Item 1.
Business.
Change in Fiscal Year
Effective December 31, 2008 the Board of Directors of Energy, Inc. changed its fiscal year end from June 30 to December 31. We made this change to align our fiscal year end with other companies within our industry. This Form 10-K is intended to cover the audited calendar year January 1, 2009 to December 31, 2009, which we refer to as “2009”. Comparative information to 2009 is provided in this Form 10-K with respect to the calendar year January 1, 2008 to December 31, 2008, which is unaudited and we refer to as “2008”. Additional information is provided with respect to the transition July 1, 2008 to December 1, 2008 (the “Transition Period”), which is audited. We refer to the period July 1, 2007 and ending June 30, 2008 as “fiscal 2008”, and the period beginning July 1, 2006 and ending June 30, 2007 as “fiscal 2007.”
Overview
We are a natural gas utility with operations in Montana, Wyoming, North Carolina and Maine. We were originally incorporated in Montana in 1909. We currently have five reporting segments:
• Natural Gas Operations
Annually, we distribute approximately 29 billion cubic feet of natural gas to approximately 62,000 customers through regulated utilities operating in and around Great Falls and West Yellowstone, Montana, Cody, Wyoming, Bangor, Maine, Elkin, North Carolina and various cities in Ohio and Western Pennsylvania. The approximate population of the service territories is 5.3 million. The operation in Elkin, North Carolina was added October 1, 2007. The operation in Bangor, Maine was added December 1, 2007. Our Ohio and Pennsylvania operations were added January 5, 2010
• Marketing and Production
Operations (EWR)
Annually, we market approximately 2.4 billion cubic feet of natural gas to commercial and industrial customers in Montana and Wyoming and manage midstream supply and production assets for transportation customers and utilities through our subsidiary, Energy West Resources, Inc. (EWR). EWR owns an average 48% gross working interest (an average 41% net revenue interest) in 160 natural gas producing wells and gas gathering assets. Energy West Propane, Inc. dba Missouri River Propane (MRP), our small Montana wholesale distribution company that sells propane to our affiliated utility, had been reported in our propane operations. It is now being reported in marketing and production operations.
• Pipeline Operations (EWD)
We own the Shoshone interstate and the Glacier gathering natural gas pipelines located in Montana and Wyoming through our subsidiary Energy West Development, Inc. (EWD). Certain natural gas producing wells owned by our pipeline operations are being managed and reported under our marketing and production operations.
• Propane Operations
(Discontinued Operations)
Our Arizona assets were sold during fiscal year 2007, and the results of operations for the propane assets related to this sale have been reclassified as income from discontinued operations. Prior to discontinuance, we distributed approximately 5.4 million gallons annually, of propane to approximately 8,000 customers through utilities operating underground vapor systems in and around Payson, Pine, and Strawberry, Arizona and retail distribution of bulk propane to approximately 2,300 customers in the same Arizona communities. The
associated assets and liabilities are shown on the consolidated balance sheet as “Assets held for sale” and “Liabilities held for sale.” MRP, our small Montana wholesale distribution company that sells propane to our affiliated utility, had been reported in propane operations. It is now being reported in our marketing and production operations.
• Corporate and Other
This segment was not reported prior to fiscal 2008. Corporate and other was established to encompass the results of corporate acquisitions and other equity transactions. Reported in Corporate and other for the years ended December 31, 2008 and December 31, 2009 are costs associated with business development and acquisitions, and dividend income and recognized gains from the sale of marketable securities.
See Note 14 to our Consolidated Financial Statements for financial information for each of our segments.
Recent Acquisitions and Future Acquisition Strategy
As a result of our success in strengthening our core business, we are now able to focus on our growth strategy which includes the acquisition and expansion of our natural gas utility operations in small and emerging markets. We regularly evaluate gas utilities of varying sizes for potential acquisition. Our acquisition strategy includes identifying geographic areas that have low market saturation rates in terms of natural gas utilization as a result of historical reliance by customers on alternative fuels such as heating oil. We believe that significant acquisitions in Montana and Wyoming are unlikely because of market saturation levels in excess of 90%. However, we intend to look for smaller acquisitions in Montana and Wyoming that are complementary to our existing business. We believe the following transactions exemplify this acquisition strategy.
We determined that due to a historical reliance on propane and heating oil, large segments of the North Carolina and Maine markets remain highly unsaturated with penetration rates as low as 1% in some of these areas. For instance, according to the American Gas Association, the national average for natural gas saturation in the residential heating market was approximately 51% in 2005, whereas large segments of the Maine market remain unsaturated, with penetration rates of less than 3%. We believe these low penetration rates are partially the result of these geographic areas being overlooked by other gas distributors in light of this historical reliance on other energy sources and that the high market price of oil over the past several years presents an opportunity for gas distributors to capture a larger share of the energy market in these states.
Expansion into North Carolina and Maine
In 2006 we began investigating potential acquisitions in North Carolina and Maine. On January 30, 2007, we entered stock purchase agreements with Sempra Energy, a California corporation, for the purchase of natural gas distribution companies in each of these states. On October 1, 2007, we consummated the acquisition of Frontier Natural Gas, which operates a natural gas utility in Elkin, North Carolina. The purchase price was $4.9 million in cash. On December 1, 2007, we acquired Bangor Gas Company, a natural gas utility in Bangor, Maine for a purchase price of $434,000.
Frontier Natural Gas and Bangor Gas Company provided us with a unique opportunity to gain market shares within these service areas since their distribution systems are relatively new and have considerable incremental capacity available to sustain a greater customer load. The acquisitions of Frontier Natural Gas and Bangor Gas Company provide us with substantial assets and potential customers in those service areas, including 149 miles of transmission pipeline and 315 miles of distribution system.
Acquisition of Additional Operations in Montana
On November 2, 2009, we completed the acquisition of a majority of the outstanding shares of Cut Bank Gas Company, a natural gas utility serving Cut Bank, Montana. Pursuant to a stock purchase agreement with the founders and controlling shareholders of Cut Bank Gas, we acquired 83.16% for a purchase price of $500,000 paid
in shares of our common stock. We also offered to purchase the remaining shares of Cut Bank Gas from the shareholders that owned the other 16.84%, most of whom have tendered their shares. The acquisition increased our customers by approximately 1,500.
Expansion into Ohio and Western Pennsylvania
On January 5, 2010, we completed the acquisition of Lightning Pipeline Company, Inc. (“Lightning Pipeline”), Great Plains Natural Gas Company (“Great Plains”), Brainard Gas Corp. (“BGC”) and Great Plains Land Development Co., LTD. (“GPL,” and collectively with Lightning Pipeline, Great Plains and BGC, the “Ohio Companies” and each an “Ohio Company”). Lightning Pipeline is the parent company of Orwell Natural Gas Company (“Orwell”) and Great Plains is the parent company of Northeast Ohio Natural Gas Corp. (“NEO”). Orwell, NEO and BGC are natural gas distribution companies that serve approximately 23,131 customers in Northeastern Ohio and Western Pennsylvania. GPL is a real estate holding company whose primary asset is real estate that is leased to NEO. The purchase price for the Ohio Companies was $37.9 million, which consisted of approximately $20.8 million in debt of the Ohio Companies’ with the remainder of the purchase price paid in 1,707,308 unregistered shares of our common stock. The issuance of shares as merger consideration was approved by the holders of our common stock at our annual meeting of stockholders on November 13, 2009. Our acquisition of the Ohio Companies was a substantial step in our growth, providing us with presence in the Midwestern United States and increasing our customers by more than 50%.
Future Acquisition Strategy
We intend to continue to look for natural gas utilities to acquire. While we believe that the best opportunities for growth remain outside Montana and Wyoming, there may be acquisitions in these states that would be attractive to us because of economies of scale.
Even though we are a small utility serving approximately 62,000 customers, we believe we have the operating expertise to handle a significantly greater number of customers. For example, several operational managers have joined our team who had natural gas utility experience with significantly larger companies. We intend to focus on acquisitions that will enable us to grow our customer base and fully utilize our personnel. We believe that there are opportunities to acquire financially-sound smaller natural gas utility companies that are individually owned or controlled. In addition, we intend to target larger diversified utility companies that have a natural gas distribution operating segment that they are willing to sell.
Our acquisition strategy includes combining newly acquired operations with our current operations to maximize efficiency and profitability. Upon acquiring a distribution company management intends to centralize functions (i.e. accounting) or decentralize functions (i.e. gas marketing), as appropriate. We believe that throughout the utility industry, there has recently been too much centralization, which has led to local operating inefficiencies. Management will evaluate each acquisition and determine the right balance of centralization and decentralization. We believe our senior management’s gas utility experience and expertise will improve the acquired company’s operating efficiency and gas marketing capabilities, and as a result, its profitability.
We may acquire natural gas utilities that have related non-regulated operations such as gathering, storage and marketing operations. Although these non-regulated operations are not the focus of our acquisition strategy, we will not disregard a potential target because of these operations. Rather, upon consummation of the acquisition, we will evaluate the non-regulated operations to determine whether these operations could be complementary to our core business or whether they should be divested.
Finally, even though we intend to further grow the company, we believe it was our focus on efficiently operating our existing businesses and managing our capital investments that put us in the position to pursue acquisitions. Therefore, we intend to continue to focus on efficient and effective management while implementing our acquisition strategy. This continued focus will include:
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cost-effective expansion of our existing customer base by prudently managing capital expenditures and ensuring that new customers provide sufficient margins for an appropriate return on the additional resources and investment required to serve these customers,
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appropriate regulatory treatment of increases in the cost of natural gas,
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continuous improvement of our operational efficiencies, and
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maintenance and improvement of our positive reputation with our regulators and customers.
New Holding Company Structure
On August 3, 2009, we completed a reorganization to implement a holding company structure. The new holding company, Energy, Inc., is the successor to Energy West, Incorporated, which is now a subsidiary of Energy, Inc. The purpose of the reorganization is to provide the flexibility to make future acquisitions through subsidiaries of the holding company rather than Energy West or its subsidiaries. The business operations of the company did not change as a result of the reorganization.
Outstanding shares of stock of Energy West were automatically converted on a share for share basis, into identical shares of common stock of the new holding company. On December 17, 2009, Energy, Inc. withdrew from the Nasdaq Global Market and began trading on the NYSE Amex Equities (formerly known as the American Stock Exchange) under the trading symbol “EGAS.”
Recent Industry Trends
Since 2000, domestic energy markets have experienced significant price increases and decreases, and price volatility. Natural gas markets have been particularly volatile, principally due to weather and concerns over supply. Rising natural gas prices have resulted in a surge in supply-related investment that we believe has stabilized domestic production. Increasing supplies and price-induced conservation have favorably impacted natural gas prices and we believe this trend is likely to continue. Given the current environment, we expect that natural gas will maintain a favorable competitive position compared to other fossil fuels which have also experienced significant price increases. We believe that conditions are favorable for consumers to convert to natural gas from more expensive fossil fuels even if the cost of conversion includes equipment purchases. In addition, given natural gas’ clean burning attributes, we believe environmental regulations may enhance this competitive outlook.
Natural Gas Operations
Our natural gas operations are located in Montana, Wyoming, North Carolina, Maine, Ohio, and Western Pennsylvania, and our revenues from the natural gas operations are generated under tariffs regulated by those states.
In many states, including Montana, Wyoming, North Carolina, Ohio and Pennsylvania, the tariff rates of natural gas utilities are generally established to allow the utility to earn revenue sufficient to recover operating and maintenance costs, plus profits in amounts equal to a reasonable rate of return on their “rate base.” A gas utility’s rate base generally includes the utility’s original cost, cost of inventory and an allowance for working capital, less accumulated depreciation of installed used and useful gas pipeline and other gas distribution or transmission facilities. In Maine, our tariff rates and permitted rate of return are not based upon the concept of rate base, but are based upon historical costs of alternative fuels so that we may compete with distributors of such fuels, and if we exceed a given rate of return, excess earnings are shared with our gas customers.
Natural Gas - Montana
Our operations in Montana provide natural gas service to customers in and around Great Falls, Cascade, West Yellowstone, and Cut Bank, Montana. The operation’s service area has a population of approximately 59,000 in the Great Falls area, 1,500 in the Cascade area , 1,200 in the West Yellowstone area, and approximately 3,100 in the Cut Bank area. Our Montana operations provide service to approximately 30,000 customers.
Our operations in Montana have right of way privileges for its distribution systems either through franchise agreements or right of way agreements within its respective service territories. The Great Falls distribution component of our Montana operations also provides natural gas transportation service to certain customers who purchase natural gas from other suppliers.
Our operations are subject to regulation by the MPSC. The MPSC regulates rates, adequacy of service, issuance of securities, compliance with U.S. Department of Transportation safety regulations and other matters. The Montana division received orders during fiscal 2005 from the MPSC respecting base rates in both Great Falls and West Yellowstone, Montana. These orders were effective on an interim basis on November 1, 2004 and made final effective September 1, 2005. The rate order effectively granted full recovery of the increased property tax liability resulting from the settlement reached with the Montana Department of Revenue in fiscal 2004. It also provided recovery of other operating expenses as we requested. The West Yellowstone rate order granted relief related to its share of the Montana Department of Revenue settlement as well as other operating expenses.
The following table shows our Montana operations’ revenues by customer class for the years ended December 31, 2009 and 2008, for the six months ended December 31, 2008 and 2007, and for the years ended June 30, 2008, and 2007.
Residential revenue has been restated from prior published reports to properly reflect intercompany eliminations. The changes for the years ended June 30, 2008 and 2007 are ($451) and ($205), respectively.
Note: Lower revenues in the year ended December 31, 2009 compared to the year ended December 31, 2008 are due to significantly lower gas costs which are passed on to our customers in accordance with approvals from the MPSC.
The following table shows the volumes of natural gas, expressed in millions of cubic feet, or “MMcf,” sold or transported by our Montana operations for the years ended December 31, 2009 and 2008, for the six months ended December 31, 2008 and 2007 and for the years ending June 30, 2008 and 2007:
Note: Volumes were higher for the year ended December 31, 2009 compared to the year ended December 31, 2008 primarily due to colder weather in the fall of 2009.
The MPSC allows customers to choose a natural gas supplier other than our Montana operations. We provide gas transportation services to customers who purchase from other suppliers.
Our Montana operations use the Northwestern Energy (NWE) pipeline transmission system to transport supplies of natural gas for its core load and to provide transportation and balancing services to customers who have chosen to obtain natural gas from other suppliers. In 2000, we entered into a ten-year transportation agreement with NWE that fixes the cost of pipeline and storage capacity for our Montana operations.
Our operations generate revenues under regulated tariffs designed to recover a base cost of gas and administrative and operating expenses and to provide a sufficient rate of return to cover interest and profit. The Montana division’s tariffs include a purchased gas adjustment clause, which allows our Montana operations to adjust rates periodically to recover changes in gas costs.
Natural Gas - Wyoming
Our operations in Wyoming provide natural gas service to customers in and around Cody, Meeteetse, and Ralston, Wyoming. This service area has a population of approximately 14,400. Our marketing and production operations supply natural gas to our Wyoming operations pursuant to an agreement through October 2010.
Our operations in Wyoming have a certificate of public convenience and necessity granted by the WPSC for transportation and distribution covering the west side of the Big Horn Basin, which extends approximately 70 miles north and south and 40 miles east and west from Cody. As of December 31, 2009, our Wyoming operations provided service to approximately 6,400 customers, including one large industrial customer. Our Wyoming operations also offer transportation through its pipeline system. This service is designed to permit producers and other purchasers of gas to transport their gas to markets outside of our Wyoming operations’ distribution and transmission system.
The following table shows our Wyoming operations’ revenues by customer class for the years ended December 31, 2009 and 2008, for the six months ended December 31, 2008 and 2007 and for the years ending June 30, 2008 and 2007:
Note: Lower revenues were realized in the year ended December 31, 2009 compared to the year ended December 31, 2008, due primarily to lower gas costs which are passed on to the customers in accordance with approvals from the WPSC.
The following table shows volumes of natural gas, expressed in MMcf, sold by our Wyoming operations for the years ended December 31, 2009 and 2008, for the six months ended December 31, 2008 and 2007 and for the years ended June 30, 2008 and 2007:
Our Wyoming operations generate their revenues under tariffs regulated by the WPSC. The tariffs are structured to enable us to recover a base cost of gas and administrative and operating expenses to provide a sufficient rate of return to cover interest and profit. Our rate of return is subject to annual review by the WPSC. Our Wyoming operations’ tariffs include a purchased gas adjustment clause, which allows our Wyoming operations to adjust rates periodically to recover changes in gas costs.
Our Wyoming operations have an industrial customer whose gas sales rates are subject to an industrial tariff, which provides for lower incremental prices as higher volumes are used. This customer accounted for approximately 9.0% of the revenues of our Wyoming operations and approximately 1.4% of the consolidated revenues of the natural gas segment of our business. This customer’s business is cyclical and depends upon the level of housing starts in its market areas.
Our Wyoming operations transport gas for third parties pursuant to a tariff filed with and approved by the WPSC. The terms of the transportation tariff (currently between $.08 and $.31 per thousand cubic feet (mcf)) are approved by the WPSC.
Natural Gas - North Carolina
On October 1, 2007, we acquired Frontier Natural Gas, a natural gas utility in Elkin, North Carolina. The purchase price was $4.9 million in cash. Our North Carolina operations provide natural gas service to customers in Ashe, Surry, Warren, Wilkes, Watauga, and Yadkin Counties. This service area has a population of approximately 42,000 people. The major communities in our North Carolina service area are Boone, Elkin, Mount Airy, Wilkesboro, Warrenton and Yadkinville. We have certificates of public convenience and necessity granted by the North Carolina Utility Commission (NCUC) for transportation and distribution in these counties and franchise agreements with municipalities located within these counties.
Our North Carolina operations provide service to approximately 1,082 residential, commercial and transportation customers through 139 miles of transmission pipeline and 215 miles of distribution system. We offer transportation services to 23 customers through special pricing contracts. For the year ended December 31, 2009, these customers have accounted for approximately 45.4% of the revenues of our North Carolina operation.
The following table shows our North Carolina operations’ revenues by customer class for the years ended December 31, 2009 and 2008, for the six months ended December 31, 2008 and 2007, and the fiscal year ended June 30, 2008:
Note: Because we acquired our North Carolina operations during the last quarter of the calendar 2007 year, the six months ended December 31, 2007 includes three months of operations and the fiscal year ended June 30, 2008 includes nine months of operations.
The following table shows volumes of natural gas, expressed in MMcf, sold by our North Carolina operations for the years ended December 31, 2009 and 2008, for the six months ended December 31, 2008 and 2007, and for the fiscal year ended June 30, 2008:
Note: Because we acquired our North Carolina operations during the last quarter of the calendar 2007 year, the six months ended December 31, 2007 includes three months of operations and the fiscal year ended June 30, 2008 includes nine months of operations.
Our North Carolina operations generate revenues under tariffs regulated by the NCUC. The tariffs are structured to enable us to recover a base cost of gas and administrative and operating expenses to provide a sufficient rate of return. In connection with our acquisition of Frontier Natural Gas, Energy West and NCUC agreed to extend the rate plan in place at the time of the acquisition for a period of five years. Accordingly, the staff of the NCUC will not seek to reduce our rates during that period, and we cannot seek a rate increase in North Carolina during that time absent extraordinary circumstances. The North Carolina regulatory framework, however, incorporates a purchased-gas commodity cost adjustment mechanism that allows Frontier to adjust rates periodically to recover changes in its wholesale gas costs.
Natural Gas - Maine
On December 1, 2007 we acquired Bangor Gas Company, a natural gas utility in Bangor, Maine, for a purchase price of $434,000. Our operations in Maine provide natural gas service to customers in Bangor, Brewer, Old Town, Orono and Veazie through 10 miles of transmission pipeline and 100 miles of distribution system. This service area has a population of approximately 60,000 people. We have certificates of public convenience and necessity granted by the Maine Public Utilities Commission (MPUC) for our Maine service territories.
Our Maine operations provide service to approximately 1,252 residential, commercial and industrial customers. We offer transportation services to 36 customers through special pricing contracts. These customers accounted for approximately 31.7% of the revenues of our Maine operations for the year ended December 31, 2009.
The following table shows our Maine operations’ revenues by customer class for the years ended December 31, 2009 and 2008, for the six months ended December 31, 2008 and 2007, and for the fiscal year ended June 30, 2008:
Note: Because we acquired our Maine operations during the last quarter of the calendar 2007 year, the six months ended December 31, 2007 includes one month of Maine operations and the fiscal year ended June 30, 2008 includes seven months of operations.
The following table shows volumes of natural gas, expressed in MMcf, sold by our Maine operations for the years ended December 31, 2009 and 2008, for the six months ended December 31, 2008 and 2007, and for the fiscal year ended June 30, 2008:
Note: Because we acquired our Maine operations during the last quarter of the calendar 2007 year, the six months ended December 31, 2007 includes one month of Maine operations and the fiscal year ended June 30, 2008 includes seven months of operations.
Our Maine operations generate revenues under tariffs regulated by the MPUC, and as in other states, our tariffs are generally structured to enable us to realize a sufficient rate of return on investment. However, our tariffs and permitted return are not based upon a “rate base” as in other states, but on an alternative framework. Because heating oil and other alternative fuels are historically prevalent in Maine and because Bangor Gas Company entered the market in 1999 with few customers and sizeable start-up costs, the MPUC established a rate plan for Bangor Gas Company that was based upon the costs of distribution of alternative fuels. The goal of this alternative framework was to allow Bangor Gas Company to compete as a start-up gas utility with distributors of alternative fuels.
Accordingly, our rates include transportation charges and customer charges, but our rates may not exceed certain thresholds established in relation to rates for alternative fuels with which we compete. Additionally, if our cumulative profits exceed certain levels, we are then subject to a revenue sharing mechanism. Bangor Gas Company has never exceeded that cumulative profit level, thus the revenue sharing mechanism has not been triggered.
Our Maine tariffs also include a purchased gas adjustment clause, which allows our operation to adjust rates periodically to recover changes in gas costs. We are also able to negotiate individual special contracts with transportation customers. In connection with our acquisition of Bangor Gas Company, the MPUC extended the ten-year rate plan that had been established in 1999 for Bangor Gas Company for an additional three years. Accordingly, we cannot seek a new rate plan in Maine until late 2012. However, our current rate plan allows for certain periodic increases and adjustments to our tariffs.
Natural Gas - Ohio and Western Pennsylvania
On January 5, 2010, we acquired Orwell, NEO, and BGC, which are natural gas distribution companies in Northeastern Ohio and Western Pennsylvania for a purchase price of $37.9 million. These operations provide natural gas services in 20 counties in eastern Ohio and western Pennsylvania through 999 miles of distribution system. The service area has a population of approximately 5.2 million people.
The Ohio and Western Pennsylvania operations provide service to approximately 23,131 residential, commercial and industrial customers.
The following table shows the Ohio and Western Pennsylvania operations’ revenues by customer class for the years ended December 31, 2009 and 2008:
The following table shows volumes of natural gas, expressed in MMcf, sold by our Ohio and Western Pennsylvania operations for the years ended December 31, 2009 and 2008:
Our Ohio operations generate their revenues under tariffs regulated by the Public Utilities Commission of Ohio (PUCO). The tariffs are structured to enable us to recover a base cost of gas and administrative and operating expenses to provide a sufficient rate of return to cover interest and profit. Our Ohio operations’ tariffs include a purchased gas adjustment clause, which allows our Ohio operations to adjust rates periodically to recover changes in gas costs.
In a similar manner, our Pennsylvania operations generate their revenues under tariffs regulated by the Pennsylvania Public Utilities Commission (PAPUC). The tariffs are structured to enable us to recover a base cost of gas and administrative and operating expenses to provide a sufficient rate of return to cover interest and profit. Our Pennsylvania operations’ tariffs include a purchased gas adjustment clause, which allows our Pennsylvania operations to adjust rates annually to recover changes in gas costs.
Marketing and Production Operations
We market approximately 2.4 bcf of natural gas annually to commercial and industrial customers in Montana and Wyoming and manage midstream supply and production assets for transportation customers and utilities through our subsidiary, EWR. In order to provide a stable source of natural gas for a portion of its requirements, EWR has an ownership interest in two natural gas production properties and three gathering systems, located in north central Montana. EWR currently holds an average 48% gross working interest (average 41% net revenue interest) in 160 natural gas producing wells in operation. This production gives EWR a partial natural hedge when market prices of natural gas are greater than the cost of production. The gas production from these wells and assets provided approximately 18.2% of the volume requirements for EWR in our Montana market for the year ended December 31, 2009. We acquired our interests in the wells by quitclaim deeds conveying interests in certain oil and gas leases for the wells from sellers who were in financial distress. We chose to purchase their interests despite the uncertain nature of the conveyance because we were able to negotiate purchase prices that, we believe, were fair and reasonable under, and accounted for, that circumstance. It is possible that our interests will be challenged in the future, but no such challenge has been made since acquiring the interests in 2002 and 2003 and we have no notice that such a challenge is forthcoming.
Additionally, EWR owns a 21.98% interest in Kykuit, a developer and operator of oil, gas and mineral leasehold estates located in Montana. We have invested a total of approximately $1.5 million in Kykuit and may invest additional funds in the future as Kykuit provides a supply of natural gas in close proximity to our natural gas operations in Montana. However, our obligations to make additional investments in Kykuit are limited under the Kykuit operating agreement. We are entitled to cease further investments in Kykuit if, in our reasonable discretion after the results of certain initial exploration activities are known, we deem the venture unworthy of further investments. Even if the venture is reasonably successful, we are obligated to invest no more than an additional $1.5 million over the life of the venture. Other investors in Kykuit include our chairman of the board, Richard M. Osborne, and John D. Oil and Gas Company, a publicly held gas exploration company, which is also the managing member of Kykuit. Also, Mr. Osborne is the chairman of the board and chief executive officer, and our director Mr. Gregory J. Osborne is president and Mr. Smith is a director of John D. Oil and Gas Company. Our net investment in Kykuit after deducting undistributed losses of approximately $700,000 is approximately $800,000. Included in this amount and on our income statement for the year ended December 31, 2009 is a loss on our equity investment in Kykuit totaling $687,000 ($423,000 net of income tax), due to the write-off of drilling costs resulting in dry holes.
