EnergySouth (ENSI) 10-Q 2008 Q1 Quarterly report

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

Form 10-Q

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

For Quarter Ended December 31, 2007

Commission File No. 0-29604

ENERGYSOUTH, INC.

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)	58-2358943 (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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o	Accelerated filer þ	Non-accelerated filer o	Smaller reporting company o
	(Do not check if a smaller reporting company)

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 February 7, 2008 — 8,099,831 shares.

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

INDEX

			Page No.
		PART I: FINANCIAL INFORMATION
Item 1		Financial Statements:
	(a)	Unaudited Condensed Consolidated Balance Sheets December 31, 2007 and 2006 and September 30, 2007	3 - 4
	(b)	Unaudited Condensed Consolidated Statements of Income Three Months Ended December 31, 2007 and 2006	5
	(c)	Unaudited Condensed Consolidated Statements of Cash Flows Three Months Ended December 31, 2007 and 2006	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 - 28
Item 3		Quantitative and Qualitative Disclosures About Market Risk	28 - 30
Item 4		Controls and Procedures	30
		PART II: OTHER INFORMATION
Item 1A		Risk Factors	31
Item 4		Submission of Matters to a Vote of Security Holders	31
Item 5		Other Information	32
Item 6		Exhibits	32
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

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PART 1. FINANCIAL INFORMATION

ITEM 1: FINANCIAL STATEMENTS

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

EnergySouth, Inc.	December 31,						September 30,
In Thousands	2007			2006			2007
	(Unaudited)
ASSETS
Current Assets
Cash and Cash Equivalents	$	7,943		$	288		$	336
Restricted Cash		48,445			1,742			47,995
Cash Held on Deposit in Margin Account		780						999
Receivables
Gas		11,817			13,823			10,106
Unbilled Revenue		5,814			4,868			1,499
Merchandise		1,868			2,145			1,926
Other		472			662			780
Allowance for Doubtful Accounts		(907	)		(1,427	)		(1,047	)
Materials, Supplies, and Merchandise, net (At Average Cost)		1,262			1,373			1,376
Gas Stored Underground (At Average Cost)		13,746			6,401			8,069
Regulatory Assets		6,838			2,452			5,015
Deferred Income Taxes		55			469
Prepaid Taxes		3,472			1,092			2,088
Prepayments		2,639			1,462			3,320
Other		1,178						333
Total Current Assets		105,422			35,350			82,795
Property, Plant, and Equipment		351,053			299,564			311,249
Less: Accumulated Depreciation and Amortization		96,552			88,093			94,025
Property, Plant, and Equipment — Net		254,501			211,471			217,224
Construction Work in Progress		178,015			20,897			53,287
Total Property, Plant, and Equipment		432,516			232,368			270,511
Other Assets
Prepaid Pension Cost		11,908			800			11,827
Prepaid Postretirement Benefit		1,608			573			1,587
Deferred Charges		1,057			413			1,093
Prepayments		2,821			1,128			1,568
Regulatory Assets		27			151			27
Merchandise Receivables Due After One Year		2,832			3,110			3,038
Total Other Assets		20,253			6,175			19,140
Total	$	558,191		$	273,893		$	372,446

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

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UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

EnergySouth, Inc.	December 31,						September 30,
In Thousands, Except Share Data	2007			2006			2007
	(Unaudited)
LIABILITIES AND CAPITALIZATION
Current Liabilities
Current Maturities of Long-Term Debt	$	5,966		$	5,680		$	5,900
Notes Payable		142,100			7,375			12,300
Accounts Payable		19,793			12,992			30,835
Dividends Declared		2,023			1,830			2,010
Customer Deposits		1,095			1,285			1,139
Taxes Accrued		2,748			1,788			3,752
Interest Accrued		1,376			593			1,031
Regulatory Liabilities		5,526			7,646			6,017
Deferred Income Taxes		1,732						741
Other		2,036			1,067			1,456
Total Current Liabilities		184,395			40,256			65,181
Other Liabilities
Deferred Income Taxes		29,553			25,692			28,748
Deferred Investment Tax Credits		191			211			196
Regulatory Liabilities		22,008			9,669			21,892
Asset Retirement Obligation		6,283			5,818			6,188
Other		2,098			1,408			1,566
Total Other Liabilities		60,133			42,798			58,590
		244,528			83,054			123,771
Capitalization
Stockholders’ Equity Common Stock, $.01 Par Value (Authorized 20,000,000 Shares; Outstanding December 2007 — 8,095,000; December 2006 — 7,957,000; September 2007 — 7,986,000 Shares)		81			80			80
Capital in Excess of Par Value		34,479			29,555			30,852
Retained Earnings		92,361			84,704			90,298
Accumulated Other Comprehensive Income (Loss), net of tax		192						22
Grantor Trust, at cost		(1,348	)		(1,792	)		(1,362	)
Deferred Compensation Liability		1,348			1,792			1,362
Total Stockholders’ Equity		127,113			114,339			121,252
Minority Interest		67,061			6,045			6,962
Long-Term Debt		119,489			70,455			120,461
Total Capitalization		313,663			190,839			248,675
Total	$	558,191		$	273,893		$	372,446

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

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UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF INCOME

	Three Months
ENERGYSOUTH, INC.	Ended December 31,
In Thousands, Except Per Share Data	2007			2006
Operating Revenues
Gas Revenues	$	34,642		$	37,659
Merchandise Sales		941			960
Other		289			311
Total Operating Revenues		35,872			38,930
Operating Expenses
Cost of Gas		13,009			16,432
Cost of Merchandise		779			749
Operations and Maintenance		8,477			7,356
Depreciation		3,181			2,762
Taxes, Other Than Income Taxes		2,494			2,633
Total Operating Expenses		27,940			29,932
Operating Income		7,932			8,998
Other Income and (Expense)
Interest Expense		(3,347	)		(1,679	)
Allowance for Borrowed Funds Used During Construction		1,623			358
Interest Income		408			18
Minority Interest		(44	)		(274	)
Total Other Income (Expense)		(1,360	)		(1,577	)
Income Before Income Taxes		6,572			7,421
Income Taxes		2,485			2,807
Net Income	$	4,087		$	4,614
Earnings Per Share
Basic	$	0.51		$	0.58
Diluted	$	0.50		$	0.57
Average Common Shares Outstanding
Basic		8,090			7,954
Diluted		8,183			8,031

