EnergySouth (ENSI) 10-Q 2007 Q2 Quarterly report

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

Form 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For Quarter EndedMarch 31, 2007

Commission File No.0-29604

ENERGYSOUTH, INC.

(Exact name of registrant as specified in its charter)

Delaware	58-2358943
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

2828 Dauphin Street, Mobile, Alabama	36606
(Address of principal executive office)	(Zip Code)

Registrant’s telephone number, including area code 251-450-4774

Indicate by check mark whether 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 reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ   Noo

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filero      Accelerated filerþ      Non-accelerated filero

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso   Noþ

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Common stock ($.01 par value) outstanding at May 7, 2007 — 7,978,190 shares.

ENERGYSOUTH, INC.
FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2007

INDEX

			Page No.
		PART I: FINANCIAL INFORMATION
Item 1		Financial Statements:
	(a)	Unaudited Condensed Consolidated Balance Sheets March 31, 2007 and 2006 and September 30, 2006		3 - 4
	(b)	Unaudited Condensed Consolidated Statements of Income Three and Six Months Ended March 31, 2007 and 2006		5
	(c)	Unaudited Condensed Consolidated Statements of Cash Flows Six Months Ended March 31, 2007 and 2006		6
	(d)	Notes to Unaudited Condensed Consolidated Financial Statements		7 - 18
Item 2		Management's Discussion and Analysis of Financial Condition and Results of Operations		19 - 26
Item 3		Quantitative and Qualitative Disclosures About Market Risk		26
Item 4		Controls and Procedures		27
		PART II: OTHER INFORMATION
Item 1A		Risk Factors		28
Item 5		Other Information		28
Item 6		Exhibits		28
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906
Press Release

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PART 1. FINANCIAL INFORMATION

ITEM 1: FINANCIAL STATEMENTS

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

EnergySouth, Inc.	March 31,						September 30,
In Thousands	2007			2006			2006
	(Unaudited)
ASSETS
Current Assets
Cash and Cash Equivalents	$	176		$	2,577		$	1,272
Restricted Cash		1,751			1,620			1,742
Receivables
Gas		14,183			12,058			5,454
Unbilled Revenue		2,224			3,343			1,492
Merchandise		1,978			2,098			2,013
Other		1,004			1,148			1,522
Allowance for Doubtful Accounts		(1,916	)		(1,761	)		(1,074	)
Materials, Supplies, and Merchandise, net (At Average Cost)		1,303			1,253			1,523
Gas Stored Underground (At Average Cost)		4,434			5,295			6,612
Regulatory Assets		5,109			2,451			2,083
Deferred Income Taxes					2,339			433
Prepaid Taxes		498						2,609
Prepayments		2,852			2,956			2,265
Total Current Assets		33,596			35,377			27,946
Property, Plant, and Equipment		300,783			288,641			295,503
Less: Accumulated Depreciation and Amortization		90,244			81,652			85,848
Property, Plant, and Equipment — Net		210,539			206,989			209,655
Construction Work in Progress		31,576			12,362			18,915
Total Property, Plant, and Equipment		242,115			219,351			228,570
Other Assets
Prepaid Pension Cost		783			879			819
Prepaid Postretirement Benefit		570						578
Deferred Charges		284			587			286
Prepayments		1,183			1,199			1,233
Regulatory Assets		109			250			193
Merchandise Receivables Due After One Year		2,971			3,188			3,055
Total Other Assets		5,900			6,103			6,164
Total	$	281,611		$	260,831		$	262,680

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

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UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

EnergySouth, Inc.	March 31,						September 30,
In Thousands, Except Share Data	2007			2006			2006
	(Unaudited)
LIABILITIES AND CAPITALIZATION
Current Liabilities
Current Maturities of Long-Term Debt	$	5,746		$	4,876		$	5,619
Notes Payable		5,975						5,300
Accounts Payable		14,608			10,213			7,355
Dividends Declared		1,834			1,619			1,828
Customer Deposits		1,326			1,223			1,170
Taxes Accrued		2,484			4,113			2,987
Deferred Taxes		245
Interest Accrued		1,039			1,027			900
Regulatory Liabilities		7,296			6,812			5,980
Other		1,229			1,097			1,149
Total Current Liabilities		41,782			30,980			32,288
Other Liabilities
Accrued Postretirement Benefit Cost					843
Deferred Income Taxes		26,716			22,540			25,235
Deferred Investment Tax Credits		206			226			216
Regulatory Liabilities		9,732			12,932			9,496
Asset Retirement Obligation		5,923						5,818
Other		1,477			1,260			1,382
Total Other Liabilities		44,054			37,801			42,147
		85,836			68,781			74,435
Capitalization
Stockholders’ Equity
Common Stock, $.01 Par Value
(Authorized 20,000,000 Shares; Outstanding
March 2007 - 7,975,000;
March 2006 - 7,920,000;
September 2006 - 7,947,000 Shares)		80			79			79
Capital in Excess of Par Value		30,199			28,194			29,092
Retained Earnings		89,700			82,764			81,919
Grantor Trust, at cost		(1,371	)		(1,656	)		(1,733	)
Deferred Compensation Liability		1,371			1,656			1,733
Total Stockholders’ Equity		119,979			111,037			111,090
Minority Interest		6,304			5,175			5,794
Long-Term Debt		69,492			75,838			71,361
Total Capitalization		195,775			192,050			188,245
Total	$	281,611		$	260,831		$	262,680

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

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UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF INCOME

	Three Months						Six Months
ENERGYSOUTH, INC.	Ended March 31,						Ended March 31,
In Thousands, Except Per Share Data	2007			2006			2007			2006
Operating Revenues
Gas Revenues	$	45,591		$	45,063		$	83,250		$	88,274
Merchandise Sales		772			761			1,731			2,053
Other		299			267			610			576
Total Operating Revenues		46,662			46,091			85,591			90,903
Operating Expenses
Cost of Gas		19,869			20,988			36,301			44,047
Cost of Merchandise		633			625			1,382			1,583
Operations and Maintenance		7,980			6,442			15,335			12,741
Depreciation		2,751			2,651			5,513			5,293
Taxes, Other Than Income Taxes		2,940			2,968			5,573			5,842
Total Operating Expenses		34,173			33,674			64,104			69,506
Operating Income		12,489			12,417			21,487			21,397
Other Income and (Expense)
Interest Expense		(1,671	)		(1,717	)		(3,350	)		(3,453	)
Interest Capitalized		466			246			824			421
Interest Income		5			41			23			118
Minority Interest		(300	)		(285	)		(574	)		(523	)
Total Other Income (Expense)		(1,500	)		(1,715	)		(3,077	)		(3,437	)
Income Before Income Taxes		10,989			10,702			18,410			17,960
Income Taxes		4,158			4,041			6,965			6,815
Net Income	$	6,831		$	6,661		$	11,445		$	11,145
Earnings Per Share
Basic	$	0.86		$	0.84		$	1.44		$	1.41
Diluted	$	0.85		$	0.84		$	1.42		$	1.40
Average Common Shares Outstanding
Basic		7,970			7,915			7,962			7,910
Diluted		8,049			7,969			8,040			7,961

