EnergySouth (ENSI) 10-Q 2005 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, 2005

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
(Address of principal executive office) 36606
(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 an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yesþ Noo

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, 2005 – 7,860,299 shares.

ENERGYSOUTH, INC.
FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2005

INDEX

		Page No.
	PART I: FINANCIAL INFORMATION
Item 1	Financial Statements:
(a)	Unaudited Condensed Consolidated Balance Sheets June 30, 2005 and 2004 and September 30, 2004		3 - 4
(b)	Unaudited Condensed Consolidated Statements of Income Three and Nine Months Ended June 30, 2005 and 2004		5
(c)	Unaudited Condensed Consolidated Statements of Cash Flows Nine Months Ended June 30, 2005 and 2004		6
(d)	Notes to Unaudited Condensed Consolidated Financial Statements		7 - 17
Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations		18 - 24
Item 3	Quantitative and Qualitative Disclosures About Market Risk		25
Item 4	Controls and Procedures		25 - 26
	PART II: OTHER INFORMATION
Item 5	Other Information		27
Item 6	Exhibits		27
Certification Pursuant to Section 302 - CEO
Certification Pursuant to Section 302 - CFO
Certification Pursuant to Section 906 - CEO
Certification Pursuant to Section 906 - CFO

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PART 1. FINANCIAL INFORMATION

ITEM 1: FINANCIAL STATEMENTS

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

EnergySouth, Inc.	June 30,							September 30,
In Thousands	2005			2004				2004
	(Unaudited)
ASSETS
Current Assets
Cash and Cash Equivalents	$	15,184		$	10,739			$	9,464
Receivables
Gas		7,824			7,671				6,394
Unbilled Revenue		1,589			1,630				1,143
Merchandise		2,197			2,281				2,249
Other		1,183			1,011				1,273
Allowance for Doubtful Accounts		(1,934	)		(1,889	)			(856	)
Materials, Supplies, and Merchandise, net (At Average Cost)		1,359			1,229				1,524
Gas Stored Underground (At Average Cost)		5,508			3,330				4,235
Regulatory Assets		323			2,895		��		3,606
Deferred Income Taxes		2,285			766				434
Prepayments		2,089			2,003				1,731
Total Current Assets		37,607			31,666				31,197
Property, Plant, and Equipment		279,534			272,625				274,789
Less: Accumulated Depreciation and Amortization		76,236			68,678				70,417
Property, Plant, and Equipment — net		203,298			203,947				204,372
Construction Work in Progress		2,933			201				225
Total Property, Plant, and Equipment		206,231			204,148				204,597
Other Assets
Prepaid Pension Cost		957			1,068				1,102
Deferred Charges		616			560				567
Prepayments		913			972				957
Regulatory Assets		415			742				660
Merchandise Receivables Due After One Year		3,161			3,421				3,374
Total Other Assets		6,062			6,763				6,660
Total	$	249,900		$	242,577			$	242,454

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

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UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

EnergySouth, Inc.	June 30,						September 30,
In Thousands, Except Share Data	2005			2004			2004
	(Unaudited)
LIABILITIES AND CAPITALIZATION
Current Liabilities
Current Maturities of Long-Term Debt	$	5,160		$	6,208		$	6,248
Accounts Payable		6,666			5,224			5,278
Dividends Declared		1,676			1,562			1,561
Customer Deposits		1,277			1,469			1,618
Taxes Accrued		3,499			3,121			2,312
Interest Accrued		463			521			1,122
Regulatory Liabilities		5,668			4,457			4,637
Other		1,302			986			998
Total Current Liabilities		25,711			23,548			23,774
Other Liabilities
Accrued Postretirement Benefit Cost		684			337			513
Deferred Income Taxes		23,534			20,919			21,378
Deferred Investment Tax Credits		247			275			262
Regulatory Liabilities		12,380			11,603			11,788
Other		1,570			1,558			1,413
Total Other Liabilities		38,415			34,692			35,354
		64,126			58,240			59,128
Capitalization
Stockholders’ Equity
Common Stock, $.01 Par Value (Authorized 20,000,000 Shares; Outstanding June 2005 - 7,855,000; June 2004 - 7,811,000; September 2004 - 7,827,000 Shares)		78			78			78
Capital in Excess of Par Value		26,835			25,818			26,162
Retained Earnings		75,377			68,368			67,625
Grantor Trust, at cost		(1,485	)		(1,315	)		(1,355	)
Deferred Compensation Liability		1,485			1,315			1,355
Total Stockholders’ Equity		102,290			94,264			93,865
Minority Interest		5,063			4,592			4,769
Long-Term Debt		78,421			85,481			84,692
Total Capitalization		185,774			184,337			183,326
Total	$	249,900		$	242,577		$	242,454

