10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 or 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Quarter Ended June 30, 2012

OR

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

Commission File Number 1-16681

THE LACLEDE GROUP, INC.

(Exact name of registrant as specified in its charter)

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

Indicate by check mark if the registrant:

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

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

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

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

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

As of July 26, 2012, there were 22,510,176 shares of the registrant’s Common Stock, par value $1.00 per share, outstanding.

TABLE OF CONTENTS			Page No.
PART I.  FINANCIAL INFORMATION
Item 1	Financial Statements:
		Statements of Consolidated Income	4
		Statements of Consolidated Comprehensive Income	5
		Consolidated Balance Sheets	6-7
		Statements of Consolidated Cash Flows	8
		Notes to Consolidated Financial Statements	9-28
Item 2	Management’s Discussion and Analysis of Financial Condition and
		Results of Operations	29-46
Item 3	Quantitative and Qualitative Disclosures About Market Risk		47
Item 4	Controls and Procedures		47
PART II.  OTHER INFORMATION
Item 1	Legal Proceedings		48
Item 1A	Risk Factors		48
Item 6	Exhibits		48
SIGNATURE			49
INDEX TO EXHIBITS			50

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. 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, 2011.

3

Item 1. Financial Statements

THE LACLEDE GROUP, INC.

STATEMENTS OF CONSOLIDATED INCOME

 (UNAUDITED)

	Three Months Ended				Nine Months Ended
	June 30,				June 30,
(Thousands, Except Per Share Amounts)		2012		2011		2012		2011
Operating Revenues:
Regulated Gas Distribution	$	116,459	$	151,423	$	665,981	$	817,241
Non-Regulated Gas Marketing		70,014		174,309		288,036		495,828
Other		376		18,549		1,920		19,192
Total Operating Revenues		186,849		344,281		955,937		1,332,261
Operating Expenses:
Regulated Gas Distribution
Natural and propane gas		46,641		76,632		364,556		510,703
Other operation expenses		32,639		36,930		108,247		111,292
Maintenance		5,712		5,932		16,781		18,513
Depreciation and amortization		10,186		9,856		30,450		29,233
Taxes, other than income taxes		10,842		12,332		45,602		52,766
Total Regulated Gas Distribution Operating Expenses		106,020		141,682		565,636		722,507
Non-Regulated Gas Marketing		65,420		168,580		279,784		484,235
Other		364		8,265		1,784		9,071
Total Operating Expenses		171,804		318,527		847,204		1,215,813
Operating Income		15,045		25,754		108,733		116,448
Other Income and (Income Deductions) – Net		451		157		3,771		2,469
Interest Charges:
Interest on long-term debt		5,739		5,739		17,218		17,421
Other interest charges		427		408		1,541		1,701
Total Interest Charges		6,166		6,147		18,759		19,122
Income Before Income Taxes		9,330		19,764		93,745		99,795
Income Tax Expense		897		4,374		30,454		33,143
Net Income	$	8,433	$	15,390	$	63,291	$	66,652
Weighted Average Number of Common Shares Outstanding:
Basic		22,282		22,120		22,243		22,087
Diluted		22,357		22,188		22,318		22,160
Basic Earnings Per Share of Common Stock	$	0.38	$	0.69	$	2.83	$	2.99
Diluted Earnings Per Share of Common Stock	$	0.38	$	0.69	$	2.82	$	2.98
Dividends Declared Per Share of Common Stock	$	0.415	$	0.405	$	1.245	$	1.215
See Notes to Consolidated Financial Statements.

4

THE LACLEDE GROUP, INC.

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

(UNAUDITED)

	Three Months Ended					Nine Months Ended
	June 30,					June 30,
(Thousands)		2012			2011		2012			2011
Net Income	$	8,433		$	15,390	$	63,291		$	66,652
Other Comprehensive Income (Loss), Before Tax:
Net gains (losses) on cash flow hedging derivative instruments:
Net hedging (loss) gain arising during the period		(1,733	)		710		6,420			1,884
Reclassification adjustment for (gains) losses included in
net income		(6,171	)		2,261		(8,593	)		(976	)
Net unrealized (losses) gains on cash flow hedging
derivative instruments		(7,904	)		2,971		(2,173	)		908
Defined benefit pension and other postretirement plans:
Net actuarial loss arising during the period		—			—		(2,366	)		—
Amortization of actuarial loss included in net periodic
pension and postretirement benefit cost		66			107		3,639			320
Net defined benefit pension and other postretirement plans		66			107		1,273			320
Other Comprehensive (Loss) Income, Before Tax		(7,838	)		3,078		(900	)		1,228
Income Tax (Benefit) Expense Related to Items of Other
Comprehensive (Loss) Income		(3,028	)		1,189		(348	)		474
Other Comprehensive (Loss) Income, Net of Tax		(4,810	)		1,889		(552	)		754
Comprehensive Income	$	3,623		$	17,279	$	62,739		$	67,406
See Notes to Consolidated Financial Statements.

5

THE LACLEDE GROUP, INC.

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	June 30,			Sept. 30,			June 30,
(Thousands)	2012			2011			2011
ASSETS
Utility Plant	$	1,455,004		$	1,386,590		$	1,362,780
Less:  Accumulated depreciation and amortization		474,008			457,907			455,075
Net Utility Plant		980,996			928,683			907,705
Non-utility property		5,899			4,588			4,597
Other investments		55,117			50,785			52,290
Other Property and Investments		61,016			55,373			56,887
Current Assets:
Cash and cash equivalents		21,523			43,277			60,922
Accounts receivable:
Utility		65,762			71,090			87,021
Non-utility		47,335			50,894			58,645
Other		22,927			12,572			6,233
Allowance for doubtful accounts		(8,842	)		(10,073	)		(11,915	)
Delayed customer billings		—			—			11,517
Inventories:
Natural gas stored underground		55,192			115,170			56,976
Propane gas		10,051			8,961			8,962
Materials and supplies at average cost		3,917			4,229			4,310
Natural gas receivable		19,710			30,689			29,767
Derivative instrument assets		3,879			7,759			10,127
Unamortized purchased gas adjustments		9,158			25,719			3,939
Deferred income taxes		—			—			9,064
Prepayments and other		11,079			8,847			9,082
Total Current Assets		261,691			369,134			344,650
Deferred Charges:
Regulatory assets		433,376			423,492			427,021
Other		4,259			6,400			6,041
Total Deferred Charges		437,635			429,892			433,062
Total Assets	$	1,741,338		$	1,783,082		$	1,742,304

6

THE LACLEDE GROUP, INC.

CONSOLIDATED BALANCE SHEETS (Continued)

(UNAUDITED)

	June 30,			Sept. 30,			June 30,
(Thousands, except share amounts)	2012			2011			2011
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock (70,000,000 shares authorized, 22,505,440,     22,430,734, and 22,416,923 shares issued, respectively)	$	22,505		$	22,431		$	22,417
Paid-in capital		166,717			163,702			162,309
Retained earnings		424,588			389,298			401,208
Accumulated other comprehensive loss		(2,652	)		(2,100	)		(6,383	)
Total Common Stock Equity		611,158			573,331			579,551
Long-term debt (less current portion) – Laclede Gas		339,401			364,357			364,343
Total Capitalization		950,559			937,688			943,894
Current Liabilities:
Notes payable		—			46,000			—
Accounts payable		81,322			96,561			101,782
Advance customer billings		6,225			15,230			—
Current portion of long-term debt		25,000			—			—
Wages and compensation accrued		12,653			13,650			14,866
Dividends payable		9,664			9,359			9,280
Customer deposits		9,123			10,048			10,914
Interest accrued		5,405			8,812			5,603
Taxes accrued		13,040			11,901			29,091
Deferred income taxes		311			8,405			—
Other		16,540			11,968			13,958
Total Current Liabilities		179,283			231,934			185,494
Deferred Credits and Other Liabilities:
Deferred income taxes		335,366			315,405			305,374
Unamortized investment tax credits		3,166			3,326			3,379
Pension and postretirement benefit costs		158,011			185,701			196,757
Asset retirement obligations		28,723			27,495			26,996
Regulatory liabilities		53,867			50,846			50,308
Other		32,363			30,687			30,102
Total Deferred Credits and Other Liabilities		611,496			613,460			612,916
Commitments and Contingencies (Note 11)
Total Capitalization and Liabilities	$	1,741,338		$	1,783,082		$	1,742,304
See Notes to Consolidated Financial Statements.

7

THE LACLEDE GROUP, INC.

STATEMENTS OF CONSOLIDATED CASH FLOWS

(UNAUDITED)

	Nine Months Ended
	June 30,
(Thousands)	2012			2011
Operating Activities:
Net Income	$	63,291		$	66,652
Adjustments to reconcile net income to net cash provided by (used in)       operating activities:
Depreciation, amortization, and accretion		30,900			29,624
Deferred income taxes and investment tax credits		22,448			5,946
Other – net		(425	)		1,145
Changes in assets and liabilities:
Accounts receivable – net		(2,699	)		(12,395	)
Unamortized purchased gas adjustments		16,561			19,779
Deferred purchased gas costs		(25,429	)		48,752
Accounts payable		(15,025	)		7,853
Delayed customer billings — net		(9,005	)		(28,326	)
Taxes accrued		568			18,577
Natural gas stored underground		59,978			56,600
Other assets and liabilities		(12,964	)		(12,901	)
Net cash provided by operating activities		128,199			201,306
Investing Activities:
Capital expenditures		(76,780	)		(47,082	)
Other investments		(1,388	)		102
Net cash used in investing activities		(78,168	)		(46,980	)
Financing Activities:
Maturity of first mortgage bonds		—			(25,000	)
Repayment of short-term debt – net		(46,000	)		(129,650	)
Changes in book overdrafts		223			474
Issuance of common stock		3,162			2,021
Non-employee directors’ restricted stock awards		(565	)		(494	)
Dividends paid		(27,599	)		(26,808	)
Employees’ taxes paid associated with restricted shares withheld upon vesting		(1,171	)		(1,162	)
Excess tax benefits from stock-based compensation		208			294
Other		(43	)		2
Net cash used in financing activities		(71,785	)		(180,323	)
Net Decrease in Cash and Cash Equivalents		(21,754	)		(25,997	)
Cash and Cash Equivalents at Beginning of Period		43,277			86,919
Cash and Cash Equivalents at End of Period	$	21,523		$	60,922
Supplemental Disclosure of Cash Paid During the Period for:
Interest	$	21,811		$	22,588
Income taxes		7,064			4,609
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 2011 Form 10-K.

The consolidated financial position, results of operations, and cash flows of Laclede Group are comprised primarily from the financial position, results of operations, and cash flowsof Laclede Gas Company (Laclede Gas or the Utility). Laclede Gas is a regulated natural gas distribution utility having a material seasonal cycle. As a result, these interim statements of income for Laclede Group are not necessarily indicative of annual results or representative of succeeding quarters of the fiscal year. Due to the seasonal nature of the business of Laclede Gas, earnings are typically concentrated in the November through April period, which generally corresponds with the heating season. Laclede Energy Resources, Inc. (LER) includes its wholly owned subsidiary, LER Storage Services, Inc., which was formed in October 2011 and became operational on January 1, 2012.

BASIS OF CONSOLIDATION - The consolidated financial statements include the accounts of Laclede Group and its subsidiary companies. All subsidiaries are wholly owned. Laclede Gas and other subsidiaries of Laclede Group may engage in related party transactions during the ordinary course of business. All material intercompany balances have been eliminated from the consolidated financial statements of Laclede Group. These transactions include sales of natural gas from Laclede Gas to LER, sales of natural gas from LER to Laclede Gas, and transportation services provided by Laclede Pipeline Company to Laclede Gas. These revenues are shown on the Intersegment revenues lines in the table included in Note 10 under Regulated Gas Distribution, Non-Regulated Gas Marketing, and Other columns, respectively.

NATURAL GAS STORED UNDERGROUND AND PROPANE GAS - For the Regulated Gas Distribution operating segment, inventory of Utility natural gas in storage is priced on a last-in, first-out (LIFO) basis and inventory of Utility propane gas in storage is priced on a first-in, first-out (FIFO) basis. The carrying value of Utility inventory is not adjusted to the lower of cost or market prices because, pursuant to the Laclede Gas Purchased Gas Adjustment (PGA) Clause, actual gas costs are recovered in customer rates. Natural gas and propane gas storage inventory in Laclede Group’s other operating segments is recorded at the lower of average cost or market.

REVENUE RECOGNITION - Laclede Gas reads meters and bills its customers on monthly cycles. The Utility records its regulated gas distribution revenues from gas sales and transportation services on an accrual basis that includes estimated amounts for gas delivered, but not yet billed. The accruals for unbilled revenues are reversed in the subsequent accounting period when meters are actually read and customers are billed. The amounts of accrued unbilled revenues at June 30, 2012 and 2011, for the Utility, were $9.0 million and $9.6 million, respectively. The amount of accrued unbilled revenue at September 30, 2011 was $11.8 million.

In the course of its business, LER enters into commitments associated with the purchase or sale of natural gas. Certain of LER’s derivative natural gas contracts are designated as normal purchases or normal sales, and, as such, are excluded from the scope of ASC Topic 815, “Derivatives and Hedging.” As such, those contracts are accounted for as executory contracts and recorded on an accrual basis. Revenues and expenses from such contracts are recorded using a gross presentation. Contracts not designated as normal purchases or normal sales are recorded as derivatives with changes in fair value (representing unrealized gains and losses) recognized in earnings in the periods prior to physical delivery. For additional information on derivative instruments, refer to Note 7, Derivative Instruments and Hedging Activities. Certain of LER’s wholesale purchase and sale transactions entered on or after January 1, 2012 are classified as trading activities for financial reporting purposes rather than elected for normal purchases or normal sales designations. Under generally accepted accounting principles (GAAP), revenues and expenses associated with trading activities are presented on a net basis in Non-Regulated Gas Marketing Operating Revenues in the Statements of Consolidated Income. This net presentation has no effect on operating income or net income.

GROSS RECEIPTS TAXES - Gross receipts taxes associated with Laclede Gas’ natural gas utility service are imposed on the Utility and billed to its customers. These amounts are recorded gross in the Statements of Consolidated Income. Amounts recorded in Regulated Gas Distribution Operating Revenues for the quarters ended June 30, 2012 and 2011 were $5.7 million and $7.5 million, respectively. Amounts recorded in Regulated Gas Distribution Operating Revenues for the nine months ended June 30, 2012 and 2011 were $31.4 million and $39.1 million, respectively. Gross receipts taxes are expensed by the Utility and included in the Taxes, other than income taxes line.

9

NEW ACCOUNTING STANDARDS - In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-04, “Amendments to Achieve Common Fair Value Measurement Disclosure Requirements in U.S. GAAP and IFRSs.” This ASU amends Accounting Standards Codification (ASC) Topic 820, “Fair Value Measurements and Disclosures,” to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and International Financial Reporting Standards (IFRS). The ASU does not change what items are measured at fair value, but instead makes various changes to the guidance pertaining to how fair value is measured. Additionally, the ASU sets forth additional disclosure requirements, including additional information about Level 3 fair value measurements. Many of the amendments in this ASU are changes to align the wording in U.S. GAAP with IFRS and, as such, are not intended to result in a change in the application of the guidance. The Company’s adoption of the guidance in this ASU on a prospective basis in the second quarter of fiscal year 2012 had no impact on its financial condition or results of operations, but certain additional disclosures have been presented as required.

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

In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities,” to amend ASC Topic 210, “Balance Sheet,” to require additional disclosures about financial instruments and derivative instruments that have been presented on a net basis (offset) in the balance sheet. Additionally, information about financial instruments and derivative instruments that are subject to enforceable master netting arrangements or similar agreements, irrespective of whether they are presented net in the balance sheet, is required to be disclosed. The ASU impacts disclosures only and will not require any changes to financial statement presentation. The Company will present the new disclosures retrospectively beginning in the first quarter of fiscal year 2014.

2. PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS

Pension Plans

Laclede Gas has non-contributory, defined benefit, trusteed forms of pension plans covering substantially all employees. Plan assets consist primarily of corporate and U.S. government obligations and equity market exposure achieved through derivative instruments.

Pension costs for the quarters ended June 30, 2012 and 2011 were $4.1 million and $4.2 million, respectively, including amounts charged to construction. Pension costs for the nine months ended June 30, 2012 and 2011 were $15.9 million and $10.0 million, respectively, including amounts charged to construction.

The net periodic pension costs include the following components:

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
(Thousands)	2012			2011			2012			2011
Service cost – benefits earned during the period	$	2,295		$	2,388		$	6,908		$	7,164
Interest cost on projected benefit obligation		4,824			4,705			14,535			14,115
Expected return on plan assets		(4,899	)		(4,712	)		(14,697	)		(14,136	)
Amortization of prior service cost		148			161			444			481
Amortization of actuarial loss		2,252			2,557			6,788			7,671
Loss on lump-sum settlement		—			—			3,407			—
Sub-total		4,620			5,099			17,385			15,295
Regulatory adjustment		(484	)		(864	)		(1,451	)		(5,259	)
Net pension cost	$	4,136		$	4,235		$	15,934		$	10,036

10

Pursuant to the provisions of the Laclede Gas pension plans, pension obligations may be satisfied by lump-sum cash payments. Pursuant to a Missouri Public Service Commission (MoPSC or Commission) Order, lump-sum payments are recognized as settlements (which can result in gains or losses) only if the total of such payments exceeds 100% of the sum of service and interest costs. Lump-sum payments recognized as settlements were $6.4 million during the nine months ended June 30, 2012. No lump-sum payments were recognized as settlements during the nine months ended June 30, 2011.

Pursuant to a MoPSC Order, the return on plan assets is based on the market-related value of plan assets implemented prospectively over a four-year period. Gains or losses not yet includible in pension cost are amortized only to the extent that such gain or loss exceeds 10% of the greater of the projected benefit obligation or the market-related value of plan assets. Such excess is amortized over the average remaining service life of active participants. The recovery in rates for the Utility’s qualified pension plans is based on an annual allowance of $4.8 million effective August 1, 2007 and $15.5 million effective January 1, 2011. The difference between these amounts and pension expense as calculated pursuant to the above and that otherwise would be included in the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income is deferred as a regulatory asset or regulatory liability.

The funding policy of Laclede Gas is to contribute an amount not less than the minimum required by government funding standards, nor more than the maximum deductible amount for federal income tax purposes. Fiscal year 2012 contributions to the pension plans through June 30, 2012 were $33.3 million to the qualified trusts and approximately $2.0 million to the non-qualified plans. Laclede Gas does not expect to make contributions to its qualified, trusteed pension plans during the remaining three months of fiscal year 2012. Contributions to the pension plans for the non-qualified plans for the remaining three months of fiscal year 2012 are anticipated to be approximately $4.7 million.

Postretirement Benefits

Laclede Gas provides certain life insurance benefits at retirement. Medical insurance is available after early retirement until age 65. The transition obligation not yet includible in postretirement benefit cost is being amortized over 20 years. Postretirement benefit costs for both the quarters ended June 30, 2012 and 2011 were $2.4 million, including amounts charged to construction. Postretirement benefit costs for the nine months ended June 30, 2012 and 2011 were $7.1 million and $6.7 million, respectively, including amounts charged to construction.

Net periodic postretirement benefit costs consisted of the following components:

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
(Thousands)	2012			2011			2012			2011
Service cost – benefits earned during the period	$	2,015		$	1,919		$	6,045		$	5,757
Interest cost on accumulated
postretirement benefit obligation		1,380			1,210			4,140			3,632
Expected return on plan assets		(991	)		(911	)		(2,973	)		(2,734	)
Amortization of transition obligation		34			34			102			102
Amortization of prior service credit		(518	)		(582	)		(1,554	)		(1,746	)
Amortization of actuarial loss		1,065			1,111			3,195			3,332
Sub-total		2,985			2,781			8,955			8,343
Regulatory adjustment		(604	)		(400	)		(1,812	)		(1,671	)
Net postretirement benefit cost	$	2,381		$	2,381		$	7,143		$	6,672

Missouri state law provides for the recovery in rates of costs accrued pursuant to GAAP provided that such costs are funded through an independent, external funding mechanism. Laclede Gas established Voluntary Employees’ Beneficiary Association (VEBA) and Rabbi trusts as its external funding mechanisms. VEBA and Rabbi trusts’ assets consist primarily of money market securities and mutual funds invested in stocks and bonds.

11

Pursuant to a MoPSC Order, the return on plan assets is based on the market-related value of plan assets implemented prospectively over a four-year period. Gains and losses not yet includible in postretirement benefit cost are amortized only to the extent that such gain or loss exceeds 10% of the greater of the accumulated postretirement benefit obligation or the market-related value of plan assets. Such excess is amortized over the average remaining service life of active participants. The recovery in rates for the Utility’s postretirement benefit plans is based on an annual allowance of $7.6 million effective August 1, 2007 and $9.5 million effective January 1, 2011. The difference between these amounts and postretirement benefit cost based on the above and that otherwise would be included in the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income is deferred as a regulatory asset or regulatory liability.

Laclede Gas’ funding policy is to contribute amounts to the trusts equal to the periodic benefit cost calculated pursuant to GAAP as recovered in rates. Fiscal year 2012 contributions to the postretirement plans through June 30, 2012 were $6.0 million to the qualified trusts and approximately $0.1 million paid directly to participants from Laclede Gas’ funds. Contributions to the postretirement plans for the remaining three months of fiscal year 2012 are anticipated to be $6.0 million to the qualified trusts and $0.1 million paid directly to participants from Laclede Gas’ funds.

3. STOCK-BASED COMPENSATION

Awards of stock-based compensation are made pursuant to The Laclede Group 2006 Equity Incentive Plan (2006 Plan) and the Restricted Stock Plan for Non-Employee Directors. Refer to Note 3 of the Consolidated Financial Statements included in the Company’s Form 10-K for the fiscal year ended September 30, 2011 for descriptions of these plans. In January 2012, shareholders approved certain amendments to the 2006 Plan, including an amendment allowing members of the Company’s Board of Directors to participate in the 2006 Plan. Accordingly, effective February 1, 2012, no additional awards will be granted under the Restricted Stock Plan for Non-Employee Directors, as any such awards will be made pursuant to the 2006 Plan.

Restricted Stock Awards

During the nine months ended June 30, 2012, the Company granted 103,763 performance-contingent restricted share units to executive officers and key employees at a weighted average grant date fair value of $36.55 per share. This number represents the maximum shares that can be earned pursuant to the terms of the awards. The share units have a performance period ending September 30, 2014. While the participants have no interim voting rights on these share units, dividends accrue during the performance period and are paid to the participants upon vesting, but are subject to forfeiture if the underlying shares units do not vest. The number of share units that will ultimately vest is dependent upon the attainment of certain levels of earnings and other strategic goals, as well as the Company’s level of total shareholder return (TSR) during the performance period relative to a comparator group of companies. This TSR provision is considered a market condition under GAAP.

Activity of restricted stock and restricted stock units subject to performance and/or market conditions during the nine months ended June 30, 2012 is presented below:

			Weighted
			Average
	Shares/		Grant Date
	Units		Fair Value
Nonvested at September 30, 2011	259,075			$	34.29
Granted (maximum shares that can be earned)	103,763			$	36.55
Vested	(48,429	)		$	48.70
Forfeited	(82,006	)		$	38.27
Nonvested at June 30, 2012	232,403			$	30.89

During the nine months ended June 30, 2012, the Company granted 30,475 shares of time-vested restricted stock to executive officers and key employees at a weighted average grant date fair value of $39.72 per share. These shares were awarded on December 1, 2011 and May 1, 2012 and vest December 1, 2014 and May 1, 2015, respectively. In the interim, participants receive full voting rights and dividends, which are not subject to forfeiture.

12

In January 2012, the Company granted 13,700 shares of time-vested restricted stock to non-employee directors at a weighted average grant date fair value of $41.36 per share. These shares were granted under the Restricted Stock Plan for Non-Employee Directors and vest depending on the participant’s age upon entering the plan and years of service as a director. The plan’s trustee acquires the shares for the awards in the open market and holds the shares as trustee for the benefit of the non-employee directors until the restrictions expire. In the interim, the participants receive full dividends and voting rights. As discussed above, effective February 1, 2012, any awards to non-employee directors will be made pursuant to The Laclede Group 2006 Equity Incentive Plan.

Time-vested restricted stock and stock unit activity for the nine months ended June 30, 2012 is presented below:

			Weighted
			Average
	Shares/		Grant Date
	Units		Fair Value
Nonvested at September 30, 2011	143,350			$	37.00
Granted	44,175			$	40.23
Vested	(54,800	)		$	41.46
Forfeited	(15,300	)		$	33.87
Nonvested at June 30, 2012	117,425			$	36.54

During the nine months ended June 30, 2012, 88,529 shares of restricted stock and stock units (performance-contingent and time-vested), awarded on February 14, 2008, November 5, 2008, and March 31, 2009, vested. The Company withheld 29,303 of the vested shares at a weighted average price of $39.96 per share pursuant to elections by employees to satisfy tax withholding obligations.

Stock Option Awards

Stock option activity for the nine months ended June 30, 2012 is presented below:

					Weighted
					Average
			Weighted		Remaining	Aggregate
			Average		Contractual	Intrinsic
	Stock		Exercise		Term	Value
	Options		Price		(Years)	($000)
Outstanding at September 30, 2011	305,875		$	30.72
Granted	—		$	—
Exercised	(57,375	)	$	31.07
Forfeited	—		$	—
Expired	—		$	—
Outstanding at June 30, 2012	248,500		$	30.65	2.5	$	2,277
Fully Vested and Expected to Vest at June 30, 2012	248,500		$	30.65	2.5	$	2,277
Exercisable at June 30, 2012	248,500		$	30.65	2.5	$	2,277

The closing price of the Company’s common stock was $39.81 at June 30, 2012.

13

Equity Compensation Costs

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

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
(Thousands)	2012			2011			2012			2011
Total equity compensation cost	$	678		$	1,555		$	2,029		$	3,095
Compensation cost capitalized		(230	)		(371	)		(589	)		(702	)
Compensation cost recognized in net income		448			1,184			1,440			2,393
Income tax benefit recognized in net income		(173	)		(457	)		(556	)		(923	)
Compensation cost recognized in net income,
net of income tax	$	275		$	727		$	884		$	1,470

As of June 30, 2012, there was $4.8 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 2.3 years.

4. EARNINGS PER COMMON SHARE

	Three Months Ended				Nine Months Ended
	June 30,				June 30,
(Thousands, Except Per Share Amounts)		2012		2011		2012		2011
Basic EPS:
Net Income	$	8,433	$	15,390	$	63,291	$	66,652
Less: Income allocated to participating securities		42		125		356		552
Net Income Available to Common Shareholders	$	8,391	$	15,265	$	62,935	$	66,100
Weighted Average Shares Outstanding		22,282		22,120		22,243		22,087
Earnings Per Share of Common Stock	$	0.38	$	0.69	$	2.83	$	2.99
Diluted EPS:
Net Income	$	8,433	$	15,390	$	63,291	$	66,652
Less: Income allocated to participating securities		42		125		355		551
Net Income Available to Common Shareholders	$	8,391	$	15,265	$	62,936	$	66,101
Weighted Average Shares Outstanding		22,282		22,120		22,243		22,087
Dilutive Effect of Stock Options
and Restricted Stock		75		68		75		73
Weighted Average Diluted Shares		22,357		22,188		22,318		22,160
Earnings Per Share of Common Stock	$	0.38	$	0.69	$	2.82	$	2.98
Outstanding Shares Excluded from the
Calculation of Diluted EPS Attributable to:
Restricted stock and stock units subject to
performance and/or market conditions		204		193		202		193

14

5. 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 (a)
(Thousands)	Carrying Amount		Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
As of June 30, 2012
Cash and cash equivalents	$	21,523	$	21,523	$	11,560	$	9,963	$	—
Short-term debt		—		—		—		—		—
Long-term debt, including current portion		364,401		445,961		—		445,961		—
As of September 30, 2011
Cash and cash equivalents	$	43,277	$	43,277
Short-term debt		46,000		46,000
Long-term debt		364,357		443,739
As of June 30, 2011
Cash and cash equivalents	$	60,922	$	60,922
Short-term debt		—		—
Long-term debt		364,343		397,684
(a) The Company adopted the provisions of ASU 2011-04 (ASC Topic 820) in the second quarter of fiscal year 2012 on a prospective basis. Accordingly, disclosures for prior periods are not required to be presented.

The carrying amounts for cash and cash equivalents and short-term debt approximate fair value due to the short maturity of these instruments. The fair values of long-term debt are estimated based on market prices for similar issues. Refer to Note 6, Fair Value Measurements, for information on financial instruments measured at fair value on a recurring basis.

15

6. FAIR VALUE MEASUREMENTS

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

(Thousands)		Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Effects of Netting and Cash Margin Receivables /Payables			Total
As of June 30, 2012
Assets
U. S. Stock/Bond Mutual Funds	$	17,535	$	—	$	—	$	—		$	17,535
NYMEX/ICE natural gas contracts		3,273		1,240		—		(4,513	)		—
NYMEX gasoline and heating
oil contracts		107		—		—		(107	)		—
Natural gas commodity contracts		—		4,288		107		(516	)		3,879
Total	$	20,915	$	5,528	$	107	$	(5,136	)	$	21,414
Liabilities
NYMEX/ICE natural gas contracts	$	22,141	$	1,590	$	—	$	(23,731	)	$	—
Natural gas commodity contracts		—		587		—		(516	)		71
Total	$	22,141	$	2,177	$	—	$	(24,247	)	$	71
As of September 30, 2011
Assets
U. S. Stock/Bond Mutual Funds	$	14,833	$	—	$	—	$	—		$	14,833
NYMEX/ICE natural gas contracts		4,856		—		—		1,975			6,831
NYMEX gasoline and heating
oil contracts		19		—		—		162			181
Natural gas commodity contracts		—		2,018		66		(108	)		1,976
Total	$	19,708	$	2,018	$	66	$	2,029		$	23,821
Liabilities
NYMEX/ICE natural gas contracts	$	20,928	$	—	$	—	$	(20,928	)	$	—
NYMEX gasoline and heating
oil contracts		124		—		—		(124	)		—
Natural gas commodity contracts		—		109		53		(108	)		54
Total	$	21,052	$	109	$	53	$	(21,160	)	$	54

16

(Thousands)		Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Effects of Netting and Cash Margin Receivables /Payables			Total
As of June 30, 2011
Assets
U. S. Stock/Bond Mutual Funds	$	16,096	$	—	$	—	$	—		$	16,096
NYMEX/ICE natural gas contracts		2,956		—		—		5,609			8,565
NYMEX gasoline and heating
oil contracts		143		—		—		164			307
Natural gas commodity contracts		—		2,150		7		(113	)		2,044
Total	$	19,195	$	2,150	$	7	$	5,660		$	27,012
Liabilities
NYMEX/ICE natural gas contracts	$	19,513	$	—	$	—	$	(19,513	)	$	—
NYMEX gasoline and heating
oil contracts		4		—		—		(4	)		—
Natural gas commodity contracts		—		138		5		(113	)		30
Total	$	19,517	$	138	$	5	$	(19,630	)	$	30

The mutual funds included in Level 1 are valued based on exchange-quoted market prices of identical securities. Derivative instruments included in Level 1 are valued using quoted market prices on the New York Mercantile Exchange (NYMEX). Derivative instruments classified in Level 2 include physical commodity derivatives that are valued using broker or dealer quotation services whose prices are derived principally from, or are corroborated by, observable market inputs. Also included in Level 2 are certain derivative instruments that have values that are similar to, and correlate with, quoted prices for exchange-traded instruments in active markets. Derivative instruments included in Level 3 are valued using generally unobservable inputs that are based upon the best information available and reflect management’s assumptions about how market participants would price the asset or liability. The Company’s policy is to recognize transfers between the levels of the fair value hierarchy, if any, as of the beginning of the interim reporting period in which circumstances change or events occur to cause the transfer. The following is a reconciliation of the Level 3 beginning and ending net derivative balances:

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
(Thousands)	2012			2011			2012			2011
Beginning of period	$	58		$	24		$	13		$	23
Settlements		(9	)		(33	)		(16	)		(85	)
Net losses related to derivatives not held   at end of period		(8	)		—			(68	)		(78	)
Net gains related to derivatives still held   at end of period		66			11			178			142
End of period	$	107		$	2		$	107		$	2

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 7, Derivative Instruments and Hedging Activities.

