EnergySouth (ENSI) 10-Q 2006 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 Ended March 31, 2006

Commission File No. 0-29604

ENERGYSOUTH, INC.

(Exact name of registrant as specified in its charter)

Alabama	58-2358943
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer 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 April 30, 2006 – 7, 922,420 shares.

ENERGYSOUTH, INC.
FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2006

INDEX

	Page No.
PART I: FINANCIAL INFORMATION
Item 1 Financial Statements:
(a) Unaudited Condensed Consolidated Balance Sheets March 31, 2006 and 2005 and September 30, 2005		3 - 4
(b) Unaudited Condensed Consolidated Statements of Income Three and Six Months Ended March 31, 2006 and 2005		5
(c) Unaudited Condensed Consolidated Statements of Cash Flows Six Months Ended March 31, 2006 and 2005		6
(d) Notes to Unaudited Condensed Consolidated Financial Statements		7 - 19
Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations		20 - 27
Item 3 Quantitative and Qualitative Disclosures About Market Risk		28
Item 4 Controls and Procedures		28 - 29
PART II: OTHER INFORMATION
Item 5 Other Information		29
Item 6 Exhibits		30
Certification Pursuant to Section 302 - Chief Executive Officer
Certification Pursuant to Section 302 - Chief Financial Officer
Certification Pursuant to Section 906 - Chief Executive Officer
Certification Pursuant to Section 906 - Chief Financial Officer
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	2006			2005			2005
	(Unaudited)
ASSETS
Current Assets
Cash and Cash Equivalents	$	4,197		$	14,785		$	9,662
Receivables
Gas		12,058			13,358			7,568
Unbilled Revenue		3,343			3,162			1,777
Merchandise		2,098			2,297			2,123
Other		1,148			857			1,468
Allowance for Doubtful Accounts		(1,761	)		(1,648	)		(1,029	)
Materials, Supplies, and Merchandise, net (At Average Cost)		1,253			1,394			1,319
Gas Stored Underground (At Average Cost)		5,295			4,088			5,666
Regulatory Assets		2,451			323			323
Deferred Income Taxes		2,339			2,539			3,784
Prepayments		2,956			2,317			1,814
Total Current Assets		35,377			43,472			34,475
Property, Plant, and Equipment		288,641			277,540			283,605
Less: Accumulated Depreciation and Amortization		81,652			74,583			77,982
Property, Plant, and Equipment — Net		206,989			202,957			205,623
Construction Work in Progress		12,362			505			6,265
Total Property, Plant, and Equipment		219,351			203,462			211,888
Other Assets
Prepaid Pension Cost		879			989			939
Deferred Charges		587			641			390
Prepayments		1,199			928			1,249
Regulatory Assets		250			497			333
Merchandise Receivables Due After One Year		3,188			3,305			3,185
Total Other Assets		6,103			6,360			6,096
Total	$	260,831		$	253,294		$	252,459

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	2006			2005			2005
	(Unaudited)
LIABILITIES AND CAPITALIZATION
Current Liabilities
Current Maturities of Long-Term Debt	$	4,876		$	5,089		$	5,213
Accounts Payable		10,213			5,874			6,235
Dividends Declared		1,619			1,557			1,684
Customer Deposits		1,223			1,352			1,294
Taxes Accrued		4,113			4,703			6,037
Interest Accrued		1,027			1,103			970
Regulatory Liabilities		6,812			6,622			6,704
Other		1,097			1,094			1,150
Total Current Liabilities		30,980			27,394			29,287
Other Liabilities
Accrued Postretirement Benefit Cost		843			627			762
Deferred Income Taxes		22,540			22,843			22,626
Deferred Investment Tax Credits		226			252			236
Regulatory Liabilities		12,932			12,225			12,576
Other		1,260			1,426			1,597
Total Other Liabilities		37,801			37,373			37,797
		68,781			64,767			67,084
Capitalization
Stockholders’ Equity
Common Stock, $.01 Par Value (Authorized 20,000,000 Shares; Outstanding March 2006 - 7,920,000; March 2005 - 7,847,000; September 2005 - 7,898,000 Shares)		79			78			79
Capital in Excess of Par Value		28,194			26,637			27,457
Retained Earnings		82,764			75,608			74,952
Grantor Trust, at cost		(1,656	)		(1,456	)		(1,539	)
Deferred Compensation Liability		1,656			1,456			1,539
Total Stockholders’ Equity		111,037			102,323			102,488
Minority Interest		5,175			4,890			5,308
Long-Term Debt		75,838			81,314			77,579
Total Capitalization		192,050			188,527			185,375
Total	$	260,831		$	253,294		$	252,459