In furtherance of management’s focus on our core business of natural gas distribution, in fiscal 2003, our marketing and production operations exited the electricity marketing business by not renewing its electric contracts as they expired. As a result, during fiscal 2008 and 2007, we had only one remaining electric contract with a margin of $5,300 and $48,000, respectively, in each of those two years. The electricity operations are reported within continuing operations because we use the same employees with the same overhead as our marketing and production operations.
Pipeline Operations
We operate two natural gas pipelines, the “Glacier” natural gas gathering pipeline placed in service in July 2002 and the “Shoshone” transmission pipeline placed in service in March 2003. The pipelines extend from the north of Cody, Wyoming to Warren, Montana. The Shoshone pipeline is approximately 30 miles in length, is a bidirectional pipeline that transports natural gas between Montana and Wyoming. This enables us to sell natural gas to customers in Wyoming and Montana through our EWR subsidiary and gives EWR access to the AECO and CIG natural gas price indices. The Glacier gathering pipeline is approximately 40 miles in length and enables us to transport production gas for processing. We believe that our pipeline operations represent an opportunity to increase our profitability over time by taking advantage of summer/winter pricing differentials as well as Alberta Energy Company Limited and Colorado Interstate Gas natural gas index differentials and to continue transporting more production gas to market. We currently are seeking ways in which we can maximize our pipeline operations by increasing the capacity and throughput of our existing pipeline assets.
Propane Operations - (Discontinued Operations)
Until March 31, 2007, we were engaged in the regulated sale of propane under the business name Energy West Arizona (EWA) and the unregulated sale of propane under the business name Energy West Propane - Arizona (EWPA), collectively known as EWP. EWP distributed propane in the Payson, Pine, and Strawberry, Arizona area located about 75 miles northeast of Phoenix in the Arizona Rim Country. EWP’s service area included approximately 575 square miles and a population of approximately 50,000.
The propane industry had become increasingly consolidated and operators with access to supply on a national scale have an advantage over smaller propane distributors. Therefore, in April 2007 we sold our propane operations in Arizona. We used the proceeds from this sale to reduce our outstanding debt and strengthen our balance sheet. Our propane operations are disclosed as discontinued operations in this Form 10-K. The small Montana wholesale distribution of propane to our affiliated utility, MRP, that had been reported in our propane operations is now reported in our marketing and production operation.
Corporate and Other
Our “Corporate and Other” reporting segment was established during the second quarter of our 2008 fiscal year. It is intended primarily to encompass the results of corporate acquisitions and other equity transactions, as well
as certain other income and expense items associated with Energy, Inc.’s holding company functions. As we continue to implement our acquisition strategy and grow, we will likely report certain income and expense items associated with potential and completed acquisitions under this reporting segment.
Our first significant event reported under this segment was a deferred tax asset that was the result of our recent acquisitions of two natural gas utilities. On October 1, 2007, we completed the acquisition of Frontier Natural Gas, a natural gas utility in Elkin, North Carolina for a total purchase price of approximately $4.9 million. On December 1, 2007, we completed the acquisition of Bangor Gas Company, a Maine natural gas utility, for a total purchase price of approximately $434,000.
Under Accounting Standards Codification (ASC) 805, Business Combinations (ASC 805), we recorded these stock acquisitions as if the net assets of the targets were acquired. For income tax purposes, we are permitted to “succeed” to the operations of the acquired companies, and thereby continue to depreciate the assets at their historical tax cost bases. As a result, we may continue to depreciate approximately $82.0 million of capital assets using the useful lives and rates employed by Frontier Natural Gas and Bangor Gas Company. This treatment results in a potential future federal and state income tax benefit of approximately $19.1 million over a 20-year period using applicable federal and state income tax rates. Under Internal Revenue Code Section 382, our ability to recognize tax deductions as a result of this tax benefit will be limited during the first five years following the acquisitions.
Following ASC 740, Income Taxes (ASC 740), our balance sheet at December 31, 2008 reflects a gross deferred tax asset of approximately $19.0 million, offset by a valuation allowance of approximately $7.5 million, resulting in a net deferred tax asset associated with the acquisition of approximately $11.5 million. The excess of the net deferred tax assets received in the transactions over their respective purchase prices has been reflected as an extraordinary gain of approximately $6.8 million on our income statement for the year ended June 30, 2008 in accordance with the provisions of ASC 805.
During the year ended December 31, 2009, we conducted a study of the deferred tax asset and valuation allowance, and based on our updated earnings projections and more complete data from the seller’s tax returns, we determined that $2.8 million of the valuation allowance related to federal taxes is no longer needed but that the state portion should be increased by $400,000. Accordingly, we reduced the valuation allowance to approximately $5.1 million. In addition, we increased the gross deferred tax asset to $19.1 million. As a result, the net deferred tax asset increased to approximately $14.0 million at December 31, 2009. Included in the results of our Corporate and Other segment for the year ended December 31, 2009 is the income tax benefit of approximately $2.8 million related to the elimination of the federal portion of the valuation allowance. An income tax expense of $300,000 resulting from the increase in the state portion of the valuation allowance partially offset by the increase in the gross deferred tax asset is included in the results of the Natural Gas Operations segment.
Also in the year ended December 31, 2009 we reported $830,000 in costs associated with business development and acquisitions, partially offset by $190,000 in dividend income, $97,000 in recognized gains on the sale of marketable securities and the associated income tax benefit from these activities of $30,000. The total net income from Corporate and Other for the year ended December 31, 2009 is approximately $2.2 million.
Competition
The traditional competition we face in our distribution and sales of natural gas is from suppliers of fuels other than natural gas, including electricity, oil, propane, and coal. Traditionally, the principal considerations affecting a customer’s selection of utility gas service over competing energy sources include service, price, equipment costs, reliability, and ease of delivery. In addition, the type of equipment already installed in a business and residence significantly affects the customer’s choice of energy. However, with respect to the majority of our service territory, previously installed equipment is not an issue. Households in recent years have generally preferred the installation of natural gas and/or propane for space and water heating as an energy source. We face more intense competition in West Yellowstone and Cascade, Montana, North Carolina and Maine due to the cost of competing fuels than we face in the Great Falls area of Montana and our service territory in Wyoming. In Ohio, we face competition from other gas companies because Ohio’s regulatory framework does not provide gas distribution companies with exclusive geographic franchises. Our principal competitors in Ohio are Dominion East Ohio Gas Company and Columbia Gas of Ohio, a NiSource company.
Our marketing and production operations’ compete principally with other natural gas marketing firms doing business in Montana and Wyoming.
Gas Supply Marketers and Gas Supply Contracts
We purchase gas for our natural gas operations and marketing and production operations from various gas supply marketers. For the past several years, the primary gas supply marketers for our natural gas distribution operations have been Jefferson Energy Trading, LLC (Jetco) and Tenaska Marketing Ventures. Jetco has also been a significant gas supply marketer for our marketing and production subsidiary, EWR. Other gas supply marketers are also used by EWR from time to time. EWR also supplies itself with natural gas through ownership of an average 48% gross working interest (41% net revenue interest) in 160 natural gas producing wells in operation in north central Montana. This production gives EWR a partial natural hedge when market prices of natural gas are greater than the cost of production. The gas production from these wells and assets provided approximately 18.2% of the volume requirements for EWR’s Montana market, for the year ended December 31, 2009. In Ohio, our gas suppliers are South Jersey Resources Group, LLC, Shell Energy North America (US), L.P., BP Canada Energy Marketing Corp. and Constellation Energy. In North Carolina, our primary gas supply marketer for Frontier Natural Gas is BP Energy, and in Maine, our primary gas supply marketer for Bangor Gas Company is Repsol Energy North America Corporation.
We purchase and store gas for distribution later in the year. We also enter agreements to buy or sell gas at a fixed price. We may use such arrangements to protect profit margins on future obligations to deliver gas at a fixed price, or to attempt to protect against adverse effects of potential market price declines on future obligations to purchase gas at fixed prices.
Governmental Regulation
State Regulation
Our continuing utility operations are subject to regulation by the Montana Public Service Commission (MPSC), Wyoming Public Service Commission (WPSC), North Carolina Utilities Commission (NCUC), Maine Public Utilities Commission (MPUC), Public Utility Commission of Ohio (PUCO), Pennsylvania Public Utility Commission (PPUC) and Federal Energy Regulatory Commission (FERC) as to rates, service area, adequacy of service, and safety standards. This regulation plays a significant role in determining our profitability. These authorities regulate many aspects of our distribution operations, including construction and maintenance of facilities, operations, safety, the rates we may charge customers, the terms of service to our customers and the rate of return we are allowed to realize. The various regulatory commissions approve rates intended to permit a reasonable rate of return on investment. Our tariffs allow gas cost to be recovered in full (barring a finding of imprudence) in regular (as often as monthly) rate adjustments. These pricing mechanisms have substantially reduced any delay between the incurrence and recovery of gas costs.
Local distribution companies periodically file rate cases with state regulatory authorities to seek permission to increase rates. We monitor our need to file rate cases with state regulators for such rate increases for our retail gas and transportation services. Through these rate cases, we are able to adjust the prices we charge customers for selling and transporting natural gas. However, in connection with our acquisitions of Frontier Natural Gas and Bangor Gas Company, the NCUC and MPUC extended the rate plans in effect at the time of acquisition for these entities for a period of five years. Accordingly, we cannot seek a new rate plan in these states during that time, although the Maine rate plan does allow us to periodically increase and adjust our rates within certain parameters within our rate plan.
Franchise Agreements
In addition to being regulated by state regulatory agencies, local distribution companies are often subject to franchise agreements entered with local governments. While the number of local governments that require franchise agreements is diminishing historically, most of the local governments in our service areas still require them. Accordingly, when and where franchise agreements are required, we enter agreements for franchises with the cities and communities in which we operate authorizing us to place our facilities in the streets and public grounds.
Generally, no utility may obtain a franchise until it has obtained approval from the relevant state regulatory agency to bid on a local franchise. We attempt to acquire or reacquire franchises whenever feasible. Where they are required, without a franchise, a local government could require us to cease our occupation of the streets and public grounds or prohibit us from extending our facilities into any new area of that city or community. To date, the absence of a franchise has caused no adverse effect on our operations.
In Montana, we hold a franchise in the city of Great Falls, and we are in the process of renewing our West Yellowstone franchise agreement. In Wyoming, we hold franchises in the cities of Cody and Meeteetse. In North Carolina, the right to distribute gas is regulated by the NCUC, which generally divides service territories by county, and we have been granted the right by the NCUC to distribute gas in the six counties in which we operate under certificates of public convenience and necessity from the NCUC. We also have franchise agreements with all of the incorporated municipalities in those six counties to install and operate gas lines in those municipalities’ streets and right-of-ways. In Maine, we have been granted the right by the MPUC to distribute gas in our service areas under certificates of public convenience and necessity. We are not required to obtain franchise agreements for our Maine operations.
Federal Regulations
Our interstate operations are also subject to federal regulations with respect to rates, services, construction/maintenance and safety standards. This regulation plays a significant role in determining our profitability. Various aspects of the transportation of natural gas are also subject to, or affected by, federal regulation under the Natural Gas Act (NGA), the Natural Gas Policy Act of 1978 and the Natural Gas Wellhead Decontrol Act of 1989. The Federal Energy Regulatory Commission (FERC) is the federal agency vested with authority to regulate the interstate gas transportation industry. Among aspects of our business subject to FERC regulation, our Shoshone Pipeline is subject to certain FERC regulations applicable to interstate activities, including (among other things) regulations regarding rates charged. Our pipeline rates must be filed with FERC. The Shoshone Pipeline has rates on file with FERC for firm and interruptible transportation that have been determined to be just and reasonable. The operations of the Shoshone Pipeline are subject to certain standards of conduct established by FERC that require the Shoshone Pipeline to operate separately from, and without sharing confidential business information with, EWR to the maximum extent practicable. In contrast, FERC has determined that our interstate pipeline and natural gas operations in Wyoming may share operating personnel so long as our natural gas operations in Wyoming do not market natural gas.
Under certain circumstances, gathering pipelines are exempt from regulation by FERC. Our Glacier gathering pipeline has been determined to be non-jurisdictional by FERC, and is therefore not subject to regulation by FERC.
Our interstate pipeline operations are also subject to federal safety standards promulgated by the Department of Transportation under applicable federal pipeline safety legislation, as supplemented by various state safety statutes and regulations.
EWR is authorized by FERC to sell wholesale electricity in interstate commerce. These operations are subject to the Federal Power Act. However, FERC has determined that Energy West is an exempt public utility holding company.
Seasonality
Our business and that of our subsidiaries in all segments is temperature-sensitive. In any given period, sales volumes reflect the impact of weather, in addition to other factors. Colder temperatures generally result in increased sales, while warmer temperatures generally result in reduced sales. We anticipate that this sensitivity to seasonal and other weather conditions will continue to be reflected in our sales volumes in future periods.
Environmental Matters
Environmental Laws and Regulations
Our business is subject to environmental risks normally incident to the operation and construction of gathering lines, pipelines, plants and other facilities for gathering, processing, treatment, storing and transporting natural gas and other products. These environmental risks include uncontrollable flows of natural gas, fluids and other substances into the environment, explosions, fires, pollution and other environmental and safety risks. The
following is a discussion of certain environmental and safety concerns related to our business. It is not intended to constitute a complete discussion of the various federal, state and local statutes, rules, regulations, or orders to which our operations may be subject. For example, we, even without regard to fault, could incur liability under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (also known as the “Superfund” law), or state counterparts, in connection with the disposal or other releases of hazardous substances and for damage to natural resources.
Our activities in connection with the operation and construction of gathering lines, pipelines, plants, storage caverns, and other facilities for gathering, processing, treatment, storing and transporting natural gas and other products are subject to environmental and safety regulation by federal and state authorities, including, without limitation, the state environmental agencies and the Environmental Protection Agency (EPA), which can increase the costs of designing, installing and operating such facilities. In most instances, the regulatory requirements relate to the discharge of substances into the environment and include measures to control water and air pollution.
Environmental laws and regulations may require the acquisition of a permit or other authorization before certain activities may be conducted. These laws also include fines and penalties for non-compliance. Further, these laws and regulations may limit or prohibit activities on certain lands lying within wilderness areas, wetlands, areas providing habitat for certain species or other protected areas. We are also subject to other federal, state, and local laws covering the handling, storage or discharge of materials used in our business and laws otherwise relating to protection of the environment, safety and health. Because the requirements imposed by environmental laws and regulations frequently change, we are unable to predict the ultimate costs of compliance with such requirements or whether the incurrence of such costs would have a material adverse effect on our operations.
Environmental Issues
We own property on which we operated a manufactured gas plant from 1909 to 1928. We currently use this site as an office facility for field personnel and storage location for certain equipment and materials. The coal gasification process utilized in the plant resulted in the production of certain by-products that have been classified by the federal government and the State of Montana as hazardous to the environment.
We have completed our remediation of soil contaminants at the plant site. In April 2002 we received a closure letter from the Montana Department of Environmental Quality (MDEQ) approving the completion of such remediation program.
We and our consultants continue to work with the MDEQ relating to the remediation plan for water contaminants. The MDEQ has established regulations that allow water contaminants at a site to exceed standards if it is technically impracticable to achieve those standards. Although the MDEQ has not established guidance respecting the attainment of a technical waiver, the EPA has developed such guidance. The EPA guidance lists factors that render remediation technically impracticable. We have filed with the MDEQ a request for a waiver from complying with certain standards. As of December, 31, 2009 there has been no action on our waiver request by the MDEQ.
Although we incurred considerable costs to evaluate and remediate the site, we have been permitted by the MPSC to recover the vast majority of those costs. On May 30, 1995, we received an order from the MPSC allowing for recovery of the costs through a surcharge on customer bills. At December 31, 2009, we had incurred cumulative costs of approximately $2.1 million in connection with our evaluation and remediation of the site and had recovered approximately $2.1 million of these costs pursuant to the order. As of December 31, 2009, the cost remaining to be recovered through the ongoing rate was $22,000. We are required to file with the MPSC every two years for approval to continue the recovery of these costs through a surcharge. During fiscal 2007, the MPSC approved the continuation of the recovery of these costs with its order dated May 15, 2007. Pursuant to this order, we filed an application with the MPSC on June 30, 2009 for continued recovery of these costs. On February 2, 2010 the MPSC issued its order granting recovery through February 28, 2010, at which time the recovery will be complete and the recovery surcharge extinguished.
We periodically conduct environmental assessments of our assets and operations. As set forth above, we continue to work with the MDEQ to address the water contamination problems associated with the former
manufactured gas plant site and we believe that under EPA standards, further remediation may be technically impracticable. Further, we are not aware of any other material environmental problems requiring remediation. For these reasons, we believe that we are in material compliance with all applicable environmental laws and regulations.
Employees
We had a total of 172 employees as of December 31, 2009. Two of these employees are employed by our marketing and production operations, 157 by our natural gas operations and 13 at the corporate office. Our natural gas operations include 15 employees represented by two labor unions. Negotiations were completed in July 2008 with the Laborers Union, with a contract in place until June 30, 2010. A three-year contract with Local Union #41 for the pipefitters expires June 30, 2010. We believe our relationship with both labor unions is good.
Item 1A.
Item 1A.
Risk Factors.
An investment in our common stock involves a substantial degree of risk. Before making an investment decision, you should give careful consideration to the following risk factors in addition to the other information contained in this report. The following risk factors, however, may not reflect all of the risks associated with our business or an investment in our common stock.
Risks Related to Our Business
We are subject to comprehensive regulation by federal, state and local regulatory agencies that impact the rates we are able to charge, our costs and profitability.
The MPSC, WPSC, NCUC, MPUC, PUCO, PAPUC and FERC regulate our rates, service area, adequacy of service and safety standards. These authorities regulate many aspects of our distribution operations, including the rates that we may charge customers, the terms of service to our customers, construction and maintenance of facilities, operations, safety and the rate of return that we are allowed to realize. Our ability to obtain rate increases and rate supplements to maintain the current rate of return depends upon regulatory discretion. There can be no assurance that we will be able to obtain rate increases or rate supplements or continue to receive the current authorized rates of return.
Our gas purchase practices are subject to an annual review by state regulatory agencies which could impact our earnings and cash flow.
The regulatory agencies that oversee our utility operations may review retrospectively our purchases of natural gas on an annual basis. The purpose of these annual reviews is to reconcile the differences, if any, between the amount we paid for natural gas and the amount our customers paid for natural gas. If any costs are disallowed in this review process, these disallowed costs would be expensed in the cost of gas but would not be recovered by us in the rates charged to our customers. The various state regulatory agencies’ reviews of our gas purchase practices creates the potential for the disallowance of our recovery through the gas cost recovery pricing mechanism. Significant disallowances could affect our earnings and cash flow.
Operational issues beyond our control could have an adverse effect on our business.
We operate in geographically dispersed areas. Our ability to provide natural gas depends both on our own operations and facilities and those of third parties, including local gas producers and natural gas pipeline operators from whom we receive our natural gas supply.
The loss of use or destruction of our facilities or the facilities of third parties due to extreme weather conditions, breakdowns, war, acts of terrorism or other occurrences could greatly reduce potential earnings and cash flows and increase our costs of repairs and replacement of assets. Our losses may not be fully recoverable through insurance or customer rates.
Storing and transporting natural gas involves inherent risks that could cause us to incur significant financial losses.
There are inherent hazards and operation risks in gas distribution activities, such as leaks, accidental explosions and mechanical problems that could cause the loss of human life, significant damage to property, environmental pollution, impairment of operations and substantial losses to us. The location of pipelines 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. These activities may subject us to litigation and administrative proceedings that could result in substantial monetary judgments, fines or penalties against us. To the extent that the occurrence of any of these events is not fully covered by insurance, they could adversely affect our earnings and cash flow.
Our earnings and cash flow are sensitive to decreases in customer consumption resulting from warmer than normal temperatures and customer conservation.
Our gas sales revenue is generated primarily through the sale and delivery of natural gas to residential and commercial customers who use natural gas mainly for space heating. Consequently, temperatures have a significant impact on sales and revenues. Given the impact of weather on our utility operations, our business is a seasonal business. Most of our gas sales revenue is generated in the first and fourth quarters of our year (January 1 to March 31 and October 1 to December 31) as we typically experience losses in the non-heating season, which occurs in the second and third quarters of our year (April 1 to September 30).
In addition, the average annual natural gas consumption of customers has been decreasing because, among other things, new homes and appliances are typically more energy efficient than older homes and appliances, and customers appear to be continuing a pattern of conserving energy by utilizing energy efficient heating systems, insulation, alternative energy sources, and other energy savings devices and techniques. A mild winter, as well as continued or increased conservation, in any of our service areas can have a significant adverse impact on demand for natural gas and, consequently, earnings and cash flow.
The increased cost of purchasing natural gas during periods in which natural gas prices are rising significantly could adversely impact our earnings and cash flow.
The rates we are permitted to charge allow us to recover our cost of purchasing natural gas. In general, the various regulatory agencies allow us to recover the costs of natural gas purchased for customers on a dollar-for-dollar basis (in the absence of disallowances), without a profit component. We periodically adjust customer rates for increases and decreases in the cost of gas purchased by us for sale to our customers. Under the regulatory body-approved gas cost recovery pricing mechanisms, the gas commodity charge portion of gas rates we charge to our customers may be adjusted upward on a periodic basis. If the cost of purchasing natural gas increases and we are unable to recover these costs from our customers, we may incur increased costs associated with lost and unaccounted for gas and higher working capital requirements. In addition, any increases in the cost of purchasing natural gas may result in higher customer bad debt expense for uncollectible accounts and reduced sales volume and related margins due to lower customer consumption.
The loss of a major commercial or industrial gas customer to which we provide natural gas may negatively impact our profitability.
In 2009, we earned 6.65% of our operating margin by providing gas marketing services to unregulated commercial and industrial gas customers. External factors over which we have no control, such as the weather and economic conditions, can significantly impact the amount of gas consumed by our major commercial and industrial customers. The loss of a major customer could have an adverse impact on our earnings and cash flow.
Volatility in the price of natural gas could result in customers switching to alternative energy sources which could reduce our revenues, earnings and cash flow.
The market price of alternative energy sources such as coal, electricity, oil and steam is a competitive factor affecting the demand for our gas distribution services. Our customers may have or may acquire the capacity to use
one or more of the alternative energy sources if the price of natural gas and our distribution services increase significantly. Natural gas has typically been less expensive than these alternative energy sources. However, if natural gas prices increase significantly, some of these alternative energy sources may become more economical or more attractive than natural gas which could reduce our earnings and cash flow.
The gas industry is intensely competitive and competition has increased in recent years as a result of changes in the price negotiation process within the supply and distribution chain of the gas industry, both of which could negatively impact earnings.
We compete with companies from various regions of the United States and may compete with foreign companies for domestic sales, many of whom are larger and have greater financial, technological, human and other resources. Additionally, legislative and regulatory initiatives, at both the federal and state levels, are designed to promote competition. These challenges have been compounded by changes in the gas industry that have allowed certain customers to negotiate gas purchases directly with producers or brokers. We could lose market share or our profit margins may decline in the future if we are unable to remain competitive.
Earnings and cash flow may be adversely affected by downturns in the economy.
Our operations are affected by the conditions and overall strength of the national, regional and local economies, which impact the amount of residential and industrial growth and actual gas consumption in our service territories. Our commercial customers use natural gas in the production of their products. During economic downturns, these customers may see a decrease in demand for their products, which in turn may lead to a decrease in the amount of natural gas they require for production. In addition, during periods of slow or little economic growth, energy conservation efforts often increase and the amount of uncollectible customer accounts increases. These factors may reduce earnings and cash flow.
Changes in the regulatory environment and events in the energy markets that are beyond our control may reduce our earnings and limit our access to capital markets.
As a result of the energy crisis in California during 2000 and 2001, the bankruptcy of some energy companies, investigations by governmental authorities into energy trading activities, the collapse in market values of energy companies, the downgrading by rating agencies of a large number of companies in the energy sector and the recent volatility of natural gas prices in North America, companies in regulated and unregulated energy businesses have generally been under increased scrutiny by regulators, participants in the capital markets and debt rating agencies. In addition, the Financial Accounting Standards Board or the Securities and Exchange Commission could enact new accounting standards that could impact the way we are required to record revenues, expenses, assets and liabilities. We cannot predict or control what effect these types of events, or future actions of regulatory agencies or others in response to such events, may have on our earnings or access to the capital markets.
We acquired interests in our natural gas wells by quitclaim deed and cannot guarantee that we hold clear title to our interests or that our interests will not be challenged in the future.
We own an average 48% working interest (average 41% net revenue interest) in 160 natural gas producing wells, which provide our marketing and production operations a partial natural hedge when market prices of natural gas are greater than the cost of production. The gas production from these wells provided approximately 18.2% of the volume requirements for EWR’s Montana market for the year ended December 31, 2009. We acquired our interests in the wells by quitclaim deed conveying interests in certain oil and gas leases for the wells. Because the sellers conveyed their interests by quitclaim, we received no warranty or representation from them that they owned their interests free and clear from adverse claims by third parties or other title defects. We have no title insurance, guaranty or warranty for our interests in the wells. Further, the wells may be subject to prior, unregistered agreements, or transfers which have not been recorded.
Accordingly, we cannot guarantee that we hold clear title to our interests or that our interests will not be challenged in the future. If our interests were challenged, expenses for curative title work, litigation or other dispute resolution mechanisms may be incurred. Loss of our interests would reduce or eliminate our production operations
and reduce or eliminate the partial natural hedge that our marketing and production subsidiary currently enjoys as a result of our production capabilities. For all of these reasons, a challenge to our ownership could negatively impact our earnings, profits and results of operations.
Failure to maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act could have a material adverse effect on our business and stock price.
Section 404 of the Sarbanes-Oxley Act of 2002 (Section 404) contains provisions requiring an annual assessment by management, as of the end of the fiscal year, of the effectiveness of internal control for financial reporting, as well as attestation and reporting by independent auditors on management’s assessment as well as other control-related matters. Beginning with the Form 10-K for the fiscal year ended June 30, 2008, we began complying with Section 404 and finished a report by our management on our internal control over financial reporting. Our auditors are not yet required to opine on our internal controls.
