ENSI Energysouth (MM)

 

 

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 June 30, 2008

Commission File No. 0-29604

ENERGYSOUTH, INC.

(Exact name of registrant as specified in its charter)

Delaware		58-2358943
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
2828 Dauphin Street, Mobile, Alabama		36606
(Address of principal executive office)		(Zip Code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ      No  o

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 (Do not check if a smaller reporting company)		Smaller Reporting Company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o     No þ

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 August 5, 2008 – 8,111,663 shares.

 

 

ENERGYSOUTH, INC.
FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2008

INDEX

		Page No.
PART I: FINANCIAL INFORMATION
Item 1 Financial Statements:
(a) Unaudited Condensed Consolidated Balance Sheets June 30, 2008 and 2007 and September 30, 2007		3 - 4
(b) Unaudited Condensed Consolidated Statements of Income Three and Nine Months Ended June 30, 2008 and 2007		5
(c) Unaudited Condensed Consolidated Statements of Cash Flows Nine Months Ended June 30, 2008 and 2007		6
(d) Notes to Unaudited Condensed Consolidated Financial Statements		7 - 23
Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations		24 - 33
Item 3 Quantitative and Qualitative Disclosures About Market Risk		34 - 36
Item 4 Controls and Procedures		36
PART II: OTHER INFORMATION
Item 1A Risk Factors		37
Item 5 Other Information		37
Item 6 Exhibits		37
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

PART 1. FINANCIAL INFORMATION

ITEM 1: FINANCIAL STATEMENTS

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

EnergySouth, Inc.		June 30,								September 30,
In Thousands		2008				2007				2007
		(Unaudited)
ASSETS
Current Assets
Cash and Cash Equivalents		$	21,800			$	57			$	336
Restricted Cash			49,111				1,910				47,995
Cash Held on Deposit in Margin Account			9,877								999
Receivables
Gas			13,084				7,594				6,419
Gas — Energy Marketing, Trading and Risk Management			5,512								3,687
Unbilled Revenue			1,998				1,576				1,499
Merchandise			2,310				1,887				1,926
Other			1,025				808				780
Allowance for Doubtful Accounts			(1,842	)			(1,582	)			(1,047	)
Materials, Supplies, and Merchandise, net (At Average Cost)			1,343				1,354				1,376
Gas Stored Underground (At Average Cost)			58,431				6,963				8,069
Regulatory Assets			5,862				3,931				5,015
Deferred Income Taxes			2,451				117
Prepaid Taxes			2,482				1,029				2,088
Prepayments			3,179				2,829				3,320
Energy Marketing, Trading and Risk Management Assets			11,694				15				333
Total Current Assets			188,317				28,488				82,795
Property, Plant, and Equipment			381,825				302,727				311,249
Less: Accumulated Depreciation and Amortization			100,980				92,254				94,025
Property, Plant, and Equipment — Net			280,845				210,473				217,224
Construction Work in Progress			202,373				43,471				53,287
Total Property, Plant, and Equipment			483,218				253,944				270,511
Other Assets
Prepaid Pension Cost			12,069				783				11,827
Prepaid Postretirement Benefit			1,650				568				1,587
Deferred Charges			1,451				686				1,093
Prepayments			2,375				981				1,568
Regulatory Assets			27				67				27
Merchandise Receivables Due After One Year			2,380				2,895				3,038
Energy Marketing, Trading and Risk Management Assets			640
Total Other Assets			20,592				5,980				19,140
Total		$	692,127			$	288,412			$	372,446

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

EnergySouth, Inc.		June 30,								September 30,
In Thousands, Except Share Data		2008				2007				2007
		(Unaudited)
LIABILITIES AND CAPITALIZATION
Current Liabilities
Current Maturities of Long-Term Debt		$	6,009			$	5,834			$	5,900
Notes Payable			149,325				19,990				12,300
Accounts Payable			24,605				9,865				11,072
Accrued Gas Payable — Energy Marketing, Trading and Risk Management			89,141				71				19,763
Dividends Declared			2,109				1,995				2,010
Customer Deposits			1,137				1,132				1,139
Taxes Accrued			3,596				3,354				3,752
Deferred Taxes			1,601				—				741
Interest Accrued			887				490				1,031
Regulatory Liabilities			4,183				6,672				6,017
Energy Marketing, Trading and Risk Management Liabilities			16,374								35
Other			1,564				1,362				1,421
Total Current Liabilities			300,531				50,765				65,181
Other Liabilities
Accrued Postretirement Benefit Cost
Deferred Income Taxes			32,754				27,446				28,748
Deferred Investment Tax Credits			181				201				196
Regulatory Liabilities			22,091				10,178				21,892
Asset Retirement Obligation			6,513				5,661				6,188
Energy Marketing, Trading and Risk Management Liabilities			404
Other			2,000				1,556				1,566
Total Other Liabilities			63,943				45,042				58,590
			364,474				95,807				123,771
Capitalization
Stockholders’ Equity
Common Stock, $.01 Par Value
(Authorized 20,000,000 Shares; Outstanding June 2008 - 8,110,000; June 2007 - 7,980,000; September 2007 - 7,986,000 Shares)			81				80				80
Capital in Excess of Par Value			35,479				30,558				30,852
Retained Earnings			97,165				89,039				90,298
Accumulated Other Comprehensive Income (Loss), net of tax			(4,032	)							22
Grantor Trust, at cost			(1,656	)			(1,375	)			(1,362	)
Deferred Compensation Liability			1,656				1,375				1,362
Total Stockholders’ Equity			128,693				119,677				121,252
Minority Interest			83,539				6,499				6,962
Long-Term Debt			115,421				66,429				120,461
Total Capitalization			327,653				192,605				248,675
Total		$	692,127			$	288,412			$	372,446

