Edgar Filing: LACLEDE GAS CO

LGC-2013.12.31-10Q

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 December 31, 2013



[ ]	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 January 31, 2014, there were 24,558 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		30

Item 4	Controls and Procedures		30

PART II. OTHER INFORMATION

Item 1	Legal Proceedings		31

Item 2	Unregistered Sales of Equity Securities and Use of Proceeds		31

Item 6	Exhibits		31

SIGNATURE			32

INDEX TO EXHIBITS			33

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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
	December 31,
(Thousands)	2013		2012
Operating Revenues:
Utility	$	435,228	$	250,791
Other	24		1,143
Total Operating Revenues	435,252		251,934
Operating Expenses:
Utility
Natural and propane gas	261,553		144,334
Other operation and maintenance expenses	62,516		39,653
Depreciation and amortization	20,026		10,965
Taxes, other than income taxes	28,589		14,806
Total Utility Operating Expenses	372,684		209,758
Other	234		124
Total Operating Expenses	372,918		209,882
Operating Income	62,334		42,052
Other Income and (Income Deductions) – Net	1,664		1,089
Interest Charges:
Interest on long-term debt	9,485		5,401
Other interest charges	782		524
Total Interest Charges	10,267		5,925
Income Before Income Taxes	53,731		37,216
Income Tax Expense	18,437		11,473
Net Income	$	35,294	$	25,743

See Notes to Financial Statements.

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LACLEDE GAS COMPANY

STATEMENTS OF COMPREHENSIVE INCOME

(UNAUDITED)



	Three Months Ended
	December 31,
(Thousands)	2013			2012
Net Income	$	35,294		$	25,743
Other Comprehensive (Loss) Income, Before Tax:
Net gains (losses) on cash flow hedging derivative instruments:
Net hedging gains arising during the period	9			57
Reclassification adjustment for gains included in net income	(58		)	(47		)
Net unrealized (losses) gains on cash flow hedging derivative instruments	(49		)	10
Defined benefit pension and other postretirement plans:
Amortization of actuarial loss included in net periodic pension and postretirement benefit cost	98			90
Other Comprehensive Income, Before Tax	49			100
Income Tax Expense Related to Items of Other Comprehensive Income	37			48
Other Comprehensive Income, Net of Tax	12			52
Comprehensive Income	$	35,306		$	25,795

See Notes to Financial Statements.

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LACLEDE GAS COMPANY

BALANCE SHEETS

(UNAUDITED)



	December 31,			September 30,			December 31,
(Thousands)	2013			2013			2012
ASSETS
Utility Plant	$	2,293,032		$	2,271,189		$	1,508,770
Less: Accumulated depreciation and amortization	507,457			494,559			470,840
Net Utility Plant	1,785,575			1,776,630			1,037,930
Goodwill	235,814			247,078			—
Other Property and Investments	55,672			54,016			47,304
Current Assets:
Cash and cash equivalents	7,923			23,916			2,803
Accounts receivable:
Utility	254,692			101,118			130,925
Non-utility	915			967			2,335
Associated companies	14,633			1,111			3,554
Other	18,383			14,148			9,658
Allowance for doubtful accounts	(10,743		)	(7,942		)	(6,951		)
Inventories:
Natural gas stored underground	135,659			164,740			85,465
Propane gas at FIFO cost	6,022			8,962			8,963
Materials and supplies at average cost	8,455			8,027			4,131
Derivative instrument assets	3,337			—			—
Unamortized purchased gas adjustments	9,903			17,533			30,492
Deferred income taxes	2,542			—			—
Prepayments and other	12,018			11,255			7,725
Total Current Assets	463,739			343,835			279,100
Deferred Charges:
Regulatory assets	530,953			545,937			440,844
Other	12,381			13,520			5,552
Total Deferred Charges	543,334			559,457			446,396
Total Assets	$	3,084,134		$	2,981,016		$	1,810,730

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LACLEDE GAS COMPANY

BALANCE SHEETS (Continued)

(UNAUDITED)