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

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UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF INCOME

	Three Months						Nine Months
ENERGYSOUTH, INC.	Ended June 30,						Ended June 30,
In Thousands, Except Per Share Data	2005			2004			2005			2004
Operating Revenues
Gas Revenues	$	21,362		$	20,003		$	99,224		$	93,093
Merchandise Sales		672			663			2,558			2,382
Other		316			330			1,035			1,083
Total Operating Revenues		22,350			20,996			102,817			96,558
Operating Expenses
Cost of Gas		6,984			6,098			40,310			35,859
Cost of Merchandise		605			522			2,174			1,872
Operations and Maintenance		6,289			6,040			19,485			19,386
Depreciation		2,544			2,439			7,640			7,308
Taxes, Other Than Income Taxes		1,735			1,694			7,071			6,744
Total Operating Expenses		18,157			16,793			76,680			71,169
Operating Income		4,193			4,203			26,137			25,389
Other Income (Expense)
Interest Expense		(1,805	)		(1,958	)		(5,518	)		(5,979	)
Allowance for Borrowed Funds Used During Construction		49			4			62			16
Interest Income		103			21			177			35
Minority Interest		(203	)		(188	)		(649	)		(583	)
Total Other Income (Expense)		(1,856	)		(2,121	)		(5,928	)		(6,511	)
Income Before Income Taxes		2,337			2,082			20,209			18,878
Income Taxes		880			784			7,641			7,139
Net Income	$	1,457		$	1,298		$	12,568		$	11,739
Earnings Per Share
Basic	$	0.19		$	0.17		$	1.60		$	1.52
Diluted	$	0.18		$	0.16		$	1.58		$	1.50
Average Common Shares Outstanding
Basic		7,854			7,803			7,843			7,745
Diluted		7,947			7,896			7,945			7,838

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

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UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Nine Months
EnergySouth, Inc.	Ended June 30,
In Thousands	2005			2004
Cash Flows from Operating Activities
Net Income	$	12,568		$	11,739
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
Depreciation and Amortization		7,915			7,596
Provision for Losses on Receivables and Inventory		967			1,096
Provision for Deferred Income Taxes		307			2,123
Minority Interest		649			583
Changes in Operating Assets and Liabilities:
Receivables		(1,570	)		(1,046	)
Inventory		(1,091	)		549
Payables		842			(1,817	)
Taxes		1,186			1,932
Deferred Purchased Gas Adjustment		4,037			(4	)
Other		716			725
Net Cash Provided by Operating Activities		26,526			23,476
Cash Flows from Investing Activites
Capital Expenditures		(8,730	)		(5,862	)
Net Cash Used in Investing Activities		(8,730	)		(5,862	)
Cash Flows from Financing Activites
Repayment of Long-Term Debt		(7,359	)		(6,956	)
Changes in Short-Term Borrowings		—			(250	)
Payment of Dividends		(4,816	)		(4,485	)
Dividend Reinvestment		307			274
Exercise of Stock Options		147			592
Partnership Distributions to Minority Interest Holders		(355	)		(132	)
Net Cash Used in Financing Activities		(12,076	)		(10,957	)
Net Increase in Cash and Cash Equivalents		5,720			6,657
Cash and Cash Equivalents at Beginning of Period		9,464			4,082
Cash and Cash Equivalents at End of Period	$	15,184		$	10,739

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); 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, 2004. 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 nine-month periods ended June 30, 2005 and 2004 are not indicative of the results to be expected for the full year.

