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, 2003
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Commission File No. 0-29604
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ENERGYSOUTH, INC.
-----------------
(Exact name of registrant as specified in its charter)
Alabama 58-2358943
- ------------------------------- -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) 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 [X] No [ ]
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 1, 2003 - 5,112,156 shares.
ENERGYSOUTH, INC.
INDEX
<Table>
<Caption>
Page No.
--------
PART I. Financial Information (Unaudited):
Consolidated Balance Sheets - June 30,
2003 and 2002 and September 30, 2002 3 - 4
Consolidated Statements of Income - Three and
Nine Months Ended June 30, 2003 and 2002 5
Consolidated Statements of Cash Flows - Nine
Months Ended June 30, 2003 and 2002 6
Notes to Consolidated Financial Statements 7 - 12
Management's Discussion and Analysis of
Financial Condition and Results of Operations 13 - 21
Quantitative and Qualitative Disclosures About
Market Risk 21
Controls and Procedures 21
PART II. Other Information 22 - 26
</Table>
2
PART 1. FINANCIAL INFORMATION
CONSOLIDATED BALANCE SHEETS
<Table>
<Caption>
ENERGYSOUTH, INC. June 30, September 30,
-------------------------- -------------
In Thousands 2003 2002 2002
- ------------ --------- --------- -------------
(Unaudited)
ASSETS
CURRENT ASSETS
Cash and Cash Equivalents $ 5,766 $ 9,770 $ 10,562
Receivables
Gas 7,422 6,408 4,733
Unbilled Revenue 1,540 1,059 956
Merchandise 2,455 2,679 2,621
Other 701 1,147 752
Allowance for Doubtful Accounts (1,599) (1,552) (951)
Materials, Supplies, and Merchandise, Net (At Average Cost) 1,259 2,019 1,598
Gas Stored Underground (At Average Cost) 1,757 961 3,086
Deferred Purchased Gas Adjustment 1,640 -- --
Deferred Income Taxes 1,068 2,810 2,583
Prepayments 1,031 916 777
--------- --------- ---------
Total Current Assets 23,040 26,217 26,717
--------- --------- ---------
PROPERTY, PLANT, AND EQUIPMENT 263,116 224,049 227,740
Less: Accumulated Depreciation and Amortization 72,777 65,610 66,912
--------- --------- ---------
Property, Plant, and Equipment - Net 190,339 158,439 160,828
Construction Work in Progress 1,701 24,955 26,995
--------- --------- ---------
Total Property, Plant, and Equipment 192,040 183,394 187,823
--------- --------- ---------
OTHER ASSETS
Prepaid Pension Cost 712 180 318
Deferred Charges 494 572 566
Prepayments 1,029 1,081 1,067
Regulatory Assets 1,340 743 653
Merchandise Receivables Due After One Year 4,005 4,562 4,463
--------- --------- ---------
Total Other Assets 7,580 7,138 7,067
--------- --------- ---------
TOTAL $ 222,660 $ 216,749 $ 221,607
--------- --------- ---------
</Table>
See Accompanying Notes to Consolidated Financial Statements
3
CONSOLIDATED BALANCE SHEETS
<Table>
<Caption>
ENERGYSOUTH, INC. June 30, September 30,
----------------------- -------------
In Thousands, Except Share Data 2003 2002 2002
- ------------------------------- -------- -------- -------------
(Unaudited)
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES
Current Maturities of Long-Term Debt $ 4,668 $ 2,393 $ 3,909
Notes Payable -- 7,550 --
Accounts Payable 4,674 5,668 5,735
Dividends Declared 1,454 1,353 1,363
Customer Deposits 1,417 1,494 1,475
Taxes Accrued 4,311 4,875 3,930
Interest Accrued 578 588 1,342
Deferred Purchased Gas Adjustment -- 3,191 3,182
Unearned Revenue (Note 8) -- 1,896 1,378
Other 1,159 1,206 1,235
-------- -------- --------
Total Current Liabilities 18,261 30,214 23,549
-------- -------- --------
OTHER LIABILITIES
Accrued Postretirement Benefit Cost 474 624 570
Deferred Income Taxes 17,228 14,408 15,275
Deferred Investment Tax Credits 296 325 314
Other 3,610 2,361 2,326
-------- -------- --------
Total Other Liabilities 21,608 17,718 18,485
-------- -------- --------
Total Liabilities 39,869 47,932 42,034
-------- -------- --------
CAPITALIZATION
Stockholders' Equity
Common Stock, $.01 Par Value
(Authorized 10,000,000 Shares; Outstanding
June 2003 - 5,103,000 Shares;
June 2002 - 5,013,000 Shares;
September 2002 - 5,048,000 Shares) 51 50 50
Capital in Excess of Par Value 22,761 20,932 21,607
Retained Earnings 61,360 56,112 55,626
-------- -------- --------
Total Stockholders' Equity 84,172 77,094 77,283
Minority Interest 4,000 3,524 3,645
Long-Term Debt 94,619 88,199 98,645
-------- -------- --------
Total Capitalization 182,791 168,817 179,573
-------- -------- --------
TOTAL $222,660 $216,749 $221,607
-------- -------- --------
</Table>
See Accompanying Notes to Consolidated Financial Statements
4
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
<Table>
<Caption>
Three Months Nine Months
Ended June 30, Ended June 30,
------------------------ ------------------------
In Thousands, Except Per Share Data 2003 2002 2003 2002
- ----------------------------------- -------- -------- -------- --------
OPERATING REVENUES
Gas Revenues $ 19,605 $ 15,251 $ 78,415 $ 68,175
Merchandise Sales 709 850 2,549 2,633
Other 269 333 930 1,055
-------- -------- -------- --------
Total Operating Revenues 20,583 16,434 81,894 71,863
-------- -------- -------- --------
OPERATING EXPENSES
Cost of Gas 5,855 3,171 26,632 20,130
Cost of Merchandise 586 970 1,940 2,369
Operations and Maintenance 6,414 5,991 19,002 18,127
