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 March 31, 2014

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 April 25, 2014, there were 32,785,833 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 (Unaudited):
		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	27
Item 3	Quantitative and Qualitative Disclosures About Market Risk		42
Item 4	Controls and Procedures		43
PART II.  OTHER INFORMATION
Item 1	Legal Proceedings		44
Item 1A	Risk Factors		44
Item 2	Unregistered Sales of Equity Securities and Use of Proceeds		46
Item 5	Other Information		46
Item 6	Exhibits		46
SIGNATURE			47
INDEX TO EXHIBITS			48

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   March 31,					Six Months Ended   March 31,
(Thousands, Except Per Share Amounts)	2014			2013		2014		2013
Operating Revenues:
Gas Utility	$	634,442		$	354,097	$	1,069,608	$	604,208
Gas Marketing	59,811			41,255		93,064		96,504
Other	251			2,261		441		3,904
Total Operating Revenues	694,504			397,613		1,163,113		704,616
Operating Expenses:
Gas Utility
Natural and propane gas	405,359			230,440		647,145		366,956
Other operation and maintenance expenses	72,009			41,191		134,331		80,842
Depreciation and amortization	20,118			11,258		40,144		22,223
Taxes, other than income taxes	41,739			21,751		70,328		36,557
Total Gas Utility Operating Expenses	539,225			304,640		891,948		506,578
Gas Marketing	65,021			35,995		116,803		93,376
Other	3,079			5,129		4,280		10,727
Total Operating Expenses	607,325			345,764		1,013,031		610,681
Operating Income	87,179			51,849		150,082		93,935
Other Income and (Income Deductions) – Net	(248		)	1,340		1,401		2,424
Interest Charges:
Interest on long-term debt	8,630			5,689		18,324		11,127
Other interest charges	742			1,016		1,509		1,604
Total Interest Charges	9,372			6,705		19,833		12,731
Income Before Income Taxes	77,559			46,484		131,650		83,628
Income Tax Expense	25,340			16,242		43,839		27,818
Net Income	$	52,219		$	30,242	$	87,811	$	55,810
Weighted Average Number of Common Shares Outstanding:
Basic	32,617			22,421		32,593		22,396
Diluted	32,656			22,498		32,652		22,466
Basic Earnings Per Share of Common Stock	$	1.59		$	1.34	$	2.68	$	2.48
Diluted Earnings Per Share of Common Stock	$	1.59		$	1.34	$	2.68	$	2.47
Dividends Declared Per Share of Common Stock	$	0.440		$	0.425	$	0.880	$	0.850
See Notes to Consolidated Financial Statements.

4

THE LACLEDE GROUP, INC.

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

(UNAUDITED)

	Three Months Ended   March 31,						Six Months Ended   March 31,
(Thousands)	2014			2013			2014			2013
Net Income	$	52,219		$	30,242		$	87,811		$	55,810
Other Comprehensive Income (Loss), Before Tax:
Net (losses) gains on cash flow hedging derivative instruments:
Net hedging loss arising during the period	(3,451		)	(7,590		)	(5,097		)	(6,201		)
Reclassification adjustment for losses (gains) included in net income	3,194			(22		)	2,016			2,228
Net unrealized losses on cash flow hedging derivative instruments	(257		)	(7,612		)	(3,081		)	(3,973		)
Defined benefit pension and other postretirement plans:
Amortization of actuarial loss included in net periodic pension and postretirement benefit cost:	97			90			195			181
Other Comprehensive Loss, Before Tax	(160		)	(7,522		)	(2,886		)	(3,792		)
Income Tax Benefit Related to Items of Other Comprehensive Income	(62		)	(2,868		)	(1,096		)	(1,417		)
Other Comprehensive Loss, Net of Tax	(98		)	(4,654		)	(1,790		)	(2,375		)
Comprehensive Income	$	52,121		$	25,588		$	86,021		$	53,435
See Notes to Consolidated Financial Statements.

5

THE LACLEDE GROUP, INC.

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	Mar. 31,			Sept. 30,			Mar. 31,
(Thousands)	2014			2013			2013
ASSETS
Utility Plant	$	2,325,358		$	2,271,189		$	1,538,890
Less:  Accumulated depreciation and amortization	522,408			494,559			478,971
Net Utility Plant	1,802,950			1,776,630			1,059,919
Non-utility property	5,539			7,694			5,456
Goodwill	216,370			247,078			—
Other investments	62,231			58,306			52,910
Other Property and Investments	284,140			313,078			58,366
Current Assets:
Cash and cash equivalents	10,931			52,981			146,880
Accounts receivable:
Utility	275,688			101,118			148,624
Non-utility	103,272			63,752			55,925
Other	14,579			14,451			9,290
Allowance for doubtful accounts	(10,549		)	(8,046		)	(8,833		)
Delayed customer billings	29,667			—			19,663
Inventories:
Natural gas stored underground	67,798			182,035			32,776
Propane gas	6,633			8,962			8,963
Materials and supplies at average cost	8,408			8,154			4,385
Natural gas receivable	3,233			18,782			13,470
Derivative instrument assets	13,560			3,291			6,021
Unamortized purchased gas adjustments	1,631			17,533			11,039
Deferred income taxes	5,871			—			2,527
Prepayments and other	10,909			12,867			9,183
Total Current Assets	541,631			475,880			459,913
Deferred Charges:
Regulatory assets	537,398			545,947			424,743
Other	14,352			13,851			6,157
Total Deferred Charges	551,750			559,798			430,900
Total Assets	$	3,180,471		$	3,125,386		$	2,009,098

6

THE LACLEDE GROUP, INC.

CONSOLIDATED BALANCE SHEETS (Continued)

(UNAUDITED)

	Mar. 31,			Sept. 30,			Mar. 31,
(Thousands, except share amounts)	2014			2013			2013
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock (70,000,000 shares authorized, 32,776,595,     32,696,836, and 22,643,693 shares issued, respectively)	$	32,777		$	32,697		$	22,644
Paid-in capital	597,468			594,269			172,736
Retained earnings	478,955			420,103			451,114
Accumulated other comprehensive loss	(2,578		)	(787		)	(6,491		)
Total Common Stock Equity	1,106,622			1,046,282			640,003
Long-term debt (less current portion)	832,817			912,712			464,434
Total Capitalization	1,939,439			1,958,994			1,104,437
Current Liabilities:
Notes payable	36,000			74,000			—
Accounts payable	215,085			140,234			108,648
Advance customer billings	—			23,736			—
Wages and compensation accrued	21,839			20,807			16,175
Dividends payable	15,083			14,556			10,059
Customer deposits	15,588			15,062			7,706
Interest accrued	8,064			8,335			6,191
Taxes accrued	71,442			32,896			44,550
Deferred income taxes	—			1,012			—
Other	16,863			22,540			14,015
Total Current Liabilities	399,964			353,178			207,344
Deferred Credits and Other Liabilities:
Deferred income taxes	392,461			379,114			343,016
Unamortized investment tax credits	2,794			2,900			3,006
Pension and postretirement benefit costs	223,970			228,653			191,778
Asset retirement obligations	73,353			74,554			41,512
Regulatory liabilities	102,407			82,560			83,026
Other	46,083			45,433			34,979
Total Deferred Credits and Other Liabilities	841,068			813,214			697,317
Commitments and Contingencies (Note 12)
Total Capitalization and Liabilities	$	3,180,471		$	3,125,386		$	2,009,098
See Notes to Consolidated Financial Statements.

7

THE LACLEDE GROUP, INC.

STATEMENTS OF CONSOLIDATED CASH FLOWS

(UNAUDITED) 

	Six Months Ended   March 31,
(Thousands)	2014			2013
Operating Activities:
Net Income	$	87,811		$	55,810
Adjustments to reconcile net income to net cash provided by (used in)       operating activities:
Depreciation, amortization, and accretion	40,501			22,913
Deferred income taxes and investment tax credits	3,396			(11,132		)
Other – net	2,102			450
Changes in assets and liabilities:
Accounts receivable – net	(211,715		)	(71,164		)
Unamortized purchased gas adjustments	15,901			29,635
Deferred purchased gas costs	27,766			43,827
Accounts payable	79,357			23,797
Delayed customer billings - net	(53,403		)	(44,809		)
Taxes accrued	38,123			32,971
Natural gas stored underground	114,237			59,953
Other assets and liabilities	(1,272		)	115
Net cash provided by operating activities	142,804			142,366
Investing Activities:
Capital expenditures	(68,226		)	(62,707		)
Other investments	(5,082		)	(2,126		)
Proceeds from sale of right to acquire NEG	11,000			—
Proceeds from final reconciliation of acquisition of MGE	23,925			—
Net cash used in investing activities	(38,383		)	(64,833		)
Financing Activities:
Issuance of long-term debt	—			125,000
Redemption and maturity of first mortgage bonds	(80,000		)	(25,000		)
Repayment of short-term debt – net	(38,000		)	(40,100		)
Changes in book overdrafts	(1,184		)	(1,262		)
Issuance of common stock	1,440			2,852
Dividends paid	(28,503		)	(19,054		)
Employees’ taxes paid associated with restricted shares withheld upon vesting	(1,053		)	(729		)
Excess tax benefits from stock-based compensation	880			636
Other	(51		)	(453		)
Net cash (used in) provided by financing activities	(146,471		)	41,890
Net (Decrease) Increase in Cash and Cash Equivalents	(42,050		)	119,423
Cash and Cash Equivalents at Beginning of Period	52,981			27,457
Cash and Cash Equivalents at End of Period	$	10,931		$	146,880
Supplemental disclosure of cash flow information:
Interest paid	$	19,724		$	14,569
Income taxes paid (refunded)	2,595			(3,165		)
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 (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 six months ended March 31, 2014, and impacts 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 Utility, Laclede Group’s earnings are typically concentrated during the heating season of November through April each fiscal year, although earnings for MGE are less seasonal than earnings from Laclede Gas due to MGE's 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 March 31, 2014 and 2013, for the Utility, were $77.1 million and $33.3 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 March 31, 2014 and 2013 were $34.3 million and $17.2 million, respectively. Amounts recorded in Gas Utility Operating Revenues for the six months ended March 31, 2014 and 2013 were $54.3 million and $27.5 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 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. (ETE) and Energy Transfer Partners, L.P. The purchase was completed pursuant to the Purchase and Sales Agreement (MGE PSA) dated December 14, 2012. Under the terms of the MGE PSA, the Utility acquired MGE for a purchase price of $975 million, subject to reconciliation of certain amounts as discussed below.

The strategic rationale for the purchase for Laclede Group to is described below:

• With a larger market capitalization and enterprise value, the Company improved trading liquidity and has

better access to the capital markets.

• The Company now serves Missouri's two largest metropolitan areas in a state where it already had a working

relationship with regulators.

In accordance with Section 3.2 of the MGE PSA, Laclede Gas provided to SUG a reconciliation of certain balance sheet accounts from the amounts at September 30, 2012 to August 31, 2013, indicating the difference due to changes in the actual net assets transferred to the Company at closing from the level at September 30, 2012. Laclede Gas and SUG agreed to the final reconciliation amount of $23.9 million which was paid by ETE to Laclede Gas on February 14, 2014.

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.

9

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. On March 26, 2014, the MDPU issued an order denying the Attorney General's motion, so the MDPU's order approving the sale of NEG is now final.

These receipts of funds in December and February effectively reduced the Utility's purchase price of MGE to $940.1 million and reduced goodwill related to the transaction to $216.4 million. 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. As part of the MGE acquisition, Laclede Gas has estimated the asset retirement obligation of MGE's long-lived assets as of the acquisition date. This allocation of asset retirement obligations is preliminary and will be finalized upon completion of a detailed fair value analysis that is being performed by the Company and will be finalized prior to September 30, 2014.

For the three and six months ended March 31, 2014, operating revenues for MGE were $236.6 million and $396.7 million, respectively.

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 March 31, 2014 and 2013 were $6.6 million and $4.2 million, respectively, including amounts charged to construction. Pension costs for the six months ended March 31, 2014 and 2013 were $13.2 million and $8.4 million, respectively, including amounts charged to construction.

The net periodic pension costs include the following components:

	Three Months Ended   March 31,						Six Months Ended   March 31,
(Thousands)	2014			2013			2014			2013
Service cost – benefits earned during the period	$	2,428		$	2,311		$	4,856		$	4,622
Interest cost on projected benefit obligation	6,010			4,066			12,020			8,132
Expected return on plan assets	(6,645		)	(4,741		)	(13,290		)	(9,482		)
Amortization of prior service cost	125			136			249			272
Amortization of actuarial loss	1,772			2,839			3,544			5,678
Loss on lump-sum settlement	1,319			—			1,319			—
Sub-total	5,009			4,611			8,698			9,222
Regulatory adjustment	1,571			(433		)	4,461			(867		)
Net pension cost	$	6,580		$	4,178		$	13,159		$	8,355

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. Lump-sum payments recognized as settlements during the six months ended March 31, 2014 were $10.9 million. There were no lump-sum payments recognized as settlements during the six months ended March 31, 2013.

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 March 31, 2014 were $9.6 million to the qualified trusts and $0.2 million to the non-qualified plans.

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Contributions to the pension plans for the remaining six months of fiscal 2014 are anticipated to be approximately $14.4 million to the qualified trusts and $0.2 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 March 31, 2014 and 2013 were $2.4 million, including amounts charged to construction. Postretirement benefit costs for both the six months ended March 31, 2014 and 2013 were $4.8 million, including amounts charged to construction.

Net periodic postretirement benefit costs consisted of the following components:

	Three Months Ended   March 31,						Six Months Ended   March 31,
(Thousands)	2014			2013			2014			2013
Service cost – benefits earned during the period	$	2,804		$	2,534		$	5,608		$	5,067
Interest cost on accumulated postretirement benefit obligation	2,170			1,279			4,339			2,558
Expected return on plan assets	(1,709		)	(1,081		)	(3,418		)	(2,162		)
Amortization of transition obligation	—			23			—			46
Amortization of prior service cost (credit)	(1		)	1			(2		)	2
Amortization of actuarial loss	1,505			1,325			3,010			2,650
Sub-total	4,769			4,081			9,537			8,161
Regulatory adjustment	(2,388		)	(1,699		)	(4,775		)	(3,398		)
Net postretirement benefit cost	$	2,381		$	2,382		$	4,762		$	4,763

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. Fiscal year 2014 contributions to the postretirement plans through March 31, 2014 were $4.8 million. Contributions to the postretirement plans for the remaining six months of fiscal year 2014 are anticipated to be $14.4 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 4 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 six months ended March 31, 2014, the Company granted 123,252 performance-contingent restricted stock units to executive officers and key employees at a weighted average grant date fair value of $37.20 per share. The number of stock units granted 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.

11

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 six months ended March 31, 2014 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)	123,252		$	37.20
Vested	(52,954	)	$	32.16
Forfeited	(22,022	)	$	29.35
Nonvested at March 31, 2014	290,544		$	36.17

During the six months ended March 31, 2014, the Company granted 71,768 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 $45.65 per share. Of the 71,768 shares, 15,200 shares will vest on July 14, 2014, 12,168 shares vest on December 2, 2014, and the remaining 44,400 shares will vest during FY 2017. In the interim, participants receive full voting rights and dividends, which are not subject to forfeiture.

Time-vested restricted stock and stock unit activity for the six months ended March 31, 2014 is presented below:

	Restricted Stock/ Stock Units		Weighted Average Grant Date Fair Value
Nonvested at September 30, 2013	119,404		$	38.64
Granted	71,768		$	45.65
Vested	(17,999	)	$	36.37
Forfeited	(16,950	)	$	38.04
Nonvested at March 31, 2014	156,223		$	42.19

During the six months ended March 31, 2014, 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 six months ended March 31, 2014 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	(23,250	)	$	30.96
Forfeited	—		$	—
Expired	—		$	—
Outstanding at March 31, 2014	110,250		$	32.07	1.4	$	1,663
Fully Vested and Expected to Vest at March 31, 2014	110,250		$	32.07	1.4	$	1,663
Exercisable at March 31, 2014	110,250		$	32.07	1.4	$	1,663

The closing price of the Company’s common stock was $47.15 on March 31, 2014.

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Equity Compensation Costs

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

	Three Months Ended   March 31,						Six Months Ended March 31,
(Thousands)	2014			2013			2014			2013
Total equity compensation cost	$	1,933		$	1,137		$	2,466		$	1,759
Compensation cost capitalized	(556		)	(356		)	(705		)	(539		)
Compensation cost recognized	$	1,377		$	781		$	1,761		$	1,220
Income tax benefit recognized	(527		)	(298		)	(674		)	(467		)

As of March 31, 2014, there was $9.8 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 2.2 years.

5. EARNINGS PER COMMON SHARE

	Three Months Ended March 31,				Six Months Ended March 31,
(Thousands, Except Per Share Amounts)	2014		2013		2014		2013
Basic EPS:
Net Income	$	52,219	$	30,242	$	87,811	$	55,810
Less: Income allocated to participating securities	210		186		350		312
Net Income Available to Common Shareholders	$	52,009	$	30,056	$	87,461	$	55,498
Weighted Average Shares Outstanding	32,617		22,421		32,593		22,396
Earnings Per Share of Common Stock	$	1.59	$	1.34	$	2.68	$	2.48
Diluted EPS:
Net Income	$	52,219	$	30,242	$	87,811	$	55,810
Less: Income allocated to participating securities	209		186		349		311
Net Income Available to Common Shareholders	$	52,010	$	30,056	$	87,462	$	55,499
Weighted Average Shares Outstanding	32,617		22,421		32,593		22,396
Dilutive Effect of Stock Options, Restricted Stock and Restricted Stock Units	39		77		59		70
Weighted Average Diluted Shares	32,656		22,498		32,652		22,466
Earnings Per Share of Common Stock	$	1.59	$	1.34	$	2.68	$	2.47
Outstanding Shares Excluded from the Calculation of Diluted EPS Attributable to:
Restricted stock and stock units subject to performance and/or market conditions	277		211		277		211

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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 March 31, 2014
Cash and cash equivalents	$	10,931	$	10,931	$	10,751	$	180	$	—
Short-term debt	36,000		36,000		—		36,000		—
Long-term debt	832,817		884,029		—		884,029		—
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	912,712		954,126		—		954,126		—
As of March 31, 2013
Cash and cash equivalents	$	146,880	$	146,880	$	136,826	$	10,054	$	—
Short-term debt	—		—		—		—		—
Long-term debt	464,434		539,260		—		539,260		—

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

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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 March 31, 2014
Assets
U. S. Stock/Bond Mutual Funds	$	16,340	$	2,780	$	—	$	—		$	19,120
NYMEX/ICE natural gas contracts	7,495		1,263		—		(5,595		)	3,163
OTCBB natural gas contracts	—		6,330		—		(315		)	6,015
NYMEX gasoline and heating oil contracts	49		—		—		—			49
Natural gas commodity contracts	—		6,619		7		(1,184		)	5,442
Total	$	23,884	$	16,992	$	7	$	(7,094	)	$	33,789
Liabilities
NYMEX/ICE natural gas contracts	$	4,374	$	565	$	—	$	(4,939	)	$	—
OTCBB natural gas contracts	—		315		—		(315		)	—
Natural gas commodity contracts	—		3,278		40		(1,184		)	2,134
Total	$	4,374	$	4,158	$	40	$	(6,438	)	$	2,134
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 March 31, 2013
Assets
U. S. Stock/Bond Mutual Funds	$	13,922	$	—	$	—	$	—		$	13,922
NYMEX/ICE natural gas contracts	11,010		379		—		(8,209		)	3,180
NYMEX gasoline and heating oil contracts	322		—		—		(192		)	130
Natural gas commodity contracts	—		2,888		117		(289		)	2,716
Total	$	25,254	$	3,267	$	117	$	(8,690	)	$	19,948
Liabilities
NYMEX/ICE natural gas contracts	$	2,447	$	1,342	$	—	$	(3,789	)	$	—
Natural gas commodity contracts	—		990		24		(289		)	725
Interest rate swap	—		4,549		—		—			4,549
Total	$	2,447	$	6,881	$	24	$	(4,078	)	$	5,274

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The mutual funds included in Level 1 are valued based on exchange-quoted market prices of individual 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 March 31,					Six Months Ended March 31,
(Thousands)	2014			2013		2014			2013
Beginning of period	$	7		$	30	$	110		$	109
Net settlements	(22		)	37		(131		)	(29		)
Net gains related to derivatives not held at end of period	17			—		3			—
Net (losses) gains related to derivatives still held at end of period	(35		)	26		(15		)	13
End of period	$	(33	)	$	93	$	(33	)	$	93

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, the Utility purchases NYMEX futures and options contracts to help stabilize operating costs associated with forecasted purchases of gasoline and diesel fuels used to power vehicles and equipment used in the course of its business. At March 31, 2014, Laclede Gas held 0.4 million gallons of gasoline futures contracts at an average price of $2.76 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 March 31, 2014, the fair values of 149.2 million MMBtu of non-exchange traded natural gas commodity contracts were reflected in the Consolidated Balance Sheet. Of these contracts, 79.2 million MMBtu will settle during fiscal year 2014, 30.2 million MMBtu will settle during fiscal year 2015, 12.4 million MMBtu will settle during fiscal year 2016, 11.0 million MMBtu will settle during fiscal year 2017, 11.0 million MMBtu will settle during fiscal year 2018, while the remaining 5.4 million MMBtu will settle during fiscal year 2019. These contracts have not been designated as hedges; therefore, changes in the fair value of these contracts are reported in earnings each period.

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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 March 31, 2014, 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 March 31, 2014 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	—	$	—	7.56	$	4.38
Fiscal 2015	—	—		1.58	4.46
Fiscal 2016	—	—		0.05	4.22
NYMEX/ICE Open long futures positions
Fiscal 2014	3.80	$	3.79	1.16	$	4.23
Fiscal 2015	0.94	3.84		0.88	4.35
Fiscal 2016	—	—		0.09	4.18
Fiscal 2017	—	—		0.02	4.28
ICE Open long basis swap positions
Fiscal 2014	—	$	—	0.92	$	0.39
Fiscal 2015	—	—		0.16	0.39
Fiscal 2016	—	—		0.92	0.80
Fiscal 2017	—	—		0.16	0.80
ICE Open short basis swap positions
Fiscal 2014	—	$	—	4.86	$	0.02
Fiscal 2015	—	—		0.62	(0.09		)
OTCBB Open long futures positions
Fiscal 2014	9.53	$	4.00	—	$	—
Fiscal 2015	9.83	4.21		—	—
Fiscal 2016	0.55	4.24		—	—

At March 31, 2014, the Utility had 28.4 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 March 31, 2014, it is expected that approximately $1.0 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.

