UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K/A
Amendment No. 1
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| þ | | Annual Report Pursuant to Section 13 or 15(d) of The Securities Exchange Act of 1934 for the fiscal year ended September 30, 2007 |
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| o | | Transition report pursuant to Section 13 or 15(d) of The Securities Exchange Act of 1934 for the transition period from to |
Commission File Number 0-29604
EnergySouth, Inc.
(Exact name of registrant as specified in its charter)
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| Delaware | | 58-2358943 |
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(State or other Jurisdiction of
incorporation or organization) | | (I.R.S. Employer
Identification No.) |
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| 2828 Dauphin Street, Mobile, Alabama | | 36606 |
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| (Address of principal executive offices) | | (Zip Code) |
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| Registrant’s telephone number, including area code | | (251)450-4774 |
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SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
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| Title of each class | | Name of each exchange
on which registered |
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| None | | None |
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.
Yeso Noþ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yeso Noþ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesþ Noo
Indicate by check mark 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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.
Large accelerated filero Accelerated filerþ Non-accelerated filero
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yeso 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, 2007 was approximately $334,092,013.
As of December 6, 2007, there were 8,093,273 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 17, 2007, for the Annual Meeting of Shareholders on January 25, 2008 are incorporated by reference into Part III.
TABLE OF CONTENTS
EXPLANATORY NOTE
This Amendment No. 1 to the Annual Report on Form 10-K of EnergySouth, Inc. (the “Company”) for the fiscal year ended September 30, 2007 is being filed for the purpose of correcting the state of incorporation of the Company on the cover page of the Form 10-K to reflect Delaware and adding the signature of the Company’s independent public accountant to the reports at pages 30 and F-2 of the Form 10-K which was inadvertently omitted. This amendment does not reflect events occurring after the original filing of the Form 10-K or modify or update those disclosures except as stated above.
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 and in February 1998 became the holding company for Mobile Gas Service Corporation (“Mobile Gas”), a natural gas utility, and its subsidiaries. Effective February 1, 2007, EnergySouth reincorporated in the State of Delaware as approved by the shareholders at the annual meeting of shareholders held January 26, 2007.
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 95,000 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 Midstream, Inc. (���Midstream”) was incorporated under the name of EnergySouth Storage Services, Inc. on December 4, 1991. In December 2000, Midstream became a wholly-owned subsidiary of EnergySouth. As of September 30, 2007, in addition to owning 100% of EnergySouth Services, Inc. (“Services”), Midstream also held a general partnership interest of 90.9% in Bay Gas Storage Company, Ltd. (“Bay Gas”), an Alabama limited partnership in which a 9.1% limited partnership interest was held by Olin Corporation. 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.
Services was incorporated in March 1983. Through Services, the Company provides natural gas marketing, trading and risk management activities. Services owns a 51% interest in Southern Gas Transmission Company, an Alabama general partnership which was formed in November 1991 and has since 1992 provided transportation services from the facilities of Gulf South Pipeline Company (“Gulf South”) near Flomaton, Alabama to the facilities of Alabama River Pulp Company, Inc. in Claiborne, Alabama. Service became a wholly-owned subsidiary of Midstream on June 12, 2007.
MGS Marketing Services, Inc. (“Marketing”) was incorporated in 1993 to assist existing and potential customers in the purchase of natural gas. Marketing became a wholly-owned subsidiary of EnergySouth during fiscal year 1998. Marketing is no longer actively engaged in business.
Business Segments
The Company’s operations are classified into the following business segments:
| • | | Natural Gas Distribution – The Natural Gas Distribution segment is actively engaged in the distribution and transportation of natural gas to residential, commercial and industrial customers in Southwest Alabama through Mobile Gas. |
| • | | Natural Gas Midstream – The Natural Gas Midstream segment provides for the underground storage of natural gas and transportation services through the operations of Bay Gas and transportation services through the operations of SGT. Through Services’ office in Houston, Texas, Midstream manages and optimizes transportation and storage assets through natural gas marketing, trading and risk management activities. The storage and transportation operations are currently located in Southwest Alabama with additional operations planned at the Mississippi Hub gas storage facility under development near Jackson, Mississippi, which was acquired in late November, 2007. |
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| • | | Other – Includes merchandising, financing, and other energy-related services which are provided through Mobile Gas and are aggregated with the corporate operations of EnergySouth, the holding company. |
For financial information by business segment, including revenues by segment, for the fiscal years ended September 30, 2007, 2006, and 2005, see Note 12 to the Consolidated Financial Statements.
Customers
Of the approximately 95,000 customers of the Company, approximately 95% are residential customers. In the fiscal year ended September 30, 2007, approximately 53% of the Company’s gas revenues were derived from residential sales, 16% from small commercial and industrial sales, 8% from large commercial and industrial sales, 8% from transportation services, and 15% from storage and miscellaneous services. Residential sales in fiscal 2007 accounted for approximately 4% 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 93%, 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 12 to the Consolidated Financial Statements. The ten largest customers of the Company accounted for approximately 21% of the Company’s gross margin in fiscal 2007, with the largest accounting for approximately 8%.
Gas Supply
The Company is directly connected to three natural gas processing plants in south Mobile County and one processing plant in north Mobile County. The Company has firm supply contracts for varying monthly payments with Chevron Natural Gas through October 31, 2008 and Exxon Mobil through November 30, 2007, and month to month thereafter, through Mobile Gas’ direct connection with the Hatters Pond processing plant.
Mobile Gas has a current peak day firm requirement of 104,000 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. The gas supply requirement for the No-Notice Service is met through a contract with BP Energy Company through March 31, 2008.
Natural Gas Midstream Operations
The natural gas midstream segment currently provides for the underground storage of natural gas and transportation services through the operations of Bay Gas and transportation services through the operations of SGT. During fiscal 2007, the Company expanded its midstream operations to include the management and optimization of transportation and storage assets through natural gas marketing, trading and risk management activities.
Construction of Bay Gas’ first storage cavern and facilities was completed in 1994 and currently has a working gas capacity of approximately 2.3 million MMBtu. The construction of natural gas-fired electric generation facilities in the Southeast has provided opportunities to provide increased gas storage and transportation services. Construction of Bay Gas’ second storage cavern was completed and the cavern was placed into service April 1, 2003. Currently, the second storage cavern has a working 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.
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Bay Gas is currently developing a third storage cavern and related facilities and has entered into multi-year contracts with customers for all of the cavern capacity. The new cavern is designed to add 5.0 Bcf of working gas capacity and is presently anticipated to be in service by April 2008. The addition of the third cavern and additional capacity development of 1.0 Bcf in one or more of the first three caverns is currently planned to ultimately increase the total working gas capacity of Bay Gas to 12.0 Bcf with injection and withdrawal capacities to 450 MMcf per day and 1.2 Bcf per day, respectively.
Having reached full subscription of the current working capacity of both existing caverns and the third cavern which is currently under development, Bay Gas plans development of two new 5.0 Bcf high deliverability underground salt-dome caverns together with additional pipeline interconnects with Transco. Midstream is currently communicating with respondents in an effort to secure agreements for firm storage services. Bay Gas has begun drilling operations for development of the fourth cavern and plans to move forward with development of the fifth cavern and the pipeline interconnects subject to its ability to execute sufficient firm storage agreements with interested parties.
Bay Gas’ growth has reflected the rapid growth in natural gas utilization in the markets it serves. Establishing interconnects with the Transco pipeline system will allow additional prospective customers to access Bay Gas. This interstate pipeline system serves a number of traditional, wintertime markets for natural gas in the United States and will complement the warmer weather markets currently connected to Bay Gas. Management believes that Bay Gas, with the possible construction of additional caverns and new interstate pipeline interconnects, is well positioned to serve the storage needs of these markets. As described above, Bay Gas plans to move forward with development of the fourth and fifth cavern and the new pipeline interconnects subject to its ability to execute sufficient firm storage agreements with the interested parties.
In its Current Report on Form 8-K filed November 5, 2007, the Company reported that Midstream had entered into agreements to acquire the Mississippi Hub gas storage facility project under development near Jackson, Mississippi, and the completion of that acquisition was reported in the Company’s Current Report on Form 8-K filed December 4, 2007.
Midstream operations include revenues from transportation and storage services provided to customers under long-term contracts and short-term interruptible contracts and include the value realized by optimizing the storage and transportation capacity that Midstream owns. Midstream participates in natural gas storage transactions in which it seeks to capture the pricing differences that occur over time. Midstream purchases physical natural gas and then sells financial contracts at favorable prices to lock in a gross profit margin. Additionally, Midstream periodically participates in park and loan transactions in which physical gas is borrowed and later repaid. Through the use of transportation and storage services and derivatives, Midstream is able to capture gross profit margin through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time.
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 approximately 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
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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 intends to continue its efforts to reduce the likelihood of bypass by offering competitive rates and services to such customers.
Midstream Competition. A number of types of competitors may provide services like or in competition with those of Midstream. These include, among others, natural gas storage facilities, natural gas aggregators, and natural gas pipelines. Midstream 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 were historically 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.
Mobile Gas has utilized a Rate Stabilization and Equalization (RSE) rate setting process since October 1, 2002. On June 14, 2005, the Alabama Public Service Commission (APSC) issued an order to extend RSE on substantially the same basis from October 1, 2005 through September 30, 2009. In addition, absent an APSC order after that date modifying the RSE rate tariff, RSE shall continue in effect beyond September 30, 2009.
RSE is a ratemaking methodology also used by the APSC to regulate certain other public Alabama energy utilities. A rate adjustment designed to increase Mobile Gas’ annual gas revenues by approximately $4.2 million was implemented December 1, 2006. Previous rate adjustments were implemented under the RSE tariff which were designed to decrease annual gas revenues by approximately $303,000 effective December 1, 2005 and to increase annual gas revenues by approximately $1.7 million effective December 1, 2004. The December 1, 2005 rate decrease was due primarily to the return of approximately $1,350,000 of the regulatory liability for gross receipts tax collections to ratepayers during fiscal 2006. Mobile Gas’ rates, as established under RSE, allow a return on average equity within a range of 13.35% to 13.85% for the period. Mobile Gas is allowed to earn a return on all of its assets with no exclusions. Increases are allowed only once each fiscal year, effective December 1, and cannot exceed four percent of prior-year revenues. Under RSE, the APSC conducts reviews using fiscal year-to-date performance through January, April, and July plus Mobile Gas’ budget projections to determine whether Mobile Gas’ return on equity is expected to be within the allowed range at the end of the fiscal year. No such adjustments were required for fiscal 2006 or through the July 2005 test periods. Mobile Gas’ financial results for fiscal year 2005 did, however, result in a return on equity above the allowed range. As a result, adjustments of $433,000 were made to fiscal year 2005 pre-tax earnings such that the return on equity, as calculated for RSE purposes, equaled 13.6%, the midpoint of the allowed range, and a regulatory liability
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was recorded which reflected the amount owed to customers. Reductions in rates were made in fiscal year 2006 which resulted in $433,000 being fully refunded to customers by the end of the fiscal year.
RSE limits the amount of Mobile Gas’ equity upon which a return within the allowed range 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 within the index range for the rate years ended September 30, 2007 and 2006; therefore, no adjustments were required. 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 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 conjunction with the approval of RSE, the APSC approved an Enhanced Stability Reserve (ESR), beginning October 1, 2002, to which Mobile Gas may charge the full amount of: 1) extraordinary O&M expenses resulting fromforce majeureevents such as storms, severe weather, and outages, when one such event results in more than $100,000 of additional O&M expense or a combination of two or more such events results in more than $150,000 of additional O&M expense during a fiscal year; or 2) losses of revenue from any individual industrial or commercial customer in excess of $100,000 during the fiscal year, if such losses cause Mobile Gas’ return on equity to fall below 13.35%. An initial ESR balance of $1.0 million was recorded October 1, 2002 and is being recovered from customers through rates. Subject to APSC approval, additional funding, up to a maximum reserve balance of $1.5 million, may be provided from any future non-recurring revenue should such revenue cause Mobile Gas’ return on equity for the fiscal year to exceed 13.85%. Following a year in which a charge against the ESR is made, the APSC allows for accruals to the ESR of no more than $15,000 monthly until the maximum funding level is achieved. The ESR balance of $1,000,000 at September 30, 2007 is included in the balance sheet of the Consolidated Financial Statements as part of Regulatory Liabilities.
In October 2000, the Corus Group plc (Corus, formerly known as British Steel) ceased operations of its Mobile facility and continued to pay Mobile Gas a minimum annual payment as required under the terms of its contract. On July 28, 2005, Corus elected to end the contract and make a termination payment as required by the terms of the contract. Under a Termination Agreement (Termination Agreement) between Mobile Gas and Corus, Corus agreed to pay Mobile Gas $6,100,000, of which $4,750,000 was paid in fiscal year 2006, and the final payment of $1,350,000 was paid October 2, 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 temperature adjustment rider applies to substantially all residential and small commercial customers. The adjustment is calculated monthly for the months of November through April and prior to November 1, 2006 was applied to customers’ bills in the same billing cycle in which the weather variation occurs. Effective November 1, 2006, Mobile Gas accumulates an adjustment for the margin impact due to variances in the weather. The accumulated adjustment from one heating season (November through April) will be billed or credited to customers in subsequent periods. This mechanism reduces the variability of both customers’ bills and Mobile Gas’ earnings due to weather fluctuations.
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.
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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 firm and interruptible interstate transportation-only services. The FERC last issued an order on April 14, 2006 approving rates for transportation-only services. In accordance with FERC filing requirements, on March 9, 2007 Bay Gas filed a petition with the FERC requesting approval of rates for transportation-only service.
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 2009. 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 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.
Based on plans for the site, the Alabama Department of Environmental Management (“ADEM”) has conducted a “Brownfield” evaluation of the property. On January 5, 2005, ADEM released a “CERCLA Targeted Brownfield Site Inspection” report on the manufactured gas plant site. Prior to the ADEM “Brownfield” evaluation, Mobile Gas engaged environmental consultants to evaluate the site in connection with the plans for the site. Based on their review, the Company recorded its best estimate of $200,000 as an expense and a remediation liability in fiscal 2004. The Company intends that, should further investigation or changes in environmental laws or regulations require material expenditures for evaluation or remediation with regard to the site, it would apply to the APSC for appropriate rate recovery of such costs. However, there can be no assurances that the APSC would approve the recovery of such costs or the amount and timing of any such recovery.
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Employees
Mobile Gas employed 244 full-time employees as of September 30, 2007. Of these, approximately 35% are represented by the Paper, Allied-Industrial, Chemical and Energy Workers International Union, Local No. 3-0541. As of September 30, 2007 Bay Gas employed 22 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.
Item 1A.Risk Factors.
The Company’s financial and operating results are subject to a number of factors, many of which are not within the control of management. Although key risk factors are discussed below, other risks may prove to be more important in the future. These factors include the following:
Third Party Facilities:The Company is served by third party facilities. These facilities include third party natural gas gathering, transportation, processing and storage facilities. Mobile Gas relies upon such facilities for access to natural gas supplies. Bay Gas relies on such facilities for access to markets for its storage services. Such facilities are typically limited in number and geographically concentrated. An extended interruption of access to or service from these facilities, whether caused by weather events, natural disaster, accident, mechanical failure, criminal act or otherwise could result in material adverse financial consequences to Mobile Gas, Bay Gas and/or the Company.
Operations:Inherent in the gas distribution activities of Mobile Gas and the storage services provided by Bay Gas are a variety of hazards and operational risks, such as leaks, explosions and mechanical problems that could cause substantial financial losses. In addition, these risks could result in loss of human life, significant damage to property, impairment of our operations and substantial losses to the Company. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of these risks and losses. The location of pipeline and storage facilities near populated areas, including residential areas, commercial business centers, and industrial sites, could increase the level of damages resulting from these risks. The occurrence of any of these events could adversely affect Mobile Gas’, Bay Gas’ and/or the Company’s financial position, results of operations and cash flows.
Regulatory Environment:Mobile Gas’ distribution system is regulated by the Alabama Public Service Commission (APSC) and utilizes a Rate Stabilization and Equalization (RSE) rate setting process. Mobile Gas’ rates, as established under RSE, allow a certain 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. Mobile Gas’ tariff also includes 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. There is a risk that changes in the regulatory environment, including rate relief to recover increased capital and operating costs, allowed rates of return and the ability to pass on to customers the increased costs of natural gas could adversely affect the financial position, results of operations and cash flows of Mobile Gas.
Bay Gas’ intrastate storage operations are regulated by the APSC on a contract basis. The Federal Energy Regulatory Commission has jurisdiction over interstate services and allows Bay Gas to
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charge market-based rates for storage services. Market-based rates minimize regulatory involvement in the setting of rates for storage services and allow Bay Gas to respond to market conditions. There is a risk that changes in the regulatory environment, such as the inability of Bay Gas to charge market based rates for storage services, could have an adverse affect on the financial position, results of operations and cash flows of Bay Gas.
Environmental Regulation:The Company is subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local governmental authorities relating to protection of the environment and health and safety matters, including those legal requirements that govern discharges of substances into the air and water, the management and disposal of hazardous substances and waste, the clean-up of contaminated sites, groundwater quality and availability, plant and wildlife protection, as well as work practices related to employee health and safety. Environmental legislation also requires that the Company’s facilities, sites and other properties associated with its operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Failure to comply with these laws, regulations, permits and licenses may expose the Company to fines, penalties or interruptions in the operations of the Company that could be significant to the financial results. In addition, existing environmental regulations may be revised or the Company’s operations may become subject to new regulations. Such revised or new regulations could result in increased compliance costs or additional operating restrictions which could adversely affect the Company’s business, financial condition and results of operations.
Volatility of Natural Gas Prices:Although Mobile Gas utilizes fixed price contracts to mitigate gas supply cost risk in the near term, fluctuations in future gas supply costs could materially affect its financial position and rates to customers. Significant increases in the price of natural gas may cause Mobile Gas’ retail customers to conserve or switch to alternate sources of energy.
Use of Derivative Instruments:Midstream operations use derivative instruments, such as swaps, options, futures and forwards, to manage commodity and financial market risks. Midstream could recognize financial losses as a result of volatility in the market values of these contracts, or should a counterparty fail to perform. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.
Customer Concentration:Revenues and related accounts receivable from Bay Gas’ storage operations are primarily generated from the storage of natural gas for customers who provide energy related services, including natural gas-fired electric generation, natural gas distribution, and energy marketing companies. This concentration of services to the energy industry has the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, in that the Company’s customers may be affected similarly by changes in economic, industry or other conditions. Bay Gas enters into long-term contracts with customers for firm storage capacity. Four customers have contracted for approximately 97% of the current working gas storage capacity under long term contracts that expire at various dates from October 2007 to March 2018. Bay Gas’ largest customer has contracted for approximately 53% of the current working gas storage capacity which expires in March 2018.
Mobile Gas Service Territory:Mobile Gas’ utility customers are geographically concentrated in southwest Alabama. Significant economic, weather, natural disaster, criminal act or other events that adversely affect this area could adversely affect Mobile Gas and the Company.
Competition:In the residential and commercial customer markets, Mobile Gas’ regulated utility operations compete with other energy products. The primary product competition is with electricity for heating, water heating and cooking. As discussed above, increases in the price of natural gas could negatively impact Mobile Gas’ competitive position by causing the customer to conserve or switch to alternate sources of energy. Adverse economic conditions, including higher natural gas costs, could cause Mobile Gas’ industrial customers to use alternate sources of energy, such as fuel oil, coal or wood chips. Due to the close proximity of various pipelines and gas processing plants to Mobile Gas’ service area, there exists the possibility that current or prospective customers could install their own facilities and
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connect directly to a supply source and thereby “bypass” Mobile Gas’ system. This potential bypass of the distribution system creates a risk of the loss of large industrial/commercial customers that could adversely affect Mobile Gas’ financial position, results of operations and cash flows.
Bay Gas operates the easternmost high deliverability, underground salt-dome storage caverns in the Southeast region of the United States. Although Bay Gas’ storage operations currently face competition from other existing natural gas storage facilities, natural gas aggregators and natural gas pipelines, competition may increase if new infrastructure is constructed near its existing facilities.
Access to Credit Markets:The natural gas distribution business and natural gas midstream businesses are capital intensive. The Company and its subsidiaries rely on access to both short-term and long-term capital markets to satisfy liquidity requirements. Adverse changes in the economy or these markets, the overall health of the industries in which the Company and its subsidiaries operate and changes to the creditworthiness of the Company could limit access to these markets and/or increase the cost of capital.
Item 1B.Unresolved Staff Comments.
None.
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 2042, 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, 2007.
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.
9
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 2007.
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 2008 Annual Meeting of Shareholders and is incorporated herein by reference.
The following is a list of names and ages of officers of the Registrant, including executive officers referred to in Rule 401(b) of Regulation S-K, 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.