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	2006			2005			2006			2005
Operating Revenues
Gas Revenues	$	45,063		$	43,059		$	88,274		$	77,862
Merchandise Sales		761			701			2,053			1,886
Other		267			339			576			719
Total Operating Revenues		46,091			44,099			90,903			80,467
Operating Expenses
Cost of Gas		20,988			18,404			44,047			33,326
Cost of Merchandise		625			610			1,583			1,569
Operations and Maintenance		6,442			6,700			12,741			13,197
Depreciation		2,651			2,545			5,293			5,095
Taxes, Other Than Income Taxes		2,968			2,885			5,842			5,336
Total Operating Expenses		33,674			31,144			69,506			58,523
Operating Income		12,417			12,955			21,397			21,944
Other Income and (Expense)
Interest Expense		(1,717	)		(1,842	)		(3,453	)		(3,713	)
Allowance for Borrowed Funds Used During Construction		246			11			421			13
Interest Income		41			42			118			74
Minority Interest		(285	)		(218	)		(523	)		(446	)
Total Other Income (Expense)		(1,715	)		(2,007	)		(3,437	)		(4,072	)
Income Before Income Taxes		10,702			10,948			17,960			17,872
Income Taxes		4,041			4,153			6,815			6,761
Net Income	$	6,661		$	6,795		$	11,145		$	11,111
Earnings Per Share
Basic	$	0.84		$	0.87		$	1.41		$	1.42
Diluted	$	0.84		$	0.85		$	1.40		$	1.40
Average Common Shares Outstanding
Basic		7,915			7,843			7,910			7,838
Diluted		7,969			7,949			7,961			7,943

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	2006			2005
Cash Flows from Operating Activities
Net Income	$	11,145		$	11,111
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
Depreciation and Amortization		5,474			5,284
Provision for Losses on Receivables and Inventory		675			673
Provision for Deferred Income Taxes		1,351			(634	)
Minority Interest		523			446
Stock-Based Employee Compensation Expense		188
Changes in Operating Assets and Liabilities:
Receivables		(5,932	)		(8,590	)
Inventory		504			298
Payables		3,348			560
Taxes		(1,925	)		2,390
Deferred Purchased Gas Adjustment		(3,588	)		4,446
Other		(91	)		467
Net Cash Provided by Operating Activities		11,672			16,451
Cash Flows from Investing Activites
Capital Expenditures		(11,741	)		(3,515	)
Net Cash Used in Investing Activities		(11,741	)		(3,515	)
Cash Flows from Financing Activites
Repayment of Long-Term Debt		(2,078	)		(4,536	)
Changes in Short-Term Borrowings
Payment of Dividends		(3,194	)		(3,116	)
Dividend Reinvestment		181			209
Exercise of Stock Options		219			107
Excess Tax Benefits from Share Based Payments		32			47
Partnership Distributions to Minority Interest Holders		(556	)		(326	)
Net Cash Used by Financing Activities		(5,396	)		(7,615	)
Net Increase/(Decrease) in Cash and Cash Equivalents		(5,465	)		5,321
Cash and Cash Equivalents at Beginning of Period		9,662			9,464
Cash and Cash Equivalents at End of Period	$	4,197		$	14,785
Noncash Transactions from Investing and Financing Activities:
Accruals for Capital Expenditures	$	773		$	290
Dividend Payments Held in Escrow	$	1,619		$	1,480

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); MGS 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, 2005. Certain amounts in the prior-year financial statements have been reclassified to conform with 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, 2006 and 2005 are not indicative of the results to be expected for the full year.