Depreciation 2,291 2,101 6,855 6,291
Taxes, Other Than Income Taxes 1,601 1,416 5,929 5,366
-------- -------- -------- --------
Total Operating Expenses 16,747 13,649 60,358 52,283
-------- -------- -------- --------
OPERATING INCOME 3,836 2,785 21,536 19,580
-------- -------- -------- --------
OTHER INCOME AND (EXPENSE)
Interest Expense (2,109) (1,963) (6,260) (6,064)
Allowance for Borrowed Funds Used During Construction 14 512 1,142 1,491
Interest Income 18 14 56 279
Minority Interest (177) (142) (563) (533)
-------- -------- -------- --------
TOTAL OTHER INCOME (EXPENSE) (2,254) (1,579) (5,625) (4,827)
-------- -------- -------- --------
INCOME BEFORE INCOME TAXES 1,582 1,206 15,911 14,753
Income Taxes 596 302 5,992 5,398
-------- -------- -------- --------
NET INCOME $ 986 $ 904 $ 9,919 $ 9,355
======== ======== ======== ========
EARNINGS PER SHARE
Basic $ 0.19 $ 0.18 $ 1.96 $ 1.88
-------- -------- -------- --------
Diluted $ 0.19 $ 0.18 $ 1.94 $ 1.85
-------- -------- -------- --------
AVERAGE COMMON SHARES OUTSTANDING
Basic 5,080 4,993 5,058 4,968
Diluted 5,133 5,098 5,116 5,060
-------- -------- -------- --------
</Table>
See Accompanying Notes to Consolidated Financial Statements
5
CONSOLIDATED STATEMENTS
OF CASH FLOWS
(Unaudited)
<Table>
<Caption>
NINE MONTHS
ENERGYSOUTH, INC. ENDED JUNE 30,
------------------------
In Thousands 2003 2002
- ------------ -------- --------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 9,919 $ 9,355
ADJUSTMENTS TO RECONCILE NET INCOME TO NET CASH
PROVIDED BY OPERATING ACTIVITIES
Depreciation and Amortization 7,141 6,623
Provision for Losses on Receivables and Inventory 575 907
Provision for Deferred Income Taxes 3,538 1,602
Minority Interest 563 533
Changes in Operating Assets and Liabilities:
Receivables (2,502) 2,081
Inventory 1,633 3,068
Payables (1,349) (4,196)
Deferred Purchased Gas Adjustment (4,822) (1,517)
Other (1,546) (2)
-------- --------
Net Cash Provided by Operating Activities 13,150 18,454
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures (11,251) (19,303)
Changes in Temporary Investments 3,000
-------- --------
Net Cash Used by Investing Activities (11,251) (16,303)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Repayment of Long-Term Debt (3,267) (1,859)
Changes in Short-Term Borrowings -- (5,685)
Payment of Dividends (4,185) (3,931)
Dividend Reinvestment 264 252
Exercise of Stock Options 701 1,068
Partnership Distributions to Minority Interest Holders (208) (278)
-------- --------
Net Cash Used by Financing Activities (6,695) (10,433)
-------- --------
NET DECREASE IN CASH AND CASH EQUIVALENTS (4,796) (8,282)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 10,562 18,052
-------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 5,766 $ 9,770
======== ========
</Table>
See Accompanying Notes to Consolidated Financial Statements
6
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Note 1. The consolidated financial statements of EnergySouth, Inc. (EnergySouth)
and its subsidiaries (collectively, the Company) include the accounts of Mobile
Gas Service Corporation (Mobile Gas); EnergySouth Services, Inc. (Services); MGS
Storage Services, Inc. (Storage); MGS Marketing Services, Inc. (Marketing); a
90.9% owned partnership, Bay Gas Storage Company, Ltd. (Bay Gas), and a 51%
owned partnership, Southern Gas Transmission Company (SGT). Minority interest
represents the respective other owners' proportionate shares of the income and
equity of Bay Gas and SGT. All significant intercompany balances and
transactions have been eliminated.
In December 2002, FASB issued Statement of Financial Accounting Standards No.
148, "Accounting for Stock-Based Compensation - Transition and Disclosure, an
amendment of FASB Statement No. 123" (SFAS 148). SFAS 148 amends FASB Statement
No. 123, "Accounting for Stock-Based Compensation," to provide alternative
methods of transition for an entity that voluntarily changes to the fair value
based method of accounting for stock-based compensation and requires prominent
disclosure about the effects on reported net income with respect to stock based
employee compensation. SFAS 148 also amends APB Opinion No. 28, "Interim
Financial Reporting," to require disclosure about those effects in interim
financial information. The disclosure requirements of SFAS 148 were adopted by
the Company during the quarter ending March 31, 2003, and the relevant interim
information has been disclosed in Note 9.
Note 2. The accompanying unaudited condensed financial statements have been
prepared in accordance with the instructions to Form 10-Q and do not include all
of the information and disclosures required by accounting principles generally
accepted in the United States of America for complete financial statements. All
adjustments, consisting of normal and recurring accruals, which are, in the
opinion of management, necessary to present fairly the results for the interim
periods have been made. The statements should be read in conjunction with the
summary of accounting policies and notes to financial statements included in the
Annual Report on Form 10-K of the Company for the fiscal year ended September
30, 2002.
Note 3. Due to the high percentage of customers using 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, 2003 and 2002 are
not indicative of the results to be expected for the full year.