	December 31,			September 30,			December 31,
(Thousands)	2013			2013			2012
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock and Paid-in capital (24,558, 24,549, and 12,825 shares issued, respectively)	$	739,364		$	738,234		$	258,900
Retained earnings	258,703			237,803			252,183
Accumulated other comprehensive loss	(2,095		)	(2,107		)	(2,049		)
Total Common Stock Equity	995,972			973,930			509,034
Long-term debt (less current portion)	807,764			887,712			339,426
Total Capitalization	1,803,736			1,861,642			848,460
Current Liabilities:
Current portion of long-term debt	80,000			—			—
Notes payable	93,500			74,000			83,050
Notes payable – associated companies	47,951			46,729			50,766
Accounts payable	99,150			66,582			53,563
Accounts payable – associated companies	7,732			6,081			1,703
Advance customer billings	16,011			23,736			15,950
Wages and compensation accrued	15,752			20,807			12,401
Dividends payable	14,407			13,912			9,589
Customer deposits	15,485			15,062			8,437
Interest accrued	9,720			8,096			4,998
Taxes accrued	41,905			32,592			16,596
Deferred income taxes	—			1,692			4,644
Other	32,111			17,611			18,340
Total Current Liabilities	473,724			326,900			280,037
Deferred Credits and Other Liabilities:
Deferred income taxes	389,498			380,113			351,539
Unamortized investment tax credits	2,847			2,900			3,060
Pension and postretirement benefit costs	229,313			228,653			195,259
Asset retirement obligations	72,205			74,302			40,692
Regulatory liabilities	70,671			61,943			56,776
Other	42,140			44,563			34,907
Total Deferred Credits and Other Liabilities	806,674			792,474			682,233
Commitments and Contingencies (Note 9)
Total Capitalization and Liabilities	$	3,084,134		$	2,981,016		$	1,810,730

See Notes to Financial Statements.

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LACLEDE GAS COMPANY

STATEMENTS OF CASH FLOWS

(UNAUDITED)



	Three Months Ended December 31,
(Thousands)	2013			2012
Operating Activities:
Net Income	$	35,294		$	25,743
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	20,026			10,970
Deferred income taxes and investment tax credits	(2,831		)	1,609
Other – net	(397		)	419
Changes in assets and liabilities:
Accounts receivable – net	(168,477		)	(60,249		)
Unamortized purchased gas adjustments	7,630			10,182
Deferred purchased gas costs	23,093			2,266
Accounts payable	38,855			14,811
Advance customer billings - net	(7,725		)	(9,196		)
Taxes accrued	9,313			2,760
Natural gas stored underground	29,081			4,387
Other assets and liabilities	11,440			(8,108		)
Net cash (used in) provided by operating activities	(4,698		)	(4,406		)
Investing Activities:
Capital expenditures	(34,002		)	(27,621		)
Other investments	(653		)	(980		)
Net cash used in investing activities	(34,655		)	(28,601		)
Financing Activities:
Maturity of first mortgage bonds	—			(25,000		)
Issuance of short-term debt - net	19,500			42,950
Borrowings from Laclede Group	19,722			46,446
Repayment of borrowings from Laclede Group	(18,500		)	(32,805		)
Changes in book overdrafts	15,847			10,160
Dividends paid	(13,917		)	(9,342		)
Issuance of common stock to Laclede Group	359			793
Excess tax benefits from stock-based compensation	364			221
Other	(15		)	(15		)
Net cash provided by financing activities	23,360			33,408
Net (Decrease) Increase in Cash and Cash Equivalents	(15,993		)	401
Cash and Cash Equivalents at Beginning of Period	23,916			2,402
Cash and Cash Equivalents at End of Period	$	7,923		$	2,803

Supplemental disclosure of cash flow information:
Interest paid	$	8,658		$	9,627
Income taxes paid	(1,346		)	(3,140		)
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, impacting the comparability of the current year financial statements to prior years. For a further discussion of the acquisition, see Note 2, MGE Acquisition. Due to the seasonal nature of the business of the Utility, Laclede Group’s earnings are typically concentrated during the heating season of November through April each year, although earnings for Missouri Gas Energy (MGE) are less seasonal than earnings from Laclede Gas, due to MGE's straight fixed-variable rate design which recovers fixed costs more evenly over the year.

