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EnergySouth 10-K 2005 Documents found in this filing:
Table of Contents
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
Commission File
Number 0-29604
EnergySouth, Inc.
(Exact name of registrant as specified in its charter)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Common Stock ($.01 par value)
(Title of Class) Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o or No þ
Indicate
by check mark if the registrant is not required to file reports
pursuant to Section 13 or Section 15(d) of the Act. Yes o or No þ
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is
not contained herein, and will not be contained, to the best of registrant’s knowledge, in
definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of
the Act). Yes þ No o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Act). Yes o Noþ
The aggregate market value of Common Stock (the only outstanding class of voting or non-voting
common equity), Par Value $.01 per share, held by non-affiliates (based upon the average of the
high and low closing price as reported by NASDAQ) on March 31, 2005 was approximately $223,177,951.
As of
December 2, 2005, there were 7,905,738 shares of Common Stock, Par Value $.01 per share,
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions
of the definitive Proxy Statement to be filed on or about December 19,
2005, for the Annual
Meeting of Stockholders on January 27, 2006 are incorporated by reference into Part III.
TABLE OF CONTENTS
Table of Contents
PART I
Item 1. Business.
General
EnergySouth, Inc. (together with its subsidiaries, the “Company” or “Registrant”, and
exclusive of its subsidiaries, “EnergySouth”) was initially incorporated under the laws of the
State of Alabama on September 5, 1997 for the primary purpose of becoming the holding company for
Mobile Gas Service Corporation (“Mobile Gas”), a natural gas utility, and its subsidiaries.
Effective February 2, 1998, Mobile Gas and its subsidiaries were reorganized (the “Reorganization”)
into a holding company structure whereby Mobile Gas became a wholly-owned subsidiary of
EnergySouth.
Mobile Gas was incorporated under the laws of the State of Alabama in 1933. Mobile Gas is
engaged in the purchase, distribution, sale and transportation of natural gas to approximately
97,000 residential, commercial and industrial customers in Southwest Alabama, including the City of
Mobile. Mobile Gas’ service territory covers approximately 300 square miles. Mobile Gas is also
involved in merchandise sales, specifically sales of natural gas appliances.
EnergySouth Services, Inc. (“Services”) was incorporated in March 1983. Through Services, the
Company provides contract and consulting work for utilities and industrial customers. Services
owns a 51% interest in Southern Gas Transmission Company (“SGT”), an Alabama general partnership
which was formed in November 1991. SGT was established to provide transportation services to the
facilities of Alabama River Pulp Company, Inc (“ARP”). During fiscal year 1992, SGT constructed
and began operating a 50-mile pipeline from the facilities of Gulf South Pipeline Company (“Gulf
South”) near Flomaton, Alabama to the facilities of ARP in Claiborne, Alabama.
MGS Marketing Services, Inc. (“Marketing”) was incorporated on March 5, 1993 to assist
existing and potential customers in the purchase of natural gas. During fiscal year 2003, as
existing contracts for marketing services expired, such contracts were not renewed by Marketing.
As of September 30, 2004 and 2005, the Company was not actively engaged in activities previously
provided by Marketing.
In connection with the Reorganization, Services and Marketing became wholly-owned subsidiaries
of EnergySouth during fiscal year 1998.
MGS Storage Services, Inc. (“Storage”) was incorporated on December 4, 1991 as a wholly-owned
subsidiary of Mobile Gas. Effective December 19, 2000, Storage became a wholly-owned subsidiary of
EnergySouth. As of September 30, 2005 Storage held a general partnership interest of 90.9% in Bay
Gas Storage Company, Ltd. (“Bay Gas”), an Alabama limited partnership, and a 9.1% limited
partnership interest was held by Olin Corporation (“Olin”). Bay Gas owns and operates
underground gas storage and related pipeline facilities which are used to provide storage and
delivery of natural gas for Mobile Gas and other customers.
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Business Segments
The Company’s operations are classified into the following business segments:
For financial information by business segment, including revenues by segment, for the fiscal
years ended September 30, 2005, 2004, and 2003, see Note 10 to the Consolidated Financial
Statements.
Customers
Of the approximately 97,000 customers of the Company, approximately 95% are residential
customers. In the fiscal year ended September 30, 2005, approximately 56% of the Company’s gas
revenues were derived from residential sales, 16% from small commercial and industrial sales, 9%
from large commercial and industrial sales, 8% from transportation services, and 11% from storage
and miscellaneous services. Residential sales in fiscal 2005 accounted for approximately 5% of the
total volume of gas delivered to the Company’s customers, with small commercial and industrial,
large commercial and industrial, and transportation deliveries accounting for approximately 2%, 1%
and 92%, respectively. For further information with respect to revenues from and deliveries to the
various categories of the Company’s customers, see Item 6, “Selected Financial Data” below.
Gross margins, defined as Gas Revenues less Cost of Gas, by business segment are shown in Note
10 of the Notes to the Consolidated Financial Statements. The ten largest customers of the Company
accounted for approximately 23% of the Company’s gross margin in fiscal 2005, with the largest
accounting for approximately 9%.
EnergySouth is located at the crossroads of the expanding offshore natural gas production
areas of the Central Gulf Coast and the developing gas-fired electric generation markets in the
lower Southeast region of the United States. Mobile Gas provides transportation services to two
electric generating facilities which became operational in fiscal 2001. Bay Gas provides
transportation services to three gas-fired electric generating facilities. During fiscal 1999 Bay
Gas entered into storage contracts with electric utilities which fully subscribed the remaining
space in its first storage cavern. During fiscal 2000 Bay Gas entered into a long term contract
with Southern Company Services, Inc., as agent for a number of electric utility subsidiaries of
Southern Company, to provide storage capacity of up to 3.2 million MMBtu of natural gas for those
subsidiaries. To accommodate this contract, Bay Gas constructed a second underground
storage cavern as discussed in “Gas Storage” below. During fiscal 2004, the remaining portion
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of
the second cavern was fully subscribed on a firm basis, primarily through additional storage
contracts with various electric utility customers.
Bay Gas held a non-binding “open season” in fiscal 2004 to assess interest for up to 5.0 Bcf
of additional working gas capacity. Based on the response to the open season, Bay Gas recently
completed design, engineering, site work, and began construction on a third storage cavern and
related facilities. It has also entered into multi-year contracts with customers for a majority of
the planned third cavern capacity. The new cavern is designed to add 5.0 Bcf of working gas
capacity and is presently anticipated to be in service by the summer of 2007.
While there are no current reported plans for additional gas-fired electric generation
facilities in the Company’s immediate service area, industry projections indicate Florida utilities
plan to add substantial gas-fueled power generation in the next decade. Management continues to
believe that Bay Gas, with the possible construction of additional caverns, is well positioned to
serve the storage needs of that market.
Gas Supply
The Company is directly connected to three natural gas processing plants in south Mobile
County. Mobile Gas has contracted for a portion of its firm supply directly with two of these
producers. For the fiscal year ended September 30, 2005, the Company obtained approximately 58% of
its gas supply from sources located in the Mobile Bay area, with the balance being obtained from
interstate sources.
Mobile Gas has a current peak day firm requirement of 105,000 MMBtus. Firm supply needs of
80,000 MMBtu/day are expected to be met through the withdrawal of gas from the storage facility
owned by Bay Gas. The Company has contracted for firm transportation and storage service
(“No-Notice Service”) for 24,000 MMBtu/day from Gulf South under an agreement effective through
March 31, 2011. Gas supply for “No-Notice Service” is met through a contract with BP
Energy Company through March 31, 2006. The Company also has firm supply contracts with Coral
Energy Resources, L.P. for varying monthly quantities through March 31, 2006 through Mobile Gas’ direct connection
with the Shell Yellowhammer processing plant .
Gas Storage
Construction of Bay Gas’ first storage cavern and facilities was completed in 1994. At
September 30, 2005, the first cavern had the capacity to hold up to 3.2 million MMBtu of natural
gas. Approximately .9 million MMBtu of the gas injected into the storage cavern, called “base
gas,” remains in the cavern to provide sufficient pressure to maintain cavern integrity, and the
remainder, approximately 2.3 million MMBtu, represents working storage capacity, referred to herein
as “working gas capacity”. In 1994 Mobile Gas entered into a gas storage agreement with Bay Gas
under which Bay Gas agreed to provide storage of .8 million MMBtu of working gas capacity of the
first cavern for an initial period of 20 years.
The construction of natural gas-fired electric generation facilities in the Southeast has
provided opportunities to provide gas storage and transportation services. Construction of
Bay Gas’ second storage cavern was completed and the cavern was placed into service April 1,
2003. Bay Gas entered into a fifteen-year contract with Southern Company Services, Inc.,
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an
affiliate of Southern Company, for most of the second cavern capacity. During fiscal year 2004,
the remaining capacity of the second cavern was fully subscribed on a firm basis. Currently, the
second storage cavern has a working gas capacity of 3.7 Bcf. Together, the two caverns at Bay Gas
currently hold 6.0 Bcf, with injection and withdrawal capacity of 200 MMcf and 610 MMcf per day,
respectively, and expansion of these caverns is currently planned to enable them to hold 7.0 Bcf.
Such development will be subject to certain operational considerations to avoid interruption of
storage operations.
With the current working gas capacity of both existing caverns fully subscribed, Bay Gas held
a non-binding “open season” in fiscal 2004 to assess interest for up to 5.0 Bcf of additional
working gas capacity. Based on the response to the open season, Bay Gas recently completed design,
engineering, site work, and began construction on a third storage cavern and related facilities. It
has also entered into multi-year contracts with customers for a majority of the planned third
cavern capacity. The new cavern is designed to add 5.0 Bcf of working gas capacity and is
presently anticipated to be in service by the summer of 2007. The addition of the third cavern and
additional capacity development of the second cavern is currently planned to ultimately increase
the total 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.
Competition
Gas Distribution Competition. The Company is not in significant direct competition with
respect to the retail distribution of natural gas to residential, small commercial and small
industrial customers within its primary service area; however, it does compete with municipal gas
distributors in some rural areas and in one small community which has allowed multiple gas
franchises. Electricity competes with natural gas for such uses as cooking, water heating and
space heating.
The Company’s large commercial and industrial customers with requirements of 200 MMBtu per day
or more have the right to contract with the Company to transport customer-owned gas while other
commercial and industrial customers buy natural gas from the Company. Some industrial customers
have the capability to use either fuel oil, coal, wood chips or natural gas, and choose their fuel
depending upon a number of factors, including the availability and price of such fuels. In recent
years, the Company has had adequate supplies so that interruptible industrial customers that are
capable of using alternative fuels have not had supplies curtailed. The Company’s rate tariffs
include a competitive fuel clause which allows the Company to adjust its rates to certain large
commercial and industrial customers in order to compete with alternative energy sources. Even so,
in recent periods of volatility in natural gas prices, several customers who have the capability to
use alternative fuels have switched to such alternative fuel sources in periods of extremely high
natural gas prices. See “Rates and Regulation” below.
Due to the close proximity of various pipelines and gas processing plants to the Company’s
service area, there exists the possibility that current or prospective customers could install
their own facilities and connect directly to a supply source and thereby “bypass” the Company’s
service. The Company believes that because it has worked closely with major
industrial customers to meet those customers’ needs, and because of its ability to provide
competitive pricing under its rate tariffs, none of the Company’s customers have bypassed its
facilities to date. Although there can be no assurance as to future developments, the Company
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intends to continue its efforts to reduce the likelihood of bypass by offering competitive rates
and services to such customers.
Gas Storage Competition. A number of types of competitors may provide services like or in
competition with those of Bay Gas. These include, among others, natural gas storage facilities,
natural gas aggregators, and natural gas pipelines. Bay Gas believes that its strategic geographic
location and its ability to charge market-based rates for interstate storage services will enable
it to effectively compete with such competitors. See “Rates and Regulation” below.
