Item 1. Business.
General
EnergySouth, Inc. (together with its subsidiaries, the “Company” or “Registrant”, and exclusive of its subsidiaries, “EnergySouth”) was initially incorporated under the laws of the State of Alabama on September 5, 1997 for the primary purpose of becoming the holding company for Mobile Gas Service Corporation (“Mobile Gas”), a natural gas utility, and its subsidiaries. Effective February 2, 1998, Mobile Gas and its subsidiaries were reorganized (the “Reorganization”) into a holding company structure whereby Mobile Gas became a wholly-owned subsidiary of EnergySouth.
Mobile Gas was incorporated under the laws of the State of Alabama in 1933. Mobile Gas is engaged in the purchase, distribution, sale and transportation of natural gas to approximately 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 Services, Inc. (“Services”) was incorporated in March 1983. Through Services, the Company provides contract and consulting work for utilities and industrial customers. Services owns a 51% interest in Southern Gas Transmission Company (“SGT”), an Alabama general partnership which was formed in November 1991. SGT was established to provide transportation services to the facilities of Alabama River Pulp Company, Inc (“ARP”). During fiscal year 1992, SGT constructed and began operating a 50-mile pipeline from the facilities of Gulf South Pipeline Company (“Gulf South”) near Flomaton, Alabama to the facilities of ARP in Claiborne, Alabama.
MGS Marketing Services, Inc. (“Marketing”) was incorporated on March 5, 1993 to assist existing and potential customers in the purchase of natural gas. During fiscal year 2003, as existing contracts for marketing services expired, such contracts were not renewed by Marketing. As of September 30, 2005 and 2006, the Company was not actively engaged in activities previously conducted by Marketing.
In connection with the Reorganization, Services and Marketing became wholly-owned subsidiaries of EnergySouth during fiscal year 1998.
EnergySouth Storage Services, Inc. (“Storage”) was incorporated on December 4, 1991 as a wholly-owned subsidiary of Mobile Gas. Effective December 19, 2000, Storage became a wholly-owned subsidiary of EnergySouth. As of September 30, 2006 Storage held a general partnership interest of 90.9% in Bay Gas Storage Company, Ltd. (“Bay Gas”), an Alabama limited partnership, and a 9.1% limited partnership interest was held by Olin Corporation (“Olin”). Bay Gas owns and operates underground gas storage and related pipeline facilities which are used to provide storage and delivery of natural gas for Mobile Gas and other customers.
Business Segments
The Company’s operations are classified into the following business segments:
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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 and SGT.
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Natural Gas Storage - The Natural Gas Storage segment provides for the underground storage of natural gas and transportation services through the operations of Bay Gas and Storage. The storage operations are located in Southwest Alabama.
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Other - Includes merchandising, financing, and other energy-related services which are provided through Mobile Gas and Services, respectively, 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, 2006, 2005, and 2004, see Note 11 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, 2006, approximately 54% of the Company’s gas revenues were derived from residential sales, 18% from small commercial and industrial sales, 10% from large commercial and industrial sales, 7% from transportation services, and 11% from storage and miscellaneous services. Residential sales in fiscal 2006 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 11 to the Consolidated Financial Statements. The ten largest customers of the Company accounted for approximately 22% of the Company’s gross margin in fiscal 2006, with the largest accounting for approximately 9%.
EnergySouth is located at the crossroads of the expanding offshore natural gas production areas of the Central Gulf Coast and the developing gas-fired electric generation markets in the lower Southeast region of the United States. Mobile Gas provides transportation services to two gas-fired electric generating facilities which became operational in fiscal 2001. Bay Gas provides transportation services to three gas-fired electric generating facilities. During fiscal 1999 Bay Gas entered into storage contracts with electric utilities which fully subscribed the remaining space in its first storage cavern. During fiscal 2000 Bay Gas entered into a long term contract with Southern Company Services, Inc., as agent for a number of electric utility subsidiaries of Southern Company, to provide storage capacity of up to 3.2 million MMBtu of natural gas for those subsidiaries. To accommodate this contract, Bay Gas constructed a second underground storage cavern as discussed in “Gas Storage” below. During fiscal 2004, the remaining portion of the second cavern was fully subscribed on a firm basis, primarily through additional storage contracts with various electric utility customers.
Bay Gas held a non-binding “open season” in fiscal 2004 to assess interest for up to 5.0 Bcf of additional working gas capacity. Based on the response to the open season, Bay Gas began construction on a third storage cavern and related facilities. It has also entered into multi-year contracts with customers for the planned third cavern capacity. The third cavern is designed to add 5.0 Bcf of working gas capacity and is presently anticipated to be in service by the fall of 2007.
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 new pipeline interconnects with Transco and SONAT interstate natural gas pipelines. Bay Gas is currently communicating with respondents in an effort to secure agreements for firm storage services. Bay Gas plans to move forward with development of the fourth and fifth caverns and the two new 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 SONAT and Transco pipeline systems will allow additional prospective customers to access Bay Gas. These interstate pipeline systems serve 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.
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, 2007 and Exxon Mobil through November 30, 2007 through Mobile Gas’ direct connection with the Hatters Pond processing plant. For the fiscal year ended September 30, 2006, the Company obtained approximately 51% of its gas supply from sources located in the Mobile Bay area, with the balance being obtained from interstate sources.
Mobile Gas has a current peak day firm requirement of 105,000 MMBtus. Firm supply needs of 80,000 MMBtu/day are expected to be met through the withdrawal of gas from the storage facility owned by Bay Gas. The Company has contracted for firm transportation and storage service (“No-Notice Service”) for 24,000 MMBtu/day from Gulf South under an agreement effective through March 31, 2011. The gas supply requirement for the No-Notice Service is met through a contract with BP Energy Company through March 31, 2007.
Gas Storage
Construction of Bay Gas’ first storage cavern and facilities was completed in 1994. At September 30, 2006, the first cavern had the capacity to hold up to 3.2 million MMBtu of natural gas. Approximately 0.9 million MMBtu of the gas injected into the storage cavern, called “base gas,” remains in the cavern to provide sufficient pressure to maintain cavern integrity, and the remainder, approximately 2.3 million MMBtu, represents working storage capacity, referred to as “working gas capacity”. In 1994 Mobile Gas entered into a gas storage agreement with Bay Gas under which Bay Gas agreed to provide storage of 0.8 million MMBtu of working gas capacity of the first cavern for an initial period of 20 years.
The construction of natural gas-fired electric generation facilities in the Southeast has provided opportunities to provide gas storage and transportation services. Construction of Bay Gas’ second storage cavern was completed and the cavern was placed into service April 1, 2003. Currently, the second storage cavern has a working gas capacity of 3.7 Bcf. Together, the two caverns at Bay Gas currently hold 6.0 Bcf, with injection and withdrawal capacity of 200 MMcf and 610 MMcf per day, respectively, and expansion of these caverns is currently planned to enable them to hold 7.0 Bcf. Such development will commence following completion of new cavern development and will be subject to certain operational considerations to avoid interruption of storage operations.
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 the fall of 2007. The addition of the third cavern and additional capacity development of the second cavern is currently planned to ultimately increase the total working gas capacity of Bay Gas to 12.0 Bcf and injection and withdrawal capacities to 450 MMcf per day and 1.2 Bcf per day, respectively.
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.
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 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.
Gas Storage Competition. A number of types of competitors may provide services like or in competition with those of Bay Gas. These include, among others, natural gas storage facilities, natural gas aggregators, and natural gas pipelines. Bay Gas believes that its strategic geographic location and its ability to charge market-based rates for interstate storage services will enable it to effectively compete with such competitors. See “Rates and Regulation” below.
Rates and Regulation
The natural gas distribution operations of Mobile Gas are under the jurisdiction of the Alabama Public Service Commission (“APSC”). The APSC approves rates which are intended to permit the recovery of the cost of service including a return on investment. Rates 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.
On June 10, 2002, the Alabama Public Service Commission (APSC) approved Mobile Gas’ request for the Rate Stabilization and Equalization (RSE) rate setting process to be effective October 1, 2002 through September 30, 2005, and thereafter unless modified or discontinued by APSC order. On June 14, 2005, the APSC issued an order to extend RSE on substantially the same basis from October 1, 2005 through September 30, 2009. In addition, absent an APSC order after that date modifying the RSE rate tariff, RSE shall continue in effect beyond September 30, 2009.