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF INCOME

		Three Months								Nine Months
ENERGYSOUTH, INC.		Ended June 30,								Ended June 30,
In Thousands, Except Per Share Data		2008				2007				2008				2007
Operating Revenues
Gas Revenues		$	31,456			$	22,812			$	112,531			$	106,062
Merchandise Sales			739				696				2,336				2,427
Other			161				237				732				846
Total Operating Revenues			32,356				23,745				115,599				109,335
Operating Expenses
Cost of Gas			9,386				7,669				42,283				43,970
Cost of Merchandise			624				585				1,980				1,967
Operations and Maintenance			10,821				7,434				27,891				22,769
Depreciation			3,159				2,750				9,454				8,262
Taxes, Other Than Income Taxes			1,981				1,867				7,628				7,440
Total Operating Expenses			25,971				20,305				89,236				84,408
Operating Income			6,385				3,440				26,363				24,927
Other Income and (Expense)
Interest Expense			(4,499	)			(1,725	)			(12,453	)			(5,075	)
Capitalized Interest			2,028				679				5,910				1,503
Interest Income			424				3				1,175				26
Minority Interest			(48	)			(247	)			(48	)			(821	)
Total Other Income (Expense)			(2,095	)			(1,290	)			(5,416	)			(4,367	)
Income Before Income Taxes			4,290				2,150				20,947				20,560
Income Taxes			1,622				816				7,920				7,782
Net Income		$	2,668			$	1,334			$	13,027			$	12,778
Earnings Per Share
Basic		$	0.33			$	0.17			$	1.61			$	1.60
Diluted		$	0.33			$	0.17			$	1.59			$	1.59
Average Common Shares Outstanding
Basic			8,109				7,979				8,101				7,968
Diluted			8,182				8,071				8,188				8,060

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

		Nine Months
EnergySouth, Inc.		Ended June 30,
In Thousands		2008				2007
Cash Flows from Operating Activities
Net Income		$	13,027			$	12,778
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities
Depreciation and Amortization			9,720				8,490
Provision for Losses on Receivables and Inventory			1,151				1,146
Provision for Deferred Income Taxes			4,865				2,516
Minority Interest			48				821
Risk Management Assets and Liabilities			(1,944	)
Stock-Based Employee Compensation Expense			487				448
Changes in Operating Assets and Liabilities:
Cash Held in Margin Account			(8,878	)
Receivables			(9,317	)			(2,220	)
Inventory			(50,329	)			(183	)
Payables			74,606				1,422
Taxes			(552	)			1,947
Deferred Purchased Gas Adjustment			(334	)			(1,730	)
Other			(1,634	)			359
Net Cash Provided by Operating Activities			30,916				25,794
Cash Flows from Investing Activites
Capital Expenditures			(213,467	)			(31,894	)
Restricted Cash			(1,115	)			(168	)
Net Cash Used in Investing Activities			(214,582	)			(32,062	)
Cash Flows from Financing Activites
Repayment of Long-Term Debt			(4,931	)			(4,716	)
Debt Issuance Costs			(1,137	)
Changes in Short-Term Borrowings			137,025				14,690
Payment of Dividends			(6,159	)			(5,659	)
Dividend Reinvestment			261				256
Exercise of Stock Options			2,441				459
Excess Tax Benefits from Share Based Payments			1,100				139
Capital Contribution from Minority Interest Holder			76,652
Partnership Distributions to Minority Interest Holders			(122	)			(116	)
Net Cash Used in Financing Activities			205,130				5,053
Net Increase (Decrease) in Cash and Cash Equivalents			21,464				(1,215	)
Cash and Cash Equivalents at Beginning of Period			336				1,272
Cash and Cash Equivalents at End of Period		$	21,800			$	57
Noncash Transactions from Investing Activities:
Accruals for Capital Expenditures		$	11,644			$	2,565

See Accompanying Notes to Unaudited Condensed Consolidated Financial Statements

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/A of the Company for the fiscal year ended September 30, 2007. Certain amounts in the prior-year financial statements have been reclassified to conform to the current year financial statement presentation.

Due to the high percentage of customers using natural gas for heating, the Company’s operations are seasonal in nature. Therefore, the results of operations for the three- and nine- month periods ended June 30, 2008 and 2007 are not indicative of the results to be expected for the full year.

The table below summarizes operating results for the twelve months ended June 30, 2008 and 2007:

		Twelve Months
EnergySouth, Inc.		Ended June 30,
In Thousands, Except Per Share Data		2008				2007
Operating Revenues		$	141,296			$	131,175
Cost of Gas			47,487				50,009
Cost of Merchandise			2,697				2,673
Operations and Maintenance Expense			35,491				29,477
Depreciation Expense			12,207				10,935
Taxes, Other Than Income Taxes			9,280				9,158
Operating Income			34,134				28,923
Interest Expense			(14,751	)			(6,765	)
Allowance for Borrowed Funds Used During Construction			6,699				1,813
Interest Income			1,450				35
Less: Minority Interest			(588	)			(1,139	)
Income Before Income Taxes		$	26,944			$	22,867
Income Taxes			10,128				8,761
Net Income		$	16,816			$	14,106
Earnings Per Share
Basic		$	2.08			$	1.77
Diluted		$	2.06			$	1.75
Average Common Shares Outstanding
Basic			8,072				7,962
Diluted			8,157				8,039

Note 3. Stock-Based Compensation

On January 25, 2008, the stockholders approved the 2008 Incentive Plan of EnergySouth, Inc. (2008 Plan) for the purpose of attracting, retaining, and motivating executive officers and other key employees. Awards granted under the 2008 Plan may be in the form of (i) stock options, including both incentive stock options and nonqualified stock options, (ii) stock appreciation rights, (iii) restricted stock, including performance shares, and (iv) cash payments. The Board of Directors has reserved 250,000 shares of the Company’s authorized but unissued Common Stock for awards that may be granted under the 2008 Plan. Awards are granted at a price that is not less than 100% of the fair market price on the date the grant is approved by the Board of Directors in accordance with the terms of the 2008 Plan.

