Distribution Natural and Propane Gas operating expenses when they are recovered through the PGA Clause and reflected in customer billings.
Fair Value of Derivative Instruments in the Consolidated Balance Sheet	'
	Fair Value of Derivative Instruments in the Consolidated Balance Sheet at September 30, 2013
		Asset Derivatives*					Liability Derivatives*
	(Thousands)	Balance Sheet Location	Fair Value				Balance Sheet Location	Fair  Value
	Derivatives designated as hedging instruments
	NYMEX/ICE natural gas contracts	Derivative Instrument Assets	$	2,222			Derivative Instrument Assets	$	440
		Other Deferred Charges	22				Other Deferred Charges	11
	NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	105				Accounts Receivable - Other	—
	Sub-total		2,349					451
	Derivatives not designated as hedging instruments
	NYMEX/ICE natural gas contracts	Derivative Instrument Assets	950				Derivative Instrument Assets	100
		Accounts Receivable - Other	1,434				Accounts Receivable - Other	3,455
		Other Deferred Charges	32				Other Deferred Charges	—
	OTCBB natural gas contracts	Other Current Liabilities	228				Other Current Liabilities	4,045
		Other Deferred Credits	4				Other Deferred Credits	1,398
	Natural gas commodity contracts	Derivative Instrument Assets	991				Derivative Instrument Assets	90
		Other Deferred Charges	20				Other Deferred Charges	137
		Other Current Liabilities	247				Other Current Liabilities	830
		Other Deferred Credits	21				Other Deferred Credits	123
	Sub-total		3,927					10,178
	Total derivatives		$	6,276				$	10,629
	Fair Value of Derivative Instruments in the Consolidated Balance Sheet at September 30, 2012
		Asset Derivatives					Liability Derivatives
	(Thousands)	Balance Sheet Location	Fair Value			*	Balance Sheet Location	Fair Value
	Derivatives designated as hedging instruments
	NYMEX/ICE natural gas contracts	Accounts Receivable - Other	$	405			Accounts Receivable - Other	$	3,413
	NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	334				Accounts Receivable - Other	—
	Sub-total		739					3,413
	Derivatives not designated as hedging instruments
	NYMEX/ICE natural gas contracts	Accounts Receivable - Other	8,000				Accounts Receivable - Other	10,731
		Other Deferred Charges	—				Other Deferred Charges	—
	Natural gas commodity contracts	Derivative Instrument Assets	3,150				Derivative Instrument Assets	295
		Other Current Liabilities	4				Other Current Liabilities	137
		Other Deferred Charges	19				Other Deferred Charges	—
	NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	10				Accounts Receivable - Other	—
	Sub-total		11,183					11,163
	Total derivatives		$	11,922				$	14,576
	*	The fair values of Asset Derivatives and Liability Derivatives exclude the fair value of cash margin receivables or payables with counterparties subject to netting arrangements. Fair value amounts of derivative contracts (including the fair value amounts of cash margin receivables and payables) for which there is a legal right to set off are presented net on the Consolidated Balance Sheets. As such, the gross balances presented in the table above are not indicative of the Company’s net economic exposure. Refer to Note 10, Fair Value Measurements, for information on the valuation of derivative instruments.
Derivative instrument Reconciliation	'
	Following is a reconciliation of the amounts in the tables above to the amounts presented in the Consolidated Balance Sheets:
	(Thousands)	2013				2012
	Fair value of asset derivatives presented above	6,276				11,922
	Fair value of cash margin receivables offset with derivatives	1,765				5,478
	Netting of assets and liabilities with the same counterparty	(4,739		)		(14,526		)
	Total	3,302				2,874
	Derivative Instrument Assets, per Consolidated Balance Sheets:
	Derivative instrument assets	3,291				2,855
	Other deferred charges	11				19
	Total	3,302				2,874
	Fair value of liability derivatives presented above	10,629				14,576
	Fair value of cash margin payables offset with derivatives	6				83
	Netting of assets and liabilities with the same counterparty	(4,739		)		(14,526		)
	Derivative instrument liabilities, per Consolidated Balance Sheets	5,896				133
	Derivative Instrument Liabilities, per Consolidated Balance Sheets:
	Other current liabilities	$	4,400			$	133
	Other deferred credits	1,496				—
	Total	$	5,896			$	133

INCOME_TAXES_Tables

INCOME TAXES (Tables)	12 Months Ended
	Sep. 30, 2013
Income Tax Disclosure [Abstract]	'
Net Provision For Income Tax	'
	The net provisions for income taxes charged during the fiscal years ended September 30, 2013, 2012, and 2011 are as follows:
	(Thousands)	2013				2012				2011
	Included in Statements of Consolidated Income:
	Federal
	Current	$	(4,173	)		$	(3,835	)		$	4,724
	Deferred	19,925				26,365				20,602
	Investment tax credits	(213		)		(213		)		(213		)
	State and local
	Current	(301		)		(430		)		573
	Deferred	2,340				4,402				3,496
	Total Income Tax Expense	$	17,578			$	26,289			$	29,182
Effective income tax rate variation from stated tax rate	'
	The effective income tax rate varied from the federal statutory income tax rate for each year due to the following:
		2013			2012			2011
	Federal income tax statutory rate	35	%		35	%		35	%
	State and local income taxes, net of federal income tax benefits	3.5			2.9			2.8
	Certain expenses capitalized on books and deducted on tax return	(9.7	)		(6.9	)		(5.0	)
	Taxes related to prior years	(1.6	)		(0.8	)		(0.7	)
	Other items – net	(2.2	)		(0.6	)		(0.7	)
	Effective income tax rate	25	%		29.6	%		31.4	%
Significant Items in Net Deferred Tax Liability	'
	The significant items comprising the net deferred tax liability recognized in the Consolidated Balance Sheets as of September 30 are as follows:
	(Thousands)	2013				2012
	Deferred tax assets:
	Reserves not currently deductible	$	13,933			$	16,400
	Pension and other postretirement benefits	71,367				73,480
	Unamortized investment tax credits	1,799				1,955
	Other*	12,522				18,224
	Total deferred tax assets	99,621				110,059
	Deferred tax liabilities:
	Relating to property	341,975				303,474
	Regulatory pension and other postretirement benefits	124,871				121,554
	Deferred gas costs	7,112				20,652
	Other	5,789				26,563
	Total deferred tax liabilities	479,747				472,243
	Net deferred tax liability	380,126				362,184
	Net deferred tax liability – current*	(1,012		)		(6,675		)
	Net deferred tax liability – non-current*	$	379,114			$	355,509
	* The Company periodically invests in tax credits. As of September 30, 2013, $7.1 million of state tax credits are included in Other and Net deferred tax liability. $4.7 million of state tax credits were classified as current. $2.4 million of state tax credits were classified as non-current.
Unrecognized Tax Benefit Reconciliation	'
	The following table presents a reconciliation of the beginning and ending balances of unrecognized tax benefits at September 30 as reported in the Consolidated Balance Sheets:
	(Thousands)	2013				2012
	Unrecognized tax benefits, beginning of year	$	5,810			$	5,596
	Increases related to prior year tax positions	145				78
	Increases related to tax positions taken in current year	1,450				547
	Reductions due to lapse of applicable statute of limitations	(5,018		)		(411		)
	Unrecognized tax benefits, end of year	$	2,387			$	5,810

OTHER_INCOME_AND_INCOME_DEDUCT1

OTHER INCOME AND (INCOME DEDUCTIONS) - NET (Tables)	12 Months Ended
	Sep. 30, 2013
Other Nonoperating Income (Expense) [Abstract]	'
Other Income and (Income Deductions) by Component	'
	(Thousands)	2013			2012			2011
	Interest income	$	1,088		$	1,309		$	1,136
	Net investment gain	2,857			3,124			185
	Other income	377			811			118
	Other income deductions	(1,878		)	(1,972		)	(1,262		)
	Other Income and (Income Deductions) – Net	$	2,444		$	3,272		$	177

INFORMATION_BY_OPERATING_SEGME1

INFORMATION BY OPERATING SEGMENT (Tables)	12 Months Ended
	Sep. 30, 2013
Segment Reporting [Abstract]	'
Schedule of operating segment information	'
		Gas Utility			Gas Marketing				Other				Eliminations			Consolidated
	(Thousands)
	Fiscal 2013
	Revenues from external customers	$	847,224		$	165,146			$	4,649			$	—		$	1,017,019
	Intersegment revenues	10,538			24,185				1,625				(36,348		)	—
	Total Operating Revenues	857,762			189,331				6,274				(36,348		)	1,017,019
	Operating Expenses
	Gas Utility
	Natural and Propane Gas	469,098			—				—				(35,656		)	433,442
	Other Operation and Maintenance	180,702			—				—				(360		)	180,342
	Depreciation and Amortization	48,283			—				—				—			48,283
	Taxes, Other than Income Taxes	60,079			—				—				—			60,079
	Total Gas Utility Operating Expenses	758,162			—				—				(36,016		)	722,146
	Gas Marketing	—			176,554			(a)	—				—			176,554
	Other	—			—				22,157			(b)	(332		)	21,825
	Total Operating Expenses	758,162			176,554				22,157				(36,348		)	920,525
	Operating Income	99,599			12,777				(15,882		)		—			96,494
	Interest income	947			103				343				(305		)	1,088
	Interest charges	26,137			135				2,635				(305		)	28,602
	Income tax expense	19,243			5,162				(6,827		)		—			17,578
	Net economic earnings	56,635			8,936				(559		)		—			65,012
	Total assets	2,981,016			163,944				115,560				(135,134		)	3,125,386
	Capital expenditures	128,496			44				2,248				—			130,788
	Fiscal 2012
	Revenues from external customers	$	763,447		$	358,145			$	3,883			$	—		$	1,125,475
	Intersegment revenues	1,204			15,330				1,042				(17,576		)	—
	Total Operating Revenues	764,651			373,475				4,925				(17,576		)	1,125,475
	Operating Expenses
	Gas Utility
	Natural and Propane Gas	414,846			—				—				(17,542		)	397,304
	Other Operation and Maintenance	167,351			—				—				—			167,351
	Depreciation and Amortization	40,739			—				—				—			40,739
	Taxes, Other than Income Taxes	53,672			—				—				—			$	53,672
	Total Gas Utility Operating Expenses	676,608			—				—				(17,542		)	659,066
	Gas Marketing	—			353,286			(a)	—				(3		)	353,283
	Other	—			—				2,555			(b)	(31		)	2,524
	Total Operating Expenses	676,608			353,286				2,555				(17,576		)	1,014,873
	Operating Income	88,043			20,189				2,370				—			110,602
	Interest income	1,230			175				371				(467		)	1,309
	Interest charges	25,156			81				175				(467		)	24,945
	Income tax expense	17,393			7,966				930				—			26,289
	Net economic earnings	48,089			12,273				2,250				—			62,612
	Total assets	1,758,952			190,709				102,241				(171,640		)	1,880,262
	Capital expenditures	106,734			140				1,969				—			108,843
	Fiscal 2011
	Revenues from external customers	$	911,614		$	645,042			$	19,704			$	—		1,576,360
	Intersegment revenues	1,576			24,333				1,038				—			26,947
	Total Operating Revenues	913,190			669,375				20,742				—			1,603,307
	Operating Expenses
	Gas Utility
	Natural and Propane Gas	549,947			—				—				—			549,947
	Other Operation and Maintenance	172,938			—				—				—			172,938
	Depreciation and Amortization	39,214			—				—				—			$	39,214
	Taxes, Other than Income Taxes	60,752			—				—				—			60,752
	Total Gas Utility Operating Expenses	822,851			—				—				—			$	822,851
	Gas Marketing	—			652,567			(a)	—				—			652,567
	Other	—			—				9,642			(b)	—			9,642
	Total Operating Expenses	822,851			652,567				9,642				—			1,485,060
	Operating Income	90,339			16,808				11,100				—			118,247
	Interest income	1,057			165				217				(303		)	1,136
	Interest charges	25,544			14				162				(303		)	25,417
	Income tax expense	18,694			6,570				3,918				—			29,182
	Net economic earnings	46,952			8,962				6,496			(c)	—			62,410
Total assets	1,641,386			175,352				129,176				(162,832		)	1,783,082
Capital expenditures	67,304			215				119				—			67,638
(a)	Depreciation and amortization for Gas Marketing is included in Gas Marketing Expenses on the Statements of Consolidated Income ($0.3 million for fiscal year 2013, $0.3 million for fiscal year 2012, and $0.1 million for fiscal year 2011).
(b)	Depreciation, amortization, and accretion for Other is included in the Other Operating Expenses on the Statements of Consolidated Income ($0.6 million for fiscal year 2013, $0.3 million for fiscal year 2012 and $0.2 million for fiscal year 2011).
(c)	Net economic earnings include income realized by the Utility from separate non-regulated sales of propane inventory no longer needed to serve utility customers, of which occurred in fiscal year 2011. This transaction resulted in after-tax earnings totaling $6.1 million.
Schedule of the reconciliation of consolidated net economic earnings to consolidated net income	'
	Reconciliation of Consolidated Net Income to Consolidated Net Economic Earnings
	(Thousands)	2013			2012				2011
	Net Income (GAAP)	$	52,758		$	62,640			$	63,825
	Unrealized loss (gain) on energy-related	614			(314		)		(1,415		)
	derivatives
	Lower of cost or market inventory adjustments	868			—				—
	Realized (gain) loss on economic hedges prior	(25		)	163				—
	to the sale of the physical commodity
	Acquisition, divestiture and restructuring activities	10,797			123				—
	Net Economic Earnings (Non-GAAP)	$	65,012		$	62,612			$	62,410