Compliance with Section 404 is both costly and challenging. Going forward, there is a risk that neither we nor our independent auditors will be able to conclude that our internal control over financial reporting is effective as required by Section 404. Further, during the course of our testing we may identify deficiencies that we may not be able to remediate in time to meet the deadlines imposed under the Sarbanes-Oxley Act for compliance with Section 404. Moreover, effective internal controls, particularly those related to revenue recognition, are necessary for us to produce reliable financial reports and are important to help prevent financial fraud. If we cannot provide reliable financial reports or prevent fraud, our business and operating results could be harmed, investors could lose confidence in our reported financial information, and the trading price of our stock could be adversely affected.
Our actual results of operations could differ from estimates used to prepare our financial statements.
In preparing our financial statements in accordance with generally accepted accounting principles, our management often must make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. We consider the regulatory accounting policy to be our most critical because of the uncertainties, judgments, and complexities of the underlying accounting standards and operations involved. Regulatory accounting allows for the actions of regulators to be reflected in the financial statements. Their actions may cause us to capitalize costs that would otherwise be included as an expense in the current period by unregulated companies. If future recovery of costs ceases to be probable, the assets will be written off as a charge in current period earnings.
We are subject to numerous environmental laws and regulations that may increase our cost of operations, impact our business plans and expose us to environmental liabilities.
Environmental regulations that may affect our present and future operations include regulation of air emissions, water quality, wastewater discharges, solid waste and hazardous waste. These laws and regulations can result in increased capital expenditures and operating costs. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. We cannot predict the outcome (financial or operational) of any related litigation that may arise.
We may be a responsible party for environmental clean-up at sites identified by a regulatory body in the future. If that occurs, we cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean-up costs. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liabilities on all potentially responsible parties.
We cannot be sure that existing environmental regulations will not be revised or that new regulations intended to protect the environment will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our results of operations.
We have a net deferred tax asset of 14.0 million and we cannot guarantee that we will be able to generate sufficient future taxable income to realize a significant portion of this net deferred tax asset, which could lead to a writedown (or even a loss) of the net deferred tax asset and adversely affect our operating results and financial position.
We have a net deferred tax asset of $14.0 million at December 31, 2009. The net deferred tax asset is the result of our recent acquisitions of Frontier Natural Gas and Bangor Gas Company. We may continue to depreciate approximately $82.0 million of their capital assets using the useful lives and rates employed by those companies, resulting in a potential future federal and state income tax benefit of approximately $19.1 million over a 20 year period using applicable federal and state income tax rates. Under Internal Revenue Code Section 382, our ability to recognize tax deductions as a result of this tax benefit will be limited during the first 5 years following the acquisitions.
Following ASC 740, our balance sheet at December 31, 2008 reflects a gross deferred tax asset of approximately $19.0 million, offset by a valuation allowance of approximately $7.5 million, resulting in a net deferred tax asset associated with the acquisition of approximately $11.5 million. The excess of the net deferred tax assets received in the transactions over their respective purchase prices has been reflected as an extraordinary gain of approximately $6.8 million on our income statement for the year ended June 30, 2008 in accordance with the provisions of ASC 805.
During the year ended December 31, 2009, we conducted a study of the deferred tax asset and valuation allowance, and based on our updated earnings projections and more complete data from the seller’s tax returns, we determined that $2.8 million of the valuation allowance related to federal taxes is no longer needed but that the state portion should be increased by $400,000. Accordingly, we reduced the valuation allowance to approximately $5.1 million. In addition, we increased the gross deferred tax asset to $19.1 million. As a result, the net deferred tax asset increased to approximately $14.0 million at December 31, 2009. Included in the results of our Corporate and Other segment for the year ended December 31, 2009 is the income tax benefit of approximately $2.8 million related to the elimination of the federal portion of the valuation allowance. An income tax expense of $300,000 resulting from the increase in the state portion of the valuation allowance partially offset by the increase in the gross deferred tax asset is included in the results of the Natural Gas Operations segment.
We cannot guarantee that we will be able to generate sufficient future taxable income to realize the $14.0 million net deferred tax asset over the next 20 years. Management will reevaluate the valuation allowance each year on completion of updated estimates of taxable income for future periods, and will further reduce the deferred tax asset by the new valuation allowance if, based on the weight of available evidence, it is more likely than not that we will not realize some portion or all of the recognized deferred tax assets. If the estimates indicate that we are unable to use all or a portion of the net deferred tax asset balance, we will record and charge a greater valuation allowance to income tax expense. Failure to achieve projected levels of profitability could lead to a write down in the deferred tax asset if the recovery period becomes uncertain or longer than expected and could also lead to the expiration of the deferred tax asset between now and 2029, either of which would adversely affect our operating results and financial position.
Changes in the market price and transportation costs of natural gas could result in financial losses that would negatively impact our results of operations.
We are exposed to the impact of market fluctuations in the price and transportation costs of natural gas. We purchase and store gas for distribution later in the year. We also enter agreements to buy or sell gas at a fixed price. We may use such arrangements to protect profit margins on future obligations to deliver gas at a fixed price, or to attempt to protect against adverse effects of potential market price declines on future obligations to purchase gas at fixed prices. Further, we are exposed to losses in the event of nonperformance or nonpayment by the counterparties to our supply agreements, which could have a material adverse impact on our earnings for a given period.
Risks Related to Our Acquisition Strategy
We face a variety of risks associated with acquiring and integrating new business operations.
The growth and success of our business will depend to a great extent on our ability to acquire new assets or business operations and to integrate the operations of businesses that we have recently acquired, including Orwell and NEO as well as those that we may acquire in the future. We cannot provide assurance that we will be able to:
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identify suitable acquisition candidates or opportunities,
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acquire assets or business operations on commercially acceptable terms,
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effectively integrate the operations of any acquired assets or businesses with our existing operations,
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manage effectively the combined operations of the acquired businesses,
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achieve our operating and growth strategies with respect to the acquired assets or businesses,
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reduce our overall selling, general, and administrative expenses associated with the acquired assets or businesses, or
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comply with the internal control requirements of Section 404 as a result of an acquisition.
The integration of the management, personnel, operations, products, services, technologies, and facilities of Orwell, NEO or any businesses that we acquire in the future could involve unforeseen difficulties. These difficulties could disrupt our ongoing businesses, distract our management and employees, and increase our expenses, which could have a material adverse affect on our business, financial condition, and operating results.
To the extent we are successful in making an acquisition, we may be exposed to a number of risks.
Any acquisition may involve a number of risks, including the assumption of material liabilities, the terms and conditions of any state or federal regulatory approvals required for an acquisition, the diversion of management’s attention from the management of daily operations to the integration of acquired operations, difficulties in the integration and retention of employees and difficulties in the integration of different cultures and practices, as well as in the integration of broad and geographically dispersed personnel and operations. The failure to make and integrate acquisitions successfully, including Orwell and NEO, could have an adverse effect on our ability to grow our business.
Subsequent to the consummation of an acquisition, we may be required to take write-downs or write-offs, restructuring and impairment charges or other charges that could have a significant negative impact on our financial condition, results of operations and our stock price.
We recently acquired Orwell and NEO and are in the process of completing other potential acquisitions. There could be material issues present inside a particular target business that are not uncovered in the course of due diligence performed prior to the acquisition, and there could be factors outside of the target business and outside of our control that later arise. As a result of these factors, after an acquisition is complete we may be forced to write-down or write-off assets, restructure our operations or incur impairment or other charges relating to an evaluation of goodwill and acquisition-related intangible assets that could result in our reporting losses. In addition, unexpected risks may arise and previously known risks may materialize in a manner not consistent with our preliminary risk analysis.
Risks Related to Our Common Stock
Our ability to pay dividends on our common stock is limited.
We cannot assure you that we will continue to pay dividends at our current monthly dividend rate or at all. In particular, our ability to pay dividends in the future will depend upon, among other things, our future earnings, cash requirements and covenants under our existing credit facility and any future credit agreements to which we may be a party. In addition, acquisitions funded by the issuance of our common stock, such as our acquisitions of Orwell and
NEO, increase the number of our shares outstanding and may make it more difficult to continue dividends at our current rate.
The possible issuance of future series of preferred stock could adversely affect the holders of our common stock.
Pursuant to our articles of incorporation, our board of directors has the authority to fix the rights, preferences, privileges and restrictions of unissued preferred stock and to issue those shares without any further action or vote by the shareholders. The rights of the holders of our common stock will be subject to, and may be adversely affected by, the rights of the holders of any series of preferred stock that may be issued in the future. These adverse effects could include subordination to preferred shareholders in the payment of dividends and upon our liquidation and dissolution, and the use of preferred stock as an anti-takeover measure, which could impede a change in control that is otherwise in the interests of holders of our common stock.
Organization, Structure and Management Risks
Our credit facilities contain restrictive covenants that may reduce our flexibility, and adversely affect our business, earnings, cash flow, liquidity and financial condition.
The terms of our credit facilities impose significant restrictions on our ability and, in some cases, the ability of our subsidiaries, to take a number of actions that we may otherwise desire to take, including:
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requiring us to dedicate a substantial portion of our cash flow from operations to the payment of principal and interest on our indebtedness, thereby reducing the availability of cash flow for working capital, capital expenditures and other business activities,
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requiring us to meet certain financial tests, which may affect our flexibility in planning for, or reacting to, changes in our business and the industries in which we operate,
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limiting our ability to sell assets, make investments or acquire assets of, or merge or consolidate with, other companies,
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limiting our ability to repurchase or redeem our stock or enter into transactions with our shareholders or affiliates, and
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limiting our ability to grant liens, incur additional indebtedness or contingent obligations or obtain additional financing for working capital, capital expenditures, acquisitions and general corporate and other activities.
These covenants place constraints on our business and may adversely affect our growth, business, earnings, cash flow, liquidity and financial condition. Our failure to comply with any of the financial covenants in the credit facilities may result in an event of default which, if not cured or waived, could result in the acceleration of the debt under the credit facilities or other agreements we may enter into from time to time that contain cross-acceleration or cross-default provisions. If this occurs, there can be no assurance that we would be able to refinance or otherwise repay such indebtedness, which could result in a material adverse effect on our business, earnings, cash flow, liquidity and financial condition.
Our primary assets are our operating subsidiaries, and our subsidiaries’ credit facilities include financial covenants that limit our ability to obtain revenue from those subsidiaries, which may limit our ability to pay dividends to shareholders.
We are a holding company with no direct operations and our principal assets are the equity securities of our subsidiary utilities. We rely on dividends from our subsidiaries for our cash flows, thus our ability to pay dividends to our shareholders and finance acquisitions would be dependent on the ability of our subsidiaries to generate sufficient net income and cash flows to pay upstream dividends to us. Further, our subsidiaries are legally distinct from us, and although they are wholly-owned and controlled by us, our ability to obtain distributions from them by way of dividends, interest or other payments (including intercompany loans) is subject to restrictions imposed by their term loans and credit facilities (under which they are borrowers and we are a guarantor). For example,
•
We may cause our Montana, Wyoming, North Carolina and Maine operating subsidiaries to pay a dividend only if the dividend, when combined with dividends over the previous five years, would not exceed 75% of their net income over those years,
•
We may cause Orwell and Lightning Pipeline to distribute no more than 60% of Orwell’s net income to us during any fiscal year, and
•
We may cause NEO, Great Plains and GPL to distribute dividends to us only if their consolidated net worth, after payment of the dividend, is no less than $1,815,000 as positively increased by 100% of net income as of the end of each fiscal quarter and year.
Additionally, as a condition to approving our holding company reorganization, the MPSC required that we stipulate to ring-fencing restrictions that require our Montana, Wyoming, North Carolina and Maine operating subsidiaries to meet certain notice and financial requirements prior to paying dividends that are above certain financial thresholds or irregularly timed.
These dividend restrictions, in addition to other financial covenants contained in the credit facilities and ring-fencing restrictions, place constraints on our business and may adversely affect our cash flow, liquidity and financial condition as well as our ability to finance acquisitions or pay dividends . Further, we may be required to comply with additional covenants. Failure to comply with financial covenants may result in the acceleration of the debt and foreclosure of our assets, which would have a material adverse effect on our business, earnings, cash flow, liquidity and financial condition. For further details on the financial covenants contained in the credit facilities, see “Restrictions on Payment of Dividends” on page 28 of this Annual Report on Form 10-K.
In acquiring the Ohio Companies, we incurred $20.9 million in additional debt, $8.2 million of which will mature in the last quarter of 2010. Our short term debt and high degree of leverage limit our flexibility in managing our business, and our inability to satisfy debts and comply with other financial covenants in the short or long term could materially and adversely affect our business, earnings, cash flow, liquidity and financial condition.
When we acquired the Ohio Companies, we guaranteed approximately $20.9 million of the Ohio companies’ debt. Richard Osborne guarantees substantially all of the third party debt of the Ohio Companies. Our debt service requirements have increased dramatically as a result of the acquisition. In addition, approximately $8.2 million of this debt will mature during the last quarter of 2010. This additional debt has made us more leveraged on a consolidated basis.
Our high degree of leverage may adversely affect our ability to respond to adverse changes in economic, business or market conditions. For example:
•
we may be required to dedicate a substantial portion of our cash flow from operations to required payments on debt, thereby reducing the availability of cash flow for working capital, capital expenditures and other general corporate activities, and
•
covenants relating to our debt may limit our ability to obtain additional financing for working capital, capital expenditures and other general corporate activities.
The occurrence of any one of these events could have a material adverse effect on our business, financial condition, results of operations, prospects and ability to satisfy our obligations under our credit facilities in the short and long term.
Further, our failure to comply with the financial covenants, pay our debt service requirements and pay or refinance our short term debt may result in an event of default which, if not cured or waived, could result in the acceleration of the debt under our credit facilities or other agreements that we may enter into from time to time that contain cross-acceleration or cross-default provisions. If this occurs, there can be no assurance that we would be able to refinance or otherwise repay such debt, which could result in a material adverse effect on our business, earnings, cash flow, liquidity and financial condition.
Our performance depends substantially on the performance of our executive officers and other key personnel and the ability of our new management team to fully implement our business strategy.
The success of our business depends on our ability to attract, train, retain, and motivate high quality personnel, especially highly qualified managerial personnel. Poor execution in the transition of our management team or the loss of services of key executive officers or personnel could have a material adverse effect on our business, results of operations and financial condition.
During fiscal 2008, new chief executive, operating and financial officers joined our management team. Because of these recent changes, our management team has not worked together as a group for an extended period of time and may not work together effectively to successfully implement our business strategy. If our new management team is unable to accomplish our business objectives, our ability to successfully operate the Company and acquire and integrate new business operations may be severely impaired.
We have entered a limited liability operating agreement with third parties to develop and operate oil, gas and mineral leasehold estates, which exposes us to the risk associated with oil, gas and mineral exploration as well as the risks inherent in relying upon third parties in business ventures and we may enter into similar agreements in the future.
Through our subsidiary Energy West Resources, Inc. (EWR), we have entered an operating agreement with various third parties regarding Kykuit Resources, LLC (Kykuit), a developer and operator of oil, gas and mineral leasehold estates located in Montana. Through EWR, we own 21.98% of the membership interests of Kykuit, and because Kykuit’s primary purpose is oil, gas and mineral exploration, our investment in Kykuit is subject to the risks associated with that business, including the risk that little or no oil, gas or minerals will be found. We have a net investment after undistributed losses of approximately $800,000 in Kykuit, and we may be required to invest additional amounts of up to approximately $1.5 million. Whether or not we may be required to invest additional funds will depend on the success, or lack thereof, of Kykuit in its initial drilling. We are entitled under the Kykuit operating agreement, as amended and restated, to exercise reasonable discretion to cease further investments in the event certain initial exploratory drilling efforts are unsuccessful.
We depend upon the performance of third party participants in endeavors such as Kykuit, and their performance of their obligations to us are outside our control. If these parties do not meet or satisfy their obligations under these arrangements, the performance and success of endeavors such as Kykuit may be adversely affected. If third parties to operating agreements and similar agreements are unable to meet their obligations we may be forced to undertake the obligations ourselves or incur additional expenses in order to have some other party perform such obligations. We may also be required to enforce our rights that may cause disputes among third parties and us. If any of these events occur, they may adversely impact us, our financial performance and results of operations.
We have entered into certain transactions with persons who are our directors and may enter into additional transactions in the future.
Richard M. Osborne, our chairman of the board and chief executive officer, owns an interest in Kykuit, a party to the joint venture arrangement involving EWR. John D. Oil and Gas Company, a publicly-held oil and gas exploration company of which Mr. Osborne is the chairman of the board and chief executive officer, our director and chief financial officer Thomas J. Smith is a director and our director Gregory J. Osborne is president, is an owner and the managing member of Kykuit. Additionally, we lease office space in Mentor, Ohio from OsAir, Inc., of which Richard M. Osborne is the president and chief executive officer. Mr. Osborne also owned all or nearly all of the outstanding equity interests of each of Orwell, Lightning Pipeline, NEO, Great Plains and GPL, which we acquired on January 5, 2010 and was the largest acquisition in our history, and Lightning Pipeline is currently indebted to Mr. Osborne in the amount of approximately $2.0 million under a 6% promissory note that matures in 2014. Finally, NEO and Orwell are party to various gas sales, transportation and metering agreements with entities owned and controlled by Mr. Osborne. In the future, we may enter into additional transactions with our directors or entities controlled by our directors. We cannot assure you that our shareholders will view the benefits of these transactions in the same manner that we or our board of directors do.
Item 2.
Item 2.
Properties.
Montana and Wyoming
In Great Falls, Montana, we own an 11,000 square foot office building, which serves as our headquarters, and a 3,000 square foot service and operating center (with various outbuildings), which supports day-to-day maintenance and construction operations. We own approximately 470 miles of underground distribution lines, or “mains,” and related metering and regulating equipment in and around Great Falls, Montana. In West Yellowstone, Montana, we own an office building and a liquefied natural gas plant that provides natural gas through approximately 14 miles of underground mains owned by us. We own approximately 10 miles of underground mains in the town of Cascade, as well as two large propane storage tanks. In Cut Bank, Montana we own an office building/operating center and approximately 33 miles of underground mains.
In addition, we lease 1,000 square feet of office space in Mentor, Ohio that serves as the offices for our chief executive officer, chief financial officer and certain other personnel associated with our Ohio subsidiaries and our holding company operations under a three year lease agreement.
We own a 48% gross working interest (41% net revenue interest) in 160 natural gas production wells and three gathering pipelines in north central Montana. The natural gas wells are operated by a third party and we are invoiced each month for our share of the operating and capital expenses incurred. We acquired our interests in the wells by quitclaim deeds conveying interests in certain oil and gas leases for the wells from sellers who were in financial distress. We chose to purchase their interests despite the uncertain nature of the conveyance because we were able to negotiate purchase prices that, we believe, were fair and reasonable under, and accounted for, that circumstance. It is possible that our interests will be challenged in the future, but no such challenge has been made since acquiring the interests in 2002 and 2003 and we have no notice that such a challenge is forthcoming.
In Cody, Wyoming, we lease office and service buildings under long-term lease agreements. We own approximately 570 miles of transmission and distribution mains and related metering and regulating equipment, all of which are located in or around Cody, Meeteetse, and Ralston, Wyoming.
Our pipeline operations own two pipelines in Wyoming and Montana. One is currently being operated as a gathering system. The other pipeline is operating as a FERC regulated natural gas interstate transmission line. The pipelines extend from north of Cody, Wyoming to Warren, Montana.
North Carolina
Our North Carolina operations are headquartered in Elkin, North Carolina. The facility is a 16,000 square foot building that has a combination of office, shop and warehouse space. We are subject to a lease agreement through June 2011. We own approximately 350 miles of transmission and distribution lines and related metering and regulating equipment.
Maine
In Bangor, Maine, we lease two office buildings under long-term lease agreements. We have approximately 110 miles of transmission and distribution lines and related metering and regulating equipment.
Ohio and Western Pennsylvania
The Company maintains facilities for its Ohio and Pennsylvania operations located in Lancaster, Strasburg and Orwell, Ohio. These facilities for office and service space are leased under various long-term lease agreements with related parties. We own approximately XX miles of transmission and distribution lines and related metering and regulating equipment that support these operations.
Item 3.
Item 3.
Legal Proceedings.
We are involved in lawsuits that have arisen in the ordinary course of our business. We are contesting each of these lawsuits vigorously and believe we have defenses to the allegations that have been made.
On February 21, 2008, a lawsuit captioned Shelby Gas Association v. Energy West Resources, Inc., Case No. DV-08-008, was filed in the Ninth Judicial District Court of Toole County, Montana. Shelby Gas Association (“Shelby”) alleges a breach of contract by the Company’s subsidiary, EWR, to provide natural gas to Shelby. The parties each filed cross motions for summary judgment. The court heard oral arguments for the pending motions on July 24, 2009. On September 9. 2009, the court ruled that Shelby Gas Association can proceed with their case for damages. The court also ruled that we can seek a setoff against any damages awarded to Shelby in an amount equal to the damages the Company has suffered as a result of Shelby’s alleged breach of contract. On March 24, 2010, the judge handling the case granted the Company’s motions in limine regarding various aspects of damages which Shelby was seeking, including disallowance of attorneys’ fees, punitive damages and certain consequential damages. A trial has been set for April 2010. The Company continues to believe that this lawsuit is without merit and is vigorously defending itself.
In our opinion, the outcome of these lawsuits, including the Shelby litigation, will not have a material adverse effect on our financial condition, cash flows or results of operations.
Item 4.
Item 4.
[RESERVED]
PART II
Item 5.
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities.
Our Common Stock
Our common stock trades on the NYSE Amex Equities (formerly known as the American Stock Exchange) under the symbol “EGAS.” On February 1, 2008, the Board of Directors authorized a 3-for-2 stock split of the company’s $0.15 par value common stock. As a result of the split, 1,437,744 additional shares were issued, and additional paid-in capital was reduced by $215,619. All references in the accompanying financial statements to the number of common shares and per-share amounts for the first quarter of 2008 and all previous time periods have been restated to reflect the stock split.
The following table sets forth, for the quarters indicated, the range of high and low prices of our common stock from the Nasdaq Monthly Statistical Reports and the NYSE Amex Equities, adjusted for the 3 for 2 stock split effectuated February 1, 2008.
Holders of Record
As of March 12, 2010, there were approximately 482 record owners of our common stock. We estimate that an additional 2,071 shareholders own stock in their accounts at brokerage firms and other financial institutions.
Dividend Policy
On October 22, 2007, we amended our credit facility with Bank of America to begin paying monthly, rather than quarterly, cash dividends on our common shares. We began to pay a monthly dividend on December 28, 2007. Monthly dividend payments per common share (adjusted for the stock split) were:
Restrictions on Payment of Dividends
As a holding company, our primary assets and sources of cash flow are our operating subsidiaries. The credit facilities of our operating subsidiaries restrict their ability to pay dividends to us, which restricts our ability to pay dividends to our shareholders. Payment of future cash dividends, if any, and their amounts, will be dependent upon a number of factors, including those restrictions, our earnings, financial requirements, number of shares of capital stock outstanding and other factors deemed relevant by our board of directors.
Energy West, which currently serves as a distribution company in Montana and Wyoming and serves as a holding company for our distribution operations in North Carolina and Maine, has a credit facility with Bank of America that restricts Energy West’s ability to pay dividends to us. Under the terms of the credit facility, Energy West is permitted to pay dividends no more frequently than once each calendar month. Further, Energy West is forbidden from paying dividends in certain circumstances. For instance, Energy West may not pay a dividend if the dividend, when combined with dividends over the previous five years, would exceed 75% of Energy West’s net income over those years. For the purposes of this restriction, extraordinary gain, such as the $6.8 million of extraordinary gain associated with the purchase of Frontier Natural Gas and Bangor Gas Company, is not included in net income. Further, stock repurchases and redemptions are treated as payments of dividends for purposes of determining whether it is permissible to pay the proposed dividend under this restriction. In addition, Energy West may not pay a dividend if Energy West is in default, or if payment would cause Energy West to be in default, under the terms of the unsecured credit agreement. Energy West also may not pay a dividend if payment would cause Energy West’s earnings before interest and taxes (EBIT), to be less than twice its interest expense. For the purpose of this restriction, EBIT and interest expense are measured over a four-quarter time period that ends with the most recently completed fiscal quarter. Similarly, they may not pay a dividend if payment would cause their total debt to exceed 65% of their capital. For the purpose of this restriction, total debt and capital are measured for the most recently completed fiscal quarter.
In addition to the Bank of America credit facility, Energy West, also has unsecured senior notes outstanding that also contain restrictions on dividend payments. Under the unsecured senior notes, Energy West may not pay a dividend to us if payment would cause its total payments of dividends for the five years prior to the proposed payment to exceed its consolidated net income for those five years.
Additionally, as a condition to approving our holding company reorganization, the MPSC required that we stipulate to ring-fencing restrictions that require Energy West to meet certain notice and financial requirements prior to paying dividends that are either above certain financial thresholds or irregularly timed (or both).
Our Ohio subsidiaries’ credit facilities with The Huntington National Bank, N.A. (“Huntington”) and Citizens Bank limit their ability to transfer funds to us in the form of loans, advances, dividends or other distributions. The Citizens Bank credit facility allows NEO, Great Plains and GPL to pay dividends to Energy, Inc. only if their net worth (as defined in the loan agreements) after payment of any dividends would not be less than $1,815,000 on a consolidated basis as positively increased by 100% of net income as of the end of each fiscal quarter and fiscal year. The Huntington credit facility allows Orwell and Lightning Pipeline to pay dividends to Energy, Inc. only if the aggregate amount of all dividends, distributions, redemptions and repurchases in any fiscal year do not exceed 60% of net income (as defined in the loan agreements) of Orwell for each fiscal year.
For additional information on loan covenants and restrictions contained in the Bank of America, Citizens and Huntington credit facilities, see “Management Discussion and Analysis − Liquidity and Capital Resources” on page 52. Additional information on the covenants and restrictions of the Bank of America loan may also be found in Note 11 to our Consolidated Financial Statements.