RSE is a ratemaking methodology also used by the APSC to regulate other public Alabama energy utilities. Rate adjustments, designed to decrease annual gas revenues by approximately $303,000 and increase annual gas revenues by approximately $1.7 million and $2.8 million, were implemented under the RSE
tariff effective December 1, 2005, 2004, and 2003, respectively. The December 1, 2005 rate adjustment resulted in decreased revenues 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 for the period. As such, Mobile Gas is allowed to earn a return on all of its assets with no exclusions. Increases are allowed only once each fiscal year, effective December 1, and cannot exceed four percent of prior-year revenues. Under RSE, the APSC has conducted reviews using fiscal year-to-date performance through January, April and July plus Mobile Gas’ budget projections to determine whether Mobile Gas’ return on equity was expected to be within the allowed range of 13.35% to 13.85% at the end of the fiscal year. No such adjustments were required for fiscal 2006 or through the July 2005 or 2004 test periods. Mobile Gas’ financial results for fiscal years 2005 and 2004 did, however, result in a return on equity above the allowed range. As a result, adjustments of $433,000 and $343,000 were made to fiscal year 2005 and fiscal year 2004 pre-tax earnings, respectively, such that the return on equity, as calculated for RSE purposes, equaled 13.6%, the midpoint of the allowed range, and a regulatory liability was recorded which reflected the amount owed to customers. Reductions in rates were made in fiscal year 2006 and 2005 which resulted in $433,000 and $343,000, respectively, being fully refunded to customers by the end of those respective fiscal years.
RSE limits the amount of Mobile Gas’ equity upon which a return is permitted to 60 percent of its total capitalization and provides for certain cost control measures designed to monitor Mobile Gas’ operations and maintenance (O&M) expense. Under the inflation-based cost control measurement established by the APSC, if a change in Mobile Gas’ O&M expense per customer falls within 1.5 percentage points above or below the change in the Consumer Price Index for All Urban Customers (index range), no adjustment is required. If the change in O&M expense per customer exceeds the index range, three-quarters of the difference is returned to customers through future rate adjustments. To the extent the change is less than the index range, Mobile Gas benefits by one-half of the difference through future rate adjustments. The increase in O&M expenses per customer was within the index range for the rate year ended September 30, 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 has approved a waiver of this RSE requirement and instead will allow this amount to be used to offset any potential required returns to customers should O&M expense per customer exceed the index range in future years.
In conjunction with the approval of RSE, the APSC approved an Enhanced Stability Reserve (ESR), beginning October 1, 2002, to which Mobile Gas may charge the full amount of: 1) extraordinary O&M expenses resulting from force majeure events such as storms, severe weather, and outages, when one such event results in more than $100,000 of additional O&M expense or a combination of two or more such events results in more than $150,000 of additional O&M expense during a fiscal year; or 2) losses of revenue from any individual industrial or commercial customer in excess of $100,000 during the fiscal year, if such losses cause Mobile Gas’ return on equity to fall below 13.35%. An initial ESR balance of $1.0 million was recorded October 1, 2002 and is being recovered from customers through rates. Subject to APSC approval, additional funding, up to a maximum reserve balance of $1.5 million, may be provided from any future non-recurring revenue should such revenue cause Mobile Gas’ return on equity for the fiscal year to exceed 13.85%. Following a year in which a charge against the ESR is made, the APSC allows for accruals to the ESR of no more than $15,000 monthly until the maximum funding level is achieved. The ESR balance of $1,000,000 at September 30, 2006 is included in the Consolidated Balance Sheet as part of Regulatory Liabilities.
In October 2000, the Corus Group plc (Corus, formerly known as British Steel) ceased operations of its Mobile facility and continued to pay Mobile Gas a minimum annual payment as required under the terms of its contract. On July 28, 2005, Corus elected to end the contract and make a termination payment as required by the terms of the contract. Under a Termination Agreement (Termination Agreement) between Mobile Gas and Corus, Corus 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. Prior to November 1, 2006, the adjustment was calculated monthly for the months of November through April and applied to customers’ bills in the same billing cycle in which the weather variation occurs. Effective November 1, 2006, Mobile Gas will accumulate 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.
The Mobile Gas rate tariffs include a purchased gas adjustment clause which allows it to pass on to its sales customers increases or decreases in gas costs from those reflected in its rate tariff charges. Adjustments under such clauses require periodic filings with the APSC but do not require a general rate proceeding. Under the purchased gas adjustment clause, Mobile Gas has a competitive fuel clause which gives it the right to adjust its rates to certain large customers in order to compete with alternative energy sources. Any margin lost as a result of competitive fuel clause adjustments is recoverable from its other customers.
Gas deliveries to certain industrial customers are subject to regulation by the APSC through contract approval. The operations of SGT, which consist only of intrastate transportation of gas, are also regulated by the APSC.
Bay Gas is a regulated utility governed under the jurisdiction of the APSC. As a regulated utility, Bay Gas’ intrastate storage contracts are subject to APSC approval. Operation of the storage cavern and well-head equipment are subject to regulation by the Oil and Gas Board of the State of Alabama. The APSC certificated Bay Gas as an Alabama gas storage public utility in 1992. Bay Gas provides substantial, long-term services for Mobile Gas and other customers that include storage and transportation of natural gas from interstate and intrastate sources. The APSC does not regulate rates for Bay Gas interstate gas storage and storage-related services. The Federal Energy Regulatory Commission (FERC), which has jurisdiction over interstate services, allows Bay Gas to charge market-based rates for such services. Market-based rates minimize regulatory involvement in the setting of rates for storage services and allow Bay Gas to respond to market conditions. Bay Gas also provides interstate transportation-only services. The FERC last issued orders on October 11, 2001 and June 3, 2002 approving rates for such services. On March 9, 2004, in accordance with FERC filing requirements, Bay Gas filed a petition with the FERC requesting approval of new rates for transportation-only service. On April 14, 2006, in response to Bay Gas’ petition for new rates, the FERC issued an order which does not have a significant impact on Bay Gas’ earnings.
Mobile Gas has been granted nonexclusive franchises to construct, maintain and operate a natural gas distribution system in the areas in which it operates. Except for the franchise granted by Mobile County, Alabama, which has no stated expiration date, the franchises have various expiration dates, the earliest of which is in 2007. The Company has no reason to believe that the franchises will not be renewed upon expiration.
Seasonal Nature of Business
The nature of the Company’s business is highly seasonal and temperature-sensitive. As a result, the Company’s operating results in any given period have historically reflected, in addition to other matters, the impact of weather, with colder temperatures resulting in increased sales by the Company. The substantial impact of this sensitivity to seasonal conditions has been reflected in the Company’s results of operations. As discussed above under “Rates and Regulation”, the application of a temperature rate adjustment in customers’
bills beginning in November 1996 has helped to level out the effects of temperature extremes on results of operations.
Due to the seasonality of the Company’s business, the generation of working capital is impaired during the summer months because of reduced gas sales. Cash needs during this period are met generally through short-term financing arrangements or the reduction of temporary investments as is common in the industry.
Environmental Issues
The Company is subject to various federal, state and local laws and regulations relating to the environment, which have not had a material effect on the Company’s financial position or results of operations.
Like many gas distribution companies, prior to the widespread availability of natural gas, the Company manufactured gas for sale to its customers. In contrast to some other companies which operated multiple manufactured gas plants, the Company and its predecessor operated only one such plant, which discontinued operations in 1933. The process for manufacturing gas produced by-products and residuals, such as coal tar, and certain remnants of these residuals are sometimes found at former gas manufacturing sites.
The Alabama Department of Environmental Management (“ADEM”) has conducted a Brownfield Site Inspection of the property. On January 5, 2005, ADEM released a “CERCLA Targeted Brownfield Site Inspection” report on the manufactured gas plant site. Mobile Gas had discussions with ADEM to identify steps necessary to obtain ADEM’s concurrence with Mobile Gas’ plans for the site. The Company 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.
Employees
Mobile Gas employed 248 full-time employees as of September 30, 2006. Of these, approximately 37.5% are represented by the Paper, Allied-Industrial, Chemical and Energy Workers International Union, Local No. 3-0541. As of September 30, 2006 Bay Gas employed 12 full-time employees. The Company believes that it enjoys generally good labor relations.
Available Information
The Company’s internet address is www.energysouth.com. The Company makes available free of charge on or through its Internet Web site its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after the Company electronically files such material with, or furnishes it to, the Securities and Exchange Commission.
Item 1A.
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 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.
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 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 and natural gas storage 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.
Item 1B. Unresolved Staff Comments.
None.
Item 2.
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, 2006.
Item 3.
Item 3. Legal Proceedings.
The Company is involved in litigation arising in the normal course of business. Management believes that the ultimate resolution of such litigation will not have a material adverse effect on the consolidated financial statements of the Company.
Item 4.
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 2006.
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 2007 Annual Meeting of Stockholders and is incorporated herein by reference.
