Edgar Filing: LACLEDE GAS CO

LGC-2014.3.31-10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q



[ X ]	QUARTERLY REPORT PURSUANT TO SECTION 13 or 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Quarter Ended March 31, 2014



[ ]	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 1-1822

LACLEDE GAS COMPANY

(Exact name of registrant as specified in its charter)



Missouri (State of Incorporation)	43-0368139 (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	[ ]	Accelerated filer	[ ]
Non-accelerated filer	[ X ]	Smaller reporting company	[ ]

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

As of April 25, 2014, there were 24,567 shares of the registrant’s Common Stock, par value $1.00 per share, outstanding, 100% of which were owned by The Laclede Group, Inc.

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TABLE OF CONTENTS			Page No.

PART I. FINANCIAL INFORMATION

Item 1	Financial Statements:
		Statements of Income	4
		Statements of Comprehensive Income	5
		Balance Sheets	6
		Statements of Cash Flows	8
		Notes to Financial Statements	9

Item 2	Management’s Discussion and Analysis of Financial Condition and
		Results of Operations	22

Item 3	Quantitative and Qualitative Disclosures About Market Risk		32

Item 4	Controls and Procedures		32

PART II. OTHER INFORMATION

Item 1	Legal Proceedings		33

Item 2	Unregistered Sales of Equity Securities and Use of Proceeds		33

Item 6	Exhibits		33

SIGNATURE			34

INDEX TO EXHIBITS			35

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PART I. FINANCIAL INFORMATION

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

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Item 1. Financial Statements

LACLEDE GAS COMPANY

STATEMENTS OF INCOME

(UNAUDITED)



	Three Months Ended					Six Months Ended
	March 31,					March 31,
(Thousands)	2014			2013		2014			2013
Operating Revenues:
Utility	$	638,718		$	363,911	$	1,073,946		$	614,702
Other	27			234		51			1,377
Total Operating Revenues	638,745			364,145		1,073,997			616,079
Operating Expenses:
Utility
Natural and propane gas	430,575			238,148		692,128			382,482
Other operation and maintenance expenses	72,229			41,193		134,745			80,846
Depreciation and amortization	20,118			11,258		40,144			22,223
Taxes, other than income taxes	41,739			21,751		70,328			36,557
Total Utility Operating Expenses	564,661			312,350		937,345			522,108
Other	(350		)	1,104		(116		)	1,228
Total Operating Expenses	564,311			313,454		937,229			523,336
Operating Income	74,434			50,691		136,768			92,743
Other Income and (Income Deductions) – Net	(606		)	988		1,056			2,076
Interest Charges:
Interest on long-term debt	8,423			5,483		17,908			10,884
Other interest charges	751			515		1,532			1,039
Total Interest Charges	9,174			5,998		19,440			11,923
Income Before Income Taxes	64,654			45,681		118,384			82,896
Income Tax Expense	20,422			15,906		38,859			27,379
Net Income	$	44,232		$	29,775	$	79,525		$	55,517

See Notes to Financial Statements.

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LACLEDE GAS COMPANY

STATEMENTS OF COMPREHENSIVE INCOME

(UNAUDITED)



	Three Months Ended						Six Months Ended
	March 31,						March 31,
(Thousands)	2014			2013			2014			2013
Net Income	$	44,232		$	29,775		$	79,525		$	55,517
Other Comprehensive (Loss) Income, Before Tax:
Net gains (losses) on cash flow hedging derivative instruments:
Net hedging gains arising during the period	57			147			66			203
Reclassification adjustment for gains included in net income	(55		)	(38		)	(113		)	(85		)
Net unrealized gains (losses) on cash flow hedging derivative instruments	2			109			(47		)	118
Defined benefit pension and other postretirement plans:
Amortization of actuarial loss included in net periodic pension and postretirement benefit cost	97			90			195			181
Other Comprehensive Income, Before Tax	99			199			148			299
Income Tax Expense Related to Items of Other Comprehensive Income	41			76			77			124
Other Comprehensive Income, Net of Tax	59			123			71			175
Comprehensive Income	$	44,291		$	29,898		$	79,596		$	55,692

See Notes to Financial Statements.

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LACLEDE GAS COMPANY

BALANCE SHEETS

(UNAUDITED)



	Mar. 31,			Sept. 30,			Mar. 31,
(Thousands)	2014			2013			2013
ASSETS
Utility Plant	$	2,323,156		$	2,271,189		$	1,538,890
Less: Accumulated depreciation and amortization	522,408			494,559			478,971
Net Utility Plant	1,800,748			1,776,630			1,059,919
Goodwill	216,370			247,078			—
Other Property and Investments	54,637			54,016			48,134
Current Assets:
Cash and cash equivalents	4,965			23,916			45,199
Accounts receivable:
Utility	275,688			101,118			148,624
Non-utility	458			967			628
Associated companies	2,926			1,111			3,917
Other	11,448			14,148			7,470
Allowance for doubtful accounts	(10,445		)	(7,942		)	(8,729		)
Delayed customer billings	29,667			—			19,663
Inventories:
Natural gas stored underground	59,684			164,740			29,899
Propane gas at FIFO cost	6,632			8,962			8,962
Materials and supplies at average cost	8,282			8,027			4,259
Derivative instrument assets	8,639			—			3,305
Unamortized purchased gas adjustments	1,631			17,533			11,039
Deferred income taxes	5,191			—			2,309
Prepayments and other	9,405			11,255			6,982
Total Current Assets	414,171			343,835			283,527
Deferred Charges:
Regulatory assets	537,387			545,937			424,707
Other	12,872			13,520			5,832
Total Deferred Charges	550,259			559,457			430,539
Total Assets	$	3,036,185		$	2,981,016		$	1,822,119

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LACLEDE GAS COMPANY

BALANCE SHEETS (Continued)

(UNAUDITED)



	Mar. 31,			Sept. 30,			Mar. 31,
(Thousands)	2014			2013			2013
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock and Paid-in capital (24,567, 24,549, and 12,847 shares issued, respectively)	$	741,172		$	738,234		$	260,618
Retained earnings	288,510			237,803			272,341
Accumulated other comprehensive loss	(2,036		)	(2,107		)	(1,926		)
Total Common Stock Equity	1,027,646			973,930			531,033
Long-term debt	807,816			887,712			439,434
Total Capitalization	1,835,462			1,861,642			970,467
Current Liabilities:
Notes payable	36,000			74,000			—
Notes payable – associated companies	77,366			46,729			—
Accounts payable	115,455			66,582			52,015
Accounts payable – associated companies	7,970			6,081			5,754
Advance customer billings	—			23,736			—
Wages and compensation accrued	21,839			20,807			16,175
Dividends payable	14,425			13,912			9,631
Customer deposits	15,588			15,062			7,706
Interest accrued	7,822			8,096			5,948
Taxes accrued	69,778			32,592			46,419
Deferred income taxes	—			1,692			—
Other	14,668			17,611			5,987
Total Current Liabilities	380,911			326,900			149,635
Deferred Credits and Other Liabilities:
Deferred income taxes	394,965			380,113			348,170
Unamortized investment tax credits	2,794			2,900			3,006
Pension and postretirement benefit costs	223,970			228,653			191,778
Asset retirement obligations	73,097			74,302			41,266
Regulatory liabilities	82,648			61,943			83,026
Other	42,338			44,563			34,771
Total Deferred Credits and Other Liabilities	819,812			792,474			702,017
Commitments and Contingencies (Note 9)
Total Capitalization and Liabilities	$	3,036,185		$	2,981,016		$	1,822,119

See Notes to Financial Statements.