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 quarter ended December 31, 2013 sales of natural gas from the Utility to LER were $0.1 million and for the quarter ended December 31, 2012 were $0.7 million. Sales of natural gas from LER to the Utility during the quarters ended December 31, 2013 and 2012 were $19.5 million and $7.6 million, respectively. Transportation services provided by Laclede Pipeline Company to the Utility during both the quarters ended December 31, 2013 and 2012 totaled $0.3 million.

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 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 $48.0 million, $46.7 million, and $50.8 million at December 31, 2013, September 30, 2013 and December 31, 2012, respectively. The interest rate on these borrowings was 0.3% at December 31, 2013, 0.3% at September 30, 2013, and 0.3% at December 31, 2012. 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 December 31, 2013 and 2012, for the Utility, were $101.9 million and $39.6 million, respectively. The amount of accrued unbilled revenue at September 30, 2013 was $25.2 million.

GROSS RECEIPTS TAXES - Gross receipts taxes associated with the Utility's natural gas utility service are imposed on the Utility and billed to its customers. These amounts are recorded gross in the Statements of Income. Amounts recorded in Utility Operating Revenues for the quarters ended December 31, 2013 and 2012 were $19.9 million and $10.3 million, respectively. Gross receipts taxes are expensed by the Utility and included in the Taxes, other than income taxes line.

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 ended December 31, 2013 and 2012 are presented below:



	Three Months Ended
	December 31,
(Thousands)	2013			2012
Total equity compensation cost	$	457		$	532
Compensation cost capitalized	(149		)	(183		)
Compensation cost recognized in net income, before income tax	$	308		$	349

As of December 31, 2013, there was $7.9 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 2.4 years.

2. MGE Acquisition

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

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

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

The acquisition was accounted for under the acquisition method of accounting in accordance with ASC 805 (“Topic 805”), “Business Combinations.” Accordingly, goodwill was measured as the excess of the acquisition-date fair value of the consideration transferred over the amount of acquisition-date identifiable assets acquired net of assumed liabilities. The Utility recorded $235.8 million of goodwill as an asset in the consolidated balance sheet.

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



3.	PENSION PLANS AND OTHER POSTRETIREMENT BENEFITS

Pension Plans

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

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

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The net periodic pension costs include the following components:



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

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

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

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

The funding policy of the Utility is to contribute an amount not less than the minimum required by government funding standards, nor more than the maximum deductible amount for federal income tax purposes. Fiscal year 2014 contributions to the pension plans through December 31, 2013 were $3.8 million to the qualified trusts. There were no contributions to the non-qualified plans in the first quarter of fiscal 2014. Contributions to the pension plans for the remaining nine months of fiscal 2014 are anticipated to be approximately $24.0 million to the qualified trusts and $0.4 million to the non-qualified plans.

Postretirement Benefits

The Utility provides certain life insurance benefits at retirement. 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 December 31, 2013 and 2012 were $2.4 million, including amounts charged to construction.

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Net periodic postretirement benefit costs consisted of the following components:



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

Missouri state law provides for the recovery in rates of costs accrued pursuant to GAAP provided that such costs are funded through an independent, external funding mechanism. The Utility established Voluntary Employees’ Beneficiary Association (VEBA) and Rabbi trusts as its external funding mechanisms. 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. There were no contributions to the postretirement plans in fiscal 2014 through December 31, 2013. Contributions to the postretirement plans for the remaining nine months of fiscal year 2014 are anticipated to be $19.2 million to the qualified trusts and $0.3 million paid directly to participants from the Utility's funds.