17

7. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Laclede Gas has a risk management policy that allows for the purchase of natural gas derivative instruments with the goal of managing price risk associated with purchasing natural gas on behalf of its customers. This policy prohibits speculation and permits the Utility to hedge up to 70% of its normal volumes purchased for up to a 36-month period. Costs and cost reductions, including carrying costs, associated with the Utility’s use of natural gas derivative instruments are allowed to be passed on to the Utility’s customers through the operation of its PGA Clause, through which the MoPSC allows the Utility to recover gas supply costs, subject to prudence review by the MoPSC. Accordingly, Laclede Gas does not expect any adverse earnings impact as a result of the use of these derivative instruments. The Utility does not designate these instruments as hedging instruments for financial reporting purposes because gains or losses associated with the use of these derivative instruments are deferred and recorded as regulatory assets or regulatory liabilities pursuant to ASC Topic 980, “Regulated Operations,” and, as a result, have no direct impact on the Statements of Consolidated Income. The timing of the operation of the PGA Clause may cause interim variations in short-term cash flows, because the Utility is subject to cash margin requirements associated with changes in the values of these instruments. Nevertheless, carrying costs associated with such requirements are recovered through the PGA Clause.

From time to time, Laclede Gas purchases NYMEX futures and options contracts to help stabilize operating costs associated with forecasted purchases of gasoline and diesel fuels used to power vehicles and equipment used in the course of its business. At June 30, 2012, Laclede Gas held 0.8 million gallons of gasoline futures contracts at an average price of $2.27 per gallon and 0.5 million gallons of gasoline options contracts. Most of these contracts, the longest of which extends to April 2014, are designated as cash flow hedges of forecasted transactions pursuant to ASC Topic 815. The gains or losses on these derivative instruments are not subject to the Utility’s PGA Clause.

In the course of its business, Laclede Group’s non-regulated gas marketing subsidiary, Laclede Energy Resources, Inc. (LER), which includes its wholly owned subsidiary LER Storage Services, Inc., enters into commitments associated with the purchase or sale of natural gas. Certain of LER’s derivative natural gas contracts are designated as normal purchases or normal sales and, as such, are excluded from the scope of ASC Topic 815 and are accounted for as executory contracts on an accrual basis. Any of LER’s derivative natural gas contracts that are not designated as normal purchases or normal sales are accounted for at fair value. At June 30, 2012, the fair values of 58.5 million MMBtu of non-exchange traded natural gas commodity contracts were reflected in the Consolidated Balance Sheet. Of these contracts, 34.6 million MMBtu will settle during fiscal year 2012, while the remaining 23.9 million MMBtu will settle during fiscal year 2013. These contracts have not been designated as hedges; therefore, changes in the fair value of these contracts are reported in earnings each period. Furthermore, LER manages the price risk associated with its fixed-priced commitments by either closely matching the offsetting physical purchase or sale of natural gas at fixed prices or through the use of NYMEX or Ice Clear Europe (ICE) futures, swap, and option contracts to lock in margins. At June 30, 2012, LER’s unmatched fixed-price positions were not material to Laclede Group’s financial position or results of operations. LER’s NYMEX and ICE natural gas futures, swap, and option contracts used to lock in margins may be designated as cash flow hedges of forecasted transactions for financial reporting purposes.

Derivative instruments designated as cash flow hedges of forecasted transactions are recognized on the Consolidated Balance Sheets at fair value and the change in the fair value of the effective portion of these hedge instruments is recorded, net of tax, in other comprehensive income (OCI). Accumulated other comprehensive income (AOCI) is a component of Total Common Stock Equity. Amounts are reclassified from AOCI into earnings when the hedged items affect net income, using the same revenue or expense category that the hedged item impacts. Based on market prices at June 30, 2012, it is expected that approximately $1.6 million of pre-tax unrealized losses 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 Company’s exchange-traded/cleared derivative instruments consist primarily of NYMEX and ICE positions. The NYMEX is the primary national commodities exchange on which natural gas derivatives are traded. Open NYMEX/ICE natural gas futures and swap positions at June 30, 2012 were as follows:

18

	Laclede Gas Company			Laclede Energy Resources, Inc.
	MMBtu (millions)	Avg. Price Per MMBtu		MMBtu (millions)	Avg. Price Per MMBtu
Open short futures positions
Fiscal 2012	—	$	—	3.34	$	2.90
Fiscal 2013	—		—	11.84		3.14
Open long futures positions
Fiscal 2012	4.29	$	4.26	0.91	$	3.29
Fiscal 2013	25.87		4.04	1.69		3.76
Fiscal 2014	1.87		3.45	0.10		4.34

At June 30, 2012, Laclede Gas and LER also had 6.6 million MMBtu and 6.0 million MMBtu, respectively, of other price mitigation in place through the use of NYMEX natural gas option-based strategies.

19

The Effect of Derivative Instruments on the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income
		Three Months Ended						Nine Months Ended
	Location of Gain (Loss)	June 30,						June 30,
(Thousands)	Recorded in Income		2012			2011			2012			2011
Derivatives in Cash Flow Hedging Relationships
Effective portion of gain (loss) recognized in OCI on derivatives:
NYMEX/ICE natural gas contracts		$	(1,802	)	$	701		$	6,218		$	1,435
NYMEX gasoline and heating oil contracts			69			9			202			449
Total		$	(1,733	)	$	710		$	6,420		$	1,884
Effective portion of gain (loss) reclassified from AOCI to income:
NYMEX/ICE natural gas contracts	Non-Regulated Gas Marketing Operating Revenues	$	7,646		$	782		$	18,434		$	6,373
	Non-Regulated Gas Marketing Operating Expenses		(1,492	)		(3,239	)		(9,861	)		(5,714	)
Sub-total			6,154			(2,457	)		8,573			659
NYMEX gasoline and heating oil contracts	Regulated Gas Distribution Other Operation Expenses		17			196			20			317
Total		$	6,171		$	(2,261	)	$	8,593		$	976
Ineffective portion of gain (loss) on derivatives recognized in income:
NYMEX/ICE natural gas contracts	Non-Regulated Gas Marketing Operating Revenues	$	(84	)	$	(10	)	$	(15	)	$	550
	Non-Regulated Gas Marketing Operating Expenses		(95	)		(371	)		(291	)		(994	)
Sub-total			(179	)		(381	)		(306	)		(444	)
NYMEX gasoline and heating oil contracts	Regulated Gas Distribution Other Operation Expenses		(46	)		(13	)		(12	)		35
Total		$	(225	)	$	(394	)	$	(318	)	$	(409	)
Derivatives Not Designated as Hedging Instruments *
Gain (loss) recognized in income on derivatives:
Natural gas commodity contracts	Non-Regulated Gas Marketing Operating Revenues	$	2,641		$	(300	)	$	3,431		$	(599	)
	Non-Regulated Gas Marketing Operating Expenses		—			1,927			687			3,123
NYMEX/ICE natural gas contracts	Non-Regulated Gas Marketing Operating Revenues		(1,123	)		(7	)		425			(85	)
	Non-Regulated Gas Marketing Operating Expenses		(655	)		—			(625	)		—
NYMEX gasoline and heating oil contracts	Other Income and (Income Deductions) - Net		(11	)		(19	)		2			44
Total		$	852		$	1,601		$	3,920		$	2,483

* 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 Regulated Gas Distribution Natural and Propane Gas operating expenses when they are recovered through the PGA Clause and reflected in customer billings.

20

Fair Value of Derivative Instruments in the Consolidated Balance Sheet at June 30, 2012
	Asset Derivatives				Liability Derivatives
(Thousands)	Balance Sheet Location		Fair Value	*	Balance Sheet Location		Fair  Value	*
Derivatives designated as hedging instruments
NYMEX/ICE natural gas contracts	Accounts Receivable – Other	$	1,064		Accounts Receivable – Other	$	2,529
NYMEX gasoline and heating oil contracts	Accounts Receivable – Other		106		Accounts Receivable - Other		—
Sub-total			1,170				2,529
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Accounts Receivable - Other		3,449		Accounts Receivable - Other		21,202
Natural gas commodity contracts	Derivative Instrument Assets		4,356		Derivative Instrument Assets		478
	Other Current Liabilities		39		Other Current Liabilities		109
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other		1		Accounts Receivable - Other		—
Sub-total			7,845				21,789
Total derivatives		$	9,015			$	24,318
Fair Value of Derivative Instruments in the Consolidated Balance Sheet at September 30, 2011
	Asset Derivatives				Liability Derivatives
(Thousands)	Balance Sheet Location		Fair Value	*	Balance Sheet Location		Fair Value	*
Derivatives designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets	$	4,395		Derivative Instrument Assets	$	4,105
	Other Deferred Charges		4		Other Deferred Charges		85
NYMEX gasoline and heating oil contracts	Derivative Instrument Assets		15		Derivative Instrument Assets		117
Sub-total			4,414				4,307
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets		457		Derivative Instrument Assets		16,330
	Other Deferred Charges		—		Other Deferred Charges		408
Natural gas commodity contracts	Derivative Instrument Assets		1,894		Derivative Instrument Assets		100
	Other Deferred Charges		183		Other Deferred Charges		—
	Other Current Liabilities		8		Other Current Liabilities		62
NYMEX gasoline and heating oil contracts	Derivative Instrument Assets		4		Derivative Instrument Assets		7
Sub-total			2,546				16,907
Total derivatives		$	6,960			$	21,214

21

Fair Value of Derivative Instruments in the Consolidated Balance Sheet at June 30, 2011
	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	$	1,031		Derivative Instrument Assets	$	7,057
	Other Deferred Charges		—		Other Deferred Charges		77
NYMEX gasoline and heating oil contracts	Derivative Instrument Assets		133		Derivative Instrument Assets		3
Sub-total			1,164				7,137
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets		1,835		Derivative Instrument Assets		12,379
	Other Deferred Charges		90		Other Deferred Charges		—
Natural gas commodity contracts	Derivative Instrument Assets		1,842		Derivative Instrument Assets		106
	Other Deferred Charges		308		Other Deferred Charges		—
	Other Current Liabilities		7		Other Current Liabilities		37
NYMEX gasoline and heating oil contracts	Derivative Instrument Assets		10		Derivative Instrument Assets		1
Sub-total			4,092				12,523
Total derivatives		$	5,256			$	19,660

* 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 6, 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:

		June 30,			Sept. 30,			June 30,
	(Thousands)	2012			2011			2011
	Fair value of asset derivatives presented above	$	9,015		$	6,960		$	5,256
	Fair value of cash margin receivables offset with derivatives		19,111			23,188			25,290
	Netting of assets and liabilities with the same counterparty		(24,247	)		(21,160	)		(19,630	)
	Total	$	3,879		$	8,988		$	10,916
	Derivative Instrument Assets, per Consolidated Balance Sheets:
	Derivative instrument assets	$	3,879		$	7,759		$	10,127
	Other deferred charges		—			1,229			789
	Total	$	3,879		$	8,988		$	10,916
	Fair value of liability derivatives presented above	$	24,318		$	21,214		$	19,660
	Netting of assets and liabilities with the same counterparty		(24,247	)		(21,160	)		(19,630	)
	Derivative instrument liabilities, per Consolidated Balance Sheets*	$	71		$	54		$	30
*	Included in the Other line of the Current Liabilities section

22

8. CONCENTRATIONS OF CREDIT RISK

A significant portion of LER’s transactions are with (or are associated with) energy producers, utility companies, and pipelines. These concentrations of transactions with these counterparties have the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that each of these three groups may be affected similarly by changes in economic, industry, or other conditions. To manage this risk, as well as credit risk from significant counterparties in these and other industries, LER has established procedures to determine the creditworthiness of its counterparties. These procedures include obtaining credit ratings and credit reports, analyzing counterparty financial statements to assess financial condition, and considering the industry environment in which the counterparty operates. This information is monitored on an ongoing basis. In some instances, LER may require credit assurances such as prepayments, letters of credit, or parental guarantees. In addition, LER may enter into netting arrangements to mitigate credit risk with counterparties in the energy industry from which LER both sells and purchases natural gas. Sales are typically made on an unsecured credit basis with payment due the month following delivery. Accounts receivable amounts are closely monitored and provisions for uncollectible amounts are accrued when losses are probable. To date, losses have not been significant. LER records accounts receivable, accounts payable, and prepayments for physical sales and purchases of natural gas on a gross basis. The amount included in accounts receivable attributable to energy producers and their marketing affiliates amounted to $13.3 million at June 30, 2012. Net receivable amounts from these customers on the same date, reflecting netting arrangements, were $3.4 million. Accounts receivable attributable to utility companies and their marketing affiliates comprised $9.1 million of total accounts receivable at June 30, 2012, while net receivable amounts from these customers, reflecting netting arrangements, were $7.9 million. LER also has concentrations of credit risk with certain individually significant counterparties. At June 30, 2012, the amounts included in accounts receivable from LER’s five largest counterparties (in terms of net accounts receivable exposure), were $11.8 million. Four of these five counterparties are either investment-grade rated or owned by investment-grade rated companies. Net receivable amounts from these customers on the same date, reflecting netting arrangements, were $8.0 million. Additionally, LER has concentrations of credit risk with pipeline companies associated with its natural gas receivable amounts.

9. OTHER INCOME AND (INCOME DEDUCTIONS) – NET

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
(Thousands)	2012			2011			2012			2011
Interest income	$	337		$	182		$	1,001		$	897
Net investment gain		264			414			2,458			1,541
Other income		(15	)		(21	)		(4	)		53
Other income deductions		(135	)		(418	)		316			(22	)
Other Income and (Income Deductions) – Net	$	451		$	157		$	3,771		$	2,469

23

10. INFORMATION BY OPERATING SEGMENT

All of Laclede Group’s subsidiaries are wholly owned. The Regulated Gas Distribution segment consists of the regulated operations of Laclede Gas and is the core business segment of Laclede Group. Laclede Gas is a public utility engaged in the retail distribution and sale of natural gas serving an area in eastern Missouri, with a population of approximately 2.2 million, including the City of St. Louis and parts of ten counties in eastern Missouri. The Non-Regulated Gas Marketing segment includes the results of LER, a subsidiary engaged in the non-regulated marketing of natural gas and related activities, and LER Storage Services, Inc., which was formed in October 2011 to utilize natural gas storage contracts for providing natural gas sales. Other includes Laclede Pipeline Company’s transportation of liquid propane regulated by the Federal Energy Regulatory Commission (FERC) as well as non-regulated activities, including, among other activities, real estate development, the compression of natural gas, and financial investments in other enterprises. These operations are conducted through seven subsidiaries. Other also includes Laclede Gas’ non-regulated business activities, which are comprised of its non-regulated propane sales transactions and its propane storage and related services. Accounting policies are described in Note 1. Intersegment transactions include sales of natural gas from Laclede Gas to LER, sales of natural gas from LER to Laclede Gas, and transportation services provided by Laclede Pipeline Company to Laclede Gas. These revenues are shown on the Intersegment revenues lines in the table under Regulated Gas Distribution, Non-Regulated Gas Marketing, and Other columns, respectively.

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

24

			Non-
	Regulated		Regulated
	Gas		Gas
(Thousands)	Distribution		Marketing		Other		Eliminations			Consolidated
Three Months Ended
June 30, 2012
Revenues from external customers	$	116,459	$	70,014	$	376	$	—		$	186,849
Intersegment revenues		1,175		587		259		(2,021	)		—
Total Operating Revenues		117,634		70,601		635		(2,021	)		186,849
Net Economic Earnings		4,597		3,605		694		—			8,896
Total assets		1,640,101		­186,394		150,117		(235,274	)		1,741,338
Nine Months Ended
June 30, 2012
Revenues from external customers	$	665,981	$	288,036	$	1,920	$	—		$	955,937
Intersegment revenues		1,178		9,125		778		(11,081	)		—
Total Operating Revenues		667,159		297,161		2,698		(11,081	)		955,937
Net Economic Earnings		51,448		9,589		1,179		—			62,216
Total assets		1,640,101		­186,394		150,117		(235,274	)		1,741,338
Three Months Ended
June 30, 2011
Revenues from external customers	$	151,423	$	167,770	$	18,289	$	—		$	337,482
Intersegment revenues		—		6,539		260		—			6,799
Total Operating Revenues		151,423		174,309		18,549		—			344,281
Net Economic Earnings		5,363		2,747		6,536		—			14,646
Total assets		1,582,214		175,606		121,088		(136,604	)		1,742,304
Nine Months Ended
June 30, 2011
Revenues from external customers	$	815,665	$	476,776	$	18,413	$	—		$	1,310,854
Intersegment revenues		1,576		19,052		779		—			21,407
Total Operating Revenues		817,241		495,828		19,192		—			1,332,261
Net Economic Earnings		53,000		6,028		6,468		—			65,496
Total assets		1,582,214		175,606		121,088		(136,604	)		1,742,304

25

Reconciliation of Consolidated Net Economic Earnings to Consolidated Net Income
	Three Months Ended					Nine Months Ended
	June 30,					June 30,
(Thousands)	2012			2011		2012			2011
Total Net Economic Earnings above	$	8,896		$	14,646	$	62,216		$	65,496
Add: Unrealized (loss) gain on energy-related
derivative contracts, net of tax		(963	)		744		1,281			1,156
Add:  Lower of cost or market inventory
adjustments, net of tax		494			—		(68	)		—
Add:  Realized gain (loss) on economic hedges
prior to sale of the physical commodity,
net of tax		6			—		(138	)		—
Net Income	$	8,433		$	15,390	$	63,291		$	66,652

11. COMMITMENTS AND CONTINGENCIES

Commitments

Laclede Gas and LER have entered into various contracts, expiring on dates through 2017, for the storage, transportation, and supply of natural gas. Minimum payments required under the contracts in place at June 30, 2012 are estimated at approximately $368 million. Additional contracts are generally entered into prior to or during the heating season. Laclede Gas recovers its costs from customers in accordance with the PGA Clause.

During fiscal 2011, the Utility initiated a multi-year project to replace its existing customer relationship and work management, financial, and supply chain software applications to enhance its technology, customer service, and business processes. At June 30, 2012, the Company was contractually committed to costs of approximately $6 million related to this project, with additional expenditures to be incurred throughout the project’s life.

Guarantees

Laclede Group had guarantees totaling $79.8 million for performance and payment of certain gas supply transactions by LER, as of June 30, 2012. Since that date, total guarantees issued by Laclede Group on behalf of LER increased by $2.0 million, bringing the total to $81.8 million in guarantees outstanding at July 27, 2012. No amounts have been recorded for these guarantees in the financial statements. As of June 30, 2012, management believes the probability is low that Laclede Group will be required to make payments under these guarantees.

Contingencies

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

Similar to other natural gas utility companies, Laclede Gas faces the risk of incurring environmental liabilities. In the natural gas industry, these are typically associated with sites formerly owned or operated by gas distribution companies like Laclede Gas and/or its predecessor companies at which manufactured gas operations took place. At this time, Laclede Gas has identified three former manufactured gas plant (MGP) sites where costs have been incurred and claims have been asserted: one in Shrewsbury, Missouri and two in the City of St. Louis, Missouri.

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

26

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

Laclede Gas has not owned the other site located in the City of St. Louis for many years. In a letter dated June 29, 2011, the Attorney General for the State of Missouri informed Laclede Gas that the Missouri Department of Natural Resources had completed an investigation of the site. The Attorney General requested that Laclede Gas participate in the follow up investigations of the site. In a letter dated January 10, 2012, the Company stated that it would participate in future environmental response activities at the site in conjunction with other potentially responsible parties that are willing to contribute to such efforts in a meaningful and equitable fashion.

To date, amounts required for remediation at these sites have not been material. However, the amount of costs relative to future remedial actions at these and other sites is unknown and may be material. Laclede Gas has notified its insurers that it seeks reimbursement for costs incurred in the past and future potential liabilities associated with the MGP sites. While some of the insurers have denied coverage and reserved their rights, Laclede Gas continues to discuss potential reimbursements with them. In 2005, the Utility’s outside consultant completed an analysis of the MGP sites to determine cost estimates for a one-time contractual transfer of risk from each of the Utility’s insurers of environmental coverage for the MGP sites. That analysis demonstrated a range of possible future expenditures to investigate, monitor, and remediate these MGP sites from $5.8 million to $36.3 million based upon then currently available facts, technology, and laws and regulations. The actual costs that Laclede Gas may incur could be materially higher or lower depending upon several factors, including whether remedial actions will be required, final selection and regulatory approval of any remedial actions, changing technologies and governmental regulations, the ultimate ability of other potentially responsible parties to pay, the successful completion of remediation efforts required by the Remediation Agreement described above, and any insurance recoveries. Costs associated with environmental remediation activities are accrued when such costs are probable and reasonably estimable.

Laclede Gas anticipates that any costs it may incur in the future to remediate these sites, less any amounts received as insurance proceeds or as contributions from other potentially responsible parties, would be deferred and recovered in rates through periodic adjustments approved by the MoPSC. Accordingly, any potential liabilities that may arise associated with remediating these sites are not expected to have a material impact on the future financial position and results of operations of Laclede Gas or the Company.

On December 28, 2006, the MoPSC Staff proposed a disallowance of $7.2 million related to Laclede Gas’ recovery of its purchased gas costs applicable to fiscal year 2005, which the Staff later reduced to a $1.7 million disallowance pertaining to Laclede Gas’ purchase of gas from a marketing affiliate, LER. The MoPSC Staff has also proposed disallowances of $2.8 million and $1.5 million of gas costs relating to Laclede Gas purchases of gas supply from LER for fiscal years 2006 and 2007, respectively. The MoPSC Staff proposed a number of non-monetary recommendations, based on its review of gas costs for fiscal years 2008 and 2009. Laclede Gas believes that the proposed disallowances lack merit and is vigorously opposing these adjustments in proceedings before the MoPSC. As such, no amount has been recorded in the financial statements for these proposed disallowances.

27

In connection with the affiliate transactions mentioned above, on July 7, 2010, the MoPSC Staff filed a complaint against Laclede Gas alleging that, by stating that it was not in possession of proprietary LER documents, Laclede Gas violated the MoPSC Order authorizing the holding company structure (2001 Order). Laclede Gas counterclaimed that the Staff failed to adhere to the pricing provisions of the MoPSC’s affiliate transaction rules and Laclede Gas’ Cost Allocation Manual. By orders dated November 3, 2010 and February 4, 2011, respectively, the MoPSC dismissed Laclede’s counterclaim and granted summary judgment to Staff, finding that Laclede Gas violated the terms of the 2001 Order and authorizing its General Counsel to seek penalties in court against Laclede Gas. On March 30, 2011, Laclede Gas sought review of the February 4 Order with the Missouri Cole County Circuit Court. On May 19, 2011, the Commission’s General Counsel filed a petition with the Cole County Circuit Court seeking penalties in connection with the Commission’s February 4 Order. On July 7, 2011, the Circuit Court Judge signed an agreed Order holding the penalty case in abeyance while the February 4 Order is appealed. On December 21, 2011, the Circuit Court reversed both the MoPSC’s November 3, 2010 Order and its February 4, 2011 Order. The MoPSC appealed and the matter is currently before the Western District Court of Appeals.

Subsequent to the July 7, 2010 complaint, the MoPSC Staff filed a related complaint on October 6, 2010 against Laclede Gas, LER, and Laclede Group, alleging that the Utility has failed to comply with the MoPSC’s affiliate transaction rules. LER and Laclede Group both filed motions to be dismissed from the proceeding, which were granted by the Commission on December 22, 2010. On January 26, 2011, the Commission also dismissed certain counts of the complaint against Laclede Gas. The remaining counts and a counterclaim against the Staff, filed by Laclede Gas, are still pending before the Commission. Laclede Gas believes that the complaint lacks merit and is vigorously opposing it.

On June 29, 2010, the Office of Federal Contract Compliance Programs issued a Notice of Violations to Laclede Gas alleging lapses in certain employment selection procedures during a two-year period ending in February 2006. The Company believes that the allegations lack merit and is vigorously defending its position. Management, after discussion with counsel, believes that the final outcome of these matters will not have a material effect on the consolidated financial position and results of operations of the Company.

As discussed in Note 7, 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. As of July 26, 2012, Laclede Gas and LER had $1.5 million and $0.4 million, respectively, on deposit with MF Global that remain unavailable pending final resolution by the bankruptcy trustee. While the Company’s total exposure at this time is not considered material, management is unable to predict when, or to what extent, these remaining funds will be returned.

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.

28

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

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

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

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

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

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

• changes in gas supply and pipeline availability, including decisions by natural gas producers to reduce production or shut in producing natural gas wells as well as other changes that impact supply for and access to the markets in which our subsidiaries transact business;

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

• allowed rates of return

• incentive regulation

• industry structure

• purchased gas adjustment provisions

• rate design structure and implementation

• regulatory assets

• non-regulated and affiliate transactions

• franchise renewals

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

• taxes

• pension and other postretirement benefit liabilities and funding obligations

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

• the results of litigation;

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

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

• discovery of material weakness in internal controls; and

• employee workforce issues.

Readers are urged to consider the risks, uncertainties, and other factors that could affect our business as described in this report. All forward-looking statements made in this report rely upon the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. We do not, by including this statement, assume any obligation to review or revise any particular forward-looking statement in light of future events.

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

29

RESULTS OF OPERATIONS

Overview

Laclede Group’s earnings are primarily derived from the regulated activities of its largest subsidiary, Laclede Gas Company (Laclede Gas or the Utility), Missouri’s largest natural gas distribution company. Laclede Gas is regulated by the Missouri Public Service Commission (MoPSC or Commission) and serves the City of St. Louis and parts of ten counties in eastern Missouri. Laclede Gas delivers natural gas to retail customers at rates and in accordance with tariffs authorized by the MoPSC. The Utility’s earnings are primarily generated by the sale of heating energy. The Utility’s weather mitigation rate design lessens the impact of weather volatility on Laclede Gas’ customers during cold winters and stabilizes the Utility’s earnings by recovering fixed costs more evenly during the heating season. Due to the seasonal nature of the business of Laclede Gas, Laclede Group’s earnings are typically concentrated in the November through April period, which generally corresponds with the heating season.

Laclede Energy Resources, Inc. (LER), which includes its wholly owned subsidiary LER Storage Services, Inc. (LSS), is engaged in the marketing of natural gas and related activities on a non-regulated basis. LER markets natural gas to both on-system Utility transportation customers and customers outside of Laclede Gas’ traditional service territory, including large retail and wholesale customers. LER’s operations and customer base are more subject to fluctuations in market conditions than the Utility. LER formed LSS in October 2011 to utilize natural gas storage contracts for providing natural gas sales. Effective January 1, 2012, LSS contracted for 1 Bcf of natural gas storage capacity for a thirteen month period through January 2013, and purchased 1 Bcf of natural gas in place during January 2012 for $3.0 million.  Further, and separately, LSS has entered into a precedent agreement with a natural gas storage facility operator that will provide 1 Bcf of natural gas storage subject to the facility’s successful completion of an expansion program in early to mid-2013.

Other subsidiaries provide less than 10% of consolidated revenues.

On January 26, 2012, the Company’s Board of Directors named Mr. William E. Nasser as Chairman of the Board and appointed Laclede Group’s President, Ms. Suzanne Sitherwood, as Chief Executive Officer (CEO). Ms. Sitherwood was also appointed Laclede Gas Company’s Chairman, President and CEO. These appointments were all effective February 1, 2012, concurrent with Mr. Douglas H. Yaeger’s retirement.

On April 27, 2012, Laclede Group announced a new organizational structure that will position the Company to grow through execution of four strategic imperatives: 1) develop and invest in emerging technologies, 2) pursue growth through the acquisition of businesses to which the Company can apply its operating model, 3) invest in infrastructure, and 4) leverage current business unit competencies to enhance growth. The Board of Directors approved the following appointments and promotions effective May 1, 2012:

• Michael R. Spotanski was appointed to the newly created position of Senior Vice President, Chief Integration and Innovation Officer.  In his new role, Mr. Spotanski will lead the Company’s efforts to integrate regulated natural gas distribution utilities and other businesses that the Company acquires as part of its growth strategy, as well as its efforts to develop and invest in emerging technologies.  Previously, Mr. Spotanski was Senior Vice President Operations and Marketing of Laclede Gas.  Until a new operating officer is appointed for Laclede Gas, Mr. Spotanski will continue to manage operations at Laclede Gas along with Suzanne Sitherwood who will remain President of Laclede Gas.

• Mark C. Darrell was appointed to the position of Senior Vice President, General Counsel and Chief Compliance Officer.  In this role, Mr. Darrell supervises the Company’s corporate legal functions, including mergers and acquisition support, litigation, regulatory affairs, contracts and environmental matters.  He is also responsible for the Company’s corporate compliance.

• Mary C. Kullman was promoted to Senior Vice President, Chief Administrative Officer and Corporate Secretary.  In her new role, Ms. Kullman’s responsibilities include overseeing corporate communications, marketing and branding; the development and implementation of standards for shared services, enterprise risk management and internal audit.  She retains her previous role as corporate secretary and responsibility for corporate governance, securities and ethics.

30

• Steven P. Rasche was promoted to Senior Vice President, Finance and Accounting of Laclede Group and appointed Chief Financial Officer of Laclede Gas.  He also serves as principal accounting officer for the Company and Laclede Gas.  Mr. Rasche’s responsibilities include accounting, financial reporting and analysis, treasury, tax and investor relations.  Mr. Rasche reports to Mr. Waltermire.

• Richard A. Skau was appointed to Senior Vice President, Chief Human Resources Officer.  In this role, Mr. Skau supervises the Company’s efforts to attract, retain, develop and train employees to prepare them to execute on the Company’s strategy.  His responsibilities also include employee relations, payroll, benefits, and diversity and inclusion.

• Mark D. Waltermire was promoted to Executive Vice President, Chief Financial Officer. In this role, Mr. Waltermire oversees strategic planning and corporate development, information technology services, finance and accounting, supply chain functions and LER.

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

Regulated Gas Distribution Segment:

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

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

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

• the Utility’s ability to access credit markets and maintain working capital sufficient to meet operating requirements; and,

• the effect of natural gas price volatility on the business.

Non-Regulated Gas Marketing Segment:

• the risks of competition;

• fluctuations in natural gas prices;

• new national pipeline infrastructure projects;

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

• credit and/or capital market access;

• counterparty risks;

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

• pursuing additional growth.

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

31

Laclede Gas continues to provide reliable natural gas service at a reasonable cost, while maintaining and building a secure and dependable infrastructure. The Utility’s strategy focuses on improving performance and mitigating the impact of weather fluctuations on Laclede Gas’ customers while improving the ability to recover its authorized distribution costs and rate of return. The Utility’s distribution costs are the essential, primarily fixed, expenditures it must incur to operate and maintain more than 16,000 miles of mains and services comprising its natural gas distribution system and related storage facilities. The Utility’s distribution costs include wages and employee benefit costs, depreciation and maintenance expenses, and other regulated utility operating expenses, excluding natural and propane gas expense. Distribution costs are considered in the ratemaking process, and recovery of these types of costs is included in revenues generated through the Utility’s tariff rates, as approved by the MoPSC. The settlement of the Utility’s rate case in 2010 retained the Utility’s weather mitigation rate design that better ensures the recovery of its fixed costs and margins despite variations in sales volumes due to the impacts of weather and other factors that affect customer usage.

