UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
| [X] | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2013
or
| [ ] | 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 | | 27-3003768 |
(State or other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification No.) |
| | |
8500 Station Street, Suite 300 Mentor, Ohio | | 44060 |
| (Address of principal executive office) | | (Zip Code) |
Registrant’s telephone number, including area code:(800) 570-5688
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 MKT 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 [ ] No [X]
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 [ ] No [X]
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 [X] No [ ]
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 [X] No [ ]
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. [ ]
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.
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Large accelerated filer | | ¨ | | Accelerated filer | | ¨ |
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Non-accelerated filer | | ¨ (Do not check if a smaller reporting company) | | Smaller Reporting Company | | ü |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No ü
The aggregate market value of the registrant’s common stock held by non-affiliates as of June 30, 2013 was $73,575,528.
The number of shares outstanding of the registrant’s common stock as of March 14, 2014 was 10,451,678 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive proxy statement for the 2014 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 is this Form 10-K is as of December 31, 2013.
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.
8500 Station Street. 8500 Station Street, LLC.
AECO. Alberta Energy Company Limited (used in reference to the AECO natural gas price index).
ASC. Accounting Standard Codification, standards issued by FASB with respect to U.S. GAAP.
ASU. Accounting Standards Update.
Bangor Gas Company. Bangor Gas Company, LLC.
Bcf. One billion cubic feet, used in reference to natural gas.
Brainard. Brainard Gas Corp.
CIG. Colorado Interstate Gas (used in reference to the Colorado Interstate Gas Index).
Clarion River. Clarion River Gas Company.
CNG. Compressed Natural Gas.
Cut Bank Gas. Cut Bank Gas Company.
Dth. Abbreviation of dekatherm. One million British thermal units, used in reference to natural gas.
EBITDA. Earnings before interest, taxes, depreciation, and amortization.
Energy West Development. Energy West Development, Inc.
Energy West Montana. Energy West Montana, Inc.
Energy West Wyoming. Energy West Wyoming, Inc.
Energy West. Energy West, Incorporated.
EPA. The United States Environmental Protection Agency.
EWR. Energy West Resources, Inc.
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.
Gas Natural. Gas Natural Inc.
GCR. Gas cost recovery.
GNR. Gas Natural Resources , LLC.
GNSC. Gas Natural Service Company, LLC.
GPL. Great Plains Land Development Co., Ltd.
Great Plains. Great Plains Natural Gas Company.
IFRS. International Financial Reporting Standards.
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Independence. Independence Oil, LLC.
JDOG Marketing. John D. Oil and Gas Marketing Company, LLC.
KPSC. Kentucky Public Service Commission.
Kykuit. Kykuit Resources, LLC.
LIBOR. London Interbank Offered Rate.
Lightning Pipeline. Lightning Pipeline Company, Inc.
LNG. Liquefied Natural Gas.
Lone Wolfe. Lone Wolfe Insurance, LLC.
MHRA. Maine Human Rights Act.
MMcf. One million cubic feet, used in reference to natural gas.
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.
OCC. Ohio Consumers’ Counsel.
Orwell. Orwell Natural Gas Company.
Osborne Trust. The Richard M. Osborne Trust, dated February 24, 2012.
PaPUC. The Pennsylvania Public Utility Commission.
Penobscot Natural Gas. Penobscot Natural Gas Company, Inc.
PGC. Public Gas Company, Inc.
PUCO. The Public Utilities Commission of Ohio.
SEC. The United States Securities and Exchange Commission.
Spelman. Spelman Pipeline Holdings, LLC.
Sun Life. Sun Life Assurance Company of Canada
U.S. GAAP. Generally accepted accounting principles in the United States of America.
USPF. United States Power Fund, L.P.
Walker Gas. Walker Gas & Oil Company, Inc.
WPSC. The Wyoming Public Service Commission.
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TABLEOF CONTENTS
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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 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 such as the pending PUCO audit, |
| | • | | the impact of weather conditions and alternative energy sources on our sales volumes and the rate at which we can recover gas costs from our customers, |
| | • | | future utilization of pipeline capacity, which can depend on energy prices, competition from alternative fuels, the general level of natural gas demand, decisions by customers not to renew expiring supply 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, |
| | • | | the ability to develop expanded markets and product offerings and our ability to maintain existing markets, |
| | • | | the outcome of the shareholder derivative suits and other actions that have been brought against the Company; |
| | • | | the ability to maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act of 2002, and |
| | • | | the 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 Inc. is a natural gas company, primarily operating local distribution companies in seven states and serving approximately 72,000 customers in total. We report results in four primary business segments.
| | • | | Natural Gas Operations. Representing the majority of our revenue, we annually distribute approximately 36 Bcf of natural gas to approximately 72,000 customers through regulated utilities operating in Kentucky, Maine, Montana, North Carolina, Ohio, Pennsylvania and Wyoming. Our natural gas utility subsidiaries include Bangor Gas Company (Maine), Brainard (Ohio), Cut Bank Gas (Montana), Energy West (Montana and Wyoming), Frontier Natural Gas (North Carolina), NEO (Ohio), Orwell (Ohio and Pennsylvania), PGC (Kentucky). |
| | • | | Marketing and Production. Annually, we market approximately 1.5 Bcf of natural gas to commercial and industrial customers in Montana, Wyoming, Ohio, and Pennsylvania through our EWR and GNR subsidiaries. Our EWR subsidiary also manages midstream supply and production assets for transportation customers and utilities. EWR owns an average 51% gross working interest (average 43% net revenue interest) in 160 natural gas producing wells and gas gathering assets located in Glacier and Toole Counties in Montana. |
| | • | | Pipeline Operations. We own the Shoshone interstate and the Glacier gathering natural gas pipelines located in Montana and Wyoming through our subsidiary EWD. |
| | • | | Corporate and Other. Corporate and other encompasses the results of our corporate acquisitions, equity transactions and discontinued operations. Included in corporate and other are costs associated with business development and acquisitions, dividend income, recognized gains or losses from the sale of marketable securities, activity from Lone Wolfe which serves as an insurance agent for the Company and other businesses in the energy industry, and the results of the Company’s Independence subsidiary which was sold in November 2013. |
Energy West was originally incorporated in Montana in 1909 and was reorganized as a holding company in 2009 to facilitate future acquisitions and corporate-level financing to support our growth strategy. On July 9, 2010, we changed our name to Gas Natural Inc. and reincorporated from Montana to Ohio. Moving the incorporation to Ohio enhances our flexibility and provides a more efficient platform from which to operate and grow.
Recent Events
2013 Sale of Independence
In November 2013, we finalized the sale of our Independence subsidiary to Blue Ridge Energies, LLC. As part of the sale, we received $2.3 million in cash. SeeNote 4 – Discontinued Operations in the notes to our consolidated financial statements for more information regarding the sale.
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. However, new technology in drilling has expanded potential sources of natural gas, including shale gases, making natural gas an abundant, economic, cleaner burning 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. Because natural gas is cleaner burning than coal, we feel it will continue to be preferred for electric power generation and industrial applications. Additionally, given the clean burning attributes of natural gas, we believe environmental regulations may enhance this competitive outlook.
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Business Strategy
Our strategy is to grow our earnings and increase cash flow by providing energy sources to users in a safe and reliable manner by focusing on the following initiatives:
| | • | | Invest in our Utilities. We have and will continue to invest substantial capital and resources in our core utility operations in order to maintain our position as a respected natural gas utility and meet or exceed applicable regulatory requirements. 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 through capital improvements and expansion projects. These capital improvements and expansion projects add to our existing utilities and enable us to continue to build rate base throughout our service footprint and provide sufficient margins for an appropriate return on the capital investments. |
| | • | | 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 acquisition opportunities in new markets 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 Efficiencies. We strive to quickly and effectively respond to changing regulatory and public policy initiatives, leverage new technologies that will 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 our 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 assets related to our regulated utility operations. Approximately 89% of our 2013 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 our operations 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 six 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 acquisition 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 seven 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 provides us with the opportunity to increase our market penetration in various regions. Additionally, our customers represent a mix of residential, commercial, industrial, agricultural and transportation and no single customer represented more than 1.1% of our natural gas revenue for 2013. Our sales ratio to large commercial and industrial customers is not concentrated in one industry segment but varies across several industry segments, reflecting the diverse nature of the communities we serve. |
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Natural Gas Operations
Our natural gas operations are located in Kentucky, Maine, Montana, North Carolina, Ohio, Pennsylvania, and Wyoming. Our revenues from 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 regulates adequacy of service, issuance of securities, compliance with U.S. Department of Transportation safety regulations and other matters.
Kentucky
Our operations in Kentucky provide natural gas service to customers in Breathitt, Wolfe, Johnson, Lawrence, Lee, Morgan, and Magoffin counties through 49 miles of distribution pipe. Our rates are subject to a tariff governed by the KPSC. Our service area has a population of approximately 94,000 people. Our Kentucky operations provide service to approximately 1,700 residential and commercial customers. The primary firm gas supply marketer for Kentucky is Jefferson Gas, LLC.
Maine
Our operations in Maine provide natural gas service to customers in Bangor, Brewer, Bucksport, Old Town, Orono and Veazie through 10 miles of transmission pipeline and 217 miles of distribution system. This service area has a population of approximately 62,000 people. Our Maine operations provide service to approximately 4,500 residential, commercial and industrial customers. We offer transportation services to approximately 44 customers through special pricing contracts. These customers accounted for approximately 15.7% of the revenue of our Maine operations in 2013.
In Maine, our primary gas supply marketer 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 Repsol Energy North America Corporation. We review the gas supply agreement every two years.
Montana
Our operations in Montana provide natural gas service to customers in and around Great Falls, Cascade, West Yellowstone, and Cut Bank. The population of our service area is approximately 65,000 people. Our Montana operations provide service to approximately 31,000 customers.
The primary gas supply marketers for our Montana natural gas distribution operations are Jefferson Energy Trading and Tenaska Marketing Ventures.
Our Montana operations use the Northwestern Energy 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 one-year contract with Northwestern Energy that includes annual renewals.
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 47,000 people. The major communities in our North Carolina service area are Boone, Elkin, Mount Airy, Wilkesboro, Warrenton, West Jefferson and Yadkinville. Our North Carolina operations provide service to approximately 2,500 residential, commercial and transportation customers through 139 miles of transmission pipeline and 306 miles of distribution system. We offer transportation services to approximately 26 customers through special pricing contracts. These customers accounted for approximately 39.6% of the revenue of our North Carolina operations in 2013.
In North Carolina, our primary gas supply marketer is Twin Eagle. We receive our gas supply from the Transcontinental Gas Pipe Line Company transmission system. Our supply contract with Twin Eagle is a two year contract that provides 100% of our gas needs and will expire in 2014.
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Ohio and Pennsylvania
Our Ohio operations provide natural gas service to customers in Ashland, Ashtabula, Carroll, Columbiana, Coshocton, Cuyahoga, Fairfield, Franklin, Geauga, Guernsey, Harrison, Hocking, Holmes, Huron, Knox, Lake, Lorain, Mahoning, Medina, Portage, Richland, Stark, Summit, Trumbull, Tuscarawas, Washington, and Wayne counties. This service area has a population of approximately 5.9 million people. Our Pennsylvania operations provide natural gas service to customers in Armstrong, Butler, Clarion, Elk, Forest and Jefferson counties. This service area has a population of approximately 377,000 people. Together, our Ohio and Pennsylvania operations provide service to approximately 25,800 residential, commercial and industrial customers through approximately 1,284 miles of transmission and distribution pipelines.
Our Ohio and Pennsylvania utilities receive gas supply from various sources, including GNR, BP Energy, Compass Energy Gas Services LLC, Constellation Energy, Exelon Energy Company, Mid-American Natural Resources, and Sequent Energy Management. We transport natural gas on the following interstate pipelines: Columbia NiSource Gas Transmission Systems, Dominion East Ohio, National Fuel, and Tennessee Gas Pipeline. We transport natural gas on the following intrastate pipelines: Central Penn, North Coast Gas Transmission, Cobra Pipeline (owned by our chairman and CEO), Orwell Trumbull Pipeline (owned by our chairman and CEO), and Spelman.
Our Ohio and Pennsylvania companies have local gas supply purchase agreements with GNR. These arrangements are at variable NYMEX based market prices. In addition, GNR acted as agent for these utilities to identify and arrange supply of natural gas in the interstate market at variable and (or) fixed prices. This relationship ended for our Ohio utilities at the end of 2013.
Our Spelman subsidiary, an Ohio regulated intrastate pipeline company, operates pipelines located in Ohio and Kentucky. The Ohio pipeline transports natural gas to new markets where natural gas service was currently not available. It also connects this area to markets served by our Ohio subsidiaries. The Kentucky pipeline is a natural gas gathering line. In October 2011, the PUCO approved the transportation service tariff of Spelman.
Wyoming
Our operations in Wyoming provide natural gas service to customers in and around Cody, Meeteetse, and Ralston. This service area has a population of approximately 10,000 people. Our Wyoming operations provide service to approximately 6,800 customers, including one large industrial customer. Our Wyoming operations transport gas for third parties pursuant to a tariff approved by the WPSC.
Our Wyoming operation has an industrial customer whose pricing is subject to an industrial tariff. This tariff provides for decreasing tiered pricing based on volume. This customer accounted for approximately 12.0% of the revenue of our Wyoming operations and approximately 1.0% of the consolidated revenue of the natural gas segment of our business in 2013. This customer’s business is cyclical and depends upon the growth in housing market in this area.
The primary gas supply marketers for our Wyoming natural gas distribution operations have been Concord Energy and Tenaska Marketing Ventures. Our marketing and production operations supply natural gas to our Wyoming operations pursuant to an agreement through March 2017.
Marketing and Production
We market approximately 1.5 Bcf of natural gas annually to commercial and industrial customers in Montana, Wyoming, Ohio, and Pennsylvania through our EWR and GNR subsidiaries. We also manage midstream supply and production assets for transportation customers and utilities through our EWR subsidiary.
In order to provide a stable source of physical natural gas volumes for a portion of its requirements, EWR currently holds an average 51% gross working interest (average 43% net revenue interest) in 160 natural gas producing wells in operation on state lease mineral rights in Glacier and Toole Counties in Montana. This production gives EWR a partial natural hedge when market prices of natural gas are greater than the cost of production. The gas production from these wells and assets provided approximately 25% of the volume requirements for EWR in our Montana market for the year ended December 31, 2013. These wells are relatively shallow and we have not yet explored the deeper formations on our production properties.
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EWR owns a 24.5% interest in Kykuit, a developer and operator of oil, gas and mineral leasehold estates located in Montana. We have invested a total of approximately $2.2 million in Kykuit and may invest additional funds in the future as Kykuit could provide 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, at our reasonable discretion, after the results of certain initial exploration activities are known. At December 31, 2013, we are obligated to invest no more than an additional $0.1 million over the life of the venture. Other investors in Kykuit include our chairman and chief executive officer, Richard M. Osborne, and John D. Oil and Gas Company, a publicly held gas exploration company, which is also the managing member of Kykuit. Additional investors include Thomas J. Smith, a director and our chief financial officer, and a director of John D. Oil and Gas Company, and Gregory J. Osborne, a director and chief operating officer and former president and director of John D. Oil and Gas Company. Our net investment in Kykuit after deducting undistributed losses of approximately $1.8 million is approximately $352,000.
Pipeline Operations
Through EWD, we operate two natural gas pipelines, the “Glacier” natural gas gathering pipeline and the “Shoshone” transmission pipeline. 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 AECO and the CIG natural gas price indices. The Glacier gathering pipeline is approximately 40 miles in length and enables us to transport production gas for processing. We believe that our pipeline operations represent an opportunity to increase our profitability over time by taking advantage of summer/winter pricing differentials, as well as, 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 disposals, equity transactions, and other income and expense items associated with holding company functions. In 2013, we completed the sale of our Independence subsidiary. Independence was our only subsidiary historically included in our Propane Operations segment. The assets and liabilities as well as results of operations for this subsidiary have been reclassified to discontinued operations and are now included in the Corporate and Other segment.
As we continue to implement our acquisition strategy and grow, we will report additional 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 acquisitions. We believe we have the operating expertise to handle a significantly greater number of customers. We intend to focus on acquisitions that will enable us to grow our customer base in a manner and scale consistent with the full strategic vision of our senior leadership team. We believe there are opportunities to acquire financially-sound smaller natural gas utility companies that are individually owned or controlled.
Acquisition Strategy
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 50% in 2011, whereas we believe 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
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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 large disparity between competitive fuels presents an opportunity for gas distributors to capture a larger share of the energy market in these states.
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.
We will evaluate potential natural gas related acquisitions to determine whether these operations could expand our core utility business. In addition, we may acquire natural gas related non-utility operations such as gathering, storage and marketing operations that will complement our existing operations.