The following is a list of names and ages of all of the executive officers who are not also directors or nominees for election as directors of the Registrant indicating all positions and offices with the Registrant held by each such person and each such person’s principal occupations or employment during the past five years. Officers are appointed by the Board of Directors of the Company.
Business Experience
Name, Age, and Position
During Past 5 Years
G. Edgar Downing, Jr., 50 *
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, Vice President and Secretary - EnergySouth Services, Inc,; Director, Vice President and Secretary - EnergySouth Services, Inc.; Vice President and Secretary - MGS Marketing Services, Inc.; Director, Vice President and Secretary - MGS Storage Services, Inc.
Secretary, General Counsel and Vice President of Administration - Mobile Gas Service Corporation; Director, Vice President and Secretary - EnergySouth Services, Inc,; Director, Vice President and Secretary - EnergySouth Services, Inc.; Vice President and Secretary - MGS Marketing Services, Inc.; Director, Vice President and Secretary - MGS Storage Services, Inc.
Susan P. Stringer, 45
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);
LaBarron N. McClendon, 42 Vice President Human Resources - EnergySouth, Inc.
Appointed in December 2001
Vice President Human Resources - Mobile Gas Service Corporation
Appointed December 2001; Previously: Director Human Resources - Mobile Gas Service Corporation (1999 - 2001); Manager Human Resources - Mobile Gas Service Corporation (1998 - 1999);
*
Mr. Downing is the son-in-law of Gaylord C. Lyon, a Director of the Company.
PART II
Item 5.
Item 5. Market for the Registrant’s Common Stock Equity and Related Stockholder Matters.
The Registrant’s Common Stock, $.01 par value, is traded on the NASDAQ National Market under the symbol “ENSI”. As of December 1, 2006 there were 1,210 holders of record of the Company’s Common Stock. Information regarding Common Stock dividends and the bid price range for Common Stock during the periods indicated is as follows:
While the Board of Directors intends to continue the practice of paying dividends quarterly, amounts and dates of such dividends as may be declared will be dependent upon the Registrant’s future earnings, financial requirements, and other factors.
The Registrant’s long-term debt instruments contain certain debt to equity ratio requirements and restrictions on the payment of cash dividends and the purchase of shares of its capital stock. None of these requirements is expected to have a significant impact on the Registrant’s ability to pay dividends in the future.
Item 6
Item 6 - EnergySouth, Inc. - Selected Financial Data
FINANCIAL SUMMARY
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation.
The Company
EnergySouth, Inc. (EnergySouth) is the holding company for a family of energy businesses. EnergySouth and its consolidated subsidiaries are collectively referred to herein as the “Company.” Mobile Gas Service Corporation (Mobile Gas) purchases, sells, and transports natural gas to residential, commercial, and industrial customers in Mobile, Alabama and surrounding areas. The Company also provides merchandise sales, service, and financing. EnergySouth Storage Services (Storage) is the general partner of Bay Gas Storage Company (Bay Gas), a limited partnership that provides underground storage and delivery of natural gas for Mobile Gas and other customers. EnergySouth Services (Services) is the general partner of Southern Gas Transmission Company (SGT), which is engaged in the intrastate transportation of natural gas.
Summary
Consolidated Net Income
All earnings per share amounts referred to herein are computed on a diluted basis. Earnings per share increased $0.02, or 1%, in fiscal 2006 as compared to fiscal 2005. Fiscal year 2005 earnings per share increased $0.14, up 9% from fiscal 2004. Financial information by business segment is shown in Note 11 to the Consolidated Financial Statements.
2006 vs 2005 Earnings 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 natural gas storage business, operated by Bay Gas, contributed increased earnings of $0.16 per diluted share in fiscal 2006 as compared to fiscal year 2005. The positive earnings contribution is due to increased storage revenues associated with new agreements for long-term and short-term storage services and an increase in the amount of interest capitalized during the construction and development of the third underground natural gas storage cavern.
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.
2005 vs 2004 Earnings from the Company’s natural gas distribution business increased $0.02 per diluted share during fiscal year 2005, primarily from its Mobile Gas subsidiary. Mobile Gas’ earnings were positively impacted by rate adjustments which became effective December 1, 2004 and 2003 based upon the guidelines established under the Rate Stabilization and Equalization (RSE) tariff. For further information on RSE, see “Natural Gas Distribution” below and Note 2 to the Consolidated Financial Statements.
The Company’s natural gas storage business, operated by Bay Gas, contributed increased earnings of $0.11 per diluted share during fiscal 2005, an increase of 22% as compared to fiscal 2004. The positive earnings contribution was due primarily to additional storage revenues associated with long and short-term storage agreements entered into during fiscal 2005. The increased revenues were partially offset by additional operating costs as a result of the expansion activities of Bay Gas.
Earnings from other business operations increased $0.01 per diluted share during fiscal 2005 due primarily to an increase in interest income from temporary investments and an increase in merchandising and related activities due to additional sales volumes in fiscal 2005 and provisions for bad debts recorded in fiscal 2004.
Results Of Operations
Natural Gas Distribution
The natural gas distribution segment of the Company is actively engaged in the distribution and transportation of natural gas to residential, commercial and industrial customers in southwest Alabama through Mobile Gas and SGT.
The Alabama Public Service Commission (APSC) regulates the Company’s gas distribution operations. Mobile Gas’ rate tariffs for gas distribution allow rate adjustments to 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 continued to rise 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 years 2004, 2005, and into 2006 has had a negative impact on the Company’s overall margins, in aggregate dollars, through 1) energy conservation efforts that reduce consumption and 2) loss of customers due to non-payment of bills. Since the winter of 2000-2001, when the commodity price of natural gas first rose to unprecedented levels, Mobile Gas has experienced negative net growth in customers served. Customer counts as of the end of the fiscal year declined approximately 0.7%, 1.1%, and 1.4% in fiscal years 2006, 2005, and 2004, respectively. While Mobile Gas continues to expand its service territory by adding new mains and services, these additions have been more than offset by the number of customers who have left the system. Mobile Gas is focused on improving net customer growth through strategies that are directed at 1) increasing natural gas appliances in new and existing customers’ homes, 2) seeking high-value commercial customers that use natural gas for purposes other than space heating, 3) retaining customers by marketing the benefits of gas appliances and identifying and targeting those customers who may be at risk for leaving the system or converting to alternative fuels, and 4) minimizing the effects of volatility of natural gas prices in customers’ bills.
Mobile Gas follows a gas purchasing strategy to secure prices for a portion of its gas supply needs for the winter heating season by locking in gas prices at fixed rates. Mobile Gas’ strategy for purchasing gas and the Company’s use of natural gas storage capacity is designed to reduce the impact of volatility in gas prices on customers’ bills. However, Mobile Gas has had to adjust its rates to reflect the increased gas costs paid to its suppliers in recent years, particularly after Hurricanes Katrina and Rita. Mobile Gas has since reduced the gas cost component of its rates as the 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 utilities. Rate adjustments, designed to decrease annual gas revenues by approximately $303,000 and increase annual gas revenues by approximately $1.7 million and $2.8 million, were implemented under the RSE tariff effective December 1, 2005, 2004, and 2003, respectively. The December 1, 2005 rate adjustment resulted in decreased revenues 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 for the period. As such, Mobile Gas is allowed to earn a return on all of its assets with no exclusions. Increases are allowed only once each fiscal year, effective December 1, and cannot exceed four percent of prior-year revenues. Under RSE, the APSC has conducted reviews using fiscal year-to-date performance through January, April and July plus Mobile Gas’ budget projections to determine whether Mobile Gas’ return on equity was expected to be within the allowed range of 13.35% to 13.85% at the end of the fiscal year. No such adjustments were required for fiscal 2006 or through the July 2005 or 2004 test periods. Mobile Gas’ financial results for fiscal years 2005 and 2004 did, however, result in a return on equity above the allowed range. As a result, adjustments of $433,000 and $343,000 were made
to fiscal year 2005 and fiscal year 2004 pre-tax earnings, respectively, such that the return on equity, as calculated for RSE purposes, equaled 13.6%, the midpoint of the allowed range, and a regulatory liability was recorded which reflected the amount owed to customers. Reductions in rates were made in fiscal year 2006 and 2005 which resulted in $433,000 and $343,000, respectively, being fully refunded to customers by the end of those respective fiscal years. See Notes 1 and 2 to the Consolidated Financial Statements.
RSE limits the amount of Mobile Gas’ equity upon which a return is permitted to 60 percent of its total capitalization and provides for certain cost control measures designed to monitor Mobile Gas’ operations and maintenance (O&M) expense. Under the inflation-based cost control measurement established by the APSC, if a change in Mobile Gas’ O&M expense per customer falls within 1.5 percentage points above or below the change in the Consumer Price Index for All Urban Customers (index range), no adjustment is required. If the change in O&M expense per customer exceeds the index range, three-quarters of the difference is returned to customers through future rate adjustments. To the extent the change is less than the index range, the utility benefits by one-half of the difference through future rate adjustments. The increase in O&M expenses per customer was within the index range for the rate year ended September 30, 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 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 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.