10
| | | |
| | | Business Experience |
| Name, Age, and Position | | During Past 5 Years |
Charles P. Huffman, 54
Executive Vice President and Chief Financial Officer - - EnergySouth, Inc. | | Appointed in August 2007;
Previously: Sr. Vice President and Chief Financial Officer — EnergySouth, Inc. (2001-2007); Sr. Vice President, Chief Financial Officer, and Treasurer — EnergySouth, Inc. (1998-2001) |
| | | |
| Executive Vice President and Chief Financial Officer - - Mobile Gas Service Corporation; Director, Executive Vice President and Chief Financial Officer - EnergySouth Services, Inc.; Director, Executive Vice President and Chief Financial Officer — MGS Marketing Services, Inc.; Director, Executive Vice President and Chief Financial Officer — EnergySouth Midstream, Inc.; Executive Vice President and Chief Financial Officer — Bay Gas Storage Company, Ltd. | | Appointed in August 2007; Previously: Sr. Vice President and Chief Financial Officer — Mobile Gas Service Corporation (2001-2007); Sr. Vice President Chief Financial Officer, Treasurer, and Assistant Secretary — Mobile Gas Service Corporation; Vice President/Treasurer - EnergySouth Services, Inc.; Director/Vice President/Treasurer — EnergySouth Midstream, Inc.; Director/Vice President/Treasurer — MGS Marketing Services, Inc. (1998-2001) |
| | | |
| Benjamin J. Reese, 51 | | Appointed in April 2007: |
| Director, President and Chief Operating Officer - EnergySouth Midstream, Inc.; Director, President - EnergySouth Services, Inc.; President — Bay Gas Storage Company, Ltd. | | Previously: Senior Vice President and Chief Commercial Officer — Centerpoint Energy (1998-2007) |
| | | |
Gregory H. Welch, 51
President and Chief Operating Officer - Mobile Gas Service Corporation; Director — MGS Marketing Services, Inc. | | Appointed in April 2007;
Previously: President and Chief Operating Officer - Bay Gas Storage Company, Ltd. (2002-2007) |
| | | |
G. Edgar Downing, Jr., 51
Senior Vice President, Secretary and General Counsel — EnergySouth, Inc.; | | Appointed in December 2005 Previously:
Vice President, Secretary and General Counsel — EnergySouth, Inc. |
| | | (1998 — 2005) |
| | | |
| Senior Vice President, Secretary and | | Appointed in December 2005; Previously: |
| General Counsel — Mobile Gas Service Corporation; Director, Senior Vice President - - EnergySouth Services, Inc,; Director, Senior Vice President and Secretary — EnergySouth Midstream, Inc.; Senior Vice President — Bay Gas Storage Company, Inc.; Director, President and Chief Operating Officer - MGS Marketing Services, Inc. | | Secretary, General Counsel and Vice President of Administration — Mobile Gas Service Corporation; Director, Vice President and Secretary — EnergySouth Services, Inc,; Vice President and Secretary - MGS Marketing Services, Inc.; Director, Vice President and Secretary — Energysouth Midstream, Inc. |
11
| | | |
| | | Business Experience |
| Name, Age, and Position | | During Past 5 Years |
LaBarron N. McClendon, 43 Sr. Vice President Administration -
EnergySouth, Inc. | | Appointed in August 2007 Previously: Vice President Human Resources - EnergySouth, Inc. (2001-2007) |
| | | |
| Sr. Vice President Administration - Mobile Gas Service Corporation | | Appointed December 2001; Previously: Vice President Human Resources - Mobile Gas (2001-2007); Director Human Resources - Mobile Gas Service Corporation (1991-2001); Manager Human Resources - Mobile Gas Service Corporation (1998 - 1999) |
| | | |
| Susan P. Stringer, 46 Vice President and Controller - EnergySouth, Inc. | | Appointed in December 2000 |
| | | |
| Vice President and Controller - Mobile Gas Service Corporation | | Appointed in December 2000; Previously: Director - Financial Reporting - Mobile Gas Service Corporation (2000); Manager - Financial Reporting - Mobile Gas Service Corporation (1999 - 2000); Accounting Manager - Mobile Gas Service Corporation (1998 - 1999) |
| | | |
| Daniel T. Ford, 41 Treasurer - EnergySouth, Inc. | | Appointed in June 2002 |
| | | |
| Treasurer - Mobile Gas Service Corporation; Treasurer - EnergySouth Services, Inc.; | | Appointed June 2002; Previously: Director Rates and Analysis - Mobile Gas Service Corporation |
PART II
Item 5.Market for the Registrant’s Common Stock Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
The Registrant’s Common Stock, $.01 par value, is traded on the NASDAQ National Market under the symbol “ENSI”. As of December 6, 2007 there were 1,149 holders of record of the Company’s Common Stock. Information regarding Common Stock dividends and the closing price range for Common Stock during the periods indicated is as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Per Share | | |
| | | Dividends Declared | | Closing Price Range |
| Fiscal Year | | | | | | | | |
| Quarter Ended | | 2007 | | 2006 | | 2007 | | 2006 |
| | | | | | | | | | | High | | Low | | High | | Low |
| December 31 | | $ | .230 | | | $ | .215 | | | $ | 41.520 | | | $ | 33.260 | | | $ | 29.910 | | | $ | 26.311 | |
| March 31 | | | .230 | | | | .215 | | | | 42.830 | | | | 37.000 | | | | 31.810 | | | | 26.400 | |
| June 30 | | | .250 | | | | .230 | | | | 52.230 | | | | 39.030 | | | | 34.920 | | | | 30.080 | |
| September 30 | | | .250 | | | | .230 | | | | 54.180 | | | | 43.790 | | | | 39.000 | | | | 31.090 | |
12
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 and credit agreements 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.
The following table summarizes information concerning securities authorized for issuance under equity compensation plans:
| | | | | | | | | | | | | |
| | | Number of Securities | | | | | | | Number of Securities | |
| | | to be Issued Upon | | | Weighted | | | Remaining Available for | |
| | | Exercise of | | | Average | | | Future Issuance Under | |
| Plan Category | | Outstanding Options | | | Exercise Price | | | Equity Compensation Plans | |
| Equity compensation plans approved by security holders | | | 441,100 | | | $ | 29.087 | | | | 113,000 | |
| Equity compensation plans not approved by security holders | | | — | | | | — | | | | — | |
| | | | | | | | | | |
| Total | | | 441,100 | | | $ | 29.087 | | | | 113,000 | |
| | | | | | | | | | |
Performance Graph
EnergySouth, Inc. – Comparison of Five-Year Cumulative Shareholder Returns
This graph compares the total shareholder returns (assuming reinvestment of dividends) of investments in the Company, the Russell 2000 Index, and an industry peer group index compiled by Hemscott, Inc. The graph assumes $100 invested at the per-share closing price of the Company’s common stock on the NASDAQ National Market on September 30, 2002, in the Company’s common stock and in each of the indices.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| |
| | As of September 30, | | | 2002 | | | 2003 | | | 2004 | | | 2005 | | | 2006 | | | 2007 | |
| | ENERGYSOUTH, INC. | | | $ | 100 | | | | $ | 128 | | | | $ | 172 | | | | $ | 179 | | | | $ | 226 | | | | $ | 345 | | |
| | HEMSCOTT GROUP INDEX | | | $ | 100 | | | | $ | 126 | | | | $ | 154 | | | | $ | 208 | | | | $ | 242 | | | | $ | 302 | | |
| | RUSSELL 2000 INDEX | | | $ | 100 | | | | $ | 135 | | | | $ | 159 | | | | $ | 185 | | | | $ | 201 | | | | $ | 218 | | |
| |
Total shareholder return includes reinvested dividends. The Hemscott Group Index includes the companies listed below: AGL Resources, Inc., Amerigas Partners L.P., Atmos Energy Corp., Chesapeake Utilities CP,
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Corning Natural Gas, Delta Natural Gas Co. Inc., Energen Corporation, Energy West, Inc., EnergySouth, Inc., Equitable Resources, Inc., Laclede Group, Inc., National Fuel Gas Co., National Grid PLC, New Jersey Resources Corp., Nicor, Inc., Northwest Natural Gas Co., Oneok, Inc., Piedmont Natural Gas Co., RGC Resources, Inc., Semco Energy, Inc., Sempra Energy, South Jersey Industries, Southern Union Co., Southwest Gas Corp., Transcanada Corp., and WGL Holdings, Inc.
14
Item 6 — EnergySouth, Inc. — Selected Financial Data
FINANCIAL SUMMARY
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Years Ended September 30, | | 2007 | | 2006 | | 2005 | | 2004 | | 2003 | | 2002 | | 2001 | | 2000 | | 1999 | | 1998 |
| SELECTED FINANCIAL DATA | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (in thousands, except per share data) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Gas Revenues | | $ | 130,738 | | | $ | 130,686 | | | $ | 119,987 | | | $ | 111,488 | | | $ | 95,150 | | | $ | 81,560 | | | $ | 103,424 | | | $ | 69,714 | | | $ | 63,889 | | | $ | 70,740 | |
| Merchandise Sales | | | 3,240 | | | | 4,046 | | | | 3,263 | | | | 3,029 | | | | 3,259 | | | | 3,499 | | | | 2,966 | | | | 2,913 | | | | 2,827 | | | | 2,920 | |
| Other | | | 1,055 | | | | 1,135 | | | | 1,356 | | | | 1,455 | | | | 1,206 | | | | 1,360 | | | | 1,369 | | | | 1,470 | | | | 1,344 | | | | 1,329 | |
| |
Total Operating Revenues | | $ | 135,033 | | | $ | 135,867 | | | $ | 124,606 | | | $ | 115,972 | | | $ | 99,615 | | | $ | 86,419 | | | $ | 107,759 | | | $ | 74,097 | | | $ | 68,060 | | | $ | 74,989 | |
| |
Income Before Cumulative Effect of Changes in Accounting Principles | | $ | 16,033 | | | $ | 14,036 | | | $ | 13,841 | | | $ | 12,568 | | | $ | 11,135 | | | $ | 10,231 | | | $ | 6,138 | | | $ | 8,792 | | | $ | 8,624 | | | $ | 8,417 | |
| Cumulative Effect of Changes in Accounting Principles | | | | | | | | | | | | | | | | | | | | | | | | | | | — | | | | — | | | | (349 | ) | | | — | |
| |
Net Income | | $ | 16,033 | | | $ | 14,036 | | | $ | 13,841 | | | $ | 12,568 | | | $ | 11,135 | | | $ | 10,231 | | | $ | 6,138 | | | $ | 8,792 | | | $ | 8,275 | | | $ | 8,417 | |
| |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| |
| Earnings Applicable to Common Stock | | $ | 16,033 | | | $ | 14,036 | | | $ | 13,841 | | | $ | 12,568 | | | $ | 11,135 | | | $ | 10,231 | | | $ | 6,138 | | | $ | 8,792 | | | $ | 8,275 | | | $ | 8,417 | |
| Cash Dividends Per Share of Common Stock (1) | | $ | 0.96 | | | $ | 0.89 | | | $ | 0.83 | | | $ | 0.78 | | | $ | 0.74 | | | $ | 0.71 | | | $ | 0.68 | | | $ | 0.65 | | | $ | 0.61 | | | $ | 0.56 | |
| |
Basic Earnings Per Share of Common Stock (1): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| |
| Income Before Cumulative Effect of Changes in Accounting Principles | | $ | 2.01 | | | $ | 1.77 | | | $ | 1.76 | | | $ | 1.62 | | | $ | 1.47 | | | $ | 1.37 | | | $ | 0.83 | | | $ | 1.19 | | | $ | 1.18 | | | $ | 1.15 | |
| Net Income (1) | | $ | 2.01 | | | $ | 1.77 | | | $ | 1.76 | | | $ | 1.62 | | | $ | 1.47 | | | $ | 1.37 | | | $ | 0.83 | | | $ | 1.19 | | | $ | 1.13 | | | $ | 1.15 | |
| |
Diluted Earnings Per Share of Common Stock (1): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Income Before Cumulative Effect of Changes in Accounting Principles | | $ | 1.99 | | | $ | 1.76 | | | $ | 1.74 | | | $ | 1.60 | | | $ | 1.45 | | | $ | 1.35 | | | $ | 0.82 | | | $ | 1.19 | | | $ | 1.17 | | | $ | 1.14 | |
| Net Income (1) | | $ | 1.99 | | | $ | 1.76 | | | $ | 1.74 | | | $ | 1.60 | | | $ | 1.45 | | | $ | 1.35 | | | $ | 0.82 | | | $ | 1.19 | | | $ | 1.12 | | | $ | 1.14 | |
| |
Average Common Shares Outstanding (1): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| |
| Basic (1) | | | 7,972 | | | | 7,924 | | | | 7,854 | | | | 7,764 | | | | 7,599 | | | | 7,451 | | | | 7,389 | | | | 7,356 | | | | 7,326 | | | | 7,298 | |
| Diluted (1) | | | 8,059 | | | | 7,978 | | | | 7,950 | | | | 7,860 | | | | 7,686 | | | | 7,569 | | | | 7,481 | | | | 7,416 | | | | 7,400 | | | | 7,389 | |
| |
| |
| Total Assets | | $ | 372,446 | | | $ | 262,680 | | | $ | 252,459 | | | $ | 242,304 | | | $ | 236,888 | | | $ | 232,213 | | | $ | 232,014 | | | $ | 175,902 | | | $ | 181,518 | | | $ | 173,862 | |
| Long-Term Debt | | $ | 120,461 | | | $ | 71,361 | | | $ | 77,579 | | | $ | 84,692 | | | $ | 92,640 | | | $ | 98,645 | | | $ | 90,592 | | | $ | 55,222 | | | $ | 58,017 | | | $ | 58,979 | |
| |
STATISTICAL | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Gas Revenue (in thousands): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| |
| Sales: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Residential | | $ | 69,102 | | | $ | 70,560 | | | $ | 66,701 | | | $ | 64,283 | | | $ | 54,470 | | | $ | 47,839 | | | $ | 65,394 | | | $ | 41,750 | | | $ | 39,575 | | | $ | 44,725 | |
| Commercial and Industrial — Small | | | 21,403 | | | | 23,129 | | | | 19,717 | | | | 17,100 | | | | 13,795 | | | | 11,105 | | | | 15,499 | | | | 9,433 | | | | 8,613 | | | | 9,208 | |
| Commercial and Industrial — Large | | | 10,360 | | | | 12,495 | | | | 10,502 | | | | 8,696 | | | | 8,101 | | | | 6,436 | | | | 10,060 | | | | 6,316 | | | | 5,242 | | | | 6,784 | |
| Transportation | | | 9,829 | | | | 9,744 | | | | 9,920 | | | | 9,799 | | | | 10,405 | | | | 10,834 | | | | 9,594 | | | | 9,336 | | | | 8,215 | | | | 8,210 | |
| Storage (other than intercompany) | | | 19,229 | | | | 13,980 | | | | 12,383 | | | | 10,805 | | | | 7,401 | | | | 4,383 | | | | 2,134 | | | | 2,153 | | | | 1,689 | | | | 1,204 | |
| Other | | | 815 | | | | 778 | | | | 764 | | | | 805 | | | | 978 | | | | 963 | | | | 743 | | | | 726 | | | | 555 | | | | 609 | |
| |
| Total | | $ | 130,738 | | | $ | 130,686 | | | $ | 119,987 | | | $ | 111,488 | | | $ | 95,150 | | | $ | 81,560 | | | $ | 103,424 | | | $ | 69,714 | | | $ | 63,889 | | | $ | 70,740 | |
| |
Delivery to Customers (in thousand therms): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| |
| Gas Sales: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Residential | | | 35,554 | | | | 32,976 | | | | 36,335 | | | | 42,546 | | | | 44,617 | | | | 42,651 | | | | 51,415 | | | | 43,014 | | | | 39,866 | | | | 51,493 | |
| Commercial and Industrial — Small | | | 13,573 | | | | 13,196 | | | | 13,314 | | | | 13,709 | | | | 13,664 | | | | 12,717 | | | | 14,318 | | | | 12,590 | | | | 11,781 | | | | 13,231 | |
| Commercial and Industrial — Large | | | 8,070 | | | | 8,562 | | | | 9,165 | | | | 8,943 | | | | 10,463 | | | | 10,679 | | | | 12,570 | | | | 12,860 | | | | 11,683 | | | | 15,169 | |
| Transportation | | | 697,300 | | | | 709,175 | | | | 646,564 | | | | 695,561 | | | | 759,936 | | | | 947,515 | | | | 790,741 | | | | 611,541 | | | | 357,183 | | | | 335,905 | |
| |
| Total | | | 754,497 | | | | 763,909 | | | | 705,378 | | | | 760,759 | | | | 828,680 | | | | 1,013,562 | | | | 869,044 | | | | 680,005 | | | | 420,513 | | | | 415,798 | |
| |
Customers Billed (peak month): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| |
| Residential | | | 90,248 | | | | 90,373 | | | | 91,343 | | | | 92,537 | | | | 93,318 | | | | 93,563 | | | | 94,948 | | | | 95,131 | | | | 95,022 | | | | 95,443 | |
| Commercial and Industrial — Small | | | 4,898 | | | | 4,974 | | | | 5,035 | | | | 5,143 | | | | 5,111 | | | | 5,153 | | | | 5,197 | | | | 5,256 | | | | 5,282 | | | | 5,305 | |
| Commercial and Industrial — Large | | | 74 | | | | 78 | | | | 82 | | | | 77 | | | | 78 | | | | 80 | | | | 89 | | | | 95 | | | | 92 | | | | 97 | |
| Transportation | | | 44 | | | | 42 | | | | 42 | | | | 41 | | | | 43 | | | | 37 | | | | 43 | | | | 37 | | | | 37 | | | | 30 | |
| |
| Total | | | 95,264 | | | | 95,467 | | | | 96,502 | | | | 97,798 | | | | 98,550 | | | | 98,833 | | | | 100,277 | | | | 100,519 | | | | 100,433 | | | | 100,875 | |
| |
| Degree Days (2) | | | 1,674 | | | | 1,470 | | | | 1,400 | | | | 1,619 | | | | 1,773 | | | | 1,577 | | | | 1,978 | | | | 1,379 | | | | 1,196 | | | | 1,889 | |
NUMBER OF EMPLOYEES (END OF PERIOD) | | | 272 | | | | 260 | | | | 261 | | | | 265 | | | | 285 | | | | 295 | | | | 300 | | | | 291 | | | | 280 | | | | 281 | |
| | |
| Note: (1) | | All references to number of shares and per share amounts have been restated to reflect the three-for-two conversion of Mobile Gas common stock into EnergySouth, Inc. common stock effective February 2, 1998 and the three-for-two stock split effective September 2, 2004. |
| |
| Note: (2) | | The number of degrees that the daily mean temperature falls below 65 degrees F. The Company’s rates were designed assuming annual normal degree days of 1,640 beginning December 1, 1995 and an annual normal of 1,695 for prior periods. |
15
Item 7.Management’s Discussion and Analysis of Results of Financial Condition and Results of Operation.
The Company
EnergySouth, Inc. (EnergySouth) is a holding company which has two principal direct wholly-owned subsidiaries, Mobile Gas Service Corporation (Mobile Gas) and EnergySouth Midstream (Midstream). EnergySouth and its consolidated subsidiaries are collectively referred to herein as the “Company.” 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. Midstream 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. Effective June 12, 2007, EnergySouth Services (Services) became a subsidiary of Midstream. Services engages in natural gas marketing, trading and risk management activities. Services is also the general partner of Southern Gas Transmission Company (SGT), which is engaged in the intrastate transportation of natural gas.
Summary
Consolidated Net Income
Earnings per diluted share increased $0.23, or 13%, in fiscal 2007 as compared to fiscal 2006. Fiscal year 2006 earnings per diluted share increased $0.02, up 1% from fiscal 2005. Financial information by business segment is shown in Note 12 to the Consolidated Financial Statements.
2007 vs 2006Earnings from the Company’s natural gas distribution business increased $0.11 per diluted share during fiscal year 2007 when compared to fiscal year 2006 due primarily to rate adjustments which became effective December 1, 2006. 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 2007. These increases were partially offset by an increase in operating expenses, depreciation and interest expense.
The Company’s midstream operations contributed increased earnings of $0.17 per diluted share in fiscal year 2007 as compared to fiscal year 2006 due primarily to increased revenues associated with short-term storage agreements, margins realized from natural gas marketing, trading and risk management activities, and a decrease in net interest expense (interest expense less capitalized interest). These increases were partially offset by an increase in operating expenses.
Earnings from other business operations decreased $0.05 per diluted share in fiscal year 2007 due primarily to a decline in merchandise sales and merchandise-related activities and an increase in corporate operating expenses.
2006 vs 2005Earnings from the Company’s natural gas distribution business decreased $0.19 per diluted share during fiscal year 2006 when compared to fiscal year 2005 due primarily to a decline in consumption from temperature-sensitive customers and an increase in operating expenses.
The Company’s midstream business contributed increased earnings of $0.16 per diluted share in fiscal 2006 as compared to fiscal year 2005 due primarily to Bay Gas’ natural gas storage operations. The positive earnings contribution was due to increased storage revenues associated with new agreements for long-term and short-term storage services and a decrease in net interest expense.
Earnings from other business operations increased $0.05 per diluted share in fiscal 2006 due primarily to an increase in interest income and merchandise sales and related activities.
16
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.
The Alabama Public Service Commission (APSC) regulates the Company’s gas distribution operations. Mobile Gas’ rate tariffs for gas distribution allow rate adjustments to ultimately pass through to customers the cost of gas and certain taxes. These costs, therefore, have little direct impact on the Company’s unit margins, which are defined as natural gas distribution revenues less the cost of natural gas and related taxes. Mobile Gas’ rate tariffs also allow a rate adjustment to pass through to customers the incremental depreciation expense and financing costs associated with the replacement of cast iron mains. In fiscal 2005, the Company accelerated the replacement of cast iron mains to improve and enhance the distribution system. Consequently, during fiscal 2006, the collection of these costs had a direct positive impact on the Company’s margins when compared to prior-year periods.
Wholesale natural gas prices rose during the first quarter of fiscal 2006 due to the tight balance between supply and demand following an active 2005 hurricane season in the Gulf of Mexico. The trend of high natural gas prices which continued throughout fiscal year 2005 and into 2006 had a negative impact on the Company’s overall margins, in aggregate dollars, through 1) energy conservation efforts that reduced 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 0.3%, 0.7%, and 1.1% in fiscal years 2007, 2006, and 2005, respectively.
Mobile Gas follows a gas purchasing strategy to secure prices for a portion of its gas supply needs for the winter heating season by securing 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 the impact of volatility in gas prices on customers’ bills. Mobile Gas adjusted its rates to reflect the increased gas costs paid to its suppliers in fiscal 2006, particularly after Hurricanes Katrina and Rita. During fiscal 2007, wholesale natural gas prices trended down as compared with previous years due primarily to inactive hurricane seasons during the summers of 2006 and 2007 and higher volumes of natural gas in storage. Mobile Gas has reduced the gas cost component of its rates as gas commodity prices have fallen.
Mobile Gas utilizes a Rate Stabilization and Equalization (RSE) tariff which is a ratemaking methodology also used by the APSC to regulate other public Alabama energy utilities. Increases are allowed only once each fiscal year, effective December 1, and cannot exceed four percent of prior-year revenues. See Note 2 to the Consolidated Financial Statements.
The Company’s distribution business is highly seasonal and temperature-sensitive since residential and commercial customers use more gas during colder weather for space heating. As a result, gas revenues, cost of gas and related taxes in any given period reflect, in addition to other factors, the impact of weather, through either increased or decreased sales volumes. The Company has utilized a temperature rate adjustment rider during the months of November through April to mitigate the impact that unusually cold or warm weather has on operating margins by reducing the base rate portion of customers’ bills in colder than normal weather and increasing the base rate portion of customers’ bills in warmer than normal weather. Effective November 1, 2006, Mobile Gas accumulates an adjustment for the margin impact due to variances in the weather. The accumulated adjustment from one heating season (November through April) will be billed or credited to customers in subsequent periods. This mechanism reduces the variability of both customers’ bills and Mobile Gas’ earnings due to weather fluctuations.