INTERIM_FINANCIAL_INFORMATION_1

INTERIM FINANCIAL INFORMATION (UNAUDITED) (Unaudited) (Tables)	12 Months Ended
	Sep. 30, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Schedule of Quarterly Financial Information Table	'
	(Thousands, Except Per Share Amounts)
	Three Months Ended	Dec. 31		31-Mar		30-Jun		Sept. 30
	Fiscal Year 2013
	Total Operating Revenues	$	307,003	$	397,613	$	165,289	$	147,114
	Operating Income (Loss)	42,085		51,849		12,282		(9,722		)
	Net Income (Loss)	25,568		30,242		6,584		(9,636		)
	Basic Earnings (Loss) Per Share of Common Stock	1.14		1.34		0.25		(0.30		)
	Diluted Earnings (Loss) Per Share of Common Stock	1.14		1.34		0.25		(0.30		)
	Three Months Ended	Dec. 31		31-Mar		30-Jun		Sept. 30
	Fiscal Year 2012
	Total Operating Revenues	$	410,913	$	358,175	$	186,849	$	169,538
	Operating Income	43,105		50,583		15,045		1,869
	Net Income (Loss)	25,174		29,684		8,433		(651		)
	Basic Earnings (Loss) Per Share of Common Stock	1.13		1.33		0.38		(0.03		)
	Diluted Earnings (Loss) Per Share of Common Stock	1.12		1.32		0.38		(0.03		)

SUMMARY_OF_SIGNIFICANT_ACCOUNT3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Part 1 (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
	customer
Nature of operations [Abstract]	'	'	'
Population of service area (more than)	1,130,000	'	'
Utility Plant, Depreciation and Amortization [Abstract]	'	'	'
Average annual depreciation and amortization expense percentage	3.20%	3.10%	3.10%
Annual capital expenditures	$128.50	$106.70	$67.30
Accruals for capital expenditures	$4.70	$9.70	$8.20

SUMMARY_OF_SIGNIFICANT_ACCOUNT4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Part 2 (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Asset retirement obligations [Roll forward]	'	'
Asset retirement obligations, beginning of year	$40,368	$27,495
Liabilities incurred during the period	801	851
Liabilities settled during the period	-1,089	-601
Accretion	2,322	1,637
Revisions in estimated cash flows	0	10,986
Addition of MGE asset retirement obligation	32,152	0
Asset retirement obligations, end of year	$74,554	$40,368

SUMMARY_OF_SIGNIFICANT_ACCOUNT5

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Part 3 (Details) (USD $)

12 Months Ended

12 Months Ended

165 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2013

Sep. 01, 2013

Sep. 01, 2013

Unamortized investment tax credits [Member]

Unamortized investment tax credits [Member]

Accrued cost of removal [Member]

Accrued cost of removal [Member]

Other Regulatory Liabilities [Member]

Other Regulatory Liabilities [Member]

Future income taxes due from customers [Member]

Future income taxes due from customers [Member]

Pension and postretirement benefit costs [Member]

Pension and postretirement benefit costs [Member]

Unamortized purchased gas adjustments [Member]

Unamortized purchased gas adjustments [Member]

Purchased gas costs [Member]

Purchased gas costs [Member]

Compensated absences [Member]

Compensated absences [Member]

Other [Member]

Other [Member]

Deferred Costs Incurred Prior to YE 1999 [Member]

Deferred Costs Incurred Prior to YE 1999 [Member]

Missouri Gas Energy (MGE) [Member]

Laclede Group [Member]

Missouri Gas Energy (MGE) [Member]

Schedule of Regulatory Assets and Liabilities[Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Regulatory Assets

$563,480,000

$496,721,000

'

'

'

'

'

'

$112,912,000

$118,997,000

$381,395,000

$304,446,000

$17,533,000

$40,674,000

$18,249,000

$18,386,000

$8,004,000

$7,836,000

$25,387,000

$6,382,000

'

'

'

'

Regulatory Liabilities

85,460,000

59,432,000

2,900,000

3,113,000

59,066,000

55,103,000

23,494,000

1,216,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Regulated Operations [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Regulatory assets not earning a rate of return

17,200,000

7,800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Regulatory assets not earning a rate of return, recovery period

'15 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Regulatory Assets - Non-current

545,947,000

456,047,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10,500,000

10,500,000

'

'

Amortization period of deferred costs (in years)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'15 years

'

'

'

Amortization of deferred costs recognized to date - total

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

9,700,000

'

'

The amount by which the replacement cost exceeds (less than) the cost basis value of stored gas inventories

13,300,000

24,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Goodwill [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Goodwill acquired during period

247,078,000

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

247,078,000

247,100,000

Revenue Recognition [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Accrued Unbilled Revenue

$25,200,000

$11,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

SUMMARY_OF_SIGNIFICANT_ACCOUNT6

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Part 4 (Details) (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
	change
Off System Sales [Line Items]	'	'	'
Number of PGA Discretionary Changes	3	'	'
Months between PGA Discretionary Changes	'2 months	'	'
Cost savings retention percentage	10.00%	'	'
Maximum amount of cost savings allowable	$3,000,000	'	'
Number of Months of the Original Maturity of Debt Instruments Purchased	'3 months	'	'
Gross Receipts taxes recorded in regulated gas distribution operating revenues	$40,800,000	$35,900,000	$43,500,000
Laclede Gas [Member] | First $2 million [Member]	'	'	'
Off System Sales [Line Items]	'	'	'
Customer Share	100.00%	'	'
Company Share	0.00%	'	'
Laclede Gas [Member] | Next $2 million [Member]	'	'	'
Off System Sales [Line Items]	'	'	'
Customer Share	80.00%	'	'
Company Share	20.00%	'	'
Laclede Gas [Member] | Next $2 million [Member]	'	'	'
Off System Sales [Line Items]	'	'	'
Customer Share	75.00%	'	'
Company Share	25.00%	'	'
Laclede Gas [Member] | Amounts exceeding $6 million [Member]	'	'	'
Off System Sales [Line Items]	'	'	'
Customer Share	70.00%	'	'
Company Share	30.00%	'	'
Missouri Gas Energy (MGE) [Member] | First $1.2 million [Member]	'	'	'
Off System Sales [Line Items]	'	'	'
Customer Share	85.00%	'	'
Company Share	15.00%	'	'
Missouri Gas Energy (MGE) [Member] | Next $1.2 million [Member]	'	'	'
Off System Sales [Line Items]	'	'	'
Customer Share	80.00%	'	'
Company Share	20.00%	'	'
Missouri Gas Energy (MGE) [Member] | Next $1.2 million [Member]	'	'	'
Off System Sales [Line Items]	'	'	'
Customer Share	75.00%	'	'
Company Share	25.00%	'	'
Missouri Gas Energy (MGE) [Member] | Amounts exceeding $3.6 million [Member]	'	'	'
Off System Sales [Line Items]	'	'	'
Customer Share	70.00%	'	'
Company Share	30.00%	'	'

ACQUISITION_OF_MGE_Part_1_Narr

ACQUISITION OF MGE Part 1 - Narrative (Details) (USD $)	12 Months Ended					0 Months Ended			0 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2013	Sep. 30, 2013	Aug. 13, 2013	Sep. 01, 2013	Sep. 01, 2013	29-May-13	Aug. 13, 2013
				Other Operating Expense [Member]	Interest on Long-term Debt [Member]	Laclede Gas [Member]	Missouri Gas Energy (MGE) [Member]	Missouri Gas Energy (MGE) [Member]	Missouri Gas Energy (MGE) [Member]	Missouri Gas Energy (MGE) [Member]
								Gas Utility [Member]	Common Stock Issued	Laclede Gas [Member]
Business Acquisition [Line Items]	'	'	'	'	'	'	'	'	'	'
Acquisition purchase price	$975,000,000	$0	$0	'	'	'	$975,000,000	'	'	'
Stock issued to finance acquisition	'	'	'	'	'	'	'	'	10,000,000	'
First mortgage bonds issued to finance acquisition	550,000,000	0	0	'	'	450,000,000	'	'	'	450,000,000
Goodwill	247,078,000	0	'	'	'	'	247,078,000	247,100,000	'	'
Merger-related transaction costs	$17,000,000	$200,000	'	$15,100,000	$1,900,000	'	'	'	'	'

ACQUISITION_OF_MGE_Part_2_Pro_

ACQUISITION OF MGE Part 2 - Pro Forma Information, Revenues and Earnings of Acquiree (Details) (Missouri Gas Energy (MGE) [Member], USD $)	1 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Sep. 30, 2013
Missouri Gas Energy (MGE) [Member]	'
Pro Forma Information of Acquiree since Acquisition Date	'
Total net revenues	$21,985
Net Income	$1,795
Earnings/(loss) per share:	'
Basic (in dollars per share)	$0.07
Diluted (in dollars per share)	$0.07

ACQUISITION_OF_MGE_Part_3_Prel

ACQUISITION OF MGE Part 3 - Preliminary Fair Value of Assets Acquired and Liabilities Assumed (Details) (USD $)	Sep. 30, 2013	Sep. 30, 2012	Sep. 01, 2013
In Thousands, unless otherwise specified			Missouri Gas Energy (MGE) [Member]
Assets:	'	'	'
Utility plant	'	'	$671,793
Non-utility property	'	'	238
Other investments	'	'	3,096
Goodwill	247,078	0	247,078
Other Property and Investments	'	'	922,205
Accounts receivable:	'	'	'
Utility	'	'	19,963
Other	'	'	6,119
Delayed customer billings	'	'	10,701
Inventories:	'	'	'
Natural gas stored underground	'	'	58,679
Materials and supplies at average cost	'	'	3,988
Prepayments and other	'	'	487
Total Current Assets	'	'	99,937
Deferred Charges:	'	'	'
Regulatory assets	'	'	84,014
Other	'	'	4,928
Total Deferred Charges	'	'	88,942
Total Assets Acquired	'	'	1,111,084
Liabilities:	'	'	'
Accounts payable	'	'	20,154
Wages and compensation accrued	'	'	5,088
Customer deposits	'	'	8,362
Interest accrued	'	'	183
Taxes accrued	'	'	17,197
Other	'	'	12,620
Total Current Liabilities	'	'	63,604
Pension and postretirement benefit costs	'	'	24,466
Asset retirement obligations	'	'	32,056
Regulatory liabilities	'	'	2,249
Regulatory liabilities	'	'	13,709
Total Deferred Credits and Other Liabilities	'	'	72,480
Total Liabilities Assumed	'	'	136,084
Net Assets Acquired	'	'	$975,000

ACQUISITION_OF_MGE_Part_4_Pro_

ACQUISITION OF MGE Part 4 - Pro Forma Information (Details) (Missouri Gas Energy (MGE) [Member], USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Missouri Gas Energy (MGE) [Member]	'	'
Business Acquisition, Pro Forma Information [Abstract]	'	'
Total net revenues	$1,518,201	$1,581,425
Net Income	$83,642	$81,722
Earnings per share:	'	'
Basic (in dollars per share)	$2.57	$2.52
Diluted (in dollars per share)	$2.56	$2.51

PENSION_PLANS_AND_OTHER_POSTRE2

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 1 (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Pension Plans [Member]	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Service cost – benefits earned during the period	$9,209	$9,203	$9,553
Interest cost on projected benefit obligation	16,959	19,358	18,819
Expected return on plan assets	-19,358	-19,595	-18,849
Amortization of prior service cost	544	592	642
Amortization of actuarial loss	10,724	9,040	10,228
Loss on lump-sum settlements	26,996	20,051	943
Sub-total	45,074	38,649	21,336
Regulatory adjustment	-27,532	-18,579	-7,066
Net pension cost	17,542	20,070	14,270
Postretirement Plans [Member]	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Service cost – benefits earned during the period	10,162	8,060	7,676
Interest cost on projected benefit obligation	5,234	5,521	4,843
Expected return on plan assets	-4,447	-3,965	-3,646
Amortization of transition obligation	93	136	136
Amortization of prior service cost	3	-2,072	-2,328
Amortization of actuarial loss	5,300	4,261	4,443
Sub-total	16,345	11,941	11,124
Regulatory adjustment	-6,821	-2,417	-2,071
Net pension cost	$9,524	$9,524	$9,053

PENSION_PLANS_AND_OTHER_POSTRE3

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 2 (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Pension Plans [Member]	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Current year actuarial loss (gain)	$17,030	$32,884	($13,485)
Amortization of actuarial loss	-10,724	-29,091	-11,171
Acceleration of loss recognized due to settlement	26,996	0	0
Amortization of prior service cost	-544	-592	-642
Sub-total	-21,234	3,201	-25,298
Regulatory adjustment	21,159	-3,510	24,533
Total recognized in other comprehensive income	-75	-309	-765
Postretirement Plans [Member]	'	'	'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'
Current year actuarial loss (gain)	16,300	10,138	1,696
Amortization of actuarial loss	-5,300	-4,261	-4,443
Amortization of prior service cost	-3	2,072	2,328
Amortization of transition obligation	-93	-136	-136
Sub-total	10,904	7,813	-555
Regulatory adjustment	-10,904	-7,813	555
Total recognized in other comprehensive income	$0	$0	$0

PENSION_PLANS_AND_OTHER_POSTRE4

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 3 (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2011
Pension Plans [Member]	'		'		'
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]	'		'		'
Benefit obligation, beginning of year	$412,171		$384,163		'
Service cost	9,209		9,203		9,553
Interest cost	16,959		19,358		18,819
Actuarial (gain) loss	-23,921		52,161		'
MGE acquisition	151,424		0		'
Settlement loss	24,999		14,348		'
Gross benefits paid	-87,023	[1]	-67,062	[1]	'
Benefit obligation, end of year	503,818		412,171		384,163
Accumulated benefit obligation, end of year	444,129		353,061		'
Postretirement Plans [Member]	'		'		'
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]	'		'		'
Benefit obligation, beginning of year	127,217		103,991		'
Service cost	10,162		8,060		7,676
Interest cost	5,234		5,521		4,843
Actuarial (gain) loss	-17,514		-15,895		'
MGE acquisition	28,444		0		'
Gross benefits paid	-8,449		-6,250		'
Benefit obligation, end of year	$180,122		$127,217		$103,991
[1]	Includes $79,484 and $60,085 lump-sum payments recognized as settlements in fiscal years 2013 and 2012, respectively.