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LACLEDE GAS COMPANY

STATEMENTS OF CASH FLOWS

(UNAUDITED)



	Six Months Ended March 31,
(Thousands)	2014			2013
Operating Activities:
Net Income	$	79,525		$	55,517
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	40,144			22,234
Deferred income taxes and investment tax credits	3,727			(10,687		)
Other – net	1,634			80
Changes in assets and liabilities:
Accounts receivable – net	(170,673		)	(72,638		)
Unamortized purchased gas adjustments	15,902			29,635
Deferred purchased gas costs	27,766			43,827
Accounts payable	55,269			21,454
Advance customer billings - net	(53,403		)	(44,809		)
Taxes accrued	36,822			32,358
Natural gas stored underground	105,056			59,953
Other assets and liabilities	2,732			(9,949		)
Net cash provided by operating activities	144,501			126,975
Investing Activities:
Capital expenditures	(67,129		)	(62,615		)
Other investments	(4,857		)	(943		)
Proceeds from final reconciliation of acquisition of MGE	23,925			—
Net cash used in investing activities	(48,061		)	(63,558		)
Financing Activities:
Issuance of first mortgage bonds	—			100,000
Redemption and maturity of first mortgage bonds	(80,000		)	(25,000		)
Repayment of short-term debt — net	(38,000		)	(40,100		)
Borrowings from Laclede Group	121,816			80,245
Repayment of borrowings from Laclede Group	(91,179		)	(117,370		)
Changes in book overdrafts	(1,184		)	(1,262		)
Dividends paid	(28,324		)	(18,917		)
Issuance of common stock to Laclede Group	753			1,687
Excess tax benefits from stock-based compensation	758			550
Other	(31		)	(453		)
Net cash used in financing activities	(115,391		)	(20,620		)
Net (Decrease) Increase in Cash and Cash Equivalents	(18,951		)	42,797
Cash and Cash Equivalents at Beginning of Period	23,916			2,402
Cash and Cash Equivalents at End of Period	$	4,965		$	45,199

Supplemental disclosure of cash flow information:
Interest paid	$	19,548		$	14,404
Income taxes (refunded) paid	(1,219		)	471
See Notes to Financial Statements.

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LACLEDE GAS COMPANY

NOTES TO FINANCIAL STATEMENTS

(UNAUDITED)



1.	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

These notes are an integral part of the accompanying unaudited financial statements of Laclede Gas Company (Laclede Gas or the Utility). In the opinion of the Utility, 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. Laclede Gas is a wholly owned subsidiary of The Laclede Group Inc. (Laclede Group or the Company). This Form 10-Q should be read in conjunction with the Notes to Financial Statements contained in the Utility’s Fiscal Year 2013 Form 10-K.

The Utility is a regulated natural gas distribution utility having a material seasonal cycle. As a result, these interim statements of income for the Utility are not necessarily indicative of annual results or representative of succeeding quarters of the fiscal year. The Utility's recent acquisition of Missouri Gas Energy (MGE) is included in the results of operations for the three months ended December 31, 2013, and impacts the comparability of the current year financial statements to prior years. For a further discussion of the acquisition, see Note 2, MGE acquisition. Due to the seasonal nature of the Utility, Laclede Group’s earnings are typically concentrated during the heating season of November through April each fiscal year, although earnings for MGE are less seasonal than earnings from Laclede Gas due to MGE's rate design which recovers fixed costs more evenly over the year.

BASIS OF PRESENTATION - In compliance with generally accepted accounting principles (GAAP), transactions between the Utility and its affiliates as well as intercompany balances on the Utility's Balance Sheets have not been eliminated from the Utility financial statements. Transactions with associated companies include sales of natural gas from the Utility to Laclede Energy Resources, Inc. (LER), sales of natural gas from LER to the Utility, and propane transportation services provided by Laclede Pipeline Company to the Utility. For the six months ended March 31, 2014 sales of natural gas from the Utility to LER were $4.3 million and for the six months ended March 31, 2013 were $10.4 million. Sales of natural gas from LER to the Utility during the six months ended March 31, 2014 and 2013 were $44.4 million and $15.0 million, respectively. Transportation services provided by Laclede Pipeline Company to the Utility during the six months ended March 31, 2014 and 2013 were $0.9 million and $0.5 million respectively.

The Utility provides administrative and general support to affiliates. All such costs, which are not material, are billed to the appropriate affiliates. Also, Laclede Group may charge or reimburse the Utility for certain tax-related amounts. Unpaid balances relating to these activities are reflected in the Utility Balance Sheets as Accounts receivable-associated companies or as Accounts payable-associated companies. Additionally, the Utility may borrow funds from Laclede Group. Unpaid balances relating to this arrangement, if any, are reflected in Notes payable-associated companies. The Utility had outstanding borrowings from Laclede Group under a revolving credit note of $77.4 million at March 31, 2014 and $46.7 million at September 30, 2013. The Utility had zero borrowings from Laclede Group at March 31, 2013. The interest rate on the borrowing was 0.3% at March 31, 2014. There was $113.4 million outstanding at March 31, 2014. Advances under this note are due and payable on demand.

REVENUE RECOGNITION - The Utility reads meters and bills its customers on monthly cycles. The Utility records its utility operating revenues from gas sales and transportation services on an accrual basis that includes estimated amounts for gas delivered, but not yet billed. The accruals for unbilled revenues are reversed in the subsequent accounting period when meters are actually read and customers are billed. The amounts of accrued unbilled revenues at March 31, 2014 and 2013, for the Utility, were $77.1 million and $33.3 million, respectively. The amount of accrued unbilled revenue at September 30, 2013 was $25.2 million.

GROSS RECEIPTS TAXES - Gross receipts taxes associated with the Utility's natural gas utility service are imposed on the Utility and billed to its customers. These amounts are recorded gross in the Statements of Income. Amounts recorded in Utility Operating Revenues for the quarters ended March 31, 2014 and 2013 were $34.3 million and $17.2 million, respectively. Amounts recorded in Utility Operating Revenues for the six months ended March 31, 2014 and 2013 were $54.3 million and $27.5 million, respectively. Gross receipts taxes are expensed by the Utility and included in the Taxes, other than income taxes line.

STOCK-BASED COMPENSATION - Officers and employees of the Utility, as determined by the Compensation Committee of Laclede Group’s Board of Directors, are eligible to be selected for awards under the Laclede Group 2006 Equity Incentive Plan (2006 Plan). Refer to Note 1 of the Notes to Financial Statements included in the Utility's Form 10-K for the fiscal year ended September 30, 2013 for descriptions of the plan. For awards made to its employees, the Utility records its allocation of compensation cost from Laclede Group with a corresponding increase to additional paid-in capital.

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The amounts of compensation cost allocated to the Utility for share-based compensation arrangements for the quarters and six months ended March 31, 2014 and 2013 are presented below:



	Three Months Ended						Six Months Ended
	March 31,						March 31,
(Thousands)	2014			2013			2014			2013
Total equity compensation cost	$	1,675		$	974		$	2,132		$	1,506
Compensation cost capitalized	(556		)	(356		)	(705		)	(539		)
Compensation cost recognized	$	1,119		$	618		$	1,427		$	967

As of March 31, 2014, there was $8.3 million in unrecognized compensation cost related to nonvested share-based compensation arrangements that is expected to be allocated to the Utility over a weighted average period of 2.2 years.