Financial information about the distribution business segment is shown in Note 12 to the Consolidated Financial Statements. Natural gas distribution revenues decreased $5,412,000 (5%) and increased $9,290,000 (9%), respectively, during fiscal 2007 and 2006. Rate adjustments which reflect a decrease in
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gas costs paid to suppliers are the primary reason for the decline in revenues during fiscal 2007. This decrease was partially offset by increased revenues from the RSE rate adjustment which went into effect on December 1, 2006, and increased consumption by temperature-sensitive customers. Fiscal 2006 revenues increased due primarily to rate adjustments to recover increased gas costs paid to suppliers.
Revenues from the sale of natural gas to residential and small commercial customers, referred to as temperature-sensitive customers because their gas usage is affected to a large degree by temperatures during the heating season, decreased $3,184,000 (3%) and increased $7,271,000 (8%), respectively, during fiscal 2007 and 2006 due to the rate adjustments discussed above. During fiscal 2007, revenues were positively impacted by the RSE rate adjustment and a 6% increase in volumes delivered to customers due to weather that was colder than normal and 14% colder than the prior year. These increases were more than offset by rate adjustments which reflected a decrease in gas costs paid to suppliers. During fiscal 2006, the increase in revenues from rate adjustments was partially offset by a decline in customers served and a decline in consumption by residential customers as discussed below.
Revenues from the sale of natural gas to large commercial and industrial customers decreased $2,135,000 (17%) and increased $1,993,000 (19%) during fiscal 2007 and 2006, respectively. During fiscal 2007, rate adjustments which reflected a decrease in gas costs more than offset increased revenues from the RSE rate adjustment. Also contributing to the decrease in revenues for fiscal 2007 was a 6% decline in volumes delivered to customers. Revenues increased during fiscal 2006 due to increases in the price of natural gas.
Revenues from the transportation of natural gas to large commercial and industrial customers decreased $130,000 (2%) during fiscal 2007 due to a 5% decline in volumes transported to these customers. Revenues decreased less than 1% for fiscal 2006 as volumes delivered to these customers were relatively flat. In fiscal 2006, transportation revenues included a decrease of approximately $195,000 as a result of the Termination Agreement discussed in Note 2 to the Consolidated Financial Statements.
The cost of natural gas decreased $8,058,000 (13%) and increased $10,101,000 (20%), respectively, for fiscal years 2007 and 2006 due to fluctuations in natural gas commodity prices.
Natural gas distribution margins, defined as revenues less cost of gas and related taxes, increased 6% during fiscal 2007 primarily as a result of the RSE rate adjustment and an increase in usage per degree-day by temperature-sensitive customers. Margins declined 3% during fiscal 2006, when increased margins from the amortization of the regulatory liability for gross receipts taxes and increased collections for cast iron replacements were more than offset by a decline in usage per degree day by temperature-sensitive customers and a decline in the number of temperature-sensitive customers served. Residential customer consumption, when adjusted for weather variations, increased 3% and declined 11%, respectively, in fiscal 2007 and 2006. 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 2007, when adjusted for weather, trended up from fiscal 2006. Management believes that this increase is the result of the fiscal 2006 decline being attributable to higher natural gas prices experienced during the fall and winter of 2005-2006 after Hurricane Katrina and unusually warm weather in January 2006, factors which did not occur in fiscal 2007. Usages per degree-day can and will vary between periods due to several factors including humidity, wind speed, cloud cover, and duration of cold weather.
Operations and maintenance (O&M) expenses increased $778,000 (3.7%) during fiscal 2007 due to an increase in compensation and related benefit expenses of $302,000, an increase of $572,000 in expenses related to the implementation of a new customer information system (CIS), increased advertising expenses of $219,000, a decrease of $93,000 in the bad debt provision, and a decrease of approximately $222,000 in various other expense items.
Operations and maintenance (O&M) expenses increased $729,000 (3.5%) during fiscal 2006 due in part to approximately $299,000 incurred in the search and employment of the successor to former President and Chief Executive Officer Mr. John S. Davis, in connection with Davis’ retirement in fiscal 2007. Additionally,
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O&M expenses for fiscal 2006 increased $328,000 due to an increase in compensation expense recorded for stock options in accordance with SFAS 123R as discussed in Note 7 to the Consolidated Financial Statements, an increase in expenses of $358,000 incurred to evaluate and select software alternatives for a new customer information system (CIS) being implemented in 2007, and an increase in the bad debt provision of $172,000 due to a rise in gas revenues associated with the increase in natural gas prices. These increases in O&M expenses were partially offset by a one-time reduction in benefit expenses. Due to a change in the Company’s provider of health insurance, certain disabled employees became ineligible for coverage under the Company’s health insurance benefits. Consequently, at the termination of the prior contract, the Company reduced the liability for future benefit payments for these employees by $346,000. Also, effective August 1, 2006, the Company discontinued term life insurance benefits for retirees, resulting in a net credit to expense of approximately $97,000 as discussed in Note 8 to the Consolidated Financial Statements.
Depreciation expense increased $346,000 (4%) and $353,000 (5%), respectively, for fiscal 2007 and 2006 due to Mobile Gas’ increased investment in property, plant and equipment.
Other taxes primarily consist of property taxes and business license taxes that are based on gross revenues and fluctuate accordingly. Other taxes decreased $308,000 (4%) and increased $662,000 (9%), respectively, for fiscal year 2007 and 2006 due primarily to the fluctuation in revenues discussed above.
Interest expense increased $341,000 (11%) and $249,000 (9%), respectively, for fiscal 2007 and 2006 due primarily to increased short term borrowings.
Natural Gas Midstream
Midstream is the general partner of Bay Gas. Effective June 12, 2007, Services became a wholly-owned subsidiary of Midstream. The natural gas midstream segment currently provides for the underground storage of natural gas and transportation services through the operations of Bay Gas and transportation services through the operations of SGT. The Company has expanded its midstream operations to include natural gas related businesses in addition to natural gas storage. During the third fiscal quarter, expansion included the establishment of Midstream operations in a new Houston, Texas office which is responsible for managing and optimizing transportation and storage assets through natural gas marketing, trading and risk management activities. See Note 10 to the Consolidated Financial Statements.
The natural gas midstream segment provides for the underground storage of natural gas and transportation services through the operations of Bay Gas. The APSC certificated Bay Gas as an Alabama natural gas storage public utility in 1992. Through its first storage cavern with 2.3 Bcf of working gas capacity and connected pipeline, Bay Gas thereafter began providing substantial, long-term services for Mobile Gas and other customers that include storage and transportation of natural gas from interstate and intrastate sources. The APSC does not regulate rates for Bay Gas’ interstate gas storage and storage-related services. The Federal Energy Regulatory Commission (FERC), which has jurisdiction over interstate services, allows Bay Gas to charge market-based rates for such services. Market-based rates minimize regulatory involvement in the setting of rates for storage services and allow Bay Gas to respond to market conditions. Bay Gas also provides firm and interruptible interstate transportation-only services. The FERC 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. The FERC last issued an order on April 14, 2006 approving rates for transportation-only services. In accordance with FERC filing requirements, on March 9, 2007 Bay Gas filed a petition with the FERC requesting approval of rates for transportation-only service.
The construction of natural gas-fired electric generation facilities in the Southeast has provided opportunities to provide increased gas storage and transportation services. Construction of Bay Gas’ second storage cavern was completed and the cavern was placed into service April 1, 2003. Currently, the second storage cavern has a working gas capacity of 3.7 Bcf. Together, the two caverns at Bay Gas
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currently hold 6.0 Bcf, with injection and withdrawal capacity of 200 MMcf and 610 MMcf per day, respectively.
Bay Gas is currently developing a third storage cavern and related facilities and has entered into multi-year contracts with customers for all of the cavern capacity. The new cavern is designed to add 5.0 Bcf of working gas capacity and is presently anticipated to be in service by April 2008. The addition of the third cavern and additional capacity development of 1.0 Bcf in one or more of the first three caverns is currently planned to ultimately increase the total working gas capacity of Bay Gas to 12.0 Bcf with injection and withdrawal capacities to 450 MMcf per day and 1.2 Bcf per day, respectively.
Having reached full subscription of the current working capacity of both existing caverns and the third cavern which is currently under development, Bay Gas held a non-binding “open season” in October 2006 to assess interest for up to 10.0 Bcf of additional working gas capacity. The planned development would include two new 5.0 Bcf high deliverability underground salt-dome caverns together with additional pipeline interconnects with Transco. Midstream is currently communicating with respondents in an effort to secure agreements for firm storage services. Bay Gas has begun drilling operations for development of the fourth cavern and plans to move forward with development of the fifth cavern and the pipeline interconnects subject to its ability to execute sufficient firm storage agreements with interested parties.
Financial information about the midstream business segment is shown in Note 12 to the Consolidated Financial Statements. Midstream’s revenues increased $5,461,000 (26%) during fiscal 2007 due primarily to short-term storage agreements, including margins captured through the arbitrage of pricing differences in various time periods and locations. Under the short-term agreements, available working gas capacity is leased or available gas is loaned to customers on an interruptible basis, thereby optimizing the use of cavern capacity. Revenues increased $1,417,000 (7%) during fiscal 2006 due to short-term storage agreements as well as new long-term storage agreements entered into during the year.
Operations and maintenance (O&M) expenses increased $3,991,000 (121%) in fiscal year 2007 due primarily to the expansion of midstream operations including Service’s marketing and risk management operations and the opening of the Houston office. The primary drivers of the increased expenses include additional compensation and related benefits of $2,576,000, increased legal expenses of $265,000, consulting services of $99,000, maintenance costs and subscriptions to software of $102,000, and increased office expenses of $279,000. Bay Gas’ cavern lease payments expensed during fiscal 2007 increased $372,000 as compared to fiscal 2006 and general repairs and maintenance of storage facilities increased $150,000.
O&M expenses decreased $62,000 (2%) in fiscal year 2006 due primarily to a one-time credit related to certain cavern lease payments recorded as a prepaid asset which will be amortized over the remaining term of the lease under which the payments are made. Also contributing to the decrease in expenses for fiscal 2006 was a reduction in the present value of future health insurance benefits for certain disabled employees and the termination of life insurance benefits for retired employees as discussed in Note 8 to the Consolidated Financial Statements below. These decreases of $249,000 were partially offset by an increase in compensation expense recorded for stock options and expenses incurred with the search and employment of a new President and Chief Executive Officer for the Company of approximately $120,000 and an increase in other operating expenses of approximately $67,000.
Depreciation expense increased $54,000 (2%) and $128,000 (5%) in fiscal year 2007 and 2006, respectively, due to increased investments in property, plant, and equipment.
Other taxes consist primarily of property taxes and business license taxes that are based on gross revenues and fluctuate accordingly. Other taxes increased $57,000 (6%) and $24,000 (3%), respectively, in fiscal 2007 and 2006.
Interest expense increased $930,000 (23%) in fiscal 2007 due to increased borrowings related to the ongoing construction of the third storage cavern and the expansion of midstream operations and decreased $175,000 (4%) in fiscal 2006 due to principal payments on long-term debt.
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Capitalized interest costs increased $1,270,000 and $777,000 in 2007 and 2006, respectively, due to the development of the third storage cavern.
Minority interest reflects the minority partner’s share of pre-tax earnings of the Bay Gas limited partnership and the SGT partnership, of which EnergySouth’s subsidiaries hold a controlling interest. Minority interest increased $209,000 (19%) and $175,000 (19%), respectively, during fiscal 2007 and 2006 due to increased pre-tax earnings of the partnerships.
Other
The Company provides merchandising, financing, and other energy-related services through Mobile Gas, which are aggregated with EnergySouth, the holding company, to comprise the Other category. See Note 12 to the Consolidated Financial Statements for segment disclosure.
Income before income taxes from Other business activities decreased $579,000 and increased $536,000 in fiscal 2007 and 2006, respectively. The fiscal 2007 decrease resulted from a decrease in merchandise sales and related activities of $233,000 and an increase in corporate operating expenses of $611,000. These decreases were partially offset by an increase in net interest income of $279,000 The fiscal 2006 increase was due primarily to net interest income earned from temporary investments of $370,000 and an increase in earnings from merchandise sales and related activities of $165,000.
Income Taxes
Income taxes fluctuate with the change in income before income taxes. The Company’s effective tax rate in 2007, 2006, and 2005 was 37.6%, 38.3%, and 39.4%, respectively. The components of income tax expense are reflected in Note 6 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’s distribution business is to maintain 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, and contracting for pipeline and storage services. These services provide access to local as well as interstate pipeline sources on a firm basis. To minimize the volatility of natural gas prices to its customers, Mobile Gas has implemented a gas supply strategy in which it enters into purchases to lock in prices for a portion of its expected gas sales in future months. All such 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, Mobile Gas’ commitments for future purchases of natural gas at fixed prices are deemed and elected to be considered purchases in the normal course of business and are not subject to derivative accounting treatment. Future minimum payments under third-party contracts for firm gas supply, which expire at various dates through the year 2011, are as follows: 2008 — $19,074,000; 2009 — $1,141,000; 2010 — $1,141,000; and 2011 — $815,000. 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
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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 from customers of demand and commodity costs of purchased gas. 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 9 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 $45.8 million, $24.9 million, and $30.8 million in 2007, 2006, and 2005, respectively. Cash provided from operating activities increased $20.9 million in 2007 as compared to 2006 due to an increase in accounts payable of $21.3 million, an increase in taxes payable of $6.9 million, an increase in net income of $2.0 million, and an increase in the collection of gas costs from customers of $0.5 million. These increases in cash flow were partially offset by an increase in accounts receivable of $7.0 million, an increase in cash held on deposit in a margin account of $1.0 million, an increase in inventories of $0.2 million and a decrease in the deferred tax provision of $1.3 million. Cash provided from operating activities decreased $5.9 million in 2006 as compared to 2005 due to a decrease in taxes payable of $9.4 million, an under-collection of increased gas costs from customers of $7.9 million and the settlement of postretirement benefits of $1.4 million upon the termination of life insurance benefits for retirees. These decreases in cash flow were partially offset by a decline in accounts receivable of $4.1 million and an $8.0 million increase in deferred taxes.
Investing activities used cash of $96.4 million, $24.5 million, and $16.6 million in fiscal 2007, 2006, and 2005, respectively. The increase in restricted cash during fiscal 2007 is primarily due to net funds received from the issuance of long-term debt in August 2007 which are held in trust for the construction of storage facilities. Cash used in investing activities reflects the capital-intensive nature of the Company’s business. During 2007, 2006, and 2005, the Company used cash of $50.1 million, $24.4 million, and $16.4 million, respectively, primarily for the construction of distribution and storage facilities, purchases of equipment and other general improvements. During fiscal 2007, Mobile Gas invested approximately $12.4 million in distribution facilities, including $1.7 million for a new customer information system, and Bay Gas invested $37.4 million, primarily in the ongoing construction of the third cavern and initial development activities of the fourth cavern. During fiscal 2006, Mobile Gas invested approximately $13.0 million in distribution facilities, including $1.1 million for a new customer information system, and Bay Gas invested $11.8 million in the ongoing construction of its third cavern.
Financing activities provided cash of $49.6 million in fiscal 2007 and used cash of $7.2 million and $14.1 million in fiscal 2006 and 2005, respectively. The increase in fiscal 2007 was due primarily to the issuance of $55.0 million in long-term debt, an additional $1.7 million borrowed under the Company’s revolving credit agreement, and receipts of $0.5 million from the exercise of stock options. Long term debt payments and the payment of quarterly dividends account for most of the cash used in each year. Dividend payments of
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$7.7 million, $7.1 million, and $6.5 million in fiscal 2007, 2006, and 2005, respectively, were offset by dividend reinvestment of $0.4 million in each fiscal year. Fiscal 2007, 2006, and 2005 included additional optional principal payments on long term debt of $0.6 million, $0.6 million, and $1.9 million, respectively. Cash used during fiscal 2006 was partially offset by an increase in short term borrowings of $5.3 million. Receipts of $0.5 million and $0.6 million in fiscal 2006 and 2005, respectively, from the exercise of stock options partially offset the cash used in financing activities.
The Company expects fiscal 2008 capital expenditures by Mobile Gas to be approximately $13.0 million for normal construction activity, including equipment purchases and other general improvements. These expenditures will be funded by internal cash generation and short and long-term borrowings. Midstream’s anticipated capital expenditures include the completion in April 2008 of Bay Gas’ third salt-dome storage cavern designed to provide 5.0 Bcf of working gas capacity. Bay Gas’ projected expenditures for 2008 also include continuing development of a fourth storage cavern designed to provide 5.0 Bcf of working gas capacity and starting construction of a fifth storage cavern. Bay Gas also will begin construction of a 29 mile pipeline from the storage facilities in McIntosh, Alabama to connect to the Transco pipeline in north Mobile County. The Company expects 2008 capital expenditures by Bay Gas to total approximately $100 million.
Subsequent to September 30, 2007, EnergySouth and certain funds managed by affiliates of Fortress Investment Group LLC (the “Fortress Funds”) acquired the net assets of the natural gas storage company, Mississippi Hub LLC, for $140 million. Mississippi Hub LLC expects to spend an additional $47 million in fiscal 2008 for development and construction of a storage cavern, supporting facilities and pipelines. EnergySouth owns a 60% majority interest and Fortress Funds owns the remaining 40% interest and the respective owners have funded their proportionate share of the foregoing capital costs.
In August 2007, the Industrial Development Authority of Washington County, Alabama issued $55 million in Industrial Development Revenue Bonds (the Bonds) due August 15, 2037, and loaned these funds to Bay Gas for financing of storage facilities construction. In connection with the Bond issuance, Bay Gas caused a $55 million letter of credit (the Letter of Credit) to be issued to secure payment of the Bonds. At September 30, 2007, the Company has a $100 million credit facility ( the Credit Agreement) which provides credit availability for the Letter of Credit, for additional letters of credit, and for a revolving credit line. At September 30, 2007, the Company had $33 million available for borrowing on its revolving credit agreement and $46 million in unused funds from the Bonds which are included in restricted cash on the Consolidated Balance Sheet. Subsequent to September 30, 2007, the Company replaced its existing $100 million credit facility with a new 364 day $250 million credit facility with a group of banks which also provides credit availability for the Letter of Credit, for additional letters of credit, and for a revolving credit line. The Company used this new credit facility to fund its $84 million portion of the $140 million purchase price of Mississippi Hub LLC.
The Company expects to fund near-term construction at Bay Gas through the continued draw down of funds from the Bonds, the new credit facility, internal cash generation, and minority partner contributions. Mississippi Hub LLC near term construction will be funded from the new credit facility and minority partner contributions. Longer term capital expenditures for both Bay Gas and Mississippi Hub LLC will be funded through the issuance of long-term debt and equity.
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The table below summarizes the Company’s contractual obligations and commercial commitments as of September 30, 2007:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Fiscal | | Fiscal | | Fiscal | | Fiscal | | Fiscal | | Fiscal Years |
| Type of Contractual | | Year | | Year | | Year | | Year | | Year | | 2013 and |
| Obligations (in thousands): | | 2008 | | 2009 | | 2010 | | 2011 | | 2012 | | thereafter |
| Long-Term Debt | | $ | 5,900 | | | $ | 6,054 | | | $ | 5,653 | | | $ | 5,955 | | | $ | 6,307 | | | $ | 96,492 | |
| Interest Payments (1) | | | 7,894 | | | | 7,408 | | | | 6,912 | | | | 6,440 | | | | 5,942 | | | | 65,504 | |
| Estimated Future Minimum Payments for Bay Gas Service Fees | | | 638 | | | | 638 | | | | 638 | | | | 638 | | | | 638 | | | | 31,950 | |
| Construction Contracts for Bay Gas’ 3rd and 4th Cavern Development | | | 9,760 | | | | | | | | | | | | | | | | | | | | | |
| Implementation of CIS Software | | | 2,620 | | | | | | | | | | | | | | | | | | | | | |
| Gas Supply Contracts | | | 19,074 | | | | 1,141 | | | | 1,141 | | | | 815 | | | | | | | | | |
| |
| Total | | $ | 45,886 | | | $ | 15,241 | | | $ | 14,344 | | | $ | 13,848 | | | $ | 12,887 | | | $ | 193,946 | |
| |
| | |
| (1) | | Amounts include estimated interest payments on $55 million Industrial Revenue Bonds and are based on the effective rate as of September 30, 2007 of 3.93%. |
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.
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Derivatives.Midstream is engaged in energy marketing and risk management activities and is exposed to risks associated with changes in the market price of natural gas. Midstream uses derivative instruments to reduce the exposure to the risk of changes in the price of natural gas. Derivative instruments utilized in connection with these activities and services are accounted for under the fair value basis of accounting in accordance with Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (SFAS 133) as amended.
Under SFAS 133, entities are required to record derivative instruments at fair value. The fair value of derivative instruments is determined through a combination of prices actively quoted on national exchanges, prices provided by other external sources and prices based on models and other valuation methods. Changes in the valuation of financial derivatives primarily result from changes in market prices, the valuation of the portfolio of contracts, maturity and settlement of these contracts and newly originated transactions, each of which directly affect the estimated fair value of derivatives. Management believes the market prices and models used to value these derivatives represent the best information available with respect to closing exchange and over-the-counter quotations, time value and volatility factors underlying the contracts.
Market value changes result in a change in the fair value of derivative instruments. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, the reason for holding it. If the derivative instrument does not qualify or is not designated as part of a hedging relationship, then the changes in fair value of the derivative are accounted for in earnings as they occur. Commodity price volatility may have a significant impact on the gain or loss in any given period.
To minimize the risk from fluctuations in natural gas prices, Midstream periodically enters into futures and other financial transactions in order to hedge anticipated purchases and sales of natural gas. Under certain conditions, these derivative instruments are designated as a hedge against exposure to changes in cash flows. For cash flow hedges, the effective portion of the gain or loss on the derivative instrument is reported initially as a component of other comprehensive income (loss) and is subsequently reclassified to earnings when the forecasted transaction affects earnings. Any hedge ineffectiveness, defined as when the gains or losses on the hedging instrument do not offset the losses or gains on the hedged item, is reported in earnings in the period the ineffectiveness occurs.
Mobile Gas enters into purchase agreements that would otherwise be required to follow derivative accounting treatment except that they qualify for normal purchase and normal sales under SFAS 133 and therefore, upon election, are exempt from fair value accounting treatment.
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 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.
