EnergySouth (ENSI) 10-Q 2006 Q3 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 EndedJune 30, 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 July 31, 2006 – 7, 938,537 shares.

ENERGYSOUTH, INC.
FORM 10-Q FOR THE QUARTER ENDED June 30, 2006

INDEX

	Page No.
PART I: FINANCIAL INFORMATION
Item 1 Financial Statements:
(a) Unaudited Condensed Consolidated Balance Sheets June 30, 2006 and 2005 and September 30, 2005		3 - 4
(b) Unaudited Condensed Consolidated Statements of Income Three and Nine Months Ended June 30, 2006 and 2005		5
(c) Unaudited Condensed Consolidated Statements of Cash Flows Nine Months Ended June 30, 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
Storage Service Agreement
Storage Service Agreement
Certification Pursuant to Section 302 - CEO
Certification Pursuant to Section 302 - CFO
Certification Pursuant to Section 906 - CEO
Certification Pursuant to Section 906 - CFO
Press Release

2

PART 1. FINANCIAL INFORMATION

ITEM 1: FINANCIAL STATEMENTS

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

EnergySouth, Inc.	June 30,						September 30,
In Thousands	2006			2005			2005
	(Unaudited)
ASSETS
Current Assets
Cash and Cash Equivalents	$	1,176		$	13,585		$	8,052
Restricted Cash		1,761			1,599			1,610
Receivables
Gas		7,531			7,824			7,568
Unbilled Revenue		1,516			1,589			1,777
Merchandise		2,028			2,197			2,123
Other		1,278			1,183			1,468
Allowance for Doubtful Accounts		(1,505	)		(1,934	)		(1,029	)
Materials, Supplies, and Merchandise, net (At Average Cost)		1,345			1,359			1,319
Gas Stored Underground (At Average Cost)		5,104			5,508			5,666
Regulatory Assets		2,449			323			323
Deferred Income Taxes		2,617			2,285			3,784
Prepayments		2,606			2,089			1,814
Total Current Assets		27,906			37,607			34,475
Property, Plant, and Equipment		291,235			279,534			283,605
Less: Accumulated Depreciation and Amortization		83,555			76,236			77,982
Property, Plant, and Equipment — Net		207,680			203,298			205,623
Construction Work in Progress		14,932			2,933			6,265
Total Property, Plant, and Equipment		222,612			206,231			211,888
Other Assets
Prepaid Pension Cost		849			957			939
Deferred Charges		387			616			390
Prepayments		1,265			913			1,249
Regulatory Assets		208			415			333
Merchandise Receivables Due After One Year		3,042			3,161			3,185
Total Other Assets		5,751			6,062			6,096
Total	$	256,269		$	249,900		$	252,459

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

3

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

EnergySouth, Inc.	June 30,						September 30,
In Thousands, Except Share Data	2006			2005			2005
	(Unaudited)
LIABILITIES AND CAPITALIZATION
Current Liabilities
Current Maturities of Long-Term Debt	$	4,957		$	5,160		$	5,213
Accounts Payable		7,459			6,526			6,235
Dividends Declared		1,809			1,676			1,684
Customer Deposits		1,159			1,277			1,294
Taxes Accrued		3,745			3,413			6,037
Interest Accrued		420			463			970
Regulatory Liabilities		6,911			5,894			6,704
Other		1,166			1,302			1,150
Total Current Liabilities		27,626			25,711			29,287
Other Liabilities
Accrued Postretirement Benefit Cost		881			684			762
Deferred Income Taxes		23,615			23,534			22,626
Deferred Investment Tax Credits		221			247			236
Regulatory Liabilities		13,068			12,380			12,576
Other		1,300			1,570			1,597
Total Other Liabilities		39,085			38,415			37,797
		66,711			64,126			67,084
Capitalization
Stockholders’ Equity
Common Stock, $.01 Par Value
(Authorized 20,000,000 Shares; Outstanding
June 2006 — 7,936,000;
June 2005 — 7,855,000;
September 2005 — 7,898,000 Shares)		79			78			79
Capital in Excess of Par Value		28,674			26,835			27,457
Retained Earnings		82,435			75,377			74,952
Grantor Trust, at cost		(1,684	)		(1,485	)		(1,539	)
Deferred Compensation Liability		1,684			1,485			1,539
Total Stockholders’ Equity		111,188			102,290			102,488
Minority Interest		5,507			5,063			5,308
Long-Term Debt		72,863			78,421			77,579
Total Capitalization		189,558			185,774			185,375
Total	$	256,269		$	249,900		$	252,459