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The table below summarizes operating results for the twelve months ended June 30, 2005 and 2004:

	Twelve Months
EnergySouth, Inc.	Ended June 30,
In Thousands, Except Per Share Data	2005			2004
Operating Revenues	$	122,231		$	114,273
Cost of Gas		45,854			40,080
Cost of Merchandise		2,884			2,403
Operations and Maintenance Expense		25,319			24,811
Depreciation Expense		10,044			9,401
Taxes, Other Than Income Taxes		8,586			8,092
Operating Income		29,544			29,486
Interest Expense		(7,436	)		(8,025	)
Allowance for Borrowed Funds Used During Construction		66			68
Interest Income		202			49
Less: Minority Interest		(871	)		(773	)
Income Before Income Taxes	$	21,505		$	20,805
Income Taxes		8,107			7,850
Net Income	$	13,398		$	12,955
Earnings Per Share
Basic	$	1.71		$	1.68
Diluted	$	1.69		$	1.66
Average Common Shares Outstanding
Basic		7,837			7,730
Diluted		7,936			7,823

Note 3. Stock-Based Compensation

The Company currently accounts for its employee 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 related interpretations. As stock options have been issued with exercise prices equal to the market value of the underlying shares on the grant date, no compensation cost has been recognized.

Had compensation cost for the plans been determined based on the fair value of the options on the grant date, consistent with Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation,” the Company’s net income and earnings per share would have been as follows:

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	Three Months				Nine Months
EnergySouth, Inc.	Ended June 30,				Ended June 30,
In Thousands, Except per Share Data	2005		2004		2005		2004
Net Income, as reported	$	1,457	$	1,298	$	12,568	$	11,739
Deduct:
Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		55		47		149		134
Pro forma net income	$	1,402	$	1,251	$	12,419	$	11,605
Earnings per share:
Basic — as reported	$	0.19	$	0.17	$	1.60	$	1.52
Basic — pro forma	$	0.18	$	0.16	$	1.58	$	1.50
Diluted — as reported	$	0.18	$	0.16	$	1.58	$	1.50
Diluted — pro forma	$	0.18	$	0.16	$	1.56	$	1.48

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:

	Pension						Postretirement
	Benefits						Benefits
For the three months ended June 30, (in thousands)	2005			2004			2005			2004
Service cost	$	215		$	214		$	43		$	29
Interest cost		445			391			79			62
Amortization of transition asset					(32	)
Amortization of prior service cost		24			24			(11	)		(11	)
Amortization of unrecognized gain/(loss)					(32	)		15			3
Expected return on plan assets		(643	)		(645	)		(68	)		(71	)
Net periodic benefit cost (credit)	$	41		$	(80	)	$	58		$	12

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	Pension						Postretirement
	Benefits						Benefits
For the nine months ended June 30, (in thousands)	2005			2004			2005			2004
Service cost	$	646		$	643		$	128		$	88
Interest cost		1,335			1,172			236			187
Amortization of transition asset					(96	)
Amortization of prior service cost		71			71			(33	)		(33	)
Amortization of unrecognized gain/(loss)					(96	)		44			9
Expected return on plan assets		(1,929	)		(1,934	)		(204	)		(212	)
Net periodic benefit cost (credit)	$	123		$	(240	)	$	171		$	39

For fiscal year 2005, 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.

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 for an additional five year period. 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 utilities. Rate adjustments, designed to increase annual gas revenues by approximately $1.7 million, $2.8 million, and $2.2 million, were implemented under the RSE tariff effective December 1, 2004, 2003, and 2002, respectively. 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. 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

10

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 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 $944,000 at June 30, 2005 is included in the balance sheet of the Unaudited Condensed Consolidated Financial Statements as part of Regulatory Liabilities.

