10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 or 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Quarter Ended December 31, 2013

OR

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

Commission File Number 1-16681

THE LACLEDE GROUP, INC.

(Exact name of registrant as specified in its charter)

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

Indicate by check mark if the registrant:

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

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

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

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

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

As of January 31, 2014, there were 32,758,189 shares of the registrant’s Common Stock, par value $1.00 per share, outstanding.

TABLE OF CONTENTS			Page No.
PART I.  FINANCIAL INFORMATION
Item 1	Financial Statements:
		Statements of Consolidated Income	4
		Statements of Consolidated Comprehensive Income	5
		Consolidated Balance Sheets	6
		Statements of Consolidated Cash Flows	8
		Notes to Consolidated Financial Statements	9
Item 2	Management’s Discussion and Analysis of Financial Condition and
		Results of Operations	26
Item 3	Quantitative and Qualitative Disclosures About Market Risk		37
Item 4	Controls and Procedures		38
PART II.  OTHER INFORMATION
Item 1	Legal Proceedings		39
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds		39
Item 6	Exhibits		39
SIGNATURE			40
INDEX TO EXHIBITS			41

2

PART I. FINANCIAL INFORMATION

The interim financial statements included herein have been prepared by The Laclede Group, Inc. (Laclede Group or the Company), without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). These financial statements should be read in conjunction with the financial statements and the notes thereto included in the Company’s Form 10-K for the fiscal year ended September 30, 2013.

3

Item 1. Financial Statements

THE LACLEDE GROUP, INC.

STATEMENTS OF CONSOLIDATED INCOME

(UNAUDITED)

	Three Months Ended
	December 31,
(Thousands, Except Per Share Amounts)	2013		2012
Operating Revenues:
Gas Utility	$	435,166	$	250,111
Gas Marketing	33,253		55,249
Other	191		1,643
Total Operating Revenues	468,610		307,003
Operating Expenses:
Gas Utility
Natural and propane gas	241,787		136,515
Other operation and maintenance expenses	62,322		39,651
Depreciation and amortization	20,026		10,965
Taxes, other than income taxes	28,589		14,806
Total Gas Utility Operating Expenses	352,724		201,937
Gas Marketing	51,782		57,382
Other	1,199		5,599
Total Operating Expenses	405,705		264,918
Operating Income	62,905		42,085
Other Income and (Income Deductions) – Net	1,647		1,084
Interest Charges:
Interest on long-term debt	9,694		5,438
Other interest charges	767		588
Total Interest Charges	10,461		6,026
Income Before Income Taxes	54,091		37,143
Income Tax Expense	18,499		11,575
Net Income	$	35,592	$	25,568
Weighted Average Number of Common Shares Outstanding:
Basic	32,570		22,372
Diluted	32,648		22,434
Basic Earnings Per Share of Common Stock	$	1.09	$	1.14
Diluted Earnings Per Share of Common Stock	$	1.09	$	1.14
Dividends Declared Per Share of Common Stock	$	0.440	$	0.425
See Notes to Consolidated Financial Statements.

4

THE LACLEDE GROUP, INC.

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

(UNAUDITED)

	Three Months Ended
	December 31,
(Thousands)	2013			2012
Net Income	$	35,592		$	25,568
Other Comprehensive Income (Loss), Before Tax:
Net (losses) gains on cash flow hedging derivative instruments:
Net hedging (loss) gain arising during the period	(1,646		)	1,389
Reclassification adjustment for (gains) losses included in net income	(1,178		)	2,249
Net unrealized (losses) gains on cash flow hedging derivative instruments	(2,824		)	3,638
Amortization of actuarial loss included in net periodic pension and postretirement benefit cost	97			90
Other Comprehensive (Loss) Income, Before Tax	(2,727		)	3,728
Income Tax (Benefit) Expense Related to Items of Other Comprehensive Income	(1,035		)	1,450
Other Comprehensive (Loss) Income, Net of Tax	(1,692		)	2,278
Comprehensive Income	$	33,900		$	27,846
See Notes to Consolidated Financial Statements.

5

THE LACLEDE GROUP, INC.

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	Dec. 31,			Sept. 30,			Dec. 31,
(Thousands)	2013			2013			2012
ASSETS
Utility Plant	$	2,295,248		$	2,271,189		$	1,508,770
Less:  Accumulated depreciation and amortization	507,457			494,559			470,840
Net Utility Plant	1,787,791			1,776,630			1,037,930
Non-utility property	5,249			7,694			5,788
Goodwill	235,814			247,078			—
Other investments	62,774			58,306			51,631
Other Property and Investments	303,837			313,078			57,419
Current Assets:
Cash and cash equivalents	34,518			52,981			46,563
Accounts receivable:
Utility	254,692			101,118			130,925
Non-utility	63,194			63,752			54,092
Other	21,801			14,451			17,822
Allowance for doubtful accounts	(10,847		)	(8,046		)	(7,055		)
Inventories:
Natural gas stored underground	153,305			182,035			88,342
Propane gas	6,022			8,962			10,200
Materials and supplies at average cost	8,581			8,154			4,257
Natural gas receivable	7,786			18,782			13,746
Derivative instrument assets	4,985			3,291			1,246
Unamortized purchased gas adjustments	9,903			17,533			30,492
Deferred income taxes	3,222			—			—
Prepayments and other	13,562			12,867			9,433
Total Current Assets	570,724			475,880			400,063
Deferred Charges:
Regulatory assets	530,963			545,947			440,880
Other	13,415			13,851			5,863
Total Deferred Charges	544,378			559,798			446,743
Total Assets	$	3,206,730		$	3,125,386		$	1,942,155

6

THE LACLEDE GROUP, INC.

CONSOLIDATED BALANCE SHEETS (Continued)

(UNAUDITED)

	Dec. 31,			Sept. 30,			Dec. 31,
(Thousands, except share amounts)	2013			2013			2012
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock (70,000,000 shares authorized, 32,751,255,     32,696,836, and 22,563,958 shares issued, respectively)	$	32,751		$	32,697		$	22,564
Paid-in capital	594,857			594,269			169,496
Retained earnings	441,259			420,103			430,556
Accumulated other comprehensive loss	(2,479		)	(787		)	(1,838		)
Total Common Stock Equity	1,066,388			1,046,282			620,778
Long-term debt (less current portion)	832,764			912,712			364,426
Total Capitalization	1,899,152			1,958,994			985,204
Current Liabilities:
Current portion of long-term debt	80,000			—			—
Notes payable	93,500			74,000			83,050
Accounts payable	160,750			140,234			100,994
Advance customer billings	16,011			23,736			15,950
Wages and compensation accrued	15,753			20,807			12,401
Dividends payable	15,142			14,556			9,931
Customer deposits	15,485			15,062			8,437
Interest accrued	9,755			8,335			5,034
Taxes accrued	36,274			32,896			13,196
Deferred income taxes	—			1,012			4,426
Other	35,054			22,540			21,651
Total Current Liabilities	477,724			353,178			275,070
Deferred Credits and Other Liabilities:
Deferred income taxes	389,557			379,114			350,738
Unamortized investment tax credits	2,847			2,900			3,060
Pension and postretirement benefit costs	229,313			228,653			195,259
Asset retirement obligations	72,459			74,554			40,936
Regulatory liabilities	90,795			82,560			56,776
Other	44,883			45,433			35,112
Total Deferred Credits and Other Liabilities	829,854			813,214			681,881
Commitments and Contingencies (Note 12)
Total Capitalization and Liabilities	$	3,206,730		$	3,125,386		$	1,942,155
See Notes to Consolidated Financial Statements.

7

THE LACLEDE GROUP, INC.

STATEMENTS OF CONSOLIDATED CASH FLOWS

(UNAUDITED) 

	Three Months Ended
	December 31,
(Thousands)	2013			2012
Operating Activities:
Net Income	$	35,592		$	25,568
Adjustments to reconcile net income to net cash provided by (used in)       operating activities:
Depreciation, amortization, and accretion	20,212			11,314
Deferred income taxes and investment tax credits	(702		)	2,572
Other – net	(157		)	670
Changes in assets and liabilities:
Accounts receivable – net	(157,564		)	(61,942		)
Unamortized purchased gas adjustments	7,630			10,182
Deferred purchased gas costs	23,093			2,266
Accounts payable	25,153			12,004
Advance customer billings - net	(7,725		)	(9,196		)
Taxes accrued	3,379			1,877
Natural gas stored underground	28,730			4,387
Other assets and liabilities	6,648			4,213
Net cash (used in) provided by operating activities	(15,711		)	3,915
Investing Activities:
Capital expenditures	(34,641		)	(27,713		)
Other investments	(679		)	(990		)
Proceeds from sale of right to acquire NEG	11,000			—
Net cash used in investing activities	(24,320		)	(28,703		)
Financing Activities:
Issuance of long-term debt	—			25,000
Maturity of first mortgage bonds	—			(25,000		)
Issuance of short-term debt – net	19,500			42,950
Changes in book overdrafts	15,847			10,160
Issuance of common stock	742			761
Dividends paid	(13,876		)	(9,495		)
Employees’ taxes paid associated with restricted shares withheld upon vesting	(1,053		)	(723		)
Excess tax benefits from stock-based compensation	423			256
Other	(15		)	(15		)
Net cash provided by financing activities	21,568			43,894
Net (Decrease) Increase in Cash and Cash Equivalents	(18,463		)	19,106
Cash and Cash Equivalents at Beginning of Period	52,981			27,457
Cash and Cash Equivalents at End of Period	$	34,518		$	46,563
Supplemental disclosure of cash flow information:
Interest paid	$	8,850		$	9,585
Income taxes paid	(2,313		)	456
See Notes to Consolidated Financial Statements.

8

THE LACLEDE GROUP, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

These notes are an integral part of the accompanying unaudited consolidated financial statements of The Laclede Group, Inc. (Laclede Group or the Company) and its subsidiaries. In the opinion of Laclede Group, this interim report includes all adjustments (consisting of only normal recurring accruals) necessary for the fair presentation of the results of operations for the periods presented. This Form 10-Q should be read in conjunction with the Notes to Consolidated Financial Statements contained in the Company’s Fiscal Year 2013 Form 10-K.

The consolidated financial position, results of operations, and cash flows of Laclede Group are primarily derived from the financial position, results of operations, and cash flows of Laclede Gas Company (Laclede Gas or the Utility), a wholly owned subsidiary. The Utility is a regulated natural gas distribution utility having a material seasonal cycle. As a result, these interim statements of income for Laclede Group are not necessarily indicative of annual results or representative of succeeding quarters of the fiscal year. The Utility's recent acquisition of Missouri Gas Energy (MGE) is included in the results of operations for the three months ended December 31, 2013, impacting the comparability of the current year financial statements to prior years. For a further discussion of the acquisition, see Note 2, MGE Acquisition. Due to the seasonal nature of the business of the Utility, Laclede Group’s earnings are typically concentrated during the heating season of November through April each year, although earnings for Missouri Gas Energy (MGE) are less seasonal than earnings from Laclede Gas, due to MGE's straight fixed-variable rate design which recovers fixed costs more evenly over the year. The Gas Utility segment serves St. Louis and eastern Missouri through Laclede Gas and serves Kansas City and western Missouri through MGE. The Company's primary non-utility business, Laclede Energy Resources, Inc. (LER), included in the Gas Marketing segment, provides non-regulated natural gas services.

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 December 31, 2013 and 2012, for the Utility, were $101.9 million and $39.6 million, respectively. The amount of accrued unbilled revenue at September 30, 2013 was $25.2 million.

GROSS RECEIPTS 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 for the three months ended December 31, 2013 and 2012 were $19.9 million and $10.3 million, respectively. Gross receipts taxes are expensed by the Utility and included in the Taxes, other than income taxes line.

2. MGE Acquisition

Effective September 1, 2013, the Utility 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, the Utility acquired MGE for a purchase price of $975 million.

On December 12, 2012, a subsidiary of Laclede Group, Plaza Massachusetts Acquisition Inc. (Plaza Mass), agreed to purchase New England Gas Company (NEG) from SUG. Subsequently, on February 11, 2013, the Company agreed to sell Plaza Mass to Algonquin Power & Utilities Corp. (APUC). On December 13, 2013, the Massachusetts Department of Public Utilities (MDPU) approved the transfer of Plaza Mass to an APUC subsidiary. Consistent with the February 11, 2013 agreements, on December 20, 2013, the Company closed the sale of Plaza Mass to an APUC subsidiary and received $11.0 million from APUC. This receipt of funds effectively reduced the Utility's purchase price of MGE to $964 million. On December 24, 2013, the Massachusetts Attorney General filed a Motion for Clarification/Reconsideration with the MDPU which, among other things, claims that legislative approval is required for a transfer of utility assets. The MDPU has not yet acted on the Attorney General’s Motion.

The Utility is currently in negotiations with SUG regarding adjustments to the purchase price of MGE due to changes in the actual net assets transferred to the Utility at closing on August 31, 2013 from the level at September 30, 2012. The Utility plans to adjust cash and goodwill for any change upon final settlement.

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. The Utility recorded $235.8 million of goodwill as an asset in the consolidated balance sheet.

9

In the first quarter of fiscal 2014, the Utility updated the fair value estimates for assets acquired and liabilities assumed as of the acquisition date, including the sale of NEG to APUC which resulted in a decrease to goodwill of $11.0 million.

3. PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS

Pension Plans

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

Pension costs for the three months ended December 31, 2013 and 2012 were $6.6 million and $4.2 million, respectively, including amounts charged to construction.

The net periodic pension costs include the following components:

	Three Months Ended December 31,
(Thousands)	2013			2012
Service cost – benefits earned during the period	$	2,428		$	2,311
Interest cost on projected benefit obligation	6,010			4,066
Expected return on plan assets	(6,645		)	(4,741		)
Amortization of prior service cost	124			136
Amortization of actuarial loss	1,772			2,839
Sub-total	3,689			4,611
Regulatory adjustment	2,890			(434		)
Net pension cost	$	6,579		$	4,177

Pursuant to the provisions of the Utility's pension plans, pension obligations may be satisfied by lump-sum cash payments. Pursuant to a Missouri Public Service Commission (MoPSC or Commission) Order, lump-sum payments are recognized as settlements (which can result in gains or losses) only if the total of such payments exceeds 100% of the sum of service and interest costs. There were no lump-sum payments recognized as settlements during the three months ended December 31, 2013 and December 31, 2012, respectively.

Pursuant to a MoPSC Order, the return on plan assets is based on the market-related value of plan assets implemented prospectively over a four-year period. Gains or losses not yet includible in pension cost are amortized only to the extent that such gain or loss exceeds 10% of the greater of the projected benefit obligation or the market-related value of plan assets. Such excess is amortized over the average remaining service life of active participants. The recovery in rates for Laclede Gas' qualified pension plans is based on an annual allowance of $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 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. Fiscal year 2014 contributions to the pension plans through December 31, 2013 were $3.8 million to the qualified trusts. There were no contributions to the non-qualified plans in the first quarter of fiscal 2014. Contributions to the pension plans for the remaining nine months of fiscal 2014 are anticipated to be approximately $24.0 million to the qualified trusts and $0.4 million to the non-qualified plans.

Postretirement Benefits

The Utility provides certain life insurance benefits at retirement. Under the Laclede Gas plans, medical insurance is currently available after early retirement until age 65. Under the MGE plans, medical insurance is currently available upon retirement until death. The transition obligation not yet includible in postretirement benefit cost is being amortized over 20 years. Postretirement benefit costs for both the three months ended December 31, 2013 and 2012 were $2.4 million, including amounts charged to construction.

10

Net periodic postretirement benefit costs consisted of the following components:

	Three Months Ended December 31,
(Thousands)	2013			2012
Service cost – benefits earned during the period	$	2,804		$	2,533
Interest cost on accumulated postretirement benefit obligation	2,169			1,279
Expected return on plan assets	(1,709		)	(1,081		)
Amortization of transition obligation	—			23
Amortization of prior service cost (credit)	(1		)	1
Amortization of actuarial loss	1,505			1,325
Sub-total	4,768			4,080
Regulatory adjustment	(2,387		)	(1,699		)
Net postretirement benefit cost	$	2,381		$	2,381

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 (VEBA) and Rabbi trusts as its external funding mechanisms. The assets of VEBA and Rabbi trusts consist primarily of money market securities and mutual funds invested in stocks and bonds.

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

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. There were no contributions to the postretirement plans in fiscal 2014 through December 31, 2013. Contributions to the postretirement plans for the remaining nine months of fiscal year 2014 are anticipated to be $19.2 million to the qualified trusts and $0.3 million paid directly to participants from the Utility's funds.

4. STOCK-BASED COMPENSATION

Awards of stock-based compensation are made pursuant to The Laclede Group 2006 Equity Incentive Plan (2006 Plan). Refer to Note 3 of the Consolidated Financial Statements included in the Company’s Form 10-K for the fiscal year ended September 30, 2013 for descriptions of the plan.

Restricted Stock Awards

During the three months ended December 31, 2013, the Company granted 104,979 performance-contingent restricted stock units to executive officers and key employees at a weighted average grant date fair value of $37.74 per share. This number represents the maximum shares that can be earned pursuant to the terms of the awards. Most of these stock units have a performance period ending September 30, 2016. While the participants have no interim voting rights on these stock units, dividends accrue during the performance period and are paid to the participants upon vesting, but are subject to forfeiture if the underlying stock units do not vest. The number of stock units that will ultimately vest is dependent upon the attainment of certain levels of earnings and other strategic goals, as well as the Company’s level of total shareholder return (TSR) during the performance period relative to a comparator group of companies. This TSR provision is considered a market condition under GAAP.

11

Activity of restricted stock and restricted stock units subject to performance and/or market conditions during the three months ended December 31, 2013 is presented below:

	Restricted Stock/ Stock Units		Weighted Average Grant Date Fair Value
Nonvested at September 30, 2013	242,268		$	34.15
Granted (maximum shares that can be earned)	104,979		$	37.74
Vested	(52,954	)	$	32.16
Forfeited	(22,022	)	$	29.35
Nonvested at December 31, 2013	272,271		$	36.31

During the three months ended December 31, 2013, the Company granted 51,943 shares of time-vested restricted stock and stock units to executive officers, key employees, and directors at a weighted average grant date fair value of $45.59 per share. Of the 51,943 shares, 12,168 shares vest on December 2, 2014 and 39,775 will vest on December 2, 2016. In the interim, participants receive full voting rights, which are not subject to forfeiture.    

Time-vested restricted stock and stock unit activity for the three months ended December 31, 2013 is presented below:

	Restricted Stock/ Stock Units		Weighted Average Grant Date Fair Value
Nonvested at September 30, 2013	119,404		$	38.64
Granted	51,943		$	45.59
Vested	(17,999	)	$	36.37
Forfeited	(7,200	)	$	38.53
Nonvested at December 31, 2013	146,148		$	41.40

During the three months ended December 31, 2013, 70,953 shares of restricted stock and stock units (performance-contingent and time-vested), awarded on December 1, 2010 and October 17, 2012 vested. The Company withheld 22,983 of the vested shares at a weighted average price of $45.83 per share pursuant to elections by employees to satisfy tax withholding obligations.

Stock Option Awards

Stock option activity for the three months ended December 31, 2013 is presented below:

	Stock Options		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (Years)	Aggregate Intrinsic Value ($000)
Outstanding at September 30, 2013	133,500		$	31.87
Granted	—		$	—
Exercised	(12,750	)	$	29.36
Forfeited	—		$	—
Expired	—		$	—
Outstanding at December 31, 2013	120,750		$	32.14	1.7	$	1,618
Fully Vested and Expected to Vest at December 31, 2013	120,750		$	32.14	1.7	$	1,618
Exercisable at December 31, 2013	120,750		$	32.14	1.7	$	1,618

The closing price of the Company’s common stock was $45.54 at December 31, 2013.

12

Equity Compensation Costs

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

	Three Months Ended December 31,
(Thousands)	2013			2012
Total equity compensation cost	$	533		$	622
Compensation cost capitalized	(149		)	(183		)
Compensation cost recognized	$	384		$	439

As of December 31, 2013, there was $9.2 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 2.4 years.