PENSION_PLANS_AND_OTHER_POSTRE5

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 4 (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012
Pension Plans [Member]	'		'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'		'
Fair value of plan assets, beginning of year	$274,130		$247,959
Actual return on plan assets	3,387		53,220
Employer contributions	27,991		40,013
MGE acquisition	126,958		0
Gross benefits paid	-87,023	[1]	-67,062	[1]
Fair value of plan assets, end of year	345,443		274,130
Funded status of plans, end of year	-158,375		-138,041
Postretirement Plans [Member]	'		'
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]	'		'
Fair value of plan assets, beginning of year	67,442		51,744
Actual return on plan assets	5,660		9,722
Employer contributions	16,596		12,226
MGE acquisition	30,396		0
Gross benefits paid	-8,449		-6,250
Fair value of plan assets, end of year	111,645		67,442
Funded status of plans, end of year	($68,477)		($59,775)
[1]	Includes $79,484 and $60,085 lump-sum payments recognized as settlements in fiscal years 2013 and 2012, respectively.

PENSION_PLANS_AND_OTHER_POSTRE6

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 5 (Details) (USD $)	Sep. 30, 2013	Sep. 30, 2012
In Thousands, unless otherwise specified
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]	'	'
Noncurrent liabilities	($228,653)	($196,558)
Pension Plans [Member]	'	'
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]	'	'
Current liabilities	-442	-468
Noncurrent liabilities	-157,933	-137,573
Total	158,375	138,041
Pre-tax amounts recognized in accumulated other comprehensive income not yet recognized as components of net periodic pension cost consist of:	'	'
Net actuarial loss	115,775	136,464
Prior service costs	4,467	5,011
Sub-total	120,242	141,475
Adjustments for amounts included in Regulatory Assets	-116,686	-137,845
Total	3,556	3,630
Postretirement Plans [Member]	'	'
Defined Benefit Plan, Amounts Recognized in Balance Sheet [Abstract]	'	'
Noncurrent assets	2,543	0
Current liabilities	-300	-790
Noncurrent liabilities	-70,720	-58,985
Total	68,477	59,775
Pre-tax amounts recognized in accumulated other comprehensive income not yet recognized as components of net periodic pension cost consist of:	'	'
Net actuarial loss	63,573	52,573
Prior service costs	-27	-24
Transition obligation	0	93
Sub-total	63,546	52,642
Adjustments for amounts included in Regulatory Assets	-63,546	-52,642
Total	$0	$0

PENSION_PLANS_AND_OTHER_POSTRE7

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 6 (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013
Pension Plans [Member]	'
Pre-tax amounts are expected to be amortized from accumulated other comprehensive income [Abstract]	'
Amortization of net actuarial loss	$7,088
Amortization of prior service cost	497
Sub-total	7,585
Regulatory adjustment	-7,196
Total Expected to be Amortized	389
Postretirement Plans [Member]	'
Pre-tax amounts are expected to be amortized from accumulated other comprehensive income [Abstract]	'
Amortization of net actuarial loss	6,021
Amortization of prior service cost	-4
Sub-total	6,017
Regulatory adjustment	-6,017
Total Expected to be Amortized	$0

PENSION_PLANS_AND_OTHER_POSTRE8

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 7 (Details)	12 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2011
Pension Plans [Member]	'		'		'
Assumptions used to calculate net periodic cost [Abstract]	'		'		'
Weighted average discount rate	3.95%	[1]	5.10%	[1]	4.75%	[1]
Weighted average rate of future compensation increase	3.00%		3.00%		3.00%
Expected long-term rate of return on plan assets	7.75%		7.75%		8.00%
Assumptions used to calculate benefit obligations [Abstract]	'		'		'
Weighted average discount rate	4.70%	[2]	3.95%	[2]	'
Weighted average rate of future compensation increase	3.00%		3.00%		'
Pension Plans [Member] | Missouri Gas Energy (MGE) [Member]	'		'		'
Assumptions used to calculate net periodic cost [Abstract]	'		'		'
Weighted average discount rate	5.05%		'		'
Assumptions used to calculate benefit obligations [Abstract]	'		'		'
Weighted average discount rate	5.00%		'		'
Postretirement Plans [Member]	'		'		'
Assumptions used to calculate net periodic cost [Abstract]	'		'		'
Weighted average discount rate	3.80%	[3]	5.05%	[3]	4.70%	[3]
Weighted average rate of future compensation increase	3.00%		3.00%		3.00%
Expected long-term rate of return on plan assets	7.75%	[4]	7.75%	[4]	8.00%	[4]
Assumptions used to calculate benefit obligations [Abstract]	'		'		'
Weighted average discount rate	4.60%	[5]	3.80%	[5]	'
Weighted average rate of future compensation increase	3.00%		3.00%		'
Postretirement Plans [Member] | Missouri Gas Energy (MGE) [Member]	'		'		'
Assumptions used to calculate net periodic cost [Abstract]	'		'		'
Weighted average discount rate	5.05%	[3]	'		'
Expected long-term rate of return on plan assets	5.75%	[4]	'		'
Assumptions used to calculate benefit obligations [Abstract]	'		'		'
Weighted average discount rate	4.95%	[3]	'		'
[1]	Weighted average discount rate assumption for the MGE pension plan is 5.05%.
[2]	Derivative assets of $3,027 net of cash margin payable of $2,750.
[3]	Weighted average discount rate assumption for the MGE postretirement plan is 5.05%.
[4]	Expected long-term rate of return on plan assets assumption for the MGE postretirement plan is
[5]	Weighted average discount rate assumption for the MGE postretirement plan is 4.95%.

PENSION_PLANS_AND_OTHER_POSTRE9

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 8 (Details) (USD $)	Sep. 30, 2013	Sep. 30, 2012
In Thousands, unless otherwise specified
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]	'	'
Projected benefit obligation	$503,818	$412,171
Accumulated benefit obligation	444,129	353,061
Fair value of plan assets, plans with benefit obligations in excess of plan assets	345,443	274,130
Fair value of plan assets, plans with accumulated benefit obligations in excess of plan assets	$345,443	$274,130

Recovered_Sheet1

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 9 (Details)	12 Months Ended
	Sep. 30, 2013		Sep. 30, 2012
Pension Plans [Member]	'		'
Targeted and actual plan assets by category [Abstract]	'		'
Targeted allocation of plan assets	100.00%		'
Actual allocation of plan assets	100.00%		100.00%
Pension Plans [Member] | Equity Markets [Member]	'		'
Targeted and actual plan assets by category [Abstract]	'		'
Targeted allocation of plan assets	42.50%		'
Actual allocation of plan assets	45.90%		37.30%
Pension Plans [Member] | Commodities [Member]	'		'
Targeted and actual plan assets by category [Abstract]	'		'
Targeted allocation of plan assets	2.50%		'
Actual allocation of plan assets	1.60%		2.20%
Pension Plans [Member] | Real Estate [Member]	'		'
Targeted and actual plan assets by category [Abstract]	'		'
Targeted allocation of plan assets	2.50%		'
Actual allocation of plan assets	3.00%		2.20%
Pension Plans [Member] | Inflation-Indexed Securities [Member]	'		'
Targeted and actual plan assets by category [Abstract]	'		'
Targeted allocation of plan assets	2.50%		'
Actual allocation of plan assets	1.40%		2.20%
Pension Plans [Member] | Debt Securities [Member]	'		'
Targeted and actual plan assets by category [Abstract]	'		'
Targeted allocation of plan assets	50.00%		'
Actual allocation of plan assets	43.30%		41.10%
Pension Plans [Member] | Other	'		'
Targeted and actual plan assets by category [Abstract]	'		'
Targeted allocation of plan assets	0.00%	[1]	'
Actual allocation of plan assets	4.80%	[1]	15.00%	[1]
Postretirement Plans [Member]	'		'
Targeted and actual plan assets by category [Abstract]	'		'
Investment policy targets asset allocation to debt securities	40.00%		'
Current investment policy targets an asset allocation to equity securities	60.00%		'
Postretirement Plans [Member] | Equity Markets [Member]	'		'
Targeted and actual plan assets by category [Abstract]	'		'
Actual allocation of plan assets	59.00%		59.00%
Postretirement Plans [Member] | Debt Securities [Member]	'		'
Targeted and actual plan assets by category [Abstract]	'		'
Actual allocation of plan assets	39.00%		39.00%
Postretirement Plans [Member] | Other	'		'
Targeted and actual plan assets by category [Abstract]	'		'
Targeted allocation of plan assets	0.00%		'
Actual allocation of plan assets	2.00%		2.00%
[1]	Other investments in 2013 consist of cash equivalents. The relatively large cash position at September 30, 2012 was due to a transition taking place between investment managers and was invested in debt securities in a matter of days.

Recovered_Sheet2

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 10 (Details) (USD $)	Sep. 30, 2013
In Millions, unless otherwise specified
Pension Plans [Member] | Paid From Qualified Trust [Member]	'
Expected benefit payments [Abstract]	'
2014	$22.90
2015	25.3
2016	27.2
2017	30.8
2018	34.2
2019 - 2023	227.2
Pension Plans [Member] | Paid From Laclede Gas Funds [Member]	'
Expected benefit payments [Abstract]	'
2014	0.4
2015	0.5
2016	0.5
2017	0.6
2018	0.6
2019 - 2023	4.5
Postretirement Plans [Member] | Paid From Qualified Trust [Member]	'
Expected benefit payments [Abstract]	'
2014	9.5
2015	9.9
2016	10.7
2017	11.7
2018	12.8
2019 - 2023	84.1
Postretirement Plans [Member] | Paid From Laclede Gas Funds [Member]	'
Expected benefit payments [Abstract]	'
2014	0.3
2015	0.3
2016	0.3
2017	0.4
2018	0.4
2019 - 2023	$2.20

Recovered_Sheet3

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 11 (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]	'	'
Medical cost trend assumed for next year	7.50%	7.00%
Rate to which the medical cost trend rate is assumed to decline (the ultimate medical cost trend rate)	5.00%	5.00%
Year the rate reaches the ultimate trend	'2020	'2017
Assumed 1% change in the assumed medical cost trend rate [Abstract]	'	'
Effect of 1% increase on net periodic postretirement benefit cost	$1,520	'
Effect of 1% decrease on net periodic postretirement benefit cost	-1,390	'
Effect of 1% increase on accumulated postretirement benefit obligation	7,060	'
Effect of 1% decrease on accumulated postretirement benefit obligation	($6,580)	'

Recovered_Sheet4

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 12 (Details) (USD $)	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2011
In Thousands, unless otherwise specified
Pension Plans [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value measurements of plan assets	$345,443		$274,130		$247,959
Derivative Assets, fair value measurements	4,186		3,027		'
Cash margin payable	5,480		2,750		'
Pension Plans [Member] | Cash and cash equivalents [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value measurements of plan assets	18,177		57,614		'
Pension Plans [Member] | Stock/Bond mutual fund [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value measurements of plan assets	115,817		'		'
Pension Plans [Member] | U.S. bond mutual funds [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value measurements of plan assets	17,682		36,767		'
Pension Plans [Member] | U.S. government [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value measurements of plan assets	55,743		57,925		'
Pension Plans [Member] | U.S. corporate [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value measurements of plan assets	110,925		93,169		'
Pension Plans [Member] | U.S. municipal [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value measurements of plan assets	6,799		9,493		'
Pension Plans [Member] | International [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value measurements of plan assets	21,594		18,885		'
Pension Plans [Member] | Derivative instrument [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value measurements of plan assets	-1,294	[1]	277	[2]	'
Pension Plans [Member] | Quoted Prices in Active Markets (Level 1) [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value measurements of plan assets	35,859		94,381		'
Pension Plans [Member] | Quoted Prices in Active Markets (Level 1) [Member] | Cash and cash equivalents [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value measurements of plan assets	18,177		57,614		'
Pension Plans [Member] | Quoted Prices in Active Markets (Level 1) [Member] | U.S. bond mutual funds [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value measurements of plan assets	17,682		36,767		'
Pension Plans [Member] | Significant Observable Inputs (Level 2) [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value measurements of plan assets	309,584		179,749		'
Pension Plans [Member] | Significant Observable Inputs (Level 2) [Member] | Stock/Bond mutual fund [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value measurements of plan assets	115,817		'		'
Pension Plans [Member] | Significant Observable Inputs (Level 2) [Member] | U.S. government [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value measurements of plan assets	55,743		57,925		'
Pension Plans [Member] | Significant Observable Inputs (Level 2) [Member] | U.S. corporate [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value measurements of plan assets	110,925		93,169		'
Pension Plans [Member] | Significant Observable Inputs (Level 2) [Member] | U.S. municipal [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value measurements of plan assets	6,799		9,493		'
Pension Plans [Member] | Significant Observable Inputs (Level 2) [Member] | International [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value measurements of plan assets	21,594		18,885		'
Pension Plans [Member] | Significant Observable Inputs (Level 2) [Member] | Derivative instrument [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value measurements of plan assets	-1,294	[1]	277	[2]	'
Postretirement Plans [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value measurements of plan assets	111,645		67,442		51,744
Postretirement Plans [Member] | Cash and cash equivalents [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value measurements of plan assets	1,411		1,106		'
Postretirement Plans [Member] | Stock/Bond mutual fund [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value measurements of plan assets	110,234		66,336		'
Postretirement Plans [Member] | Quoted Prices in Active Markets (Level 1) [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value measurements of plan assets	111,645		67,442		'
Postretirement Plans [Member] | Quoted Prices in Active Markets (Level 1) [Member] | Cash and cash equivalents [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value measurements of plan assets	1,411		1,106		'
Postretirement Plans [Member] | Quoted Prices in Active Markets (Level 1) [Member] | Stock/Bond mutual fund [Member]	'		'		'
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'		'		'
Fair value measurements of plan assets	$110,234		$66,336		'
[1]	Derivative assets of $4,186 net of cash margin payable of $5,480.
[2]	Derivative assets of $3,027 net of cash margin payable of $2,750.

