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Gas Natural Inc. 10-K 2011
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
     
þ   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2010
or
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________
Commission file number 001-34585
GAS NATURAL INC.
(Exact name of registrant as specified in its charter)
     
Ohio
(State or other jurisdiction of
incorporation or organization)
  27-3003768
(I.R.S. Employer
Identification No.)
     
1 First Avenue South
Great Falls, Montana

(Address of principal executive office)
 
59401
(Zip Code)
Registrant’s telephone number, including area code: (406) 791-7500
Securities registered pursuant to Section 12(b) of the Act:
     
Title of Each Class   Name of Each Exchange on Which Registered
     
Common, par value $.15 per share   NYSE Amex Equities
Securities registered pursuant to Section 12(g) of the Act:
     
Title of Each Class   Name of Each Exchange on Which Registered
     
None   None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files), Yes o No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
             
Large accelerated filer o   Accelerated filer o   Non-accelerated filer o   Smaller Reporting Company þ
        (Do not check if a smaller reporting company)    
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No þ
The aggregate market value of the registrant’s common stock held by non-affiliates as of June 30, 2010 was $38,096,837.
The number of shares outstanding of the registrant’s common stock as of March 31, 2011 was 8,150,551 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive proxy statement for the 2011 annual meeting of shareholders of Gas Natural Inc. are incorporated by reference into Part III of this Form 10-K.
As used in this Form 10-K, the terms “Company,” “Gas Natural,” “Registrant,” “we,” “us” and “our” mean Gas Natural Inc. and its consolidated subsidiaries as a whole, unless the context indicates otherwise. Except as otherwise stated, the information in this Form 10-K is as of December 31, 2010.
 
 

 


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GLOSSARY OF TERMS
Unless otherwise stated or the context requires otherwise, references to “we,” “us,” the “Company” and “Gas Natural” refer to Gas Natural Inc. and its consolidated subsidiaries. In addition, this glossary contains terms and acronyms that are relevant to natural gas distribution, natural gas marketing and natural gas pipeline operations and that are used in this Form 10-K.
AECO. Alberta Energy Company Limited (used in reference to the AECO natural gas price index).
ASC. FASB Accounting Standards Certification, standards issued by FASB with respect to GAAP.
Bangor Gas Company. Bangor Gas Company, LLC.
Brainard. Brainard Gas Corp.
Bcf. One billion cubic feet, used in reference to natural gas.
CIG. Colorado Interstate Gas (used in reference to the Colorado Interstate Gas Index).
Citizens. Citizens Bank of Michigan
Clarion River. Clarion River Gas Company.
Cut Bank Gas. Cut Bank Gas Company. Energy West Properties. Energy West Properties, LLC
Dekatherm. One million British thermal units, used in reference to natural gas. Abbreviated as Dkt.
EPA. The United States Environmental Protection Agency.
EWR. Energy West Resources, Inc.
Energy West. Energy West, Incorporated.
Exchange Act. The Securities Exchange Act of 1934, as amended.
FASB. Financial Accounting Standards Board.
FERC. The Federal Energy Regulatory Commission.
Frontier Natural Gas. Frontier Natural Gas, LLC.
Frontier Utilities. Frontier Utilities of North Carolina, Inc.
GNI Service Company. Gas Natural Service Company, LLC
GPL. Great Plains Land Development Co., Ltd.
Great Plains. Great Plains Natural Gas Company.
Heating Degree Day (HDD): A measure of coldness of the weather experienced, based on the extent to which the daily average temperature falls below a reference temperature, usually 65 degrees Fahrenheit.
JDOG. John D. Oil and Gas Marketing Co. LLC
Kykuit. Kykuit Resources, LLC.
Lightning Pipeline. Lightning Pipeline Company, Inc.
MMcf. One million cubic feet, used in reference to natural gas.
MRP. Energy West Propane Inc. dba Missouri River Propane.
MPSC. The Montana Public Service Commission.
MPUC. The Maine Public Utilities Commission.
NCUC. The North Carolina Utilities Commission.
NEO. Northeast Ohio Natural Gas Corp.
NGA. The Natural Gas Act.
OGCL. The Ohio General Corporation Law.
Orwell. Orwell Natural Gas Company.
Osborne Trust. The Richard M. Osborne Trust, dated January 1, 1995.
PaPUC. The Pennsylvania Public Utility Commission.
PUCO. The Public Utilities Commission of Ohio.
Penobscot Natural Gas. Penobscot Natural Gas Company, Inc.
SEC. The United States Securities and Exchange Commission.
Shelby. The Shelby Gas Association, a Montana utility cooperative.
SunLife. SunLife Assurance Company of Canada
Walker Gas. Walker Gas & Oil Company, Inc.
WPSC. The Wyoming Public Service Commission.

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Forward-Looking Statements
     This Form 10-K contains forward-looking statements within the meaning of the federal securities laws. Statements that are not historical facts, including statements about our beliefs and expectations, are forward-looking statements. Forward-looking statements include statements preceded by, followed by or that include the words “may,” “could,” “would,” “should,” “believe,” “expect,” “anticipate,” “plan,” “estimate,” “target,” “project,” “intend,” or similar expressions. These statements include, among others, statements regarding our current expectations, estimates and projections about future events and financial trends affecting the financial condition and operations of our business. Forward-looking statements are only predictions and not guarantees of performance and speak only as of the date they are made. We undertake no obligation to update any forward-looking statement in light of new information or future events.
     Although we believe that the expectations, estimates and projections reflected in the forward-looking statements are based on reasonable assumptions when they are made, we can give no assurance that these expectations, estimates and projections can be achieved. We believe the forward-looking statements in this Form 10-K are reasonable; however, you should not place undue reliance on any forward-looking statement, as they are based on current expectations. Future events and actual results may differ materially from those discussed in the forward-looking statements. Factors that could cause actual results to differ materially from our expectations include, but are not limited to:
  fluctuating energy commodity prices,
 
  the possibility that regulators may not permit us to pass through all of our increased costs to our customers,
 
  the impact of the FERC and state public service commission statutes, regulations, and actions, including allowed rates of return, and the resolution of other regulatory matters,
 
  the impact of weather conditions and alternative energy sources on our sales volumes,
 
  future utilization of pipeline capacity, which can depend on energy prices, competition from alternative fuels, the general level of natural gas and propane demand, decisions by customers not to renew expiring natural gas contracts and weather conditions,
 
  changes in federal or state laws and regulations to which we are subject, including tax, environmental, and employment laws and regulations,
 
  the ability to meet financial covenants imposed by lenders,
 
  the effect of changes in accounting policies, if any,
 
  the ability to manage our growth,
 
  the ability to control costs,
 
  the ability of each business unit to successfully implement key systems, such as service delivery systems,
 
  our ability to develop expanded markets and product offerings and our ability to maintain existing markets,
 
  our ability to maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act of 2002, and
 
  our ability to obtain governmental and regulatory approval of various expansion or other projects, including acquisitions.

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PART I
Item 1. Business.
OUR BUSINESS
Gas Natural is a natural gas company, primarily operating local distribution companies in six states and serving approximately 63,500 customers We operate under three primary business segments.
  Natural Gas Operations. Representing the majority of our revenue, we annually distribute approximately 30 Bcf of natural gas to approximately 63,500 customers through regulated utilities operating in Montana, Wyoming, Ohio, Pennsylvania, Maine and North Carolina. Our natural gas utility subsidiaries include Energy West, Incorporated (Montana and Wyoming), Cut Bank Gas Company (Montana), Northeast Ohio Natural Gas Corporation (Ohio), Brainard Gas Corp. (Ohio), Orwell Natural Gas Company (Ohio and Pennsylvania), Bangor Gas Company (Maine) and Frontier Natural Gas (North Carolina). We acquired our North Carolina and Maine operations in 2007, while Cut Bank Gas in Montana was added in November 2009. Most recently, we closed the acquisition of our Ohio and Pennsylvania operations on January 5, 2010.
 
  Pipeline Operations. We own the Shoshone interstate and the Glacier gathering natural gas pipelines located in Montana and Wyoming through our subsidiary Energy West Development, Inc.
 
  Marketing and Production. Annually, we market approximately 1.3 Bcf 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 holds lease mineral rights to 20,000 acres in Glacier and Toole Counties in Montana and owns an average 48% gross working interest (average 42% net revenue interest) in 160 natural gas producing wells and gas gathering assets located on this property.
2010 Net Income by Operating Segment
$5.8 million
(GRAPHIC)
The Company was originally incorporated in Montana in 1909 and was reorganized as a holding company in 2009 as a means to facilitate future acquisitions and corporate level financings of natural gas utility and energy-related businesses. On July 9, 2010 we moved our state of incorporation to Ohio and changed our name from Energy, Inc. to Gas Natural Inc.
Recent Industry Trends
Since 2000, domestic energy markets have experienced significant price fluctuations. Natural gas experienced peak prices in the mid-2000’s as a result of weather and concerns over supply. New technology in drilling has expanded potential cost effective development making natural gas an abundant, economic, clean energy source for the foreseeable future. Given the current environment, we expect that natural gas will maintain a favorable competitive position compared with other fossil fuels which have 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. We believe that because it is cleaner burning than

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coal, natural gas will continue to be preferred for electric power generation. Additionally, given the clean burning attributes of natural gas, we believe environmental regulations may enhance this competitive outlook.
Business Strategy
Our strategy is to grow our earnings and increase cash flow by providing natural gas to users in a safe and reliable manner by executing in the following areas:
  Invest in existing utilities to expand our distribution system, grow our customer base and maintain reliable, high quality service. To maintain our position as a respected natural gas utility, we have invested, and will continue to invest, substantial capital and resources in our core utility operations in order to meet or exceed applicable regulatory requirements and maintain our infrastructure. We are focused on prudently increasing our customer count and volumes, and increasing our market penetration and market share in areas where we have a competitive advantage on installed services, customer service or pricing to ensure that new customers provide sufficient margins for an appropriate return on the capital investments required to serve those customers. These capital improvements and expansion projects to our existing utilities enable us to continue to build rate base throughout our service footprint.
 
  Continue Active Acquisition Strategy. We are actively pursuing potential bolt-on acquisitions to increase our market penetration by acquiring utility operations in or near our current service territories with minimal corporate platform expansion. We also will opportunistically explore transformational acquisition opportunities that would provide significant operational and customer growth, as well as assist in ensuring access to long-term sources of capital and credit.
 
  Focus on Efficiency to Maximize Returns. We strive to quickly and effectively respond to changing regulatory and public policy initiatives, leverage new technology solutions that significantly improve productivity and customer service and implement organizational changes that improve our performance. By focusing on these critical areas and continuous improvement of operational efficiencies, we expect to be able to effectively control costs and provide reasonable returns to stakeholders by attaining our regulated allowable return on equity as established by our regulators.
Competitive Strengths
We believe we are well-positioned to execute our business strategy given the following competitive strengths:
  Growth-Oriented Utilities. Our core assets consist of distribution facilities necessary for the delivery of our customers’ natural gas supply needs within our service territories and regulatory assets related to our regulated utility operations. Approximately 91% of our 2010 revenue was from regulated gas distribution operations, providing a level of stability to our earnings and cash flows. As we have invested in our rate base, our earnings and cash flows have grown with that investment. We operate under a cost-of-service regulatory regime that allows us to recover our reasonable operating costs from customers and earn a reasonable return on our invested capital. We believe that there are significant opportunities for us to expand operations organically in some of our existing service areas as there are currently relatively low penetration rates of gas distribution among potential customers.
 
  Focused Acquisition Strategy. We continue to emphasize growth and have a successful track record of executing on our acquisition strategy. Since 2007, we have made acquisitions in five states representing more than 25,000 additional gas utility customers. These recent acquisitions and our integration of their operations, management, infrastructure, technology and employees provide us with the necessary platform and experience to replicate these successes through new acquisitions opportunities. We believe our track record to date promotes positive relationships and credibility with regulators, municipalities, developers and customers in both existing and prospective service areas.
 
  Geographically Diverse Customer Base. As a result of our recent acquisitions, we now have operations in six states located in the West, Midwest, Northeast and Mid-Atlantic regions of the country. We believe that this geographically diverse customer base enhances stability of operations and provide us with the opportunity to increase our market penetration in various regions. Additionally, our customers represent a mix of residential, commercial, industrial and transportation and no single customer represented more than 1.3% of our natural gas revenue for 2010. Our sales to large commercial and industrial customers are not concentrated in one industry segment but vary across several industry segments, reflecting the diverse nature of the communities we serve.
 
  Experienced Management Team. Our senior management team is highly experienced in the gas utility industry. Our senior management team averages approximately 22 years experience in the industry. We believe our management team is well-equipped to lead the continued execution of the Company’s business strategy.

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Natural Gas Operations
Our natural gas operations are located in Montana, Wyoming, Ohio, Pennsylvania, Maine and North Carolina, and our revenue from the natural gas operations are generated under tariffs regulated by those states. In many states, including all of our service territories , 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. Each state’s regulatory body, in addition to regulating rates, also regulate adequacy of service, issuance of securities, compliance with U.S. Department of Transportation safety regulations and other matters.
     Montana
Our operations in Montana provide natural gas service to customers in and around Great Falls, Cascade, West Yellowstone, and Cut Bank, Montana. The population of our service area is approximately 66,000 people. Our Montana operations provide service to approximately 30,000 customers.
The primary gas supply marketers for our Montana natural gas distribution operations have been Jefferson Energy Trading, LLC (Jetco) and Tenaska Marketing Ventures.
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. Our gas supply needs are secured under a 1-year contract with NWE that includes annual renewals.
     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 people. Our Wyoming operations provide service to approximately 6,500 customers, including one large industrial customer. Our Wyoming operations transport gas for third parties pursuant to a tariff filed with and approved by the WPSC.
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 revenue of our Wyoming operations and approximately .85% of the consolidated revenue 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.
The primary gas supply marketers for our Wyoming natural gas distribution operations have been Jetco and Tenaska Marketing Ventures. Our marketing and production operations supply natural gas to our Wyoming operations pursuant to an agreement through March 2012.
     Ohio and Pennsylvania
On January 5, 2010, we acquired Orwell, NEO, and Brainard, which are natural gas distribution companies in Northeastern Ohio and Western Pennsylvania for a purchase price of $37.9 million. These natural gas distribution companies serve approximately 24,000 customers. The acquisition increased the Company’s customers by more than 50%. We have opportunities for incremental growth in Ohio in suburban expansion areas and “bedroom” communities for gas service adjacent to our current service areas. These utilities provide both retail natural gas sales service and transportation service through approximately 1,050 miles of distribution pipelines.
Our Ohio and Pennsylvania utilities receive gas supply from various sources, including JDOG (a company owned by our chairman and CFO), BP Canada Energy Marketing Corp, Constellation Energy, Shell Energy North America (US) L.P. and South Jersey Resources Group LLC. We transport natural gas on National Fuel, Dominion and Columbia’s NiSource gas transmission systems, and North Coast Gas Transmission’s intrastate pipeline, as well as two intrastate pipelines owned by our chairman and CEO, Cobra Pipeline and Orwell-Trumbull Pipeline.
In November 2010, we organized GNI Service Company to manage transportation and storage capacity under contracts with interstate pipelines for our Ohio utilities, and to manage the gas procurement function for these utilities. The Ohio companies have assigned local gas supply purchase agreements with JDOG to GNI Service Company, which will act as their purchasing agent for local production. These arrangements are at variable prices. The Ohio companies have also assigned to GNI Service Company agreements under which JDOG acts as agent for these utilities to identify arrange suppliers of natural gas in the interstate market at variable or fixed prices.

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     Maine
On December 1, 2007, we acquired Bangor Gas Company, a natural gas utility in Bangor, Maine. 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 108 miles of distribution system. This service area has a population of approximately 60,000 people. Our Maine operations provide service to approximately 1,700 residential, commercial and industrial customers. We offer transportation services to 49 customers through special pricing contracts. These customers accounted for approximately 29.2% of the revenue of our Maine operations in 2010.
In Maine, our primary gas supply marketer for Bangor Gas Company is Repsol Energy North America Corporation. We receive our gas supply from the Maritimes & Northeast Pipeline transmission system. Our supply contract is on a full requirements basis with Energy North America Corporation with continuous renewals.
     North Carolina
On October 1, 2007, we acquired Frontier Natural Gas, a natural gas utility in Elkin, North Carolina. 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 43,000 people. The major communities in our North Carolina service area are Boone, Elkin, Mount Airy, Wilkesboro, Warrenton and Yadkinville. Our North Carolina operations provide service to approximately 1,300 residential, commercial and transportation customers through 138 miles of transmission pipeline and 227 miles of distribution system. We offer transportation services to 22 customers through special pricing contracts. For 2010, these customers accounted for approximately 39.1% of the revenue of our North Carolina operation.
In North Carolina, our primary gas supply marketer for Frontier Natural Gas is BP Energy. We receive our gas supply from the Transcontinental Gas Pipe Line Company transmission system. Our supply contract is a two-year supply agreement to provide 100% of our gas needs with BP.
Marketing and Production Operations (EWR)
We market approximately 1.3 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 physical natural gas volumes for a portion of its requirements, EWR holds state lease mineral rights to 20,000 acres in Glacier and Toole Counties in Montana with two natural gas production properties and three gathering systems. These leases are perpetual so long as production continues. EWR currently holds an average 48% gross working interest (average 42% net revenue interest) in 160 natural gas producing wells in operation on this property. 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 23.2% of the volume requirements for EWR in our Montana market for the year ended December 31, 2010. These wells are relatively shallow and we have not yet explored the deeper formations on our production properties.
EWR owns a 23.01% interest in Kykuit, a developer and operator of oil, gas and mineral leasehold estates located in Montana. We have invested a total of approximately $1.56 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 our agreement with the other Kykuit investors. 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 $1.4 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 Gregory J. Osborne is president and Thomas J. Smith, our chief financial officer, is a director of John D. Oil and Gas Company. Our net investment in Kykuit after deducting undistributed losses of approximately $918,000 is approximately $640,000.
Pipeline Operations
Through Energy West Development, Inc. 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 an approximately 30 mile long 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 Alberta Energy Company (AECO) and Colorado Interstate Gas (CIG)

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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, AECO and CIG 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.
Corporate and Other
Our Corporate and Other reporting segment 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 Gas Natural’s holding company functions. Our first significant event reported under this segment was a deferred tax asset that was the result of our acquisitions of Bangor Gas Company and Frontier Natural Gas. As we continue to implement our acquisition strategy and grow, we will likely report additional income and expense items associated with potential and completed acquisitions under this reporting segment.
Acquisitions
As a result of our success in strengthening our core natural gas 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 alternate fuels such as heating oil. 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 North Carolina and Maine market remain unsaturated, with penetration rates of less than 3% and as low as 1% in certain areas. 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. 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. This strategy led to our acquisitions of Frontier Utilities and Bangor Gas Company, which are briefly described below.
In addition to acquiring utilities in low saturation markets or close proximity to our current service areas, we continue to evaluate acquiring under-performing utilities in more mature gas markets or smaller utilities that are part of larger utility holding companies. We believe our focus on operational excellence, cost controls, and prudent capital investment facilitates our ability to increase performance and profitability of under-performing assets and non-core assets. Our strategy also includes adding geographic locations that provide balance and organic growth prospects to our overall performance, while mitigating weather, economic, regulatory and/or competitive risks.
     2007 Expansion into Maine and North Carolina
In 2006, we began investigating potential acquisitions in Maine and North Carolina. On January 30, 2007, we entered stock purchase agreements with Sempra Energy 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 share 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 provided us with substantial assets and potential customers in those service areas, including 149 miles of transmission pipeline and 315 miles of distribution system.
     2009 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 83.2% of the shares 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 16.8% of the shares. In April 2010, we completed the acquisition of the remaining shares in Cut Bank Gas for a cash purchase price of $101,000. The acquisition increased our customer base by approximately 1,500.
     2010 Expansion into Ohio and Pennsylvania
On January 5, 2010, we completed the acquisition of our Ohio utilities, Orwell, NEO and Brainard, and their parents and affiliates, Lightning Pipeline, Great Plains and GPL (collectively, the Ohio Companies). Orwell, NEO and Brainard are natural gas distribution companies that serve 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 our Ohio Companies was $37.9 million, which consisted of approximately $20.8 million in debt of the acquired companies with the remainder of the purchase price paid in 1,707,308

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unregistered shares of our common stock. Our acquisition of the Ohio Companies was a substantial step in our growth, providing us with a presence in the Midwestern United States and increasing our customer count by more than 50%.
     Focused Acquisition Strategy
We intend to continue to look for natural gas utilities to acquire. 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 have natural gas utility experience with significantly larger companies. We intend to focus on acquisitions that will enable us to grow our customer base and in a manner and to a scale consistent with the full strategic vision of our senior leadership team. 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 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 related non-utility operations such as gathering, storage and marketing operations. Although non-utility operations are not the focus of our acquisition strategy, we will evaluate potential natural gas related acquisitions to determine whether these operations could be complementary to our core utility business.
Competition
In all states, we generally face competition in the distribution and sales of natural gas from suppliers of other fuels, 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.
In Montana and Ohio, the regulatory framework does not provide gas distribution companies with exclusive geographic service territories. In Maine, although the MPUC may establish exclusive service territories, it certificated both Bangor Gas Company and Central Maine Gas to serve in the same area that had not previously been served by a gas utility. However, in Montana and Maine, we have faced relatively little competition from other gas companies primarily because geographic barriers to entry make it cost-prohibitive for competitors to enter noncontiguous locations. By contrast, in Ohio, we face significant competition from larger natural gas companies where our service territories are contiguous to other gas distribution utilities.
The following table summarizes our major competitors by state.
     