5. EARNINGS PER COMMON SHARE

	Three Months Ended December 31,
(Thousands, Except Per Share Amounts)	2013		2012
Basic EPS:
Net Income	$	35,592	$	25,568
Less: Income allocated to participating securities	144		80
Net Income Available to Common Shareholders	$	35,448	$	25,488
Weighted Average Shares Outstanding	32,570		22,372
Earnings Per Share of Common Stock	$	1.09	$	1.14
Diluted EPS:
Net Income	$	35,592	$	25,568
Less: Income allocated to participating securities	144		80
Net Income Available to Common Shareholders	$	35,448	$	25,488
Weighted Average Shares Outstanding	32,570		22,372
Dilutive Effect of Stock Options, Restricted Stock and Restricted Stock Units	78		62
Weighted Average Diluted Shares	32,648		22,434
Earnings Per Share of Common Stock	$	1.09	$	1.14
Outstanding Shares Excluded from the Calculation of Diluted EPS Attributable to:
Restricted stock and stock units subject to performance and/or market conditions	259		263

13

6. FAIR VALUE OF FINANCIAL INSTRUMENTS

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

					Classification of Estimated Fair Value
(Thousands)	Carrying Amount		Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
As of December 31, 2013
Cash and cash equivalents	$	34,518	$	34,518	$	34,354	$	164	$	—
Short-term debt	93,500		93,500		—		93,500		—
Long-term debt, including current portion	912,764		936,478		—		936,478		—
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 December 31, 2012
Cash and cash equivalents	$	46,563	$	46,563	$	36,487	$	10,076	$	—
Short-term debt	83,050		83,050		—		83,050		—
Long-term debt, including current portion	364,426		456,235		—		456,235		—

The carrying amounts for cash and cash equivalents and short-term debt approximate fair value due to the short maturity of these instruments. The fair values of long-term debt are estimated based on market prices for similar issues. Refer to Note 7, Fair Value Measurements, for information on financial instruments measured at fair value on a recurring basis.

14

7. FAIR VALUE MEASUREMENTS

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

(Thousands)	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Effects of Netting and Cash Margin Receivables /Payables			Total
As of December 31, 2013
Assets
U. S. Stock/Bond Mutual Funds	$	15,003	$	—	$	—	$	—		$	15,003
NYMEX/ICE natural gas contracts	3,697		670		—		(3,839		)	528
OTCBB natural gas contracts	—		3,609		—		(913		)	2,696
NYMEX gasoline and heating oil contracts	163		—		—		—			163
Natural gas commodity contracts	—		3,044		29		(826		)	2,247
Total	$	18,863	$	7,323	$	29	$	(5,578	)	$	20,637
Liabilities
NYMEX/ICE natural gas contracts	$	2,013	$	265	$	—	$	(2,278	)	$	—
OTCBB natural gas contracts	—		913		—		(913		)	—
Natural gas commodity contracts	—		1,732		22		(826		)	928
Total	$	2,013	$	2,910	$	22	$	(4,017	)	$	928
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
Natural gas commodity contracts	—		1,140		40		(495		)	685
Total	$	3,687	$	6,904	$	40	$	(4,735	)	$	5,896
As of December 31, 2012
Assets
U. S. Stock/Bond Mutual Funds	$	13,146	$	—	$	—	$	—		$	13,146
NYMEX/ICE natural gas contracts	2,497		749		—		(2,962		)	284
NYMEX gasoline and heating oil contracts	281		—		—		(281		)	—
Natural gas commodity contracts	—		1,228		77		(348		)	957
Total	$	15,924	$	1,977	$	77	$	(3,591	)	$	14,387
Liabilities
NYMEX/ICE natural gas contracts	$	6,650	$	749	$	—	$	(7,399	)	$	—
Natural gas commodity contracts	—		1,132		47		(348		)	831
Total	$	6,650	$	1,881	$	47	$	(7,747	)	$	831

15

The mutual funds included in Level 1 are valued based on exchange-quoted market prices of identical securities. Derivative instruments included in Level 1 are valued using quoted market prices on the 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:

	Three Months Ended December 31,
(Thousands)	2013			2012
Beginning of period	$	110		$	109
Net settlements	(108		)	(66		)
Net gains related to derivatives still held at end of period	5			(13		)
End of period	$	7		$	30

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

8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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 Purchased Gas Adjustment (PGA) Clause, through which the MoPSC allows the Utility to recover gas supply costs, subject to prudence review by the MoPSC. Accordingly, 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, they 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 December 31, 2013, Laclede Gas held 0.8 million gallons of gasoline futures contracts at an average price of $2.66 per gallon. Most of these contracts, the longest of which extends to September 2014, are designated as cash flow hedges of forecasted transactions pursuant to ASC Topic 815. The gains or losses on these derivative instruments are not subject to the Utility’s PGA Clause.

16

In the course of its business, Laclede Group’s gas marketing subsidiary, LER, which includes its wholly owned subsidiary LER Storage Services, Inc., enters into commitments associated with the purchase or sale of natural gas. Certain of LER’s derivative natural gas contracts are designated as normal purchases or normal sales and, as such, are excluded from the scope of ASC Topic 815 and are accounted for as executory contracts on an accrual basis. Any of LER’s derivative natural gas contracts that are not designated as normal purchases or normal sales are accounted for at fair value. At December 31, 2013, the fair values of 72.2 million MMBtu of non-exchange traded natural gas commodity contracts were reflected in the Consolidated Balance Sheet. Of these contracts, 57.3 million MMBtu will settle during fiscal year 2014, 13.5 million MMBtu will settle during fiscal year 2015, while the remaining 1.4 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 Clear Europe (ICE) futures, swap, and option contracts to lock in margins. At December 31, 2013, LER’s unmatched fixed-price positions were not material to Laclede Group’s financial position or results of operations. LER’s NYMEX and ICE natural gas futures, swap, and option contracts used to lock in margins may be designated as cash flow hedges of forecasted transactions for financial reporting purposes.

The Company’s exchange-traded/cleared derivative instruments consist primarily of NYMEX, OTCBB, and ICE positions. The NYMEX and OTCBB 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 December 31, 2013 were as follows:

	Laclede Gas Company			Laclede Energy Resources, Inc.
	MMBtu (millions)	Avg. Price Per MMBtu		MMBtu (millions)	Avg. Price Per MMBtu
NYMEX/ICE Open short futures positions
Fiscal 2014	—	$	—	11.04	$	4.03
Fiscal 2015	—	—		0.49	4.19
Fiscal 2016	—	—		0.01	4.10
NYMEX/ICE Open long futures positions
Fiscal 2014	5.25	$	3.88	1.64	$	3.84
Fiscal 2015	0.94	3.84		0.39	4.00
Fiscal 2016	—	—		0.09	4.18
Fiscal 2017	—	—		0.02	4.28
ICE Open basis swap positions
Fiscal 2016	—	—		0.92	$	(0.80	)
Fiscal 2017	—	—		0.16	(0.80		)
OTCBB Open long futures positions
Fiscal 2014	14.03	$	3.99	—	—
Fiscal 2015	8.60	4.20		—	—
Fiscal 2016	0.11	4.15		—	—

At December 31, 2013, the Utility had 19.2 million MMBtu of other price mitigation in place through the use of NYMEX and OTCBB natural gas option-based strategies while LER had none.

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 December 31, 2013, it is expected that approximately $0.8 million of pre-tax unrealized gains will be reclassified into the Statements of Consolidated Income during the next twelve months. Cash flows from hedging transactions are classified in the same category as the cash flows from the items that are being hedged in the Statements of Consolidated Cash Flows.

17

The Effect of Derivative Instruments on the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income
		Three Months Ended
	Location of Gain (Loss)	December 31,
(Thousands)	Recorded in Income	2013			2012
Derivatives in Cash Flow Hedging Relationships
Effective portion of gain (loss) recognized in OCI on derivatives:
NYMEX/ICE natural gas contracts		$	(1,655	)	$	1,332
NYMEX gasoline and heating oil contracts		9			57
Total		$	(1,646	)	$	1,389
Effective portion of gain (loss) reclassified from AOCI to income:
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	$	1,300		$	(1,962	)
	Gas Marketing Operating Expenses	(180		)	(334		)
Sub-total		1,120			(2,296		)
NYMEX gasoline and heating oil contracts	Gas Utility Other Operations and Maintenance Expenses	58			47
Total		$	1,178		$	(2,249	)
Ineffective portion of gain (loss) on derivatives recognized in income:
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	$	(211	)	$	(325	)
	Gas Marketing Operating Expenses	133			(85		)
Sub-total		(78		)	(410		)
NYMEX gasoline and heating oil contracts	Gas Utility Other Operations and Maintenance Expenses	120			(101		)
Total		$	42		$	(511	)
Derivatives Not Designated as Hedging Instruments *
Gain (loss) recognized in income on derivatives:
Natural gas commodity contracts	Gas Marketing Operating Revenues	$	(1,667	)	$	(970	)
	Gas Marketing Operating Expenses	—			—
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	1,990			1,067
	Gas Marketing Operating Expenses	—			—
NYMEX gasoline and heating oil contracts	Other Income and (Income Deductions) - Net	13			33
Total		$	336		$	130

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

18

Fair Value of Derivative Instruments in the Consolidated Balance Sheet at December 31, 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	$	881		Derivative Instrument Assets	$	1,030
	Other Deferred Charges	110			Other Deferred Charges	1
NYMEX gasoline and heating oil contracts	Accounts Receivable – Other	154			Accounts Receivable – Other	—
Sub-total		1,145				1,031
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets	571			Derivative Instrument Assets	955
	Accounts Receivable – Other	2,802			Accounts Receivable – Other	285
	Other Deferred Charges	3			Other Deferred Charges	7
OTCBB natural gas contracts	Derivative Instrument Assets	3,386			Derivative Instrument Assets	636
	Other Deferred Credits	223			Other Deferred Credits	278
Natural gas commodity contracts	Derivative Instrument Assets	1,915			Derivative Instrument Assets	272
	Other Deferred Charges	641			Other Deferred Charges	37
	Other Current Liabilities	333			Other Current Liabilities	1,283
	Other Deferred Credits	183			Other Deferred Credits	161
NYMEX gasoline and heating oil contracts	Derivative Instrument Assets	9			Derivative Instrument Assets	—
Sub-total		10,066				3,914
Total derivatives		$	11,211			$	4,945
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		Accounts Receivable - Other	$	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

19

Fair Value of Derivative Instruments in the Consolidated Balance Sheet at December 31, 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	Derivative Instrument Assets	$	987	Derivative Instrument Assets	$	871
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	249		Accounts Receivable - Other	—
Sub-total		1,236			871
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Accounts Receivable - Other	533		Accounts Receivable - Other	366
	Derivative Instrument Assets	1,726		Derivative Instrument Assets	6,162
Natural gas commodity contracts	Derivative Instrument Assets	1,197		Derivative Instrument Assets	240
	Other Current Liabilities	108		Other Current Liabilities	939
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	32		Accounts Receivable - Other	—
Sub-total		3,596			7,707
Total derivatives		$	4,832		$	8,578

* 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 7, 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)	December 31, 2013			September 30, 2013			December 31, 2012
Fair value of asset derivatives presented above	$	11,211		$	6,276		$	4,832
Fair value of cash margin receivables offset with derivatives	956			1,765			4,186
Netting of assets and liabilities with the same counterparty	(6,533		)	(4,739		)	(7,778		)
Total	$	5,634		$	3,302		$	1,240
Derivative Instrument Assets, per Consolidated Balance Sheets:
Derivative instrument assets	$	4,985		$	3,291		$	1,246
Other deferred charges	649			11			(6		)
Total	$	5,634		$	3,302		$	1,240
Fair value of liability derivatives presented above	$	4,945		$	10,629		$	8,578
Fair value of cash margin payables offset with derivatives	2,516			6			31
Netting of assets and liabilities with the same counterparty	(6,533		)	(4,739		)	(7,778		)
Total	$	928		$	5,896		$	831
Derivative Instrument Liabilities, per Consolidated Balance Sheets:
Other Current Liabilities	$	938		$	4,400		$	831
Other Deferred Credits	(10		)	1,496			—
Total	$	928		$	5,896		$	831

Additionally, at December 31, 2013, September 30, 2013, and December 31, 2012, the Company had $3.8 million, $3.2 million, and $4.4 million, respectively, in cash margin receivables not offset with derivatives, that are presented in Accounts Receivable - Other.

20

9. CONCENTRATIONS OF CREDIT RISK

A significant portion of LER’s transactions are with (or are associated with) energy producers, utility companies, and pipelines. These concentrations of transactions with these counterparties have the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that each of these three groups may be affected similarly by changes in economic, industry, or other conditions. To manage this risk, as well as credit risk from significant counterparties in these and other industries, LER has established procedures to determine the creditworthiness of its counterparties. These procedures include obtaining credit ratings and credit reports, analyzing counterparty financial statements to assess financial condition, and considering the industry environment in which the counterparty operates. This information is monitored on an ongoing basis. In some instances, LER may require credit assurances such as prepayments, letters of credit, or parental guarantees. In addition, LER may enter into netting arrangements to mitigate credit risk with counterparties in the energy industry from which LER both sells and purchases natural gas. Sales are typically made on an unsecured credit basis with payment due the month following delivery. Accounts receivable amounts are closely monitored and provisions for uncollectible amounts are accrued when losses are probable. To date, losses have not been significant. LER records accounts receivable, accounts payable, and prepayments for physical sales and purchases of natural gas on a gross basis. The amount included in accounts receivable attributable to energy producers and their marketing affiliates amounted to $8.9 million at December 31, 2013. Net receivable amounts from these customers on the same date, reflecting netting arrangements, were $3.8 million. Accounts receivable attributable to utility companies and their marketing affiliates comprised $20.5 million of total accounts receivable at December 31, 2013, while net receivable amounts from these customers, reflecting netting arrangements, were $18.8 million. LER also has concentrations of credit risk with certain individually significant counterparties. At December 31, 2013, the amounts included in accounts receivable from LER’s five largest counterparties (in terms of net accounts receivable exposure), were $18.4 million. These five counterparties are either investment-grade rated or owned by investment-grade rated companies. Net receivable amounts from these customers on the same date, reflecting netting arrangements, were $17.3 million. Additionally, LER has concentrations of credit risk with pipeline companies associated with its natural gas receivable amounts.

10. OTHER INCOME AND (INCOME DEDUCTIONS) - NET

	Three Months Ended December 31,
(Thousands)	2013		2012
Interest income	$	249	$	406
Net investment gain (loss)	746		(70		)
Other income	652		748
Other Income and (Income Deductions) – Net	$	1,647	$	1,084

21

11. INFORMATION BY OPERATING SEGMENT

All of Laclede Group’s subsidiaries are wholly owned. The Gas Utility segment 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 includes the results of LER, a subsidiary engaged in the non-regulated marketing of natural gas. 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, natural gas fueling stations, 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.

22

(Thousands)	Gas Utility		Gas Marketing		Other			Eliminations			Consolidated
Three Months Ended December 31, 2013
Revenues from external customers	$	435,166	$	33,253	$	191		$	—		$	468,610
Intersegment revenues	62		19,456		442			(19,960		)	—
Total Operating Revenues	435,228		52,709		633			(19,960		)	468,610
Operating Expenses
Gas Utility
Natural and Propane Gas	261,553		—		—			(19,766		)	241,787
Other Operation and Maintenance Expenses	62,516		—		—			(194		)	62,322
Depreciation and Amortization	20,026		—		—			—			20,026
Taxes, Other than Income Taxes	28,589		—		—			—			28,589
Total Gas Utility Operating Expenses	372,684		—		—			(19,960		)	352,724
Gas Marketing	—		51,782		—			—			51,782
Other	—		—		1,199			—			1,199
Total Operating Expenses	372,684		51,782		1,199			(19,960		)	405,705
Operating Income	62,544		927		(566		)	—			62,905
Net Economic Earnings (Losses)	35,778		822		(336		)	—			36,264
Total assets	3,084,134		157,239		126,890			(161,533		)	3,206,730
Three Months Ended December 31, 2012
Revenues from external customers	$	250,111	$	55,249	$	1,643		$	—		$	307,003
Intersegment revenues	680		6,906		259			(7,845		)	—
Total Operating Revenues	250,791		62,155		1,902			(7,845		)	307,003
Operating Expenses
Gas Utility
Natural and Propane Gas	144,333		—		—			(7,818		)	136,515
Other Operation and Maintenance Expenses	39,651		—		—			—			39,651
Depreciation and Amortization	10,965		—		—			—			10,965
Taxes, Other than Income Taxes	14,806		—		—			—			14,806
Total Gas Utility Operating Expenses	209,755		—		—			(7,818		)	201,937
Gas Marketing	—		57,382		—			—			57,382
Other	—		—		5,626			(27		)	5,599
Total Operating Expenses	209,755		57,382		5,626			(7,845		)	264,918
Operating Income	41,036		4,773		(3,724		)	—			42,085
Net Economic Earnings	25,341		3,281		(389		)	—			28,233
Total assets	1,809,722		188,603		124,967			(181,137		)	1,942,155

Reconciliation of Consolidated Net Income to Consolidated Net Economic Earnings
	Three Months Ended December 31,
(Thousands)	2013			2012
Net Income (GAAP)	$	35,592		$	25,568
Unrealized (gain) loss on energy-related derivative contracts	354			439
Lower of cost or market inventory adjustments	(62		)	—
Realized (gain) loss on economic hedges prior to sale of the physical commodity	(6		)	(31		)
Acquisition, divestiture, and restructuring activities	386			2,257
Net Economic Earnings (Non-GAAP)	$	36,264		$	28,233

23

12. COMMITMENTS AND CONTINGENCIES

Commitments

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 December 31, 2013 are estimated at approximately $1,127 million . Additional contracts are generally entered into prior to or during the heating season. The Utility recovers its costs from customers in accordance with the PGA Clause.

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, the Utility 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. Accordingly, Laclede Gas was able to enter into a cost sharing agreement for remedial investigation with other potentially responsible parties. Pending Missouri Department of Natural Resources approval, the remedial investigation of the site will probably begin in the Spring of 2014. 

24

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.

As discussed in Note 8, Derivative Instruments and Hedging Activities, Laclede Gas and LER enter into NYMEX and ICE exchange-traded/cleared derivative instruments. Previously, these instruments were held in accounts at MF Global, Inc. On October 31, 2011, affiliated entities of MF Global filed a Chapter 11 petition at the U.S. Bankruptcy Court in the Southern District of New York. Subsequently, the court-appointed bankruptcy trustee transferred all of the open positions and a significant portion of the margin deposits of Laclede Gas and LER to a new brokerage firm. On June 27, 2013, the bankruptcy Trustee issued a statement projecting that MF Global customers would receive a full payout of their claims. As of 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.

13. Subsequent Events

On January 6, 2014, the Utility redeemed in cash $80 million of 6.35% Series bonds due in 2038 and accrued interest of $0.3 million.

On January 17, 2014, Laclede Gas filed for a $7.4 million increase in Infrastructure System Replacement Surcharge (ISRS) revenues to recover the costs of gas safety replacement investments and public improvement projects over the previous thirteen months. Any increase in rates in this proceeding must go into effect by at least May 17, 2014.

25

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

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

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

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

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

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

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

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

• allowed rates of return

• incentive regulation

• industry structure

• purchased gas adjustment provisions

• rate design structure and implementation

• regulatory assets

• non-regulated and affiliate transactions

• franchise renewals

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

• taxes

• pension and other postretirement benefit liabilities and funding obligations

• accounting standards;

• the results of litigation;

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

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

• discovery of material weakness in internal controls; and

• employee workforce issues.

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

26

RESULTS OF OPERATIONS

Overview

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

Effective September 1, 2013, the Utility 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, the Utility acquired MGE for a purchase price of $975 million.

Also, on December 12, 2012, a subsidiary of Laclede Group, Plaza Massachusetts Acquisition Inc. (Plaza Mass), agreed to purchase New England Gas Company (NEG) from SUG. Subsequently, on February 11, 2013, the Company agreed to sell Plaza Mass to Algonquin Power & Utilities Corp. (APUC). On December 13, 2013, the Massachusetts Department of Public Utilities (MDPU) approved the transfer of NEG to an APUC subsidiary. Consistent with the February 11, 2013 agreements, on December 20, 2013, the Company closed the sale of Plaza Mass to an APUC subsidiary and received $11.0 million from APUC. This receipt of funds effectively reduced the Company's purchase price of MGE to $964 million. On December 24, 2013, the Massachusetts Attorney General filed a Motion for Clarification/Reconsideration with the MDPU which, among other things, claims that legislative approval is required for a transfer of utility assets. The MDPU has not yet acted on the Attorney General’s Motion.

The Utility is currently in negotiations with SUG regarding adjustments in the purchase price of MGE due to changes in the actual net assets transferred to the Utility at closing on August 31, 2013 from the level at September 30, 2012. 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 second quarter of fiscal 2014.

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. The Utility recorded $235.8 million of goodwill as an asset in the consolidated balance sheet.

Laclede Energy Resources, Inc. (LER) is engaged in the marketing of natural gas and related activities on a non-regulated basis and is reported in the Gas Marketing segment. LER markets natural gas to both on-system Utility transportation customers and customers outside of the Utility's traditional service territory, including large retail and wholesale customers. LER’s operations and customer base are more subject to fluctuations in market conditions than the Utility. LER entered into a 10 year contract for 1 Bcf for natural gas storage effective August 1, 2013 and has an additional 1 Bcf storage contracted through January 2016.