Recovered_Sheet5

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 13 (Details) (USD $)	12 Months Ended								12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011	Dec. 31, 2010	Aug. 01, 2007	Dec. 31, 2010	Aug. 01, 2007	Feb. 20, 2010	Sep. 30, 2013
						Laclede Gas [Member]	Laclede Gas [Member]	Missouri Gas Energy (MGE) [Member]	Postretirement Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]	'	'	'	'	'	'	'	'	'
Extent of Lump-sum payments recognized, percentage	100.00%	'	'	'	'	'	'	'	'
Lump-sum payments recognized as settlements	$79,484,000	$60,085,000	$2,300,000	'	'	'	'	'	'
Implementation period used to calculate return on plan assets (in years)	'4 years	'	'	'	'	'	'	'	'
Gains or losses includible in cost amortized to extent exceeds benefit obligations or market-related value of plan assets, percentage.	10.00%	'	'	'	'	'	'	'	'
Recovery in rates for the qualified pension plans base allowance	'	'	'	'	'	15,500,000	4,800,000	10,000,000	'
Recovery in rates for postretirement benefit	'	'	'	9,500,000	7,600,000	'	'	'	'
Anticipated Contributions to pension plans for qualified trust	24,000,000	'	'	'	'	'	'	'	'
Anticipated contributions to pension plans for non-qualified plans	400,000	'	'	'	'	'	'	'	'
Medical insurance available until age is reached after early retirement	'65 years	'	'	'	'	'	'	'	'
Amortization period for transition obligation excluded from postretirement benefit cost (in years)	'20 years	'	'	'	'	'	'	'	'
Anticipated contributions to the postretirement plans for qualified trusts	'	'	'	'	'	'	'	'	19,200,000
Anticipated payment directly to participants in postretirement plan	'	'	'	'	'	'	'	'	300,000
Current investment policy targets an asset allocation to equity securities	'	'	'	'	'	'	'	'	60.00%
Investment policy targets asset allocation to debt securities	'	'	'	'	'	'	'	'	40.00%
Other Plans [Abstract]	'	'	'	'	'	'	'	'	'
401(K) plans, cost of defined contributions	$5,000,000	$3,800,000	$3,600,000	'	'	'	'	'	'

STOCKBASED_COMPENSATION_Detail

STOCK-BASED COMPENSATION (Details) (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Number of shares of common stock that may be issued (in shares)	1,250,000	'	'
Stock Option Awards [Abstract]	'	'	'
Common stock closing price (per share)	$45	'	'
Fair Value Assumptions and Methodology [Abstract]	'	'	'
Risk free interest rate	0.32%	0.39%	0.79%
Expected dividend yield of stock	0.00%	0.00%	0.00%
Expected volatility of stock	19.60%	23.21%	33.42%
Vesting period	'2 years 9 months 18 days	'2 years 9 months 18 days	'2 years 9 months 18 days
Total equity compensation cost	$4,453,000	$2,707,000	$3,980,000
Compensation cost capitalized	-1,366,000	-808,000	-924,000
Compensation cost recognized in net income	3,087,000	1,899,000	3,056,000
Income tax benefit recognized in net income	-1,182,000	-733,000	-1,179,000
Compensation cost recognized in net income, net of income tax	1,905,000	1,166,000	1,877,000
Total unrecognized compensation cost	4,900,000	'	'
Weighted average period cost to be recognized (in years)	'2 years	'	'
Restricted Stock Awards [Member]	'	'	'
Restricted Stock Awards [Abstract]	'	'	'
Vested (in shares)	91,221	90,839	94,500
Vested restricted stock withheld for tax withholding obligations (in shares)	23,311	30,052	32,373
Vested restricted stock withheld for tax withholding obligations, weighted average price (in dollars per share)	$39.96	$40.02	$35.90
Fair value, restricted stock	3,800,000	4,200,000	3,600,000
Actual tax benefit realized	1,400,000	1,600,000	1,400,000
Shares/ Units	'	'	'
Vested (in shares)	-91,221	-90,839	-94,500
Stock Option Awards [Abstract]	'	'	'
Actual tax benefit realized	1,400,000	1,600,000	1,400,000
Restricted Stock Awards [Member] | Time Vested Restricted Stock and Time Vested Restricted Stock Units [Member]	'	'	'
Restricted Stock Awards [Abstract]	'	'	'
Granted (in shares)	59,124	'	'
Granted, weighted average grant date fair value (per share)	$40	'	'
Vested (in shares)	43,785	'	'
Shares/ Units	'	'	'
Nonvested at September 30, 2012 (in shares)	115,115	'	'
Granted (in shares)	59,124	'	'
Vested (in shares)	-43,785	'	'
Forfeited (in shares)	-11,050	'	'
Nonvested at September 30, 2013 (in shares)	119,404	'	'
Weighted Average Grant Date Fair Value	'	'	'
Nonvested at September 30, 2012 (in dollars per share)	$36.54	'	'
Granted (in dollars per share)	$40	'	'
Vested (in dollars per share)	$34.95	'	'
Forfeited (in dollars per share)	$38.61	'	'
Nonvested at September 30, 2013 (in dollars per share)	$38.64	'	'
Restricted Stock Awards [Member] | Non Employee Directors [Member] | Time Vested Restricted Stock and Time Vested Restricted Stock Units [Member]	'	'	'
Restricted Stock Awards [Abstract]	'	'	'
Granted (in shares)	15,200	'	'
Granted, weighted average grant date fair value (per share)	$39.92	$41.36	$39.48
Shares/ Units	'	'	'
Granted (in shares)	15,200	'	'
Weighted Average Grant Date Fair Value	'	'	'
Granted (in dollars per share)	$39.92	$41.36	$39.48
Restricted Stock Awards [Member] | Executive Officers and Key Employees [Member] | Performance Contingent Restricted Stock and Stock Units [Member]	'	'	'
Restricted Stock Awards [Abstract]	'	'	'
Granted (in shares)	108,419	'	'
Granted, weighted average grant date fair value (per share)	$34.49	$36.55	$30.68
Vested (in shares)	47,436	'	'
Shares/ Units	'	'	'
Nonvested at September 30, 2012 (in shares)	232,403	'	'
Granted (in shares)	108,419	'	'
Vested (in shares)	-47,436	'	'
Forfeited (in shares)	-51,118	'	'
Nonvested at September 30, 2013 (in shares)	242,268	232,403	'
Weighted Average Grant Date Fair Value	'	'	'
Nonvested at September 30, 2012 (in dollars per share)	$30.89	'	'
Granted (in dollars per share)	$34.49	$36.55	$30.68
Vested (in dollars per share)	$27.61	'	'
Forfeited (in dollars per share)	$26.11	'	'
Nonvested at September 30, 2013 (in dollars per share)	$34.15	$30.89	'
Restricted Stock Awards [Member] | Executive Officers and Key Employees [Member] | Time Vested Restricted Stock and Time Vested Restricted Stock Units [Member]	'	'	'
Restricted Stock Awards [Abstract]	'	'	'
Granted (in shares)	43,924	'	'
Granted, weighted average grant date fair value (per share)	$40.03	$39.72	$35.93
Shares/ Units	'	'	'
Granted (in shares)	43,924	'	'
Weighted Average Grant Date Fair Value	'	'	'
Granted (in dollars per share)	$40.03	$39.72	$35.93
Stock Option Awards [Member]	'	'	'
Restricted Stock Awards [Abstract]	'	'	'
Actual tax benefit realized	400,000	400,000	100,000
Stock Options	'	'	'
Outstanding at September 30, 2012 (in shares)	214,000	'	'
Granted (in shares)	0	'	'
Exercised (in shares)	-80,500	'	'
Forfeited (in shares)	0	'	'
Expired (in shares)	0	'	'
Outstanding at September 30, 2013 (in shares)	133,500	214,000	'
Fully Vested and Expected to Vest at September 30, 2013 (in shares)	133,500	'	'
Exercisable at September 30, 2013 (in shares)	133,500	'	'
Weighted Average Exercise Price	'	'	'
Outstanding at September 30, 2012 (in dollars per share)	$31.02	'	'
Granted (in dollars per share)	$0	'	'
Exercised (in dollars per share)	$29.61	'	'
Forfeited (in dollars per share)	$0	'	'
Expired (in dollars per share)	$0	'	'
Outstanding at September 30, 2013 (in dollars per share)	$31.87	$31.02	'
Fully Vested and Expected to Vest at September 30, 2013 (in dollars per share)	$31.87	'	'
Exercisable at September 30, 2013 (in dollars per share)	$31.87	'	'
Stock Options (Additional Information)	'	'	'
Outstanding at End of Period, weighted average remaining contractual term - stock options (in years)	'2 years 9 months 18 days	'	'
Fully Vested and Expected to Vest at End of Period, weighted average remaining contractual term - stock options (in years)	'2 years 9 months 18 days	'	'
Exercisable at End of Period, weighted average remaining contractual term - stock options (in years)	'2 years 9 months 18 days	'	'
Outstanding Ending Balance, aggregate intrinsic value - stock options	1,752,000	'	'
Fully Vested and Expected to Vest at End of Period, aggregate intrinsic value - stock options	1,752,000	'	'
Exercisable at End of Period, aggregate intrinsic value - stock options	1,752,000	'	'
Stock Option Awards [Abstract]	'	'	'
Exercise price range , minimum (in dollars per share)	$28.85	'	'
Exercise price range , maximum (in dollars per share)	$34.95	'	'
Cash received from the exercise of stock options	2,700,000	2,500,000	900,000
Intrinsic value of exercised	1,000,000	1,000,000	200,000
Actual tax benefit realized	$400,000	$400,000	$100,000
Minimum [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Vesting period, minimum (in years)	'3 years	'	'

EARNINGS_PER_COMMON_SHARE_Deta

EARNINGS PER COMMON SHARE (Details) (USD $)

3 Months Ended

12 Months Ended

In Thousands, except Per Share data, unless otherwise specified

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2011

Basic EPS:

'

'

'

'

'

'

'

'

'

'

'

Net income

($9,636)

[1]

$6,584

$30,242

$25,568

($651)

$8,433

$29,684

$25,174

$52,758

$62,640

$63,825

Less: Income allocated to participating securities

'

'

'

'

'

'

'

'

245

340

497

Net Income Available to Common Shareholders

'

'

'

'

'

'

'

'

52,513

62,300

63,328

Weighted Average Shares Outstanding, Basic (in Shares)

'

'

'

'

'

'

'

'

25,875

22,262

22,099

Basic Earnings Per Share of Common Stock (in dollars per share)

($0.30)

[1]

$0.25

$1.34

$1.14

($0.03)

$0.38

$1.33

$1.13

$2.03

$2.80

$2.87

Diluted EPS:

'

'

'

'

'

'

'

'

'

'

'

Net Income (Loss)

-9,636

[1]

6,584

30,242

25,568

-651

8,433

29,684

25,174

52,758

62,640

63,825

Less: Income allocated to participating securities

'

'

'

'

'

'

'

'

-245

-340

-496

Net Income Available to Common Shareholders

'

'

'

'

'

'

'

'

$52,513

$62,300

$63,329

Weighted Average Shares Outstanding, Basic (in Shares)

'

'

'

'

'

'

'

'

25,875

22,262

22,099

Dilutive Effect of Stock Options, Restricted Stock, and Restricted Stock Units

'

'

'

'

'

'

'

'

77

78

72

Weighted Average Diluted Shares (in shares)

'

'

'

'

'

'

'

'

25,952

22,340

22,171

Diluted Earnings Per Share of Common Stock (in dollars per share)

($0.30)

[1]

$0.25

$1.34

$1.14

($0.03)

$0.38

$1.32

$1.12

$2.02

$2.79

$2.86

Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Outstanding shares excluded from calculation of diluted EPS (in shares)

'

'

'

'

'

'

'

'

188

195

203

Antidilutive Stock Options [Member]

'

'

'

'

'

'

'

'

'

'

'

Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Outstanding shares excluded from calculation of diluted EPS (in shares)

'

'

'

'

'

'

'

'

0

0

0

Restricted Stock and Stock Units subject to performance and/or market conditions [Member]

'

'

'

'

'

'

'

'

'

'

'

Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Outstanding shares excluded from calculation of diluted EPS (in shares)

'

'

'

'

'

'

'

'

188

195

203

[1]

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

STOCKHOLDERS_EQUITY_Details

STOCKHOLDER'S EQUITY (Details) (USD $)

1 Months Ended

12 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

31-May-13

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2011

Jun. 30, 2013

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Nov. 26, 2013

Aug. 13, 2013

Sep. 30, 2013

Nov. 26, 2013

Net Unrealized Gains (Losses) on Cash Flow Hedges [Member]

Net Unrealized Gains (Losses) on Cash Flow Hedges [Member]

Defined Benefit Pension and Other Postretirement Benefit Plans [Member]

Defined Benefit Pension and Other Postretirement Benefit Plans [Member]

Subsequent Event [Member]

Laclede Gas [Member]

Laclede Gas [Member]

Laclede Gas [Member]

Subsequent Event [Member]

Accumulated other comprehensive income (loss), net of income taxes [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

Common stock, issued (in shares)

'

32,700,000

22,540,000

'

'

'

'

'

'

'

'

'

'

Increase in common stock and paid-in capital

'

$435,800,000

$5,000,000

'

'

'

'

'

'

'

'

'

'

Shares issued - dividend reinvestment plan and stock purchase plan (in shares)

'

44,074

46,107

'

'

'

'

'

'

'

'

'

'

Shares issued - dividend reinvestment plan and stock purchase plan

'

1,847,000

1,841,000

1,614,000

'

'

'

'

'

'

'

'

'

Shares issued - Equity plan and stock-based compensation costs

'

434,000,000

3,200,000

'

'

'

'