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The Effect of Derivative Instruments on the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income
	Location of Gain (Loss)	Three Months Ended March 31,						Six Months Ended March 31,
(Thousands)	Recorded in Income	2014			2013			2014			2013
Derivatives in Cash Flow Hedging Relationships
Effective portion of gain (loss) recognized in OCI on derivatives:
NYMEX/ICE natural gas contracts		$	(3,508	)	$	(3,188	)	$	(5,163	)	$	(1,855	)
NYMEX gasoline and heating oil contracts		57			147			66			203
Interest rate swaps		—			(4,549		)	—			(4,549		)
Total		$	(3,451	)	$	(7,590	)	$	(5,097	)	$	(6,201	)
Effective portion of gain (loss) reclassified from AOCI to income:
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	$	(4,655	)	$	302		$	(3,355	)	$	(1,661	)
	Gas Marketing Operating Expenses	1,406			(318		)	1,226			(652		)
Sub-total		(3,249		)	(16		)	(2,129		)	(2,313		)
NYMEX gasoline and heating oil contracts	Gas Utility Other Operations and Maintenance Expenses	55			38			113			85
Total		$	(3,194	)	$	22		$	(2,016	)	$	(2,228	)
Ineffective portion of gain (loss) on derivatives recognized in income:
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	$	74		$	(87	)	$	(137	)	$	(412	)
	Gas Marketing Operating Expenses	(10		)	(44		)	123			(129		)
Sub-total		64			(131		)	(14		)	(541		)
NYMEX gasoline and heating oil contracts	Gas Utility Other Operations and Maintenance Expenses	(84		)	(31		)	36			(132		)
Total		$	(20	)	$	(162	)	$	22		$	(673	)
Derivatives Not Designated as Hedging Instruments *
Gain (loss) recognized in income on derivatives:
Natural gas commodity contracts	Gas Marketing Operating Revenues	$	13,922		$	1,745		$	12,255		$	775
	Gas Marketing Operating Expenses	—			—			—			—
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	1,840			(1,679		)	3,830			(612		)
	Gas Marketing Operating Expenses	—			—			—			—
NYMEX gasoline and heating oil contracts	Other Income and (Income Deductions) - Net	(3		)	13			10			46
Total		$	15,759		$	79		$	16,095		$	209

* 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.

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Fair Value of Derivative Instruments in the Consolidated Balance Sheet at March 31, 2014
	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	$	915		Derivative Instrument Assets	$	773
	Other Deferred Charges	207			Other Deferred Charges	1
NYMEX gasoline and heating oil contracts	Derivative Instrument Assets	49			Derivative Instrument Assets	—
Sub-total		1,171				774
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets	3,166			Derivative Instrument Assets	347
	Accounts Receivable – Other	4,467			Accounts Receivable – Other	3,811
	Other Deferred Charges	3			Other Deferred Charges	7
OTCBB natural gas contracts	Derivative Instrument Assets	6,266			Derivative Instrument Assets	193
	Other Deferred Credits	64			Other Deferred Credits	122
Natural gas commodity contracts	Derivative Instrument Assets	4,466			Derivative Instrument Assets	333
	Other Deferred Charges	1,326			Other Deferred Charges	17
	Other Current Liabilities	603			Other Current Liabilities	1,574
	Other Deferred Credits	231			Other Deferred Credits	1,394
Sub-total		20,592				7,798
Total derivatives		$	21,763			$	8,572
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

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Fair Value of Derivative Instruments in the Consolidated Balance Sheet at March 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	Accounts Receivable - Other	$	520	Accounts Receivable - Other	$	2,993
	Other Deferred Charges	5		Other Deferred Charges	—
NYMEX gasoline and heating oil contracts	Derivative Instrument Assets	312		Derivative Instrument Assets	—
Interest rate swaps	Other Current Liabilities	—		Other Current Liabilities	4,549
Sub-total		837			7,542
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets	10,862		Derivative Instrument Assets	339
	Accounts Receivable - Other	2		Accounts Receivable - Other	457
Natural gas commodity contracts	Derivative Instrument Assets	2,943		Derivative Instrument Assets	227
	Other Current Liabilities	62		Other Current Liabilities	787
NYMEX gasoline and heating oil contracts	Derivative Instrument Assets	10		Derivative Instrument Assets	—
Sub-total		13,879			1,810
Total derivatives		$	14,716		$	9,352

* 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)	March 31, 2014			September 30, 2013			March 31, 2013
Fair value of asset derivatives presented above	$	21,763		$	6,276		$	14,716
Fair value of cash margin receivables offset with derivatives	—			1,765			2,928
Netting of assets and liabilities with the same counterparty	(7,094		)	(4,739		)	(11,618		)
Total	$	14,669		$	3,302		$	6,026
Derivative Instrument Assets, per Consolidated Balance Sheets:
Derivative instrument assets	$	13,560		$	3,291		$	6,021
Other deferred charges	1,109			11			5
Total	$	14,669		$	3,302		$	6,026
Fair value of liability derivatives presented above	$	8,572		$	10,629		$	9,352
Fair value of cash margin payables offset with derivatives	655			6			7,540
Netting of assets and liabilities with the same counterparty	(7,094		)	(4,739		)	(11,618		)
Total	$	2,133		$	5,896		$	5,274
Derivative Instrument Liabilities, per Consolidated Balance Sheets:
Other Current Liabilities	$	1,196		$	4,400		$	5,274
Other Deferred Credits	937			1,496			—
Total	$	2,133		$	5,896		$	5,274

Additionally, at March 31, 2014, September 30, 2013, and March 31, 2013, the Company had $3.8 million, $3.2 million, and $1.3 million, respectively, in cash margin receivables not offset with derivatives, that are presented in Accounts Receivable - Other.

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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. 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 $30.0 million at March 31, 2014. Net receivable amounts from these customers on the same date, reflecting netting arrangements, were $19.2 million. Accounts receivable attributable to utility companies and their marketing affiliates comprised $33.3 million of total accounts receivable at March 31, 2014, while net receivable amounts from these customers, reflecting netting arrangements, were $30.3 million. LER also has concentrations of credit risk with certain individually significant counterparties. At March 31, 2014, the amounts included in accounts receivable from LER’s five largest counterparties (in terms of net accounts receivable exposure), were $34.9 million. Four of these five counterparties are investment-grade rated and the fifth is privately owned. Net receivable amounts from these customers on the same date, reflecting netting arrangements, were $27.2 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 March 31,						Six Months Ended March 31,
(Thousands)	2014			2013			2014		2013
Interest income	$	142		$	257		$	391	$	663
Net investment gain (loss)	(612		)	1,174			135		1,104
Other income (deductions)	222			(91		)	875		657
Other Income and (Income Deductions) – Net	$	(248	)	$	1,340		$	1,401	$	2,424

11. INFORMATION BY OPERATING SEGMENT

All of Laclede Group’s subsidiaries are 100% 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.

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(Thousands)	Gas Utility		Gas Marketing			Other			Eliminations			Consolidated
Three Months Ended March 31, 2014
Revenues from external customers	$	634,442	$	59,811		$	251		$	—		$	694,504
Intersegment revenues	4,276		20,686			465			(25,427		)	—
Total Operating Revenues	638,718		80,497			716			(25,427		)	694,504
Operating Expenses
Gas Utility
Natural and Propane Gas	430,576		—			—			(25,217		)	405,359
Other Operation and Maintenance Expenses	72,219		—			—			(210		)	72,009
Depreciation and Amortization	20,118		—			—			—			20,118
Taxes, Other than Income Taxes	41,739		—			—			—			41,739
Total Gas Utility Operating Expenses	564,652		—			—			(25,427		)	539,225
Gas Marketing	—		65,021			—			—			65,021
Other	—		—			3,079			—			3,079
Total Operating Expenses	564,652		65,021			3,079			(25,427		)	607,325
Operating Income	74,066		15,476			(2,363		)	—			87,179
Net Economic Earnings (Losses)	$	44,727	$	7,084		$	(82	)	$	—		$	51,729
Total assets	$	3,036,185	$	199,270		$	77,505		$	(132,489	)	$	3,180,471
Three Months Ended March 31, 2013
Revenues from external customers	$	354,097	$	41,255		$	2,261		$	—		$	397,613
Intersegment revenues	9,814		(2,332		)	219			(7,701		)	—
Total Operating Revenues	363,911		38,923			2,480			(7,701		)	397,613
Operating Expenses
Gas Utility
Natural and Propane Gas	237,888		—			160			(7,608		)	230,440
Other Operation and Maintenance Expenses	41,191		—			—			—			41,191
Depreciation and Amortization	11,258		—			—			—			11,258
Taxes, Other than Income Taxes	21,751		—			—			—			21,751
Total Gas Utility Operating Expenses	312,088		—			160			(7,608		)	304,640
Gas Marketing	—		35,995			—			—			35,995
Other	—		—			5,222			(93		)	5,129
Total Operating Expenses	312,088		35,995			5,382			(7,701		)	345,764
Operating Income	51,823		2,928			(2,902		)	—			51,849
Net Economic Earnings (Losses)	$	30,197	$	2,368		$	(51	)	$	—		$	32,514
Total assets	$	1,821,372	$	202,012		$	126,668		$	(140,954	)	$	2,009,098

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(Thousands)	Gas Utility		Gas Marketing		Other			Eliminations			Consolidated
Six Months Ended March 31, 2014
Revenues from external customers	$	1,069,608	$	93,064	$	441		$	—		$	1,163,113
Intersegment revenues	4,338		40,143		906			(45,387		)	—
Total Operating Revenues	1,073,946		133,207		1,347			(45,387		)	1,163,113
Operating Expenses
Gas Utility
Natural and Propane Gas	692,128		—		—			(44,983		)	647,145
Other Operation and Maintenance Expenses	134,735		—		—			(404		)	134,331
Depreciation and Amortization	40,144		—		—			—			40,144
Taxes, Other than Income Taxes	70,328		—		—			—			70,328
Total Gas Utility Operating Expenses	937,335		—		—			(45,387		)	891,948
Gas Marketing	—		116,803		—			—			116,803
Other	100		—		4,180			—			4,280
Total Operating Expenses	937,435		116,803		4,180			(45,387		)	1,013,031
Operating Income	136,511		16,404		(2,833		)	—			150,082
Net Economic Earnings (Losses)	$	80,504	$	7,906	$	(417	)	$	—		$	87,993
Total assets	$	3,036,185	$	199,270	$	77,505		$	(132,489	)	$	3,180,471
Six Months Ended March 31, 2013
Revenues from external customers	$	604,208	$	96,504	$	3,904		$	—		$	704,616
Intersegment revenues	10,494		4,574		578			(15,646		)	—
Total Operating Revenues	614,702		101,078		4,482			(15,646		)	704,616
Operating Expenses
Gas Utility
Natural and Propane Gas	381,963		—		519			(15,526		)	366,956
Other Operation and Maintenance Expenses	80,842		—		120			(120		)	80,842
Depreciation and Amortization	22,223		—		—			—			22,223
Taxes, Other than Income Taxes	36,557		—		—			—			36,557
Total Gas Utility Operating Expenses	521,585		—		639			(15,646		)	506,578
Gas Marketing	—		93,376		—			—			93,376
Other	—		—		10,727			—			10,727
Total Operating Expenses	521,585		93,376		11,366			(15,646		)	610,681
Operating Income	93,117		7,702		(6,884		)	—			93,935
Net Economic Earnings (Losses)	$	55,538	$	5,649	$	(440	)	$	—		$	60,747
Total assets	$	1,821,372	$	202,012	$	126,668		$	(140,954	)	$	2,009,098

Reconciliation of Consolidated Net Income to Consolidated Net Economic Earnings
	Three Months Ended March 31,					Six Months Ended   March 31,
(Thousands)	2014			2013		2014			2013
Net Income (GAAP)	$	52,219		$	30,242	$	87,811		$	55,810
Unrealized (gain) loss on energy-related derivative contracts	(1,593		)	587		(1,292		)	1,026
Lower of cost or market inventory adjustments	(527		)	—		(589		)	—
Realized (gain) loss on economic hedges prior to sale of the physical commodity	(166		)	9		(119		)	(22		)
Acquisition, divestiture, and restructuring activities	1,796			1,676		2,182			3,933
Net Economic Earnings (Non-GAAP)	$	51,729		$	32,514	$	87,993		$	60,747

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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 March 31, 2014 are estimated at approximately $975 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 begin. 

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.

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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. In 2014, the Laclede Gas account was paid in full. LER is still owed $0.1 million, which it expects to receive in 2014.

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

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13. SUBSEQUENT EVENTS

On April 5, 2014, Laclede Group entered into an agreement (the Alagasco Transaction) with Energen Corporation (Energen) to acquire 100 percent of the common stock of Alabama Gas Corporation (Alagasco). Alagasco, a subsidiary of Energen, is engaged in the distribution of natural gas on a regulated basis in Alabama and serves more than 422,000 customers. The stated purchase price is $1.6 billion, subject to customary closing adjustments, comprised of approximately $1.35 billion in cash and approximately $250 million of assumed Alagasco long-term debt. The Alagasco Transaction is supported by a fully committed $1.35 billion bridge loan facility with Credit Suisse and Wells Fargo Bank, National Association, which as of April 28th has been syndicated to a group of eleven additional banks.

On April 14, 2014, Laclede and Energen jointly filed with the Alabama Public Service Commission to request approval of the Alagasco Transaction.

On April 23, 2014, the MoPSC approved a stipulation and agreement reached between MGE and all parties to the case finalizing MGE’s general rate case filed in September 2013. Under the agreement, MGE’s annual revenues will increase by $7.8 million, effective May 1, 2014. The revenues will be collected in base rates and will replace a like amount that MGE is currently authorized to collect through the Infrastructure System Replacement Surcharge mechanism.

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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.

In addition, actual results may differ materially from those contemplated in any forward-looking statement if the purchase of 100 percent of the common stock of Alabama Gas Corporation (Alagasco) from Energen Corporation (Energen) occurs before September 30, 2014. Refer to Acquisition Agreement on page 28 for additional information.

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.

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ACQUISITION AGREEMENT

On April 5, 2014, Laclede Group entered into an agreement (the Alagasco Transaction) with Energen to acquire 100 percent of the common stock of Alagasco. The strategic rationale for the Company is described below:

• The acquisition fits our growth strategy and supports the Company’s commitment to long-term shareholder value creation. 

• The acquisition is anticipated to add to net economic earnings (NEE) per share beginning in fiscal 2015, support long-term NEE per share growth, and generate additional cash flow.

• The acquisition is anticipated to support the Company's commitment to a growing dividend at a sustainable payout ratio.

• The addition of Alagasco provides geographic and regulatory diversity, adding progressive and highly rated regulatory environment.

The stated purchase price of the Alagasco Transaction is $1.6 billion, subject to customary closing adjustments, comprised of approximately $1.35 billion in cash and nearly $250 million of assumed Alagasco long-term debt. The Alagasco Transaction is supported by a fully committed $1.35 billion bridge loan facility with Credit Suisse and Wells Fargo Bank, National Association, which as of April 28th has been syndicated to a group of eleven additional banks.

The permanent financing is anticipated to be a combination of common stock, mandatory convertible securities, and long-term debt, as well as the use of corporate cash and short-term credit facilities.

This Alagasco Transaction is expected to close in 2014, subject to customary closing conditions, including regulatory approval from the Alabama Public Service Commission (APSC) as well as the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended.

On April 14, 2014, Laclede and Energen jointly filed with the Alabama Public Service Commission to request approval of the Alagasco Transaction.

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 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 rate design lessen the impact of weather volatility on its customers during cold winters and stabilizes the Utility’s earnings. Due to the seasonal nature of the Utility, Laclede Group’s earnings are typically concentrated during the heating season of November through April each fiscal year, although earnings for MGE are less seasonal than earnings from Laclede Gas due to MGE's 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 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. (ETE) and Energy Transfer Partners, L.P. The purchase was completed pursuant to the Purchase and Sales Agreement (MGE PSA) dated December 14, 2012. Under the terms of the MGE PSA, the Utility acquired MGE for a purchase price of $975 million.

In accordance with Section 3.2 of the MGE PSA, Laclede Gas provided to SUG a reconciliation of certain balance sheet accounts from the amounts at September 30, 2012 to August 31, 2013, indicating the difference due to changes in the actual net assets transferred to the Company at closing from the level at September 30, 2012. Laclede Gas and SUG agreed to the final reconciliation amount of $23.9 million that was paid by ETE to Laclede Gas on February 14, 2014.

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. 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. On March 26, 2014, the MDPU signed an order denying the Attorney General's motion, so the MDPU's order approving the sale of NEG is now final.

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These receipts of funds effectively reduced the Utility's purchase price of MGE to $940.1 million and reduced goodwill related to the transaction to $216.4 million. 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. As part of the MGE acquisition, Laclede Gas has estimated the asset retirement obligation of MGE's long-lived assets as of the acquisition date. This allocation of asset retirement obligations is preliminary and will be finalized upon completion of a detailed fair value analysis that is being performed by the Company and will be finalized prior to September 30, 2014.

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 of natural gas storage effective August 1, 2013 and has an additional 1 Bcf storage contracted through January 2016.

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 fair value and timing adjustments are made in instances 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.

Additionally, management excludes 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. The definition and measurement of net economic earnings provided above is consistent with that used by management and the Board of Directors in assessing the Company’s performance as well as for determining performance under the Company’s incentive compensation plans. Further, the Company believe this better enables an investor to view the Company’s performance in that period on a basis that would be comparative to prior periods.

These internal non-GAAP operating metrics should not be considered as an alternative to, or more meaningful than, GAAP measures such as net income. Reconciliations of net economic earnings and net economic earnings per share to the Company’s most directly comparable GAAP measures are provided below.

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THREE MONTHS ENDED MARCH 31, 2014

Net Income and Net Economic Earnings

Reconciliation of Consolidated Net Income (GAAP) to Consolidated Net Economic Earnings (Non-GAAP)
(Millions, except per share amounts)		Gas Utility		Gas Marketing			Other			Total			Per Share Amounts**
Three Months Ended March 31, 2014
	Net Income (Loss) (GAAP)	$	44.1	$	9.4		$	(1.3	)	$	52.2		$	1.59
	Unrealized gain on energy-related derivatives*	—		(1.7		)	—			(1.7		)	(0.04		)
	Lower of cost or market inventory adjustments*	—		(0.5		)	—			(0.5		)	(0.02		)
	Realized loss on economic hedges prior      to the sale of the physical commodity*	—		(0.1		)	—			(0.1		)	(0.01		)
	Acquisition, divestiture and restructuring activities*	0.6		—			1.2			1.8			0.06
	Net Economic Earnings (Losses) (Non-GAAP)	$	44.7	$	7.1		$	(0.1	)	$	51.7		$	1.58
Three Months Ended March 31, 2013
	Net Income (Loss) (GAAP)	$	30.2	$	1.8		$	(1.8	)	$	30.2		$	1.34
	Unrealized loss on energy-related derivatives*	—		0.6			—			0.6			0.03
	Acquisition, divestiture and restructuring activities*	—		—			1.7			1.7			0.07
	Net Economic Earnings (Losses) (Non-GAAP)	$	30.2	$	2.4		$	(0.1	)	$	32.5		$	1.44

* 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.

** 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 $52.2 million for the three months ended March 31, 2014, compared with $30.2 million for the three months ended March 31, 2013. Basic and diluted earnings per share for the three months ended March 31, 2014 were each $1.59, compared with basic and diluted earnings per share of $1.34, respectively, for the three months ended March 31, 2013. Net income increased compared to last year primarily due to improved results reported by Laclede Group's Gas Utility segment, which reflects the inclusion of MGE operations totaling $12.1 million in the second quarter of fiscal year 2014 as well as improved earnings from the Gas Marketing segment of $7.6 million. Net economic earnings were $51.7 million for the three months ended March 31, 2014, up from $32.5 million for the same period last year. Net economic earnings per share were $1.58 for the three months ended March 31, 2014, up from $1.44 for the three months ended March 31, 2013.

Gas Utility

Gas Utility net income and net economic earnings increased by $13.9 million and $14.5 million, respectively for the three months ended March 31, 2014, compared with the three months ended March 31, 2013. The increase was primarily due to higher operating margin (a non-GAAP measure, as discussed below) of $65.6 million, which reflects the inclusion of MGE operating margin totaling $56.0 million. These benefits were partially offset by an increase in other operating expenses of $34.4 million, including MGE other operating expenses totaling $28.7 million, an increase in depreciation and amortization expenses of $8.9 million, including MGE depreciation and amortization expense totaling $7.7 million, higher interest expense totaling $3.2 million, and increased income tax expenses of $4.3 million.

30

Gas Marketing

The Gas Marketing segment reported GAAP earnings totaling $9.4 million for the three months ended March 31, 2014, an increase of $7.6 million compared with the same period last year. Net economic earnings for the three months ended March 31, 2014 increased $4.7 million compared with the three months ended March 31, 2013. The increases in net income and net economic earnings was primarily attributable to an increase in operating margin, as discussed below.

Other

The Other segment reported a net loss of $0.5 million lower as compared with the same period last year. The decrease in net loss was primarily due to prior year acquisition-related expenses for MGE and NEG totaling $1.7 million, net of income taxes, during the three months ended March 31, 2013 partially offset by acquisition-related expenses for Alagasco of $1.2 million, net of income taxes, during the three months ended March 31, 2014.

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 to its customers (subject to prudence review by the MoPSC) increases and decreases in the wholesale cost of natural gas in accordance with its PGA Clause. The volatility of the wholesale natural gas market results in fluctuations from period to period in the recorded levels of, among other items, revenues and natural gas cost expense. Nevertheless, increases and decreases in the cost of gas associated with system gas sales volumes have no direct effect on operating 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 March 31, 2014
	Operating revenues	$	638.7	$	80.5	$	0.7		$	(25.4	)	$	694.5
	Natural and propane gas expense	430.6		63.6		—			(25.2		)	469.0
	Gross receipts tax expense	33.3		0.1		—			—			33.4
	Operating margin (non-GAAP)	174.8		16.8		0.7			(0.2		)	192.1
	Depreciation and amortization	20.1		0.1		0.1			—			20.3
	Other operating expenses	80.6		1.2		3.0			(0.2		)	84.6
	Operating income (GAAP)	$	74.1	$	15.5	$	(2.4	)	$	—		$	87.2
Three Months Ended March 31, 2013
	Operating revenues	$	363.9	$	38.9	$	2.5		$	(7.7	)	$	397.6
	Natural and propane gas expense	237.9		34.5		1.5			(7.7		)	266.2
	Gross receipts tax expense	16.8		0.1		—			—			16.9
	Operating margin (non-GAAP)	109.2		4.3		1.0			—			114.5
	Depreciation and amortization	11.2		0.1		0.3			—			11.6
	Other operating expenses	46.2		1.3		3.6			—			51.1
	Operating income (GAAP)	$	51.8	$	2.9	$	(2.9	)	$	—		$	51.8

Consolidated

Laclede Group reported operating revenues of $694.5 million for the three months ended March 31, 2014 compared with $397.6 million for the same period last year. Laclede Group's operating margin increased $77.6 million for the three months ended March 31, 2014 compared with the same period last year due to higher Gas Utility and Gas Marketing operating margin as discussed below. Depreciation and amortization expenses were $20.3 million for the three months ended March 31, 2014, compared with $11.6 million for the same period last year. Other operating expenses were $84.6 million for the three months ended March 31, 2014, compared with $51.1 million for the same period last year. The increase was primarily due to the inclusion of MGE other operating expenses and depreciation and amortization expenses totaling $28.7 million and $7.7 million, respectively.