Recent Sales of Unregistered Securities
In connection with our acquisition of Cut Bank Gas, we issued 56,900 unregistered shares of our common stock in an aggregate value of $500,000 to the sellers in payment of the purchase price. We are not obligated to register the shares under the terms of the purchase agreement we entered with the sellers. The issuance of shares to the sellers was made in reliance on Section 4(2) of the Securities Act of 1933 for the offer and sale of securities not involving a public offering.
Performance Graph
The graph below matches our cumulative five-year total shareholder return on common stock with the cumulative total returns of the S&P 500 index and the S&P Utilities index. The graph tracks the performance of a $100 investment in our common stock and in each of the indexes (with the reinvestment of all dividends) from December 31, 2004 to December 31, 2009.
Comparison of 5 Year Cumulative Total Return
Assumes Initial Investment of $100
December 2009
Item 6.
Item 6.
Selected Financial Data.
The selected financial data presented below are derived from our historical consolidated financial statements, which were audited by our independent registered public accounting firms in each of those years. The selected financial data should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and our Consolidated Financial Statements and the related notes included elsewhere in this Form 10-K. Amounts are in thousands, except per share and number of share amounts. Certain prior period revenues and expenses have been reclassified as income from discontinued operations. Results from the Ohio Companies are not included in this historical financial data.
(1)
Taxes other than income include $250,000 in fiscal 2007 for additional personal property taxes assessed by the Montana Department of Revenue. The 2008 increase results from personal property taxes on our acquired companies in Maine and North Carolina
(2)
Total interest charges include expenses in fiscal 2007 associated with refinancing our long-term debt. We expensed $991,000 of debt issue costs related to the refinanced debt.
Item 7.
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
This discussion should be read in conjunction with the consolidated financial statements, notes and tables included elsewhere in this Form 10-K. Management’s discussion and analysis contains forward-looking statements that are provided to assist in the understanding of anticipated future performance. However, future performance involves risks and uncertainties which may cause actual results to differ materially from those expressed in the forward-looking statements. See “Forward-Looking Statements.”
Executive Overview
Our primary source of revenue and operating margin has been the distribution of natural gas to end-use residential, commercial, and industrial customers. We have natural gas distribution operations in Montana, Wyoming, and we recently acquired distribution operations in North Carolina and Maine. We also market and distribute natural gas in Montana and Wyoming and conduct interstate pipeline operations in Montana and Wyoming. Formerly we conducted propane operations in Arizona, but those operations were sold in 2007.
We have five reporting segments: natural gas operations, marketing and production operations, pipeline operations, discontinued operations and corporate and other. Information regarding our Arizona propane operations is reported under discontinued operations. Our corporate and other reporting segment was recently established to report various income and expense items associated with corporate acquisitions and other equity transactions, including a deferred tax asset we received in connection with the acquisitions of our North Carolina and Maine distribution operations.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operation are based upon consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and disclosure of contingent assets and liabilities, if any, at the date of the financial statements. We analyze our estimates, including those related to regulatory assets and liabilities, income taxes and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements. See a complete list of significant accounting policies in Note 1 of the notes to the consolidated financial statements included herein.
Regulatory Accounting
Our accounting policies historically reflect the effects of the rate-making process in accordance with ASC 980 Regulated Operations. Our regulated natural gas segment continues to be cost-of-service rate regulated, and we believe the application of ASC 980 to that segment continues to be appropriate. We must reaffirm this conclusion at each balance sheet date. If, as a result of a change in circumstances, we determine that the regulated natural gas segment no longer meets the criteria of regulatory accounting under ASC 980, that segment will have to discontinue regulatory accounting and write off the respective regulatory assets and liabilities.
The application of ASC 980 results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. In some cases, we record regulatory assets before we have received approval for recovery from the state regulatory agencies. We must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. We base this conclusion on certain factors, including changes in the regulatory environment, recent rate orders issued by regulatory agencies, and the status of any potential new legislation. Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or for probable future refunds to customers. At December 31, 2009, our total regulatory assets were $2.4 million and our total regulatory liabilities were $1.7 million. A write-off of the regulatory assets and liabilities could have a material impact on our consolidated financial statements.
Our natural gas segment contains regulated utility businesses in the states of Montana, Wyoming, Maine and North Carolina and the regulation varies from state to state. If future recovery of costs, in any such jurisdiction, ceases to be probable, we would be required to charge these assets to current earnings. However, there are no current or expected proposals or changes in the regulatory environment that impact the probability of future recovery of these assets. In addition, deregulation would be a change that occurs over time, due to legal processes and procedures, which could moderate the impact to our consolidated financial statements.
Our most significant regulatory asset/liability relates to the recoverable/refundable costs of gas purchases. We account for purchased gas costs in accordance with procedures authorized by the state regulatory agencies, under which purchased gas costs that are different from those provided for in present rates are accumulated and recovered or credited through future rate changes.
Our gas cost recoveries are monitored closely by the regulatory commissions in all of the states in which we operate. The gas cost recoveries are adjusted monthly in three of the four states in which we operate, and annually in the fourth. In addition, all of the states in which we operate require us to submit gas procurement plans, which we follow closely. These plans are reviewed annually by each of the regulatory commissions. The adjustment of gas cost recoveries and the gas procurement plans reduce the risk of disallowance of recoverable gas costs. The regulatory commissions have not disallowed any of our recoverable gas costs or other costs included in our regulatory assets in the last three years. Therefore, we believe it is highly probable that we will recover the regulatory assets that have been recorded.
We use our best judgment when recording regulatory assets and liabilities. Regulatory commissions, however, can reach different conclusions about the recovery of costs and those conclusions could have a material impact on our consolidated financial statements.
Accumulated Provisions for Doubtful Accounts
We encounter risks associated with the collection of our accounts receivable. As such, we record a provision for those accounts receivable that are considered to be uncollectible. In order to calculate the appropriate provision, we primarily utilize the historical accounts receivable write-off amounts. The underlying assumptions used for the provision can change from period to period and the provision could potentially cause a material impact to our income statement and working capital. The actual weather, commodity prices, and other internal and external economic conditions, such as the mix of the customer base between residential, commercial and industrial, may vary significantly from our assumptions and may impact our operating income.
Unbilled Revenues and Gas Costs
We estimate the gas service that has been rendered from the latest date of each meter reading cycle to the month end. This estimate of unbilled usage is based on projected base load usage for each day unbilled plus projected weather sensitive usage for each degree day during the unbilled period. Unbilled revenues and gas costs are calculated from the estimate of unbilled usage multiplied by the rates in effect at month end.
Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month’s estimate is reversed. Likewise, the associated gas costs are recorded as cost of revenue and a payable and the prior month’s estimate is reversed. Actual price and usage patterns may vary from these assumptions and may impact revenues recognized and costs recorded. The critical component of calculating unbilled revenues is estimating the usage on a calendar month basis. Our estimated volumes used in the unbilled revenue calculation have varied from our actual monthly metered volumes by less than plus or minus 10% on December 31, 2009, December 31, 2008 and on June 30 of each of the last three fiscal years. A variance of 10% on our gross margin at December 31, 2009 would have been ($114,000).
Fair Value of Financial Instruments
Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, and bank borrowings. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the highly liquid nature of these short-term instruments. The allowance for doubtful accounts receivable is assessed quarterly based on sales and the breakout of aged receivables. In June, when the revenue cycle is low, specific customer accounts are chosen for write off. After this adjustment is made, the adequacy of the allowance is considered once again, based on the aging of total accounts receivable and is adjusted if needed. The fair values of the bank borrowings approximate the carrying amounts as of December 31, 2008, December 31, 2009 and at June 30, 2008 and 2007, and were determined based upon variable interest rates currently available to us for borrowings with similar terms.
Recoverable/Refundable Costs of Gas and Propane Purchases
We account for purchased gas costs in accordance with procedures authorized by the state regulatory agencies, under which purchased gas costs that are different from those provided for in present rates are accumulated and recovered or credited through future rate changes.
Deferred Tax Asset and Income Tax Accruals
Judgment, uncertainty, and estimates are a significant aspect of the income tax accrual process that accounts for the effects of current and deferred income taxes. Uncertainty associated with the application of tax statutes and regulations and the outcomes of tax audits and appeals require that judgment and estimates be made in the accrual process and in the calculation of effective tax rates.
Effective tax rates (ETR) are also highly impacted by assumptions. ETR calculations are revised every quarter based on best available year-end tax assumptions (income levels, deductions, credits, etc.) by legal entity; adjusted in the following year after returns are filed, with the tax accrual estimates being trued-up to the actual amounts claimed on the tax returns; and further adjusted after examinations by taxing authorities have been completed.
In accordance with the interim reporting rules under ASC 740, a tax expense or benefit is recorded every quarter to adjust our tax expense to the estimated annual effective rate.
We have a net deferred tax asset of $14.0 million. The net deferred tax asset is the result of our recent acquisitions of Frontier Natural Gas and Bangor Gas Company. We may continue to depreciate approximately $82.0 million of their capital assets using the useful lives and rates employed by those companies, resulting in a potential future federal and state income tax benefit of approximately $19.1million over the 20 year period using applicable federal and state income tax rates. Under Internal Revenue Code Section 382, our ability to recognize tax deductions as a result of this tax benefit will be limited during the first five years following the acquisitions.
Following ASC 740, our balance sheet at December 31, 2008 reflects a gross deferred tax asset of approximately $19.0 million, offset by a valuation allowance of approximately $7.5 million, resulting in a net deferred tax asset associated with the acquisition of approximately $11.5 million. The excess of the net deferred tax assets received in the transactions over their respective purchase prices has been reflected as an extraordinary gain of approximately $6.8 million on our income statement for the twelve months ended June 30, 2008 in accordance with the provisions of ASC 805.
During the year ended December 31, 2009, we conducted a study of the deferred tax asset and valuation allowance, and based on our updated earnings projections and more complete data from the seller’s tax returns, we determined that $2.8 million of the valuation allowance related to federal taxes is no longer needed but that the state portion should be increased by $400,000. Accordingly, we reduced the valuation allowance to approximately $5.1 million. In addition, we increased the gross deferred tax asset to $19.1 million. As a result, the net deferred tax asset increased to approximately $14.0 million at December 31, 2009. Included in the results of our Corporate and Other segment for the year ended December 31, 2009 is the income tax benefit of approximately $2.8 million related to the elimination of the federal portion of the valuation allowance. An income tax expense of $300,000 resulting from the increase in the state portion of the valuation allowance partially offset by the increase in the gross deferred tax asset is included in the results of the Natural Gas Operations segment.
We cannot guarantee that we will be able to generate sufficient future taxable income to realize the $14.0 million net deferred tax asset over the next 20 years. Management will reevaluate the valuation allowance each year on completion of updated estimates of taxable income for future periods, and will reduce the deferred tax asset by the new valuation allowance if, based on the weight of available evidence, it is more likely than not that we will not realize some portion or all of the deferred tax assets. If the estimates indicate that we are unable to use all or a portion of the net deferred tax asset balance, we will record and charge a greater valuation allowance to income tax expense. Our calculation of the valuation allowance is based on projections of our taxable income in future years. Based on these projections, we estimate that the state tax portion of the benefit will result in large net operating losses that may not be recoverable. Accordingly, we have placed the valuation allowance of approximately $5.1 million on this portion.
For the federal tax portion, there are three years remaining of the five year Internal Revenue Code limitation period discussed above. We estimate that approximately 7% of the tax benefit will be available to us during this three year period. Based on our estimates of taxable income, we project that we will recover approximately 92% of the benefit in the following nine years, with 1% recovered in small increments in the remaining years. Based on this analysis, we believe that a valuation allowance on the federal portion of the benefit is not necessary. Failure to achieve projected levels of profitability could lead to a write-down in the deferred tax asset if the recovery period becomes uncertain or longer than expected and could also lead to the expiration of the deferred tax asset between now and 2029, either of which would adversely affect our operating results and financial position.
Goodwill
Goodwill represents the excess of the purchase price over the fair value of identifiable net tangible and intangible assets acquired in a business combination. Goodwill is required to be tested for impairment annually, which is completed in the fourth quarter, or more frequently if events or changes in circumstances indicate that goodwill may be impaired.
Results of Consolidated Operations
The following discussion of financial condition and results of operations should be read in conjunction with the Consolidated Financial Statements and Notes thereto and other financial information included elsewhere in this Annual Report.
Effective December 31, 2008, we changed our fiscal year end from June 30 to December 31. This change was made in order to align our fiscal year end with other companies within the industry. The resulting six-month period ended December 31, 2008 may be referred to herein as the “Transition Period”. The six-month period ended December 31, 2007 is unaudited. We refer to the period beginning July 1, 2007 and ending June 30, 2008 as “fiscal 2008”, and the period beginning July 1, 2006 and ending June 30, 2007 as “fiscal 2007”.
In order to provide a meaningful comparison with our current calendar year 2009 results, the tables and discussion that follow compare the results for the twelve months ended December 31 2009 with the unaudited results of the twelve months ended December 31, 2008, as well as the six months ended December 31, 2008 and 2007 (unaudited) and the fiscal years ended June 30, 2008 and 2007.
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
Net Income - Our net income for the year ended December 31, 2009 was approximately $6.8 million, compared to net income of approximately $3.3 million for the year ended December 31, 2008, an increase of $3.5 million, or 106%. This increase was primarily the result of an increase in the net income from our natural gas operations of $1.6 million and from our corporate and other operations segment of $2.8 million, offset by a decrease in net income from our gas marketing and production operation of $950,000. The increase in income in our corporate and other operations segment is due primarily to the tax benefit realized from the reduction of the valuation allowance on our deferred tax asset. (See Note 3 to our Consolidated Financial Statements for further discussion of the deferred tax asset). The principal changes that contributed to the improvement in net income are explained below.
Revenues - Our revenues for the year ended December 31, 2009 were approximately $71.5 million compared to $87.3 million in the year ended December 31, 2008, a decrease of $15.8 million or 18%. The decrease was primarily attributable to: (1) a natural gas revenue decrease of $8.3 million, due to the significantly lower index price of natural gas passed through to our customers in 2009 and partially offset by increased sales in our Maine
market and (2) a decrease in our marketing and production operation’s revenue of $7.6 million, due also to significantly lower prices for natural gas and to lower volumes produced from our production operation.
Gross Margin - Gross margin was approximately $24.8 million in the year ended December 31, 2009 compared to $23.8 million in the year ended December 31, 2008, an increase of $983,000 or 4%. Our natural gas operation’s margins increased $1.5 million, of which $1.2 million was due to sales growth in our Maine market, and $194,000 was earned from two months of operations from our Cut Bank acquisition. Gross margin from our marketing and production operations decreased $500,000, due to a $1.1 million decrease in margin from gas production, a $100,000 decrease in mark to market revenue, partially offset by a $700,000 increase in margin from gas marketing.
Expenses Other Than Cost of Sales - Expenses other than cost of sales decreased by $1.2 million to $15.7 million in the year ended December 31, 2009 from $16.9 million in the year ended December 31, 2008. The year ended December 31, 2008 included $441,000 of costs related to an equity offering that was not completed. In addition, the year ended December 31, 2008 included an increase in expense for vacation accrual of approximately $401,000 because of the accrual needed for vacation that would accrue on January 1, 2009. In 2009, we changed our vacation plan so that employees accrue vacation on a monthly basis, resulting in a decrease in the accrual at December 31, 2009 of approximately $409,000. The end result is a decrease in vacation accrual expense of approximately $810,000 when comparing the year ended December 31, 2009 with the year ended December 31, 2008.
Other Income (Expense) - Other expense increased by $681,000 to a loss of $976,000 in the year ended December 31, 2009 from a loss of $295,000 in the year ended December 31, 2008. The increase is caused by (1) an increased loss in our marketing and production operation’s equity investment in Kykuit of approximately $650,000 due to the write off of drilling costs related to dry holes, (2) an increase in costs from our corporate and other segment of $69,000, and (3) an offsetting increase in other income in our natural gas operations of $38,000.
Interest Expense - Interest expense remained constant at approximately $1.2 million for the years ended December 31, 2009 and 2008.
Income Tax Expense - Income tax expense decreased by approximately $2.0 million to approximately $27,000 in the year ended December 31, 2009 from approximately $2.0 million in the year ended December 31, 2008. During 2009, we performed a study of our deferred tax asset related to the purchase of Frontier and Penobscot. As discussed in Note 3 to our Consolidated Financial Statements, we increased the gross amount of the deferred tax asset by $100,000, reduced the valuation allowance related to the federal portion of the deferred tax asset by $2.8 million to zero and increased the state portion of the valuation allowance by $400,000. The net result is an income tax benefit of approximately $2.5 million. Offsetting this is an increase due to increased pre-tax income.
Discontinued Operations
Formerly reported as propane operations, we sold our Arizona propane assets as of April 1, 2007. A small portion of our propane operations was income and expense associated with MRP, our unregulated Montana wholesale operation that supplies propane to our affiliated company reported in our natural gas operations. MRP is now being reported in our marketing and production operations.
Six Months Ended December 31, 2008 Compared to Six Months Ended December 31, 2007
Net Income - Our net income for the six months ended December 31, 2008 was approximately $1.2 million compared to net income of $7.9 million for the six months ended December 31, 2007, a decrease of $6.7 million, or 85%. This decrease was primarily due to the recognition of an extraordinary gain of $6.8 million in the six months ended December 31, 2007. This gain resulted from the recognition of a deferred tax asset of $11.5 million from the purchase of assets in Maine and North Carolina. (See Note 3 to our Consolidated Financial Statements for further discussion of the deferred tax asset and the extraordinary gain).
Net income from continuing operations for the six months ended December 31, 2008 was approximately $1.2 million compared to net income of $1.1 million for the six months ended December 31, 2007, an increase of
approximately $100,000 or 9%. The principal changes that contributed to this improvement in net income from continuing operations are explained below.
Revenues - Our revenues for the six months ended December 31, 2008 were approximately $38.7 million compared to $28.3 million in the six months ended December 31, 2007, an increase of $10.4 million or 36%. The increase was primarily attributable to: (1) a natural gas revenue increase of $7.7 million, of which $4.2 million was due to a full six months of revenue from the recently acquired gas operations in Maine and North Carolina, with the remaining $3.5 million being caused by higher natural gas commodity prices passed through in rates in our existing natural gas operations and (2) an increase in our marketing and production operation’s revenue of $2.7 million, due primarily to higher natural gas commodity prices.
Gross Margin - Gross margin was approximately $11.5 million in the six months ended December 31, 2008 compared to $8.4 million in the six months ended December 31, 2007, an increase of $3.1 million or 37%. Our natural gas operation’s margins increased $2.3 million, of which $2.1 million was due to a full six months of margin contributed by the recently acquired gas operations in Maine and North Carolina. Gross margin from our marketing and production operations increased $836,000, due to a $333,000 increase in margin from gas production, and a $624,000 increase in margin from gas marketing, offset by a $121,000 decrease in mark to market revenue.
Expenses Other Than Cost of Sales - Expenses other than cost of sales increased by approximately $1.7 million in the six months ended December 31, 2008 from the six months ended December 31, 2007. On-going expenses related to the full six months of operations in Maine and North Carolina account for $1.5 million of this increase. The remaining $200,000 is due primarily to increases in property taxes and increases in distribution, general and administrative expenses.
Other Income (Loss) - Other income (loss) was a loss of $420,000 for the six months ended December 31, 2008 compared to income of $190,000 for the six months ended December 31, 2007, a decrease of $610,000. In the six months ended December 31, 2008, other income (loss) included acquisition expenses of $585,000 written off as part of the transition to ASC 805 and $41,000 of dividends from marketable securities. Other income in our natural gas operations decreased $30,000, due to lower income from services to customers in our Great Falls, Montana service area of $47,000 offset by an increase of $17,000 from the full six months of operations in Maine and North Carolina.
Interest Expense - Interest expense increased by $147,000 to $677,000 in the six months ended December 31, 2008 from approximately $530,000 in the six months ended December 31, 2007. This increase is due to increased borrowings on our line of credit, caused by the higher costs of gas placed in storage and increased capital expenditures related to the operations in North Carolina and Maine.
Income Tax Expense - Income tax expense from continuing operations increased by $652,000 to $926,000 for the six months ended December 31, 2008 from $274,000 in the six months ended December 31, 2007, due to increased pre-tax income from continuing operations.
Extraordinary Gain
The extraordinary gain of $6.8 million reported in the six months ended December 31, 2007 is related to the acquisitions of Frontier Utilities and Penobscot Natural Gas. We recognized a deferred tax asset, net of valuation allowance, from these acquisitions. The difference between the deferred tax asset, net of a valuation reserve, and our total purchase consideration resulted in the non-taxable extraordinary gain (See Note 3 to our Consolidated Financial Statements).
Discontinued Operations
Formerly reported as propane operations, we sold our Arizona propane assets as of April 1, 2007. A small portion of our propane operations was income and expense associated with MRP, our unregulated Montana wholesale operation that supplies propane to our affiliated company reported in our natural gas operations. MRP is now being reported in our marketing and production operations.
There was no income or loss from discontinued operations for the six months ended December 31, 2008 or the six months ended December 31, 2007.
Fiscal Year Ended June 30, 2008 Compared to Fiscal Year Ended June 30, 2007
Net Income - Our net income for fiscal 2008 was approximately $10.1 million compared to net income of $6.2 million for fiscal 2007, an increase of $3.9 million or 63%. This improvement was primarily due to the recognition of an extraordinary gain of $6.8 million in the second quarter of fiscal 2008. This gain resulted from the recognition of a deferred tax asset of $11.5 million from the purchase of assets in Maine and North Carolina. We expect to realize tax benefits in future years, and therefore recorded a deferred tax asset, (net of valuation reserve) and a corresponding gain, reduced by the total consideration paid for the companies. (See Note 3 to our Consolidated Financial Statements for further discussion of the deferred tax asset.) Coupled with the extraordinary gain were increases due to net income from our North Carolina operations of $831,000, from existing natural gas operations of $476,000 and from our gas marketing and production operation of $246,000. These improvements were partially offset by a net loss from the recently acquired gas operations in Maine of $166,000. In addition, net income of $6.2 million in 2007 included $4.0 million of income from discontinued operations.
The principal changes that contributed to the improvement in net income in fiscal 2008 from fiscal 2007 are explained below.
Revenues - Our revenues for fiscal 2008 were approximately $76.8 million compared to $59.4 million in fiscal 2007, an increase of $17.4 million or 29%. The increase was primarily attributable to: (1) a natural gas revenue increase of $12.9 million, of which $10.0 million was due to revenue from our Maine and North Carolina operations, with the remaining $2.9 million being caused by higher natural gas commodity prices passed through in rates in our Montana and Wyoming natural gas operations and (2) an increase in our marketing and production operation’s revenue of $4.6 million, due primarily to higher sales volumes in our Wyoming market, offset by a decrease in electricity revenue of $180,000.
Gross Margin - Gross margin was approximately $20.7 million in fiscal 2008 compared to $15.6 million in fiscal 2007, an increase of $5.1 million or 33%. Our natural gas operation’s margins increased $5.1 million, of which $4.8 million was contributed by our Maine and North Carolina operations. Gross margin from our marketing and production operations increased $10,000, due to a $210,000 increase in margin from gas production, offset by decreases in margins from gas marketing and electricity sales of $157,000 and $43,000 respectively.
Expenses Other Than Cost of Sales - Expenses other than cost of sales increased by approximately $5.1 million in fiscal 2008 from fiscal 2007. On-going expenses related to operations in Maine and North Carolina account for $3.7 million of this increase. The remaining $1.3 million is due to increases in our distribution, general and administrative costs, including expenses related to the realignment of our management team and other outside legal and consultant fees.
Other Income - Other income was approximately $316,000 in fiscal 2008 compared to $242,000 in fiscal 2007, an increase of $74,000. Other income in our natural gas operations increased $16,000, primarily due to increased income generated in fiscal 2008 for services to customers compared to what had been provided in prior years. Other income in our marketing and production operations remained consistent with last year. Pipeline operations other income decreased $11,000. In fiscal 2008, other income also included $9,000 of dividends from marketable securities and $61,000 of gains from the sale of marketable securities.
Interest Expense - Interest expense decreased by $1.0 million to $1.1 million in fiscal 2008 from approximately $2.1 million in fiscal 2007. This decrease is primarily due to the write-off in fiscal 2007 of debt issue costs associated with the refinancing of long term debt, combined with a decrease in both short-term and long-term borrowings in fiscal 2008.
Income Tax Expense - Income tax expense from continuing operations increased by $60,000 to $1.33 million in fiscal 2008 from $1.27 million in fiscal 2007 due to increased pre-tax income from continuing operations.
Extraordinary Gain
The extraordinary gain of $6.8 million reported in fiscal 2008 is related to the acquisitions of Frontier Utilities and Penobscot Natural Gas. We recognized a deferred tax asset, net of valuation allowance, from these acquisitions. The difference between the deferred tax asset, net of a valuation reserve, and our total purchase consideration resulted in the non-taxable extraordinary gain (See Note 3 to our Condensed Consolidated Financial Statements).
Discontinued Operations
Formerly reported as propane operations, we sold our Arizona propane assets as of April 1, 2007. A small portion of our propane operations was income and expense associated with MRP, our unregulated Montana wholesale operation that supplies propane to our affiliated company reported in our natural gas operations. MRP is now being reported in our marketing and production operations.
Income from discontinued operations before income tax - There was no gain or loss from propane operations in fiscal year 2008 due to the timing of the sale of propane assets. In fiscal 2007, there was income before income taxes of approximately $975,000 from propane operations.
Gain from Disposal of Operations - There was no gain from disposal of operations in fiscal 2008 due to the timing of the sale of the propane assets. On April 1, 2007 we sold our Arizona propane assets for $15.0 million plus working capital, resulting in a pre-tax gain of approximately $5.5 million during fiscal 2007.
Income Tax Expense from discontinued operations - Income tax expense decreased by approximately $2.5 million in fiscal 2008 from fiscal 2007, due to the timing of the sale of propane assets.