27

EARNINGS

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

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

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

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

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

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

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

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

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

28

THREE MONTHS ENDEDDECEMBER 31, 2013

Net Income and Net Economic Earnings

Reconciliation of Consolidated Net Economic Earnings (Non-GAAP) to Consolidated Net Income (GAAP)
(Millions, except per share amounts)		Gas Utility		Gas Marketing			Other			Total			Per Share Amounts**
Three Months Ended December 31, 2013
	Net Income (Loss) (GAAP)	$	35.4	$	0.5		$	(0.3	)	$	35.6		$	1.09
	Unrealized (gain) loss on energy-related      derivatives*	—		0.4			—			0.4			0.01
	Lower of cost or market inventory adjustments*	—		(0.1		)	—			(0.1		)	—
	Acquisition, divestiture and restructuring activities*	0.4		—			—			0.4			0.01
	Net Economic Earnings (Losses) (Non-GAAP)	$	35.8	$	0.8		$	(0.3	)	$	36.3		$	1.11
Three Months Ended December 31, 2012
	Net Income (Loss) (GAAP)	$	25.3	$	2.9		$	(2.6	)	$	25.6		$	1.14
	Unrealized (gain) loss on energy-related      derivatives*	—		0.4			—			0.4			0.01
	Acquisition, divestiture and restructuring activities*	—		—			2.2			2.2			0.10
	Net Economic Earnings (Losses) (Non-GAAP)	$	25.3	$	3.3		$	(0.4	)	$	28.2		$	1.25

* Amounts presented net of income taxes. Income taxes are calculated by applying federal, state, and local income tax rates applicable to ordinary income to the amounts of the pre-tax reconciling items. For the three months ended December 31, 2013 and 2012, the total net amount of income tax (benefit) expense included in the reconciling items above is ($0.4) million and ($1.6) million, respectively.

** Net economic earnings per share is calculated by replacing consolidated net income with consolidated net economic earnings in the GAAP diluted earnings per share calculation.

Consolidated

Laclede Group’s net income was $35.6 million for the three months ended December 31, 2013, compared with $25.6 million for the three months ended December 31, 2012. Basic and diluted earnings per share for the three months ended December 31, 2013 were each $1.09, compared with basic and diluted earnings per share of $1.14, respectively, for the three months ended December 31, 2012. Net income increased compared to last year primarily due to improved results reported by Laclede Group's Gas Utility Segment, which included a full quarter's impact of MGE operations totaling $12.7 million. This increase was partially offset by lower earnings from the Gas Marketing Segment of $2.4 million. Acquisition-related costs, among other items, are excluded from net economic earnings, which were $36.3 million for the three months ended December 31, 2013, compared with $28.2 million for the same period last year. Net economic earnings per share were $1.11 for the three months ended December 31, 2013, compared with $1.25 for the three months ended December 31, 2012.

Gas Utility

Gas Utility net income and net economic earnings increased by $10.1 million and $10.5 million, respectively for the three months ended December 31, 2013, compared with the three months ended December 31, 2012. The increase was primarily due to higher operating margin (a non-GAAP measure, as discussed below) of $57.2 million, which included a full quarter's impact of MGE operating margin totaling $51.3 million. These benefits were partially offset by an increase in other operating expenses of $35.9 million, which included a full quarter's impact of MGE operating expenses and depreciation and amortization expenses totaling $23.2 million and $7.6 million, respectively, higher interest expense totaling $4.3 million, and increased income tax expenses of $7.0 million relating the Utility.

29

Gas Marketing

The Gas Marketing segment reported GAAP earnings totaling $0.5 million, a decrease of $2.4 million compared with the same period last year. Net economic earnings for the three months ended December 31, 2013 decreased $2.5 million compared with the three months ended December 31, 2012. The decreases in net income and net economic earnings was primarily attributable to decreases in operating margin, as discussed below.

Other

The Other segment reported a lower net loss of $2.3 million as compared with the same period last year. The decrease in net loss was primarily due to prior year acquisition-related expenses of MGE and NEG from SUG totaling $2.2 million, net of tax, and other minor expenses during the three months ended December 31, 2012. Net economic losses for the three months ended December 31, 2013 decreased $0.1 million as compared with the prior year first quarter.

Operating Revenues and Operating Expenses

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

(Millions)		Gas Utility		Gas Marketing		Other			Eliminations			Total
Three Months Ended December 31, 2013
	Operating Revenues	$	435.3	$	52.7	$	0.6		$	(20.0	)	$	468.6
	Natural and propane gas expense	261.6		50.5		—			(19.8		)	292.3
	Gross receipts tax expense	19.5		—		—			—			19.5
	Operating margin (non-GAAP)	154.2		2.2		0.6			(0.2		)	156.8
	Depreciation and amortization	20.0		0.1		0.1			—			20.2
	Other operating expenses	71.6		1.2		1.1			(0.2		)	73.7
	Operating income (GAAP)	$	62.6	$	0.9	$	(0.6	)	$	—		$	62.9
Three Months Ended December 31, 2012
	Operating revenues	$	250.8	$	62.2	$	1.8		$	(7.8	)	$	307.0
	Natural and propane gas expense	144.1		56.2		0.2			(7.8		)	192.7
	Gross receipts tax expense	9.7		—		—			—			9.7
	Operating margin (non-GAAP)	97.0		6.0		1.6			—			104.6
	Depreciation and amortization	11.0		0.1		0.3			—			11.4
	Other operating expenses	44.7		1.1		5.3			—			51.1
	Operating income (GAAP)	$	41.3	$	4.8	$	(4.0	)	$	—		$	42.1

Consolidated

Laclede Group reported operating revenues of $468.6 million for the three months ended December 31, 2013 compared with $307.0 million for the same period last year. Laclede Group's operating margin increased $52.2 million for the three months ended December 31, 2013 compared with the same period last year primarily due to higher Gas Utility operating margin, partially offset by lower operating margin reported by the Gas Marketing segment as discussed below. Depreciation and amortization expenses were $20.2 million for the three months ended December 31, 2013, compared with $11.4 million for the same period last year. Other operating expenses were $73.7 million for the three months ended December 31, 2013, compared with $51.1 million for the same period last year. The increase was primarily due to full quarter's impact of MGE operating expenses and depreciation and amortization expenses totaling $23.2 million and $7.6 million, respectively.

30

Gas Utility

Operating Revenues - Gas Utility operating revenues for the three months ended December 31, 2013 were $435.3 million, or $184.5 million more than the same period last year. The increase in Gas Utility operating revenues was primarily attributable to the following factors:

(Millions)
New customer revenue from MGE	$	160.1
Higher system sales volumes and other variations	28.7
Lower wholesale gas costs passed on to Utility customers	(8.2		)
Optimization of assets	3.8
Total Variation	$	184.4

Temperatures experienced in the Utility’s service area during the three months ended December 31, 2013 were 18.1% colder than the same period last year, and 7.6% colder than normal. Total system therms sold and transported were 308.3 million for the three months ended December 31, 2013, compared with 261.1 million for the same period last year. Total off-system therms sold and transported were 62.3 million for the three months ended December 31, 2013, compared with 80.4 million for the same period last year.

Operating Margin - Gas Utility operating margin was $154.2 million for the three months ended December 31, 2013, a $57.2 million increase over the same period last year. The increase was primarily due to the impact of MGE's operating margin totaling $51.3 million, better optimization of assets totaling $4.2 million and higher usage of natural gas reflecting colder weather and modest customer growth totaling $1.7 million.

Operating Expenses - Other operating expenses for the three months ended December 31, 2013 increased $35.9 million from the same period last year. The increase was primarily due to full quarter's impact of MGE operating expenses and depreciation and amortization expenses totaling $23.2 million and $7.6 million, respectively. The increase was also a result of higher employee-related expenses. Depreciation and amortization expense increased $1.4 million primarily due to additional depreciable property. Taxes, other than income taxes, increased $0.4 million, primarily due to higher real estate and property taxes.

Gas Marketing

Operating Revenues - Gas Marketing operating revenues during the three months ended December 31, 2013 decreased $9.5 million from the same period last year primarily due to lower volumes sold, partially offset by higher per unit gas sales prices.

Operating Margin - Gas Marketing operating margin during the three months ended December 31, 2013 decreased $3.8 million from the same period last year. The decrease in operating margin was primarily attributable to reduced sales margins, reflecting the expirations of favorable supply contracts.

Other

Operating Revenues and Operating Expenses - Other operating revenues and operating margin decreased by $1.2 million and $1.0 million, respectively, during the three months ended December 31, 2013 from the same period last year. The decrease was primarily due to prior year acquisition-related expenses related to the acquisition of MGE.

Other Income and (Income Deductions) - Net

Other Income and (Income Deductions) - Net increased $0.6 million primarily due to higher net investment gains.

Interest Charges

Interest charges during the three months ended December 31, 2013 increased $4.4 million from the same period last year. The increase was primarily due to the net effect of the December 2012, March 2013, and August 2013 issuances of additional long-term debt of $25 million, $100 million, and $450 million, respectively, and the October 2012 maturity of $25 million of 6 1/2% first mortgage bonds. Average short-term interest rates were 0.3% for both the three months ended December 31, 2013 and 2012. Average short-term borrowings were $93.2 million for the three months ended December 31, 2013, compared with $74.9 million for the three months ended December 31, 2012.

Income Taxes

Income taxes during the three months ended December 31, 2013 increased $6.9 million from the same period last year primarily due to higher pre-tax income.

31

REGULATORY AND OTHER MATTERS

A petition was filed with the Massachusetts Department of Public Utilities (MDPU) on January 24, 2013 for approval of the Company's acquisition of NEG. In accordance with the February 11, 2013 agreement between Laclede Group and Algonquin Power Utilities Corporation (APUC) providing for the sale of the Company’s subsidiary, Plaza Mass, to Liberty Utilities, an APUC subsidiary, an amended petition was filed with DPU on February 19, 2013 requesting that the DPU authorize the sale of NEG to Liberty Utilities. Evidentiary hearings were held in June and August 2013. On December 13, 2013, the MDPU approved the sale of NEG to Liberty Utilities. On December 20, 2013, the Company closed the sale of Plaza Mass and received $11.0 million from APUC. This receipt of funds effectively reduced the Utility's purchase price of MGE to $964 million. On December 24, 2013, the Massachusetts Attorney General filed a Motion for Clarification/Reconsideration with the MDPU which, among other things, claims that legislative approval is required for a transfer of utility assets. The MDPU has not yet acted on the Attorney General’s Motion.

On September 16, 2013, MGE filed tariff sheets in a new general rate case proceeding that were designed to increase the Utility's total revenues by $23.4 million, less the current annualized ISRS revenues of $6.3 million that were already being recovered from customers. Consistent with its normal practice, the MoPSC suspended implementation of the MGE proposed rates on September 17, 2013 and set the case for hearing in April 2014. On December 6, 2013, MGE filed for a $1.6 million increase in ISRS revenues to recover the costs of gas safety replacement investments and public improvement projects over the previous nine months.

CRITICAL ACCOUNTING POLICIES

Our discussion and analysis of our financial condition, results of operations, liquidity, and capital resources is based upon our consolidated financial statements, which have been prepared in accordance with GAAP. GAAP requires that we make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We evaluate our estimates on an ongoing basis. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates. Our critical accounting policies used in the preparation of our Consolidated Financial Statements are described in Item 7 of our Annual Report on Form 10-K for the fiscal year ended September 30, 2013 and include the following:

• Accounts receivable and allowance for doubtful accounts

• Employee benefits and postretirement obligations

• Regulated operations

• Gas Marketing energy contracts

There were no significant changes to these critical accounting policies during the three months ended December 31, 2013.

For discussion of other significant accounting policies, see Note 1 of the Notes to Consolidated Financial Statements included in the Company’s Form 10-K for the fiscal year ended September 30, 2013.

32

FINANCIAL CONDITION

CASH FLOWS

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

Net cash used in operating activities was $15.7 million for the three months ended December 31, 2013, compared with net cash provided by operating activities of $3.9 million for the three months ended December 31, 2012. The variation is primarily associated with the seasonality of the accounts receivable balances reflecting the inclusion of MGE's operations and higher operating revenues. This increase in cash used is partially offset by a higher sendout of natural gas stored underground, the timing of collections of gas cost under the Utility's PGA Clause, higher net income, and higher depreciation, amortization, and accretion as compared to the prior year first quarter.

Net cash used in investing activities for the three months ended December 31, 2013 was $24.3 million, compared with $28.7 million for the three months ended December 31, 2012. The decrease primarily reflects the receipt of $11.0 million associated with the sale of NEG to APUC, partially offset by additional capital expenditures this year for distribution plant investments.

Net cash provided by financing activities was $21.6 million for the three months ended December 31, 2013, compared with $43.9 million for the three months ended December 31, 2012. The variation primarily reflects a decrease in net issuances of short-term debt.

LIQUIDITY AND CAPITAL RESOURCES

Cash and Cash Equivalents

Laclede Group had no temporary cash investments at December 31, 2013. Due to lower yields available to Laclede Group on short-term investments, the Company elected to provide a portion of the Utility’s short-term funding through intercompany lending during the three months ended December 31, 2013.

Short-term Debt

As indicated in the discussion of cash flows above, the Company’s short-term borrowing requirements typically peak during the colder months. These short-term cash requirements can be met through the sale of commercial paper supported by lines of credit with banks or through direct use of the lines of credit. At December 31, 2013, the Utility had a syndicated line of credit in place of $450 million from nine banks, which is scheduled to expire in September 2018. The largest portion provided by a single bank is 15.6%. The Utility's line of credit includes a covenant limiting total debt, including short-term debt, to no more than 70% of total capitalization. As defined in the line of credit, total debt was 51% of total capitalization on December 31, 2013.

Short-term cash requirements outside of the Utility have generally been met with internally generated funds. Laclede Group also has a $150 million syndicated line of credit which expires in September 2018, to meet short-term liquidity needs of its subsidiaries. The line of credit has a covenant limiting the total debt of the consolidated Laclede Group to no more than 70% of the Company’s total capitalization. As defined in the line of credit, this ratio stood at 49% on December 31, 2013. Occasionally, Laclede Group’s line may be used to provide for the funding needs of various subsidiaries. There were no borrowings under Laclede Group’s line during the three months ended December 31, 2013.

On December 6, 2013, the Utility provided a notice of redemption to holders for the entire $80 million aggregate principal amount outstanding of its previously issued 6.35% Series bonds due in 2038. The redemption, which was for cash and included accrued interest, was effective January 6, 2014. In accordance with GAAP, the $80 million principle balance was recorded in Current portion of long-term debt in the Consolidated Balance Sheet as of December 31, 2013.

33

Information about Laclede Group’s consolidated short-term borrowings (excluding the current portion of long-term debt and intercompany borrowings) as of and during the three months ended December 31, 2013, is presented below:

	Commercial Paper Borrowings
Three Months Ended December 31, 2013
Weighted average borrowings outstanding	$93.2 million
Weighted average interest rate	0.3%
Range of borrowings outstanding	$70 - $116.2 million
As of December 31, 2013
Borrowings outstanding at end of period	$93.5 million
Weighted average interest rate	0.3%

Based on average short-term borrowings for the three months ended December 31, 2013, an increase in the average interest rate of 100 basis points would decrease Laclede Group’s pre-tax earnings and cash flows by approximately $0.9 million on an annual basis, portions of which may be offset through the application of PGA carrying costs.

Long-term Debt, Equity, and Shelf Registrations

The Utility has MoPSC authority to issue debt securities and preferred stock, including on a private placement basis, as well as to issue common stock, receive paid-in capital, and enter into capital lease agreements, all for a total of up to $518 million. This authorization is effective through June 30, 2015. During the three months ended December 31, 2013, pursuant to this authority, the Utility sold 9 shares of its common stock to Laclede Group for $0.4 million. As of February 1, 2014, $370.5 million remains available under this authorization. Laclede Gas has a shelf registration on Form S-3 for issuance of first mortgage bonds, unsecured debt, and preferred stock, which expires August 6, 2016. First mortgage bonds in the amount of $450 million were issued under this registration during fiscal year 2013. The amount, timing, and type of additional financing to be issued under this shelf registration will depend on cash requirements and market conditions, as well as future MoPSC authorizations.

At December 31, 2013, Laclede Group had fixed-rate long-term debt totaling $915 million, including the current portion. Of the $915 million long-term debt, $890 million is attributed to the Utility and $25 million is attributed to Laclede Group. The long-term debt issues are fixed-rate and are subject to changes in their fair value as market interest rates change. However, increases or decreases in fair value would impact earnings and cash flows only if the Company were to reacquire any of these issues in the open market prior to maturity. Under GAAP applicable to Laclede Gas’ regulated operations, losses or gains on early redemptions of long-term debt would typically be deferred as regulatory assets or regulatory liabilities and amortized over a future period. Of the Utility’s $890 million in long-term debt, $50 million have no call option, $410 million have make-whole call options, $350 million are callable at par three to six months prior to maturity, and $80 million are callable at par beginning in October 2013. Laclede Group's debt has a make-whole call option. None of the debt has any put options. On December 6, 2013, Laclede Gas gave notice that it would call the $80 million in callable bonds, which was completed on January 6, 2014.

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 186,117 and 179,183 shares at December 31, 2013 and January 31, 2014, respectively, remaining available for issuance under its Form S-3. Laclede Group also has a shelf registration statement on Form S-3 for the issuance of equity and debt securities. No securities have been issued under that S-3. The amount, timing, and type of financing to be issued under this shelf registration will depend on cash requirements and market conditions.

Other

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

Utility capital expenditures were $34.6 million for the three months ended December 31, 2013, compared with $27.7 million for the same period last year. The increase in capital expenditures, compared with the prior period, is primarily attributable to additional expenditures for distribution plant investments. Non-utility capital expenditures were negligible during the three months ended December 31, 2013 and 2012.

Consolidated capitalization at December 31, 2013 consisted of 56.2% common stock equity and 43.8% long-term debt.

34

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

The seasonal nature of the Utility's sales affects the comparison of certain balance sheet items at December 31, 2013 and at September 30, 2013, such as Accounts receivable - net, Gas stored underground, Notes payable, Accounts payable, Regulatory assets and Regulatory liabilities, and Advance customer billings. The Consolidated Balance Sheet at December 31, 2012 is presented to facilitate comparison of these items with the corresponding interim period of the preceding fiscal year.

CONTRACTUAL OBLIGATIONS

As of December 31, 2013, Laclede Group had contractual obligations with payments due as summarized below (in millions):

			Payments due by period
Contractual Obligations	Total		Remaining Fiscal Year 2014		Fiscal Years 2015-2016		Fiscal Years 2017-2018		Fiscal Years 2019 and thereafter
Principal Payments on Long-Term Debt	$	915	$	80	$	—	$	100	$	735
Interest Payments on Long-Term Debt	687		32		81		81		493
Capital Leases (a)	—		—		—		—		—
Operating Leases (a)	11		5		5		1		—
Purchase Obligations – Natural Gas (b)	1,127		520		310		203		94
Purchase Obligations – Other (c)	73		21		20		19		13
Other Long-Term Liabilities	157		12		31		32		82
Total (d)	$	2,970	$	670	$	447	$	436	$	1,417

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

(b) These purchase obligations represent the minimum payments required under existing natural gas transportation and storage contracts and natural gas supply agreements in the Gas Utility and Gas Marketing segments. These amounts reflect fixed obligations as well as obligations to purchase natural gas at future market prices, calculated using December 31, 2013 forward market prices. Laclede Gas recovers the costs related to its purchases, transportation, and storage of natural gas through the operation of its PGA Clause, subject to prudence review by the MoPSC; however, variations in the timing of collections of gas costs from customers affect short-term cash requirements. Additional contractual commitments are generally entered into prior to or during the heating season.

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

(d) Long-term liabilities associated with unrecognized tax benefits, totaling $2.8 million, have been excluded from the table above because the timing of future cash outflows, if any, cannot be reasonably estimated. Also, commitments related to pension and postretirement benefit plans have been excluded from the table above. Contributions to the pension plans for the remaining nine months of fiscal 2014 are anticipated to be approximately $16.1 million to the qualified trusts and $0.4 million to the non-qualified plans. With regard to the postretirement benefits, the Utility anticipates contributing $19.2 million to the qualified trusts and $0.3 million directly to participants from the Utility’s funds during the remaining nine months of fiscal year 2014. For further discussion of the Company’s pension and postretirement benefit plans, refer to Note 3, Pension Plans and Other Postretirement Benefits, of the Notes to Consolidated Financial Statements. The Spire facility capital lease is not included as there is no cash outlay.