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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 December 31, 2013
Cash and cash equivalents	$	7,923	$	7,923	$	7,899	$	24	$	—
Short-term debt	141,451		141,451		—		141,451		—
Long-term debt, including current portion	887,764		913,296		—		913,296		—

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 December 31, 2012
Cash and cash equivalents	$	2,803	$	2,803	$	2,779	$	24	$	—
Short-term debt	133,816		133,816		—		133,816		—
Long-term debt, including current portion	339,426		431,091		—		431,091		—

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 December 31, 2013
Assets
U. S. Stock/Bond Mutual Funds	$	15,003	$	—	$	—	$	—		$	15,003
NYMEX/ICE natural gas contracts	3,225		—		—		(2,802		)	423
OTCBB natural gas contracts	—		3,609		—		(913		)	2,696
NYMEX gasoline and heating oil contracts	163		—		—		—			163
Total	$	18,391	$	3,609	$	—	$	(3,715	)	$	18,285
Liabilities
NYMEX/ICE natural gas contracts	$	285	$	—	$	—	$	(285	)	$	—
OTCBB natural gas contracts	—		913		—		(913		)	—
Total	$	285	$	913	$	—	$	(1,198	)	$	—

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 December 31, 2012
Assets
U. S. Stock/Bond Mutual Funds	$	13,146	$	—	$	—	$	—		$	13,146
NYMEX natural gas contracts	1,726		—		—		(1,726		)	—
NYMEX gasoline and heating oil contracts	281		—		—		(281		)	—
Total	$	15,153	$	—	$	—	$	(2,007	)	$	13,146
Liabilities
NYMEX natural gas contracts	$	6,162	$	—	$	—	$	(6,162	)	$	—

The mutual funds included in Level 1 are valued based on exchange-quoted market prices of identical securities. Derivative instruments included in Level 1 are valued using quoted market prices on the NYMEX. Derivative instruments classified in Level 2 include physical commodity derivatives that are valued using Over The Counter Bulletin Board (OTCBB), broker, or dealer quotation services whose prices are derived principally from, or are corroborated by, observable market inputs. 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 December 31, 2013, the Utility held 0.8 million gallons of gasoline futures contracts at an average price of $2.66 per gallon. Most of these contracts, the longest of which extends to September 2014, are designated as cash flow hedges of forecasted transactions pursuant to ASC Topic 815, “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 December 31, 2013 were as follows:



	MMBtu (millions)	Avg. Price Per MMBtu
NYMEX Open long futures positions
Fiscal 2014	5.25	$	3.88
Fiscal 2015	0.94	3.84
OTCBB Open long futures positions
Fiscal 2014	14.03	$	3.99
Fiscal 2015	8.60	4.20
Fiscal 2016	0.11	4.15

At December 31, 2013, the Utility also had 19.2 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 December 31, 2013, 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
	Location of Gain (Loss)	December 31,
(Thousands)	Recorded in Income	2013		2012
Derivatives in Cash Flow Hedging Relationships
NYMEX gasoline and heating oil contracts:
Effective portion of gain (loss) recognized in OCI on derivatives		$	9	$	57
Effective portion of gain reclassified from AOCI to income and maintenance	Utility – Other Operation and Maintenance Expenses	58		47
Ineffective portion of gain (loss) on derivatives recognized in income and maintenance	Utility – Other Operation and Maintenance Expenses	120		(101		)
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	$	13	$	33

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 December 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	$	154	Derivative Instrument Assets	$	—
Derivatives not designated as hedging instruments
NYMEX natural gas contracts	Derivative Instrument Assets	423		Derivative Instrument Assets	—
	Accounts Receivable - Other	2,802		Accounts Receivable - Other	285
NYMEX gasoline and heating oil contracts	Derivative Instrument Assets	9		Accounts Receivable - Other	—
OTCBB natural gas contracts	Derivative Instrument Assets	3,386		Derivative Instrument Assets	636
	Other Deferred Credits	223		Other Deferred Credits	278
Sub-total		6,843			1,199
Total derivatives		$	6,997		$	1,199

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	Other Current Liabilities	228		Current Liabilities - Other	4,045
	Other Deferred Credits	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 December 31, 2012
	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	$	249	Accounts Receivable - Other	$	—
Derivatives not designated as hedging instruments
NYMEX natural gas contracts	Accounts Receivable - Other	1,726		Accounts Receivable - Other	6,162
NYMEX gasoline and heating oil contracts	Accounts Receivable - Other	32		Accounts Receivable - Other	—
Sub-total		1,758			6,162
Total derivatives		$	2,007		$	6,162

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)	December 31, 2013			September 30, 2013			December 31, 2012