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. As described above, Mobile Gas’ rates are established under the RSE rate setting process and are based on average equity for the period. Mobile Gas’ rates are not adjusted to exclude a return on its investment in regulatory assets during the recovery period.

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

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	June 30,				June 30,				September 30,
	2005				2004				2004
	Current		Noncurrent		Current		Noncurrent		Current		Noncurrent
Assets
Deferred Purchase Gas Adjustment					$	2,537			$	3,269
ESR Fund	$	167	$	375		167	$	542		167	$	500
Bad Debt Reserve		133		33		133		166		133		133
Other		23		7		58		34		37		27
Regulatory Assets	$	323	$	415	$	2,895	$	742	$	3,606	$	660
Liabilities
Bad Debt Reserve	$	5			$	25	$	5	$	20
ESR Fund		944				854				854
Deferred Investment Tax Credit		15	$	125		15		141		15	$	136
RSE Adjustment		16								343
Gross Receipt Tax Collections		3,920				3,563				3,405
Deferred Purchase Gas Adjustment		768
Asset Retirement Obligations				12,255				11,457				11,652
Regulatory Liabilities	$	5,668	$	12,380	$	4,457	$	11,603	$	4,637	$	11,788

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, 2005 and 2004, the net acquisition adjustments were $5,863,000 and $6,245,000, respectively, and the balance at September 30, 2004 was $6,137,000.

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				Nine Months
EnergySouth, Inc.	Ended June 30,				Ended June 30,
In Thousands	2005		2004		2005		2004
Weighted Average Common Shares		7,854		7,803		7,843		7,745
Effect of Dilutive Securities:
Options to Purchase Common Stock		93		93		102		93
Diluted Average Common Shares		7,947		7,896		7,945		7,838

Stock option awards to purchase approximately 76,000 shares and 74,000 shares as of June 30, 2005 and 2004, respectively, were not included in the computation of diluted earnings per share because inclusion of these shares would have been antidulitive as the option exercise prices were greater than the shares market prices during these periods.

On July 30, 2004, the Board of Directors of EnergySouth declared a three-for-two split of outstanding common stock whereby one additional share was issued for each two shares held as of the record date of August 16, 2004. The new shares were issued to shareholders on September 1, 2004 with cash paid in lieu of fractional shares resulting from the split. Common stock began trading on the post split basis on September 2, 2004. All references to number of shares and per share amounts have been restated to reflect the three-for-two stock split.

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
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	)
Allowance for Borrowed Funds Used During Construction		7			42									49
Less: Minority Interest		(33	)		(170	)								(203	)
Income Before Income Taxes	$	599		$	1,684		$	54					$	2,337

For the three months ended	Natural Gas			Natural Gas
June 30, 2004 (in thousands):	Distribution			Storage			Other			Eliminations			Consolidated
Operating Revenues	$	16,667		$	4,372		$	993		$	(1,036	)	$	20,996
Cost of Gas		7,134									(1,036	)		6,098
Cost of Merchandise								522						522
Operations and Maintenance Expense		4,982			695			363						6,040
Depreciation Expense		1,828			611									2,439
Taxes, Other Than Income Taxes		1,436			246			12						1,694
Operating Income		1,287			2,820			96						4,203
Interest Income		10			11									21
Interest Expense		(825	)		(1,114	)		(19	)					(1,958	)
Allowance for Borrowed Funds Used During Construction		4												4
Less: Minority Interest		(29	)		(159	)								(188	)
Income Before Income Taxes	$	447		$	1,558		$	77					$	2,082

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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	)
Allowance for Borrowed Funds Used During Construction		11			51									62
Less: Minority Interest		(98	)		(551	)								(649	)
Income Before Income Taxes	$	14,527		$	5,435		$	247					$	20,209