Operating Results of our Natural Gas Operations
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
Natural Gas Revenues and Gross Margins - Operating revenues for the year ended December 31, 2009 decreased to approximately $58.8 million from approximately $67.1 million in the year ended December 31, 2008. This $8.3 million decrease was due to the significantly lower index price of natural gas passed through to our customers in 2009, partially offset by revenue from increased sales volumes in our Maine market.
Gas purchases in natural gas operations decreased to approximately $37.1 million for the year ended December 31, 2009 from approximately $46.8 million for the year ended December 31, 2008. This $9.7 million decrease reflects the significantly lower index price of natural gas.
Gross margin increased to approximately $21.7 million for the year ended December 31, 2009 from approximately $20.2 million for the year ended December 31, 2008, an increase of $1.5 million. Sales growth in our Maine market contributed an increase in margin of approximately $1.2 million, with our Great Falls, Montana and North Carolina markets contributing the remainder of the increase. Two months of operations from our Cut Bank Gas acquisition contributed $194,000 of gross margin in 2009.
Natural Gas Operating Expenses - Operating expenses decreased to approximately $14.7 million for the year ended December 31, 2009 from $15.6 million for the year ended December 31, 2008, a decrease of approximately $900,000. Of the $810,000 decrease in expense related to vacation accrual discussed above in consolidated operations, approximately $805,000 was attributable to natural gas operations. The remaining decrease is due to lower costs for maintenance and taxes other than income taxes, partially offset by an increase in depreciation expense.
Natural Gas Other Income - Other income increased by $38,000 to approximately $254,000 in the year ended December 31, 2009 from $216,000 for the year ended December 31, 2008.
Natural Gas Interest Expense - Interest expense increased by $78,000 to approximately $1.1 million for the year ended December 31, 2009 from $1.1 million for the year ended December 31, 2008.
Natural Gas Income Tax Benefit (Expense) - Income tax expense increased by approximately $800,000 to approximately $2.3 million for the year ended December 31, 2009 from $1.5 million for the year ended December 31, 2008, due to higher pre-tax income, and the $400,000 increase to the state portion of the deferred tax asset valuation allowance, offset by the $100,000 increase in the gross deferred tax asset, discussed in Note 3 to our Consolidated Financial Statements.
For comparative purposes, the following table separates results of operations for our 2007 acquisitions in Maine and North Carolina from the other natural gas operations, for fiscal 2008. Our ownership of Frontier Utilities of North Carolina began October 1, 2007. Our ownership of Penobscot Natural Gas in Bangor, Maine began December 1, 2007. The results of these two operations are combined in the 2007 Acquisitions column below. The Total Less 2007 Acquisitions is comparable to fiscal 2007 results.
For comparison of the six months ended December 31, 2008 and 2007, the results of Frontier Utilities and Penobscot Natural Gas are not presented separately in the table, but are discussed in the narrative below.
Six Months Ended December 31, 2008 Compared to Six Months Ended December 31, 2007
Natural Gas Revenues and Gross Margins - Operating revenues for the six months ended December 31, 2008 increased to approximately $28.8 million from approximately $21.1 million in the six months ended December 31, 2007. $4.2 million of this $7.7 million increase was due to a full six months of revenue from Frontier and Penobscot for the six months ended December 31, 2008. The remaining $3.5 million increase was caused by higher gas commodity costs in our existing gas operations passed through as increased rates.
Gas purchases in natural gas operations increased to approximately $19.5 million in the six months ended December 31, 2008 from approximately $14.0 million in the six months ended December 31, 2007. $2.1 million of this $5.5 million increase is the result of the full six months of gas purchases from Frontier and Penobscot in the period ending December 31, 2008. The remaining $3.4 million results from higher gas commodity prices in our existing natural gas operations.
Gross margin increased to approximately $9.4 million in the six months ended December 31, 2008 from approximately $7.1 million for the six months ended December 31, 2007. $2.1 million of this $2.3 million increase is the result of the full six months of operations from Frontier and Penobscot in the period ending December 31, 2008. The remaining $200,000 increase is due to increased sales volumes in our existing natural gas operations, primarily in December 2008.
Natural Gas Operating Expenses - Operating expenses increased to approximately $7.9 million in the six months ended December 31, 2008 from $6.2 million in the six months ended December 31, 2007. $1.5 million of this $1.7 million increase is the result of the full six months of operations from Frontier and Penobscot in the period ending December 31, 2008. The remaining $200,000 increase is due primarily to increases in distribution, general and administrative expenses and property taxes.
Natural Gas Other Income - Other income decreased to approximately $160,000 in the six months ended December 31, 2008 from $190,000 in the six months ended December 31, 2007. Other income from Frontier and Penobscot increased by $17,000, offset by a $47,000 decrease caused by lower service sales in our Great Falls, Montana operation.
Natural Gas Interest Expense - Interest expense increased to approximately $584,000 in the six months ended December 31, 2008 from $462,000 in the six months ended December 31, 2007. This $122,000 increase is due to increased borrowings on our line of credit , caused by the higher costs of gas placed in storage and increased capital expenditures related to Frontier and Penobscot.
Natural Gas Income Tax Benefit (Expense) - Income tax expenses increased to approximately $519,000 in the six months ended December 31, 2008 from $120,000 in the six months ended December 31, 2007. $198,000 of this $399,000 increase is due to higher taxable income from the full six months of operations from Frontier and Penobscot in the period ended December 31, 2008. The remainder is due to an adjustment to tax expense in the six months ended December 31, 2007 for prior year actual tax expense from amounts that had been estimated and accrued.
Fiscal Year Ended June 30, 2008 Compared to Fiscal Year Ended June 30, 2007
Natural Gas Revenues and Gross Margins - Operating revenues without new acquisitions in fiscal 2008 increased to approximately $49.4 million from $46.4 million in fiscal 2007. This $3.0 million increase is caused by higher gas commodity costs passed through as increased rates.
Gas purchases in the natural gas operations (without new acquisitions) increased to $36.2 million in fiscal 2008 from $33.5 million in fiscal 2007. This $2.7 million increase results from higher gas commodity prices, primarily during the 4th quarter of fiscal 2008.
Gross margin (without new acquisitions) increased to $13.2 million in fiscal 2008 from approximately $12.9 million for fiscal 2007. This $304,000 increase is due to increased sales volumes, primarily in the fourth quarter of fiscal 2008.
Natural Gas Operating Expenses - Operating expenses (without new acquisitions) increased to approximately $10.3 million in fiscal 2008 from $9.3 million in fiscal 2007. This $1.0 million increase is due primarily to increases in distribution, general and administrative expenses, including expenses associated with the realignment of our management team, and increases in outside legal and consulting fees.
Natural Gas Other Income - Other income (without new acquisitions) increased to approximately $252,000 in fiscal 2008 from $229,000 in fiscal 2007. This $23,000 increase was primarily due to increased service sales in Great Falls, Montana and Cody, Wyoming.
Natural Gas Interest Expense - Interest expense (without new acquisitions) decreased to approximately $0.9 million in fiscal 2008 from $1.9 million in fiscal 2007. This $1.0 million decrease was primarily due to the write-off in fiscal 2007 of debt issue costs associated with the refinancing of long term debt, combined with a decrease in both short-term and long-term borrowings in fiscal 2008.
Natural Gas Income Tax Benefit (Expense) - Income tax expenses (without new acquisitions) increased to approximately $674,000 in fiscal 2008 from $653,000 in fiscal 2007, due to an adjustment to tax expense for prior year actual tax expense from amounts that had been estimated and accrued, offset by higher taxable income.
Operating Results of our Marketing and Production Operations (EWR)
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
With the sale of our Arizona propane assets, we have reclassified our former propane operation, Missouri River Propane, into our marketing and production operations. This is a small unregulated propane supply operation that provides propane to our affiliated regulated company accounted for in our natural gas operations. Results from this operation include a net loss of $25,000 and net income of $4,000 for the years ended December 31, 2009 and 2008, respectively.
Marketing and Production Revenues and Gross Margins - Revenues in EWR decreased $7.6 million to $12.2 million for the year ended December 31, 2009 from approximately $19.8 million for the year ended December 31, 2008. Retail gas and propane revenues decreased by approximately $5.9 million, due to significantly lower index prices for natural gas in 2009. Production revenue decreased by $1.3 million due to the significantly lower index prices received for volumes produced and less volumes produced in 2009 .
Our marketing and production operations’ gross margin of approximately $2.6 million for the year ended December 31, 2009 represents a decrease of approximately $500,000 from gross margin of approximately
$3.1 million earned in the year ended December 31, 2008. Gross margin from gas production decreased by $1.1 million due to the significantly lower index prices received for volumes produced and lower production volumes, and a decrease of $100,000 in mark to market revenue. Gross margin from gas marketing increased by $700,000, due to a more favorable cost of supply relative to our sales contracts.
Marketing and Production Operating Expenses - Operating expenses increased approximately $165,000 to $844,000 for the year ended December 31, 2009 from $679,000 for the year ended December 31, 2008. This change is caused by a one-time payment made to the pipeline company that delivers much of our gas supply for facilities improvements , along with increases in salaries and employee benefits expense, employee travel expenses, professional services, and depreciation and depletion expense.
Marketing and Production Other Income (expense) - Other expense increased approximately $650,000 to approximately $687,000 in the year ended December 31, 2009 from $37,000 for the year ended December 31, 2008. Our loss on equity investment in Kykuit totaled $687,000 in 2009 due to the write-off of drilling costs relating to dry holes, compared to $37,000 in 2008.
Marketing and Production Interest Expense - Interest expense decreased by $60,000 to $89,000 in the year ended December 31, 2009 from $149,000 in the year ended December 31, 2008, due primarily to a decrease in short term interest due to lower costs for gas placed in storage.
Marketing and Production Income Tax Expense - Income tax expense decreased to $413,000 in the year ended December 31, 2009 from $758,000 in the year ended December 31, 2008, due to lower taxable income.
Six Months Ended December 31, 2008 Compared to Six Months Ended December 31, 2007
With the sale of our Arizona propane assets, we have reclassified our former propane operation, Missouri River Propane, into our marketing and production operations. This is a small unregulated propane supply operation that provides propane to our affiliated regulated company accounted for in our natural gas operations. Results from this operation include a net loss for the six months ended December 31, 2008 and 2007 of $1,000 and $16, respectively.
Marketing and Production Revenues and Gross Margins - Revenues in EWR increased $2.7 million to $9.7 million for the six months ended December 31, 2008 from approximately $7.0 million for the six months ended December 31, 2007. Retail gas and propane revenues increased by approximately $2.2 million, due primarily to higher natural gas commodity prices in July, August and September of 2008. Production revenue increased by $549,000 due to an increase in the average price received for volumes produced.
Our marketing and production operations’ gross margin of $1.92 million for the six months ended December 31, 2008 represents an increase of $836,000 from gross margin of $1.08 million earned in the six months ended December 31, 2007. Gross margin from gas production increased by $333,000 due to higher prices received for volumes produced. The margin from gas marketing increased by $624,000 due to relative lower costs of natural gas purchased to supply our sales contracts. These increases are offset by a $121,000 decrease in mark to market revenue.
Marketing and Production Operating Expenses - Operating expenses increased approximately $48,000 to $369,000 for the six months ended December 31, 2008 from $321,000 for the six months ended December 31, 2007. This change is caused primarily by increases in salaries, professional services, and depletion expense.
Marketing and Production Interest Expense - Interest expense increased by $23,000 to $83,000 in the six months ended December 31, 2008 from $60,000 in the six months ended December 31, 2007, due primarily to an increase in short term interest due to higher gas costs for gas placed in storage.
Marketing and Production Income Tax Expense - Income tax expense increased to $551,000 in the six months ended December 31, 2008 from $135,000 in the six months ended December 31, 2007, due to higher taxable income.
Fiscal Year Ended June 30, 2008 Compared to Fiscal Year Ended June 30, 2007
With the sale of our Arizona propane assets, we have reclassified our former propane operation, Missouri River Propane, into our marketing and production operations. This is a small unregulated propane supply operation that provides propane to our affiliated regulated company accounted for in our natural gas operations. Results from this operation include net income for fiscal 2008 of $8,000 and a net loss for fiscal 2007 of $15,000.
Marketing and Production Revenues and Gross Margins - Revenues in EWR increased $4.6 million to $17.1 million in fiscal 2008 from approximately $12.5 million in fiscal 2007. Retail gas and propane revenues increased by approximately $4.5 million, due primarily to higher sales volumes in our Wyoming market. Production revenue increased by $261,000 due to an increase in the average index price received for volumes produced. These increases are offset by a decrease in electricity sales of $180,000 due to the expiration of our last remaining electricity customer contract in June 2007.
Our marketing and production operations’ fiscal 2008 gross margin of $2.29 million represents an increase of $10,000 from gross margin of $2.28 million earned in fiscal 2007. Gross margin from gas production increased by $210,000 due to higher index prices received for volumes produced. This is offset by a decrease in margin from gas marketing of $157,000 due to higher gas supply costs and a decrease in margin from electricity sales of $43,000.
Marketing and Production Operating Expenses - Operating expenses increased approximately $72,000 to $631,000 for fiscal 2008 from $559,000 for fiscal 2007. This change is caused primarily by increases in legal fees, salaries and depletion expense.
Marketing and Production Other Income - Other income decreased by $1,000 to $1,000 in fiscal 2008 from $2,000 in fiscal 2007.
Marketing and Production Interest Expense - Interest expense decreased by $60,000 to $125,000 in fiscal 2008 from $185,000 in fiscal 2007 due primarily to a decrease in amortization of debt issue costs due to the refinancing of our long-term debt.
Marketing and Production Income Tax Expense - Income tax expense decreased to $344,000 in fiscal 2008 from $593,000 in fiscal 2007 due to an adjustment in tax expense for prior year actual tax expense from amounts that had been estimated and accrued, offset by higher taxable income.
Operating Results of our Pipeline Operations
There have been no material changes in pipeline operations during the year ended December 31, 2009 compared to the year ended December 31, 2008, or in the six months ended December 31, 2008 compared to the six months ended December 31, 2007, or in fiscal 2008 compared to fiscal 2007, as illustrated in the table above.
Results of our Discontinued Operations
There was no income or expenses from discontinued operations during the years ending December 31, 2009 or 2008, during the six months ended December 31, 2008 or 2007, or during fiscal 2008.
Fiscal Year Ended June 30, 2007
Formerly reported as propane operations, we sold our Arizona propane assets as of April 1, 2007. A small portion of our propane operation as previously reported was income and expense associated with MRP. MRP is now being reported in our EWR segment. In fiscal year 2007 we reported income from discontinued operations before income tax of approximately $1 million, a gain from the disposal of these assets of approximately $5.5 million and associated income tax expense of approximately $2.5 million, for a net income from discontinued operations of approximately $4.0 million.
Results of our Corporate and Other Operations
During fiscal 2008, corporate and other operations was created to accumulate revenues and expenses that were not allocable to our utilities or other operations. Therefore, it does not have standard revenues, purchase costs or gross margin.
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
For the year ended December 31, 2009, corporate and other operations included administrative expenses of $8,000, acquisition expenses of $830,000, related primarily to the acquisition of Cut Bank Gas Company and the Ohio Companies, offset by interest and dividend income of $190,000 and a recognized gain on the sale of marketable securities of $97,000 for a total loss before income taxes of $551,000. Also included in the year ended December 31, 2009 is the income tax benefit applicable to the above items of $30,000. In addition, during 2009, we performed a study of our deferred tax asset related to the purchase of Frontier Natural Gas and Bangor Gas
Company and determined that the valuation allowance related to the federal portion of the deferred tax asset was no longer needed. This resulted in an income tax benefit of approximately $2.8 million. Please see Note 3 to our Consolidated Financial Statements for further discussion.
For the year ended December 31, 2008, results of corporate and other operations included $441,000 from an equity offering that did not occur, acquisition expenses of $585,000, written off as part of the transition to ASC 805, and offset by $50,000 of interest and dividend income and $61,000 from recognized gains on the sale of marketable securities, and the applicable income tax benefit of $331,000.
Six Months Ended December 31, 2008 Compared to Six Months Ended December 31, 2007
For the six months ended December 31, 2008, corporate and other operations included acquisition expenses of $585,000, written off as part of the transition to ASC 805, offset by $41,000 of dividend income.
For the six months ended December 31, 2007, results of corporate and other operations included a $6.8 million extraordinary gain related to the purchases of Frontier Utilities of North Carolina, Inc., and Penobscot Natural Gas, Inc.
Fiscal Year Ended June 30, 2008
Results of corporate and other operations include a $6.8 million extraordinary gain related to the purchases of Frontier Utilities of North Carolina, Inc., and Penobscot Natural Gas, Inc. Also included in corporate and other operations are $65,000 in gains from the sale of marketable securities, $9,000 in dividends from marketable securities, and $441,000 in costs associated with an equity offering that did not occur.
Consolidated Cash Flow Analysis
Sources and Uses of Cash
Operating activities provide our primary source of cash. Cash provided by operating activities consists of net income (loss) adjusted for non-cash items, including depreciation, depletion, amortization, deferred income taxes, and changes in working capital.
Our ability to maintain liquidity depends upon our $20.0 million credit facility with Bank of America, shown as line of credit on the accompanying balance sheets. Our use of the Bank of America revolving line of credit was $14.7 million and $17.6 million at December 31, 2009 and 2008, respectively. This change in our cash position is primarily due to decreased costs for gas put in storage, offset by increases in our capital expenditures due to expansion in our North Carolina and Maine markets.
We made capital expenditures for continuing operations of $8.9 million and $7.0 million for the years ended December 31, 2009 and 2008, respectively, $4.9 million and $1.4 million for the six months ended December 31, 2008 and 2007, respectively, and $3.9 million and $2.4 million during fiscal 2008 and 2007, respectively. We finance our capital expenditures on an interim basis by the use of our operating cash flow and use of the Bank of America revolving line of credit.
We periodically repay our short-term borrowings under the Bank of America revolving line of credit by using the net proceeds from the sale of long-term debt and equity securities. Long-term debt was $13.0 million at December 31, 2009, and 2008.
On April 1, 2007 we sold certain of our assets related to our Arizona propane business for cash of approximately $15.0 million plus net working capital.
Cash increased to $2,752,000 at December 31, 2009, compared with $1,065,000 at December 31, 2008. This $1.7 million increase in cash for the year ended December 31, 2009 is compared with the $840,000 decrease for the year ended December 31, 2008, the $269,000 increase and the $5.1 million decrease for the six months ended December 31, 2008 and 2007, respectively, and the $6.2 million decrease and $5.4 million increase in cash for the years ended June 30, 2008, June 30, 2007, respectively, as shown in the following table:
For the year ended December 31, 2009, cash provided by operating activities increased $14.7 million as compared to the year ended December 31, 2008. Items affecting the use of cash included a decrease in amounts paid for gas inventory of $6.5 million, a $1.0 million decrease in payments of accrued and other liabilities, an increase in accounts receivable collections of $3.3 million, an increase in net income of $3.5 million, a $2.4 million increase in collections of recoverable costs of gas, and $600,000 in investment impairments, partially offset by a $2.7 million increase in net deferred tax assets.
For the six months ended December 31, 2008, cash used in operating activities increased $4.0 million as compared to the six months ended December 31, 2007. Items affecting the use of cash included a decrease in deferred taxes of $7.2 million, a decrease in accounts payable of $2.1 million and an increase in amounts paid for inventory of $1.8 million.
For the year ended June 30, 2008, cash from operating activities increased $6.3 million as compared to the year ended June 30, 2007, primarily because of a deferred tax gain of $6.8 million from the purchase of gas utilities in North Carolina and Maine, and the sale of the Arizona propane assets, which affected 2007 but not 2008. The proceeds from the sale are recorded as cash flows from the sale of assets in investing activities, described below. Other items affecting the use of cash included an increase in payables of $1.0 million and an increase of accounts receivable of $1.3 million.
For the year ended December 31, 2009, cash used in investing activities decreased by $2.0 million as compared to the year ended December 31, 2008, primarily due to a decrease of $2.9 million in the purchase of marketable securities. Other changes include increased construction expenditures of $1.8 million and an increase of $800,000 in sales of marketable securities.
For the six months ended December 31, 2008, cash used in investing activities increased $1.1 million as compared to the six months ended December 31, 2007, primarily due to an increase in construction expenditures of $3.1 million, the purchase of marketable securities of $3.0 million in the 2008 period, offset by the purchase of the North Carolina and Maine properties of $4.6 million in the 2007 period.
For the year ended June 30, 2008, cash used in investing activities decreased $25.3 million as compared to the year ended June 30, 2007, due primarily to the sale of Arizona assets in 2007 and the purchase of Maine and North Carolina assets in 2008. Additionally, there were increases of $1.5 million in capital expenditures and $1.3 million in the purchase of marketable securities.
For the year ended December 31, 2009, cash used by financing activities decreased by $14.1 million as compared to the year ended December 31, 2008. Line of credit proceeds decreased by $8.2 million, while payments increased by $5.9 million. Other offsetting changes include a decrease in stock repurchases of $400,000 and an increase of $300,000 in dividends paid.
For the six months ended December 31, 2008, cash provided by financing activities increased by $10.5 million as compared to the six months ended December 31, 2007. The net increase in our line of credit of $11.0 million accounts for this increase and is due primarily to much higher prices paid for gas placed in storage. We paid $1.0 million in dividends in the six months ended December 31, 2008 compared to $1.1 million for the six months ended December 31, 2007. The sale of common stock resulted in cash proceeds of $222,000 in the 2007 period, and the repurchase of common stock used $406,000 in the 2008 period compared to $151,000 in the 2007 period.
For the year ended June 30, 2008, cash used in financing activities decreased by $7.3 million as compared to the year ended June 30, 2007. We paid $2.0 million in dividends in fiscal 2008 compared to $1.5 million in fiscal 2007. The sale of common stock resulted in cash proceeds of $334,000, and the repurchase of common stock used $162,000.
Liquidity and Capital Resources
We fund our operating cash needs, as well as dividend payments and capital expenditures, primarily through cash flow from operating activities and short-term borrowing. Historically, to the extent cash flow has not been sufficient to fund these expenditures; we have used our working capital line of credit. We have greater need for short-term borrowing during periods when internally generated funds are not sufficient to cover all capital and operating requirements, including costs of gas purchased and capital expenditures. In general, our short-term borrowing needs for purchases of gas inventory and capital expenditures are greatest during the summer and fall months and our short-term borrowing needs for financing customer accounts receivable are greatest during the winter months.
Bank of America Term Loans and Credit Facility
On June 29, 2007, we replaced our existing credit facility and long-term notes with a new $20.0 million revolving credit facility, and issued $13.0 million of 6.16% senior unsecured notes. The prior Bank of America credit facility had been secured, on an equal and ratable basis with our previously outstanding long-term debt, by substantially all of our assets.
Long-term Debt - $13.0 million 6.16% Senior Unsecured Notes - On June 29, 2007, we issued $13.0 million aggregate principal amount of our 6.16% Senior Unsecured Notes, due June 29, 2017. The proceeds of these notes were used to refinance our existing notes. With this refinancing, we expensed the remaining debt issue costs of $991,000 in fiscal 2007, and incurred approximately $463,000 in new debt issue costs to be amortized over the life of the new note.
Line of Credit - On June 29, 2007, we established our new five-year unsecured credit facility with Bank of America for $20.0 million which replaced a previous one-year facility with Bank of America for the same. The current credit facility includes an annual commitment fee equal to 0.20% of the unused portion of the facility and interest on amounts outstanding at the London Interbank Offered Rate, plus 120 to 145 basis points, for interest periods selected by us.
The following table represents borrowings under the Bank of America revolving line of credit for each of the fiscal quarters in the year ended December 31, 2009.
The following table represents borrowings under the Bank of America revolving line of credit for each of the fiscal quarters in the six months ending December 31, 2008 and 2007.
The following table represents borrowings under the Bank of America revolving line of credit for each of the fiscal quarters in the years ending June 30, 2008 and 2007.
Our 6.16% Senior Unsecured Note and Bank of America credit facility agreements contain various covenants, which include, among others, limitations on total dividends and distributions made in the immediately preceding 60-month period to 75% of aggregate consolidated net income for such period, restrictions on certain indebtedness, limitations on asset sales, and maintenance of certain debt-to-capital and interest coverage ratios. At December 31, 2009 and 2008, we believe we are in compliance with the financial covenants under our debt agreements or have received waivers for any defaults.
At December 31, 2009, we had approximately $2.8 million of cash on hand. In addition, at December 31, 2009, we had $14.7 million of borrowings under the $20.0 million Bank of America revolving line of credit. Our short-term borrowings under our line of credit during the year ended December 31, 2009 had a daily weighted average interest rate of 3.25% per annum.
Our 6.16% Senior Unsecured Note and Bank of America credit facility agreements contain various covenants, which include, among others, limitations on total dividends and distributions made in the immediately preceding 60-month period to 75% of aggregate consolidated net income for such period, restrictions on certain indebtedness, limitations on asset sales, and maintenance of certain debt-to-capital and interest coverage ratios. At December 31, 2009 and 2008, we believe we are in compliance with the financial covenants under our debt agreements or have received waivers for any defaults.
Citizens Bank Credit Facility
In connection with our acquisition of our Ohio operations, NEO, Great Plains and GPL each entered modifications/amendments to its credit facility with Citizens Bank (the “Citizens Credit Facility”). The Citizens Credit Facility consists of a revolving line of credit and term loan to NEO, and two other term loans to Great Plains and GPL respectively. Each amendment/modification was initially effective as of December 1, 2009, but was later modified to be effective as of January 5, 2010. Energy, Inc. guarantees each loan. Our chairman and chief executive
officer, Richard M. Osborne, guarantees each loan both individually and as trustee of the RMO Trust, and Great Plains guarantees NEO’s revolving line of credit and term loan as well as GPL’s term note.
Long-term Debt - $10.3 million 5.00% Senior Secured Notes - NEO’s, Great Plains’ and GPL’s term loans with Citizens Bank are in the amounts of $7.8 million, $2.4 million and $823,000 respectively. Each term note has a maturity date of July 1, 2013 and bears interest at an annual rate of 30-day LIBOR (Eurodollar) plus 400 basis points with an interest rate floor of 5.00% per annum. Currently, the interest rate is 5.00% per annum. The term notes require monthly payments of approximately $63,000 in the aggregate.