The 2008 Plan supersedes the 2003 Stock Option Plan of EnergySouth, Inc. (2003 Stock Option Plan) with regard to all stock option awards made after the effective date of the 2008 Plan. The 2003 Stock Option Plan will remain effective as to all stock option awards made and outstanding prior to the effective date of the 2008 Plan. Options were 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 2003 Stock Option Plan.

Stock Options:

Stock options granted under the 2008 Plan become one-third exercisable on the first anniversary of the grant date and an additional one-third become exercisable each succeeding year. Stock options granted under the 2003 Stock Option Plan become 25% exercisable on the first anniversary of the grant date and an additional 25% become exercisable each succeeding year. Under both plans, no option may be exercised after the expiration of ten years from the grant date.

In accordance with SFAS 123R, 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 based upon the grant-date fair value of those awards. Total stock-based compensation expense for stock option grants recognized during the nine months ended June 30, 2008 and 2007 was $388,000 and $448,000 respectively. The income tax benefit recognized in the income statement for these stock options during the nine months ended June 30, 2008 and 2007 was approximately $148,000 and $167,000 respectively. The impact of stock option expense was to reduce net income by $240,000 and $281,000, respectively, which represents a decrease in basic and diluted earnings per share of approximately $0.02 per diluted share for the nine months ended June 30, 2008 and 2007, respectively.

The Company granted stock options during the nine months ended June 30, 2008. In calculating the impact for options granted, the fair market value of the options at the date of grant was estimated using a Black-Scholes option pricing model. Assumptions utilized in the model are evaluated and revised, as necessary, to reflect market conditions and experience. Expected volatility has been calculated based on the historical volatility of the Company’s stock prior to the grant date. The expected term represents the period of time that options granted are expected to be outstanding and is estimated based on historical option exercise experience. The risk-free interest rate is equivalent to the U.S. Treasury yield in effect at the time of grant for the estimated life of the option grant. Options granted during the nine months ended June 30, 2008 have a weighted average fair value of $12.45 as calculated using the following assumptions: a weighted average stock price volatility of 21.4%, a weighted average expected life of six years, a weighted average risk free interest rate of 3.6% and a weighted average dividend yield of 2.0%.

A summary of option activity under the 2008 Plan and the 2003 Stock Option Plan as of June 30, 2008 and changes during the nine 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			39,120				57.120
Exercised			(112,713	)			21.661
Forfeited			(4,245	)			37.537
Outstanding at June 30, 2008			363,262			$	34.311			7.33 years				$	5,358
Exercisable at June 30, 2008			180,363			$	25.497			5.30 years				$	4,250

The total intrinsic value of options exercised during the nine months ended June 30, 2008 and 2007 was approximately $3,386,000 and $420,000, respectively. The fair value of options that vested during the nine months ended June 30, 2008 and 2007 was approximately $457,000 and $389,000, respectively.

At June 30, 2008, there was approximately $1,258,000 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 2.54 years.

During the nine months ended June 30, 2008 and 2007, cash received from options exercised was $2,441,000 and $459,000, respectively, and the actual tax benefit realized for the related tax deduction totaled $1,100,000 and $139,000, respectively.

Performance Shares:

The 2008 Plan provides for the granting of performance awards payable in any form described above upon the attainment of specific performance goals as established by the Board of Directors during the performance period which shall not be less than one year and not more than ten years.

On January 25, 2008, the Board of Directors granted a target number of performance-based shares, each representing the right to receive, on a one-for-one basis, shares of the Company’s Common Stock. Depending on the Company’s performance as defined and measured by criteria established by the Compensation Committee of the Board of Directors for the three-year period ending December 31, 2010, each grantee may receive from zero up to 150% of the target award. Each performance share that vests on December 31, 2010 will be settled in shares of the Company’s Common Stock. The performance share awards have been valued using a Monte Carlo model. The Monte Carlo model uses historical volatility and other variables to estimate the probability of satisfying the market condition of the award.

A summary of performance share award activity under the 2008 Plan as of June 30, 2008 is presented below:

		Performance
		Shares
Outstanding at September 30, 2007			—
Granted			14,960
Exercised			—
Forfeited			(340	)
Outstanding at June 30, 2008			14,620

The Company recorded expense of $99,000 for the nine months ended June 30, 2008 for performance share awards with a related deferred income tax benefit of $37,000. As of June 30, 2008, there was $617,000 of total unrecognized compensation cost related to performance share awards. These awards have a weighted average requisite service period of 2.58 years.

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 June 30, (in thousands)		2008				2007				2008				2007
Service cost		$	194			$	199			$	40			$	40
Interest cost			500				478				40				49
Amortization of prior service cost			22								(19	)			(19	)
Amortization of unrecognized gain			(29	)			23				(2	)			7
Expected return on plan assets			(780	)			(702	)			(83	)			(73	)
Net periodic benefit cost (credit)		$	(93	)		$	(2	)		$	(24	)		$	4

		Pension								Postretirement
		Benefits								Benefits
For the nine months ended June 30, (in thousands)		2008				2007				2008				2007
Service cost		$	581			$	628			$	118			$	115
Interest cost			1,501				1,436				119				113
Amortization of prior service cost			67								(56	)			(57	)
Amortization of unrecognized gain/(loss)			(86	)			70				(5	)
Expected return on plan assets			(2,339	)			(2,108	)			(248	)			(218	)
Net periodic benefit cost (credit)		$	(278	)		$	26			$	(72	)		$	(47	)