Competition
Natural Gas Operations
Our natural gas operations generally face competition in the distribution and sales of natural gas from suppliers of other fuels, including coal, electricity, oil and propane. Traditionally, the principal considerations affecting a customer’s selection of utility gas service over competing energy sources include service, price, equipment conversion 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 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, new territory and expansion is uncertified until a natural gas company builds a gas system in the community. Maine is an emerging natural gas market and new natural gas companies are entering the market. Alternative energy sources such as wood, electric, landfill gas, oil and propane continue to provide a competitive threat. However, in Montana, 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.
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State | | Competition |
Kentucky | | Columbia Gas of Kentucky, Delta Gas, Kentucky Frontier Gas |
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Maine | | Northern Utilities Inc., Maine Natural Gas, various fuel oil distributors, electric providers |
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Montana | | Northwestern Energy, Montana-Dakota Utilities Co. |
| |
North Carolina | | Various fuel oil distributors, electric providers |
| |
Ohio | | Dominion East Ohio, Columbia Gas of Ohio, National Gas & Oil, various propane and fuel oil distributors, electric providers |
| |
Pennslvania | | Various propane and fuel oil distributors, electric providers |
| |
Wyoming | | Various propane distributors, electric providers |
Our marketing and production operations compete principally with other natural gas marketing firms doing business in Montana, Wyoming, Ohio, and Pennsylvania.
Gas Supply Marketers and Gas Supply Contracts
Our local distribution companies purchase gas from various gas supply marketers for resale to our customers. The market forces of supply and demand determine the price of natural gas and affect the purchase price that our companies will pay for gas. The price we charge to our end users is a pass through commodity rate. This gas cost recovery rate includes not only the cost of the commodity, but also the transportation fees to move gas from
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major supply areas to our customers. We maintain a portfolio of both fixed price and market price contracts for our gas cost recovery customers. We use such arrangements to protect profit margins on future obligations and for protection in volatile natural gas markets. This portfolio includes a supply mixture of both interstate natural gas as well as locally produced natural gas. Our cost of gas is reviewed and approved by various public utility commissions. Jefferson Energy Trading has been a significant, non-exclusive gas supply marketer for our marketing and production subsidiary, EWR. EWR also supplies itself with natural gas through the ownership of natural gas producing wells in operation in north central Montana. For more information, see the sections captioned “Marketing and Production” and “Natural Gas Operations”.
Natural gas can be stored for indefinite periods of time. Traditionally, natural gas has been a seasonal fuel. We purchase and store natural gas during the summer months when demand and prices are low. This stored gas plays a vital role in ensuring that any excess supply delivered during the summer months is available to meet the increased demand of our customers during the winter months.
Governmental Regulation
State Regulation
Our utility operations are subject to regulation by the KPSC, MPUC, MPSC, NCUC, PUCO, PaPUC, and the WPSC. These authorities regulate many aspects of our distribution operations, including construction and maintenance of facilities, operations, safety, and regulatory rates charged to our customers which control the rate of return we are allowed to realize. For additional discussion of our Natural Gas Operations segment’s rates and regulation, seeManagement’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates.
Rate Regulation, Cost Recovery and Rate Cases
Utility ratemaking is the statutory process by which our utilities set the price we charge to our customers for utility service. It determines a utility’s revenue requirements and sets the prices paid for service accordingly. Ratemaking, carried out through “rate cases” before a public utility commission, serves as one of the primary instruments of government regulation of our utilities. The various regulatory commissions approve rates intended to permit a reasonable rate of return on investment. Funds for capital expenditures are typically obtained from capital loans or investments, revenue which recovers investment cost as depreciation expense, and undistributed retained earnings. Under regulation, our total revenue requirements (the prices paid by our customers) are limited to an amount that will yield a specified annual return on the value investment of property used and useful in public service (rate base), plus reimbursement of all necessary and proper operating expenses, taxes, interest, and depreciation. The price charged meets the test of reasonableness by our regulatory commissions and customers and at the same time permits our shareholders to earn a fair return on their investment. When our fair rate of return deviates from the assumptions used in establishing the rates, a deviation in our earned return occurs. When this becomes substantial, new proceedings are necessary to adjust the rates to provide for a fair return.
Kentucky
Our Kentucky operation generates revenue under a tariff subject to regulation by the KPSC. Our tariff is structured to enable a reasonable rate of return on investment based upon a “rate base” process. In March 2013, we finalized a rate case with the KPSC which resulted in our filing of a revised tariff with approved changes to our rate base. PGC’s new rate base is composed of a flat monthly fee, to stabilize revenues in warmer months, plus a volumetric rate per Mcf consumed by its customers. In addition to the rate base is the gas cost mechanism which is a pass-through of the cost of gas to the customer. The KPSC incorporates a purchased-gas commodity cost adjustment mechanism that allows PGC to adjust gas cost rates quarterly to recover changes in its wholesale gas costs.
Maine
Our Maine operations generates revenue under tariffs regulated by the MPUC, and as in other states, our tariffs are generally structured to enable us to realize a sufficient rate of return on investment. However, our tariffs and permitted return are not based upon a “rate base” as in other states, but on an alternative market-based framework. Because heating oil and other alternative fuels are historically prevalent in Maine and because
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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. 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 tariff also includes a purchased gas adjustment clause, which allows our operation to adjust rates monthly to recover changes in gas costs. 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. The existing rate plan in Maine was effective until December 2012. The Company has submitted an application to continue the plan with the MPUC. The current rate plan remains in place while the Company’s application is processed by the MPUC.
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.
North Carolina
Our North Carolina operations generate revenues under tariffs regulated by the NCUC. The tariffs are market-based rates structured to enable us to be competitive in the market place and 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 did not reduce our rates during that period. 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.
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 were maintained through September 2012, and the NCUC is satisfied with the continuance of our current rate. The margin rate consists of the tariff rate less benchmark gas costs.
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 by 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.” 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.
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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.
Wyoming
Our Wyoming operations generate their revenues under tariffs regulated by the WPSC. The tariffs are structured to enable us to recover a reasonable rate of return based on investment plus reimbursement of reasonable operating expenses, taxes, interest, and depreciation. 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.
Holding Company Reorganization and Ring-Fencing Measures
In August 2009, we implemented a holding company structure to reduce the regulatory limitations imposed by state regulatory commissions on our non-utility operations or on utility operations in states outside of their individual jurisdictions. However, each of our state regulatory commissions may still place limitations on us with respect to certain corporate and financial activities and with respect to the regulated activities in their states. For example, as a condition to approving our holding company reorganization, the MPSC and WPSC each imposed certain ring-fencing measures. These regulatory conditions covered a variety of activities, including a requirement that our regulated natural gas operating subsidiaries in Maine, Montana, North Carolina and Wyoming must meet certain notice and financial requirements prior to paying dividends, and that our Maine and North Carolina utilities, which are currently subsidiaries of our subsidiary Energy West, be converted to direct subsidiaries of Gas Natural upon the earlier of the expiration or refinance of Energy West’s debt, unless segregating the Maine and North Carolina operations would be detrimental to our Montana or Wyoming customers. In that event, Energy West would have the opportunity to request a waiver of the spin-off requirement from the MPSC and WPSC.
When Energy West sought to refinance its debt in 2012, it determined the required spin-off of the Maine and North Carolina operations would be detrimental to its customers in all four states, and therefore, sought appropriate waivers from the MPSC and WPSC. The MPSC and WPSC each granted the requested waiver, but any future refinancing will require an additional waiver or the spin-off of our Maine and North Carolina operations. In addition, the MPUC and the NCUCC have both expressed reluctance to permit the spin-off required by the MPSC. Therefore, it is unclear what regulatory conditions will be imposed with respect to the structure of Energy West in the future and the impact on Energy West in the event it receives conflicting regulatory orders from different commissions. In addition, each of the MPSC, MPUC, NCUCC and WPSC have issued ring-fencing and regulatory compliance requirements that Energy West and its regulated subsidiaries in Montana, Maine, North Carolina and Wyoming must continue to meet on an on-going basis.
In connection with the WPSC approval of our acquisition of the Ohio and Pennsylvania utilities, the WPSC issued an order, affirmed on rehearing issued in November 2011, holding Gas Natural subject to its general jurisdiction over public utilities. In December 2011, we timely filed a petition for review of the WPSC order in the Laramie County, Wyoming District Court. In October 2012, the District Court reversed the WPSC’s finding of jurisdiction and remanded to the WPSC for additional findings. A hearing was conducted by the WPSC on April 3 and 4, 2013. To date, the WPSC has not issued a final order in this matter. Until the jurisdictional issue is resolved, the WPSC has jurisdiction over the holding company. If, following the hearing, the WPSC affirms that it has jurisdiction over us with respect to a potential acquisition, refinancing of debt or other significant transaction and denies a request by us for exemption with respect to the transaction, it could delay, hinder or
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prevent us from completing the transaction. To date, none of the other public service commissions’ have asserted jurisdiction over Gas Natural, although we cannot predict whether or not any commission will attempt to do so in the future or under what circumstances.
Certificated Territories and Franchise Agreements
In some states, our natural gas 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 service areas in which we operate are discussed below.
Certificates of public convenience and necessity are required in Kentucky, Maine, North Carolina, Pennsylvania and Wyoming. 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. 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 Kentucky, we cannot commence providing utility service to or for the public or begin the construction of any plant, equipment, property, or facility for furnishing to the public any services until we have obtained from the KPSC a certificate that public convenience and necessity require the service or construction. Upon the filing of an application for a certificate, and after any public hearing which the commission may in its discretion conduct for all interested parties, the commission may issue or refuse to issue the certificate. No utility can apply for or obtain any franchise, license, or permit from any city or other governmental agency until it has obtained a certificate of convenience and necessity from the KPSC.
Franchise agreements are utilized in Montana, North Carolina and Wyoming. In Montana, we hold franchise agreements in the cities of Great Falls and West Yellowstone. 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. In Wyoming, we hold franchise agreements in the cities of Cody and Meeteetse. We are not required to obtain franchise agreements for our operations in Kentucky, Maine, Ohio or Pennsylvania; although in Ohio, non-exclusive franchise ordinances or agreements are permitted.
Federal Regulations
Our interstate natural gas operations are also subject to federal regulations with respect to rates, services, construction, maintenance and safety standards. This regulation plays a significant role in determining our profitability. Various aspects of the transportation of natural gas are also subject to, or affected by, federal regulation under the NGA, the Natural Gas Policy Act of 1978 and the Natural Gas Wellhead Decontrol Act of 1989. The FERC is the federal agency vested with authority to regulate the interstate gas transportation industry. Our Shoshone transmission pipeline is subject to certain FERC regulations applicable to interstate activities,
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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, treating, 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, treating, 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 North Carolina Diesel Fuel Site
Included as part of our acquisition of Independence in 2011, we identified a piece of property that encountered a diesel fuel spill and required environmental cleanup. We have completed the voluntary remediation of the soil contaminants at the property and continue to monitor the site for additional contamination in 2014.
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. Since we do not have a weather normalization adjustment in our rates, our revenue is temperature-sensitive. Colder temperatures generally result in increased
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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. Any unusually warm or cold weather patterns with further skew our sales volumes.
Employees
We had a total of 291 employees as of December 31, 2013 of which, 281 are full time, 261 are employed by our natural gas operations, four by our marketing and production operations, and 26 that spend time in all of the segments of operations. Our natural gas operations include 16 employees represented by two labor unions, the Laborers Union and Local Union No. 41. Labor contracts with both unions are in place through June 2016. We believe our relationship with our employees and unions is good.
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 public utility commissions in states where we operate and the Federal Energy Regulatory Commission (FERC) regulate many aspects of our distribution and transmission operations. State regulatory agencies set the rates that we may charge customers, which effectively limit 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 recoverable in the rates charged to our customers. The various state regulatory agencies’ review 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 recently examined NEO and Orwell under the GCR mechanism. NEO’s audit covered the GCR mechanism from September 2009 through May 2012, and Orwell’s GCR mechanism covered July 2010 through June 2012. On November 13, 2013, the PUCO issued an Opinion and Order in these GCR cases that disallowed
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our recovery of $1.0 million, primarily fees paid to JDOG Marketing, and fines of $76,000. In addition, the order finds that an investigative and forensic audit of NEO, Orwell and all affiliated and related companies and their internal management controls should be undertaken by an outside auditor. If material deficiencies are found in the investigative and forensic audit, the Company could be subject to additional civil fines, restrictions, changes or limitations to, or cessation of, existing operations in Ohio, which could adversely affect our financial condition, results of operations, cash flow and stock price.
We currently are involved in shareholder derivative lawsuits and other related legal proceedings that could have a material adverse effect on our operating results or financial condition.
Beginning on December 10, 2013, five shareholder derivative complaints were filed in federal court against Gas Natural, as a nominal defendant, and against certain of our current and former directors and officers, as real defendants. We may also be subject to additional lawsuits, investigations or proceedings in the future that relate to the allegations set forth in these derivative actions. The pending shareholder complaints allege, among other things, that the defendants have violated federal securities laws, breached their fiduciary duty and wasted corporate assets in connection with our acquisition of the Ohio utilities, services provided by John D. Marketing and the acquisition of John D. Marketing, and the sale of our common stock by Richard M. Osborne, our chairman and chief executive officer, and Thomas J. Smith, our chief financial officer. A more detailed description of these lawsuits and others is contained in Part I Item 3 “Legal Proceedings” in this Annual Report on Form 10-K.
We are a nominal defendant in the pending shareholder derivative suits, and none of the plaintiffs are seeking recovery from Gas Natural. However, we have certain indemnification obligations to the named defendants, including the advancement of defense costs to the individuals. The expenses related to continuing to defend such litigation may be significant. We cannot predict the outcome of these lawsuits or for how long they will remain active. Regardless of the outcome, the pending lawsuits, and any other related litigation, proceedings or investigations that may be brought against us or our current or former officers and directors in the future could be time-consuming, result in significant expense and divert the attention and resources of our management and other key employees from the operation of our business. Moreover, negative developments with respect to the pending lawsuits could cause our stock price to decline. We could also be required to pay damages or other monetary penalties imposed on our directors and officers as a result of these cases. Any expenses, damages or settlement amounts involved in these matters could exceed coverage provided under our applicable insurance policies. Any unfavorable outcome of the pending shareholder cases could harm our business and financial condition, results of operation or cash flows.
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.
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Our earnings and cash flow are sensitive to decreases in customer consumption resulting from warmer than normal temperatures and customer conservation.
Our natural 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 these companies are larger and have greater financial, technological, human and other resources than we do. 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.
Our earnings and cash flow may be adversely affected by downturns in the economy.
Our operations are affected by the conditions and overall strength of the national, regional and local economies, which impact the amount of residential and industrial growth and actual gas consumption in our service territories. Our commercial customers use natural gas in the production of their products. During economic downturns, these customers may see a decrease in demand for their products, which in turn may lead to a decrease in the amount of natural gas they require for production. In addition, during periods of slow or little economic growth, energy conservation efforts often increase and the amount of uncollectible customer accounts increases. These factors may reduce earnings and cash flow.
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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 may enact new accounting standards that could impact the way we are required to record revenue, expenses, assets and liabilities. In addition, 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. 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 have an ownership interest in 160 natural gas producing wells in Montana, 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 25% of the volume requirements for Energy West Resource’s Montana market for 2013. 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.
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 generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals, and can result in increased capital expenditures and operating costs. 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.
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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 $10.3 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 recorded a net deferred tax asset as the result of our acquisitions of Frontier Natural Gas and Bangor Gas Company in 2007. This tax asset was $10.3 million at December 31, 2013. We may continue to depreciate approximately $82.0 million of Frontier and Bangor’s capital assets using the useful lives and rates employed by those companies, resulting in future potential federal and state income tax benefits over a 20-year period using applicable federal and state income tax rates. Under Internal Revenue Code Section 382, our ability to recognize tax deductions as a result of this tax benefit was limited during the first five years following the acquisitions.
Management will reevaluate the valuation allowance each year on completion of updated estimates of taxable income for future periods, and will reduce the deferred tax asset by the new valuation allowance if, based on the weight of available evidence, it is more likely than not that we will not realize some portion or all of the recognized deferred tax assets. In addition, we cannot guarantee that we will be able to generate sufficient future taxable income to realize the $10.3 million net deferred tax asset over the remaining useful life of the asset. A write down in the deferred tax asset or expiration of the asset before it is utilized would adversely affect our operating results and financial position.
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 contains provisions requiring us to assess the effectiveness of internal control for financial reporting, as well as attestation and reporting by independent auditors on our internal control over financial reporting as well as other control-related matters. Because we are currently a smaller reporting company, our independent auditors are not required to attest to our internal controls over financial reporting in accordance with the Dodd-Frank Wall Street Reform and Consumer Protection Act.