Line of Credit - NEO’s revolving credit line with Citizens Bank has a maximum credit commitment of $2.1 million. The revolving line bears interest at an annual rate of 30-day LIBOR (Eurodollar) plus 400 basis points with an interest rate floor of 5.00% per annum. Currently, the interest rate is 5.00% per annum. The revolving line requires monthly interest payments with the principal due at maturity, November 30, 2010.
The Citizens Credit Facility requires Great Plains, GPL and NEO to maintain a debt service coverage ratio of at least 1.25 to 1.0 measured quarterly on a rolling four quarter basis. The Citizens Credit Facility also requires NEO, Great Plains and GPL to maintain a minimum net worth, on a combined basis, equal to the sum of $1,815,000 plus 100% of net income less the pro-rata share of any dividend paid to Energy, Inc., measured on a quarterly basis beginning with the quarter ended December 31, 2009. The Citizens Credit Facility allows NEO, Great Plains and GPL Ohio Companies a party thereto to pay dividends to Energy, Inc. if those entities’ combined net worth (as defined in the Citizens loan documents) after payment of any dividends would not be less than $1,815,000 on a consolidated basis as positively increased by 100% of net income as of the end of each fiscal quarter and fiscal year.
At December 31, 2009, $2.1 million has been borrowed under the revolving line of credit, $7.1 million under the NEO term loan, $2.4 million under the Great Plains term loan and $813,000 under the GPL term loan.
Huntington Credit Facility
On December 31, 2009, Orwell entered into an amended and restated short-term credit facility with The Huntington National Bank, N.A. (the “Huntington Credit Facility”). The Huntington Credit Facility amends and restates the previous credit facility that matured on November 30, 2009. The loan is secured by all of the assets of Orwell. The Huntington Credit Facility is guaranteed by Energy, Inc., Lightning Pipeline, Mr. Osborne individually and as Trustee of the RMO Trust, and certain entities owned and controlled by Mr. Osborne.
Long-term Debt - $4.6 Million Senior Secured Note - The Huntington Credit Facility includes a $4.6 million term note that bears interest at an annual rate of 30-day LIBOR (Eurodollar) plus 300 basis points with LIBOR floor of 1% per annum. Currently, the interest rate is 4.00% per annum. The term note requires monthly payments of approximately $35,000 and matures on November 29, 2010.
Line of Credit - The Huntington Credit Facility also includes a $1.5 million line of credit. The credit line bears interest at an annual rate of 30-day LIBOR (Eurodollar) plus 300 basis points with LIBOR floor of 1% per annum. Currently, the interest rate is 4.00% per annum. The credit line requires monthly interest payments with the principal due at maturity, November 29, 2010.
The Huntington Credit Facility requires Orwell to maintain a fixed charge coverage ratio of at least 1 to 1 of EBITDA to the sum of (i) scheduled principal payments on debt and capital leases, plus (ii) interest expense, plus (iii) federal, state and local income tax expense, plus (iv) dividends and distributions, measured on a rolling four quarter basis. The Huntington Credit Facility allows Orwell to pay dividends to Energy, Inc. as long as the aggregate amount of all dividends, distributions, redemptions and repurchases in any fiscal year do not exceed 60% of net income (as defined in the Huntington Credit Facility) of Orwell for each fiscal year. At December 31, 2009, $1.5 million has been borrowed under the credit line and $4.3 million under the term note. The Huntington Credit Facility is also secured by a pledge of $3.0 million in market value of Energy, Inc. stock by the RMO Trust.
Combined Term Loans and Credit Facilities
The $14.7 million of borrowings at December 31, 2009, leaves our borrowing capacity at $5.3 million. Including the amounts related to the Ohio companies, we have $18.3 million of borrowings and borrowing capacity
of $5.3 million. As discussed above, this level of borrowings is due primarily to increased costs for gas put in storage, increases in our capital expenditures due to expansion in our North Carolina and Maine markets, and the acquisition of the Ohio Companies.
As explained above, the cash flow from our business is seasonal and the line of credit balance in December normally represents the high point of borrowings in our annual cash flow cycle. Our cash flow increases and our borrowings decrease, beginning in January, as monthly heating bills are paid and the gas we paid for and placed in storage in the summer months is used to supply our customers.
The total amount outstanding under all of our long term debt obligations was approximately $13.0 million at December 31, 2009, with non being due within one year. Including the amounts related to the Ohio companies, the total amount is approximately $27.6 million, with approximately $5.1 million due within one year.
Capital Expenditures
We conduct ongoing construction activities in all of our utility service areas in order to support expansion, maintenance, and enhancement of our gas pipeline systems. We are actively expanding our systems in North Carolina and Maine to meet the high customer interest in natural gas service in those two service areas. For the years ended December 31, 2009 and 2008, our total capital expenditures were approximately $8.9 million and $7.0 million, respectively. We estimate future cash requirements for capital expenditures will be as follows:
We fund our operating cash needs, as well as dividend payments and capital expenditures, primarily through cash flow from operating activities and short-term borrowing. Historically, to the extent cash flow has not been sufficient to fund these expenditures; we have used our working capital line of credit.
Off-Balance-Sheet Arrangements
We do not have any off-balance-sheet arrangements, other than those currently disclosed that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.
New Accounting Pronouncements
Recently Adopted
Fair Value Measurements - In September 2006, the FASB issued guidance that defines fair value, establishes a framework and gives guidance regarding the methods used for measuring fair value, and expands disclosures about fair value measurements. This guidance was effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. On January 1, 2008 we elected to implement this guidance with the one-year deferral and the adoption did not have a material impact on our financial position, results of operations or cash flows. Beginning January 1, 2009, we have adopted the provisions for non-financial assets and non-financial liabilities that are not required or permitted to be measured at fair value on a recurring basis.
Business Combinations - In December 2007, the FASB issued new guidance on business combinations which requires an acquirer to recognize and measure the assets acquired, liabilities assumed and any non-controlling interests in the acquiree at the acquisition date, measured at their fair values as of that date, with limited
exception. In addition, the new guidance requires that acquisition-related costs will be generally expensed as incurred and also expands the disclosure requirements for business combinations. The effective date of this new guidance is for years beginning after December 15, 2008 and we have adopted it on our consolidated financial statements, effective January 1, 2009. In addition, we have recorded as expense in the year ending December 31, 2009, and the six months ending December 31, 2008 $662,000 and $585,000, respectively of acquisition costs related to acquisitions in progress as part of the transition to the new guidance.
Noncontrolling Interests - In December 2007, the FASB issued new guidance establishing standards of accounting and reporting on non-controlling interests in consolidated financial statements. Also provided is guidance on accounting for changes in the parent’s ownership interest in a subsidiary, and standards of accounting of the deconsolidation of a subsidiary due to the loss of control. The effective date of this guidance is for fiscal years beginning after December 15, 2008. We have adopted the guidance on our consolidated financial statements, effective January 1, 2009, and the implementation did not have a material impact on our consolidated financial statements.
Derivative Instruments and Hedging Activities - In March 2008, the FASB released new guidance which amends and expands previous disclosure requirements for derivative instruments and hedging activities and requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. The new guidance is effective for financial statements issued for fiscal periods beginning after November 15, 2008. We implemented the guidance on January 1, 2009, and the implementation did not have a material impact on our consolidated financial statements.
Interim Fair Value Disclosures - In April 2009, the FASB issued new guidance on interim disclosures about fair value of financial instruments which requires that disclosures regarding the fair value of financial instruments be included in interim financial statements. This new guidance was effective for interim periods ending after June 15, 2009. We adopted this guidance for the period ending June 30, 2009.
Other-Than-Temporary Impairments - In April 2009, the FASB also issued released new guidance on presentation of other-than-temporary impairments which changes the method for determining whether an other-than-temporary impairment exists for debt securities, and also requires additional disclosures regarding other-than-temporary impairments. This new guidance is effective for interim and annual periods ending after June 15, 2009. We implemented the guidance on July 1, 2009, and the implementation did not have a material impact on our consolidated financial statements.
Accounting Standards Codification (Codification) - In June 2009, the FASB established the Codification as the source of authoritative generally accepted accounting principles recognized by the FASB. All existing accounting standards are superseded, aside from those issued by the SEC. All other accounting literature not included in the Codification is considered non-authoritative. We adopted the Codification as of September 30, 2009, which is reflected in our disclosures and references to accounting standards, with no impact to our financial position or results of operations.
Earnings Per Share - In September 2009, the FASB issued guidance that provided corrections to various parts of the Codification regarding EPS. The guidance is effective immediately upon being issued. The initial adoption of this guidance did not have an impact on the consolidated earnings or financial position of the Company as the update amended the reference between the Codification and pre-Codification references.
Subsequent Events - In May 2009, the FASB issued subsequent events guidance which establishes standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. In addition it requires disclosure of the date through which the Company has evaluated subsequent events and whether it represents the date the financial statements were issued or were available to be issued. This guidance was effective for the Company on June 30, 2009. The adoption of the subsequent events guidance did not have a material effect on the Company’s financial position or results of operations.
Recently Issued
Consolidation of Variable Interest Entities - In June 2009, the FASB issued new guidance on consolidation of variable interest entities. The guidance will significantly affect various elements of consolidation under existing accounting standards, including the determination of whether an entity is a variable interest entity and whether an enterprise is a variable interest entity’s primary beneficiary. This new guidance is effective for interim and annual periods beginning after November 15, 2009. We do not expect the implementation of the guidance to have a material impact on our consolidated financial statements.
Fair Value Measurement Disclosures - In January 2010, the FASB issued Fair Value Measurements and Disclosures (Topic 820) - Improving Disclosures about Fair Value Measurements (ASU No. 2010-06), which will update the Codification to require new disclosures for assets and liabilities measured at fair value. The requirements include expanded disclosure of valuation methodologies for Level 2 and Level 3 fair value measurements, transfers in and out of Levels 1 and 2, and gross rather than net presentation of certain changes in Level 3 fair value measurements. The updates to the Codification contained in ASU No. 2010-06 are effective for interim and annual periods beginning after December 15, 2009, except for requirements related to gross presentation of certain changes in Level 3 fair value measurements, which are effective for interim and annual periods beginning after December 15, 2010. We do not expect the implementation of the guidance to have a material impact on our consolidated financial statements.
Item 7A.
Item 7A.
Quantitative and Qualitative Disclosures about Market Risk
We are subject to certain market risks, including commodity price risk (i.e., natural gas prices) and interest rate risk. The adverse effects of potential changes in these market risks are discussed below. The sensitivity analyses presented do not consider the effects that such adverse changes may have on overall economic activity nor do they consider additional actions management may take to mitigate our exposure to such changes. Actual results may differ. See the Notes to our Consolidated Financial Statements for a description of our accounting policies and other information related to these financial instruments.
Commodity Price Risk
We seek to protect ourself against natural gas price fluctuations by limiting the aggregate level of net open positions that are exposed to market price changes. We manage such open positions with policies that are designed to limit the exposure to market risk, with regular reporting to management of potential financial exposure. Our risk management committee has limited the types of contracts we will consider to those related to physical natural gas deliveries. Therefore, management believes that although revenues and cost of sales are impacted by changes in natural gas prices, our margin is not significantly impacted by these changes.
Credit Risk
Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties of their contractual obligations under the various instruments with us. Credit risk may be concentrated to the extent that one or more groups of counterparties have similar economic, industry or other characteristics that would cause their ability to meet contractual obligations to be similarly affected by changes in market or other conditions. In addition, credit risk includes not only the risk that a counter-party may default due to circumstances relating directly to it, but also the risk that a counterparty may default due to circumstances that relate to other market participants that have a direct or indirect relationship with such counterparty. We seek to mitigate credit risk by evaluating the financial strength of potential counterparties. However, despite mitigation efforts, defaults by counterparties may occur from time to time. To date, no such default has occurred.
Item 8.
Item 8.
Financial Statements and Supplementary Data.
Our Consolidated Financial Statements begin on page of this Annual Report on Form 10-K.
Item 9.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
Not applicable.
Item 9A(T).
Item 9A(T).
Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
As of December 31, 2009, we evaluated the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended. The evaluation was carried out under the supervision of and with the participation of our management, including our principal executive officer and principal financial officer. Based upon this evaluation, our chief executive officer and chief financial officer each concluded that our disclosure controls and procedures were effective as of December 31, 2009.
Management’s Report on Internal Control over Financial Reporting
Management of Energy, Inc. is responsible for establishing and maintaining an adequate system of internal control over financial reporting as such term is defined in Exchange Act Rule 13a-15(f). Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with U.S. generally accepted accounting principles defined in the Exchange Act.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation. 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.
We carried out an evaluation under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, of the effectiveness of our internal control over financial reporting. In making this evaluation, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission for the “Internal Control - Integrated Framework.” Based on that evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2009.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting during our last fiscal quarter, the last fiscal quarter of calendar year 2009, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Attestation Report of Independent Registered Public Accounting Firm
This Form 10-K does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit us to provide only management’s report on internal control over financial reporting in this Form 10-K.
Item 9B.
Item 9B.
Other Information.
The following matters were submitted to a vote of the stockholders at our 2009 annual meeting of stockholders held on November 13, 2009: One - a proposal to elect the eight director nominees named below to serve for a one year term until the next annual meeting or until their respective successors are elected and qualified; Two - a proposal to approve the issuance of shares of our common stock as merger consideration under the merger agreements; and Three - a proposal to approve the adjournment or postponement of the annual meeting, if necessary or appropriate, to solicit additional votes on favor of Proposal Two. Set forth below is the number of votes cast for or withheld with respect to each director nominee and the number of votes cast for or against or abstain, and if applicable, the number of broker non-votes, for the other matters submitted to a vote of the stockholders at the meeting.
We held our 2009 Annual Meeting of Shareholders on November 13, 2009. The following nominees were elected to the Company’s Board of Directors to serve until our next annual meeting of shareholders.
Proposal One - Election of directors
Proposal Two - Approve the issuance of shares of our common stock as merger consideration under the merger agreements
PART III
Item 10.
Item 10.
Directors, Executive Officers and Corporate Governance.
Information required by this item is incorporated by reference to the material appearing under the headings “The Board of Directors,” “Executive Officers ,” “Section 16(a) Beneficial Ownership Reporting Compliance,” “Code of Ethics,” and “Audit Committee Report” in the Proxy Statement for our 2010 Annual Meeting.
Item 11.
Item 11.
Executive Compensation.
Information required by this item is incorporated by reference to the material appearing under the headings “Director Compensation” “Compensation Discussion and Analysis,” and “Executive Compensation,” in the Proxy Statement for our 2010 Annual Meeting.
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
Information required by this item is incorporated by reference to the material appearing under the heading “Security Ownership of Principal Shareholders and Management,” and “Equity Compensation Plan Information” in the Proxy Statement for our 2010 Annual Meeting.
Item 13.
Item 13.
Certain Relationships and Related Transactions and Director Independence.
Information required by this item is incorporated by reference to the material appearing under the heading “Certain Relationships and Related Transactions” and “Director Independence” in the Proxy Statement for our 2010 Annual Meeting.
Item 14.
Item 14.
Principal Accountant Fees and Services.
Information required by this item is incorporated by reference to the material appearing under the heading “Principal Accountant Fees and Services” in the Proxy Statement for our 2010 Annual Meeting.
PART IV
Item 15.
Item 15.
Exhibits and Financial Statement Schedules.
(a)
Financial Statements:
(b) Exhibit Index.

Management agreement or compensatory plan or arrangement
*
Filed herewith
(c)
Financial Statement Schedules:
Schedule II
Valuation and Qualifying Accounts
Energy, Inc.
December 31, 2009
All other schedules are omitted because they are not applicable or the required information is shown in the financial statements or notes thereto.
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.
ENERGY, INC.
/s/ Richard M. Osborne
Richard M. Osborne
Chief Executive Officer
(principal executive officer)
Date: March 31, 2010
KNOW ALL THESE PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Thomas J. Smith, his true and lawful attorney-in-fact and agents, with full power of substitution, for him in any and all capacities, to sign any and all amendments to this Report on Form 10-K, and to file the same, with exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, hereby ratifying and confirming all that said attorney-in-fact or his substitute, may do or cause to be done by virtue hereof.
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.
CONSOLIDATED FINANCIAL STATEMENTS
OF
ENERGY, INC. AND SUBSIDIARIES
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
Energy, Inc.
Great Falls, Montana
We have audited the consolidated balance sheets of Energy, Inc. and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of income, stockholders’ equity and comprehensive income and cash flows for the year ended December 31, 2009, the six months ended December 31, 2008 and the years ended June 30, 2008 and 2007. Our audits also included the financial statement schedule as of, and for the twelve months ending December 31, 2009, the six months ended December 31, 2008 and years ended June 30, 2008 and 2007 listed in the index as Item 15(a). These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements 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, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Energy, Inc. and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for the year ended December 31, 2009, the six months ended December 31, 2008, and the years ended June 30, 2008 and 2007, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related 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 were not engaged to examine management’s assessment of the effectiveness of Energy, Inc.’s internal control over financial reporting as of December 31, 2009, included in the accompanying Management’s Report on Internal Control Over Financial Reporting and, accordingly, we do not express an opinion there on.
/s/ HEIN & ASSOCIATES LLP
Denver, Colorado
March 31, 2010
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
See notes to consolidated financial statements.
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
See notes to consolidated financial statements.
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
AND COMPREHENSIVE INCOME
FOR THE YEAR ENDED DECEMBER 31, 2009,
THE SIX MONTHS ENDED DECEMBER 31, 2008,
AND THE YEARS ENDED JUNE 30, 2008 and 2007
See notes to consolidated financial statements.
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
See notes to consolidated financial statements.
ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the year ended December 31, 2009, the six months ended December 31, 2008,
and the years ended June 30, 2008 and 2007
1.
Summary of Business and Significant Accounting Policies
Nature of Business - Energy, Inc. (the Company) is a regulated public entity with certain non-regulated operations conducted through its subsidiaries. Our regulated utility operations involve the distribution and sale of natural gas to the public in and around Great Falls, Cascade, Cut Bank and West Yellowstone, Montana, Cody, Wyoming, Bangor, Maine and Elkin, North Carolina, and the distribution and sale of propane to the public through underground propane vapor systems in Cascade, Montana, and, until April 1, 2007, in and around Payson, Arizona. Our West Yellowstone, Montana operation is supplied by liquefied natural gas. Also, on January 5, 2010 we completed the acquisition of additional regulated utility operations in Ohio and Western Pennsylvania.
Our non-regulated operations included wholesale distribution of bulk propane in Arizona, and the retail distribution of bulk propane in Arizona, until the sale of the Arizona operations on April 1, 2007. The Company also markets gas and electricity in Montana and Wyoming through its non-regulated subsidiary, Energy West Resources (EWR).
Effective on August 3, 2009, Energy West, Incorporated (“Energy West”) reorganized into a holding company organizational structure pursuant to an Agreement and Plan of Merger with, among others, Energy, Inc. The primary purpose of the reorganization was to provide flexibility to make future acquisitions through subsidiaries of the new holding company rather than Energy West or its subsidiaries. The business operations of the Company have not changed as a result of the reorganization.
Basis of Presentation - Effective December 31, 2008, the Company changed its fiscal year end from June 30 to December 31. This change was made in order to align the Company’s fiscal year end with other companies within the industry. The resulting six-month period ended December 31, 2008 may be referred to herein as the “Transition Period”. The Company refers to the period beginning July 1, 2007 and ending June 30, 2008 as “fiscal 2008”, and the period beginning July 1, 2006 and ending June 30, 2007 as “fiscal 2007”.
We follow accounting standards set by the Financial Accounting Standards Board (“FASB”). The FASB sets generally accepted accounting principles (“GAAP”) that we follow to ensure that we consistently report our financial condition, results of operations and cash flows. Over the years, the FASB and other designated GAAP-setting bodies, have issued standards in the form of FASB Statements, Interpretations, FASB Staff Positions, EITF consensuses, AICPA Statements of Position, etc. References to GAAP issued by the FASB in these footnotes are to the FASB Accounting Standards Codification, sometimes referred to as the Codification or ASC. The FASB finalized the Codification for periods ending on or after September 15, 2009. Prior FASB standards are no longer being issued in the previous format
Reclassifications - Certain reclassifications of prior year reported amounts have been made for comparative purposes. The results of operations for the propane assets related to the sale of Arizona assets have been reclassified as income from discontinued operations. Cash flows used in discontinued operations for construction expenditures were reclassified for the year ending June 30, 2007 to reflect the expenditures as an investing activity.
Principles of Consolidation - The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, Energy West Propane (EWP), EWR, Energy West Development (EWD or Pipeline Operations), Frontier Utilities of North Carolina (FUNC) and Penobscot Natural Gas (PNB). The consolidated financial statements also include our proportionate share of the assets, liabilities, revenues, and expenses of certain producing natural gas properties that were acquired in fiscal years 2002 and 2003. All intercompany transactions and accounts have been eliminated.
Segments - The Company reports financial results for five business segments: Natural Gas Operations, EWR, Pipeline Operations, Discontinued Operations, formerly reported as Propane Operations, and Corporate and Other. Summarized financial information for these five segments is set forth in Note 14.
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Use of Estimates in Preparing Financial Statements - 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, the 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 these estimates. The Company has used estimates in measuring certain deferred charges and deferred credits related to items subject to approval of the various public service commissions with jurisdiction over the Company. Estimates are also used in the development of discount rates and trend rates related to the measurement of postretirement benefit obligations and accrual amounts, allowances for doubtful accounts, asset retirement obligations, valuing derivative instruments, and in the determination of depreciable lives of utility plant. The deferred tax asset, valuation allowance and related extraordinary gain require a significant amount of judgment and are significant estimates. The estimates are based on projected future tax deductions, future taxable income, estimated limitations under the Internal Revenue Code, an estimated valuation allowance, and other assumptions.
Natural Gas Inventories - Natural gas inventory is stated at the lower of weighted average cost or net realizable value except for Energy West Montana - Great Falls, which is stated at the rate approved by the Montana Public Service Commission (MPSC), which includes transportation and storage costs.
Accumulated Provisions for Doubtful Accounts - We encounter risks associated with the collection of our accounts receivable. As such, we record a provision for those accounts receivable that are considered to be uncollectible. In order to calculate the appropriate provision, we primarily utilize the historical accounts receivable write-off amounts. The underlying assumptions used for the provision can change from period to period and the provision could potentially cause a material impact to our income statement and working capital.
Recoverable/Refundable Costs of Gas and Propane Purchases - The Company accounts for purchased gas and propane costs in accordance with procedures authorized by the MPSC, the Wyoming Public Service Commission (WPSC), the North Carolina Utilities Commission (NCUC), the Maine Public Utilities Commission (MPUC) and, until April 1, 2007 with the sale of our Arizona Propane operations, the Arizona Corporation Commission (ACC). Purchased gas and propane costs that are different from those provided for in present rates, and approved by the applicable commissions, are accumulated and recovered or credited through future rate changes. As of December 31, 2009 and 2008 and June 30, 2008 and 2007, the Company had unrecovered purchase gas costs of $641,755 and $2,041,280, respectively, and over-recovered purchase gas costs of $1,452,580 and $1,022,853, respectively.
Property, Plant, and Equipment - Property, plant and equipment are recorded at original cost when placed in service. Depreciation and amortization on assets are generally recorded on a straight-line basis over the estimated useful lives, as applicable, at various rates. These assets are depreciated and amortized over three to forty years.
Contributions in Aid and Advances Received for Construction - Contributions in aid of construction are contributions received from customers for construction that are not refundable and are amortized over the life of the assets. Customer advances for construction includes advances received from customers for construction that are to be refunded wholly or in part.
Natural Gas Reserves - EWR owns an undivided interest in certain producing natural gas reserves on properties located in northern Montana. EWD also owns an undivided interest in certain natural gas producing properties located in northern Montana. The Company is depleting these reserves using the units-of-production method. The production activities are being accounted for using the successful efforts method. The oil and gas producing properties are included at cost in Property, Plant and Equipment, Net in the accompanying consolidated financial statements. The Company is not the operator of any of the natural gas producing wells on these properties. The production of the gas reserves is not considered to be significant to the operations of the Company as defined by ASC 932, Extractive Activities - Oil and Gas.
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Impairment of Long-Lived Assets - The Company evaluates its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets or intangibles may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future undiscounted net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. As of December 31, 2009 and 2008, and June 30, 2008 and 2007, management does not consider the value of any of its long-lived assets to be impaired.
Stock-Based Compensation - The Company accounts for share-based compensation arrangements by recognizing compensation costs for all share-based awards over the respective service period for employee services received in exchange for an award of equity or equity-based compensation. The compensation cost is based on the fair value of the grant on the date it was awarded.
Accordingly, during the year ended December 31, 2009, the six months ended December 31, 2008, and the years ended June 30, 2008 and 2007, the Company recorded $27,143, $17,355, $213,286, and $58,229, respectively, ($16,704, $10,680, $131,256, and $35,811 net of related tax effects) of compensation expense for stock options granted after July 1, 2005, and for the unvested portion of previously granted stock options that remained outstanding as of July 1, 2005.
In the year ended December 31, 2009 and the six months ended December 31, 2008, 15,000 and 10,000 options were granted, respectively. In the fiscal years ended June 30, 2008 and 2007, 30,000 and 45,000 options were granted, respectively. At December 31, 2009 and 2008, and at June 30, 2008 and 2007, a total of 44,500, 29,500, 19,500 and 165,000 options were outstanding, respectively.
Comprehensive Income - Comprehensive income includes net income and other comprehensive income, which for the Company is primarily comprised of unrealized holding gains or losses on our available-for-sale securities that are excluded from the statement of operations in computing net loss and reported separately in shareholders’ equity. Comprehensive income and its components are as follows:
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Revenue Recognition - Revenues are recognized in the period that services are provided or products are delivered. The Company records gas distribution revenues for gas delivered to residential and commercial customers but not billed at the end of the accounting period. The Company periodically collects revenues subject to possible refunds pending final orders from regulatory agencies. When this occurs, appropriate reserves for such revenues collected subject to refund are established.