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. 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 from force majeure events 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 June 30, 2008 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 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):

		June 30,								June 30,								September 30,
		2008								2007								2007
		Current				Noncurrent				Current				Noncurrent				Current				Noncurrent
Assets
Deferred Purchase Gas Adjustment		$	5,070							$	3,646							$	4,736
Weather Normalization Adjustment			750								118								112
ESR Fund			42								167			$	41				167
Asset Retirement Cost						$	27								26							$	27
Other
Regulatory Assets		$	5,862			$	27			$	3,931			$	67			$	5,015			$	27
Liabilities
ESR Fund		$	1,000							$	1,000							$	1,000
Corus Contract Buyout			1,565								2,445								2,188
Gross Receipt Tax Collections			1,603								2,893								2,468
Accrued Dismantling Costs						$	10,029							$	10,084							$	9,818
Over-funded Pension and Postretirement Benefit Plans							11,983																11,984
Other			15				79				334				94				361				90
Regulatory Liabilities		$	4,183			$	22,091			$	6,672			$	10,178			$	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, 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, 2008 and 2007, the net acquisition adjustments were $4,798,000 and $5,151,000, 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								Nine Months
EnergySouth, Inc.		Ended June 30,								Ended June 30,
In Thousands		2008				2007				2008				2007
Weighted Average Common Shares			8,109				7,979				8,101				7,968
Effect of Dilutive Securities:
Options to Purchase Common Stock			73				92				87				92
Diluted Average Common Shares			8,182				8,071				8,188				8,060

Stock option awards to purchase approximately 38,600 and 81,000 shares as of June, 2008 and 2007, respectively, were not included in the computation of diluted earnings per share because inclusion of these shares would have been antidilutive.

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 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.

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
June 30, 2008 (in thousands):		Distribution				Midstream				Other				Eliminations				Consolidated
Operating Revenues		$	20,493			$	11,971			$	953			$	(1,061	)		$	32,356
Cost of Gas			10,447												(1,061	)			9,386
Cost of Merchandise											624								624
Operations and Maintenance Expense			5,286				5,169				366								10,821
Depreciation Expense			2,197				962												3,159
Taxes, Other Than Income Taxes			1,657				353				(29	)							1,981
Operating Income			906				5,487				(8	)							6,385
Interest Income			1				991				2,287				(2,855	)			424
Interest Expense			(829	)			(4,354	)			(2,171	)			2,855				(4,499	)
Interest Capitalized			14				2,014												2,028
Less: Minority Interest			—				(48	)											(48	)
Income Before Income Taxes		$	92			$	4,090			$	108							$	4,290

For the three months ended		Natural Gas				Natural Gas
June 30, 2007 (in thousands):		Distribution				Midstream				Other				Eliminations				Consolidated
Operating Revenues		$	18,688			$	5,184			$	922			$	(1,049	)		$	23,745
Cost of Gas			8,718												(1,049	)			7,669
Cost of Merchandise											585								585
Operations and Maintenance Expense			5,630				1,427				377								7,434
Depreciation Expense			2,098				652												2,750
Taxes, Other Than Income Taxes			1,584				267				16								1,867
Operating Income			658				2,838				(56	)							3,440
Interest Income			1				160				363				(521	)			3
Interest Expense			(821	)			(1,224	)			(201	)			521				(1,725	)
Interest Capitalized			19				660												679
Less: Minority Interest							(247	)											(247	)
Income Before Income Taxes		$	(143	)		$	2,187			$	106							$	2,150

For the nine months ended		Natural Gas				Natural Gas
June 30, 2008 (in thousands):		Distribution				Midstream				Other				Eliminations				Consolidated
Operating Revenues		$	91,023			$	24,775			$	2,996			$	(3,195	)		$	115,599
Cost of Gas			45,306				172								(3,195	)			42,283
Cost of Merchandise											1,980								1,980
Operations and Maintenance Expense			16,170				10,537				1,184								27,891
Depreciation Expense			6,592				2,862												9,454
Taxes, Other Than Income Taxes			6,549				1,045				34								7,628
Operating Income			16,406				10,159				(202	)							26,363
Interest Income			2				2,627				6,104				(7,558	)			1,175
Interest Expense			(2,727	)			(11,666	)			(5,618	)			7,558				(12,453	)
Interest Capitalized			55				5,855												5,910
Less: Minority Interest							(48	)											(48	)
Income Before Income Taxes		$	13,736			$	6,927			$	284							$	20,947

For the nine months ended		Natural Gas				Natural Gas
June 30, 2007 (in thousands):		Distribution				Midstream				Other				Eliminations				Consolidated
Operating Revenues		$	93,221			$	16,061			$	3,240			$	(3,187	)		$	109,335
Cost of Gas			47,157												(3,187	)			43,970
Cost of Merchandise											1,967								1,967
Operations and Maintenance Expense			17,772				3,697				1,300								22,769
Depreciation Expense			6,295				1,967												8,262
Taxes, Other Than Income Taxes			6,635				755				50								7,440
Operating Income			15,362				9,642				(77	)							24,927
Interest Income			3				239				928				(1,144	)			26
Interest Expense			(2,579	)			(3,184	)			(456	)			1,144				(5,075	)
Interest Capitalized			38				1,465												1,503
Less: Minority Interest							(821	)											(821	)
Income Before Income Taxes		$	12,824			$	7,341			$	395							$	20,560

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 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 anticipated sales of inventory that is parked and anticipated purchases of inventory. At June 30, 2008, 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 June 30, 2008, the ending balance in Accumulated OCI for derivative transactions designated as cash flow hedges under SFAS 133 was a loss of $4,032,000, 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 June 30, 2008, Midstream recorded an unrealized gain of approximately $81,000, net of tax, resulting from hedge ineffectiveness. Hedge ineffectiveness is included in revenue.