Rates and Regulation
The natural gas distribution operations of Mobile Gas are under the jurisdiction of the
Alabama Public Service Commission (“APSC”). The APSC approves rates which are intended to permit
the recovery of the cost of service including a return on investment. Rates have historically been
determined by reference to rate tariffs approved by the APSC in traditional rate proceedings or,
for certain large customers, on a case-by-case basis. In addition, pursuant to APSC order, rates
for a limited number of large industrial customers are determined on a privately negotiated basis.
Since December 1, 1995, Mobile Gas has also been allowed to recover costs associated with its
replacement of cast iron mains. This component of rates is adjusted annually through a filing with
the APSC. The rates for service rendered by Mobile Gas are on file with the APSC. The APSC also
approves the issuance of debt and equity securities and has supervision and regulatory authority
over service, pipeline safety, accounting, and other matters.
On June 10, 2002, the Alabama Public Service Commission (APSC) approved Mobile Gas’ request
for the Rate Stabilization and Equalization (RSE) rate setting process to be effective October 1,
2002 through September 30, 2005, and thereafter unless modified or discontinued by APSC order. On
May 23, 2005, Mobile Gas filed an application requesting that the APSC extend Mobile Gas’ RSE rate
making methodology. On June 14, 2005, the APSC issued an order to extend RSE on substantially the
same basis from October 1, 2005 through September 30, 2009. In addition, absent an APSC order
after that date modifying the RSE rate tariff, RSE shall continue in effect beyond September 30,
2009.
RSE is a ratemaking methodology also used by the APSC to regulate certain other Alabama
utilities. Rate adjustments, designed to increase annual gas revenues by approximately $1.7
million, $2.8 million, and $2.2 million, were implemented under the RSE tariff effective December
1, 2004, 2003, and 2002, respectively. Mobile Gas’ rates, as established under RSE, allow a return
on average equity for the period. As such, Mobile Gas is allowed to earn a return on all of its
assets with no exclusions. Increases are allowed only once each fiscal year, effective December 1,
and cannot exceed four percent of prior-year revenues. Under RSE, the APSC conducts reviews using
fiscal year-to-date performance through January, April, and July together with Mobile Gas’ budget
projections to determine whether Mobile Gas’ return on equity is expected to be within the allowed
range of 13.35% to 13.85% at the end of the fiscal year. No such adjustments were required through
the July 2005 and 2004 test periods. Mobile Gas’ financial results for fiscal year 2005 and
2004 did, however, result in a return on equity above the allowed range. As a result,
adjustments of $433,000 and $343,000 were made to fiscal year 2005 and 2004 earnings, respectively,
such that the return on equity as calculated for RSE purposes equaled 13.6%, the midpoint of the
allowed range, and a regulatory liability was recorded which reflects the amount owed to
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customers.
A $343,000 reduction in rates was made in fiscal 2005, and a corresponding reduction in rates will
be made in fiscal year 2006 for the $433,000 adjustment.
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. The increase in O&M expenses per customer was
below the index range for the fiscal year ended September 30, 2005. Under RSE Mobile Gas could
recover one-half the difference, $298,000, through a rate increase effective December 1, 2005;
however, the APSC has approved a waiver of this RSE requirement and instead will allow this amount
to be used to offset potential required returns to customers should O&M expense per customer exceed
the index range in future years.
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%. During
the year ended September 30, 2003, Mobile Gas charged $146,000 against the ESR due to revenue
losses from a large industrial customer. Following a year in which a charge against the ESR is
made, the APSC allows for accruals to the ESR of no more than $15,000 monthly until the maximum
funding level is achieved. Effective October 1, 2004, Mobile Gas began recording a monthly accrual
in the amount of $10,000 to restore the reserve to its former balance of $1.0 million. The ESR
balance of $975,000 at September 30, 2005 is included in the Consolidated Balance Sheet as part of
Regulatory Liabilities.
In October 2000, the Corus Group plc (Corus, formerly known as British Steel) ceased
operations of its Mobile facility and continued to pay Mobile Gas a minimum annual payment as
required under the terms of its contract. On July 28, 2005, Corus elected to end the contract and
make a termination payment as required by the terms of the contract. Under a
Termination Agreement (Termination Agreement) between Mobile Gas and Corus, Corus has agreed
to pay Mobile Gas $6,100,000, with $4,750,000 to be paid in fiscal 2006 and the final payment of
$1,350,000 due October 1, 2006. The APSC approved Mobile Gas’ request to recognize the termination
payments as a regulatory liability and amortize the balance into income over the remaining seven
years of the original contract term.
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Mobile Gas’ rates contain a temperature adjustment rider which is designed to offset the
impact of unusually cold or warm weather on the Company’s operating margins. The adjustment is
calculated monthly for the months of November through April and applied to customers’ bills in the
same billing cycle in which the weather variation occurs. The temperature adjustment rider applies
to substantially all residential and small commercial customers.
The Mobile Gas tariffs include a purchased gas adjustment clause which allows it to pass on to
its sales customers increases or decreases in gas costs from those reflected in its tariff charges.
Adjustments under such clauses require periodic filings with the APSC but do not require a general
rate proceeding. Under the purchased gas adjustment clause, Mobile Gas has a competitive fuel
clause which gives it the right to adjust its rates to certain large customers in order to compete
with alternative energy sources. Any margin lost as a result of competitive fuel clause
adjustments is recoverable from its other customers.
Gas deliveries to certain industrial customers are subject to regulation by the APSC through
contract approval. The operations of SGT, which consist only of intrastate transportation of gas,
are also regulated by the APSC.
Bay Gas is a regulated utility governed under the jurisdiction of the APSC. As a regulated
utility, Bay Gas’ intrastate storage contracts are subject to APSC approval. Operation of the
storage cavern and well-head equipment are subject to regulation by the Oil and Gas Board of the
State of Alabama. The APSC certificated Bay Gas as an Alabama gas storage public utility in 1992.
Bay Gas provides 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. On March 9, 2004,
in accordance with FERC filing requirements, Bay Gas filed a petition with the FERC requesting
approval of new rates for transportation-only service, which remains pending.
Mobile Gas has been granted nonexclusive franchises to construct, maintain and operate a
natural gas distribution system in the areas in which it operates. Except for the franchise
granted by Mobile County, Alabama, which has no stated expiration date, the franchises have various
expiration dates, the earliest of which is in 2007. The Company has no reason to believe that the
franchises will not be renewed upon expiration.
Seasonal Nature of Business
The nature of the Company’s business is highly seasonal and temperature-sensitive. As a
result, the Company’s operating results in any given period have historically reflected, in
addition to other matters, the impact of weather, with colder temperatures resulting in increased
sales by the Company. The substantial impact of this sensitivity to seasonal conditions has been
reflected in the Company’s results of operations. As discussed above under “Rates and Regulation”,
the application of a temperature rate adjustment in customers’ bills beginning in
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November 1996 has
helped to level out the effects of temperature extremes on results of operations.
Due to the seasonality of the Company’s business, the generation of working capital is
impaired during the summer months because of reduced gas sales. Cash needs during this period are
met generally through short-term financing arrangements or the reduction of temporary investments
as is common in the industry.
Environmental Issues
The Company is subject to various federal, state and local laws and regulations relating to
the environment, which have not had a material effect on the Company’s financial position or
results of operations.
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 Site
Inspection of the property, and recently reported that its inspection did not indicate that a
threat to human health currently exists. ADEM has, however, indicated various options for actions
on the site. The Company is evaluating those options. Based upon the report and its review by the
Company’s environmental consultants, the Company has not changed its best estimate of $200,000 as a
remediation liability. The Company sought and was allowed by the APSC to record this amount in
expense 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.
Employees
Mobile Gas employed 249 full-time employees as of September 30, 2005. Of these, approximately
38% are represented by the Paper, Allied-Industrial, Chemical and Energy Workers International
Union, Local No. 3-0541. As of September 30, 2005 Bay Gas employed 12 full-time employees. The
Company believes that it enjoys generally good labor relations.
Available Information
The Company’s internet address is www.energysouth.com. The Company makes available free of
charge on or through its Internet Web site its annual report on Form 10-K, quarterly reports on
Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably
practicable after the Company electronically files such material with, or furnishes it to, the
Securities and Exchange Commission.
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Item 2. Properties.
The Company’s physical properties consist of distribution, general, transmission, and storage
plant. The distribution plant is located in Mobile County and Baldwin County, Alabama and is used
in the distribution of natural gas to the Company’s customers. The distribution plant consists
primarily of mains, services, meters and regulating equipment, all of which are adequate to serve
the present customers. The distribution plant is located on property which the Company is entitled
to use as a result of franchises granted by municipal corporations, or on easements or
rights-of-way.
The general plant consists of land, structures (with aggregate floor space of approximately
115,000 square feet), office equipment, transportation equipment and miscellaneous equipment, all
located in Mobile County, Alabama.
The transmission plant consists of a pipeline of approximately 50 miles and related surface
equipment which is used in the transmission of natural gas by SGT and is located in Alabama’s
Monroe and Escambia Counties. Bay Gas’ transmission plant consists of pipelines totaling
approximately 51 miles and related surface equipment which are located in Alabama’s Mobile and
Washington Counties. The transmission plants are located on easements or rights-of-way.
The storage plant, consisting of two underground caverns for the storage of natural gas and
related pipelines and surface facilities, is located primarily in Washington County, Alabama. The
storage facilities are constructed on a leasehold estate with an initial term of 50 years,
which will expire in 2040, and which may be renewed at the Company’s option for an additional term
of 20 years.
Substantially all of the utility property of Mobile Gas is pledged as collateral for its
long-term debt as of September 30, 2005.
Item 3. Legal Proceedings.
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.
Item 4. Submission of Matters to a Vote of Security Holders.
There were no matters submitted to a vote of security holders during the fourth quarter of
fiscal year 2005.
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Item 4a. Executive Officers of the Registrant
Pursuant to General Instruction G(3) of Form 10-K, the following list is included as an
unnumbered Item in Part I of this Report in lieu of being included in the proxy statement to be
filed with the Securities and Exchange Commission.
Information relating to executive officers who are also directors is included under the
caption “Election of Directors” contained in the Company’s definitive proxy statement with respect
to its 2006 Annual Meeting of Stockholders and is incorporated herein by reference.
The following is a list of names and ages of all of the executive officers who are not also
directors or nominees for election as directors of the Registrant indicating all positions and
offices with the Registrant held by each such person and each such person’s principal occupations
or employment during the past five years. Officers are appointed by the Board of Directors of the
Company for terms expiring in January 2006.
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PART II
PART II
Item 5. Market for the Registrant’s Common Stock Equity and Related Stockholder Matters
The Registrant’s Common Stock, $.01 par value, is traded on the NASDAQ National Market under
the symbol “ENSI”. As of December 3, 2005 there were 1,271 holders of record of the Company’s
Common Stock. Information regarding Common Stock dividends and the bid price range, as adjusted
for the three-for-two stock split effective September 2, 2004, for Common Stock during the periods
indicated is as follows:
While the Board of Directors intends to continue the practice of paying dividends quarterly,
amounts and dates of such dividends as may be declared will be dependent upon the Registrant’s
future earnings, financial requirements, and other factors.
The Registrant’s long-term debt instruments contain certain debt to equity ratio requirements
and restrictions on the payment of cash dividends and the purchase of shares of its capital stock.
None of these requirements is expected to have a significant impact on the Registrant’s ability to
pay dividends in the future.
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Item 6 — EnergySouth, Inc. — Selected Financial Data
FINANCIAL SUMMARY
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Item 7. Management’s Discussion and Analysis of Results of Financial Condition
and Results of Operation.
The Company
EnergySouth, Inc. (EnergySouth) is the holding company for a family of energy businesses.
EnergySouth and its consolidated subsidiaries are collectively referred to herein as the “Company”.