Asset Retirement Obligation.The Company records the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred. Subsequent to initial measurement, liabilities are required to be accreted to their present value each period and capitalized costs are depreciated over the estimated useful life of the related assets. Upon settlement of the liability, the Company will settle the obligation for its recorded amount and recognize the resulting gain or loss. Bay Gas has certain removal obligations to cap the wells to its storage caverns and to purge and cap transmission lines upon
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abandonment. Mobile Gas has certain removal cost obligations related to its gas distribution assets and a conditional asset retirement obligation to purge and cap its distribution and transmission lines upon abandonment. The estimate of future restoration and removal costs includes numerous assumptions and uncertainties, including but not limited to, inflation factors, discount rates, timing of settlement, and changes in contractual, regulatory, political, environmental, safety and public relations considerations.
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 postretirement 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 8 to the Consolidated Financial Statements.)
At September 30, 2007, the discount rates used for pension and postretirement purposes were 6.25% and 6.25%, respectively. A hypothetical 25 basis point decrease in the annual discount rate would increase pension and postretirement benefit expense by $108,000 and $4,000, respectively. At September 30, 2007, the expected rates of return on assets for actuarial purposes were 8.25% and 7.75% for pension and postretirement benefits, respectively. A hypothetical 25 basis point decrease in the expected rate of return on assets would increase pension and postretirement expense by $95,000 and $11,000, respectively. At September 30, 2007, the rate of compensation increase used for actuarial purposes was 3.75%. A hypothetical 25 basis point increase in the expected rate of future compensation increases would increase pension expense by $39,000.
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 events; risks generally associated with the transportation and storage of natural gas; the possibility that contracts with storage customers could be terminated under certain circumstances, or not renewed or extended upon expiration; the prices or terms of any extended or new contracts; possible loss or material change in the financial condition of one or more major customers; market risks affecting risk management activities including market liquidity, commodity price volatility, increasing interest rates and counterparty creditworthiness; ability to continue to access the capital markets; liability for remedial actions under environmental regulations; liability resulting from litigation; national and global economic and political conditions; 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
26
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.
Risk Control Policy and Oversight
The scope of risk management, marketing and trading operations are controlled and monitored through a comprehensive set of policies and procedures by the Risk Oversight Committee (ROC). The ROC consists of members of senior management who oversee all activities related to commodity price and credit risk management, and marketing and trading activities. The ROC also monitors risk metrics including value-at-risk and mark-to-market losses. The ROC reports to the Audit Committee of the Board of Directors which has oversight responsibilities for the risk control limits and policies.
Commodity Price Risk
Distribution.Mobile Gas is exposed to load loss risks associated with significant increases in commodity prices of natural gas. Mobile Gas mitigates the price risk associated with purchases of natural gas by using a combination of natural gas storage services, fixed price contracts and spot market purchases. As part of Mobile Gas’ gas supply strategy, it has adopted a policy under which management is authorized to commit to future gas purchases at fixed prices up to a specified percentage of the normalized degree-day usage for any corresponding month as outlined within the policy. All commitments for future gas purchases at fixed prices meet the requirements of paragraph 10.b, Normal purchases and Normal sales, of SFAS 133, as amended by SFAS No. 149. Thus, the commitments for future purchases of natural gas at fixed prices are deemed to be purchases in the normal course of business and are not subject to derivative accounting treatment.
At September 30, 2007, Mobile Gas had not entered into derivative instruments for the purpose of hedging the price of natural gas. If Mobile Gas had entered into such derivative instruments, any cost incurred or benefit received from the derivative or other hedging arrangements would be recoverable or refunded through the purchased gas adjustment mechanism. As discussed in “Results of Operations” under “Natural Gas Distribution” above, the APSC currently allows for full recovery of all costs associated with natural gas purchases; therefore, costs associated with the forward purchases of natural gas will be passed through to customers when realized and should not affect future earnings.
Midstream.During the fourth quarter of fiscal 2007, Midstream began limited activity in natural gas marketing, trading and risk management activities and, as such, is exposed to risks associated with changes in the market price of natural gas. Midstream uses derivative instruments, such as forward contracts, futures contracts and swaps, to reduce the exposure to the risk of changes in the price of natural gas. The fair value of these derivative financial instruments reflects the estimated amounts that Midstream would receive or pay to terminate or close the contracts at the reporting date, taking into account the current unrealized gains or losses on open contracts. The fair value of derivative instruments is determined through a combination of prices actively quoted on national exchanges, prices provided by other external sources and prices based on models and other valuation methods. The following table shows the components of change in fair value of derivative instruments utilized in Midstream’s energy marketing and risk management assets and liabilities during fiscal 2007.
| | | | | |
| September 30, | | 2007 |
| Net fair value of new contracts entered into during the period | | $ | 1,627 | |
| Contracts realized or otherwise settled during the period | | | (1,674 | ) |
| Other changes in fair value | | | (35 | ) |
| |
| Net fair value of contracts outstanding at September 30, 2007 | | $ | (82 | ) |
| |
27
Substantially all of Midstream’s derivative contracts at September 30, 2007 are expected to be recognized in net income within fiscal 2008.
EnergySouth measures the market risk associated with Midstream’s trading portfolios using a Value-at-Risk (VaR) methodology. VaR is a common risk metric used in the industry that measures the expected maximum loss in the portfolio over a specified time horizon. Midstream uses a one-day holding period and a 95% confidence interval in its VaR determination.
Midstream’s trading activities commenced on July 1, 2007. Through September 30, 2007 the potential impact on future earnings, as measured by the VaR, was minimal. The following table details the average, high and low VaR for the period indicated.
| | | | | |
| | | July 1, 2007 |
| | | through |
| VaR(in thousands) | | September 30, 2007 |
| Average | | $ | 46 | |
| High | | | 213 | |
| Low | | | 6 | |
| |
Midstream’s open exposure is managed based on established policies that limit market risk, requiring daily reporting of potential commodity price exposure to senior management and the ROC. Midstream’s philosophy is to protect against commodity price risk by hedging with financial instruments to keep open exposure to a minimum, permitting Midstream to operate within relatively low VaR limits.
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.
28
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:
| | i. | | pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of EnergySouth, Inc.; |
| |
| | ii. | | provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America, and that receipts and expenditures of EnergySouth, Inc. are being made only in accordance with the authorization of management and directors of EnergySouth, Inc.; and |
| |
| | iii. | | provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of assets that could have a material effect on the consolidated financial statements. |
Internal control over financial reporting includes the controls themselves, monitoring (including internal auditing practices) and actions taken to correct deficiencies as identified.
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 inInternal Control – Integrated Frameworkissued 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, 2007. 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 the effectiveness of internal control over financial reporting as of September 30, 2007 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.
29
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of
EnergySouth, Inc.
Mobile, Alabama
We have audited the internal control over financial reporting of EnergySouth, Inc. and subsidiaries (the “Company”) as of September 30, 2007 based on criteria established inInternal Control — Integrated Frameworkissued 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, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on 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, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
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, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2007, based on the criteria established inInternal Control — Integrated Frameworkissued 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, 2007 of the Company and our report dated December 13, 2007 expressed an unqualified opinion on those financial statements and financial statement schedule.
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Atlanta, Georgia
December 13, 2007
30
PART III
Item 10.Directors, Executive Officers and Corporate Governance.
Information under the captions “Election of Directors” and “Nominees for Directorships” contained in the Company’s definitive proxy statement with respect to its 2008 Annual Meeting of Shareholders is incorporated herein by reference.
For information with respect to officers, including 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 2008 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 Executive Vice President and Chief Financial Officer, and its Controller. The Company has posted the Ethics Code on its internet website atwww.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, is an audit committee financial expert. Mr. Mitchell is independent as defined in the listing standards of the National Association of Securities Dealers.
Item 11.Executive Compensation.
Information under the captions “Executive Compensation,” “2007 Summary Compensation Table,” “2007 Grants of Plan-Based Awards,” “2007 Option Exercises and Stock Vested,” “Outstanding Equity Awards at Fiscal Year-End 2007,” “2007 Pension Benefits,” “2007 Nonqualified Deferred Compensation,” “Potential Payments Upon Termination or Change In Control,” and “Other Director and Executive Officer Information” contained in the Company’s definitive proxy statement with respect to its 2008 Annual Meeting of Shareholders is incorporated herein by reference.
Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
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 2008 Annual Meeting of Shareholders is incorporated herein by reference.
Item 13.Certain Relationships and Related Transactions, and Director Independence.
There were no transactions required to be disclosed pursuant to this item. Information under the caption “Related Person Transaction Approval Policy” and under the heading “Corporate Governance” contained in the Company’s definitive proxy statement with respect to its 2008 Annual Meeting of Shareholders is incorporated herein by reference.
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 2008 Annual Meeting of Shareholders is incorporated herein by reference.
31
PART IV
Item 15.Exhibits, Financial Statement Schedules.
| | (a), | (c) | Financial Statements and Financial Statement Schedules |
| |
| | | | See “EnergySouth, Inc. and Subsidiaries Index to Financial Statements and Schedules” at page F-1, which follows Part IV hereof. |
| |
| | (3) | | Exhibits — See Exhibit Index on pages E-1 through E-5. |
| |
| | (b) | | Exhibits filed with this report are attached hereto. |
32
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.
| | | | | | | |
| | | ENERGYSOUTH, INC.
| | |
| | | Registrant
| | |
| | | | | | | |
| January 7, 2008 | | By: | | /s/ Charles P. Huffman Charles P. Huffman, Executive Vice President and Chief Financial Officer | | |
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:
| | | | | |
| Signature | | Title | | Date |
| | | | | |
/s/ John C. Hope, III John C. Hope, III | | Director, Chairman | | January 7, 2008 |
| | | | | |
/s/ C. S. Liollio C. S. Liollio | | Director, President and Chief Executive Officer (Principal Executive Officer) | | January 7, 2008 |
| | | | | |
/s/ Charles P. Huffman Charles P. Huffman | | Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer) | | January 7, 2008 |
33
Signatures (Continued)
| | | | | |
| Signature | | Title | | Date |
| | | | | |
/s/ Walter A. Bell Walter A. Bell | | Director | | January 7, 2008 |
| | | | | |
/s/ Judy A. Marston Judy A. Marston | | Director | | January 7, 2008 |
| | | | | |
/s/ Harris V. Morrissette Harris V. Morrissette | | Director | | January 7, 2008 |
| | | | | |
/s/ S. Felton Mitchell S. Felton Mitchell | | Director | | January 7, 2008 |
| | | | | |
/s/ Robert H. Rouse Robert H. Rouse | | Director | | January 7, 2008 |
| | | | | |
/s/ Thomas B. Van Antwerp Thomas B. Van Antwerp | | Director | | January 7, 2008 |
| | | | | |
/s/ J. D. Woodward J. D. Woodward | | Director | | January 7, 2008 |
34
ENERGYSOUTH, INC.
AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
| | | | | |
| Report of Independent Registered Public Accounting Firm | | | F-2 | |
| | | | | |
| Consolidated Statements of Income for the years ended September 30, 2007, 2006 and 2005 | | | F-3 | |
| | | | | |
| Consolidated Balance Sheets, September 30, 2007 and 2006 | | | F-4 | |
| | | | | |
| Consolidated Statements of Common Stockholders’ Equity for the years ended September 30, 2007, 2006 and 2005 | | | F-6 | |
| | | | | |
| Consolidated Statements of Cash Flows for the years ended September 30, 2007, 2006 and 2005 | | | F-7 | |
| | | | | |
| Notes to Consolidated Financial Statements | | | F-8 | |
| | | | | |
| Financial Statement Schedules | | | | |
| | | | | |
| Schedule II Valuation and Qualifying Accounts and Reserves, Years Ended September 30, 2007, 2006 and 2005 | | S-1 |
Schedules other than that referred to above are omitted and are not applicable or not required.
F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
EnergySouth, Inc.
Mobile, Alabama
We have audited the accompanying consolidated balance sheets of EnergySouth, Inc. and subsidiaries (the “Company”) as of September 30, 2007 and 2006, and the related consolidated statements of income, common stockholders’ equity, and cash flows for each of the three years in the period ended September 30, 2007. 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 these financial statements and financial statement schedule 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, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2007, 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 Company’s internal control over financial reporting as of September 30, 2007, based on the criteria established inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated December 13, 2007 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Atlanta, Georgia
December 13, 2007
F-2
CONSOLIDATED STATEMENTS OF INCOME
EnergySouth, Inc.
| | | | | | | | | | | | | |
| Years Ended September 30, (in thousands, except per share data) | | 2007 | | 2006 | | 2005 |
| |
Operating Revenues | | | | | | | | | | | | |
| Gas Revenues | | $ | 130,738 | | | $ | 130,686 | | | $ | 119,987 | |
| Merchandise Sales | | | 3,240 | | | | 4,046 | | | | 3,263 | |
| Other | | | 1,055 | | | | 1,135 | | | | 1,356 | |
| |
| Total Operating Revenues | | | 135,033 | | | | 135,867 | | | | 124,606 | |
| |
| | | | | | | | | | | | | |
Operating Expenses | | | | | | | | | | | | |
| Cost of Gas | | | 49,173 | | | | 57,252 | | | | 47,166 | |
| Cost of Merchandise | | | 2,684 | | | | 3,150 | | | | 2,765 | |
| Operations and Maintenance | | | 31,269 | | | | 26,025 | | | | 25,314 | |
| Depreciation | | | 11,017 | | | | 10,603 | | | | 10,122 | |
| Taxes, Other Than Income Taxes | | | 9,092 | | | | 9,353 | | | | 8,655 | |
| |
| Total Operating Expenses | | | 103,235 | | | | 106,383 | | | | 94,022 | |
| |
Operating Income | | | 31,798 | | | | 29,484 | | | | 30,584 | |
| |
Other Income and (Expense) | | | | | | | | | | | | |
| Interest Expense | | | (7,373 | ) | | | (6,812 | ) | | | (7,283 | ) |
| Capitalized Interest | | | 2,292 | | | | 1,011 | | | | 210 | |
| Interest Income | | | 301 | | | | 168 | | | | 259 | |
| Minority Interest | | | (1,322 | ) | | | (1,113 | ) | | | (938 | ) |
| |
Total Other Income (Expense) | | | (6,102 | ) | | | (6,746 | ) | | | (7,752 | ) |
| |
| | | | | | | | | | | | | |
Income Before Income Taxes | | | 25,696 | | | | 22,738 | | | | 22,832 | |
| Income Taxes | | | 9,663 | | | | 8,702 | | | | 8,991 | |
| |
Net Income | | $ | 16,033 | | | $ | 14,036 | | | $ | 13,841 | |
| |
| | | | | | | | | | | | | |
Earnings Per Share | | | | | | | | | | | | |
| |
| Basic | | $ | 2.01 | | | $ | 1.77 | | | $ | 1.76 | |
| Diluted | | $ | 1.99 | | | $ | 1.76 | | | $ | 1.74 | |
| |
| | | | | | | | | | | | | |
Average Common Shares Outstanding | | | | | | | | | | | | |
| |
| Basic | | | 7,972 | | | | 7,924 | | | | 7,854 | |
| Diluted | | | 8,059 | | | | 7,978 | | | | 7,950 | |
| |
See Accompanying Notes to Consolidated Financial Statements
F-3
CONSOLIDATED BALANCE SHEETS
EnergySouth, Inc.
| | | | | | | | | |
| September 30, (in thousands): | | 2007 | | 2006 |
| |
ASSETS | | | | | | | | |
| | | | | | | | | |
Current Assets | | | | | | | | |
| Cash and Cash Equivalents | | $ | 336 | | | $ | 1,272 | |
| Restricted Cash | | | 47,995 | | | | 1,742 | |
| Cash Held on Deposit in Margin Account | | | 999 | | | | | |
| Receivables | | | | | | | | |
| Gas | | | 10,106 | | | | 5,454 | |
| Unbilled Revenue | | | 1,499 | | | | 1,492 | |
| Merchandise | | | 1,926 | | | | 2,013 | |
| Other | | | 780 | | | | 1,522 | |
| Allowance for Doubtful Accounts | | | (1,047 | ) | | | (1,074 | ) |
| Materials, Supplies, and Merchandise (At Average Cost) | | | 1,376 | | | | 1,523 | |
| Gas Stored Underground For Current Use (At Average Cost) | | | 8,069 | | | | 6,612 | |
| Regulatory Assets | | | 5,015 | | | | 2,083 | |
| Deferred Income Taxes | | | | | | | 433 | |
| Prepaid Taxes | | | 2,088 | | | | 2,609 | |
| Prepayments | | | 3,320 | | | | 2,265 | |
| Other | | | 333 | | | | | |
| |
| Total Current Assets | | | 82,795 | | | | 27,946 | |
| |
| | | | | | | | | |
Property, Plant, and Equipment | | | 311,249 | | | | 295,503 | |
| Less: Accumulated Depreciation and Amortization | | | 94,025 | | | | 85,848 | |
| |
| Property, Plant, and Equipment — Net | | | 217,224 | | | | 209,655 | |
| Construction Work in Progress | | | 53,287 | | | | 18,915 | |
| |
| Total Property, Plant, and Equipment | | | 270,511 | | | | 228,570 | |
| |
| | | | | | | | | |
Other Assets | | | | | | | | |
| Prepaid Pension Cost | | | 11,827 | | | | 819 | |
| Prepaid Postretirement Benefit | | | 1,587 | | | | 578 | |
| Deferred Charges | | | 1,093 | | | | 286 | |
| Prepayments | | | 1,568 | | | | 1,233 | |
| Regulatory Assets | | | 27 | | | | 193 | |
| Merchandise Receivables Due After One Year | | | 3,038 | | | | 3,055 | |
| |
| Total Other Assets | | | 19,140 | | | | 6,164 | |
| |
Total | | $ | 372,446 | | | $ | 262,680 | |
| |
See Accompanying Notes to Consolidated Financial Statements
F-4
| | | | | | | | | | |
| September 30, (in thousands, except share data): | | 2007 | | 2006 | |
| |
LIABILITIES AND CAPITALIZATION | | | | | | | | | |
| | | | | | | | | | |
Current Liabilities | | | | | | | | | |
| Current Maturities of Long-Term Debt | | $ | 5,900 | | | $ | 5,619 | | |
| Notes Payable | | | 12,300 | | | | 5,300 | | |
| Accounts Payable | | | 30,835 | | | | 7,355 | | |
| Dividends Declared | | | 2,010 | | | | 1,828 | | |
| Customer Deposits | | | 1,139 | | | | 1,170 | | |
| Taxes Accrued | | | 3,752 | | | | 2,987 | | |
| Interest Accrued | | | 1,031 | | | | 900 | | |
| Regulatory Liabilities | | | 6,017 | | | | 5,980 | | |
| Deferred Income Taxes | | | 741 | | | | | | |
| Other | | | 1,456 | | | | 1,149 | | |
| |
| Total Current Liabilities | | | 65,181 | | | | 32,288 | | |
| |
| | | | | | | | | | |
Other Liabilities | | | | | | | | | |
| Deferred Income Taxes | | | 28,748 | | | | 25,235 | | |
| Deferred Investment Tax Credits | | | 196 | | | | 216 | | |
| Regulatory Liabilities | | | 21,892 | | | | 9,496 | | |
| Asset Retirement Obligations | | | 6,188 | | | | 5,818 | | |
| Other | | | 1,566 | | | | 1,382 | | |
| |
| Total Other Liabilities | | | 58,590 | | | | 42,147 | | |
| |
| | | | 123,771 | | | | 74,435 | | |
| |
| | | | | | | | | | |
Capitalization | | | | | | | | | |
| Stockholders’ Equity Common Stock, $.01 Par Value (Authorized 20,000,000 Shares; Outstanding 2007 - 7,986,000 Shares; 2006 - 7,947,000 Shares) | | | 80 | | | | 79 | | |
| Capital in Excess of Par Value | | | 30,852 | | | | 29,092 | | |
| Retained Earnings | | | 90,298 | | | | 81,919 | | |
| Accumulated Other Comprehensive Income (Loss), net of tax | | | 22 | | | | | | |
| Grantor Trust, at cost | | | (1,362 | ) | | | (1,733 | ) | |
| Deferred Compensation Liability | | | 1,362 | | | | 1,733 | | |
| |
| Total Stockholders’ Equity | | | 121,252 | | | | 111,090 | | |
| Minority Interest | | | 6,962 | | | | 5,794 | | |
| Long-Term Debt | | | 120,461 | | | | 71,361 | | |
| |
| Total Capitalization | | | 248,675 | | | | 188,245 | | |
| |
Total | | $ | 372,446 | | | $ | 262,680 | | |
| |
See Accompanying Notes to Consolidated Financial Statements
F-5
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
EnergySouth, Inc.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | Accumulated | | | | | | |
| | | Common Stock | | Capital in | | | | | | Other | | | | | | |
| | | Number of | | Par | | Excess of | | Retained | | Comprehensive | | Grantor | | Deferred | | |
| (In thousands, except per share data) | | Shares | | Value | | Par Value | | Earnings | | Income (Loss) | | Trust | | Compensation | | Total |
| |
Balance at September 30, 2004 | | | 7,827 | | | $ | 78 | | | $ | 26,162 | | | $ | 67,625 | | | | | | | $ | (1,355 | ) | | $ | 1,355 | | | $ | 93,865 | |
| Net Income | | | | | | | | | | | | | | | 13,841 | | | | | | | | | | | | | | | | 13,841 | |
| Dividend Reinvestment Plan | | | 14 | | | | | | | | 396 | | | | | | | | | | | | | | | | | | | | 396 | |
| Stock Options Exercised Including Income Tax Benefits | | | 49 | | | | 1 | | | | 680 | | | | | | | | | | | | | | | | | | | | 681 | |
| Shares issued to Grantor Trust to fund Deferred Compensation Liability | | | 8 | | | | | | | | 219 | | | | | | | | | | | | (219 | ) | | | 219 | | | | 219 | |
| Distributions from Grantor Trust | | | | | | | | | | | | | | | | | | | | | | | 35 | | | | (35 | ) | | | | |
| Cash Dividends — $0.83 per share | | | | | | | | | | | | | | | (6,514 | ) | | | | | | | | | | | | | | | (6,514 | ) |
| |
Balance at September 30, 2005 | | | 7,898 | | | | 79 | | | | 27,457 | | | | 74,952 | | | | | | | | (1,539 | ) | | | 1,539 | | | | 102,488 | |
| Net Income | | | | | | | | | | | | | | | 14,036 | | | | | | | | | | | | | | | | 14,036 | |
| Dividend Reinvestment Plan | | | 12 | | | | | | | | 348 | | | | | | | | | | | | | | | | | | | | 348 | |
| Stock Options Exercised Including Income Tax Benefits | | | 29 | | | | | | | | 660 | | | | | | | | | | | | | | | | | | | | 660 | |
| Stock Based Compensation Expense | | | | | | | | | | | 407 | | | | | | | | | | | | | | | | | | | | 407 | |
| Shares issued to Grantor Trust to fund Deferred Compensation Liability | | | 8 | | | | | | | | 220 | | | | | | | | | | | | (220 | ) | | | 220 | | | | 220 | |
| Distributions from Grantor Trust | | | | | | | | | | | | | | | | | | | | | | | 26 | | | | (26 | ) | | | | |
| Cash Dividends — $0.89 per share | | | | | | | | | | | | | | | (7,069 | ) | | | | | | | | | | | | | | | (7,069 | ) |
| |
Balance at September 30, 2006 | | | 7,947 | | | | 79 | | | | 29,092 | | | | 81,919 | | | | | | | | (1,733 | ) | | | 1,733 | | | | 111,090 | |
| Net Income | | | | | | | | | | | | | | | 16,033 | | | | | | | | | | | | | | | | 16,033 | |
| Other Comprehensive Income (Loss): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Current Period Change in Fair Value of Derivative Instruments, Net of Tax of ($13) | | | | | | | | | | | | | | | | | | $ | 22 | | | | | | | | | | | | 22 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Comprehensive Income (Loss) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 16,055 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Dividend Reinvestment Plan | | | 8 | | | | | | | | 337 | | | | | | | | | | | | | | | | | | | | 337 | |
| Stock Options Exercised Including Income Tax Benefits | | | 27 | | | | 1 | | | | 740 | | | | | | | | | | | | | | | | | | | | 741 | |
| Stock Based Compensation Expense | | | | | | | | | | | 519 | | | | | | | | | | | | | | | | | | | | 519 | |
| Shares issued to Grantor Trust to fund Deferred Compensation Liability | | | 4 | | | | | | | | 164 | | | | | | | | | | | | (164 | ) | | | 164 | | | | 164 | |
| Distributions from Grantor Trust | | | | | | | | | | | | | | | | | | | | | | | 535 | | | | (535 | ) | | | | |
| Cash Dividends — $0.96 per share | | | | | | | | | | | | | | | (7,654 | ) | | | | | | | | | | | | | | | (7,654 | ) |
| |
Balance at September 30, 2007 | | | 7,986 | | | $ | 80 | | | $ | 30,852 | | | $ | 90,298 | | | $ | 22 | | | $ | (1,362 | ) | | $ | 1,362 | | | $ | 121,252 | |
| |
See Accompanying Notes to Consolidated Financial Statements
F-6
CONSOLIDATED STATEMENTS OF CASH FLOWS
EnergySouth, Inc.