For the nine months ended	Natural Gas			Natural Gas
June 30, 2004 (in thousands):	Distribution			Storage			Other			Eliminations			Consolidated
Operating Revenues	$	83,153		$	13,087		$	3,465		$	(3,147	)	$	96,558
Cost of Gas		39,006									(3,147	)		35,859
Cost of Merchandise								1,872						1,872
Operations and Maintenance Expense		15,871			2,223			1,292						19,386
Depreciation Expense		5,484			1,824									7,308
Taxes, Other Than Income Taxes		6,049			646			49						6,744
Operating Income		16,743			8,394			252						25,389
Interest Income		14			30						(9	)		35
Interest Expense		(2,457	)		(3,378	)		(153	)		9			(5,979	)
Allowance for Borrowed Funds Used During Construction		16												16
Less: Minority Interest		(117	)		(466	)								(583	)
Income Before Income Taxes	$	14,199		$	4,580		$	99					$	18,878

Note 8. Contingencies

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 ofF 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

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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 December 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 153, “Exchanges of Nonmonetary Assets — an amendment of APB Opinion No. 29” (SFAS 153). SFAS 153 eliminates the exception to fair value for exchanges of similar productive assets and replaces it with a general exception for exchange transactions that do not have commercial substance; that is, transactions that are not expected to result in significant changes in the cash flows of the reporting entity. SFAS 153 became effective for the Company beginning July 1, 2005 and did not have an impact on the Company’s financial statements.

In December 2004, the FASB issued Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (SFAS 123R) which eliminates the alternative to use APB Opinion 25’s intrinsic value method of accounting that was provided in Statement 123 as originally issued. SFAS 123R requires entities to recognize the cost of employee services received in exchange for awards of equity instruments based on the grant-date fair value of those awards. The Company accounts for its employee stock option plans under the intrinsic value recognition and measurement provisions of Opinion 25 and discloses the effect on net income and earnings per share had compensation cost for the plans been determined based on the fair value of the options on the grant date. See Note 3 to the Unaudited Condensed Consolidated Financial Statements. The Company is currently evaluating the effects of the transition to the fair value method as required in SFAS 123R, which will be effective for the Company beginning October 1, 2005 based on the Securities and Exchange Commission’s announcement dated April 14, 2005.

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

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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 adoption of FIN 47 will not have an impact on the Company’s 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 periods 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 Event

In October 2000, the Corus Group plc (Corus, formerly known as British Steel) ceased operations of their Mobile plant facility and has been paying Mobile Gas a minimum annual payment as required under the terms of their 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, Mobile Gas will receive $6,100,000 with $4,750,000 to be paid in fiscal 2006 and the final payment of $1,350,000 due October 1, 2006. Mobile Gas will petition the APSC for approval to recognize the payments as a regulatory liability and amortize the balance into income over the remaining years of the original contract term.

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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 and nine months ended June 30, 2005 increased $0.02 and $0.08, respectively, per diluted share as compared to the same prior-year periods. The increase in earnings for the three-month period ended June 30, 2005 was due to increased earnings from Mobile Gas’ natural gas distribution system and Bay Gas’ natural gas storage business. All segments contributed to the increase in earnings per share during the nine-month period ended June 30, 2005. Financial information by business segment is shown in Note 7 to the Unaudited Condensed Consolidated Financial Statements above.

Earnings from the Company’s natural gas distribution business increased $0.01 per diluted share for the three and nine-month periods ended June 30, 2005 as compared to the same prior-year periods.

The Company’s natural gas storage business, operated by Bay Gas, contributed increased earnings per share of $0.01 and $0.06 per diluted share for the three and nine-month periods ended June 30, 2005 as compared to the same prior-year periods. The positive earnings contributions are due primarily to additional storage revenues associated with long and short-term storage agreements.

Earnings from other business operations were flat for the three-month period ended June 30, 2005 and increased $0.01 per diluted share for the nine-month period ended June 30, 2005, as compared to the same prior-year periods, due primarily to an increase in interest income.

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

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to customers the cost of gas, certain taxes, and incremental costs associated with the replacement of cast iron mains. 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.

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 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. 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.