Mobile Gas Service Corporation (Mobile Gas) purchases, sells, and transports natural gas to
residential, commercial, and industrial customers in Mobile, Alabama and surrounding areas. The
Company also provides merchandise sales, service, and financing. MGS Storage Services (Storage) is
the general partner of Bay Gas Storage Company (Bay Gas), a limited partnership that provides
underground storage and delivery of natural gas for Mobile Gas and other customers. EnergySouth
Services (Services) is the general partner of Southern Gas Transmission Company (SGT), which is
engaged in the intrastate transportation of natural gas.
Summary
Consolidated Net Income
Diluted earnings per share increased $0.14 in fiscal 2005, up 9% from fiscal 2004. Fiscal year
2004 earnings per share increased 10% as compared to fiscal 2003. Financial information by
business segment is shown in Note 10 to the Consolidated Financial Statements.
2005 vs 2004 Earnings from the Company’s natural gas distribution business increased $0.02 per
diluted share during fiscal year 2005, primarily from its Mobile Gas subsidiary. Mobile Gas’
earnings were positively impacted by rate adjustments which became effective December 1, 2004 and
2003 based upon the guidelines established under the Rate Stabilization and Equalization (RSE)
tariff. For further information on RSE, see “Natural Gas Distribution” below and Note 2 to the
Consolidated Financial Statements.
The Company’s natural gas storage business, operated by Bay Gas, contributed increased earnings of
$0.11 per diluted share during fiscal 2005, an increase of 22% as compared to fiscal 2004. The
positive earnings contribution was due primarily to additional storage revenues associated with
long and short-term storage agreements entered into during fiscal 2005. The increased revenues were
partially offset by additional operating costs as a result of the expansion activities of Bay Gas.
Earnings from other business operations increased $0.01 per diluted share during fiscal 2005 due
primarily to an increase in interest income from temporary investments and an increase in
merchandising and related activities due to additional sales volumes in fiscal 2005 and provisions
for bad debts recorded in fiscal 2004.
2004 vs 2003 Earnings from the Company’s natural gas distribution business increased $0.09 per
diluted share during fiscal year 2004, primarily from its Mobile Gas subsidiary. Mobile Gas’
earnings were positively impacted by rate adjustments which became effective
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December 1, 2003 and
2002 based upon the guidelines established under the Rate Stabilization and Equalization (RSE)
tariff. For further information on RSE, see “Natural Gas Distribution” below and Note 2 to the
Consolidated Financial Statements. Earnings were also positively impacted by an increase in
temperature-sensitive customers’ gas consumption, when adjusted for weather, during the winter
heating season of fiscal year 2004. These increases were partially offset by an increase in
operating and depreciation expenses and a decline in volumes delivered to industrial customers.
The Company’s natural gas storage business, operated by Bay Gas, contributed increased earnings of
$0.07 per diluted share during fiscal 2004. This positive earnings contribution was due primarily
to increased storage revenues from its second storage cavern which was placed in service on April
1, 2003. The increased revenues were partially offset by additional operations and maintenance
costs, depreciation expense and property taxes due to the completion of the second storage cavern.
Earnings from other business operations decreased $0.01 per diluted share during fiscal 2004 due
primarily to a decrease in interest income from financing activities, additional provisions for bad
debts and increased operating expenses related to merchandise sales.
Results Of Operations
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 rate adjustments to pass through to customers
the cost of gas, certain taxes, and incremental costs associated with the replacement of cast iron
mains. These costs, therefore, have little direct impact on the Company’s unit margins, which are
defined as natural gas distribution revenues less the cost of natural gas and related taxes.
Wholesale natural gas prices continued to rise during fiscal 2005 due to the tight balance between
supply and demand and an active hurricane season in the Gulf of Mexico. The trend of high natural
gas prices which continued throughout fiscal years 2004 and 2005 has had a negative impact on the
Company’s margins, in aggregate dollars, through 1) energy conservation efforts that reduce
consumption and 2) loss of customers due to non-payment of bills. Since the winter of 2000-2001,
when the commodity price of natural gas first rose to unprecedented levels, Mobile Gas has
experienced negative net growth in customers served. Customer counts as of the end of the fiscal
year declined approximately 1.1%, 1.4%, and 0.3% in fiscal years 2005, 2004, and 2003,
respectively. While Mobile Gas continues to expand its service territory by adding new mains and
services, these additions have been more than offset by the number of customers who have left the
system. Mobile Gas is focused on improving net customer growth through strategies
that are directed at 1) increasing appliances in new and existing customers’ homes, 2) seeking
high-value commercial customers that use natural gas for purposes other than space heating, 3)
retaining customers by marketing the benefits of gas appliances and identifying and targeting
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those
customers who may be at risk for leaving the system or converting to alternative fuels, and 4)
minimizing the volatility of natural gas prices in customers’ bills.
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 is designed to reduce
volatility of gas prices on customers’ bills. However, Mobile Gas has had to adjust its rates to
reflect the increased gas costs paid to its suppliers.
In fiscal year 2002, the APSC approved Mobile Gas’ request for an RSE tariff, a ratemaking
methodology already used by the APSC to regulate certain other Alabama utilities. Rate
adjustments, designed to increase annual gas revenues by approximately $1.7 million and $2.8
million, were implemented under the RSE tariff effective December 1, 2004 and 2003, respectively.
Mobile Gas’ rates, as established under RSE, allow a return on average equity for the period. As
such, Mobile Gas is allowed to earn a return on all of its assets with no exclusions. Increases
are allowed only once each fiscal year, effective December 1, and cannot exceed four percent of
prior-year revenues. Under RSE, the APSC has conducted 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 was expected to be within the allowed range of 13.35% to
13.85% at the end of the fiscal year. No such adjustments were required through the July 2005 or
2004 test periods. Mobile Gas’ financial results for fiscal years 2005 and 2004 did, however,
result in a return on equity above the allowed range. As a result, an adjustment of $433,000 and
$343,000 was made to fiscal year 2005 and fiscal year 2004 pre-tax earnings, respectively, such
that the return on equity, as calculated for RSE purposes, equaled 13.6%, the midpoint of the
allowed range, and a regulatory liability was recorded which reflects the amount owed to customers.
A reduction in rates of $433,000 will be made in fiscal year 2006. In the same manner, a
reduction was made in fiscal year 2005 which resulted in $343,000 being fully refunded to customers
by the end of the fiscal year 2005. See Notes 1 and 2 to the Consolidated Financial
Statements.
RSE limits the amount of Mobile Gas’ equity upon which a return is permitted to 60 percent of its
total capitalization and provides for certain cost control measures designed to monitor Mobile Gas’
operations and maintenance (O&M) expense. Under the inflation-based cost control measurement
established by the APSC, if a change in Mobile Gas’ O&M expense per customer falls within 1.5
percentage points above or below the change in the Consumer Price Index for All Urban Customers
(index range), no adjustment is required. If the change in O&M expense per customer exceeds the
index range, three-quarters of the difference is returned to customers through future rate
adjustments. To the extent the change is less than the index range, the utility benefits by
one-half of the difference through future rate adjustments. The increase in O&M expenses per
customer was below the index range for the fiscal year ended September 30, 2005. Under RSE, Mobile
Gas could recover one-half the difference, $298,000, through a rate increase effective December 1,
2005; however, the APSC has approved a waiver of this RSE requirement and instead will allow this
amount to
be used to offset any potential required returns to customers should O&M expense per customer
exceed the index range in future years.
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
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contract and make a termination
payment as required by the terms of the contract. Under a Termination Agreement (Termination
Agreement) between Mobile Gas and Corus, Corus has agreed to pay Mobile Gas $6,100,000, with
$4,750,000 to be paid in fiscal 2006 and the final payment of $1,350,000 due October 1, 2006. The
APSC approved Mobile Gas’ request to recognize the termination payments as a regulatory liability
and amortize the balance into income over the remaining seven years of the original contract term.
Fiscal 2005 was an active hurricane season in which Hurricane Katrina threatened Mobile Gas’
service territory and brought devastation to neighboring Gulf Coast communities. Mobile Gas’
distribution system remained operational through the storm with the exception of minimal service
losses in one small coastal community that received damaging water levels from the storm surge.
The majority of those services were reactivated within four days and Mobile Gas continues to work
with that community toward total restoration. While some additional expenses were incurred in
maintaining system operations during the storm and in providing relief efforts in the days and
weeks that followed, Hurricane Katrina did not have a significant impact on the results of
operations of Mobile Gas’ distribution system.
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.
Natural gas distribution revenues increased $6,921,000 (7%) and $13,120,000 (15%), respectively,
during fiscal 2005 and 2004 due primarily to the rate adjustments to recover increased gas costs
paid to suppliers. Revenues also increased during the two most recent fiscal years as a result of
the RSE rate adjustments that went into effect on December 1, 2004 and 2003.
Revenues from the sale of natural gas to residential and small commercial customers, referred to as
temperature-sensitive customers, since their gas usage is affected to a large degree by
temperatures during the heating season, increased $5,035,000 (6%) and $13,119,000 (19%),
respectively, during fiscal 2005 and 2004 due to the rate adjustments discussed above. During
fiscal 2005 and fiscal 2004, the increase in revenues from rate adjustments was partially offset by
a decline in customers served and the impact of weather. Temperatures during the fiscal 2005 and
2004 winter heating season were 16% and 2%, respectively, warmer than normal. As a result, volumes
delivered to temperature-sensitive
customers declined 12% and 4% in fiscal 2005 and fiscal 2004 as compared to the respective prior
fiscal years.
Revenues from the sale of natural gas to large commercial and industrial customers increased
$1,806,000 (21%) and $594,000 (7%) during fiscal 2005 and 2004, respectively, due to increases in
the price of natural gas and the RSE adjustments. Volumes delivered to these customers increased
2.5% in fiscal 2005 due to increased usage by interruptible customers and declined 15% in fiscal
2004 due primarily to higher natural gas prices.
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Revenues from the transportation of natural gas to large commercial and industrial customers during
fiscal 2005 increased less than 2% when compared to fiscal 2004 as volumes delivered to these
customers were relatively flat. Transportation revenues decreased $417,000 (6%) during fiscal 2004
with a corresponding decline in volumes of 8% due primarily to increased gas prices.
Transportation revenues are expected to decrease, beginning in fiscal 2006, approximately $195,000
as a result of the Termination Agreement discussed in Note 2 to the Consolidated Financial
Statements.
The cost of natural gas increased $5,774,000 (13%) and $10,532,000 (30%), respectively, for fiscal
years 2005 and 2004 due to higher natural gas commodity prices.
Natural gas distribution margins, defined as revenues less cost of gas and related taxes, increased
2% and 5% for fiscal years 2005 and 2004, respectively, primarily as a result of the RSE rate
adjustments. The increase in margins realized from the rate adjustments in both years were
partially offset by a decline in the number of temperature-sensitive customers served. During
fiscal 2005, increased margins from the rate adjustments were largely offset by a decline in usage
per degree-day by temperature-sensitive customers. Mobile Gas utilizes a temperature adjustment
rider on gas sales to residential and small commercial/industrial customers during the months of
November through April to mitigate the impact that warmer or colder than normal weather has on
earnings. Temperature-sensitive margins realized during fiscal 2005 were lower than fiscal 2004
due to a decrease in residential customers’ gas consumption per heating degree-day. Consistent
with other natural gas distribution companies in the United States, Mobile Gas has over time
experienced declines in residential customer usage per degree-day as customers replace old
appliances with new, more energy efficient models and as new, more energy efficient homes are
built. Contrary to the general trend, consumption by residential customers in fiscal 2004, when
adjusted for weather, trended up from prior periods, increasing 1.3% from fiscal 2003. However,
during fiscal 2005, the 6.1% decline in consumption by these customers reflected the declining
trend in customer consumption as experienced in recent years. Usages per degree-day can and do
vary between periods due to several factors including humidity, wind speed, cloud cover, and
duration of cold weather. The increase in fiscal 2004 margins was also partially offset by the
declines in volumes delivered to large commercial and industrial customers who are not subject to
the temperature adjustment rider.