| | | | | | | | | | | | | |
| Years Ended September 30, (in thousands) | | 2007 | | 2006 | | 2005 |
| |
Cash Flows from Operating Activities | | | | | | | | | | | | |
| Net Income | | $ | 16,033 | | | $ | 14,036 | | | $ | 13,841 | |
| Depreciation and Amortization | | | 11,318 | | | | 10,922 | | | | 10,454 | |
| Provision for Losses on Receivables | | | 985 | | | | 991 | | | | 869 | |
| Provision for Losses on Inventory | | | 19 | | | | (53 | ) | | | 20 | |
| Provision for Deferred Income Taxes | | | 4,648 | | | | 5,941 | | | | (2,104 | ) |
| Minority Interest | | | 1,322 | | | | 1,113 | | | | 938 | |
| Stock-Based Employee Compensation Expense | | | 519 | | | | 407 | | | | | |
| Changes in Operating Assets and Liabilities: | | | | | | | | | | | | |
| Cash Held in Margin Account | | | (999 | ) | | | | | | | | |
| Receivables | | | (5,167 | ) | | | 1,821 | | | | (2,273 | ) |
| Inventory | | | (1,326 | ) | | | (1,084 | ) | | | (1,203 | ) |
| Payables | | | 22,058 | | | | 741 | | | | 478 | |
| Taxes Payable | | | 1,287 | | | | (5,659 | ) | | | 3,724 | |
| Deferred Purchased Gas Adjustment | | | (2,820 | ) | | | (3,295 | ) | | | 4,648 | |
| Other | | | (2,092 | ) | | | (951 | ) | | | 1,395 | |
| |
| | | | | | | | | | | | | |
| Net Cash Provided by Operating Activities | | | 45,785 | | | | 24,930 | | | | 30,787 | |
| |
| | | | | | | | | | | | | |
Cash Flows from Investing Activities | | | | | | | | | | | | |
| Capital Expenditures | | | (50,116 | ) | | | (24,378 | ) | | | (16,428 | ) |
| Changes in Restricted Cash | | | (46,253 | ) | | | (132 | ) | | | (208 | ) |
| |
| | | | | | | | | | | | | |
| Net Cash Used In Investing Activities | | | (96,369 | ) | | | (24,510 | ) | | | (16,636 | ) |
| |
| | | | | | | | | | | | | |
Cash Flows from Financing Activities | | | | | | | | | | | | |
| Repayment of Long-Term Debt | | | (5,619 | ) | | | (5,812 | ) | | | (8,148 | ) |
| Proceeds from Issuance of Long-Term Debt | | | 55,000 | | | | | | | | | |
| Changes in Short-term Borrowings | | | 7,000 | | | | 5,300 | | | | | �� |
| Payment of Dividends | | | (7,654 | ) | | | (7,069 | ) | | | (6,514 | ) |
| Dividend Reinvestment | | | 337 | | | | 348 | | | | 396 | |
| Exercise of Stock Options | | | 550 | | | | 530 | | | | 581 | |
| Excess Tax Benefits from Share Based Payments | | | 190 | | | | 130 | | | | | |
| Partnership Distributions | | | (156 | ) | | | (627 | ) | | | (401 | ) |
| |
| | | | | | | | | | | | | |
| Net Cash Used In Financing Activities | | | 49,648 | | | | (7,200 | ) | | | (14,086 | ) |
| |
| | | | | | | | | | | | | |
Net Increase (Decrease) in Cash and Cash Equivalents | | | (936 | ) | | | (6,780 | ) | | | 65 | |
| | | | | | | | | | | | | |
Cash and Cash Equivalents at Beginning of Year | | | 1,272 | | | | 8,052 | | | | 7,987 | |
| |
| | | | | | | | | | | | | |
Cash and Cash Equivalents at End of Year | | $ | 336 | | | $ | 1,272 | | | $ | 8,052 | |
| |
| | | | | | | | | | | | | |
Cash Paid During the Year for: | | | | | | | | | | | | |
| Interest | | $ | 7,067 | | | $ | 6,778 | | | $ | 7,351 | |
| |
| Income Taxes | | $ | 3,724 | | | $ | 8,596 | | | $ | 7,300 | |
| |
Noncash Transactions from Investing and Financing Activities: | | | | | | | | | | | | |
| Accruals for Capital Expenditures | | $ | 3,384 | | | $ | 1,649 | | | $ | 1,198 | |
| |
See Accompanying Notes to Consolidated Financial Statements
F-7
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 Midstream, Inc. (Midstream; formerly known as EnergySouth Storage Services, Inc.); EnergySouth Services, Inc. (Services); a 90.9% owned partnership, Bay Gas Storage Company, Ltd. (Bay Gas); and a 51% owned partnership, Southern Gas Transmission Company (SGT). On June 12, 2007, EnergySouth transferred its ownership interest in Services to Midstream. 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 midstream 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.
Revenues and costs from Midstream’s energy marketing, trading and risk management activities are presented on a net basis in Gas Revenues in the Consolidated Statements of Income.
Derivatives and Risk Management Activities
During the fourth quarter of fiscal 2007, Midstream became actively engaged in natural gas marketing, trading and risk management activities and, as such, is exposed to risks associated with changes in the market price of natural gas. Midstream uses derivative instruments to reduce the exposure to the risk of changes in the price of natural gas. The use of these instruments is subject to the Company’s risk management policies, which are monitored for compliance daily. Derivative instruments utilized in connection with these activities and services are accounted for under the fair value basis of accounting in accordance with SFAS 133.
Under SFAS 133, entities are required to record derivative instruments at fair value. Changes in the valuation of financial derivatives primarily result from changes in market prices, the valuation of the contracts, maturity and settlement of these contracts and newly originated transactions, each of which directly affect the estimated fair value of derivatives. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of
F-8
a hedging relationship. If the derivative instrument does not qualify or is not designated as part of a hedging relationship, then the changes in fair value of the derivative are accounted for in earnings as they occur.
To minimize the risk of fluctuations in natural gas prices, Midstream periodically enters into futures and other financial transactions in order to hedge anticipated purchases and sales of natural gas. Under certain conditions, these derivative instruments are designated as a hedge of exposure to changes in cash flows. For cash flow hedges, the effective portion of the gain or loss on the derivative instrument is reported initially as a component of other comprehensive income (loss) and is subsequently reclassified to earnings when the forecasted transaction affects earnings. Any hedge ineffectiveness, defined as when the gains or losses on the hedging instrument do not offset the losses or gains on the hedged item, is reported in earnings in the period the ineffectiveness occurs.
In accordance with SFAS 133, the relationship between hedging instruments and hedged items are formally documented, as well as the risk management objectives, strategies for undertaking hedge transactions and methods for assessing and testing correlation and hedge ineffectiveness. The forecasted transaction that has been designated as the hedged item is specifically identified and the effectiveness of the hedging relationship is assessed at the inception of the hedge and on an ongoing basis.
Midstream recognizes the change in value of derivative instruments as an unrealized gain or loss in revenues in the period when the market value of the instrument changes, unless designated as a hedge. Commodity price volatility may have a significant impact on the gain or loss in any given period.
Property, Plant, and Equipment
Included in property, plant, and equipment are acquisition adjustments, net of amortization, of $5,063,000 and $5,415,000 at September 30, 2007 and 2006. 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. Dismantling costs which are a component of Mobile Gas’ depreciation rates that are not a legal obligation as defined by SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143), are accounted for under the provisions of FASB Statement No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71) and recorded as a regulatory liability. 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 Sheets. 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, 2007, 2006, and 2005 approved depreciation rates
F-9
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.
Restricted Cash
Restricted cash includes funds that the Company has transferred to its transfer agent for disbursement of dividends to be paid to shareholders on October 1. Cash restricted for the payment of dividends at September 30, 2007, 2006, and 2005 amounted to $1,911,000, $1,742,000 and $1,610,000, respectively. At September 30, 2007, restricted cash also included $46,084,000 from the $55,000,000 Bonds loaned to Bay Gas. These funds are held in trust for the financing of Bay Gas’ storage facilities construction. See Liquidity and Capital Resources above.
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. A reconciliation of the weighted average common shares and the diluted average common shares is provided below:
EnergySouth, Inc.
| | | | | | | | | | | | | |
| In Thousands | | 2007 | | 2006 | | 2005 |
| |
| Weighted Average Common Shares | | | 7,972 | | | | 7,924 | | | | 7,854 | |
| | | | | | | | | | | | | |
| Effect of Dilutive Securities: | | | | | | | | | | | | |
| Options to Purchase Common Stock | | | 87 | | | | 54 | | | | 96 | |
| | | | | | | | | | | | | |
| |
| Diluted Average Common Shares | | | 8,059 | | | | 7,978 | | | | 7,950 | |
| |
Stock option awards to purchase approximately 158,000, 146,000 and 76,000 shares as of September 30, 2007, 2006, and 2005, respectively, were not included in the computation of diluted earnings per share because inclusion of these shares would have been antidulitive during these periods.
F-10
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.
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):
| | | | | | | | | | | | | | | | | |
| | | 2007 | | 2006 |
| | | Current | | Noncurrent | | Current | | Noncurrent |
| |
Assets | | | | | | | | | | | | | | | | |
| |
| Deferred Purchased Gas Adjustment | | $ | 4,736 | | | | | | | $ | 1,916 | | | | | |
| ESR Fund | | | 167 | | | | | | | | 167 | | | $ | 167 | |
| Weather Normalization Adjustment | | | 112 | | | | | | | | | | | | | |
| Asset Retirement Cost | | | | | | $ | 27 | | | | | | | | 26 | |
| |
| Regulatory Assets | | $ | 5,015 | | | $ | 27 | | | $ | 2,083 | | | $ | 193 | |
| |
| | | | | | | | | | | | | | | | | |
Liabilities | | | | | | | | | | | | | | | | |
| |
| ESR Fund | | $ | 1,000 | | | | | | | $ | 1,000 | | | | | |
| Contract Buyout | | | 2,188 | | | | | | | | 1,866 | | | | | |
| Deferred Investment Tax Credit | | | 15 | | | $ | 90 | | | | 15 | | | $ | 106 | |
| Gross Receipt Tax Collections | | | 2,468 | | | | | | | | 2,903 | | | | | |
| Accrued Dismantling Costs | | | | | | | 9,818 | | | | | | | | 9,390 | |
| Over-funded Pension and Postretirement Benefit Plans | | | | | | | 11,984 | | | | | | | | | |
| Other | | | 346 | | | | | | | | 196 | | | | | |
| |
| Regulatory Liabilities | | $ | 6,017 | | | $ | 21,892 | | | $ | 5,980 | | | $ | 9,496 | |
| |
In the event that a portion of the Company’s operations should no longer be subject to the provisions of SFAS No. 71, the Company would be required to write off related regulatory assets and liabilities that are not specifically addressed through regulated rates. In addition, the Company would be required to determine if any impairment to other assets exists, including plant, and write down the assets, if impaired, to their fair market value.
F-11
Stock-Based Compensation
The Company has employee stock option plans, which are described more fully in Note 7 below. Prior to October 1, 2005, the Company accounted for its 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 adopted the disclosure-only provisions of Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (SFAS 123). Accordingly, no compensation cost was recognized as stock options were issued with exercise prices equal to the market value of the underlying shares on the grant date. Had compensation cost for the Plan been determined on the fair value of the options on the grant date, the Company’s net income and earnings per share would have been as follows:
EnergySouth, Inc.
| | | | | |
| (In thousands, except per share data) | | 2005 |
| |
| Net Income, as reported | | $ | 13,841 | |
| Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects | | | 202 | |
| |
| Pro forma net income | | $ | 13,639 | |
| |
| | | | | |
Earnings per share | | | | |
| |
| Basic — as reported | | $ | 1.76 | |
| Basic — pro forma | | $ | 1.74 | |
| |
| | | | | |
| |
| Diluted — as reported | | $ | 1.74 | |
| Diluted — pro forma | | $ | 1.72 | |
| |
Effective October 1, 2005, the Company adopted SFAS 123R “Share Based Payment”. See Note 7 to the consolidated financial statements for full disclosure relating to stock based compensation.
New Accounting Standards
In June 2006, the FASB issued Financial Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes”, to clarify the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” FIN 48 is effective for the Company beginning October 1, 2007. The Company does not expect FIN 48 to have a significant impact on its financial statements.
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS 157) which clarifies the principle that fair value should be based on the assumptions market participants would use when pricing an asset or a liability and established a fair value hierarchy that prioritized the information used to develop those assumptions. Under SFAS 157, fair value measurements would be separately disclosed by level within the fair value hierarchy and is effective for the Company beginning October 1, 2008. The Company is currently evaluating the impact of this statement.
In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159), which permits entities to measure financial instruments and certain other items at fair value to mitigate volatility in reported earnings. SFAS 159 is effective for the Company beginning October 1, 2008. The Company is currently evaluating the impact of this statement.
F-12
On April 30, 2007, the FASB issued FSP FIN 39-1, which amended FIN 39, to indicate that the following fair value amounts could be offset against each other if certain conditions of FIN 39 are otherwise met: (a) those recognized for derivative instruments executed with the same counterparty under a master netting arrangement and (b) those recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) arising from the same master netting arrangement as the derivative instruments. In addition, a reporting entity is not precluded from offsetting the derivative instruments if it determines that the amount recognized upon payment or receipt of cash collateral is not a fair value amount. FSP FIN 39-1 is effective at the beginning of the first fiscal year after November 15, 2007. The Company will adopt FSP FIN 39-1 on October 1, 2008. The Company is currently evaluating the potential effect of FSP FIN 39-1 on its statements of financial position.
2. RATES AND REGULATIONS
Mobile Gas has utilized a Rate Stabilization and Equalization (RSE) rate setting process since October 1, 2002. On June 14, 2005, the Alabama Public Service Commission (APSC) issued an order to extend RSE on substantially the same basis from October 1, 2005 through September 30, 2009. In addition, absent an APSC order after that date modifying the RSE rate tariff, RSE shall continue in effect beyond September 30, 2009.
RSE is a ratemaking methodology also used by the APSC to regulate certain other public Alabama energy utilities. A rate adjustment designed to increase Mobile Gas’ annual gas revenues by approximately $4.2 million was implemented December 1, 2006. Previous rate adjustments were implemented under the RSE tariff which were designed to decrease annual gas revenues by approximately $303,000 effective December 1, 2005 and to increase annual gas revenues by approximately $1.7 million effective December 1, 2004. The December 1, 2005 rate decrease was due primarily to the return of approximately $1,350,000 of the regulatory liability for gross receipts tax collections to ratepayers during fiscal 2006. Mobile Gas’ rates, as established under RSE, allow a return on average equity within a range of 13.35% to 13.85% for the period. Mobile Gas is allowed to earn a return on all of its assets with no exclusions. Increases are allowed only once each fiscal year, effective December 1, and cannot exceed four percent of prior-year revenues. Under RSE, the APSC conducts reviews using fiscal year-to-date performance through January, April, and July plus Mobile Gas’ budget projections to determine whether Mobile Gas’ return on equity is expected to be within the allowed range at the end of the fiscal year. No such adjustments were required for fiscal 2006 or through the July 2005 test periods. Mobile Gas’ financial results for fiscal year 2005 did, however, result in a return on equity above the allowed range. As a result, adjustments of $433,000 were made to fiscal year 2005 pre-tax earnings 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 reflected the amount owed to customers. Reductions in rates were made in fiscal year 2006 which resulted in $433,000 being fully refunded to customers by the end of the fiscal year.
RSE limits the amount of Mobile Gas’ equity upon which a return is permitted to 60 percent of its total capitalization and provides for certain cost control measures designed to monitor Mobile Gas’ operations and maintenance (O&M) expense. Under the inflation-based cost control measurement established by the APSC, if a change in Mobile Gas’ O&M expense per customer falls within 1.5 percentage points above or below the change in the Consumer Price Index for All Urban Customers (index range), no adjustment is required. If the change in O&M expense per customer exceeds the index range, three-quarters of the difference is returned to customers through future rate adjustments. To the extent the change is less than the index range, the utility benefits by one-half of the difference through future rate adjustments. The increase in O&M expenses per customer was within the index range for the rate years ended September 30, 2007 and 2006; therefore, no adjustments were required. 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
F-13
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 conjunction with the approval of RSE, the APSC approved an Enhanced Stability Reserve (ESR), beginning October 1, 2002, to which Mobile Gas may charge the full amount of: 1) extraordinary O&M expenses resulting fromforce majeureevents such as storms, severe weather, and outages, when one such event results in more than $100,000 of additional O&M expense or a combination of two or more such events results in more than $150,000 of additional O&M expense during a fiscal year; or 2) losses of revenue from any individual industrial or commercial customer in excess of $100,000 during the fiscal year, if such losses cause Mobile Gas’ return on equity to fall below 13.35%. An initial ESR balance of $1.0 million was recorded October 1, 2002 and is being recovered from customers through rates. Subject to APSC approval, additional funding, up to a maximum reserve balance of $1.5 million, may be provided from any future non-recurring revenue should such revenue cause Mobile Gas’ return on equity for the fiscal year to exceed 13.85%. Following a year in which a charge against the ESR is made, the APSC allows for accruals to the ESR of no more than $15,000 monthly until the maximum funding level is achieved. The ESR balance of $1,000,000 at September 30, 2007 is included in the balance sheet of the Consolidated Financial Statements as part of Regulatory Liabilities.
In October 2000, the Corus Group plc (Corus, formerly known as British Steel) ceased operations of its Mobile facility and continued to pay Mobile Gas a minimum annual payment as required under the terms of its contract. On July 28, 2005, Corus elected to end the contract and make a termination payment as required by the terms of the contract. Under a Termination Agreement (Termination Agreement) between Mobile Gas and Corus, Corus agreed to pay Mobile Gas $6,100,000, of which $4,750,000 was paid in fiscal year 2006, and the final payment of $1,350,000 was paid October 2, 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 temperature adjustment rider applies to substantially all residential and small commercial customers. The adjustment is calculated monthly for the months of November through April and prior to November 1, 2006 was applied to customers’ bills in the same billing cycle in which the weather variation occurs. Effective November 1, 2006, Mobile Gas accumulates an adjustment for the margin impact due to variances in the weather. The accumulated adjustment from one heating season (November through April) will be billed or credited to customers in subsequent periods. This mechanism reduces the variability of both customers’ bills and Mobile Gas’ earnings due to weather fluctuations.
Through Midstream and Bay Gas, the Company provides underground storage of natural gas and transportation services. The APSC regulates intrastate storage operations through a contract approval process. Interstate gas storage contracts do not require APSC approval since the Federal Energy Regulatory Commission (FERC), which has jurisdiction over such contracts, allows them to have market-based rates. The FERC has granted authority to Bay Gas to provide transportation-only services to interstate shippers and has approved rates for such services.
F-14
3. PROPERTY, PLANT, AND EQUIPMENT
The functional classifications for the cost of property, plant, and equipment are as follows at September 30, (in thousands):
| | | | | | | | | | | | | |
| | | 2007 | | 2006 | | | | |
| |
| Distribution Plant | | $ | 170,366 | | | $ | 164,264 | | | | | |
| General Plant | | | 26,301 | | | | 25,048 | | | | | |
| Storage Plant | | | 81,073 | | | | 73,195 | | | | | |
| Transmission Plant | | | 24,527 | | | | 23,869 | | | | | |
| Acquisition Adjustment | | | 8,982 | | | | 9,127 | | | | | |
| |
| Total Property, Plant, and Equipment | | $ | 311,249 | | | $ | 295,503 | | | | | |
| |
4. ASSET RETIREMENT OBLIGATIONS
As of September 30, 2006, the Company adopted FIN 47, “Accounting for Conditional Asset Retirement Obligations,” which clarifies that if a legal obligation to perform an asset retirement activity exists but performance is conditional upon a future event, the liability is required to be recognized in accordance with SFAS 143, “Accounting for Asset Retirement Obligations.” Mobile Gas is required, pursuant to Federal and local regulations, to retire its distribution mains and service lines, although the timing of such retirements is uncertain. At September 30, 2007 and 2006, asset retirement obligations have been recorded in the amount of $6,188,000 and $5,818,000, respectively. The cumulative effect of the accretion of the liability and depreciation of the asset is recorded as a regulatory asset, pursuant to SFAS 71, and reduces the regulatory liability for asset dismantling costs as the Company recovers the cost of removing regulated assets through its depreciation rates.