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 will accumulate 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.
Natural gas distribution revenues increased $9,223,000 (9%) and $6,921,000 (7%), respectively, during fiscal 2006 and 2005 due primarily to the rate adjustments to recover increased gas costs paid to suppliers. Revenues also increased during fiscal 2005 as a result of the RSE rate adjustment that went into effect on December 1, 2004. Financial information about the distribution segment is shown in Note 11 to the Consolidated Financial Statements.
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 extent by temperatures during the heating season, increased $7,271,000 (8%) and $5,035,000 (6%), respectively, during fiscal 2006 and 2005 due to the rate adjustments discussed above. During fiscal 2006 and fiscal 2005, 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. Additionally, in fiscal 2005, temperatures during the winter heating season were 16% warmer than normal. As a result, volumes
delivered to temperature-sensitive customers declined 7% and 12% in fiscal 2006 and fiscal 2005, respectively.
Revenues from the sale of natural gas to large commercial and industrial customers increased $1,994,000 (19%) and $1,806,000 (21%) during fiscal 2006 and 2005, respectively, due to increases in the price of natural gas and the RSE adjustment during fiscal 2005. Volumes delivered to these customers declined 7% in fiscal 2006 due primarily to higher natural gas prices. In fiscal 2005, volumes increased 2.5% due to increased usage by interruptible customers.
Revenues from the transportation of natural gas to large commercial and industrial customers decreased less than 1% during fiscal 2006 and increased less than 2% during fiscal 2005 as volumes delivered to these customers were relatively flat. Beginning in fiscal 2006, transportation revenues included a decrease of approximately $195,000 as a result of the Termination Agreement discussed above and in Note 2 to the Consolidated Financial Statements.
The cost of natural gas increased $10,101,000 (20%) and $5,774,000 (13%), respectively, for fiscal years 2006 and 2005 due to higher natural gas commodity prices.
Natural gas distribution margins, defined as revenues less cost of gas and related taxes, declined 3% during fiscal 2006. 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. During fiscal 2005, margins increased 2% primarily as a result of the RSE rate adjustments. The increase in margins realized from the rate adjustments in fiscal 2005 were largely offset by the decline in customers served and a decline in usage per degree-day by temperature-sensitive customers. Residential customer consumption, when adjusted for weather variations, declined 11% and 6%, respectively, in fiscal 2006 and 2005. Consistent with other natural gas distribution companies in the United States, Mobile Gas has over time experienced declines in residential customer usage per degree-day as customers replace old appliances with new, more energy efficient models and as new, more energy efficient homes are built. Contrary to the general trend, consumption by residential customers in fiscal 2004, when adjusted for weather, trended up from prior periods. However, during fiscal 2005, the decline in consumption by these customers returned to the trend in customer consumption as experienced in recent years. Management believes that the decline in fiscal 2006 was also attributable to the high natural gas prices experienced during the fall and winter of 2005-2006 after Hurricane Katrina and unusually warm weather in January 2006. Additionally, 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 $731,000 (3.5%) during fiscal 2006 due in part to expenses 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. Effective August 1, 2006, Mr. C. S. Liollio became President and Chief Executive Officer of the Company. Additionally, O&M expenses increased 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 incurred to evaluate and select software alternatives for a new customer information system (CIS) to be implemented in 2007, and an increase in the bad debt provision 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 no longer provides term life insurance benefit for retirees. The settlement of the postretirement benefit obligation resulted in a net credit to expense of approximately $97,000.
Operations and maintenance (O&M) expenses decreased $80,000 during fiscal 2005. This resulted from lower payroll costs because of the elimination of sixteen positions during fiscal 2004, lower service and main repair costs which were unusually high in fiscal 2004, and the recording of a $200,000 remediation liability in fiscal 2004 related to a former manufactured gas plant. See Note 9 to the Consolidated Financial
Statements. Partially offsetting these reductions were increased benefit costs and additional audit fees associated with the review and testing of the Company’s internal controls in compliance with Section 404 of the Sarbanes Oxley Act of 2002.
Depreciation expense increased $354,000 (5%) and $342,000 (5%), respectively, for fiscal 2006 and 2005 due to Mobile Gas’ increased investment in property, plant and equipment.
Other taxes primarily consist of property taxes and business license taxes that are based on gross revenues and fluctuate accordingly. Other taxes increased $659,000 (9%) and $366,000 (5%), respectively, for fiscal year 2006 and 2005 due primarily to the increased revenues discussed above.
Interest expense decreased $248,000 (9%) and $355,000 (11%), respectively, for fiscal 2006 and 2005 due to principal payments on long-term debt.
Minority interest reflects the minority partner’s share of pre-tax earnings of the SGT partnership, of which EnergySouth’s subsidiary holds a controlling interest. Minority interest decreased $33,000 (25%) and $21,000 (14%), respectively, for fiscal 2006 and 2005 due to a decline in pre-tax earnings of the partnership.
Natural Gas Storage
The natural gas storage segment provides for the underground storage of natural gas and transportation services through the operations of Bay Gas. The APSC certificated Bay Gas as an Alabama natural gas storage public utility in 1992. Through its first storage cavern with 2.3 Bcf of working gas capacity and connected pipeline, Bay Gas thereafter began providing substantial, long-term services for Mobile Gas and other customers that include storage and transportation of natural gas from interstate and intrastate sources. The APSC does not regulate rates for Bay Gas’ interstate gas storage and storage-related services. The Federal Energy Regulatory Commission (FERC), which has jurisdiction over interstate services, allows Bay Gas to charge market-based rates for such services. Market-based rates minimize regulatory involvement in the setting of rates for storage services and allow Bay Gas to respond to market conditions. Bay Gas also provides firm and interruptible interstate transportation-only services. The FERC last issued 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. On April 14, 2006, the FERC issued an order regarding Bay Gas’ petition for new rates which does not have a significant impact on Bay Gas’ earnings.
The construction of natural gas-fired electric generation facilities in the Southeast has provided opportunities to provide gas storage and transportation services. Construction of Bay Gas’ second storage cavern was completed and the cavern was placed into service April 1, 2003. Currently, the second storage cavern has a working gas capacity of 3.7 Bcf. Together, the two caverns at Bay Gas currently hold 6.0 Bcf, with injection and withdrawal capacity of 200 MMcf and 610 MMcf per day, respectively, and expansion of these caverns is currently planned to enable them to hold 7.0 Bcf. Such development will commence following completion of new cavern development and will be subject to certain operational considerations to avoid interruption of storage operations.
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 the fall of 2007. The addition of the third cavern and additional capacity development of the second cavern is currently planned to ultimately increase the total working gas capacity of Bay Gas to 12.0 Bcf and injection and withdrawal capacities to 450 MMcf per day and 1.2 Bcf per day, respectively.
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 and SONAT. Bay Gas is currently communicating with respondents in an effort
to secure agreements for firm storage services. Bay Gas plans to move forward with development of caverns four and five and the pipeline interconnects subject to its ability to execute sufficient firm storage agreements with the interested parties.
Bay Gas’ revenues increased $1,491,000 (8%) and $1,590,000 (9%) during fiscal 2006 and 2005, respectively. See Note 11 to the Consolidated Financial Statements for segment disclosure. Revenues increased in fiscal 2006 and 2005 due to new long-term and short-term storage agreements. Under the short-term agreements, available working gas capacity is leased to customers on an interruptible basis, thereby optimizing the use of cavern capacity. Financial information about the storage segment is shown in Note 11 to the Consolidated Financial Statements.
Operations and maintenance (O&M) expenses decreased $59,000 (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 of the Consolidated Financial Statements below. These decreases 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.
O&M expenses increased $297,000 (10%) during fiscal 2005 due to increases in operating costs as a result of the expansion activities of Bay Gas.
Depreciation expense increased $127,000 (4%) and $68,000 (3%) in fiscal year 2006 and 2005, 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 $27,000 (3%) and $24,000 (3%), respectively, in fiscal 2006 and 2005.
Interest expense decreased $175,000 (4%) and $213,000 (5%), respectively, in fiscal years 2006 and 2005 due to principal payments on long-term debt.
Capitalized interest costs increased $776,000 and $174,000 in 2006 and 2005, 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, of which EnergySouth’s subsidiary holds a controlling interest. Minority interest increased $208,000 (26%) and $154,000 (24%), respectively, during fiscal 2006 and 2005 due to increased pre-tax earnings of the limited partnership.