Compliance with Section 404 is both costly and challenging. As described in Item 9A of this Form 10-K, we have identified a material weakness in our internal controls over financial reporting in the area of our gas supply procurement and gas cost recovery through rates. Although we believe we have remediated the material weakness, in the future, 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 because of the discovery of material weaknesses. Further, during the course of our testing we may identify deficiencies that we may not be able to remediate in time to meet the deadlines imposed under the Sarbanes-Oxley Act for compliance with Section 404. Moreover, effective internal controls, particularly those related to revenue recognition, are necessary for us to produce reliable financial reports and are important to help prevent financial fraud. If we cannot provide reliable financial reports or prevent fraud, our business and operating results could be harmed, investors could lose confidence in our reported financial information, and the trading price of our stock could be adversely affected.
Our actual results of operations could differ from estimates used to prepare our financial statements.
In preparing our financial statements in accordance with generally accepted accounting principles, our management often must make estimates and assumptions that affect the reported amounts of assets, liabilities, 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.
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Our Company’s operations could give rise to risk in cybersecurity attacks.
On October 13, 2011, the SEC’s Division of Corporation Finance issued Topic No. 2, Cybersecurity, relating to cybersecurity risks and cyber incidents. We rely extensively on computer systems to process transactions, maintain information and manage our business. Disruptions in our computer systems could impact our ability to service our customers and adversely affect our sales and the interruption of operations.
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 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 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, |
| | • | | 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 any businesses that we have acquired or may 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 effect 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 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.
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.
Future issuances of our common stock may dilute the interests of existing shareholders.
In connection with our acquisition strategy, we have issued shares of our common stock and expect to issue additional shares of our common stock to finance acquisitions. For example, last year we consummated a
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transaction to purchase the assets of JDOG Marketing. The initial purchase price was paid in shares of our common stock and we will issue additional earn-out shares if the acquired business achieves certain financial milestones. The issuance of any additional shares may result in economic dilution to our existing shareholders.
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 facilities and any future credit agreements to which we may be a party. In addition, acquisitions funded by the issuance of our common stock or future issuances to raise capital will increase the number of our shares outstanding and may make it more difficult to continue dividends at our current rate.
Financial covenants contained in our credit facilities 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 these covenants 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.
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 code of 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 meeting of shareholders, the acquisition is approved by both a majority of our shares and a majority of the voting shares 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 the Public Utilities Commission of Ohio. 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 MKT 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 MKT. NYSE MKT rules contain requirements with respect to corporate governance, communications with shareholders, the trading price of shares of our common stock, and various
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other matters. We believe we are in compliance with NYSE MKT 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 MKT could de-list our stock. If our stock was de-listed from NYSE MKT, our shares would likely trade in the Over-The-Counter Bulletin Board, but the ability of our shareholders to sell our stock could be impaired because smaller quantities of shares would likely be bought and sold, transactions could be delayed, and security analysts’ coverage of the Company 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, STRUCTUREAND 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, |
| | • | | limiting our ability to sell assets, make investments in 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. |
Our credit facility with Sun Life Assurance Company of Canada requires us to maintain debt service reserve accounts of $1,072,476 to cover approximately one year of interest payments. We are not able to use these funds for operational cash purposes. The terms allow us to withdraw the funds if a letter of credit is received to replace the restricted cash.
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. Currently, as a result of covenants contained in the note purchase agreements with Sun Life, our Ohio subsidiaries are not able to distribute any funds to the holding company. The inability of our Ohio subsidiaries to distribute any funds to the holding company may impact our ability to pay dividends to our shareholders. Further, our subsidiaries are legally distinct from us, and although they are wholly-owned and controlled by us, our ability to obtain distributions
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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 Maine, Montana, North Carolina and Wyoming operating subsidiaries to pay a dividend only if the dividend, when combined with dividends over the previous five years, would not exceed 80% of their net income over those years, |
| | • | | we may cause our Ohio and Pennsylvania subsidiaries to distribute dividends only if the aggregate amount of all such dividends and any distributions, redemptions and repurchases for the fiscal year do not exceed 70% of their net income. |
Additionally, the Montana and Wyoming Public Service Commissions have imposed ring-fencing restrictions under which our Maine, Montana, North Carolina and Wyoming operating subsidiaries must meet certain notice and financial requirements prior to paying dividends that are above certain financial thresholds or irregularly timed.
These dividend restrictions, in addition to other financial covenants contained in the credit facilities and ring-fencing restrictions, place constraints on our business and may adversely affect our cash flow, liquidity and financial condition as well as our ability to finance acquisitions or pay dividends. Further, we may be required to comply with additional covenants. Failure to comply with financial covenants may result in the acceleration of the debt and foreclosure of our assets, which would have a material adverse effect on our business, earnings, cash flow, liquidity and financial condition. For further details on the financial covenants contained in the credit facilities, see the “Restrictions on Dividends” subsection ofNote 12 – Stockholders’ Equity in the notes to our consolidated financial statements of our Annual Report on Form 10-K for the year ended December 31, 2013.
The Wyoming Public Service Commission has asserted jurisdiction over Gas Natural’s activities, 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 subsequently in connection with our acquisition of the Ohio operations, the WPSC issued an order, affirmed on rehearing issued in November 2011, holding us subject to its general jurisdiction over public utilities. In December 2011, we timely filed a Petition for Review of the WPSC order in the Laramie County, Wyoming District Court. On October 9, 2012, the District Court reversed the WPSC’s finding of jurisdiction and remanded to the WPSC for additional findings. A hearing was conducted by the WPSC on April 3 and 4, 2013. To date, the WPSC has not issued a final order in this matter. Until the jurisdictional issue is resolved, the WPSC has jurisdiction over the holding company. If, following the hearing, the WPSC affirms that it has jurisdiction over us with respect to any potential acquisition, refinancing of debt or other significant transaction and denies 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.
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 Resources LLC, and their performance of their obligations to us are outside our control. If these parties do not meet or satisfy their
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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 shareholders 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 some of our directors have a financial interest. In the future we may enter into other additional related party transactions on a case by case basis in accordance with our related party transaction policy. For more information on our related party transactions, see “Certain Relationships and Related Transactions” on page 21 of our definitive proxy statement for the 2013 annual meeting filed with the SEC on May 10, 2013.
ITEM 2. PROPERTIES.
KENTUCKY
In Jackson, Kentucky, we lease a 1,836 square foot building that has a combination of office and service space. We have approximately 49 miles of distribution lines and related metering and regulating equipment in Kentucky.
MAINE
In Bangor, Maine, we own a 16,000 square foot building that has a combination of office, service and warehouse space which supports our office, maintenance and construction operations. We have approximately 152 miles of transmission and distribution lines and related metering and regulating equipment in Maine.
MONTANAAND WYOMING
In Great Falls, Montana, we own an 11,000 square foot office building and a 3,000 square foot service and operating center, which supports day-to-day maintenance and construction operations. We own approximately 581 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 653 miles of transmission and distribution mains and related metering and regulating equipment, all of which are located in or around Cody, Meeteetse, and Ralston, Wyoming.
Our pipeline operations own two pipelines in Montana and Wyoming. 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 natural gas operations are headquartered in Elkin, North Carolina. We own a 12,038 square foot building that has a combination of office, shop and warehouse space. We own approximately 567 miles of transmission and distribution lines and related metering and regulating equipment in North Carolina. In Boone, North Carolina, we lease an office building/operating center.
OHIOAND WESTERN PENNSYLVANIA
We maintain facilities for our Ohio and Western Pennsylvania operations located in Lancaster, Mentor, Orwell, Strasburg, and Newton Falls, Ohio. Our Lancaster, Orwell, Strasburg, and Newton Falls sites serve as office and service space. We own the Lancaster and Strasburg sites and we lease the Orwell and Newton Falls sites under
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long-term lease agreements with related parties. In 2013 we purchased the Matchworks building in Mentor, Ohio. The building is a 51,000 square foot office building. We use approximately 11,000 square feet as the offices for our chief executive officer, chief financial officer and certain other personnel associated with our Ohio subsidiaries and lease out the remaining capacity of the building. We own approximately 1,231 miles of transmission and distribution lines and related metering and regulating equipment in Ohio and Western Pennsylvania.
ITEM 3. LEGAL PROCEEDINGS.
From time to time, 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.
Beginning on December 10, 2013, five putative shareholder derivative lawsuits were filed by five different individuals, in their capacity as shareholders of Gas Natural, in the United States District Court for the Northern District of Ohio, purportedly on behalf of Gas Natural and naming certain of our current and former executive officers and directors as individual defendants. These five shareholder lawsuits are captioned as follows: (1) Richard J. Wickham v. Richard M. Osborne, et al., (Case No. 1:13-cv-02718-LW); (2) John Durgerian v. Richard M. Osborne, et al., (Case No. 1:13-cv-02805-LW); (3) Joseph Ferrigno v. Richard M. Osborne, et al., (Case No. 1:13-cv-02822-LW); (4) Kyle Warner v. Richard M. Osborne, et al., (Case No. 1:14-cv-00007-LW) and (5) Gary F. Peters v. Richard M. Osborne, (Case No. 1:14-cv-0026-CAB).
Each lawsuit contains claims against various current or former directors or officers of Gas Natural alleging, among other things, violations of federal securities laws, breaches of fiduciary duty, waste of corporate assets, unjust enrichment and insider selling arising primarily out of our acquisition of the Ohio utilities, services provided by JDOG Marketing and the acquisition of JDOG Marketing and the sale of our common stock by Richard M. Osborne, the Company’s chairman and chief executive officer, and Thomas J. Smith, our chief financial officer. The suits seek the recovery of unspecified damages allegedly sustained by Gas Natural, which is named as a nominal defendant, corporate reforms, disgorgement, restitution, the recovery of plaintiffs’ attorney’s fees, rescission of the acquisition of the Ohio utilities and JDOG Marketing and other relief. Although we believe that insurance proceeds are available, we may incur costs and expenses related to the lawsuits that are not covered by insurance which may be substantial. Any unfavorable outcome of the pending lawsuits could adversely impact our business and results of operations.
On February 6, 2014, the five lawsuits were consolidated solely for purposes of conducting limited pretrial discovery, and on February 21, 2014, the Court appointed lead counsel for all five lawsuits. No formal discovery has been conducted to date.
On February 25, 2013, one of the Company’s former officers, Jonathan Harrington, filed a lawsuit captioned “Jonathan Harrington v. Energy West, Inc. and Does 1-4,” Case No. DDV-13-159 in the Montana Eighth Judicial District Court, Cascade County. Mr. Harrington claims that he was terminated in violation of Montana statute requiring just cause for termination. In addition, he alleges claims for negligent infliction of emotional distress and negligent slander. Mr. Harrington is seeking relief for economic loss, including lost wages and fringe benefits for a period of at least four years from the date of discharge, together with interest. Mr. Harrington is an Ohio resident and was employed in the Company’s Ohio corporate offices. On March 20, 2013, the Company filed a motion to dismiss the lawsuit on the basis that Mr. Harrington was an Ohio employee, not a Montana employee, and therefore the statute does not apply. The motion has been fully briefed but has not been ruled on by the Court. Likewise, Mr. Harrington has requested oral argument but the Court has not indicated whether such request will be granted. The Company believes his claims under Montana law are without merit, and intends to vigorously defend this case on all grounds.
In the Company’s opinion, the outcome of these legal actions will not have a material adverse effect on the financial condition, cash flows or results of operations of the Company except as described above.
ITEM 4. MINE SAFETY DISCLOSURES.
Not applicable.
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PART II
ITEM 5. MARKETFOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERSAND ISSUER PURCHASESOF EQUITY SECURITIES.
OUR COMMON STOCK
Our common stock trades on the NYSE MKT under the symbol “EGAS”.
The following table sets forth, for the quarters indicated, the range of high and low prices of our common stock from the NYSE MKT Equities.
| | | | | | | | |
Year Ended 12/31/13 | | High | | | Low | |
First Quarter | | $ | 10.21 | | | $ | 9.28 | |
Second Quarter | | $ | 10.76 | | | $ | 9.85 | |
Third Quarter | | $ | 10.84 | | | $ | 9.95 | |
Fourth Quarter | | $ | 10.47 | | | $ | 7.49 | |
| | |
Year Ended 12/31/12 | | High | | | Low | |
First Quarter | | $ | 11.66 | | | $ | 11.00 | |
Second Quarter | | $ | 11.49 | | | $ | 9.88 | |
Third Quarter | | $ | 10.27 | | | $ | 9.83 | |
Fourth Quarter | | $ | 10.07 | | | $ | 8.63 | |
Holders of Record
As of March 17, 2014, there were approximately 191 record owners of our common stock. We estimate that approximately 6,960 additional shareholders own stock in accounts at brokerage firms and other financial institutions.
Dividend Policy
We paid a monthly dividend of $0.045 per share from January 1, 2012 through December 31, 2013.
Restrictions on Payment of Dividends
As a holding company, our primary assets and sources of cash flow are our operating subsidiaries. The credit facilities and ring fencing requirements 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.
For additional information on loan covenants and restrictions contained in our debt documents, please seeManagement Discussion and Analysis of Financial Condition and Results of Operations – Capital Sources and Liquidity.
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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, 2008 to December 31, 2013.
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2008 | | | 2009 | | | 2010 | | | 2011 | | | 2012 | | | 2013 | |
Gas Natural Inc. | | $ | 100.00 | | | $ | 130.53 | | | $ | 139.56 | | | $ | 158.36 | | | $ | 136.30 | | | $ | 123.94 | |
S&P 500 Index – Total Returns | | | 100.00 | | | | 126.46 | | | | 145.51 | | | | 148.59 | | | | 172.37 | | | | 228.19 | |
S&P 500 Utilities Index | | | 100.00 | | | | 111.91 | | | | 118.02 | | | | 141.52 | | | | 143.35 | | | | 162.29 | |
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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. Prior period amounts have been reclassified to reflect current year presentations. 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.
| | | | | | | | | | | | | | | | | | | | |
| | | Years Ended December 31, | |
($ in thousands, except share and
per share data) | | 2013 (1) | | | 2012(2)(3) | | | 2011(3) | | | 2010 (4) | | | 2009 | |
| | | | | |
Revenue | | $ | 118,835 | | | $ | 89,201 | | | $ | 96,202 | | | $ | 91,500 | | | $ | 71,454 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | |
Operating income | | $ | 13,274 | | | $ | 10,089 | | | $ | 10,709 | | | $ | 11,079 | | | $ | 9,063 | |
| | | | | | | | | | | | | | | | | | | | |
Income from continuing oeprations | | $ | 7,042 | | | $ | 3,920 | | | $ | 5,114 | | | $ | 5,797 | | | $ | 6,819 | |
Income (loss) from discontinued operations | | | (371) | | | | (201) | | | | 255 | | | | - | | | | - | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | |
Net income | | $ | 6,671 | | | $ | 3,719 | | | $ | 5,369 | | | $ | 5,797 | | | $ | 6,819 | |
| | | | | | | | | | | | | | | | | | | | |
Basic and diluted earnings per share: | | | | | | | | | | | | | | | | | | | | |
Continuing operations | | $ | 0.75 | | | $ | 0.48 | | | $ | 0.63 | | | $ | 0.92 | | | $ | 1.58 | |
Discontinued operations | | | (0.04) | | | | (0.02) | | | | 0.03 | | | | - | | | | - | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | |
Net income per share | | $ | 0.71 | | | $ | 0.46 | | | $ | 0.66 | | | $ | 0.92 | | | $ | 1.58 | |
| | | | | | | | | | | | | | | | | | | | |
Weighted average dividends per common share | | $ | 0.55 | | | $ | 0.54 | | | $ | 0.54 | | | $ | 0.56 | | | $ | 0.55 | |
Weighted average shares outstanding – basic | | | 9,339,002 | | | | 8,163,814 | | | | 8,151,935 | | | | 6,292,717 | | | | 4,309,852 | |
Weighted average shares outstanding – diluted | | | 9,339,722 | | | | 8,169,679 | | | | 8,159,827 | | | | 6,300,972 | | | | 4,313,098 | |
Plant, property, & equipment, net | | $ | 133,520 | | | $ | 116,429 | | | $ | 95,123 | | | $ | 76,134 | | | $ | 41,204 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | |
Total assets | | $ | 203,744 | | | $ | 174,463 | | | $ | 152,736 | | | $ | 137,728 | | | $ | 78,626 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | |
Non-current liabilities | | $ | 54,390 | | | $ | 53,755 | | | $ | 36,931 | | | $ | 25,110 | | | $ | 15,510 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | |
Capitalization | | $ | 137,678 | | | $ | 120,045 | | | $ | 106,117 | | | $ | 95,661 | | | $ | 48,688 | |
| | | | | | | | | | | | | | | | | | | | |
| (1) | In 2013, the Company completed the purchase of substantially all the assets of JDOG Marketing. SeeNote 3 – Acquisitions to the notes to our consolidated financial statements. |
| (2) | In 2012, the Company’s sales volumes were adversely impacted by warmer than usual weather. Heat degree days were down on average by 10% across all of our utilities. |
| (3) | In 2013, the Company completed the sale of its Independence subsidiary, originally acquired in 2011. The results of operations and financial position for this subsidiary for the years 2012 and 2011 have been reclassified to Discontinued operations to match the current year’s presentation. See note 4 – Discontinued Operations to the notes to our consolidated financial statements. |
| (4) | In 2010, the Company completed the acquisition of Lightning Pipeline, Great Plains, and Brainard impacting the comparability in year over year results of operation and financial condition from 2009 to 2010. |
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ITEM 7. MANAGEMENT’S DISCUSSIONAND ANALYSISOF FINANCIAL CONDITIONAND RESULTSOF 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 seven states and serving approximately 72,000 customers in total. Our natural gas utility subsidiaries are Bangor Gas Company (Maine), Brainard Gas Corp. (Ohio), Cut Bank Gas Company (Montana), Energy West Montana (Montana), Energy West Wyoming (Wyoming), Frontier Natural Gas (North Carolina), Northeast Ohio Natural Gas Corporation (Ohio), Orwell Natural Gas Company (Ohio and Pennsylvania), and Public Gas Company (Kentucky). Our operations also include production and marketing of natural gas, gas pipeline transmission, and gathering operations. Due to the sale of Independence in November 2013, the Company’s propane operations were classified as discontinued as of December 31, 2013. SeeNote 4 – Discontinued Operations to the notes of our consolidated financial statements.Approximately 89% of our revenues in 2013 were derived from our natural gas utility operations.