35

MARKET RISK

Commodity Price Risk

The Utility's commodity price risk, which arises from market fluctuations in the price of natural gas, is primarily managed through the operation of its PGA Clause. The PGA Clause allows the Utility to flow through to customers, subject to prudence review by the MoPSC, the cost of purchased gas supplies. The Utility is allowed the flexibility to make up to three discretionary PGA changes during each year, in addition to its mandatory November PGA change, so long as such changes are separated by at least two months. The Utility is able to mitigate, to some extent, changes in commodity prices through the use of physical storage supplies and regional supply diversity. The Utility also has a risk management policy that allows for the purchase of natural gas derivative instruments with the goal of managing its price risk associated with purchasing natural gas on behalf of its customers. This policy prohibits speculation. Costs and cost reductions, including carrying costs, associated with the Utility’s use of natural gas derivative instruments are allowed to be passed on to the Utility’s customers through the operation of its PGA Clause. Accordingly, the Utility does not expect any adverse earnings impact as a result of the use of these derivative instruments. However, the timing of recovery for cash payments related to margin requirements may cause short-term cash requirements to vary. Nevertheless, carrying costs associated with such requirements, as well as other variations in the timing of collections of gas costs, are recovered through the PGA Clause. For more information about the Utility’s natural gas derivative instruments, see Note 8, Derivative Instruments and Hedging Activities, of the Notes to Consolidated Financial Statements.

In the course of its business, Laclede Group’s gas marketing subsidiary, LER, enters into contracts to purchase and sell natural gas at fixed prices and natural gas index-based prices. Commodity price risk associated with these contracts has the potential to impact earnings and cash flows. To minimize this risk, LER has a risk management policy that provides for daily monitoring of a number of business measures, including fixed price commitments. In accordance with the risk management policy, LER manages the price risk associated with its fixed-price commitments. This risk is currently managed either by closely matching the offsetting physical purchase or sale of natural gas at fixed-prices or through the use of natural gas futures, options, and swap contracts traded on or cleared through the NYMEX and ICE to lock in margins. At December 31, 2013, LER’s unmatched fixed-price positions were not material to Laclede Group’s financial position or results of operations.

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

(Thousands)	Derivative Fair Values			Cash Margin		Derivatives and Cash Margin
Net balance of derivative (liabilities) assets at September 30, 2013	$	2,643		$	254	$	2,897
Changes in fair value	(3,723		)	—		(3,723		)
Settlements/purchases - net	229			—		229
Changes in cash margin	—			4,227		4,227
Net balance of derivative assets (liabilities) at December 31, 2013	$	(851	)	$	4,481	$	3,630

	At December 31, 2013
	Maturity by Fiscal Year
(Thousands)	Total			2014			2015			2016			2017
Fair values of exchange-traded/cleared natural gas derivatives - net	$	(926	)	$	(1,015	)	$	93		$	(2	)	$	(2	)
MMBtu – net (short) long futures/swap/option positions	(9,395		)	(9,398		)	(100		)	88			15
Fair values of basis swaps - net	$	75		$	—		$	—		$	64		$	11
MMBtu – net (short) long basis swap positions	1,070			—			—			915			155

36

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

(Thousands)
Net balance of derivative assets at September 30, 2013	$	99
Changes in fair value	1,667
Settlements	(447		)
Net balance of derivative assets at December 31, 2013	$	1,319

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

Counterparty Credit Risk

LER has concentrations of counterparty credit risk in that a significant portion of its transactions are with (or are associated with) energy producers, utility companies, and pipelines. These concentrations of counterparties have the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that each of these three groups may be affected similarly by changes in economic, industry, or other conditions. LER also has concentrations of credit risk with certain individually significant counterparties. To the extent possible, LER enters into netting arrangements with its counterparties to mitigate exposure to credit risk. Although not recorded on the consolidated balance sheets, LER is also exposed to credit risk associated with its derivative contracts designated as normal purchases and normal sales.

LER closely monitors its credit exposure and, although uncollectible amounts have not been significant, increased counterparty defaults are possible and may result in financial losses and/or capital limitations. For more information on these concentrations of credit risk, including how LER manages these risks, see Note 9, Concentrations of Credit Risk, of the Notes to Consolidated Financial Statements.

Interest Rate Risk

The Company is subject to interest rate risk associated with its long-term and short-term debt issuances. Based on average short-term borrowings during the three months ended December 31, 2013, an increase of 100 basis points in the underlying average interest rate for short-term debt would have caused an increase in interest expense of approximately $0.9 million on an annual basis. Portions of such increases may be offset through the application of PGA carrying costs. At December 31, 2013, the Utility had fixed-rate long-term debt totaling $890 million, including the current portion. Additionally, Laclede Group had fixed-rate long-term debt totaling $25 million. While these long-term debt issues are fixed-rate, they are subject to changes in fair value as market interest rates change. However, increases or decreases in fair value would impact earnings and cash flows only if the Company were to reacquire any of these issues in the open market prior to maturity. Under GAAP applicable to the Utility’s regulated operations, losses or gains on early redemptions of its long-term debt would typically be deferred as regulatory assets or regulatory liabilities and amortized over a future period.

ENVIRONMENTAL MATTERS

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

OFF-BALANCE SHEET ARRANGEMENTS

Laclede Group has no off-balance sheet arrangements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

For this discussion, see Part I., Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Risk, on page 36 of this report.

37

Item 4. Controls and Procedures

Disclosure Controls and Procedures

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

Effective September 1, 2013, we acquired Missouri Gas Energy (MGE). As the acquisition occurred during the last 12 months, the scope of our assessment of the effectiveness of disclosure controls and procedures does not include MGE. This exclusion is in accordance with the SEC’s general guidance that an assessment of a recently acquired business may be omitted from our scope in the year following the acquisition.

Changes in Internal Control over Financial Reporting

As a result of the acquisition of MGE mentioned above, the Company is evaluating and implementing changes to processes, policies and other components of its internal control over financial reporting with respect to the consolidation of MGE’s operations into the Company’s financial statements. Management continues to be engaged in substantial efforts to evaluate the effectiveness of our internal control procedures and the design of those control procedures relating to MGE. Except for the activities described above, there were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended December 31, 2013 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

38

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For a description of environmental matters and legal proceedings, see Note 12, Commitments and Contingencies, of the Notes to Consolidated Financial Statements. For a description of pending regulatory matters of Laclede Group, see Part I., Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Regulatory and Other Matters, on page 32 of this report.

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

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

During the quarter ended December 31, 2013, the only repurchases of our common stock were pursuant to elections by employees to have shares of stock withheld to cover employee tax withholding obligations upon the vesting of performance-based and time-vested restricted stock and stock units. The following table provides information on those repurchases.

Period	Total No. of Shares Purchases	Average Price Paid Per Share	Total No. of Shares Purchased as Part of Publicly Announced Plans	Maximum No. of Shares that May Yet be Purchased Under the Plans
October 1, 2013 – October 31, 2013	649	$45.29	—	—
November 1, 2013 – November 30, 2013	—	—	—	—
December 1, 2013 – December 31, 2013	22,334	$45.85	—	—
Total	22,983	—	—	—

Item 6. Exhibits

(a) See Exhibit Index

39

SIGNATURE

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

		The Laclede Group, Inc.
Dated:	February 4, 2014	By:	/s/ Steven P. Rasche
			Steven P. Rasche
			Executive Vice President, Chief Financial Officer
			(Authorized Signatory and Principal Accounting Officer)

40

INDEX TO EXHIBITS

Exhibit No.
10.1	-	Lease Agreement between The Laclede Group, Inc., as Tenant, and Market 700, LLC, as Landlord, dated January 21, 2014; filed as Exhibit 10.1 to Laclede Group's Form 8-K dated January 27, 2014 and incorporated herein (File No. 1-16681).
12	-	Ratio of Earnings to Fixed Charges.
31	-	CEO and CFO Certifications under Exchange Act Rule 13a – 14(a).
32	-	CEO and CFO Section 1350 Certifications.
101.INS	-	XBRL Instance Document. (1)
101.SCH	-	XBRL Taxonomy Extension Schema. (1)
101.CAL	-	XBRL Taxonomy Extension Calculation Linkbase. (1)
101.DEF	-	XBRL Taxonomy Definition Linkbase. (1)
101.LAB	-	XBRL Taxonomy Extension Labels Linkbase. (1)
101.PRE	-	XBRL Taxonomy Extension Presentation Linkbase. (1)

(1) Attached as Exhibit 101 to this Quarterly Report are the following documents formatted in extensible business reporting language (XBRL): (i) Document and Entity Information; (ii) unaudited Statements of Consolidated Income for the three months ended December 31, 2013 and 2012; (iii) unaudited Statements of Consolidated Comprehensive Income for the three months ended December 31, 2013 and 2012; (iv) unaudited Consolidated Balance Sheets at December 31, 2013, September 30, 2013 and December 31, 2012; (v) unaudited Statements of Consolidated Cash Flows for the three months ended December 31, 2013 and 2012, and (vi) Notes to the unaudited Consolidated Financial Statements. We also make available on our website the Interactive Data Files submitted as Exhibit 101 to this Quarterly Report. 

41

EX-12

Exhibit 12

THE LACLEDE GROUP, INC. AND SUBSIDIARY COMPANIES

SCHEDULE OF COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

	Twelve Months Ended
	Dec. 31,		September 30,
(Thousands of Dollars)	2013		2013		2012		2011		2010		2009
Income from continuing      operations before interest
charges and income taxes	$	120,322	$	98,938	$	113,875	$	118,424	$	107,986	$	126,517
Add: One third of applicable
rentals charged to operating
expense (which approximates
the interest factor)	2,030		2,009		1,591		1,799		1,825		1,833
Total Earnings	$	122,352	$	100,947	$	115,466	$	120,223	$	109,811	$	128,350
Interest on long-term debt	$	29,796	$	25,539	$	22,958	$	23,161	$	24,583	$	24,583
Other interest	3,242		3,063		1,988		2,256		2,269		5,163
Add: One third of applicable
rentals charged to operating
expense (which approximates
the interest factor)	2,030		2,009		1,591		1,799		1,825		1,833
Total Fixed Charges	$	35,068	$	30,611	$	26,537	$	27,216	$	28,677	$	31,579
Ratio of Earnings to Fixed
Charges	3.49		3.30		4.35		4.42		3.83		4.06

EX-31

Exhibit 31

CERTIFICATION

I, Suzanne Sitherwood, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	February 4, 2014	Signature:	/s/ Suzanne Sitherwood
			Suzanne Sitherwood
			President and Chief Executive Officer

CERTIFICATION

I, Steven P. Rasche, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	February 4, 2014	Signature:	/s/ Steven P. Rasche
			Steven P. Rasche
			Executive Vice President and Chief Financial Officer

EX-32

Exhibit 32

Section 1350 Certification

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

(a) To the best of my knowledge, the accompanying report on Form 10-Q for the quarter ended December 31, 2013 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and

(b) To the best of my knowledge, the information contained in the accompanying report on Form 10-Q for the quarter ended December 31, 2013 fairly presents, in all material respects, the financial condition and results of operations of The Laclede Group, Inc.

Date:	February 4, 2014	Signature:	/s/ Suzanne Sitherwood
			Suzanne Sitherwood
			President and Chief Executive Officer

Section 1350 Certification

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

(a) To the best of my knowledge, the accompanying report on Form 10-Q for the quarter ended December 31, 2013 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and

(b) To the best of my knowledge, the information contained in the accompanying report on Form 10-Q for the quarter ended December 31, 2013 fairly presents, in all material respects, the financial condition and results of operations of The Laclede Group, Inc.

Date:	February 4, 2014	Signature:	/s/ Steven P. Rasche
			Steven P. Rasche
			Executive Vice President and Chief Financial Officer

XML

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Part 2) (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 11,211	$ 6,276	$ 4,832
Derivative Liability, Fair Value, Gross Liability	4,945	10,629	8,578
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	1,145	2,349	1,236
Derivative Liability, Fair Value, Gross Liability	1,031	451	871
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	10,066	3,927	3,596
Derivative Liability, Fair Value, Gross Liability	3,914	10,178	7,707
NYMEX Natural Gas Contracts [Member] | Designated as Hedging Instrument [Member] | Derivative Instruments Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	881
Derivative Liability, Fair Value, Gross Liability	1,030
NYMEX Natural Gas Contracts [Member] | Designated as Hedging Instrument [Member] | Other Deferred Charges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	110	22
Derivative Liability, Fair Value, Gross Liability	1	11
NYMEX Natural Gas Contracts [Member] | Designated as Hedging Instrument [Member] | Accounts Receivable Other [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		2,222	987
Derivative Liability, Fair Value, Gross Liability		440	871
NYMEX Natural Gas Contracts [Member] | Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		950
Derivative Liability, Fair Value, Gross Liability		100
NYMEX Natural Gas Contracts [Member] | Not Designated as Hedging Instrument [Member] | Derivative Instruments Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	571		1,726
Derivative Liability, Fair Value, Gross Liability	955		6,162
NYMEX Natural Gas Contracts [Member] | Not Designated as Hedging Instrument [Member] | Other Deferred Charges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	3	32
Derivative Liability, Fair Value, Gross Liability	7	0
NYMEX Natural Gas Contracts [Member] | Not Designated as Hedging Instrument [Member] | Accounts Receivable Other [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	2,802	1,434	533
Derivative Liability, Fair Value, Gross Liability	285	3,455	366
OTCBB Natural Gas Contracts [Member] | Not Designated as Hedging Instrument [Member] | Other Deferred Credits [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	223	4
Derivative Liability, Fair Value, Gross Liability	278	1,398
OTCBB Natural Gas Contracts [Member] | Not Designated as Hedging Instrument [Member] | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	3,386
Derivative Liability, Fair Value, Gross Liability	636
Natural Gas Commodity Contracts [Member] | Not Designated as Hedging Instrument [Member] | Derivative Instruments Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	1,915	991	1,197
Derivative Liability, Fair Value, Gross Liability	272	90	240
Natural Gas Commodity Contracts [Member] | Not Designated as Hedging Instrument [Member] | Other Deferred Credits [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	183	21
Derivative Liability, Fair Value, Gross Liability	161	123
Natural Gas Commodity Contracts [Member] | Not Designated as Hedging Instrument [Member] | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	333	247	108
Derivative Liability, Fair Value, Gross Liability	1,283	830	939
Natural Gas Commodity Contracts [Member] | Not Designated as Hedging Instrument [Member] | Other Deferred Charges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	641	20
Derivative Liability, Fair Value, Gross Liability	37	137
NYMEX Gasoline and Heating Oil Contracts [Member] | Designated as Hedging Instrument [Member] | Accounts Receivable Other [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	154	105	249
Derivative Liability, Fair Value, Gross Liability	0	0	0
NYMEX Gasoline and Heating Oil Contracts [Member] | Not Designated as Hedging Instrument [Member] | Derivative Instruments Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	9
Derivative Liability, Fair Value, Gross Liability	0
NYMEX Gasoline and Heating Oil Contracts [Member] | Not Designated as Hedging Instrument [Member] | Accounts Receivable Other [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		228	32
Derivative Liability, Fair Value, Gross Liability		$ 4,045	$ 0

XML

SUBSEQUENT EVENT Filing for an increase in ISRS revenues (Details) (USD $) In Millions, unless otherwise specified	Jan. 17, 2014
Subsequent Events [Abstract]
Filing for a increase in ISRS Revenues	$ 7.4

XML

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 2 (Details) (USD $)	3 Months Ended	9 Months Ended				3 Months Ended
	Dec. 31, 2013	Sep. 30, 2014	Dec. 31, 2010	Dec. 31, 2010 Laclede Gas [Member]	Feb. 20, 2010 Missouri Gas Energy (MGE) [Member]	Dec. 31, 2013 Pension Plan, Defined Benefit [Member]	Dec. 31, 2012 Pension Plan, Defined Benefit [Member]	Dec. 31, 2013 Other Postretirement Benefit Plan, Defined Benefit [Member]	Dec. 31, 2012 Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan Net Periodic Benefit Cost After Regulatory Adjustment						$ 6,579,000	$ 4,177,000	$ 2,381,000	$ 2,381,000
Extent of Lump-sum payments recognized, percentage	100.00%
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	10,000,000
Anticipated Contributions To Pension Plans Qualified Trusts		24,000,000
Recovery in rates for postretirement benefit			9,500,000
Document Period End Date	Dec. 31, 2013
Anticipated Contributions To Postretirement Plans Qualified Trusts	19,200,000
Defined Benefit Plan, Pension Plans, Qualified Trusts, Contributions by Employer, Fiscal Year To Date	3,800,000
Anticipated Contributions To Pension Plans Non Qualified Trusts		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 payment directly to participants in postretirement plan	$ 300,000

XML

FAIR VALUE MEASUREMENTS (Tables)

3 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Fair Value Measurements, Measured on Recurring Basis

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

(Thousands)	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Effects of Netting and Cash Margin Receivables /Payables			Total
As of December 31, 2013
Assets
U. S. Stock/Bond Mutual Funds	$	15,003	$	—	$	—	$	—		$	15,003
NYMEX/ICE natural gas contracts	3,697		670		—		(3,839		)	528
OTCBB natural gas contracts	—		3,609		—		(913		)	2,696
NYMEX gasoline and heating oil contracts	163		—		—		—			163
Natural gas commodity contracts	—		3,044		29		(826		)	2,247
Total	$	18,863	$	7,323	$	29	$	(5,578	)	$	20,637
Liabilities
NYMEX/ICE natural gas contracts	$	2,013	$	265	$	—	$	(2,278	)	$	—
OTCBB natural gas contracts	—		913		—		(913		)	—
Natural gas commodity contracts	—		1,732		22		(826		)	928
Total	$	2,013	$	2,910	$	22	$	(4,017	)	$	928
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
Natural gas commodity contracts	—		1,140		40		(495		)	685
Total	$	3,687	$	6,904	$	40	$	(4,735	)	$	5,896
As of December 31, 2012
Assets
U. S. Stock/Bond Mutual Funds	$	13,146	$	—	$	—	$	—		$	13,146
NYMEX/ICE natural gas contracts	2,497		749		—		(2,962		)	284
NYMEX gasoline and heating oil contracts	281		—		—		(281		)	—
Natural gas commodity contracts	—		1,228		77		(348		)	957
Total	$	15,924	$	1,977	$	77	$	(3,591	)	$	14,387
Liabilities
NYMEX/ICE natural gas contracts	$	6,650	$	749	$	—	$	(7,399	)	$	—
Natural gas commodity contracts	—		1,132		47		(348		)	831
Total	$	6,650	$	1,881	$	47	$	(7,747	)	$	831

Reconciliation of the Level 3 beginning and ending net derivative balances

	Three Months Ended December 31,
(Thousands)	2013			2012
Beginning of period	$	110		$	109
Net settlements	(108		)	(66		)
Net gains related to derivatives still held at end of period	5			(13		)
End of period	$	7		$	30

XML

OTHER INCOME AND (INCOME DEDUCTIONS) - NET (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Other Nonoperating Income (Expense) [Abstract]
Net investment gain	$ 249	$ 406
Other income	746	(70)
Other income deductions	652	748
Other (Income Deductions) and Income - Net	$ 1,647	$ 1,084

XML

FAIR VALUE MEASUREMENTS (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 Fair Value, Measurements, Recurring [Member]	Sep. 30, 2013 Fair Value, Measurements, Recurring [Member]	Dec. 31, 2012 Fair Value, Measurements, Recurring [Member]	Dec. 31, 2013 Fair Value, Measurements, Recurring [Member] Quoted Prices in Active Markets (Level 1) [Member]	Sep. 30, 2013 Fair Value, Measurements, Recurring [Member] Quoted Prices in Active Markets (Level 1) [Member]	Dec. 31, 2012 Fair Value, Measurements, Recurring [Member] Quoted Prices in Active Markets (Level 1) [Member]	Dec. 31, 2013 Fair Value, Measurements, Recurring [Member] Significant Observable Inputs (Level 2) [Member]	Sep. 30, 2013 Fair Value, Measurements, Recurring [Member] Significant Observable Inputs (Level 2) [Member]	Dec. 31, 2012 Fair Value, Measurements, Recurring [Member] Significant Observable Inputs (Level 2) [Member]	Dec. 31, 2013 Fair Value, Measurements, Recurring [Member] Significant Unobservable Inputs (Level 3) [Member]	Sep. 30, 2013 Fair Value, Measurements, Recurring [Member] Significant Unobservable Inputs (Level 3) [Member]	Dec. 31, 2012 Fair Value, Measurements, Recurring [Member] Significant Unobservable Inputs (Level 3) [Member]	Dec. 31, 2013 Fair Value, Measurements, Recurring [Member] Effects of Netting and Cash Margin Receivables Payables [Member]	Sep. 30, 2013 Fair Value, Measurements, Recurring [Member] Effects of Netting and Cash Margin Receivables Payables [Member]	Dec. 31, 2012 Fair Value, Measurements, Recurring [Member] Effects of Netting and Cash Margin Receivables Payables [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
U. S. Stock/Bond Mutual Funds			$ 15,003	$ 14,500	$ 13,146	$ 15,003	$ 14,500	$ 13,146	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0
NYMEX/ICE natural gas contracts- Asset			528	2,518	284	3,697	4,333	2,497	670	330	749	0	0	0	(3,839)	(2,145)	(2,962)
Derivative Assets, OTCBB Natural Gas Contracts, Fair Value			2,696	0		0	0		3,609	232		0	0		(913)	(232)
NYMEX gasoline and heating oil contracts- Asset			163	0	0	163	105	281	0	0	0	0	0	0	0	(105)	(281)
Natural gas commodity contracts- Asset			2,247	784	957	0	0	0	3,044	1,129	1,228	29	150	77	(826)	(495)	(348)
Total Assets			20,637	17,802	14,387	18,863	18,938	15,924	7,323	1,691	1,977	29	150	77	(5,578)	(2,977)	(3,591)
NYMEX/ICE natural gas contracts- Liabilities			0	0	0	2,013	3,687	6,650	265	321	749	0	0	0	(2,278)	(4,008)	(7,399)
Derivative Liabilities, OTCBB Natural Gas Contracts, Fair Value			0	5,211		0	0		913	5,443		0	0		(913)	(232)
Natural gas commodity contracts- Liabilities			928	685	831	0	0	0	1,732	1,140	1,132	22	40	47	(826)	(495)	(348)
Total Liabilities			928	5,896	831	2,013	3,687	6,650	2,910	6,904	1,881	22	40	47	(4,017)	(4,735)	(7,747)
Beginning of period	110	109
Settlements	(108)	(66)
Net gains related to derivatives still held at end of period	5	(13)
End of period	$ 7	$ 30

XML

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS

3 Months Ended

Dec. 31, 2013

Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS

3. PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS

Pension Plans

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

Pension costs for the three months ended December 31, 2013 and 2012 were $6.6 million and $4.2 million, respectively, including amounts charged to construction.