'

'

'

'

'

'

Stock Issued During Period, Shares, Share-based Compensation, Gross

10,005,000

'

'

'

'

'

'

'

'

'

'

'

'

Shares issued - Equity plan and stock-based compensation costs (in shares)

'

108,331

62,590

'

'

'

'

'

'

'

'

'

'

Dividend payment restriction formula component - fixed amount

'

8,000,000

'

'

'

'

'

'

'

'

'

'

'

Dividend payment restriction formula resulting calculation - available to pay dividends in period

'

833,000,000

355,000,000

'

'

'

'

'

'

'

'

'

'

SEC effective shelf registration Form S-3 sale and issuance authorization under the dividend reinvestment and stock purchase program (in shares)

'

285,222

'

'

'

'

'

'

'

'

'

'

'

SEC effective shelf registration Form S-3 remaining and available for issuance under the dividend reinvestment and stock purchase program (in shares)

'

194,246

'

'

'

'

'

'

'

186,919

'

'

'

Issuance of first mortgage bonds

'

550,000,000

0

0

'

'

'

'

'

'

450,000,000

'

'

MoPSC authorized debt issuance through June 30, 2013 - maximum available

'

'

'

'

518,000,000

'

'

'

'

'

'

518,000,000

'

Extension period for debt securities and preferred stock issuance authority

'

'2 years

'

'

'

'

'

'

'

'

'

'2 years

'

MoPSC authorized debt issuance - remaining available

'

370,800,000

'

'

'

'

'

'

'

'

'

'

370,800,000

Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

Balance, beginning balance

'

-4,116,000

-2,100,000

'

'

-1,886,000

320,000

-2,230,000

-2,420,000

'

'

'

'

Current-period change

'

3,329,000

-2,016,000

5,037,000

'

3,281,000

-2,206,000

48,000

190,000

'

'

'

'

Balance, ending balance

'

($787,000)

($4,116,000)

($2,100,000)

'

$1,395,000

($1,886,000)

($2,182,000)

($2,230,000)

'

'

'

'

LONGTERM_DEBT_Part_1_Maturitie

LONG-TERM DEBT Part 1 - Maturities of Long-term Debt (Details) (USD $)	Sep. 30, 2013
In Millions, unless otherwise specified
Maturities on long-term debt [Abstract]	'
2014	$0
2015	0
2016	0
2017	0
2018	$100

LONGTERM_DEBT_Part_2_Narrative

LONG-TERM DEBT Part 2 - Narrative (Details) (USD $)

12 Months Ended

12 Months Ended

0 Months Ended

0 Months Ended

0 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2011

Jun. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2012

Nov. 26, 2013

Aug. 13, 2013

Mar. 15, 2013

Oct. 15, 2012

Dec. 14, 2012

Sep. 30, 2013

Sep. 30, 2012

Mar. 15, 2013

Sep. 30, 2013

Sep. 30, 2012

Mar. 15, 2013

Sep. 30, 2013

Sep. 30, 2012

Aug. 13, 2013

Sep. 30, 2013

Sep. 30, 2012

Aug. 13, 2013

Sep. 30, 2013

Sep. 30, 2012

Aug. 13, 2013

No Call Options [Member]

Make Whole Call Options [Member]

Callable at par in 2013 [Member]

Callable at par in 2013 [Member]

Laclede Gas [Member]

Laclede Gas [Member]

Laclede Gas [Member]

First Mortgage [Member]

First Mortgage [Member]

First Mortgage Bonds 6.5% Series, due October 15, 2012 [Member]

3.31% Notes Payable, due December 15, 2022 [Member]

First Mortage Bonds 3% Series, due March 15, 2023 [Member]

First Mortage Bonds 3% Series, due March 15, 2023 [Member]

First Mortage Bonds 3% Series, due March 15, 2023 [Member]

First Mortage Bonds 3.40% Series, due March 15, 2028 [Member]

First Mortage Bonds 3.40% Series, due March 15, 2028 [Member]

First Mortage Bonds 3.40% Series, due March 15, 2028 [Member]

First Mortage Bonds 2% Series, due August 15, 2018 [Member]

First Mortage Bonds 2% Series, due August 15, 2018 [Member]

First Mortage Bonds 2% Series, due August 15, 2018 [Member]

First Mortage Bonds 3.40% Series, due August 15, 2023 [Member]

First Mortage Bonds 3.40% Series, due August 15, 2023 [Member]

First Mortage Bonds 3.40% Series, due August 15, 2023 [Member]

First Mortage Bonds 4.625% Series, due August 15, 2043 [Member]

First Mortage Bonds 4.625% Series, due August 15, 2043 [Member]

First Mortage Bonds 4.625% Series, due August 15, 2043 [Member]

Three to six months prior to maturity [Member]

Beginning October 2013 [Member]

Subsequent Event [Member]

Laclede Gas [Member]

Laclede Gas [Member]

First Mortgage [Member]

Unsecured Debt [Member]

Laclede Gas [Member]

Laclede Gas [Member]

First Mortgage [Member]

Laclede Gas [Member]

Laclede Gas [Member]

First Mortgage [Member]

Laclede Gas [Member]

Laclede Gas [Member]

First Mortgage [Member]

Laclede Gas [Member]

Laclede Gas [Member]

First Mortgage [Member]

Laclede Gas [Member]

Laclede Gas [Member]

First Mortgage [Member]

Laclede Gas [Member]

Laclede Gas [Member]

Laclede Gas [Member]

Laclede Gas [Member]

Laclede Gas [Member]

Laclede Gas [Member]

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maturity of first mortgage bonds

$25,000,000

$0

$25,000,000

'

'

'

'

'

'

'

'

'

'

$25,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Stated interest rate on debt issued

'

'

'

'

'

'

'

'

'

'

'

'

'

6.50%

3.31%

3.00%

3.00%

3.00%

3.40%

3.40%

3.40%

2.00%

2.00%

2.00%

3.40%

3.40%

3.40%

4.63%

4.63%

4.63%

Debt issued, maturity term

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'10 years

'

'

'10 years

'

'

'15 years

'

'

'

'

'

'

'

'

'

Issuance of debt

'

'

'

'

'

'

'

'

'

'

'

450,000,000

100,000,000

'

25,000,000

'

'

55,000,000

'

'

45,000,000

'

'

100,000,000

'

'

250,000,000

'

'

100,000,000

Fixed-rate long-term debt amount

915,000,000

'

'

'

50,000,000

435,000,000

350,000,000

80,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

MoPSC authorized debt issuance through June 30, 2013 - maximum available

'

'

'

518,000,000

'

'

'

'

518,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Extension period for debt securities and preferred stock issuance authority

'2 years

'

'

'

'

'

'

'

'2 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

MoPSC authorized debt issuance - remaining available

$370,800,000

'

'

'

'

'

'

'

'

'

$370,800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred stock shares authorized (in shares)

'

'

'

'

'

'

'

'

1,480,000

1,480,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

NOTES_PAYABLE_AND_CREDIT_AGREE2

NOTES PAYABLE AND CREDIT AGREEMENTS (Details) (USD $)	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 03, 2013	Sep. 30, 2013	Sep. 03, 2013	Sep. 30, 2013	Sep. 30, 2012
			Laclede Gas [Member]	Laclede Gas [Member]	Laclede Group [Member]	Laclede Group [Member]	Laclede Group [Member]	Laclede Group [Member]
			Line of Credit [Member]	Line of Credit [Member]	Line of Credit [Member]	Line of Credit [Member]	Commercial Paper [Member]	Commercial Paper [Member]
				bank
Line of Credit Facility [Line Items]	'	'	'	'	'	'	'	'
Line of credit facility borrowing capacity	'	'	'	$450,000,000	'	$150,000,000	'	'
Banks in syndicated line of credit facility	'	'	'	9	'	'	'	'
Banks in syndicated line of credit facility, largest borrowing portion provided by a single bank	'	'	'	15.60%	'	'	'	'
Minimum required ratio of earnings before interest, taxes, depreciation, and amortization (EBITDA) times interest expense as required by the line of credit covenant.	'	'	'	70.00%	'	70.00%	'	'
Debt to total capitalization ratio	'	'	48.00%	'	49.00%	'	'	'
Weighted average borrowings outstanding	'	'	'	'	'	'	34,200,000	43,800,000
Weighted average interest rate	'	'	'	'	'	'	0.30%	0.30%
Short term borrowings outstanding in the period - minimum	'	'	'	'	'	'	0	0
Short term borrowings outstanding in the period - maximum	'	'	'	'	'	'	99,400,000	133,500,000
Borrowings outstanding at end of period	$74,000,000	$40,100,000	'	'	'	'	$74,000,000	$40,100,000
Weighted average interest rate at period end	'	'	'	'	'	'	0.30%	0.20%

FAIR_VALUE_OF_FINANCIAL_INSTRU2

FAIR VALUE OF FINANCIAL INSTRUMENTS (Details) (USD $)	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011	Sep. 30, 2010
In Thousands, unless otherwise specified
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'	'	'
Cash and cash equivalents	$52,981	$27,457	$43,277	$86,919
Carrying Amount [Member]	'	'	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'	'	'
Cash and cash equivalents	52,981	27,457	'	'
Short-term debt	74,000	40,100	'	'
Long-term debt, including current portion	912,712	364,416	'	'
Fair Value [Member]	'	'	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'	'	'
Cash and cash equivalents	52,981	27,457	'	'
Short-term debt	74,000	40,100	'	'
Long-term debt, including current portion	954,126	452,768	'	'
Quoted Prices in Active Markets (Level 1) [Member]	'	'	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'	'	'
Cash and cash equivalents	52,824	17,380	'	'
Short-term debt	0	0	'	'
Long-term debt, including current portion	0	0	'	'
Significant Observable Inputs (Level 2) [Member]	'	'	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'	'	'
Cash and cash equivalents	157	10,077	'	'
Short-term debt	74,000	40,100	'	'
Long-term debt, including current portion	954,126	452,768	'	'
Significant Unobservable Inputs (Level 3) [Member]	'	'	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'	'	'
Cash and cash equivalents	0	0	'	'
Short-term debt	0	0	'	'
Long-term debt, including current portion	$0	$0	'	'

FAIR_VALUE_MEASUREMENTS_Detail

FAIR VALUE MEASUREMENTS (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]	'	'
Beginning of period	$109	$13
Settlements	-269	-54
Net losses related to derivatives not held at end of period	-99	-68
Net gains related to derivatives still held at end of period	369	218
End of period	110	109
Fair Value, Measurements, Recurring [Member]	'	'
Assets	'	'
U. S. Stock/Bond Mutual Funds	14,500	13,187
NYMEX/ICE natural gas contracts	2,518	0
OTCBB natural gas contracts	0	'
NYMEX gasoline and heating oil contracts	0	0
Natural gas commodity contracts	784	2,874
Total	17,802	16,061
Liabilities	'	'
NYMEX/ICE natural gas contracts	0	0
OTCBB natural gas contracts	5,211	'
NYMEX gasoline and heating oil contracts	0	0
Natural gas commodity contracts	685	133
Total	5,896	133
Fair Value, Measurements, Recurring [Member] | Quoted Prices in Active Markets (Level 1) [Member]	'	'
Assets	'	'
U. S. Stock/Bond Mutual Funds	14,500	13,187
NYMEX/ICE natural gas contracts	4,333	7,411
OTCBB natural gas contracts	0	'
NYMEX gasoline and heating oil contracts	105	344
Natural gas commodity contracts	0	0
Total	18,938	20,942
Liabilities	'	'
NYMEX/ICE natural gas contracts	3,687	12,253
OTCBB natural gas contracts	0	'
NYMEX gasoline and heating oil contracts	0	0
Natural gas commodity contracts	0	0
Total	3,687	12,253
Fair Value, Measurements, Recurring [Member] | Significant Observable Inputs (Level 2) [Member]	'	'
Assets	'	'
U. S. Stock/Bond Mutual Funds	0	0
NYMEX/ICE natural gas contracts	330	994
OTCBB natural gas contracts	232	'
NYMEX gasoline and heating oil contracts	0	0
Natural gas commodity contracts	1,129	3,060
Total	1,691	4,054
Liabilities	'	'
NYMEX/ICE natural gas contracts	321	1,891
OTCBB natural gas contracts	5,443	'
NYMEX gasoline and heating oil contracts	0	0
Natural gas commodity contracts	1,140	428
Total	6,904	2,319
Fair Value, Measurements, Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member]	'	'
Assets	'	'
U. S. Stock/Bond Mutual Funds	0	0
NYMEX/ICE natural gas contracts	0	0
OTCBB natural gas contracts	0	'
NYMEX gasoline and heating oil contracts	0	0
Natural gas commodity contracts	150	113
Total	150	113
Liabilities	'	'
NYMEX/ICE natural gas contracts	0	0
OTCBB natural gas contracts	0	'
NYMEX gasoline and heating oil contracts	0	0
Natural gas commodity contracts	40	4
Total	40	4
Fair Value, Measurements, Recurring [Member] | Effects of Netting and Cash Margin Receivables /Payables	'	'
Assets	'	'
U. S. Stock/Bond Mutual Funds	0	0
NYMEX/ICE natural gas contracts	-2,145	-8,405
OTCBB natural gas contracts	-232	'
NYMEX gasoline and heating oil contracts	-105	-344
Natural gas commodity contracts	-495	-299
Total	-2,977	-9,048
Liabilities	'	'
NYMEX/ICE natural gas contracts	-4,008	-14,144
OTCBB natural gas contracts	-232	'
NYMEX gasoline and heating oil contracts	0	0
Natural gas commodity contracts	-495	-299
Total	($4,735)	($14,443)

DERIVATIVE_INSTRUMENTS_AND_HED2

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES Part 1 (Details) (USD $)

12 Months Ended

0 Months Ended

0 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2011

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2012

Aug. 06, 2013

Feb. 28, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Aug. 13, 2013

gal

Designated as Hedging Instrument [Member]