State   Competition
Montana
  Northwestern Energy, Montana-Dakota Utilities Co.
 
   
Wyoming
  Various propane distributors, electric providers
 
   
Ohio
  Dominion East Ohio, Columbia Gas of Ohio, National Gas & Oil, various propane and fuel oil distributors, electric providers
 
   
Pennsylvania
  Various propane and fuel oil distributors, electric providers
 
   
Maine
  Northern Utilities Inc., Maine Natural Gas, various fuel oil distributors, electric providers
 
   
North Carolina
  Various propane distributors, electric providers
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
Our utilities purchase gas from various gas supply marketers. For more information, please see “Business — Natural Gas Operations” and “Marketing and Production Operation”. Jefferson Energy Trading, LLC 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.

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EWR also supplies itself with natural gas through the ownership of natural gas producing wells in operation in north central Montana. For more information, please see “Business — Marketing and Production Operations (EWR).”
We purchase and store gas for distribution later in the year. We also enter into 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 utility operations are subject to regulation by the MPSC, the WPSC, the PUCO, the PaPUC, the MPUC and the NCUC. 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 rates of return we are allowed to realize. For additional discussion of our Natural Gas Operations segment’s rates and regulation, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Rate and Regulatory Matters” and “Summary of Significant Accounting Policies (Regulatory Mechanisms)”, and the paragraph entitled “Effects of Regulation” in Note 1 of the Notes to the Consolidated Financial Statements of the Company.
     Rate Regulation, Cost Recovery and Rate Cases
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 until October and December 2012, respectively, although the Maine rate plan does allow us to periodically increase and adjust our rates within certain parameters within our rate plan.
     Montana
Our Montana gas utility operations are subject to regulation by the MPSC and generate revenue 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. Our largest utility, Energy West, has a traditional rate base structure in Montana, as established in a rate proceeding at the MPSC, and its rates are based upon the opportunity to earn an allowed return on equity and an overall rate of return. Cut Bank, which is a subsidiary of Energy West, has separate rates that were also established in a rate case where cost of service analysis was employed and an authorized overall rate of return identified. The MPSC allows customers to choose a natural gas supplier other than our Montana operations, and we provide gas transportation services to customers who purchase from other suppliers.
Our 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. We have right of way privileges for our Montana distribution systems either through franchise agreements or right of way agreements within our service territories.
On September 2, 2010 Energy West filed a general rate case with the MPSC that, if approved, could allow Energy West to earn approximately an additional $360,000 annually. However, we cannot guarantee that we will be able to obtain this additional revenue or maintain our current rates.
     Wyoming
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.
We 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. 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.

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     Ohio and Pennsylvania
Our Ohio and Pennsylvania operations are regulated by the PUCO and the PaPUC. Our Ohio utilities operate under a traditional rate base regulatory mechanism. However, only NEO has tariff rates established after a general rate case. A cost of service analysis was done in that case resulting in a stipulation of all parties. The stipulation identified an authorized rate of return on rate base but did not articulate a capital structure or an allowable return on equity.
Orwell’s currently approved tariff rates were established in June 2007 in an “application not for an increase in rates,” sometimes referred to as a “first filing.” Prior to this filing, Orwell had no PUCO approved tariff rates in place for these services. Prior to the approval of these tariff rates by the PUCO, Orwell’s rates had been established either by municipal ordinance in villages exercising their “home rule” powers, or by “special arrangements” authorized by Ohio law and approved by PUCO on a case-by-case basis. No cost of service analysis is required in a “first filing” and the PUCO approved the current rates by finding them not to be unjust or unreasonable.
When Orwell acquired its Clarion River and Walker Gas divisions in Pennsylvania in 2005, it adopted the tariffs of those utilities without cost of service analysis being performed. Brainard adopted the tariff of its predecessor company when the PUCO approved its acquisition of Power Energy in August 1999. The rates included in that tariff were originally approved by the PUCO as not being unjust and unreasonable in a “first filing” by Power Energy in 1998. No cost of service analysis was performed.
The PUCO conducts gas recovery financial audits of gas utilities annually, and full reviews of gas purchasing practices and procedures every two years. Full audits are currently underway for both NEO and Orwell. The PUCO staff has taken the position that Orwell has over recovered approximately $1.2 million in gas costs and recommended that these costs be offset against future gas charges. Although we agree that Orwell has over recovered some costs, we believe the amount is less than $1.1 million. With respect to NEO, the commission staff has taken the position that NEO has under recovered approximately $1.1 million in gas costs and recommended that NEO be permitted to add these costs to future gas charges. We believe that Orwell is entitled to a greater recovery. The audits of Orwell and NEO are set for evidentiary hearing on April 25 and we intend to contest the staff’s recommendations. We cannot predict whether the PUCO will allow us to recover all of the costs we seek to recover.
     Maine
Our Maine operations generates revenue under tariffs regulated by the Maine Public Utility Commission (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 market-based 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.
     North Carolina
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.

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When the NCUC approved our acquisition of Frontier Natural Gas, it instituted a set of regulatory conditions including a rate moratorium for a period of five years and a reduction of its margin rates for residential and small general firm service by 10%. These rates are to be maintained through September 2012. The margin rate consists of the tariff rate less benchmark gas costs.
     Holding Company Reorganization and Ring-Fencing Measures
In August 2009, we implemented a holding company structure to reduce the limitations imposed on us by state regulatory commissions, but those agencies may still place limitations on us with respect to certain corporate and financial activities. For example, as a condition to approving our holding company reorganization, the MPSC imposed ring-fencing measures under which our Montana, Wyoming, North Carolina and Maine operating subsidiaries must meet certain notice and financial requirements prior to paying dividends that are above certain financial thresholds or irregularly timed. Another condition of the MPSC’s approval was that our Maine and North Carolina utilities, which are currently subsidiaries of our Montana operating subsidiary Energy West, become subsidiaries of Gas Natural in the event Energy West refinances its debt. However, the MPUC subsequently conditioned its approval of the reorganization on the opportunity to approve, in advance, any such spin-out of the Maine utilities. We believe we would be able to obtain the MPUC’s approval of a spin-out when necessary, but we cannot predict what conditions, qualifications or limitations the MPUC would seek to impose as a condition to such an approval. We obtained the approval of the WPSC for our holding company reorganization in October 2008, but in connection with its approval of our acquisition of the Ohio Companies, the WPSC issued an order asserting jurisdiction over Gas Natural as a public utility in Wyoming and requested that ring-fencing measures be created and implemented. We requested rehearing of that order to clarify the scope of the jurisdiction WPSC seeks to assert. Our request was granted and in an open meeting the WPSC approved ring-fencing measures as well as this offering, but as of this date no final appealable order has been issued with respect to jurisdiction. Because the jurisdictional issue remains unresolved, we cannot predict whether or when the WPSC will assert jurisdiction over us in the future, including activities that take place at the holding company level. If the WPSC were to assert jurisdiction over us with respect to a potential acquisition, refinancing of debt or other significant transaction and deny a request by us for exemption with respect to the transaction, it could delay, hinder or prevent us from completing the transaction.
     Certificated Territories and Franchise Agreements
In some states, local distribution companies are required to obtain certificates of public convenience or necessity from the state regulatory commissions before they may distribute gas in a particular geographic area. In addition, local distribution companies are often subject to franchise agreements entered into with local governments. While the number of local governments that require franchise agreements is diminishing historically, many of the local governments in our service areas still require them and 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 if a franchise agreement is not in effect. Accordingly, when and where franchise agreements are required, we enter into agreements for franchises with the cities and communities in which we operate authorizing us to place our facilities in the streets and public grounds, and we attempt to acquire or reacquire franchises whenever feasible.
We have obtained all certificates of convenience and necessity and/or franchise agreements from state regulatory commissions and from local governments in those states where required in order to provide natural gas utility service. In most cases, certificates of public convenience and necessity and franchise agreements do not provide us with exclusive distribution rights. The specific requirements of the states and services areas in which we operate are discussed below.
Certificates of public convenience and necessity are required in Wyoming, Maine, North Carolina and Pennsylvania. In Wyoming, we 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. Certificates of public convenience and necessity are not required in Ohio or Montana. 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. A currently certificated gas utility is not required to seek MPUC authority to serve in a municipality not served by another gas utility, but otherwise must seek MPUC approval to serve. 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. In Pennsylvania, our service territories are exclusive under certificates of public convenience and authority granted by PAPUC.
Franchise agreements are utilized in Montana, Wyoming and North Carolina. In Montana, we hold a franchise in the cities of Great Falls and West Yellowstone. In Wyoming, we hold franchises in the cities of Cody and Meeteetse. In North Carolina, we have franchise agreements with all of the incorporated municipalities in the six counties certificated by NCUC to install and operate gas lines in those municipalities’ streets and right-of-ways. We are not required to obtain franchise agreements for our operations in Maine, Ohio or Pennsylvania, although in Ohio non-exclusive franchise ordinances or agreements are permitted.
     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

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are also subject to, or affected by, federal regulation under the NGA, the Natural Gas Policy Act of 1978 and the Natural Gas Wellhead Decontrol Act of 1989. 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 transmission 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. Also, to the extent that our utilities have contracts for transportation and storage services under FERC-approved tariffs with interstate pipelines, our utilities are subject to FERC rules and regulations pertaining to those services. If we fail to follow applicable FERC rules and regulations, we may be subject to judgments, fines or penalties.
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.
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 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.
     Remediation of Montana Manufactured Gas Plant
Energy West owns property in Montana on which we operated a manufactured gas plant from 1909 to 1928. We currently use this site as an office 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.
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. 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 nearly all of these costs pursuant to the order. The MPSC issued its order granting recovery through February 28, 2010. The recovery is now complete. No additional recovery has been requested and the recovery surcharge has been 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

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under EPA standards, further remediation may be technically impracticable. 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.
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. Most of our gas sales revenue is generated in the first and fourth quarters of the 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 the year (April 1 to September 30). We anticipate that this sensitivity to seasonal and other weather conditions will continue to be reflected in our sales volumes in future periods.
Employees
We had a total of 191 employees as of December 31, 2010. Two of these employees are employed by our marketing and production operations, 175 by our natural gas operations and 14 at the corporate office. Our natural gas operations include 16 employees represented by two labor unions, the Laborers Union and Local Union No. 41. Negotiations were completed in June 2010 with the Laborers Union, with a contract in place until June 30, 2013. A three-year contract with Local Union No. 41 expires June 30, 2013. We believe our relationship with our employees and unions is good. We have 179 full time employees.
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, PUCO, PAPUC, MPUC, NCUC and FERC regulate many aspects of our distribution and transmission operations. State regulatory agencies set the rates that we may charge customers, which effectively limits the rate of return we are permitted to realize. Our ability to obtain rate increases and rate supplements to maintain the current rate of return and/or recover costs 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, which could negatively impact our financial condition and results of operations. The state utility regulatory agencies also regulate our public utilities’ gas purchases, construction and maintenance of facilities, the terms of service to our customers, safety and various other aspects of our distribution operations. FERC regulates interstate transportation and storage of natural gas. FERC exercises jurisdiction over the Shoshone transmission pipeline with respect to terms of service, maintenance of facilities, safety and various other aspects of our transmission operations. Also, to the extent that our utilities have contracts for transportation and storage services under FERC-approved tariffs with interstate pipelines, our utilities are subject to FERC rules and regulations pertaining to those services. If we fail to comply with applicable state and federal regulations, we may be subject to fines or penalties.
Our gas purchase practices are subject to annual reviews 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 create the potential for the disallowance of our recovery through gas cost recovery pricing mechanisms. Significant disallowances could affect our earnings and cash flow.
The PUCO conducts gas recovery financial audits of gas utilities annually, and full reviews of gas purchasing practices and procedures every two years. Full audits are currently underway for both NEO and Orwell. The PUCO staff has taken the position that Orwell has over recovered approximately $1.1 million in gas costs and recommended that these costs be offset against future gas charges. Although we agree that Orwell has over recovered some costs, we believe the amount is less than $1.1 million. With respect to NEO, the commission staff has taken the position that NEO has under recovered approximately $1.1 million in gas costs and

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recommended that NEO be permitted to add these costs to future gas charges. We believe that NEO is entitled to a greater recovery. The audits of Orwell and NEO are set for evidentiary hearing on April 25 and we intend to contest the staff’s recommendations. We cannot predict whether the PUCO will allow us to recover all of the costs we seek to recover.
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 revenue. Given the impact of weather on our utility operations, our business is a seasonal business.
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 more 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 immediately, or at all, we may incur increased costs associated with 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.
Volatility in the price of natural gas could result in customers switching to alternative energy sources which could reduce our revenue, earnings and cash flow.
The market price of alternative energy sources such as coal, electricity, propane, 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.

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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 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.
Changes in current regulations, 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, and the 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 SEC could enact new accounting standards that could impact the way we are required to record revenue, expenses, assets and liabilities, and state utility regulatory agencies could enact more stringent rules or standards with respect to rates, cost recovery, safety, construction, maintenance or other aspects of our operations. For instance, on April 16, 2010 the MPUC proposed amendments to Chapter 420 of its regulations (Safety Standards for Natural Gas Transmission and Distribution Systems and Liquefied Natural Gas Facilities). On June 17, 2010, the MPUC issued an order suspending the comment period and indicating that the MPUC’s staff was considering significant revisions, but the proposed rules, if adopted as initially proposed, would have imposed significant new and enhanced requirements on Bangor Gas Company with respect to design, fabrication, installation, inspection, reporting, testing and safety aspects of operating and maintaining its pipeline system. On February 15, 2011 the MPUC approved the revisions to the Chapter 420 ruling which proved to be less intrusive and a more favorable outcome resulted for the utility companies operating within the state. We cannot predict or control what effect proposed regulations, events in the energy markets or other 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% gross working interest (average 42% 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 23% of the volume requirements for EWR’s Montana market for 2010. We acquired our interests in the wells in 2002 and 2003 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 our Form 10-K for the fiscal year ended June 30, 2008, we began complying with Section 404 and that Form 10-K included a report by our management on our internal control over financial reporting.
Compliance with Section 404 is both costly and challenging. Going forward, there is a risk that we will not 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

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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.
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 $13.4 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 write-down (or even a loss) of the net deferred tax asset and adversely affect our operating results and financial position.
We cannot guarantee that we will be able to generate sufficient future taxable income to realize the $13.4 million net deferred tax asset over the next 19 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.
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, revenue, 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.
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 the Ohio Companies, as well as, those that we may acquire in the future. We cannot provide assurance that we will be able to:
    identify suitable acquisition candidates or opportunities,
 
    detect, through due diligence, investigation, all actual and potential problems that may exist in the operations or financial condition of an acquisition candidate,
 
    acquire assets or business operations on commercially acceptable terms,
 
    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,
 
    achieve our operating and growth strategies with respect to the acquired assets or businesses,
 
    reduce our overall selling, general, and administrative expenses associated with the acquired assets or businesses, or
 
    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 face a number of related 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 the Ohio Companies, 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 our Ohio operations and are in the process of exploring 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 completed, 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 some acquisitions, goodwill is a significant portion of the purchase price, increasing the losses we would incur if such write-downs or write-offs occurred. 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, state ring fencing provisions, 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.
Like other small-cap companies, the price of our common stock can be volatile due to its relatively low trading volume, and sales of shares by our directors and officers could cause decreases in price. Our directors and officers own a significant interest in the Company and could limit new shareholders’ influence on corporate decisions.
As a smaller public company, our common stock typically has a lower trading volume than Fortune 500 companies and other larger public companies. As of March 30, 2011, our average daily volume for 2011 was 20,978 shares per day. This low trading volume may have a significant effect on the market price of our common stock. Our directors and officers control 26.4% of our outstanding shares, which contributes to our low public float, and sales by those individuals could be perceived unfavorably in the market and adversely affect the price of the Company’s common stock. Also, Mr. Osborne has pledged his stock to secure various debts. If there was a default on one or more of these obligations, the pledgees may seek to sell Mr. Osborne’s shares, which could adversely affect our stock prices.
Accordingly, our directors and officers possess a significant influence on all matters submitted to a vote of our shareholders including the election of the members of our board. The interests of these shareholders may not always coincide with our corporate interests or the interests of other shareholders, and they may act in a manner with which you may not agree or that may not be in the best interests of our other shareholders. Also, this concentration of ownership may have the effect of preventing or discouraging

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transactions involving an actual or a potential change of control of the Company, regardless of whether a premium is offered over then current market prices.
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.
Our charter documents and Ohio law, as well as certain utility laws and regulations, may discourage a third party from attempting to acquire us by means of a tender offer, proxy contest or otherwise, which could adversely affect the market price of our common shares.
Provisions of our articles of incorporation and regulations and state utility laws and regulations, including regulatory approval requirements, could make it more difficult for a third party to acquire us, even if doing so would be perceived to be beneficial to our shareholders. For example, our charter documents do not permit cumulative voting, allow the removal of directors only for cause, and establish certain advance notice procedures for nomination of candidates for election as directors and for shareholder proposals to be considered at shareholders’ meetings. Additionally, Ohio corporate law provides that certain notice and informational filings and special shareholder meeting and voting procedures must be followed prior to consummation of a proposed “control share acquisition” as defined in the Ohio Revised Code. Assuming compliance with the prescribed notice and information filings, a proposed control share acquisition may be made only if, at a special meeting of shareholders, the acquisition is approved by both a majority of our voting power represented at the meeting and a majority of the voting power remaining after excluding the combined voting of the “interested shares,” as defined in the Ohio Revised Code. Some takeover attempts may even be subject to approval by the Ohio Division of Securities or PUCO. The application of these provisions may inhibit a non-negotiated merger or other business combination, which, in turn, could adversely affect the market price of our common stock.
The value of our common stock may decline significantly if we do not maintain our listing on the NYSE Amex Equities stock exchange.
In addition to federal and state regulation of our utility operations and regulation by the SEC, we are subject to the listing requirements of NYSE Amex. NYSE Amex rules contain requirements with respect to corporate governance, communications with shareholders, the trading price of shares of our common stock and various other matters. We believe we are in compliance with NYSE Amex listing requirements, but there can be no assurance that we will continue to meet those listing requirements in the future. If we fail to comply with listing requirements, NYSE Amex could de-list our stock. If our stock was de-listed from NYSE Amex, our shares would likely trade in the Over-The-Counter Bulletin Board, but the ability of our shareholders to sell our stock could be more difficult because smaller quantities of shares would likely be bought and sold, transactions could be delayed, and security analysts’ coverage of us may be reduced. Further, because of the additional regulatory burdens imposed upon broker-dealers with respect to de-listed companies, delisting could discourage broker-dealers from effecting transactions in our stock, further limiting the liquidity of our shares. These factors could have a material adverse effect on the trading price, liquidity, value and marketability of our 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:
    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,
 
    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,
 
    limiting our ability to repurchase or redeem our stock or enter into transactions with our shareholders or affiliates, and
 
    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 there are limits on 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 depends on the ability of our subsidiaries to generate sufficient net income and cash flows to pay upstream dividends to us. Our Ohio subsidiaries have been unable to pay a dividend to us since May 2010. 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 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 under which our Montana, Wyoming, North Carolina and Maine operating subsidiaries must meet certain notice and financial requirements prior to paying dividends that are above certain financial thresholds or irregularly timed. Similar ring-fencing provisions were recently approved by the WPSC as well.
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 17 of this annual report.
The Wyoming Public Service Commission may assert jurisdiction over Gas Natural’s activities unexpectedly, which could hinder, delay or prevent us from pursuing acquisitions and other transactions that are important to our short term and long term financial condition and growth.
We obtained the approval of the WPSC for our holding company reorganization in October 2008, but in connection with its approval of our acquisition of the Ohio Companies, the WPSC issued an order asserting jurisdiction over Gas Natural as a public utility in Wyoming and requested that ring-fencing measures be created and implemented. We requested rehearing of that order to clarify the scope of the jurisdiction WPSC seeks to assert. Our request was granted and in an open meeting the WPSC approved ring-fencing measures as well as this offering, but as of this date no final appealable order has been issued with respect to jurisdiction. Because the jurisdictional issue remains unresolved, we cannot predict whether or when the WPSC will assert jurisdiction over us in the future, including activities that take place at the holding company level. If the WPSC were to assert jurisdiction over us with respect to a potential acquisition, refinancing of debt or other significant transaction and deny a request by us for exemption with respect to the transaction, it could delay, hinder or prevent us from completing the transaction, negatively impacting our financial condition, results of operations and growth.
In acquiring our Ohio operations, we guaranteed $20.5 million of their debt, $7.7 million of which matured and was repaid in November 2010. The remaining debt could limit our flexibility with other financial covenants and could materially adversely affect our business, earnings, cash flow, liquidity and financial condition.