2. MGE ACQUISITION

Effective September 1, 2013, the Utility completed the purchase of substantially all of the assets and liabilities of MGE, a utility engaged in the distribution of natural gas on a regulated basis in western Missouri, from Southern Union Company (SUG), an affiliate of Energy Transfer Equity, L.P. (ETE) and Energy Transfer Partners, L.P. The purchase was completed pursuant to the Purchase and Sales Agreement (MGE PSA) dated December 14, 2012. Under the terms of the MGE PSA, the Utility acquired MGE for a purchase price of $975 million, subject to reconciliation of certain amounts as discussed below.

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


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

better access to the capital markets.


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

relationship with regulators.

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

Also, on December 12, 2012, a subsidiary of Laclede Group, Plaza Massachusetts Acquisition Inc. (Plaza Mass), agreed to purchase New England Gas Company (NEG) from SUG. Subsequently, on February 11, 2013, the Company agreed to sell Plaza Mass to Algonquin Power & Utilities Corp. (APUC). On December 13, 2013, the Massachusetts Department of Public Utilities (MDPU) approved the transfer of NEG to an APUC subsidiary. Consistent with the February 11, 2013 agreements, on December 20, 2013, the Company closed the sale of Plaza Mass to an APUC subsidiary and received $11.0 million from APUC. On December 24, 2013, the Massachusetts Attorney General filed a Motion for Clarification/Reconsideration with the MDPU which, among other things, claims that legislative approval is required for a transfer of utility assets. On March 26, 2014, the MDPU issued an order denying the Attorney General's motion, so the MDPU's order approving the sale of NEG is now final.

These receipts of funds in December and February effectively reduced the Utility's purchase price of MGE to $940.1 million and reduced goodwill related to the transaction to $216.4 million. The acquisition was accounted for under the acquisition method of accounting in accordance with ASC 805 (“Topic 805”), “Business Combinations.” Accordingly, goodwill was measured as the excess of the acquisition-date fair value of the consideration transferred over the amount of acquisition-date identifiable assets acquired net of assumed liabilities. As part of the MGE acquisition, Laclede Gas has estimated the asset retirement obligation of MGE's long-lived assets as of the acquisition date. This allocation of asset retirement obligations is preliminary and will be finalized upon completion of a detailed fair value analysis that is being performed by the Company and will be finalized prior to September 30, 2014.

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

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3.	PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS

Pension Plans

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

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

The net periodic pension costs include the following components:



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

Pursuant to the provisions of the Utility pension plans, pension obligations may be satisfied by lump-sum cash payments. Pursuant to a Missouri Public Service Commission (MoPSC or Commission) Order, lump-sum payments are recognized as settlements (which can result in gains or losses) only if the total of such payments exceeds 100% of the sum of service and interest costs. Lump-sum payments recognized as settlements during six months ended March 31, 2014 were $10.9 million. There were no lump-sum payments recognized as settlements during six months ended March 31, 2013.

Pursuant to a MoPSC Order, the return on plan assets is based on the market-related value of plan assets implemented prospectively over a four-year period. Gains or losses not yet includible in pension cost are amortized only to the extent that such gain or loss exceeds 10% of the greater of the projected benefit obligation or the market-related value of plan assets.

Such excess is amortized over the average remaining service life of active participants. The recovery in rates for Laclede Gas' qualified pension plans is based on an annual allowance of $15.5 million effective January 1, 2011. The recovery in rates for MGE's qualified pension plan is based on an annual allowance of $10.0 million effective February 20, 2010. The difference between these amounts and pension expense as calculated pursuant to the above and that otherwise would be included in the Statements of Consolidated Income and Statements of Consolidated Comprehensive Income is deferred as a regulatory asset or regulatory liability.

The funding policy of the Utility is to contribute an amount not less than the minimum required by government funding standards, nor more than the maximum deductible amount for federal income tax purposes. Fiscal year 2014 contributions to the pension plans through March 31, 2014 were $9.6 million to the qualified trusts and $0.2 million to the non-qualified plans. Contributions to the pension plans for the remaining six months of fiscal 2014 are anticipated to be approximately $14.4 million to the qualified trusts and $0.2 million to the non-qualified plans.

Postretirement Benefits

The Utility provides certain life insurance benefits at retirement. Medical insurance is currently 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 March 31, 2014 and 2013 were $2.4 million, including amounts charged to construction. Postretirement benefit costs for both the six months ended March 31, 2014 and 2013 were $4.8 million, including amounts charged to construction.

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Net periodic postretirement benefit costs consisted of the following components:



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

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

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

The Utility's funding policy is to contribute amounts to the trusts equal to the periodic benefit cost calculated pursuant to GAAP as recovered in rates. Fiscal year 2014 contributions to the postretirement plans through March 31, 2014 were $4.8 million. Contributions to the postretirement plans for the remaining six months of fiscal year 2014 are anticipated to be $14.4 million to the qualified trusts and $0.3 million paid directly to participants from the Utility's funds.

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4.	FAIR VALUE OF FINANCIAL INSTRUMENTS

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



					Classification of Estimated Fair Value
(Thousands)	Carrying Amount		Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
As of March 31, 2014
Cash and cash equivalents	$	4,965	$	4,965	$	4,941	$	24	$	—
Short-term debt	113,366		113,366		—		113,366		—
Long-term debt	807,816		859,811		—		859,811		—

As of September 30, 2013
Cash and cash equivalents	$	23,916	$	23,916	$	23,892	$	24	$	—
Short-term debt	120,729		120,729		—		120,729		—
Long-term debt, including current portion	887,712		930,369		—		930,369		—

As of March 31, 2013
Cash and cash equivalents	$	45,199	$	45,199	$	45,175	$	24	$	—
Short-term debt	—		—		—		—		—
Long-term debt, including current portion	439,434		514,129		—		514,129		—

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

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5.	FAIR VALUE MEASUREMENTS

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



(Thousands)	Quoted Prices in Active Markets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Effects of Netting and Cash Margin Receivables /Payables			Total
As of March 31, 2014
Assets
U. S. Stock/Bond Mutual Funds	$	16,340	$	2,780	$	—	$	—		$	19,120
NYMEX/ICE natural gas contracts	6,983		—		—		(4,467		)	2,516
OTCBB natural gas contracts	—		6,330		—		(315		)	6,015
NYMEX gasoline and heating oil contracts	49		—		—		—			49
Total	$	23,372	$	9,110	$	—	$	(4,782	)	$	27,700
Liabilities
NYMEX/ICE natural gas contracts	$	3,811	$	—	$	—	$	—		$	3,811
OTCBB natural gas contracts	—		315		—		(315		)	—
Total	$	3,811	$	315	$	—	$	(315	)	$	3,811