Other
Through Mobile Gas and EnergySouth Services, Inc., the Company provides merchandising, financing, and other energy-related services, which are aggregated with EnergySouth, the holding company, to comprise the Other category. See Note 11 to the Consolidated Financial Statements for segment disclosure.
Income before income taxes from Other business activities increased $559,000 and $181,000 in fiscal 2006 and 2005, respectively, due primarily to interest income earned from temporary investments and an increase in earnings from merchandise sales and related activities.
Income Taxes
Income taxes fluctuate with the change in income before income taxes. The Company’s effective tax rate in 2006, 2005, and 2004 was 38.3%, 39.4%, and 37.7%, 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 is to maintain a reliable long-term supply and provide gas at the lowest possible cost. 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 commitments for future gas purchases at fixed prices meet the requirements of paragraph 10.b, Normal Purchases and Normal Sales, Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended by SFAS No. 149. Thus, the commitments for future purchases of natural gas at fixed prices are deemed to be purchases in the normal course of business and are not subject to 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: 2007 - $22,572,000; 2008 - $1,376,000; 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 with Bay Gas to receive storage services for an initial period through 2014. Mobile Gas’ purchased gas adjustment provision in rate tariffs filed with the APSC allows a recovery of demand and commodity costs of purchased gas from customers. Should Mobile Gas’ customer base decline due to deregulation or other reasons, resulting in costs related to firm gas supply in excess of requirements, Mobile Gas believes it would be able to take one or more of the following actions: as part of the regulatory decision allowing other suppliers to serve current customers, secure the right to allocate firm gas supply costs to the new company supplying gas; reduce some excess gas supply costs through a negotiated settlement with suppliers; and/or pass-through excess gas supply costs to existing customers through the purchased gas component of customers’ rates.
Environmental
The Company is subject to various federal, state and local laws and regulations relating to the environment, which have not had a material effect on the Company’s financial position or results of operations. See Note 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 $24.9 million, $30.8 million, and $26.9 million in 2006, 2005, and 2004, respectively. Cash provided from operating activities decreased $5.9 million in 2006 as compared to 2005 due to a decrease in taxes payable, an under-collection of increased gas costs from customers and the settlement of postretirement benefits upon the termination of life insurance benefits for retirees. These decreases in
cash flow were partially offset by a decline in accounts receivable and an increase in deferred taxes. Cash provided from operating activities increased $3.9 million in 2005 as compared to 2004 due primarily to collections of increased gas costs from customers, an increase in net income, and an increase in payables, including taxes. Partially offsetting the above positive impacts on cash flow from operating activities was an increase in gas inventory stored underground, an increase in accounts receivable, and a decrease in deferred income taxes.
Cash used in investing activities reflects the capital-intensive nature of the Company’s business. During 2006, 2005, and 2004, the Company used cash of $24.5 million, $16.6 million, and $8.6 million, respectively, primarily for the construction of distribution and storage facilities, purchases of equipment and other general improvements. 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 the third cavern. During fiscal 2005, Bay Gas invested $7.3 million in the ongoing construction of the third cavern and the completion of a pipeline interconnect project.
The Company expects fiscal 2007 capital expenditures by Mobile Gas to be approximately $14.8 million and by Bay Gas to be approximately $34.2 million. Mobile Gas’ projected 2007 expenditures include normal construction activity, including equipment purchases and other general improvements and will be funded by internal cash generation and short- and long-term borrowings. Bay Gas’ anticipated capital expenditures include ongoing development of a third salt-dome storage cavern designed to provide 5.0 Bcf of working gas capacity and the expansion of injection and withdrawal capabilities. Bay Gas’ projected expenditures for 2007 also include the planned development of a fourth storage cavern designed to provide 5.0 Bcf of working gas capacity. The expansion of storage facilities is expected to be funded through internal cash generation and the issuance of long-term debt.
Financing activities used cash of $7.2 million, $14.1 million, and $13.1 million in fiscal 2006, 2005, and 2004, respectively. Long term debt payments and the payment of quarterly dividends account for most of the cash used in each year. Dividend payments of $7.1 million, $6.5 million, and $6.1 million in fiscal 2006, 2005, and 2004, respectively, were offset by dividend reinvestment of $0.4 million in each fiscal year. Fiscal 2006, 2005, and 2004 included additional optional principal payments of $0.6 million, $1.9 million and $1.7 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, $0.6 million, and $0.7 million in fiscal 2006, 2005, and 2004, respectively, from the exercise of stock options partially offset the cash used in financing activities.
Funds for the Company’s short-term cash needs are expected to come from cash provided by operations and borrowings under the Company’s $20,000,000 revolving credit agreement which extends through February 28, 2007. At September 30, 2006 the Company had $14.7 million available for borrowing on its revolving credit agreement. The Company pays a fee for its committed lines of credit rather than maintain compensating balances. The commitment fee is 0.125% of the average daily unborrowed amount during the annual period of calculation. Effective November 7, 2006, the Company entered into a short term unsecured loan agreement whereby the Company has the ability to borrow up to an additional $20,000,000 as needed. The rate is the same as the line of credit and matures on February 28, 2007, the renewal date of the line of credit. Additional funds in an aggregate amount of $1,350,000 were paid to the Company in fiscal 2007 in accordance with the terms of the Termination Agreement as discussed in Note 2 to the Consolidated Financial Statements. The Company believes it has adequate financial flexibility to meet its expected cash needs in the foreseeable future.
The table below summarizes the Company’s contractual obligations and commercial commitments as of September 30, 2006:
Off-Balance Sheet Arrangements
The Company has no “off-balance sheet arrangements” as such term is defined in Item 303(a)(4) of Regulation S-K.
Critical Accounting Policies
Regulatory Accounting. The Natural Gas Distribution segment is subject to regulation by the APSC and as such, accounts for its transactions according to the provisions of Statement of Financial Accounting Standards No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71). This statement sets forth the application of accounting principles generally accepted in the United States of America for those companies whose rates are established by or are subject to approval by an independent third party regulator. The provisions of SFAS 71 require, among other things, that financial statements of a regulated enterprise reflect the actions of regulators, where appropriate. The application of this accounting policy allows the Company to defer expenses and income on the consolidated balance sheet as regulatory assets and liabilities when it is probable that those expenses and income will be allowed in the rate setting process in a period different from the period in which they would have been reflected in the consolidated statements of income of an unregulated company. These deferred regulatory assets and liabilities are then recognized in the consolidated statement of income in the period in which the same amounts are reflected in rates. See Note 1 to the Consolidated Financial Statements.
If any portion of the Natural Gas Distribution segment ceased to continue to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet and included in the consolidated statement of income for the period in which the discontinuance of regulatory accounting treatment occurred.
Revenue Recognition. Mobile Gas recognizes revenues from the sales of natural gas and transportation services in the same period in which it delivers the related volumes to customers. Sales revenues from residential and certain commercial and industrial customers are billed on the basis of scheduled meter reading cycles throughout the month. Mobile Gas records revenues for estimated deliveries of gas, not yet billed to these customers, from the meter reading date to the end of the accounting period. These revenues are included on the Company’s consolidated balance sheet as “Unbilled Revenue.” Included in the rates charged by Mobile Gas to temperature sensitive customers is a temperature rate adjustment rider which offsets the impact of unusually cold or warm weather on operating margin.
Reserves. EnergySouth companies establish reserves for uncollectible accounts receivable and slow moving merchandise, materials and supplies inventories. Such reserves are generally calculated based on currently available facts and on the application of a percentage to each aging category of receivables and inventory based on collection and sales experience, respectively. On certain specific receivables and inventory, the Company records an allowance based on currently available facts to reduce the net balance of the specific receivable or inventory item to the amount the Company reasonably expects to collect. Reserves for receivables are reported as “Allowance for Doubtful Accounts” on the balance sheet. Reserves for inventory are netted against the related asset account and reported on the balance sheet in “Materials, Supplies, and Merchandise.” The Company believes its reserves are adequate. However, actual results may differ from estimates, and estimates can be, and often are, revised either negatively or positively, depending upon actual outcomes or expectations based on the facts surrounding each potential exposure.
Employee Benefits. Employee benefits include a defined-benefit pension plan and other post-employment benefits for the benefit of substantially all full-time regular employees. Under the provisions of Statement of Financial Accounting Standards No. 87, “Employer’s Accounting for Pensions,” and Statement of Financial Accounting Standards No. 106, “Employer’s Accounting for Postretirement Benefits Other Than Pensions,” measurement of the obligations under the defined benefit pension plans and other 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, 2006, the discount rates used for pension and postretirement purposes were 6.00% and 5.75%, respectively. A hypothetical 25 basis point decrease in the annual discount rate would increase pension and postretirement benefit expense by $33,000 and $9,000, respectively. At September 30, 2006, the expected rates of return on assets for actuarial purposes were 8.25% and 7.75% for pension and post-retirement benefits, respectively. A hypothetical 25 basis point decrease in the expected rate of return on assets would increase pension and postretirement expense by $85,000 and $9,000, respectively. At September 30, 2006, 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 $29,000.