F-15
5. NOTES PAYABLE AND LONG-TERM DEBT
Long-term debt consists of the following at September 30, (in thousands):
| | | | | | | | | |
| | | 2007 | | 2006 |
| |
Mobile Gas Service Corporation | | | | | | | | |
| First Mortgage Bonds | | | | | | | | |
| 8.75% Series, due July 1, 2022 | | $ | 9,480 | | | $ | 10,110 | |
| 7.48% Series, due July 1, 2022 | | | 7,800 | | | | 9,000 | |
| 6.90% Series, due August 20, 2017 | | | 9,219 | | | | 9,846 | |
| 9% Note, due May 13, 2013 | | | 2,006 | | | | 2,250 | |
Bay Gas Storage Company, Ltd. | | | | | | | | |
| 8.45% Guaranteed Senior Secured Notes, | | | | | | | | |
| due December 1, 2017 | | | 42,856 | | | | 45,774 | |
| Industrial Development Revenue Bonds, due August 15, 2037, | | | | | | | | |
| Variable rate - 3.93% at September 30, 2007 | | | 55,000 | | | | | |
| |
| Total | | | 126,361 | | | | 76,980 | |
| Less Amounts Due Within One Year | | | 5,900 | | | | 5,619 | |
| |
| Long-Term Debt | | $ | 120,461 | | | $ | 71,361 | |
| |
Maturities and sinking fund requirements on long-term debt in each of the five fiscal years subsequent to September 30, 2007 are as follows: 2008 — $5,900,000; 2009 — $6,054,000; 2010 - $5,653,000; 2011 — $5,955,000 and 2012 — $6,307,000. 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.
In August 2007, the Industrial Development Authority of Washington County, Alabama issued $55 million in Industrial Development Revenue Bonds (the Bonds) due August 15, 2037, and loaned these funds to Bay Gas for financing of storage facilities construction. The Bonds bear interest at a variable rate that is priced weekly. The weighted average interest rate during fiscal 2007 was 3.83%. In connection with the Bond issuance, Bay Gas caused a $55 million letter of credit (the Letter of Credit) to be issued to secure payment of the Bonds. At September 30, 2007, the Company has a $100 million credit facility (the Credit Agreement) which provides credit availability for the Letter of Credit, for additional letters of credit, and for a revolving credit line. The Credit Agreement bears interest at a base rate, or the LIBOR rate plus 0.50% to 1.25%, based on the Company’s ratio of debt to earnings before interest, taxes, depreciation and amortization (EBITDA) as determined on a quarterly basis (the Leverage Ratio). The Letter of Credit bears a fee of 0.45% to 1.20% based on the Leverage Ratio. The Company pays a commitment fee that ranges from 0.125% to 0.250% depending upon the Company’s Leverage Ratio applied to the daily unused commitment. The Company does not have any compensating balances with banks. Unused committed line of credit at September 30, 2007 was $32.2 million. The weighted average interest rate on short-term borrowings at September 30, 2007 was 6.7%.
Borrowings under the Credit Agreement may be made as needed provided that the Company is in compliance with certain covenants in the Credit Agreement and all other loan agreements. The Company is currently in compliance with all such covenants.
Subsequent to September 30, 2007, the Company replaced its existing $100 million credit facility with a new 364 day $250 million credit facility with a group of banks which also provides credit availability for the Letter of Credit, for additional letters of credit, and for a revolving credit line.
F-16
6. INCOME TAXES
The components of income tax expense are as follows for the years ended September 30, (in thousands):
| | | | | | | | | | | | | |
| | | 2007 | | 2006 | | 2005 |
| |
| Current | | | | | | | | | | | | |
| Federal | | $ | 4,467 | | | $ | 2,385 | | | $ | 9,983 | |
| State | | | 597 | | | | 307 | | | | 1,162 | |
| |
| Total Current Taxes | | | 5,064 | | | | 2,692 | | | | 11,145 | |
| |
| | | | | | | | | | | | | |
| Deferred | | | | | | | | | | | | |
| Federal | | | 4,099 | | | | 5,342 | | | | (1,985 | ) |
| State | | | 526 | | | | 694 | | | | (143 | ) |
| |
| Total Deferred Taxes | | | 4,625 | | | | 6,036 | | | | (2,128 | ) |
| |
| | | | | | | | | | | | | |
| Deferred investment tax credit amortization | | | (26 | ) | | | (26 | ) | | | (26 | ) |
| |
| | | | | | | | | | | | | |
| Total Income Tax Expense | | $ | 9,663 | | | $ | 8,702 | | | $ | 8,991 | |
| |
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):
| | | | | | | | | | | | | |
| | | 2007 | | 2006 | | 2005 |
| |
| Income Tax Expense at Federal | | | | | | | | | | | | |
| Statutory Rate | | $ | 8,994 | | | $ | 7,959 | | | $ | 7,991 | |
| State Income Taxes | | | 737 | | | | 671 | | | | 729 | |
| Other — Net | | | (68 | ) | | | 72 | | | | 271 | |
| |
| Total Income Tax Expense | | $ | 9,663 | | | $ | 8,702 | | | $ | 8,991 | |
| |
| | | | | | | | | | | | | |
| Effective Tax Rate | | | 37.6 | % | | | 38.3 | % | | | 39.4 | % |
| |
F-17
The significant components of the Company’s net deferred tax liability as of September 30, are (in thousands):
| | | | | | | | | |
| | | 2007 | | 2006 |
| |
| Deferred Tax Liabilities | | | | | | | | |
| Differences Between Book and Tax Basis of Property | | $ | 31,272 | | | $ | 27,941 | |
| Post Retirement Benefits | | | 307 | | | | 316 | |
| Prepaid Insurance | | | 274 | | | | 259 | |
| Purchased Gas Adjustment | | | 1,791 | | | | 725 | |
| Pension | | | 301 | | | | 312 | |
| Other | | | 84 | | | | 72 | |
| |
| Total Deferred Tax Liabilities | | | 34,029 | | | | 29,625 | |
| |
| Deferred Tax Assets | | | | | | | | |
| Gross Receipts Taxes | | | 738 | | | | 889 | |
| Regulatory Liabilities | | | 1,184 | | | | 1,516 | |
| Bad Debts | | | 567 | | | | 538 | |
| Accrued Vacation | | | 244 | | | | 233 | |
| Uniform Capitalization | | | 246 | | | | 222 | |
| Deferred Payments | | | 982 | | | | 1,086 | |
| Stock Option Expense | | | 325 | | | | 121 | |
| Other | | | 254 | | | | 218 | |
| |
| Total Deferred Tax Assets | | | 4,540 | | | | 4,823 | |
| |
| Net Deferred Tax Liability | | $ | 29,489 | | | $ | 24,802 | |
| |
7. STOCK BASED COMPENSATION AND CAPITAL STOCK
The Stock Option Plan of EnergySouth, Inc. (Plan), as approved by the shareholders, provides for the granting of incentive stock options and non-qualified stock options to key employees. Under the Plan, an aggregate of 525,000 shares of the Company’s authorized but unissued Common Stock, have been reserved for issuance. Options are granted at an option price which represents the market price on the date the grant is approved by the Board of Directors in accordance with the terms of the Plan. Stock options become 25% exercisable on the first anniversary of the grant date and an additional 25% become exercisable each succeeding year. No option may be exercised after the expiration of ten years from the grant date.
Effective October 1, 2005, the Company adopted SFAS 123R on a modified prospective basis. Under this method, the Company records compensation cost, on a prospective basis, for the portion of outstanding awards for which the requisite service has not yet been rendered as of October 1, 2005 based upon the grant date fair value of those awards. Total stock based compensation expense for stock option grants recognized during fiscal years 2007 and 2006 was $519,000 and $407,000, respectively. The income tax benefit recognized in the income statement for these stock options during fiscal year 2007 and 2006 was approximately $195,000 and $155,000, respectively. The impact of stock option expense was to reduce net income by $324,000 and $252,000 for fiscal year 2007 and 2006, respectively, which represents a decrease in basic and diluted earnings per share of approximately $0.04 per share for fiscal year 2007 and $0.03 per share for fiscal year 2006.
The Company entered into an agreement with John S. Davis, former President and Chief Executive Officer, to aid in the transition of his retirement on June 30, 2007. As part of that agreement, effective July 1, 2007, all options previously granted to Mr. Davis that were then unvested immediately became vested. Accelerated compensation expense of approximately $45,000 was
recognized in the fourth quarter of fiscal 2006 and approximately $135,000 was recognized in fiscal 2007 due to the vesting modification of the outstanding options.
F-18
The Company granted stock options during fiscal year 2007, 2006, and 2005. In calculating the impact for options granted during the current reporting period and in prior periods, the fair market value of the options at the date of grant was estimated using a Black-Scholes option pricing model. Assumptions utilized in the model are evaluated and revised, as necessary, to reflect market conditions and experience. Expected volatility has been calculated based on the historical volatility of the Company’s stock prior to the grant date. The expected term represents the period of time that options granted are expected to be outstanding and is estimated based on historical option exercise experience. The risk-free interest rate is equivalent to the U.S. Treasury yield in effect at the time of grant for the estimated life of the option grant. The weighted average fair value of options granted was $7.58, $5.49, and $5.20 per option during 2007, 2006, and 2005, respectively.
Weighted average assumptions used in the pricing model for the years ended September 30, are:
| | | | | | | | | | | | | |
| | | 2007 | | 2006 | | 2005 |
| |
| Risk Free Interest Rate | | | 4.69 | % | | | 4.48 | % | | | 3.90 | % |
| Expected Life | | 6 years | | 6 years | | 6 years |
| Stock Price Volatility | | | 16.67 | % | | | 17.43 | % | | | 20.96 | % |
| Dividend Yield | | | 2.51 | % | | | 2.80 | % | | | 3.13 | % |
Transactions under the Plan are summarized below:
| | | | | | | | | | | | | | | | | |
| | | | | | | Weighted | | Weighted | | Aggregate |
| | | | | | | Average | | Average | | Intrinsic |
| | | | | | | Exercise | | Remaining | | Value |
| | | Shares | | Price | | Life | | (in thousands) |
| |
| Outstanding at September 30, 2004 | | | 275,900 | | | | 17.308 | | | 6.95 years | | $ | 2,743 | |
| |
| Granted | | | 75,750 | | | | 28.365 | | | | | | | | | |
| Exercised | | | (49,286 | ) | | | 11.789 | | | | | | | | | |
| Forfeited | | | (2,775 | ) | | | 20.872 | | | | | | | | | |
| |
| Outstanding at September 30, 2005 | | | 299,589 | | | | 20.979 | | | 7.44 years | | $ | 1,981 | |
| |
| Granted | | | 73,950 | | | | 30.445 | | | | | | | | | |
| Exercised | | | (29,052 | ) | | | 18.268 | | | | | | | | | |
| Forfeited | | | (12,150 | ) | | | 25.727 | | | | | | | | | |
| |
| Outstanding at September 30, 2006 | | | 332,337 | | | $ | 23.148 | | | 6.82 years | | $ | 3,523 | |
| |
| Granted | | | 159,700 | | | $ | 39.953 | | | | | | | | | |
| Exercised | | | (26,912 | ) | | $ | 20.437 | | | | | | | | | |
| Forfeited | | | (24,025 | ) | | $ | 28.861 | | | | | | | | | |
| |
| Outstanding at September 30, 2007* | | | 441,100 | | | $ | 29.087 | | | 7.438 years | | $ | 9,410 | |
| |
| Exercisable at September 30, 2005 | | | 122,627 | | | $ | 16.161 | | | 5.88 years | | $ | 1,380 | |
| Exercisable at September 30, 2006 | | | 158,851 | | | $ | 18.434 | | | 5.97 years | | $ | 2,433 | |
| Exercisable at September 30, 2007 | | | 226,076 | | | $ | 21.527 | | | 5.71 years | | $ | 6,532 | |
| |
| Remaining reserved for grant at September 30, 2007 | | | 113,000 | | | | | | | | | | | | | |
| |
| | |
| * | | Includes 67,249 shares outstanding under the 1992 Amended and Restated Stock Option Plan. |
Outstanding stock option shares granted plus remaining shares reserved for grant equal 7% of current common shares outstanding at September 30, 2007.
F-19
The total intrinsic value of options exercised during 2007, 2006, and 2005 was approximately $564,000, $369,000, and $750,000, respectively. The fair value of options that vested during 2007, 2006, and 2005 was approximately $540,000, $327,000, and $274,000, respectively.
At September 30, 2007and 2006, there was approximately $1,185,000 and $694,000, respectively, of compensation cost that has not yet been recognized related to non-vested stock-based awards. That cost is expected to be recognized over a weighted-average period of 3.11 years and 2.11 years, respectively.
During 2007, 2006, and 2005 cash received from options exercised was $550,000, $530,000, and $581,000, respectively, and the actual tax benefit realized for the related tax deduction totaled $190,000, $130,000, and $99,000, respectively.
At September 30, 2007, 255,000 shares of the Company’s authorized but unissued Common Stock were reserved for issuance under the Company’s Dividend Reinvestment and Stock Purchase Plan.
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, 2007, approximately 78,000 shares had been issued to the Trust. There are 12,000 shares of the Company’s authorized but unissued Common Stock that are reserved for issuance to fund the deferred compensation obligations under the Plan.
8. RETIREMENT PLANS AND OTHER BENEFITS
As of September 30, 2007, the Company adopted SFAS 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132R” (SFAS 158). This standard retains the previous periodic expense calculation on an actuarial basis under the provisions of SFAS 87, “Employers’ Accounting for Pensions” and SFAS 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” In addition, SFAS 158 requires an employer to recognize the net funded status of defined benefit pensions and other postretirement benefit plans as an asset or liability in its statements of financial position. The Company established a regulatory liability for the obligation to be provided through rates in the future in accordance with SFAS 71. SFAS 158 also requires an employer to measure the funded status of a plan as of the date of its year-end statements of financial position effective for fiscal years ending after December 15, 2008. The Company uses a September 30 measurement date.
F-20
The following table summarized the effect of required changes to the Company’s financial statements as of September 30, 2007 prior and subsequent to the adoption of SFAS 158:
| | | | | | | | | | | | | |
| | | Prior to | | | | | | Subsequent |
| | | SFAS 158 | | SFAS 158 | | to SFAS 158 |
| (in thousands) | | Adoption | | Adjustment | | Adoption |
| |
| Prepaid Pension Costs | | $ | 785 | | | $ | 11,042 | | | $ | 11,827 | |
| Prepaid Postretirement Benefits | | | 645 | | | | 942 | | | | 1,587 | |
| Regulatory Liabilities | | | | | | | (11,984 | ) | | | (11,984 | ) |
The Company has a noncontributory, defined benefit retirement plan covering substantially all of its employees. Benefits are based on years of service and compensation during the term of employment, or if greater for persons employed before December 1, 1999, years of service and average compensation during the last five years of employment. The Company annually contributes to the plan the amount deductible for federal income tax purposes.
The Company also provides certain health insurance benefits for retired employees. Substantially all employees are eligible for such benefits if they retire under the provisions of the Company’s retirement plan. The Company accrues the cost of such benefits over the expected service period of the employees.
The Company has also provided certain life insurance benefits for retired employees. Effective August 1, 2006, the Company discontinued this life insurance benefit. In lieu of providing this coverage, the Company made a one-time payment to each retiree based on such retiree’s life insurance coverage and age. The Company paid an aggregate amount of $1,377,000 in such payments. The termination of the retiree life insurance as of July 31, 2006 constitutes a settlement under SFAS 106 which required that the postretirement benefit obligation be remeasured using the discount rate as calculated as of that date, which was 6.0%. This settlement resulted in a credit to expense of $1,474,000, for a net credit to expense of $97,000 after the cash payment to retirees.
The “projected unit credit” actuarial method was used to determine service cost and actuarial liability.
F-21
The status of the plans was as follows at September 30 (in thousands):
|
| | | | | | | | | | | | | | | | | |
| | | Pension | | Postretirement |
| | | Benefits | | Benefits |
| | | 2007 | | 2006 | | 2007 | | 2006 |
| |
Change in Benefit Obligation | | | | | | | | | | | | | | | | |
| |
| Benefit Obligation at Beginning of the Period | | $ | 32,736 | | | $ | 33,004 | | | $ | 3,479 | | | $ | 6,191 | |
| Service Cost | | | 837 | | | | 875 | | | | 153 | | | | 154 | |
| Interest Cost | | | 1,914 | | | | 1,838 | | | | 151 | | | | 282 | |
| Participant Contributions | | | | | | | | | | | 60 | | | | 62 | |
| Plan Amendments | | | | | | | | | | | | | | | (393 | ) |
| Settlement Gains | | | | | | | | | | | | | | | (1,872 | ) |
| Benefits Paid | | | (1,605 | ) | | | (1,537 | ) | | | (203 | ) | | | (226 | ) |
| Actuarial (Gain) / Loss | | | (1,143 | ) | | | (1,444 | ) | | | (877 | ) | | | (719 | ) |
| |
| Benefit Obligation at the End of the Period | | $ | 32,739 | | | $ | 32,736 | | | $ | 2,763 | | | $ | 3,479 | |
| |
| | | | | | | | | | | | | | | | | |
Change in Plan Assets | | | | | | | | | | | | | | | | |
| |
| Fair Value of Assets at Beginning of the Period | | $ | 39,817 | | | $ | 38,427 | | | $ | 3,852 | | | $ | 3,834 | |
| Benefits Paid | | | (1,605 | ) | | | (1,537 | ) | | | (203 | ) | | | (226 | ) |
| Employer Contributions | | | | | | | | | | | 4 | | | | 3 | |
| Participant Contributions | | | | | | | | | | | 60 | | | | 62 | |
| Actual Return on Plan Assets | | | 6,354 | | | | 2,927 | | | | 637 | | | | 179 | |
| |
| Fair Value of Plan Assets at the End of the Period | | $ | 44,566 | | | $ | 39,817 | | | $ | 4,350 | | | $ | 3,852 | |
| |
| | | | | | | | | | | | | | | | | |
Reconciliation of Funded Status | | | | | | | | | | | | | | | | |
| |
| Funded Status at End of Year | | $ | 11,827 | | | $ | 7,081 | | | $ | 1,587 | | | $ | 373 | |
| Unrecognized Net (Gain) Loss | | | | | | | (6,915 | ) | | | | | | | 828 | |
| Prior Service Cost Not Yet Recognized | | | | | | | 653 | | | | | | | | (623 | ) |
| |
| Accrued Benefit Asset (Liability) | | | | | | $ | 819 | | | | | | | $ | 578 | |
| |
| | | | | | | | | | | | | | | | | |
Amounts Included In Regulatory Liabilities | | | | | | | | | | | | | | | | |
| |
| Net (Loss) Gain | | $ | 11,602 | | | | | | | $ | 394 | | | | | |
| Prior Service (Cost) Credit | | | (560 | ) | | | | | | | 548 | | | | | |
| |
| Total Amounts Included in Regulatory Liaibilities | | $ | 11,042 | | | | | | | $ | 942 | | | | | |
| |
| |
| |
| Accumulated Benefit Obligation | | $ | 29,755 | | | $ | 29,664 | | | | | | | | | |
| |
F-22
Net periodic benefit cost included the following components for the years ended September 30, (in thousands):
| | | | | | | | | | | | | |
| | | Pension Benefits |
| Components of Net Periodic Benefit Cost | | 2007 | | 2006 | | 2005 |
| |
| Service Cost | | $ | 837 | | | $ | 875 | | | $ | 861 | |
| Interest Cost | | | 1,914 | | | | 1,838 | | | | 1,780 | |
| Amortization of Prior Service Cost | | | | | | | | | | | 94 | |
| Recognized Actuarial (Gain) / Loss | | | 93 | | | | 93 | | | | | |
| Expected return on Plan Assets | | | (2,810 | ) | | | (2,687 | ) | | | (2,572 | ) |
| |
| Net Periodic Benefit Cost (Income) | | $ | 34 | | | $ | 119 | | | $ | 163 | |
| |
| | | | | | | | | | | | | |
| | | Postretirement Benefits |
| Components of Net Periodic Benefit Cost | | 2006 | | 2006 | | 2005 |
| |
| Service Cost | | $ | 153 | | | $ | 154 | | | $ | 180 | |
| Interest Cost | | | 151 | | | | 282 | | | | 322 | |
| Amortization of Prior Service Cost | | | (76 | ) | | | (76 | ) | | | (44 | ) |
| Recognized Actuarial (Gain) / Loss | | | | | | | 59 | | | | 65 | |
| Expected return on Plan Assets | | | (291 | ) | | | (283 | ) | | | (272 | ) |
| |
| Net Periodic Benefit Cost | | $ | (63 | ) | | $ | 136 | | | $ | 251 | |
| |
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 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, 2007 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:
| | | | | | | | | | | | | | | | | |
| | | Pension | | Postretirement |
| | | Benefits | | Benefits |
| | | 2007 | | 2006 | | 2007 | | 2006 |
| |
Weighted-Average Assumptions to Determine Benefits Obligations | | | | | | | | | | | | | | | | |
| |
| Discount Rate | | | 6.25% | | | | 6.00% | | | | 6.25% | | | | 5.75% | |
| Rate of Compensation Increase | | | 3.75% | | | | 3.75% | | | | | | | | | |
| Measurement Date | | | 9/30/2007 | | | | 9/30/2006 | | | | 9/30/2007 | | | | 9/30/2006 | |
| | | | | | | | | | | | | | | | | |
Weighted-Average Assumptions to Determine Net Periodic Benefit Cost | | | | | | | | | | | | | | | | |
| |
| Discount Rate | | | 6.00% | | | | 5.75% | | | | 5.75% | | | | 5.50%/6.00% | |
| Expected Long-Term Rate of Return on Plan Assets | | | 8.25% | | | | 8.25% | | | | 7.75% | | | | 7.75% | |
| Rate of Compensation Increase | | | 3.75% | | | | 3.75% | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Assumed Health Care Cost Trend Rates at September 30 | | | | | | | | | | | | | | | | |
| |
| Health Care Cost Trend Rate Assumed for Next Year | | | | | | | | | | | 9.00% | | | | 9.00% | |
| Rate to Which the Cost Trend Rate is Assumed to Decline (the ultimate trend rate) | | | | | | | | | | | 5.00% | | | | 5.00% | |
| Year that the Rate Reaches the Ultimate Trend Rate | | | | | | | | | | | 2011 | | | | 2010 | |
F-23
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):
| | | | | | | | | |
| | | Postretirement Benefits |
| One Percentage-Point Increase | | 2007 | | 2006 |
| |
| Effect on Total of Service and Interest Components | | $ | 48 | | | $ | 52 | |
| Effect on Postretirement Benefit Obligations | | | 350 | | | | 414 | |
| | | | | | | | | |
| | | Postretirement Benefits |
| One Percentage-Point Decrease | | 2007 | | 2006 |
| |
| Effect on Total of Service and Interest Components | | $ | (40 | ) | | $ | (44 | ) |
| Effect on Postretirement Benefit Obligations | | | (298 | ) | | | (353 | ) |
| The Company has a committee 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 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, 2007 and 2006 and the current target allocation range are as follows:
| | | | | | | | | | | | | |
| | | Pension Benefits |
| | | Current | | Percentage of |
| | | Target | | Plan Assets |
| | | Allocation | | September 30, |
| Asset Category | | Range | | 2007 | | 2006 |
| |
| Equity | | | 60%-65 | % | | | 65 | % | | | 65 | % |
| Fixed income | | | 35%-40 | % | | | 34 | % | | | 34 | % |
| Cash and Cash Equivalents | | 0% to 2% | | | 1 | % | | | 1 | % |
| |
| Total | | | 100% | | | | 100 | % | | | 100 | % |
| |
| | | Postretirement Benefits |
| | | Current | | Percentage of |
| | | Target | | Plan Assets |
| | | Allocation | | September 30, |
| Asset Category | | Range | | 2007 | | 2006 |
| |
| Equity | | | 57%-67 | % | | | 66 | % | | | 66 | % |
| Fixed income | | | 33%-43 | % | | | 31 | % | | | 31 | % |
| Cash and Cash Equivalents | | as needed | | | 3 | % | | | 3 | % |
| |
| Total | | | 100% | | | | 100 | % | | | 100 | % |
Pension plan equity securities include the Company’s common stock of 3.7% and 3.1% of plan assets at September 30, 2007 and 2006 respectively. The postretirement benefits plan does not invest in the Company’s common stock.