Designated as Hedging Instrument [Member]

Not Designated as Hedging Instrument [Member]

Not Designated as Hedging Instrument [Member]

NYMEX Natural Gas Contracts [Member]

NYMEX Natural Gas Contracts [Member]

NYMEX Natural Gas Contracts [Member]

NYMEX Natural Gas Contracts [Member]

NYMEX Natural Gas Contracts [Member]

NYMEX Natural Gas Contracts [Member]

NYMEX Natural Gas Contracts [Member]

NYMEX Natural Gas Contracts [Member]

Natural Gas Commodity Contracts [Member]

Natural Gas Commodity Contracts [Member]

Natural Gas Commodity Contracts [Member]

Natural Gas Commodity Contracts [Member]

Natural Gas Commodity Contracts [Member]

Natural Gas Commodity Contracts [Member]

Natural Gas Commodity Contracts [Member]

OTCBB Natural Gas Contracts [Member]

OTCBB Natural Gas Contracts [Member]

NYMEX Gasoline and Heating Oil Contracts [Member]

NYMEX Gasoline and Heating Oil Contracts [Member]

NYMEX Gasoline and Heating Oil Contracts [Member]

Cash Flow Hedging [Member]

Cash Flow Hedging [Member]

Laclede Gas Company [Member]

Laclede Gas Company [Member]

Laclede Gas Company [Member]

Laclede Gas Company [Member]

Laclede Gas Company [Member]

Laclede Gas Company [Member]

Laclede Gas Company [Member]

Laclede Energy Resources [Member]

Laclede Energy Resources [Member]

Laclede Energy Resources [Member]

Laclede Energy Resources [Member]

Laclede Energy Resources [Member]

Laclede Energy Resources [Member]

Laclede Energy Resources [Member]

Laclede Energy Resources [Member]

Laclede Gas [Member]

MMBTU

Designated as Hedging Instrument [Member]

Designated as Hedging Instrument [Member]

Designated as Hedging Instrument [Member]

Not Designated as Hedging Instrument [Member]

Not Designated as Hedging Instrument [Member]

Not Designated as Hedging Instrument [Member]

Not Designated as Hedging Instrument [Member]

Not Designated as Hedging Instrument [Member]

Not Designated as Hedging Instrument [Member]

Not Designated as Hedging Instrument [Member]

Not Designated as Hedging Instrument [Member]

Not Designated as Hedging Instrument [Member]

Not Designated as Hedging Instrument [Member]

Not Designated as Hedging Instrument [Member]

Not Designated as Hedging Instrument [Member]

Not Designated as Hedging Instrument [Member]

Not Designated as Hedging Instrument [Member]

Designated as Hedging Instrument [Member]

Designated as Hedging Instrument [Member]

Not Designated as Hedging Instrument [Member]

Interest Rate Swap [Member]

Interest Rate Swap [Member]

MMBTU

Fiscal 2014 [Member]

Fiscal 2014 [Member]

Fiscal 2014 [Member]

Fiscal 2015 [Member]

Fiscal 2015 [Member]

Fiscal 2015 [Member]

MMBTU

Fiscal 2014 [Member]

Fiscal 2014 [Member]

Fiscal 2014 [Member]

Fiscal 2015 [Member]

Fiscal 2015 [Member]

Fiscal 2015 [Member]

Fiscal 2016 [Member]

Derivative Instruments Assets [Member]

Other Deferred Charges [Member]

Accounts Receivable Other [Member]

Derivative Instruments Assets [Member]

Other Deferred Charges [Member]

Other Deferred Charges [Member]

Accounts Receivable Other [Member]

Accounts Receivable Other [Member]

Derivative Instruments Assets [Member]

Derivative Instruments Assets [Member]

Other Deferred Charges [Member]

Other Deferred Charges [Member]

Other Current Liabilities [Member]

Other Current Liabilities [Member]

Other Deferred Credits [Member]

Other Current Liabilities [Member]

Other Deferred Credits [Member]

Accounts Receivable Other [Member]

Accounts Receivable Other [Member]

Accounts Receivable Other [Member]

Open Short Futures Positions [Member]

NYMEX Natural Gas Contracts [Member]

OTCBB Natural Gas Contracts [Member]

Open Short Futures Positions [Member]

NYMEX Natural Gas Contracts [Member]

OTCBB Natural Gas Contracts [Member]

Open Short Futures Positions [Member]

Open Long Futures Positions [Member]

NYMEX Natural Gas Contracts [Member]

Open Short Futures Positions [Member]

Open Long Futures Positions [Member]

NYMEX Natural Gas Contracts [Member]

Open Long Futures Positions [Member]

MMBTU

Open Long Futures Positions [Member]

Open Long Futures Positions [Member]

MMBTU

Open Long Futures Positions [Member]

Open Long Futures Positions [Member]

MMBTU

MMBTU

Open Long Futures Positions [Member]

MMBTU

MMBTU

Open Long Futures Positions [Member]

MMBTU

MMBTU

MMBTU

MMBTU

MMBTU

MMBTU

MMBTU

Derivative [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum percentage of normal volumes hedged

70.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum number of months normal volumes can be hedged (in months)

'36 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gasoline futures contracts notional amount (in gallons)

300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Average price of gasoline futures contracts (dollars per gallon)

$2.23

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Notional amount of non-exchange traded natural gas commodity contracts (in MMBtu)

67,400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Notional amount of non-exchange traded natural gas commodity contracts to be settled during fiscal 2014

58,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Notional amount of non-exchange traded natural gas commodity contracts to be settled during fiscal 2015

8,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Notional amount of non-exchange traded natural gas commodity contracts to be settled during fiscal 2016

800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Expected pre-tax unrealized gain (loss) reclassifications into the Statements of Consolidated Income during the next twelve months

-2,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

MMBtu

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

7,260,000

16,810,000

0

940,000

7,580,000

'

12,910,000

0

1,710,000

60,000

0

190,000

0

'

Avg. Price Per MMBtu

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

3.99

3.97

0

3.84

4.22

'

3.98

0

3.94

4.21

0

4.06

4.15

'

Contract volumes of NYMEX natural gas option used to mitigate price risk (in MMBtu)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

23,600,000

'

'

'

'

'

'

0

'

'

'

'

'

'

'

'

Derivative notional amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

355,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gain (Loss) on Derivative Instruments, Net, Pretax

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

20,800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Issuance of first mortgage bonds

550,000,000

0

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

450,000,000

Derivatives, Fair Value [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Asset Derivatives

6,276,000

[1]

11,922,000

[1]

'

2,349,000

[1]

739,000

[1]

3,927,000

[1]

11,183,000

[1]

2,222,000

[1]

22,000

[1]

405,000

[1]

950,000

[1]

32,000

[1]

0

[1]

1,434,000

[1]

8,000,000

[1]

991,000

[1]

3,150,000

[1]

20,000

[1]

19,000

[1]

247,000

[1]

4,000

[1]

21,000

[1]

228,000

[1]

4,000

[1]

105,000

[1]

334,000

[1]

10,000

[1]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Liability Derivatives

10,629,000

[1]

14,576,000

'

451,000

[1]

3,413,000

10,178,000

[1]

11,163,000

440,000

[1]

11,000

[1]

3,413,000

100,000

[1]

0

[1]

0

3,455,000

[1]

10,731,000

90,000

[1]

295,000

137,000

[1]

0

830,000

[1]

137,000

123,000

[1]

4,045,000

[1]

1,398,000

[1]

0

[1]

0

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative instrument assets reconciliation [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fair value of asset derivatives presented above

6,276,000

[1]

11,922,000

[1]

'

2,349,000

[1]

739,000

[1]

3,927,000

[1]

11,183,000

[1]

2,222,000

[1]

22,000

[1]

405,000

[1]

950,000

[1]

32,000

[1]

0

[1]

1,434,000

[1]

8,000,000

[1]

991,000

[1]

3,150,000

[1]

20,000

[1]

19,000

[1]

247,000

[1]

4,000

[1]

21,000

[1]

228,000

[1]

4,000

[1]

105,000

[1]

334,000

[1]

10,000

[1]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fair value of cash margin receivables offset with derivatives

1,765,000

5,478,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Netting of assets and liabilities with the same counterparty

-4,739,000

-14,526,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total

3,302,000

2,874,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative Instrument Assets, per Consolidated Balance Sheets:

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative instrument assets

3,291,000

2,855,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Other deferred charges

11,000

19,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total

3,302,000

2,874,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fair value of liability derivatives presented above

10,629,000

[1]

14,576,000

'

451,000

[1]

3,413,000

10,178,000

[1]

11,163,000

440,000

[1]

11,000

[1]

3,413,000

100,000

[1]

0

[1]

0

3,455,000

[1]

10,731,000

90,000

[1]

295,000

137,000

[1]

0

830,000

[1]

137,000

123,000

[1]

4,045,000

[1]

1,398,000

[1]

0

[1]

0

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fair value of cash margin payables offset with derivatives

6,000

83,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Netting of assets and liabilities with the same counterparty

-4,739,000

-14,526,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative instrument liabilities, per Consolidated Balance Sheets

5,896,000

[2]

133,000

[2]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Other current liabilities

4,400,000

133,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Other deferred credits

1,496,000

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Other Receivables from Broker-Dealers and Clearing Organizations

$3,200,000

$10,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

[1]

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

[2]

DERIVATIVE_INSTRUMENTS_AND_HED3

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES Part 2 (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2011
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]	'		'		'
Derivatives in Cash Flow Hedging Relationships [Abstract]	'		'		'
Effective portion of gain (loss) reclassified from AOCI to income	($302)		$8,397		($1,861)
Ineffective portion of gain (loss) on derivatives recognized in income	-786		-124		-344
Designated as Hedging Instrument [Member] | NYMEX Natural Gas Contracts [Member] | Cash Flow Hedging [Member]	'		'		'
Derivatives in Cash Flow Hedging Relationships [Abstract]	'		'		'
Effective portion of gain (loss) reclassified from AOCI to income	-513		8,397		-2,327
Ineffective portion of gain (loss) on derivatives recognized in income	-659		-299		-356
Designated as Hedging Instrument [Member] | NYMEX Natural Gas Contracts [Member] | Other Comprehensive Income (Loss) [Member] | Cash Flow Hedging [Member]	'		'		'
Derivatives in Cash Flow Hedging Relationships [Abstract]	'		'		'
Effective portion of gain (loss) recognized in OCI on derivatives	4,923		4,505		5,226
Designated as Hedging Instrument [Member] | NYMEX Natural Gas Contracts [Member] | Non-Regulated Gas Marketing Operating Revenue [Member] | Cash Flow Hedging [Member]	'		'		'
Derivatives in Cash Flow Hedging Relationships [Abstract]	'		'		'
Effective portion of gain (loss) reclassified from AOCI to income	-4		18,929		7,443
Ineffective portion of gain (loss) on derivatives recognized in income	-420		-36		966
Designated as Hedging Instrument [Member] | NYMEX Natural Gas Contracts [Member] | Non-Regulated Gas Marketing Operating Expenses [Member] | Cash Flow Hedging [Member]	'		'		'
Derivatives in Cash Flow Hedging Relationships [Abstract]	'		'		'
Effective portion of gain (loss) reclassified from AOCI to income	-509		-10,532		-9,770
Ineffective portion of gain (loss) on derivatives recognized in income	-239		-263		-1,322
Designated as Hedging Instrument [Member] | NYMEX Gasoline and Heating Oil Contracts [Member] | Cash Flow Hedging [Member]	'		'		'
Derivatives in Cash Flow Hedging Relationships [Abstract]	'		'		'
Effective portion of gain (loss) recognized in OCI on derivatives	5,046		4,802		5,581
Designated as Hedging Instrument [Member] | NYMEX Gasoline and Heating Oil Contracts [Member] | Other Comprehensive Income (Loss) [Member] | Cash Flow Hedging [Member]	'		'		'
Derivatives in Cash Flow Hedging Relationships [Abstract]	'		'		'
Effective portion of gain (loss) recognized in OCI on derivatives	123		297		355
Designated as Hedging Instrument [Member] | NYMEX Gasoline and Heating Oil Contracts [Member] | Regulated Gas Distribution Other Operation Expenses [Member] | Cash Flow Hedging [Member]	'		'		'
Derivatives in Cash Flow Hedging Relationships [Abstract]	'		'		'
Effective portion of gain (loss) reclassified from AOCI to income	211		0		466
Ineffective portion of gain (loss) on derivatives recognized in income	-127		175		12
Not Designated as Hedging Instrument [Member] | NYMEX Natural Gas Contracts [Member] | Non-Regulated Gas Marketing Operating Revenue [Member]	'		'		'
Derivatives Not Designated as Hedging Instruments [Abstract]	'		'		'
Gain (loss) recognized in income on derivatives	-778	[1]	-615	[1]	-115	[1]
Not Designated as Hedging Instrument [Member] | NYMEX Natural Gas Contracts [Member] | Non-Regulated Gas Marketing Operating Expenses [Member]	'		'		'
Derivatives Not Designated as Hedging Instruments [Abstract]	'		'		'
Gain (loss) recognized in income on derivatives	0	[1]	-625	[1]	-3	[1]
Not Designated as Hedging Instrument [Member] | NYMEX Gasoline and Heating Oil Contracts [Member]	'		'		'
Derivatives Not Designated as Hedging Instruments [Abstract]	'		'		'
Gain (loss) recognized in income on derivatives	-815	[1]	3,248	[1]	3,488	[1]
Not Designated as Hedging Instrument [Member] | NYMEX Gasoline and Heating Oil Contracts [Member] | Other Income and (Income Deduction) - Net [Member]	'		'		'
Derivatives Not Designated as Hedging Instruments [Abstract]	'		'		'
Gain (loss) recognized in income on derivatives	41	[1]	19	[1]	37	[1]
Not Designated as Hedging Instrument [Member] | Natural Gas Commodity Contracts [Member] | Non-Regulated Gas Marketing Operating Revenue [Member]	'		'		'
Derivatives Not Designated as Hedging Instruments [Abstract]	'		'		'
Gain (loss) recognized in income on derivatives	-78	[1]	3,782	[1]	-660	[1]
Not Designated as Hedging Instrument [Member] | Natural Gas Commodity Contracts [Member] | Non-Regulated Gas Marketing Operating Expenses [Member]	'		'		'
Derivatives Not Designated as Hedging Instruments [Abstract]	'		'		'
Gain (loss) recognized in income on derivatives	$0	[1]	$687	[1]	$4,229	[1]
[1]	Gains and losses on the Utility’s natural gas derivative instruments, which are not designated as hedging instruments for financial reporting purposes, are deferred pursuant to the Utility’s PGA Clause and initially recorded as regulatory assets or regulatory liabilities. These gains and losses are excluded from the table above because they have no direct impact on the Statements of Consolidated Income. Such amounts are recognized in the Statements of Consolidated Income as a component of Regulated Gas Distribution Natural and Propane Gas operating expenses when they are recovered through the PGA Clause and reflected in customer billings.