The table below summarizes operating results for the twelve months ended March 31, 2006 and 2005:

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	Twelve Months
EnergySouth, Inc.	Ended March 31,
In Thousands, Except Per Share Data	2006			2005
Operating Revenues	$	135,043		$	120,877
Cost of Gas		57,887			44,968
Cost of Merchandise		2,780			2,801
Operations and Maintenance Expense		24,859			25,070
Depreciation Expense		10,320			9,939
Taxes, Other Than Income Taxes		9,159			8,545
Operating Income		30,038			29,554
Interest Expense		(7,022	)		(7,589	)
Allowance for Borrowed Funds Used During Construction		617			21
Interest Income		303			120
Less: Minority Interest		(1,015	)		(856	)
Income Before Income Taxes	$	22,921		$	21,250
Income Taxes		9,045			8,011
Net Income	$	13,876		$	13,239
Earnings Per Share
Basic	$	1.76		$	1.69
Diluted	$	1.75		$	1.67
Average Common Shares Outstanding
Basic		7,889			7,825
Diluted		7,941			7,922

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 has been reserved for issuance. Options are granted at an option price which represents the market price on the date of grant. 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.

Prior to October 1, 2005, the Company accounted for its stock option plans under the intrinsic value recognition and measurement provisions of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” and adopted the disclosure-only provisions of Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (SFAS 123). Accordingly, no compensation cost was recognized as stock options were issued with exercise prices equal to the market value of the underlying shares on the grant date. Had compensation cost for the Plan been determined on the fair value of the options on the grant date, the Company’s net income and earnings per share would have been as follows for the three and six months ended March 31, 2005:

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	Three Months		Six Months
EnergySouth, Inc.	Ended March 31,		Ended March 31,
In Thousands, Except per Share Data	2005		2005
Net Income, as reported	$	6,795	$	11,111
Deduct:
Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		51		95
Pro forma net income	$	6,744	$	11,016
Earnings per share:
Basic — as reported	$	0.87	$	1.42
Basic — pro forma	$	0.86	$	1.41
Diluted — as reported	$	0.85	$	1.40
Diluted — pro forma	$	0.85	$	1.39

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 options grants recognized during the three and six months ended March 31, 2006 was $102,000 and $187,000, respectively. The income tax benefit recognized in the income statement for these stock options during the three and six months ended March 31, 2006 was approximately $38,000 and $70,000, respectively. The impact of stock option expense was to reduce net income by $64,000 and $117,000, respectively, which represents a decrease in basic and diluted earnings per share of approximately $0.01 per share for the three and six months ended March 31, 2006.

The Company granted stock options during the three months ended March 31, 2006. In calculating the impact for options granted during the current reporting period and in prior periods, 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.

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A summary of option activity under the Plan as of March 31, 2006 and changes during the six months then ended is presented below:

				Weighted		Weighted
				Average		Average	Aggregate
				Exercise		Remaining	Intrinsic
	Shares			Price		Life	Value
Outstanding at September 30, 2005		299,589		$	20.979	7.44 years
Granted		73,950			30.445
Exercised		(10,627	)		20.644
Forfeited		(9,600	)		24.253
Outstanding at March 31, 2006*		353,312		$	22.896	7.53 years	$	3,213,468
Exercisable at March 31, 2006		154,926		$	18.412	6.07 years	$	2,075,716
Remaining reserved for grant at March 31, 2006		246,000

* Includes 88,562 shares outstanding under the 1992 Amended and Restated Stock Option Plan.

The total intrinsic value of options exercised during the three and six months ended March 31, 2006 was approximately $94,000 and $119,000, respectively. The fair value of options that vested during the three and six months ended March 31, 2006 was approximately $200,000 and $249,000, respectively.

At March 31, 2006, there was approximately $939,000 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 2.83 years.

During the three and six months ended March 31, 2006, cash received from options exercised was $196,000 and $219,000, respectively, and the actual tax benefit realized for the related tax deduction totaled $23,000 and $32,000, respectively.

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 the greater of amounts resulting from two different formulas: years of service and average compensation during the last five years of employment, or years of service and average compensation during the term of employment. The Company annually contributes to the plan the amount deductible for federal income tax purposes.