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Gas Utility

Operating Revenues - Gas Utility operating revenues for the three months ended March 31, 2014 were $638.7 million, or $274.8 million more than the same period last year. The increase in Gas Utility operating revenues was attributable to the following factors:

(Millions)	Variance
Customer revenue from MGE	$	236.6
Higher system sales volumes and other variations	39.5
Lower wholesale gas costs passed on to Utility customers	(4.0		)
Gross receipts tax revenues	2.7
Total Variation	$	274.8

Temperatures experienced in the Utility’s service areas during the three months ended March 31, 2014 were 16.0% colder than the same period last year, and 17.3% colder than normal, resulting in higher gas usage and operating revenues on a year-over-year comparative basis. Total system therms sold and transported were 900.5 million for the three months ended March 31, 2014, compared with 413.0 million for the same period last year. Total off-system therms sold and transported were 45.4 million for the three months ended March 31, 2014, compared with 102.0 million for the same period last year. This decrease was due to colder temperatures and increased heating demand in our service areas, reducing the gas supply resources available for off-system sales or capacity release.

Operating Margin - Gas Utility operating margin was $174.8 million for the three months ended March 31, 2014, a $65.6 million increase over the same period last year. The increase was attributable to the following factors:

(Millions)	Variance
Operating margin from MGE	$	56.0
Higher consumption and modest customer growth	3.1
Colder weather impact	6.5
Total Variation	$	65.6

The increase was primarily attributable to MGE's operating margin totaling $56.0 million, higher margins from off-system sales which resulted from colder weather and higher consumption and modest customer growth.

Operating Expenses - Other operating expenses and depreciation and amortization expenses for the three months ended March 31, 2014 increased $34.4 million and $8.9 million, respectively, from the same period last year. The increase was primarily due to the inclusion of MGE operating expenses and depreciation and amortization expenses in the second quarter of fiscal year 2014 totaling $28.7 million and $7.7 million, respectively. Approximately $5.0 million of the remaining increase in other operating expenses was due to the impact of colder weather reflected in higher provision for uncollectible accounts, higher maintenance costs and higher employee-related expenses. The remaining depreciation and amortization increase of $1.2 million was primarily due to additional depreciable property.

Gas Marketing

Operating Revenues - Gas Marketing operating revenues during the three months ended March 31, 2014 increased $41.6 million from the same period last year primarily due to higher volumes sold and higher per unit gas sales prices as the colder weather resulted in higher overall industry demand, particularly in the upper-Midwest.

Operating Margin - Gas Marketing operating margin during the three months ended March 31, 2014 increased $12.5 million from the same period last year. The increase in operating margin was primarily attributable to higher sales margins reflecting greater market volatility and basis differentials of natural gas prices between differing areas throughout the Midwest driven principally by colder weather during the three months ended March 31, 2014 as compared to the same period last year.

Other

Operating Revenues and Operating Expenses - Other operating revenues and other operating expenses decreased by $1.8 million and $0.6 million, respectively, during the three months ended March 31, 2014 from the same period last year. The decreases were primarily due to lower propane sales by Laclede Pipeline Company during the three months ended March 31, 2014 as compared to the same period last year, as well as lower acquisition-related expenses for the three months ended March 31, 2014 for Alagasco compared to prior year acquisition-related expenses for MGE and NEG.

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Other Income and (Income Deductions) - Net

Other Income and (Income Deductions) - Net decreased $1.6 million primarily due to a net investment loss during the three months ended March 31, 2014 compared to net investment gains for the same period last year.

Interest Charges

Interest charges during the three months ended March 31, 2014 increased $2.7 million from the same period last year. The increase was primarily due to the net effect of the March 2013 and August 2013 issuances of additional long-term debt of $100 million and $450 million, respectively, offset by the early redemption of $80 million, 6.35% first mortgage bonds on January 6, 2014. Average short-term interest rates were 0.3% for both the three months ended March 31, 2014 and 2013. Average short-term borrowings were $105.9 million for the three months ended March 31, 2014, compared with $46.7 million for the three months ended March 31, 2013.

Income Taxes

Income taxes during the three months ended March 31, 2014 increased $9.1 million from the same period last year primarily due to higher pre-tax income.

SIX MONTHS ENDED MARCH 31, 2014

Net Income and Net Economic Earnings

Reconciliation of Consolidated Net Income (GAAP) to Consolidated Net Economic Earnings (Non-GAAP)
(Millions, except per share amounts)		Gas Utility		Gas Marketing			Other			Total			Per Share Amounts**
Six Months Ended March 31, 2014
	Net Income (Loss) (GAAP)	$	79.5	$	9.9		$	(1.6	)	$	87.8		$	2.68
	Unrealized gain on energy-related derivatives*	—		(1.3		)	—			(1.3		)	(0.05		)
	Lower of cost or market inventory adjustments*	—		(0.6		)	—			(0.6		)	(0.02		)
	Realized loss on economic hedges prior      to the sale of the physical commodity*	—		(0.1		)	—			(0.1		)	—
	Acquisition, divestiture and restructuring activities*	1.0		—			1.2			2.2			0.07
	Net Economic Earnings (Losses) (Non-GAAP)	$	80.5	$	7.9		$	(0.4	)	$	88.0		$	2.68
Six Months Ended March 31, 2013
	Net Income (Loss) (GAAP)	$	55.4	$	4.7		$	(4.3	)	$	55.8		$	2.47
	Unrealized loss on energy-related derivatives*	0.1		0.9			—			1.0			0.05
	Acquisition, divestiture and restructuring activities*	—		—			3.9			3.9			0.17
	Net Economic Earnings (Losses) (Non-GAAP)	$	55.5	$	5.6		$	(0.4	)	$	60.7		$	2.69

* 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.

** 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 $87.8 million for the six months ended March 31, 2014, compared with $55.8 million for the six months ended March 31, 2013. Basic and diluted earnings per share for the six months ended March 31, 2014 were each $2.68, compared with basic and diluted earnings per share of $2.48 and $2.47, respectively, for the six months ended March 31, 2013. Net income increased compared to last year primarily due to improved results reported by Laclede Group's Gas Utility segment, which reflects the inclusion of MGE operations totaling $24.8 million in the first six months of fiscal year 2014, as well as improved earnings from the Gas Marketing segment of $5.2 million. Net economic earnings were $88.0 million for the six months ended March 31, 2014 , up from $60.7 million for the same period last year. Net economic earnings per share were $2.68 for the six months ended March 31, 2014, up from $2.69 for the six months ended March 31, 2013.

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Gas Utility

Gas Utility net income and net economic earnings increased by $24.1 million and $25.0 million, respectively for the six months ended March 31, 2014, compared with the six months ended March 31, 2013. The increase was primarily due to higher operating margin (a non-GAAP measure, as discussed below) of $122.7 million, which reflects the inclusion of MGE operating margin totaling $107.3 million. These benefits were partially offset by an increase in other operating expenses of $61.4 million, including MGE other operating expenses totaling $51.8 million, an increase in depreciation and amortization expenses of $17.9 million, including MGE depreciation and amortization expense totaling $15.3 million, higher interest expense totaling $7.5 million, and increased income tax expenses of $11.6 million.

Gas Marketing

The Gas Marketing segment reported GAAP earnings totaling $9.9 million, an increase of $5.2 million compared with the same period last year. Net economic earnings for the six months ended March 31, 2014 increased $2.3 million compared with the six months ended March 31, 2013. The increases in net income and net economic earnings was primarily attributable to an increase in operating margin, as discussed below.

Other

The Other segment reported a lower net loss of $2.7 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 totaling $3.9 million, net of income taxes, and other minor expenses during the six months ended March 31, 2013 partially offset by acquisition-related expenses for Alagasco of $1.2 million, net of income taxes, during the six months ended March 31, 2014.

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
Six Months Ended March 31, 2014
	Operating revenues	$	1,073.9	$	133.2	$	1.4		$	(45.4	)	$	1,163.1
	Natural and propane gas expense	692.1		114.1		—			(45.0		)	761.2
	Gross receipts tax expense	52.9		0.1		—			—			53.0
	Operating margin (non-GAAP)	328.9		19.0		1.4			(0.4		)	348.9
	Depreciation and amortization	40.1		0.2		0.2			—			40.5
	Other operating expenses	152.3		2.4		4.0			(0.4		)	158.3
	Operating income (GAAP)	$	136.5	$	16.4	$	(2.8	)	$	—		$	150.1
Six Months Ended March 31, 2013
	Operating revenues	$	614.7	$	101.1	$	4.4		$	(15.6	)	$	704.6
	Natural and propane gas expense	382.0		90.7		1.8			(15.5		)	459.0
	Gross receipts tax expense	26.5		0.1		—			—			26.6
	Operating margin (non-GAAP)	206.2		10.3		2.6			(0.1		)	219.0
	Depreciation and amortization	22.2		0.2		0.5			—			22.9
	Other operating expenses	90.9		2.4		9.0			(0.1		)	102.2
	Operating income (GAAP)	$	93.1	$	7.7	$	(6.9	)	$	—		$	93.9

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Consolidated

Laclede Group reported operating revenues of $1,163.1 million for the six months ended March 31, 2014 compared with $704.6 million for the same period last year. Laclede Group's operating margin increased $129.9 million for the six months ended March 31, 2014 compared with the same period last year due to higher Gas Utility and Gas Marketing operating margin as discussed below. Depreciation and amortization expenses were $40.5 million for the six months ended March 31, 2014, compared with $22.9 million for the same period last year. Other operating expenses were $158.3 million for the six months ended March 31, 2014, compared with $102.2 million for the same period last year. The increase was primarily due to full six months impact of MGE operating expenses and depreciation and amortization expenses totaling $51.8 million and $15.3 million, respectively.

Gas Utility

Operating Revenues - Gas Utility operating revenues for the six months ended March 31, 2014 were $1,073.9 million, or $459.2 million more than the same period last year. The increase in Gas Utility operating revenues was attributable to the following factors:

(Millions)	Variance
New customer revenue from MGE	$	396.7
Higher system sales volumes and other variations	71.6
Lower wholesale gas costs passed on to Utility customers	(11.8		)
Gross receipts tax revenues	2.7
Total Variation	$	459.2

Temperatures experienced in the Utility’s service areas during the six months ended March 31, 2014 were 17.6% colder than the same period last year, and 13.2% colder than normal, resulting in higher gas usage and operating revenues on a year-over-year comparative basis. Total system therms sold and transported were 1,417.7 million for the six months ended March 31, 2014, compared with 674.1 million for the same period last year. Total off-system therms sold and transported were 107.7 million for the six months ended March 31, 2014, compared with 182.4 million for the same period last year. This decrease was due to colder temperatures and increased heating demand in our service areas, reducing the gas supply resources available for off-system sales or capacity release.

Operating Margin - Gas Utility operating margin was $328.9 million for the six months ended March 31, 2014, a $122.7 million increase over the same period last year. The increase was attributable to the following factors:

(Millions)	Variance
Operating margin from MGE	$	107.3
Higher consumption and modest customer growth	8.9
Colder weather impact	6.5
Total Variation	$	122.7

The increase was primarily due to the impact of MGE's operating margin totaling $107.3 million, higher usage of natural gas reflecting colder weather and higher consumption and modest customer growth.

Operating Expenses - Other operating expenses and depreciation and amortization expenses for the six months ended March 31, 2014 increased $61.4 million and $17.9 million, respectively, from the same period last year. The increase was primarily due to the inclusion of MGE operating expenses and depreciation and amortization expenses totaling $51.8 million and $15.3 million, respectively, in the first six months of fiscal year 2014. Approximately $5.0 million of the remaining increase in other operating expenses was due to the impact of colder weather reflected in higher provision for uncollectible accounts, higher maintenance costs and higher employee-related expenses. The remaining depreciation and amortization expense increase of $2.6 million was primarily due to additional depreciable property.

Gas Marketing

Operating Revenues - Gas Marketing operating revenues during the six months ended March 31, 2014 increased $32.1 million from the same period last year due to higher volumes sold and higher per unit gas sales prices as the colder weather resulted in a constrained pipeline infrastructure creating higher market volatility between differing regions.

35

Operating Margin - Gas Marketing operating margin during the six months ended March 31, 2014 increased $8.7 million from the same period last year. The increase in operating margin was primarily attributable to higher sales margins, reflecting higher market volatility and basis differentials of natural gas prices during the six months ended March 31, 2014 compared to the same period last year.

Other

Operating Revenues and Operating Expenses - Other operating revenues and other operating expenses decreased by $3.0 million and $5.0 million, respectively, during the six months ended March 31, 2014 from the same period last year. The decrease was primarily due to higher prior year acquisition-related expenses for MGE and NEG as compared to current year acquisition-related expenses for Alagasco.

Other Income and (Income Deductions) - Net

Other Income and (Income Deductions) - Net decreased $1.0 million primarily due to higher net investment losses as compared to the six months ended March 31, 2013.

Interest Charges

Interest charges during the six months ended March 31, 2014 increased $7.1 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, offset by the early bond redemption of $80 million, 6.35% first mortgage bonds on January 6, 2014, 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 six months ended March 31, 2014 and 2013. Average short-term borrowings were $99.5 million for the six months ended March 31, 2014, compared with $74.9 million for the six months ended March 31, 2013.

Income Taxes

Income taxes during the six months ended March 31, 2014 increased $16.0 million from the same period last year primarily due to higher pre-tax income.

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. 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. 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. On March 26, 2014, the MDPU issued an order denying the Attorney General's motion, so the MDPU's order approving the sale of NEG is now final.

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 Infrastructure System Replacement Surcharge (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 April 11, 2014, MGE and other parties to the rate case filed a Stipulation and Agreement resolving all issues in the case. On April 16, 2014, the MoPSC approved the Stipulation and Agreement, pursuant to which MGE will increase its base rates by $7.8 million effective on May 1, 2014. This result is essentially equivalent to incorporating MGE’s ISRS revenues into base rates. In addition, effective October 1, 2014, MGE will lower its fixed monthly charge for residential and small commercial customers and instate a volumetric charge in its place. After this adjustment, MGE will still be recovering about 83% of its distribution costs to these customers through the fixed monthly charge. 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. Effective March 21, 2014, the MoPSC approved an increase in MGE’s ISRS in the amount of $1.7 million annually. However, pursuant to the settlement of the MGE rate case, the ISRS rates will be reset to zero effective May 1, 2014. MGE will be permitted to make future ISRS filings for qualifying expenditures incurred on and after January 1, 2014.

On January 17, 2014, Laclede Gas filed to re-establish an ISRS charge to recover investments made in gas safety replacement projects and public improvement projects in Laclede Gas’ eastern Missouri service territory since February 1, 2013. Effective April 12, 2014, the MoPSC approved an ISRS charge designed to collect $7.0 million in annual revenues.

36

Laclede Gas has labor agreements with Locals 884, 11-6 and 11-194 of the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial and Service Workers International Union, which represent approximately 67% of Laclede Gas’ employees.  On February 14, 2014, the agreements with Locals 11-6 and 11-194 were extended through midnight on July 31, 2015.  Laclede Gas and Local 884 have a labor agreement that expires at midnight on July 31, 2015.

On April 14, 2014, the Laclede Group, along with Energen and Alagasco, filed a joint application with the Alabama PSC for approval to acquire the common stock of Alagasco from Energen.

On April 23, 2014, the MoPSC approved a stipulation and agreement reached between MGE and all parties to the case finalizing MGE’s general rate case filed in September 2013. Under the agreement, MGE’s annual revenues will increase by $7.8 million, effective May 1, 2014. The revenues will be collected in base rates and will replace a like amount that MGE is currently authorized to collect through the Infrastructure System Replacement Surcharge mechanism.

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 six months ended March 31, 2014.

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.

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 provided by operating activities was $142.8 million for the six months ended March 31, 2014, compared with net cash provided by operating activities of $142.4 million for the six months ended March 31, 2013. On this comparative basis, the main drivers of higher cash inflows in the six months ended March 31, 2014 were a higher sendout of natural gas stored underground, higher net income, seasonality of accounts payables associated with natural gas, and higher depreciation, amortization, and accretion. These cash inflows were partially offset by the seasonality of the accounts receivable balance increases reflecting the inclusion of MGE's operations and the timing of collections of gas cost under the Utility's PGA Clauses.

Net cash used in investing activities for the six months ended March 31, 2014 was $38.4 million, compared with $64.8 million for the six months ended March 31, 2013. The decrease primarily reflects the receipt of $23.9 million from ETE for the final reconciliation amount associated with the MGE acquisition and the receipt of $11.0 million associated with the sale of NEG to APUC. The decrease was partially offset by additional capital expenditures this year for distribution plant investments.

Net cash used in financing activities was $146.5 million for the six months ended March 31, 2014, compared with $41.9 million of net cash provided for the six months ended March 31, 2013. The variation primarily reflects the maturity of $80 million of first mortgage bonds compared to $100 million of first mortgage bonds issued, net, an increase in dividends paid due to an increase in shares outstanding as well as a higher dividend rate, and a decrease in net issuances of short-term debt.

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LIQUIDITY AND CAPITAL RESOURCES

Cash and Cash Equivalents

Laclede Group had no temporary cash investments at March 31, 2014. 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 six months ended March 31, 2014.

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 March 31, 2014, 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 47% of total capitalization on March 31, 2014.

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 44% on March 31, 2014. 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 six months ended March 31, 2014.

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 six months ended March 31, 2014, is presented below:

	Commercial Paper Borrowings
Six Months Ended March 31, 2014
Weighted average borrowings outstanding	$99.5 million
Weighted average interest rate	0.3%
Range of borrowings outstanding	$20.0 - $179.5 million
As of March 31, 2014
Borrowings outstanding at end of period	$36.0 million
Weighted average interest rate	0.3%

Based on average short-term borrowings for the six months ended March 31, 2014, an increase in the average interest rate of 100 basis points would decrease Laclede Group’s pre-tax earnings and cash flows by approximately $1.0 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 six months ended March 31, 2014, pursuant to this authority, the Utility sold 18 shares of its common stock to Laclede Group for $0.7 million. As of April 25, 2014, $370.1 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 March 31, 2014, Laclede Group had fixed-rate long-term debt totaling $835 million. Of the $835 million long-term debt, $810 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 $810 million in long-term debt, $25 million have no call option, $435 million have make-whole call options, and $350 million are callable at par three to six months prior to maturity. Laclede Group's debt has a make-whole call option. None of the debt has any put options.

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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 178,252 and 170,014 shares at March 31, 2014 and April 25, 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 $67.1 million for the six months ended March 31, 2014, compared with $62.6 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 as well as the addition of MGE capital expenditures. Non-utility capital expenditures were $1.1 during the six months ended March 31, 2014, compared with $0.1 million for the same period last year.

Consolidated capitalization at March 31, 2014 consisted of 57.1% common stock equity and 42.9% long-term debt.

It is management’s view that the Company has adequate access to capital markets and will have sufficient capital resources, both internal and external, to meet anticipated capital requirements, which primarily include 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 March 31, 2014 and at September 30, 2013, such as Accounts receivable - net, Gas stored underground, Notes payable, Accounts payable, Regulatory assets, Regulatory liabilities, and Delayed and Advance customer billings. The Consolidated Balance Sheet at March 31, 2013 is presented to facilitate comparison of these items with the corresponding interim period of the preceding fiscal year.

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CONTRACTUAL OBLIGATIONS

As of March 31, 2014, 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	$	835	$	—	$	—	$	100	$	735
Interest Payments on Long-Term Debt	551		18		71		71		391
Operating Leases (a)	125		3		11		8		103
Purchase Obligations – Natural Gas (b)	975		366		356		173		80
Purchase Obligations – Other (c)	72		19		22		18		13
Other Long-Term Liabilities	155		10		31		32		82
Total (d)	$	2,713	$	416	$	491	$	402	$	1,404

(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 March 31, 2014 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 $4.0 million, have been excluded from the table above because the timing of future cash outflows, if any, cannot be reasonably estimated. Also, commitments related to pension and postretirement benefit plans have been excluded from the table above. Contributions to the pension plans for the remaining six months of fiscal 2014 are anticipated to be approximately $14.4 million to the qualified trusts and $0.2 million to the non-qualified plans. With regard to the postretirement benefits, the Utility anticipates contributing $14.4 million to the qualified trusts and $0.3 million directly to participants from the Utility’s funds during the remaining six 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.

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MARKET RISK

Commodity Price Risk

The Utility's commodity price risk, which arises from market fluctuations in the price of natural gas, is primarily managed through the operation of 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 March 31, 2014, 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 as of September 30, 2013	$	2,643		$	254	$	2,897
Changes in fair value	(9,007		)	—		(9,007		)
Settlements/purchases - net	7,012			—		7,012
Changes in cash margin	—			3,212		3,212
Net balance of derivative (liabilities) assets as of March 31, 2014	$	648		$	3,466	$	4,114

	As of March 31, 2014
	Maturity by Fiscal Year
(Thousands)	Total			2014			2015			2016		2017
Fair values of exchange-traded/cleared natural gas derivatives - net	$	46		$	(45	)	$	92		$	—	$	(1	)
MMBtu – net (short) long futures/swap/option positions	(7,045		)	(6,402		)	(703		)	45		15
Fair values of basis swaps - net	$	602		$	344		$	60		$	169	$	29
MMBtu – net (short) long basis swap positions	(3,340		)	(3,945		)	(465		)	915		155

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Certain of LER’s physical natural gas derivative contracts are designated as normal purchases or normal sales, as permitted by GAAP. This election permits the Company to account for the contract in the period the natural gas is delivered. Contracts not designated as normal purchases or normal sales, including those designated as trading activities, are accounted for as derivatives with changes in fair value recognized in earnings in the periods prior to settlement. Below is a reconciliation of the beginning and ending balances for physical natural gas contracts accounted for as derivatives, none of which will settle beyond fiscal year 2019:

(Thousands)
Net balance of derivative assets as of September 30, 2013	$	99
Changes in fair value	(12,254		)
Settlements	15,464
Net balance of derivative assets as of March 31, 2014	$	3,309

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 six months ended March 31, 2014, 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 $1.0 million on an annual basis. Portions of such increases may be offset through the application of PGA carrying costs. At March 31, 2014, Laclede Group had fixed-rate long-term debt totaling $835 million, including the Utility's fixed-rate long-term debt totaling $810 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 41 of this report.