Fair value of asset derivatives presented above	$	6,997		$	1,803		$	2,007
Fair value of cash margin receivables offset with derivatives	—			1,890			4,186
Netting of assets and liabilities with the same counterparty	(3,715		)	(3,693		)	(6,193		)
Derivative instrument assets, per Balance Sheets	$	3,282		$	—		$	—

Derivative Instrument Assets, per Balance Sheets:
Derivative instrument assets	$	3,337		$	—		$	—
Other deferred charges	(55		)	—			—
Total	$	3,282		$	—		$	—

Fair value of liability derivatives presented above	$	1,199		$	8,898		$	6,162
Fair value of cash margin payables offset with derivatives	2,516			6			31
Netting of assets and liabilities with the same counterparty	(3,715		)	(3,693		)	(6,193		)
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 December 31, 2013, September 30, 2013, and December 31, 2012 the Utility had $0.2 million, $2.9 million, and $3.5 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 December 31,
(Thousands)	2013		2012
Interest income	$	248	$	391
Net investment gain (loss)	756		(61		)
Other income	660		759
Other Income and (Income Deductions) – Net	$	1,664	$	1,089

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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 December 31, 2013
Operating revenues	$	435,228	$	24		$	—	$	435,252
Net Economic Earnings (losses)	35,778		(152		)	—		35,626
Total assets	3,084,134		—			—		3,084,134

Three Months Ended December 31, 2012
Operating revenues	$	250,791	$	1,143		$	—	$	251,934
Net Economic Earnings	25,341		460			—		25,801
Total assets	1,809,722		1,008			—		1,810,730



Reconciliation of Net Economic Earnings to Net Income
	Three Months Ended
	December 31,
(Thousands)	2013			2012
Total Net Economic Earnings above	$	35,626		$	25,801
Add: Unrealized gain (loss) on energy-relate derivative contracts, net of tax	53			(58		)
Add: Acquisition, divestiture, and restructuring costs, net of tax	(385		)	—
Net Income	$	35,294		$	25,743



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 December 31, 2013 are estimated at approximately $876 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.

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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 probably begin in the Spring of 2014.

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

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

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

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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. As of November 26, 2013, the Utility had $0.2 million on deposit with MF Global that remains unavailable to the Utility pending final resolution by the bankruptcy trustee. As the Company has recovered 98% of the amount at issue in the MF Global bankruptcy, the total remaining exposure is not considered material.

On February 19, 2013, Heartland Midwest, LLC, a contractor for Time Warner Cable, hit a MGE natural gas line causing a gas leak while directionally boring during underground cable installation. The natural gas leak resulted in an explosion and fire which killed one person, injured approximately seventeen (including three MGE employees who were at the scene), caused major damage to JJ's restaurant, and caused property damage to adjacent buildings. Several lawsuits have been filed in state court in Jackson County, Missouri, alleging wrongful death, personal injury, property damage, and business interruption. The lawsuits are in the early stages of discovery. While the Company's total exposure is not considered material at this time, management plans to vigorously defend the matter and will continue to evaluate its exposure as discovery proceeds. Management believes, after discussion with counsel, that the final outcome of this matter will not have a material effect on the consolidated financial position, results of operations, or cash flows of the Company.

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

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

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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 straight fixed variable rate design lessen the impact of weather volatility on its customers during cold winters and stabilizes the Utility’s earnings by recovering fixed costs more evenly during the heating season. Due to the seasonal nature of the business of the Utility, Laclede Group’s earnings are typically concentrated in the November through April period, which generally corresponds with the heating season. Due to the seasonal nature of the business of the Utility, Laclede Group’s earnings are typically concentrated during the heating season of November through April each year, although earnings for Missouri Gas Energy (MGE) are less seasonal than earnings from Laclede Gas, due to MGE's straight fixed-variable rate design which recovers fixed costs more evenly over the year.

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

EARNINGS

THREE MONTHS ENDED DECEMBER 31, 2013

Net Income

The Utility's net income totaled $35.3 million for the quarter ended December 31, 2013, an increase of $9.6 million compared with the quarter ended December 31, 2012. The increase was primarily due to the acquisition of MGE. The increase was partially offset by higher interest and income tax expenses.