The following summarizes the critical events that impacted our results of operations during the year ended December 31, 2013:
Gross margin increased $6,783,000 in 2013 primarily as a result of:
| | • | | Customer growth in our North Carolina, Maine, and Ohio markets |
| | • | | Colder weather throughout our service territories |
| | • | | Our LNG business, formed, in May of 2012, and our PGC subsidiary, acquired on April 1, 2012, contributing a full year of operations to gross margin. |
| | • | | A total charge of $1.3 million recorded in 2013 for the disallowance of gas costs resulting from the gas cost recovery audit and Opinion and Order issued in November 2013 by the PUCO |
Net income increased $2,952,000 in 2013 primarily due to:
| | • | | Our subsidiary, GNR, completed the acquisition of the assets of JDOG Marketing, which contributed new revenue, gross margin and expenses in 2013. Included as an offset to expense is an unrealized holding gain of $1,565,000. As described inNote 3 – Acquisitions to the notes of our consolidated financial statements, the purchase contract for the JDOG Marketing assets includes an earn-out provision for which we have recorded a contingent consideration liability on the accompanying Consolidated Balance Sheet at December 31, 2013. Pursuant to accounting rules, this liability has been revalued to fair value at December 31, 2013, resulting in a net unrealized holding gain of $1,565,000. |
| | • | | Partially offsetting the gain from the contingent consideration liability revaluation was expense of $725,744 related to the impairment of goodwill from the purchase of JDOG Marketing. The non-cash, non-tax-deductible charge was largely the result of the disallowance of the customer relationships by the PUCO, as discussed inNote 5 – Goodwill to the notes of our consolidated financial statements. |
| | • | | On November 6, 2013, the Company closed on the sale of Independence, causing the results of operations and financial position of Independence to be reclassified as discontinued operations in the consolidated financial statements. SeeNote 4 – Discontinued Operations to the notes of our consolidated financial statements for more information regarding this sale. |
| | • | | Costs related to acquisitions were significantly lower in 2013 than in 2012. |
| | • | | We incurred costs of $309,000 in 2013 in connection with our CEO’s stock sale, as compared to $274,000 in 2012. |
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| | • | | The amortizing term loan with Bank of America and the $2.989 million Senior Secured Guaranteed Note with Sun Life which were procured in the last half of 2012 and the capital lease obligation related to the Loring pipeline purchase caused an increase in interest expense for the year ended December 31, 2013 compared to 2012. |
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 on capital to our shareholders in the form of dividends. In addition, we are actively pursuing our acquisition strategy to further grow our operations.
CRITICAL ACCOUNTING POLICIESAND 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. SeeNote 2 – Significant Accounting Policies to the notes of our consolidated financial statements for a complete list of the Company’s significant accounting policies.
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, 2013, our total regulatory assets were $1.9 million and our total regulatory liabilities were $0.9 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 Kentucky, Maine, Montana, North Carolina, Ohio, Pennsylvania, and Wyoming 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.
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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 five of the seven states in which we operate, and semi-annually or 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.
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 current conditions as well as historical bad debt write-offs as a percentage of aged receivables. The underlying assumptions used for the provision can change from period to period and the provision could potentially cause a material impact to the accompanying financial statements by overstating liquidity and over-valuing net worth. 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, 2013 and December 31, 2012. A variance of 10% on our gross margin from unbilled revenue at December 31, 2013 would have been plus or minus $168,000.
Fair Value of Financial Instruments
Our financial instruments consist of cash and cash equivalents, marketable securities, 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 fair values of marketable securities are estimated based on closing share price on the quoted market price for those investments.
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.
We have a deferred tax asset of approximately $10.3 million as of December 31, 2013 related to the carryover tax basis of Frontier Utilities and Penobscot Natural Gas, which were acquired in 2007. The carryover tax basis is subject to the limitations in Section 382 of the Internal Revenue Code, which limit our tax depreciation in tax years 2007 through 2012. We have approximately $26.8 million of carryover tax basis as of December 31, 2013 and will recognize potential future federal and state income tax benefits of approximately $10.3 million over the remaining life of the carryover tax basis of the assets. For Federal income tax purposes, we have 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
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taxable income projections. For state income tax purposes, we have concluded that the realization of the deferred tax asset associated with the carryover tax basis will not be realized, due to state net operating loss carryovers and future state taxable income projections. Therefore, management has placed a valuation allowance of approximately $1.7 million on the state deferred tax assets associated with the carryover tax basis of its subsidiaries acquired in 2007.
Management will reevaluate the valuation allowance annually based on future taxable income projections, and will adjust the deferred tax asset valuation allowance, if based on the weight of available evidence, it ismore-likely-than not that we 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, we will adjust the valuation allowance to income tax expense. The valuation allowance is based on projections of our taxable income in future reporting years. Based on future taxable income projections, our state net operating losses will not be realized. Therefore, management has placed a valuation allowance of approximately $3.9 million on the state deferred tax asset associated with state net operating losses.
For the federal tax portion, the five year Internal Revenue Code limitation period discussed above expired in 2012. Based on our estimates of taxable income, we project that we will recover approximately 97% of the remaining benefit in the next eight 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 not amortized, rather, the goodwill is required to be tested for impairment annually, which we perform in the fourth quarter, or if events or changes in circumstances indicate that goodwill may be impaired. We test for goodwill impairment using a two-step approach. A recoverability test at the reporting unit level must be performed during the first step. If the asset is not recoverable, the second step calculates the impairment loss, if any. The Company’s impairment evaluations as of December 31, 2013 indicated impairment of its goodwill for the purchase of the assets of JDOG Marketing, and therefore step two of the impairment testing process was performed, resulting in an impairment expense of $725,744. SeeNote 5 – Goodwill to the notes of our consolidated financial statements.
The goodwill amounts in the consolidated balance sheets at December 31, 2013 and 2012 relate to the acquisition of the assets of JDOG Marketing on June 1, 2013, the acquisition of PGC on April 1, 2012, the acquisition of the Ohio and Pennsylvania subsidiaries on January 5, 2010 and the acquisition of Cut Bank Gas on November 2, 2009.
The schedule below represents goodwill allocated to the Ohio Subsidiaries as well as the excess of the fair value over the carrying value of goodwill as of December 31, 2013:
| | | | | | | | | | | | | | | | |
Operating Unit | | Goodwill
($000s) | | | Fair Value
($000s) | | | Carrying Value
($000s) | | | % By Which Fair Value
Exceeds Carrying Value | |
Ohio Subsidiaries | | $ | 13,551 | | | $ | 53,059 | | | $ | 52,061 | | | | 1.92% | |
There is a degree of uncertainty related to assumptions used to determine fair value. There are estimates and assumptions for organic growth, market equity risk, realized return on equity investments, market multiples, risk premium for size, weighted average cost of capital, capital structure, and tax rate. Weather can negatively impact our key assumptions and results.
When testing goodwill impairment of the Ohio Subsidiaries, the enterprise value calculation was determined by putting an equal emphasis on a discounted cash flow method and a guideline public company method. The key assumptions made for each approach used in the impairment testing of the Ohio Subsidiaries were (1) for discounted cash flow method, the weighted average cost of capital was 7.25%, the tax rate was 34%, and the perpetuity growth rate was 2.5%, (2) for the guideline public company method, we applied a one-third weighting to each of the values indicated by operating revenue, operating EBITDA and property, plant, and equipment indications.
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Lease Commitments
Capital Leases
We apply the guidance of ASC 840 –Leases to determine if a lease meets the definition of a capital lease. A lease must meet one of four criteria to meet the requirements of a capital lease. If capital lease requirements are met, we measure a capital lease asset and capital lease obligation initially at an amount equal to the present value of minimum lease payments during the lease term, excluding any executory costs, at the beginning of the lease term. If the present value of the minimum lease payments exceeds the fair value of the leased property at lease inception, the amount measured initially as the asset and obligation shall be the fair value.
RESULTSOF 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 Form 10-K.
For the year ended December 31, 2013, revenue increased $29,634,000 due to colder weather in all of our markets, customer growth in our North Carolina, Maine, and Ohio markets, and higher natural gas prices passed on to our customers. Colder weather and increased customer growth also contributed to the gross margin increase of $6,783,000. Net income increased $2,952,000.
EARNINGS
Year Ended December 31, 2013 Compared with Year Ended December 31, 2012
Loss from Discontinued Operations – The 2013 and 2012 results of the Company’s Propane Operations segment have been classified as discontinued operations as a result of the sale of the assets of Independence. SeeNote 4 – Discontinued Operations for further information. The Company’s loss from discontinued operations for the year ended December 31, 2013 was $370,000 or $0.04 per share, compared to a net loss of $201,000 or $0.02 per share for the year ended December 31, 2012, an increase of $169,000. The increased loss is primarily due to an increase in the state income tax rates applied to the Independence operations in North Carolina.
Net Income from Continuing Operations – Net income for the year ended December 31, 2013 was $7,042,000 or $0.75 per diluted share, compared to $3,920,000 or $0.48 per diluted share for the year ended December 31, 2012, an increase of $3,121,000. This was primarily due to colder weather and customer growth in 2013, income from our newly-acquired marketing company and lower acquisition expenses in 2013. Net income from our natural gas operations increased by $2,730,000, due primarily to colder weather and customer growth. Net income from our gas marketing and production operations increased by $436,000 due to increased net income from our LNG business and our newly-acquired marketing company GNR. Net income from our pipeline operations increased $28,000. Net loss from our corporate and other operations increased $72,000.
Revenues – Revenues increased by $29,634,000 to $118,835,000 for the year ended December 31, 2013 compared to $89,201,000 for 2012. The increase was primarily attributable to (1) a natural gas revenue increase of $24,959,000 due to colder weather in the majority of the markets we serve, higher prices for natural gas passed through to customers, growth in customers and revenue in our Maine and North Carolina markets, and a full year of operations from PGC which caused an increase in revenue of $716,000, and (2) an increase in revenue from our marketing and production operation of $4,674,000, primarily as a result of a full year of operations from our LNG line of business which caused an increase in revenue of $4,080,000 and sales from our newly-acquired marketing company, GNR, of $1,947,000 offset by a decrease in revenue of $1,353,000 by our existing marketing operations.
Gross Margin – Gross margin increased by $6,783,000 to $47,545,000 for the year ended December 31, 2013 compared to $40,762,000 for the same period in 2012. Gross margin from our natural gas operations increased $6,208,000 due to colder weather and growth in customers and margin in our North Carolina, Maine and Ohio markets. Gross margin from our marketing and production operations increased $574,000, primarily from our newly-formed GNR and from a full year of operations of our LNG business.
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Operating Expenses – Operating expenses, other than cost of sales, increased by $3,598,000 to $34,271,000 for the year ended December 31, 2013 compared to $30,673,000 for the same period in 2012. Operating expenses in natural gas operations increased by $3,284,000 due primarily to the following: (1) distribution, general and administrative expenses increased by $1,296,000 due to increases in salaries and professional services; (2) operating expenses from the newly-acquired Loring pipeline increased $669,000; (3) depreciation expense increased $569,000 due to the increases in capital expenditures; (4) other taxes increased $435,000 due to increased property taxes in our Montana and Maine subsidiaries; and (5) a full year of expenses associated with our newly acquired subsidiary PGC added additional expenses of $208,000. In our marketing and production segment, operating expenses from the newly-acquired marking company GNR accounted for $584,000 of decreased expenses in 2013, due to a net unrealized holding gain of $1,565,000, related to the required quarterly revaluation of the contingent consideration liability from the earn-out provision in the JDOG Marketing purchase contract, and partially offset by the goodwill impairment of $726,000. Operating expenses increased by $600,000 in the corporate and other segment compared to the prior year due primarily to increased professional fees and the write-off of $117,000 of construction work in progress relating to a software conversion project that has been terminated.
Loss from Unconsolidated Affiliate – Loss from unconsolidated affiliate decreased by $4,000 to $5,000 for the year ended December 31, 2013 compared to $9,000 for the same period in 2012.
Other Income (Expense), net – Other income (expense) increased by $489,000 to $925,000 for the year ended December 31, 2013 compared to $436,000 for the same period in 2012. The increase was primarily due to increased service sales in 2013 and a gain on the sale of compressed natural gas equipment of $154,000.
Acquisition Expense – Acquisition expense decreased by $687,000 to $272,000 for the year ended December 31, 2013 compared to $959,000 for the same period in 2012 due to less acquisition due diligence activity in the 2013 period. The 2013 period includes costs related to the acquisition of the assets of JDOG Marketing of $230,000 compared to $429,000 of costs in 2012. The 2012 period also included $149,000 related to the purchase of the Loring pipeline and $362,000 related to the potential expansion of natural gas into another state.
Stock Sale Expense – Stock sale expense increased by $35,000 to $309,000 for the year ended December 31, 2013 compared to $274,000 in 2012. The increase is due to the expenses paid in connection with our CEO’s stock sales which were completed in the fourth quarter of 2013 and the second quarter of 2012, respectively.
Interest Expense – Interest expense increased by $478,000 to $3,179,000 for the year ended December 31, 2013 compared to $2,700,000 in 2012. The amortizing term loan with Bank of America and the $2.989 million Senior Secured Guaranteed Note with Sun Life which were procured in the last half of 2012 resulted in an additional $161,000 and $99,000, respectively of interest expense in 2013, and the amortization of the debt issue costs incurred in obtaining these two loans resulted in $142,000 of additional expense in 2013. The capital lease obligation related to the Loring pipeline purchase resulted in a $127,000 increase in interest expense for the year ended December 31, 2013 compared to 2012. The borrowing on our Bank of America line of credit averaged $18,987,000 during 2013, compared to $20,111,000 in 2012, resulting in $61,000 less interest expense in 2013. The remaining difference is primarily due to interest incurred in the regular course of business.
Income Tax Expense – Income tax expense increased by $741,000 to $3,392,000 for the year ended December 31, 2013 compared to $2,651,000 for the same period in 2012. The increase is primarily due to the increase in pre-tax income. In addition, the 2013 and 2012 periods each included a tax benefit from the true-up to the prior year’s tax return of $103,000 and $245,000, respectively, causing an increase in tax expense of $142,000. Our effective tax rate was 37.5% for 2013 and 37.7% in 2012. The 2013 period included a tax benefit of $336,007 related to a change in the state effective tax rates as discussed inNote 14 – Income Taxes to the notes of our consolidated financial statements.