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

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UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Three Months
EnergySouth, Inc.	Ended December 31,
In Thousands	2007			2006
Cash Flows from Operating Activities
Net Income	$	4,087		$	4,614
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
Depreciation and Amortization		3,275			2,860
Provision for Losses on Receivables and Inventory		360			295
Provision for Deferred Income Taxes		1,791			418
Minority Interest		44			274
Stock-Based Employee Compensation Expense		114			158
Changes in Operating Assets and Liabilities:
Cash Held in Margin Account		219
Receivables		(5,956	)		(11,411	)
Inventory		(5,562	)		356
Payables		(11,287	)		5,658
Taxes		(2,547	)		317
Deferred Purchased Gas Adjustment		(1,188	)		(370	)
Other		(207	)		2,581
Net Cash Provided (Used) by Operating Activities		(16,857	)		5,750
Cash Flows from Investing Activites
Capital Expenditures		(164,763	)		(6,357	)
Changes in Restricted Cash		(450	)
Net Cash Used in Investing Activities		(165,213	)		(6,357	)
Cash Flows from Financing Activites
Repayment of Long-Term Debt		(905	)		(844	)
Debt Issuance Costs		(1,137	)
Changes in Short-Term Borrowings		129,800			2,075
Payment of Dividends		(1,924	)		(1,830	)
Dividend Reinvestment		86			86
Exercise of Stock Options		2,329			116
Excess Tax Benefits from Share Based Payments		1,098			43
Capital Contributions		60,356
Partnership Distributions to Minority Interest Holders		(26	)		(23	)
Net Cash Provided (Used) by Financing Activities		189,677			(377	)
Net Increase (Decrease) in Cash and Cash Equivalents		7,607			(984	)
Cash and Cash Equivalents at Beginning of Period		336			1,272
Cash and Cash Equivalents at End of Period	$	7,943		$	288
Noncash Transactions from Investing Activities:
Accruals for Capital Expenditures	$	3,615		$	1,324

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1. Principles of Consolidation

The consolidated financial statements of EnergySouth, Inc. (EnergySouth) and its subsidiaries (collectively, the Company) include the accounts of Mobile Gas Service Corporation (Mobile Gas); EnergySouth Midstream, Inc. (Midstream); EnergySouth Services, Inc. (Services); a 90.9% owned limited partnership, Bay Gas Storage Company, Ltd. (Bay Gas); a 60% ownership interest in Mississippi Hub, LLC (Mississippi Hub); 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, Mississippi Hub 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, 2007. 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-month periods ended December 31, 2007 and 2006 are not indicative of the results to be expected for the full year.

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

	Twelve Months
EnergySouth, Inc.	Ended December 31,
In Thousands, Except Per Share Data	2007			2006
Operating Revenues	$	131,975		$	129,985
Cost of Gas		45,750			50,625
Cost of Merchandise		2,714			2,940
Operations and Maintenance Expense		32,390			27,082
Depreciation Expense		11,436			10,723
Taxes, Other Than Income Taxes		8,953			9,113
Operating Income		30,732			29,502
Interest Expense		(9,041	)		(6,755	)
Allowance for Borrowed Funds Used During Construction		3,557			1,194
Interest Income		691			109
Less: Minority Interest		(1,092	)		(1,149	)
Income Before Income Taxes	$	24,847		$	22,901
Income Taxes		9,341			8,736
Net Income	$	15,506		$	14,165
Earnings Per Share
Basic	$	1.94		$	1.78
Diluted	$	1.91		$	1.77
Average Common Shares Outstanding
Basic		8,006			7,936
Diluted		8,104			7,997

Note 3. Stock-Based Compensation

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

Effective October 1, 2005, the Company adopted SFAS 123R on a modified prospective basis. Under this method, the Company records compensation cost, on a prospective basis, for the portion of outstanding awards for which the requisite service has not yet been rendered as of October 1, 2005 based upon the grant-date fair value of those awards. Total stock-based compensation expense for stock option grants recognized during the three months ended December 31, 2007 and 2006 was $114,000 and $158,000, respectively. The income tax benefit recognized in the income statement for these stock options during the three months ended

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December 31, 2007 and 2006 was approximately $43,000 and $60,000, respectively. The impact of stock option expense was to reduce net income by $71,000 and $98,000, respectively, which represents a decrease in basic and diluted earnings per share of approximately $0.01 per diluted share for the three months ended December 31, 2007 and less than $0.01 per diluted share for the three months ended December 31, 2006.

There were no options granted during the three months ended December 31, 2007 and 2006. In calculating the impact for options granted 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.

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

				Weighted		Weighted	Aggregate
				Average		Average	Intrinsic
				Exercise		Remaining	Value
	Shares			Price		Life	(in thousands)
Outstanding at September 30, 2007		441,100			29.087	7.44 years	$	9,410
Granted
Exercised		(107,613	)		18.709
Forfeited
Outstanding at December 31, 2007*		333,487		$	31.489	8.21 years	$	8,841
Exercisable at December 31, 2007		118,463		$	21.422	6.32 years	$	4,333
Remaining reserved for grant at December 31, 2007		113,000

^* Includes 36,209 shares outstanding under the 1992 Amended and Restated Stock Option Plan.

The total intrinsic value of options exercised during the three months ended December 31, 2007 and 2006 was approximately $3,215,000 and $128,000, respectively. The fair value of options that vested during the three months ended December 31, 2006 and 2005 was approximately $-0- and $49,000, respectively.

At December 31, 2007, there was approximately $1,070,000 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 2.91 years.

During the three months ended December 31, 2007 and 2006, cash received from options exercised was $2,329,000 and $116,000, respectively, and the actual tax benefit realized for the related tax deduction totaled $1,098,000 and $48,000, respectively.

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Note 4. Retirement Plans and Other Benefits

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

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

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

	Pension						Postretirement
	Benefits						Benefits
For the three months ended December 31, (in thousands)	2007			2006			2007			2006
Service cost	$	211		$	220		$	39		$	39
Interest cost		498			479			42			48
Amortization of prior service cost		22						(19	)		(19	)
Amortization of loss		(32	)		23			6
Expected return on plan assets		(780	)		(703	)		(83	)		(72	)
Net periodic benefit cost	$	(81	)	$	19		$	(21	)	$	2

For fiscal year 2008, 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

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

RSE is a ratemaking methodology also used by the APSC to regulate certain other public Alabama energy utilities. A rate adjustment designed to decrease Mobile Gas’ annual gas revenues by approximately $333,000 was implemented December 1, 2007. Previous rate adjustments were implemented under the RSE tariff which were designed to increase annual gas revenues by approximately $4.2 million effective December 1, 2006 and decrease annual gas revenues by approximately $303,000 effective December 1, 2005. The December 1, 2007 rate decrease is due primarily to the return of approximately $1,600,000 of the regulatory liability for gross receipts tax collections to ratepayers during fiscal 2008. Mobile Gas’ rates, as established under RSE, allow a return on average equity within a range of 13.35% to 13.85% for the period.