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When we acquired our Ohio operations, we guaranteed approximately $20.5 million of the acquired companies’ debt, $7.7 million of which matured and was repaid in November 2010. Richard M. Osborne, our chairman of the board and chief executive officer, guaranteed substantially all of the third party debt of our Ohio Companies. Our debt service requirements have increased dramatically as a result of the acquisition. This additional debt has made us more levered on a consolidated basis.
Our debt 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, payment of dividends, 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, we are seeking to extend or refinance our short term debt, but there can be no assurance we will be able to do so. Our failure to comply with any financial covenants, pay our debt service requirements and extend or refinance our debt may result in an event of default which, if not cured or waived, could result in the acceleration of the debt under our debt 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 extend or refinance 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 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 performance of our management team or the loss of services of key executive officers or personnel could impair our ability to successfully operate the Company and to acquire and integrate new business operations, either of which could have a material adverse effect on our business, results of operations and financial condition.
We have entered into 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.
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 various transactions in which some of our directors have a financial interest, and stockholders and potential investors in Gas Natural may not value these transactions in the same manner as our board.
We have entered into agreements and transactions in which our directors have a financial interest. For example, Richard M. Osborne, our chairman of the board and chief executive officer, owned nearly all of the stock of the Ohio companies we acquired in January 2010. The Ohio Companies are party to various leases, gas sales, transportation and metering agreements and other arrangements with entities owned and controlled by Mr. Osborne. The Ohio Companies are dependent upon Mr. Osborne’s pipeline company, Cobra Pipeline Co., Ltd., to transport gas to some of their customers. In the future we may enter into other additional related party transactions on a case by case basis. For more information on our related party transactions, see “Certain Relationships and Related Party Transactions” in our Definitive Proxy Statement filed with the SEC May 27, 2010.
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 567 miles of underground distribution lines, or “mains,” and related metering and regulating equipment in Montana. In West Yellowstone, Montana, we own an office building and a liquefied natural gas plant. In the town of Cascade we own two large propane storage tanks. In Cut Bank, Montana we own an office building/operating center.
In Cody, Wyoming, we lease office and service buildings under long-term lease agreements. We own approximately 598 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.

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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 365 miles of transmission and distribution lines and related metering and regulating equipment in North Carolina.
Maine
In Bangor, Maine, we lease two office buildings under long-term lease agreements. We have approximately 118 miles of transmission and distribution lines and related metering and regulating equipment in Maine.
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. 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 approximately 1,060 miles of transmission and distribution lines and related metering and regulating equipment in Ohio and Western Pennsylvania.
Item 3. Legal Proceedings.
We are involved in lawsuits that have arisen in the ordinary course of business. We are contesting each of these lawsuits vigorously and believe we have defenses to the allegations that have been made.
Item 4. [RESERVED]

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PART II
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 under the symbol “EGAS.” Prior to December 17, 2009, our stock traded on the NASDAQ Global Market.
     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.
                 
Year Ended 12/31/10   High     Low  
First Quarter
  $ 9.86     $ 9.30  
Second Quarter
  $ 11.85     $ 9.76  
Third Quarter
  $ 11.95     $ 9.86  
Fourth Quarter
  $ 11.21     $ 9.63  
                 
Year Ended 12/31/09   High     Low  
First Quarter
  $ 8.39     $ 6.61  
Second Quarter
  $ 8.65     $ 7.24  
Third Quarter
  $ 8.55     $ 7.74  
Fourth Quarter
  $ 10.61     $ 8.12  
Holders of Record
As of March 23, 2011, there were approximately 312 record owners of our common stock. We estimate that approximately 5,663 additional shareholders own stock in accounts at brokerage firms and other financial institutions.
Dividend Policy
Monthly dividend payments per common share were:
         
January 30, 2009
  $ 0.040  
February 27, 2009
  $ 0.040  
March 31, 2009
  $ 0.040  
April 30, 2009
  $ 0.045  
May 29, 2009
  $ 0.045  
July 2, 2009
  $ 0.045  
July 31, 2009
  $ 0.045  
September 4, 2009
  $ 0.045  
September 30, 2009
  $ 0.045  
October 30, 2009
  $ 0.045  
November 30, 2009
  $ 0.045  
December 31, 2009
  $ 0.045  
January 13, 2010
  $ 0.045  
February 10, 2010
  $ 0.045  
March 11, 2010
  $ 0.045  
April 13, 2010
  $ 0.045  
May 12, 2010
  $ 0.045  
June 11, 2010
  $ 0.045  
July 13, 2010
  $ 0.045  
August 11, 2010
  $ 0.045  
September 13, 2010
  $ 0.045  
October 13, 2010
  $ 0.045  
November 10, 2010
  $ 0.045  
December 13, 2010
  $ 0.045  

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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 gains, such as the $6.8 million of extraordinary gain associated with the purchase of Frontier Natural Gas and Bangor Gas Company, are 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). The WPSC has imposed similar restrictions.
In December 2010 Orwell repaid upon maturity its $1.5 million Huntington Bank Line of Credit, and its $4.1 million Huntington Bank Term Loan and NEO repaid upon maturity its $2.1 million Citizens Bank Line of Credit. The NEO, Great Plains, and GPL notes currently outstanding with 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 Gas Natural 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. At current, Orwell Natural Gas and Lightning Pipeline have no dividend restrictions following the extinguishment of their debt obligations.
For additional information on loan covenants and restrictions contained in our debt documents, please see “Management Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources” and Note 9 to our Consolidated Financial Statements.
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, 2005 to December 31, 2010.

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(CHART)

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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.
                                                 
    Years ended December 31,     Fiscal years ended June 30,  
    2010     2009     2008     2008     2007     2006  
($ in thousands, except per share)             (unaudited)                          
Summary of Operations
                                               
Operating revenues
  $ 91,500     $ 71,454     $ 87,278     $ 76,833     $ 59,373     $ 74,696  
Operating expenses:
                                               
Gas and electric purchases
    54,706       46,699       63,506       56,170       43,806       60,398  
General and administrative
    17,382       10,562       11,777       10,662       6,198       6,389  
Maintenance
    1,052       667       645       650       567       505  
Depreciation and amortization
    4,119       2,213       1,999       1,865       1,692       1,672  
Taxes other than income (1)
    3,162       2,250       2,501       2,080       1,697       1,453  
 
                                   
 
                                               
Total operating expenses
    80,421       62,391       80,428       71,427       53,960       70,417  
 
                                   
 
                                               
Operating income
    11,079       9,063       6,850       5,406       5,413       4,279  
 
                                               
Other income (expense)
    385       (976 )     (295 )     316       241       391  
 
                                               
Total interest expense (2)
    2,178       1,241       1,224       1,077       2,124       1,649  
 
                                   
 
                                               
Income before taxes
    9,286       6,846       5,331       4,645       3,530       3,021  
Income tax expense (benefit)
    3,489       27       1,985       1,333       1,273       1,109  
Discontinued operations (net of tax)
                            3,955       405  
 
                                   
 
                                               
Net Income (Loss) before extraordinary item
    5,797       6,819       3,346       3,312       6,212       2,317  
Extraordinary gain
                        6,819              
 
                                   
Net Income
  $ 5,797     $ 6,819     $ 3,346     $ 10,131     $ 6,212     $ 2,317  
 
                                   
 
                                               
Basic earnings per common share
  $ 0.92     $ 1.58     $ 0.77     $ 2.35     $ 1.40     $ 0.53  
Diluted earnings per common share
  $ 0.92     $ 1.58     $ 0.77     $ 2.35     $ 1.39     $ 0.52  
Dividends per common share
  $ 0.56     $ 0.55     $ 0.46     $ 0.47     $ 0.34     $ 0.11  
Weighted average common shares Outstanding — diluted
    6,300,972       4,313,098       4,338,240       4,316,244       4,484,073       4,422,069  
At Year End:
                                               
Current assets
  $ 41,738     $ 25,641     $ 31,484     $ 16,340     $ 18,830     $ 23,669  
Total assets
  $ 137,728     $ 78,626     $ 75,819     $ 58,377     $ 51,582     $ 56,629  
 
                                               
Current liabilities
  $ 38,916     $ 27,428     $ 30,114     $ 11,962     $ 8,756     $ 10,796  
 
                                               
Total long-term debt
  $ 21,959     $ 13,000     $ 13,000     $ 13,000     $ 13,000     $ 17,605  
Total stockholders’ equity
  $ 73,702     $ 35,688     $ 30,082     $ 30,649     $ 22,296     $ 19,165  
 
                                   
 
                                               
Total capitalization
  $ 95,661     $ 48,688     $ 43,082     $ 43,649     $ 35,296     $ 36,770  
 
                                   

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(1)   Taxes other than income include $259,000 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. 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
Gas Natural is a natural gas company, primarily operating local distribution companies in six states and serving approximately 63,500 customers. Our natural gas utility subsidiaries are Energy West, Incorporated (Montana and Wyoming), Cut Bank Gas Company (Montana), Northeast Ohio Natural Gas Corporation (Ohio), Brainard Gas Corp. (Ohio), Orwell Natural Gas Company (Ohio and Pennsylvania), Bangor Gas Company (Maine) and Frontier Natural Gas (North Carolina). Our operations also include production and marketing of natural gas and gas pipeline transmission and gathering. Approximately 91% of our revenues in 2010 were derived from our utility operations.
For the year ended December 31, 2010 compared to the year ended December 31, 2009, the Company experienced significant growth in gross margin, income from operations and income before income taxes. Net income was $5.8 million in 2010 as compared to $6.8 million in 2009. The year ended December 31, 2009 included an income tax benefit of $2.5 million, primarily as a result of the reduction of the valuation allowance on our deferred tax asset related to the acquisition of Frontier Utilities and Penobscot Natural Gas. This is offset by an increase in net income from operations of $1.5 million in 2010.
We are focused on building rate base profitably in all of our jurisdictions, maintaining cost discipline, adherence to safety standards, and generating recurring streams of earnings and cash flow that support our continued investment in fixed assets, as well as a return of capital to our shareholders in the form of dividends. In addition, we are actively pursuing our acquisition strategy to further grow our operations.
We intend to continue to reinforce success of Bangor Gas Company and Frontier Natural Gas given the current commodity environment. We compete against fuel oil in Maine and propane distributors in North Carolina. With fuel oil and propane commodity prices tied to the price of oil, we are able to offer a significant value savings to customers within those states. We are specifically pursuing commercial and industrial customers as we build out our Maine and North Carolina platforms. We continue to add residential customers to balance our portfolio.
In October 2010, we entered into note purchase agreements with SunLife Assurance Company of Canada for a private placement of senior secured notes to refinance the Ohio utilities’ existing bank lines of credit and term loans. On March 30, 2011, we obtained PUCO approval for the refinancing and expect to close the transaction in the second quarter. If the refinancing is completed as proposed, Orwell, NEO, and Brainard will jointly issue a $15.3 million senior secured note. This note will mature in June 2017 and will be fixed rate with interest-only payments and no amortization of principal until final maturity. Additionally, Great Plains would issue a $3.0 million three-year senior secured floating rate note.
In November 2010, we completed a public secondary offering of our common stock, selling 2.415 million shares (including 340,000 selling shareholder shares). The offering proceeds will support our expansion projects in 2011 as we seek to obtain additional customers and build rate base across our platform, particularly in Maine and North Carolina.

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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, 2010, our total regulatory assets were $4.0 million and our total regulatory liabilities were $1.4 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, Ohio, Pennsylvania, 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 four of the six states in which we operate, and annually in the other two. 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. Based on our experience, we believe it is highly probable that we will recover the regulatory assets that have been recorded.
During the year ended December 31, 2010, the PUCO conducted audits of NEO and Orwell of the rates as filed from January 2008 through August 2009 and January 2008 through June 2010, respectively. As of December 31, 2010, the PUCO had not completed the audits of NEO and Orwell. The PUCO did provide the preliminary audit findings noting NEO had not included approximately $1,050,000 of costs and Orwell included an excess of approximately $1,100,000 of costs in the filings under audit.
In accordance with ASC 980, Regulated Operations, the Company recorded an adjustment of $1,050,000 and ($1,100,000) in the Company’s consolidated statements of income for NEO and Orwell, respectively. These adjustments appear on the Company’s Consolidated Balance Sheet as part of “Recoverable cost of gas purchases” and “Over-recovered gas purchases”, respectively. When

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the PUCO concludes each audit, if the amounts are different than initially recorded, the Company will record an additional adjustment.
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 Revenue 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 revenue 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, 2010 and December 31, 2009. A variance of 10% on our gross margin at December 31, 2010 would have been plus or minus $157,000.
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, 2010 and December 31, 2009 and were determined based upon variable interest rates currently available to us for borrowings with similar terms.
Recoverable/Refundable Costs of Gas
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, regulations, and income tax examinations require that judgments and estimates be made in the accrual process.
The Company has a deferred tax asset of approximately $13.4 million as of December 31, 2010 related to the carryover tax basis of Frontier Utilities of North Carolina, Inc. and Penobscot Natural Gas Company. The $13.4 million deferred tax asset relates to acquisitions of these two subsidiaries during 2007. The carryover tax basis is subject to Section 382 of the Internal Revenue Code. Due to limitations imposed under Section 382, the Company’s tax depreciation is limited in tax years 2007 through 2011. The Company has approximately $36.0 million of carryover tax basis as of December 31, 2010. Starting in 2012, the Company will recognize potential future federal and state income tax benefits of approximately $13.4 million over the remaining life of the carryover tax basis of the assets. For the federal income tax purposes, the Company has concluded that the realization of the deferred tax asset associated with the carryover tax basis will be realized in future reporting periods based on future taxable income projections. For state income tax purposes, the Company has concluded that the realization of the deferred tax asset associated with

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the carryover tax basis will not be realized, due to state net operating loss carryovers and future state taxable income projections. As such, management has placed a valuation allowance of approximately $2.0 million on the state deferred tax assets associated with the carryover tax basis of its subsidiaries acquired during 2007.
Management will reevaluate the valuation allowance each year based on future taxable income projections, and will adjust the deferred tax asset valuation allowance if, based on the weight of available evidence, it is more-likely-than-not that the Company will realize some portion or all of the deferred tax assets. If the projections indicate that we are unable to use all or a portion of the net deferred tax assets, the Company will adjust the valuation allowance to income tax expense (benefit). The valuation allowance is based on projections of our taxable income in future reporting years. Based on future taxable income projections, the Company’s state net operating losses will not be realized and as such, management has placed a valuation allowance of approximately $2.5 million on the state deferred tax asset associated with state net operating losses.
For the federal tax portion, there are two years remaining of the five year Internal Revenue Code limitation period discussed above. We estimate that approximately 5% of the tax benefit will be available to us during this two 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 3% 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 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.
Earnings
Year Ended December 31, 2010 Compared with Year Ended December 31, 2009
     Net Income — Our net income for the year ended December 31, 2010 was $5.8 million or $0.92 per diluted share, compared to net income of approximately $6.8 million or $1.58 per diluted share for the year ended December 31, 2009, a decrease of $1.0 million. This decrease is primarily the result of a large income tax benefit of $2.5 million in the year ended December 31, 2009, offset by an increase in net income from operations of $1.5 million in 2010. Net income from our natural gas operations increased by $1.8 million due primarily to net income from sales growth in our Maine and North Carolina markets of approximately $1.2 million, net income contribution from the Ohio Companies of $893,000 offset by a decrease in earnings in our remaining natural gas operations, Montana and Wyoming. Our gas marketing and production operation incurred a decrease in net income of $442,000. The principal reasons for the change in net income are explained below.
     Revenues — Our revenues for the year ended December 31, 2010 were approximately $91.5 million compared to $71.5 million for the year ended December 31, 2009. This $20.0 million increase was primarily attributable to: (1) a natural gas revenue increase of $24.8 million due to $26.1 million in revenue from the Ohio Companies, sales growth in our North Carolina and Maine markets of approximately $3.7 million and offset by a decrease of $5.0 million due to lower costs of natural gas passed through to our customers in 2010 and (2) a decrease in our marketing and production operation’s revenue of $4.8 million. The year ended December 31, 2009 included sales volumes caused by a favorable differential between the AECO and CIG Rockies indexes. This differential turned unfavorable in the year ended December 31, 2010, causing a decrease in revenue.
     Gross Margin — Gross margin was approximately $36.8 million in the year ended December 31, 2010 compared to approximately $24.8 million in the year ended December 31, 2009, an increase of $12.0 million. Our natural gas operation’s margins increased $13.0 million, of which $10.3 million was contributed by the Ohio Companies and $2.5 million was due to the sales growth in our North Carolina markets. Gross margin from our marketing and production operations decreased $954,000, due to lower sales volumes from the reversal of the favorable AECO and CIG Rockies index differential described above.
     Operating Expenses — Expenses other than cost of sales increased by $10.0 million to $25.7 million in the year ended December 31, 2010 from $15.7 million in the year ended December 31, 2009. Expenses from the Ohio Companies accounted for $8.2 million of the increase and a full year of operations from our Cut Bank operation caused an increase of $505,000. In 2010, we began paying our CEO a salary of $250,000. Mr. Osborne had previously only received a fee of $24,000. Depreciation expense in our Maine and North Carolina operations increased by $145,000. The year ended December 31, 2009 included a decrease in expense of approximately $409,000 resulting from the change in our vacation plan so that employees accrue vacation on a monthly basis.
     Other Income (Expense) , including Loss From Unconsolidated Affiliate — Other income increased by approximately $1.3 million to income of $384,000 from expense of $976,000 in the year ended December 31, 2009 and is caused by the following: (1) other income from the Ohio Companies totaled $589,000; (2) the loss from investment in unconsolidated affiliate, which is our investment in Kyuit, decreased by $493,000; (3) our Corporate and Other segment posted other income of $147,000 in 2010 compared to a loss in 2009 of $543,000, resulting in a decrease in costs of $690,000; and (4) offset by expense from the conclusion of the lawsuit with Shelby Gas Association of $441,000 in 2010.
     Interest Expense — Interest expense increased by $937,000 to $2.2 million in the year ended December 31, 2010 from $1.2 million in the year ended December 31, 2009. Interest expense from the Ohio Companies totaled $1.0 million.
     Income Tax Expense — Income tax expense increased by approximately $3.5 million to approximately $3.5 million in the year ended December 31, 2010 from $27,000 in the year ended December 31, 2009. Income tax expense related to the Ohio Companies totaled $782,000 and the tax-effect of the increase in pre-tax income without the Ohio Companies was $285,000. During 2009, we performed a study of our deferred tax asset related to the purchase of Frontier Utilities and Penobscot Natural Gas. We increased the gross amount of the deferred tax asset slightly, 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 $300,000. The net result was an income tax benefit of approximately $2.5 million.

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NET INCOME BY SERVICE AREA
The components of net income for 2010 and 2009 are:
                 
    Year Ended December 31,  
($ in thousands)   2010     2009  
Natural Gas Operations
               
Energy West Montana (MT)
  $ 937     $ 1,619  
Energy West Wyoming (WY)
    284       379  
Frontier Natural Gas (NC)
    2,350       1,437  
Bangor Gas (ME)
    1,210       454  
Orwell Natural Gas (OH)
    (417 )      
Northeast Ohio Natural Gas (OH)
    1,257        
Brainard Gas Corp. (OH)
    53        
 
           
Natural Gas Operations
  $ 5,674     $ 3,889  
Marketing & Production
    116       558  
Pipelines
    153       157  
 
           
 
    5,943       4,604  
Corporate & Other
    (146 )     2,215  
 
           
Consolidated Net Income
  $ 5,797     $ 6,819  
 
           

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The following highlights our results by operating segments:
NATURAL GAS OPERATIONS
Income Statement
                 
    Year Ended December 31,  
($ in thousands)   2010     2009  
Natural Gas Operations
               
Operating revenues
  $ 83,608     $ 58,766  
Gas Purchased
    48,877       37,052  
 
           
Gross Margin
    34,731       21,714  
Operating expenses
    24,682       14,663  
 
           
Operating income
    10,049       7,051  
Other income
    872       254  
 
           
Income before interest and taxes
    10,921       7,305  
Interest (expense)
    (2,086 )     (1,135 )
 
           
Income before income taxes
    8,835       6,170  
Income tax (expense)
    (3,161 )     (2,281 )
 
           
Net Income
  $ 5,674     $ 3,889  
 
           
Operating Revenues
                 
    Year Ended December 31,  
($ in thousands)   2010     2009  
Full Service Distribution Revenues
               
Residential
  $ 40,087       25,209  
Commercial
    32,713       24,721  
Industrial
    712       840  
Other
    262        
 
           
Total full service distribution
    73,774       50,770  
Transportation
    8,683       6,845  
Bucksport
    1,151       1,151  
 
           
Total operating revenues
  $ 83,608       58,766  
 
           
Utility Throughput
                 
    Year Ended December 31,  
(in million cubic feet (MMcf))   2010     2009  
Full Service Distribution
               
Residential
    4,401       3,027  
Commercial
    3,885       2,908  
Industrial
    129       189  
 
           
Total full service
    8,415       6,124  
Transportation
    7,334       4,510  
Bucksport
    14,500       14,127  
 
           
Total Volumes
    30,249       24,761  
 
           

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Degree Days
                                         
                            Percent (Warmer) Colder  
                            2010 Compared to  
    Normal     2010     2009     Normal     2009  
Great Falls, MT
    7,540       7,611       7,956       0.94 %     (4.34 %)
Cody, WY
    6,925       7,253       7,672       4.74 %     (5.46 %)
Bangor, ME
    7,676       6,543       8,046       (14.76 %)     (18.68 %)
Elkin, NC
    3,963       4,101       3,554       3.48 %     15.39 %
Youngstown, OH
    6,536       5,988       6,195       (8.38 %)     (3.34 %)
Year Ended December 31, 2010 Compared with Year Ended December 31, 2009
Revenues and Gross Margin
     Operating revenues for the year ended December 31, 2010 increased to approximately $83.6 million from approximately $58.8 million in the year ended December 31, 2009. This $24.8 million increase is the result of the three factors described below:
  1)   We earned approximately $26.1 million in revenues from the Ohio Companies. This is based on sales volumes of 2,627 MMcf and transportation volumes of 2,479 MMcf. The Ohio Companies served approximately 24,000 customers at December 31, 2010.
 