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

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UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Six Months
EnergySouth, Inc.	Ended March 31,
In Thousands	2007			2006
Cash Flows from Operating Activities
Net Income	$	11,445		$	11,145
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
Depreciation and Amortization		5,685			5,474
Provision for Losses on Receivables and Inventory		978			675
Provision for Deferred Income Taxes		2,152			1,351
Minority Interest		574			523
Stock-Based Employee Compensation Expense		276			188
Changes in Operating Assets and Liabilities:
Receivables		(9,311	)		(5,932	)
Inventory		2,389			504
Payables		8,051			3,485
Taxes		1,608			(1,925	)
Deferred Purchased Gas Adjustment		(2,575	)		(3,588	)
Other		780			(91	)
Net Cash Provided by Operating Activities		22,052			11,809
Cash Flows from Investing Activites
Capital Expenditures		(19,058	)		(11,741	)
Changes in Restricted Cash		(9	)		(9	)
Net Cash Used in Investing Activities		(19,067	)		(11,750	)
Cash Flows from Financing Activites
Repayment of Long-Term Debt		(1,741	)		(2,078	)
Changes in Short-Term Borrowings		675
Payment of Dividends		(3,664	)		(3,332	)
Dividend Reinvestment		174			181
Exercise of Stock Options		417			219
Excess Tax Benefits from Share Based Payments		122			32
Partnership Distributions to Minority Interest Holders		(64	)		(556	)
Net Cash Used by Financing Activities		(4,081	)		(5,534	)
Net Decrease in Cash and Cash Equivalents		(1,096	)		(5,475	)
Cash and Cash Equivalents at Beginning of Period		1,272			8,052
Cash and Cash Equivalents at End of Period	$	176		$	2,577
Noncash Transactions from Investing Activities:
Accruals for Capital Expenditures	$	997		$	773

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Principles of Consolidation

The consolidated financial statements of EnergySouth, Inc. (EnergySouth) and its subsidiaries (collectively, the Company) include the accounts of Mobile Gas Service Corporation (Mobile Gas); EnergySouth Services, Inc. (Services); EnergySouth Storage Services, Inc. (Storage); a 90.9% owned limited partnership, Bay Gas Storage Company, Ltd. (Bay Gas); and a 51% owned partnership, Southern Gas Transmission Company (SGT). Minority interest represents the respective other owners’ proportionate shares of the income and equity of Bay Gas and SGT. All significant intercompany balances and transactions have been eliminated.

Note 2. Basis of Presentation

The accompanying unaudited consolidated condensed financial statements have been prepared in accordance with the instructions to Form 10-Q and do not include all of the information and disclosures required by accounting principles generally accepted in the United States of America for complete financial statements. All adjustments, consisting of normal and recurring accruals, which are, in the opinion of management, necessary to present fairly the results for the interim periods have been made. The statements should be read in conjunction with the summary of accounting policies and notes to financial statements included in the Annual Report on Form 10-K of the Company for the fiscal year ended September 30, 2006. Certain amounts in the prior-year financial statements have been reclassified to conform to the current year financial statement presentation.

Due to the high percentage of customers using natural gas for heating, the Company’s operations are seasonal in nature. Therefore, the results of operations for the three- and six-month periods ended March 31, 2007 and 2006 are not indicative of the results to be expected for the full year.

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The table below summarizes operating results for the twelve months ended March 31, 2007 and 2006:

	Twelve Months
EnergySouth, Inc.	Ended March 31,
In Thousands, Except Per Share Data	2007			2006
Operating Revenues	$	130,556		$	135,043
Cost of Gas		49,506			57,887
Cost of Merchandise		2,948			2,780
Operations and Maintenance Expense		28,626			24,859
Depreciation Expense		10,823			10,320
Taxes, Other Than Income Taxes		9,079			9,159
Operating Income		29,574			30,038
Interest Expense		(6,709	)		(7,022	)
Allowance for Borrowed Funds Used
During Construction		1,414			617
Interest Income		73			303
Less: Minority Interest		(1,164	)		(1,015	)
Income Before Income Taxes	$	23,188		$	22,921
Income Taxes		8,853			9,045
Net Income	$	14,335		$	13,876
Earnings Per Share
Basic	$	1.80		$	1.76
Diluted	$	1.79		$	1.75
Average Common Shares Outstanding
Basic		7,950			7,889
Diluted		8,014			7,941

Note 3. Stock-Based Compensation

The Stock Option Plan of EnergySouth, Inc. (Plan), as approved by the shareholders, provides for the granting of incentive stock options and non-qualified stock options to key employees. Under the Plan, an aggregate of 525,000 shares of the Company’s authorized but unissued Common Stock have been reserved for issuance. Options are granted at an option price which represents the market price on the date the grant is approved by the Board of Directors in accordance with the terms of the Plan. Stock options become 25% exercisable on the first anniversary of the grant date and an additional 25% become exercisable each succeeding year. No option may be exercised after the expiration of ten years from the grant date.

Effective October 1, 2005, the Company adopted SFAS 123R on a modified prospective basis. Under this method, the Company records compensation cost, on a prospective basis, for the portion of outstanding awards for which the requisite service has not yet been rendered as of October 1, 2005 based upon the grant-date fair value of those awards. Total stock-based compensation expense for stock option grants recognized during the six months

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ended March 31, 2007 and 2006 was $276,000 and $187,000, respectively. The income tax benefit recognized in the income statement for these stock options during the six months ended March 31, 2007 and 2006 was approximately $103,000 and $70,000, respectively. The impact of stock option expense was to reduce net income by $173,000 and $117,000, respectively, which represents a decrease in basic and diluted earnings per share of approximately $0.02 and $0.01 per diluted share for the six months ended March 31, 2007 and 2006, respectively.

The Company granted stock options during the six months ended March 31, 2007. In calculating the impact for options granted, the fair market value of the options at the date of grant was estimated using a Black-Scholes option pricing model. Assumptions utilized in the model are evaluated and revised, as necessary, to reflect market conditions and experience. Expected volatility has been calculated based on the historical volatility of the Company’s stock prior to the grant date. The expected term represents the period of time that options granted are expected to be outstanding and is estimated based on historical option exercise experience. The risk-free interest rate is equivalent to the U.S. Treasury yield in effect at the time of grant for the estimated life of the option grant.

A summary of option activity under the Plan as of March 31, 2007 and changes during the six months then ended is presented below:

				Weighted		Weighted	Aggregate
				Average		Average	Intrinsic
				Exercise		Remaining	Value
	Shares			Price		Life	(in thousands)
Outstanding at September 30, 2006*		332,337		$	23.148	6.82 years	$	3,523
Granted		78,600			37.675
Exercised		(20,050	)		20.800
Forfeited		(7,350	)		27.095
Outstanding at March 31, 2007*		383,537		$	26.173	6.96 years	$	6,044
Exercisable at March 31, 2007		190,113		$	20.677	6.04 years	$	4,040
Remaining reserved for grant at March 31, 2007		176,550

* Includes 81,059 shares outstanding under the 1992 Amended and Restated Stock Option Plan.

The total intrinsic value of options exercised during the six months ended March 31, 2007 and 2006 was approximately $371,000 and $89,000, respectively. The fair value of options that vested during the six months ended March 31, 2007 and 2006 was approximately $317,000 and $249,000, respectively.

At March 31, 2007, there was approximately $923,000 of compensation cost that has not yet been recognized related to non-vested stock-based awards. That cost is expected to be recognized over a weighted-average period of 2.97 years.

During the six months ended March 31, 2007 and 2006, cash received from options exercised was $417,000 and $219,000, respectively, and the actual tax benefit realized for the related tax deduction totaled $122,000 and $32,000, respectively.