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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 March 31, 2014 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For a description of environmental matters and legal proceedings, see Note 12, Commitments and Contingencies, of the Notes to Consolidated Financial Statements. For a description of pending regulatory matters of Laclede Group, see Part I., Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Regulatory and Other Matters, on page 36 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 1A. Risk Factors

The paragraphs should be read in conjunction with the risk factors included in Part I, Item 1A of the Company's Annual Report on Form 10-K for the year ended September 30, 2013.

RISKS RELATED TO THE COMPANY'S ACQUISITION AGREEMENT WITH ENERGEN CORPORATION

The transactions may not be completed or may be approved subject to unfavorable regulatory conditions, which could adversely affect anticipated benefits or Laclede Group's business, financial condition, results of operations and/or share price.

On April 5, 2014, Laclede Group entered into an agreement with Energen Corporation (Energen) to acquire 100 percent of the common stock of Alabama Gas Corporation (Alagasco), which management expects to complete in 2014 subject to customary closing conditions, including regulatory approval from the Alabama Public Service Commission (APSC) as well as the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. There can be no assurance as to the receipt or timing of the necessary APSC approvals.

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

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

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

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

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

The acquisition agreement contains certain termination rights for both the Company and Energen, including, among others, the right to terminate if the transaction is not completed by May 1, 2015 (subject to extension to August 3, 2015, under certain circumstances related to fulfillment of the regulatory closing conditions).

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

Laclede Group expects to issue significant debt, common stock and mandatory convertible securities to provide permanent financing for the acquisition of Alagasco in lieu of and/or to refund borrowings under the bridge loan facility, and, as a result, the Company is subject to market risks including share price, market demand for debt and equity offerings, interest rate volatility, and adverse impacts on its credit ratings.

In connection with the acquisition agreement, Laclede Group has obtained a commitment from Credit Suisse, Wells Fargo Bank, National Association and various other banks for a syndicated bridge loan facility, which may be used to finance a significant portion of the acquisition and pay related fees and expenses in the event that permanent financing is not completed at the time of the closing of the acquisition. The permanent financing is anticipated to be a combination of equity, mandatory convertible securities, and long-term debt, as well as the use of corporate cash and short-term credit facilities.

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

Among other risks, the planned increase in indebtedness may:

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

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

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

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

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

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

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

Among other risks, the planned issuance of equity by Laclede Group may:

• be dilutive to Laclede Group's existing shareholders and earnings per share;

• impact the Company's capital structure and cost of the capital;

• be adversely impacted by movements in the overall equity markets and/or the utility or natural gas utility industry sectors of that market, which could impact the offering price of the Company's new equity or necessitate the use of other equity or equity-like instruments such as common stock, convertible common shares, or convertible debt; and

• impact Laclede Group's ability to pay dividends.

As a part of its planned permanent financing, Laclede Group may consider issuing additional shares of common stock or securities convertible into shares of common stock, reducing discretionary uses of cash or a combination of these or other measures to maintain or improve its capital structure, credit ratings or overall cost of financing.   The timing of such issuances will depend upon a number of factors including market conditions, the timing of regulatory approvals and forecasts at the time of the contemplated offerings.

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

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

While management currently anticipates that the acquisition of Alagasco will be accretive to the Company's net economic earnings in fiscal year 2015, and thereafter, this expectation is based on preliminary estimates which may materially change. Laclede Group may encounter additional transaction and integration-related costs, may fail to realize all of the anticipated benefits of the acquisition or be subject to other factors that affect those preliminary estimates.

The diversion of management's attention and any delays or difficulties encountered in connection with the transaction and the integration of the Alagasco’s operations could have an adverse effect on the business, results of operations, financial condition or prospects of Laclede Group after the acquisition is ultimately consummated.

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

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

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

During the quarter ended March 31, 2014, 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
January 1, 2014 – January 31, 2014	—	$—	—	—
February 1, 2014 – February 28, 2014	—	$—	—	—
March 1, 2014 – March 31, 2014	—	$—	—	—
Total	—	$—	—	—

Item 5. Other Information

On April 28, 2014, the Company entered into a first amendment (“First Amendment”) to its Loan Agreement, dated as of September 3, 2013 (“Loan Agreement”), with Wells Fargo Bank, National Association, as Administrative Agent; U.S. Bank National Association and JPMorgan Chase Bank, N.A., as Co-Syndication Agents; Well Fargo Securities, LLC, U.S. Bank National Association, and J.P. Morgan Securities LLC as Joint Lead Arrangers; Bank of America, Morgan Stanley Bank and Fifth Third Bank as Co-Documentation Agents; and Commerce Bank, UMB Bank, N.A., and Stifel Bank & Trust as the other participating banks.

The First Amendment was entered into in connection with (i) Laclede Group’s Alagasco Transaction, and (ii) the related commitment letter (the “Commitment Letter”) among Laclede Group, Credit Suisse AG, Credit Suisse Securities (USA) LLC, Wells Fargo Bank, National Association and Wells Fargo Securities, LLC. The First Amendment is expected to facilitate the financing of the Alagasco Transaction by Laclede Group.

The Loan Agreement was amended to, among other things, increase the allowed Maximum Consolidated Capitalization Ratio, as defined in the Loan Agreement, to 73% from 70% from the date the Alagasco Transaction is consummated through September 30, 2015, after which date the maximum ratio will return to 70%. The change to the Maximum Consolidated Capitalization Ratio provision makes it consistent with Laclede Group’s comparable financial covenant in the Commitment Letter.

In addition, the maximum amount to which Laclede Group may request an increase in the amount of the total revolving credit commitment under the Loan Agreement was increased to $300 million from $200 million. Also, the banks approved a waiver of a potential event of default relating to existing debt of Alagasco that Laclede Group will be required to offer to prepay within five days of the closing of the Transaction.

The First Amendment is filed as Exhibit 10.1

Item 6. Exhibits

(a) See Exhibit Index

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SIGNATURE

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

		The Laclede Group, Inc.
Dated:	April 29, 2014	By:	/s/ Steven P. Rasche
			Steven P. Rasche
			Executive Vice President, Chief Financial Officer
			(Authorized Signatory and Principal Accounting Officer)

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INDEX TO EXHIBITS

Exhibit No.
10.1	-	First Amendment to Loan Agreement, dated as of April 28, 2014, among The Laclede Group, Inc. and the several banks parties thereto, including Wells Fargo Bank, National Association as Administrative Agent.
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 and six months ended March 31, 2014 and 2013; (iii) unaudited Statements of Consolidated Comprehensive Income for the three and six months ended March 31, 2014 and 2013; (iv) unaudited Consolidated Balance Sheets at March 31, 2014, September 30, 2013 and March 31, 2013; (v) unaudited Statements of Consolidated Cash Flows for the six months ended March 31, 2014 and 2013, 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. 

48

EX-10.1

FIRST AMENDMENT AND WAIVER TO LOAN AGREEMENT

THIS FIRST AMENDMENT AND WAIVER TO LOAN AGREEMENT, dated as of April 28, 2014 (this “Agreement”), is entered into among The Laclede Group, Inc., a Missouri corporation (the “Borrower”), each bank party hereto and Wells Fargo Bank, National Association, as administrative agent for the Banks (the “Administrative Agent”).

RECITALS

A.    The Borrower, the banks party thereto and the Administrative Agent are parties to that certain Loan Agreement dated as of September 3, 2013 (the “Loan Agreement”). Capitalized terms used herein without definition shall have the meanings given to them in the Loan Agreement as they may be amended pursuant to this Agreement.

B    The Borrower intends to acquire Alabama Gas Corporation, an Alabama corporation (“ALG”; the acquisition of which is hereinafter referred to as the “ALG Acquisition”), from Energen Corporation, an Alabama corporation (the “Seller”). The acquisition of ALG will be effected pursuant to a Stock Purchase Agreement, dated as of April 5, 2014, between the Borrower, Seller and ALG (the “ALG Acquisition Agreement”).

C.    The Borrower, the Administrative Agent, and the Required Banks have agreed to (i) make certain amendments to the Loan Agreement and (ii) waive certain provisions of the Loan Agreement, all on the terms and conditions set forth herein.

STATEMENT OF AGREEMENT

NOW, THEREFORE, in consideration of the foregoing and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

ARTICLE I

AMENDMENTS TO LOAN AGREEMENT

1.1Amendments to Section 1.01 Consisting of New Definitions. The following definitions are hereby added to Section 1.01 of the Loan Agreement in appropriate alphabetical order:

“Acquisition Date has the meaning given to such term in Section 6.02 hereof.”

“ALG has the meaning given to such term in the First Amendment.”

“ALG Acquisition has the meaning given to such term in the First Amendment.”

1

“Bridge Facility” means the $1.350 billion senior unsecured bridge facility provided to the Borrower by Credit Suisse AG, Wells Fargo and other lenders from time to time pursuant to that certain commitment letter, entered into as of April 5, 2014, between the Borrower, Credit Suisse AG, Credit Suisse Securities (USA) LLC, Wells Fargo and Wells Fargo Securities, LLC.

“First Amendment shall mean the First Amendment and Waiver to Loan Agreement, dated as of April 28, 2014, among the Borrower, the Banks party thereto, and the Administrative Agent.”

“First Amendment Effective Date has the meaning given to such term in Article II of the First Amendment.”

1.2Amendment to Section 2.01(e). Section 2.01(e) of the Loan Agreement is hereby amended by deleting the figure “$200,000,000” in clause (iv) thereof and substituting therefor the figure “$300,000,000.”

1.3Amendment to Section 6.02. Section 6.02 of the Loan Agreement is hereby amended and restated in its entirety as follows:

“6.02    Maximum Consolidated Capitalization Ratio. Borrower will at all times have a Consolidated Capitalization Ratio of not more than seventy percent (70%), provided that if on the date the ALG Acquisition is consummated (such date, the “Acquisition Date”), any debt financing is incurred under the Bridge Facility to finance the ALG Acquisition by Borrower, then on the Acquisition Date and thereafter, Borrower will at all times during each period set forth below have a Consolidated Capitalization Ratio of not more than the ratio set forth below opposite such period:

Period	Maximum Consolidated Capitalization Ratio
From Acquisition Date through September 30, 2015	73.0%
Thereafter	70%

ARTICLE II

WAIVER

The Required Banks hereby waive, in accordance with Section 9.07 of the Loan Agreement, any Event of Default set forth in Section 7(i) of the Loan Agreement solely with respect to the occurrence of the following events: (i) the occurrence of the Acquisition Date and (ii) the Borrower or ALG (A) within five Business Days following the Acquisition Date, giving written notice of the consummation of the Transactions (as defined in the ALG Acquisition Agreement) to the holders of ALG’s 3.86% senior notes due December 22, 2021 (the “AIG Notes”), making an offer to prepay the AIG Notes not less than ten nor more than 30 days following the date of such offer as provided in Section 8.3 of the Note Purchase Agreement dated December 22, 2011, between ALG and certain affiliates of American International Group,

2

Inc. (the “AIG Note Purchase Agreement”), and thereafter prepaying each ALG Note validly tendered and not withdrawn pursuant to such offer, in each case in accordance with the provisions of the AIG Note Purchase Agreement and (B) within five Business Days following the Acquisition Date, giving written notice of the consummation of the Transactions (as defined in the ALG Acquisition Agreement) to the holders of ALG’s 3.86% senior notes due December 22, 2021 (the “Prudential Notes”), making an offer to prepay the Prudential Notes not less than ten nor more than 30 days following the date of such offer as provided in Section 8.3 of the Note Purchase Agreement dated December 22, 2011, between ALG and The Prudential Insurance Company of America and certain of its affiliates (the “Prudential Note Purchase Agreement”), and thereafter prepaying each Prudential Note validly tendered and not withdrawn pursuant to such offer, in each case in accordance with the provisions of the Prudential Note Purchase Agreement.

ARTICLE III

CONDITIONS OF EFFECTIVENESS

3.1The amendments set forth in Article I hereof and the waiver set forth in Article II hereof shall become effective as of the date (such date being referred to as the “First Amendment Effective Date”) when, and only when, each of the following conditions precedent shall have been satisfied:

(a)The Administrative Agent (or its counsel) shall have received from the Borrower and the Required Banks either (i) a counterpart of this Agreement signed on behalf of such party or (ii) written evidence satisfactory to the Administrative Agent (which may include facsimile or other electronic image scan transmission of a signed signature page of this Agreement) that such party has signed a counterpart of this Agreement.

(b)The Borrower shall have paid all fees and reasonable documented out-of-pocket expenses of the Administrative Agent and the Banks required under the Loan Agreement and any other Transaction Document to be paid on or prior to the First Amendment Effective Date (including reasonable fees and expenses of counsel) in connection with this Agreement.

ARTICLE IV

REPRESENTATIONS AND WARRANTIES

The Borrower represents and warrants to the Administrative Agent and the Banks that (i) each of the representations and warranties contained in the Loan Agreement and the other Transaction Documents are true and correct in all material respects on and as of the First Amendment Effective Date, both immediately before and after giving effect to this Agreement (except to the extent any such representation or warranty is expressly stated to have been made as of a specific date, in which case such representation or warranty shall be true and correct in all material respects as of such date, and except that the representations and warranties contained in (x) Section 5.08 of the Loan Agreement shall be deemed to refer to September 30, 2013 rather than September 30, 2012 and (y) Section 5.09 of the Loan Agreement shall be deemed to refer to

3

the most recent statements furnished pursuant to Section 6.01(a) thereof), (ii) this Agreement has been duly authorized, executed and delivered by the Borrower and constitutes the legal, valid and binding obligation of the Borrower enforceable against it in accordance with its terms, except as such enforceability may be limited by bankruptcy, insolvency or other similar laws affecting creditors’ rights generally and by general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law) and (iii) no Default or Event of Default shall have occurred and be continuing on the First Amendment Effective Date, both immediately before and after giving effect to this Agreement.

ARTICLE V

ACKNOWLEDGMENT AND CONFIRMATION OF THE BORROWER

The Borrower hereby confirms and agrees that after giving effect to this Agreement, the Loan Agreement and the other Transaction Documents remain in full force and effect and enforceable against it in accordance with their respective terms and shall not be discharged, diminished, limited or otherwise affected in any respect, and the amendments contained herein shall not, in any manner, be construed to constitute payment of, or impair, limit, cancel or extinguish, or constitute a novation in respect of, the obligations of the Borrower evidenced by or arising under the Loan Agreement and the other Transaction Documents, which shall not in any manner be impaired, limited, terminated, waived or released, but shall continue in full force and effect. The Borrower represents and warrants to the Banks that it has no knowledge of any claims, counterclaims, offsets, or defenses to or with respect to its obligations under the Transaction Documents, or if the Borrower has any such claims, counterclaims, offsets, or defenses to the Transaction Documents or any transaction related to the Transaction Documents, the same are hereby waived, relinquished, and released in consideration of the execution of this Agreement. This acknowledgment and confirmation by the Borrower is made and delivered to induce the Administrative Agent and the Banks to enter into this Agreement. The Borrower acknowledges that the Administrative Agent and the Banks would not enter into this Agreement in the absence of the acknowledgment and confirmation contained herein.

ARTICLE VI

MISCELLANEOUS

6.1Governing Law. This Agreement shall be governed by and construed and enforced in accordance with the laws of the State of New York.

6.2Full Force and Effect. Except as expressly amended hereby, the Loan Agreement shall continue in full force and effect in accordance with the provisions thereof on the date hereof. As used in the Loan Agreement, “hereinafter,” “hereto,” “hereof,” and words of similar import shall, unless the context otherwise requires, mean the Loan Agreement after amendment by this Agreement. Any reference to the Loan Agreement or any of the other Transaction Documents herein or in any such documents shall refer to the Loan Agreement and Transaction Documents as amended hereby. This Agreement is limited as specified and shall not constitute or be deemed to constitute an amendment, modification or waiver of any provision of the Loan Agreement except as expressly set forth herein. This Agreement shall constitute a Transaction Document under the terms of the Loan Agreement.

4

6.3Expenses. The Borrower agrees on demand (i) to pay all reasonable fees and expenses of counsel to the Administrative Agent, and (ii) to reimburse the Administrative Agent for all reasonable documented out-of-pocket costs and expenses, in each case, in connection with the preparation, negotiation, execution and delivery of this Agreement.

6.4Severability. To the extent any provision of this Agreement is prohibited by or invalid under the applicable law of any jurisdiction, such provision shall be ineffective only to the extent of such prohibition or invalidity and only in any such jurisdiction, without prohibiting or invalidating such provision in any other jurisdiction or the remaining provisions of this Agreement in any jurisdiction.

6.5Successors and Assigns. This Agreement shall be binding upon, inure to the benefit of and be enforceable by the respective successors and permitted assigns of the parties hereto.

6.6Construction. The headings of the various sections and subsections of this Agreement have been inserted for convenience only and shall not in any way affect the meaning or construction of any of the provisions hereof. The provisions of Section 1.03 of the Loan Agreement are hereby incorporated by reference as if fully set forth herein.

6.7Counterparts. This Agreement may be executed in any number of counterparts and by different parties hereto on separate counterparts, each of which when so executed and delivered shall be an original, but all of which shall together constitute one and the same instrument. Delivery of an executed counterpart of a signature page of this Agreement by telecopy or by electronic mail in a .pdf or similar file shall be effective as delivery of a manually executed counterpart of this Agreement.

5

IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed by their respective authorized officers as of the day and year first above written.

THE LACLEDE GROUP, INC., as Borrower

By:    /s/ Lynn D. Rawlings    

Name:    Lynn D. Rawlings

Title: Vice President, Treasurer and Assistant Secretary

SIGNATURE PAGE-FIRST AMENDMENT TO LOAN AGREEMENT (LACLEDE GROUP)

WELLS FARGO BANK, NATIONAL ASSOCIATION, as a Bank, the Issuing Bank, the Swingline Bank and Administrative Agent

By:    /s/ Frederick W. Price     

Name:    Frederick W. Price

Title: Managing Director

SIGNATURE PAGE-FIRST AMENDMENT TO LOAN AGREEMENT (LACLEDE GROUP)

U.S. Bank National Association,

By:    /s/ John M. Eyerman    

Name:    John M. Eyerman

Title: Vice President

SIGNATURE PAGE-FIRST AMENDMENT TO LOAN AGREEMENT (LACLEDE GROUP)

JPMORGAN CHASE BANK, N.A.

By:    /s/ Helen D. Davis    

Name:    Helen D. Davis    

Title: Vice President    

SIGNATURE PAGE-FIRST AMENDMENT TO LOAN AGREEMENT (LACLEDE GROUP)

Bank of America, N.A.

By:    /s/ Eric A. Escagne    

Name:    Eric A. Escagne

Title: Senior Vice President

SIGNATURE PAGE-FIRST AMENDMENT TO LOAN AGREEMENT (LACLEDE GROUP)

Fifth Third Bank

By:    /s/ Mark P. Stapleton    

Name:    Mark P. Stapleton

Title: Vice President

SIGNATURE PAGE-FIRST AMENDMENT TO LOAN AGREEMENT (LACLEDE GROUP)

Morgan Stanley Bank, N.A.

By:    /s/ John Durland    

Name:    John Durland    

Title: Authorized Signatory    

SIGNATURE PAGE-FIRST AMENDMENT TO LOAN AGREEMENT (LACLEDE GROUP)

Commerce Bank

By:    /s/ Chris M. Steuterman    

Name:    Chris M. Steuterman

Title: Vice President

SIGNATURE PAGE-FIRST AMENDMENT TO LOAN AGREEMENT (LACLEDE GROUP)

UMB Bank. N.A., as a Bank

By:    /s/ Thomas J. Zeigler    

Name:    Thomas J. Zeigler

Title: Senior Vice President

SIGNATURE PAGE-FIRST AMENDMENT TO LOAN AGREEMENT (LACLEDE GROUP)

STIFEL BANK & TRUST

By:    /s/ Matthew L. Diehl    

Name:    Matthew L. Diehl

Title: Senior Vice President

SIGNATURE PAGE-FIRST AMENDMENT TO LOAN AGREEMENT (LACLEDE GROUP)

EX-12

Exhibit 12

THE LACLEDE GROUP, INC. AND SUBSIDIARY COMPANIES

SCHEDULE OF COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

	Twelve Months Ended
	Mar. 31,		September 30,
(Thousands of Dollars)	2014		2013		2012		2011		2010		2009
Income from continuing      operations before interest
charges and income taxes	$	154,063	$	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)	1,975		2,009		1,591		1,799		1,825		1,833
Total Earnings	$	156,038	$	100,947	$	115,466	$	120,223	$	109,811	$	128,350
Interest on long-term debt	$	32,736	$	25,539	$	22,958	$	23,161	$	24,583	$	24,583
Other interest	2,968		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)	1,975		2,009		1,591		1,799		1,825		1,833
Total Fixed Charges	$	37,679	$	30,611	$	26,537	$	27,216	$	28,677	$	31,579
Ratio of Earnings to Fixed
Charges	4.14		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:	April 29, 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:	April 29, 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 March 31, 2014 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 March 31, 2014 fairly presents, in all material respects, the financial condition and results of operations of The Laclede Group, Inc.

Date:	April 29, 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 March 31, 2014 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 March 31, 2014 fairly presents, in all material respects, the financial condition and results of operations of The Laclede Group, Inc.