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Mobile Gas is allowed to earn a return on all of its assets with no exclusions. Increases are allowed only once each fiscal year, effective December 1, and cannot exceed four percent of prior-year revenues. Under RSE, the APSC conducts reviews using fiscal year-to-date performance through January, April, and July plus Mobile Gas’ budget projections to determine whether Mobile Gas’ return on equity is expected to be within the allowed range at the end of the fiscal year.

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

In conjunction with the approval of RSE, the APSC approved an Enhanced Stability Reserve (ESR), beginning October 1, 2002, to which Mobile Gas may charge the full amount of: 1) extraordinary O&M expenses resulting fromforce majeureevents such as storms, severe weather, and outages, when one such event results in more than $100,000 of additional O&M expense or a combination of two or more such events results in more than $150,000 of additional O&M expense during a fiscal year; or 2) losses of revenue from any individual industrial or commercial customer in excess of $100,000 during the fiscal year, if such losses cause Mobile Gas’ return on equity to fall below 13.35%. An initial ESR balance of $1.0 million was recorded October 1, 2002 and is being recovered from customers through rates. Subject to APSC approval, additional funding, up to a maximum reserve balance of $1.5 million, may be provided from any future non-recurring revenue should such revenue cause Mobile Gas’ return on equity for the fiscal year to exceed 13.85%. Following a year in which a charge against the ESR is made, the APSC allows for accruals to the ESR of no more than $15,000 monthly until the maximum funding level is achieved. The ESR balance of $1,000,000 at December 31, 2007 is included in the balance sheet of the Unaudited Condensed Consolidated Financial Statements as part of Regulatory Liabilities.

In October 2000, the Corus Group plc (Corus, formerly known as British Steel) ceased operations of its Mobile facility and continued to pay Mobile Gas a minimum annual payment as required under the terms of its contract. On July 28, 2005, Corus elected to end the contract and make a termination payment as required by the terms of the contract. Under a Termination Agreement (Termination Agreement) between Mobile Gas and Corus, Corus agreed to pay Mobile Gas $6,100,000. The APSC approved Mobile Gas’ request to recognize the termination payments as a regulatory liability and amortize the balance into income over the remaining seven years of the original contract term.

Mobile Gas’ rates contain a temperature adjustment rider which is designed to offset the impact of unusually cold or warm weather on the Company’s operating margins. The temperature adjustment rider applies to substantially all residential and small commercial customers. The adjustment for the margin impact due to variances in weather is calculated monthly for the months of November through April and is accumulated. The accumulated adjustment from one

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heating season (November through April) will be billed or credited to customers in subsequent periods. This mechanism reduces the variability of both customers’ bills and Mobile Gas’ earnings due to weather fluctuations.

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

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

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

	December 31,				December 31,				September 30,
	2007				2006				2007
	Current		Noncurrent		Current		Noncurrent		Current		Noncurrent
Assets
Deferred Purchase Gas Adjustment	$	5,924			$	2,285			$	4,736
ESR Fund		125				167	$	125		167
Weather Normalization Adjustment		789
Asset Retirement Cost			$	27				26		112	$	27
Regulatory Assets	$	6,838	$	27	$	2,452	$	151	$	5,015	$	27
Liabilities
ESR Fund	$	1,000			$	1,000			$	1,000
Termination Agreement		1,980				2,959				2,188
Deferred Investment Tax Credit		15	$	86		15	$	102		15	$	90
RSE Adjustment
Weather Normalization Adjustment						188
Gross Receipt Tax Collections		2,191				3,275				2,468
Accrued Dismantling Costs				9,938				9,567				9,818
Over-funded Pension and Postretirement Benefit Plans				11,984								11,984
Other		340				209				346
Regulatory Liabilities	$	5,526	$	22,008	$	7,646	$	9,669	$	6,017	$	21,892

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,

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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 December 31, 2007 and 2006, the net acquisition adjustments were $4,975,000 and $5,327,000, respectively, and the balance at September 30, 2007 was $5,063,000.

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:

	Three Months
EnergySouth, Inc.	Ended December 31,
In Thousands	2007		2006
Weighted Average Common Shares		8,090		7,954
Effect of Dilutive Securities:
Options to Purchase Common Stock		93		77
Diluted Average Common Shares		8,183		8,031

Note 7. Segment Information

The Company is principally engaged in two reportable business segments: Natural Gas Distribution and Natural Gas Midstream. 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. The Natural Gas Midstream segment provides for the underground storage of natural gas and transportation services through the operations of Bay Gas and Mississippi Hub and transportation services through the operations of SGT. Through Services, Midstream manages and optimizes transportation and storage assets through natural gas marketing, trading and risk management activities. The Company also provides merchandising and other energy-related services through Mobile Gas which are aggregated with EnergySouth, the holding company, and included in the Other segment.

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Segment earnings information presented in the table below includes intersegment revenues, interest income, and interest expense which are eliminated in consolidation. Such intersegment revenues are primarily amounts paid by the Natural Gas Distribution segment to the Natural Gas Midstream segment.

For the three months ended	Natural Gas			Natural Gas
December 31, 2007 (in thousands):	Distribution			Midstream			Other			Eliminations			Consolidated
Operating Revenues	$	29,382		$	6,338		$	1,210		$	(1,058	)	$	35,872
Cost of Gas		13,895			172						(1,058	)		13,009
Cost of Merchandise								779						779
Operations and Maintenance Expense		5,486			2,522			469						8,477
Depreciation Expense		2,224			957									3,181
Taxes, Other Than Income Taxes		2,134			341			19						2,494
Operating Income		5,643			2,346			(57	)					7,932
Interest Income					827			1,418			(1,837	)		408
Interest Expense		(977	)		(3,016	)		(1,191	)		1,837			(3,347	)
Interest Capitalized		32			1,591									1,623
Less: Minority Interest					(44	)								(44	)
Income Before Income Taxes	$	4,698		$	1,704		$	170					$	6,572

For the three months ended	Natural Gas			Natural Gas
December 31, 2006 (in thousands):	Distribution			Midstream			Other			Eliminations			Consolidated
Operating Revenues	$	33,230		$	5,501		$	1,261		$	(1,062	)	$	38,930
Cost of Gas		17,494									(1,062	)		16,432
Cost of Merchandise								749						749
Operations and Maintenance Expense		5,717			1,169			470						7,356
Depreciation Expense		2,098			664									2,762
Taxes, Other Than Income Taxes		2,369			245			19						2,633
Operating Income		5,552			3,423			23						8,998
Interest Income		1			43			278			(304	)		18
Interest Expense		(880	)		(976	)		(127	)		304			(1,679	)
Interest Capitalized		13			345									358
Less: Minority Interest					(274	)								(274	)
Income Before Income Taxes	$	4,686		$	2,561		$	174					$	7,421

Note 8. Energy Marketing and Risk Management Activities

Since the fourth quarter of fiscal 2007, Midstream has been engaged in natural gas marketing, trading and risk management activities and, as such, is exposed to risks associated with changes in the market price of natural gas. Midstream uses derivative instruments to reduce the exposure to the risk of changes in the price of natural gas. The use of these instruments is subject to the Company’s risk control policies, which are monitored for compliance daily. Derivative instruments utilized in connection with these activities and services are accounted for under the fair value basis of accounting in accordance with SFAS 133.