As of September 30, 2013
Assets
U. S. Stock/Bond Mutual Funds	$	14,500	$	—	$	—	$	—		$	14,500
NYMEX natural gas contracts	1,466		—		—		(1,466		)	—
OTCBB natural gas contracts	—		232		—		(232		)	—
NYMEX gasoline and heating oil contracts	105		—		—		(105		)	—
Total	$	16,071	$	232	$	—	$	(1,803	)	$	14,500
Liabilities
NYMEX natural gas contracts	$	3,455	$	—	$	—	$	(3,455	)	$	—
OTCBB natural gas contracts	—		5,443		—		(232		)	5,211
Total	$	3,455	$	5,443	$	—	$	(3,687	)	$	5,211

As of March 31, 2013
Assets
U. S. Stock/Bond Mutual Funds	$	13,922	$	—	$	—	$	—		$	13,922
NYMEX natural gas contracts	10,862		—		—		(7,687		)	3,175
NYMEX gasoline and heating oil contracts	322		—		—		(192		)	130
Total	$	25,106	$	—	$	—	$	(7,879	)	$	17,227
Liabilities
NYMEX natural gas contracts	$	339	$	—	$	—	$	(339	)	$	—

The mutual funds included in Level 1 are valued based on exchange-quoted market prices of individual securities. Derivative instruments included in Level 1 are valued using quoted market prices on the NYMEX. Derivative instruments classified in Level 2 include physical commodity derivatives that are valued using Over The Counter Bulletin Board (OTCBB), broker, or dealer quotation services whose prices are derived principally from, or are corroborated by, observable market inputs. The Utility’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 mutual funds are included in the Other Property and Investments line of the Balance Sheets. Derivative assets and liabilities, including receivables and payables associated with cash margin requirements, are presented net in the Balance Sheets when a legally enforceable netting agreement exists between the Utility and the counterparty to a derivative contract. For additional information on derivative instruments, see Note 6, Derivative Instruments and Hedging Activities.

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6.	DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

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

From time to time, the Utility purchases NYMEX futures and options contracts to help stabilize operating costs associated with forecasted purchases of gasoline and diesel fuels used to power vehicles and equipment used in the course of its business. At March 31, 2014, the Utility held 0.4 million gallons of gasoline futures contracts at an average price of $2.76 per gallon. Most of these contracts, the longest of which extends to September 2014, are designated as cash flow hedges of forecasted transactions pursuant to ASC Topic 815, “Derivatives and Hedging.” The gains or losses on these derivative instruments are not subject to the Utility’s PGA Clause.

The Utility’s derivative instruments consist primarily of NYMEX and OTCBB positions. The NYMEX is the primary national commodities exchange on which natural gas derivatives are traded. Open NYMEX and OTCBB natural gas futures positions at March 31, 2014 were as follows:



	MMBtu (millions)	Avg. Price Per MMBtu
NYMEX Open long futures positions
Fiscal 2014	3.80	$	3.79
Fiscal 2015	0.94	3.84
OTCBB Open long futures positions
Fiscal 2014	9.53	$	4.00
Fiscal 2015	9.83	4.21
Fiscal 2016	0.55	4.24

At March 31, 2014, the Utility also had 28.4 million MMBtu of other price mitigation in place through the use of NYMEX and OTCBB natural gas option-based strategies.

Derivative instruments designated as cash flow hedges of forecasted transactions are recognized on the Balance Sheets at fair value and the change in the fair value of the effective portion of these hedge instruments is recorded, net of tax, in other comprehensive income (OCI). Accumulated other comprehensive income (AOCI) is a component of Total Common Stock Equity. Amounts are reclassified from AOCI into earnings when the hedged items affect net income, using the same revenue or expense category that the hedged item impacts. Based on market prices at March 31, 2014, it is expected that approximately $0.1 million pre-tax gains will be reclassified into the Statements of 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 Cash Flows.

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The Effect of Derivative Instruments on the Statements of Income and Statements of Comprehensive Income
		Three Months Ended						Six Months Ended
	Location of Gain (Loss)	March 31,						March 31,
(Thousands)	Recorded in Income	2014			2013			2014		2013
Derivatives in Cash Flow Hedging Relationships
NYMEX gasoline and heating oil contracts:
Effective portion of gain (loss) recognized in OCI on derivatives		$	56		$	147		$	66	$	203
Effective portion of gain reclassified from AOCI to income and maintenance	Utility – Other Operation and Maintenance Expenses	54			38			113		85
Ineffective portion of gain (loss) on derivatives recognized in income and maintenance	Utility – Other Operation and Maintenance Expenses	(84		)	(31		)	36		(132		)
Derivatives Not Designated as Hedging Instruments *
NYMEX gasoline and heating oil contracts:
(Loss) gain recognized in income on derivative	Other Income and (Income Deductions) – Net	$	(3	)	$	13		$	10	$	46

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

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Fair Value of Derivative Instruments in the Balance Sheet at March 31, 2014
	Asset Derivatives*			Liability Derivatives*
(Thousands)	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments
NYMEX gasoline and heating oil contracts	Derivative Instrument Assets	$	49	Derivative Instrument Assets	$	—
Derivatives not designated as hedging instruments
NYMEX natural gas contracts	Derivative Instrument Assets	2,516		Derivative Instrument Assets	—
	Accounts Receivable - Other	4,467		Accounts Receivable - Other	3,811
OTCBB natural gas contracts	Derivative Instrument Assets	6,266		Derivative Instrument Assets	193
	Other Deferred Credits	64		Other Deferred Credits	122
Sub-total		13,313			4,126
Total derivatives		$	13,362		$	4,126

Fair Value of Derivative Instruments in the Balance Sheet at September 30, 2013
	Asset Derivatives*			Liability Derivatives*
(Thousands)	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	$	105	Accounts Receivable - Other	$	—
Derivatives not designated as hedging instruments
NYMEX natural gas contracts	Accounts Receivable - Other	1,434		Accounts Receivable - Other	3,455
	Other Deferred Charges	32		Other Deferred Charges	—
OTCBB natural gas contracts	Current Liabilities - Other	228		Current Liabilities - Other	4,045
	Deferred Credits - Other	4		Deferred Credits - Other	1,398
Sub-total		1,698			8,898
Total derivatives		$	1,803		$	8,898

Fair Value of Derivative Instruments in the Balance Sheet at March 31, 2013
	Asset Derivatives*			Liability Derivatives*
(Thousands)	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments
NYMEX gasoline and heating oil contracts	Derivative Instrument Assets	$	312	Derivative Instrument Assets	$	—
Derivatives not designated as hedging instruments
NYMEX natural gas contracts	Derivative Instrument Assets	10,862		Derivative Instrument Assets	339
NYMEX gasoline and heating oil contracts	Derivative Instrument Assets	10		Derivative Instrument Assets	—
Sub-total		10,872			339
Total derivatives		$	11,184		$	339

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 Balance Sheets. As such, the gross balances presented in the table above are not indicative of the Utility’s net economic exposure. Refer to Note 5, Fair Value Measurements, for information on the valuation of derivative instruments.