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Note 4. Retirement Plans and Other Benefits

The Company has a noncontributory, defined benefit plan covering substantially all of its employees. Benefits are based on years of service and compensation during the term of employment, or if greater for persons employed before December 1, 1999, years of service and average compensation during the last five years of employment. The Company annually contributes to the plan the amount deductible for federal income tax purposes.

The Company also provides certain health insurance benefits for retired employees. Substantially all employees are eligible for such benefits if they retire under the provisions of the Company’s retirement plan. The Company accrues the cost of such benefits over the expected service period of the employees.

The “projected unit credit” actuarial method was used to determine service cost and actuarial liability. Net periodic benefit cost for the periods indicated included the following components:

	Pension						Postretirement
	Benefits						Benefits
For the three months ended March 31, (in thousands)	2007			2006			2007			2006
Service cost	$	199		$	198		$	40		$	23
Interest cost		478			455			49			67
Amortization of prior service cost					24			(19	)		(27	)
Amortization of unrecognized gain		23						7			15
Expected return on plan assets		(702	)		(672	)		(73	)		(70	)
Net periodic benefit cost (credit)	$	(2	)	$	5		$	4		$	8

	Pension						Postretirement
	Benefits						Benefits
For the six months ended March 31, (in thousands)	2007			2006			2007			2006
Service cost	$	419		$	438		$	79		$	78
Interest cost		957			919			97			150
Amortization of prior service cost					47			(38	)		(38	)
Amortization of unrecognized gain/(loss)		47						13			33
Expected return on plan assets		(1,405	)		(1,344	)		(145	)		(141	)
Net periodic benefit cost (credit)	$	17		$	60		$	6		$	82

For fiscal year 2007, the Company does not anticipate making any contributions to its pension plan due to the fact that the plan is currently fully funded and any contributions to the Company’s postretirement benefit plan are expected to be immaterial.

Effective December 31, 2005, there was a change in the provider of the Company’s health insurance coverage. As a result of this change, certain disabled employees were no longer eligible for coverage under the Company’s health insurance benefits. In accordance with Statement of Financial Accounting Standards No. 112, the Company had previously recorded a liability which represented the present value of the Company’s portion of future health insurance benefits for these employees. At December 31, 2005, the liability was reduced and expenses were credited for approximately $397,000.

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Note 5. Rates and Regulatory Matters

Mobile Gas has utilized a Rate Stabilization and Equalization (RSE) rate setting process since October 1, 2002. On June 14, 2005, the Alabama Public Service Commission (APSC) issued an order to extend RSE on substantially the same basis from October 1, 2005 through September 30, 2009. In addition, absent an APSC order after that date modifying the RSE rate tariff, RSE shall continue in effect beyond September 30, 2009.

RSE is a ratemaking methodology also used by the APSC to regulate other public Alabama energy utilities. A rate adjustment designed to increase Mobile Gas’ annual gas revenues by approximately $4.2 million was implemented December 1, 2006. Previous rate adjustments were implemented under the RSE tariff which were designed to decrease annual gas revenues by approximately $303,000 effective December 1, 2005 and to increase annual gas revenues by approximately $1.7 million effective December 1, 2004. The December 1, 2005 rate decrease was due primarily to the return of approximately $1,350,000 of the regulatory liability for gross receipts tax collections to ratepayers during fiscal 2006. Mobile Gas’ rates, as established under RSE, allow a return on average equity within a range of 13.35% to 13.85% for the period. Mobile Gas is allowed to earn a return on all of its assets with no exclusions. Increases are allowed only once each fiscal year, effective December 1, and cannot exceed four percent of prior-year revenues. Under RSE, the APSC conducts reviews using fiscal year-to-date performance through January, April, and July plus Mobile Gas’ budget projections to determine whether Mobile Gas’ return on equity is expected to be within the allowed range at the end of the fiscal year.

On December 7, 2005, Mobile Gas consented to a request by the APSC that Mobile Gas maintain its rates through March 31, 2006 at levels no higher than those implemented with the December 1, 2005 rate adjustment. The rate freeze had no impact on Mobile Gas’ margins, defined as revenues less cost of gas and related taxes, due to the components of Mobile Gas’ rate tariffs. Increases or decreases in the cost of gas and certain other costs are passed through to customers in accordance with provisions in the Company’s rate tariffs. Any over-or-under recoveries of these costs are charged or credited to cost of gas and included in the Deferred Purchased Gas Adjustment which is classified as part of Regulatory Assets or Regulatory Liabilities, as the case may be, on the Company’s Balance Sheet. See the table of regulatory assets and liabilities below.

RSE limits the amount of Mobile Gas’ equity upon which a return is permitted to 60 percent of its total capitalization and provides for certain cost control measures designed to monitor Mobile Gas’ operations and maintenance (O&M) expense. Under the inflation-based cost control measurement established by the APSC, if a change in Mobile Gas’ O&M expense per customer falls within 1.5 percentage points above or below the change in the Consumer Price Index for All Urban Customers (index range), no adjustment is required. If the change in O&M expense per customer exceeds the index range, three-quarters of the difference is returned to customers through future rate adjustments. To the extent the change is less than the index range, Mobile Gas benefits by one-half of the difference through future rate adjustments.

In conjunction with the approval of RSE, the APSC approved an Enhanced Stability Reserve (ESR), beginning October 1, 2002, to which Mobile Gas may charge the full amount of: 1) extraordinary O&M expenses resulting fromforce majeureevents such as storms, severe

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weather, and outages, when one such event results in more than $100,000 of additional O&M expense or a combination of two or more such events results in more than $150,000 of additional O&M expense during a fiscal year; or 2) losses of revenue from any individual industrial or commercial customer in excess of $100,000 during the fiscal year, if such losses cause Mobile Gas’ return on equity to fall below 13.35%. An initial ESR balance of $1.0 million was recorded October 1, 2002 and is being recovered from customers through rates. Subject to APSC approval, additional funding, up to a maximum reserve balance of $1.5 million, may be provided from any future non-recurring revenue should such revenue cause Mobile Gas’ return on equity for the fiscal year to exceed 13.85%. Following a year in which a charge against the ESR is made, the APSC allows for accruals to the ESR of no more than $15,000 monthly until the maximum funding level is achieved. The ESR balance of $1,000,000 at December 31, 2006 is included in the balance sheet of the Unaudited Condensed Consolidated Financial Statements as part of Regulatory Liabilities.

In October 2000, the Corus Group plc (Corus, formerly known as British Steel) ceased operations of its Mobile facility and continued to pay Mobile Gas a minimum annual payment as required under the terms of its contract. On July 28, 2005, Corus elected to end the contract and make a termination payment as required by the terms of the contract. Under a Termination Agreement (Termination Agreement) between Mobile Gas and Corus, Corus agreed to pay Mobile Gas $6,100,000. Of the $4,750,000 which was paid in fiscal 2006, $3,500,000 was received during the six months ended March 31, 2006. The final payment of $1,350,000 was paid on October 2, 2006. The APSC approved Mobile Gas’ request to recognize the termination payments as a regulatory liability and amortize the balance into income over the remaining seven years of the original contract term.

Mobile Gas’ rates contain a temperature adjustment rider which is designed to offset the impact of unusually cold or warm weather on the Company’s operating margins. The temperature adjustment rider applies to substantially all residential and small commercial customers. The adjustment is calculated monthly for the months of November through April and prior to November 1, 2006 was applied to customers’ bills in the same billing cycle in which the weather variation occurred. Effective November 1, 2006, Mobile Gas accumulates an adjustment for the margin impact due to variances in the weather. The accumulated adjustment from one heating season (November through April) will be billed or credited to customers in subsequent periods. This mechanism reduces the variability of both customers’ bills and Mobile Gas’ earnings due to weather fluctuations.