The net periodic pension costs include the following components:

	Three Months Ended December 31,
(Thousands)	2013			2012
Service cost – benefits earned during the period	$	2,428		$	2,311
Interest cost on projected benefit obligation	6,010			4,066
Expected return on plan assets	(6,645		)	(4,741		)
Amortization of prior service cost	124			136
Amortization of actuarial loss	1,772			2,839
Sub-total	3,689			4,611
Regulatory adjustment	2,890			(434		)
Net pension cost	$	6,579		$	4,177

Pursuant to the provisions of the Utility's pension plans, pension obligations may be satisfied by lump-sum cash payments. Pursuant to a Missouri Public Service Commission (MoPSC or Commission) Order, lump-sum payments are recognized as settlements (which can result in gains or losses) only if the total of such payments exceeds 100% of the sum of service and interest costs. There were no lump-sum payments recognized as settlements during the three months ended December 31, 2013 and December 31, 2012, respectively.

Pursuant to a MoPSC Order, the return on plan assets is based on the market-related value of plan assets implemented prospectively over a four-year period. Gains or losses not yet includible in pension cost are amortized only to the extent that such gain or loss exceeds 10% of the greater of the projected benefit obligation or the market-related value of plan assets. Such excess is amortized over the average remaining service life of active participants. The recovery in rates for Laclede Gas' qualified pension plans is based on an annual allowance of $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 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. Fiscal year 2014 contributions to the pension plans through December 31, 2013 were $3.8 million to the qualified trusts. There were no contributions to the non-qualified plans in the first quarter of fiscal 2014. Contributions to the pension plans for the remaining nine months of fiscal 2014 are anticipated to be approximately $24.0 million to the qualified trusts and $0.4 million to the non-qualified plans.

Postretirement Benefits

The Utility provides certain life insurance benefits at retirement. Under the Laclede Gas plans, medical insurance is currently available after early retirement until age 65. Under the MGE plans, medical insurance is currently available upon retirement until death. The transition obligation not yet includible in postretirement benefit cost is being amortized over 20 years. Postretirement benefit costs for both the three months ended December 31, 2013 and 2012 were $2.4 million, including amounts charged to construction.

Net periodic postretirement benefit costs consisted of the following components:

	Three Months Ended December 31,
(Thousands)	2013			2012
Service cost – benefits earned during the period	$	2,804		$	2,533
Interest cost on accumulated postretirement benefit obligation	2,169			1,279
Expected return on plan assets	(1,709		)	(1,081		)
Amortization of transition obligation	—			23
Amortization of prior service cost (credit)	(1		)	1
Amortization of actuarial loss	1,505			1,325
Sub-total	4,768			4,080
Regulatory adjustment	(2,387		)	(1,699		)
Net postretirement benefit cost	$	2,381		$	2,381

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 (VEBA) and Rabbi trusts as its external funding mechanisms. The assets of VEBA and Rabbi trusts consist primarily of money market securities and mutual funds invested in stocks and bonds.

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

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. There were no contributions to the postretirement plans in fiscal 2014 through December 31, 2013. Contributions to the postretirement plans for the remaining nine months of fiscal year 2014 are anticipated to be $19.2 million to the qualified trusts and $0.3 million paid directly to participants from the Utility's funds.

XML

INFORMATION BY OPERATING SEGMENT (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Dec. 31, 2013 subsidiary	Dec. 31, 2012	Sep. 30, 2013
Segment Reporting [Abstract]
Number of entity subsidiaries	7
Operating Segment Information [Abstract]
Revenues from external customers	$ 468,610	$ 307,003
Total Operating Revenues	468,610	307,003
Operating Expenses [Abstract]
Natural and propane gas	241,787	136,515
Utilities Operating Expense, Other	62,322	39,651
Other Operation and Maintenance	62,322	39,651
Depreciation and amortization	20,026	10,965
Taxes, other than income taxes	28,589	14,806
Total Gas Utility Operating Expenses	352,724	201,937
Non-Regulated Gas Marketing	51,782	57,382
Gas Marketing	51,782	57,382
Other Cost and Expense, Operating	1,199	5,599
Total Operating Expenses	405,705	264,918
Operating Income (Loss)	62,905	42,085
Net Economic Earnings (Losses)	36,264	28,233
Total assets	3,206,730	1,942,155	3,125,386
Reconciliation of Consolidated Net Economic Earnings to Consolidated Net Income [Abstract]
Total Net Economic Earnings above	36,264	28,233
Add: Unrealized gain (loss) on energy-related derivative contracts, net of tax	(354)	439
Add: Realized gain (loss) on economic hedges prior to sale of the physical commodity, net of tax	6	(31)
Add: Acquisition, divestiture, and restructuring activities	386
Add: Acquisition, divestiture, and restructuring activities, net of tax		(2,257)
Add: Lower of cost or market inventory adjustments, net of tax	62	0
Net Income	35,592	25,568
Consolidation, Eliminations [Member] | Unallocated and Eliminations [Member]
Operating Segment Information [Abstract]
Revenues from external customers	0	0
Total Operating Revenues	(19,960)	(7,845)
Operating Expenses [Abstract]
Natural and propane gas	(19,766)	(7,818)
Utilities Operating Expense, Other	(194)	0
Depreciation and amortization	0	0
Taxes, other than income taxes	0	0
Total Gas Utility Operating Expenses	(19,960)	(7,818)
Non-Regulated Gas Marketing	0	0
Other Cost and Expense, Operating	0	(27)
Total Operating Expenses	(19,960)	(7,845)
Operating Income (Loss)	0	0
Net Economic Earnings (Losses)	0	0
Total assets	(161,533)	(181,137)
Reconciliation of Consolidated Net Economic Earnings to Consolidated Net Income [Abstract]
Total Net Economic Earnings above	0	0
Regulated Gas Distribution [Member] | Gas Utility [Member]
Operating Segment Information [Abstract]
Revenues from external customers	435,166	250,111
Total Operating Revenues	435,228	250,791
Operating Expenses [Abstract]
Natural and propane gas	261,553	144,333
Utilities Operating Expense, Other	62,516	39,651
Depreciation and amortization	20,026	10,965
Taxes, other than income taxes	28,589	14,806
Total Gas Utility Operating Expenses	372,684	209,755
Non-Regulated Gas Marketing	0	0
Other Cost and Expense, Operating	0	0
Total Operating Expenses	372,684	209,755
Operating Income (Loss)	62,544	41,036
Net Economic Earnings (Losses)	35,778	25,341
Total assets	3,084,134	1,809,722
Reconciliation of Consolidated Net Economic Earnings to Consolidated Net Income [Abstract]
Total Net Economic Earnings above	35,778	25,341
Other [Member] | Other [Member]
Operating Segment Information [Abstract]
Revenues from external customers	191	1,643
Total Operating Revenues	633	1,902
Operating Expenses [Abstract]
Natural and propane gas	0	0
Utilities Operating Expense, Other	0	0
Depreciation and amortization	0	0
Taxes, other than income taxes	0	0
Total Gas Utility Operating Expenses	0	0
Non-Regulated Gas Marketing	0	0
Other Cost and Expense, Operating	1,199	5,626
Total Operating Expenses	1,199	5,626
Operating Income (Loss)	(566)	(3,724)
Net Economic Earnings (Losses)	(336)	(389)
Total assets	126,890	124,967
Reconciliation of Consolidated Net Economic Earnings to Consolidated Net Income [Abstract]
Total Net Economic Earnings above	(336)	(389)
Non-Regulated Gas Marketing [Member] | Gas Marketing [Member]
Operating Segment Information [Abstract]
Revenues from external customers	33,253	55,249
Total Operating Revenues	52,709	62,155
Operating Expenses [Abstract]
Natural and propane gas	0	0
Utilities Operating Expense, Other	0	0
Depreciation and amortization	0	0
Taxes, other than income taxes	0	0
Total Gas Utility Operating Expenses	0	0
Non-Regulated Gas Marketing	51,782	57,382
Other Cost and Expense, Operating	0	0
Total Operating Expenses	51,782	57,382
Operating Income (Loss)	927	4,773
Net Economic Earnings (Losses)	822	3,281
Total assets	157,239	188,603
Reconciliation of Consolidated Net Economic Earnings to Consolidated Net Income [Abstract]
Total Net Economic Earnings above	822	3,281
Intersubsegment Eliminations [Member]
Operating Segment Information [Abstract]
Revenue from Related Parties	0	0
Intersubsegment Eliminations [Member] | Consolidation, Eliminations [Member] | Unallocated and Eliminations [Member]
Operating Segment Information [Abstract]
Revenue from Related Parties	(19,960)	(7,845)
Intersubsegment Eliminations [Member] | Regulated Gas Distribution [Member] | Gas Utility [Member]
Operating Segment Information [Abstract]
Revenue from Related Parties	62	680
Intersubsegment Eliminations [Member] | Other [Member] | Other [Member]
Operating Segment Information [Abstract]
Revenue from Related Parties	442	259
Intersubsegment Eliminations [Member] | Non-Regulated Gas Marketing [Member] | Gas Marketing [Member]
Operating Segment Information [Abstract]
Revenue from Related Parties	$ 19,456	$ 6,906

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Part 1 (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Accrued Unbilled Revenue	$ 101.9	$ 25.2	$ 39.6

XML

INFORMATION BY OPERATING SEGMENT (Tables)

3 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

Schedule of operating segment information

(Thousands)	Gas Utility		Gas Marketing		Other			Eliminations			Consolidated
Three Months Ended December 31, 2013
Revenues from external customers	$	435,166	$	33,253	$	191		$	—		$	468,610
Intersegment revenues	62		19,456		442			(19,960		)	—
Total Operating Revenues	435,228		52,709		633			(19,960		)	468,610
Operating Expenses
Gas Utility
Natural and Propane Gas	261,553		—		—			(19,766		)	241,787
Other Operation and Maintenance Expenses	62,516		—		—			(194		)	62,322
Depreciation and Amortization	20,026		—		—			—			20,026
Taxes, Other than Income Taxes	28,589		—		—			—			28,589
Total Gas Utility Operating Expenses	372,684		—		—			(19,960		)	352,724
Gas Marketing	—		51,782		—			—			51,782
Other	—		—		1,199			—			1,199
Total Operating Expenses	372,684		51,782		1,199			(19,960		)	405,705
Operating Income	62,544		927		(566		)	—			62,905
Net Economic Earnings (Losses)	35,778		822		(336		)	—			36,264
Total assets	3,084,134		157,239		126,890			(161,533		)	3,206,730
Three Months Ended December 31, 2012
Revenues from external customers	$	250,111	$	55,249	$	1,643		$	—		$	307,003
Intersegment revenues	680		6,906		259			(7,845		)	—
Total Operating Revenues	250,791		62,155		1,902			(7,845		)	307,003
Operating Expenses
Gas Utility
Natural and Propane Gas	144,333		—		—			(7,818		)	136,515
Other Operation and Maintenance Expenses	39,651		—		—			—			39,651
Depreciation and Amortization	10,965		—		—			—			10,965
Taxes, Other than Income Taxes	14,806		—		—			—			14,806
Total Gas Utility Operating Expenses	209,755		—		—			(7,818		)	201,937
Gas Marketing	—		57,382		—			—			57,382
Other	—		—		5,626			(27		)	5,599
Total Operating Expenses	209,755		57,382		5,626			(7,845		)	264,918
Operating Income	41,036		4,773		(3,724		)	—			42,085
Net Economic Earnings	25,341		3,281		(389		)	—			28,233
Total assets	1,809,722		188,603		124,967			(181,137		)	1,942,155

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

Reconciliation of Consolidated Net Income to Consolidated Net Economic Earnings
	Three Months Ended December 31,
(Thousands)	2013			2012
Net Income (GAAP)	$	35,592		$	25,568
Unrealized (gain) loss on energy-related derivative contracts	354			439
Lower of cost or market inventory adjustments	(62		)	—
Realized (gain) loss on economic hedges prior to sale of the physical commodity	(6		)	(31		)
Acquisition, divestiture, and restructuring activities	386			2,257
Net Economic Earnings (Non-GAAP)	$	36,264		$	28,233

XML

COMMITMENTS AND CONTINGENCIES (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Dec. 31, 2013 site	Sep. 30, 2005	Nov. 26, 2013 Laclede Gas [Member]	Nov. 26, 2013 LER [Member]	Dec. 31, 2013 MF Global Inc [Member]
Commitments [Abstract]
Minimum total payments required for natural gas contracts	$ 1,127
Site Contingency [Line Items]
Document Period End Date	Dec. 31, 2013
Contingencies and Indemnifications [Abstract]
Number Of Former Manufactured Gas Plant Sites In Missouri	3
Number of former manufactured gas plant (MGP) sites in Shrewsbury, Missouri	1
Number of former manufactured gas plant (MGP) sites in the City of St. Louis	2
Minimum cost estimate for a one-time contractual transfer of risk		5.8
Maximum cost estimate for a one-time contractual transfer of risk		36.3
Amount Remaining On Deposit With Brokerage Firm			$ 0.2	$ 0.1
BankruptcyClaimsAggregatePercentageOfDepositsRecoveredFromBankruptEntity1					98.00%

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Part 2 (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Gross Receipts taxes recorded in gas utility operating revenues	$ 19.9	$ 10.3

XML

MGE ACQUISITION MGE ACQUISITION (Details) (USD $)	3 Months Ended			0 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Sep. 30, 2013	Dec. 20, 2013 Laclede Group [Member] Missouri Gas Energy (MGE) [Member]	Sep. 01, 2013 Laclede Group [Member] Missouri Gas Energy (MGE) [Member]	Dec. 20, 2013 Gas Utility [Member] Laclede Group [Member] Missouri Gas Energy (MGE) [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross				$ 964,000,000	$ 975,000,000
Proceeds from Divestiture of Businesses	11,000,000	0				11,000,000
Goodwill	235,814,000	0	247,078,000
Goodwill, Other Changes						$ 11,000,000

XML

MGE ACQUISITION MGE Acquisition

3 Months Ended

Dec. 31, 2013

MGE Acquisition [Abstract]

Business Combination Disclosure [Text Block]

2. MGE Acquisition

Effective September 1, 2013, the Utility 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, the Utility acquired MGE for a purchase price of $975 million.

On December 12, 2012, a subsidiary of Laclede Group, Plaza Massachusetts Acquisition Inc. (Plaza Mass), agreed to purchase New England Gas Company (NEG) from SUG. Subsequently, on February 11, 2013, the Company agreed to sell Plaza Mass to Algonquin Power & Utilities Corp. (APUC). On December 13, 2013, the Massachusetts Department of Public Utilities (MDPU) approved the transfer of Plaza Mass to an APUC subsidiary. Consistent with the February 11, 2013 agreements, on December 20, 2013, the Company closed the sale of Plaza Mass to an APUC subsidiary and received $11.0 million from APUC. This receipt of funds effectively reduced the Utility's purchase price of MGE to $964 million. On December 24, 2013, the Massachusetts Attorney General filed a Motion for Clarification/Reconsideration with the MDPU which, among other things, claims that legislative approval is required for a transfer of utility assets. The MDPU has not yet acted on the Attorney General’s Motion.

The Utility is currently in negotiations with SUG regarding adjustments to the purchase price of MGE due to changes in the actual net assets transferred to the Utility at closing on August 31, 2013 from the level at September 30, 2012. The Utility plans to adjust cash and goodwill for any change upon final settlement.

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. The Utility recorded $235.8 million of goodwill as an asset in the consolidated balance sheet.

In the first quarter of fiscal 2014, the Utility updated the fair value estimates for assets acquired and liabilities assumed as of the acquisition date, including the sale of NEG to APUC which resulted in a decrease to goodwill of $11.0 million.

XML

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 1 (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Pension Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost - benefits earned during the period	$ 2,428	$ 2,311
Interest Cost	6,010	4,066
Expected return on plan assets	6,645	4,741
Amortization of prior service cost (credit)	124	136
Amortization of actuarial loss	(1,772)	(2,839)
Sub-total	3,689	4,611
Regulatory adjustment	2,890	(434)
Net benefit cost	6,579	4,177
Postretirement Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost - benefits earned during the period	2,804	2,533
Interest Cost	2,169	1,279
Expected return on plan assets	1,709	1,081
Amortization of transition obligation	0	23
Amortization of prior service cost (credit)	(1)	1
Amortization of actuarial loss	(1,505)	(1,325)
Sub-total	4,768	4,080
Regulatory adjustment	(2,387)	(1,699)
Net benefit cost	$ 2,381	$ 2,381

XML

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Part 3) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Derivatives in Cash Flow Hedging Relationships [Abstract]
Ineffective portion of gain (loss) on derivatives recognized in income	$ 42	$ (511)
Effective portion of gain (loss) reclassiffied from AOCI to income	1,178	(2,249)
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | NYMEX Natural Gas Contracts [Member]
Derivatives in Cash Flow Hedging Relationships [Abstract]
Ineffective portion of gain (loss) on derivatives recognized in income	(78)	(410)
Effective portion of gain (loss) reclassiffied from AOCI to income	1,120	(2,296)
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | NYMEX Natural Gas Contracts [Member] | Gas Marketing Operating Expenses [Member]
Derivatives in Cash Flow Hedging Relationships [Abstract]
Ineffective portion of gain (loss) on derivatives recognized in income	133	(85)
Effective portion of gain (loss) reclassiffied from AOCI to income	(180)	(334)
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | NYMEX Natural Gas Contracts [Member] | Other Comprehensive Income (Loss) [Member]
Derivatives in Cash Flow Hedging Relationships [Abstract]
Effective portion of gain (loss) recognized in OCI on derivatives	(1,655)	1,332
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | NYMEX Natural Gas Contracts [Member] | Gas Marketing Operating Revenue [Member]
Derivatives in Cash Flow Hedging Relationships [Abstract]
Ineffective portion of gain (loss) on derivatives recognized in income	(211)	(325)
Effective portion of gain (loss) reclassiffied from AOCI to income	1,300	(1,962)
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | NYMEX Gasoline and Heating Oil Contracts [Member]
Derivatives in Cash Flow Hedging Relationships [Abstract]
Effective portion of gain (loss) recognized in OCI on derivatives	(1,646)	1,389
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | NYMEX Gasoline and Heating Oil Contracts [Member] | Other Comprehensive Income (Loss) [Member]
Derivatives in Cash Flow Hedging Relationships [Abstract]
Effective portion of gain (loss) recognized in OCI on derivatives	9	57
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | NYMEX Gasoline and Heating Oil Contracts [Member] | Other Gas Utility Operating Expenses [Member]
Derivatives in Cash Flow Hedging Relationships [Abstract]
Ineffective portion of gain (loss) on derivatives recognized in income	120	(101)
Effective portion of gain (loss) reclassiffied from AOCI to income	58	47
Not Designated as Hedging Instrument [Member] | NYMEX Gasoline and Heating Oil Contracts [Member]
Derivatives Not Designated as Hedging Instruments [Abstract]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	336	130
Not Designated as Hedging Instrument [Member] | Not Designated as Hedging Instrument [Member] | NYMEX Natural Gas Contracts [Member] | Gas Marketing Operating Expenses [Member]
Derivatives Not Designated as Hedging Instruments [Abstract]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	0
Not Designated as Hedging Instrument [Member] | Not Designated as Hedging Instrument [Member] | NYMEX Natural Gas Contracts [Member] | Gas Marketing Operating Revenue [Member]
Derivatives Not Designated as Hedging Instruments [Abstract]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	1,990	1,067
Not Designated as Hedging Instrument [Member] | Not Designated as Hedging Instrument [Member] | NYMEX Gasoline and Heating Oil Contracts [Member] | Other Income and (Income Deductions) - Net [Member]
Derivatives Not Designated as Hedging Instruments [Abstract]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	13	33
Not Designated as Hedging Instrument [Member] | Not Designated as Hedging Instrument [Member] | Natural Gas Commodity Contracts [Member] | Gas Marketing Operating Expenses [Member]
Derivatives Not Designated as Hedging Instruments [Abstract]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	0
Not Designated as Hedging Instrument [Member] | Not Designated as Hedging Instrument [Member] | Natural Gas Commodity Contracts [Member] | Gas Marketing Operating Revenue [Member]
Derivatives Not Designated as Hedging Instruments [Abstract]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$ (1,667)	$ (970)