Operations and maintenance (O&M) expenses decreased $80,000 during fiscal 2005. This is the result
of lower payroll costs because of the elimination of sixteen positions during fiscal 2004, lower
service and main repair costs which were unusually high in fiscal 2004, and the recording of a
$200,000 remediation liability in fiscal 2004 related to a former
manufactured gas plant. See Note 8 to the Consolidated Financial Statements. Partially offsetting
these reductions were increased benefit costs and additional audit fees associated with the review
and testing of the Company’s internal controls in compliance with Section 404 of the Sarbanes Oxley
Act of 2002.
O&M expenses increased $285,000 in fiscal 2004 when bad debt provisions increased $299,000 as
compared to fiscal 2003 due to a rise in gas revenues associated with the increase in natural gas
prices. Mobile Gas’ O&M expenses in fiscal 2004 also reflect the remediation liability discussed
above and increases in insurance, employee benefit costs and an unusually high level of repairs and
maintenance on mains. These increased expenses
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were offset by a decrease in payroll costs and
associated benefits related to the elimination of sixteen positions during fiscal 2004 and a
decrease in advertising and promotional expenses.
Depreciation expense increased $342,000 (5%) and $351,000 (5%), respectively, for fiscal 2005 and
2004 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 $366,000 (5%) and $723,000 (11%),
respectively, for fiscal year 2005 and 2004 due primarily to the increased revenues discussed
above.
Interest expense decreased $355,000 (11%) and $219,000 (6%), respectively, for fiscal 2005 and 2004
due to principal payments on long-term debt.
Minority interest reflects the minority partner’s share of pre-tax earnings of the SGT partnership,
of which EnergySouth’s subsidiary holds a controlling interest. Minority interest decreased
$21,000 (14%) and $58,000 (28%), respectively, for fiscal 2005 and 2004 due to a decline in pretax
earnings of the partnership.
Natural Gas Storage
The natural gas storage segment provides for the underground storage of natural gas and
transportation services through the operations of Bay Gas. The APSC certificated Bay Gas as an
Alabama 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 interstate transportation-only firm and interruptible services. The FERC last issued
orders on October 11, 2001 and June 3, 2002 approving rates for such services. On March 9, 2004, in
accordance with FERC filing requirements, Bay Gas filed a petition with the FERC requesting
approval of new rates for transportation-only service, which remains pending.
The construction of natural gas-fired electric generation facilities in the Southeast has provided
opportunities to provide gas storage and transportation services. Construction of Bay Gas’ second
storage cavern was completed and the cavern was placed into service April 1, 2003. Bay Gas entered
into a fifteen-year contract with Southern Company Services, Inc., an affiliate of Southern
Company, for most of the second cavern capacity. During fiscal year 2004, the remaining capacity
of the second cavern was fully subscribed on a firm basis. Currently, the second storage cavern
has a working gas capacity of 3.7 Bcf. Together, the two caverns at Bay Gas currently hold 6.0
Bcf, with injection and withdrawal capacity of 200 MMcf and 610 MMcf per day, respectively, and
expansion of these caverns is currently planned to enable them to hold 7.0 Bcf. Such development
will be subject to certain operational considerations to avoid interruption of storage operations.
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With the current working gas capacity of both existing caverns fully subscribed, Bay Gas held a
non-binding “open season” in fiscal 2004 to assess interest for up to 5.0 Bcf of additional working
gas capacity. Based on the response to the open season, Bay Gas recently completed design,
engineering, site work, and began construction on a third storage cavern and related facilities. It
has also entered into multi-year contracts with customers for a majority of the cavern. The new
cavern is designed to add 5.0 Bcf of working gas capacity and is presently anticipated to be in
service by the summer of 2007. The addition of the third cavern and additional capacity
development of the second cavern is currently planned to ultimately increase the total working gas
capacity of Bay Gas to 12.0 Bcf and injection and withdrawal capacities to 450 MMcf per day and 1.2
Bcf per day, respectively .
Bay Gas’ revenues increased $1,590,000 (9%) and $3,177,000 (22%) during fiscal 2005 and 2004,
respectively. See Note 10 to the Consolidated Financial Statements for segment disclosure.
Revenues increased in fiscal 2005 due to new long and short-term storage agreements. Under the
short-term agreements, available working gas capacity is leased to customers on an interruptible
basis, thereby optimizing the use of cavern capacity. Fiscal 2004 revenues were positively
impacted by additional storage revenues associated with the first full year of operations of the
second cavern and the signing of a new storage agreement during the first quarter of fiscal year
2004. Partially offsetting 2004 revenues was the expiration in May 2003 of an option agreement for
transportation services over and above contracted volumes. Bay Gas entered into an agreement in
November 2001 which granted to a customer an option to order transportation of additional volumes
in excess of the volumes currently under long-term contract. Bay Gas received $3,274,000 in
consideration of the option agreement which was amortized over the nineteen-month option period.
Operations and maintenance (O&M) expenses increased $297,000 (10%) and $401,000 (16%) during fiscal
2005 and 2004, respectively, due to increases in operating costs as a result of the expansion
activities of Bay Gas.
Depreciation expense increased $68,000 (3%) in fiscal year 2005 due to increased investments in
property, plant, and equipment. Fiscal 2004 depreciation expense increased $438,000 (22%) due
primarily to the second storage cavern which was placed in service in April 2003.
Other taxes consist primarily of property taxes and business license taxes that are based on gross
revenues and fluctuate accordingly. Other taxes increased $24,000
(3%) and $249,000 (41%), respectively, in fiscal 2005 and 2004. Fiscal 2004 taxes increased as a result of
the commencement of operations of Bay Gas’ second storage cavern.
Interest expense decreased $213,000 (5%) and $173,000 (4%), respectively, in fiscal years 2005 and
2004 due to principal payments on long-term debt.
Allowance for borrowed funds used during construction represents the capitalization of interest
costs to construction work-in-progress. During fiscal 2005, capitalized interest cost increased
$174,000 due to the commencement of the development of the third storage cavern. Capitalized
interest costs decreased $1,109,000 for the 2004 fiscal year due to the completion of Bay Gas’
second storage cavern on April 1, 2003.
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Minority interest reflects the minority partner’s share of pre-tax earnings of the Bay Gas limited
partnership, of which EnergySouth’s subsidiary holds a controlling interest. Minority interest
increased $154,000 (24%) and $109,000 (20%), respectively, during fiscal 2005 and 2004 due to
increased pretax earnings of the limited partnership.
Other
Through Mobile Gas and EnergySouth Services, Inc., the Company provides merchandising, financing,
and other energy-related services, which are aggregated with EnergySouth, the holding company, to
comprise the Other category. See Note 10 to the Consolidated Financial Statements for segment
disclosure.
Income before income taxes from Other business activities increased $181,000 in fiscal 2005 due
primarily to interest income earned from temporary investments and an increase in merchandising and
merchandising related activities due to additional sales volumes in fiscal 2005 and provisions for
bad debts recorded in fiscal 2004 . In fiscal 2004, income decreased $97,000 (38%) due
primarily to a decline in interest income earned from financing activities, the establishment of
additional bad debt provisions associated with financing activities and increases in operating
expenses related to merchandising activities.
Income Taxes
Income taxes fluctuate with the change in income before income taxes. The Company’s effective tax
rate in 2005, 2004, and 2003 was 39.4%, 37.7%, and 37.6%, respectively. The components of income
tax expense are reflected in Note 5 to the Consolidated Financial Statements.
Effects of Inflation
Inflation impacts the prices the Company must pay for labor and other goods and services required
for operation, maintenance and capital improvements. For Mobile Gas, increases in these costs are
recovered through the rate process. See Note 2 to the Consolidated Financial Statements. Changes
in purchased gas costs are passed through to customers in accordance with the purchased gas
adjustment provision of Mobile Gas’ rate tariffs.
Gas Supply
A primary goal of the Company is to provide gas at the lowest possible cost while maintaining a
reliable long-term supply. To accomplish this goal the Company has diversified its gas supply by
constructing and purchasing pipelines to access the vast gas reserves in its area, both offshore
and onshore. The Company has also contracted with certain of these sources for firm supply. To
minimize the volatility of natural gas prices to its customers, Mobile Gas has implemented a gas
supply strategy in which it enters into forward purchases to lock in prices for a majority of its
expected gas sales during the upcoming winter heating season. All commitments for future gas
purchases at fixed prices meet the requirements of paragraph 10.b, Normal Purchases and Normal
Sales, Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative
Instruments and Hedging Activities,” as amended by SFAS No. 149. Thus, the commitments for future
purchases of natural gas at fixed prices are deemed to be purchases in the normal course of
business and are not subject to
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derivative accounting treatment. Future minimum payments under
third-party contracts for firm gas supply, which expire at various dates through the year 2011, are
as follows: 2006 — $14,012,000; 2007 — $1,187,000; 2008 — $1,187,000; 2009 — $1,187,000; 2010 -
$1,187,000; and 2011 — $842,000. A portion of firm supply requirements is met through the
withdrawal of gas from the storage facility owned by Bay Gas. Mobile Gas has a gas storage
agreement with Bay Gas to receive storage services for an initial period through 2014. Mobile Gas’
purchased gas adjustment provision in rate tariffs filed with the APSC allows a recovery of demand
and commodity costs of purchased gas from customers. Should Mobile Gas’ customer base decline due
to deregulation or other reasons, resulting in costs related to firm gas supply in excess of
requirements, Mobile Gas believes it would be able to take one or more of the following actions:
as part of the regulatory decision allowing other suppliers to serve current customers, secure the
right to allocate firm gas supply costs to the new company supplying gas; reduce some excess gas
supply costs through a negotiated settlement with suppliers; and/or pass-through excess gas supply
costs to existing customers through the purchased gas component of customers’ rates.
Environmental
The Company is subject to various federal, state and local laws and regulations relating to the
environment, which have not had a material effect on the Company’s financial position or results of
operations. See Note 8 to the Consolidated Financial Statements for a discussion of certain
environmental issues.
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. Cash provided by operating activities was $30.6 million, $26.9 million, and $17.6 million in
2005, 2004, and 2003, respectively. Cash provided from operating activities increased $3.7 million
in 2005 as compared to 2004 due primarily to collections of increased gas costs from customers, an
increase in net income,
and an increase in payables, including taxes. Partially offsetting the above positive impacts on
cash flow from operating activities was an increase in gas inventory stored underground, an
increase in accounts receivable, and a decrease in deferred income taxes. Cash provided from
operating activities increased $9.3 million in 2004 as compared to 2003 due to an increase in net
income, an increase in taxes payable, and an under-collection of increased gas costs from customers
in the prior year.
Cash used in investing activities reflects the capital-intensive nature of the Company’s business.
During 2005, 2004, and 2003, the Company used cash of $16.4 million, $8.5 million and $16.2
million, respectively, for construction of distribution and storage facilities, purchases of
equipment and other general improvements. During fiscal 2005, Bay Gas invested $7.3 million in the
ongoing construction of the third cavern and the completion of a pipeline interconnect project. In
fiscal 2003, $4.9 million was invested by Bay Gas in the completion of the second cavern. In
addition, Mobile Gas entered into a thirty-year franchise agreement in October 2002 with the City
of Spanish Fort and invested $1.5 million during fiscal 2003 in the expansion of its distribution
system into the City of Spanish Fort.
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The Company expects fiscal 2006 capital expenditures by Mobile Gas to be approximately $11.9
million and by Bay Gas to be approximately $22.6 million. Mobile Gas’ projected 2006 expenditures
include normal construction activity, including equipment purchases and other general improvements
and will be funded by internal cash generation and short-term borrowings. Bay Gas’ anticipated
capital expenditures include ongoing development of a third salt-dome storage cavern designed to
provide 5.0 Bcf of working gas capacity and the expansion of injection and withdrawal capabilities.