The Company also provides certain health care and life insurance benefits for retired employees. Substantially all employees may become eligible for such benefits if they retire under the provisions of the Company’s retirement plan. The Company is accruing the costs 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:

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	Pension						Postretirement
	Benefits						Benefits
For the three months ended March 31, (in thousands)	2006			2005			2006			2005
Service cost	$	198		$	227		$	23		$	43
Interest cost		455			448			67			79
Amortization of prior service cost		24			24			(27	)		(11	)
Amortization of unrecognized gain								15			15
Expected return on plan assets		(672	)		(643	)		(70	)		(68	)
Net periodic benefit cost (credit)	$	5		$	56		$	8		$	58

	Pension						Postretirement
	Benefits						Benefits
For the six months ended March 31, (in thousands)	2006			2005			2006			2005
Service cost	$	438		$	454		$	78		$	85
Interest cost		919			897			150			158
Amortization of transition asset
Amortization of prior service cost		47			47			(38	)		(22	)
Amortization of unrecognized gain/(loss)								33			29
Expected return on plan assets		(1,344	)		(1,286	)		(141	)		(136	)
Net periodic benefit cost (credit)	$	60		$	112		$	82		$	114

For fiscal year 2006, 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.

Note 5. Rates and Regulatory Matters

On June 10, 2002, the Alabama Public Service Commission (APSC) approved Mobile Gas’ request for the Rate Stabilization and Equalization (RSE) rate setting process to be effective October 1, 2002 through September 30, 2005, and thereafter unless modified or discontinued by APSC order. On May 23, 2005, Mobile Gas filed an application requesting that the APSC extend Mobile Gas’ RSE rate making methodology. On June 14, 2005, the 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 certain other Alabama

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utilities. A rate adjustment designed to decrease annual gas revenues by approximately $303,000 was implemented December 1, 2005. Rate adjustments, designed to increase annual gas revenues by approximately $1.7 million and $2.8 million, were implemented under the RSE tariff effective December 1, 2004, and 2003, respectively. Mobile Gas’ rates, as established under RSE, allow a return on average equity for the period. As such, 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 of 13.35% to 13.85% at the end of the fiscal year.

On December 7, 2005, Mobile Gas consented to a request by the Alabama Public Service Commission that the utility maintain its rates through March 31, 2006, at levels no higher than those implemented with the December 1, 2005 rate adjustment. The rate freeze has 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 and/or Liabilities within the Company’s Balance Sheet. See “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, the utility 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 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%. During the year ended September 30, 2003, Mobile Gas charged $146,000 against the ESR due to revenue losses from a large industrial customer. 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. Effective

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October 1, 2004, Mobile Gas began recording a monthly accrual in the amount of $10,000 to restore the reserve to its former balance of $1.0 million. The ESR balance of $1,000,000 at March 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 has agreed to pay Mobile Gas $6,100,000, with $4,750,000 to be paid in fiscal 2006, of which $3,500,000 has been received, and the final payment of $1,350,000 due October 1, 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 adjustment is calculated monthly for the months of November through April and applied to customers’ bills in the same billing cycle in which the weather variation occurs. The temperature adjustment rider applies to substantially all residential and small commercial customers.

The Company is subject to 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.

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

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	March 31,				March 31,				September 30,
	2006				2005				2005
	Current		Noncurrent		Current		Noncurrent		Current		Noncurrent
Assets
Deferred Purchase Gas Adjustment	$	2,208
ESR Fund		167	$	250	$	167	$	417	$	167	$	333
Bad Debt Reserve		66				133		66		133
Other		10				23		14		23
Regulatory Assets	$	2,451	$	250	$	323	$	497	$	323	$	333
Liabilities
Bad Debt Reserve					$	10
ESR Fund	$	1,000				914			$	975
Deferred Investment Tax Credit		15	$	113		16	$	129		15	$	121
RSE Adjustment		118				78				433
Gross Receipt Tax Collections		4,295				4,287				3,751
Deferred Purchase Gas Adjustment						1,177				1,379
Contract Termination Payment		1,229
Accrued Dismantling Costs				12,819				12,096				12,455
Other		155				140				151
Regulatory Liabilities	$	6,812	$	12,932	$	6,622	$	12,225	$	6,704	$	12,576

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, 2006 and 2005, the net acquisition adjustments were $5,595,000 and $5,955,000, respectively, and the balance at September 30, 2005 was $5,774,000.