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Net Income by Service Area
The components of net income (loss) for 2013 and 2012 are:
| | | | | | | | |
| | | Years Ended December 31, | |
| ($ in thousands) | | 2013 | | | 2012 | |
| | |
Natural Gas Operations | | | | | | | | |
Energy West Montana (MT) | | $ | 1,345 | | | $ | 798 | |
Energy West Wyoming (WY) | | | 377 | | | | (2) | |
Frontier Natural Gas (NC) | | | 2,503 | | | | 2,103 | |
Bangor Gas (ME) | | | 2,383 | | | | 1,439 | |
Ohio Companies (OH and PA) | | | 633 | | | | 229 | |
Public Gas (KY) | | | (44) | | | | (100) | |
| | | | | | | | |
Total Natural Gas Operations | | $ | 7,197 | | | $ | 4,467 | |
Marketing & Production Operations | | | 1,037 | | | | 600 | |
Pipeline Operations | | | 121 | | | | 93 | |
| | | | | | | | |
| | | 8,355 | | | | 5,160 | |
Corporate & Other | | | (1,314) | | | | (1,240) | |
| | | | | | | | |
Income from Continuing Operations | | | 7,041 | | | | 3,920 | |
Propane Operations – Discontinued Operations | | | (370) | | | | (201) | |
| | | | | | | | |
| | |
Consolidated Net Income | | $ | 6,671 | | | $ | 3,719 | |
| | | | | | | | |
The following highlights our results by operating segments:
NATURAL GAS OPERATIONS
Income Statement
| | | | | | | | |
| | | Years Ended December 31, | |
| ($ in thousands) | | 2013 | | | 2012 | |
| | |
Natural Gas Operations | | | | | | | | |
Operating revenues | | $ | 106,265 | | | $ | 81,306 | |
Gas Purchased | | | 61,237 | | | | 42,486 | |
| | | | | | | | |
Gross Margin | | | 45,028 | | | | 38,820 | |
Operating expenses | | | 32,408 | | | | 29,124 | |
| | | | | | | | |
Operating income | | | 12,620 | | | | 9,696 | |
Other income | | | 805 | | | | 418 | |
| | | | | | | | |
Income before interest and taxes | | | 13,425 | | | | 10,114 | |
Interest expense | | | (2,881) | | | | (2,512) | |
| | | | | | | | |
Income before income taxes | | | 10,544 | | | | 7,602 | |
Income tax expense | | | (3,347) | | | | (3,135) | |
| | | | | | | | |
Net Income | | $ | 7,197 | | | $ | 4,467 | |
| | | | | | | | |
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Operating Revenues
| | | | | | | | |
| | | Years Ended December 31, | |
| ($ in thousands) | | 2013 | | | 2012 | |
| | |
Full Service Distribution Revenues | | | | | | | | |
Residential | | $ | 45,146 | | | $ | 35,016 | |
Commercial | | | 46,951 | | | | 33,501 | |
Industrial | | | 1,108 | | | | 814 | |
Other | | | 81 | | | | 104 | |
| | | | | | | | |
Total full service distribution | | | 93,286 | | | | 69,435 | |
Transportation | | | 11,828 | | | | 10,720 | |
Bucksport | | | 1,151 | | | | 1,151 | |
| | | | | | | | |
Total operating revenues | | $ | 106,265 | | | $ | 81,306 | |
| | | | | | | | |
Utility Throughput
| | | | | | | | |
| | | Years Ended December 31, | |
| (in MMcf) | | 2013 | | | 2012 | |
| | |
Full Service Distribution | | | | | | | | |
Residential | | | 5,143 | | | | 4,349 | |
Commercial | | | 5,075 | | | | 4,250 | |
Industrial | | | 202 | | | | 178 | |
| | | | | | | | |
Total full service | | | 10,420 | | | | 8,777 | |
Transportation | | | 11,558 | | | | 10,301 | |
Bucksport | | | 14,301 | | | | 14,144 | |
| | | | | | | | |
Total Volumes | | | 36,279 | | | | 33,222 | |
| | | | | | | | |
Heating Degree Days
A heating degree day is 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.
| | | | | | | | | | | | | | | | | | | | |
| | | | | | Years Ended
December 31, | | | Percent (Warmer) Colder
2013 Compared to | |
| | | Normal | | | 2013 | | | 2012 | | | Normal | | | 2012 | |
Great Falls, MT | | | 7,496 | | | | 7,350 | | | | 6,828 | | | | (1.95%) | | | | 7.64% | |
Cody, WY | | | 6,924 | | | | 7,161 | | | | 6,291 | | | | 3.42% | | | | 13.83% | |
Bangor, ME | | | 7,327 | | | | 7,786 | | | | 7,020 | | | | 6.26% | | | | 10.91% | |
Elkin, NC | | | 4,259 | | | | 4,320 | | | | 3,661 | | | | 1.43% | | | | 18.00% | |
Youngstown, OH | | | 6,349 | | | | 6,337 | | | | 5,345 | | | | (0.19%) | | | | 18.56% | |
Jackson, KY | | | 4,380 | | | | 4,711 | | | | 3,870 | | | | 7.56% | | | | 21.73% | |
Year Ended December 31, 2013 Compared with Year Ended December 31, 2012
Revenues and Gross Margin
Revenues increased by $24,959,000 to $106,265,000 for the year ended December 31, 2013 compared to $81,306,000 for the same period in 2012. This increase is the result of the following factors:
| | 1) | Revenue from our Montana and Wyoming markets increased $3,700,000 on a volume increase of 496 MMcf in the year ended December 31, 2013 compared to the year ended December 31, 2012 due to colder weather and higher prices for natural gas passed through to customers. |
| | 2) | Revenues from our Ohio market increased $8,854,000 due to colder weather and customer growth. Revenue to full service customers increased $8,620,000 on a volume increase in 2013 of 757 MMcf compared to 2012. |
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| | 3) | Revenue from our Maine and North Carolina markets increased by $11,689,000 on a volume increase from full service and transportation customers of 1,139 MMcf in 2013 compared to 2012 due to colder weather and customer growth. |
| | 4) | A full year of operations for PGC accounted for $716,000 of additional revenue. In March 2013, PGC completed a rate case providing for a monthly service charge and increased distribution base rate. |
Gas purchased increased by $18,751,000 to $61,237,000 for the year ended December 31, 2013 compared to $42,486,000 in 2012. The increase is due to higher prices for natural gas in 2013 compared to 2012 combined with the higher volume throughput. Included in the 2013 results is a charge of $1,502,000 for the disallowance of gas costs resulting from the gas cost recovery audit by the PUCO in Ohio. Our gas costs are passed on dollar for dollar to our customers under tariffs regulated by the various public utility commissions in the jurisdictions in which we operate. Our gas costs are subject to periodic audits and prudency reviews in all of these jurisdictions.
Gross margin increased by $6,208,000 to $45,028,000 for the year ended December 31, 2013 compared to $38,820,000 for the same period in 2012 due to customer growth in our Maine, North Carolina and Ohio markets and colder weather in all of our service territories. Maine and North Carolina accounted for $3,808,000 of the increase, Ohio for $1,663,000, Montana and Wyoming for $407,000, and PGC for $330,000.
Earnings
The Natural Gas Operations segment’s income for the year ended December 31, 2013 was $7,197,000, or $0.78 per diluted share, compared to $4,467,000, or $0.55 per diluted share for the year ended December 31, 2012.
Operating expenses increased by $3,284,000 to $32,408,000 for the year ended December 31, 2013 compared to $29,124,000 for the same period in 2012. Distribution, general and administrative expenses increased by $1,296,000 due to increases in salaries and professional services. Operating expenses from the newly-acquired Loring pipeline increased $669,000. Depreciation expense increased $569,000 due to the increased capital expenditures. Other taxes increased $435,000 due primarily to increased property taxes in our Montana and Maine subsidiaries. Operating expenses from the newly-acquired PGC increased by $208,000.
Other income increased by $387,000 to $805,000 for the year ended December 31, 2013 compared to $418,000 for the same period in 2012. Income from service sales in 2013 increased by $434,000 compared to 2012. Acquisition costs related to the purchase of the Matchworks building asset in 2013 totaled $47,000, compared to $154,000 of acquisition costs in 2012 related to the Loring purchase.
Interest expense increased by $369,000 to $2,881,000 for the year ended December 31, 2013 compared to $2,512,000 for the same period in 2012. The amortizing term loan with Bank of America and the $2.989 million Senior Secured Guaranteed Note with Sun Life which were procured in the last half of 2012 resulted in an additional $166,000 and $99,000, respectively of interest expense in 2013, and the amortization of the debt issue costs incurred in the obtaining of these two leans resulted in $111,000 of additional expense in 2013. The capital lease obligation related to the Loring pipeline purchase resulted in $160,000 expense for the year ended December 31, 2013 compared to $33,000 in 2012. The decreased borrowing on the Bank of America line of credit during 2013 compared to 2012 resulted in $144,000 less interest expense in 2013. The remaining difference is primarily due to interest incurred in the regular course of business.
Income tax expense increased by $211,000 to $3,347,000 for the year ended December 31, 2013 compared to $3,135,000 for the same period in 2012. The effect of the increase in pre-tax income in 2013 compared to the 2012 period is supplemented by the decrease in the true-up to the prior year’s tax return recorded in each year. The 2013 period includes a benefit of $107,000 related to the true-up of the prior year’s tax return, while the 2012 period included expense of $144,000, for an increase in expense of $37,000. The 2013 period included a tax benefit related to a change in the state effective tax rates as discussed inNote 14 – Income Taxes to the notes of our consolidated financial statements.
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MARKETINGAND PRODUCTION
Income Statement
| | | | | | | | |
| | | Years Ended December 31, | |
| ($ in thousands) | | 2013 | | | 2012 | |
| | |
Marketing and Production | | | | | | | | |
Operating revenues | | $ | 12,167 | | | $ | 7,493 | |
Gas Purchased | | | 10,053 | | | | 5,953 | |
| | | | | | | | |
Gross Margin | | | 2,114 | | | | 1,540 | |
Operating expenses | | | 500 | | | | 805 | |
| | | | | | | | |
Operating income | | | 1,614 | | | | 735 | |
Other income (loss) | | | 151 | | | | (6) | |
| | | | | | | | |
Income before interest and taxes | | | 1,765 | | | | 729 | |
Interest expense | | | (142) | | | | (134) | |
| | | | | | | | |
Income before income taxes | | | 1,623 | | | | 595 | |
Income tax benefit (expense) | | | (586) | | | | 5 | |
| | | | | | | | |
Net Income | | $ | 1,037 | | | $ | 600 | |
| | | | | | | | |
Year Ended December 31, 2013 Compared with Year Ended December 31, 2012
Revenues and Gross Margin
Revenues increased by $4,674,000 to $12,167,000 for the year ended December 31, 2013 compared to $7,493,000 for the same period in 2012. Our newly-formed GNR subsidiary containing the assets of JDOG Marketing purchased in June 2013 contributed revenue of $1,947,000. Revenue from our LNG business increased by $4,080,000. Revenue from our production operations increased by $88,000 due primarily to higher prices received for volumes produced. Revenues from our existing gas marketing operation decreased by $1,441,000, due primarily to lower sales volumes.
Gross margin increased by $574,000 to $2,114,000 for the year ended December 31, 2013 compared to $1,540,000 for the same period in 2012. GNR returned gross margin of $616,000 in 2013, our LNG business increased gross margin by $197,000 in 2013 compared to 2012, and gross margin from our production operation increased by $12,000. This was offset by a decrease in gross margin from our existing gas marketing operation of $251,000 due to the lower sales volumes.
Earnings
The Marketing and Production segment’s income for the year ended December 31, 2013 was $1,037,000, or $0.12 per diluted share, compared to income of $600,000, or $0.07 per diluted share for the year ended December 31, 2012.
Operating expenses decreased by $305,000 to $501,000 for the year ended December 31, 2013 compared to $805,000 for the same period in 2012. Our newly-acquired GNR subsidiary was responsible for $584,000 of decreased expenses in the 2013 period. This was primarily due to the net unrealized holding gain on the write down of the contingent consideration liability of $1,565,000 for the year, partially offset by goodwill impairment of $726,000 and amortization of customer relationships of $169,000. Expenses from our existing marketing and production operations increased by $279,000. This was primarily due to increased costs in salaries and fees for professional services.
Other income increased by $157,000 to income of $151,000 for the year ended December 31, 2013 compared to a loss of $6,000 for the same period in 2012 due to the gain on the sale of compressed natural gas equipment of $154,000. The loss from an unconsolidated affiliate was $5,000 in 2013, compared to $9,000 in 2012.
Income tax expense increased by $591,000 to an expense of $586,000 for the year ended December 31, 2013 compared to benefit of $5,000 for the same period in 2012. Tax expense increased on the increase in pre-tax
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income in 2013 compared to 2012. The 2013 and 2012 periods each included a tax benefit from the true-up to the prior year’s tax return of $6,000 and $241,000 respectively, accounting for an increase in expense of $235,000. The remaining increase is due to the increase in pre-tax income.
PIPELINE OPERATIONS
Income Statement
| | | | | | | | |
| | | Years Ended December 31, | |
| ($ in thousands) | | 2013 | | | 2012 | |
| | |
Pipeline Operations | | | | | | | | |
Operating revenues | | $ | 403 | | | $ | 402 | |
Gas Purchased | | | - | | | | - | |
| | | | | | | | |
Gross Margin | | | 403 | | | | 402 | |
Operating expenses | | | 217 | | | | 198 | |
| | | | | | | | |
Operating income | | | 186 | | | | 204 | |
Other income | | | - | | | | - | |
| | | | | | | | |
Income before interest and taxes | | | 186 | | | | 204 | |
Interest expense | | | (26) | | | | (13) | |
| | | | | | | | |
Income before income taxes | | | 160 | | | | 191 | |
Income tax expense | | | (39) | | | | (98) | |
| | | | | | | | |
Net Income | | $ | 121 | | | $ | 93 | |
| | | | | | | | |
Year Ended December 31, 2013 Compared with Year Ended December 31, 2012
Net income increased by $28,000 to $121,000 for the year ended December 31, 2013 compared to $93,000 for the same period in 2012. The overall impact of the results of our pipeline operations was not material to our results of consolidated operations.
CORPORATEAND OTHER
Our Corporate and Other reporting segment is intended primarily to encompass the results of corporate acquisitions and other equity transactions, as well as certain other income and expense items associated with Gas Natural’s holding company functions. Therefore, it does not have standard revenues, gas purchase costs, or gross margin.
Income Statement
| | | | | | | | |
| | | Years Ended December 31, | |
| ($ in thousands) | | 2013 | | | 2012 | |
| | |
Corporate and Other | | | | | | | | |
Operating revenues | | $ | - | | | $ | - | |
Gas Purchased | | | - | | | | - | |
| | | | | | | | |
Gross Margin | | | - | | | | - | |
Operating expenses | | | 1,146 | | | | 546 | |
| | | | | | | | |
Operating loss | | | (1,146) | | | | (546) | |
Other expense | | | (618) | | | | (1,231) | |
| | | | | | | | |
Loss before interest and taxes | | | (1,764) | | | | (1,776) | |
Interest expense | | | (130) | | | | (40) | |
| | | | | | | | |
Loss before income taxes | | | (1,894) | | | | (1,817) | |
Income tax benefit | | | 580 | | | | 577 | |
| | | | | | | | |
Loss from continuing operations | | | (1,314) | | | | (1,240) | |
Discontinued operations | | | (370) | | | | (201) | |
| | | | | | | | |
Net Loss | | $ | (1,684) | | | $ | (1,441) | |
| | | | | | | | |
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Year Ended December 31, 2013 Compared with Year Ended December 31, 2012
Results of corporate and other operations for the year ended December 31, 2013 include administrative costs of $1,146,000, acquisition related costs of $225,000, costs related to expenses for our CEO’s stock sale of $309,000, corporate expenses of $98,000, interest expense of $130,000, offset by an income tax benefit of $580,000, and interest and other income of $14,000, for a net loss from operations of $1,314,000.
Results of corporate and other operations for the year ended December 31, 2012 include administrative costs of $546,000 (of which $236,000 had previously been allocated to Independence), acquisition costs of $805,000, $429,000 of which relate to the acquisition of JDOG Marketing, costs related to expenses for our CEO’s stock sale of $274,000, corporate expenses of $163,000, interest expense of $40,000, offset by interest income of $12,000 and income tax benefit of $577,000 (of which $89,000 had previously been allocated to Independence), for a net loss from continuing operations of $1,240,000.
Loss from discontinued operations
A portion of the prior period and current period results of operations relate to the sale of the Independence assets and related business operations that have been reclassified as loss from discontinued operations. SeeNote 4 – Discontinued Operations to the notes of our consolidated financial statements for more information regarding the sale of Independence. Net loss from discontinued operations increased by $169,000 to a loss of $370,000 for the year ended December 31, 2013 as compared to a loss of $201,000 for the same period in 2012 due primarily to an increase in the state income tax rates applied to the Independence operations in North Carolina.