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

4

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF INCOME

	Three Months						Nine Months
ENERGYSOUTH, INC.	Ended June 30,						Ended June 30,
In Thousands, Except Per Share Data	2006			2005			2006			2005
Operating Revenues
Gas Revenues	$	21,729		$	21,362		$	110,003		$	99,224
Merchandise Sales		1,099			672			3,152			2,558
Other		298			316			874			1,035
Total Operating Revenues		23,126			22,350			114,029			102,817
Operating Expenses
Cost of Gas		7,166			6,984			51,213			40,310
Cost of Merchandise		860			605			2,443			2,174
Operations and Maintenance		6,583			6,289			19,324			19,485
Depreciation		2,638			2,544			7,931			7,640
Taxes, Other Than Income Taxes		1,788			1,735			7,630			7,071
Total Operating Expenses		19,035			18,157			88,541			76,680
Operating Income		4,091			4,193			25,488			26,137
Other Income and (Expense)
Interest Expense		(1,669	)		(1,805	)		(5,123	)		(5,518	)
Capitalized Interest		280			49			701			62
Interest Income		41			103			159			177
Minority Interest		(272	)		(203	)		(795	)		(649	)
Total Other Income (Expense)		(1,620	)		(1,856	)		(5,058	)		(5,928	)
Income Before Income Taxes		2,471			2,337			20,430			20,209
Income Taxes		908			880			7,722			7,641
Net Income	$	1,563		$	1,457		$	12,708		$	12,568
Earnings Per Share
Basic	$	0.20		$	0.19		$	1.61		$	1.60
Diluted	$	0.20		$	0.18		$	1.59		$	1.58
Average Common Shares Outstanding
Basic		7,931			7,854			7,917			7,843
Diluted		7,988			7,947			7,970			7,945

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

5

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Nine Months
EnergySouth, Inc.	Ended June 30,
In Thousands	2006			2005
Cash Flows from Operating Activities
Net Income	$	12,708		$	12,568
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
Depreciation and Amortization		8,183			7,915
Provision for Losses on Receivables and Inventory		1,029			967
Provision for Deferred Income Taxes		2,144			307
Minority Interest		795			649
Stock-Based Employee Compensation Expense		265
Changes in Operating Assets and Liabilities:
Receivables		(110	)		(1,570	)
Inventory		612			(1,091	)
Payables		564			47
Taxes		(2,293	)		1,100
Deferred Purchased Gas Adjustment		(3,625	)		4,037
Other		1,213			942
Net Cash Provided by Operating Activities		21,485			25,871
Cash Flows from Investing Activites
Capital Expenditures		(17,770	)		(8,075	)
Restricted Cash		(151	)		(122	)
Net Cash Used in Investing Activities		(17,921	)		(8,197	)
		��
Cash Flows from Financing Activites
Repayment of Long-Term Debt		(4,972	)		(7,359	)
Payment of Dividends		(5,225	)		(4,816	)
Dividend Reinvestment		268			307
Exercise of Stock Options		423			147
Excess Tax Benefits from Share Based Payments		93
Partnership Distributions to Minority Interest Holders		(595	)		(355	)
Net Cash Used in Financing Activities		(10,008	)		(12,076	)
Net Increase (Decrease) in Cash and Cash Equivalents		(6,444	)		5,598
Cash and Cash Equivalents at Beginning of Period		8,052			7,987
Cash and Cash Equivalents at End of Period	$	1,608		$	13,585
Noncash Transactions from Investing Activities:
Accruals for Capital Expenditures	$	1,257		$	1,023

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

6

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, 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 nine-month periods ended June 30, 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 June 30, 2006 and 2005:

7

	Twelve Months
EnergySouth, Inc.	Ended June 30,
In Thousands, Except Per Share Data	2006			2005
Operating Revenues	$	135,819		$	122,231
Cost of Gas		58,069			45,854
Cost of Merchandise		3,035			2,884
Operations and Maintenance Expense		25,153			25,319
Depreciation Expense		10,414			10,044
Taxes, Other Than Income Taxes		9,212			8,586
Operating Income		29,936			29,544
Interest Expense		(6,886	)		(7,436	)
Allowance for Borrowed Funds Used During Construction		848			66
Interest Income		241			202
Less: Minority Interest		(1,084	)		(871	)
Income Before Income Taxes	$	23,055		$	21,505
Income Taxes		9,073			8,107
Net Income	$	13,982		$	13,398
Earnings Per Share
Basic	$	1.77		$	1.71
Diluted	$	1.76		$	1.69
Average Common Shares Outstanding
Basic		7,909			7,837
Diluted		7,962			7,936

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 nine months ended June 30, 2005:

8

	Three Months		Nine Months
EnergySouth, Inc.	Ended June 30,		Ended June 30,
In Thousands, Except per Share Data	2005		2005
Net Income, as reported	$	1,457	$	12,568
Deduct:
Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		54		149
Pro forma net income	$	1,403	$	12,419
Earnings per share:
Basic — as reported	$	0.19	$	1.60
Basic — pro forma	$	0.18	$	1.58
Diluted — as reported	$	0.18	$	1.58
Diluted — pro forma	$	0.18	$	1.56

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 nine months ended June 30, 2006 was $78,000 and $265,000, respectively. The income tax benefit recognized in the income statement for these stock options during the three and nine months ended June 30, 2006 was approximately $30,000 and $100,000, respectively. The impact of stock option expense was to reduce net income by $48,000 and $165,000, respectively, which represents a decrease in basic and diluted earnings per share of less than $0.01 per share for the three months ended June 30, 2006 and $0.02 per share for the nine months ended June 30, 2006.

The Company granted stock options during the nine months ended June 30, 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. Options granted during the nine months ended June 30, 2006 have an estimated fair value of $5.49 as calculated using the following assumptions: a stock price volatility of 17.43%, an expected life of six years, a risk free interest rate of 4.48% and a dividend yield of 2.8%.

9

A summary of option activity under the Plan as of June 30, 2006 and changes during the nine months then ended is presented below:

				Weighted		Weighted	Aggregate
				Average		Average	Intrinsic
				Exercise		Remaining	Value (in
	Shares			Price		Life	thousands)
Outstanding at September 30, 2005		299,589		$	20.979	7.44 years
Granted		73,950			30.445
Exercised		(23,252	)		18.612
Forfeited		(12,150	)		25.727
Outstanding at June 30, 2006*		338,137		$	23.049	7.57 years	$	2,709
Exercisable at June 30, 2006		158,851		$	18.434	6.16 years	$	2,033
Remaining reserved for grant at June 30, 2006		248,000

* Includes 83,812 shares outstanding under the 1992 Amended and Restated Stock Option Plan

The total intrinsic value of options exercised during the three and nine months ended June 30, 2006 was approximately $147,000 and $266,000, respectively. The fair value of options that vested during the three and nine months ended June 30, 2006 was approximately $78,000 and $327,000, respectively.

At June 30, 2006, there was approximately $765,000 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 2.65 years.

During the three and nine months ended June 30, 2006, cash received from options exercised was $204,000 and $423,000, respectively, and the actual tax benefit realized for the related tax deduction totaled $61,000 and $93,000, 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 are eligible for such benefits if they retire under the provisions of the Company’s retirement plan. The Company accrues the costs of such benefits over the expected service period of the employees. Effective August 1, 2006, the Company will no longer provide

10

life insurance benefits for retired employees. See Note 10 to the Unaudited Condensed Consolidated Financial Statements below.