  2)   Revenue from our Maine and North Carolina markets increased by approximately $3.7 million on a volume increase of 1,325 MMcf in 2010 compared to 2009.
 
  3)   Offsetting these is a decrease in revenue due to lower costs of gas passed through to customers in 2010 compared to 2009 of approximately $5.0 million.
     Gas purchases in natural gas operations increased to approximately $48.9 million for the year ended December 31, 2009 from approximately $37.1 million for the year ended December 31, 2008. Of this $11.8 million increase, $15.7 million comes from the Ohio Companies, and $1.2 million is due to the sales growth in our Maine and North Carolina markets. These are partially offset by $5.2 million due to lower index prices paid for natural gas in 2010 compared to 2009. Our gas costs are passed on dollar for dollar to our customers under tariffs regulated by the Public Utility Commissions in the jurisdictions in which we operate. Our gas costs are subject to periodic audits and prudency review in all of these jurisdictions. During 2010, the PUCO conducted audits of the gas costs recovery activities of Orwell and NEO. These cases are still pending, but based on recommendations of the PUCO Staff, we have included in our gas purchases expense for 2010 an increase in costs for Orwell of $1,100,000 and a decrease in costs of $1,050,000 for NEO. The net effect to the Company is an increase in gas purchases expense of $44,507. Please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies” and “Estimates” for further discussion.
     Gross margin increased to approximately $34.7 million for the year ended December 31, 2010 from approximately $21.7 million for the year ended December 31, 2009, an increase of $13.0 million. Gross margin from the Ohio Companies accounted for $10.3 million of this increase. Sales growth in our Maine and North Carolina markets contributed an increase in margin of approximately $2.5 million. A full year of operations from our Cut Bank, Montana operation contributed an increase of $527,000 to gross margin. Warmer weather in 2010 compared to 2009 caused a decrease in margin from the other Montana and Wyoming operations of approximately $326,000.
Earnings
     The Natural Gas Operations segment’s earnings in 2010 were $5.7 million, or $0.90 per diluted share, up 46% from earnings of $3.9 million and equal on a per share basis to the $0.90 per diluted share in 2009.
     Operating expenses increased by $10.0 million to $24.7 million for the year ended December 31, 2010 from $14.7 million for the year ended December 31, 2009. The Ohio Companies accounted for $8.2 million of the increase and a full year of operations from our Cut Bank operation caused an increase of $505,000. The year ended December 31, 2009 included a decrease in expense of approximately $405,000 resulting from the change in our vacation plan so that employees accrue vacation on a monthly basis. In 2010, we began paying our CEO a salary of $250,000. Mr. Osborne had previously only received director’s fees. Depreciation expense in our Maine and North Carolina operations increased by $145,000 in the 2010 due to capital expansion to meet the customer growth in those markets. The remaining increase is caused by increases in property taxes, salaries, employee benefits, and professional services.

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     Other Income increased by $618,000 to $872,000 for the year ended December 31, 2010 from $254,000 for the year ended December 31, 2009. Other income from the Ohio Companies totaled $589,000, accounting for the majority of the increase.
     Interest expense increased by $1.0 million to $2.1 million for the year ended December 31, 2010 from $1.1 million for the year ended December 31, 2009. Interest expense from the recently acquired Ohio Companies totaled $1.0 million and was partially offset by a small decrease from existing operations.
     Income tax expense increased by $900,000 to approximately $3.2 million in the year ended December 31, 2010 compared with approximately $2.3 million in the year ended December 31, 2009. Income tax expense from the Ohio Companies totaled $782,000. Income tax expense from existing operations increased by $99,000, reflecting an increase in income tax expense of $369,000 on the increase in pre-tax income, an adjustment related to the change in our overall effective tax rate of $41,000, and offset by a $311,000 income tax benefit from the true-up of income tax expense to our filed 2009 income tax return.
Marketing and Production Operations (EWR)
Income Statement
                 
    Year Ended December 31,  
($ in thousands)   2010     2009  
Energy West Resources
               
Operating revenues
  $ 7,466     $ 12,239  
Gas Purchased
    5,829       9,648  
 
           
Gross Margin
    1,637       2,591  
Operating expenses
    780       844  
 
           
Operating income
    857       1,747  
Other income (expense)
    (635 )     (687 )
 
           
Income before interest and taxes
    222       1,060  
Interest (expense)
    (67 )     (89 )
 
           
Income before income taxes
    155       971  
Income tax (expense)
    (39 )     (413 )
 
           
Net Income
  $ 116     $ 558  
 
           
Year Ended December 31, 2010 Compared with Year Ended December 31, 2009
Revenues and Gross Margin
     Revenues decreased approximately $4.8 million to $7.5 million for the year ended December 31, 2010 from approximately $12.2 million for the year ended December 31, 2009. This decrease is due primarily to lower sales volumes in our Wyoming market. The year ended December 31, 2009 included sales volumes caused by a favorable differential between the AECO and CIG Rockies indexes. This differential turned the other direction and was unfavorable in the year ended December 31, 2010, causing the decrease in revenue. Production revenues stayed flat from the year ended December 31, 2009 to the year ended December 31, 2010.
     Gross margin decreased $954,000 to approximately $1.6 million in the year ended December 31, 2010 from approximately $2.6 million in year ended December 31, 2009. Gross margin from retail gas decreased by $947,000 due to the lower sales volumes and gross margin from gas production decreased by $7,000.
Earnings
     The Marketing and Production segment’s earnings in 2010 were $116,000, or $0.02 per diluted share, down 79% from earnings of $558,000 or $0.13 diluted share in 2009.
     Our operating expenses decreased approximately $64,000, to $780,000 in the year ended December 31, 2010 from $844,000 in the year ended December 31, 2009. The year ended December 31, 2009 included a one-time payment of approximately $57,000 made to the pipeline company that delivers much of our gas supply, for facilities improvements.

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     Other expense totaled $635,000 in the year ended December 31, 2010. The trial in our lawsuit with Shelby Gas Association (“Shelby”) concluded on April 27, 2010 with the jury awarding Shelby damages in the amount of $522,000. We had an existing liability recorded of $82,000 and recorded the remaining liability and associated expense of $441,000 in the first quarter of 2010. In 2010 we also incurred a loss of $194,000 on our equity investment in Kykuit. For the year ended December 31, 2009, we incurred expense of $687,000 from our loss on equity investment in Kykuit, due to the write-off of drilling costs relating to dry holes.
     Income tax expense decreased approximately $374,000 to an expense of $39,000 in the year ended December 31, 2010 from an expense of $413,000 in the year ended December 31, 2009, due to the tax benefit of $305,000 on the decrease in pre-tax income, the tax benefit of $254,000 related to the true-up of income tax expense to our filed 2009 income tax return and offset by the tax expense from adjusting to our final 2010 effective tax rate of $185,000.
Pipeline Operations
Income Statement
                 
    Year Ended December 31,  
($ in thousands)   2010     2009  
Pipeline Operations
               
Operating revenues
  $ 427     $ 450  
Gas Purchased
           
 
           
Gross Margin
    427       450  
Operating expenses
    230       177  
Operating income
    197       273  
Other income
           
 
           
Income before interest and taxes
    197       273  
Interest (expense)
    (26 )     (17 )
 
           
Income before income taxes
    171       256  
Income tax (expense)
    (18 )     (99 )
 
           
Net Income
  $ 153     $ 157  
 
           
Year Ended December 31, 2010 Compared with Year Ended December 31, 2009
     Net income stayed flat at approximately $153,000 in the year ended December 31, 2010 compared to approximately $157,000 in the year ended December 31, 2009. The overall impact of the results of our pipeline operations was not material to our results of consolidated operations.

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Corporate and Other Operations
Income Statement
                 
    Year Ended December 31,  
($ in thousands)   2010     2009  
Corporate and Other
               
Operating revenues
  $     $  
Gas Purchased
             
 
           
Gross Margin
           
Operating expenses
    23       8  
 
           
Operating income
    (23 )     (8 )
Other income (expense)
    147       (543 )
 
           
Income before interest and taxes
    124       (551 )
Interest expense
             
 
           
Income before income taxes
    124       (551 )
Income tax benefit (expense)
    (270 )     2,766  
 
           
Net Income (loss)
  $ (146 )   $ 2,215  
 
           
Year Ended December 31, 2010 Compared with Year Ended December 31, 2009
Our Corporate and Other reporting segment 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 Gas Natural Inc.’s holding company functions. Therefore, it does not have standard revenues, gas purchase costs, or gross margin. Our first significant event reported under this segment was a deferred tax asset that was the result of our acquisitions of Bangor Gas Company and Frontier Natural Gas. Under ASC 805 we recorded these stock acquisitions as if the net assets of the targets were acquired. At December 31, 2010, the deferred tax asset is $13.4 million. For more information about this deferred tax asset, please see “Critical Accounting Policies and Estimates — Deferred Tax Asset and Income Tax Accruals.”
     For the year ended December 31, 2010, corporate and other operations included administrative expenses of $23,000, acquisition expenses of $154,000, related primarily to the acquisition of the Ohio Companies, offset by interest and dividend income of $142,000 and a recognized gain on the sale of marketable securities of $159,000 for total income before income taxes of $124,000. Income taxes totaled $270,000 and consisted of expense related to pre-tax income of $46,000, income tax expense resulting from the true-up of income tax expense to our filed 2009 income tax return of $101,000 and year-end adjustments related to changes in our overall effective tax rate of $123,000. The end result is a net loss of approximately$146,000.
     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 12 to our Consolidated Financial statements for further discussion.
Capital Sources and Liquidity
Sources and Uses of Cash
     Operating activities provide our primary source of cash. At December 31, 2010 and 2009, we had approximately $13.0 million and $2.8 million of cash on hand, respectively. 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 $18.2 million and $14.7 million at

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December 31, 2010 and 2009, respectively. This change in our cash position is primarily due to increases in our capital expenditures due to expansion in our North Carolina and Maine markets.
     We made capital expenditures for continuing operations of $8.5 million and $8.9 million for the years ended December 31, 2010 and 2009, 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 $22.0 million and $13.0 million at December 31, 2010 and 2009, respectively.
     Cash increased to $13,027,000 at December 31, 2010, compared with $2,752,000 at December 31, 2009.
                 
    For the Year Ended December 31,  
    2010     2009  
Cash provided by Operating Activities
  $ 6,727,000     $ 16,301,000  
Cash used in Investing Activities
    (4,424,000 )     (9,185,000 )
Cash provided by (used in) Financing Activities
    7,972,000       (5,429,000 )
 
           
Increase in Cash
  $ 10,275,000     $ 1,687,000  
 
           
OPERATING CASH FLOW
For the year ended December 31, 2010, cash provided by operating activities decreased $9.6 million as compared to the year ended December 31, 2009. Items affecting the use of cash included an increase in amounts paid on accounts payable of $4.0 million, an increase in amounts paid for gas supply of $4.6 million, increased amounts paid for other assets and liabilities of $3.6 million, and a $3.0 million decrease in collections of recoverable costs of gas, offset by a $5.0 million decrease in net deferred tax assets. Cash inflows increased from additional accounts receivable collections of $700,000, additional related party receivable collections of $1.2 million, and a $1.5 million increase in depreciation expense, offset by a decrease in net income of $1.0 million. Other changes included higher payments on accrued interest of $300,000, a $100,000 decrease in prepayments, a $600,000 decrease in asset impairments, an increase in payments on accounts payable to related parties of $900,000, and a $100,000 increase in realized gains on marketable securities.
INVESTING CASH FLOW
For the year ended December 31, 2010, cash used in investing activities decreased by $4.8 million as compared to the year ended December 31, 2009, primarily due to a $3.0 million increase in the sale of marketable securities. Other changes include a $1.3 million decrease in marketable securities purchases, decreased construction expenditures of $300,000 and a decrease of $300,000 in purchases of other investments.
Capital Expenditures
Our capital expenditures for continuing operations totaled $8.5 million and $8.9 million for the years ended December 31, 2010 and 2009, 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.
The majority of our capital spending is focused on the growth of our Natural Gas Operations segment. 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.
Estimated Capital Expenditures
Our capital expenditures for 2010 and 2009 were as follows and we estimate future cash requirements for capital expenditures will be as follows:

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                    Estimated Future  
    Year Ended December 31,     Cash Requirements  
($ in thousands)   2010     2009     2011  
Natural Gas Operations
  $ 8,490     $ 8,649     $ 15,023  
Marketing and Production
          191        
Pipeline Operations
                114  
Corporate and Other
    33       14        
 
                 
Total Capital Expenditures
  $ 8,523     $ 8,854     $ 15,137  
 
                 
FINANCING CASH FLOW
For the year ended December 31, 2010, cash provided by financing activities increased by $13.4 million as compared with the year ended December 31, 2009. The primary reason for this is an increase in sales of common stock of $18.8 million due to the completion of a secondary public offering in November 2010. Line of credit proceeds increased by $1.3 million, while payments decreased by $1.7 million. Other offsetting changes include an increase of $5.3 million in payments on other short-term borrowings, an increase in payments on related party notes payable of $2.1 million, and an increase of $1.2 million in dividends paid.
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. 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 $18.2 million and $14.7 million at December 31, 2010 and 2009, respectively. 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 $22.0 million and $13.0 million at December 31, 2010, and 2009, respectively.
In November 2010, Gas Natural completed a 2.415 million share secondary public offering. Of these shares, 340,000 were selling shareholder shares and 2.075 million were primary shares. The primary shares sold by Gas Natural include a full exercise of the over-allotment option. Gas Natural did not receive any of the proceeds from the selling shareholder shares. Net proceeds to Gas Natural were approximately $19.0 million after sales concessions, underwriting expenses, and deal expenses. The primary uses of proceeds are for investment in utility operations as we continue to expand our organic footprint. Additionally, proceeds were used to repay three separate Ohio utility maturing debt instruments as those entities await final approval of their financing application. That application was originally filed with the PUCO in October 2010 and was approved on March 30, 2011. Upon this approval, Gas Natural will be able to replenish cash at the holding company for investment in our operating subsidiaries.
In December 2010, NEO repaid upon maturity the Citizens Bank Line of Credit in the amount of $2.1 million and Orwell repaid upon maturity the Huntington Bank Line of Credit in the amount of $1.5 million and the Huntington Bank Term Loan in the amount of $4.1 million. These notes were secured by all assets of the Ohio utilities, as well as a personal guarantee from our chairman and CEO. These three instruments had a maturity date due the end of November 2010. These notes were repaid and extinguished with no ability to redraw at this time. As previously stated, Gas Natural is pursuing a refinancing of those notes through a private placement with qualified institutional investors.
In addition to these notes that had a pending maturity date, a related party demand note was also repaid in December 2010. Lightning Pipeline Company, the intermediate holding company for Orwell, had a $2.0 million unsecured demand note payable with our chairman, which was repaid in December of 2010, to include accrued interest.
The following discussion describes our credit facilities as of December 31, 2010.

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Bank of America Credit Facility — 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 amount. 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 years ended December 31, 2010 and 2009.
                                 
    First     Second     Third     Fourth  
    Quarter     Quarter     Quarter     Quarter  
Twelve Months Ended December 31, 2010
                               
Minimum Borrowing
  $ 7,798,000     $ 9,448,000     $ 9,900,000     $ 14,600,000  
Maximum Borrowing
  $ 14,650,000     $ 14,448,000     $ 17,100,000     $ 20,450,000  
Average Borrowing
  $ 10,630,000     $ 7,431,000     $ 11,990,000     $ 16,641,000  
 
Twelve Months Ended December 31, 2009
                               
Minimum borrowing
  $ 5,595,000     $     $ 3,600,000     $ 9,950,000  
Maximum borrowing
  $ 18,095,000     $ 5,045,000     $ 10,250,000     $ 15,250,000  
Average borrowing
  $ 11,987,000     $ 2,002,000     $ 7,654,000     $ 12,351,000  
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. 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, 2010 and 2009, we had $18.2 million and $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 years ended December 31, 2010 and 2009 had a daily weighted average interest rate of 2.29% and 3.25% per annum, respectively.
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.
Citizens Bank Credit Facility and Term Loans
     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. Gas Natural 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. The line of credit was repaid in December 2010.
     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, $2.65 million and $892,000 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.
     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 Gas Natural Inc., measured on a quarterly basis beginning with the quarter ended December 31, 2009. The Citizens

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Credit Facility allows NEO, Great Plains and GPL to pay dividends to Gas Natural 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, 2010, $6.6 million under the NEO term loan, $2.2 million under the Great Plains term loan and $753,000 under the GPL term loan.
Huntington Bank Credit Facility and Term Loan
     These two facilities, $1.5 million line of credit and $4.1 million term loan, were both repaid and extinguished in December 2010.
Combined Term Loans and Credit Facilities
     The $18.2 million of borrowings at December 31, 2010, leaves our borrowing capacity at $1.8 million. Including the amounts related to the Ohio Companies, we have $18.2 million of borrowings and borrowing capacity of $1.8 million. As discussed above, this level of borrowings is due primarily to increases in our capital expenditures due to expansion in our North Carolina and Maine markets, and the acquisition of the Ohio Companies.
     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 $22.9 million at December 31, 2010, with approximately $911,000 due within one year.
     At December 31, 2010 and 2009, we believe we are in compliance with the financial covenants under our debt agreements or have received waivers for any defaults.
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
ASU No. 2009-17, “Consolidations (Topic 810) Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities”
On January 1, 2010, the Company adopted new authoritative guidance under this ASU, which requires ongoing reassessments of whether an enterprise is the primary beneficiary of a variable interest entity. Additionally, this guidance requires enhanced disclosures that will provide users of financial statements with more transparent information about an enterprise’s involvement in variable interest entities. The adoption of this guidance did not have a material impact on the consolidated financial statements.
ASU No. 2010-06, “Fair Value Measurements and Disclosures (Topic 820) Improving Disclosures about Fair Value Measurements”
This ASU which requires additional fair value disclosures including disclosing the amount of significant transfers in and out of Level 1 and 2 fair value measurements and to describe the reasons for the transfers. In addition, the guidance also requires disclosures about gross purchases, sales, issuances and settlement activity in Level 3 fair value measurements. The Company has applied the disclosure requirements which did not have a material impact on the consolidated financial statements.
Recently Issued
ASU No. 2010-28, “Intangibles —Goodwill and Other (Topic 350) When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts”
This ASU modifies Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts. For those reporting units, an entity is required to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists. In determining whether it is more likely than not that a goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors indicating that an impairment may exist such as if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. This ASU is not expected to have a material impact on the consolidated financial statements

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ASU No. 2010-29, “Business Combinations (Topic 805) Disclosure of Supplementary Pro Forma Information for Business Combinations”
This ASU provides clarification regarding the acquisition date that should be used for reporting pro forma financial information disclosures required by Topic 805 when comparative financial statements are presented. This ASU also requires entities to provide a description of the nature and amount of material, nonrecurring pro forma adjustments that are directly attributable to the business combination. This ASU is effective for the Company prospectively for business combinations occurring after December 31, 2010. This ASU is not expected to have a material impact on the consolidated financial statements.
ASU No. 2011-01, “Deferral of the Effective Date of Disclosures about Troubled Debt Restructurings in Update No. 2010-20”
In January 2011, the FASB issued ASU 2011-01, which temporarily delays the effective date of the disclosures about troubled debt restructurings in ASU 2010-20. The delay is intended to allow the FASB time to complete its deliberations on what constitutes a troubled debt restructuring. The effective date of the new disclosures about troubled debt restructurings for public entities and the guidance for determining what constitutes a troubled debt restructuring will then be coordinated. Currently, that guidance is anticipated to be effective for interim and annual periods ending after June 15, 2011. This ASU is not expected to have a material impact on the consolidated financial statements.
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. Financial Statements and Supplementary Data.
Our Consolidated Financial Statements begin on page F-1 of this Annual Report on Form 10-K.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
     None.
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures

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As of December 31, 2010, 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, 2010.
Management’s Report on Internal Control over Financial Reporting
Management of Gas Natural 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, 2010.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting during the last fiscal quarter of calendar year 2010, 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 is not subject to attestation by our registered public accounting firm pursuant to Section 989G of the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010.
Item 9B. Other Information
None.
PART III
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 2011 Annual Meeting.
Item 11. Executive Compensation.
Information required by this item is incorporated by reference to the material appearing under the headings “Director Compensation” and “Executive Compensation,” in the Proxy Statement for our 2011 Annual Meeting.

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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 2011 Annual Meeting.
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 2011 Annual Meeting.
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 2011 Annual Meeting.
PART IV
Item 15. Exhibits and Financial Statement Schedules.
(a) Financial Statements:
(b) Exhibit Index.
     