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

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	Three Months				Six Months
EnergySouth, Inc.	Ended March 31,				Ended March 31,
In Thousands	2006		2005		2006		2005
Weighted Average Common Shares		7,915		7,843		7,910		7,838
Effect of Dilutive Securities:
Options to Purchase Common Stock		54		106		51		105
Diluted Average Common Shares		7,969		7,949		7,961		7,943

Stock option awards to purchase approximately 143,000 shares as of March 31, 2006 were not included in the computation of diluted earnings per share because inclusion of these shares would have been antidilutive as the option exercise prices were greater than the shares’ market prices during this period.

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.

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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	)
Allowance for Borrowed Funds Used During Construction		18			228									246
Less: Minority Interest		(26	)		(259	)								(285	)
Income Before Income Taxes	$	8,059		$	2,562		$	81					$	10,702

For the three months ended	Natural Gas			Natural Gas
March 31, 2005 (in thousands):	Distribution			Storage			Other			Eliminations			Consolidated
Operating Revenues	$	39,383		$	4,725		$	1,040		$	(1,049	)	$	44,099
Cost of Gas		19,453									(1,049	)		18,404
Cost of Merchandise								610						610
Operations and Maintenance Expense		5,546			810			344						6,700
Depreciation Expense		1,925			620									2,545
Taxes, Other Than Income Taxes		2,627			236			22						2,885
Operating Income		9,832			3,059			64						12,955
Interest Income		1			38			93			(90	)		42
Interest Expense		(782	)		(1,074	)		(76	)		90			(1,842	)
Allowance for Borrowed Funds Used During Construction		2			9									11
Less: Minority Interest		(30	)		(188	)								(218	)
Income Before Income Taxes	$	9,023		$	1,844		$	81					$	10,948

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	)
Allowance for Borrowed Funds Used During Construction		39			382									421
Less: Minority Interest		(56	)		(467	)								(523	)
Income Before Income Taxes	$	12,958		$	4,634		$	368					$	17,960

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For the six months ended	Natural Gas			Natural Gas
March 31, 2005 (in thousands):	Distribution			Storage			Other			Eliminations			Consolidated
Operating Revenues	$	70,441		$	9,508		$	2,605		$	(2,087	)	$	80,467
Cost of Gas		35,413									(2,087	)		33,326
Cost of Merchandise								1,569						1,569
Operations and Maintenance Expense		10,843			1,588			766						13,197
Depreciation Expense		3,851			1,244									5,095
Taxes, Other Than Income Taxes		4,837			458			41						5,336
Operating Income		15,497			6,218			229						21,944
Interest Income		2			67			95			(90	)		74
Interest Expense		(1,510	)		(2,162	)		(131	)		90			(3,713	)
Allowance for Borrowed Funds Used During Construction		4			9									13
Less: Minority Interest		(65	)		(381	)								(446	)
Income Before Income Taxes	$	13,928		$	3,751		$	193					$	17,872

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 ameliorates 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, 2006, 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 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. The purchased gas adjustment provisions of the Company’s rate schedules permit the recovery of all costs associated with gas supply from customers.

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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. 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, 2006, Bay Gas had entered into contracts for compressors and other services to be performed in the development of the third storage cavern.

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		Payments for		Construction		Total
Year	Contracts		Service Fees		Contracts		Commitments
remaining 2006	$	6,895	$	75	$	8,317	$	15,287
2007		2,009		333				2,342
2008		1,187		378				1,565
2009		1,187		423				1,610
2010 - and thereafter		2,028		11,426				13,454
Total	$	13,306	$	12,635	$	8,317	$	34,258

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 recent 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. Mobile Gas has begun discussions with ADEM to identify steps necessary to obtain ADEM’s concurrence with Mobile Gas’ plans for the site. 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