Derivatives - The Company accounts for derivative financial instruments that are used to manage risk is in accordance with ASC 815, Derivatives and Hedging (ASC 815). Derivatives are recorded at estimated fair value and gains and losses from derivative instruments are included as a component of gas and electric - wholesale revenues in the accompanying consolidated statements of income. Contracts for the purchase or sale of natural gas at fixed prices and notional volumes must be valued at fair value unless the contracts qualify for treatment as a “normal” purchase or “normal” sale and the appropriate election has been made. As of December 31, 2009 and 2008 and June 30, 2008 and 2007, the Company has no derivative instruments designated and qualifying as hedges under ASC 815.
Debt Issuance and Reacquisition Costs - Debt premium, discount, and issue costs are amortized over the life of each debt issue. Costs associated with refinanced debt are amortized over the remaining life of the new debt.
Cash and Cash Equivalents - All highly liquid investments with original maturities of three months or less at the date of acquisition are considered to be cash equivalents. The Company maintains cash balances at several banks. Accounts at each institution are insured by the Federal Deposit Insurance Corporation up to $250,000. Deposits exceeding federal insurable limits as of December 31, 2009 were $997,669.
Earnings Per Share - Net income per common share is computed by both the basic method, which uses the weighted average number of our common shares outstanding, and the diluted method, which includes the dilutive common shares from stock options, as calculated using the treasury stock method. The only potentially dilutive securities are the stock options described in Note 15. Options to purchase 44,500, 29,500, 19,500 and 165,000 shares of common stock were outstanding at December 31, 2009 and 2008 and June 30, 2008 and 2007, respectively. Earnings per share of prior periods have been adjusted for the 3-for-2 stock split effectuated February 1, 2008.
Credit Risk - Our primary market areas are Montana, Wyoming, North Carolina, Maine and, until April 1, 2007, Arizona. Exposure to credit risk may be impacted by the concentration of customers in these areas due to changes in economic or other conditions. Customers include individuals and numerous industries that may be affected differently by changing conditions. Management believes that its credit review procedures, loss reserves, customer deposits, and collection procedures have adequately provided for usual and customary credit related losses.
Effects of Regulation - The Company follows the provisions of Accounting Standards Codification (ASC) 980, Regulated Operations, and its consolidated financial statements reflect the effects of the different rate-making principles followed by the various jurisdictions regulating the Company. The economic effects of regulation can result in regulated companies recording costs that have been or are expected to be allowed in the ratemaking process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. When this occurs, costs are deferred as assets in the balance sheet (regulatory assets) and recorded as expenses in the periods when those same amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers (regulatory liabilities).
Income Taxes - The Company files its income tax returns on a consolidated basis. Rate-regulated operations record cumulative increases in deferred taxes as income taxes recoverable from customers. The Company uses the deferral method to account for investment tax credits as required by regulatory commissions. Deferred income taxes are determined using the asset and liability method, under which deferred tax assets and liabilities are measured based upon the temporary differences between the financial statement and income tax bases of assets and liabilities, using current tax rates.
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Tax positions must meet a more-likely-than-not recognition threshold to be recognized. The Company has no unrecognized tax benefits that would have a material impact to the Company’s financial statements for any open tax years. No adjustments were recognized for uncertain tax positions during the years ended December 31, 2009 and 2008, the six months ended December 31, 2008, and the fiscal years ended June 30, 2008 and 2007.
The Company recognizes interest and penalties related to unrecognized tax benefits in operating expense. As of December 31, 2009 and 2008, the Company had no unrecognized tax benefits, recognized no interest and penalties and had no interest or penalties accrued related to unrecognized tax benefits.
The Company, or one or more of its subsidiaries, files income tax returns in the U.S. federal jurisdiction and various state jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal tax or state and local income tax examinations by tax authorities for tax years prior to June 30, 2005. Currently, the Company is not being examined by any taxing authorities.
Financial Instruments - The fair value of all financial instruments with the exception of fixed rate long-term debt approximates carrying value because they have short maturities or variable rates of interest that approximate prevailing market interest rates. See Note 6 for a discussion of the fair value of the fixed rate long-term debt.
Asset Retirement Obligations (ARO) - The Company records the fair value of a liability for an asset retirement obligation in the period in which it was incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in carrying value of a property associated with the capitalization of an asset retirement cost is included in “Property, plant and equipment, net” in the accompanying consolidated balance sheets. The Company depreciates the amount added to property, plant, and equipment, net. The accretion of the asset retirement liability is allocated to operating expense using a systematic and rational method. As of December 31, 2009 and 2008, the Company has recorded a net asset of $214,531 and $256,153 and a related liability of $787,233, and $746,199, respectively. In the future, the Company may have other asset retirement obligations arising from its business operations.
The Company has identified but not recognized ARO liabilities related to gas transmission and distribution assets resulting from easements over property not owned by the Company. These easements are generally perpetual and only require retirement action upon abandonment or cessation of use of the property for the specified purpose. The ARO liability is not estimable for such easements as the Company intends to utilize these properties indefinitely. In the event the Company decides to abandon or cease the use of a particular easement, an ARO liability would be recorded at that time.
Changes in the asset retirement obligation are as follows:
Goodwill - Goodwill represents the excess of the purchase price over the fair value of identifiable net tangible and intangible assets acquired in a business combination. Goodwill is required to be tested for impairment annually, which is completed in the fourth quarter, or more frequently if events or changes in circumstances indicate
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
that goodwill may be impaired. At December 31, 2009, the Company has recorded $1,056,771 of goodwill related to the acquisition of Cut Bank Gas Company. This acquisition was completed on November 2, 2009.
Equity Method Investments - Our marketing and production operations segment owns a 21.98% interest in Kykuit Resources, LLC, (Kykuit), a developer and operator of oil, gas and mineral leasehold estates located in Montana. We have invested a total of approximately $1.5 million in Kykuit, with a net investment after undistributed losses of approximately $782,000.
Our obligations to make additional investments in Kykuit are limited under the Kykuit operating agreement. We are entitled to cease further investments in Kykuit if, in our reasonable discretion after the results of certain initial exploration activities are known, we deem the venture unworthy of further investments. Even if the venture is reasonably successful, we are obligated to invest no more than an additional $1.5 million over the life of the venture. Other investors in Kykuit include our chairman of the board, Richard M. Osborne, and John D. Oil and Gas Company, a publicly held gas exploration company, which is also the managing member of Kykuit. Also, Mr. Osborne is the chairman of the board and chief executive officer, and our director Mr. Gregory J. Osborne is president and Mr. Smith is a director of John D. Oil and Gas Company.
The loss on our equity investment in Kykuit for 2009 included an impairment charge of $687,000, due to the write-off of drilling costs resulting in dry holes.
We are accounting for the investment in Kykuit using the equity method. The Company’s investment in Kykuit at December 31, 2009 and 2008 was approximately $782,000 and $1.1 million including undistributed losses of approximately $700,000 and $37,000, respectively.
New Accounting Pronouncements
Recently Adopted
Fair Value Measurements - In September 2006, the FASB issued guidance that defines fair value, establishes a framework and gives guidance regarding the methods used for measuring fair value, and expands disclosures about fair value measurements. This guidance is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. On January 1, 2008 we elected to implement this guidance with the one-year deferral and the adoption did not have a material impact on our financial position, results of operations or cash flows. Beginning January 1, 2009, we have adopted the provisions for non-financial assets and non-financial liabilities that are not required or permitted to be measured at fair value on a recurring basis.
Business Combinations - In December 2007, the FASB issued new guidance on business combinations which requires an acquirer to recognize and measure the assets acquired, liabilities assumed and any non-controlling interests in the acquiree at the acquisition date, measured at their fair values as of that date, with limited exception. In addition, the new guidance requires that acquisition-related costs will be generally expensed as incurred and also expands the disclosure requirements for business combinations. The effective date of this new guidance is for years beginning after December 15, 2008 and we have adopted it on our consolidated financial statements, effective January 1, 2009. In addition, we have recorded as expense in the year ending December 31, 2009, and the six months ending December 31, 2008, $830,000 and $585,000, respectively of acquisition costs related to acquisitions in progress as part of the transition to the new guidance.
Noncontrolling Interests - In December 2007, the FASB issued new guidance establishing standards of accounting and reporting on non-controlling interests in consolidated financial statements. Also provided is guidance on accounting for changes in the parent’s ownership interest in a subsidiary, and standards of accounting for the deconsolidation of a subsidiary due to the loss of control. The effective date of this guidance is for fiscal years beginning after December 15, 2008. We have adopted the guidance on our consolidated financial statements, effective January 1, 2009. The implementation did not have a material impact on our consolidated financial statements.
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Derivative Instruments and Hedging Activities - In March 2008, the FASB released new guidance which amends and expands previous disclosure requirements for derivative instruments and hedging activities and requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. The new guidance is effective for financial statements issued for fiscal periods beginning after November 15, 2008. We implemented the guidance on January 1, 2009. The implementation did not have a material impact on our consolidated financial statements.
Interim Fair Value Disclosures - In April 2009, the FASB issued new guidance on interim disclosures about fair value of financial instruments which requires that disclosures regarding the fair value of financial instruments be included in interim financial statements. This new guidance was effective for interim periods ending after June 15, 2009. We adopted this guidance for the period ending June 30, 2009.
Other-Than-Temporary Impairments - In April 2009, the FASB also issued released new guidance on presentation of other-than-temporary impairments which changes the method for determining whether an other-than-temporary impairment exists for debt securities, and also requires additional disclosures regarding other-than-temporary impairments. This new guidance is effective for interim and annual periods ending after June 15, 2009. We implemented the guidance on July 1, 2009. The implementation did not have a material impact on our consolidated financial statements.
Accounting Standards Codification (Codification) - In June 2009, the FASB established the Codification as the source of authoritative generally accepted accounting principles recognized by the FASB. All existing accounting standards are superseded, aside from those issued by the SEC. All other accounting literature not included in the Codification is considered non-authoritative. We adopted the Codification as of September 30, 2009, which is reflected in our disclosures and references to accounting standards, with no impact to our financial position or results of operations.
Earnings Per Share - In September 2009, the FASB issued guidance that provided corrections to various parts of the Codification regarding EPS. The guidance is effective immediately upon being issued. The initial adoption of this guidance did not have an impact on the consolidated earnings or financial position of the Company as the update amended the reference between the Codification and pre-Codification references.
Subsequent Events - In May 2009, the FASB issued subsequent events guidance which establishes standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. In addition it requires disclosure of the date through which the Company has evaluated subsequent events and whether it represents the date the financial statements were issued or were available to be issued. This guidance was effective for the Company on June 30, 2009. The adoption of the subsequent events guidance did not have a material effect on the Company’s financial position or results of operations.
Recently Issued
Consolidation of Variable Interest Entities - In June 2009, the FASB issued new guidance on consolidation of variable interest entities. The guidance will significantly affect various elements of consolidation under existing accounting standards, including the determination of whether an entity is a variable interest entity and whether an enterprise is a variable interest entity’s primary beneficiary. This new guidance is effective for interim and annual periods beginning after November 15, 2009. We do not expect the implementation of the guidance to have a material impact on our consolidated financial statements.
Fair Value Measurement Disclosures - In January 2010, the FASB issued Fair Value Measurements and Disclosures (Topic 820) - Improving Disclosures about Fair Value Measurements (ASU No. 2010-06), which will update the Codification to require new disclosures for assets and liabilities measured at fair value. The requirements include expanded disclosure of valuation methodologies for Level 2 and Level 3 fair value measurements, transfers
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
in and out of Levels 1 and 2, and gross rather than net presentation of certain changes in Level 3 fair value measurements. The updates to the Codification contained in ASU No. 2010-06 are effective for interim and annual periods beginning after December 15, 2009, except for requirements related to gross presentation of certain changes in Level 3 fair value measurements, which are effective for interim and annual periods beginning after December 15, 2010. We do not expect the implementation of the guidance to have a material impact on our consolidated financial statements.
2.
Discontinued Operations
Until March 31, 2007, we were engaged in the regulated sale of propane under the business name Energy West Arizona, or “EWA”, and the unregulated sale of propane under the business name Energy West Propane - Arizona, or “EWPA”, collectively known as EWP. EWP distributed propane in the Payson, Pine, and Strawberry, Arizona area located about 75 miles northeast of Phoenix in the Arizona Rim Country. EWP’s service area included approximately 575 square miles and a population of approximately 50,000.
On July 17, 2006, we entered into an Asset Purchase Agreement among Energy West, EWP, and SemStream, L.P. Pursuant to the Asset Purchase Agreement, we agreed to sell, and SemStream agreed to buy, (i) all of the assets and business operations associated with our regulated propane gas distribution system operated in the cities and outlying areas of Payson, Pine, and Strawberry, Arizona (the “Regulated Business”), and (ii) all of the assets and business operations of EWP that are associated with certain “non-regulated” propane assets (the “Non-Regulated Business,” and together with the Regulated Business, the “Business”).
SemStream purchased only the assets and business operations of EWP that pertain to the Business within the state of Arizona, and that also pertain to the Energy West Propane - Arizona division of our company and/or EWP (collectively, the “Arizona Assets”). Pursuant to the Asset Purchase Agreement, SemStream paid a cash purchase price of $15,000,000 for the Arizona Assets, plus working capital.
Pursuant to the Purchase and Sale Agreement, the sale was conditioned on approval by the Arizona Corporation Commission, or “ACC”, with the closing to occur on the first day of the month after receipt of ACC approval. This approval was received on March 13, 2007, and the closing date of the transaction was April 1, 2007.
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The gain on the sale of these assets is presented under the heading “Gain from disposal of operations”. The results of operations for the propane assets related to this sale have been reclassified as income from discontinued operations in the accompanying Statement of Income, and consist of the following:
The small Montana wholesale distribution of propane to our affiliated utility, which was formerly reported in Propane Operations, is now being reported in EWR.
3.
Acquisitions and Extraordinary Gain
On October 1, 2007, the Company completed the acquisition of Frontier Utilities, which operates a natural gas utility in and around Elkin, North Carolina through its subsidiary, Frontier Natural Gas. The purchase price was $4.5 million in cash, plus adjustment for taxes and working capital, resulting in a total purchase price of approximately $4.9 million. On December 1, 2007, the Company completed the acquisition of Penobscot Natural Gas for a purchase price of approximately $226,000, plus adjustment for working capital, resulting in a total purchase price of approximately $434,000. Penobscot Natural Gas is the parent company of Bangor Gas Company LLC, which operates a natural gas utility in and around Bangor, Maine.
The results of operations for Frontier Utilities and Penobscot Natural Gas have been included in the consolidated financial statements since the dates of acquisition.
Under ASC 805, Business Combinations (formerly FAS 141), the Company has recorded these stock acquisitions as if the net assets of the targets were acquired. For income tax purposes, the Company is permitted to “succeed” to the operations of the acquired companies, whereby the Company may continue to depreciate the assets at their historical tax cost bases. As a result, the Company may continue to depreciate approximately $82.0 million of capital assets using the useful lives and rates employed by both Frontier Utilities and Penobscot Natural Gas. This treatment results in a potential future federal and state income tax benefit of approximately $19.0 million over an estimated 24-year period using applicable federal and state income tax rates. Under Internal Revenue Code Section 382, our ability to recognize tax deductions as a result of this tax benefit will be limited during the first 5 years following the acquisitions.
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Following FASB ASC 740, Income Taxes, our balance sheet at December 31, 2008 reflects a gross deferred tax asset of approximately $19.0 million, offset by a valuation allowance of approximately $7.5 million, resulting in a net deferred tax asset associated with the acquisition of approximately $11.5 million.
The excess of the net deferred tax assets received in the transactions over the total purchase consideration has been reflected in fiscal 2008 as an extraordinary gain of approximately $6.8 million on the accompanying statement of income in accordance with the provisions of ASC 805, Business Combinations (formerly FAS 141).
During the year ended December 31, 2009, we conducted a study of the deferred tax asset and valuation allowance, and based on our updated earnings projections and more complete data from the seller’s tax returns, we determined that $2.8 million of the valuation allowance related to federal taxes is no longer needed but that the state portion should be increased by $400,000. Accordingly, we reduced the valuation allowance to approximately $5.1 million. In addition, we increased the gross deferred tax asset to $19.1 million. As a result, the net deferred tax asset increased to approximately $14.0 million at December 31, 2009. Included in the results of our Corporate and Other segment for the year ended December 31, 2009 is the income tax benefit of approximately $2.8 million related to the elimination of the federal portion of the valuation allowance. An income tax expense of $300,000 resulting from the increase in the state portion of the valuation allowance partially offset by the increase in the gross deferred tax asset is included in the results of the Natural Gas Operations segment.
On November 2, 2009, we completed the acquisition of a majority of the outstanding shares of Cut Bank Gas Company, a natural gas utility serving Cut Bank, Montana. Pursuant to a stock purchase agreement with the founders and controlling shareholders of Cut Bank Gas, we acquired 83.16% for a purchase price of $500,000 paid in shares of our common stock. We also offered to purchase the remaining shares of Cut Bank Gas from the shareholders that owned the other 16.84%, most of whom have tendered their shares. The acquisition increased our customers by approximately 1,500.
The acquisition of Cut Bank Gas Company is accounted for under the purchase method of accounting. Under the purchase method of accounting, the purchase price is allocated to the assets acquired and liabilities assumed based on their estimated fair values. The assets acquired and liabilities assumed are not material to the financial position of the Company and the results of operations from Cut Bank Gas are not material to our Consolidated Statement of Income.
4.
Natural Gas Wells
In order to provide a stable source of natural gas for a portion of its requirements, EWR and EWD purchased ownership in two natural gas production properties and three gathering systems located in north central Montana. The purchases were made in May 2002 and March of 2003. The Company is depleting the cost of the gas properties using the units-of-production method. As of December 31, 2009, management of the Company estimated the net gas reserves at 2.3 Bcf (unaudited) and a $2,940,000 net present value after applying a 10% discount (unaudited), considering reserve estimates provided by an independent reservoir engineer. The net book value of the gas properties totals $1,746,982 and is included in the “Property, plant and equipment, net” in the accompanying consolidated financial statements.
Beginning in fiscal 2007, the Company engaged in a limited drilling program of developmental wells on these existing properties. As of December 31, 2008, this program was complete. Five wells had been drilled and were capitalized as part of the drilling program, with two wells finding production and being tied in to the gathering system. The reserves from these wells are included in the reserves listed above.
The wells are depleted based upon production at approximately 10% per year as of December 31, 2009. For the year ended December 31, 2009, EWR’s portion of the daily gas production was approximately 412 Mcf per day, or approximately 13.1% of EWR’s present volume requirements.
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
In March 2003, EWD acquired working interests in a group of producing natural gas properties consisting of 47 wells and a 75% ownership interest in a gathering system located in northern Montana.
For the year ended December 31, 2009, EWD’s portion of the daily gas production was approximately 162 Mcf per day, or approximately 5.1% of EWR’s present volume requirements.
EWR and EWD’s combined portion of the estimated daily gas production from the reserves is approximately 574 Mcf, or approximately 18.2% of our present volume requirements in our Montana market. The wells are operated by an independent third party operator who also has an ownership interest in the properties. In 2002 and 2003 the Company entered into agreements with the operator of the wells to purchase a portion of the operator’s share of production. The production of the gas reserves is not considered to be significant to the operations of the Company as defined by FASB ASC 932, Extractive Activities - Oil and Gas.
5.
Marketable Securities
Securities investments that the Company has the positive intent and ability to hold to maturity are classified as held-to-maturity securities and recorded at amortized cost. Securities investments not classified as either held-to-maturity or trading securities are classified as available-for-sale securities. Available-for-sale securities are recorded at fair value in investments and other assets on the balance sheet, with the change in fair value during the period excluded from earnings and recorded net of tax as a component of other comprehensive income.
The following is a summary of available-for-sale securities at December 31, 2009 and 2008:
As of December 31, 2009 and 2008, unrealized gains on available-for-sale securities of $146,701 (net of $91,571 in taxes) and unrealized losses on available-for-sale securities of $319,147 (net of $199,454 in taxes) were included in accumulated other comprehensive income in the accompanying Consolidated Balance Sheets. There were no unrealized gains or losses during the 12 months ended June 30, 2008 and 2007.
6.
Fair Value Measurements
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., an exit price). Measuring fair value requires the use of market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, corroborated by market data, or generally unobservable. Valuation techniques are required to maximize the use of observable inputs and minimize the use of unobservable inputs. Our management believes that we are not exposed to significant interest or credit risk from these financial instruments.
Valuation Hierarchy
A fair value hierarchy that prioritizes the inputs used to measure fair value, and requires fair value measurements to be categorized based on the observability of those inputs has been established by the applicable accounting guidance. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for
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identical assets or liabilities (Level 1 inputs) and the lowest priority to unobservable inputs (Level 3 inputs). The following table represents the Company’s fair value hierarchy for its financial assets measured at fair value on a recurring basis as of December 31, 2009 and 2008:
7.
Property, Plant and Equipment
Property, plant and equipment consist of the following as of December 31, 2009 and 2008:
Property, plant and equipment includes contributions in aid of construction of $1,677,549 and $1,418,460, at December 31, 2009 and 2008, respectively.
8.
Deferred Charges
Deferred charges consist of the following as of December 31, 2009 and 2008:
Regulatory assets will be recovered over a period of approximately seven to twenty years.
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The regulatory asset for property tax is recovered in rates over a ten-year period starting January 1, 2004. The income taxes and environmental remediation costs earn a return equal to that of the Company’s rate base. No other assets listed above earn a return or are recovered in the rate structure.
9.
Accrued and Other Current Liabilities
Accrued and other current liabilities consist of the following as of December 31, 2009 and 2008:
10.
Other Long-Term Liabilities
Other long-term liabilities consist of the following as of December 31, 2009 and 2008:
11.
Credit Facilities and Long-Term Debt
On June 29, 2007, the Company replaced its existing credit facility and long-term notes with a new $20,000,000 revolving credit facility with Bank of America and $13,000,000 of 6.16% Senior unsecured notes. The prior Bank of America credit facility had been secured, on an equal and ratable basis with our previously outstanding long-term debt, by substantially all of our assets.
Bank of America Line of Credit The new credit facility includes an annual commitment fee equal to 0.20% of the unused portion of the facility and interest on amounts outstanding at the London Interbank Offered Rate, plus 120 to 145 basis points, for interest periods selected by the Company.
For the year ended December 31, 2009, the weighted average interest rate on the facility was 3.25% .
$13,000,000 6.16% Senior Unsecured Notes - On June 29, 2007, the Company authorized the sale of $13,000,000 aggregate principal amount of its 6.16% Senior Unsecured Notes, due June 29, 2017. The proceeds of these notes were used to refinance our existing notes - the Series 1997 Notes, the Series 1993 Notes, and the
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Series 1992B Industrial Development Revenue Obligations. With this refinancing, we expensed the remaining debt issue costs of $991,000 in fiscal 2007, and incurred approximately $463,000 in new debt issue costs to be amortized over the life of the note using the effective interest method.
Series 1997 Notes Payable - On August 1, 1997, the Company issued $8,000,000 of Series 1997 notes bearing interest at the rate of 7.5%, payable semiannually on June 1 and December 1 of each year. All principal amounts of the 1997 notes then outstanding, plus accrued interest, were due and payable on June 1, 2012. At our option, the notes could be redeemed at any time prior to maturity, in whole or part, at 101% of face value if redeemed before June 1, 2005, and at 100% of face value if redeemed thereafter, plus accrued interest. On June 27, 2007, the Company redeemed the notes under this issue at 100% of face value plus accrued interest.
Series 1993 Notes Payable - On June 24, 1993, the Company issued $7,800,000 of Series 1993 notes bearing interest at rates ranging from 6.20% to 7.60%, payable semiannually on June 1 and December 1 of each year. The 1993 notes mature serially in increasing amounts on June 1 of each year beginning in 1999 and extending to June 1, 2013. At our option, the notes could be redeemed at any time prior to maturity, in whole or part, at redemption prices declining from 103% to 100% of face value, plus accrued interest. On June 27, 2007, the Company redeemed the Series 1993 notes at 100% of face value plus accrued interest.
Series 1992B Industrial Development Revenue Obligations - On September 15, 1992, Cascade County, Montana issued $1,800,000 of Series 1992B Industrial Development Revenue Bonds (the “1992B Bonds”) bearing interest at rates ranging from 3.35% to 6.50%, and loaned the proceeds to the Company. The Company is required to pay the loan, with interest, in amounts and on a schedule to repay the 1992B Bonds. Interest is payable semiannually on April 1 and October 1 of each year. The 1992B Bonds began maturing serially in increasing amounts on October 1, 1993, and continuing on each October 1 thereafter until October 1, 2012. At our option, 1992B Bonds may be redeemed in whole or in part on any interest payment date at redemption prices declining from 101% to 100% of face value, plus accrued interest. On June 27, 2007, the Company redeemed the 1992B Bonds at 100% of face value plus accrued interest.
Term Loan - In 2004, in addition to the Series 1997 and 1993 Notes and the 1992B Bonds discussed above, the Company had a revolving credit agreement with Bank of America. In March 2004, the Company converted $8,000,000 of existing revolving loans into a $6,000,000, five-year term loan with principal payments of $33,333 each month and a $2,000,000 short-term loan. On May 26, 2005, the Company completed the sale of 287,500 common shares at a price of $8.00 per share for net proceeds of $2,202,956 after deducting $97,044 of issuance expenses. $2,000,000 of the equity proceeds were immediately used to pay off the $2,000,000 short-term loan. The remaining balance of the $6,000,000 five-year term loan was paid in full on April 2, 2007 with proceeds from the sale of the Arizona propane assets.
Debt Covenants - The Company’s 6.16% Senior Unsecured Note and Bank of America credit facility agreements contain various covenants, which include, among others, limitations on total dividends and distributions made in the immediately preceding 60-month period to 75% of aggregate consolidated net income for such period, restrictions on certain indebtedness, limitations on asset sales, and maintenance of certain debt-to-capital and interest coverage ratios. At December 31, 2009, the Company believes it was in compliance with the financial covenants under its debt agreements.
12.