The Utility’s income from off-system sales and capacity release remains subject to fluctuations in market conditions. The Utility is allowed to retain 15% to 25% of the first $6 million in annual income earned (depending on the level of income earned) and 30% of income exceeding $6 million annually. Some of the factors impacting the level of off-system sales include the availability and cost of the Utility’s natural gas supply, the weather in its service area, and the weather in other markets. When Laclede Gas’ service area experiences warmer-than-normal weather while other markets experience colder weather or supply constraints, some of the Utility’s natural gas supply is available for off-system sales and there may be a demand for such supply in other markets. See the Regulatory and Other Matters section on page 39 of this report for additional information on regulatory issues relative to the Utility.

Laclede Gas works actively to reduce the impact of wholesale natural gas price volatility on its costs by strategically structuring its natural gas supply portfolio to increase its gas supply availability and pricing alternatives and through the use of derivative instruments to protect its customers from significant changes in the commodity price of natural gas. Nevertheless, the overall cost of purchased gas remains subject to fluctuations in market conditions. The Utility’s Purchased Gas Adjustment (PGA) Clause allows Laclede Gas to flow through to customers, subject to prudence review by the MoPSC, the cost of purchased gas supplies, including costs, cost reductions, and related carrying costs associated with the use of derivative instruments to hedge the purchase price of natural gas, as well as gas inventory carrying costs. The Utility believes it will continue to be able to obtain sufficient gas supply. The price of natural gas supplies and other economic conditions may affect sales volumes, due to the conservation efforts of customers, and cash flows associated with the timing of collection of gas costs and related accounts receivable from customers.

The Utility relies on both short-term credit and long-term capital markets, as well as cash flows from operations, to satisfy its seasonal cash requirements and fund its cost of capital expenditures. Laclede Gas’ ability to issue commercial paper supported by lines of credit, to issue long-term bonds, or to obtain new lines of credit is dependent on current conditions in the credit and capital markets. Management focuses on maintaining a strong balance sheet and believes it currently has adequate access to credit and capital markets and will have sufficient capital resources to meet its foreseeable obligations. See the Liquidity and Capital Resources section on page 41 for additional information.

LER provides both on-system Utility transportation customers and customers outside of Laclede Gas’ traditional service area with another choice in non-regulated natural gas suppliers. LER utilizes its natural gas supply agreements, transportation agreements, storage agreements, and other executory contracts to support a variety of services to its customers at competitive prices. It closely monitors and manages the natural gas commodity price risk associated with providing such services to its customers through the use of exchange-traded/cleared derivative instruments and other contractual arrangements. LER is committed to managing commodity price risk, while it seeks to expand the services that it now provides. Nevertheless, income from LER’s operations is more subject to fluctuations in market conditions than the Utility’s operations. LER’s business is directly impacted by the effects of competition in the marketplace, the impact of new pipeline infrastructure, and surplus natural gas supplies on natural gas commodity prices.

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

32

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

In response to new pipeline infrastructure, changes in availability of regional natural gas supplies, and other changes in marketplace dynamics, there is a reduced probability of physical settlement of some of LER’s wholesale purchase and sale transactions. As such, certain transactions entered into on or after January 1, 2012 are designated as trading activities for financial reporting purposes, due to their settlement characteristics, rather than elected for normal purchases or normal sales designations under generally accepted accounting principles (GAAP). Results of operations from trading activities are reported on a net basis (instead of a gross basis) in Non-Regulated Gas Marketing Operating Revenues, which may cause reductions in and/or volatility in the Company’s operating revenues, but has no effect on operating income or net income.

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

EARNINGS

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

•	Net unrealized gains and losses on energy-related derivatives that are required by GAAP fair value accounting associated with current changes in the fair value of financial and physical transactions prior to their completion and settlement. These unrealized gains and losses result primarily from two sources:
	1)	changes in the fair values of physical and/or financial derivatives prior to the period of settlement; and,
	2)	ineffective portions of accounting hedges, required to be recorded in earnings prior to settlement, due to differences in commodity price changes between the locations of the forecasted physical purchase or sale transactions and the locations of the underlying hedge instruments;
•	Lower of cost or market adjustments to the carrying value of commodity inventories resulting when the market price of the commodity falls below its original cost, to the extent that those commodities are economically hedged; and,
•	Realized gains and losses resulting from the settlement of economic hedges prior to the sale of the physical commodity.

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

33

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 will exclude the effect of costs related to unique acquisition, divestiture, and restructuring activities, if any, when evaluating on-going performance, and therefore will exclude these costs from net economic earnings. These internal non-GAAP operating metrics should not be considered as an alternative to, or more meaningful than, GAAP measures such as net income. Reconciliations of net economic earnings and net economic earnings per share to the Company’s most directly comparable GAAP measures are provided below.

Quarter Ended June 30, 2012

(Millions, except per share amounts)			Regulated Gas Distribution				Non-Regulated Gas Marketing				Other			Total				Per Share Amounts**
Quarter Ended June 30, 2012
	Net Economic Earnings (Non-GAAP)			$	4.7			$	3.6			$	0.6		$	8.9			$	0.40
	Add:  Unrealized gain (loss) on energy-related      derivatives*				(0.1	)			(0.9	)			—			(1.0	)			(0.04	)
	Add:  Lower of cost or market inventory adjustments*				—				0.5				—			0.5				0.02
	Add:  Realized gain (loss) on economic hedges prior      to the sale of the physical commodity*				—				—				—			—				—
	Net Income (GAAP)			$	4.6			$	3.2			$	0.6		$	8.4			$	0.38
Quarter Ended June 30, 2011
	Net Economic Earnings (Non-GAAP)			$	5.4			$	2.7			$	6.5		$	14.6			$	0.65
	Add:  Unrealized gain (loss) on energy-related      derivatives*				—				0.8				—			0.8				0.04
	Add:  Lower of cost or market inventory adjustments*				—				—				—			—				—
	Add:  Realized gain (loss) on economic hedges prior      to the sale of the physical commodity*				—				—				—			—				—
	Net Income (GAAP)			$	5.4			$	3.5			$	6.5		$	15.4			$	0.69
*		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. For the quarters ended June 30, 2012 and 2011, the total net amount of income tax (benefit) expense included in the reconciling items above is $(0.3) million and $0.5 million, respectively.
**		Net economic earnings per share is calculated by replacing consolidated net income with consolidated net economic earnings in the GAAP diluted earnings per share calculation.

Laclede Group’s net income was $8.4 million for the quarter ended June 30, 2012, compared with $15.4 million for the quarter ended June 30, 2011. Basic and diluted earnings per share for the quarter ended June 30, 2012 were $0.38, compared with basic and diluted earnings per share of $0.69 for the quarter ended June 30, 2011. Earnings decreased compared to last year primarily due to the $6.1 million effect of an April 2011 non-regulated sale of propane inventory recorded in Other operating income and lower income reported by Laclede Group’s Regulated Gas Distribution and Non-Regulated Gas Marketing segments. Net economic earnings were $8.9 million for the quarter ended June 30, 2012, compared with $14.6 million for the same quarter last year. Net economic earnings per share were $0.40 for the quarter ended June 30, 2012, compared with $0.65 for the quarter ended June 30, 2011.

Regulated Gas Distribution net income and Regulated Gas Distribution net economic earnings decreased by $0.8 and $0.7 million, respectively, for the quarter ended June 30, 2012, compared with the quarter ended June 30, 2011. The decrease was primarily due to the following factors, quantified on a pre-tax basis:

• lower system gas sales margins and other variations, totaling $4.3 million, primarily due to the effect of  warmer weather in the Utility’s service area during the three months ended June 30, 2012; and

• lower income from off-system sales and capacity release, higher depreciation and amortization expenses, and other minor variations totaling $1.4 million.

34

These factors were partially offset by:

• decreases in operation and maintenance expenses totaling $4.5 million; and

• higher Infrastructure System Replacement Surcharge (ISRS) revenues totaling $1.1 million.

The Non-Regulated Gas Marketing segment reported GAAP earnings totaling $3.2 million, a decrease of $0.3 million compared with the same quarter last year. Net economic earnings for the quarter ended June 30, 2012 increased $0.9 million from the quarter ended June 30, 2011. The improved net economic earnings were primarily attributable to increased sales volumes, partially offset by reduced sales margins. On a GAAP basis, LER’s results were impacted by the effect of higher unrealized losses from certain of LER’s energy-related derivative contracts, the effect of which was partially offset by the reversal of a portion of a lower of cost or market inventory adjustment due to a recovery in market prices of natural gas this quarter.

Both Other net income and Other net economic earnings decreased $5.9 million compared with the same period last year primarily due to the effect of Laclede Gas’ April 2011 sale of 320,000 barrels of propane from inventory that were no longer required to serve utility customers. The revenues from this non-regulated transaction were $17.9 million and the resulting income, net of income taxes, totaled $6.1 million.

Regulated Gas Distribution Operating Revenues

Laclede Gas passes on to Utility customers (subject to prudence review by the MoPSC) increases and decreases in the wholesale cost of natural gas in accordance with its PGA Clause. The volatility of the wholesale natural gas market results in fluctuations from period to period in the recorded levels of, among other items, revenues and natural gas cost expense. Nevertheless, increases and decreases in the cost of gas associated with system gas sales volumes have no direct effect on net revenues and net income.

Regulated Gas Distribution Operating Revenues for the quarter ended June 30, 2012 were $116.5 million, or $35.0 million less than the same period last year. Temperatures experienced in the Utility’s service area during the quarter ended June 30, 2012 were 29.8% warmer than the same quarter last year and 40.7% warmer than normal. Total system therms sold and transported were 97.1 million for the quarter ended June 30, 2012, compared with 111.8 million for the same period last year. Total off-system therms sold and transported were 45.0 million for the quarter ended June 30, 2012, compared with 64.0 million for the same period last year. The decrease in Regulated Gas Distribution Operating Revenues was primarily attributable to the following factors:

(Millions)
Lower system sales volumes and other variations	$	(14.4	)
Lower prices charged for off-system sales		(9.8	)
Lower off-system sales volumes (reflecting less favorable market conditions as described in greater      detail in the Results of Operations - Overview)		(8.6	)
Lower wholesale gas costs passed on to Utility customers (subject to prudence review by the MoPSC)		(3.3	)
Higher ISRS revenues		1.1
Total Variation	$	(35.0	)

Regulated Gas Distribution Operating Expenses

Regulated Gas Distribution Operating Expenses for the quarter ended June 30, 2012 decreased $35.7 million from the same quarter last year. Natural and propane gas expense decreased $30.0 million, or 39.1%, from last year’s level, primarily attributable to lower off-system gas expense, decreased system volumes purchased for sendout, and lower rates charged by our suppliers. Other operation and maintenance expenses decreased $4.5 million, or 10.5%, primarily due to a higher rate of overheads capitalized and lower compensation expenses. Taxes, other than income taxes, decreased $1.5 million, or 12.1%, primarily due to decreased gross receipts taxes (attributable to decreased system sales revenues).

35

Non-Regulated Gas Marketing Operating Revenues and Operating Expenses

Non-Regulated Gas Marketing Operating Revenues and Operating Expenses decreased $104.3 million and $103.2 million, respectively, primarily due to the effect of lower per unit gas prices, partially offset by the effect of higher volumes purchased and sold. These decreases in operating revenues and operating expenses also include the effect of recording certain transactions on a net basis (instead of a gross basis), as described in greater detail in Results of Operations – Overview.

Other Operating Revenues and Operating Expenses

Other Operating Revenues decreased $18.2 million primarily due to the effect of the aforementioned non-regulated sale of propane inventory by Laclede Gas. The decrease in Other Operating Expenses, totaling $7.9 million, was primarily due to the expenses associated with this propane transaction. This propane transaction resulted in pre-tax income of $10.0 million.

Interest Charges

Interest charges during the quarter ended June 30, 2012 were essentially unchanged from the same period last year. Average short-term interest rates were 0.2% and 0.3% for the quarters ended June 30, 2012 and 2011, respectively. Average short-term borrowings were $7.5 million for the quarter ended June 30, 2012, compared with $0.4 million for the quarter ended June 30, 2011.

Income Taxes

The $3.5 million decrease in income taxes was primarily due to lower pre-tax income.

Nine Months Ended June 30, 2012

(Millions, except per share amounts)			Regulated Gas Distribution			Non-Regulated Gas Marketing				Other			Total				Per Share Amounts**
Nine Months Ended June 30, 2012
	Net Economic Earnings (Non-GAAP)			$	51.4		$	9.6			$	1.2		$	62.2			$	2.77
	Add:  Unrealized gain (loss) on energy-related      derivatives*				—			1.3				—			1.3				0.06
	Add:  Lower of cost or market inventory adjustments*				—			(0.1	)			—			(0.1	)			—
	Add:  Realized gain (loss) on economic hedges prior      to the sale of the physical commodity*				—			(0.1	)			—			(0.1	)			(0.01	)
	Net Income (GAAP)			$	51.4		$	10.7			$	1.2		$	63.3			$	2.82
Nine Months Ended June 30, 2011
	Net Economic Earnings (Non-GAAP)			$	53.0		$	6.0			$	6.5		$	65.5			$	2.93
	Add:  Unrealized gain (loss) on energy-related      derivatives*				—			1.2				—			1.2				0.05
	Add:  Lower of cost or market inventory adjustments*				—			—				—			—				—
	Add:  Realized gain (loss) on economic hedges prior      to the sale of the physical commodity*				—			—				—			—				—
	Net Income (GAAP)			$	53.0		$	7.2			$	6.5		$	66.7			$	2.98
*		Amounts presented net of income taxes. Income taxes are calculated by applying federal, state, and local income tax rates applicable to ordinary income to the amounts of the pre-tax reconciling items. For both the nine months ended June 30, 2012 and 2011, the total net amount of income tax expense included in the reconciling items above is $0.7 million.
**		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.

36

Laclede Group’s net income was $63.3 million for the nine months ended June 30, 2012, compared with $66.7 million for the nine months ended June 30, 2011. Basic and diluted earnings per share for the nine months ended June 30, 2012 were $2.83 and $2.82, respectively, compared with basic and diluted earnings per share of $2.99 and $2.98, respectively, for the nine months ended June 30, 2011. Earnings decreased compared to last year primarily due to the effect of an April 2011 non-regulated sale of propane inventory recorded in Other operating income and lower income reported by Laclede Group’s Regulated Gas Distribution segment, partially offset by increased income reported by Laclede Group’s Non-Regulated Gas Marketing segment. Net economic earnings were $62.2 million for the nine months ended June 30, 2012, compared with $65.5 million for the same period last year. Net economic earnings per share were $2.77 for the nine months ended June 30, 2012, compared with $2.93 for the nine months ended June 30, 2011.

Regulated Gas Distribution net income and net economic earnings decreased by $1.6 million for the nine months ended June 30, 2012, compared with the nine months ended June 30, 2011. These decreases were primarily attributable to the following factors, quantified on a pre-tax basis:

• lower system gas sales margins and other variations, totaling $8.0 million, primarily due to the effect of weather in the Utility’s service area during the nine months ended June 30, 2012, which was the warmest based on records dating back more than 100 years;

• increases in pension and group insurance expenses totaling $5.0 million;

• increases in depreciation and amortization expenses totaling $1.2 million; and

• lower income from off-system sales and capacity release totaling $0.9 million.

These factors were partially offset by:

• decreases in operating and maintenance expenses, excluding pension and group insurance expenses, totaling $9.8 million; and

• higher ISRS revenues totaling $3.3 million.

The Non-Regulated Gas Marketing segment reported an increase in GAAP earnings of $3.5 million compared with the same period last year. Net economic earnings for the nine months ended June 30, 2012 increased $3.6 million from the nine months ended June 30, 2011. The increased net economic earnings were primarily due to LER’s increased margins on sales of natural gas, mainly due to the effect of reduced transportation costs resulting from the renegotiation of contracts that were renewed during the latter half of fiscal year 2011, and increased sales volumes. 
 

Both Other net income and Other net economic earnings decreased $5.3 million compared with the same period last year primarily due to the effect of Laclede Gas’ April 2011 sale of 320,000 barrels of propane from inventory that were no longer required to serve utility customers. This transaction resulted in income, net of income taxes, totaling $6.1 million.

Regulated Gas Distribution Operating Revenues

Laclede Gas passes on to Utility customers (subject to prudence review by the MoPSC) increases and decreases in the wholesale cost of natural gas in accordance with its PGA Clause. The volatility of the wholesale natural gas market results in fluctuations from period to period in the recorded levels of, among other items, revenues and natural gas cost expense. Nevertheless, increases and decreases in the cost of gas associated with system gas sales volumes have no direct effect on net revenues and net income.

Regulated Gas Distribution Operating Revenues for the nine months ended June 30, 2012 were $666.0 million, or $151.3 million less than the same period last year. Temperatures experienced in the Utility’s service area during the nine months ended June 30, 2012, which were the warmest on record, were 27.7% warmer than the same period last year and 27.9% warmer than normal. Total system therms sold and transported were 640.8 million for the nine months ended June 30, 2012, compared with 808.8 million for the same period last year. Total off-system therms sold and transported were 273.2 million for the nine months ended June 30, 2012, compared with 202.1 million for the same period last year. The decrease in Regulated Gas Distribution Operating Revenues was primarily attributable to the following factors:

37

(Millions)
Lower system sales volumes and other variations	$	(116.4	)
Lower prices charged for off-system sales		(37.9	)
Lower wholesale gas costs passed on to Utility customers (subject to prudence review by the MoPSC)		(30.4	)
Higher off-system sales volumes (reflecting more favorable market conditions as described in greater      detail in the Results of Operations - Overview)		30.1
Higher ISRS revenues		3.3
Total Variation	$	(151.3	)

Regulated Gas Distribution Operating Expenses

Regulated Gas Distribution Operating Expenses for the nine months ended June 30, 2012 decreased $156.9 million from the same period last year. Natural and propane gas expense decreased $146.1 million, or 28.6%, from last year’s level, primarily attributable to decreased system volumes purchased for sendout, lower rates charged by our suppliers, and lower off-system gas expense. Other operation and maintenance expenses decreased $4.8 million, or 3.7%, primarily due to a higher rate of overheads capitalized, decreased maintenance charges, a lower provision for uncollectible accounts, and decreases in compensation expenses, partially offset by higher pension and group insurance expenses. Depreciation and amortization expense increased $1.2 million, or 4.2%, primarily due to additional depreciable property. Taxes, other than income taxes, decreased $7.2 million, or 13.6%, primarily due to decreased gross receipts taxes (attributable to decreased system sales revenues).

Non-Regulated Gas Marketing Operating Revenues and Operating Expenses

Non-Regulated Gas Marketing Operating Revenues and Operating Expenses decreased $207.8 million and $204.5 million, respectively, primarily due to the effect of lower per unit gas prices, partially offset by effect of higher volumes purchased and sold. These decreases in operating revenues and operating expenses also include the effect of recording certain transactions on a net basis (instead of a gross basis), as described in greater detail in Results of Operations - Overview.

Other Operating Revenues and Expenses

Other Operating Revenues decreased $17.3 million primarily due to the effect of the aforementioned non-regulated sale of propane inventory by Laclede Gas. The decrease in Other Operating Expenses, totaling $7.3 million, was primarily due to the expenses associated with this propane transaction. This propane transaction resulted in pre-tax income of $10.0 million.

Other Income and (Income Deductions) - Net

Other Income and (Income Deductions) – Net increased $1.3 million primarily due to higher net investment gains.

Interest Charges

The $0.4 million decrease in interest charges was primarily due to lower interest on long-term debt, attributable to the November 2010 maturity of $25 million principal amount of 6 1/2 % first mortgage bonds. Average short-term interest rates were 0.3% for both the nine months ended June 30, 2012 and 2011. Average short-term borrowings were $52.6 million for the nine months ended June 30, 2012, compared with $61.1 million for the nine months ended June 30, 2011.

Income Taxes

The $2.7 million decrease in income taxes was primarily due to lower pre-tax income.

38

Labor Agreements

Laclede Gas has labor agreements with Locals 11-6 and 11-194 of the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied-Industrial & Service Workers International Union, which represent approximately 62% of Laclede Gas’ employees. The agreements expire at midnight on July 31, 2012. Negotiations on new contracts are in progress.

REGULATORY AND OTHER MATTERS

On December 28, 2006, the MoPSC Staff proposed a disallowance of $7.2 million related to Laclede Gas’ recovery of its purchased gas costs applicable to fiscal year 2005, which the Staff later reduced to a $1.7 million disallowance pertaining to Laclede Gas’ purchase of gas from a marketing affiliate, LER. The MoPSC Staff has also proposed disallowances of $2.8 million and $1.5 million of gas costs relating to Laclede Gas purchases of gas supply from LER for fiscal years 2006 and 2007, respectively. The MoPSC Staff proposed a number of non-monetary recommendations, based on its review of gas costs for fiscal years 2008 and 2009. Laclede Gas believes that the proposed disallowances lack merit and is vigorously opposing these adjustments in proceedings before the MoPSC. As such, no amount has been recorded in the financial statements for these proposed disallowances.

In connection with the affiliate transactions mentioned above, on July 7, 2010, the MoPSC Staff filed a complaint against Laclede Gas alleging that, by stating that it was not in possession of proprietary LER documents, Laclede Gas violated the MoPSC Order authorizing the holding company structure (2001 Order). Laclede Gas counterclaimed that the Staff failed to adhere to the pricing provisions of the MoPSC’s affiliate transaction rules and Laclede Gas’ Cost Allocation Manual. By orders dated November 3, 2010 and February 4, 2011, respectively, the MoPSC dismissed Laclede’s counterclaim and granted summary judgment to Staff, finding that Laclede Gas violated the terms of the 2001 Order and authorizing its General Counsel to seek penalties in court against Laclede Gas. On March 30, 2011, Laclede Gas sought review of the February 4 Order with the Missouri Cole County Circuit Court. On May 19, 2011, the Commission’s General Counsel filed a petition with the Cole County Circuit Court seeking penalties in connection with the Commission’s February 4 Order. On July 7, 2011, the Circuit Court Judge signed an agreed Order holding the penalty case in abeyance while the February 4 Order is appealed. On December 21, 2011, the Circuit Court reversed both the MoPSC’s November 3, 2010 Order and its February 4, 2011 Order. The MoPSC appealed and the matter is currently before the Western District Court of Appeals.

Subsequent to the July 7, 2010 complaint, the MoPSC Staff filed a related complaint on October 6, 2010 against Laclede Gas, LER, and Laclede Group, alleging that the Utility has failed to comply with the MoPSC’s affiliate transaction rules. LER and Laclede Group both filed motions to be dismissed from the proceeding, which were granted by the Commission on December 22, 2010. On January 26, 2011, the Commission also dismissed certain counts of the complaint against Laclede Gas. The remaining counts and a counterclaim against the Staff, filed by Laclede Gas, are still pending before the Commission. Laclede Gas believes that the complaint lacks merit and is vigorously opposing it.

On November 9, 2011, the Utility made an ISRS filing with the Commission designed to increase revenues by $2.0 million annually, essentially all of which was approved by the MoPSC effective January 13, 2012. On April 27, 2012, the Utility made another ISRS filing with the Commission. As a result of such filing, on June 27, 2012 the MoPSC approved an annual increase in ISRS revenues of $3.2 million effective July 9, 2012.

On June 29, 2010, the Office of Federal Contract Compliance Programs issued a Notice of Violations to Laclede Gas alleging lapses in certain employment selection procedures during a two-year period ending in February 2006. The Company believes that the allegations lack merit and is vigorously defending its position. Management, after discussion with counsel, believes that the final outcome of these matters will not have a material effect on the consolidated financial position and results of operations of the Company.

39

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, 2011 and include the following:

• Accounts receivable and allowance for doubtful accounts

• Employee benefits and postretirement obligations

• Regulated operations

There were no significant changes to these critical accounting policies during the nine months ended June 30, 2012. The Company’s policy on certain energy contracts is presented below:

Non-Regulated Gas Marketing Energy Contracts – LER routinely enters into contracts associated with the physical purchase or sale of natural gas in a future period. In determining the appropriate accounting treatment for these contracts, management is required to assess the contract terms and various other factors to determine if the contracts are subject to the derivative accounting guidance in ASC Topic 815, “Derivatives and Hedging.” If a contract is deemed to meet the definition of derivative, management’s judgment may be further required in determining if the contract is eligible for the normal purchases or normal sales election, which, if elected, permits the Company to account for the contract in the period the natural gas is delivered. Pursuant to GAAP, contracts not designated as normal purchases or normal sales are required to be accounted for as derivatives with changes in fair value (representing unrealized gains or losses) recognized in earnings in the periods prior to physical delivery. Furthermore, management is required to determine whether revenues and expenses, including realized and unrealized gains and losses, on energy contracts should be reported on a gross or net basis in the Statements of Consolidated Income. In the absence of quoted prices in active markets for identical assets or liabilities, determining the fair value of a derivative contract requires judgment as to the appropriateness of various market inputs and involves making assumptions regarding how market participants would price the asset or liability. In addition to these physical contracts, LER also utilizes natural gas futures, swap, and option contracts traded on or cleared through the New York Mercantile Exchange (NYMEX) and Ice Clear Europe (ICE) to manage the price risk associated with certain of its fixed-price commitments. These contracts may be designated for hedge accounting treatment, as discussed in Note 7 of the Notes to Consolidated Financial Statements.

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, 2011.

ACCOUNTING PRONOUNCEMENTS

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

The Company continues to monitor the developments of the Financial Accounting Standards Board (FASB) relative to possible changes in accounting standards. Currently, the FASB is considering various changes to U. S. GAAP, some of which may be significant, as part of a joint effort with the International Accounting Standards Board to converge accounting standards. Future developments, depending on the outcome, have the potential to impact the Company’s financial condition and results of operations.

40

FINANCIAL CONDITION

CASH FLOWS

The Company’s short-term borrowing requirements typically peak during colder months when Laclede Gas borrows money to cover the lag between when it purchases its natural gas and when its customers pay for that gas. Changes in the wholesale cost of natural gas (including cash payments for margin deposits associated with the Utility’s use of natural gas derivative instruments), variations in the timing of collections of gas cost under the Utility’s PGA Clause, 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 $128.2 million for the nine months ended June 30, 2012, compared with $201.3 million for the same period last year. The variation is primarily attributable to increased cash payments for margin deposits associated with the Utility’s use of natural gas derivative instruments and other variations associated with the timing of collections of gas cost under the Utility’s PGA Clause, as well as increased cash payments for the funding of pension plans. These factors were partially offset by improved cash flows at LER.

Net cash used in investing activities for the nine months ended June 30, 2012 was $78.2 million compared with $47.0 million for the nine months ended June 30, 2011. The variation primarily reflects additional capital expenditures this year for distribution plant and information technology investments.

Net cash used in financing activities was $71.8 million for the nine months ended June 30, 2012 compared with $180.3 million for the nine months ended June 30, 2011. The variation primarily reflects decreased repayments of short-term debt this year and the effect of the maturity of long-term debt last year.

LIQUIDITY AND CAPITAL RESOURCES

Cash and Cash Equivalents

Laclede Group had temporary cash investments totaling $17.3 million at June 30, 2012, earning an average interest rate of 0.2%. These investments, which are presented in the Cash and cash equivalents line of the Consolidated Balance Sheets, were diversified among money market funds and interest-bearing deposits at highly-rated commercial banks. The money market funds are accessible by the Company on demand. The bank deposits are also generally available on demand, though the banks reserve the right to require seven days’ notice for a withdrawal. These funds are used to support the working capital needs of the Company’s subsidiaries. The balance of short-term investments ranged between $5.3 million and $19.8 million during the nine months ended June 30, 2012. Due to lower yields available to Laclede Group on its short-term investments, Laclede Group elected to provide a) a portion of Laclede Gas’ short-term funding through intercompany lending during the nine months ended June 30, 2012 and b) all of its short-term funding on June 30, 2012.

Short-term Debt

As indicated in the discussion of cash flows above, the Company’s short-term borrowing requirements typically peak during the colder months. These short-term cash requirements can be met through the sale of commercial paper supported by lines of credit with banks or through direct use of the lines of credit. At June 30, 2012, Laclede Gas had a syndicated line of credit in place of $300 million from seven banks, with the largest portion provided by a single bank being 17.9%. This line is scheduled to expire in July 2016. Laclede Gas’ 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 50% of total capitalization on June 30, 2012.

Short-term cash requirements outside of Laclede Gas have generally been met with internally-generated funds. However, Laclede Group has $50 million in a syndicated line of credit, scheduled to expire in July 2016, to meet short-term liquidity needs of its subsidiaries. The line of credit has a covenant limiting the total debt of the consolidated Laclede Group to no more than 70% of the Company’s total capitalization. As defined in the line of credit, this ratio stood at 38% on June 30, 2012. Laclede Group’s lines have been used to provide for seasonal funding needs. There were no borrowings under Laclede Group’s line during the nine months ended June 30, 2012.

41

Information about Laclede Group’s consolidated short-term borrowings (excluding intercompany borrowings) during the nine months ended June 30, 2012 and as of June 30, 2012, is presented below:

	Laclede Gas Commercial Paper Borrowings
Nine Months Ended June 30, 2012
Weighted average borrowings outstanding	$52.6 million
Weighted average interest rate	0.3%
Range of borrowings outstanding	$0 - $133.5 million
As of June 30, 2012
Borrowings outstanding at end of period	None
Weighted average interest rate	N/A

Based on average short-term borrowings for the nine months ended June 30, 2012, an increase in the average interest rate of 100 basis points would decrease Laclede Group’s pre-tax earnings and cash flows by approximately $0.5 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, effective through June 30, 2013. During the nine months ended June 30, 2012, pursuant to this authority, the Utility sold 51 shares of its common stock to Laclede Group for $2.0 million. As of July 27, 2012, $513.8 million remains available under this authorization. The amount, timing, and type of additional financing to be issued will depend on cash requirements and market conditions, as well as future MoPSC authorizations.

The Company is in negotiations to issue $125 million in long-term debt to take advantage of attractive market terms, and on July 20, 2012, Laclede Gas Company tentatively committed to issue $100 million of first mortgage bonds in a private placement.  Terms of the bonds will be between 10 and 15 years, with settlement planned for March 2013. Simultaneously, Laclede Group tentatively committed to the issuance of $25 million of 10-year unsecured notes in a private placement, with settlement planned for December 2012.  Interest rates on these issuances are anticipated to be between 3.0% and 3.5% per annum. Both commitments are subject to final purchaser due diligence and the execution of definitive documentation, and the proceeds are expected to be used for general corporate purposes.

At June 30, 2012, Laclede Gas had fixed-rate long-term debt totaling $365 million (including current maturities). While these long-term debt issues are fixed-rate, they are subject to changes in their fair value as market interest rates change. However, increases or decreases in fair value would impact earnings and cash flows only if Laclede Gas were to reacquire any of these issues in the open market prior to maturity. Under GAAP applicable to Laclede Gas’ regulated operations, losses or gains on early redemptions of long-term debt would typically be deferred as regulatory assets or regulatory liabilities and amortized over a future period. Of the Utility’s $365 million in long-term debt, $50 million have no call option, $235 million have make-whole call options, and $80 million are callable at par in 2013. None of the debt has any put options.

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 249,640 and 241,514 shares at June 30, 2012 and July 27, 2012, respectively, remaining available for issuance under its Form S-3. Laclede Group also has an automatic shelf registration statement on Form S-3 for the issuance of equity and debt securities. No securities have been issued under that S-3. The amount, timing, and type of financing to be issued under this shelf registration will depend on cash requirements and market conditions.