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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 March 2005, the FASB issued Financial Interpretation No. 47 to clarify the term “conditional asset retirement obligation” as used in Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.” Conditional asset retirement obligation refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred — generally, upon acquisition, construction, development and/or through the normal operation of the asset. Uncertainty about the timing and/or method of settlement should be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective for the Company no later than September 30, 2006. The Company is evaluating the impact of FIN 47 on its financial statements.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections”, a replacement of Accounting Principle Board (APB) Opinion No. 20 and SFAS No. 3. SFAS 154 applies to all voluntary changes in accounting principle and changes the requirements for accounting for and reporting of a change in accounting principle. Retrospective application to prior period’s financial statements of the change in accounting principle is required unless it is impracticable. SFAS 154 is effective for fiscal years beginning after December 15, 2005, with earlier application permitted in fiscal years beginning after June 1, 2005. The adoption of SFAS 154 will not have an 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. MGS Storage Services is the general partner of Bay Gas Storage Company, a limited partnership that provides underground storage and delivery of natural gas for Mobile Gas and other customers. 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 months ended March 31, 2006 decreased $0.01 per diluted share and were relatively flat for the six months ended March 31, 2006 as compared to the same prior-year periods. The decrease in earnings for the three-month period ended March 31, 2006 was due primarily to a decline in earnings from Mobile Gas’ distribution business which was mostly offset by increased earnings from Bay Gas’ natural gas storage business. 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 decreased $0.07 per diluted share for the three- and six-month periods ended March 31, 2006 when compared to the same prior year periods due primarily to a decline in consumption from temperature-sensitive customers during the second fiscal quarter.

The Company’s natural gas storage business, operated by Bay Gas, contributed increased earnings per share of $0.05 and $0.06 per diluted share for the three- and six-month periods ended March 31, 2006 as compared to the same prior-year periods. The positive earnings contributions are due to increased storage revenues associated with new contracts for long-term storage services, a reduction in operating expenses and an increase in the amount of interest capitalized during the construction and development of the third underground natural gas storage cavern.

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.

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The Alabama Public Service Commission (APSC) regulates the Company’s gas distribution operations. Mobile Gas’ rate tariffs for gas distribution allow rate adjustments to pass through to customers the cost of gas and certain taxes. These costs, therefore, have little direct impact on the Company’s 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 2005, the Company accelerated the replacement of cast iron mains to improve and enhance the distribution system. Consequently, during fiscal 2006, the collection of these costs has a direct impact on the Company’s margins when compared to prior-year periods.

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 certain other utilities. Rate adjustments, designed to decrease annual gas revenues by approximately $303,000 and increase annual gas revenues by approximately $1.7 million, were implemented under the RSE tariff effective December 1, 2005 and December 1, 2004, respectively. The December 1, 2005 rate adjustment results in decreased revenues due primarily to the return of approximately $1,350,000 of the regulatory liability for gross receipts tax collections to ratepayers during fiscal 2006. 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 utilizes 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. 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 $1,739,000 (4%) and $10,256,000 (15%) during the three- and six-month periods ended March 31, 2006 as compared to the same prior-year periods due to the rate adjustments to recover increased gas costs paid to suppliers. The increase in revenues during the three- and six-month periods were partially offset by declines of 13% and 5%, respectively, in volumes delivered to temperature-sensitive customers. The increase in revenues was also partially offset by a decline in the number of temperature-sensitive customers served during the current-year periods.

Revenues from the sale of natural gas to large commercial and industrial customers increased $427,000 (13%) and $1,929,000 (32%) for the three-and six-month periods ended March 31, 2006 due to the rate adjustments noted above. The increase in revenues during the three- and six-month periods were partially offset by declines of 14% and 4%, respectively, in volumes delivered to customers during the current year periods as a result of the increased price of

21

natural gas.

Revenues from the transportation of natural gas to large commercial and industrial customers increased $163,000 (9%) and $139,000 (4%) during the three-and six-month periods ended March 31, 2006 due to a increase in volumes delivered to customers.

The cost of natural gas increased $2,594,000 (13%) and $10,751,000 (30%) for the three- and six-month periods ended March 31, 2006 as compared to the same prior-year periods due to higher natural gas commodity prices.

Natural gas distribution margins, defined as revenues less cost of gas and related taxes, declined approximately 4% and 1% during the three- and six-month periods ended March 31, 2006 as compared to the same prior-year periods. Increased margins from the amortization of the regulatory liability for gross receipts taxes and increased collections for cast iron replacements were more than offset by a decline in usage per degree day by temperature-sensitive customers and a decline in the number of temperature-sensitive customers served during the current-year periods. Residential customer consumption, when adjusted for weather variations, declined 15% and 11%, respectively, for the three- and six-month periods ended March 31, 2006 when compared to the same prior-year periods. These declines are significantly higher than historical declines in usage that Mobile Gas has experienced over time as customers replace old appliances with new, more energy efficient models and as new, more energy efficient homes are built. Management believes that this decline is largely attributable to the high natural gas prices experienced during the fall and winter of 2005-2006 after Hurricane Katrina. Additionally, usages per degree-day can and do vary between periods due to several factors including humidity, wind speed, cloud cover, and duration of cold weather.