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 June 30, (in thousands)	2006			2005			2006			2005
Service cost	$	219		$	215		$	39		$	43
Interest cost		460			445			75			79
Amortization of prior service cost		23			24			(19	)		(11	)
Amortization of unrecognized gain								17			15
Expected return on plan assets		(672	)		(643	)		(71	)		(68	)
Net periodic benefit cost (credit)	$	30		$	41		$	41		$	58

	Pension						Postretirement
	Benefits						Benefits
For the nine months ended June 30, (in thousands)	2006			2005			2006			2005
Service cost	$	656		$	646		$	117		$	128
Interest cost		1,379			1,335			225			236
Amortization of prior service cost		70			71			(57	)		(33	)
Amortization of unrecognized gain/(loss)								50			44
Expected return on plan assets		(2,015	)		(1,929	)		(212	)		(204	)
Net periodic benefit cost (credit)	$	90		$	123		$	123		$	171

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.

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.

11

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 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 the table of significant regulatory assets and liabilities shown 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

12

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 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 June 30, 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, of which $4,750,000 has been received to date in fiscal year 2006, and the final payment of $1,350,000 is 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):

13

	June 30,				June 30,				September 30,
	2006				2005				2005
	Current		Noncurrent		Current		Noncurrent		Current		Noncurrent
Assets
Deferred Purchase Gas Adjustment	$	2,246
ESR Fund		167	$	208	$	167	$	375	$	167	$	333
Other		36				156		40		156
Regulatory Assets	$	2,449	$	208	$	323	$	415	$	323	$	333
Liabilities
ESR Fund	$	1,000				944			$	975
Deferred Investment Tax Credit		15	$	110		15	$	125		15	$	121
RSE Adjustment		46				16				433
Gross Receipt Tax Collections		3,495				4,006				3,751
Deferred Purchase Gas Adjustment						768				1,379
Contract Termination Payment		2,172
Accrued Dismantling Costs				12,958				12,255				12,455
Other		183				145				151
Regulatory Liabilities	$	6,911	$	13,068	$	5,894	$	12,380	$	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 June 30, 2006 and 2005, the net acquisition adjustments were $5,506,000 and $5,863,000, 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:

14

	Three Months				Nine Months
EnergySouth, Inc.	Ended June 30,				Ended June 30,
In Thousands	2006		2005		2006		2005
Weighted Average Common Shares		7,931		7,854		7,917		7,843
Effect of Dilutive Securities:
Options to Purchase Common Stock		57		93		53		102
Diluted Average Common Shares		7,988		7,947		7,970		7,945

Stock option awards to purchase approximately 141,000 shares as of June 30, 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.

For the three months ended	Natural Gas			Natural Gas
June 30, 2006 (in thousands):	Distribution			Storage			Other			Eliminations			Consolidated
Operating Revenues	$	17,600		$	5,175		$	1,397		$	(1,046	)	$	23,126
Cost of Gas		8,212									(1,046	)		7,166
Cost of Merchandise								860						860
Operations and Maintenance Expense		5,368			877			338						6,583
Depreciation Expense		1,995			643									2,638
Taxes, Other Than Income Taxes		1,558			215			15						1,788
Operating Income		467			3,440			184						4,091
Interest Income		1			42			201			(203	)		41
Interest Expense		(780	)		(1,007	)		(85	)		203			(1,669	)
Capitalized Interest		13			267									280
Less: Minority Interest		(24	)		(248	)								(272	)
Income (Loss) Before Income Taxes	$	(323	)	$	2,494		$	300					$	2,471

15

For the three months ended	Natural Gas			Natural Gas
June 30, 2005 (in thousands):	Distribution			Storage			Other			Eliminations			Consolidated
Operating Revenues	$	17,950		$	4,476		$	988		$	(1,064	)	$	22,350
Cost of Gas		8,048									(1,064	)		6,984
Cost of Merchandise								605						605
Operations and Maintenance Expense		5,181			794			314						6,289
Depreciation Expense		1,925			619									2,544
Taxes, Other Than Income Taxes		1,484			238			13						1,735
Operating Income		1,312			2,825			56						4,193
Interest Income		15			50			64			(26	)		103
Interest Expense		(702	)		(1,063	)		(66	)		26			(1,805	)
Capitalized Interest		7			42									49
Less: Minority Interest		(33	)		(170	)								(203	)
Income Before Income Taxes	$	599		$	1,684		$	54					$	2,337