42

Guarantees

Laclede Group had guarantees totaling $79.8 million for performance and payment of certain wholesale gas supply purchases by LER, as of June 30, 2012. Since that date, total guarantees issued by Laclede Group on behalf of LER increased by $2.0 million, bringing the total to $81.8 million in guarantees outstanding at July 27, 2012. No amounts have been recorded for these guarantees in the financial statements.

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 $75.0 million for the nine months ended June 30, 2012, compared with $46.8 million for the same period last year. The increase in capital expenditures, compared with the prior period, is primarily attributable to additional expenditures for distribution plant and information technology investments. During fiscal 2011, Laclede Gas began a multi-year project to enhance its technology, customer service, and business processes by replacing its existing customer relationship and work management, financial, and supply chain software applications. Non-utility capital expenditures were $1.8 million for the nine months ended June 30, 2012 compared with $0.3 million for the nine months ended June 30, 2011.

Consolidated capitalization at June 30, 2012 consisted of 64.3% Laclede Group common stock equity and 35.7% Laclede Gas 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 Laclede Gas’ sales affects the comparison of certain balance sheet items at June 30, 2012 and at September 30, 2011, such as Accounts receivable - net, Gas stored underground, Notes payable, Accounts payable, Regulatory assets and Regulatory liabilities, and Advance and Delayed customer billings. The Consolidated Balance Sheet at June 30, 2011 is presented to facilitate comparison of these items with the corresponding interim period of the preceding fiscal year.

CONTRACTUAL OBLIGATIONS

As of June 30, 2012, Laclede Group had contractual obligations with payments due as summarized below (in millions):

			Payments due by period
			Remaining						Fiscal Years
Contractual Obligations	Total		Fiscal Year 2012		Fiscal Years 2013-2014		Fiscal Years 2015-2016		2017 and thereafter
Principal Payments on Long-Term Debt (a)	$	365.0	$	—	$	25.0	$	—	$	340.0
Interest Payments on Long-Term Debt (a)		440.6		2.5		43.5		42.6		352.0
Capital Leases (b)		0.2		—		0.1		0.1		—
Operating Leases (b)		9.1		1.1		6.8		1.2		—
Purchase Obligations – Natural Gas (c)		367.6		129.7		206.2		21.4		10.3
Purchase Obligations – Other (d)		94.3		18.2		28.7		18.3		29.1
Total (e)	$	1,276.8	$	151.5	$	310.3	$	83.6	$	731.4

43

(a)	The principal and interest payments on long-term debt included in the table above do not include obligations associated with Laclede Group’s commitment to issue $25 million of unsecured notes or Laclede Gas’ commitment to issue $100 million of first mortgage bonds in private placements scheduled for settlement in December 2012 and March 2013, respectively. Refer to Long-term Debt, Equity, and Shelf Registrations on page 42 for additional information.
(b)	Lease obligations are primarily for office space, office equipment, vehicles, and power operated equipment in the Regulated Gas Distribution segment. Additional payments will be incurred if renewal options are exercised under the provisions of certain agreements.
(c)	These purchase obligations represent the minimum payments required under existing natural gas transportation and storage contracts and natural gas supply agreements in the Regulated Gas Distribution and Non-Regulated Gas Marketing segments. These amounts reflect fixed obligations as well as obligations to purchase natural gas at future market prices, calculated using June 30, 2012 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.
(d)	These purchase obligations primarily reflect miscellaneous agreements for the purchase of materials and the procurement of services necessary for normal operations.
(e)	The category of Other Long-Term Liabilities has been excluded from the table above because there are no material amounts of contractual obligations under this category. Long-term liabilities associated with unrecognized tax benefits, totaling $6.3 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. At this writing, the Company does not expect to make any contributions to its qualified, trusteed pension plans during the remaining three months of fiscal year 2012. Laclede Gas anticipates a $4.7 million contribution relative to its non-qualified pension plans during the remaining three months of fiscal year 2012. With regard to the postretirement benefits, the Company anticipates Laclede Gas will contribute $6.0 million to the qualified trusts and $0.1 million directly to participants from Laclede Gas’ funds during the remaining three months of fiscal year 2012. For further discussion of the Company’s pension and postretirement benefit plans, refer to Note 2, Pension Plans and Other Postretirement Benefits, of the Notes to Consolidated Financial Statements.

MARKET RISK

Commodity Price Risk

Laclede Gas’ commodity price risk, which arises from market fluctuations in the price of natural gas, is primarily managed through the operation of its PGA Clause. The PGA Clause allows Laclede Gas to flow through to customers, subject to prudence review by the MoPSC, the cost of purchased gas supplies. The Utility is allowed the flexibility to make up to three discretionary PGA changes during each year, in addition to its mandatory November PGA change, so long as such changes are separated by at least two months. The Utility is able to mitigate, to some extent, changes in commodity prices through the use of physical storage supplies and regional supply diversity. Laclede Gas also has a risk management policy that allows for the purchase of natural gas derivative instruments with the goal of managing its price risk associated with purchasing natural gas on behalf of its customers. This policy prohibits speculation. Costs and cost reductions, including carrying costs, associated with the Utility’s use of natural gas derivative instruments are allowed to be passed on to the Utility’s customers through the operation of its PGA Clause. Accordingly, Laclede Gas does not expect any adverse earnings impact as a result of the use of these derivative instruments. However, the timing of recovery for cash payments related to margin requirements may cause short-term cash requirements to vary. Nevertheless, carrying costs associated with such requirements, as well as other variations in the timing of collections of gas costs, are recovered through the PGA Clause. For more information about the Utility’s natural gas derivative instruments, see Note 7, Derivative Instruments and Hedging Activities, of the Notes to Consolidated Financial Statements.

44

In the course of its business, Laclede Group’s non-regulated 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 and swap contracts traded on or cleared through the NYMEX and ICE to lock in margins. At June 30, 2012, 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, swap, and option 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 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 assets at September 30, 2011	$	209		$	1,100	$	1,309
Changes in fair value		5,713			—		5,713
Settlements/purchases - net		(6,836	)		—		(6,836	)
Changes in cash margin		—			1,337		1,337
Net balance of derivative (liabilities) assets at June 30, 2012	$	(914	)	$	2,437	$	1,523

	At June 30, 2012
	Maturity by Fiscal Year
(Thousands)		Total			2012			2013			2014
Fair values of exchange-traded/cleared natural gas derivatives - net	$	(914	)	$	10		$	(879	)	$	(45	)
MMBtu – net (short) long futures/swap/option positions		(12,473	)		(2,423	)		(10,150	)		100

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 2013:

(Thousands)
Net balance of derivative assets at September 30, 2011	$	1,923
Changes in fair value		4,118
Settlements		(2,232	)
Net balance of derivative assets at June 30, 2012	$	3,809

For further details related to LER’s derivatives and hedging activities, see Note 7, Derivative Instruments and Hedging Activities, of the Notes to Consolidated Financial Statements.

45

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 8, Concentrations of Credit Risk, of the Notes to Consolidated Financial Statements.

Interest Rate Risk

The Company is subject to interest rate risk associated with its long-term and short-term debt issuances. Based on average short-term borrowings during the nine months ended June 30, 2012, an increase of 100 basis points in the underlying average interest rate for short-term debt would have caused an increase in interest expense of approximately $0.5 million on an annual basis. Portions of such increases may be offset through the application of PGA carrying costs. At June 30, 2012, Laclede Gas had fixed-rate long-term debt totaling $365 million (including current maturities). 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 Laclede Gas were to reacquire any of these issues in the open market prior to maturity. Under GAAP applicable to Laclede Gas’ regulated operations, losses or gains on early redemptions of long-term debt would typically be deferred as regulatory assets or regulatory liabilities and amortized over a future period.

ENVIRONMENTAL MATTERS

Laclede Gas owns and operates natural gas distribution, transmission and storage facilities, the operations of which are subject to various environmental laws, regulations and interpretations. While environmental issues resulting from such operations arise in the ordinary course of business, such issues have not materially affected the Company’s or Laclede Gas’ financial position and results of operations. As environmental laws, regulations, and their interpretations change, however, Laclede Gas may be required to incur additional costs. For information relative to environmental matters, see Note 11, Commitments and Contingencies, of the Notes to Consolidated Financial Statements.

OFF-BALANCE SHEET ARRANGEMENTS

Laclede Group has no off-balance sheet arrangements.

46

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 44 of this report.

Item 4. Controls and Procedures

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

There have been no changes in our internal control over financial reporting that occurred during our third fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

47

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For a description of environmental matters and legal proceedings, see Note 11, Commitments and Contingencies, of the Notes to Consolidated Financial Statements. For a description of pending regulatory matters of Laclede Gas, see Part I., Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Regulatory and Other Matters, on page 39 of this report.

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

Item 1A. Risk Factors

The following paragraphs should be read in conjunction with the risk factors included in Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended September 30, 2011.

RISKS THAT RELATE TO THE NON-REGULATED GAS MARKETING SEGMENT

Increased competition, fluctuations in natural gas commodity prices, and pipeline infrastructure projects may adversely impact LER’s future profitability.

Competition in the marketplace and fluctuations in natural gas commodity prices have a direct impact on LER’s business. Changing market conditions and prices, the narrowing of regional and seasonal price differentials, and limited future price volatility may adversely impact LER’s sales margins or affect LER’s ability to procure gas supplies and/or to serve certain customers, which may reduce sales profitability and/or increase certain credit requirements caused by reductions in netting capability. Although the FERC regulates the interstate transportation of natural gas and establishes the general terms and conditions under which LER may use interstate gas pipeline capacity to purchase and transport natural gas, LER must occasionally renegotiate its transportation agreements with a concentrated group of pipeline companies. Renegotiated terms of new agreements may impact LER’s future profitability. Profitability may also be adversely impacted if pipeline capacity or future storage capacity secured by LER is not fully utilized and/or its costs are not fully recovered.

Risk management policies, including the use of derivative instruments, may not fully protect LER’s sales and results of operations from volatility and may result in financial losses.

In the course of its business, LER enters into contracts to purchase and sell natural gas at fixed prices and 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. LER currently manages the commodity price risk associated with fixed-price commitments for the purchase or sale of natural gas by either closely matching the offsetting physical purchase or sale of natural gas at fixed prices or through the use of natural gas futures and swap contracts traded on or cleared through the NYMEX and ICE to lock in margins. These exchange-traded/cleared contracts may be designated as cash flow hedges of forecasted transactions. However, market conditions and regional price changes may cause ineffective portions of matched positions to result in financial losses. Additionally, to the extent that LER’s natural gas commitments do not qualify for the normal purchases or normal sales designation (or the designation is not elected), the contracts are recorded as derivatives at fair value each period. Accordingly, the associated gains and losses are reported directly in earnings and may cause volatility in results of operations. Gains or losses (realized and unrealized) on certain wholesale purchase and sale contracts may be required to be presented on a net basis (instead of a gross basis) in the statements of consolidated income. Such presentation could result in reductions to and/or volatility in the Company’s operating revenues.

Item 6. Exhibits

(a) See Exhibit Index

48

SIGNATURE

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

		The Laclede Group, Inc.
Dated:	July 27, 2012	By:	/s/ Steven P. Rasche
			Steven P. Rasche
			Senior Vice President, Finance and Accounting
			(Authorized Signatory and Principal Accounting Officer)

49

INDEX TO EXHIBITS

Exhibit No.
10.1	-	Amended and Restated Firm (Rate Schedule FT) Transportation Service Agreement between Laclede Energy Resources, Inc. and CenterPoint Energy Gas Transmission Company TSA # 1006667.
12	-	Ratio of Earnings to Fixed Charges.
31	-	CEO and CFO Certifications under Exchange Act Rule 13a – 14(a).
32	-	CEO and CFO Section 1350 Certifications.
101.INS	-	XBRL Instance Document. (1)
101.SCH	-	XBRL Taxonomy Extension Schema. (1)
101.CAL	-	XBRL Taxonomy Extension Calculation Linkbase. (1)
101.DEF	-	XBRL Taxonomy Definition Linkbase. (1)
101.LAB	-	XBRL Taxonomy Extension Labels Linkbase. (1)
101.PRE	-	XBRL Taxonomy Extension Presentation Linkbase. (1)

(1) Attached as Exhibit 101 to this Quarterly Report are the following documents formatted in extensible business reporting language (XBRL): (i) Document and Entity Information; (ii) unaudited Statements of Consolidated Income for the three months and nine months ended June 30, 2012 and 2011; (iii) unaudited Statements of Consolidated Comprehensive Income for the three months and nine months ended June 30, 2012 and 2011; (iv) unaudited Consolidated Balance Sheets at June 30, 2012, September 30, 2011 and June 30, 2011; (v) unaudited Statements of Consolidated Cash Flows for the nine months ended June 30, 2012 and 2011, (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.  

50

EX-10.1

Exhibit 10.1

AMENDED AND RESTATED

FIRM (RATE SCHEDULE FT)

TRANSPORTATION SERVICE AGREEMENT

TSA NO.:  1006667

          THIS TRANSPORTATION SERVICE AGREEMENT (“Agreement”), between CenterPoint Energy Gas Transmission Company, LLC (“CEGT”), a Delaware limited liability company (“Transporter”), and Shipper (defined below), covering the transportation of natural gas by Transporter on behalf of Shipper as more particularly described herein, is entered into in accordance with the following terms and conditions:

1)	SHIPPER INFORMATION: Laclede Energy Resources, Inc. 720 Olive Street St. Louis, MO 63101 Attn:  George Godat Phone:  (314)516-8588 Fax:      (314)516-8551 Email:  ggodat@lacledeenergy.com
	Type of Entity: Missouri Corporation
	Transporter’s wire transfer information and addresses for notices and payments shall be located on Transporter’s Internet Web Site.

2)	REGULATORY AUTHORITY:        Subpart G
3)	TERM, CONTRACT DEMAND AND POINTS:

The term, Contract Demand, Receipt Entitlements, if applicable, and Receipt and Delivery Points for this Agreement shall be as shown below. Absent designation of MRO’s for any specific physical Point of Receipt, Transporter shall have no obligation to permit Shipper to utilize any such Point of Receipt or to receive any specific quantities on Shipper’s behalf at such point.
Term:	Effective Date:     Originally November 5, 2008, as amended and restated May 3, 2012, subject to FERC approval.
	Primary Term End Date:  The end of the Day on October 31, 2017
	Evergreen/Term Extension?  No

Contract Demand:	75,000 Dth/D
Receipt Entitlement(s):	Line CP Pooling Area 75,000 Dth/D

Primary Receipt Point(s):	Maximum Receipt Obligation (Dth/D)
ETC/HPL to CP (Meter No. 822000)	50,000
EASTRANS DCP CARTHGE CP (Meter No. 220015)	25,000

Primary Delivery Point(s):	Maximum Delivery Obligation (Dth/D)	Maximum Delivery Pressure (psig)
CGT CP Del	35,509	900
(Meter No. 13548)
TGC CP Del	15,000	Not applicable
(Meter No. 13546)
SESH 42 Header Del	20,000	Not applicable
(Meter No. 898400)
ANR CP Del	4,491	Not applicable
(Meter No. 13547)

Page  1 of 7

AMENDED AND RESTATED

FIRM (RATE SCHEDULE FT)

TRANSPORTATION SERVICE AGREEMENT

TSA NO.:  1006667

4)

RATE:  Unless provided otherwise in an Attachment A to this Agreement in effect during the term of this Agreement, in a capacity release award, or below, Shipper shall pay, or cause to be paid, to Transporter each   month for all services provided hereunder the maximum applicable rate, and any other charges, fees, direct bill amounts, taxes, assessments, or surcharges provided for in Transporter’s Tariff, as on file and in effect from time to time, for each service rendered hereunder.  If Attachment A or this Agreement provides for a rate other than the maximum applicable rate, the following shall apply:

Shipper agrees to pay the rates specified below or on Attachment A for performance of certain gas transportation service under the Agreement. These rates are applicable only in accordance with the following:

(a) Term, Points and/or Rates: The term of the rates, and the Receipt Point(s) and the Delivery Point(s) eligible for such rates, shall be specified below.

(i) Negotiated Rate.

(ii) Description of Points:

The Receipt Points eligible for the rates specified below shall be the points listed in Section 3 of  the Agreement (as such agreement provides on the effective date hereof), all generally available AIRPs and Pools in the Line CP and Neutral Pooling Areas, and all Receipt Points in the Line CP Pooling Area in existence as of July 1, 2009, listed below:

EASTRANS DCP CARTHGE_CP	Meter No. 220015
Marlin Midstream	Meter No. 220025
MARKWEST EAST TX CP	Meter No. 220050
ETC/HPL to CP	Meter No. 822000
CEFS Waskom Plant ST-21	Meter No. 220040
Enbridge DD to CP	Meter No. 220020
Sligo CP Lateral	Meter No. 14101
CHK/LAMID – KEATCHIE	Meter No. 822040
Kinderhawk - Line CP IC	Meter No. 220325
Enterprise @ CP	Meter No. 220060
PVR to CP-3	Meter No. 220017
Arcadia CP IC REC	Meter No. 822090

The Delivery Points eligible for the rates specified below shall be the Primary Delivery Points listed in Section 3 of the Agreement (as such Agreement provides on the effective date hereof) and the following Secondary Delivery Points:

PTP Delivery	Meter No. 808739
Arcadia IC CP Del	Meter No. 822091

(iii)	Description of Rates:
	Transporter shall bill and Shipper shall pay for services under the Agreement up to the Contract Demand (as in effect on the Effective Date hereof) the rates described below.  For the purposes hereof, the term “Transmission Allowance” shall mean the applicable total rate(s) (reservation and commodity components) applicable to the eligible quantities as provided herein.  The applicable Transmission Allowance calculated as provided herein shall not be subject to refund or reduction even if in excess of the maximum otherwise allowed.  If Shipper releases capacity, it shall pay Transporter for any portion of the applicable commodity component calculated as set forth below not paid by the Replacement Shipper.
	Shipper shall pay a Reservation Charge each Month as specified below, expressed as a unit rate on an assumed 100% load factor basis, based on the Dth of Contract Demand specified in the Agreement, regardless of the quantity of gas transported during the Service Month.  Shipper

Page  2 of 7

AMENDED AND RESTATED

FIRM (RATE SCHEDULE FT)

TRANSPORTATION SERVICE AGREEMENT

TSA NO.:  1006667

hereby elects to be billed on a levelized basis to the extent Transporter so determines and such option is available under the Tariff. 

For the period May 1, 2012 through October 31, 2013: 

The applicable Reservation Charge component for services up to Contract Demand (as in effect on the effective date hereof) shall be a unit rate of $0.1441 per Dth. Shipper shall also pay the minimum applicable RS FT Base Commodity Rate for each eligible Dth delivered under this Agreement; provided, however, any deliveries to the Secondary Delivery Point Arcadia IP CP Del (Meter No. 822091) shall incur a fixed incremental charge of $0.02/Dth in addition to the minimum applicable RS FT Base Commodity Rate.

For the period November 1, 2013 through October 31, 2017: 

The applicable Reservation Charge component for services up to Contract Demand (as in effect on the effective date hereof) shall be a unit rate of $0.0500 per Dth.  In addition, if on any Day Shipper does not schedule its entire CD quantity, then the Reservation Charge (expressed as a unit rate) for each Dth not scheduled shall be increased by an amount calculated as follows:

.65 x weighted average Daily Index Spread

The Index Spreads shall be calculated using the formulas set forth below based on Daily Index Prices (“Daily Index”) (using the applicable Midpoint Prices for spot gas delivered to the pipelines at the locations specified below for the Day(s) of flow as published in Platts Gas Daily daily pricesurvey).  If the price information or the applicable publication is unavailable or ceases to be published, the parties shall use a substitute Index price or formula as posted on the CEGT Internet Web Site for the day or month in question.

For daily deliveries scheduled to all eligible Delivery Points, calculate the applicable Daily Index Spread as follows:

Daily Index for the relevant Primary or Secondary Delivery Point (see below), minus

$0.09, minus

Daily Index for Oklahoma, CenterPoint, East, minus

Fuel Value plus applicable EPC

If on any Day, the result of the above calculation would yield a Daily Index Spread of 0 or less, then the Daily Index Spread for that point for that Day shall be deemed to be 0. 

The Fuel Value shall be calculated by multiplying the applicable fuel percentage (the sum of applicable Fuel Use and LUFG percentages), as authorized and in effect from time to time in Transporter’s Tariff, by the Daily Index for Oklahoma, CenterPoint, East.

For purposes of calculation of the applicable Index Spreads, use the following Daily Index Prices:

 • TGC Rich Core Del:  Others, Trunkline, Zone 1A

 • CGT PV Core Del, SESH 42 Header Del, PTP Delivery, and Arcadia IP CP Del:  Louisiana – Onshore South, Columbia Gulf, mainline

Shipper shall also pay the minimum applicable RS FT Base Commodity Rate for each eligible Dth delivered under this Agreement.

Term of Rate:
Begin Date(s):	Effective Date
End Date(s):	End of the Day on October 31, 2017

Page 3 of 7

 AMENDED AND RESTATED

FIRM (RATE SCHEDULE FT)

TRANSPORTATION SERVICE AGREEMENT

TSA NO.:  1006667

(b)	Authorized Overrun:  Unless Transporter agrees otherwise, the rate for any authorized overrun quantities shall be the greater of the maximum Tariff rate or the applicable rate described above.
(c)	General:  In consideration for Shipper’s continuing compliance with the provisions of the Agreement, the transportation rates and charges as defined above or on Attachment A for the specified services provided under the Agreement only apply to receipts from, and subsequent deliveries to, the Points of Receipt and Delivery, quantities and/or time periods described above or on Attachment A and to reserved capacity necessary to effect such service. In addition to any rate or amount referred to herein (including discounted rates, Negotiated Rates, overrun rates and maximum Tariff rates), except as specifically provided otherwise herein or on Attachment A, Shipper shall provide or pay and Transporter shall retain or charge Fuel Use and LUFG allowances or charges (including the EPC surcharge) in such quantities or amounts as authorized from time to time by the Tariff and shall pay any applicable charges, penalties, surcharges, fees, taxes, assessments and/or direct billed amounts provided for in the Tariff.  In any event, the rate in any Month shall never be below Transporter’s applicable minimum Tariff rate for a discount rate transaction.  For a Negotiated Rate transaction, the rate in any month shall never be below Transporter’s applicable minimum Tariff rate, unless Transporter otherwise agrees.  Transporter shall not be responsible for the payment and satisfaction of any taxes assessed or levied on the receipt, transmission (and any activities in connection therewith), delivery, use and/or consumption with respect to Gas delivered or received by Shipper, unless Transporter agrees otherwise.
(d)	Rate-Related Provisions:

(i) Consideration for Rate Granted:  Transporter agrees to the rates specified herein or on Attachment A in exchange for Shipper’s agreement to forego credits or other benefits to which Shipper would otherwise be entitled, but only to the extent such credits or benefits would result in a greater economic benefit over the applicable term than that represented by the agreed-upon rate.  Accordingly, unless Transporter otherwise agrees, Shipper will not receive credits (with the exception of (1) penalty revenue credits provided pursuant to Section 31 of the General Terms and Conditions of Transporter’s Tariff, and (2) capacity release credits) from rates, refunds or other revenues collected by Transporter or Shipper if to do so would effectively result in a lower rate or greater economic benefit to Shipper; provided, however, that for a Shipper taking service under a Negotiated Rate agreement, Transporter and Shipper can agree pursuant to Section 19.8 of the General Terms and Conditions of Transporter’s Tariff that Transporter will retain some or all of the capacity release credits to the extent those credits exceed the amount of the Shipper’s invoiced  demand  component.  If  the  parties’ agreement to the foregoing is determined invalid or if Shipper seeks to obtain credits or benefits inconsistent therewith, unless Transporter otherwise agrees, it will have the right to immediately terminate or modify any provisions herein or of Attachment A that would allow Shipper to pay amounts less than the maximum applicable Tariff rate.

(ii) Limitation on Agreed Upon Rate:  Unless Transporter agrees otherwise, if at any time receipts and/or deliveries are initially sourced into the system, nominated, scheduled and/or made, by any means or by operation of any Tariff mechanisms, with respect to the capacity obtained by, through or under the Agreement at points, or under conditions, other than those specified herein or on Attachment A, then as of such date, and for the remainder of the Service Month in which such non-compliance occurred, or the remainder of the term of the Agreement, whichever is shorter, Shipper shall be obligated to pay no less than the maximum applicable Tariff rates for service under the Agreement.  This limitation shall not apply to the extent that Transporter has requested Shipper to receive and/or deliver other than as specified herein or on Attachment A.  Such request may be made via e-mail, in writing, or via Internet Web Site posting, and the document in which such request is made shall be deemed to amend this Agreement to the extent applicable.

(iii) Regulatory Authority:  This Agreement (including Attachment A) is subject to Section 16 of the GT&C of Transporter’s Tariff.  Transporter and Shipper hereby acknowledge that this Agreement is subject to all valid and applicable federal and local laws and to the orders, rules and regulations of any duly constituted federal or local regulatory body or governmental authority having jurisdiction.   Any provision of this Agreement which is determined by any court or regulatory body having jurisdiction to

Page  4 of 7

AMENDED AND RESTATED

FIRM (RATE SCHEDULE FT)

TRANSPORTATION SERVICE AGREEMENT

TSA NO.:  1006667

be invalid or unenforceable will be ineffective to the extent of such determination only, without invalidating, or otherwise affecting the validity of, the remaining provisions.  Unless the parties agree otherwise, if Transporter has made a good faith determination that a federal or local law, or order, rule or regulation of any governmental authority having or asserting jurisdiction (1) requires performance by Transporter that is inconsistent with the terms specified herein or on Attachment A, or (2) conditions or prohibits the granting of selective discounts or other rates specified herein or on Attachment A, then Transporter may provide notice that it intends to renegotiate the rates under the Agreement.  If the parties fail to reach agreement within forty-five (45) days of any renegotiation notice given pursuant to the terms of this paragraph, then:  (1) the rate provisions herein or on Attachment A shall be terminated, and the rate for service herein or under Attachment A shall be Transporter’s applicable maximum Tariff rate, or (2) if Transporter’s applicable maximum Tariff rate is greater than the rate for service herein or on Attachment A, at the Shipper’s option, the Agreement and any applicable  Attachment A shall terminate.  The effective date of this renegotiation or termination shall be the first day of the month following the end of the 45-day renegotiation period; provided, however, that the effective date will comply with the requirements of the applicable federal or local law, or order, rule or regulation of any governmental authority having or asserting jurisdiction.

(iv) Entire Agreement:  Attachment A, if applicable, shall supplement the Agreement with respect to the matters agreed to, and together shall constitute the entire understanding of the parties relating to said matters as of the effective date stated therein.  Unless otherwise specified, all prior agreements, correspondence, understandings and representations are hereby superseded and replaced by Attachment A and the Agreement.  Except as otherwise provided herein, all terms used herein with initial capital letters are so used with the respective meanings ascribed to them in Transporter’s Tariff.

(v) Failure to Exercise Rights:  Failure to exercise any right under Attachment A, if applicable, or the Agreement shall not be considered a waiver of such right in the future.  No waiver of any default in the performance of Attachment A or the Agreement shall be construed as a waiver of any other existing or future default, whether of a like or different character.

(e) Inability to Collect Negotiated Rates:  If this Agreement covers a Negotiated Rate transaction, and Transporter is unable to collect Negotiated Rates due to a change in Commission policy or rejection of the transaction by the Commission prior to or during the term of such transaction, then, unless the parties agree otherwise, Shipper shall pay the maximum Tariff rate for the services.  In such event, Transporter shall notify Shipper in writing of the requirement to pay maximum Tariff rates and, if the maximum Tariff rates are greater than the Negotiated Rates under such transaction, Shipper shall have no more than thirty (30) days from the date of such notification to give notice in writing of termination of the applicable Agreement, with such termination to be effective no earlier than the end of the Month following the Month in which such termination notice is received.

5) OTHER PROVISIONS:

5.1)	Payments shall be received by Transporter within the time prescribed by Section 14 of the GT&C of Transporter’s Tariff.  Amounts past due hereunder shall bear interest as provided in Section 14 of the GT&C of the Tariff.  Shipper shall pay all costs associated with the collection of such past due amounts including, but not limited to, attorneys’ fees and court costs.  Shipper hereby represents and warrants that the party executing this Agreement on its behalf is duly authorized and possesses all necessary corporate or other authority required to legally bind Shipper.
5.2)	Do the parties agree that the provisions of Section 13.4 of the GT&C of Transporter’s Tariff shall apply with respect to third-party transportation?               Yes _____ No __X__
5.3)	a)	Does this Agreement supersede and cancel a pre-existing Transportation Service Agreement(s) between the parties?  Yes _____ No __X___

Page  5 of 7

 AMENDED AND RESTATED

FIRM (RATE SCHEDULE FT)

TRANSPORTATION SERVICE AGREEMENT

TSA NO.:  1006667

	b)	Does this Agreement amend and restate in its entirety a pre-existing Transportation Service Agreement(s) between the parties?   Yes __X___ No _____
		If Yes, the Transportation Service Agreement(s) are described as follows:
		Effective May 3, 2012, this Agreement amends and restates Transportation Service Agreement No. 1006667, originally effective November 5, 2008, as subsequently amended, restated and/or superseded prior to or as of the effective date hereof.
5.4)	Is this Agreement entered into pursuant to and subject to CAPACITY RELEASE, Section 19 of the GT&C of Transporter’s Tariff?    Yes _____ No __X__
5.5)	Does this Agreement include any other terms/provisions permitted by the Tariff?              Yes __X___ No _____
	If Yes, those provisions (including a specific reference to the Tariff authority for each such provision) are as follows:
	(a)	In accordance with Section 19.8 of the GT&C of the Tariff, the parties hereby agree that Transporter shall retain, and not credit to Shipper, credits for capacity releases to the extent amounts paid by or invoiced to Replacement Shipper(s) as demand or reservation type charges exceed the amount of Shipper’s invoiced demand component.
	(b)	In accordance with Section 21.1 of the GT&C of Transporter’s Tariff, the parties hereby agree that Shipper shall have a contractual “right-of-first-refusal” which will provide to it the same rights and obligations regarding extending service under the Agreement as to reserved capacity on Transporter’s system beyond the termination or expiration dates as would be available to Shippers eligible to invoke the provisions of Section 21 of the GT&C of Transporter’s Tariff, as on file and in effect from time to time.
	(c)	Pursuant to Section 5.4 (b) of the General Terms and Conditions, the parties have agreed to the maximum pressure at which Transporter must deliver Gas as set forth in Section 3 above.

6) All modifications, amendments or supplements to the terms and provisions hereof shall be effected only by supplementary written (or electronic, to the extent Transporter permits or requires) consent of the parties.

7) SIGNATURE:  This Agreement constitutes a contract with Transporter for the transportation of natural gas, subject to the terms and conditions hereof, the General Terms and Conditions attached hereto, and any applicable attachment(s), all of which are incorporated herein by reference and made part of this Agreement.

  CENTERPOINT ENERGY GAS TRANSMISSION COMPANY, LLC LACLEDE ENERGY RESOURCES, INC.

By:	/s/ Carol Burchfield	By:	/s/ S.E. Jaskowiak
Name:	Carol Burchfield	Name:	S.E. Jaskowiak
Title:	Div. VP Mktg. & Bus. Dev.	Title:	President
Date:	5/03/12	Date:	5/03/12

Page  6 of 7

GENERAL TERMS AND CONDITIONS

TO AMENDED AND RESTATED FIRM (RATE SCHEDULE FT)

TRANSPORTATION SERVICE AGREEMENT

TSA NO.:  1006667

1. This Agreement shall be subject to the provisions of Rate Schedule FT as well as the General Terms and Conditions (“GT&C”) set forth in Transporter’s Tariff, as on file and in effect from time to time, all of which by this reference are made a part hereof.