7
The table below summarizes operating results for the twelve months ended June
30, 2003 and 2002:
<Table>
<Caption>
Twelve Months
ENERGYSOUTH, INC. Ended June 30,
------------------------
IN THOUSANDS, EXCEPT PER SHARE DATA 2003 2002
- ----------------------------------- -------- --------
Operating Revenues $ 96,506 $ 86,731
Cost of Gas 28,769 24,220
Cost of Merchandise 2,815 2,903
Operations and Maintenance Expense 24,386 22,324
Depreciation Expense 8,736 8,147
Taxes, Other Than Income Taxes 7,112 6,719
-------- --------
Operating Income 24,688 22,418
-------- --------
Interest Income (Expense) - Net (8,242) (7,742)
Allowance for Borrowed Funds Used
During Construction 1,695 2,144
Less: Minority Interest (770) (679)
-------- --------
INCOME BEFORE INCOME TAXES $ 17,371 $ 16,141
-------- --------
Income Taxes 6,577 6,090
NET INCOME $ 10,794 $ 10,051
======== ========
EARNINGS PER SHARE
Basic $ 2.14 $ 2.03
-------- --------
Diluted $ 2.11 $ 1.99
-------- --------
AVERAGE COMMON SHARES OUTSTANDING
Basic 5,048 4,960
-------- --------
Diluted 5,108 5,045
-------- --------
</Table>
Note 4. On June 10, 2002, the Alabama Public Service Commission (APSC) approved
Mobile Gas' request for the Rate Stabilization and Equalization (RSE) rate
setting process to be effective October 1, 2002 through September 30, 2005 and
thereafter, unless modified or discontinued by APSC order. Under RSE, the APSC
conducts quarterly reviews to determine, based on Mobile Gas' projections and
fiscal year-to-date performance, whether Mobile Gas' return on equity is
expected to be within the allowed range of 13.35% to 13.85%. Reductions in rates
can be made quarterly to bring the projected return within the allowed range;
increases, however, are allowed only once each fiscal year, effective December
1, and cannot exceed four percent of prior-year revenues. 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
8
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. To the extent the change is less than the
index range, the utility benefits by one-half of the difference through future
rate adjustments.
In conjunction with the approval of RSE, the APSC approved an Enhanced Stability
Reserve (ESR), beginning October 1, 2002, to which Mobile Gas may charge the
full amount of: 1) extraordinary O&M expenses resulting 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 (the "Initial Reserve Balance") has been recorded October 1,
2002 within Regulatory Assets and Other Long-Term Liabilities on the
accompanying balance sheet and is being recovered from customers, up to an
amount in any one year not to exceed one-third of the Initial Reserve Balance,
through rates beginning October 1, 2002.
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
margin. The adjustment is calculated monthly for the months of November through
April and applied to customers' bills in the same billing cycle in which the
weather variation occurs. The temperature adjustment rider applies to
substantially all residential and small commercial customers.
Note 5. The Company is principally engaged in two reportable business segments:
Natural Gas Distribution and Natural Gas Storage. The Natural Gas Distribution
segment is actively engaged in the distribution and transportation of natural
gas to residential, commercial and industrial customers through Mobile Gas and
SGT. The Natural Gas Storage segment provides for the underground storage of
natural gas and transportation services through the operations of Bay Gas and
Storage. Through Marketing, Mobile Gas, and Services, the Company also provides
marketing, merchandising, and other energy-related services which are aggregated
with EnergySouth, the holding company, and included in the Other segment.
Segment earnings information presented in the table below includes intersegment
revenues which are eliminated in consolidation. Such intersegment revenues are
primarily amounts paid by the Natural Gas Distribution segment to the Natural
Gas Storage segment.
9
<Table>
<Caption>
FOR THE THREE MONTHS ENDED NATURAL GAS NATURAL GAS
JUNE 30, 2003 (IN THOUSANDS): DISTRIBUTION STORAGE OTHER ELIMINATIONS CONSOLIDATED
- ----------------------------- ------------ ----------- ----- ------------ ------------
Operating Revenues $ 16,461 $ 4,181 $ 978 $ (1,037) $ 20,583
Cost of Gas 6,888 (1,033) 5,855
Cost of Merchandise 586 586
Operations and Maintenance Expense 5,275 817 326 (4) 6,414
Depreciation Expense 1,756 535 2,291
Taxes, Other Than Income Taxes 1,420 171 10 1,601
-------- ------- ----- -------- --------
Operating Income 1,122 2,658 56 -- 3,836
-------- ------- ----- -------- --------
Interest Income (Expense) - Net (830) (1,175) (86) (2,091)
Allow. for Borrowed Funds Used
During Construction 14 -- 14
Less: Minority Interest (42) (135) (177)
-------- ------- ----- -------- --------
Income Before Income Taxes $ 264 $ 1,348 $ (30) $ 1,582
======== ======= ===== ======== ========
</Table>
<Table>
<Caption>
FOR THE THREE MONTHS ENDED NATURAL GAS NATURAL GAS
JUNE 30, 2002 (IN THOUSANDS): DISTRIBUTION STORAGE OTHER ELIMINATIONS CONSOLIDATED
- ----------------------------- ------------ ----------- ------- ------------ ------------
Operating Revenues $ 13,480 $ 2,816 $ 1,176 $ (1,038) $ 16,434
Cost of Gas 4,203 (1,032) 3,171
Cost of Merchandise & Jobbing 970 970
Operations and Maintenance Expense 5,051 599 347 (6) 5,991
Depreciation Expense 1,658 437 6 2,101
Taxes, Other Than Income Taxes 1,280 125 11 1,416
-------- ------- ------- -------- --------
Operating Income 1,288 1,655 (158) -- 2,785
-------- ------- ------- -------- --------
Interest Income (Expense) - Net (772) (1,117) (60) (1,949)
Allow. for Borrowed Funds Used
During Construction 8 504 512