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; liability for remedial actions under environmental regulations; liability resulting from litigation; national and global economic and political
conditions; and changes in tax and other laws applicable to the business. Additional factors that may impact forward-looking statements include, but are not limited to, the Company’s ability to successfully achieve internal performance goals, competition, the effects of state and federal regulation, including rate relief to recover increased capital and operating costs, allowed rates of return and purchased gas adjustment provisions; general economic conditions, specific conditions in the Company’s service area, and the Company’s dependence on external suppliers, contractors, partners, operators, service providers, and governmental agencies.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Mobile Gas is exposed to market risks associated with commodity prices of natural gas. Mobile Gas ameliorates the price risk associated with purchases of natural gas by using a combination of natural gas storage services, fixed price contracts and spot market purchases. As part of Mobile Gas’ gas supply strategy, it has adopted a policy under which management is authorized to commit to future gas purchases at fixed prices up to a specified percentage of the normalized degree-day usage for any corresponding month as outlined within the policy. All commitments for future gas purchases at fixed prices meet the requirements of paragraph 10.b, Normal purchases and Normal sales, of Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended by SFAS No. 149. Thus, the commitments for future purchases of natural gas at fixed prices are deemed to be purchases in the normal course of business and are not subject to derivative accounting treatment.
At September 30, 2006, Mobile Gas had not entered into derivative instruments, other than those for gas supply purchases that are in the normal course of business, 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 will not affect future earnings or cash flows.
At September 30, 2006 the Company had approximately $77.0 million of long-term debt at fixed interest rates. Interest rates range from 6.9% to 9.0% and the maturity dates of such debt extend to 2022.
See also the information provided under the captions “The Company,” “Gas Supply,” and “Liquidity and Capital Resources” under Item 7 for a discussion of the Company’s risks related to regulation, weather, gas supply and prices, and the capital-intensive nature of the Company’s business.
Item 8.
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, which follows Part IV hereof.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A. Controls and Procedures
Conclusion Regarding Disclosure Controls and Procedures
As of the end of the period covered by this report, an evaluation was carried out, under the supervision and with the participation of the company’s President and Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), of the effectiveness of the design and operation of the Company’s disclosure controls and procedures. Based on the evaluation, the CEO and CFO concluded that the Company’s disclosure controls are effective in timely alerting them to material information required to be included in the Company’s periodic SEC reports.
Management’s Report On Internal Control Over Financial Reporting
The Management of EnergySouth, Inc. is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). EnergySouth Inc.’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Internal control over financial reporting includes those written policies and procedures that:
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 in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organization of the Treadway Commission (COSO). Management’s assessment included an evaluation of the design of EnergySouth Inc.’s internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Management reviewed the results of its assessment with the Audit Committee of our Board of Directors.
Based on our evaluation, Management concluded that EnergySouth, Inc.’s internal control over financial reporting was effective as of September 30, 2006. Deloitte & Touche LLP, an independent registered public accounting firm that audited the consolidated financial statements of EnergySouth, Inc. included in this report, have issued an attestation report on management’s assessment of the effectiveness of internal control over financial reporting as of September 30, 2006 as stated in their report which appears herein.
Changes in Internal Control Over Financial Reporting
The CEO and CFO have concluded that during the most recent fiscal quarter covered by this report there were no changes in internal controls over financial reporting that materially affected or are reasonably likely to materially affect internal controls over financial reporting.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of
EnergySouth, Inc.
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that EnergySouth, Inc. and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of September 30, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of September 30, 2006, is fairly stated, in all material respects, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2006, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended September 30, 2006 of the Company and our report dated December 1, 2006 expressed an unqualified opinion on those financial statements and financial statement schedule.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Atlanta, Georgia
December 1, 2006
PART III
Item 10.
Item 10. Directors, Executive Officers, and Control Persons of the Registrant.
Information under the captions “Election of Directors” and “Information Regarding the Board of Directors” contained in the Company’s definitive proxy statement with respect to its 2007 Annual Meeting of Stockholders is incorporated herein by reference.
For information with respect to executive officers of the Registrant, see “Executive Officers of the Registrant” at the end of Part I of this Report.
Information under the caption “Section 16(a) Beneficial Ownership Reporting Compliance” contained in the Company’s definitive proxy statement with respect to its 2007 Annual Meeting of Stockholders is incorporated herein by reference.
Code of Ethics
The Company has adopted a Code of Business Conduct and Ethics (the “Ethics Code”) that applies to the Company’s directors, officers, and employees, including its President and Chief Executive Officer, its Senior Vice President and Chief Financial Officer, and its Controller. The Company has posted the Ethics Code on its internet website at www.energysouth.com.
Audit Committee Financial Expert
The Board of Directors of the Company has determined that S. Felton Mitchell, Jr., who currently serves as the Chairman of the Audit Committee of the Company’s Board of Directors, and Walter L. Hovell are audit committee financial experts. Mr. Mitchell and Mr. Hovell are independent as defined in the listing standards of the National Association of Securities Dealers.
Item 11.
Item 11. Executive Compensation.
Information under the captions “Executive Compensation,” “Option Grants in Last Fiscal Year,” “Aggregated Option Exercises in Last Fiscal Year and 2006 Fiscal Year-End Option Values,” “Compensation Committee Report,” “Compensation Committee Interlocks and Insider Participation in Compensation Decisions” and “EnergySouth, Inc. Stock Performance Graph” and under the headings “Employees’ Retirement Plan,” Employee Savings Plan,” “Agreement with Mr. Liollio,” “Agreements with Mr. Davis,” “Change of Control Agreements” and “Other Compensation” contained in the Company’s definitive proxy statement with respect to its 2007 Annual Meeting of Stockholders is incorporated herein by reference.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
Information under the captions “Equity Compensation Plan Information” and “Security Ownership of Certain Beneficial Owners and Management” contained in the Company’s definitive proxy statement with respect to its 2007 Annual Meeting of Stockholders is incorporated herein by reference.
Item 13.
Item 13. Certain Relationships and Related Transactions.
There were no transactions required to be disclosed pursuant to this item.
Item 14.
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 2007 Annual Meeting of Stockholders is incorporated herein by reference.
PART IV
Item 15.
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, 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.
Signatures
Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the Undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the Capacities and on the dates indicated:
Signatures (Continued)
ENERGYSOUTH, INC.
AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
Schedules other than that referred to above are omitted and are not applicable or not required.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
EnergySouth, Inc.
We have audited the accompanying consolidated balance sheets of EnergySouth, Inc. and subsidiaries (the “Company”) as of September 30, 2006 and 2005, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended September 30, 2006. Our audits also included the financial statement schedule listed in the Index as Schedule II. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement 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, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended September 30, 2006, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of September 30, 2006, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated December 1, 2006 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Atlanta, Georgia
December 1, 2006
CONSOLIDATED STATEMENTS OF INCOME
EnergySouth, Inc.
See Accompanying Notes to Consolidated Financial Statements
CONSOLIDATED BALANCE SHEETS
EnergySouth, Inc.
See Accompanying Notes to Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
EnergySouth, Inc.
See Accompanying Notes to Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF CASH FLOWS
EnergySouth, Inc.
See Accompanying Notes to Consolidated Financial Statements
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The consolidated financial statements of EnergySouth, Inc. (EnergySouth) and its subsidiaries (collectively, the Company) include the accounts of Mobile Gas Service Corporation (Mobile Gas); EnergySouth Services, Inc. (Services); MGS Storage Services, Inc. (Storage); a 90.9% owned partnership, Bay Gas Storage Company, Ltd. (Bay Gas), and a 51% owned partnership, Southern Gas Transmission Company (SGT). Minority interest represents the respective other owners’ proportionate shares of the income and equity of Bay Gas and SGT. All significant intercompany balances and transactions have been eliminated.
Revenues and Gas Costs
Revenues are recorded when distribution services are provided to customers. Those revenues are based on rates approved by the Alabama Public Service Commission (APSC). The Company’s distribution segment reads meters on a monthly cycle basis and records revenues based upon estimated consumption through the end of the month for all customers regardless of the meter reading date.
Increases or decreases in the cost of gas and certain other costs are passed through to customers in accordance with provisions in the Company’s rate tariffs. Any over-or-under recoveries of these costs are charged or credited to cost of gas and included in the Deferred Purchased Gas Adjustment which is classified as part of Regulatory Assets and/or Liabilities within the Company’s Balance Sheet. See “Regulatory Assets and Liabilities” below.