2. In accordance with Section 12.2 of the GT&C of Transporter’s Tariff, Transporter shall have the right at any time, and from time to time, to file and place into effect unilateral changes or modifications in the rates and charges, and other terms and conditions of service hereunder, and as set forth in said Rate Schedule and in said GT&C of Transporter’s Tariff, in accordance with the Natural Gas Act or other applicable law.  Nothing contained in the foregoing provision shall preclude or prevent Shipper from protesting any such changes or modifications; however, Shipper agrees to pay all rates and charges, and to comply with all terms and conditions, in effect under the Tariff.

3. Upon Shipper’s failure to pay when due all or any part of amounts billed in connection with services rendered or to comply with the terms of this Agreement, Transporter may terminate this Agreement and/or suspend service, as appropriate, in accordance with the provisions of Section 14 of the GT&C of Transporter’s Tariff. 

4. In accordance with Section 21.1 of the GT&C of Transporter’s Tariff, upon termination hereof for whatever reason, Shipper agrees to stop delivering gas to Transporter for service and, unless otherwise agreed by Transporter, to seek no further service from Transporter hereunder.  Shipper agrees to cooperate with and assist Transporter in obtaining such regulatory approvals and authorizations, if any, as are necessary or appropriate in view of such termination and abandonment of service hereunder.

5. In accordance with Section 5.7(e) of the GT&C of Transporter’s Tariff, termination of this Agreement shall not relieve either party of any obligation that might otherwise exist to cash-out or correct any Imbalance hereunder nor relieve Shipper of its obligation to pay any monies due hereunder to Transporter and any portions of this Agreement necessary to accomplish such purposes shall be deemed to survive for the time and to the extent required.

6. In accordance with Sections 2.1 and 2.2 of Rate Schedule FT of Transporter’s Tariff, subject to the provisions of the Tariff and this Agreement, Transporter shall receive, transport, and deliver, for the account of Shipper for the purposes contemplated herein, on a firm basis a quantity of Gas up to the quantity or quantities specified in  the Agreement.

7. In accordance with Sections 2.1 and 3.3 of Rate Schedule FT of Transporter’s Tariff, Gas shall be (i) tendered to Transporter for transportation hereunder at the Point(s) of Receipt and (ii) delivered by Transporter after transportation to Shipper, or for Shipper’s account, at the Point(s) of Delivery on the terms and at the points shown in this Agreement.  Subject to the provisions of the Tariff, Transporter shall tender for delivery quantities of Gas thermally-equivalent to those delivered by Shipper, less, as applicable, Fuel Use and LUFG, or Alternate Fuel Retentions, retained.

8. Except as otherwise permitted in the Tariff, and in accordance with Section 19 of the GT&C of Transporter’s Tariff, this Agreement shall not be assigned by Shipper in whole or in part, nor shall Shipper agree to provide services to others by use of any capacity contracted for under the Agreement, without Transporter’s prior written consent.  In addition to all other rights and remedies, Transporter may terminate the Agreement immediately if it is assigned by Shipper or if Shipper subcontracts the capacity to others contrary to the provisions hereof, whether the assignment or contract be voluntary, or by operation of law or otherwise.  Subject to the above, the respective rights and obligations of the parties under the Agreement shall extend to and be binding upon their heirs, successors, assigns and legal representatives.  Shipper may request that Transporter consent to Shipper’s assignment of this Agreement to an entity with which Shipper is affiliated subject to the assignee’s satisfaction of the criteria in Section 14 of the GT&C of Transporter’s Tariff, in the situation in which, after Shipper obtains the Agreement, a corporate reorganization results in a transfer to an affiliate of the function for which the capacity was obtained.  Any person which shall succeed by purchase, merger or consolidation to the properties, substantially as an entirety, of either party hereto, shall be entitled to the rights and shall be subject to the obligations of its predecessor in title under this Agreement; and either party may assign or pledge this Agreement under the provisions of any mortgage, deed of trust, indenture, bank credit agreement, assignment or similar instrument which it has executed or may execute hereafter.

9. Any notice, statement, or bill provided for in this Agreement shall be in writing (or provided electronically via the Internet to the extent Transporter permits or requires) and shall be considered as having been given if hand delivered, or, if received, when mailed by United States mail, postage prepaid, to the addresses specified herein, or such other addresses as either party shall designate by written notice to the other.  Additionally, notices shall be considered as having been given, if received, when sent via facsimile or through electronic data interchange.

10. In accordance with the form of credit application contained in the Tariff, Shipper agrees that any representations and agreements contained in any credit application submitted in connection with this service shall be incorporated herein by reference and made a part hereof.  

Page  7 of 7

CENTERPOINT ENERGY GAS TRANSMISSION COMPANY, LLC (‘CEGT’)

TRANSACTION CONFIRMATION

FIRM POOL TRANSFER (RATE SCHEDULE PS)

PSA NO. 1003129

TRANSACTION CONFIRMATION NO. 3000001

Pool Manager:  Laclede Energy Resources, Inc.

Description of Rates, Points, Quantity and Term:

CEGT hereby agrees to offer Firm Services to Pool Manager in accordance with the provisions set forth below and in accordance with the provisions of the Tariff.
Pool Transfers:  Firm between Pool Manager's
	Neutral Pooling Area Pools to Line CP Pooling Area Pools
Capacity Reserved:  75,000 Dth/Day

Term:	Originally effective as of July 1, 2009, as amended and restated May 1, 2012, through the end of the Day on November 30, 2017
Rates:	CEGT shall bill and Pool Manager shall pay a Monthly Reservation Charge under the Agreement for services which shall be $0.04 per Dth of Capacity Reserved.

Other Tariff-Permitted Provisions:

Pursuant to Section 21.10, GT & C, of the Tariff, the parties have agreed to an extension of the term with respect to all the capacity committed under the Service Agreement being extended and amended to provide the service at discounted rates.

CEGT is successor by conversion to CenterPoint Energy Gas Transmission Company.

Executed by a duly authorized representative of each party hereto, in the space provided below:

TRANSPORTER:	POOL MANAGER:
CENTERPOINT ENERGY GAS TRANSMISSION COMPANY, LLC	LACLEDE ENERGY RESOURCES, INC.

By:	/s/ Carol Burchfield	By:	/s/ S.E. Jaskowiak
Name:	Carol Burchfield	Name:	S.E. Jaskowiak
Title:	Div. VP Mktg. & Bus. Dev.	Title:	President
Date:	5/01/12	Date:	4/30/12

EX-12

Exhibit 12

THE LACLEDE GROUP, INC. AND SUBSIDIARY COMPANIES

SCHEDULE OF COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

	Twelve Months Ended
	June 30,		September 30,
(Thousands of Dollars)		2012		2011		2010		2009		2008		2007
Income from continuing      operations before interest
charges and income taxes	$	112,011	$	118,424	$	107,986	$	126,517	$	113,228	$	101,867
Add: One third of applicable
rentals charged to operating
expense (which approximates
the interest factor)		1,671		1,799		1,825		1,833		1,691		1,485
Total Earnings	$	113,682	$	120,223	$	109,811	$	128,350	$	114,919	$	103,352
Interest on long-term debt –
Laclede Gas	$	22,958	$	23,161	$	24,583	$	24,583	$	19,851	$	22,502
Other interest		2,095		2,256		2,269		5,163		9,626		11,432
Add: One third of applicable
rentals charged to operating
expense (which approximates
the interest factor)		1,671		1,799		1,825		1,833		1,691		1,485
Total Fixed Charges	$	26,724	$	27,216	$	28,677	$	31,579	$	31,168	$	35,419
Ratio of Earnings to Fixed
Charges		4.25		4.42		3.83		4.06		3.69		2.92

EX-31

Exhibit 31

CERTIFICATION

I, Suzanne Sitherwood, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of The Laclede Group, Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
		a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
		b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
		c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
		d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
		a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
		b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	July 27, 2012	Signature:	/s/ Suzanne Sitherwood
			Suzanne Sitherwood
			President and Chief Executive Officer

CERTIFICATION

I, Mark D. Waltermire, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of The Laclede Group, Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
		a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
		b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
		c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
		d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.	The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
		a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
		b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	July 27, 2012	Signature:	/s/ Mark D. Waltermire
			Mark D. Waltermire
			Executive Vice President, Chief Financial Officer

EX-32

Exhibit 32

Section 1350 Certification

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, I, Suzanne Sitherwood, President and Chief Executive Officer of The Laclede Group, Inc., hereby certify that
	(a)	To the best of my knowledge, the accompanying report on Form 10-Q for the quarter ended June 30, 2012 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and
	(b)	To the best of my knowledge, the information contained in the accompanying report on Form 10-Q for the quarter ended June 30, 2012 fairly presents, in all material respects, the financial condition and results of operations of The Laclede Group, Inc.

Date:	July 27, 2012	/s/ Suzanne Sitherwood
		Suzanne Sitherwood
		President and Chief Executive Officer

Section 1350 Certification

Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, I, Mark D. Waltermire, Executive Vice President, Chief Financial Officer of The Laclede Group, Inc., hereby certify that
	(a)	To the best of my knowledge, the accompanying report on Form 10-Q for the quarter ended June 30, 2012 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and
	(b)	To the best of my knowledge, the information contained in the accompanying report on Form 10-Q for the quarter ended June 30, 2012 fairly presents, in all material respects, the financial condition and results of operations of The Laclede Group, Inc.

Date:	July 27, 2012	/s/ Mark D. Waltermire
		Mark D. Waltermire
		Executive Vice President, Chief Financial Officer

XML

COMMITMENTS AND CONTINGENCIES (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended	12 Months Ended
	Jun. 30, 2012	Sep. 30, 2007	Sep. 30, 2006	Jul. 27, 2012	Jul. 26, 2012
Commitments [Abstract]
Approximate contract amount of project	$ 6
Minimum total payments required for natural gas contracts	368
Leases and Guarantees [Abstract]
Guaranteed amount for performance and payment of certain wholesale gas supply purchases	79.8			81.8
Increase (decrease) in guaranteed amount for performance and payment of certain wholesale gas supply purchases	2.0
Contingencies and Indemnifications [Abstract]
Number of former manufactured gas plant (MGP) sites in Missouri	three
Number of former manufactured gas plant (MGP) sites in Shrewsbury, Missouri	one
Number of former manufactured gas plant (MGP) sites in the City of St. Louis	two
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
Original proposed disallowance amount related to recovery of purchased gas costs	7.2	1.5	2.8
Adjusted proposed disallowance amount related to purchase gas costs	1.7
Amount remaining on deposit with a brokerage firm for Laclede Gas					1.5
Amount remaining on deposit with a brokerage firm for Laclede Energy Resources, Inc.					$ 0.4

XML

FAIR VALUE OF FINANCIAL INSTRUMENTS (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Sep. 30, 2011	Jun. 30, 2011	Sep. 30, 2010
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	$ 21,523	$ 43,277	$ 60,922	$ 86,919
Carrying (Reported) Amount, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	21,523	43,277	60,922
Short-term debt	0	46,000	0
Long-term debt, including current portion	364,401	364,357	364,343
Estimate of Fair Value, Fair Value Disclosure [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	21,523	43,277	60,922
Short-term debt	0	46,000	0
Long-term debt, including current portion	445,961	443,739	397,684
Quoted Prices in Active Markets (Level 1) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	11,560
Short-term debt	0
Long-term debt, including current portion	0
Significant Observable Inputs (Level 2) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	9,963
Short-term debt	0
Long-term debt, including current portion	445,961
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	0
Short-term debt	0
Long-term debt, including current portion	$ 0

XML

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

9 Months Ended

Jun. 30, 2012

Other Income and (Income Deductions) -- Net [Abstract]

Other Income and (Income Deductions) by Component

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
(Thousands)	2012			2011			2012			2011
Interest income	$	337		$	182		$	1,001		$	897
Net investment gain		264			414			2,458			1,541
Other income		(15	)		(21	)		(4	)		53
Other income deductions		(135	)		(418	)		316			(22	)
Other Income and (Income Deductions) – Net	$	451		$	157		$	3,771		$	2,469

XML

OTHER INCOME AND (INCOME DEDUCTIONS) - NET (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Other Income and (Income Deductions) -- Net [Abstract]
Interest income	$ 337	$ 182	$ 1,001	$ 897
Net investment gain	264	414	2,458	1,541
Other income	(15)	(21)	(4)	53
Other income deductions	(135)	(418)	316	(22)
Other Income and (Income Deductions) - Net	$ 451	$ 157	$ 3,771	$ 2,469

XML

STOCK-BASED COMPENSATION

9 Months Ended

Jun. 30, 2012

Disclosure of Compensation Related Costs Share Based Payments [Abstract]

STOCK-BASED COMPENSATION

3. STOCK-BASED COMPENSATION

Awards of stock-based compensation are made pursuant to The Laclede Group 2006 Equity Incentive Plan (2006 Plan) and the Restricted Stock Plan for Non-Employee Directors. Refer to Note 3 of the Consolidated Financial Statements included in the Company’s Form 10-K for the fiscal year ended September 30, 2011 for descriptions of these plans. In January 2012, shareholders approved certain amendments to the 2006 Plan, including an amendment allowing members of the Company’s Board of Directors to participate in the 2006 Plan. Accordingly, effective February 1, 2012, no additional awards will be granted under the Restricted Stock Plan for Non-Employee Directors, as any such awards will be made pursuant to the 2006 Plan.

Restricted Stock Awards

During the nine months ended June 30, 2012, the Company granted 103,763 performance-contingent restricted share units to executive officers and key employees at a weighted average grant date fair value of $36.55 per share. This number represents the maximum shares that can be earned pursuant to the terms of the awards. The share units have a performance period ending September 30, 2014. While the participants have no interim voting rights on these share units, dividends accrue during the performance period and are paid to the participants upon vesting, but are subject to forfeiture if the underlying shares units do not vest. The number of share units that will ultimately vest is dependent upon the attainment of certain levels of earnings and other strategic goals, as well as the Company’s level of total shareholder return (TSR) during the performance period relative to a comparator group of companies. This TSR provision is considered a market condition under GAAP.

Activity of restricted stock and restricted stock units subject to performance and/or market conditions during the nine months ended June 30, 2012 is presented below:

			Weighted
			Average
	Shares/		Grant Date
	Units		Fair Value
Nonvested at September 30, 2011	259,075			$	34.29
Granted (maximum shares that can be earned)	103,763			$	36.55
Vested	(48,429	)		$	48.70
Forfeited	(82,006	)		$	38.27
Nonvested at June 30, 2012	232,403			$	30.89

During the nine months ended June 30, 2012, the Company granted 30,475 shares of time-vested restricted stock to executive officers and key employees at a weighted average grant date fair value of $39.72 per share. These shares were awarded on December 1, 2011 and May 1, 2012 and vest December 1, 2014 and May 1, 2015, respectively. In the interim, participants receive full voting rights and dividends, which are not subject to forfeiture.

In January 2012, the Company granted 13,700 shares of time-vested restricted stock to non-employee directors at a weighted average grant date fair value of $41.36 per share. These shares were granted under the Restricted Stock Plan for Non-Employee Directors and vest depending on the participant’s age upon entering the plan and years of service as a director. The plan’s trustee acquires the shares for the awards in the open market and holds the shares as trustee for the benefit of the non-employee directors until the restrictions expire. In the interim, the participants receive full dividends and voting rights. As discussed above, effective February 1, 2012, any awards to non-employee directors will be made pursuant to The Laclede Group 2006 Equity Incentive Plan.

Time-vested restricted stock and stock unit activity for the nine months ended June 30, 2012 is presented below:

			Weighted
			Average
	Shares/		Grant Date
	Units		Fair Value
Nonvested at September 30, 2011	143,350			$	37.00
Granted	44,175			$	40.23
Vested	(54,800	)		$	41.46
Forfeited	(15,300	)		$	33.87
Nonvested at June 30, 2012	117,425			$	36.54

During the nine months ended June 30, 2012, 88,529 shares of restricted stock and stock units (performance-contingent and time-vested), awarded on February 14, 2008, November 5, 2008, and March 31, 2009, vested. The Company withheld 29,303 of the vested shares at a weighted average price of $39.96 per share pursuant to elections by employees to satisfy tax withholding obligations.

Stock Option Awards

Stock option activity for the nine months ended June 30, 2012 is presented below:

					Weighted
					Average
			Weighted		Remaining	Aggregate
			Average		Contractual	Intrinsic
	Stock		Exercise		Term	Value
	Options		Price		(Years)	($000)
Outstanding at September 30, 2011	305,875		$	30.72
Granted	—		$	—
Exercised	(57,375	)	$	31.07
Forfeited	—		$	—
Expired	—		$	—
Outstanding at June 30, 2012	248,500		$	30.65	2.5	$	2,277
Fully Vested and Expected to Vest at June 30, 2012	248,500		$	30.65	2.5	$	2,277
Exercisable at June 30, 2012	248,500		$	30.65	2.5	$	2,277

The closing price of the Company’s common stock was $39.81 at June 30, 2012.

Equity Compensation Costs

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

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
(Thousands)	2012			2011			2012			2011
Total equity compensation cost	$	678		$	1,555		$	2,029		$	3,095
Compensation cost capitalized		(230	)		(371	)		(589	)		(702	)
Compensation cost recognized in net income		448			1,184			1,440			2,393
Income tax benefit recognized in net income		(173	)		(457	)		(556	)		(923	)
Compensation cost recognized in net income,
net of income tax	$	275		$	727		$	884		$	1,470

As of June 30, 2012, there was $4.8 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 2.3 years.

XML

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 1 (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Pension Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost - benefits earned during the period	$ 2,295	$ 2,388	$ 6,908	$ 7,164
Interest Cost	4,824	4,705	14,535	14,115
Expected return on plan assets	(4,899)	(4,712)	(14,697)	(14,136)
Amortization of prior service cost (credit)	148	161	444	481
Amortization of actuarial loss	2,252	2,557	6,788	7,671
Loss on lump-sum settlement	0	0	3,407	0
Sub-total	4,620	5,099	17,385	15,295
Regulatory adjustment	(484)	(864)	(1,451)	(5,259)
Net benefit cost	4,136	4,235	15,934	10,036
Postretirement Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost - benefits earned during the period	2,015	1,919	6,045	5,757
Interest Cost	1,380	1,210	4,140	3,632
Expected return on plan assets	(991)	(911)	(2,973)	(2,734)
Amortization of transition obligation	34	34	102	102
Amortization of prior service cost (credit)	(518)	(582)	(1,554)	(1,746)
Amortization of actuarial loss	1,065	1,111	3,195	3,332
Sub-total	2,985	2,781	8,955	8,343
Regulatory adjustment	(604)	(400)	(1,812)	(1,671)
Net benefit cost	$ 2,381	$ 2,381	$ 7,143	$ 6,672

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Part 2 (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Abstract]
Gross Receipts taxes recorded in regulated gas distribution operating revenues	$ 5.7	$ 7.5	$ 31.4	$ 39.1

XML

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS Part 2 (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Jun. 30, 2012	Dec. 31, 2010	Aug. 01, 2007
Pension Plans and Other Postretirement Benefits [Abstract]
Extent of Lump-sum payments recognized, percentage	100%
Lump-sum payments recognized as settlements	$ 6.4
Implementation period used to calculate return on plan assets (in years)	four-year
Gains or losses includible in cost amortized to extent exceeds benefit obligations or market-related value of plan assets, percentage	10.00%
Recovery in rates for the qualified pension plans base allowance		15.5	4.8
Recovery in rates for postretirement benefit		9.5	7.6
Defined Benefit Plan, Pension Plans, Qualified Trusts, Contributions by Employer, Fiscal Year To Date	33.3
Defined Benefit Plan, Pension Plans, Non-Qualified Plans, Contributions by Emplyer, Fiscal Year To Date	2.0
Defined Benefit Plan, Pension Plans, Non-Qualified Plans, Estimated Future Employer Contributions Remaining For Current Fiscal Year, Description	4.7
Medical insurance available until age is reached after early retirement	65
Amortization period for transition obligation excluded from postretirement benefit cost (in years)	20 years
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Other Postretirement Benefit Plans, Qualified Trusts, Contributions by Employer, Fiscal Year To Date	6.0
Defined Benefit Plan, Other Postretirement Benefit Plans, Non-Qualified Plans, Contributions by Employer, Fiscal Year To Date	0.1
Defined Benefit Plan, Other Postretirement Benefit Plans, Qualified Trusts, Estimated Future Employer Contributions Remaining for Current Fiscal Year, Description	6.0
Defined Benefit Plan, Other Postretirement Benefit Plans, Estimated Future Payment Directly to Participants, Description	$ 0.1

XML

STOCK-BASED COMPENSATION (Details) (USD $)	3 Months Ended		9 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012 Restricted Stock Awards [Member]	Jun. 30, 2012 Restricted Stock Awards [Member] Time Vested Restricted Stock and Time Vested Restricted Stock Units [Member]	Jun. 30, 2012 Restricted Stock Awards [Member] Non Employee Directors [Member] Time Vested Restricted Stock and Time Vested Restricted Stock Units [Member]	Jun. 30, 2012 Restricted Stock Awards [Member] Executive Officers and Key Employees [Member] Performance Contingent Restricted Stock and Stock Units [Member]	Jun. 30, 2012 Restricted Stock Awards [Member] Executive Officers and Key Employees [Member] Time Vested Restricted Stock and Time Vested Restricted Stock Units [Member]	Jun. 30, 2012 Stock Options Awards [Member]	Sep. 30, 2011 Stock Options Awards [Member]
Restricted Stock Awards [Abstract]
Granted (in shares)						44,175	13,700	103,763	30,475
Granted, weighted average grant date fair value (per share)						$ 40.23	$ 41.36	$ 36.55	$ 39.72
Vested restricted stock withheld for tax withholding obligations (in shares)					29,303
Vested restricted stock withheld for tax withholding obligations, weighted average price (in dollars per share)					$ 39.96
Restricted shares/units activity [Roll-Forward]
Nonvested, beginning of period (in shares)						143,350		259,075
Granted (in shares)						44,175	13,700	103,763	30,475
Vested (in shares)					(88,529)	(54,800)		(48,429)
Forfeited (in shares)						(15,300)		(82,006)
Nonvested, end of period (in shares)						117,425		232,403
Weighted average Grant Date Fair Value [Abstract]
Nonvested Beginning Balance, weighted average grant date fair value (per share)						$ 37.00		$ 34.29
Granted, weighted average grant date fair value (per share)						$ 40.23	$ 41.36	$ 36.55	$ 39.72
Vested, weighted average grant date fair value (per share)						$ 41.46		$ 48.70
Forfeited, weighted average grant date fair value (per share)						$ 33.87		$ 38.27
Nonvested Ending Balance, weighted average grant date fair value (per share)						$ 36.54		$ 30.89
Stock Options - Shares [Roll Forward]
Outstanding Balance - stock options										248,500	305,875
Fully Vested and Expected to Vest, end of period (in shares)										248,500
Exercisable, end of period (in shares)										248,500
Granted - stock options (in shares)										0
Exercised - stock options (in shares)										(57,375)
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)										$ 30.65	$ 30.72
Granted, weighted average exercise price - stock options (per share)										$ 0.00
Exercised, weighted average exercise price - stock options (per share)										$ 31.07
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)										$ 30.65	$ 30.72
Fully Vested and Expected to Vest at End of Period, weighted average exercise price - stock options (per share)										$ 30.65
Exercisable at End of Period, weighted average exercise price - stock options (per share)										$ 30.65
Outstanding Ending Balance, weighted average remaining contractual term - stock options (in years)										2 years 6 months 0 days
Fully Vested and Expected to Vest at End of Period, weighted average remaining contractual term - stock options (in years)										2 years 6 months 0 days
Exercisable at End of Period, weighted average remaining contractual term - stock options (in years)										2 years 6 months 0 days
Outstanding Ending Balance, aggregate intrinsic value - stock options										$ 2,277,000
Fully Vested and Expected to Vest at End of Period, aggregate intrinsic value - stock options										2,277,000
Exercisable at End of Period, aggregate intrinsic value - stock options										2,277,000
Stock Option Awards [Abstract]
Common stock closing price (per share)										$ 39.81
Total equity compensation cost	678,000	1,555,000	2,029,000	3,095,000
Compensation cost capitalized	(230,000)	(371,000)	(589,000)	(702,000)
Compensation cost recognized in net income	448,000	1,184,000	1,440,000	2,393,000
Income tax benefit recognized in net income	(173,000)	(457,000)	(556,000)	(923,000)
Compensation cost recognized in net income, net of income tax	275,000	727,000	884,000	1,470,000
Total unrecognized compensation cost	$ 4,800,000		$ 4,800,000
Weighted average period cost to be recognized (in years)			2 years 3 months 18 days

XML

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS

9 Months Ended

Jun. 30, 2012

Pension Plans and Other Postretirement Benefits [Abstract]

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS

2. PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS

Pension Plans

Laclede Gas has non-contributory, defined benefit, trusteed forms of pension plans covering substantially all employees. Plan assets consist primarily of corporate and U.S. government obligations and equity market exposure achieved through derivative instruments.

Pension costs for the quarters ended June 30, 2012 and 2011 were $4.1 million and $4.2 million, respectively, including amounts charged to construction. Pension costs for the nine months ended June 30, 2012 and 2011 were $15.9 million and $10.0 million, respectively, including amounts charged to construction.

The net periodic pension costs include the following components:

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
(Thousands)	2012			2011			2012			2011
Service cost – benefits earned during the period	$	2,295		$	2,388		$	6,908		$	7,164
Interest cost on projected benefit obligation		4,824			4,705			14,535			14,115
Expected return on plan assets		(4,899	)		(4,712	)		(14,697	)		(14,136	)
Amortization of prior service cost		148			161			444			481
Amortization of actuarial loss		2,252			2,557			6,788			7,671
Loss on lump-sum settlement		—			—			3,407			—
Sub-total		4,620			5,099			17,385			15,295
Regulatory adjustment		(484	)		(864	)		(1,451	)		(5,259	)
Net pension cost	$	4,136		$	4,235		$	15,934		$	10,036

Pursuant to the provisions of the Laclede Gas pension plans, pension obligations may be satisfied by lump-sum cash payments. Pursuant to a Missouri Public Service Commission (MoPSC or Commission) Order, lump-sum payments are recognized as settlements (which can result in gains or losses) only if the total of such payments exceeds 100% of the sum of service and interest costs. Lump-sum payments recognized as settlements were $6.4 million during the nine months ended June 30, 2012. No lump-sum payments were recognized as settlements during the nine months ended June 30, 2011.

Pursuant to a MoPSC Order, the return on plan assets is based on the market-related value of plan assets implemented prospectively over a four-year period. Gains or losses not yet includible in pension cost are amortized only to the extent that such gain or loss exceeds 10% of the greater of the projected benefit obligation or the market-related value of plan assets. Such excess is amortized over the average remaining service life of active participants. The recovery in rates for the Utility’s qualified pension plans is based on an annual allowance of $4.8 million effective August 1, 2007 and $15.5 million effective January 1, 2011. The difference between these amounts and pension expense as calculated pursuant to the above and that otherwise would be included in the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income is deferred as a regulatory asset or regulatory liability.

The funding policy of Laclede Gas is to contribute an amount not less than the minimum required by government funding standards, nor more than the maximum deductible amount for federal income tax purposes. Fiscal year 2012 contributions to the pension plans through June 30, 2012 were $33.3 million to the qualified trusts and approximately $2.0 million to the non-qualified plans. Laclede Gas does not expect to make contributions to its qualified, trusteed pension plans during the remaining three months of fiscal year 2012. Contributions to the pension plans for the non-qualified plans for the remaining three months of fiscal year 2012 are anticipated to be approximately $4.7 million.

Postretirement Benefits

Laclede Gas provides certain life insurance benefits at retirement. Medical insurance is available after early retirement until age 65. The transition obligation not yet includible in postretirement benefit cost is being amortized over 20 years. Postretirement benefit costs for both the quarters ended June 30, 2012 and 2011 were $2.4 million, including amounts charged to construction. Postretirement benefit costs for the nine months ended June 30, 2012 and 2011 were $7.1 million and $6.7 million, respectively, including amounts charged to construction.

Net periodic postretirement benefit costs consisted of the following components:

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
(Thousands)	2012			2011			2012			2011
Service cost – benefits earned during the period	$	2,015		$	1,919		$	6,045		$	5,757
Interest cost on accumulated
postretirement benefit obligation		1,380			1,210			4,140			3,632
Expected return on plan assets		(991	)		(911	)		(2,973	)		(2,734	)
Amortization of transition obligation		34			34			102			102
Amortization of prior service credit		(518	)		(582	)		(1,554	)		(1,746	)
Amortization of actuarial loss		1,065			1,111			3,195			3,332
Sub-total		2,985			2,781			8,955			8,343
Regulatory adjustment		(604	)		(400	)		(1,812	)		(1,671	)
Net postretirement benefit cost	$	2,381		$	2,381		$	7,143		$	6,672

Missouri state law provides for the recovery in rates of costs accrued pursuant to GAAP provided that such costs are funded through an independent, external funding mechanism. Laclede Gas established Voluntary Employees’ Beneficiary Association (VEBA) and Rabbi trusts as its external funding mechanisms. VEBA and Rabbi trusts’ assets consist primarily of money market securities and mutual funds invested in stocks and bonds.

Pursuant to a MoPSC Order, the return on plan assets is based on the market-related value of plan assets implemented prospectively over a four-year period. Gains and losses not yet includible in postretirement benefit cost are amortized only to the extent that such gain or loss exceeds 10% of the greater of the accumulated postretirement benefit obligation or the market-related value of plan assets. Such excess is amortized over the average remaining service life of active participants. The recovery in rates for the Utility’s postretirement benefit plans is based on an annual allowance of $7.6 million effective August 1, 2007 and $9.5 million effective January 1, 2011. The difference between these amounts and postretirement benefit cost based on the above and that otherwise would be included in the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income is deferred as a regulatory asset or regulatory liability.

Laclede Gas’ funding policy is to contribute amounts to the trusts equal to the periodic benefit cost calculated pursuant to GAAP as recovered in rates. Fiscal year 2012 contributions to the postretirement plans through June 30, 2012 were $6.0 million to the qualified trusts and approximately $0.1 million paid directly to participants from Laclede Gas’ funds. Contributions to the postretirement plans for the remaining three months of fiscal year 2012 are anticipated to be $6.0 million to the qualified trusts and $0.1 million paid directly to participants from Laclede Gas’ funds.