Through Storage and Bay Gas, the Company provides underground storage of natural gas and transportation services. The APSC regulates intrastate storage operations through a contract approval process. Interstate gas storage contracts do not require APSC approval since the Federal Energy Regulatory Commission (FERC), which has jurisdiction over such contracts, allows them to have market-based rates. The FERC has granted authority to Bay Gas to provide transportation-only services to interstate shippers and approved rates for such services.

Mobile Gas and certain cost-based operations of Bay Gas meet the criteria for application of the provisions of FASB Statement No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71). Regulatory assets represent probable future revenues associated with certain costs that are expected to be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are expected to be credited to customers through the ratemaking process.

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The following table presents the significant regulatory assets and liabilities as of the stated dates (in thousands):

	March 31,				March 31,				September 30,
	2007				2006				2006
	Current		Noncurrent		Current		Noncurrent		Current		Noncurrent
Assets
Deferred Purchase Gas Adjustment	$	4,491			$	2,208			$	1,916
Weather Normalization Adjustment		451
ESR Fund		167	$	83		167	$	250		167	$	167
Asset Retirement Cost				26								26
Other						76
Regulatory Assets	$	5,109	$	109	$	2,451	$	250	$	2,083	$	193
Liabilities
ESR Fund	$	1,000			$	1,000			$	1,000
Contract Buyout		2,702			$	1,229				1,866
Deferred Investment Tax Credit		15	$	98		15	$	113		15	$	106
RSE Adjustment				��		118
Gross Receipt Tax Collections		3,254				4,295				2,903
Accrued Dismantling Costs				9,634				12,819				9,390
Other		325				155				196
Regulatory Liabilities	$	7,296	$	9,732	$	6,812	$	12,932	$	5,980	$	9,496

In the event that a portion of the Company’s operations should no longer be subject to the provisions of SFAS No. 71, the Company would be required to write off related regulatory assets and liabilities that are not specifically addressed through regulated rates. In addition, the Company would be required to determine if any impairment to other assets exists, including plant, and write down the assets, if impaired, to their fair market value.

The excess of total acquisition costs over book value of net assets of acquired municipal gas plant distribution systems is included in utility plant and is being amortized through Mobile Gas’ rate-setting mechanism on a straight-line basis over approximately 26 years. At March 31, 2007 and 2006, the net acquisition adjustments were $5,239,000 and $5,595,000, respectively, and the balance at September 30, 2006 was $5,415,000.

Note 6. Earnings Per Share

Basic earnings per share and diluted earnings per share are calculated by dividing net income by the weighted average common shares outstanding during the period and the weighted average common shares outstanding during the period plus potential dilutive common shares. Dilutive potential common shares are calculated in accordance with the treasury stock method, which assumes that proceeds from the exercise of all options are used to repurchase common stock at market value. The amount of shares remaining after the proceeds are exhausted represents the potentially dilutive effect of the securities.

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A reconciliation of the weighted average common shares and the diluted average common shares is provided below:

	Three Months				Six Months
EnergySouth, Inc.	Ended March 31,				Ended March 31,
In Thousands	2007		2006		2007		2006
Weighted Average Common Shares		7,970		7,915		7,962		7,910
Effect of Dilutive Securities:
Options to Purchase Common Stock		79		54		78		51
Diluted Average Common Shares		8,049		7,969		8,040		7,961

Stock options to purchase approximately 79,000 and 143,000 shares as of March 31, 2007 and 2006, respectively, were not included in the computation of diluted earnings per share because inclusion of these shares would have been antidulitive.

Note 7. Segment Information

The Company is principally engaged in two reportable business segments: Natural Gas Distribution and Natural Gas Storage. The Natural Gas Distribution segment is actively engaged in the distribution and transportation of natural gas to residential, commercial and industrial customers through Mobile Gas and SGT. The Natural Gas Storage segment provides for the underground storage of natural gas and transportation services through the operations of Bay Gas and Storage. Through Mobile Gas and Services, the Company also provides merchandising and other energy-related services which are aggregated with EnergySouth, the holding company, and included in the Other segment.

Segment earnings information presented in the table below includes intersegment revenues which are eliminated in consolidation. Such intersegment revenues are primarily amounts paid by the Natural Gas Distribution segment to the Natural Gas Storage segment.

For the three months ended	Natural Gas			Natural Gas
March 31, 2007 (in thousands):	Distribution			Storage			Other			Eliminations			Consolidated
Operating Revenues	$	41,433		$	5,234		$	1,071		$	(1,076	)	$	46,662
Cost of Gas		20,945									(1,076	)		19,869
Cost of Merchandise								633						633
Operations and Maintenance Expense		6,441			1,086			453						7,980
Depreciation Expense		2,120			631									2,751
Taxes, Other Than Income Taxes		2,689			235			16						2,940
Operating Income		9,238			3,282			(31	)					12,489
Interest Income		1			24			298			(318	)		5
Interest Expense		(878	)		(983	)		(128	)		318			(1,671	)
Interest Capitalized		6			460									466
Less: Minority Interest		(42	)		(258	)								(300	)
Income Before Income Taxes	$	8,325		$	2,525		$	139					$	10,989

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For the three months ended	Natural Gas			Natural Gas
March 31, 2006 (in thousands):	Distribution			Storage			Other			Eliminations			Consolidated
Operating Revenues	$	41,122		$	5,000		$	1,028		$	(1,059	)	$	46,091
Cost of Gas		22,047									(1,059	)		20,988
Cost of Merchandise								625						625
Operations and Maintenance Expense		5,510			556			376						6,442
Depreciation Expense		1,995			656									2,651
Taxes, Other Than Income Taxes		2,727			216			25						2,968
Operating Income		8,843			3,572			2						12,417
Interest Income		1			42			174			(176	)		41
Interest Expense		(777	)		(1,021	)		(95	)		176			(1,717	)
Interest Capitalized		18			228									246
Less: Minority Interest		(26	)		(259	)								(285	)
Income Before Income Taxes	$	8,059		$	2,562		$	81					$	10,702

For the six months ended	Natural Gas			Natural Gas
March 31, 2007 (in thousands):	Distribution			Storage			Other			Eliminations			Consolidated
Operating Revenues	$	74,767		$	10,622		$	2,341		$	(2,139	)	$	85,591
Cost of Gas		38,440									(2,139	)		36,301
Cost of Merchandise								1,382						1,382
Operations and Maintenance Expense		12,186			2,226			923						15,335
Depreciation Expense		4,240			1,273									5,513
Taxes, Other Than Income Taxes		5,065			472			36						5,573
Operating Income		14,836			6,651			—						21,487
Interest Income		1			55			589			(622	)		23
Interest Expense		(1,687	)		(1,959	)		(326	)		622			(3,350	)
Interest Capitalized		19			805									824
Less: Minority Interest		(65	)		(509	)								(574	)
Income Before Income Taxes	$	13,104		$	5,043		$	263					$	18,410