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



(Thousands)	March 31, 2014			September 30, 2013			March 31, 2013

Fair value of asset derivatives presented above	$	13,362		$	1,803		$	11,184
Fair value of cash margin receivables offset with derivatives	—			1,890			—
Netting of assets and liabilities with the same counterparty	(4,782		)	(3,693		)	(7,879		)
Derivative instrument assets, per Balance Sheets	$	8,580		$	—		$	3,305

Derivative Instrument Assets, per Balance Sheets:
Derivative instrument assets	$	8,639		$	—		$	3,305
Other deferred charges	(59		)	—			—
Total	$	8,580		$	—		$	3,305

Fair value of liability derivatives presented above	$	4,126		$	8,898		$	339
Fair value of cash margin payables offset with derivatives	656			6			7,540
Netting of assets and liabilities with the same counterparty	(4,782		)	(3,693		)	(7,879		)
Derivative instrument liabilities, per Balance Sheets	$	—		$	5,211		$	—

Derivative Instrument Liabilities, per Balance Sheets:
Other current liabilities	$	—		$	3,817		$	—
Other deferred credits	—			1,394			—
Total	$	—		$	5,211		$	—

Additionally, at March 31, 2014, September 30, 2013, and March 31, 2013 the Utility had $0.3 million, $2.9 million, and $8.0 million, respectively, in cash margin receivables not offset with derivatives, that are presented in Accounts Receivable - Other.



7.	OTHER INCOME AND (INCOME DEDUCTIONS) – NET



	Three Months Ended March 31,						Six Months Ended March 31,
(Thousands)	2014			2013			2014			2013
Interest income	$	142		$	240		$	390		$	631
Net investment (loss) gain	(1,011		)	832			(255		)	771
Other income (deductions)	263			(84		)	921			674
Other Income and (Income Deductions) – Net	$	(606	)	$	988		$	1,056		$	2,076

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8.	INFORMATION BY OPERATING SEGMENT

The Gas Utility segment consists of the regulated operations of the Utility. The Utility is a public utility engaged in the retail distribution and sale of natural gas serving an area in eastern Missouri, including the City of St. Louis, through Laclede Gas and an area in western Missouri, including Kansas City, through MGE. The Other segment includes the Utility's 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, Summary of Significant Accounting Policies. There are no material intersegment revenues.

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.



(Thousands)	Gas Utility		Other		Adjustments & Eliminations		Total
Three Months Ended March 31, 2014
Operating revenues	$	638,718	$	27	$	—	$	638,745
Net Economic Earnings	44,727		197		—		44,924
Total assets	3,036,185		—		—		3,036,185

Six Months Ended March 31, 2014
Operating revenues	$	1,073,946	$	51	$	—	$	1,073,997
Net Economic Earnings	80,504		46		—		80,550
Total assets	3,036,185		—		—		3,036,185

Three Months Ended March 31, 2013
Operating revenues	$	363,911	$	234	$	—	$	364,145
Net Economic Earnings	30,197		207		—		30,404
Total assets	1,821,372		747		—		1,822,119

Six Months Ended March 31, 2013
Operating revenues	$	614,702	$	1,377	$	—	$	616,079
Net Economic Earnings	55,538		667		—		56,205
Total assets	1,821,372		747		—		1,822,119



Reconciliation of Net Economic Earnings to Net Income
	Three Months Ended				Six Months Ended
	March 31,				March 31,
(Thousands)	2014		2013		2014			2013
Net Income (GAAP)	$	44,232	$	29,775	$	79,525		$	55,517
Add: Unrealized gain (loss) on energy-relate derivative contracts, net of tax	51		32		(3		)	91
Add: Acquisition, divestiture, and restructuring costs, net of tax	641		597		1,028			597
Net Economic Earnings (Non-GAAP)	$	44,924	$	30,404	$	80,550		$	56,205

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9.	COMMITMENTS AND CONTINGENCIES

Commitments

The Utility has entered into various contracts, expiring on dates through fiscal year 2019, for the storage, transportation, and supply of natural gas. Minimum payments required under the contracts in place at March 31, 2014 are estimated at approximately $805 million. Additional contracts are generally entered into prior to or during the heating season. The Utility recovers its costs from customers in accordance with the PGA Clause.

Contingencies

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

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

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

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

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

To date, amounts required for remediation at these sites have not been material. However, the amount of costs relative to future remedial actions at these and other sites is unknown and may be material. Laclede Gas has notified its insurers that it seeks reimbursement for costs incurred in the past and future potential liabilities associated with the MGP sites. While some of the insurers have denied coverage and reserved their rights, Laclede Gas continues to discuss potential reimbursements with them. In 2005, the Utility’s outside consultant completed an analysis of the MGP sites to determine cost estimates for a one-time contractual transfer of risk from each of the Utility’s insurers of environmental coverage for the MGP sites. That analysis demonstrated a range of possible future expenditures to investigate, monitor, and remediate these MGP sites from $5.8 million to $36.3 million based upon then currently available facts, technology, and laws and regulations.

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The actual costs that Laclede Gas may incur could be materially higher or lower depending upon several factors, including whether remedial actions will be required, final selection and regulatory approval of any remedial actions, changing technologies and governmental regulations, the ultimate ability of other potentially responsible parties to pay, the successful completion of remediation efforts required by the Remediation Agreement described above, and any insurance recoveries.

MGE has seven owned MGP sites enrolled in the BVCP, including Joplin MGP #1, St. Joseph MGP #1, Kansas City Coal Gas Station B, Kansas City Station A Railroad, Kansas City Coal Gas Station A North, Kansas City Coal Gas Station A South, and Independence MGP #2. The Missouri Department of Natural Resources awarded a Certificate of Completion to Missouri Gas Energy in 2001 for a site located at 20th and Indiana in Kansas City after an initial site analysis and the property was subsequently sold.

Source removal has been conducted at all of the owned sites since 2003 with the exception of Joplin, which is in the early stages of site analysis and characterization. Remediation efforts at these sites are at various stages of completion, ranging from groundwater monitoring and sampling following source removal activities to early site characterization in Joplin. As part of its participation in the BVCP, MGE communicates regularly with the Missouri Department of Natural Resources with respect to its remediation efforts and monitoring activities at these sites.

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

As discussed in Note 6, Derivative Instruments and Hedging Activities, the Utility enters into NYMEX exchange-traded 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 the Utility to a new brokerage firm. On June 27, 2013 the bankruptcy Trustee issued a statement projecting that MF Global customers would receive a full payout of their claims. In 2014, the Utility account was paid in full.

The Utility 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 Utility.



10.	SUBSEQUENT EVENTS

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

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

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

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

Among the factors that may cause results to differ materially from those contemplated in any forward-looking statement are:



•	weather conditions and catastrophic events, particularly severe weather in the natural gas producing areas of the country;
•	volatility in gas prices, particularly sudden and sustained changes in natural gas prices, including the related impact on margin deposits associated with the use of natural gas derivative instruments;
•	the impact of changes and volatility in natural gas prices on our competitive position in relation to suppliers of alternative heating sources, such as electricity;
•	changes in gas supply and pipeline availability, including decisions by natural gas producers to reduce production or shut in producing natural gas wells as well as other changes that impact supply for and access to our service area;
•	legislative, regulatory and judicial mandates and decisions, some of which may be retroactive, including those affecting
	•	allowed rates of return
	•	incentive regulation
	•	industry structure
	•	purchased gas adjustment provisions
	•	rate design structure and implementation
	•	regulatory assets
	•	non-regulated and affiliate transactions
	•	franchise renewals
	•	environmental or safety matters, including the potential impact of legislative and regulatory actions related to climate change and pipeline safety
	•	taxes
	•	pension and other postretirement benefit liabilities and funding obligations
	•	accounting standards;
•	the results of litigation;
•	retention of, ability to attract, ability to collect from, and conservation efforts of, customers;
•	capital and energy commodity market conditions, including the ability to obtain funds with reasonable terms for necessary capital expenditures and general operations and the terms and conditions imposed for obtaining sufficient gas supply;
•	discovery of material weakness in internal controls; and
•	employee workforce issues.