For the three and nine months ended June 30, 2008, accumulated other comprehensive income decreased $3,332,000 and $4,054,000, net of tax, respectively. These decreases in the deferred hedging position were due primarily to increases in future commodity prices relative to the commodity prices stipulated in the derivative contracts. The net deferred hedging losses 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. All of the $4,032,000 deferred hedging loss as of June 30, 2008 is expected to be reclassified to net income within the next twelve months, of which approximately 9% will be reclassified in the fourth quarter of fiscal 2008, when the respective forecasted transactions will affect earnings.

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.

		June 30,				September 30,
Fair Value (in thousands)		2008				2007
Energy Marketing and Risk Management Assets, current		$	11,694			$	117
Energy Marketing and Risk Management Assets, long-term			640
Energy Marketing and Risk Management Liabilities, current			(16,375	)			(35	)
Energy Marketing and Risk Management Liabilities, long-term			(404	)
Net Assets (Liabilities)		$	(4,445	)		$	82

Note 9. Other Comprehensive Income (Loss)

Other Comprehensive Income (Loss) consisted of the following:

		Three Months Ended
		June 30,
(in thousands)		2008				2007
Net Income		$	3,204			$	1,334
Other Comprehensive Income (Loss):
Current period change in fair value of derivative instruments, net of tax benefit of $1,899			(3,124	)
Reclassification adjustment for derivative instruments, net of tax benefit of $127			(208	)
Comprehensive Income (Loss)		$	(128	)		$	1,334

		Nine Months Ended
		June 30,
(in thousands)		2008				2007
Net Income		$	13,562			$	12,778
Other Comprehensive Income (Loss):
Current period change in fair value of derivative instruments, net of tax benefit of $2,478			(4,076	)
Reclassification adjustment for derivative instruments, net of tax of $13			22
Comprehensive Income (Loss)		$	9,508			$	12,778

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

		June 30,				September 30,
(in thousands)		2008				2007
Unrealized gain (loss) on hedges, net of tax of $2,451 and $13		$	(4,032	)		$	22

Note 10. Acquisition of Assets

On October 31, 2007, Midstream formed a limited liability company, Mississippi Hub Acquisition Company LLC (“Acquisition”), that is 60% owned by Midstream and 40% owned by certain funds managed by affiliates of Fortress Investment Group LLC (the “Fortress Funds”) 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, Acquisition acquired the net assets of Mississippi Hub, LLC for $140 million. 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 in the first quarter of calendar 2010.

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 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 June 30, 2008, 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. The new system was completed and placed into service on March 1, 2008.

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 June 30, 2008, Bay Gas had entered into contracts for services to be performed in the development of the fourth storage cavern and pipeline facilities.

As of June 30, 2008, 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.

Midstream has entered into long-term agreements to obtain storage and transportation capacity through November 1, 2013. Midstream entered into two storage agreements with Kinder Morgan Texas which total two Bcf of storage capacity. The first agreement for one Bcf started April 1, 2008 and ends April 1, 2013. The second storage agreement, also for one Bcf, starts October 1, 2008 and ends April 1, 2013. Midstream entered into two separate intrastate transportation agreements with Kinder Morgan Texas Pipeline for 20,000 MMBtu per day which mirror the terms of the storage agreements. Midstream also entered into a transportation agreement with Natural Gas Pipeline Company of America (NGPL) for 25,000 MMBtu per day beginning April 1, 2008 and ending April 1, 2013. In addition, Midstream has entered into transportation agreements with Trunkline Gas Company, LLC for 25,000 MMBtu per day beginning October 1, 2008 and ending October 1, 2013 and for 25,000 MMBtu per day with Panhandle Eastern Pipe Line Company, LP beginning November 1, 2008 and ending November 1, 2013.

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

		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				Total
Distribution:
Gas Supply Contracts		$	3,079			$	2,742			$	1,161			$	829											$	7,811
Implementation of CIS Software			933																								933
Midstream:
Estimated Future Minimum Payments for Bay Gas Service Fees			159				638				638				638			$	638			$	31,950				34,661
Construction Contracts for Bay Gas’ Storage Facilities			25,065				33,166				6																58,237
Construction Contracts for Mississippi Hub Storage Facilities		17,248					23,030				82				82												40,442
Storage and Transportation Capacity			1,346				12,193				12,307				12,307				12,307				8,408				58,868
Total		$	47,830			$	71,769			$	14,194			$	13,856			$	12,945			$	40,358			$	200,952

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, 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.

Based on measurements of gas receipts and withdrawals, the Company potentially has unaccounted-for volumes of approximately 380,000 MMBtu on its Bay Gas system. The Company is in the process of reviewing its gas measurements as well as the measurements of supplier pipelines and customers to determine the reason for unaccounted-for volumes of gas. The likelihood of gas actually being lost and the likelihood that the Company would need to replace the gas cannot be determined at this time. The Company has not booked the unaccounted-for gas volumes as a liability on its balance sheet. The Company’s exposure for potential replacement of lost gas could range from zero to $4.7 million based on FGT Zone 3 prices at June 30, 2008. Should it be determined that there is lost gas, the Company believes that it would have recourse against third parties for replacement of the gas.

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 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 June 30, 2008. 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 does not expect SFAS 157 to have a significant impact on its financial statements.

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.

In March 2008, the FASB issued SFAS No, 161, “Disclosures About Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (SFAS 161), which requires entities to provide enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS 133, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 requires significant quantitative disclosures to be presented in a tabular format, including disclosures of the location, by line item, of fair value amounts of derivative instruments in the balance sheet and the location, by line item, of amounts o derivative gains and losoes reported in the income statement. SFAS 161 also requires entities to disclose information regarding the existence and nature of credit-risk-related contingent features included in derivative instruments that require the instrument to be settled or collateral posted in the event of a credit downgrade. SFAS 161 will be effective for the Company on October 1, 2009 and will change certain disclosures in the notes to the financial statements, but will have no impact on the Company’s financial position or results of operations.