To minimize the risk of fluctuations in natural gas prices, Midstream periodically enters into futures and other financial transactions in order to hedge anticipated purchases and sales of natural gas. Midstream has entered into park and loan transactions with pipelines and with

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Storage which allow it to park gas on or borrow gas from the pipeline or storage facility in one period and reclaim gas from or repay gas to the pipeline in a subsequent period. Midstream entered into forward NYMEX contracts to hedge its inventory that is parked. At December 31, 2007, these derivative transactions are designated as cash flow hedges under SFAS 133. Derivative gains or losses arising from cash flow hedges are recorded in Other Comprehensive Income (OCI) and are reclassified into earnings in the same period the underlying hedged item is reflected in the income statement. As of December 31, 2007, the ending balance in OCI for derivative transactions designated as cash flow hedges under SFAS 133 was a gain of $192,000, net of taxes. Any hedge ineffectiveness, defined as when the gains or losses on the hedging instrument do not offset the losses or gains on the hedged item, is recorded into earnings in the period in which it occurs. As of December 31, 2007, Midstream had immaterial hedge ineffectiveness.

Additionally, Midstream participated in park and loan transactions in which physical gas was borrowed and later repaid. Through the use of swaps and futures, Midstream was able to capture gross profit margin through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time. Although the purpose of these instruments is to either reduce basis or other risks or lock in arbitrage opportunities, these derivative instruments were not designated as hedges. Accordingly, these derivative instruments were recorded at fair value with all changes in fair value included in revenue.

Derivatives are recorded as a component of risk management assets and liabilities, which are classified as current or noncurrent based upon the anticipated settlement date of the underlying derivative. The determination of the fair value of these derivative financial instruments reflects the estimated amounts that Midstream would receive or pay to terminate or close the contracts at the reporting date. In the determination of fair value, various factors are considered, including closing exchange and over-the-counter quotations, time value and volatility factors underlying the contracts. These energy marketing and risk management assets and liabilities are subject to continuing market risk until the underlying derivative contracts are settled.

The following table shows the fair values of the energy marketing and risk management assets and liabilities which are included in other assets and/or other liabilities, as appropriate, in the Unaudited Condensed Consolidated Balance Sheet.

	December 31,			September 30,
Fair Value(in thousands)	2007			2007
Energy Marketing and Risk Management Assets, current	$	857		$	115
Energy Marketing and Risk Management Assets, long-term		—			2
Energy Marketing and Risk Management Liabilities, current		(395	)		(35	)
Energy Marketing and Risk Management Liabilities, long-term
Net Assets (Liabilities)	$	462		$	82

For the three months ended December 31, 2007, the change of $274,000 in the deferred hedging position in accumulated other comprehensive income was attributable to increases in future commodity prices relative to the commodity prices stipulated in the derivative contracts. The net deferred hedging gains associated with open cash flow hedges remain subject to market price fluctuations until the positions are either settled under the terms of the hedge contracts or terminated prior to settlement. Substantially all of the deferred hedging gain as of December 31,

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2007 is expected to be recognized in net income within the 2008 fiscal year.

Note 9. Other Comprehensive Income (Loss)

Other Comprehensive Income (Loss) consisted of the following:

	Three Months Ended
	December 31,
(in thousands)	2007		2006
Net Income	$	4,087	$	4,614
Other Comprehensive Income (Loss):
Current period change in fair value of derivative instruments, net of tax of $104		170
Comprehensive Income (Loss)	$	4,257	$	4,614

Accumulated Other Comprehensive Income (Loss) consisted of the following:

	December 31,		September 30,
(in thousands)	2007		2007
Unrealized gain (loss) on hedges, net of tax of $117 and $13	$	192	$	22

Note 10. Acquisition of Assets

Midstream formed a limited liability company for the purpose of acquiring the assets of Mississippi Hub, LLC that had begun development of an underground natural gas storage facility in April 2007. On November 28, 2007, Midstream and certain funds managed by affiliates of Fortress Investment Group LLC (the “Fortress Funds”) completed the acquisition of the net assets of Mississippi Hub, LLC for $140 million. Midstream owns a 60% majority membership interest and Fortress Funds owns the remaining 40% membership interest. SFAS No. 141, “Business Combinations” refers to EITF Issue No. 98-3, “Determining Whether a Nonmonetary Transaction Involves Receipt of Productive Assets or of a Business,” to provide guidance on determining whether the acquisition of an asset group constitutes a business combination. Based on this guidance, and primarily due to the fact that the assets purchased are currently in the development stage, it was determined that the acquisition should be accounted for as the purchase of a group of assets. Commercial operations are expected to commence by the fourth quarter of 2009 when the first of two caverns is completed.

Note 11. 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 load loss risks associated with significant increases in commodity prices of natural gas. Mobile Gas mitigates the price risk associated with purchases of natural gas by using a combination of natural gas storage services, fixed price contracts and spot market purchases. As part of Mobile Gas’ gas supply strategy, it has adopted a policy under which management is authorized to commit to future gas purchases at fixed prices up to a specified percentage of the normalized degree-day

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usage for any corresponding month as outlined within the policy. All such 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, Mobile Gas’ commitments for future purchases of natural gas at fixed prices are deemed and elected to be considered purchases in the normal course of business and are not subject to derivative accounting treatment.

At December 31, 2007, Mobile Gas had not entered into derivative instruments that did not qualify and were not designated as normal purchases under SFAS 133. 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 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 a period of 20 years which began in September 1994 with the commencement of commercial operations of the storage facility.

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. At the end of the initial 50 year land and subsurface lease term, Bay Gas has the right to renew the lease term for an additional 20 year period and would be required to remit annual payments based on the initial minimum service fees. Payments relating to the third cavern will extend over the life of the initial lease term or for as long as the cavern is in service. Payments are adjusted for annual Consumer Price Index (CPI) changes. Minimum commitments shown below reflect the CPI at the commitment date for each cavern. As of December 31, 2007, Bay Gas had entered into contracts for compressors and other services to be performed in the completion of the third storage cavern and the development of the fourth storage cavern and pipeline facilities.