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 $1,283,000 (8%) and $5,238,000 (6%), respectively, during the three and nine-month periods ended June 30, 2005 as compared to the same prior-year periods due to the rate adjustments to recover increased gas costs paid to suppliers and the RSE rate adjustments which went into effect on December 1, 2004 and 2003. The increase in revenues during the three and nine-month periods were partially offset by declines of 3% and 13%, respectively, in volumes delivered to temperature-sensitive customers due to temperatures that were 16% warmer than the nine-month period last year. A decline in the number of temperature-sensitive customers served during the current year periods also contributed to the offset.

Revenues from the sale of natural gas to large commercial and industrial customers increased $337,000 (17%) and $1,809,000 (27%), respectively, for the three and nine-month periods ended June 30, 2005 due to 4% and 8% increases in volumes delivered to these customers in the three and nine-month periods, respectively, and the rate adjustments noted above.

Revenues from the transportation of natural gas to large commercial and industrial customers during the three and nine-month periods ended June 30, 2005 were approximately the same as in the comparable prior-year periods.

The cost of natural gas increased $914,000 (13%) and $4,455,000 (11%) for the three and nine-month periods ended June 30, 2005 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, increased for the three and nine-month periods ended June 30, 2005 as compared to the

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same prior-year periods due primarily to the rate adjustments and increased sales to large commercial and industrial customers.

Increased margins realized from the rate adjustments effective December 1, 2003 and 2004 were largely offset by a decline in the number of temperature-sensitive customers served and a decline in usage per degree day by temperature-sensitive customers during the current year periods. Mobile Gas utilizes a temperature adjustment rider on gas sales to residential and small commercial/industrial customers during the months of November through April to mitigate the impact that warmer or colder than normal weather has on earnings. Temperature-sensitive margins realized during the current year periods were, in fact, lower than the prior-year due to a decrease in residential customers’ gas consumption per heating degree-day. Consistent with other natural gas distribution companies in the United States, Mobile Gas has over time experienced declines in residential customer usage per degree-day as customers replace old appliances with new, more energy efficient models and as new, more energy efficient homes are built. During the prior-year periods, residential customers’ usage deviated from this pattern and was unusually high. However, during the nine months ended June 30, 2005, the decline in consumption by these customers reflected the declining trend in customer consumption as experienced in recent years. 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 increased $199,000 (4%) and $152,000 (1%) for the three and nine months ended June 30, 2005 due to accruals to restore the ESR reserve to its former balance, additional audit fees associated with the review and testing of the Company’s internal controls in compliance with Section 404 of the Sarbanes-Oxley Act of 2002, and increased payroll-related benefit costs.

Depreciation expense increased $97,000 (5%) and $293,000 (5%), respectively, for the three and nine-month periods ended June 30, 2005 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 $48,000 (3%) and $272,000 (5%), respectively, for the three and nine-month periods ended June 30, 2005 due primarily to the increased revenues.

Interest expense decreased $123,000 (15%) and $245,000 (10%) for the three and nine-month periods ended June 30, 2005 as compared to the same prior-year periods due 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 was flat for the three months ended June 30, 2005 as compared to the same prior-year period and decreased slightly during the nine-month period ended June 30, 2005 due to a decline in pretax earnings of the partnership.

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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, which remains pending.

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 occur pending certain operational considerations.

With the current working capacity of both caverns fully subscribed, Bay Gas held a non-binding “open season” in fiscal 2004 to assess interest for up to 5.0 Bcf of additional working capacity. Based on the response to the open season, Bay Gas recently completed design, engineering, and site work on a third storage cavern and related facilities and has entered into multi-year contract agreements with customers for a substantial portion of the cavern. Development of the third cavern is currently expected to begin in August 2005. The new cavern is designed to add 5.0 Bcf of working gas capacity and is anticipated to be in service by 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 storage 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 $104,000 (2%) during the three-month period ended June 30, 2005 as compared to the same prior-year period due primarily to additional revenues derived from a new long-term storage agreement. Revenues increased $897,000 (7%) during the nine-month period ended June 30, 2005 as compared to the same prior year period due primarily to long and short-term storage agreements entered into during fiscal 2005. Under the short-term agreements, available storage capacity is leased to customers on an interruptible basis, thereby optimizing the use of cavern capacity.