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.

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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
Quarter Ended December 31, 2013
	Operating Revenues	$	435.3	$	—		$	435.3
	Natural and propane gas expense	261.6		—			261.6
	Gross receipts tax expenses	19.5		—			19.5
	Operating margin (non-GAAP)	154.2		—			154.2
	Depreciation and amortization	20.0		—			20.0
	Other operating expenses	71.6		0.3			71.9
	Operating income (GAAP)	$	62.6	$	(0.3	)	$	62.3

Quarter Ended December 31, 2012
	Operating Revenues	$	250.8	$	1.1		$	251.9
	Natural and propane gas expense	144.1		0.2			144.3
	Gross receipts tax expenses	9.7		—			9.7
	Operating margin (non-GAAP)	97.0		0.9			97.9
	Depreciation and amortization	11.0		—			11.0
	Other operating expenses	44.7		0.1			44.8
	Operating income (GAAP)	$	41.3	$	0.8		$	42.1

Gas Utility

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



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

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

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

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

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Other

Other operating revenues and operating margin decreased by $1.1 million and $0.9 million, respectively, during the three months ended December 31, 2013 from the same period last year. The decrease is primarily attributed to propane sales being classified within regulated gas utility operating revenues pursuant to MoPSC requirements. Other operating expenses remained consistent during the three months ended December 31, 2013 from the same period last year.

Other Income and (Income Deductions) - Net

Other Income and (Income Deductions) - Net during the three months ended December 31, 2013 increased by $0.6 million from the same period last year, primarily due to higher net investment gains.

Interest Charges

Interest charges during the three months ended December 31, 2013 increased $4.4 million from the same period last year. The increase was primarily due to the net effect of the March 2013 and August 2013 issuances of additional long-term debt of $100 million and $450 million, respectively, and the October 2012 maturity of $25 million of 6 1/2% first mortgage bonds. Average short-term interest rates were 0.3% for both the three months ended December 31, 2013 and 2012. Average short-term borrowings were $138.2 million for the three months ended December 31, 2013, compared with $141.5 million for the three months ended December 31, 2012.

Income Taxes

The $7.0 million decrease in income taxes was primarily due to lower pre-tax income.

REGULATORY AND OTHER MATTERS

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

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

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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 three months ended December 31, 2013.

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

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 used in operating activities was $4.7 million for the three months ended December 31, 2013, compared with $4.4 million for the three months ended December 31, 2012. The variation is primarily associated with the seasonality of the accounts receivable balances reflecting the inclusion of MGE's operations and higher operating revenues. This increase in cash used is partially offset by a higher sendout of natural gas stored underground, the timing of collections of gas cost under the Utility's PGA Clause, higher net income, and higher depreciation, amortization, and accretion as compared to the prior year first quarter.

Net cash used in investing activities for the three months ended December 31, 2013 was $34.7 million, compared with $28.6 million for the three months ended December 31, 2012. The increase primarily reflects additional capital expenditures this year for distribution plant investments.

Net cash provided by financing activities was $23.4 million for the three months ended December 31, 2013, compared with $33.4 million for the three months ended December 31, 2012. The variation primarily reflects a decrease in net issuances of short-term debt, lower net borrowings from the Laclede Group and an increase in the payment of dividends, partially offset by the prior year repayment of first mortgage bonds.

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 December 31, 2013, the Utility had a syndicated line of credit in place of $450 million from nine banks, which is scheduled to expire in September 2018. The largest portion provided by a single bank is 15.6%. The Utility's line of credit includes a covenant limiting total debt, including short-term debt, to no more than 70% of total capitalization. As defined in the line of credit, total debt was 51% of total capitalization on December 31, 2013.