Date:	April 29, 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	Mar. 31, 2014	Sep. 30, 2013	Mar. 31, 2013
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 21,763	$ 6,276	$ 14,716
Derivative Liability, Fair Value, Gross Liability	8,572	10,629	9,352
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	1,171	2,349	837
Derivative Liability, Fair Value, Gross Liability	774	451	7,542
Not Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	20,592	3,927	13,879
Derivative Liability, Fair Value, Gross Liability	7,798	10,178	1,810
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	915
Derivative Liability, Fair Value, Gross Liability	773
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	207	22	5
Derivative Liability, Fair Value, Gross Liability	1	11	0
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	520
Derivative Liability, Fair Value, Gross Liability		440	2,993
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	3,166		2
Derivative Liability, Fair Value, Gross Liability	347		457
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	4,467	1,434	10,862
Derivative Liability, Fair Value, Gross Liability	3,811	3,455	339
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	64	4
Derivative Liability, Fair Value, Gross Liability	122	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	6,266
Derivative Liability, Fair Value, Gross Liability	193
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	4,466	991	2,943
Derivative Liability, Fair Value, Gross Liability	333	90	227
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	231	21
Derivative Liability, Fair Value, Gross Liability	1,394	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	603	247	62
Derivative Liability, Fair Value, Gross Liability	1,574	830	787
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	1,326	20
Derivative Liability, Fair Value, Gross Liability	17	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	49	105	312
Derivative Liability, Fair Value, Gross Liability	0	0	0
NYMEX Gasoline and Heating Oil Contracts [Member] | Not Designated as Hedging Instrument [Member] | Accounts Receivable Other [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		228	10
Derivative Liability, Fair Value, Gross Liability		$ 4,045	$ 0

XML

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 2 (Details) (USD $)	6 Months Ended				3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended
	Mar. 31, 2014	Dec. 31, 2010	Dec. 31, 2010 Laclede Gas [Member]	Feb. 20, 2010 Missouri Gas Energy (MGE) [Member]	Mar. 31, 2014 Pension Plan, Defined Benefit [Member]	Mar. 31, 2013 Pension Plan, Defined Benefit [Member]	Mar. 31, 2014 Pension Plan, Defined Benefit [Member]	Mar. 31, 2013 Pension Plan, Defined Benefit [Member]	Mar. 31, 2014 Other Postretirement Benefit Plan, Defined Benefit [Member]	Mar. 31, 2013 Other Postretirement Benefit Plan, Defined Benefit [Member]	Mar. 31, 2014 Other Postretirement Benefit Plan, Defined Benefit [Member]	Mar. 31, 2013 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					$ 6,580,000	$ 4,178,000	$ 13,159,000	$ 8,355,000	$ 2,381,000	$ 2,382,000	$ 4,762,000	$ 4,763,000
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	14,400,000
Recovery in rates for postretirement benefit		9,500,000
Anticipated Contributions To Postretirement Plans Qualified Trusts	14,400,000
Defined Benefit Plan, Pension Plans, Qualified Trusts, Contributions by Employer, Fiscal Year To Date	9,600,000
Anticipated Contributions To Pension Plans Non Qualified Trusts	200,000
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)

6 Months Ended

Mar. 31, 2014

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 March 31, 2014
Assets
U. S. Stock/Bond Mutual Funds	$	16,340	$	2,780	$	—	$	—		$	19,120
NYMEX/ICE natural gas contracts	7,495		1,263		—		(5,595		)	3,163
OTCBB natural gas contracts	—		6,330		—		(315		)	6,015
NYMEX gasoline and heating oil contracts	49		—		—		—			49
Natural gas commodity contracts	—		6,619		7		(1,184		)	5,442
Total	$	23,884	$	16,992	$	7	$	(7,094	)	$	33,789
Liabilities
NYMEX/ICE natural gas contracts	$	4,374	$	565	$	—	$	(4,939	)	$	—
OTCBB natural gas contracts	—		315		—		(315		)	—
Natural gas commodity contracts	—		3,278		40		(1,184		)	2,134
Total	$	4,374	$	4,158	$	40	$	(6,438	)	$	2,134
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 March 31, 2013
Assets
U. S. Stock/Bond Mutual Funds	$	13,922	$	—	$	—	$	—		$	13,922
NYMEX/ICE natural gas contracts	11,010		379		—		(8,209		)	3,180
NYMEX gasoline and heating oil contracts	322		—		—		(192		)	130
Natural gas commodity contracts	—		2,888		117		(289		)	2,716
Total	$	25,254	$	3,267	$	117	$	(8,690	)	$	19,948
Liabilities
NYMEX/ICE natural gas contracts	$	2,447	$	1,342	$	—	$	(3,789	)	$	—
Natural gas commodity contracts	—		990		24		(289		)	725
Interest rate swap	—		4,549		—		—			4,549
Total	$	2,447	$	6,881	$	24	$	(4,078	)	$	5,274

Reconciliation of the Level 3 beginning and ending net derivative balances

	Three Months Ended March 31,					Six Months Ended March 31,
(Thousands)	2014			2013		2014			2013
Beginning of period	$	7		$	30	$	110		$	109
Net settlements	(22		)	37		(131		)	(29		)
Net gains related to derivatives not held at end of period	17			—		3			—
Net (losses) gains related to derivatives still held at end of period	(35		)	26		(15		)	13
End of period	$	(33	)	$	93	$	(33	)	$	93

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OTHER INCOME AND (INCOME DEDUCTIONS) - NET (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014	Mar. 31, 2013
Other Nonoperating Income (Expense) [Abstract]
Investment Income, Interest	$ 142	$ 257	$ 391	$ 663
Net investment gain	(612)	1,174	135	1,104
Other income deductions	222	(91)	875	657
Other (Income Deductions) and Income - Net	$ (248)	$ 1,340	$ 1,401	$ 2,424

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FAIR VALUE MEASUREMENTS (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014 Fair Value, Measurements, Recurring [Member]	Sep. 30, 2013 Fair Value, Measurements, Recurring [Member]	Mar. 31, 2013 Fair Value, Measurements, Recurring [Member]	Mar. 31, 2014 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]	Mar. 31, 2013 Fair Value, Measurements, Recurring [Member] Quoted Prices in Active Markets (Level 1) [Member]	Mar. 31, 2014 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]	Mar. 31, 2013 Fair Value, Measurements, Recurring [Member] Significant Observable Inputs (Level 2) [Member]	Mar. 31, 2014 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]	Mar. 31, 2013 Fair Value, Measurements, Recurring [Member] Significant Unobservable Inputs (Level 3) [Member]	Mar. 31, 2014 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]	Mar. 31, 2013 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					$ 19,120	$ 14,500	$ 13,922	$ 16,340	$ 14,500	$ 13,922	$ 2,780	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0
NYMEX/ICE natural gas contracts- Asset					3,163	2,518	3,180	7,495	4,333	11,010	1,263	330	379	0	0	0	(5,595)	(2,145)	(8,209)
Derivative Assets, OTCBB Natural Gas Contracts, Fair Value					6,015	0		0	0		6,330	232		0	0		(315)	(232)
NYMEX gasoline and heating oil contracts- Asset					49	0	130	49	105	322	0	0	0	0	0	0	0	(105)	(192)
Natural gas commodity contracts- Asset					5,442	784	2,716	0	0	0	6,619	1,129	2,888	7	150	117	(1,184)	(495)	(289)
Total Assets					33,789	17,802	19,948	23,884	18,938	25,254	16,992	1,691	3,267	7	150	117	(7,094)	(2,977)	(8,690)
NYMEX/ICE natural gas contracts- Liabilities					0	0	0	4,374	3,687	2,447	565	321	1,342	0	0	0	(4,939)	(4,008)	(3,789)
Derivative Liabilities, OTCBB Natural Gas Contracts, Fair Value					0	5,211		0	0		315	5,443		0	0		(315)	(232)
Natural gas commodity contracts- Liabilities					2,134	685	725	0	0	0	3,278	1,140	990	40	40	24	(1,184)	(495)	(289)
Interest Rate Swaps							4,549			0			4,549			0			0
Total Liabilities					2,134	5,896	5,274	4,374	3,687	2,447	4,158	6,904	6,881	40	40	24	(6,438)	(4,735)	(4,078)
Beginning of period	7	30	110	109
Settlements	(22)	37	(131)	(29)
Net gains related to derivatives not held at end of period	17	0	3	0
Net gains related to derivatives still held at end of period	(35)	26	(15)	13
End of period	$ (33)	$ 93	$ (33)	$ 93

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS

6 Months Ended

Mar. 31, 2014

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 March 31, 2014 and 2013 were $6.6 million and $4.2 million, respectively, including amounts charged to construction. Pension costs for the six months ended March 31, 2014 and 2013 were $13.2 million and $8.4 million, respectively, including amounts charged to construction.

The net periodic pension costs include the following components:

	Three Months Ended   March 31,						Six Months Ended   March 31,
(Thousands)	2014			2013			2014			2013
Service cost – benefits earned during the period	$	2,428		$	2,311		$	4,856		$	4,622
Interest cost on projected benefit obligation	6,010			4,066			12,020			8,132
Expected return on plan assets	(6,645		)	(4,741		)	(13,290		)	(9,482		)
Amortization of prior service cost	125			136			249			272
Amortization of actuarial loss	1,772			2,839			3,544			5,678
Loss on lump-sum settlement	1,319			—			1,319			—
Sub-total	5,009			4,611			8,698			9,222
Regulatory adjustment	1,571			(433		)	4,461			(867		)
Net pension cost	$	6,580		$	4,178		$	13,159		$	8,355

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. Lump-sum payments recognized as settlements during the six months ended March 31, 2014 were $10.9 million. There were no lump-sum payments recognized as settlements during the six months ended March 31, 2013.

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 March 31, 2014 were $9.6 million to the qualified trusts and $0.2 million to the non-qualified plans.

Contributions to the pension plans for the remaining six months of fiscal 2014 are anticipated to be approximately $14.4 million to the qualified trusts and $0.2 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 March 31, 2014 and 2013 were $2.4 million, including amounts charged to construction. Postretirement benefit costs for both the six months ended March 31, 2014 and 2013 were $4.8 million, including amounts charged to construction.

Net periodic postretirement benefit costs consisted of the following components:

	Three Months Ended   March 31,						Six Months Ended   March 31,
(Thousands)	2014			2013			2014			2013
Service cost – benefits earned during the period	$	2,804		$	2,534		$	5,608		$	5,067
Interest cost on accumulated postretirement benefit obligation	2,170			1,279			4,339			2,558
Expected return on plan assets	(1,709		)	(1,081		)	(3,418		)	(2,162		)
Amortization of transition obligation	—			23			—			46
Amortization of prior service cost (credit)	(1		)	1			(2		)	2
Amortization of actuarial loss	1,505			1,325			3,010			2,650
Sub-total	4,769			4,081			9,537			8,161
Regulatory adjustment	(2,388		)	(1,699		)	(4,775		)	(3,398		)
Net postretirement benefit cost	$	2,381		$	2,382		$	4,762		$	4,763

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. Fiscal year 2014 contributions to the postretirement plans through March 31, 2014 were $4.8 million. Contributions to the postretirement plans for the remaining six months of fiscal year 2014 are anticipated to be $14.4 million to the qualified trusts and $0.3 million paid directly to participants from the Utility's funds.

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INFORMATION BY OPERATING SEGMENT (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2014 subsidiary	Mar. 31, 2013	Mar. 31, 2014 subsidiary	Mar. 31, 2013	Sep. 30, 2013
Segment Reporting [Abstract]
Number of entity subsidiaries	7		7
Segment Reporting, Revenue Reconciling Item [Line Items]
Equity Method Investment, Ownership Percentage	100.00%		100.00%
Operating Segment Information [Abstract]
Revenues from external customers	$ 694,504	$ 397,613	$ 1,163,113	$ 704,616
Revenue from Related Parties			7,800
Total Operating Revenues	694,504	397,613	1,163,113	704,616
Operating Expenses [Abstract]
Natural and propane gas	405,359	230,440	647,145	366,956
Utilities Operating Expense, Other	72,009	41,191	134,331	80,842
Other Operation and Maintenance	72,009	41,191	134,331	80,842
Depreciation and amortization	20,118	11,258	40,144	22,223
Taxes, other than income taxes	41,739	21,751	70,328	36,557
Total Gas Utility Operating Expenses	539,225	304,640	891,948	506,578
Non-Regulated Gas Marketing	65,021	35,995	116,803	93,376
Other Cost and Expense, Operating	3,079	5,129	4,280	10,727
Total Operating Expenses	607,325	345,764	1,013,031	610,681
Operating Income (Loss)	87,179	51,849	150,082	93,935
Net Economic Earnings (Losses)	51,729	32,514	87,993	60,747
Total assets	3,180,471	2,009,098	3,180,471	2,009,098	3,125,386
Reconciliation of Consolidated Net Economic Earnings to Consolidated Net Income [Abstract]
Net Income	52,219	30,242	87,811	55,810
Add: Unrealized gain (loss) on energy-related derivative contracts, net of tax	1,593	(587)	1,292	(1,026)
Add: Lower of cost or market inventory adjustments, net of tax	527	0	589	0
Add: Realized gain (loss) on economic hedges prior to sale of the physical commodity, net of tax	166	(9)	119	22
Add: Acquisition, divestiture, and restructuring activities, net of tax	(1,796)	(1,676)	(2,182)	(3,933)
Total Net Economic Earnings above	51,729	32,514	87,993	60,747
Consolidation, Eliminations [Member] | Unallocated and Eliminations [Member]
Operating Segment Information [Abstract]
Revenues from external customers	0	0	0	0
Total Operating Revenues	(25,427)	(7,701)	(45,387)	(15,646)
Operating Expenses [Abstract]
Natural and propane gas	(25,217)	(7,608)	(44,983)	(15,526)
Utilities Operating Expense, Other	(210)	0	(404)	(120)
Depreciation and amortization	0	0	0	0
Taxes, other than income taxes	0	0	0	0
Total Gas Utility Operating Expenses	(25,427)	(7,608)	(45,387)	(15,646)
Non-Regulated Gas Marketing	0	0
Other Cost and Expense, Operating	0	(93)
Total Operating Expenses	(25,427)	(7,701)	(45,387)	(15,646)
Operating Income (Loss)	0	0	0	0
Net Economic Earnings (Losses)	0	0	0	0
Total assets	(132,489)	(140,954)	(132,489)	(140,954)
Reconciliation of Consolidated Net Economic Earnings to Consolidated Net Income [Abstract]
Total Net Economic Earnings above	0	0	0	0
Regulated Gas Distribution [Member] | Gas Utility [Member]
Operating Segment Information [Abstract]
Revenues from external customers	634,442	354,097	1,069,608	604,208
Total Operating Revenues	638,718	363,911	1,073,946	614,702
Operating Expenses [Abstract]
Natural and propane gas	430,576	237,888	692,128	381,963
Utilities Operating Expense, Other	72,219	41,191	134,735	80,842
Depreciation and amortization	20,118	11,258	40,144	22,223
Taxes, other than income taxes	41,739	21,751	70,328	36,557
Total Gas Utility Operating Expenses	564,652	312,088	937,335	521,585
Non-Regulated Gas Marketing	0	0
Other Cost and Expense, Operating	0	0
Total Operating Expenses	564,652	312,088	937,435	521,585
Operating Income (Loss)	74,066	51,823	136,511	93,117
Net Economic Earnings (Losses)	44,727	30,197	80,504	55,538
Total assets	3,036,185	1,821,372	3,036,185	1,821,372
Reconciliation of Consolidated Net Economic Earnings to Consolidated Net Income [Abstract]
Total Net Economic Earnings above	44,727	30,197	80,504	55,538
Other [Member] | Other [Member]
Operating Segment Information [Abstract]
Revenues from external customers	251	2,261	441	3,904
Total Operating Revenues	716	2,480	1,347	4,482
Operating Expenses [Abstract]
Natural and propane gas	0	160	0	519
Utilities Operating Expense, Other	0	0	0	120
Depreciation and amortization	0	0	0	0
Taxes, other than income taxes	0	0	0	0
Total Gas Utility Operating Expenses	0	160	0	639
Non-Regulated Gas Marketing	0	0
Other Cost and Expense, Operating	3,079	5,222	4,180	10,727
Total Operating Expenses	3,079	5,382	4,180	11,366
Operating Income (Loss)	(2,363)	(2,902)	(2,833)	(6,884)
Net Economic Earnings (Losses)	(82)	(51)	(417)	(440)
Total assets	77,505	126,668	77,505	126,668
Reconciliation of Consolidated Net Economic Earnings to Consolidated Net Income [Abstract]
Total Net Economic Earnings above	(82)	(51)	(417)	(440)
Non-Regulated Gas Marketing [Member] | Gas Marketing [Member]
Operating Segment Information [Abstract]
Revenues from external customers	59,811	41,255	93,064	96,504
Total Operating Revenues	80,497	38,923	133,207	101,078
Operating Expenses [Abstract]
Natural and propane gas	0	0	0	0
Utilities Operating Expense, Other	0	0	0	0
Depreciation and amortization	0	0	0	0
Taxes, other than income taxes	0	0	0	0
Total Gas Utility Operating Expenses	0	0	0	0
Non-Regulated Gas Marketing	65,021	35,995	116,803	93,376
Other Cost and Expense, Operating	0	0
Total Operating Expenses	65,021	35,995	116,803	93,376
Operating Income (Loss)	15,476	2,928	16,404	7,702
Net Economic Earnings (Losses)	7,084	2,368	7,906	5,649
Total assets	199,270	202,012	199,270	202,012
Reconciliation of Consolidated Net Economic Earnings to Consolidated Net Income [Abstract]
Total Net Economic Earnings above	7,084	2,368	7,906	5,649
Intersubsegment Eliminations [Member]
Operating Segment Information [Abstract]
Revenues from external customers			0	0
Revenue from Related Parties	0	0
Intersubsegment Eliminations [Member] | Consolidation, Eliminations [Member] | Unallocated and Eliminations [Member]
Operating Segment Information [Abstract]
Revenues from external customers			(45,387)	(15,646)
Revenue from Related Parties	(25,427)	(7,701)
Intersubsegment Eliminations [Member] | Regulated Gas Distribution [Member] | Gas Utility [Member]
Operating Segment Information [Abstract]
Revenues from external customers			4,338	10,494
Revenue from Related Parties	4,276	9,814
Intersubsegment Eliminations [Member] | Other [Member] | Other [Member]
Operating Segment Information [Abstract]
Revenues from external customers			906	578
Revenue from Related Parties	465	219
Intersubsegment Eliminations [Member] | Non-Regulated Gas Marketing [Member] | Gas Marketing [Member]
Operating Segment Information [Abstract]
Revenues from external customers			40,143	4,574
Revenue from Related Parties	$ 20,686	$ (2,332)

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Part 1 (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Sep. 30, 2013	Mar. 31, 2013
Accounting Policies [Abstract]
Accrued Unbilled Revenue	$ 77.1	$ 25.2	$ 33.3

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INFORMATION BY OPERATING SEGMENT (Tables)

6 Months Ended

Mar. 31, 2014

Segment Reporting [Abstract]

Schedule of operating segment information

(Thousands)	Gas Utility		Gas Marketing			Other			Eliminations			Consolidated
Three Months Ended March 31, 2014
Revenues from external customers	$	634,442	$	59,811		$	251		$	—		$	694,504
Intersegment revenues	4,276		20,686			465			(25,427		)	—
Total Operating Revenues	638,718		80,497			716			(25,427		)	694,504
Operating Expenses
Gas Utility
Natural and Propane Gas	430,576		—			—			(25,217		)	405,359
Other Operation and Maintenance Expenses	72,219		—			—			(210		)	72,009
Depreciation and Amortization	20,118		—			—			—			20,118
Taxes, Other than Income Taxes	41,739		—			—			—			41,739
Total Gas Utility Operating Expenses	564,652		—			—			(25,427		)	539,225
Gas Marketing	—		65,021			—			—			65,021
Other	—		—			3,079			—			3,079
Total Operating Expenses	564,652		65,021			3,079			(25,427		)	607,325
Operating Income	74,066		15,476			(2,363		)	—			87,179
Net Economic Earnings (Losses)	$	44,727	$	7,084		$	(82	)	$	—		$	51,729
Total assets	$	3,036,185	$	199,270		$	77,505		$	(132,489	)	$	3,180,471
Three Months Ended March 31, 2013
Revenues from external customers	$	354,097	$	41,255		$	2,261		$	—		$	397,613
Intersegment revenues	9,814		(2,332		)	219			(7,701		)	—
Total Operating Revenues	363,911		38,923			2,480			(7,701		)	397,613
Operating Expenses
Gas Utility
Natural and Propane Gas	237,888		—			160			(7,608		)	230,440
Other Operation and Maintenance Expenses	41,191		—			—			—			41,191
Depreciation and Amortization	11,258		—			—			—			11,258
Taxes, Other than Income Taxes	21,751		—			—			—			21,751
Total Gas Utility Operating Expenses	312,088		—			160			(7,608		)	304,640
Gas Marketing	—		35,995			—			—			35,995
Other	—		—			5,222			(93		)	5,129
Total Operating Expenses	312,088		35,995			5,382			(7,701		)	345,764
Operating Income	51,823		2,928			(2,902		)	—			51,849
Net Economic Earnings (Losses)	$	30,197	$	2,368		$	(51	)	$	—		$	32,514
Total assets	$	1,821,372	$	202,012		$	126,668		$	(140,954	)	$	2,009,098

(Thousands)	Gas Utility		Gas Marketing		Other			Eliminations			Consolidated
Six Months Ended March 31, 2014
Revenues from external customers	$	1,069,608	$	93,064	$	441		$	—		$	1,163,113
Intersegment revenues	4,338		40,143		906			(45,387		)	—
Total Operating Revenues	1,073,946		133,207		1,347			(45,387		)	1,163,113
Operating Expenses
Gas Utility
Natural and Propane Gas	692,128		—		—			(44,983		)	647,145
Other Operation and Maintenance Expenses	134,735		—		—			(404		)	134,331
Depreciation and Amortization	40,144		—		—			—			40,144
Taxes, Other than Income Taxes	70,328		—		—			—			70,328
Total Gas Utility Operating Expenses	937,335		—		—			(45,387		)	891,948
Gas Marketing	—		116,803		—			—			116,803
Other	100		—		4,180			—			4,280
Total Operating Expenses	937,435		116,803		4,180			(45,387		)	1,013,031
Operating Income	136,511		16,404		(2,833		)	—			150,082
Net Economic Earnings (Losses)	$	80,504	$	7,906	$	(417	)	$	—		$	87,993
Total assets	$	3,036,185	$	199,270	$	77,505		$	(132,489	)	$	3,180,471
Six Months Ended March 31, 2013
Revenues from external customers	$	604,208	$	96,504	$	3,904		$	—		$	704,616
Intersegment revenues	10,494		4,574		578			(15,646		)	—
Total Operating Revenues	614,702		101,078		4,482			(15,646		)	704,616
Operating Expenses
Gas Utility
Natural and Propane Gas	381,963		—		519			(15,526		)	366,956
Other Operation and Maintenance Expenses	80,842		—		120			(120		)	80,842
Depreciation and Amortization	22,223		—		—			—			22,223
Taxes, Other than Income Taxes	36,557		—		—			—			36,557
Total Gas Utility Operating Expenses	521,585		—		639			(15,646		)	506,578
Gas Marketing	—		93,376		—			—			93,376
Other	—		—		10,727			—			10,727
Total Operating Expenses	521,585		93,376		11,366			(15,646		)	610,681
Operating Income	93,117		7,702		(6,884		)	—			93,935
Net Economic Earnings (Losses)	$	55,538	$	5,649	$	(440	)	$	—		$	60,747
Total assets	$	1,821,372	$	202,012	$	126,668		$	(140,954	)	$	2,009,098

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 March 31,					Six Months Ended   March 31,
(Thousands)	2014			2013		2014			2013
Net Income (GAAP)	$	52,219		$	30,242	$	87,811		$	55,810
Unrealized (gain) loss on energy-related derivative contracts	(1,593		)	587		(1,292		)	1,026
Lower of cost or market inventory adjustments	(527		)	—		(589		)	—
Realized (gain) loss on economic hedges prior to sale of the physical commodity	(166		)	9		(119		)	(22		)
Acquisition, divestiture, and restructuring activities	1,796			1,676		2,182			3,933
Net Economic Earnings (Non-GAAP)	$	51,729		$	32,514	$	87,993		$	60,747

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COMMITMENTS AND CONTINGENCIES (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Mar. 31, 2014 site	Sep. 30, 2005	Nov. 26, 2013 LER [Member]
Contingencies and Indemnifications [Abstract]
Minimum total payments required for natural gas contracts	$ 975
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			$ 0.1

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Part 2 (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014	Mar. 31, 2013
Accounting Policies [Abstract]
Gross Receipts taxes recorded in gas utility operating revenues	$ 34.3	$ 17.2	$ 54.3	$ 27.5

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MGE ACQUISITION MGE ACQUISITION (Details) (USD $)	3 Months Ended	6 Months Ended			0 Months Ended	6 Months Ended	0 Months Ended
	Mar. 31, 2014	Mar. 31, 2014	Mar. 31, 2013	Sep. 30, 2013	Sep. 01, 2013 Laclede Group [Member] Missouri Gas Energy (MGE) [Member]	Mar. 31, 2014 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					$ 975,000,000
Assets, Fair Value Adjustment						23,900,000
Proceeds from Divestiture of Businesses		23,925,000	0				11,000,000
Payments to Acquire Businesses, Net of Cash Acquired						940,100,000
Goodwill	216,370,000	216,370,000	0	247,078,000
Regulated Operating Revenue, Other	$ 236,600,000	$ 396,700,000

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MGE ACQUISITION MGE Acquisition

6 Months Ended

Mar. 31, 2014

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 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. (ETE) and Energy Transfer Partners, L.P. The purchase was completed pursuant to the Purchase and Sales Agreement (MGE PSA) dated December 14, 2012. Under the terms of the MGE PSA, the Utility acquired MGE for a purchase price of $975 million, subject to reconciliation of certain amounts as discussed below.