For the nine months ended	Natural Gas			Natural Gas
June 30, 2006 (in thousands):	Distribution			Storage			Other			Eliminations			Consolidated
Operating Revenues	$	98,297		$	14,869		$	4,026		$	(3,163	)	$	114,029
Cost of Gas		54,376									(3,163	)		51,213
Cost of Merchandise								2,443						2,443
Operations and Maintenance Expense		16,062			2,153			1,109						19,324
Depreciation Expense		5,985			1,946									7,931
Taxes, Other Than Income Taxes		6,922			645			63						7,630
Operating Income		14,952			10,125			411						25,488
Interest Income		16			146			489			(492	)		159
Interest Expense		(2,304	)		(3,077	)		(234	)		492			(5,123	)
Capitalized Interest		52			649									701
Less: Minority Interest		(80	)		(715	)								(795	)
Income Before Income Taxes	$	12,636		$	7,128		$	666					$	20,430

For the nine months ended	Natural Gas			Natural Gas
June 30, 2005 (in thousands):	Distribution			Storage			Other			Eliminations			Consolidated
Operating Revenues	$	88,391		$	13,984		$	3,593		$	(3,151	)	$	102,817
Cost of Gas		43,461									(3,151	)		40,310
Cost of Merchandise								2,174						2,174
Operations and Maintenance Expense		16,023			2,382			1,080						19,485
Depreciation Expense		5,777			1,863									7,640
Taxes, Other Than Income Taxes		6,321			696			54						7,071
Operating Income		16,809			9,043			285						26,137
Interest Income		17			117			159			(116	)		177
Interest Expense		(2,212	)		(3,225	)		(197	)		116			(5,518	)
Capitalized Interest		11			51									62
Less: Minority Interest		(98	)		(551	)								(649	)
Income Before Income Taxes	$	14,527		$	5,435		$	247					$	20,209

16

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 June 30, 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.

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.

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 June 30, 2006, Bay Gas had entered into contracts for compressors and other services to be performed in the development of the third storage cavern.

17

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 2006	$	4,732	$	225	$	75	$	2,666	$	7,698
2007		5,613		2,150		333		6,429		14,525
2008		1,187		613		378				2,178
2009		1,187				423				1,610
2010 — and thereafter		2,028				11,426				13,454
Total	$	14,747	$	2,988	$	12,635	$	9,095	$	39,465

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 had 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 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

18

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.

Note 10. Subsequent Events

As noted in Note 4 above, the Company has provided a term life insurance benefit for retirees. Effective August 1, 2006, the Company will no longer provide this benefit. In lieu of providing this coverage, the Company made a one-time payment to each retiree based on such retiree’s life insurance coverage and age. The Company paid an aggregate amount of $1,377,000 in such payments. The termination of the retiree life insurance as of July 31, 2006 constitutes a settlement under SFAS 106 which requires that the postretirement benefit obligation be remeasured. This settlement results in a credit to expense that approximates the amount of payments made to retirees and will be reported in the Company’s fourth quarter results in fiscal year 2006.

In a letter dated July 5, 2006, the Company entered into an agreement with John S. Davis, President and Chief Executive Officer, to aid in the transition of his previously announced retirement on June 30, 2007. As part of that agreement, effective July 1, 2007, all options previously granted to Mr. Davis that are then unvested will immediately become vested. Accelerated compensation expense of approximately $34,000 and $103,000 will be recognized in the fourth quarter of fiscal 2006 and in fiscal 2007, respectively, due to the vesting modification of the outstanding options.

19

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 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 increased $0.02 and $0.01 per diluted share for the three- and nine-month periods ended June 30, 2006, respectively, as compared to the same prior-year periods. The increase in earnings for the three- and nine-month periods ended June 30, 2006 was due primarily to increased earnings from Bay Gas’ natural gas storage business and other business operations. These increases were mostly offset by a decline in earnings from Mobile Gas’ distribution 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 $0.08 and $0.15 per diluted share for the three- and nine-month periods ended June 30, 2006 when compared to the same prior year periods due primarily to a decline in consumption from temperature-sensitive customers.