F-24
The Company does not anticipate contributing to its pension plan in fiscal year 2008 but expects to contribute $4,000 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):
| | | | | | | | | | | | | |
| | | | | | | Post- | | |
| | | Pension | | Retirement | | |
| Expected Benefit Payments | | Benefits | | Benefits | | Total |
| |
| Fiscal Year Ending | | | | | | | | | | | | |
| 9/30/2008 | | $ | 1,695 | | | $ | 175 | | | $ | 1,870 | |
| 9/30/2009 | | | 1,709 | | | | 169 | | | | 1,878 | |
| 9/30/2010 | | | 1,743 | | | | 167 | | | | 1,910 | |
| 9/30/2011 | | | 1,773 | | | | 193 | | | | 1,966 | |
| 9/30/2012 | | | 1,857 | | | | 171 | | | | 2,028 | |
| Next Five Years | | | 10,333 | | | | 928 | | | | 11,261 | |
The Company has formed two voluntary employees’ beneficiary association (VEBA) trusts to fund postretirement health and life insurance benefits. The Company contributed $4,500 in 2007 and $3,000 in 2006.
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, 2007, 2006, and 2005 were $237,000, $226,000, and $223,000, respectively.
9. COMMITMENTS AND CONTINGENCIES
The Company has third-party contracts, which expire at various dates through the year 2011, for the purchase, storage and delivery of gas supplies. Mobile Gas is exposed to load loss risks associated with significant increases in commodity prices of natural gas. Mobile Gas 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 such commitments for future gas purchases at fixed prices meet the requirements of paragraph 10.b,Normal Purchases and Normal Sales,of Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended by SFAS No. 149. Thus, Mobile Gas’ commitments for future purchases of natural gas at fixed prices are deemed and elected to be considered purchases in the normal course of business and are not subject to derivative accounting treatment.
At September 30, 2007, Mobile Gas had not entered into derivative instruments that did not qualify and were not designated as normal purchases under SFAS 133. If Mobile Gas had entered into such derivative instruments, any cost incurred or benefit received from the derivative or other hedging arrangements would be recoverable or refunded through the purchased gas adjustment mechanism as the APSC currently allows for full recovery of all costs associated with natural gas purchases; therefore, costs associated with the forward purchases of natural gas will be passed through to customers when realized and will not affect future earnings.
A portion of firm supply requirements is expected to be met through the withdrawal of gas from the storage facility owned by Bay Gas. Mobile Gas has entered into a Gas Storage Agreement under which Bay Gas is to provide storage services for an initial period of 20 years which began in September 1994 with the commencement of commercial operations of the storage facility. The
F-25
purchased gas adjustment provisions of the Company’s rate schedules permit the recovery of all costs associated with gas supply from customers.
As part of a project to identify, evaluate and select new Customer Information System (CIS) software, on June 30, 2006, Mobile Gas entered into contracts with SAP America, Inc. for the purchase of CIS software and with Axon Solutions, Inc. for related implementation and consulting services.
Bay Gas has contracted for rights to develop caverns for the storage of natural gas on property owned by Olin Corporation. With respect to the first and second caverns, the terms of the agreement state that Bay Gas shall pay to Olin twenty consecutive annual cash payments to begin upon completion of each storage cavern. At the end of the initial 50 year lease term, Bay Gas has the right to renew the lease term for an additional 20 year period and would be required to remit annual payments based on the initial minimum service fees. Payments relating to the third cavern will extend over the life of the initial lease term or for as long as the cavern is in service. Payments are adjusted for annual Consumer Price Index (CPI) changes. Minimum commitments shown below reflect the CPI at the commitment date for each cavern. As of September 30, 2007, Bay Gas had entered into contracts for compressors and other services to be performed in 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.
| | | | | | | | | | | | | | | | | | | | | |
| | | Mobile Gas | | Bay Gas | | |
| | | Gas | | | | | | Minimum | | | | |
| Fiscal | | Supply | | Implemention of | | Payments for | | Construction | | Total |
| Year | | Contracts | | CIS Software | | Service Fees | | Contracts | | Commitments |
| |
| 2008 | | $ | 19,074 | | | $ | 2,620 | | | $ | 638 | | | $ | 9,760 | | | $ | 32,092 | |
| 2009 | | | 1,141 | | | | | | | | 638 | | | | | | | | 1,779 | |
| 2010 | | | 1,141 | | | | | | | | 638 | | | | | | | | 1,779 | |
| 2011 | | | 815 | | | | | | | | 638 | | | | | | | | 1,453 | |
| 2012 | | | | | | | | | | | 638 | | | | | | | | 638 | |
| 2013 - and thereafter | | | | | | | | | | | 31,950 | | | | | | | | 31,950 | |
| |
Total | | $ | 22,171 | | | $ | 2,620 | | | $ | 35,140 | | | $ | 9,760 | | | $ | 69,691 | |
| |
Like many gas distribution companies, prior to the widespread availability of natural gas, the Company manufactured gas for sale to its customers. In contrast to some other companies which operated multiple manufactured gas plants, the Company and its predecessor operated only one such plant, which discontinued operations in 1933. The process for manufacturing gas produced by-products and residuals, such as coal tar, and certain remnants of these residuals are sometimes found at former gas manufacturing sites.
Based on plans for the site, the Alabama Department of Environmental Management (“ADEM”) has conducted a “Brownfield” evaluation of the property. On January 5, 2005, ADEM released a “CERCLA Targeted Brownfield Site Inspection” report on the manufactured gas plant site. Prior to the ADEM “Brownfield” evaluation, Mobile Gas engaged environmental consultants to evaluate the site in connection with the plans for the site. Based on their review, the Company recorded its best estimate of $200,000 as an expense and a remediation liability in fiscal 2004. The Company intends that, should further investigation or changes in environmental laws or regulations require material expenditures for evaluation or remediation with regard to the site, it would apply to the APSC for appropriate rate recovery of such costs. However, there can be no assurances that the APSC would approve the recovery of such costs or the amount and timing of any such recovery.
F-26
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.
10. ENERGY MARKETING AND RISK MANAGEMENT ACTIVITIES
During the fourth quarter of fiscal 2007, Midstream began limited activity in natural gas marketing, trading and risk management activities and, as such, is exposed to risks associated with changes in the market price of natural gas. Midstream uses derivative instruments to reduce the exposure to the risk of changes in the price of natural gas. The use of these instruments is subject to the Company’s risk control policies, which are monitored for compliance daily. Derivative instruments utilized in connection with these activities and services are accounted for under the fair value basis of accounting in accordance with SFAS 133.
To minimize the risk of fluctuations in natural gas prices, Midstream periodically enters into futures and other financial transactions in order to hedge anticipated purchases and sales of natural gas. During the fourth quarter of fiscal 2007, Midstream entered into park and loan transactions with pipelines and with Storage which allow it to park gas on or borrow gas from the pipeline or storage facility in one period and reclaim gas from or repay gas to the pipeline in a subsequent period. Midstream entered into forward NYMEX contracts to hedge its inventory that is parked. At September 30, 2007, these derivative transactions are designated as cash flow hedges under SFAS 133. Derivative gains or losses arising from cash flow hedges are recorded in Other Comprehensive Income (OCI) and are reclassified into earnings in the same period the underlying hedged item is reflected in the income statement. As of September 30, 2007, the ending balance in OCI for derivative transactions designated as cash flow hedges under SFAS 133 was a gain of $22,000, net of taxes. Any hedge ineffectiveness, defined as when the gains or losses on the hedging instrument do not offset the losses or gains on the hedged item, is recorded into earnings in the period in which it occurs. As of September 30, 2007, Midstream had minimal hedge ineffectiveness.
Additionally, Midstream participated in park and loan transactions in which physical gas was borrowed and later repaid. Through the use of swaps, Midstream was able to capture gross profit margin through the arbitrage of pricing differences in various locations and by recognizing pricing differences that occur over time. Although the purpose of these instruments is to either reduce basis or other risks or lock in arbitrage opportunities, these derivative instruments were not designated as hedges. Accordingly, these derivative instruments were recorded at fair value with all changes in fair value included in revenue.
Derivatives are recorded as a component of risk management assets and liabilities, which are classified as current or noncurrent based upon the anticipated settlement date of the underlying derivative. The determination of the fair value of these derivative financial instruments reflects the estimated amounts that Midstream would receive or pay to terminate or close the contracts at the reporting date. In the determination of fair value, various factors are considered, including closing exchange and over-the-counter quotations, time value and volatility factors underlying the contracts. These energy marketing and risk management assets and liabilities are subject to continuing market risk until the underlying derivative contracts are settled.
The following table shows the fair values of the energy marketing and risk management assets and liabilities which are included in other assets and/or other liabilities, as appropriate, in the Consolidated Balance Sheet at September 30, 2007.
F-27
| | | | | |
| Fair Value As of September 30, (in thousands) | | 2007 | |
| |
| Energy Marketing and Risk Management Assets, current | | $ | 115 | |
| Energy Marketing and Risk Management Assets, long-term | | | 2 | |
| Energy Marketing and Risk Management Liabilities, current | | | (35 | ) |
| Energy Marketing and Risk Management Liabilities, long-term | | | | |
| | | | |
| Net Assets (Liabilities) | | $ | 82 | |
| | | | |
For the year ended September 30, 2007, the change in the deferred hedging position in accumulated other comprehensive income was attributable to increases in future commodity prices relative to the commodity prices stipulated in the derivative contracts totaling $35,000. The net deferred hedging gains associated with open cash flow hedges remain subject to market price fluctuations until the positions are either settled under the terms of the hedge contracts or terminated prior to settlement. Substantially all of the deferred hedging gain as of September 30, 2007 is expected to be recognized in net income within the next fiscal year.
11. 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.
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):
| | | | | | | | | | | | | | | | | |
| | | 2007 | | 2006 |
| | | Carrying | | Estimated | | Carrying | | Estimated |
| | | Amount | | Fair Value | | Amount | | Fair Value |
| |
| Long-term debt | | $ | 126,361 | | | $ | 136,124 | | | $ | 76,980 | | | $ | 87,818 | |
12. 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
F- 28
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 Midstream. The Natural Gas Distribution segment is actively engaged in the distribution and transportation of natural gas to residential, commercial and industrial customers through Mobile Gas. The Natural Gas Midstream segment provides for the underground storage of natural gas and transportation services through the operations of Bay Gas and transportation services through the operations of SGT. Through Services, Midstream manages and optimizes transportation and storage assets through natural gas marketing, trading and risk management activities. The Company also provides merchandising and other energy-related services through Mobile Gas which are aggregated with EnergySouth, the holding company, and included in the Other segment. For the years ended September 30, 2007, 2006, and 2005, all segments were located in Southwest Alabama. During fiscal 2007, Midstream established an office in Houston, Texas.
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.
| | | | | | | | | | | | | | | | | | | | | |
| As of and for the year ended | | Natural Gas | | Natural Gas | | | | | | |
| September 30, 2007 (in thousands): | | Distribution | | Midstream | | Other | | Eliminations | | Consolidated |
| |
| Gas Revenues | | $ | 108,254 | | | $ | 26,721 | | | | | | | $ | (4,237 | ) | | $ | 130,738 | |
| Other Revenues | | | | | | | 23 | | | $ | 4,272 | | | | | | | | 4,295 | |
| |
| Operating Revenues | | | 108,254 | | | | 26,744 | | | | 4,272 | | | | (4,237 | ) | | | 135,033 | |
| | | | | | | | | | | | | | | | | | | | | |
| Cost of Gas | | | 53,410 | | | | | | | | | | | | (4,237 | ) | | | 49,173 | |
| Cost of Merchandise | | | | | | | | | | | 2,684 | | | | | | | | 2,684 | |
| Operations and Maintenance Expense | | | 22,049 | | | | 7,290 | | | | 1,939 | | | | | | | | 31,278 | |
| Depreciation Expense | | | 8,264 | | | | 2,739 | | | | 5 | | | | | | | | 11,008 | |
| Taxes, Other Than Income Taxes | | | 8,027 | | | | 997 | | | | 68 | | | | | | | | 9,092 | |
| |
| Operating Income | | | 16,504 | | | | 15,718 | | | | (424 | ) | | | | | | | 31,798 | |
| |
| Interest Income (Expense) — Net | | | (3,504 | ) | | | (4,224 | ) | | | 656 | | | | | | | | (7,072 | ) |
| Capitalized Interest | | | 72 | | | | 2,220 | | | | | | | | | | | | 2,292 | |
| Less: Minority Interest | | | | | | | (1,322 | ) | | | | | | | | | | | (1,322 | ) |
| |
| Income Before Income Taxes | | $ | 13,072 | | | $ | 12,392 | | | $ | 232 | | | | | | | $ | 25,696 | |
| |
| Capital Expenditures | | $ | 12,460 | | | $ | 39,390 | | | | | | | | | | | $ | 51,850 | |
| Property, Plant, and Equipment, Net | | $ | 136,895 | | | $ | 133,616 | | | | | | | | | | | $ | 270,511 | |
| Total Assets | | $ | 172,814 | | | $ | 191,885 | | | $ | 7,747 | | | | | | | $ | 372,446 | |
F- 29
| | | | | | | | | | | | | | | | | | | | | |
| As of and for the year ended | | Natural Gas | | Natural Gas | | | | | | |
| September 30, 2006 (in thousands): | | Distribution | | Midstream | | Other | | Eliminations | | Consolidated |
| |
| Gas Revenues | | $ | 113,666 | | | $ | 21,236 | | | | | | | $ | (4,216 | ) | | $ | 130,686 | |
| Other Revenues | | | | | | | 47 | | | $ | 5,134 | | | | | | | | 5,181 | |
| |
| Operating Revenues | | | 113,666 | | | | 21,283 | | | | 5,134 | | | | (4,216 | ) | | | 135,867 | |
| | | | | | | | | | | | | | | | | | | | | |
| Cost of Gas | | | 61,468 | | | | | | | | | | | | (4,216 | ) | | | 57,252 | |
| Cost of Merchandise | | | | | | | | | | | 3,150 | | | | | | | | 3,150 | |
| Operations and Maintenance Expense | | | 21,271 | | | | 3,299 | | | | 1,455 | | | | | | | | 26,025 | |
| Depreciation Expense | | | 7,918 | | | | 2,685 | | | | | | | | | | | | 10,603 | |
| Taxes, Other Than Income Taxes | | | 8,335 | | | | 940 | | | | 78 | | | | | | | | 9,353 | |
| |
| Operating Income | | | 14,674 | | | | 14,359 | | | | 451 | | | | | | | | 29,484 | |
| |
| Interest Income (Expense) — Net | | | (3,135 | ) | | | (3,869 | ) | | | 360 | | | | | | | | (6,644 | ) |
| Capitalized Interest | | | 61 | | | | 950 | | | | | | | | | | | | 1,011 | |
| Less: Minority Interest | | | | | | | (1,113 | ) | | | | | | | | | | | (1,113 | ) |
| |
| Income Before Income Taxes | | $ | 11,600 | | | $ | 10,327 | | | $ | 811 | | | | | | | $ | 22,738 | |
| |
| Capital Expenditures | | $ | 12,954 | | | $ | 11,876 | | | | | | | | | | | $ | 24,830 | |
| Property, Plant, and Equipment, Net | | $ | 132,143 | | | $ | 96,427 | | | | | | | | | | | $ | 228,570 | |
| Total Assets | | $ | 152,964 | | | $ | 102,648 | | | $ | 7,068 | | | | | | | $ | 262,680 | |
| | | | | | | | | | | | | | | | | | | | | |
| As of and for the year ended | | Natural Gas | | Natural Gas | | | | | | |
| September 30, 2005 (in thousands): | | Distribution | | Midstream | | Other | | Eliminations | | Consolidated |
| |
| Gas Revenues | | $ | 104,376 | | | $ | 19,812 | | | | | | | $ | (4,201 | ) | | $ | 119,987 | |
| Other Revenues | | | | | | | 54 | | | $ | 4,565 | | | | | | | | 4,619 | |
| |
| Operating Revenues | | $ | 104,376 | | | $ | 19,866 | | | $ | 4,565 | | | $ | (4,201 | ) | | $ | 124,606 | |
| | | | | | | | | | | | | | | | | | | | | |
| Cost of Gas | | | 51,367 | | | | | | | | | | | | (4,201 | ) | | | 47,166 | |
| Cost of Merchandise | | | | | | | | | | | 2,765 | | | | | | | | 2,765 | |
| Operations and Maintenance Expense | | | 20,542 | | | | 3,361 | | | | 1,411 | | | | | | | | 25,314 | |
| Depreciation Expense | | | 7,565 | | | | 2,557 | | | | | | | | | | | | 10,122 | |
| Taxes, Other Than Income Taxes | | | 7,673 | | | | 916 | | | | 66 | | | | | | | | 8,655 | |
| |
| Operating Income | | | 17,229 | | | | 13,032 | | | | 323 | | | | | | | | 30,584 | |
| |
| Interest Income (Expense) — Net | | | (2,896 | ) | | | (4,080 | ) | | | (48 | ) | | | | | | | (7,024 | ) |
| Capitalized Interest | | | 37 | | | | 173 | | | | | | | | | | | | 210 | |
| Less: Minority Interest | | | | | | | (938 | ) | | | | | | | | | | | (938 | ) |
| |
| Income Before Income Taxes | | $ | 14,370 | | | $ | 8,187 | | | $ | 275 | | | | | | | $ | 22,832 | |
| |
| Capital Expenditures | | $ | 9,571 | | | $ | 7,307 | | | | | | | | | | | $ | 16,878 | |
| Property, Plant, and Equipment, Net | | $ | 124,734 | | | $ | 87,154 | | | | | | | | | | | $ | 211,888 | |
| Total Assets | | $ | 147,017 | | | $ | 97,928 | | | $ | 7,514 | | | | | | | $ | 252,459 | |
13. SUBSEQUENT EVENT
Subsequent to September 30, 2007, EnergySouth and certain funds managed by affiliates of Fortress Investment Group LLC (the “Fortress Funds”) acquired the net assets of the natural gas storage company, Mississippi Hub LLC, for $140 million. EnergySouth, by obtaining a 60% majority interest, will be the operating entity for the development, construction, and operation of the facility. The Fortress Funds own the remaining 40% interest. Mississippi Hub LLC expects to complete construction of its first underground natural gas storage cavern in 2009.