As of December 31, 2007, Mississippi Hub had entered into contracts for services to be performed in the development of an underground salt-dome storage cavern and related surface facilities.

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

	Mobile Gas				Bay Gas
	Gas				Minimum				Mississippi Hub
Fiscal	Supply		Implemention of		Payments for		Construction		Construction		Total
Year	Contracts		CIS Software		Service Fees		Contracts		Contracts		Commitments
Remaining 2008	$	15,269	$	2,116	$	478	$	33,587	$	12,046	$	63,496
2009		1,498				638		20,468		4,691		27,295
2010		1,141				638				82		1,861
2011		815				638				82		1,535
2012						638						638
2013 — and						31,950						31,950
thereafter
Total	$	18,723	$	2,116	$	34,980	$	54,055	$	16,901	$	126,775

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.

The Alabama Department of Environmental Management (“ADEM”) has conducted a “Brownfield” evaluation of the property. On January 5, 2005, ADEM released a “CERCLA Targeted Brownfield Site Inspection” report on the manufactured gas plant site. Prior to the ADEM “Brownfield” evaluation, Mobile Gas engaged environmental consultants to evaluate the site in connection with the plans for the site. Based on their review, the Mobile Gas 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 12. New Accounting Pronouncements

On October 1, 2007, the Company adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109” (FIN 48). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement 109, “Accounting for Income Taxes,” by prescribing a recognition threshold and measurement attribute for the financial statement

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recognition and measurement of a tax position taken or expected to be taken in a tax return. Under FIN 48, the financial statement effects of a tax position should initially be recognized when it is more likely than not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold should initially and subsequently be measured as the largest amount of tax benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with a taxing authority.

The Company classifies interest and penalties recognized on the liability for unrecognized tax benefits as income tax expense. Interest and penalties of $50,000 were accrued as of the date of adoption and as of December 31, 2007. The U.S. Federal statute of limitations expires during the third quarter of 2008 for the Company’s 2003 and 2004 tax years. The Company does not expect a significant increase or decrease in its liability for unrecognized tax benefits within 12 months of this reporting date. The Company files income tax returns in the U. S. federal and various state jurisdictions. Generally, the Company is not subject to changes in income taxes by any taxing jurisdiction for the years prior to 2003.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS 157) which clarifies the principle that fair value should be based on the assumptions market participants would use when pricing an asset or a liability and established a fair value hierarchy that prioritized the information used to develop those assumptions. Under SFAS 157, fair value measurements would be separately disclosed by level within the fair value hierarchy and is effective for the Company beginning October 1, 2008. The Company is currently evaluating the impact of this statement.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159), which permits entities to measure financial instruments and certain other items at fair value to mitigate volatility in reported earnings. SFAS 159 is effective for the Company beginning October 1, 2008. The Company is currently evaluating the impact of this statement.

On April 30, 2007, the FASB issued FSP FIN 39-1, which amended FIN 39, to indicate that the following fair value amounts could be offset against each other if certain conditions of FIN 39 are otherwise met: (a) those recognized for derivative instruments executed with the same counterparty under a master netting arrangement and (b) those recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) arising from the same master netting arrangement as the derivative instruments. In addition, a reporting entity is not precluded from offsetting the derivative instruments if it determines that the amount recognized upon payment or receipt of cash collateral is not a fair value amount. FSP FIN 39-1 is effective at the beginning of the first fiscal year after November 15, 2007. The Company will adopt FSP FIN 39-1 on October 1, 2008. The Company is currently evaluating the potential effect of FSP FIN 39-1 on its statements of financial position.

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Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations

The Company

EnergySouth, Inc. (EnergySouth) is a holding company which has two principal wholly-owned subsidiaries, Mobile Gas Service Corporation (Mobile Gas) and EnergySouth Midstream, Inc. (Midstream). EnergySouth and its consolidated subsidiaries are collectively referred to herein as the “Company.” The Company’s natural gas distribution business is conducted by Mobile Gas, which purchases, sells, and transports natural gas to residential, commercial, and industrial customers in Mobile, Alabama and surrounding areas. Mobile Gas also provides merchandise sales, service, and financing. The Company’s natural gas midstream operations are conducted by Midstream, which is the general partner and 90.9% owner of Bay Gas Storage Company (Bay Gas), a limited partnership that provides underground storage and delivery of natural gas. Midstream owns 60% of Mississippi Hub, LLC, a limited liability company engaged in the construction and development of natural gas storage caverns. EnergySouth Services, Inc. (Services) is a wholly-owned subsidiary of Midstream and is engaged in natural gas marketing, trading and risk management activities. Services is also the general partner of Southern Gas Transmission Company (SGT), which is engaged in the intrastate transportation of natural gas.

Results Of Operations

Consolidated Earnings

Earnings per share for the three months ended December 31, 2007 increased $0.02 per diluted share as compared to the same prior-year period. The increase in earnings for the three-month period ended December 31, 2007 was due to increased earnings from the Company’s midstream operations. Earnings from the Company’s natural gas distribution business and other business operations were relatively flat for the three-month period ended December 31, 2007 as compared to the same prior-year period. Financial information by business segment is shown in Note 7 to the Unaudited Condensed Consolidated Financial Statements above.

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.

The Alabama Public Service Commission (APSC) regulates the Company’s gas distribution operations. Mobile Gas’ rate tariffs for gas distribution allow rate adjustments to ultimately pass through to customers the cost of gas and certain taxes. These costs, therefore, have little direct impact on the Company’s unit margins, which are defined as natural gas distribution revenues less the cost of natural 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.

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

The Company’s distribution business is highly seasonal and temperature-sensitive since residential and commercial customers use more gas during colder weather for space heating. As a result, gas revenues, cost of gas and related taxes in any given period reflect, in addition to other factors, the impact of weather, through either increased or decreased sales volumes. The Company has utilized a temperature rate adjustment rider during the months of November through April to mitigate the impact that unusually cold or warm weather has on operating margins by reducing the base rate portion of customers’ bills in colder than normal weather and increasing the base rate portion of customers’ bills in warmer than normal weather. Mobile Gas accumulates an adjustment for the margin impact due to variances in the weather. The accumulated adjustment from one heating season (November through April) will be billed or credited to customers in subsequent periods. See Note 5 to the Unaudited Condensed Consolidated Financial Statements above. This mechanism reduces the variability of both customers’ bills and Mobile Gas’ earnings due to weather fluctuations.