XML

EARNINGS PER COMMON SHARE (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Basic EPS [Abstract]
Net Income	$ 8,433	$ 15,390	$ 63,291	$ 66,652
Less: Income allocated to participating securities	42	125	356	552
Net Income Available to Common Shareholders, Basic	8,391	15,265	62,935	66,100
Weighted Average Shares Outstanding, Basic (In Shares)	22,282	22,120	22,243	22,087
Earnings Per Share of Common Stock, Basic (Per Share)	$ 0.38	$ 0.69	$ 2.83	$ 2.99
Diluted EPS [Abstract]
Net Income	8,433	15,390	63,291	66,652
Less: Income allocated to participating securities	42	125	355	551
Net Income Available to Common Stockholders, Diluted	$ 8,391	$ 15,265	$ 62,936	$ 66,101
Weighted Average Shares Outstanding, Basic (In Shares)	22,282	22,120	22,243	22,087
Dilutive Effect of Stock Options and Restricted Stock (In Shares)	75	68	75	73
Weighted Average Diluted Shares (In shares)	22,357	22,188	22,318	22,160
Earnings Per Share of Common Stock, Diluted (Per share)	$ 0.38	$ 0.69	$ 2.82	$ 2.98
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 (in shares)	204	193	202	193

XML

STATEMENTS OF CONSOLIDATED INCOME (UNAUDITED) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Operating Revenues:
Regulated Gas Distribution	$ 116,459	$ 151,423	$ 665,981	$ 817,241
Non-Regulated Gas Marketing	70,014	174,309	288,036	495,828
Other	376	18,549	1,920	19,192
Total Operating Revenues	186,849	344,281	955,937	1,332,261
Regulated Gas Distribution
Natural and propane gas	46,641	76,632	364,556	510,703
Other operation expenses	32,639	36,930	108,247	111,292
Maintenance	5,712	5,932	16,781	18,513
Depreciation and amortization	10,186	9,856	30,450	29,233
Taxes, other than income taxes	10,842	12,332	45,602	52,766
Total Regulated Gas Distribution Operating Expenses	106,020	141,682	565,636	722,507
Non-Regulated Gas Marketing	65,420	168,580	279,784	484,235
Other	364	8,265	1,784	9,071
Total Operating Expenses	171,804	318,527	847,204	1,215,813
Operating Income	15,045	25,754	108,733	116,448
Other Income and (Income Deductions) - Net	451	157	3,771	2,469
Interest Charges:
Interest on long-term debt	5,739	5,739	17,218	17,421
Other interest charges	427	408	1,541	1,701
Total Interest Charges	6,166	6,147	18,759	19,122
Income Before Income Taxes	9,330	19,764	93,745	99,795
Income Tax Expense	897	4,374	30,454	33,143
Net Income	$ 8,433	$ 15,390	$ 63,291	$ 66,652
Weighted Average Number of Common Shares Outstanding:
Basic	22,282	22,120	22,243	22,087
Diluted	22,357	22,188	22,318	22,160
Basic Earnings Per Share of Common Stock:
Basic Earnings Per Share of Common Stock	$ 0.38	$ 0.69	$ 2.83	$ 2.99
Diluted Earnings Per Share of Common Stock:
Diluted Earnings Per Share of Common Stock	$ 0.38	$ 0.69	$ 2.82	$ 2.98
Dividends Declared Per Share of Common Stock	$ 0.415	$ 0.405	$ 1.245	$ 1.215

XML

STATEMENTS OF CONSOLIDATED CASH FLOWS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
Operating Activities:
Net Income	$ 63,291	$ 66,652
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, amortization, and accretion	30,900	29,624
Deferred income taxes and investment tax credits	22,448	5,946
Other - net	(425)	1,145
Changes in assets and liabilities:
Accounts receivable - net	(2,699)	(12,395)
Unamortized purchased gas adjustments	16,561	19,779
Deferred purchased gas costs	(25,429)	48,752
Accounts payable	(15,025)	7,853
Delayed customer billings - net	(9,005)	(28,326)
Taxes accrued	568	18,577
Natural gas stored underground	59,978	56,600
Other assets and liabilities	(12,964)	(12,901)
Net cash provided by operating activities	128,199	201,306
Investing Activities:
Capital expenditures	(76,780)	(47,082)
Other investments	(1,388)	102
Net cash used in investing activities	(78,168)	(46,980)
Financing Activities:
Maturity of first mortgage bonds	0	(25,000)
Repayment of short-term debt - net	(46,000)	(129,650)
Changes in book overdrafts	223	474
Issuance of common stock	3,162	2,021
Non-employee directors' restricted stock awards	(565)	(494)
Dividends paid	(27,599)	(26,808)
Employees' taxes paid associated with restricted shares withheld upon vesting	(1,171)	(1,162)
Excess tax benefits from stock-based compensation	208	294
Other	(43)	2
Net cash used in financing activities	(71,785)	(180,323)
Net Decrease in Cash and Cash Equivalents	(21,754)	(25,997)
Cash and Cash Equivalents at Beginning of Period	43,277	86,919
Cash and Cash Equivalents at End of Period	21,523	60,922
Supplemental Disclosure of Cash Paid During the Period for:
Interest	21,811	22,588
Income taxes	$ 7,064	$ 4,609

XML

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Details) (USD $)	9 Months Ended																											3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended
	Jun. 30, 2012 MMBTU Gal	Sep. 30, 2011	Jun. 30, 2011	Sep. 30, 2011 NYMEX/ICE Natural Gas Contracts [Member] Designated as Hedging Instrument [Member] Derivative Instruments Assets [Member]	Jun. 30, 2011 NYMEX/ICE Natural Gas Contracts [Member] Designated as Hedging Instrument [Member] Derivative Instruments Assets [Member]	Sep. 30, 2011 NYMEX/ICE Natural Gas Contracts [Member] Designated as Hedging Instrument [Member] Other Deferred Charges [Member]	Jun. 30, 2011 NYMEX/ICE Natural Gas Contracts [Member] Designated as Hedging Instrument [Member] Other Deferred Charges [Member]	Jun. 30, 2012 NYMEX/ICE Natural Gas Contracts [Member] Designated as Hedging Instrument [Member] Accounts Receivable - Other [Member]	Sep. 30, 2011 NYMEX/ICE Natural Gas Contracts [Member] Not Designated as Hedging Instrument [Member] Derivative Instruments Assets [Member]	Jun. 30, 2011 NYMEX/ICE Natural Gas Contracts [Member] Not Designated as Hedging Instrument [Member] Derivative Instruments Assets [Member]	Sep. 30, 2011 NYMEX/ICE Natural Gas Contracts [Member] Not Designated as Hedging Instrument [Member] Other Deferred Charges [Member]	Jun. 30, 2011 NYMEX/ICE Natural Gas Contracts [Member] Not Designated as Hedging Instrument [Member] Other Deferred Charges [Member]	Jun. 30, 2012 NYMEX/ICE Natural Gas Contracts [Member] Not Designated as Hedging Instrument [Member] Accounts Receivable - Other [Member]	Sep. 30, 2011 NYMEX Gasoline and Heating Oil Contracts [Member] Designated as Hedging Instrument [Member] Derivative Instruments Assets [Member]	Jun. 30, 2011 NYMEX Gasoline and Heating Oil Contracts [Member] Designated as Hedging Instrument [Member] Derivative Instruments Assets [Member]	Jun. 30, 2012 NYMEX Gasoline and Heating Oil Contracts [Member] Designated as Hedging Instrument [Member] Accounts Receivable - Other [Member]	Sep. 30, 2011 NYMEX Gasoline and Heating Oil Contracts [Member] Not Designated as Hedging Instrument [Member] Derivative Instruments Assets [Member]	Jun. 30, 2011 NYMEX Gasoline and Heating Oil Contracts [Member] Not Designated as Hedging Instrument [Member] Derivative Instruments Assets [Member]	Jun. 30, 2012 NYMEX Gasoline and Heating Oil Contracts [Member] Not Designated as Hedging Instrument [Member] Accounts Receivable - Other [Member]	Jun. 30, 2012 Natural Gas Commodity Contracts [Member] Not Designated as Hedging Instrument [Member] Derivative Instruments Assets [Member]	Sep. 30, 2011 Natural Gas Commodity Contracts [Member] Not Designated as Hedging Instrument [Member] Derivative Instruments Assets [Member]	Jun. 30, 2011 Natural Gas Commodity Contracts [Member] Not Designated as Hedging Instrument [Member] Derivative Instruments Assets [Member]	Sep. 30, 2011 Natural Gas Commodity Contracts [Member] Not Designated as Hedging Instrument [Member] Other Deferred Charges [Member]	Jun. 30, 2011 Natural Gas Commodity Contracts [Member] Not Designated as Hedging Instrument [Member] Other Deferred Charges [Member]	Jun. 30, 2012 Natural Gas Commodity Contracts [Member] Not Designated as Hedging Instrument [Member] Other Current Liabilities [Member]	Sep. 30, 2011 Natural Gas Commodity Contracts [Member] Not Designated as Hedging Instrument [Member] Other Current Liabilities [Member]	Jun. 30, 2011 Natural Gas Commodity Contracts [Member] Not Designated as Hedging Instrument [Member] Other Current Liabilities [Member]	Jun. 30, 2012 Other Comprehensive Income (Loss) [Member] NYMEX/ICE Natural Gas Contracts [Member] Cash Flow Hedging [Member]	Jun. 30, 2011 Other Comprehensive Income (Loss) [Member] NYMEX/ICE Natural Gas Contracts [Member] Cash Flow Hedging [Member]	Jun. 30, 2012 Other Comprehensive Income (Loss) [Member] NYMEX/ICE Natural Gas Contracts [Member] Cash Flow Hedging [Member]	Jun. 30, 2011 Other Comprehensive Income (Loss) [Member] NYMEX/ICE Natural Gas Contracts [Member] Cash Flow Hedging [Member]	Jun. 30, 2012 Other Comprehensive Income (Loss) [Member] NYMEX Gasoline and Heating Oil Contracts [Member] Cash Flow Hedging [Member]	Jun. 30, 2011 Other Comprehensive Income (Loss) [Member] NYMEX Gasoline and Heating Oil Contracts [Member] Cash Flow Hedging [Member]	Jun. 30, 2012 Other Comprehensive Income (Loss) [Member] NYMEX Gasoline and Heating Oil Contracts [Member] Cash Flow Hedging [Member]	Jun. 30, 2011 Other Comprehensive Income (Loss) [Member] NYMEX Gasoline and Heating Oil Contracts [Member] Cash Flow Hedging [Member]	Jun. 30, 2012 Non-Regulated Gas Marketing Operating Revenue [Member] NYMEX/ICE Natural Gas Contracts [Member] Cash Flow Hedging [Member]	Jun. 30, 2011 Non-Regulated Gas Marketing Operating Revenue [Member] NYMEX/ICE Natural Gas Contracts [Member] Cash Flow Hedging [Member]	Jun. 30, 2012 Non-Regulated Gas Marketing Operating Revenue [Member] NYMEX/ICE Natural Gas Contracts [Member] Cash Flow Hedging [Member]	Jun. 30, 2011 Non-Regulated Gas Marketing Operating Revenue [Member] NYMEX/ICE Natural Gas Contracts [Member] Cash Flow Hedging [Member]	Jun. 30, 2012 Non-Regulated Gas Marketing Operating Revenue [Member] NYMEX/ICE Natural Gas Contracts [Member] Not Designated as Hedging Instrument [Member]	Jun. 30, 2011 Non-Regulated Gas Marketing Operating Revenue [Member] NYMEX/ICE Natural Gas Contracts [Member] Not Designated as Hedging Instrument [Member]	Jun. 30, 2012 Non-Regulated Gas Marketing Operating Revenue [Member] NYMEX/ICE Natural Gas Contracts [Member] Not Designated as Hedging Instrument [Member]	Jun. 30, 2011 Non-Regulated Gas Marketing Operating Revenue [Member] NYMEX/ICE Natural Gas Contracts [Member] Not Designated as Hedging Instrument [Member]	Jun. 30, 2012 Non-Regulated Gas Marketing Operating Revenue [Member] Natural Gas Commodity Contracts [Member] Not Designated as Hedging Instrument [Member]	Jun. 30, 2011 Non-Regulated Gas Marketing Operating Revenue [Member] Natural Gas Commodity Contracts [Member] Not Designated as Hedging Instrument [Member]	Jun. 30, 2012 Non-Regulated Gas Marketing Operating Revenue [Member] Natural Gas Commodity Contracts [Member] Not Designated as Hedging Instrument [Member]	Jun. 30, 2011 Non-Regulated Gas Marketing Operating Revenue [Member] Natural Gas Commodity Contracts [Member] Not Designated as Hedging Instrument [Member]	Jun. 30, 2012 Non-Regulated Gas Marketing Operating Expenses [Member] NYMEX/ICE Natural Gas Contracts [Member] Cash Flow Hedging [Member]	Jun. 30, 2011 Non-Regulated Gas Marketing Operating Expenses [Member] NYMEX/ICE Natural Gas Contracts [Member] Cash Flow Hedging [Member]	Jun. 30, 2012 Non-Regulated Gas Marketing Operating Expenses [Member] NYMEX/ICE Natural Gas Contracts [Member] Cash Flow Hedging [Member]	Jun. 30, 2011 Non-Regulated Gas Marketing Operating Expenses [Member] NYMEX/ICE Natural Gas Contracts [Member] Cash Flow Hedging [Member]	Jun. 30, 2012 Non-Regulated Gas Marketing Operating Expenses [Member] NYMEX/ICE Natural Gas Contracts [Member] Not Designated as Hedging Instrument [Member]	Jun. 30, 2011 Non-Regulated Gas Marketing Operating Expenses [Member] NYMEX/ICE Natural Gas Contracts [Member] Not Designated as Hedging Instrument [Member]	Jun. 30, 2012 Non-Regulated Gas Marketing Operating Expenses [Member] NYMEX/ICE Natural Gas Contracts [Member] Not Designated as Hedging Instrument [Member]	Jun. 30, 2011 Non-Regulated Gas Marketing Operating Expenses [Member] NYMEX/ICE Natural Gas Contracts [Member] Not Designated as Hedging Instrument [Member]	Jun. 30, 2012 Non-Regulated Gas Marketing Operating Expenses [Member] Natural Gas Commodity Contracts [Member] Not Designated as Hedging Instrument [Member]	Jun. 30, 2011 Non-Regulated Gas Marketing Operating Expenses [Member] Natural Gas Commodity Contracts [Member] Not Designated as Hedging Instrument [Member]	Jun. 30, 2012 Non-Regulated Gas Marketing Operating Expenses [Member] Natural Gas Commodity Contracts [Member] Not Designated as Hedging Instrument [Member]	Jun. 30, 2011 Non-Regulated Gas Marketing Operating Expenses [Member] Natural Gas Commodity Contracts [Member] Not Designated as Hedging Instrument [Member]	Jun. 30, 2012 Regulated Gas Distribution Other Operation Expenses [Member] NYMEX Gasoline and Heating Oil Contracts [Member] Cash Flow Hedging [Member]	Jun. 30, 2011 Regulated Gas Distribution Other Operation Expenses [Member] NYMEX Gasoline and Heating Oil Contracts [Member] Cash Flow Hedging [Member]	Jun. 30, 2012 Regulated Gas Distribution Other Operation Expenses [Member] NYMEX Gasoline and Heating Oil Contracts [Member] Cash Flow Hedging [Member]	Jun. 30, 2011 Regulated Gas Distribution Other Operation Expenses [Member] NYMEX Gasoline and Heating Oil Contracts [Member] Cash Flow Hedging [Member]	Jun. 30, 2012 Other Income and (Income Deductions) - Net [Member] NYMEX Gasoline and Heating Oil Contracts [Member] Not Designated as Hedging Instrument [Member]	Jun. 30, 2011 Other Income and (Income Deductions) - Net [Member] NYMEX Gasoline and Heating Oil Contracts [Member] Not Designated as Hedging Instrument [Member]	Jun. 30, 2012 Other Income and (Income Deductions) - Net [Member] NYMEX Gasoline and Heating Oil Contracts [Member] Not Designated as Hedging Instrument [Member]	Jun. 30, 2011 Other Income and (Income Deductions) - Net [Member] NYMEX Gasoline and Heating Oil Contracts [Member] Not Designated as Hedging Instrument [Member]	Jun. 30, 2012 Laclede Gas Company [Member] MMBTU	Jun. 30, 2012 Laclede Gas Company [Member] Fiscal 2012 [Member] Open Short Futures Positions [Member] MMBTU	Jun. 30, 2012 Laclede Gas Company [Member] Fiscal 2012 [Member] Open Long Futures Positions [Member] MMBTU	Jun. 30, 2012 Laclede Gas Company [Member] Fiscal 2013 [Member] Open Short Futures Positions [Member] MMBTU	Jun. 30, 2012 Laclede Gas Company [Member] Fiscal 2013 [Member] Open Long Futures Positions [Member] MMBTU	Jun. 30, 2012 Laclede Gas Company [Member] Fiscal 2014 [Member] Open Long Futures Positions [Member] MMBTU	Jun. 30, 2012 Laclede Energy Resources [Member] MMBTU	Jun. 30, 2012 Laclede Energy Resources [Member] Fiscal 2012 [Member] Open Short Futures Positions [Member] MMBTU	Jun. 30, 2012 Laclede Energy Resources [Member] Fiscal 2012 [Member] Open Long Futures Positions [Member] MMBTU	Jun. 30, 2012 Laclede Energy Resources [Member] Fiscal 2013 [Member] Open Short Futures Positions [Member] MMBTU	Jun. 30, 2012 Laclede Energy Resources [Member] Fiscal 2013 [Member] Open Long Futures Positions [Member] MMBTU	Jun. 30, 2012 Laclede Energy Resources [Member] Fiscal 2014 [Member] Open Long Futures Positions [Member] MMBTU
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES [Abstract]
Maximum percentage of normal volumes hedged	70.00%
Maximum number of months normal volumes can be hedged (in months)	36-month
Derivative [Line Items]
Gasoline futures contracts notional amount (in gallons)	800,000
Average price of gasoline futures contracts (dollars per gallon)	$ 2.27
Gasoline options contracts notional amount (in gallons)	500,000
Notional amount of non-exchange traded natural gas commodity contracts (in MMBtu)	58,500,000
Notional amount of non-exchange traded natural gas commodity contracts to be settled during fiscal 2012 (in MMBtu)	34,600,000
Notional amount of non-exchange traded natural gas commodity contracts to be settled during fiscal 2013 (in MMBtu)	23,900,000
Expected pre-tax unrealized gain (loss) reclassifications into the Statements of Consolidated Income during the next twelve months	(1,600,000)
MMBtu																																																																					0	4,290,000	0	25,870,000	1,870,000		3,340,000	910,000	11,840,000	1,690,000	100,000
Avg. Price Per MMBtu																																																																					0.00	4.26	0.00	4.04	3.45		2.90	3.29	3.14	3.76	4.34
Contract volumes of NYMEX natural gas option used to mitigate price risk (in MMBtu)																																																																				6,600,000						6,000,000
Derivatives in Cash Flow Hedging Relationships [Abstract]
Effective portion of gain (loss) recognized in OCI on derivatives																												(1,802,000)	701,000	6,218,000	1,435,000	69,000	9,000	202,000	449,000
Effective portion of gain (loss) reclassiffied from AOCI to income																																				7,646,000	782,000	18,434,000	6,373,000									(1,492,000)	(3,239,000)	(9,861,000)	(5,714,000)									17,000	196,000	20,000	317,000
Ineffective portion of gain (loss) on derivatives recognized in income																																				(84,000)	(10,000)	(15,000)	550,000									(95,000)	(371,000)	(291,000)	(994,000)									(46,000)	(13,000)	(12,000)	35,000
Derivatives Not Designated as Hedging Instruments [Abstract]
Gain (loss) recognized in income on derivatives																																								(1,123,000)	(7,000)	425,000	(85,000)	2,641,000	(300,000)	3,431,000	(599,000)					(655,000)	0	(625,000)	0	0	1,927,000	687,000	3,123,000					(11,000)	(19,000)	2,000	44,000
Derivatives, Fair Value [Line Items]
Asset Derivatives Fair Value	9,015,000	6,960,000	5,256,000	4,395,000	1,031,000	4,000	0	1,064,000	457,000	1,835,000	0	90,000	3,449,000	15,000	133,000	106,000	4,000	10,000	1,000	4,356,000	1,894,000	1,842,000	183,000	308,000	39,000	8,000	7,000
Liabilities Fair Value	24,318,000	21,214,000	19,660,000	4,105,000	7,057,000	85,000	77,000	2,529,000	16,330,000	12,379,000	408,000	0	21,202,000	117,000	3,000	0	7,000	1,000	0	478,000	100,000	106,000	0	0	109,000	62,000	37,000
Derivative instrument assets reconciliation [Abstract]
Fair value of asset derivatives presented above	9,015,000	6,960,000	5,256,000	4,395,000	1,031,000	4,000	0	1,064,000	457,000	1,835,000	0	90,000	3,449,000	15,000	133,000	106,000	4,000	10,000	1,000	4,356,000	1,894,000	1,842,000	183,000	308,000	39,000	8,000	7,000
Fair value of cash margin receivables offset with derivatives	19,111,000	23,188,000	25,290,000
Netting of assets and liabilities with the same counterparty	(24,247,000)	(21,160,000)	(19,630,000)
Derivative Assets	3,879,000	8,988,000	10,916,000
Derivative Instrument Assets, per Consolidated Balance Sheets: [Abstract]
Derivative instrument assets	3,879,000	7,759,000	10,127,000
Other deferred charges derivative instruments	0	1,229,000	789,000
Derivative Assets	3,879,000	8,988,000	10,916,000
Fair value of liability derivatives presented above	24,318,000	21,214,000	19,660,000	4,105,000	7,057,000	85,000	77,000	2,529,000	16,330,000	12,379,000	408,000	0	21,202,000	117,000	3,000	0	7,000	1,000	0	478,000	100,000	106,000	0	0	109,000	62,000	37,000
Netting of assets and liabilities with the same counterparty	(24,247,000)	(21,160,000)	(19,630,000)
Derivative instrument liabilities, per Consolidated Balance Sheets	$ 71,000	$ 54,000	$ 30,000

XML

FAIR VALUE OF FINANCIAL INSTRUMENTS (Tables)

9 Months Ended

Jun. 30, 2012

Fair value of financial instruments [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 (a)
(Thousands)	Carrying Amount		Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
As of June 30, 2012
Cash and cash equivalents	$	21,523	$	21,523	$	11,560	$	9,963	$	—
Short-term debt		—		—		—		—		—
Long-term debt, including current portion		364,401		445,961		—		445,961		—
As of September 30, 2011
Cash and cash equivalents	$	43,277	$	43,277
Short-term debt		46,000		46,000
Long-term debt		364,357		443,739
As of June 30, 2011
Cash and cash equivalents	$	60,922	$	60,922
Short-term debt		—		—
Long-term debt		364,343		397,684
(a) The Company adopted the provisions of ASU 2011-04 (ASC Topic 820) in the second quarter of fiscal year 2012 on a prospective basis. Accordingly, disclosures for prior periods are not required to be presented.

XML

CONCENTRATIONS OF CREDIT RISK (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012
Concentration Risk [Line Items]
Number of large counterparties for which credit risk is disclosed	five
Number of investment-grade rated counterparties for which credit risk is disclosed, in terms of net accounts receivable exposure	Four
Credit Concentration Risk [Member] | Largest Counterparties [Member]
Concentration Risk [Line Items]
Accounts receivable	11.8
Net receivable amount	8.0
Accounts Receivable [Member] | Energy Producers And Their Affiliates [Member]
Concentration Risk [Line Items]
Accounts receivable	13.3
Net receivable amount	3.4
Accounts Receivable [Member] | Utility Companies And Their Affiliates [Member]
Concentration Risk [Line Items]
Accounts receivable	9.1
Net receivable amount	7.9

XML

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES (Tables)

9 Months Ended

Jun. 30, 2012

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES [Abstract]

Derivative Instruments and Hedging Activities

Open NYMEX/ICE natural gas futures and swap positions at June 30, 2012 were as follows:

	Laclede Gas Company			Laclede Energy Resources, Inc.
	MMBtu (millions)	Avg. Price Per MMBtu		MMBtu (millions)	Avg. Price Per MMBtu
Open short futures positions
Fiscal 2012	—	$	—	3.34	$	2.90
Fiscal 2013	—		—	11.84		3.14
Open long futures positions
Fiscal 2012	4.29	$	4.26	0.91	$	3.29
Fiscal 2013	25.87		4.04	1.69		3.76
Fiscal 2014	1.87		3.45	0.10		4.34

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

The Effect of Derivative Instruments on the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income
		Three Months Ended						Nine Months Ended
	Location of Gain (Loss)	June 30,						June 30,
(Thousands)	Recorded in Income		2012			2011			2012			2011
Derivatives in Cash Flow Hedging Relationships
Effective portion of gain (loss) recognized in OCI on derivatives:
NYMEX/ICE natural gas contracts		$	(1,802	)	$	701		$	6,218		$	1,435
NYMEX gasoline and heating oil contracts			69			9			202			449
Total		$	(1,733	)	$	710		$	6,420		$	1,884
Effective portion of gain (loss) reclassified from AOCI to income:
NYMEX/ICE natural gas contracts	Non-Regulated Gas Marketing Operating Revenues	$	7,646		$	782		$	18,434		$	6,373
	Non-Regulated Gas Marketing Operating Expenses		(1,492	)		(3,239	)		(9,861	)		(5,714	)
Sub-total			6,154			(2,457	)		8,573			659
NYMEX gasoline and heating oil contracts	Regulated Gas Distribution Other Operation Expenses		17			196			20			317
Total		$	6,171		$	(2,261	)	$	8,593		$	976
Ineffective portion of gain (loss) on derivatives recognized in income:
NYMEX/ICE natural gas contracts	Non-Regulated Gas Marketing Operating Revenues	$	(84	)	$	(10	)	$	(15	)	$	550
	Non-Regulated Gas Marketing Operating Expenses		(95	)		(371	)		(291	)		(994	)
Sub-total			(179	)		(381	)		(306	)		(444	)
NYMEX gasoline and heating oil contracts	Regulated Gas Distribution Other Operation Expenses		(46	)		(13	)		(12	)		35
Total		$	(225	)	$	(394	)	$	(318	)	$	(409	)
Derivatives Not Designated as Hedging Instruments *
Gain (loss) recognized in income on derivatives:
Natural gas commodity contracts	Non-Regulated Gas Marketing Operating Revenues	$	2,641		$	(300	)	$	3,431		$	(599	)
	Non-Regulated Gas Marketing Operating Expenses		—			1,927			687			3,123
NYMEX/ICE natural gas contracts	Non-Regulated Gas Marketing Operating Revenues		(1,123	)		(7	)		425			(85	)
	Non-Regulated Gas Marketing Operating Expenses		(655	)		—			(625	)		—
NYMEX gasoline and heating oil contracts	Other Income and (Income Deductions) - Net		(11	)		(19	)		2			44
Total		$	852		$	1,601		$	3,920		$	2,483

* 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 Regulated Gas Distribution Natural and Propane Gas operating expenses when they are recovered through the PGA Clause and reflected in customer billings.

Fair Value of Derivative Instruments in the Consolidated Balance Sheet

Fair Value of Derivative Instruments in the Consolidated Balance Sheet at June 30, 2012
	Asset Derivatives				Liability Derivatives
(Thousands)	Balance Sheet Location		Fair Value	*	Balance Sheet Location		Fair  Value	*
Derivatives designated as hedging instruments
NYMEX/ICE natural gas contracts	Accounts Receivable – Other	$	1,064		Accounts Receivable – Other	$	2,529
NYMEX gasoline and heating oil contracts	Accounts Receivable – Other		106		Accounts Receivable - Other		—
Sub-total			1,170				2,529
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Accounts Receivable - Other		3,449		Accounts Receivable - Other		21,202
Natural gas commodity contracts	Derivative Instrument Assets		4,356		Derivative Instrument Assets		478
	Other Current Liabilities		39		Other Current Liabilities		109
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other		1		Accounts Receivable - Other		—
Sub-total			7,845				21,789
Total derivatives		$	9,015			$	24,318
Fair Value of Derivative Instruments in the Consolidated Balance Sheet at September 30, 2011
	Asset Derivatives				Liability Derivatives
(Thousands)	Balance Sheet Location		Fair Value	*	Balance Sheet Location		Fair Value	*
Derivatives designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets	$	4,395		Derivative Instrument Assets	$	4,105
	Other Deferred Charges		4		Other Deferred Charges		85
NYMEX gasoline and heating oil contracts	Derivative Instrument Assets		15		Derivative Instrument Assets		117
Sub-total			4,414				4,307
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets		457		Derivative Instrument Assets		16,330
	Other Deferred Charges		—		Other Deferred Charges		408
Natural gas commodity contracts	Derivative Instrument Assets		1,894		Derivative Instrument Assets		100
	Other Deferred Charges		183		Other Deferred Charges		—
	Other Current Liabilities		8		Other Current Liabilities		62
NYMEX gasoline and heating oil contracts	Derivative Instrument Assets		4		Derivative Instrument Assets		7
Sub-total			2,546				16,907
Total derivatives		$	6,960			$	21,214

Fair Value of Derivative Instruments in the Consolidated Balance Sheet at June 30, 2011
	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	$	1,031		Derivative Instrument Assets	$	7,057
	Other Deferred Charges		—		Other Deferred Charges		77
NYMEX gasoline and heating oil contracts	Derivative Instrument Assets		133		Derivative Instrument Assets		3
Sub-total			1,164				7,137
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets		1,835		Derivative Instrument Assets		12,379
	Other Deferred Charges		90		Other Deferred Charges		—
Natural gas commodity contracts	Derivative Instrument Assets		1,842		Derivative Instrument Assets		106
	Other Deferred Charges		308		Other Deferred Charges		—
	Other Current Liabilities		7		Other Current Liabilities		37
NYMEX gasoline and heating oil contracts	Derivative Instrument Assets		10		Derivative Instrument Assets		1
Sub-total			4,092				12,523
Total derivatives		$	5,256			$	19,660

* 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 6, 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:

		June 30,			Sept. 30,			June 30,
	(Thousands)	2012			2011			2011
	Fair value of asset derivatives presented above	$	9,015		$	6,960		$	5,256
	Fair value of cash margin receivables offset with derivatives		19,111			23,188			25,290
	Netting of assets and liabilities with the same counterparty		(24,247	)		(21,160	)		(19,630	)
	Total	$	3,879		$	8,988		$	10,916
	Derivative Instrument Assets, per Consolidated Balance Sheets:
	Derivative instrument assets	$	3,879		$	7,759		$	10,127
	Other deferred charges		—			1,229			789
	Total	$	3,879		$	8,988		$	10,916
	Fair value of liability derivatives presented above	$	24,318		$	21,214		$	19,660
	Netting of assets and liabilities with the same counterparty		(24,247	)		(21,160	)		(19,630	)
	Derivative instrument liabilities, per Consolidated Balance Sheets*	$	71		$	54		$	30
*	Included in the Other line of the Current Liabilities section

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

9 Months Ended

Jun. 30, 2012

SUMMARY OF SIGNIFICANT 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 2011 Form 10-K.

The consolidated financial position, results of operations, and cash flows of Laclede Group are comprised primarily from the financial position, results of operations, and cash flowsof Laclede Gas Company (Laclede Gas or the Utility). Laclede Gas is a regulated natural gas distribution utility having a material seasonal cycle. As a result, these interim statements of income for Laclede Group are not necessarily indicative of annual results or representative of succeeding quarters of the fiscal year. Due to the seasonal nature of the business of Laclede Gas, earnings are typically concentrated in the November through April period, which generally corresponds with the heating season. Laclede Energy Resources, Inc. (LER) includes its wholly owned subsidiary, LER Storage Services, Inc., which was formed in October 2011 and became operational on January 1, 2012.

BASIS OF CONSOLIDATION - The consolidated financial statements include the accounts of Laclede Group and its subsidiary companies. All subsidiaries are wholly owned. Laclede Gas and other subsidiaries of Laclede Group may engage in related party transactions during the ordinary course of business. All material intercompany balances have been eliminated from the consolidated financial statements of Laclede Group. These transactions include sales of natural gas from Laclede Gas to LER, sales of natural gas from LER to Laclede Gas, and transportation services provided by Laclede Pipeline Company to Laclede Gas. These revenues are shown on the Intersegment revenues lines in the table included in Note 10 under Regulated Gas Distribution, Non-Regulated Gas Marketing, and Other columns, respectively.