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

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RESULTS OF OPERATIONS

Overview

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

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

Also, on December 12, 2012, a subsidiary of Laclede Group, Plaza Massachusetts Acquisition Inc. (Plaza Mass), agreed to purchase New England Gas Company (NEG) from SUG. Subsequently, on February 11, 2013, the Company agreed to sell Plaza Mass to Algonquin Power & Utilities Corp. (APUC). On December 13, 2013, the Massachusetts Department of Public Utilities (MDPU) approved the transfer of NEG to an APUC subsidiary. Consistent with the February 11, 2013 agreements, on December 20, 2013, the Company closed the sale of Plaza Mass to an APUC subsidiary and received $11.0 million from APUC. On December 24, 2013, the Massachusetts Attorney General filed a Motion for Clarification/Reconsideration with the MDPU which, among other things, claims that legislative approval is required for a transfer of utility assets. On March 26, 2014, the MDPU signed an order denying the Attorney General's motion, so the MDPU's order approving the sale of NEG is now final.

These receipts of funds effectively reduced the Utility's purchase price of MGE to $940.1 million and reduced goodwill related to the transaction to $216.4 million. The acquisition was accounted for under the acquisition method of accounting in accordance with ASC 805 (“Topic 805”), “Business Combinations.” Accordingly, goodwill was measured as the excess of the acquisition-date fair value of the consideration transferred over the amount of acquisition-date identifiable assets acquired net of assumed liabilities.

EARNINGS

THREE MONTHS ENDED MARCH 31, 2014

Net Income

The Utility's net income totaled $44.2 million for the quarter ended March 31, 2014, an increase of $14.5 million compared with the quarter ended March 31, 2013. The increase was primarily due to the acquisition of MGE. The increase was partially offset by higher interest and income tax expenses which also related to the acquisition of MGE.

Operating Revenues and Operating Expenses

In addition to operating revenues and operating expenses, management also uses the non-GAAP measure of operating margin when evaluating result of operations, as shown in the table below. The Utility passes on to its customers (subject to prudence review by the MoPSC) increases and decreases in the wholesale cost of natural gas in accordance with its PGA Clause. The volatility of the wholesale natural gas market results in fluctuations from period to period in the recorded levels of, among other items, revenues and natural gas cost expense.

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Nevertheless, increases and decreases in the cost of gas associated with system gas sales volumes have no direct effect on operating income. Reconciliations of operating margin to the most directly comparable GAAP measure are shown below.



(Millions)		Gas Utility		Other			Total
Three Months Ended March 31, 2014
	Operating Revenues	$	638.7	$	—		$	638.7
	Natural and propane gas expense	430.6		—			430.6
	Gross receipts tax expenses	33.3		—			33.3
	Operating margin (non-GAAP)	174.8		—			174.8
	Depreciation and amortization	20.1		—			20.1
	Other operating expenses	80.6		(0.3		)	80.3
	Operating income (GAAP)	$	74.1	$	0.3		$	74.4

Three Months Ended March 31, 2013
	Operating Revenues	$	363.9	$	0.2		$	364.1
	Natural and propane gas expense	237.9		—			237.9
	Gross receipts tax expenses	16.8		—			16.8
	Operating margin (non-GAAP)	109.2		0.2			109.4
	Depreciation and amortization	11.2		—			11.2
	Other operating expenses	46.2		1.3			47.5
	Operating income (GAAP)	$	51.8	$	(1.1	)	$	50.7

Gas Utility

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



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

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

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



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

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

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

Interest Charges

Interest charges during the three months ended March 31, 2014 increased $3.2 million from the same period last year. The increase was primarily due to the net effect of the March 2013 and August 2013 issuances of additional long-term debt of $100 million and $450 million, respectively. Average short-term interest rates were 0.3% for both the three months ended March 31, 2014 and 2013. Average short-term borrowings were $138.2 million for the three months ended March 31, 2014, compared with $50.9 million for the three months ended March 31, 2013.

Income Taxes

The $4.5 million increase in income taxes was primarily due to higher pre-tax income.

SIX MONTHS ENDED MARCH 31, 2014

Net Income

The Utility's net income totaled $79.5 million for the six months ended March 31, 2014, an increase of $24.0 million compared with the six months ended March 31, 2013. The increase was primarily due to the acquisition of MGE.

Operating Revenues and Operating Expenses

In addition to operating revenues and operating expenses, management also uses the non-GAAP measure of operating margin when evaluating result of operations, as shown in the table below. The Utility passes on (subject to prudence review by the MoPSC) increases and decreases in the wholesale cost of natural gas in accordance with its PGA Clause to their customers. The volatility of the wholesale natural gas market results in fluctuations from period to period in the recorded levels of, among other items, revenues and natural gas cost expense.



(Millions)		Gas Utility		Other			Total
Six Months Ended March 31, 2014
	Operating Revenues	$	1,073.9	$	0.1		$	1,074.0
	Natural and propane gas expense	692.1		—			692.1
	Gross receipts tax expenses	52.9		—			52.9
	Operating margin (non-GAAP)	328.9		0.1			329.0
	Depreciation and amortization	40.1		—			40.1
	Other operating expenses	152.3		(0.2		)	152.1
	Operating income (GAAP)	$	136.5	$	0.3		$	136.8

Six Months Ended March 31, 2013
	Operating Revenues	$	614.7	$	1.4		$	616.1
	Natural and propane gas expense	382.0					382.0
	Gross receipts tax expenses	26.5		—			26.5
	Operating margin (non-GAAP)	206.2		1.4			207.6
	Depreciation and amortization	22.2		—			22.2
	Other operating expenses	90.9		1.8			92.7
	Operating income (GAAP)	$	93.1	$	(0.4	)	$	92.7

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Gas Utility

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



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

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

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



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

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

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

Interest Charges

Interest charges during the six months ended March 31, 2014 increased $7.5 million from the same period last year. The increase was primarily due to the net effect of the March 2013 and August 2013 issuances of additional long-term debt of $100 million and $450 million, respectively. Average short-term interest rates were 0.3% for both the six months ended March 31, 2014 and 2013. Average short-term borrowings were $138.7 million for the six months ended March 31, 2014, compared with $108.2 million for the six months ended March 31, 2013.

Income Taxes

The $11.5 million increase in income taxes was primarily due to higher pre-tax income.

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REGULATORY AND OTHER MATTERS

A petition was filed with the Massachusetts Department of Public Utilities (MDPU) on January 24, 2013 for approval of the Company's acquisition of NEG. In accordance with the February 11, 2013 agreement between Laclede Group and Algonquin Power Utilities Corporation (APUC) providing for the sale of the Company’s subsidiary, Plaza Mass, to Liberty Utilities, an APUC subsidiary, an amended petition was filed with DPU on February 19, 2013 requesting that the DPU authorize the sale of NEG to Liberty Utilities. On December 13, 2013, the MDPU approved the sale of NEG to Liberty Utilities. On December 20, 2013, the Company closed the sale of Plaza Mass and received $11.0 million from APUC. On December 24, 2013, the Massachusetts Attorney General filed a Motion for Clarification/Reconsideration with the MDPU which, among other things, claims that legislative approval is required for a transfer of utility assets. On March 26, 2014, the MDPU issued an order denying the Attorney General's motion, so the MDPU's order approving the sale of NEG is now final.