The strategic rationale for the purchase for Laclede Group to is described below:

• With a larger market capitalization and enterprise value, the Company improved trading liquidity and has

better access to the capital markets.

• The Company now serves Missouri's two largest metropolitan areas in a state where it already had a working

relationship with regulators.

In accordance with Section 3.2 of the MGE PSA, Laclede Gas provided to SUG a reconciliation of certain balance sheet accounts from the amounts at September 30, 2012 to August 31, 2013, indicating the difference due to changes in the actual net assets transferred to the Company at closing from the level at September 30, 2012. Laclede Gas and SUG agreed to the final reconciliation amount of $23.9 million which was paid by ETE to Laclede Gas on February 14, 2014.

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.

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. On March 26, 2014, the MDPU issued an order denying the Attorney General's motion, so the MDPU's order approving the sale of NEG is now final.

These receipts of funds in December and February effectively reduced the Utility's purchase price of MGE to $940.1 million and reduced goodwill related to the transaction to $216.4 million. 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. As part of the MGE acquisition, Laclede Gas has estimated the asset retirement obligation of MGE's long-lived assets as of the acquisition date. This allocation of asset retirement obligations is preliminary and will be finalized upon completion of a detailed fair value analysis that is being performed by the Company and will be finalized prior to September 30, 2014.

For the three and six months ended March 31, 2014, operating revenues for MGE were $236.6 million and $396.7 million, respectively.

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 1 (Details) (USD $)	3 Months Ended		6 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014	Mar. 31, 2013
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to postretirement plans			$ 4,800,000
Contributions to pension plans for non-qualified plans			200,000
Extent of Lump-sum payments recognized, percentage			100.00%
Lump-sum payments recognized as settlements			10,900,000
Pension Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost - benefits earned during the period	2,428,000	2,311,000	4,856,000	4,622,000
Interest Cost	6,010,000	4,066,000	12,020,000	8,132,000
Expected return on plan assets	(6,645,000)	(4,741,000)	(13,290,000)	(9,482,000)
Amortization of prior service cost (credit)	125,000	136,000	249,000	272,000
Amortization of actuarial loss	1,772,000	2,839,000	3,544,000	5,678,000
Loss on lump-sum settlement	(1,319,000)	0	(1,319,000)	0
Sub-total	5,009,000	4,611,000	8,698,000	9,222,000
Regulatory adjustment	1,571,000	(433,000)	4,461,000	(867,000)
Net benefit cost	6,580,000	4,178,000	13,159,000	8,355,000
Postretirement Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost - benefits earned during the period	2,804,000	2,534,000	5,608,000	5,067,000
Interest Cost	2,170,000	1,279,000	4,339,000	2,558,000
Expected return on plan assets	(1,709,000)	(1,081,000)	(3,418,000)	(2,162,000)
Defined Benefit Plan, Amortization of Transition Obligations (Assets)	0	23,000	0	46,000
Amortization of prior service cost (credit)	(1,000)	1,000	(2,000)	2,000
Amortization of actuarial loss	1,505,000	1,325,000	3,010,000	2,650,000
Sub-total	4,769,000	4,081,000	9,537,000	8,161,000
Regulatory adjustment	(2,388,000)	(1,699,000)	(4,775,000)	(3,398,000)
Net benefit cost	$ 2,381,000	$ 2,382,000	$ 4,762,000	$ 4,763,000

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Part 3) (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014	Mar. 31, 2013
Cash Flow Hedging [Member] | Interest Rate Swap [Member] | Other Comprehensive Income (Loss) [Member]
Derivatives in Cash Flow Hedging Relationships [Abstract]
Effective portion of gain (loss) recognized in OCI on derivatives	$ 0	$ (4,549)	$ 0	$ (4,549)
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	(20)	(162)	22	(673)
Effective portion of gain (loss) reclassiffied from AOCI to income	(3,194)	22	(2,016)	(2,228)
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	64	(131)	(14)	(541)
Effective portion of gain (loss) reclassiffied from AOCI to income	(3,249)	(16)	(2,129)	(2,313)
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			123	(129)
Effective portion of gain (loss) reclassiffied from AOCI to income			1,226	(652)
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	(3,508)	(3,188)	(5,163)	(1,855)
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | NYMEX Natural Gas Contracts [Member] | Non Regulated Gas Marketing Operating Revenue [Member]
Derivatives in Cash Flow Hedging Relationships [Abstract]
Ineffective portion of gain (loss) on derivatives recognized in income	74	(87)
Effective portion of gain (loss) reclassiffied from AOCI to income	(4,655)	302
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			(137)	(412)
Effective portion of gain (loss) reclassiffied from AOCI to income			(3,355)	(1,661)
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | NYMEX Natural Gas Contracts [Member] | Non Regulated Gas Marketing Operating Expenses [Member]
Derivatives in Cash Flow Hedging Relationships [Abstract]
Ineffective portion of gain (loss) on derivatives recognized in income	(10)	(44)
Effective portion of gain (loss) reclassiffied from AOCI to income	1,406	(318)
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	(3,451)	(7,590)	(5,097)	(6,201)
Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member] | NYMEX Gasoline and Heating Oil Contracts [Member] | Other Regulated Gas Distribution Operating Expenses [Member]
Derivatives in Cash Flow Hedging Relationships [Abstract]
Ineffective portion of gain (loss) on derivatives recognized in income	(84)	(31)
Effective portion of gain (loss) reclassiffied from AOCI to income	55	38
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	57	147	66	203
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			36	(132)
Effective portion of gain (loss) reclassiffied from AOCI to income			113	85
Not Designated as Hedging Instrument [Member] | NYMEX Natural Gas Contracts [Member] | Non Regulated Gas Marketing Operating Revenue [Member]
Derivatives Not Designated as Hedging Instruments [Abstract]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	1,840	(1,679)
Not Designated as Hedging Instrument [Member] | NYMEX Natural Gas Contracts [Member] | Non Regulated Gas Marketing Operating Expenses [Member]
Derivatives Not Designated as Hedging Instruments [Abstract]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0	0
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	15,759	79	16,095	209
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	(3)	13
Not Designated as Hedging Instrument [Member] | Natural Gas Commodity Contracts [Member] | Non Regulated Gas Marketing Operating Revenue [Member]
Derivatives Not Designated as Hedging Instruments [Abstract]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	13,922	1,745
Not Designated as Hedging Instrument [Member] | Natural Gas Commodity Contracts [Member] | Non Regulated Gas Marketing Operating Expenses [Member]
Derivatives Not Designated as Hedging Instruments [Abstract]
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 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			3,830	(612)
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			10	46
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			$ 12,255	$ 775

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STATEMENTS OF CONSOLIDATED INCOME (UNAUDITED) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014	Mar. 31, 2013
Operating Revenues:
Gas Utility	$ 634,442	$ 354,097	$ 1,069,608	$ 604,208
Gas Marketing	59,811	41,255	93,064	96,504
Other	251	2,261	441	3,904
Total Operating Revenues	694,504	397,613	1,163,113	704,616
Gas Utility
Natural and propane gas	405,359	230,440	647,145	366,956
Other operation and maintenance expense	72,009	41,191	134,331	80,842
Depreciation and amortization	20,118	11,258	40,144	22,223
Taxes, other than income taxes	41,739	21,751	70,328	36,557
Total Gas Utility Operating Expenses	539,225	304,640	891,948	506,578
Non-Regulated Gas Marketing	65,021	35,995	116,803	93,376
Other	3,079	5,129	4,280	10,727
Total Operating Expenses	607,325	345,764	1,013,031	610,681
Operating Income	87,179	51,849	150,082	93,935
Other (Income Deductions) and Income - Net	(248)	1,340	1,401	2,424
Interest Charges:
Interest on long-term debt	8,630	5,689	18,324	11,127
Other interest charges	742	1,016	1,509	1,604
Total Interest Charges	9,372	6,705	19,833	12,731
Income Before Income Taxes	77,559	46,484	131,650	83,628
Income Tax (Benefit) Expense	25,340	16,242	43,839	27,818
Net Income	$ 52,219	$ 30,242	$ 87,811	$ 55,810
Weighted Average Number of Common Shares Outstanding:
Basic	32,617	22,421	32,593	22,396
Diluted	32,656	22,498	32,652	22,466
Basic Earnings Per Share of Common Stock:
Basic Earnings Per Share of Common Stock	$ 1.59	$ 1.34	$ 2.68	$ 2.48
Diluted Earnings Per Share of Common Stock:
Diluted Earnings Per Share of Common Stock	$ 1.59	$ 1.34	$ 2.68	$ 2.47
Dividends Declared Per Share of Common Stock	$ 0.440	$ 0.425	$ 0.880	$ 0.850

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SUBSEQUENT EVENT Subsequent Event (Details) (USD $)	6 Months Ended	0 Months Ended
	Mar. 31, 2014	Apr. 05, 2014 Subsequent Event [Member]
Subsequent Event [Line Items]
Business Acquisition, Cost of Acquired Entity, Purchase Price, Total		$ 1,600,000,000
Payments to Acquire Businesses, Gross		1,350,000,000
Number of customers acquired		422,000
Percentage of common shares acquired		100.00%
Business acquisition liabilities assumed		250,000,000
Increase (Decrease) in Other Loans		1,350,000,000
Revenue from Related Parties	$ 7,800,000

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STATEMENTS OF CONSOLIDATED CASH FLOWS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Operating Activities:
Net Income	$ 87,811	$ 55,810
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, amortization, and accretion	40,501	22,913
Deferred income taxes and investment tax credits	3,396	(11,132)
Other - net	2,102	450
Changes in assets and liabilities:
Accounts receivable - net	(211,715)	(71,164)
Unamortized purchased gas adjustments	15,901	29,635
Deferred purchased gas costs	27,766	43,827
Accounts payable	79,357	23,797
Increase (Decrease) in Customer Advances	(53,403)	(44,809)
Taxes accrued	38,123	32,971
Natural gas stored underground	114,237	59,953
Other assets and liabilities	(1,272)	115
Net cash provided by (used in) operating activities	142,804	142,366
Investing Activities:
Capital expenditures	(68,226)	(62,707)
Other investments	(5,082)	(2,126)
Proceeds from sale of right to acquire NEG	(11,000)	0
Proceeds from Divestiture of Businesses	23,925	0
Net cash used in investing activities	(38,383)	(64,833)
Financing Activities:
Issuance of long-term debt	0	125,000
Maturity of first mortgage bonds	(80,000)	(25,000)
Repayment of short-term debt - net	(38,000)	(40,100)
Changes in book overdrafts	(1,184)	(1,262)
Issuance of common stock	1,440	2,852
Dividends paid	(28,503)	(19,054)
Employees' taxes paid associated with restricted shares withheld upon vesting	(1,053)	(729)
Excess tax benefits from stock-based compensation	880	636
Other	(51)	(453)
Net cash provided by financing activities	(146,471)	41,890
Net Increase (Decrease) in Cash and Cash Equivalents	(42,050)	119,423
Cash and Cash Equivalents at Beginning of Period	52,981	27,457
Cash and Cash Equivalents at End of Period	10,931	146,880
Supplemental Disclosure of Cash Paid (Refunded) During the Period for:
Interest	19,724	14,569
Income taxes	$ 2,595	$ (3,165)

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EARNINGS PER COMMON SHARE (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014	Mar. 31, 2013
Basic EPS [Abstract]
Net Income	$ 52,219	$ 30,242	$ 87,811	$ 55,810
Less: Income allocated to participating securities	210	186	350	312
Net Income Available to Common Shareholders, Basic	52,009	30,056	87,461	55,498
Weighted Average Shares Outstanding, Basic	32,617	22,421	32,593	22,396
Earnings Per Share of Common Stock, Basic (Per Share)	$ 1.59	$ 1.34	$ 2.68	$ 2.48
Diluted EPS [Abstract]
Net Income	52,219	30,242	87,811	55,810
Less: Income allocated to participating securities	(209)	(186)	(349)	311
Net Income Available to Common Stockholders, Diluted	$ 52,010	$ 30,056	$ 87,462	$ 55,499
Weighted Average Shares Outstanding, Basic	32,617	22,421	32,593	22,396
Dilutive Effect of Stock Options, Restricted Stock, and Restricted Stock Units	39	77	59	70
Weighted Average Diluted Shares	32,656	22,498	32,652	22,466
Earnings Per Share of Common Stock, Diluted (Per share)	$ 1.59	$ 1.34	$ 2.68	$ 2.47
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	277	211	277	211

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STOCK-BASED COMPENSATION (Tables)

6 Months Ended

Mar. 31, 2014

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

Restricted stock and restricted stock unit activity

Time-vested restricted stock and stock unit activity for the six months ended March 31, 2014 is presented below:

	Restricted Stock/ Stock Units		Weighted Average Grant Date Fair Value
Nonvested at September 30, 2013	119,404		$	38.64
Granted	71,768		$	45.65
Vested	(17,999	)	$	36.37
Forfeited	(16,950	)	$	38.04
Nonvested at March 31, 2014	156,223		$	42.19

Activity of restricted stock and restricted stock units subject to performance and/or market conditions during the six months ended March 31, 2014 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)	123,252		$	37.20
Vested	(52,954	)	$	32.16
Forfeited	(22,022	)	$	29.35
Nonvested at March 31, 2014	290,544		$	36.17

Stock option awards activity

Stock option activity for the six months ended March 31, 2014 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	(23,250	)	$	30.96
Forfeited	—		$	—
Expired	—		$	—
Outstanding at March 31, 2014	110,250		$	32.07	1.4	$	1,663
Fully Vested and Expected to Vest at March 31, 2014	110,250		$	32.07	1.4	$	1,663
Exercisable at March 31, 2014	110,250		$	32.07	1.4	$	1,663

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   March 31,						Six Months Ended March 31,
(Thousands)	2014			2013			2014			2013
Total equity compensation cost	$	1,933		$	1,137		$	2,466		$	1,759
Compensation cost capitalized	(556		)	(356		)	(705		)	(539		)
Compensation cost recognized	$	1,377		$	781		$	1,761		$	1,220
Income tax benefit recognized	(527		)	(298		)	(674		)	(467		)

XML

FAIR VALUE OF FINANCIAL INSTRUMENTS (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Sep. 30, 2013	Mar. 31, 2013	Sep. 30, 2012
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	$ 10,931	$ 52,981	$ 146,880	$ 27,457
Carrying (Reported) Amount, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	10,931	52,981	146,880
Short-term debt	36,000	74,000	0
Long-term debt, including current portion	832,817	912,712	464,434
Estimate of Fair Value, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	10,931	52,981	146,880
Short-term debt	36,000	74,000	0
Long-term debt, including current portion	884,029	954,126	539,260
Quoted Prices in Active Markets (Level 1) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	10,751	52,824	136,826
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	180	157	10,054
Short-term debt	36,000	74,000	0
Long-term debt, including current portion	884,029	954,126	539,260
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	0	0	0
Short-term debt	0	0	0
Long-term debt, including current portion	$ 0	$ 0	$ 0

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FAIR VALUE OF FINANCIAL INSTRUMENTS (Tables)

6 Months Ended

Mar. 31, 2014

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 March 31, 2014
Cash and cash equivalents	$	10,931	$	10,931	$	10,751	$	180	$	—
Short-term debt	36,000		36,000		—		36,000		—
Long-term debt	832,817		884,029		—		884,029		—
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	912,712		954,126		—		954,126		—
As of March 31, 2013
Cash and cash equivalents	$	146,880	$	146,880	$	136,826	$	10,054	$	—
Short-term debt	—		—		—		—		—
Long-term debt	464,434		539,260		—		539,260		—

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

6 Months Ended

Mar. 31, 2014

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 (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 six months ended March 31, 2014, and impacts 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 Utility, Laclede Group’s earnings are typically concentrated during the heating season of November through April each fiscal year, although earnings for MGE are less seasonal than earnings from Laclede Gas due to MGE's 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 March 31, 2014 and 2013, for the Utility, were $77.1 million and $33.3 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 March 31, 2014 and 2013 were $34.3 million and $17.2 million, respectively. Amounts recorded in Gas Utility Operating Revenues for the six months ended March 31, 2014 and 2013 were $54.3 million and $27.5 million, respectively. Gross receipts taxes are expensed by the Utility and included in the Taxes, other than income taxes line.

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STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (UNAUDITED) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014	Mar. 31, 2013
Statement of Comprehensive Income [Abstract]
Net Income	$ 52,219	$ 30,242	$ 87,811	$ 55,810
Net gains (losses) on cash flow hedging derivative instruments:
Net hedging gain (loss) arising during the period	(3,451)	(7,590)	(5,097)	(6,201)
Reclassification adjustment for losses (gains) included in net income	3,194	(22)	2,016	2,228
Net unrealized gain (loss) on cash flow hedging derivative instruments	(257)	(7,612)	(3,081)	(3,973)
Defined benefit pension and other postretirement benefit plans:
Amortization of actuarial loss included in net periodic pension and postretirement benefit cost	97	90	195	181
Other Comprehensive Income (Loss), Before Tax	(160)	(7,522)	(2,886)	(3,792)
Income Tax (Benefit) Expense Related to Items of Other Comprehensive Income	(62)	(2,868)	(1,096)	(1,417)
Other Comprehensive Income (Loss), Net of Tax	(98)	(4,654)	(1,790)	(2,375)
Comprehensive Income	$ 52,121	$ 25,588	$ 86,021	$ 53,435

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INFORMATION BY OPERATING SEGMENT

6 Months Ended

Mar. 31, 2014

Segment Reporting [Abstract]

INFORMATION BY OPERATING SEGMENT

11. INFORMATION BY OPERATING SEGMENT

All of Laclede Group’s subsidiaries are 100% 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 March 31, 2014
Revenues from external customers	$	634,442	$	59,811		$	251		$	—		$	694,504
Intersegment revenues	4,276		20,686			465			(25,427		)	—
Total Operating Revenues	638,718		80,497			716			(25,427		)	694,504
Operating Expenses
Gas Utility
Natural and Propane Gas	430,576		—			—			(25,217		)	405,359
Other Operation and Maintenance Expenses	72,219		—			—			(210		)	72,009
Depreciation and Amortization	20,118		—			—			—			20,118
Taxes, Other than Income Taxes	41,739		—			—			—			41,739
Total Gas Utility Operating Expenses	564,652		—			—			(25,427		)	539,225
Gas Marketing	—		65,021			—			—			65,021
Other	—		—			3,079			—			3,079
Total Operating Expenses	564,652		65,021			3,079			(25,427		)	607,325
Operating Income	74,066		15,476			(2,363		)	—			87,179
Net Economic Earnings (Losses)	$	44,727	$	7,084		$	(82	)	$	—		$	51,729
Total assets	$	3,036,185	$	199,270		$	77,505		$	(132,489	)	$	3,180,471
Three Months Ended March 31, 2013
Revenues from external customers	$	354,097	$	41,255		$	2,261		$	—		$	397,613
Intersegment revenues	9,814		(2,332		)	219			(7,701		)	—
Total Operating Revenues	363,911		38,923			2,480			(7,701		)	397,613
Operating Expenses
Gas Utility
Natural and Propane Gas	237,888		—			160			(7,608		)	230,440
Other Operation and Maintenance Expenses	41,191		—			—			—			41,191
Depreciation and Amortization	11,258		—			—			—			11,258
Taxes, Other than Income Taxes	21,751		—			—			—			21,751
Total Gas Utility Operating Expenses	312,088		—			160			(7,608		)	304,640
Gas Marketing	—		35,995			—			—			35,995
Other	—		—			5,222			(93		)	5,129
Total Operating Expenses	312,088		35,995			5,382			(7,701		)	345,764
Operating Income	51,823		2,928			(2,902		)	—			51,849
Net Economic Earnings (Losses)	$	30,197	$	2,368		$	(51	)	$	—		$	32,514
Total assets	$	1,821,372	$	202,012		$	126,668		$	(140,954	)	$	2,009,098

(Thousands)	Gas Utility		Gas Marketing		Other			Eliminations			Consolidated
Six Months Ended March 31, 2014
Revenues from external customers	$	1,069,608	$	93,064	$	441		$	—		$	1,163,113
Intersegment revenues	4,338		40,143		906			(45,387		)	—
Total Operating Revenues	1,073,946		133,207		1,347			(45,387		)	1,163,113
Operating Expenses
Gas Utility
Natural and Propane Gas	692,128		—		—			(44,983		)	647,145
Other Operation and Maintenance Expenses	134,735		—		—			(404		)	134,331
Depreciation and Amortization	40,144		—		—			—			40,144
Taxes, Other than Income Taxes	70,328		—		—			—			70,328
Total Gas Utility Operating Expenses	937,335		—		—			(45,387		)	891,948
Gas Marketing	—		116,803		—			—			116,803
Other	100		—		4,180			—			4,280
Total Operating Expenses	937,435		116,803		4,180			(45,387		)	1,013,031
Operating Income	136,511		16,404		(2,833		)	—			150,082
Net Economic Earnings (Losses)	$	80,504	$	7,906	$	(417	)	$	—		$	87,993
Total assets	$	3,036,185	$	199,270	$	77,505		$	(132,489	)	$	3,180,471
Six Months Ended March 31, 2013
Revenues from external customers	$	604,208	$	96,504	$	3,904		$	—		$	704,616
Intersegment revenues	10,494		4,574		578			(15,646		)	—
Total Operating Revenues	614,702		101,078		4,482			(15,646		)	704,616
Operating Expenses
Gas Utility
Natural and Propane Gas	381,963		—		519			(15,526		)	366,956
Other Operation and Maintenance Expenses	80,842		—		120			(120		)	80,842
Depreciation and Amortization	22,223		—		—			—			22,223
Taxes, Other than Income Taxes	36,557		—		—			—			36,557
Total Gas Utility Operating Expenses	521,585		—		639			(15,646		)	506,578
Gas Marketing	—		93,376		—			—			93,376
Other	—		—		10,727			—			10,727
Total Operating Expenses	521,585		93,376		11,366			(15,646		)	610,681
Operating Income	93,117		7,702		(6,884		)	—			93,935
Net Economic Earnings (Losses)	$	55,538	$	5,649	$	(440	)	$	—		$	60,747
Total assets	$	1,821,372	$	202,012	$	126,668		$	(140,954	)	$	2,009,098

Reconciliation of Consolidated Net Income to Consolidated Net Economic Earnings
	Three Months Ended March 31,					Six Months Ended   March 31,
(Thousands)	2014			2013		2014			2013
Net Income (GAAP)	$	52,219		$	30,242	$	87,811		$	55,810
Unrealized (gain) loss on energy-related derivative contracts	(1,593		)	587		(1,292		)	1,026
Lower of cost or market inventory adjustments	(527		)	—		(589		)	—
Realized (gain) loss on economic hedges prior to sale of the physical commodity	(166		)	9		(119		)	(22		)
Acquisition, divestiture, and restructuring activities	1,796			1,676		2,182			3,933
Net Economic Earnings (Non-GAAP)	$	51,729		$	32,514	$	87,993		$	60,747

XML

Document and Entity Information (USD $)	6 Months Ended
	Mar. 31, 2014	Apr. 25, 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		32,785,833
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q2
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2014

XML

COMMITMENTS AND CONTINGENCIES

6 Months Ended

Mar. 31, 2014

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 March 31, 2014 are estimated at approximately $975 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 begin. 