Note 13. Subsequent Event

On July 25, 2008, the Company entered into an Agreement and Plan of Merger (Merger Agreement) with Sempra Energy in which Sempra Energy will acquire the Company for $510 million in cash. As a result of the merger, the Company will become a wholly owned indirect subsidiary of Sempra Energy. Shareholders of the Company will receive $61.50 per share for their Company stock. The merger transaction, which is subject to approval by the shareholders of the Company and regulators, is expected to close in the fourth quarter of calendar 2008. The boards of directors of Sempra Energy and the Company both have approved the merger

transaction. The Company filed a current report on Form 8-K with the Securities and Exchange Commission on July 29, 2008 (“July 29 Form 8-K”) which discloses the Merger Agreement.

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 and 51% owner 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 June 30, 2008 increased $0.16 and were unchanged for the nine months ended June 30, 2008, as compared to the same prior-year periods. The increase in earnings for the current year fiscal quarter was driven by the expansion of the Company’s midstream operations. Financial information by business segment is shown in Note 7 to the Unaudited Condensed Consolidated Financial Statements above.

Earnings from the Company’s midstream operations for the three months ended June 30, 2008 were $0.31 per diluted share, an increase of $0.14 per diluted share as compared to the same period last year. Earnings for the nine months ended June 30, 2008 were $0.53 per diluted share, a decrease of $0.04 per diluted share as compared to the same period last year. Earnings for each of the three and nine month periods include approximately $0.15 of net gains associated with storage and transportation hedge positions that are required to be marked-to-market. Approximately $0.09 of the $0.15 of net gains is margin not subject to price risk. Earnings also increased for the current year periods as a result of increased revenues associated with the commencement of operations of a third storage cavern in McIntosh, Alabama on April 1, 2008 and additional revenues from short-term storage agreements. These increases were offset by increased operating expenses incurred as a result of the continuing expansion of the midstream operations. The Company acquired assets in Mississippi in November 2007 and is currently developing storage caverns at that location. During the nine months ended June 30, 2008, in addition to the current development activities in Mississippi, expenses also increased in anticipation of the third storage cavern in McIntosh, Alabama that went into service on April 1, 2008

which increased the storage capacity of that facility from 6.0 Bcf to 11.4 Bcf of working gas. Additional compressors which serve the third cavern, as well as existing caverns, went into service in December 2007. Since the compressors are eligible for a fifty percent additional first year tax depreciation allowance under the Gulf Opportunity Zone Act of 2005, the Company will realize tax savings of approximately $4 million. As such, the Company incurred additional net interest expense of $0.06 per diluted share in the current year nine month period that was previously being capitalized and additional depreciation expense of $0.02 per diluted share.

Earnings from the Company’s natural gas distribution business increased $0.01 and $0.05 per diluted share, respectively, for the three- and nine- month periods ended June 30, 2008 as compared to the same prior-year periods due primarily to a decline in operating expenses.

Earnings from other business operations were unchanged for the three month period ended June 30, 2008 and decreased $0.01 per diluted share for the nine month period ended June 30, 2008 as compared to the same prior-year periods due primarily to a decrease in merchandise sales and related activities.

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.

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 increased $1,805,000 (10%) and decreased $2,198,000 (2%) during the three- and nine-month periods ended June 30, 2008 as compared to the same prior-year periods. Rate adjustments which reflect changes in gas costs paid to suppliers are the predominant reason for the change in revenues during the three- and nine- month periods ended June 30, 2008. Also contributing to the decreased revenues during the nine months ended June 30, 2008 was a decline in volumes delivered to customers. The decline in revenues for the nine months ended June 30, 2008 was partially offset by the amortization to revenues of the regulatory liability for gross receipts taxes and the RSE rate adjustment increase which went into effect on December 1, 2006.

Revenues from the sale of natural gas to temperature sensitive customers increased $1,954,000 (14%) and decreased $2,294,000 (3%), respectively, for the three- and nine- month periods ended June 30, 2008 due to the rate adjustments noted above. Additionally, revenues decreased during the nine month period due to a 7% decline in volumes delivered to customers as Mobile Gas’ service territory experienced weather that was 4% warmer than normal and 6% warmer than the prior year.

Revenues from the sale of natural gas to large commercial and industrial customers increased $43,000 (2%) and $239,000 (3%) for the three- and nine- month period ended June 30, 2008 due primarily to the rate adjustments noted above. Also contributing to the increased revenues during the nine month period was an increase in volumes delivered in the first quarter of fiscal 2008 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 were partially offset by the rate adjustments noted above. The increased usage by this customer was an isolated event and, as expected, did not continue during the second and third quarter periods.

Revenues from the transportation of natural gas to large commercial and industrial customers decreased $99,000 (52%) and $132,000 (21%) during the three- and nine-month periods ended June 30, 2008, due primarily to a reduction in the amortization of the regulatory liability 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 for the three month period ended June 30, 2008 increased $1,729,000 (20%) and decreased $1,851,000 (4%) for the nine-month period ended June 30, 2008 as compared to the same prior-year periods due to fluctuations in natural gas commodity prices.