For the six months ended	Natural Gas			Natural Gas
March 31, 2006 (in thousands):	Distribution			Storage			Other			Eliminations			Consolidated
Operating Revenues	$	80,697		$	9,694		$	2,629		$	(2,117	)		$	90,903
Cost of Gas		46,164									(2,117	)			44,047
Cost of Merchandise								1,583							1,583
Operations and Maintenance Expense		10,694			1,276			771							12,741
Depreciation Expense		3,990			1,303										5,293
Taxes, Other Than Income Taxes		5,365			430			47							5,842
Operating Income		14,484			6,685			228							21,397
Interest Income		15			104			288			(289	)			118
Interest Expense		(1,524	)		(2,070	)		(148	)		289				(3,453	)
Interest Capitalized		39			382										421
Less: Minority Interest		(56	)		(467	)									(523	)
Income Before Income Taxes	$	12,958		$	4,634		$	368						$	17,960

Note 8. Commitments and Contingencies

The Company has third-party contracts, which expire at various dates through the year 2011, for the purchase, storage and delivery of gas supplies. Mobile Gas is exposed to market risks associated with commodity prices of natural gas. Mobile Gas mitigates the price risk associated with purchases of natural gas by using a combination of natural gas storage services, fixed price contracts and spot market purchases. As part of Mobile Gas’ gas supply

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strategy, it has adopted a policy under which management is authorized to commit to future gas purchases at fixed prices up to a specified percentage of the normalized degree-day usage for any corresponding month as outlined within the policy. All commitments for future gas purchases at fixed prices meet the requirements of paragraph 10.b,Normal Purchases and Normal Sales,of Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended by SFAS No. 149. Thus, the commitments for future purchases of natural gas at fixed prices are deemed to be purchases in the normal course of business and are not subject to derivative accounting treatment.

At March 31, 2007, Mobile Gas had not entered into derivative instruments for the purpose of hedging the price of natural gas. If Mobile Gas had entered into such derivative instruments, any cost incurred or benefit received from the derivative or other hedging arrangements would be recoverable or refunded through the purchased gas adjustment mechanism under Mobile Gas’ rate tariffs. As discussed in “Results of Operations” under “Natural Gas Distribution” within Item 2 below, the APSC currently allows for full recovery of all costs associated with natural gas purchases; therefore, costs associated with the forward purchases of natural gas will be passed through to customers when realized and will not affect future earnings.

A portion of firm supply requirements is expected to be met through the withdrawal of gas from the storage facility owned by Bay Gas. Mobile Gas has entered into a Gas Storage Agreement under which Bay Gas is to provide storage services for an initial period of 20 years which began in September 1994 with the commencement of commercial operations of the storage facility.

Bay Gas has contracted for rights to develop caverns for the storage of natural gas on property owned by Olin Corporation. With respect to the first and second caverns, the terms of the agreement state that Bay Gas shall pay to Olin twenty consecutive annual cash payments to begin upon completion of each storage cavern. At the end of the initial 50 year land and subsurface lease term, Bay Gas has the right to renew the lease term for an additional 20 year period and would be required to remit annual payments based on the initial minimum service fees. Payments relating to the third cavern will extend over the life of the initial lease term or for as long as the cavern is in service. Payments are adjusted for annual Consumer Price Index (CPI) changes. Minimum commitments shown below reflect the CPI at the commitment date for each cavern. As of March 31, 2007, Bay Gas had entered into contracts for compressors and other services to be performed in the development of the third storage cavern.

As part of a project to identify, evaluate and select new Customer Information System (CIS) software, on June 30, 2006 Mobile Gas entered into contracts with SAP America, Inc. for the purchase of CIS software and with Axon Solutions, Inc. for related implementation and consulting services.

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Total future minimum payments for these commitments as discussed above are listed, in thousands, in the table below.

	Mobile Gas				Bay Gas
	Gas				Minimum
Fiscal	Supply		Implemention of		Payments for		Construction		Total
Year	Contracts		CIS Software		Service Fees		Contracts		Commitments
Remaining 2007	$	5,052	$	1,950	$	181	$	17,092	$	24,275
2008		1,807		1,238		363				3,408
2009		1,141				363				1,504
2010		1,141				363				1,504
2011		815				363				1,178
2012 - and thereafter						18,541				18,541
Total	$	9,956	$	3,188	$	20,174	$	17,092	$	50,410

Like many gas distribution companies, prior to the widespread availability of natural gas, the Company manufactured gas for sale to its customers. In contrast to some other companies which operated multiple manufactured gas plants, the Company and its predecessor operated only one such plant, which discontinued operations in 1933. The process for manufacturing gas produced by-products and residuals, such as coal tar, and certain remnants of these residuals are sometimes found at former gas manufacturing sites.

Based on plans for the site, the Alabama Department of Environmental Management (“ADEM”) has conducted a “Brownfield” evaluation of the property. On January 5, 2005, ADEM released a “CERCLA Targeted Brownfield Site Inspection” report on the manufactured gas plant site. Prior to the ADEM “Brownfield” evaluation, the Company engaged environmental consultants to evaluate the site in connection with the plans for the site. Based on their review, the Company recorded its best estimate of $200,000 as an expense and a remediation liability in fiscal 2004. The Company intends that, should further investigation or changes in environmental laws or regulations require material expenditures for evaluation or remediation with regard to the site, it would apply to the APSC for appropriate rate recovery of such costs. However, there can be no assurances that the APSC would approve the recovery of such costs or the amount and timing of any such recovery.

The Company is involved in litigation arising in the normal course of business. Management believes that the ultimate resolution of such litigation will not have a material adverse effect on the consolidated financial statements of the Company.

Note 9. New Accounting Pronouncements

In June 2006, the FASB issued Financial Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes”, to clarify the accounting for uncertain tax positions in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” FIN 48 defines a minimum recognition threshold that a tax position must meet to be recognized in an enterprise’s financial statements. Additionally, FIN 48 provides guidance on derecognition, measurement, classification, interim period accounting, disclosure and transition requirements in accounting for uncertain tax positions. FIN 48 will be effective for the

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Company beginning October 1, 2007. The Company is currently evaluating the impact of FIN 48 on its financial statements, however, it is expected that the adoption of FIN 48 will not have a material impact on the Company’s financial position, results of operations or cash flows.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS 157) which defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS 157 does not require any new fair value measurements, however, it eliminates inconsistencies in the guidance provided in previous accounting pronouncements. SFAS 157 will be effective for the Company beginning October 1, 2008 and is not expected to have a material impact on the Company’s financial statements.

In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R)” (SFAS 158) which requires the employer to recognize the overfunded or underfunded status of a defined benefit pension plan and other postretirement plans as an asset or liability in its statement of financial position. Additionally, SFAS 158 requires that the measurement date must correspond to the fiscal year end balance sheet date. SFAS 158 does not change how net periodic pension and postretirement cost or the projected benefit obligation is determined. Based on a preliminary assessment of regulatory treatment granted by the APSC to other public Alabama energy companies, management believes that regulatory asset or liability treatment will be afforded to any amounts that would otherwise be recorded in accumulated Other Comprehensive Income resulting from the implementation of SFAS 158. The Company is currently evaluating the impact on its financial statements of SFAS 158, which will be effective as of September 30, 2007.

In February 2007, the FASB issue SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159) which provides companies with an option to report selected financial assets and liabilities at fair value. Its objective is to reduce the complexity in accounting for financial instruments and to mitigate the volatility in earnings caused by measuring related assets and liabilities differently. Although SFAS 159 does not eliminate disclosure requirements included in other accounting standards, it does establish additional presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS is effective for the Company beginning October 1, 2008 and is not expected to have a material impact on the Company’s financial statements.