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. In 2014, the Laclede Gas account was paid in full. LER is still owed $0.1 million, which it expects to receive in 2014.

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

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CONSOLIDATED BALANCE SHEETS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Sep. 30, 2013	Mar. 31, 2013
ASSETS
Utility Plant	$ 2,325,358	$ 2,271,189	$ 1,538,890
Less: Accumulated depreciation and amortization	522,408	494,559	478,971
Net Utility Plant	1,802,950	1,776,630	1,059,919
Non-utility property	5,539	7,694	5,456
Goodwill	216,370	247,078	0
Other investments	62,231	58,306	52,910
Other Property and Investments	284,140	313,078	58,366
Current Assets:
Cash and cash equivalents	10,931	52,981	146,880
Accounts receivable:
Utility	275,688	101,118	148,624
Non-utility	103,272	63,752	55,925
Other	14,579	14,451	9,290
Allowance for doubtful accounts	(10,549)	(8,046)	(8,833)
Delayed customer billings	29,667	0	19,663
Inventories:
Natural gas stored underground	67,798	182,035	32,776
Propane gas	6,633	8,962	8,963
Materials and supplies at average cost	8,408	8,154	4,385
Natural gas receivable	3,233	18,782	13,470
Derivative instrument assets	13,560	3,291	6,021
Unamortized purchased gas adjustments	1,631	17,533	11,039
Deferred income taxes	5,871	0	2,527
Prepayments and other	10,909	12,867	9,183
Total Current Assets	541,631	475,880	459,913
Deferred Charges:
Regulatory assets	537,398	545,947	424,743
Other	14,352	13,851	6,157
Total Deferred Charges	551,750	559,798	430,900
Total Assets	3,180,471	3,125,386	2,009,098
Capitalization:
Common stock (70,000,000 shares authorized, 32,776,595, 32,696,836, and 22,563,958 shares issued, respectively)	32,777	32,697	22,644
Paid-in capital	597,468	594,269	172,736
Retained earnings	478,955	420,103	451,114
Accumulated other comprehensive loss	(2,578)	(787)	(6,491)
Total Common Stock Equity	1,106,622	1,046,282	640,003
Long-term debt (less current portion)	832,817	912,712	464,434
Total Capitalization	1,939,439	1,958,994	1,104,437
Current Liabilities:
Notes payable	36,000	74,000	0
Accounts payable	215,085	140,234	108,648
Advance customer billings	0	23,736	0
Wages and compensation accrued	21,839	20,807	16,175
Dividends payable	15,083	14,556	10,059
Customer deposits	15,588	15,062	7,706
Interest accrued	8,064	8,335	6,191
Taxes accrued	71,442	32,896	44,550
Deferred income taxes	0	1,012	0
Other	16,863	22,540	14,015
Total Current Liabilities	399,964	353,178	207,344
Deferred Credits and Other Liabilities:
Deferred income taxes	392,461	379,114	343,016
Unamortized investment tax credits	2,794	2,900	3,006
Pension and postretirement benefit costs	223,970	228,653	191,778
Asset retirement obligations	73,353	74,554	41,512
Regulatory liabilities	102,407	82,560	83,026
Other	46,083	45,433	34,979
Total Deferred Credits and Other Liabilities	841,068	813,214	697,317
Total Capitalization and Liabilities	$ 3,180,471	$ 3,125,386	$ 2,009,098

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FAIR VALUE OF FINANCIAL INSTRUMENTS

6 Months Ended

Mar. 31, 2014

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 March 31, 2014
Cash and cash equivalents	$	10,931	$	10,931	$	10,751	$	180	$	—
Short-term debt	36,000		36,000		—		36,000		—
Long-term debt	832,817		884,029		—		884,029		—
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	912,712		954,126		—		954,126		—
As of March 31, 2013
Cash and cash equivalents	$	146,880	$	146,880	$	136,826	$	10,054	$	—
Short-term debt	—		—		—		—		—
Long-term debt	464,434		539,260		—		539,260		—

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

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EARNINGS PER COMMON SHARE

6 Months Ended

Mar. 31, 2014

Earnings Per Share [Abstract]

EARNINGS PER COMMON SHARE

5. EARNINGS PER COMMON SHARE

	Three Months Ended March 31,				Six Months Ended March 31,
(Thousands, Except Per Share Amounts)	2014		2013		2014		2013
Basic EPS:
Net Income	$	52,219	$	30,242	$	87,811	$	55,810
Less: Income allocated to participating securities	210		186		350		312
Net Income Available to Common Shareholders	$	52,009	$	30,056	$	87,461	$	55,498
Weighted Average Shares Outstanding	32,617		22,421		32,593		22,396
Earnings Per Share of Common Stock	$	1.59	$	1.34	$	2.68	$	2.48
Diluted EPS:
Net Income	$	52,219	$	30,242	$	87,811	$	55,810
Less: Income allocated to participating securities	209		186		349		311
Net Income Available to Common Shareholders	$	52,010	$	30,056	$	87,462	$	55,499
Weighted Average Shares Outstanding	32,617		22,421		32,593		22,396
Dilutive Effect of Stock Options, Restricted Stock and Restricted Stock Units	39		77		59		70
Weighted Average Diluted Shares	32,656		22,498		32,652		22,466
Earnings Per Share of Common Stock	$	1.59	$	1.34	$	2.68	$	2.47
Outstanding Shares Excluded from the Calculation of Diluted EPS Attributable to:
Restricted stock and stock units subject to performance and/or market conditions	277		211		277		211

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EARNINGS PER COMMON SHARE (Tables)

6 Months Ended

Mar. 31, 2014

Earnings Per Share [Abstract]

Earnings Per Common Share

5. EARNINGS PER COMMON SHARE

	Three Months Ended March 31,				Six Months Ended March 31,
(Thousands, Except Per Share Amounts)	2014		2013		2014		2013
Basic EPS:
Net Income	$	52,219	$	30,242	$	87,811	$	55,810
Less: Income allocated to participating securities	210		186		350		312
Net Income Available to Common Shareholders	$	52,009	$	30,056	$	87,461	$	55,498
Weighted Average Shares Outstanding	32,617		22,421		32,593		22,396
Earnings Per Share of Common Stock	$	1.59	$	1.34	$	2.68	$	2.48
Diluted EPS:
Net Income	$	52,219	$	30,242	$	87,811	$	55,810
Less: Income allocated to participating securities	209		186		349		311
Net Income Available to Common Shareholders	$	52,010	$	30,056	$	87,462	$	55,499
Weighted Average Shares Outstanding	32,617		22,421		32,593		22,396
Dilutive Effect of Stock Options, Restricted Stock and Restricted Stock Units	39		77		59		70
Weighted Average Diluted Shares	32,656		22,498		32,652		22,466
Earnings Per Share of Common Stock	$	1.59	$	1.34	$	2.68	$	2.47
Outstanding Shares Excluded from the Calculation of Diluted EPS Attributable to:
Restricted stock and stock units subject to performance and/or market conditions	277		211		277		211

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SUBSEQUENT EVENT

6 Months Ended

Mar. 31, 2014

Subsequent Events [Abstract]

SUBSEQUENT EVENTS

13. SUBSEQUENT EVENTS

On April 5, 2014, Laclede Group entered into an agreement (the Alagasco Transaction) with Energen Corporation (Energen) to acquire 100 percent of the common stock of Alabama Gas Corporation (Alagasco). Alagasco, a subsidiary of Energen, is engaged in the distribution of natural gas on a regulated basis in Alabama and serves more than 422,000 customers. The stated purchase price is $1.6 billion, subject to customary closing adjustments, comprised of approximately $1.35 billion in cash and approximately $250 million of assumed Alagasco long-term debt. The Alagasco Transaction is supported by a fully committed $1.35 billion bridge loan facility with Credit Suisse and Wells Fargo Bank, National Association, which as of April 28th has been syndicated to a group of eleven additional banks.

On April 14, 2014, Laclede and Energen jointly filed with the Alabama Public Service Commission to request approval of the Alagasco Transaction.

On April 23, 2014, the MoPSC approved a stipulation and agreement reached between MGE and all parties to the case finalizing MGE’s general rate case filed in September 2013. Under the agreement, MGE’s annual revenues will increase by $7.8 million, effective May 1, 2014. The revenues will be collected in base rates and will replace a like amount that MGE is currently authorized to collect through the Infrastructure System Replacement Surcharge mechanism.

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CONCENTRATIONS OF CREDIT RISK

6 Months Ended

Mar. 31, 2014

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. 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 $30.0 million at March 31, 2014. Net receivable amounts from these customers on the same date, reflecting netting arrangements, were $19.2 million. Accounts receivable attributable to utility companies and their marketing affiliates comprised $33.3 million of total accounts receivable at March 31, 2014, while net receivable amounts from these customers, reflecting netting arrangements, were $30.3 million. LER also has concentrations of credit risk with certain individually significant counterparties. At March 31, 2014, the amounts included in accounts receivable from LER’s five largest counterparties (in terms of net accounts receivable exposure), were $34.9 million. Four of these five counterparties are investment-grade rated and the fifth is privately owned. Net receivable amounts from these customers on the same date, reflecting netting arrangements, were $27.2 million. Additionally, LER has concentrations of credit risk with pipeline companies associated with its natural gas receivable amounts.

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FAIR VALUE MEASUREMENTS

6 Months Ended

Mar. 31, 2014

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 March 31, 2014
Assets
U. S. Stock/Bond Mutual Funds	$	16,340	$	2,780	$	—	$	—		$	19,120
NYMEX/ICE natural gas contracts	7,495		1,263		—		(5,595		)	3,163
OTCBB natural gas contracts	—		6,330		—		(315		)	6,015
NYMEX gasoline and heating oil contracts	49		—		—		—			49
Natural gas commodity contracts	—		6,619		7		(1,184		)	5,442
Total	$	23,884	$	16,992	$	7	$	(7,094	)	$	33,789
Liabilities
NYMEX/ICE natural gas contracts	$	4,374	$	565	$	—	$	(4,939	)	$	—
OTCBB natural gas contracts	—		315		—		(315		)	—
Natural gas commodity contracts	—		3,278		40		(1,184		)	2,134
Total	$	4,374	$	4,158	$	40	$	(6,438	)	$	2,134
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 March 31, 2013
Assets
U. S. Stock/Bond Mutual Funds	$	13,922	$	—	$	—	$	—		$	13,922
NYMEX/ICE natural gas contracts	11,010		379		—		(8,209		)	3,180
NYMEX gasoline and heating oil contracts	322		—		—		(192		)	130
Natural gas commodity contracts	—		2,888		117		(289		)	2,716
Total	$	25,254	$	3,267	$	117	$	(8,690	)	$	19,948
Liabilities
NYMEX/ICE natural gas contracts	$	2,447	$	1,342	$	—	$	(3,789	)	$	—
Natural gas commodity contracts	—		990		24		(289		)	725
Interest rate swap	—		4,549		—		—			4,549
Total	$	2,447	$	6,881	$	24	$	(4,078	)	$	5,274

The mutual funds included in Level 1 are valued based on exchange-quoted market prices of individual 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 March 31,					Six Months Ended March 31,
(Thousands)	2014			2013		2014			2013
Beginning of period	$	7		$	30	$	110		$	109
Net settlements	(22		)	37		(131		)	(29		)
Net gains related to derivatives not held at end of period	17			—		3			—
Net (losses) gains related to derivatives still held at end of period	(35		)	26		(15		)	13
End of period	$	(33	)	$	93	$	(33	)	$	93

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

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

6 Months Ended

Mar. 31, 2014

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, the Utility purchases NYMEX futures and options contracts to help stabilize operating costs associated with forecasted purchases of gasoline and diesel fuels used to power vehicles and equipment used in the course of its business. At March 31, 2014, Laclede Gas held 0.4 million gallons of gasoline futures contracts at an average price of $2.76 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 March 31, 2014, the fair values of 149.2 million MMBtu of non-exchange traded natural gas commodity contracts were reflected in the Consolidated Balance Sheet. Of these contracts, 79.2 million MMBtu will settle during fiscal year 2014, 30.2 million MMBtu will settle during fiscal year 2015, 12.4 million MMBtu will settle during fiscal year 2016, 11.0 million MMBtu will settle during fiscal year 2017, 11.0 million MMBtu will settle during fiscal year 2018, while the remaining 5.4 million MMBtu will settle during fiscal year 2019. 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 March 31, 2014, 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 March 31, 2014 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	—	$	—	7.56	$	4.38
Fiscal 2015	—	—		1.58	4.46
Fiscal 2016	—	—		0.05	4.22
NYMEX/ICE Open long futures positions
Fiscal 2014	3.80	$	3.79	1.16	$	4.23
Fiscal 2015	0.94	3.84		0.88	4.35
Fiscal 2016	—	—		0.09	4.18
Fiscal 2017	—	—		0.02	4.28
ICE Open long basis swap positions
Fiscal 2014	—	$	—	0.92	$	0.39
Fiscal 2015	—	—		0.16	0.39
Fiscal 2016	—	—		0.92	0.80
Fiscal 2017	—	—		0.16	0.80
ICE Open short basis swap positions
Fiscal 2014	—	$	—	4.86	$	0.02
Fiscal 2015	—	—		0.62	(0.09		)
OTCBB Open long futures positions
Fiscal 2014	9.53	$	4.00	—	$	—
Fiscal 2015	9.83	4.21		—	—
Fiscal 2016	0.55	4.24		—	—

At March 31, 2014, the Utility had 28.4 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 March 31, 2014, it is expected that approximately $1.0 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
	Location of Gain (Loss)	Three Months Ended March 31,						Six Months Ended March 31,
(Thousands)	Recorded in Income	2014			2013			2014			2013
Derivatives in Cash Flow Hedging Relationships
Effective portion of gain (loss) recognized in OCI on derivatives:
NYMEX/ICE natural gas contracts		$	(3,508	)	$	(3,188	)	$	(5,163	)	$	(1,855	)
NYMEX gasoline and heating oil contracts		57			147			66			203
Interest rate swaps		—			(4,549		)	—			(4,549		)
Total		$	(3,451	)	$	(7,590	)	$	(5,097	)	$	(6,201	)
Effective portion of gain (loss) reclassified from AOCI to income:
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	$	(4,655	)	$	302		$	(3,355	)	$	(1,661	)
	Gas Marketing Operating Expenses	1,406			(318		)	1,226			(652		)
Sub-total		(3,249		)	(16		)	(2,129		)	(2,313		)
NYMEX gasoline and heating oil contracts	Gas Utility Other Operations and Maintenance Expenses	55			38			113			85
Total		$	(3,194	)	$	22		$	(2,016	)	$	(2,228	)
Ineffective portion of gain (loss) on derivatives recognized in income:
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	$	74		$	(87	)	$	(137	)	$	(412	)
	Gas Marketing Operating Expenses	(10		)	(44		)	123			(129		)
Sub-total		64			(131		)	(14		)	(541		)
NYMEX gasoline and heating oil contracts	Gas Utility Other Operations and Maintenance Expenses	(84		)	(31		)	36			(132		)
Total		$	(20	)	$	(162	)	$	22		$	(673	)
Derivatives Not Designated as Hedging Instruments *
Gain (loss) recognized in income on derivatives:
Natural gas commodity contracts	Gas Marketing Operating Revenues	$	13,922		$	1,745		$	12,255		$	775
	Gas Marketing Operating Expenses	—			—			—			—
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	1,840			(1,679		)	3,830			(612		)
	Gas Marketing Operating Expenses	—			—			—			—
NYMEX gasoline and heating oil contracts	Other Income and (Income Deductions) - Net	(3		)	13			10			46
Total		$	15,759		$	79		$	16,095		$	209

* 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 March 31, 2014
	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	$	915		Derivative Instrument Assets	$	773
	Other Deferred Charges	207			Other Deferred Charges	1
NYMEX gasoline and heating oil contracts	Derivative Instrument Assets	49			Derivative Instrument Assets	—
Sub-total		1,171				774
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets	3,166			Derivative Instrument Assets	347
	Accounts Receivable – Other	4,467			Accounts Receivable – Other	3,811
	Other Deferred Charges	3			Other Deferred Charges	7
OTCBB natural gas contracts	Derivative Instrument Assets	6,266			Derivative Instrument Assets	193
	Other Deferred Credits	64			Other Deferred Credits	122
Natural gas commodity contracts	Derivative Instrument Assets	4,466			Derivative Instrument Assets	333
	Other Deferred Charges	1,326			Other Deferred Charges	17
	Other Current Liabilities	603			Other Current Liabilities	1,574
	Other Deferred Credits	231			Other Deferred Credits	1,394
Sub-total		20,592				7,798
Total derivatives		$	21,763			$	8,572
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 March 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	Accounts Receivable - Other	$	520	Accounts Receivable - Other	$	2,993
	Other Deferred Charges	5		Other Deferred Charges	—
NYMEX gasoline and heating oil contracts	Derivative Instrument Assets	312		Derivative Instrument Assets	—
Interest rate swaps	Other Current Liabilities	—		Other Current Liabilities	4,549
Sub-total		837			7,542
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets	10,862		Derivative Instrument Assets	339
	Accounts Receivable - Other	2		Accounts Receivable - Other	457
Natural gas commodity contracts	Derivative Instrument Assets	2,943		Derivative Instrument Assets	227
	Other Current Liabilities	62		Other Current Liabilities	787
NYMEX gasoline and heating oil contracts	Derivative Instrument Assets	10		Derivative Instrument Assets	—
Sub-total		13,879			1,810
Total derivatives		$	14,716		$	9,352

* 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)	March 31, 2014			September 30, 2013			March 31, 2013
Fair value of asset derivatives presented above	$	21,763		$	6,276		$	14,716
Fair value of cash margin receivables offset with derivatives	—			1,765			2,928
Netting of assets and liabilities with the same counterparty	(7,094		)	(4,739		)	(11,618		)
Total	$	14,669		$	3,302		$	6,026
Derivative Instrument Assets, per Consolidated Balance Sheets:
Derivative instrument assets	$	13,560		$	3,291		$	6,021
Other deferred charges	1,109			11			5
Total	$	14,669		$	3,302		$	6,026
Fair value of liability derivatives presented above	$	8,572		$	10,629		$	9,352
Fair value of cash margin payables offset with derivatives	655			6			7,540
Netting of assets and liabilities with the same counterparty	(7,094		)	(4,739		)	(11,618		)
Total	$	2,133		$	5,896		$	5,274
Derivative Instrument Liabilities, per Consolidated Balance Sheets:
Other Current Liabilities	$	1,196		$	4,400		$	5,274
Other Deferred Credits	937			1,496			—
Total	$	2,133		$	5,896		$	5,274

Additionally, at March 31, 2014, September 30, 2013, and March 31, 2013, the Company had $3.8 million, $3.2 million, and $1.3 million, respectively, in cash margin receivables not offset with derivatives, that are presented in Accounts Receivable - Other.