RELATED PARTY TRANSACTIONS
In the ordinary course of operations, we incur expenses for natural gas purchases, general and administrative expenses, and pipeline construction purchases from companies owned or controlled by Richard M. Osborne, our chairman and chief executive officer. SeeNote 15 – Related Party Transactions to the notes of our consolidated financial statements for more information regarding all of the Company’s related party transactions.
CAPITAL SOURCESAND LIQUIDITY
Sources and Uses of Cash
Operating activities provide our primary source of cash and are occasionally supplemented by equity offerings. At December 31, 2013 and 2012, we had approximately $13.1 million and $3.4 million of cash on hand, respectively. Cash provided by operating activities consists of net income adjusted for non-cash items, including depreciation and amortization, accretion, deferred income taxes and changes in working capital.
Cash provided by discontinued operations is presented separately from cash flows from continuing operations in the Consolidated Statement of Cash Flows. The disposition of the propane operations during the year ended December 31, 2013 is not expected to have a material negative impact on the Company’s liquidity.
Our ability to maintain liquidity depends upon our credit facility with Bank of America, shown as line of credit on the accompanying Consolidated Balance Sheets. Our use of the Bank of America revolving line of credit was $24.5 million and $23.9 million at December 31, 2013 and 2012, respectively. This increase is primarily attributable to capital expenditures in our Maine and North Carolina markets due to expansion. The line of credit from Yadkin Valley Bank was paid off and extinguished as part of the sale of the assets of Independence on November 6, 2013.
We made capital expenditures of $24.1 million and $20.7 million for the years ended December 31, 2013 and 2012, 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 $43.7 million and $44.3 million at December 31, 2013 and December 31, 2012, respectively, including the amount due within one year.
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Cash, excluding restricted cash, increased to $13.1 million at December 31, 2013, compared to $3.4 million at December 31, 2012.
| | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2013 | | | 2012 | |
Cash Flows from Continuing Operations | | | | | | | | |
Cash provided by operating activities | | $ | 16,656,000 | | | $ | 9,140,000 | |
Cash used in investing activities | | | (20,767,000) | | | | (23,206,000) | |
Cash provided by financing activities | | | 12,485,000 | | | | 7,165,000 | |
| | | | | | | | |
Increase (decrease) in cash | | $ | 8,374,000 | | | $ | (6,901,000) | |
| | | | | | | | |
Cash Flows from Discontinued Operations | | | | | | | | |
Cash used in operating activities | | $ | (394,000) | | | $ | (523,000) | |
Cash provided by (used in) investing activities | | | 2,346,000 | | | | (46,000) | |
Cash provided by (used in) financing activities | | | (614,000) | | | | 401,000 | |
| | | | | | | | |
Increase (decrease) in cash | | $ | 1,338,000 | | | $ | (168,000) | |
| | | | | | | | |
OPERATING CASH FLOW
For the year ended December 31, 2013, cash provided by operating activities increased by $7.5 million as compared to the year ended December 31, 2012. Major items affecting operating cash included an increase in net income from continuing operations of $3.1 million, a $2.7 million net increase in unbilled revenue, a $2.5 million decrease in prepayments, an increase of $2.3 million in purchases of inventory, a $2.2 million increase in accounts payable, a $2.0 million decrease in payments of other liabilities, a $1.5 million increase in collections of recoverable costs of gas, a $1.5 million decrease in payments for other assets, and a decrease in accounts receivable collections of $0.8 million.
INVESTING CASH FLOW
For the year ended December 31, 2013, cash used in investing activities decreased by $2.4 million as compared to the year ended December 31, 2012. This decrease is primarily attributable to a net increase in capital expenditures of $3.4 million comprised of $1.6 million paid for the acquisition of the Matchworks Building in Mentor, Ohio in 2013 and $4.1 million paid for other capital expenditures, a $2.6 million release of restricted cash related to capital expenditures, a $1.0 million increase in contributions in aid of construction, and a $0.9 million increase in proceeds from sales of fixed assets. In 2012, cash used in investing activities was impacted by the acquisition deposit paid for the purchase of the Loring pipeline of $2.3 million and the purchase of PGC for $1.6 million.
Capital Expenditures
Our capital expenditures for continuing operations totaled $24.1 million and $20.7 million for the years ended December 31, 2013 and 2012, respectively. Included in capital expenditures for 2013 is $1.6 million for the acquisition of the Matchworks Building in Mentor, Ohio. Included in capital expenditures for 2012 is $2.3 million for the acquisition of the Loring Pipeline.
The majority of our capital spending is focused on the growth of our Natural Gas Operations segment. We conduct ongoing construction activities in all of our utility service areas in order to support expansion, maintenance, and enhancement of our gas pipeline systems. We are actively expanding our systems in North Carolina and Maine to meet the high customer interest in natural gas service in those two service areas.
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The table below details our capital expenditures for the years ended December 31, 2013 and 2012 and provides an estimate of future cash requirements for the year ended December 31, 2014:
| | | | | | | | | | | | |
| | | Years Ended December 31, | | | Estimated Future Cash
Requirements for
December 31, 2014 | |
| | | |
| ($ in thousands) | | 2013 | | | 2012 | | |
Natural Gas Operations | | $ | 23,812 | | | $ | 18,382 | | | $ | 15,486 | |
Marketing and Production | | | 217 | | | | 1,393 | | | | - | |
Pipeline Operations | | | 3 | | | | 23 | | | | 45 | |
Corporate and Other | | | 58 | | | | 908 | | | | 222 | |
| | | | | | | | | | | | |
Total Capital Expenditures | | $ | 24,090 | | | $ | 20,706 | | | $ | 15,753 | |
| | | | | | | | | | | | |
FINANCING CASH FLOW
For the year ended December 31, 2013, cash provided by financing activities increased by $5.3 million as compared with the year ended December 31, 2012. The change is due primarily to $16.7 million in proceeds from the issuance of common shares in 2013 compared to $13 million proceeds from notes payable in 2012. In 2013, cash provided by financing activities also included a $1.6 million release of restricted cash related to our debt service fund, $0.6 million additional dividends paid, and $0.8 million in long term debt and capital lease payments, offset by a decrease in debt issuance cost of $1.2 million.
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 credit facilities with Bank of America shown as line of credit on the accompanying Consolidated Balance Sheets. Our use of the Bank of America revolving line of credit was $24.5 million and $23.9 million at December 31, 2013 and 2012, 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. The line of credit from Yadkin Valley Bank was paid off and extinguished as part of the sale of the assets of Independence on November 6, 2013. Long-term debt was $43.7 million and $44.3 million at December 31, 2013, and 2012, respectively, including the amount due within one year.
The following discussion describes our credit facilities as of December 31, 2013.
Bank of America Credit Agreement and Line of Credit
On September 20, 2012, the Company’s subsidiary, Energy West, entered into an Amended and Restated Credit Agreement (the “Credit Agreement”), with the Bank of America, N.A. (“Bank of America”) which modifies the original credit agreement entered into on June 29, 2007, as amended from time to time. The Credit Agreement renewed the $30.0 million revolving credit facility available to Energy West and provides for a maturity date of April 1, 2017. In addition, Energy West entered into a $10.0 million term loan with Bank of America with a maturity date of April 1, 2017 (the “Term Loan”). Pursuant to the terms of the Credit Agreement, Energy West issued a second amended and substitute note to Bank of America in the amount of $30.0 million for the revolving credit facility and another note in the original principal amount of $10.0 million for the Term Loan.
The Credit Agreement includes an annual commitment fee ranging from 25 to 45 basis points of the unused portion of the Credit Agreement and interest on the amounts outstanding at the LIBOR rate plus 175 to 225 basis points.
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The following table represents borrowings under the Bank of America revolving line of credit for each of the fiscal quarters and the years ended December 31, 2013 and 2012.
| | | | | | | | | | | | | | | | | | | | |
| ($ in thousands) | | First
Quarter | | | Second Quarter | | | Third
Quarter | | | Fourth Quarter | | | Full Year | |
Year Ended December 31, 2013 | | | | | | | | | | | | | | | | | | | | |
Minimum borrowing | | $ | 17,920 | | | $ | 13,000 | | | $ | 14,611 | | | $ | 18,211 | | | $ | 13,000 | |
Maximum borrowing | | $ | 23,860 | | | $ | 17,920 | | | $ | 18,211 | | | $ | 25,830 | | | $ | 25,830 | |
Average borrowing | | $ | 20,893 | | | $ | 14,903 | | | $ | 16,712 | | | $ | 21,729 | | | $ | 18,987 | |
| | | | | |
Year Ended December 31, 2012 | | | | | | | | | | | | | | | | | | | | |
Minimum borrowing | | $ | 16,800 | | | $ | 15,100 | | | $ | 18,020 | | | $ | 18,020 | | | $ | 15,100 | |
Maximum borrowing | | $ | 23,610 | | | $ | 17,650 | | | $ | 26,966 | | | $ | 23,860 | | | $ | 26,966 | |
Average borrowing | | $ | 20,363 | | | $ | 16,381 | | | $ | 22,899 | | | $ | 20,802 | | | $ | 20,111 | |
For the years ended December 31, 2013 and 2012, the weighted average interest rate on the existing and renewed revolving credit facility was 2.42% and 3.33%, respectively, resulting in $454,551 and $500,063 of interest expense, respectively. The balance on the revolving credit facility was $24.5 million and $23.9 million at December 31, 2013 and 2012, respectively. The $24.5 million of borrowings as of December 31, 2013, leaves the remaining borrowing capacity on the line of credit at $5.5 million.
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 $43.7 million at December 31, 2013, with $4.2 million being due within one year.
Bank of America Term Loan
The Term Loan portion of the Bank of America credit agreement has an interest rate of LIBOR plus 175 to 225 basis points with an interest rate swap provision that allows for the interest rate to be fixed in the future. The Term Loan is amortized at a rate of $125,000 per quarter. As of December 31, 2013, the Company had not exercised the interest rate swap provision for the fixed interest rate.
For the year ended December 31, 2013, the weighted average interest rate was 2.19% resulting in interest expense of $215,593. The balance outstanding on the Term Loan at December 31, 2013 was $9,375,000.
Senior Unsecured Notes of Energy West
On June 29, 2007, Energy West authorized the sale of $13,000,000 aggregate principal amount of its 6.16% Senior Unsecured Notes with Allstate/CUNA, due June 29, 2017 (the “Senior Unsecured Notes”). The proceeds of these notes were used to refinance existing notes. Interest expense was $800,800 for the years ended December 31, 2013 and 2012.
Sun Life Assurance Company of Canada
On May 2, 2011, the Company and its Ohio subsidiaries, NEO, Orwell and Brainard (together “the Issuers”), issued a $15.3 million, 5.38% Senior Secured Guaranteed Fixed Rate Note due June 1, 2017 (“Fixed Rate Note”). Additionally, Great Plains issued a $3.0 million, Senior Secured Guaranteed Floating Rate Note due May 3, 2014 (“Floating Rate Note”). Both notes were placed with Sun Life.
Each of the notes is governed by a Note Purchase Agreement (“NPA”). Concurrent with the funding and closing of the notes, which occurred on May 3, 2011, the parties executed amended note purchase agreements that are substantially the same as the note purchase agreements executed on November 2, 2010. On April 9, 2012, the Company entered into a waiver and amendment of the Fixed Rate Note and Floating Rate Note to cure certain breaches of covenants. The Company has remedied the breaches and is currently in compliance with the covenants.
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The Fixed Rate Note, in the amount of $15.3 million, is a joint obligation of the Issuers, and is guaranteed by the Company, Lightning Pipeline and Great Plains (together with the Issuers, the “Fixed Rate Obligors”). Prepayment of this note prior to maturity is subject to a 50 basis point make-whole premium.
The Floating Rate Note, in the amount of $3.0 million, is an obligation of Great Plains and is guaranteed by the Company (together, the “Floating Rate Obligors”). The note is priced at a fixed spread of 385 basis points over three month LIBOR. Pricing for this note will reset on a quarterly basis to the then current yield of three month LIBOR. Prepayment of this note prior to maturity is at par.
The use of proceeds for both notes extinguished existing amortizing bank debt and other existing indebtedness, funded $3.4 million for the 2011 capital program for Orwell and NEO, established two debt service reserve accounts, and replenished the Company’s treasuries prior repayment of maturing bank debt and transaction expenses. The capital program funds and debt service reserve accounts are in interest bearing accounts and included in restricted cash.
Payments for both notes prior to maturity are interest-only.
For the years ended December 31, 2013 and 2012, the weighted average interest rate on the Fixed Rate Note was 5.38%, resulting in $824,969 and $824,969 of interest expense, respectively. For the years ended December 31, 2013 and 2012, the weighted average interest rate on the Floating Rate Note was 4.13% and 4.31%, resulting in $123,850 and $129,200 of interest expense, respectively.
On October 24, 2012, Orwell, NEO, and Brainard issued a Senior Secured Guaranteed Note in the amount of $2.989 million. The Senior Note was placed with Sun Life, pursuant to a third amendment to the original NPA dated as of November 1, 2010, by and among Orwell, NEO, and Brainard, and Great Plains, Lightning Pipeline, Gas Natural and Sun Life. The Senior Note will bear an interest rate of 4.15%, compounded semi-annually, and it matures on June 1, 2017. The Senior Note is a joint obligation of the Ohio subsidiaries and is guaranteed by Gas Natural’s non-regulated Ohio subsidiaries. For the years ended December 31, 2013 and 2012, the weighted average interest rate on the Senior Note was 4.15% resulting in $123,007 and $23,576 of interest expense, respectively.
Yadkin Valley Bank
On February 13, 2012, Independence entered into a one year, $500,000 revolving credit facility with Yadkin Valley Bank with an interest rate based on the prime rate, with a floor of 4.5% per annum and a maximum of 16% per annum. The revolving credit facility expired February 13, 2013. On April 12, 2013, Yadkin Valley Bank extended the $500,000 commercial line of credit beginning May 12, 2013. The debt was secured by a blanket lien on all assets owned or acquired by Independence. For the years ended December 31, 2013 and 2012, the weighted average interest rate on the facility was 4.5%, resulting in $11,912 and $11,350 of interest expense, respectively. The balance on the facility was $401,000 at December 31, 2012. On November 6, 2013, the credit facility was paid off and extinguished as part of the sale of the assets of Independence. SeeNote 4 – Discontinued Operations for more information regarding this sale.
Debt Covenants
The Bank of America revolving credit agreement and term loan contain various covenants, which include limitations on total dividends and distributions, limitations on investments in other entities, maintenance of certain debt-to-capital and interest coverage ratios, and restrictions on certain indebtedness as outlined below.
The credit facility restricts Energy West’s ability to pay dividends and make distributions, redemptions and repurchases of stock during any 60-month period to 80% (previously 75%) of its net income over that period. In addition, no event of default may exist at the time such dividend, distribution, redemption or repurchase is made.
The amended credit facility limits investments in another entity by acquisition of any debt or equity securities or assets or by making loans or advances to such entity. Energy West is also prohibited from consummating a merger or consolidation or selling all or substantially all of its assets or stock except for (i) any merger consolidation or sale by or with certain of its subsidiaries, (ii) any such purchase or other
41
acquisition by Energy West or certain of its subsidiaries and (iii) sales and dispositions of assets for at least fair market value so long as the net book value of all assets sold or otherwise disposed of in any fiscal year does not exceed 5% of the net book value of Energy West’s assets as of the last day of the preceding fiscal year.
Energy West must maintain a total debt- to-capital ratio of not more than .55-to-1.00 and an interest coverage ratio of no less than 2.0-to-1.0. The credit facility restricted Energy West’s ability to create, incur or assume indebtedness except (i) indebtedness under the credit facility (ii) indebtedness incurred under certain capitalized leases including the capital lease related to the Loring pipeline, and purchase money obligations not to exceed $500,000, (iii) certain indebtedness of Energy West’s subsidiaries, (iv) certain subordinated indebtedness, (v) certain hedging obligations and (vi) other indebtedness not to exceed $1.0 million.
The Senior Unsecured Notes contain various covenants, which include limitations on Energy West’s total dividends and distributions, restrictions on certain indebtedness as outlined below, maintenance of certain interest coverage ratios, and limitations on asset sales as outlined below.
The credit facility limits Energy West’s total dividends and distributions made in the immediately preceding 60-month period to 100% of aggregate consolidated net income for such period.
The notes restrict Energy West from incurring additional senior indebtedness in excess of 65% of capitalization at any time.
The credit facility also requires Energy West to maintain an interest coverage ratio of more than 150% of the pro forma annual interest charges on a consolidated basis in two of the three preceding fiscal years.