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Item 2

Management’s Discussion and Analysis

of Financial Condition and Results of Operations

The Company

EnergySouth, Inc. is the holding company for a family of energy businesses. Mobile Gas purchases, sells, and transports natural gas to residential, commercial, and industrial customers in Mobile, Alabama and surrounding areas. The Company also provides merchandise sales, service, and financing. EnergySouth Storage Services is the general partner of Bay Gas Storage Company, a limited partnership that provides underground storage and delivery of natural gas. EnergySouth Services is the general partner of Southern Gas Transmission Company, which is engaged in the intrastate transportation of natural gas.

Results Of Operations

Consolidated Earnings

All earnings per share amounts referred to herein are computed on a diluted basis. Earnings per share for the three and six months ended March 31, 2007 increased $0.01 and $0.02 per diluted share, respectively, as compared to the same prior-year periods. The increase in earnings for the three-month period ended March 31, 2007 was due to increased earnings from Mobile Gas’ distribution business. The increase in earnings for the six-month period ended March 31, 2007 was due primarily to increased earnings from Bay Gas’ natural gas storage business during the first fiscal quarter. Financial information by business segment is shown in Note 7 to the Unaudited Condensed Consolidated Financial Statements above.

Earnings from the Company’s natural gas distribution business increased $0.01 per diluted share for the three-month period ended March 31, 2007 and decreased $0.01 per diluted share for the six months ended March 31, 2007 as compared to the same prior-year periods. Although net income for the first six months of fiscal 2007 approximated the same prior year period, the $0.01 decrease in earnings per share resulted from an increase in the average number of common shares outstanding as compared to the same prior year period.

Earnings from the Company’s natural gas storage business, operated by Bay Gas, remained relatively unchanged for the three months ended March 31, 2007 compared to the prior-year period, but Bay Gas contributed increased earnings of $0.03 per diluted share for the six-month period ended March 31, 2007 as compared to the same prior-year period. Increased earnings from storage revenues associated with short-term storage agreements and an increase in the amount of interest capitalized during the construction and development of the third underground natural gas storage cavern were partially offset by an increase in operating expenses.

Earnings from other business operations were relatively flat for the three- and six-month periods ended March 31, 2007, as compared to the same prior-year periods.

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Natural Gas Distribution

The Natural Gas Distribution segment is actively engaged in the distribution and transportation of natural gas to residential, commercial and industrial customers in Southwest Alabama through Mobile Gas and SGT.

The Alabama Public Service Commission (APSC) regulates the Company’s gas distribution operations. Mobile Gas’ rate tariffs for gas distribution allow rate adjustments to ultimately pass through to customers the cost of gas and certain taxes. These costs, therefore, have little direct impact on the Company’s unit margins, which are defined as natural gas distribution revenues less the cost of gas and related taxes. Mobile Gas’ rate tariffs also allow a rate adjustment to pass through to customers the incremental depreciation expense and financing costs associated with the replacement of cast iron mains.

In fiscal year 2002, the APSC approved Mobile Gas’ request for a Rate Stabilization and Equalization (RSE) tariff, a ratemaking methodology also used by the APSC to regulate other public Alabama energy utilities. Increases are allowed only once each fiscal year, effective December 1, and cannot exceed four percent of prior-year revenues. See Note 5 to the Unaudited Condensed Consolidated Financial Statements above.

The Company’s distribution business is highly seasonal and temperature-sensitive since residential and commercial customers use more gas during colder weather for space heating. As a result, gas revenues, cost of gas and related taxes in any given period reflect, in addition to other factors, the impact of weather, through either increased or decreased sales volumes. The Company has utilized a temperature rate adjustment rider during the months of November through April to mitigate the impact that unusually cold or warm weather has on operating margins by reducing the base rate portion of customers’ bills in colder than normal weather and increasing the base rate portion of customers’ bills in warmer than normal weather. See Note 5 to the Unaudited Condensed Consolidated Financial Statements above. Normal weather for the Company’s service territory is defined as the 30-year average temperature as determined by the National Weather Service.

Natural gas distribution revenues increased $311,000 (1%) and decreased $5,930,000 (7 %), respectively, during the three- and six-month periods ended March 31, 2007 as compared to the same prior-year periods. The increase in revenues for the second fiscal quarter was due primarily to the RSE rate adjustment which went into effect on December 1, 2006. Rate adjustments which reflect a decrease in gas costs paid to suppliers partially offset the increased revenues during the three months ended March 31, 2007 and are the primary reason for the decline in revenues year to date. This decrease during the six months ended March 31, 2007 was partially offset by the RSE rate adjustment.

Revenues from the sale of natural gas to temperature-sensitive customers increased $1,137,000 (3%) and decreased $3,686,000 (5%), respectively, for the three- and six-month periods ended March 31, 2007 due to the rate adjustments noted above. Revenues were positively impacted by 16% and 6% increases in volumes delivered to customers during the three- and six-month periods ended March 31, 2007, respectively, due to temperatures that were 19% and 7% colder than the three- and six-month periods last year.

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Revenues from the sale of natural gas to large commercial and industrial customers decreased $649,000 (17%) and $1,941,000 (24%) for the three- and six-month periods ended March 31, 2007 due primarily to the rate adjustments noted above. Rate adjustments which reflected a decrease in gas costs more than offset increased revenues from the RSE rate adjustment. Also contributing to the decrease in revenues during the three- and six-month periods were declines of 5% and 10%, respectively, in volumes delivered to customers during the current year periods. Volumes were significantly higher in the prior year six-month period as a result of the unique operational needs of one industrial customer. The increased usage by this customer was an isolated event.

Revenues from the transportation of natural gas to large commercial and industrial customers decreased $194,000 (10%) and $327,000 (9%) during the three- and six-month periods ended March 31, 2007 due to a decline in volumes transported of 7% and 9%, respectively.

The cost of natural gas decreased $1,102,000 (5%) and $7,725,000 (17%) for the three-and six-month periods ended March 31, 2007 as compared to the same prior-year periods due primarily to lower natural gas commodity prices.

Natural gas distribution margins, defined as revenues less cost of gas and related taxes, increased approximately 8% and 7%, respectively, during the three- and six-month periods ended March 31, 2007 as compared to the same prior-year periods due primarily to the rate adjustment effective December 1, 2006. Additionally, consumption by residential temperature-sensitive customers, when adjusted for weather, increased approximately 3% and 4%, respectively, during the first three and six months of fiscal 2007 when compared to the same prior year periods. However, the additional margin realized from the increased consumption was partially offset by a slight decline in the number of temperature-sensitive customers served and volumes delivered to large industrial and commercial customers.

Operations and maintenance (O&M) expenses increased $931,000 (17%) and $1,492,000 (14%), respectively, for the three and six months ended March 31, 2007 as compared to the same prior-year periods due to increases in compensation and related benefit expenses, increases in training expenses due to the implementation of a new customer information system (CIS), and an increase in the bad debt provision due to an increase in customer receivables. Also contributing to the increase in O&M expenses for the six months ended March 31, 2007 were lower postemployment health insurance expenses in the prior-year period. Due to a change in the Company’s provider of health insurance which was effective December 31, 2005, certain disabled employees became ineligible for coverage under the Company’s health insurance benefits. Consequently, at the termination of the prior contract on December 31, 2005, the Company reduced the liability for future benefit payments for these employees by $346,000.

Depreciation expense increased $125,000 (6%) and $250,000 (6%), respectively, for the three- and six-month periods ended March 31, 2007 as compared to the same prior-year periods due to Mobile Gas’ increased investment in property, plant and equipment.