CONCENTRATIONS_OF_CREDIT_RISK_

CONCENTRATIONS OF CREDIT RISK (Details) (USD $)	Sep. 30, 2013
In Millions, unless otherwise specified	counterparty
Concentration Risk [Line Items]	'
Number of large counterparties for which credit risk is disclosed	5
Energy Producers And Their Affiliates [Member]	'
Concentration Risk [Line Items]	'
Accounts receivable	22.8
Utility Companies And Their Affiliates [Member]	'
Concentration Risk [Line Items]	'
Accounts receivable	23.5
Net receivable amount	16.6
Largest Counterparties [Member]	'
Concentration Risk [Line Items]	'
Accounts receivable	16.6
Net receivable amount	14.5

INCOME_TAXES_Details

INCOME TAXES (Details) (USD $)	12 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2011	Sep. 30, 2013	Sep. 03, 2013
						State	State
Federal	'		'		'	'	'
Current	($4,173,000)		($3,835,000)		$4,724,000	'	'
Deferred	19,925,000		26,365,000		20,602,000	'	'
Investment tax credits	-213,000		-213,000		-213,000	'	'
State and local	'		'		'	'	'
Current	-301,000		-430,000		573,000	'	'
Deferred	2,340,000		4,402,000		3,496,000	'	'
Total Income Tax Expense	17,578,000		26,289,000		29,182,000	'	'
Effective income tax rate variance from federal statutory rate [Abstract]	'		'		'	'	'
Federal income tax statutory rate	35.00%		35.00%		35.00%	'	'
State and local income taxes, net of federal income tax benefits	3.50%		2.90%		2.80%	'	'
Certain expenses capitalized on books and deducted on tax return	-9.70%		-6.90%		-5.00%	'	'
Taxes related to prior years	-1.60%		-0.80%		-0.70%	'	'
Other items – net	-2.20%		-0.60%		-0.70%	'	'
Effective income tax rate	25.00%		29.60%		31.40%	'	'
Deferred tax assets:	'		'		'	'	'
Reserves not currently deductible	13,933,000		16,400,000		'	'	'
Pension and other postretirement benefits	71,367,000		73,480,000		'	'	'
Unamortized investment tax credits	1,799,000		1,955,000		'	'	'
Other	12,522,000	[1]	18,224,000	[1]	'	'	'
Total deferred tax assets	99,621,000		110,059,000		'	'	'
Deferred tax liabilities:	'		'		'	'	'
Relating to property	341,975,000		303,474,000		'	'	'
Regulatory pension and other postretirement benefits	124,871,000		121,554,000		'	'	'
Deferred gas costs	7,112,000		20,652,000		'	'	'
Other	5,789,000		26,563,000		'	'	'
Total deferred tax liabilities	479,747,000		472,243,000		'	'	'
Total deferred tax liabilities	380,126,000		362,184,000		'	'	'
Net deferred tax liability - current	-1,012,000	[1]	-6,675,000	[1]	'	'	'
Net deferred tax liability - non-current	379,114,000	[1]	355,509,000	[1]	'	'	'
Unrecognized tax benefits [Roll Forward]	'		'		'	'	'
Unrecognized tax benefits, beginning of year	5,810,000		5,596,000		'	'	'
Increases related to prior year tax positions	145,000		78,000		'	'	'
Increases related to tax positions taken in current year	1,450,000		547,000		'	'	'
Reductions due to lapse of applicable statute of limitations	-5,018,000		-411,000		'	'	'
Unrecognized tax benefits, end of year	2,387,000		5,810,000		5,596,000	'	'
Tax credits included in net deferred tax liability	'		'		'	'	7,100,000
Tax credits classified as current	'		'		'	4,700,000	'
Tax credits classified as noncurrent	'		'		'	2,400,000	'
Unrecognized tax benefits affect on the Company's effective tax rate	1,900,000		1,400,000		'	'	'
Interest accrued associated with uncertain tax positions	100,000		600,000		'	'	'
Interest expense accrued during fiscal year	100,000		200,000		200,000	'	'
Reversal of accrued penalties	$600,000		'		'	'	'
[1]	The Company periodically invests in tax credits. As of September 30, 2013, $7.1 million of state tax credits are included in Other and Net deferred tax liability. $4.7 million of state tax credits were classified as current. $2.4 million of state tax credits were classified as non-current.

OTHER_INCOME_AND_INCOME_DEDUCT2

OTHER INCOME AND (INCOME DEDUCTIONS) - NET (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Other Nonoperating Income (Expense) [Abstract]	'	'	'
Interest income	$1,088	$1,309	$1,136
Net investment gain	2,857	3,124	185
Other income	377	811	118
Other income deductions	-1,878	-1,972	-1,262
Other Income and (Income Deductions) – Net	$2,444	$3,272	$177

INFORMATION_BY_OPERATING_SEGME2

INFORMATION BY OPERATING SEGMENT (Details) (USD $)

3 Months Ended

12 Months Ended

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2011

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2011

subsidiary

subsidiary

Segment Reporting [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Number of entity subsidiaries

7

'

'

'

'

'

'

'

7

'

'

Amount of depreciation and amortization for Non-Regulated Gas Marketing included in Non-Regulated Gas Marketing Expenses on the Statements of Consolidated Income

'

'

'

'

'

'

'

'

$300,000

$300,000

$100,000

Amount of depreciation, amortization, and accretion for Other included in Other Operating Expenses on the Statements of Consolidated Income

'

'

'

'

'

'

'

'

600,000

300,000

200,000

After-tax earnings resulting from the non-regulated sale of propane inventory

'

'

'

'

'

'

'

'

'

'

6,100,000

Reconciliation of Consolidated Net Income to Consolidated Net Economic Earnings

'

'

'

'

'

'

'

'

'

'

'

Net income

-9,636,000

[1]

6,584,000

30,242,000

25,568,000

-651,000

8,433,000

29,684,000

25,174,000

52,758,000

62,640,000

63,825,000

Unrealized loss (gain) on energy-related derivatives

'

'

'

'

'

'

'

'

614,000

-314,000

-1,415,000

Lower of cost or market inventory adjustments

'

'

'

'

'

'

'

'

868,000

0

0

Realized (gain) loss on economic hedges prior to the sale of the physical commodity

'

'

'

'

'

'

'

'

-25,000

163,000

0

Acquisition, divestiture and restructuring activities

'

'

'

'

'

'

'

'

10,797,000

123,000

0

Net Economic Earnings (Non-GAAP)

'

'

'

'

'

'

'

'

65,012,000

62,612,000

62,410,000

Operating Segment Information [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Total revenues including intersegment revenues

'

'

'

'

'

'

'

'

1,017,019,000

1,125,475,000

1,576,360,000

Total Operating Revenues

147,114,000

[1]

165,289,000

397,613,000

307,003,000

169,538,000

186,849,000

358,175,000

410,913,000

1,017,019,000

1,125,475,000

1,603,307,000

Gas Utility

'

'

'

'

'

'

'

'

'

'

'

Natural and propane gas

'

'

'

'

'

'

'

'

433,442,000

397,304,000

549,947,000

Other operation and maintenance expenses

'

'

'

'

'

'

'

'

180,342,000

167,351,000

172,938,000

Depreciation & amortization

'

'

'

'

'

'

'

'

48,283,000

40,739,000

39,214,000

Taxes, other than income taxes

'

'

'

'

'

'

'

'

60,079,000

53,672,000

60,752,000

Total Gas Utility Operating Expenses

'

'

'

'

'

'

'

'

722,146,000

659,066,000

822,851,000

Gas Marketing

'

'

'

'

'

'

'

'

176,554,000

353,283,000

652,567,000

Other

'

'

'

'

'

'

'

'

21,825,000

2,524,000

9,642,000

Costs and Expenses

'

'

'

'

'

'

'

'

920,525,000

1,014,873,000

1,485,060,000

Operating Income

-9,722,000

[1]

12,282,000

51,849,000

42,085,000

1,869,000

15,045,000

50,583,000

43,105,000

96,494,000

110,602,000

118,247,000

Interest income

'

'

'

'

'

'

'

'

1,088,000

1,309,000

1,136,000

Interest charges

'

'

'

'

'

'

'

'

28,602,000

24,945,000

25,417,000

Income Tax Expense

'

'

'

'

'

'

'

'

17,578,000

26,289,000

29,182,000

Net Economic Earnings (Non-GAAP)

'

'

'

'

'

'

'

'

65,012,000

62,612,000

62,410,000

Total assets

3,125,386,000

'

'

'

1,880,262,000

'

'

'

3,125,386,000

1,880,262,000

1,783,082,000

Capital expenditures

'

'

'

'

'

'

'

'

130,788,000

108,843,000

67,638,000

Intersegment Revenues [Member]

'

'

'

'

'

'

'

'

'

'

'

Operating Segment Information [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Total revenues including intersegment revenues

'

'

'

'

'

'

'

'

0

0

26,947,000

Gas Utility [Member]

'

'

'

'

'

'

'

'

'

'

'

Reconciliation of Consolidated Net Income to Consolidated Net Economic Earnings

'

'

'

'

'

'

'

'

'

'

'

Net Economic Earnings (Non-GAAP)

'

'

'

'

'

'

'

'

56,635,000

48,089,000

46,952,000

Operating Segment Information [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Total revenues including intersegment revenues

'

'

'

'

'

'

'

'

847,224,000

763,447,000

911,614,000

Total Operating Revenues

'

'

'

'

'

'

'

'

857,762,000

764,651,000

913,190,000

Gas Utility

'

'

'

'

'

'

'

'

'

'

'

Natural and propane gas

'

'

'

'

'

'

'

'

469,098,000

414,846,000

549,947,000

Other operation and maintenance expenses

'

'

'

'

'

'

'

'

180,702,000

167,351,000

172,938,000

Depreciation & amortization

'

'

'

'

'

'

'

'

48,283,000

40,739,000

39,214,000

Taxes, other than income taxes

'

'

'

'

'

'

'

'

60,079,000

53,672,000

60,752,000

Total Gas Utility Operating Expenses

'

'

'

'

'

'

'

'

758,162,000

676,608,000

822,851,000

Gas Marketing

'

'

'

'

'

'

'

'

0

0

0

Other

'

'

'

'

'

'

'

'

0

0

0

Costs and Expenses

'

'

'

'

'

'

'

'

758,162,000

676,608,000

822,851,000

Operating Income

'

'

'

'

'

'

'

'

99,599,000

88,043,000

90,339,000

Interest income

'

'

'

'

'

'

'

'

947,000

1,230,000

1,057,000

Interest charges

'

'

'

'

'

'

'

'

26,137,000

25,156,000

25,544,000

Income Tax Expense

'

'

'

'

'

'

'

'

19,243,000

17,393,000

18,694,000

Net Economic Earnings (Non-GAAP)

'

'

'

'

'

'

'

'

56,635,000

48,089,000

46,952,000

Total assets

2,981,016,000

'

'

'

1,758,952,000

'

'

'

2,981,016,000

1,758,952,000

1,641,386,000

Capital expenditures

'

'

'

'

'

'

'

'

128,496,000

106,734,000

67,304,000

Gas Utility [Member] | Intersegment Revenues [Member]

'

'

'

'

'

'

'

'

'

'

'

Operating Segment Information [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Total revenues including intersegment revenues

'

'

'

'

'

'

'

'

10,538,000

1,204,000

1,576,000

Gas Marketing [Member]

'

'

'

'

'

'

'

'

'

'

'

Reconciliation of Consolidated Net Income to Consolidated Net Economic Earnings

'

'

'

'

'

'

'

'

'

'

'

Net Economic Earnings (Non-GAAP)

'

'

'

'

'

'

'

'

8,936,000

12,273,000

8,962,000

Operating Segment Information [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Total revenues including intersegment revenues

'

'

'

'

'

'

'

'

165,146,000

358,145,000

645,042,000

Total Operating Revenues

'

'

'

'

'

'

'

'

189,331,000

373,475,000

669,375,000

Gas Utility

'

'

'

'

'

'

'

'

'

'

'

Natural and propane gas

'

'

'

'

'

'

'

'

0

0

0

Other operation and maintenance expenses

'

'

'

'

'

'

'

'

0

0

0

Depreciation & amortization

'

'

'

'

'

'

'

'

0

0

0

Taxes, other than income taxes

'

'

'

'

'

'

'

'

0

0

0

Total Gas Utility Operating Expenses

'

'

'

'

'

'

'

'

0

0

0

Gas Marketing

'

'

'

'

'

'

'

'

176,554,000

[2]

353,286,000

[2]

652,567,000

[2]

Other

'

'

'

'

'

'

'

'

0

0

0

Costs and Expenses

'

'

'

'

'

'

'

'

176,554,000

353,286,000

652,567,000

Operating Income

'

'

'

'

'

'

'

'

12,777,000

20,189,000

16,808,000

Interest income

'

'

'