Natural gas distribution margins, defined as revenues less cost of gas and related taxes, was unchanged for the three month period ended June 30, 2008 and decreased approximately 0.5% for the nine- month period ended June 30, 2008 as compared to the same prior-year periods. Increased margins realized from the return of the regulatory liability for gross receipts tax collections to ratepayers were more than offset by the RSE rate adjustment decrease which was effective December 1, 2007. Margins for the nine months ended March 31, 2008 were also

positively impacted by the RSE rate adjustment increase which was effective December 1, 2006 and were negatively impacted by a decline in usage per degree-day by temperature-sensitive customers. Consumption by residential temperature-sensitive customers, when adjusted for weather, decreased approximately 6% during the nine months ended June 30, 2008 compared to the same prior year period. 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. Usages per degree-day can and do vary between periods due to several factors including humidity, wind speed, cloud cover, and the duration of cold weather.

Operations and maintenance (O&M) expenses decreased $344,000 (6%) for the three months ended June 30, 2008 due to a decline in compensation and benefits expenses of approximately $356,000, a decrease in advertising related expenses of $148,000, and a decrease in training expense of $70,000. These decreases were partially offset by an increase in reserves for uncollectible accounts of $245,000. O&M expenses decreased $1,602,000 (9%) for the nine months ended June 30, 2008 as compared to the same prior-year period due to a decline in compensation and benefits expenses of approximately $1,211,000, a decrease in training expense of $119,000 and a decrease in advertising related expenses of $288,000.

Depreciation expense increased $99,000 (5%) and $297,000 (5%), respectively, for the three- and nine- month periods ended June 30, 2008 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 $73,000 (5%) and decreased $86,000 (1%), respectively, for the three- and nine- month periods ended June 30, 2008 due primarily to the fluctuation in revenues.

Interest expense increased $8,000 (1%) and $148,000 (6%), respectively, for the three-and nine- month periods ended June 30, 2008 as compared to the same prior-year periods 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.

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. Bay Gas’ third storage cavern and related facilities were placed into service on April 1, 2008. The new third cavern increases total working gas capacity by 5.4 Bcf, bringing total working gas capacity to 11.4 Bcf. An additional 0.4 Bcf of working gas capacity was achieved during the development process, over the original planned capacity of 5.0 Bcf for the third cavern. The cavern’s original storage capacity was fully contracted in August of 2006. Additional capacity development of 0.6 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 a new pipeline interconnect with Transco and an additional pipeline interconnect with Florida Gas Transmission. Midstream has commitments for long term storage services for 92% of the 5.0 Bcf capacity for Bay Gas’ fourth cavern and expects the remainder to be contracted by the end of calendar year 2008. Bay Gas has drilled a well and has begun salt cavern leaching for development of the fourth cavern and its related pipeline interconnects and plans to move forward with development of the fifth cavern. Cavern four has an expected in service date of the first calendar quarter of 2010 and would add 5.0 Bcf of total working gas capacity.

On November 28, 2007, Acquisition acquired certain natural gas storage assets currently under development. The previous owners received section 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 has commitments in place for a majority of the 7.5 Bcf of the first of two caverns which is expected to be operational in the first calendar quarter of 2010. The second cavern has a planned in-service date of mid-calendar year 2011. Midstream expects to complete pipeline interconnects with Sonat, SESH, and Transco.

Financial information about the midstream business segment is shown in Note 7 to the Unaudited Condensed Consolidated Financial Statements above. Midstream’s revenues increased $6,787,000 (131%) and $8,714,000 (54%), respectively, during the three- and nine- month periods ended June 30, 2008 as compared to the same prior-year periods due to increased revenues of approximately $2,557,000 associated with the commencement of operations of Bay

Gas’ third storage cavern on April 1, 2008 and an increase in revenues from short-term storage agreements, including margins captured through the arbitrage of pricing differences in various time periods and locations. 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. For the three and nine month periods ended June 30, 2008, revenues from short-term storage agreements includes approximately $1.9 million of net unrealized gains associated with storage and transportation hedge positions that are required to be marked-to-market for accounting purposes. Of this $1.9 million, $1.2 million is derived from financial trades that are hedging physical transportation and storage positions and is not subject to price risk.

Operations and maintenance (O&M) expenses increased $3,742,000 and $6,840,000 during the three- and nine- month periods ended June 30, 2008 as compared to the same prior-year periods due to increased expenses incurred as a result of the continuing expansion of Midstream’s operations, including the development of the Mississippi Hub assets acquired in November 2007. The increase in expenses resulted from an increase in compensation and related benefits of approximately $2,223,000 and $3,696,000, respectively, increased legal expenses of $132,000 and $437,000, respectively, consulting services of $276,000 and $661,000, respectively, increased insurance of $53,000 and $126,000, respectively, increased utilities of $563,000 and $714,000, respectively, increased expenses of $74,000 and $214,000, respectively, related to Bay Gas’ cavern lease payments, and increased office expenses and general repairs and maintenance due to the growth of Midstream’s operations.

Depreciation expense increased $310,000 (48%) and $895,000 (46%), respectively, for the three- and nine- month periods ended June 30, 2008 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 $86,000 (32%) and $290,000 (38%), respectively, during the three- and nine- month periods ended June 30, 2008 as compared to the same prior-year periods.

Interest expense increased $3,130,000 and $8,482,000, respectively, for the three- and nine- month periods ended June 30, 2008 due primarily to increased borrowings to fund Midstream’s capital expansion projects at Bay Gas and Mississippi Hub.

Capitalized interest costs increased $1,354,000 and $4,390,000, respectively, for the three- and nine- month periods ended June 30, 2008 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 $161,000 and $734,000, respectively, during the three- and nine- month periods ended June 30, 2008 as compared to the same prior-year periods due to pretax losses of Mississippi Hub.

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 June 30, 2008 approximated the same prior year period and decreased $111,000 for the nine- month period ended June 30, 2008 due primarily to a decrease in merchandise sales and related merchandising activities.

Income Taxes

Income taxes fluctuate with the change in income before income taxes. Income tax expense increased $1,132,000 and $464,000 (6%) for the three- and nine- month periods ended June 30, 2008 as compared to the same prior-year periods.