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OTHER INCOME AND (INCOME DEDUCTIONS) - NET

6 Months Ended

Mar. 31, 2014

Other Nonoperating Income (Expense) [Abstract]

OTHER INCOME AND (INCOME DEDUCTIONS) - NET

10. OTHER INCOME AND (INCOME DEDUCTIONS) - NET

	Three Months Ended March 31,						Six Months Ended March 31,
(Thousands)	2014			2013			2014		2013
Interest income	$	142		$	257		$	391	$	663
Net investment gain (loss)	(612		)	1,174			135		1,104
Other income (deductions)	222			(91		)	875		657
Other Income and (Income Deductions) – Net	$	(248	)	$	1,340		$	1,401	$	2,424

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STOCK-BASED COMPENSATION (Details) (USD $)	3 Months Ended		6 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014 Restricted Stock Awards [Member]	Mar. 31, 2014 Restricted Stock Awards [Member] Time Vested Restricted Stock and Time Vested Restricted Stock Units [Member]	Mar. 31, 2014 Restricted Stock Awards [Member] Executive Officers and Key Employees [Member] Performance Contingent Restricted Stock and Stock Units [Member]	Mar. 31, 2014 Restricted Stock Awards [Member] Executive Officers and Key Employees [Member] Time Vested Restricted Stock and Time Vested Restricted Stock Units [Member]	Mar. 31, 2014 Stock Options Awards [Member]	Sep. 30, 2013 Stock Options Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares to vest on July 14, 2014								15,200
Shares to vest on December 2, 2014								12,168
Shares to vest during fiscal 2017								44,400
Restricted Stock Awards [Abstract]
Granted (in shares)							123,252	71,768
Granted, weighted average grant date fair value (per share)							$ 37.20	$ 45.65
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)						119,404	242,268
Granted (in shares)							123,252	71,768
Vested (in shares)					(70,953)	(17,999)	(52,954)
Forfeited (in shares)						(16,950)	(22,022)
Nonvested, end of period (in shares)						156,223	290,544
Weighted average Grant Date Fair Value [Abstract]
Nonvested Beginning Balance, weighted average grant date fair value (per share)						$ 38.64	$ 34.15
Granted, weighted average grant date fair value (per share)							$ 37.20	$ 45.65
Vested, weighted average grant date fair value (per share)						$ 36.37	$ 32.16
Forfeited, weighted average grant date fair value (per share)						$ 38.04	$ 29.35
Nonvested Ending Balance, weighted average grant date fair value (per share)						$ 42.19	$ 36.17
Stock Options - Shares [Roll Forward]
Outstanding Balance - stock options									110,250	133,500
Fully Vested and Expected to Vest, end of period (in shares)									110,250
Exercisable, end of period (in shares)									110,250
Granted - stock options (in shares)									0
Exercised - stock options (in shares)									(23,250)
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)									$ 32.07	$ 31.87
Granted, weighted average exercise price - stock options (per share)									$ 0.00
Exercised, weighted average exercise price - stock options (per share)									$ 30.96
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)									$ 32.07	$ 31.87
Fully Vested and Expected to Vest at End of Period, weighted average exercise price - stock options (per share)									$ 32.07
Exercisable at End of Period, weighted average exercise price - stock options (per share)									$ 32.07
Outstanding Ending Balance, weighted average remaining contractual term - stock options (in years)									1 year 4 months 12 days
Fully Vested and Expected to Vest at End of Period, weighted average remaining contractual term - stock options (in years)									1 year 4 months 12 days
Exercisable at End of Period, weighted average remaining contractual term - stock options (in years)									1 year 4 months 12 days
Outstanding Ending Balance, aggregate intrinsic value - stock options									$ 1,663,000
Fully Vested and Expected to Vest at End of Period, aggregate intrinsic value - stock options									1,663,000
Exercisable at End of Period, aggregate intrinsic value - stock options									1,663,000
Stock Option Awards [Abstract]
Common stock closing price (per share)									$ 47.15
Equity Compensation Cost [Abstract]
Compensation cost capitalized	(556,000)	(356,000)	(705,000)	(539,000)
Employee Service Share Based Compensation Allocation Of Recognized Period Costs Total Amount	1,933,000	1,137,000	2,466,000	1,759,000
Compensation cost recognized in net income	(1,377,000)	(781,000)	(1,761,000)	1,220,000
Income tax benefit recognized in net income	(527,000)	(298,000)	(674,000)	(467,000)
Total unrecognized compensation cost	$ 9,800,000		$ 9,800,000
Weighted average period cost to be recognized (in years)			2 years 2 months 11 days

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PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS (Tables)

6 Months Ended

Mar. 31, 2014

Defined Contribution Pension and Other Postretirement Plans Disclosure [Abstract]

Net Periodic Cost

Net periodic postretirement benefit costs consisted of the following components:

	Three Months Ended   March 31,						Six Months Ended   March 31,
(Thousands)	2014			2013			2014			2013
Service cost – benefits earned during the period	$	2,804		$	2,534		$	5,608		$	5,067
Interest cost on accumulated postretirement benefit obligation	2,170			1,279			4,339			2,558
Expected return on plan assets	(1,709		)	(1,081		)	(3,418		)	(2,162		)
Amortization of transition obligation	—			23			—			46
Amortization of prior service cost (credit)	(1		)	1			(2		)	2
Amortization of actuarial loss	1,505			1,325			3,010			2,650
Sub-total	4,769			4,081			9,537			8,161
Regulatory adjustment	(2,388		)	(1,699		)	(4,775		)	(3,398		)
Net postretirement benefit cost	$	2,381		$	2,382		$	4,762		$	4,763

The net periodic pension costs include the following components:

	Three Months Ended   March 31,						Six Months Ended   March 31,
(Thousands)	2014			2013			2014			2013
Service cost – benefits earned during the period	$	2,428		$	2,311		$	4,856		$	4,622
Interest cost on projected benefit obligation	6,010			4,066			12,020			8,132
Expected return on plan assets	(6,645		)	(4,741		)	(13,290		)	(9,482		)
Amortization of prior service cost	125			136			249			272
Amortization of actuarial loss	1,772			2,839			3,544			5,678
Loss on lump-sum settlement	1,319			—			1,319			—
Sub-total	5,009			4,611			8,698			9,222
Regulatory adjustment	1,571			(433		)	4,461			(867		)
Net pension cost	$	6,580		$	4,178		$	13,159		$	8,355

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)

6 Months Ended

Mar. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities

Open NYMEX/ICE and OTCBB natural gas futures and swap positions at March 31, 2014 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	—	$	—	7.56	$	4.38
Fiscal 2015	—	—		1.58	4.46
Fiscal 2016	—	—		0.05	4.22
NYMEX/ICE Open long futures positions
Fiscal 2014	3.80	$	3.79	1.16	$	4.23
Fiscal 2015	0.94	3.84		0.88	4.35
Fiscal 2016	—	—		0.09	4.18
Fiscal 2017	—	—		0.02	4.28
ICE Open long basis swap positions
Fiscal 2014	—	$	—	0.92	$	0.39
Fiscal 2015	—	—		0.16	0.39
Fiscal 2016	—	—		0.92	0.80
Fiscal 2017	—	—		0.16	0.80
ICE Open short basis swap positions
Fiscal 2014	—	$	—	4.86	$	0.02
Fiscal 2015	—	—		0.62	(0.09		)
OTCBB Open long futures positions
Fiscal 2014	9.53	$	4.00	—	$	—
Fiscal 2015	9.83	4.21		—	—
Fiscal 2016	0.55	4.24		—	—

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

The Effect of Derivative Instruments on the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income
	Location of Gain (Loss)	Three Months Ended March 31,						Six Months Ended March 31,
(Thousands)	Recorded in Income	2014			2013			2014			2013
Derivatives in Cash Flow Hedging Relationships
Effective portion of gain (loss) recognized in OCI on derivatives:
NYMEX/ICE natural gas contracts		$	(3,508	)	$	(3,188	)	$	(5,163	)	$	(1,855	)
NYMEX gasoline and heating oil contracts		57			147			66			203
Interest rate swaps		—			(4,549		)	—			(4,549		)
Total		$	(3,451	)	$	(7,590	)	$	(5,097	)	$	(6,201	)
Effective portion of gain (loss) reclassified from AOCI to income:
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	$	(4,655	)	$	302		$	(3,355	)	$	(1,661	)
	Gas Marketing Operating Expenses	1,406			(318		)	1,226			(652		)
Sub-total		(3,249		)	(16		)	(2,129		)	(2,313		)
NYMEX gasoline and heating oil contracts	Gas Utility Other Operations and Maintenance Expenses	55			38			113			85
Total		$	(3,194	)	$	22		$	(2,016	)	$	(2,228	)
Ineffective portion of gain (loss) on derivatives recognized in income:
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	$	74		$	(87	)	$	(137	)	$	(412	)
	Gas Marketing Operating Expenses	(10		)	(44		)	123			(129		)
Sub-total		64			(131		)	(14		)	(541		)
NYMEX gasoline and heating oil contracts	Gas Utility Other Operations and Maintenance Expenses	(84		)	(31		)	36			(132		)
Total		$	(20	)	$	(162	)	$	22		$	(673	)
Derivatives Not Designated as Hedging Instruments *
Gain (loss) recognized in income on derivatives:
Natural gas commodity contracts	Gas Marketing Operating Revenues	$	13,922		$	1,745		$	12,255		$	775
	Gas Marketing Operating Expenses	—			—			—			—
NYMEX/ICE natural gas contracts	Gas Marketing Operating Revenues	1,840			(1,679		)	3,830			(612		)
	Gas Marketing Operating Expenses	—			—			—			—
NYMEX gasoline and heating oil contracts	Other Income and (Income Deductions) - Net	(3		)	13			10			46
Total		$	15,759		$	79		$	16,095		$	209

* 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 March 31, 2014
	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	$	915		Derivative Instrument Assets	$	773
	Other Deferred Charges	207			Other Deferred Charges	1
NYMEX gasoline and heating oil contracts	Derivative Instrument Assets	49			Derivative Instrument Assets	—
Sub-total		1,171				774
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets	3,166			Derivative Instrument Assets	347
	Accounts Receivable – Other	4,467			Accounts Receivable – Other	3,811
	Other Deferred Charges	3			Other Deferred Charges	7
OTCBB natural gas contracts	Derivative Instrument Assets	6,266			Derivative Instrument Assets	193
	Other Deferred Credits	64			Other Deferred Credits	122
Natural gas commodity contracts	Derivative Instrument Assets	4,466			Derivative Instrument Assets	333
	Other Deferred Charges	1,326			Other Deferred Charges	17
	Other Current Liabilities	603			Other Current Liabilities	1,574
	Other Deferred Credits	231			Other Deferred Credits	1,394
Sub-total		20,592				7,798
Total derivatives		$	21,763			$	8,572
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 March 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	Accounts Receivable - Other	$	520	Accounts Receivable - Other	$	2,993
	Other Deferred Charges	5		Other Deferred Charges	—
NYMEX gasoline and heating oil contracts	Derivative Instrument Assets	312		Derivative Instrument Assets	—
Interest rate swaps	Other Current Liabilities	—		Other Current Liabilities	4,549
Sub-total		837			7,542
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets	10,862		Derivative Instrument Assets	339
	Accounts Receivable - Other	2		Accounts Receivable - Other	457
Natural gas commodity contracts	Derivative Instrument Assets	2,943		Derivative Instrument Assets	227
	Other Current Liabilities	62		Other Current Liabilities	787
NYMEX gasoline and heating oil contracts	Derivative Instrument Assets	10		Derivative Instrument Assets	—
Sub-total		13,879			1,810
Total derivatives		$	14,716		$	9,352

* 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)	March 31, 2014			September 30, 2013			March 31, 2013
Fair value of asset derivatives presented above	$	21,763		$	6,276		$	14,716
Fair value of cash margin receivables offset with derivatives	—			1,765			2,928
Netting of assets and liabilities with the same counterparty	(7,094		)	(4,739		)	(11,618		)
Total	$	14,669		$	3,302		$	6,026
Derivative Instrument Assets, per Consolidated Balance Sheets:
Derivative instrument assets	$	13,560		$	3,291		$	6,021
Other deferred charges	1,109			11			5
Total	$	14,669		$	3,302		$	6,026
Fair value of liability derivatives presented above	$	8,572		$	10,629		$	9,352
Fair value of cash margin payables offset with derivatives	655			6			7,540
Netting of assets and liabilities with the same counterparty	(7,094		)	(4,739		)	(11,618		)
Total	$	2,133		$	5,896		$	5,274
Derivative Instrument Liabilities, per Consolidated Balance Sheets:
Other Current Liabilities	$	1,196		$	4,400		$	5,274
Other Deferred Credits	937			1,496			—
Total	$	2,133		$	5,896		$	5,274

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CONCENTRATIONS OF CREDIT RISK (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014 counterparty
Concentration Risk [Line Items]
Number of large counterparties that are investment grade rated	4
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	$ 30.0
Net receivable amount	19.2
Utility Companies And Their Affiliates [Member]
Concentration Risk [Line Items]
Accounts receivable	33.3
Net receivable amount	30.3
Largest Counterparties [Member]
Concentration Risk [Line Items]
Accounts receivable	34.9
Net receivable amount	$ 27.2

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CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical)	Mar. 31, 2014	Sep. 30, 2013	Mar. 31, 2013
Capitalization:
Common Stock Shares Authorized (in shares)	70,000,000	70,000,000	70,000,000
Common Stock Shares Issued (in shares)	32,776,595	32,696,836	22,643,693

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STOCK-BASED COMPENSATION

6 Months Ended

Mar. 31, 2014

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 4 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 six months ended March 31, 2014, the Company granted 123,252 performance-contingent restricted stock units to executive officers and key employees at a weighted average grant date fair value of $37.20 per share. The number of stock units granted 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 six months ended March 31, 2014 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)	123,252		$	37.20
Vested	(52,954	)	$	32.16
Forfeited	(22,022	)	$	29.35
Nonvested at March 31, 2014	290,544		$	36.17

During the six months ended March 31, 2014, the Company granted 71,768 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 $45.65 per share. Of the 71,768 shares, 15,200 shares will vest on July 14, 2014, 12,168 shares vest on December 2, 2014, and the remaining 44,400 shares will vest during FY 2017. In the interim, participants receive full voting rights and dividends, which are not subject to forfeiture.

Time-vested restricted stock and stock unit activity for the six months ended March 31, 2014 is presented below:

	Restricted Stock/ Stock Units		Weighted Average Grant Date Fair Value
Nonvested at September 30, 2013	119,404		$	38.64
Granted	71,768		$	45.65
Vested	(17,999	)	$	36.37
Forfeited	(16,950	)	$	38.04
Nonvested at March 31, 2014	156,223		$	42.19

During the six months ended March 31, 2014, 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 six months ended March 31, 2014 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	(23,250	)	$	30.96
Forfeited	—		$	—
Expired	—		$	—
Outstanding at March 31, 2014	110,250		$	32.07	1.4	$	1,663
Fully Vested and Expected to Vest at March 31, 2014	110,250		$	32.07	1.4	$	1,663
Exercisable at March 31, 2014	110,250		$	32.07	1.4	$	1,663

The closing price of the Company’s common stock was $47.15 on March 31, 2014.

Equity Compensation Costs

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

	Three Months Ended   March 31,						Six Months Ended March 31,
(Thousands)	2014			2013			2014			2013
Total equity compensation cost	$	1,933		$	1,137		$	2,466		$	1,759
Compensation cost capitalized	(556		)	(356		)	(705		)	(539		)
Compensation cost recognized	$	1,377		$	781		$	1,761		$	1,220
Income tax benefit recognized	(527		)	(298		)	(674		)	(467		)

As of March 31, 2014, there was $9.8 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 2.2 years.

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

6 Months Ended

Mar. 31, 2014

Other Nonoperating Income (Expense) [Abstract]

Other Income and (Income Deductions) by Component

	Three Months Ended March 31,						Six Months Ended March 31,
(Thousands)	2014			2013			2014		2013
Interest income	$	142		$	257		$	391	$	663
Net investment gain (loss)	(612		)	1,174			135		1,104
Other income (deductions)	222			(91		)	875		657
Other Income and (Income Deductions) – Net	$	(248	)	$	1,340		$	1,401	$	2,424

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DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Part 1) (Details) (USD $)	3 Months Ended
	Mar. 31, 2014 gal MMBTU	Sep. 30, 2013	Mar. 31, 2013
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	$ 1,196,000	$ 4,400,000	$ 5,274,000
Gasoline futures contracts notional amount (in gallons)	400,000
Average price of gasoline futures contracts (dollars per gallon)	2.76
Notional amount of non-exchange traded natural gas commodity contracts (in MMBtu)	149,200,000
Notional amount of non-exchange traded natural gas commodity contracts to be settled during fiscal 2014 (in MMBtu)	79,200,000
Notional amount of non-exchange traded natural gas commodity contracts to be settled during fiscal 2015 (in MMBtu)	12,400,000
Notional amount of non-exchange traded natural gas commodity contracts to be settled during fiscal 2014 (in MMBtu)	30,200,000
Expected pre-tax unrealized gain (loss) reclassifications into the Statements of Consolidated Income during the twelve months	1,000,000
Notional amount of non-exchange traded natural gas commodity contracts to be settled during fiscal 2017 (in MMBtu)	11,000,000
Notional amount of non-exchange traded natural gas commodity contracts to be settled during fiscal 2018 (in MMBtu)	11,000,000
Notional amount of non-exchange traded natural gas commodity contracts to be settled during fiscal 2019 (in MMBtu)	5,400,000
Derivative instrument reconciliation [Abstract]
Fair value of asset derivatives presented above	21,763,000	6,276,000	14,716,000
Fair value of cash margin receivables offset with derivatives	0	1,765,000	2,928,000
Cash margin receivables not offset with derivatives	3,800,000	3,200,000	1,300,000
Netting of assets and liabilities with the same counterparty	(7,094,000)	(4,739,000)	(11,618,000)
Derivative Assets	14,669,000	3,302,000	6,026,000
Fair value of liability derivatives presented above	8,572,000	10,629,000	9,352,000
Payables to Broker-Dealers and Clearing Organizations	655,000	6,000	7,540,000
Derivative Instrument, per Consolidated Balance Sheets: [Abstract]
Derivative instrument assets	13,560,000	3,291,000	6,021,000
Other deferred charges derivative instruments	1,109,000	11,000	5,000
Derivative Assets	14,669,000	3,302,000	6,026,000
Other Current Liabilities	2,133,000	5,896,000	5,274,000
Netting of assets and liabilities with the same counterparty	(7,094,000)	(4,739,000)	(11,618,000)
Other Deferred Credits, Current	937,000	1,496,000	0
Laclede Gas Company [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	28,400,000
Laclede Energy Resources [Member] | Fiscal 2014 [Member] | Open Short Futures Positions [Member]
Derivative [Line Items]
Avg. Price Per MMBtu	4.38
Mmbtu	7,560,000
Laclede Energy Resources [Member] | Fiscal 2015 [Member] | Open Short Futures Positions [Member]
Derivative [Line Items]
Avg. Price Per MMBtu	4.46
Mmbtu	1,580,000
Laclede Energy Resources [Member] | Fiscal 2016 [Member] | Open Short Futures Positions [Member]
Derivative [Line Items]
Avg. Price Per MMBtu	4.22
Mmbtu	50,000
Designated as Hedging Instrument [Member]
Derivative instrument reconciliation [Abstract]
Fair value of asset derivatives presented above	1,171,000	2,349,000	837,000
Fair value of liability derivatives presented above	774,000	451,000	7,542,000
Not Designated as Hedging Instrument [Member]
Derivative instrument reconciliation [Abstract]
Fair value of asset derivatives presented above	20,592,000	3,927,000	13,879,000
Fair value of liability derivatives presented above	7,798,000	10,178,000	1,810,000
NYMEX Natural Gas Contracts [Member] | Laclede Gas Company [Member] | Fiscal 2014 [Member] | Open Long Futures Positions [Member]
Derivative [Line Items]
Avg. Price Per MMBtu	3.79
Mmbtu	3,800,000
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	4.23
Mmbtu	1,160,000
NYMEX Natural Gas Contracts [Member] | Laclede Energy Resources [Member] | Fiscal 2015 [Member] | Open Long Futures Positions [Member]
Derivative [Line Items]
Avg. Price Per MMBtu	4.35
Mmbtu	880,000
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 2014 [Member] | Open Short Futures Positions [Member]
Derivative [Line Items]
Avg. Price Per MMBtu	0.02
Mmbtu	4,860,000
ICE open basis swap positions [Member] | Laclede Energy Resources [Member] | Fiscal 2014 [Member] | Open Long Futures Positions [Member]
Derivative [Line Items]
Avg. Price Per MMBtu	0.39
Mmbtu	920,000
ICE open basis swap positions [Member] | Laclede Energy Resources [Member] | Fiscal 2015 [Member] | Open Short Futures Positions [Member]
Derivative [Line Items]
Avg. Price Per MMBtu	(0.09)
Mmbtu	620,000
ICE open basis swap positions [Member] | Laclede Energy Resources [Member] | Fiscal 2015 [Member] | Open Long Futures Positions [Member]
Derivative [Line Items]
Avg. Price Per MMBtu	0.39
Mmbtu	160,000
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	4.00
Mmbtu	9,530,000
OTCBB Natural Gas Contracts [Member] | Laclede Gas Company [Member] | Fiscal 2015 [Member] | Open Long Futures Positions [Member]
Derivative [Line Items]
Avg. Price Per MMBtu	4.21
Mmbtu	9,830,000
OTCBB Natural Gas Contracts [Member] | Laclede Gas Company [Member] | Fiscal 2016 [Member] | Open Long Futures Positions [Member]
Derivative [Line Items]
Avg. Price Per MMBtu	4.24
Mmbtu	550,000
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	4,466,000	991,000	2,943,000
Fair value of liability derivatives presented above	333,000	90,000	227,000
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	915,000
Fair value of liability derivatives presented above	773,000
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	3,166,000		2,000
Fair value of liability derivatives presented above	347,000		457,000
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	520,000
Fair value of liability derivatives presented above		440,000	2,993,000
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	4,467,000	1,434,000	10,862,000
Fair value of liability derivatives presented above	3,811,000	3,455,000	339,000
Accounts Receivable Other [Member] | NYMEX Gasoline and Heating Oil Contracts [Member] | Designated as Hedging Instrument [Member]
Derivative instrument reconciliation [Abstract]
Fair value of asset derivatives presented above	49,000	105,000	312,000
Fair value of liability derivatives presented above	0	0	0
Accounts Receivable Other [Member] | NYMEX Gasoline and Heating Oil Contracts [Member] | Not Designated as Hedging Instrument [Member]
Derivative instrument reconciliation [Abstract]
Fair value of asset derivatives presented above		228,000	10,000
Fair value of liability derivatives presented above		4,045,000	0
Accounts Receivable Other [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]
Derivative instrument reconciliation [Abstract]
Fair value of asset derivatives presented above			0
Fair value of liability derivatives presented above			4,549,000
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	1,326,000	20,000
Fair value of liability derivatives presented above	17,000	137,000
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	207,000	22,000	5,000
Fair value of liability derivatives presented above	1,000	11,000	0
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

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SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

6 Months Ended

Mar. 31, 2014

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 March 31, 2014 and 2013, for the Utility, were $77.1 million and $33.3 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 March 31, 2014 and 2013 were $34.3 million and $17.2 million, respectively. Amounts recorded in Gas Utility Operating Revenues for the six months ended March 31, 2014 and 2013 were $54.3 million and $27.5 million, respectively. Gross receipts taxes are expensed by the Utility and included in the Taxes, other than income taxes line.