Financial information about the distribution business segment in shown in Note 7 to the Unaudited Condensed Consolidated Financial Statements above. Natural gas distribution revenues decreased $3,848,000 (12%) during the three-month period ended December 31, 2007 as compared to the same prior-year period. Rate adjustments and warmer than normal temperatures contributed to the decrease in revenues during the first fiscal quarter of 2008. Rate adjustments which reflect a decrease in gas costs paid to suppliers are the predominant reason for the decline in revenues. These decreases were partially offset by the RSE rate adjustment which went into effect on December 1, 2006. Weather in Mobile Gas’ service territory was unseasonably warm with temperatures that were 14% warmer than normal and 6% warmer than the same prior-year period.

Revenues from the sale of natural gas to temperature sensitive customers decreased $4,542,000 (16%) for the three-month period ended December 31, 2007 due to the rate adjustments noted above and an 18% decrease in volumes delivered to customers due to temperatures that were 6% warmer than in the prior year. A decline of approximately 1% in the number of temperature-sensitive customers served during the current-year period also contributed to the decrease in revenues.

Revenues from the sale of natural gas to large commercial and industrial customers increased $214,000 (7%) for the three-month period ended December 31, 2007 due primarily to a 16% increase in volumes delivered to customers during the current year period. Volumes were significantly higher in the current year period as a result of the unique operational needs of one industrial customer which accounted for increased revenues of $728,000. The increased revenues realized from this customer’s usage was partially offset by the rate adjustments noted above. The increased usage by this customer was an isolated event and is not expected to continue.

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Revenues from the transportation of natural gas to large commercial and industrial customers increased $44,000 (3%) during the three-month period ended December 31, 2007, due primarily to a 26% increase in volumes transported. Increased revenues were partially offset by a reduction in the amount of the regulatory liability recognized in income for the Termination Agreement with Corus as approved by the APSC. See Note 5 to the Unaudited Condensed Consolidated Financial Statements.

The cost of natural gas decreased $3,599,000 (21%) for the three-month period ended December 31, 2007 as compared to the same prior-year period due primarily to lower natural gas commodity prices and a decrease in the volumes delivered to temperature-sensitive customers.

Natural gas distribution margins, defined as revenues less cost of gas and related taxes, during the three-month period ended December 31, 2007 decreased approximately 1.5% as compared to the same prior-year period. Increased margins realized from the rate adjustment effective December 1, 2006 and the return of the regulatory liability for gross receipts tax collections to ratepayers were more than offset by a decline in volumes delivered to temperature-sensitive customers and a decline in the number of temperature-sensitive customers served. Consumption by residential temperature-sensitive customers, when adjusted for weather, decreased approximately 1% during the first quarter of fiscal 2008 compared to the same prior year period.

Operations and maintenance (O&M) expenses decreased $231,000 (21%) for the three months ended December 31, 2007 as compared to the same prior-year period due to a decline in compensation and benefits expenses of approximately $500,000. This decline in expense was partially offset by an increase of $157,000 in expenses related to the implementation of a new customer information system (CIS), increased advertising expenses of $70,000 and an increase of approximately $42,000 in various other expense items.

Depreciation expense increased $126,000 (6%) for the three-month period ended December 31, 2007 as compared to the same prior-year period 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 decreased $235,000 (10%) for the three-month period ended December 31, 2007 due primarily to the decrease in revenues.

Interest expense increased $97,000 (11%) for the three-month period ended December 31, 2007 as compared to the same prior-year period due primarily to increased short-term borrowings.

Natural Gas Midstream

The natural gas midstream segment provides for the underground storage of natural gas and transportation services through the operations of Bay Gas and Mississippi Hub and transportation services through the operations of SGT. The Company’s midstream operations manage and optimize transportation and storage assets through natural gas marketing, trading and risk management activities. See Note 7 to the Unaudited Condensed Consolidated Financial Statements above.

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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 substantial, long-term services for Mobile Gas and other customers that include storage and transportation of natural gas from interstate and intrastate sources. The APSC does not regulate rates for Bay Gas’ interstate gas storage and storage-related services. The Federal Energy Regulatory Commission (FERC), which has jurisdiction over interstate services, allows Bay Gas to charge market-based rates for such services. Market-based rates minimize regulatory involvement in the setting of rates for storage services and allow Bay Gas to respond to market conditions. Bay Gas also provides firm and interruptible interstate transportation-only services. The FERC last issued an order on April 14, 2006 approving rates for transportation-only services. In accordance with FERC filing requirements, on March 9, 2007 Bay Gas filed a petition with the FERC requesting approval of rates for transportation-only service.

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

Bay Gas is currently developing a third storage cavern and related facilities and has entered into multi-year contracts with customers for all of the cavern capacity. New compressors were placed in service during the first quarter of fiscal 2008 upon completion of the installation and testing of the new compressors. The new cavern is designed to add 5.0 Bcf of working gas capacity and is presently anticipated to be in service by April 2008. The addition of the third cavern and additional capacity development of 1.0 Bcf in one or more of the first three caverns 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.

Additional planned development includes two new 5.0 Bcf high deliverability underground salt-dome caverns together with additional pipeline interconnects with Transco. Midstream is currently communicating with potential customers in an effort to secure agreements for firm storage services. Bay Gas has drilled a well for development of the fourth cavern and its related pipeline interconnects and plans to move forward with development of the fifth cavern.

On November 28, 2007, Mississippi Hub acquired certain natural gas storage assets currently under development. The previous owners received 7(c) FERC approval in February 2007 and began development of natural gas storage facilities and appurtenant pipeline facilities in Simpson County, Mississippi in April 2007. Midstream held a non-binding “open season” in January 2008 to assess interest for up to 12.0 Bcf of high deliverability natural gas storage capacity from two salt dome storage caverns to be developed by Mississippi Hub. Midstream expects to complete pipeline interconnects with Sonat, SESH, and Transco. The first of the two caverns is expected to be operational by the fourth quarter of 2009. The second cavern has a planned in-service date of mid 2011.

Financial information about the midstream business segment is shown in Note 7 to the Unaudited Condensed Consolidated Financial Statements above. Midstream’s revenues increased

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$837,000 (15%) during the three-month period ended December 31, 2007 as compared to the same prior-year period due to increased revenues from short-term storage agreements during the current-year period. Under the short-term agreements, available working gas capacity is provided or available gas is loaned to customers on an interruptible basis, thereby optimizing the use of cavern capacity.

Operations and maintenance (O&M) expenses increased $1,353,000 during the three-month period ended December 31, 2007 as compared to the same prior-year period due to increased expenses incurred as a result of the continuing expansion of Midstream’s operations, including the acquisition of assets in November 2007 to be developed in Mississippi. The increase in expenses resulted from an increase in compensation and related benefits of approximately $600,000, increased legal expenses of $150,000, consulting services of $120,000, increased expenses of $72,000 related to Bay Gas’ cavern lease payments and $411,000 in increased office expenses and general repairs and maintenance due to the growth of Midstream’s operations.