The expansion of storage facilities is expected to be funded through internal cash generation and
the issuance of long-term debt.
Financing activities used cash of $14.0 million, $13.0 million and $7.9 million in fiscal 2005,
2004 and 2003, respectively. Long term debt payments and the payment of quarterly dividends
account for most of the cash used in each year. Dividend payments of $6.4 million, $6.0 million,
and $5.6 million in fiscal 2005, 2004, and 2003, respectively, were offset by dividend reinvestment
of $0.4 million in each fiscal year. Fiscal 2005 and fiscal 2004 included additional optional
principal payments of $1.9 million and $1.7 million, respectively. Receipts of $0.6 million, $0.7
million, and $1.2 million in fiscal 2005, 2004 and 2003, respectively, from the exercise of stock
options partially offset the cash used in financing activities.
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 which extends through February 28,
2007. At September 30, 2005 the Company had $20.0 million available for borrowing on its revolving
credit agreement. The Company pays a fee for its committed lines of credit rather than maintain
compensating balances. The commitment fee is 0.125% of the average daily unborrowed amount during
the annual period of calculation. Additional funds in an aggregate amount of $6,100,000 is
expected to be provided in fiscal 2006 and 2007 in accordance with the terms of the Termination
Agreement as discussed in Note 2 to the Consolidated Financial Statements. 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
September 30, 2005:
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Off-Balance Sheet Arrangements
The Company has no “off-balance sheet arrangements” as such term is defined in Item 303(a)(4) of
Regulation S-K.
Critical Accounting Policies
Regulatory Accounting. The Natural Gas Distribution segment is subject to regulation by the APSC
and as such, accounts for its transactions according to the provisions of Statement of Financial
Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71).
This statement sets forth the application of accounting principles generally accepted in the
United States of America for those companies whose rates are established by or are subject to
approval by an independent third party regulator. The provisions of SFAS 71 require, among other
things, that financial statements of a regulated enterprise reflect the actions of regulators,
where appropriate. The application of this accounting policy allows the Company to defer expenses
and income on the consolidated balance sheet as regulatory assets and liabilities when it is
probable that those expenses and income will be allowed in the rate setting process in a period
different from the period in which they would have been reflected in the consolidated statements of
income of an unregulated company. These deferred regulatory assets and liabilities are then
recognized in the consolidated statement of income in the period in which the same amounts are
reflected in rates. See Note 1 to the Consolidated Financial Statements.
If any portion of the Natural Gas Distribution segment ceased to continue to meet the criteria for
application of regulatory accounting treatment for all or part of its operations, the regulatory
assets and liabilities related to those portions ceasing to meet such criteria would be eliminated
from the consolidated balance sheet and included in the consolidated statement of income for the
period in which the discontinuance of regulatory accounting treatment occurred.
Revenue Recognition. Mobile Gas recognizes revenues from the sales of natural gas and
transportation services in the same period in which it delivers the related volumes to customers.
Sales revenues from residential and certain commercial and industrial customers are billed on the
basis of scheduled meter reading cycles throughout the month. Mobile Gas records revenues for
estimated deliveries of gas, not yet billed to these customers, from the meter reading date to the
end of the accounting period. These revenues are included on the Company’s consolidated balance
sheet as “Unbilled Revenue.” Included in the rates charged by Mobile Gas to temperature sensitive
customers is a temperature rate adjustment rider which offsets the impact of unusually cold or warm
weather on operating margin.
Reserves. EnergySouth companies establish reserves for uncollectible accounts receivable and slow
moving merchandise, materials and supplies inventories. Such reserves are generally calculated
based on currently available facts and on the application of a percentage to each aging category of
receivables and inventory based on collection and sales experience, respectively. On certain
specific receivables and inventory, the Company records an allowance based on currently available
facts to reduce the net balance of the specific receivable or inventory item to the amount the
Company reasonably expects to
collect. Reserves for receivables are reported as “Allowance for Doubtful Accounts” on the balance
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sheet. Reserves for inventory are netted against the related asset account and reported on the
balance sheet in “Materials, Supplies, and Merchandise.” The Company believes its reserves are
adequate. However, actual results may differ from estimates, and estimates can be, and often are,
revised either negatively or positively, depending upon actual outcomes or expectations based on
the facts surrounding each potential exposure.
Employee Benefits. Employee benefits include a defined-benefit pension plan and other
post-employment benefits for the benefit of substantially all full-time regular employees. Under
the provisions of Statement of Financial Accounting Standards No. 87, “Employer’s Accounting for
Pensions,” and Statement of Financial Accounting Standards No. 106, “Employer’s Accounting for
Postretirement Benefits Other Than Pensions,” measurement of the obligations under the defined
benefit pension plans and other post-retirement benefit plans is subject to a number of statistical
factors and assumptions which attempt to anticipate future events. These factors include
assumptions about the discount rate, expected return on plan assets and rate of future compensation
increases as determined by the Company. In addition, the Company’s actuarial consultants also use
subjective factors such as withdrawal and mortality rates to estimate the projected benefits
obligation. The actuarial assumptions used may differ materially from actual results due to
changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life
spans of participants. These differences may result in a significant impact on the amount of
pension expense recorded in future periods. (See Note 7 to the Consolidated Financial Statements.)
At September 30, 2005, the discount rate used for pension and postretirement purposes was 5.75 and
5.5 percent, respectively. A hypothetical 25 basis point decrease in the annual discount rate
would increase pension and postretirement benefit expense by $38,000 and $17,000, respectively. At
September 30, 2005, the expected rate of return on assets for actuarial purposes was 8.25 percent
and 7.75 percent for pension and post-retirement benefits, respectively. A hypothetical 25 basis
point decrease in the expected rate of return on assets would increase pension and postretirement
expense by $82,000 and $9,000, respectively. At September 30, 2005, the rate of compensation
increase used for actuarial purposes was 3.75 percent. A hypothetical 25 basis point increase in
the expected rate of future compensation increases would increase pension expense by $26,000.
Forward-Looking Statements
Statements contained in this report, which are not historical in nature, are forward-looking
statements within the meaning of the Private Securities Litigation Reform Act of 1995. Such
forward-looking statements are made as of the date of this report and involve known and unknown
risks, uncertainties and other important factors that could cause the actual results, performance
or achievements of EnergySouth or its affiliates, or industry results, to differ materially from
any future results, performance or achievement expressed or implied by such forward-looking
statements. Such risks, uncertainties and other important factors include, among others, risks
associated with fluctuations in natural gas prices, including changes in the historical seasonal
variances in natural gas prices and changes in historical patterns of collections of accounts
receivable; the prices of alternative fuels; the relative pricing of natural gas versus other
energy sources; changes in historical patterns of consumption by temperature-sensitive customers;
the availability of other natural gas storage capacity; failures or delays in completing planned
Bay Gas cavern development; disruption or
interruption of pipelines serving the Bay Gas storage facilities due to accidents or other
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events;
risks generally associated with the transportation and storage of natural gas; the possibility that
contracts with storage customers could be terminated under certain circumstances, or not renewed or
extended upon expiration; the prices or terms of any extended or new contracts; possible loss or
material change in the financial condition of one or more major customers; liability for remedial
actions under environmental regulations; liability resulting from litigation; national and global
economic and political conditions; and changes in tax and other laws applicable to the business.
Additional factors that may impact forward-looking statements include, but are not limited to, the
Company’s ability to successfully achieve internal performance goals, competition, the effects of
state and federal regulation, including rate relief to recover increased capital and operating
costs, allowed rates of return and purchased gas adjustment provisions; general economic
conditions, specific conditions in the Company’s service area, and the Company’s dependence on
external suppliers, contractors, partners, operators, service providers, and governmental agencies.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Mobile Gas is exposed to market risks associated with commodity prices of natural gas. Mobile Gas
ameliorates the price risk associated with purchases of natural gas by using a combination of
natural gas storage services, fixed price contracts and spot market purchases. As part of Mobile
Gas’ gas supply strategy, it has adopted a policy under which management is authorized to commit to
future gas purchases at fixed prices up to a specified percentage of the normalized degree-day
usage for any corresponding month as outlined within the policy. All commitments for future gas
purchases at fixed prices meet the requirements of paragraph 10.b, Normal purchases and Normal
sales, of Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative
Instruments and Hedging Activities”, as amended by SFAS No. 149. Thus, the commitments for future
purchases of natural gas at fixed prices are deemed to be purchases in the normal course of
business and are not subject to derivative accounting treatment.
At September 30, 2005, Mobile Gas had not entered into derivative instruments for the purpose of
hedging the price of natural gas. If Mobile Gas had entered into such derivative instruments, any
cost incurred or benefit received from the derivative or other hedging arrangements would be
recoverable or refunded through the purchased gas adjustment mechanism. As discussed in “Results
of Operations” under “Natural Gas Distribution” within Item 2 above, the APSC currently allows for
full recovery of all costs associated with natural gas purchases; therefore, costs associated with
the forward purchases of natural gas will be passed through to customers when realized and will not
affect future earnings or cash flows.
At September 30, 2005 the Company had approximately $82.8 million of long-term debt at fixed
interest rates. Interest rates range from 6.9% to 9.0% and the maturity dates of such debt extend
to 2023.
See also the information provided under the captions “The Company,” “Gas Supply,” and “Liquidity
and Capital Resources” under Item 7 for a discussion of the Company’s risks related to regulation,
weather, gas supply and prices, and the capital-intensive nature of the Company’s business.
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Item 8. Financial Statements and Supplementary Data.
The
financial statements and financial statement schedules and the Report
of Independent Registered Public Accounting Firm thereon filed as part of this report are listed in the “EnergySouth, Inc. and Subsidiaries Index to
Financial Statements and Schedules” at Page F-1, which follows Part IV hereof.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures
Conclusion Regarding Disclosure Controls and Procedures
As of the end of the period covered by this report, an 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. 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.
Management’s Report On Internal Control Over Financial Reporting
The Management of EnergySouth, Inc. is responsible for establishing and maintaining adequate
internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f).
EnergySouth Inc.’s internal control over financial reporting is a process designed to provide
reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with accounting principles generally
accepted in the United States of America. Internal control over financial reporting includes those
written policies and procedures that:
Internal control over financial reporting includes the controls themselves, monitoring (including
internal auditing practices) and actions taken to correct deficiencies as identified.
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Because of its inherent limitations, internal control over financial reporting may not prevent or
detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
Under the supervision and with the participation of our management, including our principal
executive officer and principal financial officer, Management conducted an evaluation of the
effectiveness of our internal control over financial reporting based on the framework in Internal
Control – Integrated Framework issued by the Committee of Sponsoring Organization of the Treadway
Commission (COSO). Management’s assessment included an evaluation of the design of EnergySouth
Inc.’s internal control over financial reporting and testing of the operational effectiveness of
its internal control over financial reporting. Management reviewed the results of its assessment
with the Audit Committee of our Board of Directors.
Based on our evaluation, Management concluded that EnergySouth, Inc.’s internal control over
financial reporting was effective as of September 30, 2005. Deloitte & Touche LLP, an independent
registered public accounting firm that audited the consolidated financial statements of
EnergySouth, Inc. included in this report, have issued an attestation report on management’s
assessment of the effectiveness of internal control over financial reporting as of September 30,
2005 as stated in their report which appears herein.