2.1
  Agreement and Plan of Merger, dated June 29, 2009, by and among Energy West, Incorporated, Various Acquisition Subsidiaries, Lightning Pipeline Co., Inc., Great Plains Natural Gas Company, Brainard Gas Corp., Richard M. Osborne, Trustee, Rebecca Howell, Stephen G. Rigo, Marty Whelan and Thomas J. Smith, incorporated by reference to Exhibit 10.2 to Gas Natural Inc.’s current report on Form 8-K dated June 26, 2009 as filed with the Securities and Exchange Commission
 
   
2.2
  Agreement and Plan of Merger, dated June 29, 2009, by and among Energy West, Incorporated, an Acquisition Subsidiary, Great Plains Land Development Company, LTD. and Richard M. Osborne, Trustee, incorporated by reference to Exhibit 10.3 to Gas Natural Inc.’s current report on Form 8-K as filed July 2, 2009 with the Securities and Exchange Commission
 
   
2.3
  Agreement and Plan of Merger by and among Energy Inc., Energy West, Incorporated and Energy West Merger Sub, Inc., dated August 3, 2009, incorporated by reference to Exhibit 2.1 to Gas Natural Inc.’s current report on Form 8-K as filed August 4, 2009 with the Securities and Exchange Commission
 
   
2.4
  Assignment and Assumption Agreement, dated December 30, 2009, by and between Energy West, Incorporated and Gas Natural Inc., filed as Exhibit 2.3 to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference
 
   
2.5
  Assignment and Assumption Agreement, dated December 30, 2009, by and between Energy West, Incorporated and Gas Natural Inc., filed as Exhibit 2.4 to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference
 
   
2.6
  First Amendment to Agreement and Plan of Merger, dated as of January 5, 2010, by and among Richard M. Osborne, Trustee, Rebecca Howell, Stephen G. Rigo, Marty Whelan and Thomas J. Smith, Lightning Pipeline Co., Inc., Great Plains Natural Gas Company, and Brainard Gas Corp., Lightning Pipeline Acquisition Inc., Great Plains Acquisition Inc. and Brainard Acquisition Inc. and Gas Natural Inc., filed as Exhibit 2.5 to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference
 
   
2.7
  First Amendment to Agreement and Plan of Merger, dated as of January 5, 2010, by and among Richard M. Osborne, Trustee, Great Plains Land Development Company, LTD. and GPL Acquisition LLC and Gas Natural Inc., filed as Exhibit 2.6 to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference
 
   
3.1(a)
  Restated Articles of Incorporation. Filed as Exhibit 3.1 to Amendment No. 1 to the Registrant’s Annual Report on Form 10-K/A for the year ended June 30, 1996 and incorporated herein by reference
 
   
3.1(b)
  Articles of Amendment to the Articles of Incorporation dated January 28, 2008. Filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K dated February 1, 2008 and incorporated herein by reference
 
   
3.1(c)
  Articles of Amendment to the Articles of Incorporation dated December 5, 2007. Filed as Exhibit 3.1(e) to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended December 31, 2007 and incorporated herein by reference
 
   
3.1(d)
  Articles of Amendment to the Articles of Incorporation dated May 29, 2007. Filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K, filed on June 4, 2007, and incorporated herein by reference
 
   
3.2
  Amended and Restated Bylaws. Filed as Exhibit 3.2 to the Registrant’s Current Report on Form 8-K on March 5, 2004 and incorporated herein by reference
 
   
3.2(a)
  Amendment No. 3 to Amended and Restated Bylaws dated August 12, 2008. Filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K dated August 12, 2008 and incorporated herein by reference

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3.2(b)
  Amendment No. 2 to Amended and Restated Bylaws dated April 10, 2008. Filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K dated April 10, 2008 and incorporated herein by reference
 
   
3.2(c)
  Amendment No. 1 to Amended and Restated Bylaws dated November 14, 2007. Filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K dated November 14, 2007 and incorporated herein by reference
 
   
10.1
  Note Purchase Agreement dated June 29, 2007, between the Registrant and various Purchasers relating to 6.16% Senior Unsecured Notes due June 29, 2017. Filed as Exhibit 10.4 to the Registrant’s Current Report on Form 8-K, filed July 5, 2007, and incorporated herein by reference
 
   
10.2
  Credit Agreement dated as of June 29, 2007, by and among the Registrant and various financial institutions and LaSalle Bank National Association. Filed as Exhibit 10.5 to the Registrant’s Current Report on Form 8-K, filed July 5, 2007, and incorporated herein by reference
 
   
10.3
  Amendment dated October 22, 2007 to the Credit Agreement among the Registrant, various financial institutions and LaSalle Bank National Association, as agent. Filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K dated October 22, 2007 and incorporated herein by reference
 
   
10.4†
  Gas Natural Inc. 2002 Stock Option Plan. Filed as Appendix A to the Registrant’s Proxy Statement on Schedule 14A, filed on October 30, 2002, and incorporated herein by reference
 
   
10.5†
  First Amendment to Energy West Incorporated 2002 Stock Option Plan, filed as Exhibit 10.8 to the Registrant’s Transition Report on 10-K/T for the transition period ended December 31, 2008 and incorporated herein by reference
 
   
10.6†
  Employee Stock Ownership Plan Trust Agreement. Filed as Exhibit 10.2 to Registration Statement on Form S-1 (File No. 33-1672) and incorporated herein by reference
 
   
10.7†
  Management Incentive Plan. Filed as Exhibit 10.12 to the Registrant’s Annual Report on Form 10-K/A for the year ended June 30, 1996, filed on July 8, 1997, and incorporated herein by reference
 
   
10.8†
  Energy West Senior Management Incentive Plan. Filed as Exhibit 10.19 to the Registrant’s Annual Report on Form 10-K for the year ended June 30, 2002, filed on September 30, 2002, and incorporated herein by reference
 
   
10.9†
  Energy West Incorporated Deferred Compensation Plan for Directors. Filed as Exhibit 10.20 to the Registrant’s Annual Report on Form 10-K for the year ended June 30, 2002, filed on September 30, 2002, and incorporated herein by reference
 
   
10.10†
  Amended and Restated Energy West Incorporated Deferred Compensation Plan for Directors, filed as Exhibit 10.13 to the Registrant’s Transition Report on 10-K/T for the transition period ended December 31, 2008 and incorporated herein by reference
 
   
10.11
  Lease Agreement dated February 25, 2008 between OsAir, Inc. and Energy West, Incorporated. Filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K dated February 25, 2008 and incorporated herein by reference
 
   
10.12
  Natural Gas Transportation Service Agreement dated as of July 1, 2008 between Orwell-Trumbull Pipeline Co., LLC, Orwell Natural Gas Company and Brainard Gas Corp. Filed as Exhibit 10.26 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2008 and incorporated herein by reference
 
   
10.13
  Transportation Service Agreement dated as of July 1, 2008 between Cobra Pipeline Co., Ltd., Northeast Ohio Natural Gas Company, Orwell Natural Gas Company and Brainard Gas Corp. Filed as Exhibit 10.27 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2008 and incorporated herein by reference

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10.14
  First Amendment dated July 1, 2008 to the Orwell-Trumbull Pipeline Co., LLC Operations Agreement between Orwell Natural Gas Company and Orwell-Trumbull Pipeline Co., LLC. Filed as Exhibit 10.28 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2008 and incorporated herein by reference
 
   
10.15
  Orwell-Trumbull Pipeline Co., LLC Operations Agreement dated January 1, 2008 between Orwell Natural Gas Company and Orwell-Trumbull Pipeline Co., LLC. Filed as Exhibit 10.29 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2008 and incorporated herein by reference
 
   
10.16
  Triple Net Lease Agreement dated as of July 1, 2008 between Station Street Partners, LLC and Orwell Natural Gas Company. Filed as Exhibit 10.30 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2008 and incorporated herein by reference
 
   
10.17
  Triple Net Lease Agreement dated as of July 1, 2008 between OsAir, Inc. and Orwell Natural Gas Company. Filed as Exhibit 10.31 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2008 and incorporated herein by reference
 
   
10.18
  Triple Net Lease Agreement dated as of July 1, 2008 between Richard M. Osborne, Trustee and Orwell Natural Gas Company. Filed as Exhibit 10.32 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2008 and incorporated herein by reference
 
   
10.19
  Triple Net Lease Agreement dated as of July 1, 2008 between OsAir, Inc. and Northeast Ohio Natural Gas Company. Filed as Exhibit 10.33 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2008 and incorporated herein by reference
 
   
10.20†
  Employment Agreement dated August 25, 2006 between Gas Natural Inc. and Kevin J. Degenstein, filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K dated September 18, 2006 and incorporated herein by reference
 
   
10.21†
  First Amendment to Employment Agreement dated as of December 31, 2008, between Gas Natural Inc. and Kevin J. Degenstein, filed as Exhibit 10.39 to the Registrant’s Transition Report on 10-K/T for the transition period ended December 31, 2008 and incorporated herein by reference
 
   
10.22†
  Employment Agreement dated April 13, 2007 between Gas Natural Inc. and David C. Shipley, filed as Exhibit 10.40 to the Registrant’s Transition Report on 10-K/T for the transition period ended December 31, 2008 and incorporated herein by reference
 
   
10.23
  Asset Management Agreement, dated January 3, 2010, by and between Orwell Natural Gas Company and John D. Oil and Gas Marketing Company, LLC, filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference
 
   
10.24
  Asset Management Agreement, dated January 3, 2010, by and between Northeast Ohio Natural Gas and John D. Oil and Gas Marketing Company, LLC, filed as Exhibit 10.2 to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference
 
   
10.25
  Demand Promissory Note, dated December 1, 2008, to Richard M. Osborne, Trustee from Lightning Pipeline Company, Inc., incorporated by reference to Exhibit 10.8 to Gas Natural Inc.’s current report on Form 8-K as filed July 2, 2009 with the Securities and Exchange Commission
 
   
10.26
  Amended and Restated Promissory Note, dated January 3, 2010, to Richard M. Osborne, Trustee from Lightning Pipeline Company, Inc., filed as Exhibit 10.5(a) to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference
 
   
10.27
  Demand Cognovit Note, dated August 6, 2008, to Richard M. Osborne from Brainard Gas Corp., filed as Exhibit 10.5(b) to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference

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10.28
  Electronic Metering Service and Operation Agreement, as of April 15, 2009, by and between Orwell Trumbull Pipeline, LTD. and Orwell Natural Gas Co., incorporated by reference to Exhibit 10.4 to Gas Natural Inc.’s current report on Form 8-K as filed July 2, 2009 with the Securities and Exchange Commission
 
   
10.20
  Electronic Metering Service and Operation Agreement, as of April 15, 2009, by and between COBRA Pipeline Company, LTD. and Brainard Gas Corporation, incorporated by reference to Exhibit 10.5 to Gas Natural Inc.’s current report on Form 8-K as filed July 2, 2009 with the Securities and Exchange Commission
 
   
10.30
  Electronic Metering Service and Operation Agreement, as of April 15, 2009, by and between COBRA Pipeline Company, LTD. and Northeast Ohio Natural Gas Corporation, Incorporated by reference to Exhibit 10.6 to Gas Natural Inc.’s current report on Form 8-K as filed July 2, 2009 with the Securities and Exchange Commission
 
   
10.31
  Electronic Metering Service and Operation Agreement, as of April 15, 2009, by and between COBRA Pipeline Company, LTD. and Orwell Natural Gas Co., Incorporated by reference to Exhibit 10.7 to Gas Natural Inc.’s current report on Form 8-K as filed July 2, 2009 with the Securities and Exchange Commission
 
   
10.32
  Guaranty, dated July 3, 2008, by Great Plains Natural Gas Company in favor of Citizens Bank with respect to Northeast Ohio Natural Gas Corp. as borrower, filed as Exhibit 10.24(a) to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference
 
   
10.33
  Guaranty, dated July 3, 2008, by Richard M. Osborne, individually, in favor of Citizens Bank with respect to Northeast Ohio Natural Gas Corp. as borrower, filed as Exhibit 10.24(b) to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference
 
   
10.34
  Guaranty, dated July 3, 2008, by Richard M. Osborne, Trustee UTA January 13, 1995, in favor of Citizens Bank with respect to Northeast Ohio Natural Gas Corp. as borrower, filed as Exhibit 10.24(c) to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference
 
   
10.35
  Credit Agreement, dated July 3, 2008, by and between Great Plains Natural Gas Company, as borrower, and Citizens Bank, as lender, filed as Exhibit 10.25 to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference
 
   
10.36
  Term Note, dated July 3, 2008, by Great Plains Natural Gas Company, as maker, to Citizens Bank, as holder, filed as Exhibit 10.26 to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference
 
   
10.37
  Security Agreement, dated July 3, 2008, by Great Plains Natural Gas Company in favor of Citizens Bank, filed as Exhibit 10.27 to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference
 
   
10.38
  Guaranty, dated July 3, 2008, by Richard M. Osborne, individually, in favor of Citizens Bank with respect to Great Plains Natural Gas Company as borrower, filed as Exhibit 10.28(a) to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference
 
   
10.39
  Guaranty, dated July 3, 2008, by Richard M. Osborne, Trustee UTA January 13, 1995, in favor of Citizens Bank with respect to Great Plains Natural Gas Company as borrower, filed as Exhibit 10.28(b) to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference
 
   
10.40
  Credit Agreement, dated July 3, 2008, by and between Great Plains Land Development Co., LTD., as borrower and Citizens Bank, N.A., as lender, filed as Exhibit 10.29 to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference

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10.41
  Term Note, dated July 3, 2008, by Great Plains Land Development Co., LTD., as maker, to Citizens Bank, N.A. as holder, filed as Exhibit 10.30 to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference
 
   
10.42
  Security Agreement, dated July 3, 2008, by Great Plains Land Development Co., LTD. in favor of Citizens Bank, filed as Exhibit 10.31 to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference
 
   
10.43
  Guaranty, dated July 3, 2008, by Great Plains Natural Gas Company in favor of Citizens Bank with respect to Great Plains Land Development Co., LTD. as borrower, filed as Exhibit 10.32(a) to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference
 
   
10.44
  Guaranty, dated July 3, 2008, by Richard M. Osborne, individually, in favor of Citizens Bank with respect to Great Plains Land Development Co., LTD. as borrower, filed as Exhibit 10.32(b) to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference
 
   
10.45
  Guaranty, dated July 3, 2008, by Richard M. Osborne, Trustee UTA January 13, 1995, in favor of Citizens Bank with respect to Great Plains Land Development Co., LTD. as borrower, filed as Exhibit 10.32(c) to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference
 
   
10.46
  Loan Modification Agreement, effective as of December 1, 2009, by and among Northeast Ohio Natural Gas Corp., as borrower, and Richard M. Osborne, individually, Richard M. Osborne, Trustee UTA January 13, 1995, and Great Plains Natural Gas Company, each as guarantors, and Citizens Bank, filed as Exhibit 10.33 to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference
 
   
10.47
  Loan Modification Agreement, effective as of December 1, 2009, by and among Great Plains Natural Gas Company, as borrower, and Richard M. Osborne, individually, and Richard M. Osborne, Trustee UTA January 13, 1995, each as guarantors, and Citizens Bank, filed as Exhibit 10.34 to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference
 
   
10.48
  Loan Modification Agreement, effective as of December 1, 2009, by and among Great Plains Land Development Co., LTD., as borrower, and Richard M. Osborne, individually, Richard M. Osborne, Trustee UTA January 13, 1995, and Great Plains Natural Gas Company, each as guarantors, and Citizens Bank, filed as Exhibit 10.35 to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference
 
   
10.49
  Guaranty, dated January 5, 2010, by Gas Natural Inc. in favor of Citizens Bank with respect to Northeast Ohio Natural Gas Corp. as borrower, filed as Exhibit 10.36 to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference
 
   
10.50
  Guaranty, dated January 5, 2010, by Gas Natural Inc. in favor of Citizens Bank with respect to Great Plains Natural Gas Company as borrower, filed as Exhibit 10.37 to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference
 
   
10.51
  Guaranty, dated January 5, 2010, by Gas Natural Inc. in favor of Citizens Bank with respect to Great Plains Land Development Co., LTD. as borrower, filed as Exhibit 10.38 to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference
 
   
10.52*
  Base Contract for Sale and Purchase of Natural Gas, dated February 23, 2011, between John D. Oil & Gas Marketing, LLC and Gas Natural Service Company, LLC (relating to interstate gas sales)
 
   
10.53*
  Brokerage Contract for Interstate Natural Gas Sales, dated February 23, 2011, between Gas Natural Service Company, LLC and John D. Oil & Gas Marketing, LLC (relating to interstate gas sales)

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10.54*
  Base Contract for Sale and Purchase of Natural Gas, dated February 23, 2011, between John D. Oil & Gas Marketing, LLC and Gas Natural Service Company, LLC (relating to intrastate gas sales)
 
   
10.55*
  Intrastate Natural Gas Sales Contract, dated February 23, 2011, between Gas Natural Service Company, LLC and John D. Oil & Gas Marketing, LLC
 
   
10.56*
  Asset Management Agreement, dated February 24, 2011, between John D. Oil and Gas Marketing, LLC and Gas Natural Service Company
 
   
10.57*
  Asset Management Agreement, dated February 24, 2011, between John D. Oil and Gas Marketing, LLC and Gas Natural Service Company (relating to gas supplied to Northeast Ohio Natural Gas Corp.)
 
   
10.58*
  Asset Management Agreement, dated February 24, 2011, between John D. Oil and Gas Marketing, LLC and Gas Natural Service Company (relating to gas supplied to Orwell Natural Gas Company)
 
   
10.59*
  Gas Sales Agreement (ID: JOHND2008 - Intrastate Sales - LDCs #1.1), dated July 1, 2008, as amended, between John D. Oil and Gas Marketing Co., LLC, Northeast Ohio Natural Gas Corp., Orwell Natural Gas Company and Brainard Gas Corp.
 
   
10.60
  Credit Agreement, dated July 3, 2008, by and between Northeast Ohio Natural Gas Corp., as borrower and Citizens Bank, as lender, filed as Exhibit 10.20 to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference
 
   
10.61
  Term Note, dated July 3, 2008, by Northeast Ohio Natural Gas Corp., as maker, to Citizens Bank, as holder, filed as Exhibit 10.22 to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference
 
   
10.62
  Security Agreement, dated July 3, 2008, by Northeast Ohio Natural Gas Corp. in favor of Citizens Bank, filed as Exhibit 10.23 to the Registrant’s Current Report on Form 8-K dated January 5, 2010 and incorporated herein by reference
 
   
14
  Code of Business Conduct, filed as Exhibit 14 to the Registrant’s Annual Report on 10-K for the year ended June 30, 2006 and incorporated herein by reference
 
   
21*
  Company Subsidiaries
 
   
23.1*
  Consent of Hein & Associates LLP
 
   
31*
  Certifications pursuant to SEC Release No. 33-8238, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
   
32*
  Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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  Management agreement or compensatory plan or arrangement
 
*   Filed herewith
(c)   Financial Statement Schedules:
Schedule II
Valuation and Qualifying Accounts
Gas Natural Inc.
December 31, 2010
                                         
    Balance at             Charged to     Write-Offs     Balance  
    Beginning     Balances     Costs &     Net of     at End of  
Description   of Period     Acquired     Expenses     Recoveries     Period  
Allowance for bad debts
                                       
 
                                       
Year Ended December 31, 2009
  $ 207,942        —     $ 139,512     $ (114,122 )   $ 233,332  
Year Ended December 31, 2010
  $ 233,332     $ 103,169     $ 484,824     $ (466,609 )   $ 354,719  
All other schedules are omitted because they are not applicable or the required information is shown in the financial statements or notes thereto.

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SIGNATURES
Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
         
  GAS NATURAL INC.
 
 
  /s/ Richard M. Osborne    
  Richard M. Osborne   
  Chief Executive Officer
(principal executive officer) 
 
 
Date: April 4, 2011
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.
         
/s/ Richard M. Osborne
 
Richard M. Osborne
  Chief Executive Officer
(Principal Executive Officer)
  April 4, 2011
 
       
/s/ Thomas J. Smith
 
Thomas J. Smith
  Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)   April 4, 2011
 
       
/s/ W.E. Argo
 
W.E. Argo
  Director    April 4, 2011
 
       
/s/ Nicholas U. Fedeli
 
Nicholas U. Fedeli
  Director    April 4, 2011
 
       
/s/ John R. Male
 
John R. Male
  Director    April 4, 2011
 
       
/s/ Michael T. Victor
 
Michael T. Victor
  Director    April 4, 2011
 
       
/s/ Wade F. Brooksby
 
Wade F. Brooksby
  Director    April 4, 2011
 
       
/s/ Gregory J. Osborne
 
Gregory J. Osborne
  Director    April 4, 2011

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CONSOLIDATED FINANCIAL STATEMENTS OF
GAS NATURAL INC. AND SUBSIDIARIES
TABLE OF CONTENTS

 


Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
Gas Natural Inc.
We have audited the accompanying consolidated balance sheets of Gas Natural Inc. and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of income, stockholders’ equity and comprehensive income, and cash flows for the years then ended. Our audits also included the financial statement schedule as of and for the years ended December 31, 2010 and 2009 of Gas Natural Inc. listed in the index as Item 15(c). 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 Gas Natural Inc. and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for the years then ended 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.
HEIN & ASSOCIATES LLP
Denver, Colorado
April 4, 2011

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Table of Contents

Gas Natural Inc. and Subsidiaries
Consolidated Balance Sheets
                 
    December 31,     December 31,  
    2010     2009  
ASSETS
               
CURRENT ASSETS
               
Cash and cash equivalents
  $ 13,026,585     $ 2,752,168  
Marketable securities
    274,950       4,411,171  
Accounts receivable
               
Trade, less allowance for doubtful accounts of $354,719 and $233,332, respectively
    9,610,738       7,579,974  
Related party
    542,486          
Unbilled gas
    5,724,346       2,869,826  
Note receivable-related parties-current portion
    9,565        
Inventory
               
Natural gas and propane
    5,876,710       5,251,942  
Materials and supplies
    1,414,367       1,018,673  
Prepaid income taxes
    1,601,798        
Prepayments and other
    912,959       552,641  
Recoverable cost of gas purchases
    2,628,824       641,755  
Deferred tax asset
    114,362       562,936  
 
           
Total current assets
    41,737,690       25,641,086  
 
               
PROPERTY, PLANT AND EQUIPMENT, net
    76,134,401       41,203,668  
 
               
OTHER ASSETS
               
Notes receivable — related parties, less current portion
    45,665        
Deferred tax assets, less current portion
    1,804,264       7,550,970  
Deferred charges
    1,875,357       2,094,468  
Goodwill
    14,607,952       1,056,771  
Customer relationships
    662,167        
Investment in unconsolidated affiliate
    640,216       784,363  
Other
    220,224       294,356  
 
           
Total other assets
    19,855,845       11,780,928  
 
           
 
               
TOTAL ASSETS
  $ 137,727,936     $ 78,625,682  
 
           
The accompanying notes are an integral part of these consolidated financial statements.