On September 16, 2013, MGE filed tariff sheets in a new general rate case proceeding that were designed to increase the Utility's total revenues by $23.4 million, less the current annualized Infrastructure System Replacement Surcharge (ISRS) revenues of $6.3 million that were already being recovered from customers. Consistent with its normal practice, the MoPSC suspended implementation of the MGE proposed rates on September 17, 2013 and set the case for hearing in April 2014. On April 11, 2014, MGE and other parties to the rate case filed a Stipulation and Agreement resolving all issues in the case. On April 16, 2014, the MoPSC approved the Stipulation and Agreement, pursuant to which MGE will increase its base rates by $7.8 million effective on May 1, 2014. This result is essentially equivalent to incorporating MGE’s ISRS revenues into base rates. In addition, effective October 1, 2014, MGE will lower its fixed monthly charge for residential and small commercial customers and instate a volumetric charge in its place. After this adjustment, MGE will still be recovering about 83% of its distribution costs to these customers through the fixed monthly charge. On December 6, 2013, MGE filed for a $1.6 million increase in ISRS revenues to recover the costs of gas safety replacement investments and public improvement projects over the previous nine months. Effective March 21, 2014, the MoPSC approved an increase in MGE’s ISRS in the amount of $1.7 million annually. However, pursuant to the settlement of the MGE rate case, the ISRS rates will be reset to zero effective May 1, 2014. MGE will be permitted to make future ISRS filings for qualifying expenditures incurred on and after January 1, 2014.

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

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

CRITICAL ACCOUNTING POLICIES

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


•	Accounts receivable and allowance for doubtful accounts


•	Employee benefits and postretirement obligations


•	Regulated operations

There were no significant changes to these critical accounting policies during the six months ended March 31, 2014.

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

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FINANCIAL CONDITION

CASH FLOWS

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

Net cash provided by operating activities was $144.5 million for the six months ended March 31, 2014, compared with $127.0 million for the six months ended March 31, 2013. On this comparative basis, the main drivers of higher cash inflows in the six months ended March 31, 2014 were a higher sendout of natural gas stored underground, higher net income, seasonality of accounts payables associated with natural gas, and higher depreciation, amortization, and accretion. These cash inflows were partially offset by the seasonality of the accounts receivable balance increases reflecting the inclusion of MGE's operations and the timing of collections of gas cost under the Utility's PGA Clauses. quarter.

Net cash used in investing activities for the six months ended March 31, 2014 was $48.1 million, compared with $63.6 million for the six months ended March 31, 2013. The decrease primarily reflects the receipt of $23.9 million from ETE for the final reconciliation amount associated with the MGE acquisition. The decrease was partially offset by additional capital expenditures this year for distribution plant investments associated with the addition of MGE.

Net cash used in financing activities was $115.4 million for the six months ended March 31, 2014, compared with $20.6 million for the six months ended March 31, 2013. The variation primarily reflects the maturity of $80 million of first mortgage bonds compared to $100 million of first mortgage bonds issued, an increase in dividends paid due to an increase in shares outstanding as well as a higher dividend rate. These cash outflows were partially offset by increased net borrowings from the Laclede Group.

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LIQUIDITY AND CAPITAL RESOURCES

Short-term Debt

As indicated in the discussion of cash flows above, the Utility’s short-term borrowing requirements typically peak during the colder months. These short-term cash requirements can be met through the sale of commercial paper supported by lines of credit with banks or through direct use of the lines of credit. At March 31, 2014, the Utility had a syndicated line of credit in place of $450 million from nine banks, which is scheduled to expire in September 2018. The largest portion provided by a single bank is 15.6%. The Utility's line of credit includes a covenant limiting total debt, including short-term debt, to no more than 70% of total capitalization. As defined in the line of credit, total debt was 47% of total capitalization on March 31, 2014.

Due to lower yields available to Laclede Group on short-term investments, Laclede Group elected to provide a portion of the Utility's short-term funding through intercompany lending during the six months ended March 31, 2014. Information about the Utility’s short-term borrowings during the six months ended March 31, 2014 and as of March 31, 2014, is presented below:



	Commercial Paper Borrowings	Borrowings from Laclede Group	Total Short-Term Borrowings
Six Months Ended March 31, 2014
Weighted average borrowings outstanding	$99.5 million	$39.2 million	$138.7 million
Weighted average interest rate	0.3%	0.3%	0.3%
Range of borrowings outstanding	$20.0 - $179.5 million	$8.2 - $77.4 million	$40.7 - $229.4 million

As of March 31, 2014
Borrowings outstanding at end of period	$36.0 million	$77.4 million	$113.4 million
Weighted average interest rate	0.3%	0.3%	0.3%

Based on average short-term borrowings for the six months ended March 31, 2014, an increase in the average interest rate of 100 basis points would decrease the Utility’s pre-tax earnings and cash flows by approximately $1.4 million on an annual basis, portions of which may be offset through the application of PGA carrying costs.

Long-term Debt and Equity

The Utility has MoPSC authority to issue debt securities and preferred stock, including on a private placement basis, as well as to issue common stock, receive paid-in capital, and enter into capital lease agreements, all for a total of up to $518 million. This authorization is effective through June 30, 2015. During the six months ended March 31, 2014, pursuant to this authority, the Utility sold 18 shares of its common stock to Laclede Group for $0.7 million. For more information on these sales of stock, see Part II., Item 2. Unregistered Sales of Equity Securities and Use of Proceeds. As of April 25, 2014, $370.1 million remains available under this authorization. Laclede Gas has a shelf registration on form S-3 for issuance of first mortgage bonds, unsecured debt and preferred stock, which expires August 6, 2016. First mortgage bonds in the amount of $450 million were issued under this registration in fiscal year 2013. The amount, timing, and type of additional financing to be issued under this shelf registration will depend on cash requirements and market conditions, as well as future MoPSC authorizations.

On December 6, 2013, the Utility provided a notice of redemption to holders for the entire $80 million aggregate principal amount outstanding of its previously issued 6.35% Series bonds due in 2038. The redemption, which was for cash and included accrued interest, was completed on January 6, 2014. At March 31, 2014, the Utility had fixed-rate long-term debt totaling $810 million. While the remaining long-term debt issues are fixed-rate, they are subject to changes in their fair value as market interest rates change. However, increases or decreases in fair value would impact earnings and cash flows only if the Utility were to reacquire any of these issues in the open market prior to maturity. Under GAAP applicable to the Utility's regulated operations, losses or gains on early redemptions of long-term debt would typically be deferred as regulatory assets or regulatory liabilities and amortized over a future period. Of the Utility’s $810 million in long-term debt, $25 million have no call option, $435 million have make-whole call options, and $350 million are callable at par three to six months prior to maturity. None of the debt has any put options.

Other

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

Utility capital expenditures were $67.1 million for the six months ended March 31, 2014, compared with $62.6 million for the same period last year. The increase in capital expenditures, compared with the prior period, is primarily attributable to additional expenditures for distribution plant investments as well as the addition of MGE capital expenditures.

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Capitalization at March 31, 2014 consisted of 56.0% common stock equity and 44.0% long-term debt.