F- 30
14. QUARTERLY FINANCIAL DATA (Unaudited)
Quarterly financial data for fiscal 2007 and 2006 is summarized as follows
(in thousands, except per share data):
| | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended | | Dec. 31 | | Mar. 31 | | Jun. 30 | | Sep. 30 | | | | |
| |
Fiscal 2007 | | | | | | | | | | | | | | | | | | | | |
| |
| | | | | | | | | | | | | | | | | | | | | |
| Total Operating Revenues | | $ | 38,930 | | | $ | 46,662 | | | $ | 23,745 | | | $ | 25,696 | | | | | |
| Total Operating Income | | | 8,998 | | | | 12,489 | | | | 3,440 | | | | 6,871 | | | | | |
| Net income | | | 4,614 | | | | 6,831 | | | | 1,334 | | | | 3,254 | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Basic Earnings Per Share (1) | | $ | 0.58 | | | $ | 0.86 | | | $ | 0.17 | | | $ | 0.40 | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Diluted Earnings Per Share (1) | | $ | 0.57 | | | $ | 0.85 | | | $ | 0.17 | | | $ | 0.40 | | | | | |
| |
Fiscal 2006 | | | | | | | | | | | | | | | | | | | | |
| |
| | | | | | | | | | | | | | | | | | | | | |
| Total Operating Revenues | | $ | 44,812 | | | $ | 46,091 | | | $ | 23,126 | | | $ | 21,838 | | | | | |
| Total Operating Income | | | 8,980 | | | | 12,417 | | | | 4,091 | | | | 3,996 | | | | | |
| Net income | | | 4,485 | | | | 6,661 | | | | 1,563 | | | | 1,327 | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Basic Earnings Per Share (1) | | $ | 0.57 | | | $ | 0.84 | | | $ | 0.20 | | | $ | 0.16 | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Diluted Earnings Per Share (1) | | $ | 0.56 | | | $ | 0.84 | | | $ | 0.20 | | | $ | 0.16 | | | | | |
| |
Fiscal 2005 | | | | | | | | | | | | | | | | | | | | |
| |
| | | | | | | | | | | | | | | | | | | | | |
| Total Operating Revenues | | $ | 36,367 | | | $ | 44,099 | | | $ | 22,350 | | | $ | 21,790 | | | | | |
| Total Operating Income | | | 8,988 | | | | 12,955 | | | | 4,193 | | | | 4,448 | | | | | |
| Net Income | | | 4,316 | | | | 6,795 | | | | 1,457 | | | | 1,273 | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Basic Earnings Per Share (1) | | $ | 0.55 | | | $ | 0.87 | | | $ | 0.19 | | | $ | 0.16 | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Diluted Earnings Per Share (1) | | $ | 0.54 | | | $ | 0.85 | | | $ | 0.18 | | | $ | 0.16 | | | | | |
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. |
F- 31
SCHEDULE II
ENERGYSOUTH, INC. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEARS ENDED SEPTEMBER 30, 2007, 2006, AND 2005
(in thousands)
| | | | | | | | | | | | | | | | | |
| COLUMN A | | COLUMN B | | COLUMN C | | COLUMN D | | COLUMN E |
| | | | | | | ADDITIONS | | | | |
| | | BALANCE | | CHARGED | | CHARGED | | | | |
| | | AT | | TO COSTS | | TO OTHER | | | | BALANCE |
| | | BEGINNING | | AND | | ACCOUNTS | | DEDUCTIONS | | AT END |
| DESCRIPTION | | OF YEAR | | EXPENSES | | AMOUNT | | AMOUNT | | OF YEAR |
| Reserves deducted from assets to which they apply: | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Allowance for Doubtful Accounts | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| September 30, 2007 | | $ | 1,074 | | | $ | 931 | | | | | $958(1) | | $ | 1,047 | |
| September 30, 2006 | | $ | 1,029 | | | $ | 991 | | | | | $946(1) | | $ | 1,074 | |
| September 30, 2005 | | $ | 856 | | | $ | 868 | | | | | $695(1) | | $ | 1,029 | |
Notes:
| | |
| (1) | | Amounts written off — net of recoveries. |
S- 1
EXHIBIT INDEX
| | | |
| Exhibit No. | | Description (Exhibits prior to February 2, 1998 filed by Mobile Gas) |
| 2 | | Articles of Merger of MBLE Merger Co., Inc. into Mobile Gas Service Corporation (incorporated by reference to Exhibit 2 to Form 10-Q Quarterly Report dated February 13, 1998) |
| | | |
| 2.1 | | Agreement and Plan of Merger between EnergySouth, Inc., an Alabama corporation, and EnergySouth, Inc., a Delaware corporation, dated January 30, 2007 (incorporated by reference to Exhibit 2.1 to Form 8-K filed February 1, 2007) |
| | | |
| 2(a)-1 | | Limited Liability Company Agreement of Mississippi Hub Acquisition Company, LLC dated |
| | | October 31, 2007 (incorporated by reference to Exhibit 2.1 to Form 8-K dated November 5, 2007) |
| | | |
| 2(a)-2 | | Membership Interest Purchase Agreement, dated October 31, 2007, among Mississippi Hub |
| | | Acquisition Company, LLC, Theo B. Bean, Jr. and Theo B. Bean, Jr., as trustee for The Theo B. Bean, Jr. Family Trust (incorporated by reference to Exhibit 2.2 to Form 8-K dated November 5, 2007) |
| | | |
| 2(a)-3 | | Purchase and Sale Agreement, dated October 31, 2007, between Mississippi Hub Acquisition |
| | | Company, LLC and BRI-Marsh, L.L.C. (incorporated by reference to Exhibit 2.3 to Form 8-K dated November 5, 2007) |
| | | |
| 3(i) | | Restated Articles of Incorporation of EnergySouth, Inc. (incorporated by reference to Exhibit 3(i) to Form 10-Q Quarterly Report dated February 2, 2005) |
| | | |
| 3(ii) | | By-laws of EnergySouth, Inc., amended October 26, 2007 (incorporated by reference to Exhibit 3(ii) to Form 8-K dated October 29, 2007) |
| | | |
| 3.1 | | Certificate of Incorporation of EnergySouth, Inc. (incorporated by reference to Exhibit 3.1 to Form 8-K filed February 1, 2007) |
| | | |
| 4(a)-1 | | Indenture of Mortgage and Deed of Trust of Mobile Gas Service Corporation dated as of December 1, 1941 (incorporated by reference to Exhibit B-a to Mobile Gas Registration Statement No. 2-4887) |
| | | | | | | |
| | | Sup. Ind. | | | | |
| | | Dated as of | | File Reference | | Exhibit |
| 4(a)-2 | | 10/1/44 | | Reg. No. 2-5493 | | 7-6 |
| | | | | | | |
| 4(a)-3 | | 7/1/52 | | Form 10-K for fiscal year ended
September 30, 1985 | | 4(a)-3 |
| 4(a)-4 | | 6/1/54 | | ” | | 4(a)-4 |
| 4(a)-5 | | 4/1/57 | | ” | | 4(a)-5 |
| 4(a)-6 | | 7/1/61 | | ” | | 4(a)-6 |
| 4(a)-7 | | 6/1/63 | | ” | | 4(a)-7 |
| 4(a)-8 | | 10/1/64 | | ” | | 4(a)-8 |
| 4(a)-9 | | 7/1/72 | | ” | | 4(a)-9 |
| 4(a)-10 | | 8/1/75 | | ” | | 4(a)-10 |
| 4(a)-11 | | 7/1/79 | | ” | | 4(a)-11 |
| 4(a)-12 | | 7/1/82 | | ” | | 4(a)-12 |
| 4(a)-13 | | 7/1/86 | | Form 10-K for fiscal ended
September 30,1986 | | 4(a)-13 |
E- 1
| | | | | | | |
| | | Sup. Ind. | | | | |
| | | Dated as of | | File Reference | | Exhibit |
| 4(a)-14 | | 10/1/88 | | Form 10-K for fiscal year ended September 30, 1986 | | 4(a)-14 |
| | | | | | | |
| 4(a)-15 | | 7/1/92 | | Form 10-K for fiscal year ended September 30, 1992 | | 4(a)-15 |
| | | | | | | |
| 4(a)-16 | | 7/1/93 | | Form 10-K for fiscal year ended September 30, 1993 | | 4(a)-16 |
| | | | | | | |
| 4(a)-17 | | 12/3/93 | | Form 10-K for fiscal year ended September 30, 1993 | | 4(a)-17 |
| | | | | | | |
| 4(a)-18 | | 11/1/96 | | Form 10-K for fiscal year ended September 30, 1997 | | 4(a)-18 |
| | | | | | | |
| 4(a)-19 | | 8/1/02 | | Form 10-K for fiscal year ended September 30, 2002 | | 4(a)-19 |
| | | |
| 4(c)-3 | | Trust Indenture and Security Agreement dated as of December 1, 2000 made by Bay Gas Storage Company, Ltd. (incorporated by reference to Exhibit 4(c)-3 to Form 10-Q for the quarter ended December 31, 2000) |
| | | |
| 4(c)-4 | | First Supplemental Indenture, dated as of August 1, 2007 and executed August 14, 2007, to the Trust Indenture and Security Agreement, dated December 1, 2000, among Bay Gas Storage Company, Ltd., Regions Bank, as trustee, and each of the institutions which is a signatory to the First Supplemental Indenture (incorporated by reference to Exhibit 4(c)-4 to Form 8-K dated August 21, 2007) |
| | | |
| 4(d) | | Promissory Note to the Utilities Board of the Town of Citronelle dated May 13, 1993 (incorporated by reference to Exhibit 4(d) to Form 10-K for fiscal year ended September 30, 1993) |
| | | |
| 10(a) | | Transportation agreement between Mobile Gas Service Corporation and Alabama Power Company dated February 18, 1999 (incorporated by reference to Exhibit 10(a) to Form 10-Q for the quarter ended March 31, 1999)(3) |
| | | |
| 10(b) | | Agreement for Firm and Interruptible Storage Service between Bay Gas Storage Company, Ltd. and Southern Company Services, Inc., as agent, dated April 1, 1999 (incorporated by reference to Exhibit 10(b) to Form 10-Q for the quarter ended March 31, 1999)(3) |
| | | |
| 10(b)-1 | | Letter agreement dated July 19, 2000, modifying Agreement for Firm and Interruptible Storage Services between Bay Gas Storage Company, Ltd. and Southern Company Services, Inc., as agent, dated April 1, 1999 (incorporated by reference to Exhibit 10(b)-1 to Form 10-K for fiscal year ended September 30, 2000)(3) |
| | | |
| 10(b)-2 | | Storage Service Agreement between Bay Gas Storage Company, Ltd. and Southern Company Services, Inc., as agent, dated as of August 1, 2000 (incorporated by reference to Exhibit 10(b)-2 to Form 10-K for fiscal year ended September 30, 2000)(3) |
| | | |
| 10(c) | | Agreement for Firm Intrastate Transportation Services between Bay Gas Storage Company, Ltd. and Alabama Power Company dated April 8, 1999 (incorporated by reference to Exhibit 10(c) to Form 10-Q for the quarter ended March 31, 1999)(3) |
E- 2
| | | |
| 10(c)-1 | | Letter agreement dated July 19, 2000, modifying Agreement for Firm Intrastate Transportation Services between Bay Gas Storage Company, Ltd. and Alabama Power Company dated April 8, 1999 (incorporated by reference to Exhibit 10(c)-1 to Form 10-K for fiscal year ended September 30, 2000) (3) |
| | | |
| 10(d)-5 | | NNS Settlement Agreement between Koch Gateway Pipeline Company and Mobile Gas Service Corporation dated March 26, 1998 (incorporated by reference to Exhibit 10(d)-5 to Form 10-K for fiscal year ended September 30, 1998) |
| | | |
| 10(e) | | Storage Service Agreement between Bay Gas Storage Company, Ltd. and Florida Power and Light Company dated as of July 19, 2005 (incorporated by reference to Exhibit 10(e) to Form 10-K for fiscal year ended September 30, 2005)(3) |
| | | |
| 10(f) | | Loan Agreement, dated as of August 1, 2007 and executed on August 15, 2007, between the Industrial Development Authority of Washington County and Bay Gas Storage Company, Ltd. (incorporated by reference to Exhibit 10(f) to Form 8-K dated August 21, 2007) |
| | | |
| 10(g) | | Deferred Compensation Agreement with John S. Davis dated January 26, 1996 (incorporated by reference to Exhibit 10(g) to Form 8-K Current Report dated February 7, 1996) |
| | | |
| 10(g)-1 | | Supplemental Deferred Compensation Agreement with John S. Davis dated December 10, 1999 (incorporated by reference to Exhibit 10(g)-1 to Form 10-K for fiscal year ended September 30, 1999)(2) |
| | | |
| 10(g)-2 | | Letter Agreement with John S. Davis dated July 6, 2006 (incorporated by reference to Exhibit 99.1 to Form 8-K filed July 7, 2006) (2) |
| | | |
| 10(h) | | Transportation Agreement between Mobile Gas and Mobile Energy LLC dated November 12, 1999 (incorporated by reference to Exhibit 10(h) to Form 10-K for fiscal year ended September 30, 1999)(3) |
| |
| 10(i) | | Mobile Gas Service Corporation/Bay Gas Storage Company, Ltd. Gas Storage Agreement dated February 26, 1992 (incorporated by reference to Exhibit 10(i) to Form 10-K for fiscal year ended September 30, 1992) |
| | | |
| 10(j) | | Directors/Officers Indemnification Agreement (incorporated by reference to Exhibit 10(j) to Form 10-K for fiscal year ended September 30, 1992) |
| | | |
| 10(j)-1 | | Form of Change of Control Agreement entered into as of December 8, 1999 by and between EnergySouth, Inc. and the Executive Officers of EnergySouth, Inc. and/or one or more of its subsidiaries (incorporated by reference to Exhibit 10(j)-1 to Form 10-K for fiscal year ended September 30, 1999)(2) |
| | | |
| 10(k)-1 | | Amended and Restated Supplemental Deferred Compensation Agreement with Walter L. Hovell, dated December 11, 1992 (incorporated by reference to Exhibit 10(k) to Form 10-K for fiscal year ended September 30, 1992) (2) |
| | | |
| 10(k)-2 | | Amendment to Amended and Restated Supplemental Deferred Compensation Agreement dated January 27, 1995 between the Company and Walter L. Hovell (incorporated by reference to Exhibit 10(k)-2 to Form 8-K Current Report dated January 27, 1995) (2) |
| | | |
| 10(l)-1 | | Bay Gas Agreement by and among Mobile Gas Service Corporation, MGS Storage Services, Inc., MGS Energy Services, Inc. and Olin Corporation, dated December 5, |
E- 3
| | | |
| | | 1991 (incorporated by reference to Exhibit 10(l) to Form 10-K for fiscal year ended September 30, 1992) |
| | | |
| 10(m)-1 | | Limited Partnership Agreement between MGS Storage Services, Inc., as General Partner, and MGS Energy Services, Inc., as Limited Partner (forming Bay Gas Storage Company, Ltd.), dated December 5, 1991 (incorporated by reference to Exhibit 10(m) to Form 10-K for fiscal year ended September 30, 1992) |
| | | |
| 10(m)-2 | | First Amendment to Limited Partnership Agreement dated as of April 6, 1992 and Second Amendment to Limited Partnership Agreement dated as of September 12, 1994 (incorporated by reference to Exhibit 10(m)-2 to Form 10-K for fiscal year ended September 30, 1994) |
| | | |
| 10(n)-1 | | Cavity Development and Storage Agreement between Olin Corporation and Bay Gas Storage Company, Ltd., dated January 14, 1992 (incorporated by reference to Exhibit 10(n) to Form 10-K for fiscal year ended September 30, 1992) |
| | | |
| 10(n)-2 | | Fourth Amendment to Cavity Development and Storage Agreement between Olin Corporation and Bay Gas Storage Company, Ltd., dated July 30, 2004 (incorporated by reference to Exhibit 10(n)-2 to Form 10-K for fiscal year ended September 30, 2004)(3) |
| | | |
| 10(n)-3 | | Amended and Restated Cavity Development and Storage Agreement by and between Bay Gas Storage Company, Ltd. and Olin Corporation dated May 22, 2007 (incorporated by reference to Exhibit 10(n)-3 to Form 10-Q for the quarter ended June 30, 2007)(3) |
| | | |
| 10(o)-1 | | Transportation Agreement between Mobile Gas Service Corporation and Tuscaloosa Steel Corporation dated as of May 15, 1995 (incorporated by reference to Exhibit 10(o) to Form 10-K for fiscal year ended September 30, 1995) (3) |
| | | |
| 10(o)-2 | | Amendment dated August 23, 1996 to Transportation Agreement between Mobile Gas Service Corporation and Tuscaloosa Steel Corporation (incorporated by reference to Exhibit 10(o)-2 to Form 10-K for fiscal year ended September 30, 1996)(3) |
| | | |
| 10(o)-3 | | Termination agreement dated July 28, 2005 between Mobile Gas Service Corporation and Tuscaloosa Steel Corporation (incorporated by reference to Exhibit 10(o)-3 to Form 10-K for fiscal year ended September 30, 2005) |
| | | |
| 10(p) | | Employment Agreement between EnergySouth, Inc. and C. S. Liollio dated October 27, 2006 (incorporated by reference to Exhibit 99.1 to Form 8-K filed October 30, 2006)(2) |
| | | |
| 10(p)-1 | | Restoration Pension Plan Agreement, dated as of February 1, 2007 and effective as of August 1, 2006, between EnergySouth, Inc. and C. S. “Dean” Liollio (incorporated by reference to Exhibit 99.1 to Form 8-K filed February 6, 2007)(2) |
| | | |
| 10(q)-1 | | Guaranty Agreement dated as of December 1, 2000 made by EnergySouth, Inc., relating to Trust Indenture and Security Agreement made by Bay Gas Storage Company, Ltd. (incorporated by reference to Exhibit 10(q)-1 to Form 10-Q for the quarter ended December 31, 2000) |
| | | |
| 10(r) | | Amended and Restated Stock Option Plan of EnergySouth, Inc. (incorporated by reference to Appendix A to definitive proxy statement dated December 17, 1998) (2) |
E- 4
| | | |
| | | |
| 10(r)-2 | | 2003 Stock Option Plan of EnergySouth, Inc. (incorporated by reference to Appendix A to definitive proxy statement dated December 23, 2003)(2) |
| | | |
| 10(s) | | Mobile Gas Service Corporation Incentive Compensation Plan (incorporated by reference to Exhibit B to definitive proxy statement dated December 21, 1992) (2)(4) |
| | | |
| 10(t) | | Agreement for Purchase and Sale of Assets by and between The Utilities Board of the Town of Citronelle and Mobile Gas Service Corporation dated January 28, 1993 (incorporated by reference to Exhibit 10(t) to Form 10-K for fiscal year ended September 30, 1993) |
| | | |
| 10(u) | | Storage Service Agreement by and between Bay Gas Storage Company, Ltd. and Tampa Electric Company made as of October 14, 2005 (incorporated by reference to Exhibit 10(u) to Form 10-Q for the quarter ended December 31, 2005) (3) |
| | | |
| 10(v)-1 | | Revolving Credit Agreement dated January 31, 2005 by and among EnergySouth, Inc. as Borrower, Regions Bank as Agent and Regions Bank, AmSouth Bank, and SouthTrust Bank as Lenders (incorporated by reference to Exhibit 10(v)-1 to Form 10-K for fiscal year ended September 30, 2005) |
| | | |
| 10(v)-2 | | Note for Business and Commercial Loans – Revolving, from EnergySouth, Inc. in favor or AmSouth Bank, now Regions Bank, in the principal amount of up to $20,000,000, dated November 7, 2006 (incorporated by reference to Exhibit 10.1 to Form 8-K filed November 13, 2006) |
| | | |
| 10(v)-3 | | Credit Agreement, dated as of August 14, 2007, by and among EnergySouth Inc., Bay Gas Storage Company, Ltd., and Regions Bank, as administrative agent for the lenders form time to time a party to the Credit Agreement (incorporated by reference to Exhibit 10(v)-3 to Form 8-K dated August 21, 2007) |
| | | |
| 10(v)-4 | | Parent Guarantee, made as of August 14, 2007, by EnergySouth, Inc., in favor of Regions Bank and the lenders from time to time a party to the Credit Agreement dated August 14, 2007 (incorporated by reference to Exhibit 10(v)-4 to Form 8-K dated August 21, 2007) |
| | | |
| 10(v)-5 | | Amended and Restated Credit Agreement, dated as of November 28, 2007, by and among EnergySouth, Inc., Bay Gas Storage Company, Ltd., and Regions Bank, as Administrative Agent for the lenders from time to time party to the Amended and Restated Credit Agreement (incorporated by reference to Exhibit 10(v)-5 to Form 8-K filed December 4, 2007) |
| | | |
| 10(v)-6 | | Amended and Restated Parent Guarantee, made as of November 28, 2007, by EnergySouth, Inc., in favor of regions Bank and the lenders from time to time a party to the Amended and Restated Credit Agreement dated November 28, 2007 (incorporated by reference to Exhibit 10(v)-6 to Form 8-K filed December 4, 2007) |
| | | |
| 10(v)-7 | | Subsidiary Guarantee, made as of November 28, 2007, by EnergySouth Midstream, Inc., EnergySouth Services, Inc. and MGS Marketing Services, Inc., in favor of Regions Bank, as Administrative Agent for the lenders from time to time party to the Amended and Restated Credit Agreement dated November 28, 2007 (incorporated by reference to Exhibit 10(v)-7 to Form 8-K filed December 4, 2007) |
| | | |
| 10(v)-8 | | Pledge Agreement made as of November 28, 2007, by EnergySouth, Inc., EnergySouth Midstream, Inc., EnergySouth Services, Inc., and MGS Marketing Services, Inc., in favor of Regions Bank, as Administrative Agent for the lenders from time to time party to the Amended and Restated Credit Agreement dated November |
E- 5
| | | |
| | | 28, 2007 (incorporated by reference to Exhibit 10(v)-8 to Form 8-K filed December 4, 2007) |
| | | |
| 10(w) | | Storage Service Agreement by and between Bay Gas Storage Company, Ltd. and Florida Power Corporation d/b/a Progress Energy Florida, Inc. made as of April 19, 2006 (incorporated by reference to Exhibit 10(w) to Form 10-Q for the quarter ended June 30, 2006) (3) |
| | | |
| 10(x) | | Letter dated October 7, 1994 from Mobile Gas Service Corporation to John S. Davis confirming terms of employment (incorporated by reference to Exhibit A to Form 8-K current report filed November 2, 1994) (2) |
| | | |
| 10(y) | | Storage Service Agreement by and between Bay Gas Storage Company, Ltd. and Constellation Energy Commodities Group, Inc. made as of May 23, 2006 (incorporated by reference to Exhibit 10(y) to Form 10-Q for the quarter ended June 30, 2006) (3) |
| | | |
| 10(z)-2 | | 2nd Amended and Restated EnergySouth, Inc. Non-Employee Directors Deferred Fee Plan (incorporated by reference to Exhibit 99.1 to Schedule S-8 filed April 1, 2004) (2) |
| | | |
| 10(aa) | | Employment Agreement between EnergySouth Midstream, Inc. and Ben J. Reese dated July 31, 2007(1) |
| | | |
| 14 | | Code of Business Conduct and Ethics (incorporated by reference to Exhibit 14 to Form 10-K for fiscal year ended September 30, 2003) |
| | | |
| 18 | | Letter regarding change in Accounting Principle (incorporated by reference to Exhibit 18 to Form 10-Q Quarterly Report dated February 12, 1999) |
| | | |
| 21 | | Subsidiaries of Registrant and Partnerships in which Registrant Owns an Interest(1) |
| | | |
| 23 | | Consent of Deloitte & Touche LLP(1) |
| | | |
| 31.1 | | Certifications Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 — Chief Executive Officer(1) |
| | | |
| 31.2 | | Certifications Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 — Chief Financial Officer(1) |
| | | |
| 32.1 | | Certification Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 — Chief Executive Officer(1) |
| | | |
| 32.2 | | Certification Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 — Chief Financial Officer(1) |
| | |
| (1) | | Filed herewith. |
| |
| (2) | | Management contract or compensatory plan or arrangement. |
E- 6
| | |
| (3) | | Confidential portions of this exhibit have been omitted and previously filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment made in accordance with Rule 24b-2 promulgated under the Securities Exchange Act of 1934, as amended. |
| |
| (4) | | Amended to use Company Common Stock instead of Mobile Gas common stock effective February 2, 1998. |
E- 7