Less: Minority Interest (48) (94) (142)
-------- ------- ------- -------- --------
Income Before Income Taxes $ 476 $ 948 $ (218) $ 1,206
======== ======= ======= ======== ========
</Table>
<Table>
<Caption>
FOR THE NINE MONTHS ENDED NATURAL GAS NATURAL GAS
JUNE 30, 2003 (IN THOUSANDS): DISTRIBUTION STORAGE OTHER ELIMINATIONS CONSOLIDATED
- ----------------------------- ------------ ----------- ------- ------------ ------------
Operating Revenues $ 71,191 $ 10,397 $ 3,475 $ (3,169) $ 81,894
Cost of Gas 29,775 (3,143) 26,632
Cost of Merchandise & Jobbing 1,940 1,940
Operations and Maintenance Expense 15,989 1,888 1,151 (26) 19,002
Depreciation Expense 5,268 1,587 6,855
Taxes, Other Than Income Taxes 5,379 512 38 5,929
-------- -------- ------- -------- --------
Operating Income 14,780 6,410 346 -- 21,536
-------- -------- ------- -------- --------
Interest Income (Expense) - Net (2,631) (3,429) (144) (6,204)
Allow. for Borrowed Funds Used
During Construction 32 1,110 1,142
Less: Minority Interest (189) (374) (563)
-------- -------- ------- -------- --------
Income Before Income Taxes $ 11,992 $ 3,717 $ 202 $ 15,911
======== ======== ======= ======== ========
</Table>
10
<Table>
<Caption>
FOR THE NINE MONTHS ENDED NATURAL GAS NATURAL GAS
JUNE 30, 2002 (IN THOUSANDS): DISTRIBUTION STORAGE OTHER ELIMINATIONS CONSOLIDATED
- ----------------------------- ------------ ----------- ------- ------------ ------------
Operating Revenues $ 63,044 $ 8,335 $ 3,674 $ (3,190) $ 71,863
Cost of Gas 23,289 (3,159) 20,130
Cost of Merchandise & Jobbing 2,369 2,369
Operations and Maintenance Expense 15,256 1,638 1,264 (31) 18,127
Depreciation Expense 4,975 1,299 17 6,291
Taxes, Other Than Income Taxes 4,964 356 46 5,366
-------- ------- ------- -------- --------
Operating Income 14,560 5,042 (22) -- 19,580
-------- ------- ------- -------- --------
Interest Income (Expense) - Net (2,401) (3,254) (130) (5,785)
Allow. for Borrowed Funds Used
During Construction 30 1,461 1,491
Less: Minority Interest (239) (294) (533)
-------- ------- ------- -------- --------
Income Before Income Taxes $ 11,950 $ 2,955 $ (152) $ 14,753
======== ======= ======= ======== ========
</Table>
Note 6. Basic earnings per share are computed based on the weighted average
number of common shares outstanding during each period. Diluted earnings per
share are computed based on the weighted average number of common shares
outstanding and diluted potential common shares, using the treasury stock
method, outstanding during each period.
Average common shares used to compute basic earnings per share differed from
average common shares used to compute diluted earnings per share by equivalent
shares of 53,000 and 105,000 for the three months ended June 30, 2003 and 2002,
respectively, and 58,000 and 92,000 for the nine months ended June 30, 2003 and
2002, respectively. These differences in equivalent shares are from outstanding
stock options.
Note 7. In June 2002, FASB issued Statement of Financial Accounting Standards
No. 146, "Accounting for Costs Associated with Exit or Disposal Activities"
(SFAS 146). This Statement nullifies Emerging Issues Task Force Issue No. 94-3,
"Liability Recognition for Certain Employee Termination Benefits and Other Costs
to Exit an Activity (including Certain Costs Incurred in a Restructuring)," and
addresses the recognition and measurement of costs associated with an exit
activity that does not involve an entity newly acquired in a business
combination or with a disposal activity covered by SFAS 144. SFAS 146 applies to
all disposal activities initiated after December 31, 2002. SFAS 146 was adopted
by the Company in the second quarter of 2003 and did not have an impact on the
Company's financial statements.
Note 8. In November 2001, Bay Gas entered into an agreement which granted a
customer a nineteen-month option to transport additional volumes in excess of
the volumes currently under long-term contract. During the first quarter of
fiscal 2002, Bay Gas received $3,274,000 in consideration of the option
agreement, which was fully amortized as of the end of May 2003.
11
Note 9. At the Annual Meeting of the Stockholders of EnergySouth, Inc. on
January 31, 2003, the stockholders approved the 2003 Stock Option Plan of
EnergySouth, Inc. (the 2003 Plan). The Company's previous stock option plan, the
Amended and Restated Stock Option Plan of EnergySouth, Inc. (the Plan), which
expired on December 4, 2002, provided for the granting of incentive stock
options, non-qualified stock options, and stock appreciation rights to key
employees. Stock options granted under the Plan became 25% exercisable on the
first anniversary of the grant date and an additional 25% became exercisable in
each of the next three succeeding years. No option granted under the Plan may be
exercised after the expiration of ten years from the grant date, and such
options were granted at option prices which represented the market price on the
grant date. The 2003 Plan provides for substantially similar option grants. As
of June 30, 2003, 45,000 options had been granted under the 2003 Plan.
The Company accounts for the plans under the recognition and measurement
principles of APB Opinion 25, "Accounting for Stock Issued to Employees," and
related Interpretations. No stock-based compensation cost is reflected in net
income, as all options granted under those plans had an exercise price equal to
the market value of the underlying common stock on the date of grant. The
following table illustrates the effect on net income and earnings per share if
the Company had applied the fair value recognition provisions of FASB Statement
No. 123, "Accounting for Stock-Based Compensation," to stock-based employee
compensation.