Changes in Internal Control Over Financial Reporting
The CEO and CFO have concluded that during the most recent fiscal quarter covered by this report
there were no changes in internal controls over financial reporting that materially affected or are
reasonably likely to materially affect internal controls over financial reporting.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of
EnergySouth, Inc. We have audited management’s assessment, included in the accompanying Management’s Report on
Internal Control Over Financial Reporting, that EnergySouth, Inc. and subsidiaries (the “Company”)
maintained effective internal control over financial reporting as of September 30, 2005, based on
criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. The Company’s management is responsible for maintaining
effective internal control over financial reporting and for its assessment of the effectiveness of
internal control over financial reporting. Our responsibility is to express an opinion on
management’s assessment and an opinion on the effectiveness of the Company’s internal control over
financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was
maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, evaluating management’s assessment, testing and evaluating the
design and operating effectiveness of internal control,
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and performing such other procedures as we
considered necessary in the circumstances. We believe that our audit provides a reasonable basis
for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the
supervision of, the company’s principal executive and principal financial officers, or persons
performing similar functions, and effected by the company’s board of directors, management, and
other personnel to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes
those policies and procedures that (1) pertain to the maintenance of records that, in reasonable
detail, accurately and fairly reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles,
and that receipts and expenditures of the company are being made only in accordance with
authorizations of management and directors of the company; and (3) provide reasonable assurance
regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the
company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the
possibility of collusion or improper management override of controls, material misstatements due to
error or fraud may not be prevented or detected on a timely basis. Also, projections of any
evaluation of the effectiveness of the internal control over financial reporting to future periods
are subject to the risk that the controls may become inadequate because of changes in conditions,
or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that the Company maintained effective internal control over
financial reporting as of September 30, 2005, is fairly stated, in all material respects, based on
the criteria established in Internal Control—Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained,
in all material respects, effective internal control over financial reporting as of September
30,2005, based on the criteria established in Internal Control—Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the consolidated financial statements and financial statement schedule as of
and for the year ended September 30, 2005 of the Company and our report dated November 30, 2005
expressed an unqualified opinion on those financial statements and financial statement schedule.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP Atlanta, Georgia November 30, 2005 31
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PART III
Item 10. Directors, Executive Officers, and Control Persons of the Registrant.
Information under the captions “Election of Directors” and “Information Regarding the Board of
Directors” contained in the Company’s definitive proxy statement with respect to its 2006 Annual
Meeting of Stockholders is incorporated herein by reference.
For information with respect to executive officers of the Registrant, see “Executive Officers of
the Registrant” at the end of Part I of this Report.
Information under the caption “Section 16(a) Beneficial Ownership Reporting Compliance” contained
in the Company’s definitive proxy statement with respect to its 2006 Annual Meeting of Stockholders
is incorporated herein by reference.
Code of Ethics
The Company has adopted a Code of Business Conduct and Ethics (the “Ethics Code”) that applies to
the Company’s directors, officers, and employees, including its President and Chief Executive
Officer, its Senior Vice President and Chief Financial Officer, and its Controller. The Company has
posted the Ethics Code on its internet website at www.energysouth.com.
Audit Committee Financial Expert
The Board of Directors of the Company has determined that S. Felton Mitchell, Jr., who currently
serves as the Chairman of the Audit Committee of the Company’s Board of Directors, and Walter L.
Hovell are audit committee financial experts. Mr. Mitchell and Mr. Hovell are independent as
defined in the listing standards of the National Association of Securities Dealers.
Item 11. Executive Compensation.
Information under the captions “Executive Compensation,” “Option Grants in Last Fiscal Year,”
“Aggregated Option Exercises in Last Fiscal Year and 2005 Year-End Option Values,” “Compensation
Committee Report,” “Compensation Committee Interlocks and Insider Participation in Compensation
Decisions” and “EnergySouth, Inc. Stock Performance Graph” and under the headings “Employees’
Retirement Plan,” Employee Savings Plan,” “Agreements with Mr. Davis,” “Change of Control
Agreements,” “Insurance” and “Other Compensation” contained in the Company’s definitive proxy
statement with respect to its 2006 Annual Meeting of Stockholders is incorporated herein by
reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
Information under the captions “Equity Compensation Plan Information” and “Security Ownership of
Certain Beneficial Owners and Management” contained in the Company’s definitive proxy statement
with respect to its 2006 Annual Meeting of Stockholders is incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions.
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There were no transactions required to be disclosed pursuant to this item.
Item 14. Principal Accountant Fees and Services
Information under the Caption “Relationship With Independent Public Accountants” contained in the
Company’s definitive proxy statement with respect to its 2006 Annual Meeting of Stockholders is
incorporated herein by reference.
PART IV
Item 15. Exhibits, Financial Statement Schedules.
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Signatures
Pursuant to the requirements of Section 13 or 15 (d) 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.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant and in the
Capacities and on the dates indicated:
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Signatures (Continued)
35
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ENERGYSOUTH, INC.
AND SUBSIDIARIES INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
Schedules other than that referred to above are omitted and are not applicable or not required.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
EnergySouth, Inc. We have audited the accompanying consolidated balance sheets of EnergySouth, Inc. and subsidiaries
(the “Company”) as of September 30, 2005 and 2004, and the related consolidated statements of
income, stockholders’ equity, and cash flows for each of the three years in the period ended
September 30, 2005. Our audits also included the financial statement schedule listed in the Index
as Schedule II. These financial statements and financial statement schedule are the responsibility
of the Company’s management. Our responsibility is to express an opinion on the financial
statements and financial statement schedules based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects,
the financial position of EnergySouth, Inc. and subsidiaries at September 30, 2005 and 2004, and
the results of their operations and their cash flows for each of the three years in the period
ended September 30, 2005, in conformity with accounting principles generally accepted in the United
States of America. Also, in our opinion, such financial statement schedule, when considered in
relation to the basic consolidated financial statements taken as a whole, presents fairly, in all
material respects, the information set forth therein.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the effectiveness of the Company’s internal control over financial reporting
as of September 30, 2005, based on the criteria established in Internal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our
report dated November 30, 2005 expressed an unqualified opinion on management’s assessment of the
effectiveness of the Company’s internal control over financial reporting and an unqualified opinion
on the effectiveness of the Company’s internal control over financial reporting.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP Atlanta, Georgia November 30, 2005 F-2
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ONSOLIDATED STATEMENTS OF INCOME
EnergySouth, Inc.
See Accompanying Notes to Consolidated Financial Statements
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CONSOLIDATED BALANCE SHEETS
EnergySouth, Inc.
See Accompanying Notes to Consolidated Financial Statements
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See Accompanying Notes to Consolidated Financial Statements
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CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
EnergySouth, Inc.
See Accompanying Notes to Consolidated Financial Statements
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CONSOLIDATED STATEMENTS OF CASH FLOWS
EnergySouth, Inc.
See Accompanying Notes to Consolidated Financial Statements
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The consolidated financial statements of EnergySouth, Inc. (EnergySouth) and its subsidiaries
(collectively, the Company) include the accounts of Mobile Gas Service Corporation (Mobile Gas);
EnergySouth Services, Inc. (Services); MGS Storage Services, Inc. (Storage); a 90.9% owned
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.
Revenues and Gas Costs
Revenues are recorded when distribution services are provided to customers. Those revenues are
based on rates approved by the Alabama Public Service Commission (APSC). The Company’s
distribution segment reads meters on a monthly cycle basis and records revenues based upon
estimated consumption through the end of the month for all customers regardless of the meter
reading date.
Increases or decreases in the cost of gas and certain other costs are passed through to customers
in accordance with provisions in the Company’s rate tariffs. Any over-or-under recoveries of these
costs are charged or credited to cost of gas and included in the Deferred Purchased Gas Adjustment
which is classified as part of Regulatory Assets and/or Liabilities within the Company’s Balance
Sheet. See “Regulatory Assets and Liabilities” below.
The Company’s natural gas storage segment recognizes revenues when services are provided in
accordance with contractual agreements for storage and transportation services. The agreements
include fees for monthly storage of natural gas, fees for the injection and withdrawal of natural
gas, and transportation of natural gas through Bay Gas’ system.
Property, Plant, and Equipment
Included in property, plant, and equipment are acquisition adjustments, net of amortization, of
$5,774,000 and $6,137,000 at September 30, 2005 and 2004, respectively. Such acquisition
adjustments are being amortized to cost of service over the lives of the assets acquired and are
recovered through rates approved by the APSC.
The cost of additions includes direct labor and materials, allocable administrative and general
expenses, pension and payroll taxes, and an allowance for funds used during construction. The cost
of depreciable property retired, less salvage, is charged to accumulated depreciation. In
accordance with the provisions of Financial Accounting
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Standards Board (FASB) Statement No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143),
estimated dismantling costs, which are a component of Mobile Gas’ depreciation rates, are
classified as a regulatory liability. Dismantling costs are not a legal obligation as defined by
SFAS No. 143 but rather the result of cost-based regulation and are accounted for under the
provisions of FASB Statement No. 71, “Accounting for the Effects of Certain Types of Regulation”
(SFAS 71). Estimated interest cost associated with property under construction, based upon
weighted average interest rates for short-term and long-term borrowings and, if applicable, the
actual interest rate on borrowings for specific projects, is capitalized as an allowance for
borrowed funds used during construction. Maintenance, repairs, and minor renewals and betterment
of property are charged to operations.
Bay Gas’ storage caverns include recoverable gas volumes (“base gas”) that are necessary to
maintain pressure and deliverability requirements. Base gas is accounted for at cost and is
included in Storage Plant as disclosed in Note 3 below and within Property, Plant, and Equipment in
the Consolidated Balance Sheet. Since base gas is recoverable, it is not subject to depreciation.
Provisions for depreciation are computed principally on straight-line rates for financial statement
purposes and on accelerated rates for income tax purposes. Depreciation for financial statement
purposes is provided over the estimated useful lives of utility property at rates approved by the
APSC. For the years ended September 30, 2005, 2004, and 2003 approved depreciation rates averaged
approximately 4.1% of depreciable property, excluding the gas storage facility which is depreciated
at an annual rate averaging 2.7%.
Cash Equivalents
The Company considers all highly liquid investments with a maturity of three months or less when
purchased to be cash equivalents.
Income Taxes
The Company records deferred tax liabilities and assets, as measured by enacted tax rates, for all
temporary differences caused when the tax basis of an asset or liability differs from that reported
in the financial statements. Investment tax credits realized after 1980 are deferred and amortized
over the average life of the related property in accordance with regulatory treatment.
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.
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A reconciliation of the weighted average common shares and the diluted average common
shares is provided below:
Stock option awards to purchase approximately 76,000 and 72,000 shares as of September 30,
2005 and 2004, respectively, were not included in the computation of diluted earnings per share
because inclusion of these shares would have been antidulitive as the option exercise prices were
greater than the shares’ market prices during these periods.
On July 30, 2004, the Board of Directors of EnergySouth declared a three-for-two split of
outstanding common stock whereby one additional share was issued for each two shares held as of the
record date of August 16, 2004. The new shares were issued to shareholders on September 1, 2004
with cash paid in lieu of fractional shares resulting from the split. Common stock began trading
on the post split basis on September 2, 2004. All references to number of shares and per share
amounts have been restated to reflect the three-for-two stock split.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted
in the United States of America requires management to make estimates and assumptions that affect
the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities
at the date of the financial statements and the reported amounts of revenues and expenses during
the reporting period. Actual results could differ from those estimates.
Long-lived Assets
The Company reviews its long-lived assets whenever indications of impairment are present. If any
assets were determined to be impaired, such assets would be written down to their estimated fair
market values. The Company does not believe it has any assets which are currently impaired.
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Regulatory Assets and Liabilities
Mobile Gas and certain cost based operations of Bay Gas meet the criteria for application of 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 significant regulatory assets and liabilities as of September 30, are (in thousands):
In the event that a portion of the Company’s operations were no longer 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.
Stock-Based Compensation
The Company has employee stock option plans, which are described more fully in Note 6 below. The
Company accounts for its employee stock option plans under the intrinsic value recognition and
measurement provisions of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued
to Employees,” and related interpretations. As stock options have been issued with exercise
prices equal to the market value of the underlying shares on the grant date, no compensation cost
has been recognized.