The Company’s natural gas storage business, operated by Bay Gas, contributed increased earnings per share of $0.07 and $0.13 per diluted share for the three- and nine-month periods ended June 30, 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 and short-term storage services and an increase in the amount of interest capitalized during the construction and development of the third underground natural gas storage cavern. A reduction in operating expenses also contributed to the increased earnings during the nine months ended June 30, 2006.

Earnings from other business operations increased $0.03 per diluted share for the three and nine-month periods ended June 30, 2006 as compared to the same prior-year periods, due primarily to an increase in interest income and merchandise sales and related activities.

20

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 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.

Mobile Gas utilizes a Rate Stabilization and Equalization (RSE) tariff which is 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 decreased $350,000 (2%) and increased $9,906,000 (11%) during the three- and nine-month periods ended June 30, 2006 as compared to the same prior-year periods. Rate adjustments to recover increased gas costs paid to suppliers during the three months ended June 30, 2006 were more than offset by a 16% decline in volumes delivered to temperature-sensitive customers. This decline resulted from customer reaction to historically high natural gas prices and from temperatures that were warmer than the same period last year. During the nine months ended June 30, 2006, increased revenues resulting from rate adjustments to recover increased gas costs paid to suppliers were partially offset by a 7% decline

21

in volumes delivered to customers. Revenues during the current-year three- and nine-month periods were also negatively impacted by a decline in the number of temperature-sensitive customers served.

Revenues from the sale of natural gas to large commercial and industrial customers were relatively flat for the three months ended June 30, 2006 and increased $1,929,000 (23%) for the nine-month period ended June 30, 2006. Increased revenues during the three- and nine-month periods due to the rate adjustments noted above were offset by declines of 17% and 8%, respectively, in volumes delivered to customers during the current year periods as a result of the increased price of natural gas.

Revenues from the transportation of natural gas to large commercial and industrial customers decreased $183,000 (10%) and $44,000 (1%) during the three-and nine-month periods ended June 30, 2006 due to a decrease in volumes delivered to such customers.

The cost of natural gas increased $164,000 (2%) and $10,915,000 (25%) for the three- and nine-month periods ended June 30, 2006 as compared to the same prior-year periods due to higher natural gas commodity prices. The increased commodity price of natural gas during the three month period ended June 30, 2006 was mostly offset by the decline in volumes delivered to customers as noted above.

Natural gas distribution margins, defined as revenues less cost of gas and related taxes, declined approximately 6% and 4% during the three- and nine-month periods ended June 30, 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 12% and 11%, respectively, for the three- and nine-month periods ended June 30, 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 June 30, 2006 increased $187,000 (4%) as compared to the same prior year period due primarily to 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 and an increase in expenses incurred to evaluate and select software alternatives for a new customer information system (CIS) to be implemented in fiscal 2007.

O&M expenses for the nine months ended June 30, 2006 approximated the same 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

22

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 offset by an increase in compensation expense recorded for stock options and the expenses related to the CIS software evaluation and selection as discussed above, and an increase in expenses related to the search for a successor for the current President and Chief Executive Officer in connection with his retirement in fiscal 2007.

Depreciation expense increased $70,000 (4%) and $208,000 (4%) for the three- and nine-month periods ended June 30, 2006 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 increased $74,000 (5%) and $601,000 (10%) for the three- and nine-month periods ended June 30, 2006 due primarily to the increased revenues.