XML

STATEMENTS OF CONSOLIDATED INCOME (UNAUDITED) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Operating Revenues:
Gas Utility	$ 435,166	$ 250,111
Gas Marketing	33,253	55,249
Other	191	1,643
Total Operating Revenues	468,610	307,003
Gas Utility
Natural and propane gas	241,787	136,515
Other operation and maintenance expense	62,322	39,651
Depreciation and amortization	20,026	10,965
Taxes, other than income taxes	28,589	14,806
Total Gas Utility Operating Expenses	352,724	201,937
Gas Marketing	51,782	57,382
Other	1,199	5,599
Total Operating Expenses	405,705	264,918
Operating Income	62,905	42,085
Other (Income Deductions) and Income - Net	1,647	1,084
Interest Charges:
Interest on long-term debt	9,694	5,438
Other interest charges	767	588
Total Interest Charges	10,461	6,026
Income Before Income Taxes	54,091	37,143
Income Tax (Benefit) Expense	18,499	11,575
Net Income	$ 35,592	$ 25,568
Weighted Average Number of Common Shares Outstanding:
Basic	32,570	22,372
Diluted	32,648	22,434
Basic Earnings Per Share of Common Stock:
Basic Earnings Per Share of Common Stock	$ 1.09	$ 1.14
Diluted Earnings Per Share of Common Stock:
Diluted Earnings Per Share of Common Stock	$ 1.09	$ 1.14
Dividends Declared Per Share of Common Stock	$ 0.440	$ 0.425

XML

SUBSEQUENT EVENT Subsequent Event (Details) (First Mortgage [Member], Six Point Three Five Series Due in 2038 [Member], Laclede Gas [Member], USD $) In Millions, unless otherwise specified	0 Months Ended
	Jan. 06, 2014
First Mortgage [Member] | Six Point Three Five Series Due in 2038 [Member] | Laclede Gas [Member]
Six Point Three Five Series Due in 2038 [Line Items]
Repayments of Long-term Debt	$ 80
Debt Instrument, Interest Rate, Stated Percentage	6.35%
Interest Paid	$ 0.3

XML

STATEMENTS OF CONSOLIDATED CASH FLOWS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Operating Activities:
Net Income	$ 35,592	$ 25,568
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, amortization, and accretion	20,212	11,314
Deferred income taxes and investment tax credits	(702)	2,572
Other - net	(157)	670
Changes in assets and liabilities:
Accounts receivable - net	(157,564)	(61,942)
Unamortized purchased gas adjustments	7,630	10,182
Deferred purchased gas costs	23,093	2,266
Accounts payable	25,153	12,004
Increase (Decrease) in Customer Advances	(7,725)	(9,196)
Taxes accrued	3,379	1,877
Natural gas stored underground	28,730	4,387
Other assets and liabilities	6,648	4,213
Net cash provided by (used in) operating activities	(15,711)	3,915
Investing Activities:
Capital expenditures	(34,641)	(27,713)
Other investments	(679)	(990)
Proceeds from Divestiture of Businesses	11,000	0
Net cash used in investing activities	(24,320)	(28,703)
Financing Activities:
Issuance of long-term debt	0	25,000
Maturity of first mortgage bonds	0	(25,000)
Repayment of short-term debt - net	19,500	42,950
Changes in book overdrafts	15,847	10,160
Issuance of common stock	742	761
Dividends paid	(13,876)	(9,495)
Employees' taxes paid associated with restricted shares withheld upon vesting	(1,053)	(723)
Excess tax benefits from stock-based compensation	423	256
Other	(15)	(15)
Net cash provided by financing activities	21,568	43,894
Net Increase (Decrease) in Cash and Cash Equivalents	(18,463)	19,106
Cash and Cash Equivalents at Beginning of Period	52,981	27,457
Cash and Cash Equivalents at End of Period	34,518	46,563
Supplemental Disclosure of Cash Paid (Refunded) During the Period for:
Interest	8,850	9,585
Income taxes	$ (2,313)	$ 456

XML

EARNINGS PER COMMON SHARE (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Basic EPS [Abstract]
Net Income	$ 35,592	$ 25,568
Less: Income allocated to participating securities	144	80
Net Income Available to Common Shareholders, Basic	35,448	25,488
Weighted Average Shares Outstanding, Basic	32,570	22,372
Earnings Per Share of Common Stock, Basic (Per Share)	$ 1.09	$ 1.14
Diluted EPS [Abstract]
Net Income	35,592	25,568
Less: Income allocated to participating securities	(144)	80
Net Income Available to Common Stockholders, Diluted	$ 35,448	$ 25,488
Weighted Average Shares Outstanding, Basic	32,570	22,372
Dilutive Effect of Stock Options, Restricted Stock, and Restricted Stock Units	78	62
Weighted Average Diluted Shares	32,648	22,434
Earnings Per Share of Common Stock, Diluted (Per share)	$ 1.09	$ 1.14
Restricted Stock and Stock Units Subject to Performance and/or Market Conditions [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Outstanding shares excluded from the calculation of diluted EPS	259	263

XML

STOCK-BASED COMPENSATION (Tables)

3 Months Ended

Dec. 31, 2013

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

Restricted stock and restricted stock unit activity

Activity of restricted stock and restricted stock units subject to performance and/or market conditions during the three months ended December 31, 2013 is presented below:

	Restricted Stock/ Stock Units		Weighted Average Grant Date Fair Value
Nonvested at September 30, 2013	242,268		$	34.15
Granted (maximum shares that can be earned)	104,979		$	37.74
Vested	(52,954	)	$	32.16
Forfeited	(22,022	)	$	29.35
Nonvested at December 31, 2013	272,271		$	36.31

Time-vested restricted stock and stock unit activity for the three months ended December 31, 2013 is presented below:

	Restricted Stock/ Stock Units		Weighted Average Grant Date Fair Value
Nonvested at September 30, 2013	119,404		$	38.64
Granted	51,943		$	45.59
Vested	(17,999	)	$	36.37
Forfeited	(7,200	)	$	38.53
Nonvested at December 31, 2013	146,148		$	41.40

Stock option awards activity

Stock option activity for the three months ended December 31, 2013 is presented below:

	Stock Options		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (Years)	Aggregate Intrinsic Value ($000)
Outstanding at September 30, 2013	133,500		$	31.87
Granted	—		$	—
Exercised	(12,750	)	$	29.36
Forfeited	—		$	—
Expired	—		$	—
Outstanding at December 31, 2013	120,750		$	32.14	1.7	$	1,618
Fully Vested and Expected to Vest at December 31, 2013	120,750		$	32.14	1.7	$	1,618
Exercisable at December 31, 2013	120,750		$	32.14	1.7	$	1,618

Compensation cost recognized for share-based compensation arrangements

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

	Three Months Ended December 31,
(Thousands)	2013			2012
Total equity compensation cost	$	533		$	622
Compensation cost capitalized	(149		)	(183		)
Compensation cost recognized	$	384		$	439

XML

FAIR VALUE OF FINANCIAL INSTRUMENTS (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2012
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	$ 34,518	$ 52,981	$ 46,563	$ 27,457
Carrying (Reported) Amount, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	34,518	52,981	46,563
Short-term debt	93,500	74,000	83,050
Long-term debt, including current portion	912,764	912,712	364,426
Estimate of Fair Value, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	34,518	52,981	46,563
Short-term debt	93,500	74,000	83,050
Long-term debt, including current portion	936,478	954,126	456,235
Quoted Prices in Active Markets (Level 1) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	34,354	52,824	36,487
Short-term debt	0	0	0
Long-term debt, including current portion	0	0	0
Significant Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	164	157	10,076
Short-term debt	93,500	74,000	83,050
Long-term debt, including current portion	936,478	954,126	456,235
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	0	0	0
Short-term debt	0	0	0
Long-term debt, including current portion	$ 0	$ 0	$ 0

XML

FAIR VALUE OF FINANCIAL INSTRUMENTS (Tables)

3 Months Ended

Dec. 31, 2013

Financial Instruments, Owned, at Fair Value [Abstract]

Fair value - financial instruments

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

					Classification of Estimated Fair Value
(Thousands)	Carrying Amount		Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
As of December 31, 2013
Cash and cash equivalents	$	34,518	$	34,518	$	34,354	$	164	$	—
Short-term debt	93,500		93,500		—		93,500		—
Long-term debt, including current portion	912,764		936,478		—		936,478		—
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 December 31, 2012
Cash and cash equivalents	$	46,563	$	46,563	$	36,487	$	10,076	$	—
Short-term debt	83,050		83,050		—		83,050		—
Long-term debt, including current portion	364,426		456,235		—		456,235		—

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

3 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

These notes are an integral part of the accompanying unaudited consolidated financial statements of The Laclede Group, Inc. (Laclede Group or the Company) and its subsidiaries. In the opinion of Laclede Group, this interim report includes all adjustments (consisting of only normal recurring accruals) necessary for the fair presentation of the results of operations for the periods presented. This Form 10-Q should be read in conjunction with the Notes to Consolidated Financial Statements contained in the Company’s Fiscal Year 2013 Form 10-K.

The consolidated financial position, results of operations, and cash flows of Laclede Group are primarily derived from the financial position, results of operations, and cash flows of Laclede Gas Company (Laclede Gas or the Utility), a wholly owned subsidiary. The Utility is a regulated natural gas distribution utility having a material seasonal cycle. As a result, these interim statements of income for Laclede Group are not necessarily indicative of annual results or representative of succeeding quarters of the fiscal year. The Utility's recent acquisition of Missouri Gas Energy (MGE) is included in the results of operations for the three months ended December 31, 2013, impacting the comparability of the current year financial statements to prior years. For a further discussion of the acquisition, see Note 2, MGE Acquisition. Due to the seasonal nature of the business of the Utility, Laclede Group’s earnings are typically concentrated during the heating season of November through April each year, although earnings for Missouri Gas Energy (MGE) are less seasonal than earnings from Laclede Gas, due to MGE's straight fixed-variable rate design which recovers fixed costs more evenly over the year. The Gas Utility segment serves St. Louis and eastern Missouri through Laclede Gas and serves Kansas City and western Missouri through MGE. The Company's primary non-utility business, Laclede Energy Resources, Inc. (LER), included in the Gas Marketing segment, provides non-regulated natural gas services.

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 December 31, 2013 and 2012, for the Utility, were $101.9 million and $39.6 million, respectively. The amount of accrued unbilled revenue at September 30, 2013 was $25.2 million.

GROSS RECEIPTS 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 for the three months ended December 31, 2013 and 2012 were $19.9 million and $10.3 million, respectively. Gross receipts taxes are expensed by the Utility and included in the Taxes, other than income taxes line.

XML

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (UNAUDITED) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
Net Income	$ 35,592	$ 25,568
Net gains (losses) on cash flow hedging derivative instruments:
Net hedging gain (loss) arising during the period	(1,646)	1,389
Reclassification adjustment for losses (gains) included in net income	(1,178)	2,249
Net unrealized gain (loss) on cash flow hedging derivative instruments	(2,824)	3,638
Defined benefit pension and other postretirement benefit plans:
Amortization of actuarial loss included in net periodic pension and postretirement benefit cost	97	90
Other Comprehensive Income (Loss), Before Tax	(2,727)	3,728
Income Tax (Benefit) Expense Related to Items of Other Comprehensive Income	(1,035)	1,450
Other Comprehensive Income (Loss), Net of Tax	(1,692)	2,278
Comprehensive Income	$ 33,900	$ 27,846

XML

INFORMATION BY OPERATING SEGMENT

3 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

INFORMATION BY OPERATING SEGMENT

11. INFORMATION BY OPERATING SEGMENT

All of Laclede Group’s subsidiaries are wholly owned. The Gas Utility segment 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 includes the results of LER, a subsidiary engaged in the non-regulated marketing of natural gas. 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, natural gas fueling stations, 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.

(Thousands)	Gas Utility		Gas Marketing		Other			Eliminations			Consolidated
Three Months Ended December 31, 2013
Revenues from external customers	$	435,166	$	33,253	$	191		$	—		$	468,610
Intersegment revenues	62		19,456		442			(19,960		)	—
Total Operating Revenues	435,228		52,709		633			(19,960		)	468,610
Operating Expenses
Gas Utility
Natural and Propane Gas	261,553		—		—			(19,766		)	241,787
Other Operation and Maintenance Expenses	62,516		—		—			(194		)	62,322
Depreciation and Amortization	20,026		—		—			—			20,026
Taxes, Other than Income Taxes	28,589		—		—			—			28,589
Total Gas Utility Operating Expenses	372,684		—		—			(19,960		)	352,724
Gas Marketing	—		51,782		—			—			51,782
Other	—		—		1,199			—			1,199
Total Operating Expenses	372,684		51,782		1,199			(19,960		)	405,705
Operating Income	62,544		927		(566		)	—			62,905
Net Economic Earnings (Losses)	35,778		822		(336		)	—			36,264
Total assets	3,084,134		157,239		126,890			(161,533		)	3,206,730
Three Months Ended December 31, 2012
Revenues from external customers	$	250,111	$	55,249	$	1,643		$	—		$	307,003
Intersegment revenues	680		6,906		259			(7,845		)	—
Total Operating Revenues	250,791		62,155		1,902			(7,845		)	307,003
Operating Expenses
Gas Utility
Natural and Propane Gas	144,333		—		—			(7,818		)	136,515
Other Operation and Maintenance Expenses	39,651		—		—			—			39,651
Depreciation and Amortization	10,965		—		—			—			10,965
Taxes, Other than Income Taxes	14,806		—		—			—			14,806
Total Gas Utility Operating Expenses	209,755		—		—			(7,818		)	201,937
Gas Marketing	—		57,382		—			—			57,382
Other	—		—		5,626			(27		)	5,599
Total Operating Expenses	209,755		57,382		5,626			(7,845		)	264,918
Operating Income	41,036		4,773		(3,724		)	—			42,085
Net Economic Earnings	25,341		3,281		(389		)	—			28,233
Total assets	1,809,722		188,603		124,967			(181,137		)	1,942,155

Reconciliation of Consolidated Net Income to Consolidated Net Economic Earnings
	Three Months Ended December 31,
(Thousands)	2013			2012
Net Income (GAAP)	$	35,592		$	25,568
Unrealized (gain) loss on energy-related derivative contracts	354			439
Lower of cost or market inventory adjustments	(62		)	—
Realized (gain) loss on economic hedges prior to sale of the physical commodity	(6		)	(31		)
Acquisition, divestiture, and restructuring activities	386			2,257
Net Economic Earnings (Non-GAAP)	$	36,264		$	28,233

XML

Document and Entity Information (USD $)	3 Months Ended
	Dec. 31, 2013	Jan. 31, 2014	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		32,758,189
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q1
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Dec. 31, 2013

XML

COMMITMENTS AND CONTINGENCIES

3 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS AND CONTINGENCIES

12. COMMITMENTS AND CONTINGENCIES

Commitments

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 December 31, 2013 are estimated at approximately $1,127 million . Additional contracts are generally entered into prior to or during the heating season. The Utility recovers its costs from customers in accordance with the PGA Clause.

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, the Utility 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. Accordingly, Laclede Gas was able to enter into a cost sharing agreement for remedial investigation with other potentially responsible parties. Pending Missouri Department of Natural Resources approval, the remedial investigation of the site will probably begin in the Spring of 2014. 

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.

As discussed in Note 8, Derivative Instruments and Hedging Activities, Laclede Gas and LER enter into NYMEX and ICE exchange-traded/cleared derivative instruments. Previously, these instruments were held in accounts at MF Global, Inc. On October 31, 2011, affiliated entities of MF Global filed a Chapter 11 petition at the U.S. Bankruptcy Court in the Southern District of New York. Subsequently, the court-appointed bankruptcy trustee transferred all of the open positions and a significant portion of the margin deposits of Laclede Gas and LER to a new brokerage firm. On June 27, 2013, the bankruptcy Trustee issued a statement projecting that MF Global customers would receive a full payout of their claims. As of 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.

XML

CONSOLIDATED BALANCE SHEETS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2012
ASSETS
Utility Plant	$ 2,295,248	$ 2,271,189	$ 1,508,770
Less: Accumulated depreciation and amortization	507,457	494,559	470,840
Net Utility Plant	1,787,791	1,776,630	1,037,930
Non-utility property	5,249	7,694	5,788
Goodwill	235,814	247,078	0
Other investments	62,774	58,306	51,631
Other Property and Investments	303,837	313,078	57,419
Current Assets:
Cash and cash equivalents	34,518	52,981	46,563
Accounts receivable:
Utility	254,692	101,118	130,925
Non-utility	63,194	63,752	54,092
Other	21,801	14,451	17,822
Allowance for doubtful accounts	10,847	(8,046)	(7,055)
Inventories:
Natural gas stored underground	153,305	182,035	88,342
Propane gas	6,022	8,962	10,200
Materials and supplies at average cost	8,581	8,154	4,257
Natural gas receivable	7,786	18,782	13,746
Derivative instrument assets	4,985	3,291	1,246
Unamortized purchased gas adjustments	9,903	17,533	30,492
Deferred income taxes	3,222	0	0
Prepayments and other	13,562	12,867	9,433
Total Current Assets	570,724	475,880	400,063
Deferred Charges:
Regulatory assets	530,963	545,947	440,880
Other	13,415	13,851	5,863
Total Deferred Charges	544,378	559,798	446,743
Total Assets	3,206,730	3,125,386	1,942,155
Capitalization:
Common stock (70,000,000 shares authorized, 32,751,255, 32,696,836, and 22,563,958 shares issued, respectively)	32,751	32,697	22,564
Paid-in capital	594,857	594,269	169,496
Retained earnings	441,259	420,103	430,556
Accumulated other comprehensive loss	(2,479)	(787)	(1,838)
Total Common Stock Equity	1,066,388	1,046,282	620,778
Long-term debt (less current portion)	832,764	912,712	364,426
Total Capitalization	1,899,152	1,958,994	985,204
Current Liabilities:
Notes payable	93,500	74,000	83,050
Accounts payable	160,750	140,234	100,994
Advance customer billings	16,011	23,736	15,950
Current portion of long-term debt	80,000	0	0
Wages and compensation accrued	15,753	20,807	12,401
Dividends payable	15,142	14,556	9,931
Customer deposits	15,485	15,062	8,437
Interest accrued	9,755	8,335	5,034
Taxes accrued	36,274	32,896	13,196
Deferred income taxes	0	1,012	4,426
Other	35,054	22,540	21,651
Total Current Liabilities	477,724	353,178	275,070
Deferred Credits and Other Liabilities:
Deferred income taxes	389,557	379,114	350,738
Unamortized investment tax credits	2,847	2,900	3,060
Pension and postretirement benefit costs	229,313	228,653	195,259
Asset retirement obligations	72,459	74,554	40,936
Regulatory liabilities	90,795	82,560	56,776
Other	44,883	45,433	35,112
Total Deferred Credits and Other Liabilities	829,854	813,214	681,881
Total Capitalization and Liabilities	$ 3,206,730	$ 3,125,386	$ 1,942,155

XML

FAIR VALUE OF FINANCIAL INSTRUMENTS

3 Months Ended

Dec. 31, 2013

Financial Instruments, Owned, at Fair Value [Abstract]

FAIR VALUE OF FINANCIAL INSTRUMENTS

6. FAIR VALUE OF FINANCIAL INSTRUMENTS

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

					Classification of Estimated Fair Value
(Thousands)	Carrying Amount		Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
As of December 31, 2013
Cash and cash equivalents	$	34,518	$	34,518	$	34,354	$	164	$	—
Short-term debt	93,500		93,500		—		93,500		—
Long-term debt, including current portion	912,764		936,478		—		936,478		—
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 December 31, 2012
Cash and cash equivalents	$	46,563	$	46,563	$	36,487	$	10,076	$	—
Short-term debt	83,050		83,050		—		83,050		—
Long-term debt, including current portion	364,426		456,235		—		456,235		—

The carrying amounts for cash and cash equivalents and short-term debt approximate fair value due to the short maturity of these instruments. The fair values of long-term debt are estimated based on market prices for similar issues. Refer to Note 7, Fair Value Measurements, for information on financial instruments measured at fair value on a recurring basis.