Liquidity and Capital Resources

The Company generally relies on cash generated from operations and, on a temporary basis, short-term borrowings, to meet working capital requirements and to finance normal capital expenditures. The Company issues debt and equity for longer term financing as needed. Impacts of operating, investing, and financing activities are shown on the Unaudited Condensed Consolidated Statements of Cash Flows. Operating activities provided $5,122,000 more cash during the nine-month period ended June 30, 2008 than in the same period last fiscal year due to an increase in accounts payable of $72,283,000 as payables for natural gas at June 30, 2008 were significantly higher due to the trading activities of Services. Additionally, cash flows were provided by an increase in depreciation expenses of $1,230,000 and an increase in deferred income taxes of $2,490,000. Offsetting these cash flows provided by operating activities was an increase in gas inventory stored underground of $50,011,000, an increase in current taxes paid of $2,170,000, an increase in accounts receivable of $7,097,000, an increase in cash held on deposit in a margin account for trading of $8,878,000, and $1,944,000 of unrealized gains from trading activities of Services. 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.

Cash used in investing activities reflects the capital-intensive nature of the Company’s business. During the nine months ended June 30, 2008, the Company used cash of $214,582,000 for investing activities including the purchase of its interest in the net assets of Mississippi Hub and the construction of distribution and storage facilities, purchases of equipment and other general improvements. Midstream invested $163,205,000 in the purchase and development of its interest in Mississippi Hub and $39,196,000 in the development of Bay Gas’ third and fourth salt-dome storage caverns. The remainder was invested in Mobile Gas’ distribution system and other general improvements. During the nine-month period ended June 30, 2007, the Company used cash of $32,062,000 for the purchase and construction of distribution and storage facilities, purchases of equipment and other general improvements, of which $22,710,000 was used in the ongoing development of Bay Gas’ third salt-dome storage cavern.

Financing activities provided cash of $205,130,000 during the nine months ended June 30, 2008 due primarily to $137,025,000 in increased borrowings under the Company’s amended credit

facility discussed below and $76,652,000 in capital contributions from the minority partner for its 40% interest in Mississippi Hub. Cash was also provided by stock options exercised and the related tax benefits realized from share-based payments of $3,541,000. These cash receipts were partially offset by the payment of quarterly dividends of $6,159,000, repayment of long-term debt of $4,931,000 and debt issuance costs of $1,137,000 related to the amendment of the Company’s credit facility. Financing activities provided cash of $5,053,000 during the nine months ended June 30, 2007 due primarily to an increase in short-term borrowings of $14,690,000 and stock options exercised of $459,000. Partially offsetting these cash receipts was the payment of quarterly dividends of $5,659,000 and payments on long term debt of $4,716,000.

Midstream’s anticipated capital expenditures include Bay Gas’ projected expenditures for fiscal 2008 and 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 will also 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 capital expenditures by Bay Gas to total approximately $26 million during the fourth quarter of fiscal 2008.

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 $30 million in the fourth quarter of 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 (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 capital contribution in connection with the acquisition of its Mississippi Hub LLC interest. At June 30, 2008, the Company had $46 million available for borrowing under the Credit Facility and $47 million in unused funds from the Bonds which are included in restricted cash on the Unaudited Condensed Consolidated Balance Sheet. On July 25, 2008, the Company amended the Credit Facility to increase the available borrowings by an additional $30 million. The amendment to the Credit Facility is disclosed in the July 29 Form 8-K. See Note 13 to the Unaudited Condensed Consolidated Financial Statements above.

The Company expects to fund near-term construction at Bay Gas through the continued draw down of funds from the Bond proceeds, the Credit Facility, internal cash generation, and minority partner contributions. Mississippi Hub LLC near term construction will be funded from cash on hand, the Credit Facility and minority member contributions. Management believes that these sources provide adequate funding for cash needs until the effective date of the merger under the Merger Agreement which is expected to be in the fourth quarter of calendar 2008. See Note 13 to the Unaudited Condensed Consolidated Financial Statements above.

The table below summarizes the Company’s contractual obligations and commercial commitments as of June 30, 2008:

		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		$	2,799			$	6,054			$	5,653			$	5,955			$	6,307			$	96,491
Interest Payments (1)			1,932				6,127				5,630				5,159				4,660				33,467
Estimated Future Minimum Payments for Bay Gas Service Fees			159				638				638				638				638				31,950
Construction Contracts for Bay Gas’ Storage Facilities			25,065				33,166				6
Construction Contracts for Mississippi Hub Storage Facilities			17,248				23,030				82				82
Storage and Transportation Capacity			1,346				12,193				12,307				12,307				12,307				8,408
Implementation of CIS Software			933
Gas Supply Contracts			3,079				2,742				1,161				829
Total		$	52,561			$	83,950			$	25,477			$	24,970			$	23,912			$	170,316

(1)		Amounts include estimated interest payments on $55 million Industrial Revenue Bonds and are based on the effective rate as of June 30, 2008 of 1.6%.

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 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 June 30, 2008, Mobile Gas had not entered into derivative instruments for the purpose of hedging the price of natural gas. If Mobile Gas had entered into such derivative instruments, any cost incurred or benefit received from the derivative or other hedging arrangements would be recoverable or refunded through the purchased gas adjustment mechanism. As discussed in “Results of Operations” under “Natural Gas Distribution” within Item 2 above , the APSC currently allows for full recovery of all costs associated with natural gas purchases; therefore, costs associated with the forward purchases of natural gas will be passed through to customers when realized and should not affect future earnings.

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 and prices provided by other external sources. The following tables show the components of change in fair value of derivative instruments utilized in Midstream’s energy marketing and risk management assets and liabilities during the three and nine months ended June 30, 2008.