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Operations and maintenance (O&M) expenses increased $99,000 (14%) and $159,000 (7%), respectively, during the three and nine-month periods ended June 30, 2005 as compared to the same prior-year periods due to increases in operating costs as a result of the expansion activities of Bay Gas.

Other taxes were flat for the three-month period ended June 30, 2005 as compared to the same prior year period. Other taxes increased $50,000 (8%) for the nine months ended June 30, 2005 as a combined result of increased revenues associated with the expanded operations of Bay Gas’ second storage cavern and the increase in the assessed value of Bay Gas’ property, plant, and equipment due to the completion of the second 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 $11,000 (7%) and $85,000 (18%), respectively, during the three and nine-month periods ended June 30, 2005 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 remained flat for the three-month period ended June 30, 2005 as compared to the same prior-year period. During the nine-month period ended June 30, 2005 income before income taxes increased $148,000 as compared to the same prior year period due primarily to interest income earned from temporary investments.

Income Taxes

Income taxes fluctuate with the change in income before income taxes. Income tax expense increased $96,000 (12%) and $502,000 (7%), respectively, for the three and nine-month periods ended June 30, 2005 as compared to the same prior-year period.

Liquidity and Capital Resources

The Company generally relies on cash generated from operations and, on a temporary basis, short-term borrowings, to meet working capital requirements and to finance normal capital expenditures. The Company issues debt and equity for longer term financing as needed. Impacts of operating, investing, and financing activities are shown on the Unaudited Condensed Consolidated Statements of Cash Flows. Cash provided by operating activities increased $3,050,000 during the nine-month period ended June 30, 2005 as compared to the same period last fiscal year due primarily to collections of increased gas costs from customers, an increase in net income, and an increase in payables. Partially offsetting the above positive impacts on cash flow from operating activities was an increase in gas

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inventory stored underground and a decrease in deferred income tax expense. See Natural Gas Distribution section for additional information regarding the pass-through to customers of the cost of gas.

Cash used in investing activities reflects the capital-intensive nature of the Company’s business. During the nine months ended June 30, 2005 and 2004, the Company used cash of $8,730,000 and $5,862,000, respectively, for the construction of distribution and storage facilities, purchases of equipment and other general improvements. The Company plans that the construction of Bay Gas’ third natural gas storage cavern, which is currently scheduled to commence in August 2005 at a total cost of up to $58,000,000, will be funded through the issuance of long-term debt and from internal cash.

Financing activities used cash of $12,076,000 and $10,957,000 during the nine months ended June 30, 2005 and 2004, respectively. The additional cash used in financing activities was due to an increase in dividends, partnership distributions, and principal payments on long-term debt.

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 June 30, 2005, 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. 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, 2004 and Item 3 below for further information.

The table below summarizes the Company’s contractual obligations and commercial commitments as of June 30, 2005:

	Remaining								Fiscal Years
Type of Contractual	Fiscal Year		Fiscal Year		Fiscal Year		Fiscal Year		2009 and
Obligations (in thousands):	2005		2006		2007		2008		thereafter
Long-Term Debt	$	789	$	5,213	$	5,019	$	5,300	$	67,260
Interest Payments		1,220		6,656		6,242		5,822		31,722
Gas Supply Contracts		3,443		6,693		1,187		1,187		3,215

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

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Company for the fiscal year ended September 30, 2004.

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, 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 June 30, 2005, 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 will not affect future earnings or cash flows.

At June 30, 2005 the Company had approximately $83.6 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, 2004 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.

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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

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:August 9, 2005	/s/ John S. Davis
	John S. Davis
	President and Chief Executive Officer Chief
Date:August 9, 2005	/s/ Charles P. Huffman
	Charles P. Huffman
	Senior Vice President and Chief Financial Officer

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