Operations and maintenance (O&M) expenses for the three months ended March 31, 2006 approximated the same prior year period. O&M expenses decreased $149,000 (1%) for the six months ended March 31, 2006 as compared to the same prior-year period due in part to a decrease in postemployment health insurance expenses. 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. This decrease in benefit expenses was partially offset by an increase in compensation expense recorded for stock options in accordance with SFAS 123R as discussed in Note 3 to the Unaudited Condensed Consolidated Financial Statements above, an increase in expenses related to the search for a successor for the current President and Chief Executive Officer upon his retirement in fiscal 2007, and an increase in bad debt reserves due to the rise in gas revenues associated with the increase in natural gas prices discussed above. In response to the corresponding increase in revenues, Mobile Gas established additional reserves for anticipated uncollectible account balances for gas delivered during the current year period.

Depreciation expense increased $70,000 (4%) and $139,000 (4%) for the three- and six-month periods ended March 31, 2006 as compared to the same prior-year periods due to Mobile Gas’ increased investment in property, plant and equipment.

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Other taxes primarily consist of property taxes and business license taxes that are based on gross revenues and fluctuate accordingly. Other taxes increased $100,000 (4%) and $528,000 (11%) for the three- and six-month periods ended March 31, 2006 due primarily to the increased revenues.

Interest expense decreased approximately $5,000 and $14,000 for the three- and six-month periods ended March 31, 2006 as compared to the same prior-year periods due primarily to principal payments on long-term debt.

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 decreased slightly during the three-and six-month periods ended March 31, 2006 due to a decline 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 orders on October 11, 2001 and June 3, 2002 approving rates for such services. On March 9, 2004, in accordance with FERC filing requirements, Bay Gas filed a petition with the FERC requesting approval of new rates for transportation-only service. On April 14, 2006, the FERC issued an order regarding Bay Gas’ petition for new rates which does not have a material impact on Bay Gas’ earnings.

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. Bay Gas entered into a fifteen-year contract with Southern Company Services, Inc. (Southern), an affiliate of Southern Company, for most of the second cavern capacity. During fiscal year 2004, the remaining capacity of the second cavern was fully subscribed on a firm basis. 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, and expansion of these caverns is currently planned to enable them to ultimately hold 7.0 Bcf. Such development will commence after development of the third cavern and will be subject to certain operational considerations to avoid interruption of storage operations.

Bay Gas recently began construction on a third storage cavern and related facilities and has

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entered into multi-year contracts with customers for a majority 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 during the summer of 2007. The addition of the third cavern and additional capacity development of the second cavern 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.

Bay Gas’ revenues increased $275,000 (6%) and $186,000 (2%) during the three-and six-month periods ended March 31, 2006 as compared to the same prior-year periods due primarily to additional revenues derived from new long-term storage agreements.

Operations and maintenance (O&M) expenses decreased $254,000 (31%) and $312,000 (20%) during the three- and six-month periods ended March 31, 2006 as compared to the same prior-year periods due primarily to a one time credit of approximately $270,000 related to certain cavern lease payments recorded as a prepaid asset which will be amortized over the remaining term of the lease under which the payments are made. Also contributing to the decrease in expenses for the six months ended March 31, 2006 was a reduction in the present value of future health insurance benefits for certain disabled employees as discussed in Note 4 to the Unaudited Condensed Consolidated Financials Statements above.

Depreciation expense increased $36,000 (6%) and $59,000 (5%) during the three- and six-month periods ended March 31, 2006 due to increased investments in property, plant and equipment.