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Gas Natural Inc. and Subsidiaries
Consolidated Balance Sheets
                 
    December 31,     December 31,  
    2010     2009  
LIABILITIES AND STOCKHOLDERS’ EQUITY
               
CURRENT LIABILITIES
               
Checks in excess of amounts on deposit
    532,145       663,777  
Line of credit
    18,149,999       14,650,000  
Accounts payable
               
Trade
    9,200,297       5,530,645  
Related party accounts payable
    417,543        
Notes payable, current portion
    910,917       1,265  
Notes payable — related parties, current portion
    49,361        
Accrued income taxes
          534,710  
Accrued and other current liabilities
    8,039,612       4,594,883  
Accrued liabilities, related parties
    413,399        
Over-recovered gas purchases
    1,203,191       1,452,580  
 
           
Total current liabilities
    38,916,464       27,427,860  
 
               
LONG-TERM LIABILITIES
               
Deferred investment tax credits
    197,441       218,503  
Notes payable, less current portion
    21,958,616       13,003,416  
Other long-term liabilities
    2,953,913       2,288,095  
 
           
Total long-term liabilities
    25,109,970       15,510,014  
 
               
Total liabilities
    64,026,434       42,937,874  
 
           
 
               
COMMITMENTS AND CONTINGENCIES (NOTE 15)
           
 
               
STOCKHOLDERS’ EQUITY
               
Preferred stock; $.15 par value, 1,500,000 shares authorized, no shares outstanding
           
Common stock; $.15 par value, 15,000,000 shares authorized, 8,149,801 and 4,361,869 shares outstanding, respectively
    1,222,470       654,280  
Capital in excess of par value
    41,910,067       6,514,851  
Capital in excess of par value — non-controlling interest
          100,989  
Accumulated other comprehensive income
    46,590       146,701  
Retained earnings
    30,522,375       28,270,987  
 
           
Total stockholders’ equity
    73,701,502       35,687,808  
 
           
 
               
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
  $ 137,727,936     $ 78,625,682  
 
           
The accompanying notes are an integral part of these consolidated financial statements.

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Gas Natural Inc. and Subsidiaries
Consolidated Statements of Income
                 
    For the Year Ended December 31,  
    2010     2009  
REVENUES
               
Natural gas operations
  $ 83,607,356     $ 58,765,618  
Marketing and production
    7,466,057       12,238,906  
Pipeline operations
    426,644       449,757  
 
           
Total revenues
    91,500,057       71,454,281  
 
               
COST OF SALES
               
Gas purchased
    48,876,837       37,051,852  
Marketing and production
    5,829,103       9,647,693  
 
           
Total cost of sales
    54,705,940       46,699,545  
 
           
 
               
GROSS MARGIN
    36,794,117       24,754,736  
 
               
GENERAL AND ADMINISTRATIVE EXPENSES
               
Distribution, general, and administrative
    17,381,468       10,562,069  
Maintenance
    1,051,766       666,477  
Depreciation and amortization
    4,119,381       2,212,553  
Taxes other than income
    3,162,200       2,250,298  
 
           
Total general and administrative expenses
    25,714,815       15,691,397  
 
           
 
               
INCOME FROM OPERATIONS
    11,079,302       9,063,339  
 
               
LOSS FROM INVESTMENT IN UNCONSOLIDATED AFFILIATE
    (193,951 )     (686,771 )
OTHER INCOME (EXPENSE)
    578,368       (289,563 )
INTEREST (EXPENSE)
    (2,178,222 )     (1,241,226 )
 
           
 
               
INCOME FROM OPERATIONS BEFORE INCOME TAXES
    9,285,497       6,845,779  
 
               
INCOME TAX EXPENSE
    3,488,996       27,242  
 
           
 
               
NET INCOME
  $ 5,796,501     $ 6,818,537  
 
           
 
               
EARNINGS PER SHARE — BASIC
  $ 0.92     $ 1.58  
 
               
EARNINGS PER SHARE — DILUTED
  $ 0.92     $ 1.58  
 
               
DIVIDENDS DECLARED PER SHARE
  $ 0.56     $ 0.55  
 
               
WEIGHTED AVERAGE SHARES OUTSTANDING — BASIC
    6,292,717       4,309,852  
 
               
WEIGHTED AVERAGE SHARES OUTSTANDING — DILUTED
    6,300,972       4,313,098  

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Gas Natural Inc. and Subsidiaries
Consolidated Statements of Changes in Stockholders’ Equity and Comprehensive Income
                                                                         
                                            Other                    
                                    Capital In     Compre -     Non-              
    Common     Treasury     Excess Of     hensive     Controlling     Retained        
    Shares     Stock     Shares     Stock     Par Value     Income (Loss)     Interest     Earnings     Total  
BALANCE AT DECEMBER 31, 2008
    4,296,603     $ 652,503       53,416     $ (8,012 )   $ 5,926,028     $ (319,147 )   $     $ 23,830,766     $ 30,082,138  
 
                                                                       
Comprehensive Income:
                                                                       
Net income
                                              6,818,537       6,818,537  
Net unrealized gains on available for sale securities
                                  465,848                   465,848  
Total Comprehensive Income
                                                    7,284,385  
Stock based compensation
    8,366       1,255                   98,345                         99,600  
Reissue treasury stock
    53,416             (53,416 )     8,012       (8,012 )                        
Cut Bank acquisition
    3,484       522                   498,490             100,989             600,001  
Dividends declared
                                              (2,378,316 )     (2,378,316 )
 
                                                     
 
                                                                       
BALANCE AT DECEMBER 31, 2009
    4,361,869       654,280                   6,514,851       146,701       100,989       28,270,987       35,687,808  
 
                                                                       
Comprehensive Income:
                                                                       
Net income
                                              5,796,501       5,796,501  
Net unrealized losses on available for sale securities
                                  (100,111 )                 (100,111 )
Total Comprehensive Income
                                                    5,696,390  
Stock based compensation
    5,624       844                   82,492                         83,336  
Equity Offering, net of offering costs of $598,014
    2,075,000       311,250                   18,495,736                         18,806,986  
Acquisition of Ohio Companies
    1,707,308       256,096                   16,816,988                         17,073,084  
Purchase of remaining shares in Cut Bank Gas Company
                                        (100,989 )           (100,989 )
Dividends declared
                                              (3,545,113 )     (3,545,113 )
 
                                                     
 
                                                                       
BALANCE AT DECEMBER 31, 2010
    8,149,801     $ 1,222,470           $     $ 41,910,067     $ 46,590     $     $ 30,522,375     $ 73,701,502  
 
                                                     

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GAS NATURAL INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
                 
    For the year ended  
    December 31  
    2010     2009  
CASH FLOWS FROM OPERATING ACTIVITIES:
               
Net income
  $ 5,796,501     $ 6,818,537  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation, amortization, and accretion including deferred charges and financing costs
    4,119,381       2,583,322  
Stock-based compensation
    83,336       99,600  
Gain on sale of securities
    (159,520 )     (96,888 )
Investment tax credit
    (21,062 )     (21,062 )
Deferred income taxes
    2,426,479       (2,545,742 )
Impairment of other investments
          620,789  
Changes in assets and liabilities:
               
Accounts receivable and unbilled gas
    2,671,102       1,938,979  
Accounts and notes receivable — related parties
    309,236      
Natural gas and propane inventories
    6,810       4,641,344  
Accounts payable
    (4,213,097 )     (238,499 )
Accounts payable — related parties
    1,187,080      
Accrued liabilities — related parties
    413,399        
Recoverable/refundable cost of gas purchases
    (2,944,969 )     1,750,042  
Prepayments and other
    (94,112 )     (123,454 )
Equity in income of Kykuit — unconsolidated affiliate
    193,951       65,982  
Accrued interest — related parties
    (262,495 )      
Other assets
    32,250     314,051  
Other liabilities
    (2,817,364 )     493,998  
 
           
Net cash provided by operating activities
    6,726,906       16,300,999  
 
           
 
               
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Construction expenditures
    (8,522,517 )     (8,854,010 )
Purchase of available-for-sale securities
    (52,948 )     (1,392,275 )
Proceeds from sale of available-for-sale securities
    4,185,867       1,211,740  
Purchase of Cut Bank shares
    (100,989 )      
Purchase of Kidron investment
    (105,078 )      
Cash acquired in acquisitions
    144,203       48,020  
Other investments
    (62,581 )     (386,888 )
Customer advances received for construction
    149,184       (70,851 )
Change from contributions in aid of construction
    (59,536 )     259,090  
 
           
Net cash used in investing activities
    (4,424,395 )     (9,185,174 )
 
           
 
               
CASH FLOWS FROM FINANCING ACTIVITIES:
               
Proceeds from lines of credit
    20,800,000       19,550,000  
Repayment of notes payable and lines of credit
    (20,899,170 )     (22,645,000 )
Proceeds from other notes payable
    57,336        
Repayments of long-term debt
    (5,255,578 )      
Repayments of other short-term borrowings
          (54,967 )
Repayments of related party notes payable
    (2,086,167 )    
Net proceeds from the sale of Common Stock
    18,806,986       (17 )
Dividends paid
    (3,451,501 )     (2,279,202 )
 
           
Net cash provided by (used in) financing activities
    7,971,906       (5,429,186 )
 
           
 
               
NET INCREASE IN CASH AND CASH EQUIVALENTS
    10,274,417       1,686,639  
 
               
CASH AND CASH EQUIVALENTS:
               
Beginning of year
    2,752,168       1,065,529  
 
           
End of year
  $ 13,026,585     $ 2,752,168  
 
           
The accompanying notes are an integral part of these condensed financial statements.

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GAS NATURAL INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
                 
    For the year ended  
    December 31  
    2010     2009  
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
               
Cash paid for interest
  $ 2,029,757     $ 1,107,269  
Cash paid for income taxes
    1,678,896       1,053,830  
 
               
SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES
               
Shares issued to purchase Cut Bank Gas
          499,013  
Shares issued to purchase Ohio Companies
    17,073,084        
Construction expenditures included in accounts payable
    191,457       44,928  
Capitalized interest
    4,009       14,231  
Accrued dividends
    366,725       273,114  
The accompanying notes are an integral part of these condensed financial statements.

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Table of Contents

GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 — Summary of Business and Significant Accounting Policies
Nature of Business — Gas Natural Inc. (“GNI” or the “Company”) is the parent company of Energy West, Incorporated (“Energy West”), Lightning Pipeline Company, Inc. (“Lightning Pipeline”), Great Plains Natural Gas Company (“Great Plains”) and Brainard Gas Corp. (“Brainard”). Energy West is a natural gas utility with operations in Montana, Wyoming, North Carolina and Maine. Lightning Pipeline is a natural gas utility with operations in Ohio and Pennsylvania. Great Plains and Brainard, each is a natural gas utility with operations in Ohio. The Company was originally incorporated in Montana in 1909. The Company currently has four reporting segments:
         
 
  •     Natural Gas Operations   Annually distribute approximately 30 billion cubic feet of natural gas to approximately 63,500 customers through regulated utilities operating in Montana, Wyoming, Maine, North Carolina, Ohio and Pennsylvania. The Maine and North Carolina operations were acquired in 2007, while Cut Bank Gas in Montana was added in November 2009 and the Ohio and Pennsylvania operations were acquired in January 2010.
 
       
 
  •     Marketing and Production
      Operations (EWR)
  Annually market approximately 1.3 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 the subsidiary, Energy West Resources, Inc. (EWR). EWR owns an average 48% gross working interest (an average 42% net revenue interest) in 160 natural gas producing wells and gas gathering assets.
 
       
 
  •     Pipeline Operations (EWD)   The Shoshone interstate and Glacier gathering natural gas pipelines located in Montana and Wyoming are owned through the subsidiary Energy West Development, Inc. (EWD). Certain natural gas producing wells owned by the Company’s pipeline operations are being managed and reported under the marketing and production operations.
 
       
 
  •     Corporate and Other   Corporate and other encompasses the results of corporate acquisitions and other equity transactions. Included in corporate and other are costs associated with business development and acquisitions, dividend income and recognized gains from the sale of marketable securities.
Effective August 3, 2009, Energy West reorganized into a holding company organizational structure pursuant to an Agreement and Plan of Merger with, among others, Gas Natural 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.
On June 30, 2010, the shareholders approved the reincorporation of the Company from Montana to Ohio. The reincorporation was effectuated on July 9, 2010. The reincorporation effected a change in the legal domicile of the Company and other changes of a legal nature, but did not result in any change in the business nature, management personnel, operations or location of facilities. As part of the reincorporation, the Company changed its name to “Gas Natural Inc.” The common shares of stock continue to trade on the NYSE Amex Equities under the symbol “EGAS.”
Basis of Presentation — The Company follows accounting standards set by the Financial Accounting Standards Board (“FASB”). The FASB sets generally accepted accounting principles (“GAAP”) to ensure the Company consistently report the 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

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GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Standards Codification, sometimes referred to as the Codification or ASC. Prior FASB standards are no longer being issued in the previous format. Rules and interpretive releases of the United States Securities and Exchange Commission (“SEC”) under the authority of federal securities laws are also sources of authoritative GAAP for SEC registrants.
Principles of Consolidation — The consolidated financial statements also include the proportionate share of assets, liabilities, revenues, and expenses of certain producing natural gas properties. All intercompany transactions and accounts have been eliminated.
Use of Estimates — The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, 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, and in the determination of depreciable lives of utility plant. The deferred tax asset and valuation allowance 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.
Such estimates could change in the near term and could significantly impact the Company’s results of operations and financial position.
Credit Risk — The primary market areas are Montana, Wyoming, Ohio, Pennsylvania, North Carolina, and Maine. 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 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 rate-making 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 consolidated balance sheets (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 which are recorded as liabilities in the consolidated balance sheets (regulatory liabilities).
Cash and Cash Equivalents — The Company considers all highly liquid investments with original maturities of three months or less, at the date of acquisition, to be cash equivalents. The Company maintains, at various financial institutions, cash and equivalents which may exceed federally insurable limits and which may, at times, significantly exceed balance sheet amounts.
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 4 for discussion of fair value measurement.
Receivables — The accounts receivable are generated from sales and delivery of natural gas as measured by inputs from meter reading devices. Trade accounts receivable are carried at the expected net realizable value. There is risk associated with the collection of these receivables. As such, a provision is recorded for the receivables considered to be uncollectible. The provision- is based on management’s assessment of the collectability of specific customer accounts, the aging of the accounts receivable and historical write-off amounts. The underlying assumptions used for the provision can change from period to period and the provision could potentially cause a negative material impact to the income statement and working capital.

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GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Two of the Company’s utilities in Ohio, Orwell Natural Gas (“Orwell”) and Northeast Ohio Natural Gas (“NEO”) collect from their customers through rates an amount per Mcf billed to provide an allowance for doubtful accounts. As accounts are identified as uncollectible, they are written off against this allowance for doubtful accounts with no income statement impact. In effect, all bad debt expense is funded by the customer base. The total amount collected from customers and the amounts written off are reviewed annually by the Public Utility Commission of Ohio (“PUCO”) and the rate per Mcf is adjusted as necessary.
The Company’s bad debt expense for the years ended December 31, 2010 and 2009 was $150,293 and $142,042, respectively
Natural Gas Inventory — 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.
Recoverable/Refundable Costs of Gas Purchases — The Company accounts for purchased gas 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), the PUCO and the Pennsylvania Public Utility Commission (PaPUC). Purchased gas costs that are different from those provided for in present rates, and approved by the respective commission, 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 and are subject to periodic audits or other review processes.
During the year ended December 31, 2010, the PUCO conducted audits of NEO and Orwell of the rates as filed from September 2007 through August 2009 and January 2008 through June 2010, respectively. As of December 31, 2010, the PUCO had not completed the audits of NEO and Orwell. The PUCO did provide the preliminary audit findings noting NEO had not included approximately $1,050,000 of costs and Orwell included an excess of approximately $1,100,000 of costs in the filings under audit.
In accordance with ASC 980, Regulated Operations, the Company recorded an adjustment of $1,050,000 and ($1,100,000) in the Company’s consolidated statements of income for NEO and Orwell, respectively. These adjustments appear on the Company’s Consolidated Balance Sheet as part of “Recoverable cost of gas purchases” and “Over-recovered gas purchases”, respectively. When the PUCO concludes each audit, if the amounts are different than initially recorded, the Company will record an additional adjustment.
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.
EWR owns an interest in certain producing natural gas reserves on properties located in northern Montana. EWD also owns an 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 Company is not the operator of any of the natural gas producing wells on these properties and the Company is not regarded as having significant oil- and gas-producing activities as defined by ASC 932, Extractive Activities — Oil and Gas. Therefore, the disclosures defined in ASC 932 are not required to be included.
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.
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 not amortized, rather, the 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. The goodwill amounts in the consolidated balance sheets at December 31, 2010 and

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GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2009 relate to acquisition of the Ohio Companies on January 5, 2010 and the acquisition of Cut Bank Gas Company on November 2, 2009. The schedule below describes the activity and year-end balances for the years ended December 31,
                 
    2010     2009  
Balance, beginning of year
  $ 1,056,771     $  
Acquisition of Cut Bank Gas Company
          1,056,771  
Acquisition of Ohio Companies
    13,551,181          
Impairments
           
 
           
 
               
Balance, end of year
  $ 14,607,952     $ 1,056,771  
The Company’s impairment evaluations as of December 31, 2010 and 2009 did not indicate impairment of its goodwill.
Investment in Unconsolidated Affiliate — The marketing and production operations segment owns a 23.01% and 21.98% interest in Kykuit Resources, LLC, (“Kykuit”), a developer and operator of oil, natural gas and mineral leasehold estates located in Montana at December 31, 2010 and 2009, respectively.
The Company is accounting for the investment in Kykuit using the equity method. The total invested in Kykuit is approximately $1.56 million and $1.5 million, with a net investment after undistributed losses of approximately $640,000 and $782,000 at December 31, 2010 and 2009, respectively. The loss on the equity investment in Kykuit for the years ended December 31, 2010 and 2009 include an impairment charge of $0 and $687,000, respectively, due to the write-off of drilling costs related to dry holes.
Obligations to make additional investments in Kykuit are limited under the Kykuit operating agreement. The Company is entitled to cease further investments in Kykuit if, in reasonable discretion after the results of certain initial exploration activities are known, the Company deems the venture unworthy of further investments. At December 31, 2010, the Company is obligated to invest no more than an additional $1.4 million over the future life of the venture. Other investors in Kykuit include the chairman of the board, Richard M. Osborne (“Mr. Osborne”), and John D. Oil and Gas Company, a publicly held oil and gas exploration company, which is also the managing member of Kykuit. Also, Mr. Osborne is the chairman of the board and chief executive officer, Mr. Gregory J. Osborne, director, is president and Mr. Thomas J. Smith (“Mr. Smith”), chief financial officer, is a director of John D. Oil and Gas Company.
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, 2010 and 2009, management does not consider the value of any of its long-lived assets to be impaired.
Debt Issuance Costs — Debt issuance costs are fees and other direct incremental costs incurred by the Company in obtaining debt financing and are recognized as assets and are amortized using straight-line amortization as interest expense over the term of the related debt. The unamortized balance of debt issuance costs was $485,244 and $356,339 as of December 31, 2010 and 2009, respectively. Costs related to refinancing the debt in Ohio are included in the balance as of December 31, 2010. The amortization expense was $134,600 and $47,150 for the years ended December 31, 2010 and 2009, respectively.
Asset Retirement Obligations — The Company records the fair value of a liability for an asset retirement obligation (“ARO”) 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 consolidated balance sheets. The Company amortizes 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, 2010 and 2009, the Company has recorded a net asset of $172,909 and $214,531, and a related liability of $1,546,867, and $787,233, respectively.