Energy West is prohibited from selling or otherwise disposing of any of its property or assets except (i) in the ordinary course of business, (ii) property or assets that are no longer usable in its business or (iii) property or assets transferred between Energy West and its subsidiaries if the aggregate net book value of all properties and assets so disposed of during the twelve month period next preceding the date of such sale or disposition would constitute more than 15% of the aggregate book value of all Energy West’s tangible assets. In addition, Energy West may only consummate a merger or consolidation, dissolve or otherwise dispose of all or substantially all of its assets (i) if there is no event of default, (ii) the provisions of the notes are assumed by the surviving or continuing corporation and such entity further agrees that it will continue to operate its facilities as part of a system comprising a public utility regulated by the Public Service Commission of Montana or another federal or state agency or authority and (iii) the surviving or continuing corporation has a net worth immediately subsequent to such acquisition, consolidation or merger equal to or greater than $10 million.
The Sun Life Fixed Rate Note, Floating Rate Note, and Senior Note contain various covenants, which include, among others, limitations on total dividends and distributions, restrictions on certain indebtedness, limitations on asset sales, and maintenance of certain debt-to-capital and interest coverage ratios as outlined below.
The amendments provide that any cash dividends, distributions, redemptions or repurchases of common stock may be made by the obligors to the holding company only if (i) the aggregate amount of all such dividends, distributions, redemptions and repurchases for the fiscal year do not exceed 70% of net income of the obligors for the four fiscal quarters then ending determined as of the end of each fiscal quarter for the four fiscal quarters then ending, and (ii) there exists no other event of default at the time the dividend, distribution, redemption or repurchase is made. Due to the covenants, the Obligors are unable to pay a dividend to the holding company, which may impact the Company’s ability to pay a dividend to shareholders.
The Ohio subsidiaries and PGC are prohibited from creating, assuming or incurring additional indebtedness except for (i) obligations under certain financing agreements, (ii) indebtedness incurred under certain capitalized leases and purchase money obligations not to exceed $500,000 at any one time outstanding, (iii) indebtedness outstanding as of March 31, 2011, (iv) certain unsecured intercompany indebtedness and (v) certain other indebtedness permitted under the notes.
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The notes prohibit us from selling or otherwise transferring assets except in the ordinary course of business and to the extent such sales or transfers, in the aggregate, over each rolling twelve month period, do not exceed 1% of our total assets. Generally, we may consummate a merger or consolidation if there is no event of default and the provisions of the notes are assumed by the surviving or continuing corporation. We are also generally limited in making acquisitions in excess of 10% of our total assets. An event of default, if not cured, would require us to immediately pay the outstanding principal balance of the notes as well as any and all interest and other payments due. An event of default would also entitle Sun Life to exercise certain rights with respect to the collateral that secures the indebtedness incurred under the notes.
The Fixed Rate Note and Floating Rate Note require, on a consolidated basis, an interest coverage ratio of at least 2.0 to 1.0, measured quarterly on a trailing four quarter basis. The notes generally define the interest coverage ratio as the ratio of EBITDA to gross interest expense. The note defines EBITDA as net income plus the sum of interest expense, any provision for federal, state, and local taxes, depreciation, and amortization determined on a consolidated basis in accordance with GAAP, but excluding any extraordinary non-operating income or loss and any gain or loss from non-operating transactions. The interest coverage ratio is measured with respect to the Obligors on a consolidated basis and also with respect to the Company and all of its subsidiaries, on a consolidated basis. The notes also require that the Company does not permit indebtedness to exceed 60% of capitalization at any time. Like the interest coverage ratio, the ratio of debt to capitalization is measured on a consolidated basis for the Obligors, and again on a consolidated basis with respect to the Company and all of its subsidiaries.
Additionally, Sun Life restricted certain cash balances and required two main types of debt service reserve accounts to be created to cover approximately one year of interest payments. The balance in both debt service reserve accounts was $1,080,000 and $1,078,000 at December 31, 2013 and 2012, respectively, and is included in restricted cash. The debt service reserve accounts cannot be used for operating cash needs. In addition, the Company had deposited $750,000 into a reserve account where Sun Life is the beneficiary. In July, 2013, this additional covenant was lifted and the cash became unrestricted.
The Senior Note is a joint obligation of the Ohio subsidiaries and is guaranteed by Gas Natural’s non-regulated Ohio subsidiaries. The Senior Note is subject to other customary loan covenants and default provisions.
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
Our recently adopted and issued accounting pronouncements can be found inNote 2 – Significant Accounting Policies to the notes of our consolidated financial statements.
ITEM 7A. QUANTITATIVEAND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
We are subject to certain market risks, including commodity price risk (i.e., natural gas prices) and credit 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.
COMMODITY PRICE RISK
We seek to protect our self 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
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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 counterparty 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 STATEMENTSAND SUPPLEMENTARY DATA.
Our Consolidated Financial Statements begin on page F-1 of this Annual Report on Form 10-K.
ITEM 9. CHANGESINAND DISAGREEMENTS WITH ACCOUNTANTSON ACCOUNTINGAND FINANCIAL DISCLOSURE.
As previously disclosed in a Current Report on Form 8-K dated December 27, 2013, following a competitive selection process, the Company entered into an engagement letter with MaloneBailey LLP (“MaloneBailey”), approved by the Audit Committee, and engaged MaloneBailey as the Company’s independent registered public accounting firm to replace ParenteBeard LLC (“ParenteBeard”).
ParenteBeard’s reports on the Company’s consolidated financial statements for the years ended December 31, 2012 and 2011 contained no adverse opinion or disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope or accounting principles. During the Company’s fiscal 2012 and fiscal 2011 and the subsequent interim period preceding ParenteBeard’s dismissal, there were:
| (i) | no “disagreements” (within the meaning of Item 304(a) of Regulation S-K) with ParenteBeard on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of ParenteBeard, would have caused it to make reference to the subject matter of the disagreements in its reports on the consolidated financial statements of the Company; and |
| (ii) | no “reportable events” (as such term is defined in Item 304(a)(1)(v) of Regulation S-K). |
ITEM 9A. CONTROLSAND PROCEDURES.
EVALUATIONOF DISCLOSURE CONTROLSAND PROCEDURES
As of December 31, 2013, we evaluated the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rule 13a-15(e) of the Exchange Act. 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, 2013.
MANAGEMENT’S REPORTON INTERNAL CONTROLOVER FINANCIAL REPORTING
As of December 31, 2013, we evaluated the effectiveness of the design and operation of our internal control over financial reporting as defined in Rule 13a-15(f) 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 internal control over financial reporting was not effective as of December 31, 2013.
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In our assessment of the effectiveness of internal control over financial reporting at December 31, 2013, we have identified a material weakness related to our procedures concerning gas procurement from related parties and gas cost recovery. In 2011, the PUCO, following a gas cost recovery audit, directed us to modify the gas procurement procedures at our Ohio utilities, NEO and Orwell, and adjust amounts billed to our Ohio customers for the audit period. In its audit in 2012, the PUCO staff argued that we failed to comply with the procedures set forth in the prior GCR audit. This led to the disallowance of gas costs in the PUCO’s November 13, 2013 Order as discussed in Note 17 — Commitments and Contingencies of our accompanying consolidated financial statements. During 2013, we accrued the amount of the disallowance as well as post audit period costs that were disallowed during the audit period. This accrual remains on our balance sheet at December 31, 2013. The failure to comply with the PUCO Order leads management to conclude that we did not maintain adequate and effective internal control in the area of our gas supply procurement and the gas cost recovery through rates.
We have implemented measures that we believe remediated the weakness in our internal control over financial reporting described above. We have accrued the amount of the disallowance in the three months ended June 30, 2013 and we performed additional analyses and implemented additional procedures designed to provide reasonable assurance that our consolidated financial statements were prepared in accordance with GAAP. As a result, we believe that the condensed consolidated financial statements included in this Form 10-K as of and for the year ended December 31, 2013 fairly presents, in all material respects, our financial condition, results of operations and cash flow for the periods presented, in conformity with GAAP.
During the third quarter, we implemented changes at Gas Natural to improve our internal control over financial reporting such as (1) hiring a new corporate controller, a new controller at our Ohio utilities and two new general accountants, (2) attending training sessions given by the PUCO for gas recovery procedures, and (3) effecting other corporate and accounting changes referenced in the PUCO Order.
During the fourth quarter, we continued to implement changes to improve our internal control over financial reporting such as (1) our utilities began purchasing local production gas directly, bypassing possible related party mark-ups and fees on this gas, (2) adopting procedures that ensure that local production gas purchased from GNR by our utilities must come from unrelated, third-party pipelines at competitive prices and without commission, (3) we started the process of designing and implementing our new RFP for gas purchasing, which was successfully completed on March 14, 2014, and (4) we continue to improve our Ohio GCR filings through an active dialogue between us and the PUCO staff.
We completed our remediation efforts to fully comply with the PUCO Order, which included design, implementation and testing, during the first quarter of 2014.
We believe that the remediation measures described above have strengthened our internal control over financial reporting related to our procedures concerning gas procurement from related parties and gas cost recovery and remediated the material weakness discussed above. We are committed to continuing to improve our internal control processes and will continue to diligently review our financial controls and procedures.
CHANGESIN INTERNAL CONTROLOVER FINANCIAL REPORTING
Other than as stated above, there were no changes in our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ATTESTATION REPORTOF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We are not required to include an attestation report of our registered public accounting firm regarding internal control over financial reporting in this Form 10-K. 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.
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ITEM 9B. OTHER INFORMATION.
On March 26, 2014, the board of directors formed a special committee comprised of three independent directors to investigate the allegations contained in a letter received from one of our shareholders. The letter demands that the board take legal action to remedy alleged breaches of fiduciary duties by the board and certain of our executive officers in connection with the Order and Opinion issued by the PUCO on November 13, 2013. The special committee has the power to retain any advisors, including legal counsel and accounting, financial and regulatory advisors, that the committee determines to be appropriate to carry out its responsibilities in connection with its investigation. The special committee will investigate, evaluate and determine the position Gas Natural will take with respect to the letter.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERSAND 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 2014 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 2014 Annual Meeting.
ITEM 12. SECURITY OWNERSHIPOF CERTAIN BENEFICIAL OWNERSAND MANAGEMENTAND 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 2014 Annual Meeting.
ITEM 13. CERTAIN RELATIONSHIPSAND 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 2014 Annual Meeting.
ITEM 14. PRINCIPAL ACCOUNTING FEESAND SERVICES.
Information required by this item is incorporated by reference to the material appearing under the heading “Principal Accountant Firm Fees and Services” in the Proxy Statement for our 2014 Annual Meeting.
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PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.
(A) FINANCIAL STATEMENTS
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| | | Page No. | |
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Report of Independent Registered Public Accounting Firm – MaloneBailey LLP | | | F-2 | |
Report of Independent Registered Public Accounting Firm – ParenteBeard LLC | | | F-3 | |
Consolidated Balance Sheets | | | F-4 | |
Consolidated Statements of Comprehensive Income | | | F-6 | |
Consolidated Statements of Changes in Stockholders’ Equity | | | F-7 | |
Consolidated Statements of Cash Flows | | | F-8 | |
Notes to Consolidated Financial Statements | | | F-10 | |
Schedule I – Condensed Financial Information of Registrant for the years ended December 31, 2013 and 2012 | | | 54 | |
Schedule II – Financial Statement Schedules | | | | |
Schedule II omitted because of the absence of the conditions under which it is required or because the required information is shown in the financial statements or notes thereto | | | | |
(B) EXHIBIT INDEX
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| 1 | | Underwriting Agreement, dated June 27, 2012, by and among Richard M. Osborne, as Trustee of the Chowder Trust dated February 24, 2012, the Selling Shareholder named therein, and Janney Montgomery Scott LLC, as representative of the several underwriters named therein. Filed as, and incorporated herein by reference to, Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on June 27, 2012 |
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| 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. Filed as, and incorporated herein by reference to, Exhibit 10.2 to Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on July 2, 2009 |
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| 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. Filed as, and incorporated herein by reference to, Exhibit 10.3 to Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on July 2, 2009 |
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| 2.3 | | Agreement and Plan of Merger, dated August 3, 2009, by and among Energy Inc., Energy West, Incorporated and Energy West Merger Sub, Inc. Filed as, and incorporated herein by reference to, Exhibit 2.1 to Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on August 4, 2009 |
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| 2.4 | | Assignment and Assumption Agreement, dated December 30, 2009, by and between Energy West, Incorporated and Gas Natural Inc. Filed as, and incorporated herein by reference to, Exhibit 2.3 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on January 11, 2010 |
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| 2.5 | | Assignment and Assumption Agreement, dated December 30, 2009, by and between Energy West, Incorporated and Gas Natural Inc. Filed as, and incorporated herein by reference to, Exhibit 2.4 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on January 11, 2010 |
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| 2.6 | | First Amendment to Agreement and Plan of Merger, dated as of January 4, 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, and incorporated herein by reference to, Exhibit 2.5 to the Registrant’s Current Report on Form 8-K, as filed with the Securities Exchange Commission on January 11, 2010 |
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| 2.7 | | First Amendment to Agreement and Plan of Merger, dated as of January 4, 2010, by and among Richard M. Osborne, Trustee, Great Plains Land Development Company, LTD., GPL Acquisition LLC and Gas Natural Inc. Filed as, and incorporated herein by reference to, Exhibit 2.6 to the Registrant’s Current Report on Form 8-K, as filed with the Securities Exchange Commission on January 11, 2010 |
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| 3.1 | | Articles of Incorporation of Gas Natural Inc., dated July 15, 2010. Filed as, and incorporated herein by reference to, Exhibit 3.1 to the Registrant’s Form S-1/A, as filed with the Securities and Exchange Commission on July 15, 2010 |
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| 3.2 | | Code of Regulations of Gas Natural Inc., dated July 15, 2010. Filed as, and incorporated herein by reference to, Exhibit 3.2 to the Registrant’s Form S-1/A, as filed with the Securities and Exchange Commission on July 15, 2010 |
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| 10.1 | | Note Purchase Agreement, dated June 29, 2007, between Energy West, Incorporated and various Purchasers relating to 6.16% Senior Unsecured Notes due June 29, 2017. Filed as, and incorporated herein by reference to, Exhibit 10.4 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on July 5, 2007 |
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| 10.2† | | Employee Stock Ownership Plan Trust Agreement. Filed as, and incorporated herein by reference to, Exhibit 10.2 to Registration Statement on Form S-1 (File No. 33-1672), as filed with the Securities and Exchange Commission on November 20, 2005 |
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| 10.3† | | Gas Natural Inc. 2012 Incentive and Equity Award Plan. Filed as, and incorporated herein by reference to, Annex B to the Registrant’s Proxy Statement on Schedule 14A, as filed with the Securities and Exchange Commission on November 19, 2012 |
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| 10.4† | | Gas Natural Inc. 2012 Non-Employee Director Stock Award Plan. Filed as, and incorporated herein by reference to, Annex C to the Registrant’s Proxy Statement on Schedule 14A, as filed with the Securities and Exchange Commission on November 19, 2012 |
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| 10.5† | | Employment Agreement, dated December 18, 2013, between Gas Natural Inc. and James E. Sprague. Filed as, and incorporated herein by reference to, Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on December 20, 2013 |