<Table>
<Caption>
Three Months Nine Months
ENERGYSOUTH, INC. Ended June 30, Ended June 30,
------------------------- -------------------------
In Thousands, Except per Share Data 2003 2002 2003 2002
- ----------------------------------- --------- --------- --------- ---------
NET INCOME, AS REPORTED $ 986 $ 904 $ 9,919 $ 9,355
Deduct:
Total stock-based employee compensation
expense determined under fair value based
method for all awards, net of related tax effects 42 33 117 95
--------- --------- --------- ---------
PRO FORMA NET INCOME $ 944 $ 871 $ 9,802 $ 9,260
--------- --------- --------- ---------
EARNINGS PER SHARE:
Basic - as reported $ 0.19 $ 0.18 $ 1.96 $ 1.88
--------- --------- --------- ---------
Basic - pro forma $ 0.18 $ 0.17 $ 1.94 $ 1.86
--------- --------- --------- ---------
Diluted - as reported $ 0.19 $ 0.18 $ 1.94 $ 1.85
--------- --------- --------- ---------
Diluted - pro forma $ 0.18 $ 0.17 $ 1.92 $ 1.83
--------- --------- --------- ---------
</Table>
12
ITEM 2 MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
THE COMPANY
EnergySouth, Inc. (EnergySouth) is a holding company for a family of energy
businesses. EnergySouth and its consolidated subsidiaries are collectively
referred to herein as the "Company." The Company, through Mobile Gas Service
Corporation (Mobile Gas) and Southern Gas Transmission Company (SGT), is engaged
in the distribution of natural gas to residential, commercial and industrial
customers in southwest Alabama. Through Bay Gas Storage Company, Ltd. (Bay Gas),
the Company provides underground natural gas storage services and transportation
services. Other EnergySouth subsidiaries are engaged in gas marketing,
merchandising and other energy-related services.
RESULTS OF OPERATIONS
CONSOLIDATED EARNINGS
All earnings per share amounts referred to herein are computed on a diluted
basis. Earnings per share for the three and nine months ended June 30, 2003
increased $0.01 and $0.09, respectively, due primarily to increased earnings
from Bay Gas' natural gas storage business. Financial information by business
segment is shown in Note 5 to the unaudited Consolidated Financial Statements
above.
Earnings from the Company's natural gas distribution business decreased $0.03
and $0.01, respectively, for the three and nine-month periods ended June 30,
2003. Mobile Gas' earnings were positively impacted by a rate adjustment which
became effective December 1, 2002 based upon the guidelines established under
the Rate Stabilization and Equalization (RSE) tariff. For further information on
RSE, see "Natural Gas Distribution" below. Because of the rate adjustment,
margins from temperature-sensitive customers and commercial customers increased
during the three and nine-month periods; however, these increases were offset by
an increase in operating expenses and depreciation expense.
The Company's natural gas storage business, operated by Bay Gas, contributed
increased earnings per share of $0.03 and $0.06, respectively, for the three and
nine-month periods ended June 30, 2003 as compared to the same prior year
periods. The positive earnings contribution is due primarily to increased
storage revenues from the second cavern, increased transportation revenues, and
revenues realized from short-term interruptible storage contracts. Increased
revenues were partially offset by additional operations and maintenance costs,
depreciation expense and property taxes as major expansion projects were
completed and placed into service.
Earnings from other business operations increased $0.01 and $0.04, respectively,
for the three and nine-month periods ended June 30, 2003. The prior-year periods
included losses
13
associated with the exit from the natural gas generator sales business and the
closing of a retail specialty store.
NATURAL GAS DISTRIBUTION
The natural gas distribution segment of the Company is actively engaged in the
distribution and transportation of natural gas to residential, commercial and
industrial customers in southwest Alabama through Mobile Gas and SGT.
The Alabama Public Service Commission (APSC) regulates the Company's gas
distribution operations. Mobile Gas' rate tariffs for gas distribution allow a
pass-through to customers of the cost of gas, certain taxes, and incremental
costs associated with the replacement of cast iron mains. These costs,
therefore, have little direct impact on the Company's margins. Colder than
normal weather during the 2002-2003 winter heating season, lower national
storage levels, and increased natural gas electric generation facilities have
combined to drive natural gas prices to the highest levels in two years. Mobile
Gas follows a gas purchasing strategy to secure prices for a portion of its gas
supply needs for the winter heating season by locking in gas prices at fixed
rates. Mobile Gas' strategy for purchasing gas and the Company's use of natural
gas storage capacity helped to mitigate the impact of increased prices on
customers' bills this past winter. Effective March 1, 2003, however, Mobile Gas
adjusted its rates to reflect increased gas costs paid to its suppliers.
The Company's distribution business is highly seasonal and temperature-sensitive
since residential and commercial customers use more gas during colder weather
for space heating. As a result, gas revenues, cost of gas and related taxes in
any given period reflect, in addition to other factors, the impact of weather,
through either increased or decreased sales volumes. The Company utilizes a
temperature rate adjustment rider during the months of November through April to
mitigate the impact that unusually cold or warm weather has on operating margins
by reducing the base rate portion of customers' bills in colder than normal
weather and increasing the base rate portion of customers' bills in warmer than
normal weather. Normal weather for the Company's service territory is defined as
the 30-year average temperature as determined by the National Weather Service.