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

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 three months ended December 31, 2013. Information about the Utility’s short-term borrowings during the three months ended December 31, 2013 and as of December 31, 2013, is presented below:



	Commercial Paper Borrowings	Borrowings from Laclede Group	Total Short-Term Borrowings
Three Months Ended December 31, 2013
Weighted average borrowings outstanding	$93.2 million	$45.0 million	$138.2 million
Weighted average interest rate	0.3%	0.3%	0.3%
Range of borrowings outstanding	$70.0 – $116.2 million	$40.1 - $50.7 million	$110.1 - $162.9 million
As of December 31, 2013
Borrowings outstanding at end of period	$93.5 million	$48.0 million	$141.5 million
Weighted average interest rate	0.3%	0.3%	0.3%

Based on average short-term borrowings for the three months ended December 31, 2013, an increase in the average interest rate of 100 basis points would decrease 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 three months ended December 31, 2013, pursuant to this authority, the Utility sold 9 shares of its common stock to Laclede Group for $0.4 million. For more information on these sales of stock, see Part II., Item 2. Unregistered Sales of Equity Securities and Use of Proceeds. As of January 31, 2014, $370.5 million remains available under this authorization. Laclede Gas has a shelf registration on form S-3 for issuance of first mortgage bonds, unsecured debt and preferred stock, which expires August 6, 2016. First mortgage bonds in the amount of $450 million were issued under this registration 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.

At December 31, 2013, the Utility had fixed-rate long-term debt totaling $890 million, including the current portion. 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 $890 million in long-term debt, $50 million have no call option, $410 million have make-whole call options, $350 million are callable at par three to six months prior to maturity, and $80 million are callable at par beginning in October 2013. None of the debt has any put options. On December 6, 2013, Laclede Gas gave notice that it would call the $80 million in callable bonds, which was completed on January 6, 2014.

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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 $34.0 million for the three months ended December 31, 2013, compared with $27.6 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 and information technology investments.

Capitalization at December 31, 2013 consisted of 55.2% common stock equity and 44.8% 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 December 31, 2013 and at September 30, 2013, such as Accounts receivable - net, Gas stored underground, Notes payable, Accounts payable, Regulatory assets and Regulatory liabilities, and Delayed and Advance customer billings. The Balance Sheet at December 31, 2012 is presented to facilitate comparison of these items with the corresponding interim period of the preceding fiscal year.

CONTRACTUAL OBLIGATIONS

As of December 31, 2013, 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	890		$	80	$	—	$	100	$	710
Interest Payments on Long-Term Debt	678		31		79		79		489
Capital Leases (a)	—		—		—		—		—
Operating Leases (a)	11		5		5		1		—
Purchase Obligations – Natural Gas (b)	876		344		249		197		86
Purchase Obligations – Other (c)	73		21		20		19		13
Other Long-Term Liabilities	156		12		31		31		82
Total (d)	$	2,684	$	493	$	384	$	427	$	1,380


(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 December 31, 2013 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 $2.8 million, have been excluded from the table above because the timing of future cash outflows, if any, cannot be reasonably estimated. Also, commitments related to pension and postretirement benefit plans have been excluded from the table above. Contributions to the pension plans for the remaining nine months of fiscal 2014 are anticipated to be approximately $16.1 million to the qualified trusts and $0.4 million to the non-qualified plans. With regard to the postretirement benefits, the Utility anticipates contributing $19.2 million to the qualified trusts and $0.3 million directly to participants from the Utility’s funds during the remaining nine months of fiscal year 2014. For further discussion of the Company’s pension and postretirement benefit plans, refer to Note 3, Pension Plans and Other Postretirement Benefits, of the Notes to 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 three months ended December 31, 2013, an increase of 100 basis points in the underlying average interest rate for short-term debt would have caused an increase in interest expense of approximately $1.4 million on an annual basis. Portions of such increases may be offset through the application of PGA carrying costs. At December 31, 2013, the Utility had fixed-rate long-term debt totaling $890 million, including the current portion. 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 29 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 December 31, 2013 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 25 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 three months ended December 31, 2013, pursuant to this authority, the Utility sold 9 shares of its common stock to Laclede Group for $0.4 million. 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:	February 4, 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 three months ended December 31, 2013 and 2012; (iii) unaudited Statements of Comprehensive Income for the three months ended December 31, 2013 and 2012; (iv) unaudited Balance Sheets at December 31, 2013, September 30, 2013 and December 31, 2012; (v) unaudited Statements of Cash Flows for the three months ended December 31, 2013 and 2012, 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.