NATURAL GAS STORED UNDERGROUND AND PROPANE GAS - For the Regulated Gas Distribution operating segment, inventory of Utility natural gas in storage is priced on a last-in, first-out (LIFO) basis and inventory of Utility propane gas in storage is priced on a first-in, first-out (FIFO) basis. The carrying value of Utility inventory is not adjusted to the lower of cost or market prices because, pursuant to the Laclede Gas Purchased Gas Adjustment (PGA) Clause, actual gas costs are recovered in customer rates. Natural gas and propane gas storage inventory in Laclede Group’s other operating segments is recorded at the lower of average cost or market.

REVENUE RECOGNITION - Laclede Gas reads meters and bills its customers on monthly cycles. The Utility records its regulated gas distribution revenues from gas sales and transportation services on an accrual basis that includes estimated amounts for gas delivered, but not yet billed. The accruals for unbilled revenues are reversed in the subsequent accounting period when meters are actually read and customers are billed. The amounts of accrued unbilled revenues at June 30, 2012 and 2011, for the Utility, were $9.0 million and $9.6 million, respectively. The amount of accrued unbilled revenue at September 30, 2011 was $11.8 million.

In the course of its business, LER enters into commitments associated with the purchase or sale of natural gas. Certain of LER’s derivative natural gas contracts are designated as normal purchases or normal sales, and, as such, are excluded from the scope of ASC Topic 815, “Derivatives and Hedging.” As such, those contracts are accounted for as executory contracts and recorded on an accrual basis. Revenues and expenses from such contracts are recorded using a gross presentation. Contracts not designated as normal purchases or normal sales are recorded as derivatives with changes in fair value (representing unrealized gains and losses) recognized in earnings in the periods prior to physical delivery. For additional information on derivative instruments, refer to Note 7, Derivative Instruments and Hedging Activities. Certain of LER’s wholesale purchase and sale transactions entered on or after January 1, 2012 are classified as trading activities for financial reporting purposes rather than elected for normal purchases or normal sales designations. Under generally accepted accounting principles (GAAP), revenues and expenses associated with trading activities are presented on a net basis in Non-Regulated Gas Marketing Operating Revenues in the Statements of Consolidated Income. This net presentation has no effect on operating income or net income.

GROSS RECEIPTS TAXES - Gross receipts taxes associated with Laclede Gas’ natural gas utility service are imposed on the Utility and billed to its customers. These amounts are recorded gross in the Statements of Consolidated Income. Amounts recorded in Regulated Gas Distribution Operating Revenues for the quarters ended June 30, 2012 and 2011 were $5.7 million and $7.5 million, respectively. Amounts recorded in Regulated Gas Distribution Operating Revenues for the nine months ended June 30, 2012 and 2011 were $31.4 million and $39.1 million, respectively. Gross receipts taxes are expensed by the Utility and included in the Taxes, other than income taxes line.

NEW ACCOUNTING STANDARDS - In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-04, “Amendments to Achieve Common Fair Value Measurement Disclosure Requirements in U.S. GAAP and IFRSs.” This ASU amends Accounting Standards Codification (ASC) Topic 820, “Fair Value Measurements and Disclosures,” to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and International Financial Reporting Standards (IFRS). The ASU does not change what items are measured at fair value, but instead makes various changes to the guidance pertaining to how fair value is measured. Additionally, the ASU sets forth additional disclosure requirements, including additional information about Level 3 fair value measurements. Many of the amendments in this ASU are changes to align the wording in U.S. GAAP with IFRS and, as such, are not intended to result in a change in the application of the guidance. The Company’s adoption of the guidance in this ASU on a prospective basis in the second quarter of fiscal year 2012 had no impact on its financial condition or results of operations, but certain additional disclosures have been presented as required.

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

In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities,” to amend ASC Topic 210, “Balance Sheet,” to require additional disclosures about financial instruments and derivative instruments that have been presented on a net basis (offset) in the balance sheet. Additionally, information about financial instruments and derivative instruments that are subject to enforceable master netting arrangements or similar agreements, irrespective of whether they are presented net in the balance sheet, is required to be disclosed. The ASU impacts disclosures only and will not require any changes to financial statement presentation. The Company will present the new disclosures retrospectively beginning in the first quarter of fiscal year 2014.

XML

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (UNAUDITED) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Other Comprehensive Income [Abstract]
Net Income	$ 8,433	$ 15,390	$ 63,291	$ 66,652
Net gains (losses) on cash flow hedging derivative instruments:
Net hedging (loss) gain arising during the period	(1,733)	710	6,420	1,884
Reclassification adjustment for (gains) losses included in net income	(6,171)	2,261	(8,593)	(976)
Net unrealized (losses) gain on cash flow hedging derivative instruments	(7,904)	2,971	(2,173)	908
Defined benefit pension and other postretirement benefit plans:
Net actuarial loss arising during the period	0	0	(2,366)	0
Amortization of actuarial loss included in net periodic pension and postretirement benefit cost	66	107	3,639	320
Net defined benefit pension and other postretirement plans	66	107	1,273	320
Other Comprehensive (Loss) Income, Before Tax	(7,838)	3,078	(900)	1,228
Income Tax (Benefit) Expense Related to Items of Other Comprehensive (Loss) Income	(3,028)	1,189	(348)	474
Other Comprehensive (Loss) Income, Net of Tax	(4,810)	1,889	(552)	754
Comprehensive Income	$ 3,623	$ 17,279	$ 62,739	$ 67,406

XML

COMMITMENTS AND CONTINGENCIES

9 Months Ended

Jun. 30, 2012

COMMITMENTS AND CONTINGENCIES [Abstract]

COMMITMENTS AND CONTINGENCIES

11. COMMITMENTS AND CONTINGENCIES

Commitments

Laclede Gas and LER have entered into various contracts, expiring on dates through 2017, for the storage, transportation, and supply of natural gas. Minimum payments required under the contracts in place at June 30, 2012 are estimated at approximately $368 million. Additional contracts are generally entered into prior to or during the heating season. Laclede Gas recovers its costs from customers in accordance with the PGA Clause.

During fiscal 2011, the Utility initiated a multi-year project to replace its existing customer relationship and work management, financial, and supply chain software applications to enhance its technology, customer service, and business processes. At June 30, 2012, the Company was contractually committed to costs of approximately $6 million related to this project, with additional expenditures to be incurred throughout the project’s life.

Guarantees

Laclede Group had guarantees totaling $79.8 million for performance and payment of certain gas supply transactions by LER, as of June 30, 2012. Since that date, total guarantees issued by Laclede Group on behalf of LER increased by $2.0 million, bringing the total to $81.8 million in guarantees outstanding at July 27, 2012. No amounts have been recorded for these guarantees in the financial statements. As of June 30, 2012, management believes the probability is low that Laclede Group will be required to make payments under these guarantees.

Contingencies

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

Similar to other natural gas utility companies, Laclede Gas faces the risk of incurring environmental liabilities. In the natural gas industry, these are typically associated with sites formerly owned or operated by gas distribution companies like Laclede Gas and/or its predecessor companies at which manufactured gas operations took place. At this time, Laclede Gas has identified three former manufactured gas plant (MGP) sites where costs have been incurred and claims have been asserted: one in Shrewsbury, Missouri and two in the City of St. Louis, Missouri.

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

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

Laclede Gas has not owned the other site located in the City of St. Louis for many years. In a letter dated June 29, 2011, the Attorney General for the State of Missouri informed Laclede Gas that the Missouri Department of Natural Resources had completed an investigation of the site. The Attorney General requested that Laclede Gas participate in the follow up investigations of the site. In a letter dated January 10, 2012, the Company stated that it would participate in future environmental response activities at the site in conjunction with other potentially responsible parties that are willing to contribute to such efforts in a meaningful and equitable fashion.

To date, amounts required for remediation at these sites have not been material. However, the amount of costs relative to future remedial actions at these and other sites is unknown and may be material. Laclede Gas has notified its insurers that it seeks reimbursement for costs incurred in the past and future potential liabilities associated with the MGP sites. While some of the insurers have denied coverage and reserved their rights, Laclede Gas continues to discuss potential reimbursements with them. In 2005, the Utility’s outside consultant completed an analysis of the MGP sites to determine cost estimates for a one-time contractual transfer of risk from each of the Utility’s insurers of environmental coverage for the MGP sites. That analysis demonstrated a range of possible future expenditures to investigate, monitor, and remediate these MGP sites from $5.8 million to $36.3 million based upon then currently available facts, technology, and laws and regulations. The actual costs that Laclede Gas may incur could be materially higher or lower depending upon several factors, including whether remedial actions will be required, final selection and regulatory approval of any remedial actions, changing technologies and governmental regulations, the ultimate ability of other potentially responsible parties to pay, the successful completion of remediation efforts required by the Remediation Agreement described above, and any insurance recoveries. Costs associated with environmental remediation activities are accrued when such costs are probable and reasonably estimable.

Laclede Gas anticipates that any costs it may incur in the future to remediate these sites, less any amounts received as insurance proceeds or as contributions from other potentially responsible parties, would be deferred and recovered in rates through periodic adjustments approved by the MoPSC. Accordingly, any potential liabilities that may arise associated with remediating these sites are not expected to have a material impact on the future financial position and results of operations of Laclede Gas or the Company.

On December 28, 2006, the MoPSC Staff proposed a disallowance of $7.2 million related to Laclede Gas’ recovery of its purchased gas costs applicable to fiscal year 2005, which the Staff later reduced to a $1.7 million disallowance pertaining to Laclede Gas’ purchase of gas from a marketing affiliate, LER. The MoPSC Staff has also proposed disallowances of $2.8 million and $1.5 million of gas costs relating to Laclede Gas purchases of gas supply from LER for fiscal years 2006 and 2007, respectively. The MoPSC Staff proposed a number of non-monetary recommendations, based on its review of gas costs for fiscal years 2008 and 2009. Laclede Gas believes that the proposed disallowances lack merit and is vigorously opposing these adjustments in proceedings before the MoPSC. As such, no amount has been recorded in the financial statements for these proposed disallowances.

In connection with the affiliate transactions mentioned above, on July 7, 2010, the MoPSC Staff filed a complaint against Laclede Gas alleging that, by stating that it was not in possession of proprietary LER documents, Laclede Gas violated the MoPSC Order authorizing the holding company structure (2001 Order). Laclede Gas counterclaimed that the Staff failed to adhere to the pricing provisions of the MoPSC’s affiliate transaction rules and Laclede Gas’ Cost Allocation Manual. By orders dated November 3, 2010 and February 4, 2011, respectively, the MoPSC dismissed Laclede’s counterclaim and granted summary judgment to Staff, finding that Laclede Gas violated the terms of the 2001 Order and authorizing its General Counsel to seek penalties in court against Laclede Gas. On March 30, 2011, Laclede Gas sought review of the February 4 Order with the Missouri Cole County Circuit Court. On May 19, 2011, the Commission’s General Counsel filed a petition with the Cole County Circuit Court seeking penalties in connection with the Commission’s February 4 Order. On July 7, 2011, the Circuit Court Judge signed an agreed Order holding the penalty case in abeyance while the February 4 Order is appealed. On December 21, 2011, the Circuit Court reversed both the MoPSC’s November 3, 2010 Order and its February 4, 2011 Order. The MoPSC appealed and the matter is currently before the Western District Court of Appeals.

Subsequent to the July 7, 2010 complaint, the MoPSC Staff filed a related complaint on October 6, 2010 against Laclede Gas, LER, and Laclede Group, alleging that the Utility has failed to comply with the MoPSC’s affiliate transaction rules. LER and Laclede Group both filed motions to be dismissed from the proceeding, which were granted by the Commission on December 22, 2010. On January 26, 2011, the Commission also dismissed certain counts of the complaint against Laclede Gas. The remaining counts and a counterclaim against the Staff, filed by Laclede Gas, are still pending before the Commission. Laclede Gas believes that the complaint lacks merit and is vigorously opposing it.

On June 29, 2010, the Office of Federal Contract Compliance Programs issued a Notice of Violations to Laclede Gas alleging lapses in certain employment selection procedures during a two-year period ending in February 2006. The Company believes that the allegations lack merit and is vigorously defending its position. Management, after discussion with counsel, believes that the final outcome of these matters will not have a material effect on the consolidated financial position and results of operations of the Company.

As discussed in Note 7, 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. As of July 26, 2012, Laclede Gas and LER had $1.5 million and $0.4 million, respectively, on deposit with MF Global that remain unavailable pending final resolution by the bankruptcy trustee. While the Company’s total exposure at this time is not considered material, management is unable to predict when, or to what extent, these remaining funds will be returned.

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

XML

Document and Entity Information (USD $)	9 Months Ended
	Jun. 30, 2012	Jul. 26, 2012	Mar. 31, 2011
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			$ 793,509,957
Entity Common Stock, Shares Outstanding		22,510,176
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2012

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)

9 Months Ended

Jun. 30, 2012

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Abstract]

BASIS OF CONSOLIDATION

BASIS OF CONSOLIDATION - The consolidated financial statements include the accounts of Laclede Group and its subsidiary companies. All subsidiaries are wholly owned. Laclede Gas and other subsidiaries of Laclede Group may engage in related party transactions during the ordinary course of business. All material intercompany balances have been eliminated from the consolidated financial statements of Laclede Group. These transactions include sales of natural gas from Laclede Gas to LER, sales of natural gas from LER to Laclede Gas, and transportation services provided by Laclede Pipeline Company to Laclede Gas. These revenues are shown on the Intersegment revenues lines in the table included in Note 10 under Regulated Gas Distribution, Non-Regulated Gas Marketing, and Other columns, respectively.

NATURAL GAS STORED UNDERGROUND AND PROPANE GAS

NATURAL GAS STORED UNDERGROUND AND PROPANE GAS - For the Regulated Gas Distribution operating segment, inventory of Utility natural gas in storage is priced on a last-in, first-out (LIFO) basis and inventory of Utility propane gas in storage is priced on a first-in, first-out (FIFO) basis. The carrying value of Utility inventory is not adjusted to the lower of cost or market prices because, pursuant to the Laclede Gas Purchased Gas Adjustment (PGA) Clause, actual gas costs are recovered in customer rates. Natural gas and propane gas storage inventory in Laclede Group’s other operating segments is recorded at the lower of average cost or market.

REVENUE RECOGNITION

REVENUE RECOGNITION - Laclede Gas reads meters and bills its customers on monthly cycles. The Utility records its regulated gas distribution revenues from gas sales and transportation services on an accrual basis that includes estimated amounts for gas delivered, but not yet billed. The accruals for unbilled revenues are reversed in the subsequent accounting period when meters are actually read and customers are billed. The amounts of accrued unbilled revenues at June 30, 2012 and 2011, for the Utility, were $9.0 million and $9.6 million, respectively. The amount of accrued unbilled revenue at September 30, 2011 was $11.8 million.

In the course of its business, LER enters into commitments associated with the purchase or sale of natural gas. Certain of LER’s derivative natural gas contracts are designated as normal purchases or normal sales, and, as such, are excluded from the scope of ASC Topic 815, “Derivatives and Hedging.” As such, those contracts are accounted for as executory contracts and recorded on an accrual basis. Revenues and expenses from such contracts are recorded using a gross presentation. Contracts not designated as normal purchases or normal sales are recorded as derivatives with changes in fair value (representing unrealized gains and losses) recognized in earnings in the periods prior to physical delivery. For additional information on derivative instruments, refer to Note 7, Derivative Instruments and Hedging Activities. Certain of LER’s wholesale purchase and sale transactions entered on or after January 1, 2012 are classified as trading activities for financial reporting purposes rather than elected for normal purchases or normal sales designations. Under generally accepted accounting principles (GAAP), revenues and expenses associated with trading activities are presented on a net basis in Non-Regulated Gas Marketing Operating Revenues in the Statements of Consolidated Income. This net presentation has no effect on operating income or net income.

GROSS RECEIPTS TAXES

GROSS RECEIPTS TAXES - Gross receipts taxes associated with Laclede Gas’ natural gas utility service are imposed on the Utility and billed to its customers. These amounts are recorded gross in the Statements of Consolidated Income. Amounts recorded in Regulated Gas Distribution Operating Revenues for the quarters ended June 30, 2012 and 2011 were $5.7 million and $7.5 million, respectively. Amounts recorded in Regulated Gas Distribution Operating Revenues for the nine months ended June 30, 2012 and 2011 were $31.4 million and $39.1 million, respectively. Gross receipts taxes are expensed by the Utility and included in the Taxes, other than income taxes line.

NEW ACCOUNTING STANDARDS

NEW ACCOUNTING STANDARDS - In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2011-04, “Amendments to Achieve Common Fair Value Measurement Disclosure Requirements in U.S. GAAP and IFRSs.” This ASU amends Accounting Standards Codification (ASC) Topic 820, “Fair Value Measurements and Disclosures,” to improve the comparability of fair value measurements presented and disclosed in financial statements prepared in accordance with U.S. GAAP and International Financial Reporting Standards (IFRS). The ASU does not change what items are measured at fair value, but instead makes various changes to the guidance pertaining to how fair value is measured. Additionally, the ASU sets forth additional disclosure requirements, including additional information about Level 3 fair value measurements. Many of the amendments in this ASU are changes to align the wording in U.S. GAAP with IFRS and, as such, are not intended to result in a change in the application of the guidance. The Company’s adoption of the guidance in this ASU on a prospective basis in the second quarter of fiscal year 2012 had no impact on its financial condition or results of operations, but certain additional disclosures have been presented as required.

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

In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities,” to amend ASC Topic 210, “Balance Sheet,” to require additional disclosures about financial instruments and derivative instruments that have been presented on a net basis (offset) in the balance sheet. Additionally, information about financial instruments and derivative instruments that are subject to enforceable master netting arrangements or similar agreements, irrespective of whether they are presented net in the balance sheet, is required to be disclosed. The ASU impacts disclosures only and will not require any changes to financial statement presentation. The Company will present the new disclosures retrospectively beginning in the first quarter of fiscal year 2014.

XML

CONSOLIDATED BALANCE SHEETS (UNAUDITED) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Sep. 30, 2011	Jun. 30, 2011
ASSETS
Utility Plant	$ 1,455,004	$ 1,386,590	$ 1,362,780
Less: Accumulated depreciation and amortization	474,008	457,907	455,075
Net Utility Plant	980,996	928,683	907,705
Non-utility property	5,899	4,588	4,597
Other investments	55,117	50,785	52,290
Other Property and Investments	61,016	55,373	56,887
Current Assets:
Cash and cash equivalents	21,523	43,277	60,922
Accounts receivable:
Utility	65,762	71,090	87,021
Non-utility	47,335	50,894	58,645
Other	22,927	12,572	6,233
Allowance for doubtful accounts	(8,842)	(10,073)	(11,915)
Delayed customer billings	0	0	11,517
Inventories:
Natural gas stored underground	55,192	115,170	56,976
Propane gas	10,051	8,961	8,962
Materials and supplies at average cost	3,917	4,229	4,310
Natural gas receivable	19,710	30,689	29,767
Derivative instrument assets	3,879	7,759	10,127
Unamortized purchased gas adjustments	9,158	25,719	3,939
Deferred income taxes	0	0	9,064
Prepayments and other	11,079	8,847	9,082
Total Current Assets	261,691	369,134	344,650
Deferred Charges:
Regulatory assets	433,376	423,492	427,021
Other	4,259	6,400	6,041
Total Deferred Charges	437,635	429,892	433,062
Total Assets	1,741,338	1,783,082	1,742,304
Capitalization:
Common stock (70,000,000 shares authorized, 22,505,440, 22,430,734, and 22,416,923 shares issued, respectively)	22,505	22,431	22,417
Paid-in capital	166,717	163,702	162,309
Retained earnings	424,588	389,298	401,208
Accumulated other comprehensive (loss)	(2,652)	(2,100)	(6,383)
Total Common Stock Equity	611,158	573,331	579,551
Long-term debt (less current portion) - Laclede Gas	339,401	364,357	364,343
Total Capitalization	950,559	937,688	943,894
Current Liabilities:
Notes payable	0	46,000	0
Accounts payable	81,322	96,561	101,782
Advance customer billings	6,225	15,230	0
Current portion of long-term debt	25,000	0	0
Wages and compensation accrued	12,653	13,650	14,866
Dividends payable	9,664	9,359	9,280
Customer deposits	9,123	10,048	10,914
Interest accrued	5,405	8,812	5,603
Taxes accrued	13,040	11,901	29,091
Deferred income taxes	311	8,405	0
Other	16,540	11,968	13,958
Total Current Liabilities	179,283	231,934	185,494
Deferred Credits and Other Liabilities:
Deferred income taxes	335,366	315,405	305,374
Unamortized investment tax credits	3,166	3,326	3,379
Pension and postretirement benefit costs	158,011	185,701	196,757
Asset retirement obligations	28,723	27,495	26,996
Regulatory liabilities	53,867	50,846	50,308
Other	32,363	30,687	30,102
Total Deferred Credits and Other Liabilities	611,496	613,460	612,916
Commitments and Contingencies (Note 11)
Total Capitalization and Liabilities	$ 1,741,338	$ 1,783,082	$ 1,742,304

XML

FAIR VALUE MEASUREMENTS

9 Months Ended

Jun. 30, 2012

Fair Value Measurements [Abstract]

FAIR VALUE MEASUREMENTS

6. FAIR VALUE MEASUREMENTS

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

(Thousands)		Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Effects of Netting and Cash Margin Receivables /Payables			Total
As of June 30, 2012
Assets
U. S. Stock/Bond Mutual Funds	$	17,535	$	—	$	—	$	—		$	17,535
NYMEX/ICE natural gas contracts		3,273		1,240		—		(4,513	)		—
NYMEX gasoline and heating
oil contracts		107		—		—		(107	)		—
Natural gas commodity contracts		—		4,288		107		(516	)		3,879
Total	$	20,915	$	5,528	$	107	$	(5,136	)	$	21,414
Liabilities
NYMEX/ICE natural gas contracts	$	22,141	$	1,590	$	—	$	(23,731	)	$	—
Natural gas commodity contracts		—		587		—		(516	)		71
Total	$	22,141	$	2,177	$	—	$	(24,247	)	$	71
As of September 30, 2011
Assets
U. S. Stock/Bond Mutual Funds	$	14,833	$	—	$	—	$	—		$	14,833
NYMEX/ICE natural gas contracts		4,856		—		—		1,975			6,831
NYMEX gasoline and heating
oil contracts		19		—		—		162			181
Natural gas commodity contracts		—		2,018		66		(108	)		1,976
Total	$	19,708	$	2,018	$	66	$	2,029		$	23,821
Liabilities
NYMEX/ICE natural gas contracts	$	20,928	$	—	$	—	$	(20,928	)	$	—
NYMEX gasoline and heating
oil contracts		124		—		—		(124	)		—
Natural gas commodity contracts		—		109		53		(108	)		54
Total	$	21,052	$	109	$	53	$	(21,160	)	$	54

As of June 30, 2011
Assets
U. S. Stock/Bond Mutual Funds	$	16,096	$	—	$	—	$	—		$	16,096
NYMEX/ICE natural gas contracts		2,956		—		—		5,609			8,565
NYMEX gasoline and heating
oil contracts		143		—		—		164			307
Natural gas commodity contracts		—		2,150		7		(113	)		2,044
Total	$	19,195	$	2,150	$	7	$	5,660		$	27,012
Liabilities
NYMEX/ICE natural gas contracts	$	19,513	$	—	$	—	$	(19,513	)	$	—
NYMEX gasoline and heating
oil contracts		4		—		—		(4	)		—
Natural gas commodity contracts		—		138		5		(113	)		30
Total	$	19,517	$	138	$	5	$	(19,630	)	$	30

The mutual funds included in Level 1 are valued based on exchange-quoted market prices of identical securities. Derivative instruments included in Level 1 are valued using quoted market prices on the New York Mercantile Exchange (NYMEX). Derivative instruments classified in Level 2 include physical commodity derivatives that are valued using broker or dealer quotation services whose prices are derived principally from, or are corroborated by, observable market inputs. Also included in Level 2 are certain derivative instruments that have values that are similar to, and correlate with, quoted prices for exchange-traded instruments in active markets. Derivative instruments included in Level 3 are valued using generally unobservable inputs that are based upon the best information available and reflect management’s assumptions about how market participants would price the asset or liability. The Company’s policy is to recognize transfers between the levels of the fair value hierarchy, if any, as of the beginning of the interim reporting period in which circumstances change or events occur to cause the transfer. The following is a reconciliation of the Level 3 beginning and ending net derivative balances:

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
(Thousands)	2012			2011			2012			2011
Beginning of period	$	58		$	24		$	13		$	23
Settlements		(9	)		(33	)		(16	)		(85	)
Net losses related to derivatives not held   at end of period		(8	)		—			(68	)		(78	)
Net gains related to derivatives still held   at end of period		66			11			178			142
End of period	$	107		$	2		$	107		$	2

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 7, Derivative Instruments and Hedging Activities.

XML

FAIR VALUE OF FINANCIAL INSTRUMENTS

9 Months Ended

Jun. 30, 2012

Fair value of financial instruments [Abstract]

FAIR VALUE OF FINANCIAL INSTRUMENTS

5. 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 (a)
(Thousands)	Carrying Amount		Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
As of June 30, 2012
Cash and cash equivalents	$	21,523	$	21,523	$	11,560	$	9,963	$	—
Short-term debt		—		—		—		—		—
Long-term debt, including current portion		364,401		445,961		—		445,961		—
As of September 30, 2011
Cash and cash equivalents	$	43,277	$	43,277
Short-term debt		46,000		46,000
Long-term debt		364,357		443,739
As of June 30, 2011
Cash and cash equivalents	$	60,922	$	60,922
Short-term debt		—		—
Long-term debt		364,343		397,684
(a) The Company adopted the provisions of ASU 2011-04 (ASC Topic 820) in the second quarter of fiscal year 2012 on a prospective basis. Accordingly, disclosures for prior periods are not required to be presented.

The carrying amounts for cash and cash equivalents and short-term debt approximate fair value due to the short maturity of these instruments. The fair values of long-term debt are estimated based on market prices for similar issues. Refer to Note 6, Fair Value Measurements, for information on financial instruments measured at fair value on a recurring basis.

XML

FAIR VALUE MEASUREMENTS (Tables)

9 Months Ended

Jun. 30, 2012

Fair Value Measurements [Abstract]

Fair Value Measurements, Measured on Recurring Basis

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

(Thousands)		Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Effects of Netting and Cash Margin Receivables /Payables			Total
As of June 30, 2012
Assets
U. S. Stock/Bond Mutual Funds	$	17,535	$	—	$	—	$	—		$	17,535
NYMEX/ICE natural gas contracts		3,273		1,240		—		(4,513	)		—
NYMEX gasoline and heating
oil contracts		107		—		—		(107	)		—
Natural gas commodity contracts		—		4,288		107		(516	)		3,879
Total	$	20,915	$	5,528	$	107	$	(5,136	)	$	21,414
Liabilities
NYMEX/ICE natural gas contracts	$	22,141	$	1,590	$	—	$	(23,731	)	$	—
Natural gas commodity contracts		—		587		—		(516	)		71
Total	$	22,141	$	2,177	$	—	$	(24,247	)	$	71
As of September 30, 2011
Assets
U. S. Stock/Bond Mutual Funds	$	14,833	$	—	$	—	$	—		$	14,833
NYMEX/ICE natural gas contracts		4,856		—		—		1,975			6,831
NYMEX gasoline and heating
oil contracts		19		—		—		162			181
Natural gas commodity contracts		—		2,018		66		(108	)		1,976
Total	$	19,708	$	2,018	$	66	$	2,029		$	23,821
Liabilities
NYMEX/ICE natural gas contracts	$	20,928	$	—	$	—	$	(20,928	)	$	—
NYMEX gasoline and heating
oil contracts		124		—		—		(124	)		—
Natural gas commodity contracts		—		109		53		(108	)		54
Total	$	21,052	$	109	$	53	$	(21,160	)	$	54

As of June 30, 2011
Assets
U. S. Stock/Bond Mutual Funds	$	16,096	$	—	$	—	$	—		$	16,096
NYMEX/ICE natural gas contracts		2,956		—		—		5,609			8,565
NYMEX gasoline and heating
oil contracts		143		—		—		164			307
Natural gas commodity contracts		—		2,150		7		(113	)		2,044
Total	$	19,195	$	2,150	$	7	$	5,660		$	27,012
Liabilities
NYMEX/ICE natural gas contracts	$	19,513	$	—	$	—	$	(19,513	)	$	—
NYMEX gasoline and heating
oil contracts		4		—		—		(4	)		—
Natural gas commodity contracts		—		138		5		(113	)		30
Total	$	19,517	$	138	$	5	$	(19,630	)	$	30

Reconciliation of the Level 3 beginning and ending net derivative balances

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
(Thousands)	2012			2011			2012			2011
Beginning of period	$	58		$	24		$	13		$	23
Settlements		(9	)		(33	)		(16	)		(85	)
Net losses related to derivatives not held   at end of period		(8	)		—			(68	)		(78	)
Net gains related to derivatives still held   at end of period		66			11			178			142
End of period	$	107		$	2		$	107		$	2

XML

PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS (Tables)

9 Months Ended

Jun. 30, 2012

Pension Plans and Other Postretirement Benefits [Abstract]

Net Periodic Cost

The net periodic pension costs include the following components:

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
(Thousands)	2012			2011			2012			2011
Service cost – benefits earned during the period	$	2,295		$	2,388		$	6,908		$	7,164
Interest cost on projected benefit obligation		4,824			4,705			14,535			14,115
Expected return on plan assets		(4,899	)		(4,712	)		(14,697	)		(14,136	)
Amortization of prior service cost		148			161			444			481
Amortization of actuarial loss		2,252			2,557			6,788			7,671
Loss on lump-sum settlement		—			—			3,407			—
Sub-total		4,620			5,099			17,385			15,295
Regulatory adjustment		(484	)		(864	)		(1,451	)		(5,259	)
Net pension cost	$	4,136		$	4,235		$	15,934		$	10,036

Net periodic postretirement benefit costs consisted of the following components:

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
(Thousands)	2012			2011			2012			2011
Service cost – benefits earned during the period	$	2,015		$	1,919		$	6,045		$	5,757
Interest cost on accumulated
postretirement benefit obligation		1,380			1,210			4,140			3,632
Expected return on plan assets		(991	)		(911	)		(2,973	)		(2,734	)
Amortization of transition obligation		34			34			102			102
Amortization of prior service credit		(518	)		(582	)		(1,554	)		(1,746	)
Amortization of actuarial loss		1,065			1,111			3,195			3,332
Sub-total		2,985			2,781			8,955			8,343
Regulatory adjustment		(604	)		(400	)		(1,812	)		(1,671	)
Net postretirement benefit cost	$	2,381		$	2,381		$	7,143		$	6,672

XML

OTHER INCOME AND (INCOME DEDUCTIONS) - NET

9 Months Ended

Jun. 30, 2012

Other Income and (Income Deductions) -- Net [Abstract]

OTHER INCOME AND (INCOME DEDUCTIONS) - NET

9. OTHER INCOME AND (INCOME DEDUCTIONS) – NET

	Three Months Ended						Nine Months Ended
	June 30,						June 30,
(Thousands)	2012			2011			2012			2011
Interest income	$	337		$	182		$	1,001		$	897
Net investment gain		264			414			2,458			1,541
Other income		(15	)		(21	)		(4	)		53
Other income deductions		(135	)		(418	)		316			(22	)
Other Income and (Income Deductions) – Net	$	451		$	157		$	3,771		$	2,469

XML

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

9 Months Ended

Jun. 30, 2012

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES [Abstract]

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

7. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

Laclede Gas has a risk management policy that allows for the purchase of natural gas derivative instruments with the goal of managing price risk associated with purchasing natural gas on behalf of its customers. This policy prohibits speculation and permits the Utility to hedge up to 70% of its normal volumes purchased for up to a 36-month period. Costs and cost reductions, including carrying costs, associated with the Utility’s use of natural gas derivative instruments are allowed to be passed on to the Utility’s customers through the operation of its PGA Clause, through which the MoPSC allows the Utility to recover gas supply costs, subject to prudence review by the MoPSC. Accordingly, Laclede Gas does not expect any adverse earnings impact as a result of the use of these derivative instruments. The Utility does not designate these instruments as hedging instruments for financial reporting purposes because gains or losses associated with the use of these derivative instruments are deferred and recorded as regulatory assets or regulatory liabilities pursuant to ASC Topic 980, “Regulated Operations,” and, as a result, have no direct impact on the Statements of Consolidated Income. The timing of the operation of the PGA Clause may cause interim variations in short-term cash flows, because the Utility is subject to cash margin requirements associated with changes in the values of these instruments. Nevertheless, carrying costs associated with such requirements are recovered through the PGA Clause.