The table below summarizes operating revenues, margins and volumes by customer
class for the three and nine-month periods ended June 30, 2003 and 2002:
14
<Table>
<Caption>
THREE MONTHS NINE MONTHS
NATURAL GAS DISTRIBUTION ENDED JUNE 30, ENDED JUNE 30,
2003 2002 2003 2002
-------- -------- --------- ---------
REVENUE (BEFORE ELIMINATIONS)
Residential $ 9,279 $ 7,520 $ 47,079 $ 41,854
Commercial and Industrial - Small 2,906 2,066 11,345 9,331
-------- -------- --------- ---------
Total Temperature Sensitive Revenue 12,185 9,586 58,424 51,185
-------- -------- --------- ---------
Commercial and Industrial - Large 2,176 1,748 6,353 5,076
Transportation (includes SGT revenues) 1,811 1,894 5,620 5,965
Other 289 252 794 818
-------- -------- --------- ---------
TOTAL NATURAL GAS DISTRIBUTION REVENUE $ 16,461 $ 13,480 $ 71,191 $ 63,044
======== ======== ========= =========
Cost of Natural Gas (before eliminations) (6,888) (4,203) (29,775) (23,289)
Revenue Taxes (included in Taxes, Other (842) (677) (3,579) (3,136)
Than Income on the consolidated income statement)
-------- -------- --------- ---------
NATURAL GAS DISTRIBUTION SALES
AND TRANSPORTATION MARGINS $ 8,731 $ 8,600 $ 37,837 $ 36,619
======== ======== ========= =========
DELIVERIES (THERMS)
Residential 5,606 5,547 40,550 38,612
Commercial and Industrial - Small 2,406 2,259 11,692 10,790
-------- -------- --------- ---------
Total Temperature Sensitive Deliveries 8,012 7,806 52,242 49,402
-------- -------- --------- ---------
Commercial and Industrial - Large 2,456 2,886 8,565 8,499
Transportation (including SGT volumes) 71,295 80,822 217,888 264,727
-------- -------- --------- ---------
TOTAL NATURAL GAS DISTRIBUTION VOLUMES 81,763 91,514 278,695 322,628
======== ======== ========= =========
</Table>
Natural gas distribution revenues increased $2,981,000 (22%) and $8,147,000
(13%), respectively, during the three and nine-month periods ended June 30, 2003
due partially to the rate adjustment, which went into effect March 1, 2003, to
recover increased gas costs paid to suppliers. Fluctuations in the actual cost
of gas are passed on to customers through the purchased gas adjustment provision
of the rate tariffs and do not directly result in any increases or decreases in
margins. Revenues were also increased during the current year periods as a
result of the RSE rate adjustment which went into effect on December 1, 2002.
See Note 4 to the unaudited Consolidated Financial Statements above for
information pertaining to RSE. Increased volumes delivered to
temperature-sensitive customers due to colder than normal weather also had an
impact on revenues for the nine-month periods ended June 30, 2003.
Natural gas distribution margins increased $131,000 (2%) and $1,218,000 (3%),
respectively, for the three and nine-month periods ended June 30, 2003 primarily
as a result of the RSE rate adjustments. This increase in margins was partially
offset by a slight decline in the number of residential general customers served
during the current year periods and a decline
15
of approximately 2% in consumption by temperature-sensitive customers. Customer
usage varies between periods due to a number of factors, including cloud cover,
duration of cold weather, humidity, wind speed, and customer conservation
efforts. The impact of RSE was also partially offset by a decline in volumes
delivered to large commercial and industrial customers, which are not subject to
weather normalization.
Volumes from transportation customers declined 12% and 18%, respectively, for
the three and nine-month periods with a corresponding decline in margins of 4%
and 5%, respectively, due to general economic conditions. Mobile Gas' service
territory has experienced the effects of plant closings, particularly in the
pulp and paper industry, during the last two years. In addition to two
customers' previous plant closings, a chemical company, which is a customer of
the Company, ceased operations of its Mobile plant in June 2003 and some
industrial plants have decreased production. Management currently expects that
the impact on this fiscal year of these reduced revenues will be immaterial.
Known changes in margin such as this, as well as other changes affecting net
income, would generally be reflected in the next RSE adjustment on December 1,
2003.
Operations and maintenance (O&M) expenses increased $224,000 (4%) and $733,000
(5%), respectively, for the three and nine months ended June 30, 2003 due to an
increase in insurance expense, increased bad debt reserves, customer incentive
expenses, and expenses related to the establishment of the ESR reserve as
discussed in Note 4 to the unaudited Consolidated Financial Statements above.
Bad debt reserves increased due to a rise in gas receivables associated with an
increase in natural gas prices discussed above. In response to the corresponding
increase in accounts receivable, Mobile Gas has established additional reserves
for anticipated uncollectible account balances for gas delivered during the
current-year winter heating season. Management currently expects that the
impact, if any, from Mobile Gas' inflation-based cost control formula
established by the APSC and described in Note 4 would be immaterial.
Depreciation expense increased $98,000 (6%) and $293,000 (6%), respectively, for
the three and nine-month periods ended June 30, 2003 due to Mobile Gas' capital
expansion projects and increased investment in property, plant and equipment.
Taxes, other than income taxes (other taxes), primarily consist of property
taxes and business license taxes that are based on gross revenues and fluctuate
accordingly. Other taxes increased $140,000 (11%) and $415,000 (8%) for the
three and nine-month periods ended June 30, 2003.
Interest expense increased $65,000 (8%) and $187,000 (8%) for the three and
nine-month periods ended June 30, 2003 due partially to the 6.9%, $12.0 million,
First Mortgage Bonds issued in August 2002. Interest expense from long-term debt
was partially offset by a decrease in short-term borrowings and a decline in
short-term borrowing rates.