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GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
Orwell and Brainard are the exceptions to this methodology. As a result of regulatory action by the PUCO related to prior depreciation audits, Orwell and Brainard accrue towards an estimated liability for removing gas mains, meter and regulator station equipment and service lines at the end of their useful lives. The liability is to be equal to a percent of the asset cost according to the following table:
                 
    Percent of Asset Cost  
    Orwell     Brainard  
Mains
    20 %     15 %
Meter/regulator stations
    10 %     10 %
Service lines
    75 %     75 %
The Company has no assets legally restricted for purposes of settling its asset retirement obligations. The schedule below is a reconciliation of the Company’s liability for the years ended December 31:
                 
    2010     2009  
Balance, beginning of year
  $ 787,233     $ 746,199  
Liabilities incurred or acquired
    631,340        
Liabilities settled
           
Accretion expense
    128,294       41,034  
 
           
 
               
Balance, end of year
  $ 1,546,867     $ 787,233  
 
           
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.
Stock-Based Compensation — The Company accounts for stock-based compensation arrangements by recognizing compensation costs for all stock-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 award on the date it was granted.
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 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:

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GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                 
    Years ended December 31,  
    2010     2009  
Net Income
  $ 5,796,501     $ 6,818,537  
Other comprehensive income
               
Change in unrealized gain/loss on available-for-sale securities, net of $62,621 and ($291,025) of income tax
    (100,111 )     465,848  
 
           
 
               
Comprehensive Income
  $ 5,696,390     $ 7,284,385  
 
           
Earnings Per Share — Net income per common share is computed by both the basic method, which uses the weighted average number of common shares outstanding, and the diluted method, which includes the dilutive common shares from stock options and other dilutive securities, as calculated using the treasury stock method.
                 
    December 31,  
    2010     2009  
Weighted average number of common shares outstanding used in the basic earnings per common share calculations
    6,292,717       4,309,852  
Dilutive effect of stock options
    8,255       3,246  
 
           
Weighted average number of common shares outstanding adjusted for effective of dilutive options and warrants
  6,300,972     4,313,098  
 
           
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.
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 for the years ended December 31, 2010 and 2009.
The Company recognizes interest and penalties related to unrecognized tax benefits in operating expense. As of December 31, 2010 and 2009, there were no unrecognized tax benefits nor interest or penalties accrued related to unrecognized tax benefits. For the years ended December 31, 2010 and 2009, the Company did not recognize interest or penalties.
The Company, or one or more of its subsidiaries, files income tax returns in the U.S. federal jurisdiction and various state jurisdictions. The tax years 2007 through 2009 for federal and state returns remain open to examination by the major taxing jurisdictions in which we operate.
Reclassifications — Certain reclassifications of prior year reported amounts have been made for comparative purposes. Such reclassifications had no effect on income.
New Accounting Pronouncements
Recently Adopted
ASU No. 2009-17, “Consolidations (Topic 810) Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities”
On January 1, 2010, the Company adopted new authoritative guidance under this ASU, which requires ongoing reassessments of whether an enterprise is the primary beneficiary of a variable interest entity. Additionally, this guidance requires enhanced disclosures that will provide users of financial statements with more transparent information about an enterprise’s involvement in variable interest entities. The adoption of this guidance did not have a material impact on the consolidated financial statements.
ASU No. 2010-06, “Fair Value Measurements and Disclosures (Topic 820) Improving Disclosures about Fair Value Measurements”
This ASU requires additional fair value disclosures including disclosing the amount of significant transfers in and out of Level 1 and 2 fair value measurements and to describe the reasons for the transfers. In addition, the guidance also requires

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GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
disclosures about gross purchases, sales, issuances and settlement activity in Level 3 fair value measurements. The Company has applied the disclosure requirements which did not have a material impact on the consolidated financial statements.
Recently Issued
ASU No. 2010-28, “Intangibles —Goodwill and Other (Topic 350) When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts”
This ASU modifies Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts. For those reporting units, an entity is required to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists. In determining whether it is more likely than not that a goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors indicating that an impairment may exist such as if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. This ASU is not expected to have a material impact on the consolidated financial statements.
ASU No. 2010-29, “Business Combinations (Topic 805) Disclosure of Supplementary Pro Forma Information for Business Combinations”
This ASU provides clarification regarding the acquisition date that should be used for reporting pro forma financial information disclosures required by Topic 805 when comparative financial statements are presented. This ASU also requires entities to provide a description of the nature and amount of material, nonrecurring pro forma adjustments that are directly attributable to the business combination. This ASU is effective for the Company prospectively for business combinations occurring after December 31, 2010. This ASU is not expected to have a material impact on the consolidated financial statements.
ASU No. 2011-01, “Deferral of the Effective Date of Disclosures about Troubled Debt Restructurings in Update No. 2010-20”
In January 2011, the FASB issued ASU 2011-01, which temporarily delays the effective date of the disclosures about troubled debt restructurings in ASU 2010-20. The delay is intended to allow the FASB time to complete its deliberations on what constitutes a troubled debt restructuring. The effective date of the new disclosures about troubled debt restructurings for public entities and the guidance for determining what constitutes a troubled debt restructuring will then be coordinated. Currently, that guidance is anticipated to be effective for interim and annual periods ending after June 15, 2011. This ASU is not expected to have a material impact on the consolidated financial statements.
Note 2 — Acquisitions
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. During 2010 we completed the purchase of the remaining shares of Cut Bank Gas from the shareholders that owned the other 16.84% and now own 100% of the 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 the consolidated statements of income.
On January 5, 2010, the Company completed the acquisition of Lightning Pipeline, Great Plains, Brainard and Great Plains Land Development Co., LTD. (“GPL”) and collectively with Lightning Pipeline, Great Plains and Brainard, the “Ohio Companies” and each an “Ohio Company”. Lightning Pipeline is the parent company of Orwell and Great Plains is the parent company of NEO. Orwell, NEO and Brainard are natural gas distribution companies that serve approximately 24,000 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.

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GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Merger Agreements — As previously reported in Form 8-K filed on July 2, 2009 with the SEC, Energy West, now a wholly-owned subsidiary of the Company, entered into an Agreement and Plan of Merger (the “Merger Agreement”) on June 29, 2009 with Mr. Osborne, as Trustee of the Richard M. Osborne Trust (the “RMO Trust”), Rebecca Howell, Stephen M. Rigo, Marty Whelan, and Mr. Smith (Messrs. Osborne, Rigo, Whelan and Smith and Ms. Howell are hereinafter collectively referred to as “Shareholders”), Lightning Pipeline, Great Plains, Brainard 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 the chief financial officer, and Ms. Howell is the corporate secretary. As previously reported in Form 8-K filed on August 4, 2009 with the SEC, the Company 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 the Energy West 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 — 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 Brainard 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 = 2,231multiplied 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, the Company issued 1,707,308 Shares in the aggregate. The Company 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 owned 2,487,972 Shares, or 41.0% of the Company, Mr. Smith owned 86,744 Shares, or 1.4% of the Company and Ms. Howell owned 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 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.

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GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                                 
    Total                      
    Ohio             Lightning        
    Companies     Great Plains     Pipeline     Brainard  
Current assets
  $ 11,475,899     $ 7,343,431     $ 4,012,843     $ 119,625  
Property and equipment
    29,530,636       18,290,612       10,818,923       421,101  
Deferred Tax Assets
    76,772             11,535       65,237  
Other Noncurrent assets
    152,585       1,000       140,002       11,583  
Customer Relationships
    685,000       640,000       45,000        
Goodwill
    13,551,181       9,112,901       4,312,007       126,273  
 
                       
 
                               
Total assets acquired
    55,472,073       35,387,944       19,340,310       743,819  
 
                       
 
                               
Current liabilities
    13,836,123       7,589,554       5,842,518       404,051  
Asset Retirement Obligation
    487,447             477,939       9,508  
Deferred Tax Liability
    3,279,164       1,483,525       1,651,769       143,870  
 
                       
Total liabilities assumed
    17,602,734       9,073,079       7,972,226       557,429  
 
                       
 
                               
Net assets acquired:
  $ 37,869,339     $ 26,314,865     $ 11,368,084     $ 186,390  
 
                       
Approximately $13.6 million of the total purchase price was allocated to goodwill. None of the goodwill is expected to be deductible for tax purposes. Transaction costs related to the mergers totaled $136,346 and $487,889 for the years ended December 31, 2010 and 2009, respectively, and are recorded in the consolidated statements of income within the other income (expense).
The following table summarizes unaudited pro forma results of operations (in thousands) for the year ended December 31, 2009 as if the acquisitions had occurred on January 1, 2009. 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 year ended December 31, 2009, 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. The results of operations for the Ohio companies for the period from January 1, 2010 to January 4, 2010 were not material.
         
    Year Ended  
    December 31,  
    2009  
    (in thousands)  
Revenues
  $ 102,708  
 
       
Operating income
    11,918  
 
       
Net income
    8,403  
 
       
Earnings per share — basic
  $ 1.400  
 
       
Earnings per share — diluted
  $ 1.400  
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.

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GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 3 — 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 bought expressly for the purpose of selling in the near term are classified as trading securities and are measured at fair value with unrealized gains and losses reported in earnings. 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 marketable securities in the consolidated balance sheets, with the change in fair value during the period excluded from earnings and recorded net of tax as a component of other comprehensive income. Realized gains and losses, and declines in value judged to be other than temporary, are in the consolidated statements of income. The Company did not hold any held-to-maturity or trading securities as of December 31, 2010 and 2009. The Company did not realize any other than temporary declines for the years ended December 31, 2010 and 2009.
The following is a summary of available-for-sale securities at:
                         
    December 31, 2010  
    Investment     Unrealized     Estimated  
    at cost     Gains     Fair Value  
Common Stock
  $ 199,500     $ 75,450     $ 274,950  
 
                 
                         
    December 31, 2009  
    Investment     Unrealized     Estimated  
    at cost     Losses     Fair Value  
Common Stock
  $ 4,172,899     $ 238,272     $ 4,411,171  
 
                 
For the years ending December 31, 2010 and 2009, unrealized gains on available-for-sale securities of $46,590 and $146,701, respectively (net of $28,132 and $91,571 in taxes, respectively.
The gross realized gains are summarized below:
                         
                    Gross  
Years Ended   Sales             Realized  
December 31,   Proceeds     Cost     Gains  
2010
  $ 4,185,867     $ 4,026,347     $ 159,520  
2009
  $ 1,211,735     $ 1,114,846     $ 96,889  
As of December 31, 2010 and 2009, the Company did not hold any securities in an unrealized loss position. The Company did not realize any other than temporary declines for the years ended December 31, 2010 and 2009.
Note 4 — 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.

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GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 identical assets or liabilities (Level 1 inputs) and the lowest priority to unobservable inputs (Level 3 inputs).
The following tables represent the Company’s fair value hierarchy for its financial assets measured at fair value on a recurring basis as of:
                                 
    December 31, 2010  
    Level 1     Level 2     Level 3     TOTAL  
Available-for-sale securities
  $ 274,950                 $ 274,950  
 
                       
                                 
    December 31, 2009  
    Level 1     Level 2     Level 3     TOTAL  
Available-for-sale securities
  $ 4,411,171                 $ 4,411,171  
 
                       
Note 5 — Property, Plant and Equipment
Property, plant and equipment consist of the following as of December 31:
                 
    2010     2009  
Gas transmission and distribution facilities
  $ 89,094,495     $ 56,346,112  
Land
    1,663,759       164,903  
Buildings and leasehold improvements
    4,775,954       2,967,108  
Transportation equipment
    2,104,664       1,985,805  
Computer equipment
    3,408,189       3,165,260  
Other equipment
    5,457,504       3,984,996  
Construction work-in-progress
    3,260,004       2,639,507  
Producing natural gas properties
    3,911,404       3,911,404  
 
           
Gross Assets
  $ 113,675,973     $ 75,165,095  
 
               
Accumulated depreciation, depletion, and amortization
    (37,541,572 )     (33,961,427 )
 
           
 
               
Total Property, Plant and Equipment, net
  $ 76,134,401     $ 41,203,668  
 
           
Property, plant and equipment includes contributions in aid of construction of $1,618,011 and $1,677,549, at December 31, 2010 and 2009, respectively
Producing Natural Gas Properties
In order to provide a stable source of natural gas for a portion of its requirements, EWR and EWD own two natural gas production properties and three gathering systems located in north central Montana. The Company is depleting the cost of

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
the gas properties using the units-of-production method. As of December 31, 2010 and 2009, management of the Company estimated the net gas reserves at 2.4 and 2.3 Bcf (unaudited) and $3,069,000 and $2,940,000 of net present value after applying a 10% discount (unaudited), considering reserve estimates provided by an independent reservoir engineer, respectively. The net book value of the gas properties totals $1,705,360 and $1,746,982, at December 31, 2010 and 2009, respectively.
The wells are depleted based upon production at approximately 11% per and 10% per year as of December 31, 2010 and 2009, respectively. For the years ended December 31, 2010 and 2009, EWR’s portion of the daily gas production was 496 Mcf and 412 Mcf per day, or 17.4% and 13.1% of EWR’s volume requirements, respectively.
EWD owns working interests in a group of approximately 50 producing natural gas properties and a 75% ownership interest in a gathering system located in northern Montana. For the years ended December 31, 2010 and 2009, EWD’s portion of the daily gas production was 167 Mcf and 162 Mcf per day, or 5.8% and 5.1% of EWR’s volume requirements, respectively.
For the years ended December 31, 2010 and 2009, EWR and EWD’s combined portion of the estimated daily gas production from the reserves was 663 Mcf and 574 Mcf, or 23.2% and 18.2% of our volume requirements in our Montana market, respectively. The wells are operated by an independent third party operator who also has an ownership interest in the properties.
Note 6 — Deferred Charges
Deferred charges consist of the following as of December 31:
                 
    2010     2009  
Regulatory asset for property tax
  $ 873,197     $ 1,247,993  
Regulatory asset for income taxes
    452,645       452,646  
Regulatory assets for deferred environmental remediation costs
          22,042  
Rate case costs
    64,271       15,448  
Unamortized debt issue costs
    485,244       356,339  
 
           
 
               
Total
  $ 1,875,357     $ 2,094,468  
 
           
Regulatory assets will be recovered over a period of approximately seven to twenty years.
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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 7 — Accrued and Other Current Liabilities
Accrued and other current liabilities consist of the following as of December 31:
                 
    2010     2009  
Property tax settlement, current portion
  $ 242,120     $ 242,120  
Payable to employee benefit plans
    103,257       81,045  
Accrued vacation
    86,194       55,416  
Customer deposits
    679,237       521,535  
Accrued interest
    29,810       31,900  
Accrued taxes other than income
    2,961,853       640,801  
Deferred payments from levelized billing
    2,916,408       2,176,671  
Other regulatory liabilities
    18,272       59,996  
Other
    1,002,462       785,399  
 
           
 
               
Total
  $ 8,039,613     $ 4,594,883  
 
           
Note 8 — Other Long-Term Liabilities
Other long-term liabilities consist of the following as of December 31:
                 
    2010     2009  
Asset retirement obligation
  $ 1,546,867     $ 787,233  
Customer advances for construction
    949,434       800,250  
Regulatory liability for income taxes
    83,161       83,161  
Regulatory liability for gas costs
    131,443       131,443  
Property tax settlement
    243,008       486,008  
 
           
 
               
Total
  $ 2,953,913     $ 2,288,095  
 
           
Note 9 — Credit Facilities and Long-Term Debt
Bank of America
The Company has a $20,000,000 revolving credit facility that includes an annual commitment fee equal to 0.20% of the unused portion of the facility and interest on amounts outstanding at the monthly London Interbank Offered Rate (LIBOR) plus 120 to 145 basis points for interest periods selected by the Company. For the years ended December 31, 2010 and 2009, the weighted average interest rate on the facility was 2.29% and 3.25%, respectively, resulting in $241,625 and $264,866 of interest expense, respectively. The balance on the revolving credit facility was $18,150,000 and $14,650,000 at December 31, 2010 and 2009, respectively.
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 existing notes. Approximately

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
$463,000 was incurred related to the debt issuance which was capitalized and are being amortized over the life of the note using the effective interest method. Interest expense was $800,800 and $800,800 for the years ended December 31, 2010 and 2009, respectively.
Citizens Bank
In connection with the acquisition of the Ohio Companies, NEO, Great Plains and GPL each entered modifications/amendments to its credit facility with Citizens Bank (the “Citizens Credit Facility”). The Citizens Credit Facility consisted 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. Gas Natural Inc. guarantees each loan. Mr. 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.
NEO’s, Great Plains’ and GPL’s term loans with Citizens Bank are in the amounts of $7.8 million, $2.65 million and $892,000 respectively. Each term note has a maturity date of July 1, 2013 and bears interest at an annual rate of 30-day LIBOR plus 400 basis points with an interest rate floor of 5.00% per annum. For the year ended December 31, 2010 the weighted average interest rate on the term loans was 5%, resulting in $479,384 of interest expense.
NEO’s revolving credit line with Citizens Bank matured on November 29, 2010 and was repaid and extinguished at that time. NEO does not have the ability to redraw on that facility and is awaiting approval by the PUCO of a pending financing application. For the year ended December 31, 2010, the weighted average interest rate on the revolving credit line was 5%, resulting in $97,862 of interest expense.
At December 31, 2010, $6.6 million has been borrowed under the NEO term loan, $2.2 million under the Great Plains term loan, and $753,000 under the GPL term loan.
Huntington Bank
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 amended and restated the previous credit facility that matured on November 30, 2009. The loan was secured by all of the assets of Orwell. The Huntington Credit Facility was guaranteed by Gas Natural Inc., Lightning Pipeline, Mr. Osborne individually and as Trustee of the RMO Trust, and certain entities owned and controlled by Mr. Osborne. The Huntington Credit Facility was also secured by a pledge of $3.0 million in market value of Gas Natural Inc. stock by the RMO Trust.
The Huntington Line of Credit and Term Loan both had a maturity date of November 28, 2010. Orwell repaid and extinguished these debt obligations at that time.
For the year ended December 31, 2010, the weighted average interest rate on the term note was 4%, resulting in $166,344 of interest expense. The weighted average interest rate on the credit line was 4%, resulting in $59,424 of interest expense.
Combined Term Loans and Credit Facilities
The $18.2 million of borrowings at December 31, 2010, leaves the borrowing capacity on our line of credit at $1.8 million.
The total amount outstanding under the Energy West long term debt obligations was approximately $13.0 million at December 31, 2010, with none being due within one year. Including the amounts related to the Ohio Companies, the total amount is approximately $22.9 million, with approximately $911,000 due within one year.
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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
The Citizens Credit Facility requires a minimum 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 a minimum tangible net worth equal to the sum of $1,815,000 plus 100% of net income less the pro-rata share of any dividend paid to Gas Natural Inc., measured on a quarterly basis beginning with the quarter ended December 31, 2009. The Citizens Credit Facility allows the payment of dividends to Gas Natural Inc. if the net worth (as defined in the Citizens loan documents) after payment of any dividends would not be less than $1,815,000 as positively increased by 100% of net income as of the end of each fiscal quarter and fiscal year.
For the years ended December 31, 2010 and 2009, the Company believes it was in compliance with the financial covenants under its debt agreements.
The following table shows our future minimum payments on long-term debt for the years ended December 31:
         
2011
  $ 910,917  
2012
    873,463  
2013
    8,075,078  
2014
    5,319  
2015
    4,756  
Thereafter
    13,000,000  
 
     
 
       
Total
  $ 22,869,533  
 
     
Long-term debt consists of the following as of December 31:
                 
    2010     2009  
GAS NATURAL
               
Bank of America — Senior unsecured notes
  $ 13,000,000     $ 13,000,000  
Auto and Equipment loans — various lenders
    320,079       4,681  
Citizens’ Bank Term Loan — Great Plains Land Development
    752,917        
Citizens’ Bank Term Loan — Great Plains Natural Gas
    2,231,835        
Citizens’ Bank Term Loan — Northeast Ohio
    6,564,702        
Less: Current portion
    (910,917 )     (1,265 )
 
           
 
               
Total
  $ 21,958,616     $ 13,003,416  
 
           
Note 10 — Stockholders’ Equity
The Company’s common stock trades on the NYSE Amex Equities (formerly known as the American Stock Exchange) under the symbol “EGAS.”
On February 13, 2007, the 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. The Company began this stock buyback on May 30, 2007. The stock repurchases included 217,500 shares from Mr. Mark Grossi, a former director. During the year ended December 31, 2009, shares repurchased in 2008 were reissued for the purchase of Cut Bank Gas. There was no share repurchase activity during the year ended December 31, 2010.
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 common stock to be issued to certain key employees. As of December 31, 2010 and 2009, there are 39,500 and 44,500 options outstanding, respectively, and the maximum number of shares available for future grants under this plan is 53,500 shares. Additionally, the 1992 Stock Option Plan (the “1992 Option Plan”), which expired in September 2002, provided for the issuance of up to 100,000 shares of 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, 110% 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.
The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                 
    For the years ended  
    December 31,  
    2010     2009  
Expected dividend rate
    5.13 %     5.24 %
Risk free interest rate
    2.71 %     3.39 %
Weighted average expected lives, in years
    10.00       8.33  
Price volatility
    26.91 %     42.23 %
Total intrinsic value of options exercised
  $     $  
Total cash received from options exercised
  $     $  
A summary of the status of the stock option plans as of December 31, 2010 and 2009 is presented below.
                         