Other taxes primarily consist of property taxes and business license taxes that are based on gross revenues and fluctuate accordingly. Other taxes during the second quarter of fiscal 2007 were approximately the same as for the comparable prior-year period and decreased $300,000 (6%) for the six-month period ended March 31, 2007 due primarily to the decrease in revenues.

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Interest expense increased $101,000 (13%) and $164,000 (11%), respectively, for the three- and six-month periods ended March 31, 2007 as compared to the same prior-year periods due primarily to increased short-term borrowings.

Minority interest reflects the minority partner’s share of pre-tax earnings of the SGT partnership, of which EnergySouth’s subsidiary holds a controlling interest. Minority interest increased slightly during the three- and six-month periods ended March 31, 2007 due to an increase in pretax earnings of the partnership.

Natural Gas Storage

The natural gas storage segment provides for the underground storage of natural gas and transportation services through the operations of Bay Gas. The APSC certificated Bay Gas as an Alabama natural gas storage public utility in 1992. Through its first storage cavern with 2.3 Bcf of working gas capacity and connected pipeline, Bay Gas thereafter began providing for Mobile Gas and other customers substantial, long-term services that include storage and transportation of natural gas from interstate and intrastate sources. The APSC does not regulate rates for Bay Gas’ interstate gas storage and storage-related services. The Federal Energy Regulatory Commission (FERC), which has jurisdiction over interstate services, allows Bay Gas to charge market-based rates for such services. Market-based rates minimize regulatory involvement in the setting of rates for storage services and allow Bay Gas to respond to market conditions. Bay Gas also provides firm and interruptible interstate transportation-only services. The FERC last issued an order on April 14, 2006 approving rates for transportation-only services. In accordance with FERC filing requirements, on March 9, 2007 Bay Gas filed a petition with the FERC requesting approval of rates for transportation-only service.

The construction of natural gas-fired electric generation facilities in the Southeast has provided opportunities to provide gas storage and transportation services. Construction of Bay Gas’ second storage cavern was completed and the cavern was placed into service April 1, 2003. Currently, the second storage cavern has a working capacity of approximately 3.7 Bcf. Together, the two caverns at Bay Gas currently hold approximately 6.0 Bcf, with injection and withdrawal capacity of 200 MMcf and 610 MMcf per day, respectively.

Bay Gas is currently developing a third storage cavern and related facilities and has entered into multi-year contracts with customers for all of the cavern capacity. The new cavern is designed to add 5.0 Bcf of working gas capacity and is presently anticipated to be in service by the fall of 2007. The addition of the third cavern and additional capacity development of 1.0 Bcf is currently planned to ultimately increase the total working gas capacity of Bay Gas to 12.0 Bcf and injection and withdrawal capacities to 450 MMcf per day and 1.2 Bcf per day, respectively.

Having reached full subscription of the current working capacity of both existing caverns and the third cavern which is currently under development, Bay Gas held a non-binding “open season” in October 2006 to assess interest for up to 10.0 Bcf of additional working gas capacity. The planned development would include two new 5.0 Bcf high deliverability underground salt-dome caverns together with additional pipeline interconnects with Transco and SONAT. Bay Gas is currently communicating with respondents in an effort to secure agreements for firm storage services. Bay Gas plans to move forward with development of the fourth and fifth caverns and the pipeline interconnects subject to its ability to execute sufficient firm storage agreements with the interested parties.

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Bay Gas’ revenues increased $234,000 (5%) and $928,000 (10%), respectively, during the three- and six-month periods ended March 31, 2007 as compared to the same prior-year periods due primarily to increased revenues from short-term storage agreements. Under the short-term agreements, available storage capacity is leased to customers on an interruptible basis, thereby optimizing the use of cavern capacity.

Operations and maintenance (O&M) expenses increased $530,000 (95%) and $950,000 (74%), respectively, during the three- and six-month periods ended March 31, 2007 as compared to the same prior-year periods due to an increase in compensation expense and related benefits, increased expenses related to the cavern lease payments and general repairs and maintenance due to the growth of Bay Gas’ operations.

Other taxes consist primarily of property taxes and business license taxes that are based on gross revenues and fluctuate accordingly. Other taxes increased $19,000 (9%) and $42,000 (10%), respectively, during the three and six months ended March 31, 2007 as compared to the same prior-year periods.

Interest expense decreased $38,000 (4%) and $111,000 (5%), respectively, during the three and six months ended March 31, 2007 due primarily to principal payments which reduced long-term debt.

Capitalized interest costs increased $232,000 and $423,000 for the three- and six-month periods ended March 31, 2007 due to the ongoing construction of the third storage cavern.

Minority interest reflects the minority partner’s share of pre-tax earnings of the Bay Gas limited partnership, of which EnergySouth’s subsidiary holds a controlling interest. Minority interest during the three-month period ended March 31, 2007 approximated the amount in the comparable prior-year period and increased $42,000 (9%) for the six months ended March 31, 2007 due to increased pretax earnings of Bay Gas as discussed above.

Other

Through Mobile Gas and EnergySouth Services, Inc., the Company provides merchandising, financing, and other energy-related services, which are aggregated with EnergySouth, the holding company, to comprise the Other category. See Note 7 to the Unaudited Condensed Consolidated Financial Statements above for segment disclosure.

Income before income taxes from Other business activities increased $58,000 for the three-month period ended March 31, 2007 as compared to the same prior-year period due primarily to an increase in interest earned from temporary investments. Income before income taxes from Other business activities decreased $105,000 for the six months ended March 31, 2007 due primarily to a decrease in merchandise sales and related merchandising activities and an increase in interest expense. The decrease in earnings for the six-month period was partially offset by an increase in interest earned from temporary investments.

Income Taxes

Income taxes fluctuate with the change in income before income taxes. Income tax expense

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increased $117,000 (3%) and $150,000 (2%) for the three- and six month periods ended March 31, 2007 as compared to the same prior-year periods.

Liquidity and Capital Resources

The Company generally relies on cash generated from operations and, on a temporary basis, short-term borrowings, to meet working capital requirements and to finance normal capital expenditures. The Company issues debt and equity for longer term financing as needed. Impacts of operating, investing, and financing activities are shown on the Unaudited Condensed Consolidated Statements of Cash Flows. Cash provided by operating activities increased $10,243,000 during the six-month period ended March 31, 2007 as compared to the same period last fiscal year due to an increase in accounts payable and taxes payable, an increase in collections of gas costs from customers and a decrease in gas stored in inventory. Offsetting these positive impacts on cash flow from operating activities was an increase in accounts receivable.

Cash used in investing activities reflects the capital-intensive nature of the Company’s business. During the six months ended March 31, 2007 and 2006, the Company used cash of $19,067,000 and $11,750,000, respectively, for the construction of distribution and storage facilities, purchases of equipment and other general improvements. During the six- month periods ended March 31, 2007 and 2006, Bay Gas invested $13,155,000 and $6,177,000, respectively, in the ongoing development of a third salt-dome storage cavern.

Financing activities used cash of $4,081,000 during the six months ended March 31, 2007 due primarily to the payment of quarterly dividends, payments on long term debt, and partnership distributions. Partially offsetting these cash payments was an increase in short term borrowings and stock options exercised. Financing activities used cash of $5,534,000 during the six months ended March 31, 2006 due primarily to payments on long term debt, quarterly dividends, and partnership distributions. These payments were partially offset by stock options exercised and reinvested dividends.