16
NATURAL GAS STORAGE
The natural gas storage segment provides for the underground storage of natural
gas and transportation services through the operations of Bay Gas. The APSC
certificated Bay Gas as an Alabama natural gas storage public utility in 1992.
With its first storage cavern with 2.0 Bcf of working gas capacity and connected
21-mile pipeline, Bay Gas has provided 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 interstate transportation-only services. The FERC last
issued orders on October 11, 2001 and June 3, 2002 approving rates for such
services.
The construction of natural gas-fired electric generation facilities in the
southeast has provided new opportunities to provide gas storage and
transportation services. Construction of Bay Gas' second storage cavern was
completed and the cavern was placed into service April 1, 2003. Bay Gas has
entered into a fifteen-year contract with Southern Company Services, Inc.
(Southern), an affiliate of Southern Company, for a substantial portion of the
second cavern capacity. Currently, the second salt-dome storage cavern has a
working capacity of 3.5 Bcf and will provide sufficient capacity to serve the
new long-term contract with Southern. Additional cavern development is planned
to provide for an extra 1.0 Bcf of working gas capacity. Together, the two
caverns at Bay Gas will hold 6.5 Bcf, with injection and withdrawal capacity of
225 MMcf and 610 MMcf per day, respectively. The additional cavern development
is projected to be complete in fiscal 2004 and will be done without interruption
of storage operations.
Bay Gas' revenues increased $1,365,000 (49%) and $2,062,000 (25%) during the
three and nine-month period ended June 30, 2003 due primarily to additional
storage revenues associated with the commencement of operations of the second
cavern and short-term storage agreements. Under these short-term agreements,
available storage capacity is leased to customers on a day-to-day basis, thereby
optimizing the use of the cavern capacity. For the three-month period ended June
2003, increased storage revenues were partially offset by a slight decline in
transportation revenues and the expiration in May 2003 of an option agreement
for transportation services over and above contracted volumes. During the
nine-month period, Bay Gas experienced an overall increase in transportation
revenues. See Note 5 to the unaudited Consolidated Financial Statements above
for information about the Natural Gas Storage segment and Note 8 for additional
information relating to the recently-expired option agreement.
Operations and maintenance (O&M) expenses increased $218,000 (36%) and $250,000
(15%) during the three and nine months ended June 30, 2003, respectively,
primarily due to additional operating expenses associated with the second cavern
and an increase in insurance costs related to property and liability coverages.
17
Depreciation expense increased $98,000 (22%) and $288,000 (22%), respectively,
for the three and nine-month periods ended June 30, 2003 due to additional
property completed and placed in service.
Taxes, other than income taxes, consist primarily of property taxes and
increased as a result of the new pipelines placed in service June 2001 and
November 2001 and Bay Gas' second storage cavern which was placed in service
April 1, 2003.
Allowance for borrowed funds used during construction represents the
capitalization of interest costs to construction work-in-progress. Capitalized
interest costs decreased $504,000 and $351,000 for the three and nine-month
periods ended June 30, 2003 due to the completion of Bay Gas' second storage
cavern.
Interest income declined $36,000 (78%) and $194,000 (84%), respectively, during
the three and nine-month periods ended June 30, 2003 due to the expenditure of
the proceeds from Bay Gas' debt issuance used to finance the second cavern.
Minority interest reflects the minority partner's share of pre-tax earnings of
the Bay Gas partnership, of which EnergySouth's subsidiary holds a controlling
interest. Minority interest increased $41,000 (44%) and $80,000 (27%) during the
three and nine-month periods ended June 30, 2003 due to increased pretax
earnings of the partnership.
OTHER
The Company provides marketing, merchandising and other energy-related services
through Marketing, Mobile Gas, and Services, which are aggregated with
EnergySouth, the holding company, to comprise the Other category. See Note 5 to
the unaudited Consolidated Financial Statements above for segment disclosure.
Other revenues decreased $198,000 (17%) and $199,000 (5%) during the three and
nine-month periods ended June 30, 2003 due to the closing of a specialty store
in October 2002 and the exit from the natural gas generator sales business in
September 2002.
Cost of merchandise (COM) sold decreased $384,000 (40%) and $429,000 (18%),
respectively, for the three and nine months ended June 30, 2003. Additional
costs of $366,000 and $386,000, respectively, were recognized in the same prior
year periods due to the establishment of reserves for slow-moving merchandise
inventory.
O&M expenses decreased $21,000 (6%) and $113,000 (9%) for the three and nine
months ended June 30, 2003 primarily due to expenses incurred in the prior year
periods for the closed specialty store and natural gas generator sales.
18
INCOME TAXES
Income taxes fluctuate with the change in income before income taxes. Income tax
expense increased $294,000 (97%) and $594,000 (11%), respectively, for the three
and nine months ended June 30, 2003.
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 Consolidated Statements of Cash Flows above. The
decrease in cash flow from operating activities of $5,304,000 was due primarily
to the option payment received by Bay Gas in November 2001, timing of the
collection of gas costs from customers, an increase in gas inventory stored
underground, and an increase in accounts receivable due to an increase in rates
to customers in response to higher gas prices.
Cash used in investing activities reflects the capital-intensive nature of the
Company's business. During the nine months ended June 30, 2003 and 2002, the
Company used cash of $11,251,000 and $19,303,000, respectively, for the
construction of distribution and storage facilities, purchases of equipment and
other general improvements. Bay Gas' temporary investments of $3,000,000, which
represented a portion of the unused proceeds of the December 2000 debt issuance,
matured in December 2001 and were used in Bay Gas' construction projects. Bay
Gas' second natural gas storage cavern was completed and placed in service on
April 1, 2003. Injections of base gas into the second cavern will continue for
several months at an estimated cost of $5,000,000. Additional expansion of the
second cavern is currently planned and is projected to be complete in fiscal
2004 at an estimated cost of $1,500,000. Mobile Gas is expanding its presence in
Baldwin County, Alabama by extending its gas main by 11 miles at an estimated
cost of $1,700,000, of which $1,200,000 has been incurred as of June 30, 2003.