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

The seasonal nature of the Utility's sales affects the comparison of certain balance sheet items at March 31, 2014 and at September 30, 2013, such as Accounts receivable - net, Gas stored underground, Notes payable, Accounts payable, Regulatory assets, Regulatory liabilities, and Delayed and Advance customer billings. The Balance Sheet at March 31, 2013 is presented to facilitate comparison of these items with the corresponding interim period of the preceding fiscal year.

CONTRACTUAL OBLIGATIONS

As of March 31, 2014, the Utility had contractual obligations with payments due as summarized below (in millions):



			Payments due by period
Contractual Obligations	Total		Remaining Fiscal Year 2014		Fiscal Years 2015-2016		Fiscal Years 2017-2018		Fiscal Years 2019 and thereafter
Principal Payments on Long-Term Debt	$	810	$	—	$	—	$	100	$	710
Interest Payments on Long-Term Debt	542		17		69		69		387
Operating Leases (a)	125		3		11		8		103
Purchase Obligations – Natural Gas (b)	805		271		296		167		71
Purchase Obligations – Other (c)	71		18		22		18		13
Other Long-Term Liabilities	155		10		31		32		82
Total (d)	$	2,508	$	319	$	429	$	394	$	1,366


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

(b)

These purchase obligations represent the minimum payments required under existing natural gas transportation and storage contracts and natural gas supply agreements. These amounts reflect fixed obligations as well as obligations to purchase natural gas at future market prices, calculated using March 31, 2014 NYMEX futures prices. The Utility recovers the costs related to its purchases, transportation, and storage of natural gas through the operation of its PGA Clause, subject to prudence review by the MoPSC; however, variations in the timing of collections of gas costs from customers affect short-term cash requirements. Additional contractual commitments are generally entered into prior to or during the heating season.


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

(d)

Long-term liabilities associated with unrecognized tax benefits, totaling $3.6 million, have been excluded from the table above because the timing of future cash outflows, if any, cannot be reasonably estimated. Also, commitments related to pension and postretirement benefit plans have been excluded from the table above. Contributions to the pension plans for the remaining six months of fiscal 2014 are anticipated to be approximately $14.4 million to the qualified trusts and $0.2 million to the non-qualified plans. With regard to the postretirement benefits, the Utility anticipates contributing $14.4 million to the qualified trusts and $0.3 million directly to participants from the Utility’s funds during the remaining six months of fiscal year 2014. For further discussion of the Company’s pension and postretirement benefit plans, refer to Note 3, Pension Plans and Other Postretirement Benefits, of the Notes to Financial Statements.

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MARKET RISK

Commodity Price Risk

The Utility's commodity price risk, which arises from market fluctuations in the price of natural gas, is primarily managed through the operation of its PGA Clause. The PGA Clause allows the Utility to flow through to customers, subject to prudence review by the MoPSC, the cost of purchased gas supplies. The Utility is allowed the flexibility to make up to three discretionary PGA changes during each year, in addition to its mandatory November PGA change, so long as such changes are separated by at least two months. The Utility is able to mitigate, to some extent, changes in commodity prices through the use of physical storage supplies and regional supply diversity. The Utility also has a risk management policy that allows for the purchase of natural gas derivative instruments with the goal of managing its price risk associated with purchasing natural gas on behalf of its customers. This policy prohibits speculation. Costs and cost reductions, including carrying costs, associated with the Utility’s use of natural gas derivative instruments are allowed to be passed on to the Utility’s customers through the operation of its PGA Clause. Accordingly, the Utility does not expect any adverse earnings impact as a result of the use of these derivative instruments. However, the timing of recovery for cash payments related to margin requirements may cause short-term cash requirements to vary. Nevertheless, carrying costs associated with such requirements, as well as other variations in the timing of collections of gas costs, are recovered through the PGA Clause. For more information about the Utility’s natural gas derivative instruments, see Note 6, Derivative Instruments and Hedging Activities, of the Notes to Financial Statements.

Interest Rate Risk

The Utility is subject to interest rate risk associated with its long-term and short-term debt issuances. Based on average short-term borrowings during the six months ended March 31, 2014, an increase of 100 basis points in the underlying average interest rate for short-term debt would have caused an increase in interest expense of approximately $1.4 million on an annual basis. Portions of such increases may be offset through the application of PGA carrying costs. At March 31, 2014, the Utility had fixed-rate long-term debt totaling $810 million. While these long-term debt issues are fixed-rate, they are subject to changes in fair value as market interest rates change. However, increases or decreases in fair value would impact earnings and cash flows only if the Utility were to reacquire any of these issues in the open market prior to maturity. Under GAAP applicable to the Utility's regulated operations, losses or gains on early redemptions of its long-term debt would typically be deferred as regulatory assets or regulatory liabilities and amortized over a future period.

ENVIRONMENTAL MATTERS

The Utility owns and operates natural gas distribution, transmission and storage facilities, the operations of which are subject to various environmental laws, regulations and interpretations. While environmental issues resulting from such operations arise in the ordinary course of business, such issues have not materially affected the Utility's financial position and results of operations. As environmental laws, regulations, and their interpretations change, however, the Utility may be required to incur additional costs. For information relative to environmental matters, see Note 9, Commitments and Contingencies, of the Notes to Financial Statements.

OFF-BALANCE SHEET ARRANGEMENTS

The Utility has no off-balance sheet arrangements.

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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 31 of this report.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

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

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

Changes in Internal Control over Financial Reporting

As a result of the acquisition of MGE mentioned above, the Company is evaluating and implementing changes to processes, policies and other components of its internal control over financial reporting with respect to the consolidation of MGE’s operations into the Company’s financial statements. Management continues to be engaged in substantial efforts to evaluate the effectiveness of our internal control procedures and the design of those control procedures relating to MGE. Except for the activities described above, there were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended March 31, 2014 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

For a description of environmental matters and legal proceedings, see Note 9, Commitments and Contingencies, of the Notes to Financial Statements. For a description of pending regulatory matters of the Utility, see Part I., Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Regulatory and Other Matters, on page 27 of this report.

The Utility is involved in litigation, claims and investigations arising in the normal course of business. Management, after discussion with counsel, believes that the final outcome of these matters will not have a material effect on the financial position or results of operations of the Utility.

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

During the six months ended March 31, 2014, pursuant to this authority, the Utility sold 18 shares of its common stock to Laclede Group for $0.7 million. The proceeds from the sale were used for general corporate purposes. Exemption from registration was claimed under Section 4(a)(2) of the Securities Act of 1933, as amended.

Item 6. Exhibits


(a)	See Exhibit Index

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SIGNATURE

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



		Laclede Gas Company

Dated:	April 29, 2014	By:	/s/ Steven P. Rasche
			Steven P. Rasche
			Chief Financial Officer
			(Authorized Signatory and Chief Financial Officer)

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INDEX TO EXHIBITS



Exhibit No.

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 Income for the six months ended March 31, 2014 and 2013; (iii) unaudited Statements of Comprehensive Income for the six months ended March 31, 2014 and 2013; (iv) unaudited Balance Sheets at March 31, 2014, September 30, 2013 and March 31, 2013; (v) unaudited Statements of Cash Flows for the six months ended March 31, 2014 and 2013, and (vi) Notes to the unaudited Financial Statements. We also make available on our website the Interactive Data Files submitted as Exhibit 101 to this Quarterly Report.