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Had compensation cost for the plans been determined based on the fair value of the options on the
grant date, consistent with Statement of Financial Accounting Standards
No. 123, “Accounting for Stock-Based Compensation,” the Company’s net income and earnings per share
would have been as follows:
See discussion of SFAS 123R, which modifies SFAS 123, under “New Accounting Standards” below.
New Accounting Standards
In December 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial
Accounting Standards No. 153, “Exchanges of Nonmonetary Assets — an amendment of APB Opinion No.
29” (SFAS 153). SFAS 153 eliminates the exception to fair value for exchanges of similar
productive assets unless fair value cannot be reasonably determined or the transaction lacks
commercial substance. SFAS 153 is effective for non-monetary asset exchanges occurring after July
1, 2005 and did not have an impact on the Company’s financial statements.
In December 2004, the FASB issued Statement of Financial Accounting Standards No. 123 (revised
2004), “Share-Based Payment” (SFAS 123R) which eliminates the alternative to use APB Opinion 25’s
intrinsic value method of accounting that was provided in Statement 123 as originally issued.
SFAS 123R requires entities to recognize the cost of employee services received in exchange for
awards of equity instruments based on the grant-date fair value of those awards. The Company
accounts for its employee stock option plans under the intrinsic value recognition and measurement
provisions of Opinion 25 and discloses the effect on net income and earnings per share had
compensation cost for the plans been determined based on the fair value of the options on the grant
date. The Company adopted SFAS 123R as of
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October 1, 2005 using the modified prospective method.
Under this method, the Company will recognize compensation cost, on a prospective basis, for the
portion of outstanding awards for which the requisite service has not yet been rendered as of
October 1, 2005, based upon the grant-date fair value of those awards calculated under SFAS 123 for
pro forma disclosure purposes. The Company expects that the adoption of SFAS 123R will reduce
fiscal year 2006 net income by approximately $210,000, or
$0.03 per diluted share, for compensation cost recognized on awards outstanding at October 1, 2005.
In March 2005, the FASB issued Financial Interpretation No. 47 to clarify the term “conditional
asset retirement obligation” as used in Statement of Financial Accounting Standards No. 143,
“Accounting for Asset Retirement Obligations.” Conditional asset retirement obligation refers to a
legal obligation to perform an asset retirement activity in which the timing and/or method of
settlement are conditional on a future event that may or may not be within the control of the
entity. The obligation to perform the asset retirement activity is unconditional even though
uncertainty exists about the timing and/or method of settlement. Accordingly, an entity is required
to recognize a liability for the fair value of a conditional asset retirement obligation if the
fair value of the liability can be reasonably estimated. The fair value of a liability for the
conditional asset retirement obligation should be recognized when incurred — generally, upon
acquisition, construction, development and/or through the normal operation of the asset.
Uncertainty about the timing and/or method of settlement should be factored into the measurement of
the liability when sufficient information exists. FIN 47 also clarifies when an entity would have
sufficient information to reasonably estimate the fair value of an asset retirement obligation.
FIN 47 is effective for the Company no later than September 30, 2006. The adoption of FIN 47 will
not have a material impact on the Company’s financial statements.
In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections”, a
replacement of Accounting Principles Board (APB) Opinion No. 20 and SFAS No. 3. SFAS 154 applies
to all voluntary changes in accounting principle and changes the requirements for accounting for
and reporting of a change in accounting principle. Retrospective application to prior periods
financial statements of the change in accounting principle is required unless it is impracticable.
SFAS 154 is effective for fiscal years beginning after December 15, 2005, with earlier application
permitted in fiscal years beginning after June 1, 2005. The adoption of SFAS 154 will not have an
impact on the Company’s financial statements.
Reclassifications
Certain amounts in the prior years’ financial statements have been reclassified to conform with the
2005 financial statement presentation.
2. RATES AND REGULATIONS
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
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effective October 1, 2002
through September 30, 2005, and thereafter unless modified or discontinued by APSC order. On May
23, 2005, Mobile Gas filed an application requesting that the APSC extend Mobile Gas’ RSE rate
making methodology. On June 14, 2005, the APSC issued an order to extend RSE on substantially the
same basis from October 1, 2005 through September 30, 2009. In
addition, absent an APSC order after that date modifying the RSE rate tariff, RSE shall continue in
effect beyond September 30, 2009.
RSE is a ratemaking methodology also used by the APSC to regulate certain other Alabama utilities.
Rate adjustments, designed to increase annual gas revenues by approximately $1.7 million, $2.8
million, and $2.2 million, were implemented under the RSE tariff effective December 1, 2004, 2003,
and 2002, respectively. Mobile Gas’ rates, as established under RSE, allow a return on average
equity for the period. As such, Mobile Gas is allowed to earn a return on all of its assets with
no exclusions. Increases are allowed only once each fiscal year, effective December 1, and cannot
exceed four percent of prior-year revenues. Under RSE, the APSC conducts reviews using fiscal
year-to-date performance through January, April, and July plus Mobile Gas’ budget projections to
determine whether Mobile Gas’ return on equity is expected to be within the allowed range of 13.35%
to 13.85% at the end of the fiscal year. No such adjustments were required through the July 2005
and 2004 test periods. Mobile Gas’ financial results for fiscal year 2005 and 2004 did, however,
result in a return on equity above the allowed range. As a result, adjustments of $433,000 and
$343,000 were made to fiscal year 2005 and 2004 earnings, respectively, such that the return on
equity as calculated for RSE purposes equaled 13.6%, the midpoint of the allowed range, and a
regulatory liability was recorded which reflects the amount owed to customers. A $343,000
reduction in rates was made in fiscal 2005, and a corresponding reduction in rates will be made in
fiscal year 2006 for the $433,000 adjustment.
RSE limits the amount of Mobile Gas’ equity upon which a return is permitted to 60 percent of its
total capitalization and provides for certain cost control measures designed to monitor Mobile Gas’
operations and maintenance (O&M) expense. Under the inflation-based cost control measurement
established by the APSC, if a change in Mobile Gas’ O&M expense per customer falls within 1.5
percentage points above or below the change in the Consumer Price Index for All Urban Customers
(index range), no adjustment is required. If the change in O&M expense per customer exceeds the
index range, three-quarters of the difference is returned to customers through future rate
adjustments. To the extent the change is less than the index range, the utility benefits by
one-half of the difference through future rate adjustments. The increase in O&M expenses per
customer was below the index range for the fiscal year ended September 30, 2005. Under RSE Mobile
Gas could recover one-half the difference, $298,000, through a rate increase effective December 1,
2005; however, the APSC has approved a waiver of this RSE requirement and instead will allow this
amount to be used to offset potential required returns to customers should O&M expense per customer
exceed the index range in future years.
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
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$100,000 of additional O&M expense or a
combination of two or more such events results in more than $150,000 of additional O&M expense
during a fiscal year; or 2) losses of revenue from any individual industrial or commercial customer
in excess of $100,000 during the fiscal year, if such losses cause Mobile Gas’ return on equity to
fall below 13.35%. An initial ESR balance of $1.0 million was recorded October 1, 2002
and is being recovered from customers through rates. Subject to APSC approval, additional funding,
up to a maximum reserve balance of $1.5 million, may be provided from any future non-recurring
revenue should such revenue cause Mobile Gas’ return on equity for the fiscal year to exceed
13.85%. During the year ended September 30, 2003, Mobile Gas charged $146,000 against the ESR due
to revenue losses from a large industrial customer. Following a year in which a charge against the
ESR is made, the APSC allows for accruals to the ESR of no more than $15,000 monthly until the
maximum funding level is achieved. Effective October 1, 2004, Mobile Gas began recording a monthly
accrual in the amount of $10,000 to restore the reserve to its former balance of $1.0 million. The
ESR balance of $975,000 at September 30, 2005 is included in the Consolidated Balance Sheet as part
of Regulatory Liabilities.
In October 2000, the Corus Group plc (Corus, formerly known as British Steel) ceased operations of
its Mobile facility and continued to pay Mobile Gas a minimum annual payment as required under the
terms of its contract. On July 28, 2005, Corus elected to end the contract and make a termination
payment as required by the terms of the contract. Under a Termination Agreement (Termination
Agreement) between Mobile Gas and Corus, Corus has agreed to pay Mobile Gas $6,100,000, with
$4,750,000 to be paid in fiscal 2006 and the final payment of $1,350,000 due October 1, 2006. The
APSC approved Mobile Gas’ request to recognize the termination payments as a regulatory liability
and amortize the balance into income over the remaining seven years of the original contract term.
Mobile Gas’ rates contain a temperature adjustment rider which is designed to offset the impact of
unusually cold or warm weather on the Company’s operating margins. The adjustment is calculated
monthly for the months of November through April and applied to customers’ bills in the same
billing cycle in which the weather variation occurs. The temperature adjustment rider applies to
substantially all residential and small commercial customers.
Through Storage and Bay Gas, the Company provides underground storage of natural gas and
transportation services. The APSC regulates intrastate storage operations through contract
approval. 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.
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3. PROPERTY, PLANT, AND EQUIPMENT
The functional classifications for the cost of property, plant, and equipment are as follows at
September 30, (in thousands):
4. NOTES PAYABLE AND LONG-TERM DEBT
Long-term debt consists of the following at September 30, (in thousands):
Maturities and sinking fund requirements on long-term debt in each of the five fiscal years
subsequent to September 30, 2005 are as follows: 2006 — $5,213,000; 2007 — $5,019,000; 2008 -
$5,300,000; 2009 — $5,454,000 and 2010 — $5,653,000. The Company’s long-term debt instruments
contain certain debt to equity ratio requirements and restrictions on the payment of cash dividends
and the purchase of shares of its capital stock. None of these requirements and restrictions are
presently expected to have a significant impact on the Company’s ability to pay dividends in the
future. Substantially all of the property of Mobile Gas is pledged as collateral for its long-term
debt, and Bay Gas’ material contracts have been pledged as collateral for its long-term debt.
At September 30, 2005, the Company had a $20 million revolving credit agreement with a group of
banks which expires February 28, 2007. Borrowings under the agreement may be made as needed
provided that the Company is in compliance with certain covenants in the revolving credit agreement
and all other loan agreements. The Company currently is in compliance with all such covenants. The
Company pays a fee
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for its committed lines of credit rather than maintaining compensating balances.
The commitment fee is 0.125% of the average daily unborrowed amount during the annual period of
calculation. Unused committed lines of credit at September 30, 2005 and 2004 were $20.0 million,
respectively.
5. INCOME TAXES
The components of income tax expense are as follows for the years ended
September 30, (in thousands):
A reconciliation of income tax expense and the amount computed by multiplying income before
income taxes by the statutory federal income tax rate for the periods indicated is as follows for
the years ended September 30, (in thousands):
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The significant components of the Company’s net deferred tax liability as of September 30, are
(in thousands):
6. CAPITAL STOCK
The Stock Option Plan of EnergySouth, Inc. (Plan) provides for the granting of incentive stock
options and non-qualified stock options to key employees. Under the Plan, an aggregate of 525,000
shares of the Company’s authorized but unissued Common Stock has been reserved for issuance. Stock
options become 25% exercisable on the first anniversary of the grant date and an additional 25%
become exercisable each succeeding year. No option may be exercised after the expiration of ten
years from the grant date. Options are granted at an option price which represents the market
price on the date of grant.
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Transactions under the Prior Plan and the Plan are summarized below:
The Company has adopted the disclosure-only provisions of Statement of Financial Accounting
Standards No. 123, “Accounting for Stock-Based Compensation” (SFAS 123). Accordingly, no
compensation expense has been recognized for its stock options granted. For purposes of disclosing
pro forma net income, the fair market value of the options at the date of grant was estimated using
a Black-Scholes options pricing model. The weighted average fair value of options granted was
$5.20, $5.46, and $5.35 per option during 2005, 2004 and 2003, respectively.