From time to time, Laclede Gas purchases NYMEX futures and options contracts to help stabilize operating costs associated with forecasted purchases of gasoline and diesel fuels used to power vehicles and equipment used in the course of its business. At June 30, 2012, Laclede Gas held 0.8 million gallons of gasoline futures contracts at an average price of $2.27 per gallon and 0.5 million gallons of gasoline options contracts. Most of these contracts, the longest of which extends to April 2014, are designated as cash flow hedges of forecasted transactions pursuant to ASC Topic 815. The gains or losses on these derivative instruments are not subject to the Utility’s PGA Clause.

In the course of its business, Laclede Group’s non-regulated gas marketing subsidiary, Laclede Energy Resources, Inc. (LER), which includes its wholly owned subsidiary LER Storage Services, Inc., enters into commitments associated with the purchase or sale of natural gas. Certain of LER’s derivative natural gas contracts are designated as normal purchases or normal sales and, as such, are excluded from the scope of ASC Topic 815 and are accounted for as executory contracts on an accrual basis. Any of LER’s derivative natural gas contracts that are not designated as normal purchases or normal sales are accounted for at fair value. At June 30, 2012, the fair values of 58.5 million MMBtu of non-exchange traded natural gas commodity contracts were reflected in the Consolidated Balance Sheet. Of these contracts, 34.6 million MMBtu will settle during fiscal year 2012, while the remaining 23.9 million MMBtu will settle during fiscal year 2013. These contracts have not been designated as hedges; therefore, changes in the fair value of these contracts are reported in earnings each period. Furthermore, LER manages the price risk associated with its fixed-priced commitments by either closely matching the offsetting physical purchase or sale of natural gas at fixed prices or through the use of NYMEX or Ice Clear Europe (ICE) futures, swap, and option contracts to lock in margins. At June 30, 2012, LER’s unmatched fixed-price positions were not material to Laclede Group’s financial position or results of operations. LER’s NYMEX and ICE natural gas futures, swap, and option contracts used to lock in margins may be designated as cash flow hedges of forecasted transactions for financial reporting purposes.

Derivative instruments designated as cash flow hedges of forecasted transactions are recognized on the Consolidated Balance Sheets at fair value and the change in the fair value of the effective portion of these hedge instruments is recorded, net of tax, in other comprehensive income (OCI). Accumulated other comprehensive income (AOCI) is a component of Total Common Stock Equity. Amounts are reclassified from AOCI into earnings when the hedged items affect net income, using the same revenue or expense category that the hedged item impacts. Based on market prices at June 30, 2012, it is expected that approximately $1.6 million of pre-tax unrealized losses 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 Company’s exchange-traded/cleared derivative instruments consist primarily of NYMEX and ICE positions. The NYMEX is the primary national commodities exchange on which natural gas derivatives are traded. Open NYMEX/ICE natural gas futures and swap positions at June 30, 2012 were as follows:

	Laclede Gas Company			Laclede Energy Resources, Inc.
	MMBtu (millions)	Avg. Price Per MMBtu		MMBtu (millions)	Avg. Price Per MMBtu
Open short futures positions
Fiscal 2012	—	$	—	3.34	$	2.90
Fiscal 2013	—		—	11.84		3.14
Open long futures positions
Fiscal 2012	4.29	$	4.26	0.91	$	3.29
Fiscal 2013	25.87		4.04	1.69		3.76
Fiscal 2014	1.87		3.45	0.10		4.34

At June 30, 2012, Laclede Gas and LER also had 6.6 million MMBtu and 6.0 million MMBtu, respectively, of other price mitigation in place through the use of NYMEX natural gas option-based strategies.

The Effect of Derivative Instruments on the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income
		Three Months Ended						Nine Months Ended
	Location of Gain (Loss)	June 30,						June 30,
(Thousands)	Recorded in Income		2012			2011			2012			2011
Derivatives in Cash Flow Hedging Relationships
Effective portion of gain (loss) recognized in OCI on derivatives:
NYMEX/ICE natural gas contracts		$	(1,802	)	$	701		$	6,218		$	1,435
NYMEX gasoline and heating oil contracts			69			9			202			449
Total		$	(1,733	)	$	710		$	6,420		$	1,884
Effective portion of gain (loss) reclassified from AOCI to income:
NYMEX/ICE natural gas contracts	Non-Regulated Gas Marketing Operating Revenues	$	7,646		$	782		$	18,434		$	6,373
	Non-Regulated Gas Marketing Operating Expenses		(1,492	)		(3,239	)		(9,861	)		(5,714	)
Sub-total			6,154			(2,457	)		8,573			659
NYMEX gasoline and heating oil contracts	Regulated Gas Distribution Other Operation Expenses		17			196			20			317
Total		$	6,171		$	(2,261	)	$	8,593		$	976
Ineffective portion of gain (loss) on derivatives recognized in income:
NYMEX/ICE natural gas contracts	Non-Regulated Gas Marketing Operating Revenues	$	(84	)	$	(10	)	$	(15	)	$	550
	Non-Regulated Gas Marketing Operating Expenses		(95	)		(371	)		(291	)		(994	)
Sub-total			(179	)		(381	)		(306	)		(444	)
NYMEX gasoline and heating oil contracts	Regulated Gas Distribution Other Operation Expenses		(46	)		(13	)		(12	)		35
Total		$	(225	)	$	(394	)	$	(318	)	$	(409	)
Derivatives Not Designated as Hedging Instruments *
Gain (loss) recognized in income on derivatives:
Natural gas commodity contracts	Non-Regulated Gas Marketing Operating Revenues	$	2,641		$	(300	)	$	3,431		$	(599	)
	Non-Regulated Gas Marketing Operating Expenses		—			1,927			687			3,123
NYMEX/ICE natural gas contracts	Non-Regulated Gas Marketing Operating Revenues		(1,123	)		(7	)		425			(85	)
	Non-Regulated Gas Marketing Operating Expenses		(655	)		—			(625	)		—
NYMEX gasoline and heating oil contracts	Other Income and (Income Deductions) - Net		(11	)		(19	)		2			44
Total		$	852		$	1,601		$	3,920		$	2,483

* 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 Regulated Gas Distribution Natural and Propane Gas operating expenses when they are recovered through the PGA Clause and reflected in customer billings.

Fair Value of Derivative Instruments in the Consolidated Balance Sheet at June 30, 2012
	Asset Derivatives				Liability Derivatives
(Thousands)	Balance Sheet Location		Fair Value	*	Balance Sheet Location		Fair  Value	*
Derivatives designated as hedging instruments
NYMEX/ICE natural gas contracts	Accounts Receivable – Other	$	1,064		Accounts Receivable – Other	$	2,529
NYMEX gasoline and heating oil contracts	Accounts Receivable – Other		106		Accounts Receivable - Other		—
Sub-total			1,170				2,529
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Accounts Receivable - Other		3,449		Accounts Receivable - Other		21,202
Natural gas commodity contracts	Derivative Instrument Assets		4,356		Derivative Instrument Assets		478
	Other Current Liabilities		39		Other Current Liabilities		109
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other		1		Accounts Receivable - Other		—
Sub-total			7,845				21,789
Total derivatives		$	9,015			$	24,318
Fair Value of Derivative Instruments in the Consolidated Balance Sheet at September 30, 2011
	Asset Derivatives				Liability Derivatives
(Thousands)	Balance Sheet Location		Fair Value	*	Balance Sheet Location		Fair Value	*
Derivatives designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets	$	4,395		Derivative Instrument Assets	$	4,105
	Other Deferred Charges		4		Other Deferred Charges		85
NYMEX gasoline and heating oil contracts	Derivative Instrument Assets		15		Derivative Instrument Assets		117
Sub-total			4,414				4,307
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets		457		Derivative Instrument Assets		16,330
	Other Deferred Charges		—		Other Deferred Charges		408
Natural gas commodity contracts	Derivative Instrument Assets		1,894		Derivative Instrument Assets		100
	Other Deferred Charges		183		Other Deferred Charges		—
	Other Current Liabilities		8		Other Current Liabilities		62
NYMEX gasoline and heating oil contracts	Derivative Instrument Assets		4		Derivative Instrument Assets		7
Sub-total			2,546				16,907
Total derivatives		$	6,960			$	21,214

Fair Value of Derivative Instruments in the Consolidated Balance Sheet at June 30, 2011
	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	$	1,031		Derivative Instrument Assets	$	7,057
	Other Deferred Charges		—		Other Deferred Charges		77
NYMEX gasoline and heating oil contracts	Derivative Instrument Assets		133		Derivative Instrument Assets		3
Sub-total			1,164				7,137
Derivatives not designated as hedging instruments
NYMEX/ICE natural gas contracts	Derivative Instrument Assets		1,835		Derivative Instrument Assets		12,379
	Other Deferred Charges		90		Other Deferred Charges		—
Natural gas commodity contracts	Derivative Instrument Assets		1,842		Derivative Instrument Assets		106
	Other Deferred Charges		308		Other Deferred Charges		—
	Other Current Liabilities		7		Other Current Liabilities		37
NYMEX gasoline and heating oil contracts	Derivative Instrument Assets		10		Derivative Instrument Assets		1
Sub-total			4,092				12,523
Total derivatives		$	5,256			$	19,660

* 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 6, 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:

		June 30,			Sept. 30,			June 30,
	(Thousands)	2012			2011			2011
	Fair value of asset derivatives presented above	$	9,015		$	6,960		$	5,256
	Fair value of cash margin receivables offset with derivatives		19,111			23,188			25,290
	Netting of assets and liabilities with the same counterparty		(24,247	)		(21,160	)		(19,630	)
	Total	$	3,879		$	8,988		$	10,916
	Derivative Instrument Assets, per Consolidated Balance Sheets:
	Derivative instrument assets	$	3,879		$	7,759		$	10,127
	Other deferred charges		—			1,229			789
	Total	$	3,879		$	8,988		$	10,916
	Fair value of liability derivatives presented above	$	24,318		$	21,214		$	19,660
	Netting of assets and liabilities with the same counterparty		(24,247	)		(21,160	)		(19,630	)
	Derivative instrument liabilities, per Consolidated Balance Sheets*	$	71		$	54		$	30
*	Included in the Other line of the Current Liabilities section

XML

CONCENTRATIONS OF CREDIT RISK

9 Months Ended

Jun. 30, 2012

CONCENTRATIONS OF CREDIT RISK [Abstract]

CONCENTRATIONS OF CREDIT RISK

8. CONCENTRATIONS OF CREDIT RISK

A significant portion of LER’s transactions are with (or are associated with) energy producers, utility companies, and pipelines. These concentrations of transactions with these counterparties have the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that each of these three groups may be affected similarly by changes in economic, industry, or other conditions. To manage this risk, as well as credit risk from significant counterparties in these and other industries, LER has established procedures to determine the creditworthiness of its counterparties. These procedures include obtaining credit ratings and credit reports, analyzing counterparty financial statements to assess financial condition, and considering the industry environment in which the counterparty operates. This information is monitored on an ongoing basis. In some instances, LER may require credit assurances such as prepayments, letters of credit, or parental guarantees. In addition, LER may enter into netting arrangements to mitigate credit risk with counterparties in the energy industry from which LER both sells and purchases natural gas. Sales are typically made on an unsecured credit basis with payment due the month following delivery. Accounts receivable amounts are closely monitored and provisions for uncollectible amounts are accrued when losses are probable. To date, losses have not been significant. LER records accounts receivable, accounts payable, and prepayments for physical sales and purchases of natural gas on a gross basis. The amount included in accounts receivable attributable to energy producers and their marketing affiliates amounted to $13.3 million at June 30, 2012. Net receivable amounts from these customers on the same date, reflecting netting arrangements, were $3.4 million. Accounts receivable attributable to utility companies and their marketing affiliates comprised $9.1 million of total accounts receivable at June 30, 2012, while net receivable amounts from these customers, reflecting netting arrangements, were $7.9 million. LER also has concentrations of credit risk with certain individually significant counterparties. At June 30, 2012, the amounts included in accounts receivable from LER’s five largest counterparties (in terms of net accounts receivable exposure), were $11.8 million. Four of these five counterparties are either investment-grade rated or owned by investment-grade rated companies. Net receivable amounts from these customers on the same date, reflecting netting arrangements, were $8.0 million. Additionally, LER has concentrations of credit risk with pipeline companies associated with its natural gas receivable amounts.

XML

INFORMATION BY OPERATING SEGMENT

9 Months Ended

Jun. 30, 2012

INFORMATION BY OPERATING SEGMENT [Abstract]

INFORMATION BY OPERATING SEGMENT

10. INFORMATION BY OPERATING SEGMENT

All of Laclede Group’s subsidiaries are wholly owned. The Regulated Gas Distribution segment consists of the regulated operations of Laclede Gas and is the core business segment of Laclede Group. Laclede Gas is a public utility engaged in the retail distribution and sale of natural gas serving an area in eastern Missouri, with a population of approximately 2.2 million, including the City of St. Louis and parts of ten counties in eastern Missouri. The Non-Regulated Gas Marketing segment includes the results of LER, a subsidiary engaged in the non-regulated marketing of natural gas and related activities, and LER Storage Services, Inc., which was formed in October 2011 to utilize natural gas storage contracts for providing natural gas sales. Other includes Laclede Pipeline Company’s transportation of liquid propane regulated by the Federal Energy Regulatory Commission (FERC) as well as non-regulated activities, including, among other activities, real estate development, the compression of natural gas, and financial investments in other enterprises. These operations are conducted through seven subsidiaries. Other also includes Laclede Gas’ non-regulated business activities, which are comprised of its non-regulated propane sales transactions and its propane storage and related services. Accounting policies are described in Note 1. Intersegment transactions include sales of natural gas from Laclede Gas to LER, sales of natural gas from LER to Laclede Gas, and transportation services provided by Laclede Pipeline Company to Laclede Gas. These revenues are shown on the Intersegment revenues lines in the table under Regulated Gas Distribution, Non-Regulated Gas Marketing, and Other columns, respectively.

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

			Non-
	Regulated		Regulated
	Gas		Gas
(Thousands)	Distribution		Marketing		Other		Eliminations			Consolidated
Three Months Ended
June 30, 2012
Revenues from external customers	$	116,459	$	70,014	$	376	$	—		$	186,849
Intersegment revenues		1,175		587		259		(2,021	)		—
Total Operating Revenues		117,634		70,601		635		(2,021	)		186,849
Net Economic Earnings		4,597		3,605		694		—			8,896
Total assets		1,640,101		­186,394		150,117		(235,274	)		1,741,338
Nine Months Ended
June 30, 2012
Revenues from external customers	$	665,981	$	288,036	$	1,920	$	—		$	955,937
Intersegment revenues		1,178		9,125		778		(11,081	)		—
Total Operating Revenues		667,159		297,161		2,698		(11,081	)		955,937
Net Economic Earnings		51,448		9,589		1,179		—			62,216
Total assets		1,640,101		­186,394		150,117		(235,274	)		1,741,338
Three Months Ended
June 30, 2011
Revenues from external customers	$	151,423	$	167,770	$	18,289	$	—		$	337,482
Intersegment revenues		—		6,539		260		—			6,799
Total Operating Revenues		151,423		174,309		18,549		—			344,281
Net Economic Earnings		5,363		2,747		6,536		—			14,646
Total assets		1,582,214		175,606		121,088		(136,604	)		1,742,304
Nine Months Ended
June 30, 2011
Revenues from external customers	$	815,665	$	476,776	$	18,413	$	—		$	1,310,854
Intersegment revenues		1,576		19,052		779		—			21,407
Total Operating Revenues		817,241		495,828		19,192		—			1,332,261
Net Economic Earnings		53,000		6,028		6,468		—			65,496
Total assets		1,582,214		175,606		121,088		(136,604	)		1,742,304

Reconciliation of Consolidated Net Economic Earnings to Consolidated Net Income
	Three Months Ended					Nine Months Ended
	June 30,					June 30,
(Thousands)	2012			2011		2012			2011
Total Net Economic Earnings above	$	8,896		$	14,646	$	62,216		$	65,496
Add: Unrealized (loss) gain on energy-related
derivative contracts, net of tax		(963	)		744		1,281			1,156
Add:  Lower of cost or market inventory
adjustments, net of tax		494			—		(68	)		—
Add:  Realized gain (loss) on economic hedges
prior to sale of the physical commodity,
net of tax		6			—		(138	)		—
Net Income	$	8,433		$	15,390	$	63,291		$	66,652

XML

FAIR VALUE MEASUREMENTS (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Quoted Prices in Active Markets (Level 1) [Member]	Sep. 30, 2011 Fair Value, Measurements, Recurring [Member] Quoted Prices in Active Markets (Level 1) [Member]	Jun. 30, 2011 Fair Value, Measurements, Recurring [Member] Quoted Prices in Active Markets (Level 1) [Member]	Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Significant Observable Inputs (Level 2) [Member]	Sep. 30, 2011 Fair Value, Measurements, Recurring [Member] Significant Observable Inputs (Level 2) [Member]	Jun. 30, 2011 Fair Value, Measurements, Recurring [Member] Significant Observable Inputs (Level 2) [Member]	Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Significant Unobservable Inputs (Level 3) [Member]	Sep. 30, 2011 Fair Value, Measurements, Recurring [Member] Significant Unobservable Inputs (Level 3) [Member]	Jun. 30, 2011 Fair Value, Measurements, Recurring [Member] Significant Unobservable Inputs (Level 3) [Member]	Jun. 30, 2012 Fair Value, Measurements, Recurring [Member] Effects of Netting and Cash Margin Receivables Payables [Member]	Sep. 30, 2011 Fair Value, Measurements, Recurring [Member] Effects of Netting and Cash Margin Receivables Payables [Member]	Jun. 30, 2011 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					$ 17,535	$ 14,833	$ 16,096	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0
NYMEX/ICE natural gas contracts- Asset					3,273	4,856	2,956	1,240	0	0	0	0	0	(4,513)	1,975	5,609
NYMEX gasoline and heating oil contracts- Asset					107	19	143	0	0	0	0	0	0	(107)	162	164
Natural gas commodity contracts- Asset					0	0	0	4,288	2,018	2,150	107	66	7	(516)	(108)	(113)
Total Assets					20,915	19,708	19,195	5,528	2,018	2,150	107	66	7	(5,136)	2,029	5,660
NYMEX/ICE natural gas contracts- Liabilities					22,141	20,928	19,513	1,590	0	0	0	0	0	(23,731)	(20,928)	(19,513)
NYMEX gasoline & heating oil contracts- Liabilities						124	4		0	0		0	0		(124)	(4)
Natural gas commodity contracts- Liabilities					0	0	0	587	109	138	0	53	5	(516)	(108)	(113)
Total Liabilities					22,141	21,052	19,517	2,177	109	138	0	53	5	(24,247)	(21,160)	(19,630)
Beginning of period	58	24	13	23
Settlements	(9)	(33)	(16)	(85)
Net losses related to derivatives not held at end of period	(8)	0	(68)	(78)
Net gains related to derivatives still held at end of period	66	11	178	142
End of period	$ 107	$ 2	$ 107	$ 2

XML

EARNINGS PER COMMON SHARE (Tables)

9 Months Ended

Jun. 30, 2012

EARNINGS PER COMMON SHARE [Abstract]

Earnings Per Common Share

	Three Months Ended				Nine Months Ended
	June 30,				June 30,
(Thousands, Except Per Share Amounts)		2012		2011		2012		2011
Basic EPS:
Net Income	$	8,433	$	15,390	$	63,291	$	66,652
Less: Income allocated to participating securities		42		125		356		552
Net Income Available to Common Shareholders	$	8,391	$	15,265	$	62,935	$	66,100
Weighted Average Shares Outstanding		22,282		22,120		22,243		22,087
Earnings Per Share of Common Stock	$	0.38	$	0.69	$	2.83	$	2.99
Diluted EPS:
Net Income	$	8,433	$	15,390	$	63,291	$	66,652
Less: Income allocated to participating securities		42		125		355		551
Net Income Available to Common Shareholders	$	8,391	$	15,265	$	62,936	$	66,101
Weighted Average Shares Outstanding		22,282		22,120		22,243		22,087
Dilutive Effect of Stock Options
and Restricted Stock		75		68		75		73
Weighted Average Diluted Shares		22,357		22,188		22,318		22,160
Earnings Per Share of Common Stock	$	0.38	$	0.69	$	2.82	$	2.98
Outstanding Shares Excluded from the
Calculation of Diluted EPS Attributable to:
Restricted stock and stock units subject to
performance and/or market conditions		204		193		202		193

XML

INFORMATION BY OPERATING SEGMENT (Tables)

9 Months Ended

Jun. 30, 2012

INFORMATION BY OPERATING SEGMENT [Abstract]

Schedule of operating segment information

			Non-
	Regulated		Regulated
	Gas		Gas
(Thousands)	Distribution		Marketing		Other		Eliminations			Consolidated
Three Months Ended
June 30, 2012
Revenues from external customers	$	116,459	$	70,014	$	376	$	—		$	186,849
Intersegment revenues		1,175		587		259		(2,021	)		—
Total Operating Revenues		117,634		70,601		635		(2,021	)		186,849
Net Economic Earnings		4,597		3,605		694		—			8,896
Total assets		1,640,101		­186,394		150,117		(235,274	)		1,741,338
Nine Months Ended
June 30, 2012
Revenues from external customers	$	665,981	$	288,036	$	1,920	$	—		$	955,937
Intersegment revenues		1,178		9,125		778		(11,081	)		—
Total Operating Revenues		667,159		297,161		2,698		(11,081	)		955,937
Net Economic Earnings		51,448		9,589		1,179		—			62,216
Total assets		1,640,101		­186,394		150,117		(235,274	)		1,741,338
Three Months Ended
June 30, 2011
Revenues from external customers	$	151,423	$	167,770	$	18,289	$	—		$	337,482
Intersegment revenues		—		6,539		260		—			6,799
Total Operating Revenues		151,423		174,309		18,549		—			344,281
Net Economic Earnings		5,363		2,747		6,536		—			14,646
Total assets		1,582,214		175,606		121,088		(136,604	)		1,742,304
Nine Months Ended
June 30, 2011
Revenues from external customers	$	815,665	$	476,776	$	18,413	$	—		$	1,310,854
Intersegment revenues		1,576		19,052		779		—			21,407
Total Operating Revenues		817,241		495,828		19,192		—			1,332,261
Net Economic Earnings		53,000		6,028		6,468		—			65,496
Total assets		1,582,214		175,606		121,088		(136,604	)		1,742,304

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

Reconciliation of Consolidated Net Economic Earnings to Consolidated Net Income
	Three Months Ended					Nine Months Ended
	June 30,					June 30,
(Thousands)	2012			2011		2012			2011
Total Net Economic Earnings above	$	8,896		$	14,646	$	62,216		$	65,496
Add: Unrealized (loss) gain on energy-related
derivative contracts, net of tax		(963	)		744		1,281			1,156
Add:  Lower of cost or market inventory
adjustments, net of tax		494			—		(68	)		—
Add:  Realized gain (loss) on economic hedges
prior to sale of the physical commodity,
net of tax		6			—		(138	)		—
Net Income	$	8,433		$	15,390	$	63,291		$	66,652

XML

CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical)	Jun. 30, 2012	Sep. 30, 2011	Jun. 30, 2011
Capitalization:
Common Stock Shares Authorized (in shares)	70,000,000	70,000,000	70,000,000
Common Stock Shares Issued (in shares)	22,505,440	22,430,734	22,416,923

XML

EARNINGS PER COMMON SHARE

9 Months Ended

Jun. 30, 2012

EARNINGS PER COMMON SHARE [Abstract]

EARNINGS PER COMMON SHARE

4. EARNINGS PER COMMON SHARE

	Three Months Ended				Nine Months Ended
	June 30,				June 30,
(Thousands, Except Per Share Amounts)		2012		2011		2012		2011
Basic EPS:
Net Income	$	8,433	$	15,390	$	63,291	$	66,652
Less: Income allocated to participating securities		42		125		356		552
Net Income Available to Common Shareholders	$	8,391	$	15,265	$	62,935	$	66,100
Weighted Average Shares Outstanding		22,282		22,120		22,243		22,087
Earnings Per Share of Common Stock	$	0.38	$	0.69	$	2.83	$	2.99
Diluted EPS:
Net Income	$	8,433	$	15,390	$	63,291	$	66,652
Less: Income allocated to participating securities		42		125		355		551
Net Income Available to Common Shareholders	$	8,391	$	15,265	$	62,936	$	66,101
Weighted Average Shares Outstanding		22,282		22,120		22,243		22,087
Dilutive Effect of Stock Options
and Restricted Stock		75		68		75		73
Weighted Average Diluted Shares		22,357		22,188		22,318		22,160
Earnings Per Share of Common Stock	$	0.38	$	0.69	$	2.82	$	2.98
Outstanding Shares Excluded from the
Calculation of Diluted EPS Attributable to:
Restricted stock and stock units subject to
performance and/or market conditions		204		193		202		193

XML

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Part 1 (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012	Sep. 30, 2011	Jun. 30, 2011
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES [Abstract]
Accrued Unbilled Revenue	$ 9.0	$ 11.8	$ 9.6

XML

INFORMATION BY OPERATING SEGMENT (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Sep. 30, 2011
INFORMATION BY OPERATING SEGMENT [Abstract]
Regulated Gas Distribution segment, population of service area (in millions)	2.2		2.2
Number of service area counties	ten		ten
Number of entity subsidiaries	seven		seven
Operating Segment Information [Abstract]
Total Operating Revenues	$ 186,849	$ 344,281	$ 955,937	$ 1,332,261
Depreciation & amortization	10,186	9,856	30,450	29,233
Interest income	337	182	1,001	897
Interest charges	6,166	6,147	18,759	19,122
Income tax expense	897	4,374	30,454	33,143
Net economic earnings	8,896	14,646	62,216	65,496
Total assets	1,741,338	1,742,304	1,741,338	1,742,304	1,783,082
Reconciliation of Consolidated Net Economic Earnings to Consolidated Net Income [Abstract]
Total Net Economic Earnings above	8,896	14,646	62,216	65,496
Unrealized gain (loss) on energy-related derivative contracts, net of tax	(963)	744	1,281	1,156
Add: Lower of cost or market inventory adjustments, net of tax	494	0	(68)	0
Realized gain (loss) on economic hedges prior to sale of the physical commodity, net of tax	6	0	(138)	0
Net Income	8,433	15,390	63,291	66,652
Regulated Gas Distribution [Member]
Operating Segment Information [Abstract]
Revenues from external customers	116,459	151,423	665,981	815,665
Intersegment revenues	1,175	0	1,178	1,576
Total Operating Revenues	117,634	151,423	667,159	817,241
Net economic earnings	4,597	5,363	51,448	53,000
Total assets	1,640,101	1,582,214	1,640,101	1,582,214
Reconciliation of Consolidated Net Economic Earnings to Consolidated Net Income [Abstract]
Total Net Economic Earnings above	4,597	5,363	51,448	53,000
Non-Regulated Gas Marketing [Member]
Operating Segment Information [Abstract]
Revenues from external customers	70,014	167,770	288,036	476,776
Intersegment revenues	587	6,539	9,125	19,052
Total Operating Revenues	70,601	174,309	297,161	495,828
Net economic earnings	3,605	2,747	9,589	6,028
Total assets	186,394	175,606	186,394	175,606
Reconciliation of Consolidated Net Economic Earnings to Consolidated Net Income [Abstract]
Total Net Economic Earnings above	3,605	2,747	9,589	6,028
Other [Member]
Operating Segment Information [Abstract]
Revenues from external customers	376	18,289	1,920	18,413
Intersegment revenues	259	260	778	779
Total Operating Revenues	635	18,549	2,698	19,192
Net economic earnings	694	6,536	1,179	6,468
Total assets	150,117	121,088	150,117	121,088
Reconciliation of Consolidated Net Economic Earnings to Consolidated Net Income [Abstract]
Total Net Economic Earnings above	694	6,536	1,179	6,468
Unallocated and Eliminations [Member]
Operating Segment Information [Abstract]
Revenues from external customers	0	0	0	0
Intersegment revenues	(2,021)	0	(11,081)	0
Total Operating Revenues	(2,021)	0	(11,081)	0
Net economic earnings	0	0	0	0
Total assets	(235,274)	(136,604)	(235,274)	(136,604)
Reconciliation of Consolidated Net Economic Earnings to Consolidated Net Income [Abstract]
Total Net Economic Earnings above	$ 0	$ 0	$ 0	$ 0

XML

STOCK-BASED COMPENSATION (Tables)

9 Months Ended

Jun. 30, 2012

Disclosure of Compensation Related Costs Share Based Payments [Abstract]

Restricted stock and restricted stock unit activity

Activity of restricted stock and restricted stock units subject to performance and/or market conditions during the nine months ended June 30, 2012 is presented below:

			Weighted
			Average
	Shares/		Grant Date
	Units		Fair Value
Nonvested at September 30, 2011	259,075			$	34.29
Granted (maximum shares that can be earned)	103,763			$	36.55
Vested	(48,429	)		$	48.70
Forfeited	(82,006	)		$	38.27
Nonvested at June 30, 2012	232,403			$	30.89

Time-vested restricted stock and stock unit activity for the nine months ended June 30, 2012 is presented below:

			Weighted
			Average
	Shares/		Grant Date
	Units		Fair Value
Nonvested at September 30, 2011	143,350			$	37.00
Granted	44,175			$	40.23
Vested	(54,800	)		$	41.46
Forfeited	(15,300	)		$	33.87
Nonvested at June 30, 2012	117,425			$	36.54

Stock option awards activity

Stock option activity for the nine months ended June 30, 2012 is presented below:

					Weighted
					Average
			Weighted		Remaining	Aggregate
			Average		Contractual	Intrinsic
	Stock		Exercise		Term	Value
	Options		Price		(Years)	($000)
Outstanding at September 30, 2011	305,875		$	30.72
Granted	—		$	—
Exercised	(57,375	)	$	31.07
Forfeited	—		$	—
Expired	—		$	—
Outstanding at June 30, 2012	248,500		$	30.65	2.5	$	2,277
Fully Vested and Expected to Vest at June 30, 2012	248,500		$	30.65	2.5	$	2,277
Exercisable at June 30, 2012	248,500		$	30.65	2.5	$	2,277

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						Nine Months Ended
	June 30,						June 30,
(Thousands)	2012			2011			2012			2011
Total equity compensation cost	$	678		$	1,555		$	2,029		$	3,095
Compensation cost capitalized		(230	)		(371	)		(589	)		(702	)
Compensation cost recognized in net income		448			1,184			1,440			2,393
Income tax benefit recognized in net income		(173	)		(457	)		(556	)		(923	)
Compensation cost recognized in net income,
net of income tax	$	275		$	727		$	884		$	1,470