'

'

'

'

'

103,000

175,000

165,000

Interest charges

'

'

'

'

'

'

'

'

135,000

81,000

14,000

Income Tax Expense

'

'

'

'

'

'

'

'

5,162,000

7,966,000

6,570,000

Net Economic Earnings (Non-GAAP)

'

'

'

'

'

'

'

'

8,936,000

12,273,000

8,962,000

Total assets

163,944,000

'

'

'

190,709,000

'

'

'

163,944,000

190,709,000

175,352,000

Capital expenditures

'

'

'

'

'

'

'

'

44,000

140,000

215,000

Gas Marketing [Member] | Intersegment Revenues [Member]

'

'

'

'

'

'

'

'

'

'

'

Operating Segment Information [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Total revenues including intersegment revenues

'

'

'

'

'

'

'

'

24,185,000

15,330,000

24,333,000

Other [Member]

'

'

'

'

'

'

'

'

'

'

'

Reconciliation of Consolidated Net Income to Consolidated Net Economic Earnings

'

'

'

'

'

'

'

'

'

'

'

Net Economic Earnings (Non-GAAP)

'

'

'

'

'

'

'

'

-559,000

2,250,000

6,496,000

[3]

Operating Segment Information [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Total revenues including intersegment revenues

'

'

'

'

'

'

'

'

4,649,000

3,883,000

19,704,000

Total Operating Revenues

'

'

'

'

'

'

'

'

6,274,000

4,925,000

20,742,000

Gas Utility

'

'

'

'

'

'

'

'

'

'

'

Natural and propane gas

'

'

'

'

'

'

'

'

0

0

0

Other operation and maintenance expenses

'

'

'

'

'

'

'

'

0

0

0

Depreciation & amortization

'

'

'

'

'

'

'

'

0

0

0

Taxes, other than income taxes

'

'

'

'

'

'

'

'

0

0

0

Total Gas Utility Operating Expenses

'

'

'

'

'

'

'

'

0

0

0

Gas Marketing

'

'

'

'

'

'

'

'

0

0

0

Other

'

'

'

'

'

'

'

'

22,157,000

[4]

2,555,000

[4]

9,642,000

[4]

Costs and Expenses

'

'

'

'

'

'

'

'

22,157,000

2,555,000

9,642,000

Operating Income

'

'

'

'

'

'

'

'

-15,882,000

2,370,000

11,100,000

Interest income

'

'

'

'

'

'

'

'

343,000

371,000

217,000

Interest charges

'

'

'

'

'

'

'

'

2,635,000

175,000

162,000

Income Tax Expense

'

'

'

'

'

'

'

'

-6,827,000

930,000

3,918,000

Net Economic Earnings (Non-GAAP)

'

'

'

'

'

'

'

'

-559,000

2,250,000

6,496,000

[3]

Total assets

115,560,000

'

'

'

102,241,000

'

'

'

115,560,000

102,241,000

129,176,000

Capital expenditures

'

'

'

'

'

'

'

'

2,248,000

1,969,000

119,000

Other [Member] | Intersegment Revenues [Member]

'

'

'

'

'

'

'

'

'

'

'

Operating Segment Information [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Total revenues including intersegment revenues

'

'

'

'

'

'

'

'

1,625,000

1,042,000

1,038,000

Eliminations [Member]

'

'

'

'

'

'

'

'

'

'

'

Reconciliation of Consolidated Net Income to Consolidated Net Economic Earnings

'

'

'

'

'

'

'

'

'

'

'

Net Economic Earnings (Non-GAAP)

'

'

'

'

'

'

'

'

0

0

0

Operating Segment Information [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Total revenues including intersegment revenues

'

'

'

'

'

'

'

'

0

0

0

Total Operating Revenues

'

'

'

'

'

'

'

'

-36,348,000

-17,576,000

0

Gas Utility

'

'

'

'

'

'

'

'

'

'

'

Natural and propane gas

'

'

'

'

'

'

'

'

-35,656,000

-17,542,000

0

Other operation and maintenance expenses

'

'

'

'

'

'

'

'

-360,000

0

0

Depreciation & amortization

'

'

'

'

'

'

'

'

0

0

0

Taxes, other than income taxes

'

'

'

'

'

'

'

'

0

0

0

Total Gas Utility Operating Expenses

'

'

'

'

'

'

'

'

-36,016,000

-17,542,000

0

Gas Marketing

'

'

'

'

'

'

'

'

0

-3,000

0

Other

'

'

'

'

'

'

'

'

-332,000

-31,000

0

Costs and Expenses

'

'

'

'

'

'

'

'

-36,348,000

-17,576,000

0

Operating Income

'

'

'

'

'

'

'

'

0

0

0

Interest income

'

'

'

'

'

'

'

'

-305,000

-467,000

-303,000

Interest charges

'

'

'

'

'

'

'

'

-305,000

-467,000

-303,000

Income Tax Expense

'

'

'

'

'

'

'

'

0

0

0

Net Economic Earnings (Non-GAAP)

'

'

'

'

'

'

'

'

0

0

0

Total assets

-135,134,000

'

'

'

-171,640,000

'

'

'

-135,134,000

-171,640,000

-162,832,000

Capital expenditures

'

'

'

'

'

'

'

'

0

0

0

Eliminations [Member] | Intersegment Revenues [Member]

'

'

'

'

'

'

'

'

'

'

'

Operating Segment Information [Abstract]

'

'

'

'

'

'

'

'

'

'

'

Total revenues including intersegment revenues

'

'

'

'

'

'

'

'

($36,348,000)

($17,576,000)

$0

[1]

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

[2]

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

[3]

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

[4]

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

COMMITMENTS_AND_CONTINGENCIES_

COMMITMENTS AND CONTINGENCIES (Details) (USD $)

12 Months Ended

36 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2011

Sep. 30, 2007

Sep. 30, 2005

Nov. 26, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Jun. 30, 2010

Sep. 30, 2013

Sep. 30, 2013

site

Subsequent Event [Member]

Three-year period ending September 30, 2016 [Member]

From October 1, 2016 [Member]

MF Global Inc [Member]

Laclede Gas [Member]

Missouri Gas Energy (MGE) [Member]

Vehicles and Power Operated Equipment Leases [Member]

Laclede Gas [Member]

Commitments [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

Estimated capital expenditures, next fiscal year

'

$175,000,000

'

'

'

'

'

'

'

'

'

'

'

Approximate contract amount of project

'

1,500,000

'

'

'

'

'

'

'

'

'

'

'

Estimated capital expenditures for non-regulated subsidiaries

'

10,000,000

'

'

'

'

'

'

'

'

'

'

'

Minimum total payments required for natural gas contracts

'

981,000,000

'

'

'

'

'

'

'

'

'

'

'

Leases and Guarantees [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

Additional years available for lease renewal (in years)

'

'5 years

'

'

'

'

'

'

'

'

'

'

'

Office headquarters lease rental aggregate expense

'

1,000,000

900,000

900,000

'

'

'

'

'

'

'

600,000

'

Annual minimum rental payments

1,000,000

'

'

'

'

'

'

'

'

'

'

'

'

Minimum rental costs obligations - current fiscal year

'

'

'

'

'

'

'

'

'

'

'

'

2,700,000

Minimum rental costs obligations - due in two years

'

'

'

'

'

'

'

'

'

'

'

'

1,800,000

Minimum rental costs obligations - due in three years

'

'

'

'

'

'

'

'

'

'

'

'

1,000,000

Minimum rental costs obligations - due in four years

'

'

'

'

'

'

'

'

'

'

'

'

400,000

Minimum rental costs obligations - due in five years

'

'

'

'

'

'

'

'

'

'

'

'

100,000

Outstanding mortgage loans incurred in connection with various real estate ventures with general partners

'

1,600,000

'

'

'

'

'

'

'

'

'

'

'

Contingencies and Indemnifications [Abstract]

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of former manufactured gas plant (MGP) sites in Missouri

'

3

'

'

'

'

'

'

'

'

'

'

'

Number of former manufactured gas plant (MGP) sites in Shrewsbury, Missouri

'

1

'

'

'

'

'

'

'

'

'

'

'

Number of former manufactured gas plant (MGP) sites in the City of St. Louis

'

2

'

'

'

'

'

'

'

'

'

'

'

Minimum cost estimate for a one-time contractual transfer of risk

'

'

'

'

'

5,800,000

'

'

'

'

'

'

'

Maximum cost estimate for a one-time contractual transfer of risk

'

'

'

'

'

36,300,000

'

'

'

'

'

'

'

Original proposed disallowance amount related to recovery of purchased gas costs

'

'

'

'

6,000,000

'

'

'

'

'

'

'

'

Revenue sharing agreements, Company's net margin amount subject to reduced sharing percentage

'

2,000,000

'

'

'

'

'

'

'

'

'

'

'

Revenue sharing agreements, Company's net margin amount subject to reduced sharing percentage, Company's percentage share

'

15.00%

'

'

'

'

'

0.00%

15.00%

'

'

'

'

Notice of employment related violations issued to company, applicable period

'

'

'

'

'

'

'

'

'

'

'2 years

'

'

Amount remaining on deposit with a brokerage firm for Laclede Gas

'

'

'

'

'

'

200,000

'

'

'

'

'

'

Amount remaining on deposit with a brokerage firm for Laclede Energy Resources, Inc.

'

'

'

'

'

'

100,000

'

'

'

'

'

'

Percentage of deposits recovered from bankrupt entity

'

'

'

'

'

'

'

'

'

$0.98

'

'

'

INTERIM_FINANCIAL_INFORMATION_2

INTERIM FINANCIAL INFORMATION (UNAUDITED) (Unaudited) (Details) (USD $)	3 Months Ended									12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Sep. 30, 2013		Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Quarterly Financial Information Disclosure [Abstract]	'		'	'	'	'	'	'	'	'	'	'
Total Operating Revenues	$147,114	[1]	$165,289	$397,613	$307,003	$169,538	$186,849	$358,175	$410,913	$1,017,019	$1,125,475	$1,603,307
Operating Income (Loss)	-9,722	[1]	12,282	51,849	42,085	1,869	15,045	50,583	43,105	96,494	110,602	118,247
Net Income (Loss)	($9,636)	[1]	$6,584	$30,242	$25,568	($651)	$8,433	$29,684	$25,174	$52,758	$62,640	$63,825
Basic Earnings (Loss) Per Share of Common Stock (in dollars per share)	($0.30)	[1]	$0.25	$1.34	$1.14	($0.03)	$0.38	$1.33	$1.13	$2.03	$2.80	$2.87
Diluted Earnings (Loss) Per Share of Common Stock (in dollars per share)	($0.30)	[1]	$0.25	$1.34	$1.14	($0.03)	$0.38	$1.32	$1.12	$2.02	$2.79	$2.86
[1]	All quarters of 2013 reflect transaction costs incurred associated with the acquisition of MGE. The fourth quarter of 2013 includes one month of activity of the operations of MGE, significant transaction costs incurred in the quarter and the interest impact of the debt issued in the quarter. Total impact of all of these during the quarter was a decrease in net income of $5.5 million.

SCHEDULE_II_Details

SCHEDULE II (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2011
DOUBTFUL ACCOUNTS [Member]	'		'		'
CHANGES IN RESERVES [Roll Forward]	'		'		'
BALANCE AT BEGINNING OF PERIOD	$7,705		$10,073		$10,295
ADDITIONS TO INCOME	5,584		6,011		7,242
CHARGED TO OTHER ACCOUNTS	8,234	[1]	10,145	[1]	11,340	[1]
DEDUCTIONS FROM RESERVES	13,477	[2]	18,524	[2]	18,804	[2]
BALANCE AT END OF PERIOD	8,046		7,705		10,073
MISCELLANEOUS: Injuries and property damage [Member]	'		'		'
CHANGES IN RESERVES [Roll Forward]	'		'		'
BALANCE AT BEGINNING OF PERIOD	4,540		3,603		3,228
ADDITIONS TO INCOME	1,934		3,150		2,416
CHARGED TO OTHER ACCOUNTS	0		0		0
DEDUCTIONS FROM RESERVES	2,135	[3]	2,213	[3]	2,041	[3]
BALANCE AT END OF PERIOD	4,339		4,540		3,603
MISCELLANEOUS: deferred compensation [Member]	'		'		'
CHANGES IN RESERVES [Roll Forward]	'		'		'
BALANCE AT BEGINNING OF PERIOD	14,205		13,474		12,571
ADDITIONS TO INCOME	1,781		1,756		1,893
CHARGED TO OTHER ACCOUNTS	0		0		0
DEDUCTIONS FROM RESERVES	1,306		1,025		990
BALANCE AT END OF PERIOD	14,680		14,205		13,474
MISCELLANEOUS: group medical claims incurred but not reported [Member]	'		'		'
CHANGES IN RESERVES [Roll Forward]	'		'		'
BALANCE AT BEGINNING OF PERIOD	1,560		1,300		1,450
ADDITIONS TO INCOME	17,205		15,381		14,171
CHARGED TO OTHER ACCOUNTS	0		0		0
DEDUCTIONS FROM RESERVES	16,116	[3]	15,121	[3]	14,321	[3]
BALANCE AT END OF PERIOD	2,649		1,560		1,300
Total MISCELLANEOUS [Member]	'		'		'
CHANGES IN RESERVES [Roll Forward]	'		'		'
BALANCE AT BEGINNING OF PERIOD	20,305		18,377		17,249
ADDITIONS TO INCOME	20,920	[4]	20,287		18,480
CHARGED TO OTHER ACCOUNTS	0	[4]	0		0
DEDUCTIONS FROM RESERVES	19,557	[4]	18,359		17,352
BALANCE AT END OF PERIOD	$21,668		$20,305		$18,377
[1]	Accounts reinstated, cash recoveries, etc.
[2]	Accounts written off.
[3]	Claims settled, less reimbursements from insurance companies.
[4]	Totals for the year ended September 30, 2013 includes one month of MGE activity.