Funds for the Company’s short-term cash needs are expected to come from cash provided by operations, the issuance of long term debt, and borrowings under the Company’s $25,000,000 revolving credit agreement which extends through February 28, 2008. At March 31, 2007, the Company had $19,025,000 available for borrowing on its revolving credit agreement. The Company pays a fee for its committed lines of credit rather than maintain compensating balances. The commitment fee is 0.125% of the average daily unborrowed amount during the annual period of calculation. The Company believes it has adequate financial flexibility to meet its expected cash needs in the foreseeable future.

Under its gas supply strategy, Mobile Gas enters into forward purchases of natural gas to lock in prices for a majority of its expected gas sales for the upcoming winter heating season. The commitments for future purchases of natural gas at fixed prices are deemed to be purchases in the normal course of business and are not subject to derivative accounting treatment. For further information, see “Gas Supply” under “Management’s Discussion and Analysis of Financial Condition and Results of Operation” included in the Annual Report on Form 10-K of the Company for the fiscal year ended September 30, 2006 and Item 3 below.

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The table below summarizes the Company’s contractual obligations and commercial commitments as of March 31, 2007:

	Remaining										Fiscal Years
Type of Contractual	Fiscal Year		Fiscal Year		Fiscal Year		Fiscal Year		Fiscal Year		2012 and
Obligations (in thousands):	2007		2008		2009		2010		2011		thereafter
Long-Term Debt	$	3,877	$	5,900	$	6,054	$	5,653	$	5,955	$	47,799
Interest Payments		3,164		5,732		5,247		4,750		4,279		15,247
Estimated Future Minimum Payments for Bay Gas Service Fees		181		363		363		363		363		18,541
Construction Contracts for Bay Gas’ 3rd Cavern Development		17,092
Implementation of CIS Software		1,950		1,238
Gas Supply Contracts		5,052		1,807		1,141		1,141		815
Total	$	31,316	$	15,040	$	12,805	$	11,907	$	11,412	$	81,587

Critical Accounting Policies

See “Critical Accounting Policies” under “Management’s Discussion and Analysis of Financial Condition and Results of Operation” included in the Annual Report on Form 10-K of the Company for the fiscal year ended September 30, 2006.

Forward-Looking Statements

Statements contained in this report, which are not historical in nature, are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements are made as of the date of this report and involve known and unknown risks, uncertainties and other important factors that could cause the actual results, performance or achievements of EnergySouth or its affiliates, or industry results, to differ materially from any future results, performance or achievement expressed or implied by such forward-looking statements. Such risks, uncertainties and other important factors include, among others, risks associated with fluctuations in natural gas prices, including changes in the historical seasonal variances in natural gas prices and changes in historical patterns of collections of accounts receivable; the prices of alternative fuels; the relative pricing of natural gas versus other energy sources; changes in historical patterns of consumption by temperature-sensitive customers; the availability of other natural gas storage capacity; failures or delays in completing planned Bay Gas cavern development; disruption or interruption of pipelines serving the Bay Gas storage facilities due to accidents or other events; risks generally associated with the transportation and storage of natural gas; the possibility that contracts with storage customers could be terminated under certain circumstances, or not renewed or extended upon expiration; the prices or terms of any extended or new contracts; possible loss or material change in the financial condition of one or more major customers; liability for remedial actions under environmental regulations; liability resulting from litigation; national and global economic and political conditions; and changes in tax and other laws applicable to the business. Additional factors that may impact forward-looking statements include, but are not limited to, the Company’s ability to

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successfully achieve internal performance goals, competition, the effects of state and federal regulation, including rate relief to recover increased capital and operating costs, allowed rates of return and purchased gas adjustment provisions; general economic conditions, specific conditions in the Company’s service area, and the Company’s dependence on external suppliers, contractors, partners, operators, service providers, and governmental agencies.

Item 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Mobile Gas is exposed to market risks associated with commodity prices of natural gas. Mobile Gas mitigates the price risk associated with purchases of natural gas by using a combination of natural gas storage services, fixed price contracts and spot market purchases. As part of Mobile Gas’ gas supply strategy, it has adopted a policy under which management is authorized to commit to future gas purchases at fixed prices up to a specified percentage of the normalized degree-day usage for any corresponding month as outlined within the policy. All commitments for future gas purchases at fixed prices meet the requirements of paragraph 10.b,Normal purchases and Normal sales,of Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended by SFAS No. 149. Thus, the commitments for future purchases of natural gas at fixed prices are deemed to be purchases in the normal course of business and are not subject to derivative accounting treatment.

At March 31, 2007, Mobile Gas had not entered into derivative instruments for the purpose of hedging the price of natural gas. If Mobile Gas had entered into such derivative instruments, any cost incurred or benefit received from the derivative or other hedging arrangements would be recoverable or refunded through the purchased gas adjustment mechanism. As discussed in “Results of Operations” under “Natural Gas Distribution” within Item 2 above, the APSC currently allows for full recovery of all costs associated with natural gas purchases; therefore, costs associated with the forward purchases of natural gas will be passed through to customers when realized and should not affect future earnings.

At March 31, 2007 the Company had approximately $75.2 million of long-term debt at fixed interest rates. Interest rates range from 6.9% to 9.0% and the maturity dates of such debt extend to 2023.

See also the information provided under the captions “The Company,” “Gas Supply,” and “Liquidity and Capital Resources” in the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2006 for a discussion of the Company’s risks related to regulation, weather, gas supply and prices, and the capital-intensive nature of the Company’s business.

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Item 4 CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

EnergySouth, Inc. carried out evaluations of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities and Exchange Act of 1934, as amended) as of the end of the fiscal quarter ended March 31, 2007. These evaluations were conducted under the supervision, and with the participation, of the Company’s management, including the Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) and the Company’s Disclosure Committee. Based upon these evaluations, the CEO and CFO of the Company have concluded as of the end of the period covered by this report that the disclosure controls and procedures of the Company are functioning effectively to provide reasonable assurance that: (i) the information required to be disclosed by the Company in the reports that it files or submits under the Securities and Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange’s rules and forms, and (ii) the information required to be disclosed by the Company in the reports that the Company files or submits under the Securities and Exchange Act of 1934, as amended, is accumulated and communicated to the Company’s management, including the principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control

There has been no change in the Company’s internal control over financial reporting that occurred during the quarter ended March 31, 2007, that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1A. Risk Factors

There have been no material changes to the risk factors previously disclosed in the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2006.

Item 5. Other Information

On April 27, 2007, EnergySouth, Inc. (the “Company”) issued a press release announcing earnings for the three and six months ended March 31, 2007 and the declaration of a dividend on outstanding Common Stock. The full text of the press release is set forth in Exhibit 99.1 hereto. The exhibit is furnished under this Item 5 in lieu of its being furnished under cover of and pursuant to the instructions for Form 8-K.

Item 6. Exhibits

Exhibit No.	Description
31.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 — Chief Executive Officer
31.2	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 — Chief Financial Officer
32.1	Certification Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - Chief Executive Officer
32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 — Chief Financial Officer
99.1	Press release dated April 27, 2007

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SIGNATURES

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.

	ENERGYSOUTH, INC. (Registrant)
Date: May 9, 2007	/s/ C.S. Liollio
	C. S. Liollio
	President and Chief Executive Officer
Date:May 9, 2007	/s/Charles P. Huffman
	Charles P. Huffman
	Senior Vice President and Chief Financial Officer

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