XML

EARNINGS PER COMMON SHARE

3 Months Ended

Dec. 31, 2013

Earnings Per Share [Abstract]

EARNINGS PER COMMON SHARE

5. EARNINGS PER COMMON SHARE

	Three Months Ended December 31,
(Thousands, Except Per Share Amounts)	2013		2012
Basic EPS:
Net Income	$	35,592	$	25,568
Less: Income allocated to participating securities	144		80
Net Income Available to Common Shareholders	$	35,448	$	25,488
Weighted Average Shares Outstanding	32,570		22,372
Earnings Per Share of Common Stock	$	1.09	$	1.14
Diluted EPS:
Net Income	$	35,592	$	25,568
Less: Income allocated to participating securities	144		80
Net Income Available to Common Shareholders	$	35,448	$	25,488
Weighted Average Shares Outstanding	32,570		22,372
Dilutive Effect of Stock Options, Restricted Stock and Restricted Stock Units	78		62
Weighted Average Diluted Shares	32,648		22,434
Earnings Per Share of Common Stock	$	1.09	$	1.14
Outstanding Shares Excluded from the Calculation of Diluted EPS Attributable to:
Restricted stock and stock units subject to performance and/or market conditions	259		263

XML

EARNINGS PER COMMON SHARE (Tables)

3 Months Ended

Dec. 31, 2013

Earnings Per Share [Abstract]

Earnings Per Common Share

5. EARNINGS PER COMMON SHARE

	Three Months Ended December 31,
(Thousands, Except Per Share Amounts)	2013		2012
Basic EPS:
Net Income	$	35,592	$	25,568
Less: Income allocated to participating securities	144		80
Net Income Available to Common Shareholders	$	35,448	$	25,488
Weighted Average Shares Outstanding	32,570		22,372
Earnings Per Share of Common Stock	$	1.09	$	1.14
Diluted EPS:
Net Income	$	35,592	$	25,568
Less: Income allocated to participating securities	144		80
Net Income Available to Common Shareholders	$	35,448	$	25,488
Weighted Average Shares Outstanding	32,570		22,372
Dilutive Effect of Stock Options, Restricted Stock and Restricted Stock Units	78		62
Weighted Average Diluted Shares	32,648		22,434
Earnings Per Share of Common Stock	$	1.09	$	1.14
Outstanding Shares Excluded from the Calculation of Diluted EPS Attributable to:
Restricted stock and stock units subject to performance and/or market conditions	259		263

XML

SUBSEQUENT EVENT

3 Months Ended

Dec. 31, 2013

Subsequent Events [Abstract]

SUBSEQUENT EVENT

13. Subsequent Events

On January 6, 2014, the Utility redeemed in cash $80 million of 6.35% Series bonds due in 2038 and accrued interest of $0.3 million.

On January 17, 2014, Laclede Gas filed for a $7.4 million increase in Infrastructure System Replacement Surcharge (ISRS) revenues to recover the costs of gas safety replacement investments and public improvement projects over the previous thirteen months. Any increase in rates in this proceeding must go into effect by at least May 17, 2014.

XML

CONCENTRATIONS OF CREDIT RISK

9 Months Ended

Jun. 30, 2013

Risks and Uncertainties [Abstract]

CONCENTRATIONS OF CREDIT RISK

9. CONCENTRATIONS OF CREDIT RISK

A significant portion of LER’s transactions are with (or are associated with) energy producers, utility companies, and pipelines. These concentrations of transactions with these counterparties have the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that each of these three groups may be affected similarly by changes in economic, industry, or other conditions. To manage this risk, as well as credit risk from significant counterparties in these and other industries, LER has established procedures to determine the creditworthiness of its counterparties. These procedures include obtaining credit ratings and credit reports, analyzing counterparty financial statements to assess financial condition, and considering the industry environment in which the counterparty operates. This information is monitored on an ongoing basis. In some instances, LER may require credit assurances such as prepayments, letters of credit, or parental guarantees. In addition, LER may enter into netting arrangements to mitigate credit risk with counterparties in the energy industry from which LER both sells and purchases natural gas. Sales are typically made on an unsecured credit basis with payment due the month following delivery. Accounts receivable amounts are closely monitored and provisions for uncollectible amounts are accrued when losses are probable. To date, losses have not been significant. LER records accounts receivable, accounts payable, and prepayments for physical sales and purchases of natural gas on a gross basis. The amount included in accounts receivable attributable to energy producers and their marketing affiliates amounted to $8.9 million at December 31, 2013. Net receivable amounts from these customers on the same date, reflecting netting arrangements, were $3.8 million. Accounts receivable attributable to utility companies and their marketing affiliates comprised $20.5 million of total accounts receivable at December 31, 2013, while net receivable amounts from these customers, reflecting netting arrangements, were $18.8 million. LER also has concentrations of credit risk with certain individually significant counterparties. At December 31, 2013, the amounts included in accounts receivable from LER’s five largest counterparties (in terms of net accounts receivable exposure), were $18.4 million. These five counterparties are either investment-grade rated or owned by investment-grade rated companies. Net receivable amounts from these customers on the same date, reflecting netting arrangements, were $17.3 million. Additionally, LER has concentrations of credit risk with pipeline companies associated with its natural gas receivable amounts.

XML

FAIR VALUE MEASUREMENTS

3 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

7. FAIR VALUE MEASUREMENTS

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

(Thousands)	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Effects of Netting and Cash Margin Receivables /Payables			Total
As of December 31, 2013
Assets
U. S. Stock/Bond Mutual Funds	$	15,003	$	—	$	—	$	—		$	15,003
NYMEX/ICE natural gas contracts	3,697		670		—		(3,839		)	528
OTCBB natural gas contracts	—		3,609		—		(913		)	2,696
NYMEX gasoline and heating oil contracts	163		—		—		—			163
Natural gas commodity contracts	—		3,044		29		(826		)	2,247
Total	$	18,863	$	7,323	$	29	$	(5,578	)	$	20,637
Liabilities
NYMEX/ICE natural gas contracts	$	2,013	$	265	$	—	$	(2,278	)	$	—
OTCBB natural gas contracts	—		913		—		(913		)	—
Natural gas commodity contracts	—		1,732		22		(826		)	928
Total	$	2,013	$	2,910	$	22	$	(4,017	)	$	928
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
Natural gas commodity contracts	—		1,140		40		(495		)	685
Total	$	3,687	$	6,904	$	40	$	(4,735	)	$	5,896
As of December 31, 2012
Assets
U. S. Stock/Bond Mutual Funds	$	13,146	$	—	$	—	$	—		$	13,146
NYMEX/ICE natural gas contracts	2,497		749		—		(2,962		)	284
NYMEX gasoline and heating oil contracts	281		—		—		(281		)	—
Natural gas commodity contracts	—		1,228		77		(348		)	957
Total	$	15,924	$	1,977	$	77	$	(3,591	)	$	14,387
Liabilities
NYMEX/ICE natural gas contracts	$	6,650	$	749	$	—	$	(7,399	)	$	—
Natural gas commodity contracts	—		1,132		47		(348		)	831
Total	$	6,650	$	1,881	$	47	$	(7,747	)	$	831

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:

	Three Months Ended December 31,
(Thousands)	2013			2012
Beginning of period	$	110		$	109
Net settlements	(108		)	(66		)
Net gains related to derivatives still held at end of period	5			(13		)
End of period	$	7		$	30

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

XML

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

3 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

8. 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 Purchased Gas Adjustment (PGA) Clause, through which the MoPSC allows the Utility to recover gas supply costs, subject to prudence review by the MoPSC. Accordingly, 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, they 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 December 31, 2013, Laclede Gas held 0.8 million gallons of gasoline futures contracts at an average price of $2.66 per gallon. Most of these contracts, the longest of which extends to September 2014, are designated as cash flow hedges of forecasted transactions pursuant to ASC Topic 815. The gains or losses on these derivative instruments are not subject to the Utility’s PGA Clause.

In the course of its business, Laclede Group’s gas marketing subsidiary, LER, which includes its wholly owned subsidiary LER Storage Services, Inc., enters into commitments associated with the purchase or sale of natural gas. Certain of LER’s derivative natural gas contracts are designated as normal purchases or normal sales and, as such, are excluded from the scope of ASC Topic 815 and are accounted for as executory contracts on an accrual basis. Any of LER’s derivative natural gas contracts that are not designated as normal purchases or normal sales are accounted for at fair value. At December 31, 2013, the fair values of 72.2 million MMBtu of non-exchange traded natural gas commodity contracts were reflected in the Consolidated Balance Sheet. Of these contracts, 57.3 million MMBtu will settle during fiscal year 2014, 13.5 million MMBtu will settle during fiscal year 2015, while the remaining 1.4 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 Clear Europe (ICE) futures, swap, and option contracts to lock in margins. At December 31, 2013, LER’s unmatched fixed-price positions were not material to Laclede Group’s financial position or results of operations. LER’s NYMEX and ICE natural gas futures, swap, and option contracts used to lock in margins may be designated as cash flow hedges of forecasted transactions for financial reporting purposes.

The Company’s exchange-traded/cleared derivative instruments consist primarily of NYMEX, OTCBB, and ICE positions. The NYMEX and OTCBB 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 December 31, 2013 were as follows:

	Laclede Gas Company			Laclede Energy Resources, Inc.
	MMBtu (millions)	Avg. Price Per MMBtu		MMBtu (millions)	Avg. Price Per MMBtu
NYMEX/ICE Open short futures positions
Fiscal 2014	—	$	—	11.04	$	4.03
Fiscal 2015	—	—		0.49	4.19
Fiscal 2016	—	—		0.01	4.10
NYMEX/ICE Open long futures positions
Fiscal 2014	5.25	$	3.88	1.64	$	3.84
Fiscal 2015	0.94	3.84		0.39	4.00
Fiscal 2016	—	—		0.09	4.18
Fiscal 2017	—	—		0.02	4.28
ICE Open basis swap positions
Fiscal 2016	—	—		0.92	$	(0.80	)
Fiscal 2017	—	—		0.16	(0.80		)
OTCBB Open long futures positions
Fiscal 2014	14.03	$	3.99	—	—
Fiscal 2015	8.60	4.20		—	—
Fiscal 2016	0.11	4.15		—	—

At December 31, 2013, the Utility had 19.2 million MMBtu of other price mitigation in place through the use of NYMEX and OTCBB natural gas option-based strategies while LER had none.

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 December 31, 2013, it is expected that approximately $0.8 million of pre-tax unrealized gains will be reclassified into the Statements of Consolidated Income during the next twelve months. Cash flows from hedging transactions are classified in the same category as the cash flows from the items that are being hedged in the Statements of Consolidated Cash Flows.

The Effect of Derivative Instruments on the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income
		Three Months Ended
	Location of Gain (Loss)	December 31,
(Thousands)	Recorded in Income	2013			2012
Derivatives in Cash Flow Hedging Relationships
Effective portion of gain (loss) recognized in OCI on derivatives:
NYMEX/ICE natural gas contracts		$	(1,655	)	$	1,332
NYMEX gasoline and heating oil contracts		9			57
Total		$	(1,646	)	$	1,389
Effective portion of gain (loss) reclassified from AOCI to income:
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	$	1,300		$	(1,962	)
	Gas Marketing Operating Expenses	(180		)	(334		)
Sub-total		1,120			(2,296		)
NYMEX gasoline and heating oil contracts	Gas Utility Other Operations and Maintenance Expenses	58			47
Total		$	1,178		$	(2,249	)
Ineffective portion of gain (loss) on derivatives recognized in income:
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	$	(211	)	$	(325	)
	Gas Marketing Operating Expenses	133			(85		)
Sub-total		(78		)	(410		)
NYMEX gasoline and heating oil contracts	Gas Utility Other Operations and Maintenance Expenses	120			(101		)
Total		$	42		$	(511	)
Derivatives Not Designated as Hedging Instruments *
Gain (loss) recognized in income on derivatives:
Natural gas commodity contracts	Gas Marketing Operating Revenues	$	(1,667	)	$	(970	)
	Gas Marketing Operating Expenses	—			—
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	1,990			1,067
	Gas Marketing Operating Expenses	—			—
NYMEX gasoline and heating oil contracts	Other Income and (Income Deductions) - Net	13			33
Total		$	336		$	130

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

Fair Value of Derivative Instruments in the Consolidated Balance Sheet at December 31, 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	$	881		Derivative Instrument Assets	$	1,030
	Other Deferred Charges	110			Other Deferred Charges	1
NYMEX gasoline and heating oil contracts	Accounts Receivable – Other	154			Accounts Receivable – Other	—
Sub-total		1,145				1,031
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets	571			Derivative Instrument Assets	955
	Accounts Receivable – Other	2,802			Accounts Receivable – Other	285
	Other Deferred Charges	3			Other Deferred Charges	7
OTCBB natural gas contracts	Derivative Instrument Assets	3,386			Derivative Instrument Assets	636
	Other Deferred Credits	223			Other Deferred Credits	278
Natural gas commodity contracts	Derivative Instrument Assets	1,915			Derivative Instrument Assets	272
	Other Deferred Charges	641			Other Deferred Charges	37
	Other Current Liabilities	333			Other Current Liabilities	1,283
	Other Deferred Credits	183			Other Deferred Credits	161
NYMEX gasoline and heating oil contracts	Derivative Instrument Assets	9			Derivative Instrument Assets	—
Sub-total		10,066				3,914
Total derivatives		$	11,211			$	4,945
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		Accounts Receivable - Other	$	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 December 31, 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	Derivative Instrument Assets	$	987	Derivative Instrument Assets	$	871
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	249		Accounts Receivable - Other	—
Sub-total		1,236			871
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Accounts Receivable - Other	533		Accounts Receivable - Other	366
	Derivative Instrument Assets	1,726		Derivative Instrument Assets	6,162
Natural gas commodity contracts	Derivative Instrument Assets	1,197		Derivative Instrument Assets	240
	Other Current Liabilities	108		Other Current Liabilities	939
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	32		Accounts Receivable - Other	—
Sub-total		3,596			7,707
Total derivatives		$	4,832		$	8,578

* 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 7, 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)	December 31, 2013			September 30, 2013			December 31, 2012
Fair value of asset derivatives presented above	$	11,211		$	6,276		$	4,832
Fair value of cash margin receivables offset with derivatives	956			1,765			4,186
Netting of assets and liabilities with the same counterparty	(6,533		)	(4,739		)	(7,778		)
Total	$	5,634		$	3,302		$	1,240
Derivative Instrument Assets, per Consolidated Balance Sheets:
Derivative instrument assets	$	4,985		$	3,291		$	1,246
Other deferred charges	649			11			(6		)
Total	$	5,634		$	3,302		$	1,240
Fair value of liability derivatives presented above	$	4,945		$	10,629		$	8,578
Fair value of cash margin payables offset with derivatives	2,516			6			31
Netting of assets and liabilities with the same counterparty	(6,533		)	(4,739		)	(7,778		)
Total	$	928		$	5,896		$	831
Derivative Instrument Liabilities, per Consolidated Balance Sheets:
Other Current Liabilities	$	938		$	4,400		$	831
Other Deferred Credits	(10		)	1,496			—
Total	$	928		$	5,896		$	831

Additionally, at December 31, 2013, September 30, 2013, and December 31, 2012, the Company had $3.8 million, $3.2 million, and $4.4 million, respectively, in cash margin receivables not offset with derivatives, that are presented in Accounts Receivable - Other.

XML

OTHER INCOME AND (INCOME DEDUCTIONS) - NET

3 Months Ended

Dec. 31, 2013

Other Nonoperating Income (Expense) [Abstract]

OTHER INCOME AND (INCOME DEDUCTIONS) - NET

10. OTHER INCOME AND (INCOME DEDUCTIONS) - NET

	Three Months Ended December 31,
(Thousands)	2013		2012
Interest income	$	249	$	406
Net investment gain (loss)	746		(70		)
Other income	652		748
Other Income and (Income Deductions) – Net	$	1,647	$	1,084

XML

STOCK-BASED COMPENSATION (Details) (USD $)	3 Months Ended			12 Months Ended		3 Months Ended	12 Months Ended	3 Months Ended			3 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 Restricted Stock Awards [Member]	Sep. 30, 2013 Restricted Stock Awards [Member] Time Vested Restricted Stock and Time Vested Restricted Stock Units [Member]	Dec. 31, 2013 Restricted Stock Awards [Member] Time Vested Restricted Stock and Time Vested Restricted Stock Units [Member]	Dec. 31, 2013 Restricted Stock Awards [Member] Executive Officers and Key Employees [Member] Performance Contingent Restricted Stock and Stock Units [Member]	Sep. 30, 2013 Restricted Stock Awards [Member] Executive Officers and Key Employees [Member] Performance Contingent Restricted Stock and Stock Units [Member]	Dec. 31, 2013 Restricted Stock Awards [Member] Executive Officers and Key Employees [Member] Time Vested Restricted Stock and Time Vested Restricted Stock Units [Member]	Dec. 02, 2016 Restricted Stock Awards [Member] Executive Officers and Key Employees [Member] Time Vested Restricted Stock and Time Vested Restricted Stock Units [Member]	Dec. 02, 2014 Restricted Stock Awards [Member] Executive Officers and Key Employees [Member] Time Vested Restricted Stock and Time Vested Restricted Stock Units [Member]	Dec. 31, 2013 Stock Options Awards [Member]	Sep. 30, 2013 Stock Options Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights									39,775	12,168
Restricted Stock Awards [Abstract]
Granted (in shares)						104,979		51,943
Granted, weighted average grant date fair value (per share)						$ 37.74		$ 45.59
Vested restricted stock withheld for tax withholding obligations (in shares)			22,983
Vested restricted stock withheld for tax withholding obligations, weighted average price (in dollars per share)			$ 45.83
Restricted stock/stock units activity [Roll-Forward]
Nonvested, beginning of period (in shares)					146,148	242,268
Granted (in shares)						104,979		51,943
Vested (in shares)			(70,953)	(17,999)			(52,954)
Forfeited (in shares)				(7,200)			(22,022)
Nonvested, end of period (in shares)				119,404	146,148	272,271	242,268
Weighted average Grant Date Fair Value [Abstract]
Nonvested Beginning Balance, weighted average grant date fair value (per share)					$ 41.40	$ 34.15
Granted, weighted average grant date fair value (per share)						$ 37.74		$ 45.59
Vested, weighted average grant date fair value (per share)				$ 36.37			$ 32.16
Forfeited, weighted average grant date fair value (per share)				$ 38.53			$ 29.35
Nonvested Ending Balance, weighted average grant date fair value (per share)				$ 38.64	$ 41.40	$ 36.31	$ 34.15
Stock Options - Shares [Roll Forward]
Outstanding Balance - stock options											120,750	133,500
Fully Vested and Expected to Vest, end of period (in shares)											120,750
Exercisable, end of period (in shares)											120,750
Granted - stock options (in shares)											0
Exercised - stock options (in shares)											(12,750)
Forfeited - stock options (in shares)											0
Expired - stock options (in shares)											0
Stock Options - Shares Weighted Average Exercise Price [Abstract]
Outstanding Beginning Balance, weighted average exercise price - stock options (per share)											$ 32.14	$ 31.87
Granted, weighted average exercise price - stock options (per share)											$ 0.00
Exercised, weighted average exercise price - stock options (per share)											$ 29.36
Forfeited, weighted average exercise price - stock options (per share)											$ 0.00
Expired, weighted average exercise price - stock options (per share)											$ 0.00
Outstanding Ending Balance, weighted average exercise price - stock options (per share)											$ 32.14	$ 31.87
Fully Vested and Expected to Vest at End of Period, weighted average exercise price - stock options (per share)											$ 32.14
Exercisable at End of Period, weighted average exercise price - stock options (per share)											$ 32.14
Outstanding Ending Balance, weighted average remaining contractual term - stock options (in years)											1 year 8 months 12 days
Fully Vested and Expected to Vest at End of Period, weighted average remaining contractual term - stock options (in years)											1 year 8 months 12 days
Exercisable at End of Period, weighted average remaining contractual term - stock options (in years)											1 year 8 months 12 days
Outstanding Ending Balance, aggregate intrinsic value - stock options											$ 1,618,000
Fully Vested and Expected to Vest at End of Period, aggregate intrinsic value - stock options											1,618,000
Exercisable at End of Period, aggregate intrinsic value - stock options											1,618,000
Stock Option Awards [Abstract]
Common stock closing price (per share)											$ 45.54
Equity Compensation Cost [Abstract]
Compensation cost capitalized	533,000	622,000
Compensation cost recognized in net income	(149,000)	(183,000)
Income tax benefit recognized in net income	(384,000)	(439,000)
Total unrecognized compensation cost	$ 9,200,000
Weighted average period cost to be recognized (in years)	2 years 5 months 6 days
Document Period End Date	Dec. 31, 2013

XML

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS (Tables)

3 Months Ended

Dec. 31, 2013

Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]

Net Periodic Cost

The net periodic pension costs include the following components:

	Three Months Ended December 31,
(Thousands)	2013			2012
Service cost – benefits earned during the period	$	2,428		$	2,311
Interest cost on projected benefit obligation	6,010			4,066
Expected return on plan assets	(6,645		)	(4,741		)
Amortization of prior service cost	124			136
Amortization of actuarial loss	1,772			2,839
Sub-total	3,689			4,611
Regulatory adjustment	2,890			(434		)
Net pension cost	$	6,579		$	4,177

Net periodic postretirement benefit costs consisted of the following components:

	Three Months Ended December 31,
(Thousands)	2013			2012
Service cost – benefits earned during the period	$	2,804		$	2,533
Interest cost on accumulated postretirement benefit obligation	2,169			1,279
Expected return on plan assets	(1,709		)	(1,081		)
Amortization of transition obligation	—			23
Amortization of prior service cost (credit)	(1		)	1
Amortization of actuarial loss	1,505			1,325
Sub-total	4,768			4,080
Regulatory adjustment	(2,387		)	(1,699		)
Net postretirement benefit cost	$	2,381		$	2,381

XML

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)

3 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities

Open NYMEX/ICE and OTCBB natural gas futures and swap positions at December 31, 2013 were as follows:

	Laclede Gas Company			Laclede Energy Resources, Inc.
	MMBtu (millions)	Avg. Price Per MMBtu		MMBtu (millions)	Avg. Price Per MMBtu
NYMEX/ICE Open short futures positions
Fiscal 2014	—	$	—	11.04	$	4.03
Fiscal 2015	—	—		0.49	4.19
Fiscal 2016	—	—		0.01	4.10
NYMEX/ICE Open long futures positions
Fiscal 2014	5.25	$	3.88	1.64	$	3.84
Fiscal 2015	0.94	3.84		0.39	4.00
Fiscal 2016	—	—		0.09	4.18
Fiscal 2017	—	—		0.02	4.28
ICE Open basis swap positions
Fiscal 2016	—	—		0.92	$	(0.80	)
Fiscal 2017	—	—		0.16	(0.80		)
OTCBB Open long futures positions
Fiscal 2014	14.03	$	3.99	—	—
Fiscal 2015	8.60	4.20		—	—
Fiscal 2016	0.11	4.15		—	—

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

The Effect of Derivative Instruments on the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income
		Three Months Ended
	Location of Gain (Loss)	December 31,
(Thousands)	Recorded in Income	2013			2012
Derivatives in Cash Flow Hedging Relationships
Effective portion of gain (loss) recognized in OCI on derivatives:
NYMEX/ICE natural gas contracts		$	(1,655	)	$	1,332
NYMEX gasoline and heating oil contracts		9			57
Total		$	(1,646	)	$	1,389
Effective portion of gain (loss) reclassified from AOCI to income:
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	$	1,300		$	(1,962	)
	Gas Marketing Operating Expenses	(180		)	(334		)
Sub-total		1,120			(2,296		)
NYMEX gasoline and heating oil contracts	Gas Utility Other Operations and Maintenance Expenses	58			47
Total		$	1,178		$	(2,249	)
Ineffective portion of gain (loss) on derivatives recognized in income:
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	$	(211	)	$	(325	)
	Gas Marketing Operating Expenses	133			(85		)
Sub-total		(78		)	(410		)
NYMEX gasoline and heating oil contracts	Gas Utility Other Operations and Maintenance Expenses	120			(101		)
Total		$	42		$	(511	)
Derivatives Not Designated as Hedging Instruments *
Gain (loss) recognized in income on derivatives:
Natural gas commodity contracts	Gas Marketing Operating Revenues	$	(1,667	)	$	(970	)
	Gas Marketing Operating Expenses	—			—
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	1,990			1,067
	Gas Marketing Operating Expenses	—			—
NYMEX gasoline and heating oil contracts	Other Income and (Income Deductions) - Net	13			33
Total		$	336		$	130

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

Fair Value of Derivative Instruments in the Consolidated Balance Sheet

Fair Value of Derivative Instruments in the Consolidated Balance Sheet at December 31, 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	$	881		Derivative Instrument Assets	$	1,030
	Other Deferred Charges	110			Other Deferred Charges	1
NYMEX gasoline and heating oil contracts	Accounts Receivable – Other	154			Accounts Receivable – Other	—
Sub-total		1,145				1,031
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets	571			Derivative Instrument Assets	955
	Accounts Receivable – Other	2,802			Accounts Receivable – Other	285
	Other Deferred Charges	3			Other Deferred Charges	7
OTCBB natural gas contracts	Derivative Instrument Assets	3,386			Derivative Instrument Assets	636
	Other Deferred Credits	223			Other Deferred Credits	278
Natural gas commodity contracts	Derivative Instrument Assets	1,915			Derivative Instrument Assets	272
	Other Deferred Charges	641			Other Deferred Charges	37
	Other Current Liabilities	333			Other Current Liabilities	1,283
	Other Deferred Credits	183			Other Deferred Credits	161
NYMEX gasoline and heating oil contracts	Derivative Instrument Assets	9			Derivative Instrument Assets	—
Sub-total		10,066				3,914
Total derivatives		$	11,211			$	4,945
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		Accounts Receivable - Other	$	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 December 31, 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	Derivative Instrument Assets	$	987	Derivative Instrument Assets	$	871
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	249		Accounts Receivable - Other	—
Sub-total		1,236			871
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Accounts Receivable - Other	533		Accounts Receivable - Other	366
	Derivative Instrument Assets	1,726		Derivative Instrument Assets	6,162
Natural gas commodity contracts	Derivative Instrument Assets	1,197		Derivative Instrument Assets	240
	Other Current Liabilities	108		Other Current Liabilities	939
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	32		Accounts Receivable - Other	—
Sub-total		3,596			7,707
Total derivatives		$	4,832		$	8,578

* 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 7, 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)	December 31, 2013			September 30, 2013			December 31, 2012
Fair value of asset derivatives presented above	$	11,211		$	6,276		$	4,832
Fair value of cash margin receivables offset with derivatives	956			1,765			4,186
Netting of assets and liabilities with the same counterparty	(6,533		)	(4,739		)	(7,778		)
Total	$	5,634		$	3,302		$	1,240
Derivative Instrument Assets, per Consolidated Balance Sheets:
Derivative instrument assets	$	4,985		$	3,291		$	1,246
Other deferred charges	649			11			(6		)
Total	$	5,634		$	3,302		$	1,240
Fair value of liability derivatives presented above	$	4,945		$	10,629		$	8,578
Fair value of cash margin payables offset with derivatives	2,516			6			31
Netting of assets and liabilities with the same counterparty	(6,533		)	(4,739		)	(7,778		)
Total	$	928		$	5,896		$	831
Derivative Instrument Liabilities, per Consolidated Balance Sheets:
Other Current Liabilities	$	938		$	4,400		$	831
Other Deferred Credits	(10		)	1,496			—
Total	$	928		$	5,896		$	831

XML

CONCENTRATIONS OF CREDIT RISK (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013 counterparty
Concentration Risk [Line Items]
Number of large counterparties for which credit risk is disclosed	5
Number of investment-grade rated counterparties for which credit risk is disclosed, in terms of net accounts receivable exposure	5
Energy Producers And Their Affiliates [Member]
Concentration Risk [Line Items]
Accounts receivable	$ 8.9
Net receivable amount	3.8
Utility Companies And Their Affiliates [Member]
Concentration Risk [Line Items]
Accounts receivable	20.5
Net receivable amount	18.8
Largest Counterparties [Member]
Concentration Risk [Line Items]
Accounts receivable	18.4
Net receivable amount	$ 17.3

XML

CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical)	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2012
Capitalization:
Common Stock Shares Authorized (in shares)	70,000,000	70,000,000	70,000,000
Common Stock Shares Issued (in shares)	32,751,255	32,696,836	22,563,958

XML

STOCK-BASED COMPENSATION

3 Months Ended

Dec. 31, 2013

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

STOCK-BASED COMPENSATION

4. STOCK-BASED COMPENSATION

Awards of stock-based compensation are made pursuant to The Laclede Group 2006 Equity Incentive Plan (2006 Plan). Refer to Note 3 of the Consolidated Financial Statements included in the Company’s Form 10-K for the fiscal year ended September 30, 2013 for descriptions of the plan.

Restricted Stock Awards

During the three months ended December 31, 2013, the Company granted 104,979 performance-contingent restricted stock units to executive officers and key employees at a weighted average grant date fair value of $37.74 per share. This number represents the maximum shares that can be earned pursuant to the terms of the awards. Most of these stock units have a performance period ending September 30, 2016. While the participants have no interim voting rights on these stock units, dividends accrue during the performance period and are paid to the participants upon vesting, but are subject to forfeiture if the underlying stock units do not vest. The number of stock units that will ultimately vest is dependent upon the attainment of certain levels of earnings and other strategic goals, as well as the Company’s level of total shareholder return (TSR) during the performance period relative to a comparator group of companies. This TSR provision is considered a market condition under GAAP.

Activity of restricted stock and restricted stock units subject to performance and/or market conditions during the three months ended December 31, 2013 is presented below:

	Restricted Stock/ Stock Units		Weighted Average Grant Date Fair Value
Nonvested at September 30, 2013	242,268		$	34.15
Granted (maximum shares that can be earned)	104,979		$	37.74
Vested	(52,954	)	$	32.16
Forfeited	(22,022	)	$	29.35
Nonvested at December 31, 2013	272,271		$	36.31

During the three months ended December 31, 2013, the Company granted 51,943 shares of time-vested restricted stock and stock units to executive officers, key employees, and directors at a weighted average grant date fair value of $45.59 per share. Of the 51,943 shares, 12,168 shares vest on December 2, 2014 and 39,775 will vest on December 2, 2016. In the interim, participants receive full voting rights, which are not subject to forfeiture.    

Time-vested restricted stock and stock unit activity for the three months ended December 31, 2013 is presented below:

	Restricted Stock/ Stock Units		Weighted Average Grant Date Fair Value
Nonvested at September 30, 2013	119,404		$	38.64
Granted	51,943		$	45.59
Vested	(17,999	)	$	36.37
Forfeited	(7,200	)	$	38.53
Nonvested at December 31, 2013	146,148		$	41.40

During the three months ended December 31, 2013, 70,953 shares of restricted stock and stock units (performance-contingent and time-vested), awarded on December 1, 2010 and October 17, 2012 vested. The Company withheld 22,983 of the vested shares at a weighted average price of $45.83 per share pursuant to elections by employees to satisfy tax withholding obligations.

Stock Option Awards

Stock option activity for the three months ended December 31, 2013 is presented below:

	Stock Options		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (Years)	Aggregate Intrinsic Value ($000)
Outstanding at September 30, 2013	133,500		$	31.87
Granted	—		$	—
Exercised	(12,750	)	$	29.36
Forfeited	—		$	—
Expired	—		$	—
Outstanding at December 31, 2013	120,750		$	32.14	1.7	$	1,618
Fully Vested and Expected to Vest at December 31, 2013	120,750		$	32.14	1.7	$	1,618
Exercisable at December 31, 2013	120,750		$	32.14	1.7	$	1,618

The closing price of the Company’s common stock was $45.54 at December 31, 2013.

Equity Compensation Costs

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

	Three Months Ended December 31,
(Thousands)	2013			2012
Total equity compensation cost	$	533		$	622
Compensation cost capitalized	(149		)	(183		)
Compensation cost recognized	$	384		$	439

As of December 31, 2013, there was $9.2 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 2.4 years.

XML

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

3 Months Ended

Dec. 31, 2013

Other Nonoperating Income (Expense) [Abstract]

Other Income and (Income Deductions) by Component

	Three Months Ended December 31,
(Thousands)	2013		2012
Interest income	$	249	$	406
Net investment gain (loss)	746		(70		)
Other income	652		748
Other Income and (Income Deductions) – Net	$	1,647	$	1,084

XML

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Part 1) (Details) (USD $)	3 Months Ended
	Dec. 31, 2013 MMBTU gal	Sep. 30, 2013	Dec. 31, 2012
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Maximum percentage of normal volumes hedged	70.00%
Maximum number of months normal volumes can be hedged (in months)	36 months
Derivative [Line Items]
Derivative Instruments in Other Current Liabilities	$ 938,000	$ 4,400,000	$ 831,000
Gasoline futures contracts notional amount (in gallons)	800,000
Average price of gasoline futures contracts (dollars per gallon)	2.66
Notional amount of non-exchange traded natural gas commodity contracts (in MMBtu)	72,200,000
Notional amount of non-exchange traded natural gas commodity contracts to be settled during fiscal 2014 (in MMBtu)	57,300,000
Notional amount of non-exchange traded natural gas commodity contracts to be settled during fiscal 2015 (in MMBtu)	1,400,000
Notional amount of non-exchange traded natural gas commodity contracts to be settled during fiscal 2014 (in MMBtu)	13,500,000
Expected pre-tax unrealized gain (loss) reclassifications into the Statements of Consolidated Income during the twelve months	800,000
Derivative instrument reconciliation [Abstract]
Fair value of asset derivatives presented above	11,211,000	6,276,000	4,832,000
Fair value of cash margin receivables offset with derivatives	956,000	1,765,000	4,186,000
Cash margin receivables not offset with derivatives	3,800,000	3,200,000	4,400,000
Netting of assets and liabilities with the same counterparty	(6,533,000)	(4,739,000)	(7,778,000)
Derivative Assets	5,634,000	3,302,000	1,240,000
Fair value of liability derivatives presented above	4,945,000	10,629,000	8,578,000
Payables to Broker-Dealers and Clearing Organizations	2,516,000	6,000	31,000
Derivative Instrument, per Consolidated Balance Sheets: [Abstract]
Derivative instrument assets	4,985,000	3,291,000	1,246,000
Other deferred charges derivative instruments	649,000	11,000	(6,000)
Derivative Assets	5,634,000	3,302,000	1,240,000
Other Current Liabilities	928,000	5,896,000	831,000
Netting of assets and liabilities with the same counterparty	(6,533,000)	(4,739,000)	(7,778,000)
Other Deferred Credits, Current	(10,000)	1,496,000	0
Laclede Gas Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	19,200,000
Laclede Energy Resources [Member] | Fiscal 2014 [Member] | Open Short Futures Positions [Member]
Derivative [Line Items]
Avg. Price Per MMBtu	4.03
Mmbtu	11,040,000
Laclede Energy Resources [Member] | Fiscal 2015 [Member] | Open Short Futures Positions [Member]
Derivative [Line Items]
Avg. Price Per MMBtu	4.19
Mmbtu	490,000
Laclede Energy Resources [Member] | Fiscal 2016 [Member] | Open Short Futures Positions [Member]
Derivative [Line Items]
Avg. Price Per MMBtu	4.10
Mmbtu	10,000
Designated as Hedging Instrument [Member]
Derivative instrument reconciliation [Abstract]
Fair value of asset derivatives presented above	1,145,000	2,349,000	1,236,000
Fair value of liability derivatives presented above	1,031,000	451,000	871,000
Not Designated as Hedging Instrument [Member]
Derivative instrument reconciliation [Abstract]
Fair value of asset derivatives presented above	10,066,000	3,927,000	3,596,000
Fair value of liability derivatives presented above	3,914,000	10,178,000	7,707,000
NYMEX Natural Gas Contracts [Member] | Laclede Gas Company [Member] | Fiscal 2014 [Member] | Open Long Futures Positions [Member]
Derivative [Line Items]
Avg. Price Per MMBtu	3.88
Mmbtu	5,250,000
NYMEX Natural Gas Contracts [Member] | Laclede Gas Company [Member] | Fiscal 2015 [Member] | Open Long Futures Positions [Member]
Derivative [Line Items]
Avg. Price Per MMBtu	3.84
Mmbtu	940,000
NYMEX Natural Gas Contracts [Member] | Laclede Energy Resources [Member] | Fiscal 2014 [Member] | Open Long Futures Positions [Member]
Derivative [Line Items]
Avg. Price Per MMBtu	3.84
Mmbtu	1,640,000
NYMEX Natural Gas Contracts [Member] | Laclede Energy Resources [Member] | Fiscal 2015 [Member] | Open Long Futures Positions [Member]
Derivative [Line Items]
Avg. Price Per MMBtu	4.00
Mmbtu	390,000
NYMEX Natural Gas Contracts [Member] | Laclede Energy Resources [Member] | Fiscal 2016 [Member] | Open Long Futures Positions [Member]
Derivative [Line Items]
Avg. Price Per MMBtu	4.18
Mmbtu	90,000
NYMEX Natural Gas Contracts [Member] | Laclede Energy Resources [Member] | Fiscal 2017 [Member] | Open Long Futures Positions [Member]
Derivative [Line Items]
Avg. Price Per MMBtu	4.28
Mmbtu	20,000
NYMEX Natural Gas Contracts [Member] | Not Designated as Hedging Instrument [Member]
Derivative instrument reconciliation [Abstract]
Fair value of asset derivatives presented above		950,000
Fair value of liability derivatives presented above		100,000
ICE open basis swap positions [Member] | Laclede Energy Resources [Member] | Fiscal 2016 [Member] | Open Long Futures Positions [Member]
Derivative [Line Items]
Avg. Price Per MMBtu	(0.80)
Mmbtu	920,000
ICE open basis swap positions [Member] | Laclede Energy Resources [Member] | Fiscal 2017 [Member] | Open Long Futures Positions [Member]
Derivative [Line Items]
Avg. Price Per MMBtu	(0.80)
Mmbtu	160,000
OTCBB Natural Gas Contracts [Member] | Laclede Gas Company [Member] | Fiscal 2014 [Member] | Open Long Futures Positions [Member]
Derivative [Line Items]
Avg. Price Per MMBtu	3.99
Mmbtu	14,030,000
OTCBB Natural Gas Contracts [Member] | Laclede Gas Company [Member] | Fiscal 2015 [Member] | Open Long Futures Positions [Member]
Derivative [Line Items]
Avg. Price Per MMBtu	4.20
Mmbtu	8,600,000
OTCBB Natural Gas Contracts [Member] | Laclede Gas Company [Member] | Fiscal 2016 [Member] | Open Long Futures Positions [Member]
Derivative [Line Items]
Avg. Price Per MMBtu	4.15
Mmbtu	110,000
Accounts Receivable Other [Member] | NYMEX Natural Gas Contracts [Member] | Designated as Hedging Instrument [Member]
Derivative instrument reconciliation [Abstract]
Fair value of asset derivatives presented above		2,222,000	987,000
Fair value of liability derivatives presented above		440,000	871,000
Accounts Receivable Other [Member] | NYMEX Natural Gas Contracts [Member] | Not Designated as Hedging Instrument [Member]
Derivative instrument reconciliation [Abstract]
Fair value of asset derivatives presented above	2,802,000	1,434,000	533,000
Fair value of liability derivatives presented above	285,000	3,455,000	366,000
Other Deferred Charges [Member] | NYMEX Natural Gas Contracts [Member] | Designated as Hedging Instrument [Member]
Derivative instrument reconciliation [Abstract]
Fair value of asset derivatives presented above	110,000	22,000
Fair value of liability derivatives presented above	1,000	11,000
Other Deferred Charges [Member] | NYMEX Natural Gas Contracts [Member] | Not Designated as Hedging Instrument [Member]
Derivative instrument reconciliation [Abstract]
Fair value of asset derivatives presented above	3,000	32,000
Fair value of liability derivatives presented above	7,000	0
Other Deferred Charges [Member] | Natural Gas Commodity Contracts [Member] | Not Designated as Hedging Instrument [Member]
Derivative instrument reconciliation [Abstract]
Fair value of asset derivatives presented above	641,000	20,000
Fair value of liability derivatives presented above	37,000	137,000
Derivative Instruments Assets [Member] | NYMEX Natural Gas Contracts [Member] | Designated as Hedging Instrument [Member]
Derivative instrument reconciliation [Abstract]
Fair value of asset derivatives presented above	881,000
Fair value of liability derivatives presented above	1,030,000
Derivative Instruments Assets [Member] | NYMEX Natural Gas Contracts [Member] | Not Designated as Hedging Instrument [Member]
Derivative instrument reconciliation [Abstract]
Fair value of asset derivatives presented above	571,000		1,726,000
Fair value of liability derivatives presented above	955,000		6,162,000
Derivative Instruments Assets [Member] | Natural Gas Commodity Contracts [Member] | Not Designated as Hedging Instrument [Member]
Derivative instrument reconciliation [Abstract]
Fair value of asset derivatives presented above	1,915,000	991,000	1,197,000
Fair value of liability derivatives presented above	$ 272,000	$ 90,000	$ 240,000

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

3 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

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 December 31, 2013 and 2012, for the Utility, were $101.9 million and $39.6 million, respectively. The amount of accrued unbilled revenue at September 30, 2013 was $25.2 million.

GROSS RECEIPTS TAXES

GROSS RECEIPTS 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 for the three months ended December 31, 2013 and 2012 were $19.9 million and $10.3 million, respectively. Gross receipts taxes are expensed by the Utility and included in the Taxes, other than income taxes line.