Employee Benefit Plans
The Company has a defined contribution plan (the “401k Plan”) which covers substantially all of its employees. The plan provides for an annual contribution of 3% of salaries, with a discretionary contribution of up to an additional 3%. Total contributions to the 401k Plan for the year ended December 31, 2009, the six months ended December 31, 2008, and the years ended June 30, 2008 and 2007 were $175,940, $170,766, $130,107 and $132,131, respectively.
The Company makes matching contributions in the form of Company stock equal to 10% of each participant’s elective deferrals in our 401k Plan. The Company contributed shares of our stock valued at $29,770, $24,735, and $21,690 in the years ended December 31, 2009, June 30, 2008 and 2007, respectively. The Company contributed
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
shares of our stock valued at $17,493 during the six months ended December 31, 2008. In addition, a portion of our 401k Plan consists of an Employee Stock Ownership Plan (“ESOP”) that covers most of our employees. The ESOP receives contributions of our common stock from the Company each year as determined by the Board of Directors. The contribution is recorded based on the current market price of our common stock. The Company made no contributions for the year ended December 31, 2009, the six months ended December 31, 2008, or the fiscal years ended June 30, 2008 and 2007.
The Company has sponsored a defined postretirement health benefit plan (the “Retiree Health Plan”) providing health and life insurance benefits to eligible retirees. The Plan pays eligible retirees (post-65 years of age) up to $125 per month in lieu of contracting for health and life insurance benefits. The amount of this payment is fixed and will not increase with medical trends or inflation. In addition, our Retiree Health Plan allows retirees between the ages of 60 and 65 and their spouses to remain on the same medical plan as active employees by contributing 125% of the current COBRA rate to retain this coverage. The amounts paid in excess of the current COBRA rate is held in a VEBA trust account, and benefits for this plan are paid from assets held in the VEBA Trust account. During fiscal 2006, the Company discontinued contributions and is no longer required to fund the Retiree Health Plan. As of December 31, 2009, the value of plan assets is $273,181. The assets remaining in the trust will be used to fund the plan until these assets are exhausted.
13.
Income Taxes
Significant components of our deferred tax assets and liabilities as of December 31, 2009 and 2008 are as follows:
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Income tax expense for the year ended December 31, 2009, the six months ended December 31, 2008 and the years ended June 30, 2008 and 2007 consists of the following:
Income tax expense differs from the amount computed by applying the federal statutory rate to pre-tax income for the following reasons:
Income tax from discontinued operations was $0, $0, $0, and $2,499,875 during the year ended December 31, 2009, the six months ended December 31, 2008, and the fiscal years ended June 30, 2008 and 2007, respectively. Other taxes include true ups of prior year’s tax expense to the various tax returns.
14.
Segments of Operations
The following tables set forth summarized financial information for the Company’s natural gas operations, marketing and production operations, pipeline operations, discontinued (formerly propane) operations, and corporate and other operations. The Company classifies its segments to provide investors with the view of the business through management’s eyes. The Company primarily separates its state regulated utility businesses from the non-regulated marketing and production business and from the federally regulated pipeline business. The Company has regulated utility businesses in the states of Montana, Wyoming, North Carolina and Maine and these businesses are aggregated together to form our natural gas operations. Transactions between reportable segments are accounted for on the accrual basis, and eliminated prior to external financial reporting. Inter-company
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eliminations between segments consist primarily of gas sales from the marketing and production operations to the natural gas operations, inter-company accounts receivable, accounts payable, equity, and subsidiary investment:
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15.
Stockholders’ Equity
Our common stock trades on the NYSE Amex Equities (formerly known as the American Stock Exchange) under the symbol “EGAS.” On February 1, 2008, the Board of Directors authorized a 3-for-2 stock split of the company’s $0.15 par value common stock. As a result of the split, 1,437,744 additional shares were issued, and additional paid-in capital was reduced by $215,619. All references in the accompanying financial statements to the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
number of common shares and per-share amounts for fiscal 2008 and 2007 have been restated to reflect the stock split.
Purchases of Equity Securities by Our Company
All shares adjusted for 3-for-2 stock split effectuated February 1, 2008.
On February 13, 2007, our Board of Directors approved a stock repurchase plan whereby the Company intends to buy back up to 448,500 shares of the Company’s common stock. We began this stock buyback on May 30, 2007. The stock repurchases included 217,500 shares from Mr. Mark Grossi, one of our directors. During the six months ended December 31, 2008, we repurchased 53,416 shares of common stock. During the year ended December 31, 2009, these shares were reissued for the purchase of Cut Bank Gas.
2002 Stock Option Plan - The Energy West Incorporated 2002 Stock Option Plan (the “Option Plan”) provides for the issuance of up to 300,000 shares of our common stock to be issued to certain key employees. As of December 31, 2009, there are 44,500 options outstanding and the maximum number of shares available for future grants under this plan is 48,500 shares. Additionally, our 1992 Stock Option Plan (the “1992 Option Plan”), which expired in September 2002, provided for the issuance of up to 100,000 shares of our common stock pursuant to options issuable to certain key employees. Under the 2002 Option Plan and the 1992 Option Plan (collectively, “the Option Plans”), the option price may not be less than 100% of the common stock fair market value on the date of grant (in the event of incentive stock options, 100% of the fair market value if the employee owns more than 10% of our outstanding common stock). Pursuant to the Option Plans, the options vest over four to five years and are exercisable over a five to ten-year period from date of issuance. When the 1992 Option Plan expired in September 2002, 12,600 shares remained unissued and were no longer available for issuance.
During fiscal year 2008, 54,375 stock options were exercised in a noncash transaction for the exercise price of $333,988. As part of the transaction, 37,500 shares were canceled and returned to authorized/unissued stock at a value of $374,499. These shares were accepted by the Company as total payment of the exercise price and the employee’s share of related payroll taxes.
Stock Option Disclosures - The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model. See Note 1 for the related pro forma disclosures. The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing.
A summary of the status of our stock option plans as of December 31, 2009 and 2008, and June 30, 2008 and 2007, and changes during the six months and years ended on these dates is presented below.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The weighted average fair value of options granted during the year ended December 31, 2009, six months ended December 31, 2008 and years ended June 30, 2008 and 2007 was $2.50, $2.52, $2.33, and $2.50, respectively. At December 31, 2009, there was $40,356 of total unrecognized compensation cost related to stock-based compensation. That cost is expected to be recognized over a period of three years.
The following information applies to options outstanding at December 31, 2009:
For the year ended December 31, 2009, the six months ended December 31, 2008, and the years ended June 30, 2008 and 2007, all stock options granted have an exercise price equal to the fair market value of the Company’s stock at the date of grant.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Termination of Preferred Stock Rights Agreement by Amendment of Final Expiration Date - Expiration of the Preferred Stock Purchase Rights - On April 23, 2007, the Company’s Board of Directors approved Amendment No. 2 (“Amendment No. 2”) to the Company’s Preferred Stock Rights Agreement, dated June 3, 2004, as previously amended by Amendment No. 1 thereto dated May 25, 2005 (the “Rights Agreement”). Amendment No. 2 accelerates the Final Expiration Date of the Rights Agreement so as to cause the Rights Agreement, as well as the Preferred Stock Purchase Rights (the “Rights”) defined by the Rights Agreement, to expire, terminate and cease to exist at 5:00 p.m., New York time (EST) on May 25, 2007. Amendment No. 2 became effective April 24, 2007.
The Rights Agreement was designed and approved by the Board of Directors to deter coercive tactics by an acquirer in connection with any unsolicited attempt to acquire or take over the Company in a manner or on terms not approved by the Board of Directors. Under the Rights Agreement, any “Acquiring Person” (as defined in the Rights Agreement) was generally precluded from acquiring additional shares of common stock without becoming subject to significant dilution as a result of triggering the dilutive provisions of the Rights Agreement, commonly known as a “poison pill.” Amendment No. 2 terminated the Rights Agreement on May 25, 2007, thus permitting Acquiring Persons after that date to acquire additional shares of Common Stock of the Company without being subject to such dilution.
16.
Commitments and Contingencies
Commitments - In 2000, the Company entered into a ten year transportation agreement with Northwestern Energy that fixed the cost of pipeline and storage capacity. Based on original contract prices, the minimum obligation under this agreement at December 31, 2009 was $1,064,724 for the year ending December 31, 2010.
The Company’s operating unit, Bangor Gas Company, LLC entered into an agreement with Maritimes and Northeast Pipeline for the transportation and storage of natural gas. Future obligations due to Maritimes and Northeast Pipeline consist of the following:
The Company also guarantees the gas supply obligations of its subsidiaries for up to $7.0 million of amounts purchased.
Environmental Contingency - The Company owns property on which it operated a manufactured gas plant from 1909 to 1928. The site is currently used as an office facility for Company field personnel and storage location for certain equipment and materials. The coal gasification process utilized in the plant resulted in the production of certain by-products that have been classified by the federal government and the State of Montana as hazardous to the environment.
In 1999, the Company received approval from the Montana Department of Environmental Quality (“MDEQ”) for its plan for remediation of soil contaminants. The Company has completed its remediation of soil contaminants and in April 2002 received a closure letter from MDEQ approving the completion of such remediation program.
The Company and its consultants continue to work with the MDEQ relating to the remediation plan for water contaminants. The MDEQ has established regulations that allow water contaminants at a site to exceed standards if it is technically impracticable to achieve them. Although the MDEQ has not established guidance to attain a
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
technical waiver, the U.S. Environmental Protection Agency (“EPA”) has developed such guidance. The EPA guidance lists factors which render remediations technically impracticable. The Company has filed a request for a waiver respecting compliance with certain standards with the MDEQ. As of December, 31, 2009 there has been no action on our waiver request by the MDEQ.
At December 31, 2009, we had incurred cumulative costs of approximately $2.1 million in connection with our evaluation and remediation of the site. On May 30, 1995, we received an order from the Montana Public Service Commission (“MPSC”) allowing for recovery of the costs associated with the evaluation and remediation of the site through a surcharge on customer bills. As of December 31, 2009, we had recovered approximately $2.1 million through such surcharges. As of December 31, 2009, the cost remaining to be recovered through the on-going rate is $22,000.
We are required to file with the MPSC every two years for approval to continue the recovery of these costs through a surcharge. During fiscal 2007, the MPSC approved the continuation of the recovery of these costs with its order dated May 15, 2007. During fiscal 2007, the MPSC approved the continuation of the recovery of these costs with its order dated May 15, 2007. Pursuant to this order, we filed an application with the MPSC on June 30, 2009 for continued recovery of these costs. On February 2, 2010 the MPSC issued its order granting recovery through February 28, 2010, at which time the recovery will be complete and the recovery surcharge extinguished.
Derivative Contingencies - Among the risks involved in natural gas marketing is the risk of nonperformance by counterparties to contracts for purchase and sale of natural gas. EWR is party to certain contracts for purchase or sale of natural gas at fixed prices for fixed time periods. Some of these contracts are recorded as derivatives, valued on a mark-to-market basis.
Litigation - The Company is involved in lawsuits that have arisen in the ordinary course of business. The Company is contesting each of these lawsuits vigorously and believes it has defenses to the allegations that have been made.
On February 21, 2008, a lawsuit captioned Shelby Gas Association v. Energy West Resources, Inc., Case No. DV-08-008, was filed in the Ninth Judicial District Court of Toole County, Montana. Shelby Gas Association (“Shelby”) alleges a breach of contract by the Company’s subsidiary, EWR, to provide natural gas to Shelby. The parties each filed cross motions for summary judgment. The court heard oral arguments for the pending motions on July 24, 2009. On September 9, 2009, the court ruled that Shelby Gas Association can proceed with their case for damages. The court also ruled that we can seek a setoff against any damages awarded to Shelby in an amount equal to the damages the Company has suffered as a result of Shelby’s alleged breach of contract. On March 24, 2010, the judge handling the case granted the Company’s motions in limine regarding various aspects of damages which Shelby was seeking, including disallowance of attorneys’ fees, punitive damages and certain consequential damages. A trial has been set for April 2010. The Company continues to believe that this lawsuit is without merit and is vigorously defending itself.
In the Company’s opinion, the outcome of these lawsuits, including the Shelby litigation, will not have a material adverse effect on the Company’s financial condition, cash flows or results of operations.
We are party to certain other legal proceedings in the normal course of our business, that, in the opinion of management, are not material to our business or financial condition. The Company utilizes various risk management strategies, including maintaining liability insurance against certain risks, employee education and safety programs, and other processes intended to reduce liability risk.
The Company reached agreement with the Montana Department of Revenue (“DOR”) to settle personal property tax claims for the years 1997-2002. The settlement amount is being paid in ten annual installments of $243,000 each, beginning November 30, 2003. The Company has obtained rate relief that includes full recovery of the property tax associated with the DOR settlement.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Operating Leases - The Company leases certain properties including land, office buildings, and other equipment under non-cancelable operating leases. The future minimum lease payments on these leases are as follows:
Lease expense from continuing operations resulting from operating leases for the year ended December 31, 2009, the six months ended December 31, 2008 and the years ended June 30, 2008 and 2007 totaled $238,869, $149,563, $233,947 and $90,624, respectively.
17.
Financial Instruments and Risk Management
Management of Risks Related to Derivatives - The Company and its subsidiaries are subject to certain risks related to changes in certain commodity prices and risks of counterparty performance. The Company has established policies and procedures to manage such risks. The Company has a Risk Management Committee comprised of Company officers and management to oversee our risk management program as defined in its risk management policy. The purpose of the risk management program is to minimize adverse impacts on earnings resulting from volatility of energy prices, counterparty credit risks, and other risks related to the energy commodity business.
In order to mitigate the risk of natural gas market price volatility related to firm commitments to purchase or sell natural gas or electricity, from time to time the Company and its subsidiaries have entered into hedging arrangements. Such arrangements may be used to protect profit margins on future obligations to deliver gas at a fixed price, or to protect against adverse effects of potential market price declines on future obligations to purchase gas at fixed prices.
The Company accounts for certain of such purchases or sale agreements in accordance with ASC 815, Derivatives and Hedging. Such contracts are reflected in our financial statements as derivative assets or derivative liabilities and valued at “fair value,” determined as of the date of the balance sheet. Fair value accounting treatment is also referred to as “mark-to-market” accounting. Mark-to-market accounting results in disparities between reported earnings and realized cash flow, because changes in the derivative values are reported in our Consolidated Statement of Income as an increase or (decrease) in “Revenues - Gas and Electric - Wholesale” without regard to whether any cash payments have been made between the parties to the contract. If such contracts are held to maturity, the cash flow from the contracts and their hedges are realized over the life of the contracts. ASC 815 requires that contracts for purchase or sale at fixed prices and volumes must be valued at fair value (under mark-to-market accounting) unless the contracts qualify for treatment as a “normal purchase or normal sale.”
Quoted market prices for natural gas derivative contracts of the Company and its subsidiaries are generally not available. Therefore, to determine the fair value of natural gas derivative contracts, the Company uses internally developed valuation models that incorporate independently available current and forecasted pricing information.
As of December 31, 2009, all of the Company’s contracts for purchase or sale at fixed prices and volumes qualified for treatment as a “normal purchase or a normal sale.”
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
18.
Subsequent Event
Other than the item mentioned below, no significant events have occurred subsequent to the Company’s year end. Subsequent events have been evaluated through the date these financial statements were issued.
Acquisition of Ohio Gas Utilities by Mergers - As previously reported in our Form 8-K filed on January 11, 2010 with the SEC, on January 5, 2010 we completed the acquisition of Lightning Pipeline Company, Inc. (“Lightning Pipeline”), Great Plains Natural Gas Company (“Great Plains”), Brainard Gas Corp. (“BGC”) and Great Plains Land Development Co., LTD. (“GPL,” and collectively with Lightning Pipeline, Great Plains and BGC, the “Ohio Companies” and each an “Ohio Company”). Lightning Pipeline is the parent company of Orwell Natural Gas Company (“Orwell”) and Great Plains is the parent company of Northeast Ohio Natural Gas Corp. (“NEO”). Orwell, NEO and BGC are natural gas distribution companies that serve approximately 23,131 customers in Northeastern Ohio and Western Pennsylvania. The acquisition increased the Company’s customers by more than 50%. GPL is a real estate holding company whose primary asset is real estate that is leased to NEO.
Merger Agreements - As previously reported in our Form 8-K filed on July 2, 2009 with the SEC, Energy West, Incorporated, now a wholly-owned subsidiary of the Company (“Energy West”), entered into an Agreement and Plan of Merger (the “Merger Agreement”) on June 29, 2009 with Richard M. Osborne, as Trustee of the Richard M. Osborne Trust (the “RMO Trust”), Rebecca Howell, Stephen M. Rigo, Marty Whelan, and Thomas J. Smith (Messrs. Osborne, Rigo, Whelan and Smith and Ms. Howell are hereinafter collectively referred to as “Shareholders”), Lightning Pipeline, Great Plains, BGC and three to-be-formed wholly-owned Ohio subsidiary corporations of Energy West. On June 29, 2009, Energy West also entered into an Agreement and Plan of Merger (together with the Merger Agreement, the “Merger Agreements”) with GPL, the RMO Trust and a fourth to-be-formed Ohio acquisition subsidiary (each acquisition subsidiary hereinafter referred to as an “Acquisition Sub” and collectively, as the “Acquisition Subs”) of Energy West. Mr. Osborne is our chairman of the board and chief executive officer, Mr. Smith is a director and our chief financial officer, and Ms. Howell is our corporate secretary. As previously reported in our Form 8-K filed on August 4, 2009 with the SEC, we completed on August 3, 2009 a reorganization to implement a holding company structure. The Company, as the new holding company, became the successor issuer to Energy West, and Energy West assigned its rights under the Merger Agreements to the Company. Pursuant to the terms of the Merger Agreements, on January 5, 2010, four separate mergers occurred whereby an Acquisition Sub of Energy, Inc. merged with and into each Ohio Company. The Ohio Companies survived the mergers, becoming four separate wholly-owned subsidiaries of the Company. The transactions contemplated by the Merger Agreements are referred to herein as the “Merger Transaction.”
Merger Consideration - Issuance of Shares (unaudited) - The final aggregate purchase price for the Ohio Companies was $37.9 million, which consisted of approximately $20.8 million in debt of the Ohio Companies with the remainder of the purchase price paid in unregistered shares of common stock of the Company. In accordance with the Merger Agreements, on January 5, 2010, the shares of common stock of Lightning Pipeline, Great Plains and BGC and the membership units of GPL were converted into the right to receive unregistered shares of common stock of the Company (the “Shares”) in accordance with the following calculation:
The total number of Shares the Shareholders received equaled the total of $34,304,000 plus $3,565,339 (which was the number of additional active customers of the Ohio Companies in excess of 20,900 at closing (23,131-20,900=2,231) multiplied by $1,598.09), less $20,796,254 (which was the debt of the Ohio Companies at closing), divided by $10.
Based on this calculation, we issued 1,707,308 Shares in the aggregate. We issued Mr. Osborne, as trustee, 1,565,701 Shares, Mr. Smith 73,244 Shares and Ms. Howell 19,532 Shares. After the closing of the Merger Transaction on January 5, 2010, Mr. Osborne owns 2,487,972 Shares, or 41.0% of the Company Mr. Smith owns 86,744 Shares, or 1.4% of the Company and Ms. Howell owns 19,532 Shares, or less than 1% of the Company.
The acquisition of the Ohio Companies is being accounted for under the purchase method of accounting. Under the purchase method of accounting, the purchase price is allocated to the assets acquired and liabilities
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
assumed based on their estimated fair values. For purposes of measuring the estimated fair value of the assets acquired and liabilities assumed as reflected in the unaudited pro forma results of operations, an independent appraisal firm conducted a valuation analysis as of date of acquisition, January 5, 2010. The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition (unaudited):
Of the total purchase price, approximately $12.7 million has been allocated to goodwill. Goodwill represents the excess of the purchase price of an acquired business over the fair value of the underlying net tangible and intangible assets. Goodwill is not amortized, rather, the goodwill will be tested for impairment, at least annually, or more frequently if there is an indication of impairment. The goodwill resulting from this acquisition is not deductible for tax purposes.
Transaction costs related to the mergers totaled $871,634, and are recorded on our Consolidated Statement of Income within the other income (expense) line on the statement of income.
The following table summarizes unaudited pro forma results of operations (in thousands) for the years ended December 31, 2009 and 2008 as if the acquisitions had occurred on January 1, 2009 and January 1, 2008, respectively. The unaudited pro forma results of operations are based on the historical financial statements and related notes of each of the Company and the Ohio Companies for the years ended December 31, 2009 and 2008, and contain adjustments to depreciation and amortization for the effects of the purchase price allocation, and to income tax expense to record income tax expense for the Ohio Companies.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The pro forma information is presented for informational purposes only and is not necessarily indicative of the results of operations that actually would have been achieved had the acquisition been consummated as of that time, nor is it intended to be a projection of future results.
The following is a discussion of the credit facilities and term loans being assumed in connection with our acquisition of the Ohio operations. This information is unaudited.
Citizens Bank Credit Facility (Unaudited)
In connection with our acquisition of our Ohio operations, NEO, Great Plains and GPL each entered modifications/amendments to its credit facility with Citizens Bank (the “Citizens Credit Facility”). The Citizens Credit Facility consists of a revolving line of credit and term loan to NEO, and two other term loans to Great Plains and GPL respectively. Each amendment/modification was initially effective as of December 1, 2009, but was later modified to be effective as of January 5, 2010. Energy, Inc. guarantees each loan. Our chairman and chief executive officer, Richard M. Osborne, guarantees each loan both individually and as trustee of the RMO Trust, and Great Plains guarantees NEO’s revolving line of credit and term loan as well as GPL’s term note.
Long-term Debt - $10.3 million 5.00% Senior Secured Notes - NEO’s, Great Plains’ and GPL’s term loans with Citizens Bank are in the amounts of $7.8 million, $2.4 million and $823,000 respectively. Each term note has a maturity date of July 1, 2013 and bears interest at an annual rate of 30-day LIBOR (Eurodollar) plus 400 basis points with an interest rate floor of 5.00% per annum. Currently, the interest rate is 5.00% per annum. The term notes require monthly payments of approximately $63,000 in the aggregate.
Line of Credit - NEO’s revolving credit line with Citizens Bank has a maximum credit commitment of $2.1 million. The revolving line bears interest at an annual rate of 30-day LIBOR (Eurodollar) plus 400 basis points with an interest rate floor of 5.00% per annum. Currently, the interest rate is 5.00% per annum. The revolving line requires monthly interest payments with the principal due at maturity, November 30, 2010.
The Citizens Credit Facility requires Great Plains, GPL and NEO to maintain a debt service coverage ratio of at least 1.25 to 1.0 measured quarterly on a rolling four quarter basis. The Citizens Credit Facility also requires NEO, Great Plains and GPL to maintain a minimum net worth, on a combined basis, equal to the sum of $1,815,000 plus 100% of net income less the pro-rata share of any dividend paid to Energy, Inc., measured on a quarterly basis beginning with the quarter ended December 31, 2009. The Citizens Credit Facility allows NEO, Great Plains and GPL Ohio Companies a party thereto to pay dividends to Energy, Inc. if those entities’ combined net worth (as defined in the Citizens loan documents) after payment of any dividends would not be less than $1,815,000 on a consolidated basis as positively increased by 100% of net income as of the end of each fiscal quarter and fiscal year.
At December 31, 2009, $2.1 million has been borrowed under the revolving line of credit, $7.1 million under the NEO term loan, $2.4 million under the Great Plains term loan and $813,000 under the GPL term loan.
Huntington Credit Facility (unaudited)
On December 31, 2009, Orwell entered into an amended and restated short-term credit facility with The Huntington National Bank, N.A. (the “Huntington Credit Facility”). The Huntington Credit Facility amends and restates the previous credit facility that matured on November 30, 2009. The loan is secured by all of the assets of Orwell. The Huntington Credit Facility is guaranteed by Energy, Inc., Lightning Pipeline, Mr. Osborne individually and as Trustee of the RMO Trust, and certain entities owned and controlled by Mr. Osborne.
Long-term Debt - $4.6 Million Senior Secured Note - The Huntington Credit Facility includes a $4.6 million term note that bears interest at an annual rate of 30-day LIBOR (Eurodollar) plus 300 basis points with LIBOR floor of 1% per annum. Currently, the interest rate is 4.00% per annum. The term note requires monthly payments of approximately $35,000 and matures on November 29, 2010.
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Line of Credit - The Huntington Credit Facility also includes a $1.5 million line of credit. The credit line bears interest at an annual rate of 30-day LIBOR (Eurodollar) plus 300 basis points with LIBOR floor of 1% per annum. Currently, the interest rate is 4.00% per annum. The credit line requires monthly interest payments with the principal due at maturity, November 29, 2010.
The Huntington Credit Facility requires Orwell to maintain a fixed charge coverage ratio of at least 1 to 1 of EBITDA to the sum of (i) scheduled principal payments on debt and capital leases, plus (ii) interest expense, plus (iii) federal, state and local income tax expense, plus (iv) dividends and distributions, measured on a rolling four quarter basis. The Huntington Credit Facility allows Orwell to pay dividends to Energy, Inc. as long as the aggregate amount of all dividends, distributions, redemptions and repurchases in any fiscal year do not exceed 60% of net income (as defined in the Huntington Credit Facility) of Orwell for each fiscal year. At December 31, 2009, $1.5 million has been borrowed under the credit line and $4.3 million under the term note. The Huntington Credit Facility is also secured by a pledge of $3.0 million in market value of Energy, Inc. stock by the RMO Trust.
Combined Term Loans and Credit Facilities (unaudited)
The $14.7 million of borrowings at December 31, 2009, leaves our borrowing capacity at $5.3 million. Including the amounts related to the Ohio companies, we have $18.3 million of borrowings and borrowing capacity of $5.3 million.
The total amount outstanding under all of our long term debt obligations was approximately $13.0 million at December 31, 2009, with none being due within one year. Including the amounts related to the Ohio companies, the total amount is approximately $27.6 million, with approximately $5.1 million due within one year.
19.
Quarterly Information (Unaudited)
Quarterly results (unaudited) for the year ended December 31, 2009, the six months ended December 31, 2008 and the year ended June 30, 2008 are as follows (in thousands, except per share data):
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Certain revenue items have been restated from prior published reports.
ENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Certain revenue items have been restated from prior published reports.