Weighted average assumptions used in the pricing model for the years ended September 30, are:
See “New Accounting Standards” under Note 1 above for a discussion of SFAS 123R which modifies
SFAS 123.
At September 30, 2005, 272,000 shares of the Company’s authorized but unissued Common Stock were
reserved for issuance under the Company’s Dividend Reinvestment and Stock Purchase Plan.
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The Company maintains The Second Amended and Restated EnergySouth, Inc. Non-Employee Directors
Deferred Fee Plan (the Plan) which is a nonqualified deferred compensation plan available to each
director of the Company who is not an employee of the Company. Under the Plan, the Company
provides each such director with the opportunity to defer receipt of fees to be paid to such
director as a member of the Board of Directors of the Company. A director who enrolls in the Plan
may elect to have the deferred compensation credited in the form of phantom stock and any payments
from the Plan to satisfy the deferred compensation obligations of such director will be made in
shares of common stock. On April 1, 2004, the Company established a non-qualified grantor trust
(the Trust) to assist in meeting obligations under the Plan which are funded through the issuance
of Company stock. The assets held in the Trust are intended to be used to pay benefits payable
under the Plan, but are subject to, among other things, the claims of general creditors of the
Company. At September 30, 2005, approximately 66,000 shares had been issued to the Trust. There
are 24,000 shares of the Company’s authorized but unissued Common Stock that are reserved for
issuance to fund the deferred compensation obligations under the Plan.
7. RETIREMENT PLANS AND OTHER BENEFITS
The Company has a noncontributory, defined benefit retirement plan covering substantially all of
its employees. Benefits are based on the greater of amounts resulting from two different formulas:
years of service and average compensation during the last five years of employment, or years of
service and compensation during the term of employment. The Company annually contributes to the
plan the amount deductible for federal income tax purposes.
The Company also provides certain health insurance benefits for retired employees until they are 65
years of age. Substantially all employees may become eligible for such benefits if they retire
before age 65 under the provisions of the Company’s retirement plan. The Company also provides
certain life insurance benefits for employees who retired prior to April 1, 2005. The Company is
accruing the costs over the expected service period of the employees.
The “projected unit credit” actuarial method was used to determine service cost and actuarial
liability. The Company uses a September 30 measurement date.
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The status of the plans was as follows at September 30 (in thousands):
Net periodic benefit cost included the following components for the years ended September 30,
(in thousands):
The expected return on plan assets for the benefit plans is derived with the assistance of
investment managers and is based on the current allocation of the plan assets and their expected
long-term rates of return. For the pension plan, the expected return on plan
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assets is applied to
a market related value of plan assets equal to the market value of assets adjusted to reflect a
five-year straight-line phase-in of the net investment gains and losses, both realized and
unrealized. The weighted average discount rate at September 30, 2005 is developed using the
estimated payouts of the respective plans and a spot interest yield curve based upon a broad group
of corporate bonds rated AA or better. The weighted average rate of compensation increase is the
average of the increases during the expected working lifetime years after an employee reaches the
average age of all participants. Assumptions used to determine benefit obligations and periodic
benefit costs are as follows:
Assumed health care cost trend rates have a significant effect on the amounts reported for the
health care plan. A one-percentage-point change in assumed health care cost trend rates would have
the following effects (in thousands):
The Company has a Retirement Committee composed of outside Directors that oversees the
investments of the pension plan. The Committee has adopted an Investment Policy with the
investment objective of meeting the Plan’s benefit obligations and which employs a total return on
investment approach whereby a mix of equities and fixed income investments are used to maximize the
long-term return on plan assets within reasonable and prudent levels of risk in order to minimize
contributions. All investments are expected to satisfy the requirements of the rule of prudent
investments
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as set forth under the Employee Retirement Income Security Act of 1974 (ERISA). The
Committee has retained investment managers who invest assets in accordance with the guidelines of
the Investment Policy. Comparative market and peer group benchmarks are utilized to ensure that
investment managers are performing satisfactorily. Approved asset classes are cash and cash
equivalents, fixed income, and domestic and non-U.S. equities. Target ranges for asset allocations
are determined by matching the actuarial projections of the Plan’s future liabilities and benefit
payments with expected long-term rates of return on the assets taking into account investment
return volatility.
The Company’s pension plan and postretirement benefit plan asset allocation at September 30, 2005
and 2004 and the current target allocation range are as follows:
Pension plan equity securities include the Company’s common stock of 4.3% and 6.8% of plan
assets at September 30, 2005 and 2004 respectively. The Postretirement benefits plan does not
invest in the Company’s common stock.
The Company does not anticipate contributing to its pension plan in fiscal year 2006 but expects to
contribute $3,000 to its postretirement benefit plan.
The following benefit payments, which reflect expected future service, as appropriate, are expected
to be paid in the following fiscal years (in thousands):
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The Company has formed two voluntary employees’ beneficiary association (VEBA) trusts to fund
postretirement health and life insurance benefits. The Company contributed $3,000 in 2005 and
$2,000 in 2004.
The Company has previously entered into unfunded and unsecured deferred compensation agreements
with Mr. John S. Davis, President and Chief Executive Officer, which provide for supplemental
payments upon retirement or termination of employment. At September 30, 2005 and 2004, the
Company had recorded a liability of $932,000 and $658,000, respectively, for the payment of future
benefits. Expense under these agreements for the years ended September 30, 2005, 2004, and 2003 was
$274,000, $122,000, and $117,000, respectively. The increase in fiscal 2005 expense included
adjustments for a change in the discount rate and an increase in life expectancy.
The Company’s eligible employees may participate in the Employee Savings Plan or the Bargaining
Unit Employees Savings Plan, both of which are 401(k) plans. The Company’s contributions to these
401(k) plans for the years ended September 30, 2005, 2004, and 2003 were $223,000 ,$230,000, and
$240,000, respectively.
8. COMMITMENTS AND CONTINGENCIES
The Company has third-party contracts, which expire at various dates through the year 2011, for the
purchase, storage and delivery of gas supplies. Mobile Gas is exposed to
market risks associated with commodity prices of natural gas. Mobile Gas ameliorates the price
risk associated with purchases of natural gas by using a combination of natural gas storage
services, fixed price contracts and spot market purchases. As part of Mobile Gas’ gas supply
strategy, it has adopted a policy under which management is authorized to commit to future gas
purchases at fixed prices up to a specified percentage of the normalized degree-day usage for any
corresponding month as outlined within the policy. All commitments for future gas purchases at
fixed prices meet the requirements of paragraph 10.b, Normal purchases and Normal sales, of
Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative
Instruments and Hedging Activities”, as amended by SFAS No. 149. Thus, the commitments for future
purchases of natural gas at fixed prices are deemed to be purchases in the normal course of
business and are not subject to derivative accounting treatment.
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At June 30, 2005, Mobile Gas had not entered into derivative instruments for the purpose of hedging
the price of natural gas. If Mobile Gas had entered into such derivative instruments, any cost
incurred or benefit received from the derivative or other hedging arrangements would be recoverable
or refunded through the purchased gas adjustment mechanism. As discussed in “Results of
Operations” under “Natural Gas Distribution” within Item 2 above, the APSC currently allows for
full recovery of all costs associated with natural gas purchases; therefore, costs associated with
the forward purchases of natural gas will be passed through to customers when realized and will not
affect future earnings or cash flows.
A portion of firm supply requirements is expected to be met through the withdrawal of gas from the
storage facility owned by Bay Gas. Mobile Gas has entered into a Gas Storage Agreement under which
Bay Gas is to provide storage services for an initial period of 20 years which began in September
1994 with the commencement of commercial operations of the storage facility. The purchased gas
adjustment provisions of the Company’s rate schedules permit the recovery of gas costs from
customers.
Bay Gas has contracted for rights to develop caverns for the storage of natural gas on property
owned by Olin Corporation. With respect to the first and second caverns, the terms of the
agreement state that Bay Gas shall pay to Olin twenty consecutive annual cash payments to begin
upon completion of each storage cavern. Payments relating to the third cavern will extend over
fifty years. 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
September 30, 2005, Bay Gas had entered into contracts for the drilling and casing materials for
the development of the third storage cavern.
Total future minimum payments for these commitments as discussed above are listed, in thousands, in
the table below.
The Company is subject to various federal, state and local laws and regulations relating to
the environment, which have not had a material effect on the Company’s financial position or
results of operations.
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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 Site
Inspection of the property, and recently reported that its inspection did not indicate that a
threat to human health currently exists. ADEM has, however, indicated various options for actions
on the site. The Company is evaluating those options. Based upon the report and its review by the
Company’s environmental consultants, the Company has not changed its best estimate of $200,000 as a
remediation liability. The Company sought and was allowed by the APSC to record this amount in
expense in fiscal 2004. The Company intends that, should further
investigation or changes in environmental laws or regulations require material expenditures for
evaluation or remediation with regard to the site, it would apply to the APSC for appropriate rate
recovery of such costs. However, there can be no assurances that the APSC would approve the
recovery of such costs or the amount and timing of any such recovery.
The Company is involved in litigation arising in the normal course of business. Management
believes that the ultimate resolution of such litigation will not have a material adverse effect on
the consolidated financial statements of the Company.
9. FAIR VALUE OF FINANCIAL INSTRUMENTS
Fair values of financial instruments have been reported to meet the disclosure requirements of
Statement of Financial Accounting Standards No. 107, “Disclosures About Fair Values of Financial
Instruments,” and are not necessarily indicative of the amounts that the Company could realize in a
current market exchange.
The carrying amounts for cash and cash equivalents, gas and other receivables, merchandise
receivables, notes payable, accounts payable and other current liabilities approximate fair value.
The fair value of long-term debt is estimated based on interest rates available to the Company at
the end of each respective year for the issuance of debt with similar terms and remaining
maturities.
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The carrying amount and the estimated fair value of long-term debt, including current maturities of
long-term debt, is as follows at September 30, (in thousands):
10. FINANCIAL INFORMATION BY BUSINESS SEGMENT
Statement of Financial Accounting Standards No. 131, “Disclosures About Segments of An Enterprise
and Related Information,” requires that companies disclose segment information which reflects how
management makes decisions about allocating resources to segments and measuring their performance.
The reportable segments disclosed herein were determined based on such factors as the regulatory
environment and the types of products and services offered.
The Company is principally engaged in two reportable business segments: Natural Gas Distribution
and Natural Gas Storage. The Natural Gas Distribution segment is actively engaged in the
distribution and transportation of natural gas to residential, commercial and industrial customers
through Mobile Gas and SGT. The Natural Gas Storage segment provides for the underground storage
of natural gas and transportation services through the operations of Bay Gas and Storage. Through
Mobile Gas and Services, the Company also provides merchandising and other energy-related services
which are aggregated with EnergySouth, the holding company, and included in the Other segment. For
the years ended September 30, 2005, 2004, and 2003, all segments were located in Southwest Alabama.
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 Storage segment.
Segment assets are provided as additional information and are net of intercompany advances,
intercompany notes receivable and investments in subsidiaries.
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The following table reconciles the distribution and storage segment operating revenues to the
natural gas revenue data segregated by class of customer as presented
in Item 6 — Selected
Financial Data.
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11. QUARTERLY FINANCIAL DATA (Unaudited)
Quarterly financial data for fiscal 2005 and 2004 is summarized as follows
(in thousands, except per share data):
The pattern of quarterly earnings reflects a seasonal nature because weather conditions strongly
influence operating results.
(1) The sum of the quarterly amounts does not equal the year’s amount due to rounding of the
quarterly amounts or a changing number of average shares.
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SCHEDULE II
ENERGYSOUTH, INC. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEARS ENDED SEPTEMBER 30, 2005, 2004, AND 2003 (in thousands)
Notes:
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EXHIBIT INDEX
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