Allowance for borrowed funds used during construction represents the capitalization of interest costs to construction work-in-progress. Capitalized interest costs increased $219,000 and $373,000 for the three- and six-month periods ended March 31, 2006 due to the 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 increased $71,000 (38%) and $86,000 (23%) during the three-and six-month periods ended March 31, 2006 as compared to the same prior-year periods 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 for the three-month period ended March 31, 2006 was approximately the same as the comparable prior year period. Income before income taxes from Other business activities for the six-month period ended March 31, 2006 increased approximately $0.01 per diluted share as compared to the same prior-year period due primarily to an increase in interest income.

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Income Taxes

Income taxes fluctuate with the change in income before income taxes. Income tax expense decreased $112,000 (3%) for the three-month period ended March 31, 2006 and increased $54,000 (1%) for the six-month period ended March 31, 2006 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 decreased $4,779,000 during the six-month period ended March 31, 2006 as compared to the same period last fiscal year due to a decrease in collections of increased gas costs from customers and the payment of federal, state, and local taxes. Offsetting the above negative impacts on cash flow from operating activities was a decrease in accounts receivable, an increase in deferred income tax expense, and an increase in payables.

Cash used in investing activities reflects the capital-intensive nature of the Company’s business. During the six months ended March 31, 2006 and 2005, the Company used cash of $11,741,000 and $3,515,000, respectively, for the construction of distribution and storage facilities, purchases of equipment and other general improvements. During the six month period ended March 31, 2006, Bay Gas invested $6,177,000 in the ongoing development of a third salt-dome storage cavern. The expansion of storage facilities is expected to be funded through internal cash generation and the issuance of long-term debt.

Financing activities used cash of $5,396,000 and $7,615,000 during the six months ended March 31, 2006 and March 31, 2005, respectively, due primarily to payments on long term debt and quarterly dividends.

Funds for the Company’s short-term cash needs are expected to come from cash provided by operations and borrowings under the Company’s revolving credit agreement. At March 31, 2006, the Company had $20,000,000 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. Additional funds in an aggregate amount of $2,600,000 are expected to be provided in the remaining portion of calendar year 2006 in accordance with the Termination Agreement as discussed in Note 5 to the Notes to the Unaudited Condensed Consolidated Financial Statements. 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

25

the normal course of business and are not subject to derivative accounting treatment. 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, 2005 and Item 3 below for further information.

The table below summarizes the Company’s contractual obligations and commercial commitments as of March 31, 2006:

	Remaining								Fiscal Years
Type of Contractual	Fiscal Year		Fiscal Year		Fiscal Year		Fiscal Year		2010 and
Obligations (in thousands):	2006		2007		2008		2009		thereafter
Long-Term Debt	$	3,135	$	5,019	$	5,300	$	5,454	$	61,806
Interest Payments		3,397		6,242		5,822		5,382		26,340
Estimated Future Minimum Payments for Bay Gas Service Fees		75		333		378		423		11,426
Construction Contracts for Bay Gas’		8,317
3rd Cavern Development
Gas Supply Contracts		6,895		2,009		1,187		1,187		2,028
Total	$	21,819	$	13,603	$	12,687	$	12,446	$	101,600

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, 2005.

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

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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 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.

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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 ameliorates 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, 2006, 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, 2006 the Company had approximately $80.7 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, 2005 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.

Item 4 CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, an evaluation (the “Evaluation”) was carried out, under the supervision and with the participation of the Company’s President and Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), of the effectiveness of the design and operation of the Company’s disclosure controls and procedures (“Disclosure Controls”). Based on the Evaluation, the CEO and CFO concluded that the Company’s Disclosure Controls are effective in timely alerting them to material information required to be included in the Company’s periodic SEC reports.

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Changes in Internal Control

Internal controls for financial reporting were also evaluated and there have been no significant changes in internal controls or in other factors that could significantly affect those controls subsequent to the date of their last evaluation.

Limitations on the Effectiveness of Controls

A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected.

PART II. OTHER INFORMATION

Item 5. Other Information

On April 28, 2006, EnergySouth, Inc. (the “Company”) issued a press release announcing earnings for the three and six months ended March 31, 2006 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.

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PART II. OTHER INFORMATION

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 28, 2006

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 1, 2006	/s/ John S. Davis
	John S. Davis
	President and
	Chief Executive Officer
Date: May 1, 2006	/s/ Charles P. Huffman
	Charles P. Huffman
	Senior Vice President and
	Chief Financial Officer

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