            Weighted     Aggregate  
    Number of     Average     Intrinsic  
    Shares     Exercise Price     Value  
Outstanding December 31, 2008
    29,500     $ 9.10          
Granted
    15,000     $ 8.71          
Exercised
        $          
Expired
        $          
 
                   
 
                       
Outstanding December 31, 2009
    44,500     $ 8.52          
Granted
    10,000     $ 10.15          
Exercised
        $          
Expired
    (15,000 )   $ 9.93          
 
                   
 
                       
Outstanding December 31, 2010
    39,500     $ 8.40     $ 83,780  
 
                 
 
                       
Exerciseable December 31, 2010
    17,500     $ 8.23     $ 40,125  
 
                 
The weighted average fair value of options granted during the year ended December 31, 2010 and 2009 was $1.41 and $2.50, respectively. At December 31, 2010 and 2009, there was $31,824 and $40,356 of total unrecognized compensation cost related to stock-based compensation, respectively. That cost is expected to be recognized over a period of three years.
The following information applies to options outstanding at December 31, 2010:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                                                 
                            Weighted                
                            Average                
                    Weighted     Remaining             Weighted  
                    Average     Contractual             Average  
Grant   Exercise     Number     Exercise     Life     Number     Exercise  
Date   Price     Outstanding     Price     (Years)     Exercisable     Price  
1/6/2006
  $ 6.35       4,500     $ 6.35       0.01           $ 6.35  
12/1/2008
  $ 7.10       10,000     $ 7.10       7.92       7,500     $ 7.10  
6/3/2009
  $ 8.44       5,000     $ 8.44       3.42       2,500     $ 8.44  
12/1/2009
  $ 8.85       10,000     $ 8.85       8.92       5,000     $ 8.85  
12/1/2010
  $ 10.15       10,000     $ 10.15       9.92       2,500     $ 10.15  
 
                                           
 
            39,500                       17,500          
 
                                           
For the years ended December 31, 2010 and 2009, all stock options granted have an exercise price equal to the fair market value of the Company’s stock at the date of grant.
During the years ended December 31, 2010 and 2009, the Company recorded $22,631 and $27,143, respectively ($14,193 and $16,704, respectively, 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. For the years ended December 31, 2010 and 2009, 10,000 and 15,000 options were granted, respectively.
Note 11 — 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 years ended December 31, 2010 and 2009, were $218,169 and $175,940, 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 stock valued at $41,650 and $29,770 for the years ended December 31, 2010 and 2009, respectively. In addition, a portion of the 401k Plan consists of an Employee Stock Ownership Plan (“ESOP”) that covers most employees. The ESOP receives contributions of 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 the Company’s common stock. The Company made no contributions for the years ended December 31, 2010 or 2009.
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, the 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, 2010 and 2009, the value of plan assets is $212,678 and $273,181. The assets remaining in the trust will be used to fund the plan until these assets are exhausted.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 12 — Income Taxes
Significant components of our deferred tax assets and liabilities are as follows as of December 31:
                                 
    December 31,  
    2010     2009  
    Current     Long-Term     Current     Long-Term  
Deferred tax asset:
                               
Allowances for doubtful accounts
  $ 134,236     $     $ 84,150     $  
Contributions in aid of construction
          607,562             635,484  
Property, Plant and Equipment
            2,861,764             8,652,601  
Other nondeductible accruals
    30,172             38,071       37,153  
Recoverable purchase gas costs
    104,934             487,653        
Unrealized (loss) gain on securities held for sale
                (91,571 )      
Net operating loss (NOL) carryforwards
          2,929,738             3,243,317  
Other
    191,138       928,687       291,452       995,952  
 
                       
Total
  $ 460,480     $ 7,327,751     $ 809,755     $ 13,564,507  
 
                       
 
                               
Deferred tax liabilities:
                               
Recoverable purchase gas costs
  $ 317,539     $     $ 246,819     $  
Property tax liability
          331,377             450,594  
Unrealized loss on securities held for sale
    28,579                    
Amortization of intangibles
          79,639             113,545  
Other
          528,310             272,928  
 
                       
Total Deferred Tax Liabilities
  $ 346,118     $ 939,326     $ 246,819     $ 837,067  
 
                       
 
                               
Net deferred tax asset (liability)
  $ 114,362     $ 6,388,425     $ 562,936     $ 12,727,440  
Less: valuation allowance
          (4,584,161 )           (5,176,470 )
 
                       
Net deferred tax asset (liability)
  $ 114,362     $ 1,804,264     $ 562,936     $ 7,550,970  
 
                       

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Income tax expense consists of the following for the years ended December 31:
                 
    2010     2009  
Current income taxes:
               
Federal
  $ 365,046     $ 2,218,263  
State
    94,150       392,196  
Total current income taxes
  $ 459,196     $ 2,610,459  
 
           
 
               
Deferred income taxes:
               
Federal
  $ 3,008,000     $ (2,100,967 )
State
    42,862       (461,188 )
Total deferred income taxes
  $ 3,050,862     $ (2,562,155 )
 
           
 
               
Total income taxes before credits
  $ 3,510,058     $ 48,304  
Investment tax credit, net
    (21,062 )     (21,062 )
 
           
 
               
Total income tax expense
  $ 3,488,996     $ 27,242  
 
           
Income tax expense differs from the amount computed by applying the federal statutory rate to pre-tax income for the following reasons for the years ended December 31:
                 
    2010     2009  
Tax expense at statutory rate of 34%
  $ 3,157,069     $ 2,327,565  
State income tax, net of federal tax benefit
    305,434       314,906  
Amortization of deferred investment tax credits
    (21,062 )     (21,062 )
Decrease in valuation allowance
    (626,618 )     (2,781,334 )
Other
    674,173       187,167  
 
           
 
               
Total
  $ 3,488,996     $ 27,242  
 
           
The Company has approximately $0.4 million federal net operating loss carryover as of December 31, 2010. The net operating losses begin to expire in 2024. Due to acquisitions, these net operating losses are subject to Section 382 of the Internal Revenue Code. The Company has approximately $71.9 million of state net operating loss carryover as of December 31, 2010. The Company has placed a state deferred tax asset valuation allowance of $2.5 million against the state net operating loss carryover. In addition, the Company has approximately $36.0 million of carryover tax basis as of December 31, 2010. The Company has placed a state deferred tax asset valuation allowance of $2.0 million on the carryover tax basis of the subsidiaries, since the carryover tax basis is subject to Section 382 of the Internal Revenue Code. Management has concluded that the realization of these state deferred tax assets do not meet the “more-likely-than-not” requirements of ASC 740.
During the year ended December 31, 2010, the net deferred tax assets decreased by $6.2 million. This decrease is comprised of a deferred income tax expense of $3.1 million, and $3.1 million related to the acquisition of the Ohio subsidiaries in January 2010. The valuation allowance decreased by $0.6 million related to changes in the effective tax rate on the acquired deferred tax assets of Frontier Utilities of North Carolina, Inc., and Penobscot Natural Gas Company.

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GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future results of operations, and tax planning strategies in making this assessment.
The Company adopted the applicable provisions of ASC 740 to recognize, measure, and disclose uncertain tax positions in the financial statements. Under ASC 740, tax positions must meet a “more-likely-than-not” recognition threshold at the effective date to be recognized upon the adoption and in subsequent periods. During the year ended December 31, 2010, no adjustments were recognized for uncertain tax benefits.
The Company recognizes interest and penalties related to uncertain tax positions in operating expense. No interest and penalties related to uncertain tax positions were accrued as of December 31, 2010.
The tax years 2007 through 2009 for federal and state returns remain open to examination by the major taxing jurisdictions in which we operate.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 13 – Related Party Transactions
As a result of the Ohio Companies acquisition, the Company is party to certain agreements and transactions with Mr. Osborne, or companies owned or controlled by Mr. Osborne. These transactions can be generally grouped into three categories as follows:
Notes Payable to Mr. Osborne
The Company has two notes payable to Mr. Osborne. The first note is payable on demand bears interest at a rate equal to the prime rate as published by Key Bank (3.25% as of December 31, 2010). The second note has a maturity date of January 3, 2014 and bears interest at 6.0% annually. Interest expense of $110,184 and $1,609, respectively were incurred for the year ended December 31, 2010. On December 1, 2010, the Company repaid the first note in full, including all interest accrued to date. As of December 31, 2010, the second note had a balance of $52,578, which included $3,217 of accrued interest.
Gas Supply, Pipeline Transport and Gas Sales
The table below details gas supply and transport related balances and transactions with companies owned or controlled by Mr. Osborne:
                 
            Natural Gas Purchased  
    Accounts     and Imbalance Activity  
    Payable     For the Year Ended  
    December 31, 2010     December 31, 2010  
John D. Oil and Gas Marketing
  $ 247,430     $ 4,432,412  
Cobra Pipeline
    84,597       438,429  
Orwell Trumbell Pipeline
    77,325       (411,640 )
Great Plains Exploration
          31,358  
The Company also accrued a liability of $413,399 due to companies controlled by Mr. Osborne for natural gas used through December 31, 2010 that is not yet invoiced. The related expense is included in the gas purchased line item in the consolidated statements of income. These amounts will be trued up to the actual invoices when received in future periods.
The table below details gas sales transactions and balances with companies owned or controlled by Mr. Osborne:
                 
    Accounts     Natural Gas Sold For  
    Receivable     the Year Ended  
    December 31, 2010     December 31, 2010  
John D. Oil and Gas Marketing
  $ 40,750     $ 49,824  
Great Plains Exploration
    110,732       1,953,052  

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GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Administrative and Other
The Company has a note receivable from John D. Oil and Gas Marketing, a company controlled by Mr. Osborne, with a maturity date of December 31, 2016 and an annual interest rate of 7.0% relating to funds loaned to John D. Oil and Gas Marketing to finance the acquisition of a gas pipeline. The balance due from John D. Oil and Gas Marketing was $55,230 (of which, $9,565 is due within one year) as of December 31, 2010. The Company has a corresponding agreement to lease the pipeline from John D. Oil and Gas Marketing through December 31, 2016. The Company made lease payments of $14,427 for the year ended December 31, 2010. There is no balance due at December 31, 2010 to John D. Oil and Gas Marketing related to these lease payments.
The Company purchased $1,098,713 of pipe and other construction supplies from Big Oats Pipeline Supply (“Big Oats”), a company controlled by Mr. Osborne, for the year ended December 31, 2010. The balance due to Big Oats was $4,723 as of December 31, 2010 for the purchase of these supplies.
The Company sold supplies and incurred other expenses of $4,010 on the behalf of Big Oats for the year ended December 31, 2010. The balance due from Big Oats was $4 as of December 31, 2010 related to these expenses.
The Company incurred expenses of $377,128 for rent, supplies, and consulting services received from various companies controlled by Mr. Osborne, for the year ended December 31, 2010. The balance payable due to the various companies was $3,468 as of December 31, 2010.
The Company provided management and other services of $363,972 to various companies controlled by Mr. Osborne, for the year ended December 31, 2010. The balance due from the various companies for these services was $391,000 as of December 31, 2010.

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GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 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, 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, Maine, Ohio and Pennsylvania and these businesses are aggregated together to form the natural gas operations. Transactions between reportable segments are accounted for on the accrual basis, and eliminated prior to external financial reporting. Inter-company 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:
Twelve Months Ended December 31, 2010
                                                 
            Marketing                          
    Natural Gas     and     Pipeline     Corporate and              
    Operations     Production     Operations     Other     Eliminations     Consolidated  
Operating Revenue
                                               
Natural Gas Operations
  $ 83,926,733     $     $     $     $ (319,377 )   $ 83,607,356  
Marketing and Production
          15,116,196                   (7,650,139 )     7,466,057  
Pipeline Operations
                426,644                   426,644  
 
                                   
 
                                               
Total Operating Revenue
  $ 83,926,733     $ 15,116,196     $ 426,644     $     $ (7,969,516 )   $ 91,500,057  
 
                                               
Gas Purchased
  $ 49,196,214     $     $     $     $ (319,377 )   $ 48,876,837  
Gas — Wholesale
          13,479,242                   (7,650,139 )     5,829,103  
Distribution, general, and administrative
    16,774,046       455,111       132,529       19,782             17,381,468  
Maintenance
    1,036,836       627       14,303                   1,051,766  
Depreciation and Amortization
    3,764,145       299,649       55,587                   4,119,381  
Taxes other than income
    3,106,991       24,285       27,641       3,283             3,162,200  
 
                                   
Operating expenses
  $ 73,878,232     $ 14,258,914     $ 230,060     $ 23,065     $ (7,969,516 )   $ 80,420,755  
 
                                   
 
                                               
Operating income (expense)
  $ 10,048,501     $ 857,282     $ 196,584     $ (23,065 )   $     $ 11,079,302  
 
                                               
Other income (expense)
    872,221       (635,328 )           196,659       (49,135 )     384,417  
 
                                               
Interest (expense) benefit
    (2,134,869 )     (67,070 )     (25,418 )           49,135       (2,178,222 )
 
                                   
 
                                               
Income from continuing operations
  $ 8,785,853     $ 154,884     $ 171,166     $ 173,594     $     $ 9,285,497  
 
                                               
Income taxes expense (benefit)
    3,161,630       39,280       18,383       269,703             3,488,996  
 
                                   
 
                                               
Net Income
  $ 5,624,223     $ 115,604     $ 152,783     $ (96,109 )   $     $ 5,796,501  
 
                                   
 
                                               
Capital expenditures and natural gas properties
  $ 8,489,529     $     $     $ 32,988     $     $ 8,522,517  
Total assets
  $ 118,954,130     $ 5,733,857     $ 705,817     $ 77,157,019     $ (64,822,887 )   $ 137,727,936  
Equity Method investments
  $     $ 640,216     $     $     $     $ 640,216  
Goodwill
  $ 14,607,952     $     $     $     $     $ 14,607,952  

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Table of Contents

GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Twelve Months Ended December 31, 2009
                                                 
            Marketing                          
    Natural Gas     and     Pipeline     Corporate and              
    Operations     Production     Operations     Other     Eliminations     Consolidated  
Operating Revenue
                                               
Natural Gas Operations
  $ 59,301,564     $     $     $     $ (535,946 )   $ 58,765,618  
Marketing and Wholesale
          19,656,795                   (7,417,889 )     12,238,906  
Pipeline Operations
                449,757                   449,757  
 
                                   
 
                                               
Total Operating Revenue
  $ 59,301,564     $ 19,656,795     $ 449,757     $     $ (7,953,835 )   $ 71,454,281  
 
                                               
Gas Purchased
  $ 37,587,798     $     $     $     $ (535,946 )   $ 37,051,852  
Gas — Wholesale
          17,065,582                   (7,417,889 )     9,647,693  
Distribution, general, and administrative
    9,942,220       526,305       85,573       7,971             10,562,069  
Maintenance
    654,281       641       11,555                   666,477  
Depreciation and Amortization
    1,865,941       290,872       55,740                   2,212,553  
Taxes other than income
    2,200,487       26,112       23,699                   2,250,298  
 
                                   
Operating expenses
  $ 52,250,727     $ 17,909,512     $ 176,567     $ 7,971     $ (7,953,835 )   $ 62,390,942  
 
                                   
 
                                               
Operating income (expense)
  $ 7,050,837     $ 1,747,283     $ 273,190     $ (7,971 )   $     $ 9,063,339  
 
                                               
Other income (expense)
    254,326       (686,771 )           (543,889 )           (976,334 )
 
                                               
Interest (expense)
    (1,134,858 )     (89,151 )     (16,841 )     (376 )           (1,241,226 )
 
                                   
 
                                               
Income (loss) from continuing operations
  $ 6,170,305     $ 971,361     $ 256,349     $ (552,236 )   $     $ 6,845,779  
 
                                               
Income taxes expense (benefit)
    2,281,053       413,017       100,115       (2,766,943 )           27,242  
 
                                   
 
                                               
Net Income
  $ 3,889,252     $ 558,344     $ 156,234     $ 2,214,707     $     $ 6,818,537  
 
                                   
 
                                               
Capital expenditures and natural gas properties
  $ 8,648,035     $ 191,608     $     $ 14,367     $     $ 8,854,010  
Total assets
  $ 62,610,159     $ 6,589,064     $ 733,070     $ 44,022,556     $ (35,329,167 )   $ 78,625,682  
Equity Method investments
  $     $ 784,363     $     $     $     $ 784,363  
Goodwill
  $ 1,056,771     $     $     $     $     $ 1,056,771  

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Table of Contents

GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 15 – Commitments and Contingencies
Commitments
In 2010, the Company’s long term contract with Northwestern Energy for pipeline and storage capacity expired and was replaced with a new contract. The new contract commits the Company to purchase certain blocks of pipeline capacity for terms of five years and eight years at the interconnect with the TransCanada pipeline. The Company has a companion contract with TransCanada for pipeline capacity of equal quantities and terms. Based on current tariff prices as specified in the contracts, the future obligations under these agreements at December 31, 2010 are as follows:
                 
    Northwestern        
    Energy     Trans-Canada  
2011
  $ 1,498,000     $ 920,000  
2012
    1,498,000       920,000  
2013
    1,498,000       920,000  
2014
    1,498,000       920,000  
2015
    1,498,000       828,000  
Thereafter
    1,331,000       1,073,000  
     
 
               
Total
  $ 8,821,000     $ 5,581,000  
     
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:
         
2011
  $ 500,874  
2012
    500,874  
2013
    500,874  
2014
    500,874  
2015
    500,874  
Thereafter
    1,091,600  
 
     
 
       
Total
  $ 3,595,970  
 
     
The Company also guarantees the gas supply obligations of its subsidiaries for up to $9.5 million of amounts purchased.
The Company’s marketing and production segment has several contracts to sell natural gas to customers at fixed prices that range from a low of $4.20 per dekatherm (Dkt) to a high of $5.65 per Dkt. Two of these contracts are for a term of three years with an approximate annual volume commitment of 331,000 Dkt. The remaining contracts have terms of less than one year, with a total approximate volume commitment of 86,000 Dkt.
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.

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GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 technical waiver, the U.S. Environmental Protection Agency (“EPA”) has developed such guidance. The EPA guidance lists factors which render remediation technically impracticable. The Company has filed a request for a waiver respecting compliance with certain standards with the MDEQ. As of December, 31, 20010 there has been no action on the waiver request by the MDEQ.
At December 31, 2010, the Company had incurred cumulative costs of approximately $2.1 million in connection with the evaluation and remediation of the site. On May 30, 1995, an order was received from the MPSC allowing for recovery of the costs associated with the evaluation and remediation of the site through a surcharge on customer bills. The Company is 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, the Company 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 was complete. No additional recovery has been requested and the recovery surcharge has been extinguished.
Litigation
We are involved in lawsuits that have arisen in the ordinary course of business. We are contesting each of these lawsuits vigorously and believe we have defenses to the allegations that have been made.
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.
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 for the years ended December 31:
         
2011
  $ 327,164  
2012
    268,743  
2013
    254,495  
2014
    253,151  
2015
    239,351  
Thereafter
    1,315,444  
 
     
 
  $ 2,658,348  
 
     
Lease expense resulting from operating leases for the years ended December 31, 2010 and 2009, totaled $405,839 and $238,869, respectively.
Note 16 – Financial Instruments and Risk Management
Management of Risks Related to Fixed Contracts
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

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GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, from time to time the Company and its subsidiaries have entered into fixed contracts. 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 these contracts in accordance with ASC 815, Derivatives and Hedging. In accordance with ASC 815, such contracts are reflected in the balance sheet as assets or 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. The changes in the derivative values are reported in the income statement as an increase or (decrease) in revenues without regard to whether any cash payments have been made between the parties to the contract. ASC 815 specifies 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.”
For the years ended December 31, 2010 and 2009, all of the Company’s fixed contracts for purchase or sale at fixed prices and volumes qualified for treatment as a “normal purchase or a normal sale.”
Note 17 – Quarterly Information (Unaudited)
Quarterly results (unaudited) for the years ended December 31, 2010 and 2009 are as follows (in thousands, except per share data):
Year Ended December 31, 2010
                                 
    For the quarters ended  
    March 31,     June 30,     September 30,     December 31,  
($ in thousands except per share amounts)   2010     2010     2010     2010  
Revenues
  $ 34,733     $ 16,656     $ 10,902     $ 29,209  
Gross margin
    12,521       7,274       5,718       11,281  
Operating income
    6,340       867       (556 )     4,429  
 
                               
Income (loss) before extraordinary items
  $ 3,663     $ 466     $ (45 )   $ 1,713  
Extraordinary gain
                       
Net income (loss)
  $ 3,663     $ 466     $ (45 )   $ 1,713  
 
                               
Basic earnings (loss) per common share
  $ 0.61     $ 0.08     $ (0.01 )   $ 0.24  
 
                               
Diluted earnings (loss) per share
  $ 0.61     $ 0.08     $ (0.01 )   $ 0.24  

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GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Year Ended December 31, 2009
                                 
    For the quarters ended  
    March 31,     June 30,     September 30,     December 31,  
($ in thousands except per share amounts)   2009     2009     2009     2009  
Revenues
  $ 31,334     $ 12,238     $ 8,326     $ 19,556  
Gross margin
    7,774       5,248       4,190       7,543  
Operating income
    3,564       1,523       245       3,731  
 
                               
Income (loss) before extraordinary items
  $ 1,963     $ 686     $ (172 )   $ 4,342  
Extraordinary gain
                       
Net income (loss)
  $ 1,963     $ 686     $ (172 )   $ 4,342  
 
                               
Basic earnings (loss) per common share
  $ 0.46     $ 0.16     $ (0.04 )   $ 1.00  
 
                               
Diluted earnings (loss) per share
  $ 0.46     $ 0.16     $ (0.04 )   $ 1.00  

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