Upon completion of the project, which is expected to occur in the fourth quarter
of fiscal 2003, Mobile Gas will provide natural gas services to customers in the
City of Spanish Fort in addition to its service area along Highway 225 in
Baldwin County.
Financing activities used cash of $6,695,000 and $10,433,000 during the nine
months ended June 30, 2003 and 2002, respectively, due primarily to dividend
payments and repayments of long- and short-term borrowings. Mobile Gas issued
$12,000,000 of 6.9% First Mortgage Bonds in August 2002 of which a portion of
the proceeds were used to pay off short-term borrowings. Partially offsetting
the debt and dividend payments were receipts of $701,000 and $1,068,000 from the
exercise of stock options.
Funds for the Company's short-term cash needs are expected to come from cash
provided by operations and borrowings under the Company's revolving credit
agreement. At June 30, 2003
19
the Company had $20,000,000 available for borrowing on its revolving credit
agreement. The Company pays a fee for its committed lines of credit rather than
maintain compensating balances. The commitment fee is 0.125% of the average
daily unborrowed amount during the annual period of calculation. The Company
believes it has adequate financial flexibility to meet its expected cash needs
in the foreseeable future.
The table below summarizes the Company's contractual obligations and commercial
commitments as of June 30, 2003:
<Table>
<Caption>
REMAINING FISCAL YEARS
TYPE OF CONTRACTUAL FISCAL YEAR FISCAL YEAR FISCAL YEAR FISCAL YEAR FISCAL YEAR 2008 AND
OBLIGATIONS (IN THOUSANDS): 2003 2004 2005 2006 2007 THEREAFTER
- --------------------------- ----------- ----------- ----------- ----------- ----------- ------------
Long-Term Debt $ 642 $ 6,006 $ 6,248 $ 6,463 $ 6,769 $73,159
Gas Supply Contracts 844 7,569 1,166 1,170 1,187 4,402
</Table>
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, 2002.
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; the availability of other natural gas storage
capacity; failures or delays in completing the planned cavern development
project; disruption or interruption of pipelines serving the Bay Gas storage
facilities due to accidents or other events; risks generally associated with the
transportation and storage of natural gas; the possibility that contracts with
storage customers could be terminated under certain circumstances, or not
renewed or extended upon expiration; the prices or terms of any extended or new
contracts; possible loss or material change in the financial condition of one or
more major customers; liability for remedial actions under environmental
regulations; liability resulting from litigation; national and global economic
and political conditions; and changes in tax and other laws applicable to the
business. Additional factors that may impact
20
forward-looking statements include, but are not limited to, the Company's
ability to successfully achieve internal performance goals, competition, the
effects of state and federal regulation, including rate relief to recover
increased capital and operating costs, general economic conditions, specific
conditions in the Company's service area, and the Company's dependence on
external suppliers, contractors, partners, operators, service providers, and
governmental agencies.
ITEM 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK
At June 30, 2003 the Company had approximately $94.6 million of long-term debt
at fixed interest rates. Interest rates range from 6.9% to 9.00% and the
maturity dates of such debt extend to 2023. See the information provided under
the captions "The Company", "Gas Supply", and "Liquidity and Capital Resources"
in the Company's Form 10-K for the fiscal year ended September 30, 2002 for a
discussion of the Company's risks related to regulation, weather, gas supply,
and the capital-intensive nature of the Company's business.
ITEM 4 CONTROLS AND PROCEDURES
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
Within 90 days prior to the date of this report, an evaluation (the
"Evaluation") was carried out, under the supervision and with the participation
of the Company's President and Chief Executive Officer ("CEO") and Chief
Financial Officer ("CFO"), of the effectiveness of the design and operation of
the Company's disclosure controls and procedures ("Disclosure Controls"). Based
on the Evaluation, the CEO and CFO concluded that the Company's Disclosure
Controls are effective in timely alerting them to material information required
to be included in the Company's periodic SEC reports.
CHANGES IN INTERNAL CONTROL
Internal controls for financial reporting were also evaluated and there have
been no significant changes in internal controls or in other factors that could
significantly affect those controls subsequent to the date of their last
evaluation.
LIMITATIONS ON THE EFFECTIVENESS OF CONTROLS
A control system, no matter how well conceived and operated, can provide only
reasonable, not absolute, assurance that the objectives of the control system
are met. Because of the inherent limitations in all control systems, no
evaluation of controls can provide absolute assurance that all control issues
and instances of fraud, if any, within the Company have been detected.
21
PART II. OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibit No. Description
31.1 Certification Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002 - Chief Executive Officer
31.2 Certification Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002 - Chief Financial Officer
32.1 Certification Pursuant to 18 U.S.C. Section 1350, as
adopted Pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002 - Chief Executive Officer
32.2 Certification Pursuant to 18 U.S.C. Section 1350, as
Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002 - Chief Financial Officer
(b) Reports on Form 8-K
On May 2, 2003, EnergySouth, Inc. filed its current report on Form 8-K
reporting earnings for the quarter ended March 31, 2003 and declaration
of a dividend.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
ENERGYSOUTH, INC.
----------------
(Registrant)
Date: August 6, 2003 /s/ John S. Davis
---------------------- ---------------------------------------
John S. Davis
President and
Chief Executive Officer
Date: August 6, 2003 /s/ Charles P. Huffman
---------------------- ---------------------------------------
Charles P. Huffman
Senior Vice President and
Chief Financial Officer
22