Depreciation expense increased $293,000 (44%) for the three-month period ended December 31, 2007 as compared to the same prior-year period due to increased investment in property, plant and equipment.

Other taxes consist primarily of property taxes and business license taxes that are based on gross revenues and fluctuate accordingly. Other taxes increased $96,000 (39%) during the three months ended December 31, 2007 as compared to the same prior-year period.

Interest expense increased $2,040,000 for the three-month period ended December 31, 2007 due primarily to increased borrowings to fund Midstream’s capital expansion projects at Bay Gas and Mississippi Hub.

Capitalized interest costs increased $1,246,000 for the three-month period ended December 31, 2007 due to the ongoing construction of Bay Gas’ third and fourth storage caverns and the purchase and development of storage assets of Mississippi Hub.

Minority interest reflects the minority partner’s share of pre-tax earnings of the Bay Gas limited partnership and the SGT partnership, of which EnergySouth’s subsidiary holds a controlling interest. Minority interest also reflects the minority membership’s share of pre-tax earnings of Mississippi Hub LLC. Minority interest decreased $230,000 during the three-month period ended December 31, 2007 as compared to the same prior-year period due to decreased pretax earnings of these companies.

Other

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

Income before income taxes from Other business activities for the three-month period ended December 31, 2007 approximated the same prior-year period. A decrease in merchandise sales

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and related merchandising activities was offset by an increase in net interest income earned during the current year period.

Income Taxes

Income taxes fluctuate with the change in income before income taxes. Income tax expense decreased $322,000 (11%) for the three-month period ended December 31, 2007 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. Operating activities used $22,607,000 more cash during the three-month period ended December 31, 2007 as compared to the same period last fiscal year due to an increase in accounts payable of $16,945,000, an increase in gas inventory stored underground of $5,918,000, a decrease in collection of gas costs from customers of $818,000, an increase in current taxes paid of $2,956,000, and a decrease in net income of $527,000. Additionally, cash during the current-year period decreased due to the final cash payment of $1,350,000 received from Corus in October 2006 in accordance with the terms of the Termination Agreement as discussed in Note 5 above. Offsetting these cash flows used in operating activities was a decrease in accounts receivable of $5,456,000.

Cash used in investing activities reflects the capital-intensive nature of the Company’s business. During the three months ended December 31, 2007, the Company used cash of $164,763,000 for the purchase of the net assets of Mississippi Hub and for the construction of distribution and storage facilities, purchases of equipment and other general improvements. Midstream invested $147,368,000 in the purchase and development of its’ interest in Mississippi Hub and $14,461,000 in the development of Bay Gas’ third and fourth salt-dome storage caverns. During the three-month period ended December 31, 2006, the Company used cash of $6,357,000 for the purchase and construction of distribution and storage facilities, purchases of equipment and other general improvements, of which $3,264,000 was used in the ongoing development of Bay Gas’ third salt-dome storage cavern.

Financing activities provided cash of $189,578,000 during the three months ended December 31, 2007 due primarily to $129,800,000 in increased borrowings under the Company’s amended credit facility discussed below and $60,356,000 in capital contributions from the minority partner for its 40 % interest in the purchase of Mississippi Hub. Cash was also provided by stock options exercised and the related tax benefits realized from share based payments of $3,427,000. These cash receipts were offset by the payment of quarterly dividends of $2,023,000, repayment of long-term debt of $905,000 and debt issuance costs of $1,137,000 related to the amendment of the Company’s credit facility. Financing activities used cash of $377,000 during the three months ended December 31, 2006 due primarily to the payment of quarterly dividends of $1,830,000, payments on long term debt of $844,000, and partnership distributions. Partially offsetting these cash payments was an increase in short term borrowings of $2,075,000 and stock options exercised of $116,000.

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Midstream’s anticipated capital expenditures include the completion in April 2008 of Bay Gas’ third salt-dome storage cavern designed to provide 5.0 Bcf of working gas capacity. Bay Gas’ projected expenditures for 2008 also include continuing development of a fourth storage cavern designed to provide 5.0 Bcf of working gas capacity and starting construction of a fifth storage cavern. Bay Gas also will begin construction of a 29 mile pipeline from the storage facilities in McIntosh, Alabama to connect to the Transco pipeline in north Mobile County. The Company expects 2008 capital expenditures by Bay Gas to total approximately $100 million.

On November 28, 2007, Midstream and the Fortress Funds completed the acquisition of the net assets of Mississippi Hub LLC, for $140 million. Mississippi Hub LLC expects to spend an additional $50 million in fiscal 2008 for development and construction of a storage cavern, supporting facilities and pipelines.

In August 2007, the Industrial Development Authority of Washington County, Alabama issued $55 million in Industrial Development Revenue Bonds (the Bonds) due August 15, 2037, and loaned these funds to Bay Gas for financing of storage facilities construction. In connection with the bond issuance, Bay Gas caused a $55 million letter of credit (Letter of Credit) to be issued to secure payment of the Bonds. On November 28, 2007, the Company amended its existing $100 million credit facility with a new 364 day $250 million credit facility with a group of banks which also provides credit availability for Bay Gas’ Letter of Credit, for additional letters of credit, and for a revolving credit line. The Company used this credit facility to fund its $84 million portion of the $140 million purchase price of Mississippi Hub LLC. At December 31, 2007, the Company had $53 million available for borrowing on its revolving credit agreement and $46 million in unused funds from the Bonds which are included in restricted cash on the Unaudited Condensed Consolidated Balance Sheet.

The Company expects to fund near-term construction at Bay Gas through the continued draw down of funds from the Bonds, the new credit facility, internal cash generation, and minority partner contributions. Mississippi Hub LLC near term construction will be funded from the new credit facility and minority member contributions. Longer term capital expenditures for both Bay Gas and Mississippi Hub LLC will be funded through the issuance of long-term debt and equity.

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

	Remaining		Fiscal		Fiscal		Fiscal		Fiscal		Fiscal Years
Type of Contractual	Fiscal Year		Year		Year		Year		Year		2013 and
Obligations (in thousands):	2008		2009		2010		2011		2012		thereafter
Long-Term Debt	$	4,994	$	6,054	$	5,653	$	5,955	$	6,307	$	96,492
Interest Payments (1)		6,084		7,133		6,637		6,165		5,667		58,628
Estimated Future Minimum Payments for Bay Gas Service Fees		478		638		638		638		638		31,950
Construction Contracts for Bay Gas’ Storage Facilities		33,587		20,468
Construction Contracts for Mississippi Hub Storage Facilities		12,046		4,691		82		82
Implementation of CIS Software		2,116
Gas Supply Contracts		15,269		1,498		1,141		815
Total	$	74,574	$	40,482	$	14,151	$	13,655	$	12,612	$	187,070

(1) Amounts include estimated interest payments on $55 million Industrial Revenue Bonds and are based on the effective rate as of December 31, 2007 of 3.43%.