Interest expense increased approximately $78,000 and $92,000 for the three- and nine-month periods ended June 30, 2006 as compared to the same prior-year periods due primarily to inter-company 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 decreased slightly during the three-and nine-month periods ended June 30, 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’

23

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, and expansion of these caverns is currently planned to enable them to ultimately hold 7.0 Bcf. Such development will commence following completion of new cavern development 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 entered into multi-year contracts with customers for substantially 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 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 $699,000 (16%) and $885,000 (6%) during the three-and nine-month periods ended June 30, 2006 as compared to the same prior-year periods due primarily to additional revenues derived from new long-term and 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 $83,000 (10%) during the three months ended June 30, 2006 due primarily to an increase in the cavern lease expense resulting from the construction and expansion activities of the third cavern. O&M expenses decreased $229,000 (10%) during the nine-month period ended June 30, 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 nine months ended June 30, 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. These decreases were partially offset by an increase in compensation expense recorded for stock options.

Depreciation expense increased $24,000 (4%) and $83,000 (4%) during the three- and nine-month periods ended June 30, 2006 due to increased investments in property, plant and equipment.

Capitalized interest costs increased $225,000 and $598,000 for the three- and nine-month periods ended June 30, 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 $78,000 (46%) and $164,000 (30%) during the three-and nine-month periods ended June 30, 2006 as compared to the same prior-year periods due to increased pretax earnings of Bay Gas as discussed above.

24

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 approximately $0.03 per diluted share for the three and nine-month periods ended June 30, 2006 as compared to the same prior-year periods due primarily to an increase in interest income and an increase in merchandise sales and related activities.

Income Taxes

Income taxes fluctuate with the change in income before income taxes. Income tax expense increased $28,000 (3%) and $81,000 (1%) for the three- and nine-month periods ended June 30, 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 $4,818,000 during the nine-month period ended June 30, 2006 as compared to the same period last fiscal year due to a decrease in collections of increased gas costs from customers and an increase in 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 and inventory, 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 nine months ended June 30, 2006 and 2005, the Company used cash of $17,921,000 and $8,197,000, respectively, for the construction of distribution and storage facilities, purchases of equipment and other general improvements. During the nine month period ended June 30, 2006, Bay Gas invested $8,246,000 in the ongoing development of a third underground 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 $10,008,000 and $12,076,000 during the nine months ended June 30, 2006 and June 30, 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

25

operations and borrowings under the Company’s revolving credit agreement and the issuance of long-term debt to fund Bay Gas’ construction. At June 30, 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 $1,350,000 are expected to be provided in calendar year 2007 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 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 June 30, 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	$	842	$	5,619	$	5,900	$	6,054	$	59,405
Interest Payments		1,153		6,197		5,732		5,247		24,276
Estimated Future Minimum Payments for Bay Gas Service Fees		75		333		378		423		11,426
Construction Contracts for Bay Gas’ 3rd Cavern Development		2,666		6,429
Implementation of CIS Software		225		2,150		613
Gas Supply Contracts		4,732		5,613		1,187		1,187		2,028
Total	$	9,693	$	26,341	$	13,810	$	12,911	$	97,135

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.

26

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 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.

27

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 June 30, 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 June 30, 2006 the Company had approximately $77.8 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

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 June 30, 2006. 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

28

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 June 30, 2006, that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II. OTHER INFORMATION

Item 5. Other Information

On July 28, 2006, EnergySouth, Inc. (the “Company”) issued a press release announcing earnings for the three and nine months ended June 30, 2006, the declaration of a dividend on outstanding Common Stock and the election of a new Chief Executive Officer. 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.

29

PART II. OTHER INFORMATION

Item 6. Exhibits

Exhibit No.	Description
10(w)	Storage Service Agreement by and between Bay Gas Storage Company, Ltd. and Florida Power Corporation d/b/a Progress Energy Florida, Inc. made as of the 19th day of April, 2006(1)
10(y)	Storage Service Agreement by and between Bay Gas Storage Company, Ltd. and Constellation Energy Commodities Group, Inc. made as of the 23rd day of May, 2006(1)
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 July 28, 2006

(1) Confidential portions of this exhibit have been omitted and previously filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment made in accordance with Rule 24b-2 promulgated under the Securities and Exchange Act of 1934, as amended.

30

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: July 31, 2006	/s/ John S. DavisJohn S. Davis
	President and
	Chief Executive Officer
Date: July 31, 2006	/s/ Charles P. HuffmanCharles P. Huffman
	Senior Vice President and
	Chief Financial Officer

31