The Company’s natural gas storage segment recognizes revenues when services are provided in accordance with contractual agreements for storage and transportation services. The agreements include fees for monthly storage of natural gas, fees for the injection and withdrawal of natural gas, and transportation of natural gas through Bay Gas’ system.
Property, Plant, and Equipment
Included in property, plant, and equipment are acquisition adjustments, net of amortization, of $5,415,000 and $5,774,000 at September 30, 2006 and 2005. 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, 2006, 2005, and 2004 approved depreciation rates averaged approximately 4.1% of depreciable property, excluding the gas storage facility which is depreciated at an annual rate averaging 2.7%.
Cash Equivalents
The Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents.
Income Taxes
The Company records deferred tax liabilities and assets, as measured by enacted tax rates, for all temporary differences caused when the tax basis of an asset or liability differs from that reported in the financial statements. Investment tax credits realized after 1980 are deferred and amortized over the average life of the related property in accordance with regulatory treatment.
Earnings Per Share
Basic earnings per share and diluted earnings per share are calculated by dividing net income by the weighted average common shares outstanding during the period and the weighted average common shares outstanding during the period plus potential dilutive common shares. Dilutive potential common shares are calculated in accordance with the treasury stock method, which assumes that proceeds from the exercise of all options are used to repurchase common stock at market value. The amount of shares remaining after the proceeds are exhausted represents the potentially dilutive effect of the securities. A reconciliation of the weighted average common shares and the diluted average common shares is provided below:
Stock option awards to purchase approximately 146,000, 76,000 and 72,000 shares as of September 30, 2006, 2005, and 2004, respectively, were not included in the computation of diluted earnings per share because inclusion of these shares would have been antidulitive during these periods.
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):
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.
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:
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 March 2005, the FASB issued Financial Interpretation No. 47 (FIN47) to clarify the term “conditional asset retirement obligation” as used in Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.” Conditional asset retirement obligation refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred - generally, upon acquisition, construction, development and/or through the normal operation of the asset. Uncertainty about the timing and/or method of settlement should be factored into the measurement of the liability when sufficient information exists, but is not a basis upon which to avoid liability recognition. See Note 4 to the Consolidated Financial Statements for disclosure of the adoption of FIN 47 as of September 30, 2006.
In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections”, a replacement of Accounting Principle Board (APB) Opinion No. 20 and SFAS No. 3. SFAS 154 applies to all voluntary changes in accounting principle and changes the requirements for accounting for and reporting of a change in accounting principle. Retrospective application to prior period’s
financial statements of the change in accounting principle is required unless it is impracticable. SFAS 154 is effective for fiscal years beginning after December 15, 2005, with earlier application permitted in fiscal years beginning after June 1, 2005. The adoption of SFAS 154 will not have an impact on the Company’s financial statements.
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 is evaluating the impact of FIN 48 on its financial statements.
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS 157) which defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS 157 is effective for the Company beginning October 1, 2008.
In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (SFAS 158) which requires the employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability in its statement of financial position. The Company is currently evaluating the impact of SFAS 158 on its financial statements which is effective as of the end of fiscal 2007.
Reclassifications
Certain amounts in the prior years’ financial statements have been reclassified to conform with the 2006 financial statement presentation.
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 other public Alabama energy utilities. A rate adjustment designed to decrease annual gas revenues by approximately $303,000 was implemented December 1, 2005. Rate adjustments, designed to increase annual gas revenues by approximately $1.7 million and $2.8 million, were implemented under the RSE tariff effective December 1, 2004, and 2003, respectively. The December 1, 2005 rate adjustment resulted in decreased revenues 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 for the period. As such, Mobile Gas is allowed to earn a return on all of its assets with no exclusions. Increases are allowed only once each fiscal year, effective December 1, and cannot exceed four percent of prior-year revenues. Under RSE, the APSC conducts reviews using fiscal year-to-date performance through January, April, and July plus Mobile Gas’ budget projections to determine whether Mobile Gas’ return on equity is expected to be within the allowed range of 13.35% to 13.85% at the end of the fiscal year. No such adjustments were required for fiscal 2006 or through the July 2005 or 2004 test periods. Mobile Gas’ financial results for fiscal years 2005 and 2004 did, however, result in a return on equity above the allowed range. As a result, adjustments of $433,000 and $343,000 were made to fiscal year 2005 and fiscal year 2004 pre-tax earnings, respectively, such that the return on equity, as calculated for RSE purposes, equaled 13.6%, the midpoint of the allowed range, and a regulatory liability was recorded which reflected the amount owed to customers. Reductions in rates were made in fiscal year 2006
and 2005 which resulted in $433,000 and $343,000, respectively, being fully refunded to customers by the end of those respective fiscal years.
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 year ended September 30, 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 from force majeure events such as storms, severe weather, and outages, when one such event results in more than $100,000 of additional O&M expense or a combination of two or more such events results in more than $150,000 of additional O&M expense during a fiscal year; or 2) losses of revenue from any individual industrial or commercial customer in excess of $100,000 during the fiscal year, if such losses cause Mobile Gas’ return on equity to fall below 13.35%. An initial ESR balance of $1.0 million was recorded October 1, 2002 and is being recovered from customers through rates. Subject to APSC approval, additional funding, up to a maximum reserve balance of $1.5 million, may be provided from any future non-recurring revenue should such revenue cause Mobile Gas’ return on equity for the fiscal year to exceed 13.85%. Following a year in which a charge against the ESR is made, the APSC allows for accruals to the ESR of no more than $15,000 monthly until the maximum funding level is achieved. The ESR balance of $1,000,000 at September 30, 2006 is included in the balance sheet of the Unaudited Condensed Consolidated Financial Statements as part of Regulatory Liabilities.
In October 2000, the Corus Group plc (Corus, formerly known as British Steel) ceased operations of its Mobile facility and continued to pay Mobile Gas a minimum annual payment as required under the terms of its contract. On July 28, 2005, Corus elected to end the contract and make a termination payment as required by the terms of the contract. Under a Termination Agreement (Termination Agreement) between Mobile Gas and Corus, Corus agreed to pay Mobile Gas $6,100,000, 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 adjustment is calculated monthly for the months of November through April and applied to customers’ bills in the same billing cycle in which the weather variation occurs. The temperature adjustment rider applies to substantially all residential and small commercial customers. Effective November 1, 2006, Mobile Gas will accumulate 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 Storage and Bay Gas, the Company provides underground storage of natural gas and transportation services. The APSC regulates intrastate storage operations through contract approval. Interstate gas storage contracts do not require APSC approval since the Federal Energy Regulatory Commission (FERC), which has jurisdiction over such contracts, allows them to have market-based rates. The FERC has granted authority to Bay Gas to provide transportation-only services to interstate shippers and approved rates for such services.
3. PROPERTY, PLANT, AND EQUIPMENT
The functional classifications for the cost of property, plant, and equipment are as follows at September 30, (in thousands):
4. ASSET RETIREMENT OBLIGATIONS
The Company adopted FIN 47 as of September 30, 2006. 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. Upon adoption of FIN 47, asset retirement obligations were recorded in the amount of $5,818,000. Of this amount, $2,720,000 was recorded as an incremental cost of the underlying property, plant and equipment, less $748,000 of accumulated depreciation. The cumulative effect related to the accretion of the liability and depreciation of the asset was $3,846,000, of which $3,818,000 was 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 our regulated assets through its depreciation rates.
If FIN 47 had been adopted as of September 30, 2005 and 2004, the pro forma asset retirement obligations would have been $5,651,000 and $5,471,000, respectively.
5. NOTES PAYABLE AND LONG-TERM DEBT
Long-term debt consists of the following at September 30, (in thousands):
Maturities and sinking fund requirements on long-term debt in each of the five fiscal years subsequent to September 30, 2006 are as follows: 2007 - $5,619,000; 2008 - $5,900,000; 2009 - $6,054,000; 2010 - $5,653,000 and 2011 - $5,955,000. The Company’s long-term debt instruments contain certain debt to equity ratio requirements and restrictions on the payment of cash dividends and the purchase of shares of its capital stock. None of these requirements and restrictions are presently expected to have a significant impact on the Company’s ability to pay dividends in the future. Substantially all of the property of Mobile Gas is pledged as collateral for its long-term debt, and Bay Gas’ material contracts have been pledged as collateral for its long-term debt.