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, 2007.

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 Midstream cavern development; disruption or interruption of pipelines serving the Midstream 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

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financial condition of one or more major customers; market risks affecting risk management activities including market liquidity, commodity price volatility, increasing interest rates and counterparty creditworthiness; ability to continue to access the capital markets; 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.

Item 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Risk Control Policy and Oversight

The scope of risk management, marketing and trading operations are controlled and monitored through a comprehensive set of policies and procedures by the Risk Oversight Committee (ROC). The ROC consists of members of senior management who oversee all activities related to commodity price and credit risk management, and marketing and trading activities. The ROC also monitors risk metrics including value-at-risk and mark-to-market losses. The ROC reports to the Audit Committee of the Board of Directors which has oversight responsibilities for the risk control limits and policies.

Commodity Price Risk

Distribution.Mobile Gas is exposed to load loss risks associated with significant increases in commodity prices of natural gas. Mobile Gas mitigates the price risk associated with purchases of natural gas by using a combination of natural gas storage services, fixed price contracts and spot market purchases. As part of Mobile Gas’ gas supply strategy, it has adopted a policy under which management is authorized to commit to future gas purchases at fixed prices up to a specified percentage of the normalized degree-day usage for any corresponding month as outlined within the policy. All commitments for future gas purchases at fixed prices meet the requirements of paragraph 10.b, Normal purchases and Normal sales, of SFAS 133, 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 December 31, 2007, Mobile Gas had not entered into derivative instruments for the purpose of hedging the price of natural gas. If Mobile Gas had entered into such derivative instruments, any cost incurred or benefit received from the derivative or other hedging arrangements would be recoverable or refunded through the purchased gas adjustment mechanism. As discussed in “Results of Operations” under “Natural Gas Distribution” within Item 2 above , the APSC currently allows for full recovery of all costs associated with natural gas purchases; therefore, costs

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associated with the forward purchases of natural gas will be passed through to customers when realized and should not affect future earnings.

Midstream.Midstream is engaged in natural gas marketing, trading and risk management activities and, as such, is exposed to risks associated with changes in the market price of natural gas. Midstream uses derivative instruments, such as forward contracts, futures contracts and swaps, to reduce the exposure to the risk of changes in the price of natural gas. The fair value of these derivative financial instruments reflects the estimated amounts that Midstream would receive or pay to terminate or close the contracts at the reporting date, taking into account the current unrealized gains or losses on open contracts. The fair value of derivative instruments is determined through a combination of prices actively quoted on national exchanges, prices provided by other external sources and prices based on models and other valuation methods. The following table shows the components of change in fair value of derivative instruments utilized in Midstream’s energy marketing and risk management assets and liabilities during the first quarter of fiscal 2008.

	October 1, through
(in thousands)	December 31, 2007
Net fair value of contracts outstanding at September 30, 2007	$	82
Net fair value of new contracts entered into during the period		846
Contracts realized or otherwise settled during the period		(584	)
Other changes in fair value		131
Net fair value of contracts outstanding at December 31, 2007		475
Less net fair value of contracts outstanding at September 30, 2007		(82	)
Unrealized gain (loss) related to changes in the fair value of derivative instruments	$	393

Substantially all of Midstream’s derivative contracts at December 31, 2007 are expected to be recognized in net income within fiscal 2008.

EnergySouth measures the market risk associated with Midstream’s trading portfolios using a Value-at-Risk (VaR) methodology. VaR is a common risk metric used in the industry that measures the expected maximum loss in the portfolio over a specified time horizon. Midstream uses a one-day holding period and a 95% confidence interval in its VaR determination. The following table details the average, high and low VaR for the three months ended December 31, 2007.

	October 1, 2007
	through
VaR (in thousands)	December 31, 2007
Average	$	124
High		316
Low		25

Midstream’s open exposure is managed based on established policies that limit market risk, requiring daily reporting of potential commodity price exposure to senior management and the ROC. Midstream’s philosophy is to protect against commodity price risk by hedging with financial instruments to keep open exposure to a minimum, permitting Midstream to operate within relatively low VaR limits.

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

Changes in Internal Control

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

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PART II. OTHER INFORMATION

Item 1A. Risk Factors

There have been no material changes to the risk factors previously disclosed in the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2007.

Item 4. Submission of Matters to a Vote of Security Holders

(a)	The Annual Meeting of Stockholders of EnergySouth, Inc. was held on January 25, 2008.
(b)	The following nominees were elected as Directors of the Company, to serve until the 2011 Annual Meeting of Stockholders, by the votes indicated:

Nominee	For		Withheld
Walter A. Bell		6,737,981		77,408
Harris V. Morrissette		6,742,540		72,850

The other Directors of the Company whose terms of office continued after the 2008 Annual Meeting are as indicated below:

	To Serve Until the Annual
Director	Meeting of Stockholders in the year
John C. Hope, III		2009
Judy A. Marston		2009
S. Felton Mitchell, Jr.		2009
Thomas B. Van Antwerp		2009
C. S. “Dean” Liollio		2010
Robert H. Rouse		2010
J. D. Woodward		2010

(c) At the Annual Meeting, the shareholders of the Company approved the 2008 Incentive Plan of EnergySouth, Inc. by the following vote:

Votes For:	4,305,753
Votes Against:	321,408
Abstentions:	298,835
Broker Non-Votes:	1,889,393

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Item 5. Other Information

On February 6, 2008, EnergySouth, Inc. (the “Company”) issued a press release announcing earnings for the fiscal quarter ended December 31, 2007 and the declaration of a dividend on outstanding Common Stock. The full text of the press release is set forth in Exhibit 99.1 hereto. The exhibit is furnished under this Item 5 in lieu of its being furnished under cover of and pursuant to the instructions for Form 8-K.

Item 6. Exhibits

Exhibit No.	Description
31.1	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 — Chief Executive Officer
31.2	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 — Chief Financial Officer
32.1	Certification Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 — Chief Executive Officer
32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 — Chief Financial Officer
99.1	Press release dated February 6, 2008

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:February 8, 2008	/s/ C. S. Liollio
	C. S. Liollio
	President and Chief Executive Officer
Date:February 8, 2008	/s/ Charles P. Huffman
	Charles P. Huffman
	Executive Vice President and Chief Financial Officer

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