At September 30, 2006, the Company had $14.7 million available for borrowing on its $20.0 million revolving credit agreement. Borrowings under the agreement may be made as needed provided that the Company is in compliance with certain covenants in the revolving credit agreement and all other loan agreements. The Company currently is in compliance with all such covenants. Effective November 7, 2006, the Company entered into a short-term unsecured loan agreement whereby the Company has the ability to borrow up to an additional $20,000,000 as needed. The rate is the same as the line of credit and matures on February 28, 2007, the renewal date of the line of credit. The Company pays a fee for its committed lines of credit rather than maintaining compensating balances. The commitment fee is 0.125% of the average daily unborrowed amount during the annual period of calculation. Unused committed lines of credit at September 30, 2006 and 2005 were $14.7 and $20.0 million, respectively. The interest rate on short-term borrowings at September30, 2006 was 6.37%.
6. INCOME TAXES
The components of income tax expense are as follows for the years ended September 30, (in thousands):
A reconciliation of income tax expense and the amount computed by multiplying income before income taxes by the statutory federal income tax rate for the periods indicated is as follows for the years ended September 30, (in thousands):
The significant components of the Company’s net deferred tax liability as of September 30, are (in thousands):
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, representing 6% 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 of grant 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 year 2006 was $407,000. The income tax benefit recognized in the income statement for these stock options during fiscal year 2006 was approximately $155,000. The impact of stock option expense was to reduce net income by $252,000 which represents a decrease in basic and diluted earnings per share of approximately $0.03 per share for fiscal year 2006.
The Company entered into an agreement with John S. Davis, President and Chief Executive Officer, to aid in the transition of his previously announced retirement on June 30, 2007. As part of that agreement, effective July 1, 2007, all options previously granted to Mr. Davis that are then unvested will immediately become vested. Accelerated compensation expense of approximately $45,000 was recognized in the fourth quarter of fiscal 2006 and approximately $135,000 will be recognized in fiscal 2007 due to the vesting modification of the outstanding options.
The Company granted stock options during fiscal year 2006, 2005, and 2004. 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 $5.49, $5.20, and $5.46 per option during 2006, 2005, and 2004, respectively.
Weighted average assumptions used in the pricing model for the years ended September 30, are:
Transactions under the Plan are summarized below:
* Includes 81,059 shares outstanding under the 1992 Amended and Restated Stock Option Plan.
The total intrinsic value of options exercised during 2006, 2005, and 2004 was approximately $369,000, $750,000, and $569,000, respectively. The fair value of options that vested during 2006, 2005, and 2004 was approximately $327,000, $274,000 and $280,000, respectively.
At September 30, 2006, there was approximately $694,000 of compensation cost that has not yet been recognized related to non-vested stock-based awards. That cost is expected to be recognized over a weighted-average period of 2.11 years.
During 2006, 2005, and 2004 cash received from options exercised was $530,000, $581,000 and $748,000, respectively, and the actual tax benefit realized for the related tax deduction totaled $130,000, $99,000, and $192,000, respectively.
At September 30, 2006, 263,000 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, 2006, approximately 73,000 shares had been issued to the Trust. There are 17,000 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
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 no longer provides 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 requires 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. The Company uses a September 30 measurement date.
The status of the plans was as follows at September 30 (in thousands):
Net periodic benefit cost included the following components for the years ended September 30, (in thousands):
The expected return on plan assets for the benefit plans is derived with the assistance of investment managers and is based on the current allocation of the plan assets and their expected long-term rates
of return. For the pension plan, the expected return on plan 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, 2006 is developed using the estimated payouts of the respective plans and a spot interest yield curve based upon a broad group of corporate bonds rated AA or better. The weighted average rate of compensation increase is the average of the increases during the expected working lifetime years after an employee reaches the average age of all participants. Assumptions used to determine benefit obligations and periodic benefit costs are as follows:
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plan. A one-percentage-point change in assumed health care cost trend rates would have the following effects (in thousands):
The Company has a Retirement Committee composed of outside Directors that oversees the investments of the pension plan. The Committee has adopted an Investment Policy with the investment objective of meeting the Plan’s benefit obligations and which employs a total return on investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return on plan assets within reasonable and prudent levels of risk in order to minimize
contributions. All investments are expected to satisfy the requirements of the rule of prudent investments 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, 2006 and 2005 and the current target allocation range are as follows:
Pension plan equity securities include the Company’s common stock of 3.1% and 4.3% of plan assets at September 30, 2006 and 2005 respectively. The postretirement benefits plan does not invest in the Company’s common stock.
The Company does not anticipate contributing to its pension plan in fiscal year 2007 but expects to contribute $3,000 to its postretirement benefit plan.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid in the following fiscal years (in thousands):
The Company has formed two voluntary employees’ beneficiary association (VEBA) trusts to fund postretirement health and life insurance benefits. The Company contributed $3,000 in 2006 and $3,000 in 2005.
The Company has previously entered into unfunded and unsecured deferred compensation agreements with Mr. John S. Davis, Vice Chairman of EnergySouth and the former President and Chief Executive Officer, which provide for supplemental payments upon retirement or termination of employment. At September 30, 2006 and 2005, the Company had recorded a liability of $1,096,000 and $932,000, respectively, for the payment of future benefits. Expense under these agreements for the years ended September 30, 2006, 2005, and 2004 was $164,000, $274,000, and $122,000, respectively. The increase in fiscal 2005 expense included adjustments for a change in the discount rate and an increase in life expectancy.
The Company’s eligible employees may participate in the Employee Savings Plan or the Bargaining Unit Employees Savings Plan, both of which are 401(k) plans. The Company’s contributions to these 401(k) plans for the years ended September 30, 2006, 2005, and 2004 were $226,000, $223,000, and $230,000, 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 market risks associated with commodity prices of natural gas. Mobile Gas ameliorates the price risk associated with purchases of natural gas by using a combination of natural gas storage services, fixed price contracts and spot market purchases. As part of Mobile Gas’ gas supply strategy, it has adopted a policy under which management is authorized to commit to future gas purchases at fixed prices up to a specified percentage of the normalized degree-day usage for any corresponding month as outlined within the policy. All commitments for future gas purchases at fixed prices meet the requirements of paragraph 10.b, Normal Purchases and Normal Sales, of Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended by SFAS No. 149. Thus, the commitments for future purchases of natural gas at fixed prices are deemed to be purchases in the normal course of business and are not subject to derivative accounting treatment.
At September 30, 2006, 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 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 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. 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, 2006, 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.
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 recent 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. Mobile Gas had discussions with ADEM to identify steps necessary to obtain ADEM’s concurrence with Mobile Gas’ plans for the site. The Company 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.
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. 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):
11. FINANCIAL INFORMATION BY BUSINESS SEGMENT
Statement of Financial Accounting Standards No. 131, “Disclosures About Segments of An Enterprise and Related Information,” requires that companies disclose segment information which reflects how management makes decisions about allocating resources to segments and measuring their performance. The reportable segments disclosed herein were determined based on such factors as the regulatory environment and the types of products and services offered.
The Company is principally engaged in two reportable business segments: Natural Gas Distribution and Natural Gas Storage. The Natural Gas Distribution segment is actively engaged in the distribution and transportation of natural gas to residential, commercial and industrial customers through Mobile Gas and SGT. The Natural Gas Storage segment provides for the underground storage of natural gas and transportation services through the operations of Bay Gas and Storage. Through Mobile Gas and Services, the Company also provides merchandising and other energy-related services which are aggregated with EnergySouth, the holding company, and included in the Other segment. For the years ended September 30, 2006, 2005, and 2004, all segments were located in Southwest Alabama.
Segment earnings information presented in the table below includes intersegment revenues, interest income, and interest expense which are eliminated in consolidation. Such intersegment revenues are primarily amounts paid by the Natural Gas Distribution segment to the Natural Gas Storage
segment. Segment assets are provided as additional information and are net of intercompany advances, intercompany notes receivable and investments in subsidiaries.
The following table reconciles the distribution and storage segment operating revenues to the natural gas revenue data segregated by class of customer as presented in Item 6 - Selected Financial Data.
12. QUARTERLY FINANCIAL DATA (Unaudited)
Quarterly financial data for fiscal 2006 and 2005 is summarized as follows
(in thousands, except per share data):
The pattern of quarterly earnings reflects a seasonal nature because weather conditions strongly influence operating results.
(1)
The sum of the quarterly amounts does not equal the year’s amount due to rounding of the quarterly amounts or a changing number of average shares.
SCHEDULE II
ENERGYSOUTH, INC. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEARS ENDED SEPTEMBER 30, 2006, 2005, AND 2004
(in thousands)
Notes:
(1)
Amounts written off - net of recoveries.
S-1
EXHIBIT INDEX
E-1
E-2
E-3
E-4
(1)
Filed herewith.
(2)
Management contract or compensatory plan or arrangement.
(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-5