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| 10.6 | | 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, and incorporated herein by reference to, Exhibit 10.26 to the Registrant’s Annual Report on Form 10-K for the year ended June 30, 2008, as filed with the Securities and Exchange Commission on September 30, 2008 |
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| 10.7 | | First Amendment to the Orwell-Trumbull Pipeline Co., LLC Operations Agreement, dated July 1, 2008, between Orwell Natural Gas Company and Orwell-Trumbull Pipeline Co., LLC. Filed as, and incorporated herein by reference to Exhibit 10.28 to the Registrant’s Annual Report on Form 10-K for the year ended June 30, 2008, as filed with the Securities and Exchange Commission on September 30, 2008 |
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| 10.8 | | 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, and incorporated herein by reference to, Exhibit 10.27 to the Registrant’s Annual Report on Form 10-K for the year ended June 30, 2008, as filed with the Securities and Exchange Commission on September 30, 2008 |
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| 10.9 | | Orwell-Trumbull Pipeline Co., LLC Operations Agreement, dated January 1, 2008, between Orwell Natural Gas Company and Orwell-Trumbull Pipeline Co., LLC. Filed as, and incorporated herein by reference to, Exhibit 10.29 to the Registrant’s Annual Report on Form 10-K for the year ended June 30, 2008, as filed with the Securities and Exchange Commission on September 30, 2008 |
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| 10.10 | | Triple Net Lease Agreement, dated as of July 1, 2008, between Station Street Partners, LLC and Orwell Natural Gas Company. Filed as, and incorporated herein by reference to, Exhibit 10.30 to the Registrant’s Annual Report on Form 10-K for the year ended June 30, 2008, as filed with the Securities and Exchange Commission on September 30, 2008 |
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| 10.11 | | Triple Net Lease Agreement, dated as of July 1, 2008, between Richard M. Osborne, Trustee and Orwell Natural Gas Company. Filed as, and incorporated herein by reference to, Exhibit 10.32 to the Registrant’s Annual Report on Form 10-K for the year ended June 30, 2008, as filed with the Securities and Exchange Commission on September 30, 2008 |
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| 10.12 | | Electronic Metering Service and Operation Agreement, dated April 15, 2009, by and between Orwell Trumbull Pipeline, LTD. and Orwell Natural Gas Co. Filed as, and incorporated herein by reference to, Exhibit 10.4 to Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on July 2, 2009 |
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| 10.13 | | Electronic Metering Service and Operation Agreement, dated April 15, 2009, by and between COBRA Pipeline Company, LTD. and Brainard Gas Corporation. Filed as, and incorporated herein by reference to, Exhibit 10.5 to Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on July 2, 2009 |
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| 10.14 | | Electronic Metering Service and Operation Agreement, dated April 15, 2009, by and between COBRA Pipeline Company, LTD. and Northeast Ohio Natural Gas Corporation. Filed as, and incorporated herein by reference to, Exhibit 10.6 to Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on July 2, 2009 |
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| 10.15 | | Electronic Metering Service and Operation Agreement, dated April 15, 2009, by and between COBRA Pipeline Company, LTD. and Orwell Natural Gas Co. Filed as, and incorporated herein by reference to, Exhibit 10.7 to Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on July 2, 2009 |
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| 10.16 | | Reaffirmation and Second Amendment to Credit Facility, dated June 1, 2012, by and among Energy West, Incorporated and Bank of America, N.A. Filed as, and incorporated herein by reference to, Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on June 5, 2012 |
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| 10.17 | | Reaffirmation and Third Amendment to Credit Facility, dated August 22, 2012, by and among Energy West, Incorporated and Bank of America, N.A. Filed as, and incorporated herein by reference to, Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on August 28, 2012 |
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| 10.18 | | Amended and Restated Credit Agreement dated September 20, 2012, by and among Energy West, Incorporated and the Bank of America, N.A., as agent for various participating banks. Filed as, and incorporated herein by reference to, Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on September 26, 2012 |
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| 10.19 | | Term Note dated September 20, 2012, in the original principal amount of $10.0 million, by and among Energy West, Incorporated and Bank of America, N.A., as agent for various participating banks. Filed as, and incorporated herein by reference to, Exhibit 10.2 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on September 26, 2012 |
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| 10.20 | | Second Amended and Substitute Note dated September 20, 2012, regarding the $30.0 million Credit Facility, by and by and among Energy West, Incorporated and the Bank of America, N.A., as agent for various participating banks. Filed as, and incorporated herein by reference to, Exhibit 10.3 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on September 26, 2012 |
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| 10.21 | | Continuing Guaranty dated September 20, 2012, by and among Penobscot Natural Gas Company, Bangor Gas Company, LLC, and Bank of America, N.A., as agent for various participant banks. Filed as, and incorporated herein by reference to, Exhibit 10.4(a) to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on September 26, 2012 |
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| 10.22 | | Continuing Guaranty dated September 20, 2012, by and among Energy West Montana Inc. and Bank of America N.A., as agent for various participant banks. Filed as, and incorporated herein by reference to, Exhibit 10.4(b) to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on September 26, 2012 |
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| 10.23 | | Continuing Guaranty dated September 20, 2012, by and among Frontier Utilities of North Carolina, Inc., Frontier Natural Gas Company, LLC and Bank of America N.A., as agent for various participant banks. Filed as, and incorporated herein by reference to, Exhibit 10.4(c) to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on September 26, 2012 |
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| 10.24 | | Continuing Guaranty dated September 20, 2012, by and among Energy West Properties, LLC, Energy West Development, Inc., Energy West Resources, Inc., and Energy West Propane, Inc, and Bank of America N.A., as agent for various participant banks. Filed as, and incorporated herein by reference to, Exhibit 10.4(d) to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on September 26, 2012 |
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| 10.25 | | Continuing Guaranty dated September 20, 2012, by and among Energy West Wyoming, Inc. and Bank of America N.A., as agent for various participant banks. Filed as, and incorporated herein by reference to, Exhibit 10.4(e) to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on September 26, 2012 |
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| 10.26 | | First Amendment and Joinder to Note Purchase Agreement, dated May 3, 2011, by and among Northeast Ohio Natural Gas Corp., Orwell Natural Gas Company, Brainard Gas Corp. and Great Plains Natural Gas Company, Lightning Pipeline Company, Inc., Spelman Pipeline Holdings, LLC, Kidron Pipeline, LLC, Gas Natural Service Company, LLC, Gas Natural Inc. and Sun Life Assurance Company of Canada. Filed as, and incorporated herein by reference to, Exhibit 10.3 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on May 5, 2011 |
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| 10.27 | | First Amendment and Joinder to Note Purchase Agreement, dated May 3, 2011, by and among Great Plains Natural Gas Company and Lightning Pipeline Company, Inc., Spelman Pipeline Holdings LLC, Kidron Pipeline, LLC, Gas Natural Service Company, LLC and Gas Natural Inc. and Sun Life Assurance Company of Canada, as the purchaser. Filed as, and incorporated herein by reference to, Exhibit 10.4 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on May 5, 2011 |
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| 10.28 | | Senior Secured Guaranteed Note Agreement, dated May 3, 2011, by and among Northeast Ohio Natural Gas Corp, Orwell Natural Gas Co., and Brainard Gas Corp. and Sun Life Assurance Company of Canada. Filed as, and incorporated herein by reference to, Exhibit 10.5 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on May 5, 2011 |
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| 10.29 | | Floating Rate Senior Secured Guaranteed Note Agreement, dated May 3, 2011, by and among Great Plains Natural Gas Company and Sun Life Assurance Company of Canada. Filed as, and incorporated herein by reference to, Exhibit 10.6 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on May 5, 2011 |
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| 10.30 | | Security Agreement, dated May 3, 2011 by and among Northeast Ohio Natural Gas Corp., Orwell Natural Gas Company, Brainard Gas Corp., Great Plains Natural Gas Company, Lightning Pipeline Company Inc., Spelman Pipeline Holdings, Kidron Pipeline LLC, Gas Natural Service Company, LLC, Gas Natural Inc. and Sun Life Assurance Company of Canada. Filed as, and incorporated herein by reference to, Exhibit 10.7 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on May 5, 2011 |
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| 10.31 | | Pledge Agreement, dated May 3, 2011, by and among Northeast Ohio Natural Gas Corp., Orwell Natural Gas Company, Brainard Gas Corp., Great Plains Natural Gas Company, Lightning Pipeline Inc., Spelman Pipeline Holdings, LLC, Kidron Pipeline LLC, Gas Natural Service Company, Gas Natural Inc. and Sun Life Assurance Company of Canada. Filed as, and incorporated herein by reference to, Exhibit 10.8 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on May 5, 2011 |
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| 10.32 | | Mortgage, Security Agreement, Assignment of Leases and Rents and Fixture Filing Statement, dated May 3, 2011, by and among Northeast Ohio Natural Gas Corp., Orwell Natural Gas Company, Brainard Gas Corp., Great Plains Natural Gas Company, Lightning Pipeline, LLC, Gas Natural Service Company, LLC Gas Natural Inc. and Sun Life Assurance Company of Canada. Filed as, and incorporated herein by reference to, Exhibit 10.9 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on May 5, 2011 |
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| 10.33 | | Second Amendment and Waiver to Note Purchase Agreement, dated April 9, 2012, by and among Northeast Ohio Natural Gas Corp., Orwell Natural Gas Company, Brainard Gas Corp., Great Plains Natural Gas Company, Lightning Pipeline Company, Inc., Spelman Pipeline Holdings LLC, Kidron Pipeline, LLC, Gas Natural Service Company, LLC, Gas Natural Inc. and Sun Life Assurance Company of Canada. Filed as, and incorporated herein by reference to, Exhibit 10.72 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2011, as filed with the Securities and Exchange Commission on April 10, 2012 |
| |
| 10.34 | | Second Amendment and Waiver to Note Purchase Agreement, dated April 9, 2012, by and among Great Plains Natural Gas Company, Lightning Pipeline Company, Inc., Spelman Pipeline Holdings LLC, Kidron Pipeline, LLC, Gas Natural Service Company, LLC, Gas Natural Inc. and Sun Life Assurance Company of Canada. Filed as, and incorporated herein by reference to, Exhibit 10.73 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2011, as filed with the Securities and Exchange Commission on April 10, 2012 |
| |
| 10.35 | | Omnibus Third Amendment, Supplement and Joinder to Note Purchase Agreement and Collateral Documents dated October 24, 2012, by and among Northeast Ohio Natural Gas Corp., Orwell Natural Gas Company, Brainard Gas Corp., Great Plains Natural Gas Company, Lightning Pipeline Company, Inc., Spelman Pipeline Holdings LLC, Kidron Pipeline, LLC, Gas Natural Service Company, LLC, Gas Natural Inc., Independence Oil, L.L.C., Independence Oil Real Estate 1, L.L.C., Independence Oil Real Estate 2, L.L.C., Independence Oil Real Estate 3, L.L.C., and Sun Life Assurance Company of Canada. Filed as, and incorporated herein by reference to, Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on October 30, 2012 |
| |
| 10.36 | | Senior Secured Guaranteed Note Agreement, dated October 24, 2012, by and among Northeast Ohio Natural Gas Corp, Orwell Natural Gas Co., and Brainard Gas Corp., and Sun Life Assurance Company of Canada. Filed as, and incorporated herein by reference to, Exhibit 10.2 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on October 30, 2012 |
| |
| 10.37 | | Joinder Agreement, dated October 24, 2012, by and among Independence Oil, L.L.C., Independence Oil Real Estate 1, L.L.C., Independence Oil Real Estate 2, L.L.C., Independence Oil Real Estate 3, L.L.C., and Sun Life Assurance Company of Canada. Filed as, and incorporated herein by reference to, Exhibit 10.3 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on October 30, 2012 |
| |
| 10.38 | | Addendum to Pledge Agreement, dated October 24, 2012, by and among Independence Oil, L.L.C., Independence Oil Real Estate 1, L.L.C., Independence Oil Real Estate 2, L.L.C., Independence Oil Real Estate 3, L.L.C., and Sun Life Assurance Company of Canada. Filed as, and incorporated herein by reference to, Exhibit 10.4 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on October 30, 2012 |
| |
| 10.39 | | Addendum to Security Agreement, dated October 24, 2012, by and among Independence Oil, L.L.C., Independence Oil Real Estate 1, L.L.C., Independence Oil Real Estate 2, L.L.C., Independence Oil Real Estate 3, L.L.C., and Sun Life Assurance Company of Canada. Filed as, and incorporated herein by reference to, Exhibit 10.5 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on October 30, 2012 |
51
| | |
| 10.40 | | Asset Purchase Agreement, dated August 15, 2012, by and among Gas Natural Inc., Acquisition Subsidiary, John D. Oil and Gas Marketing Company, LLC, and Richard M. Osborne, Trustee. Filed as, and incorporated herein by reference to, Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on August 20, 2012 |
| |
| 10.41 | | Purchase Agreement dated December 21, 2012, by and between McKay Real Estate Corporation, Matchworks, LLC and Nathan Properties, LLC by and through Mark E. Dottore, duly appointed Receiver in the United States District Court, Northern District of Ohio, Eastern Division, Case Number 1:11-CV-023464 and Gas Natural Inc. Filed as, and incorporated herein by reference to, Exhibit 10.1 |
| |
| 10.42 | | D.A. Compliance Agreement, dated May 1, 2010, between Northeast Ohio Natural Gas Corp. and Great Plains Exploration Ltd. Filed as, and incorporated herein by reference to, Exhibit 10.1 to the Registrant’s Current Report on Form 10-Q, as filed with the Securities and Exchange Commission on May 15, 2013 |
| |
| 10.43 | | Holmesville Transportation Service Agreement, dated April 1, 2013, between Northeast Ohio Natural Gas Corp. and Cobra Pipeline Co., Ltd. Filed as, and incorporated herein by reference to, Exhibit 10.2 to the Registrant’s Current Report on Form 10-Q, as filed with the Securities and Exchange Commission on May 15, 2013 |
| |
| 10.44 | | North Trumbull Transportation Service Agreement, dated April 1, 2013, between Northeast Ohio Natural Gas Corp. and Cobra Pipeline Co., Ltd. Filed as, and incorporated herein by reference to, Exhibit 10.3 to the Registrant’s Current Report on Form 10-Q, as filed with the Securities and Exchange Commission on May 15, 2013 |
| |
| 10.45 | | Churchtown Transportation Service Agreement, dated April 1, 2013, between Northeast Ohio Natural Gas Corp. and Cobra Pipeline Co., Ltd. Filed as, and incorporated herein by reference to, Exhibit 10.4 to the Registrant’s Current Report on Form 10-Q, as filed with the Securities and Exchange Commission on May 15, 2013 |
| |
| 10.46 | | Transportation Service Agreement for the Churchtown System dated January 30, 2008, between John D. Oil and Gas Marketing Company, LLC and Cobra Pipeline Co., Ltd. Filed as, and incorporated herein by reference to, Exhibit 10.1 to the Registrant’s Current Report on Form 10-Q, as filed with the Securities and Exchange Commission on June 6, 2013 |
| |
| 10.47 | | Transportation Service Agreement for the Holmesville System dated January 30, 2008, between John D. Oil and Gas Marketing Company, LLC and Cobra Pipeline Co., Ltd. Filed as, and incorporated herein by reference to, Exhibit 10.2 to the Registrant’s Current Report on Form 10-Q, as filed with the Securities and Exchange Commission on June 6, 2013 |
| |
| 10.48 | | Transportation Service Agreement for the North Trumbull System dated January 30, 2008, between John D. Oil and Gas Marketing Company, LLC and Cobra Pipeline Co., Ltd. Filed as, and incorporated herein by reference to, Exhibit 10.3 to the Registrant’s Current Report on Form 10-Q, as filed with the Securities and Exchange Commission on June 6, 2013 |
| |
| 10.49 | | Transportation Service Agreement dated January 15, 2009, between John D. Oil and Gas Marketing Company, LLC and Orwell-Trumbull Pipeline Co., LLC. Filed as, and incorporated herein by reference to, Exhibit 10.4 to the Registrant’s Current Report on Form 10-Q, as filed with the Securities and Exchange Commission on June 6, 2013 |
| |
| 10.50 | | Base Contract for Sale and Purchase of Natural Gas dated April 1, 2011, between John D. Oil and Gas Marketing Company, LLC and Great Plains Exploration Ltd. Filed as, and incorporated herein by reference to, Exhibit 10.5 to the Registrant’s Current Report on Form 10-Q, as filed with the Securities and Exchange Commission on June 6, 2013 |
| |
| 10.51 | | Base Contract for Sale and Purchase of Natural Gas dated April 1, 2010, between John D. Oil and Gas Marketing Company, LLC and Cobra Pipeline Co., Ltd. Filed as, and incorporated herein by reference to, Exhibit 10.6 to the Registrant’s Current Report on Form 10-Q, as filed with the Securities and Exchange Commission on June 6, 2013 |
52
| | |
| 10.52 | | Base Contract for Sale and Purchase of Natural Gas dated April 1, 2011, between John D. Oil and Gas Marketing Company, LLC and OsAir Inc. Filed as, and incorporated herein by reference to, Exhibit 10.7 to the Registrant’s Current Report on Form 10-Q, as filed with the Securities and Exchange Commission on June 6, 2013 |
| |
| 10.53 | | Base Contract for Sale and Purchase of Natural Gas dated April 1, 2011, between John D. Oil and Gas Marketing Company, LLC and John D. Resources, LLC. Filed as, and incorporated herein by reference to, Exhibit 10.8 to the Registrant’s Current Report on Form 10-Q, as filed with the Securities and Exchange Commission on June 6, 2013 |
| |
| 10.54 | | Base Contract for Sale and Purchase of Natural Gas dated April 1, 2011, between John D. Oil and Gas Marketing Company, LLC and Mentor Energy and Resources Company. Filed as, and incorporated herein by reference to, Exhibit 10.9 to the Registrant’s Current Report on Form 10-Q, as filed with the Securities and Exchange Commission on June 6, 2013 |
| |
| 10.55 | | Base Contract for Sale and Purchase of Natural Gas dated April 1, 2011, between John D. Oil and Gas Marketing Company, LLC and John D. Oil and Gas Company. Filed as, and incorporated herein by reference to, Exhibit 10.10 to the Registrant’s Current Report on Form 10-Q, as filed with the Securities and Exchange Commission on June 6, 2013 |
| |
| 10.56 | | Base Contract for Sale and Purchase of Natural Gas dated August 6, 2013, between Gas Natural Resources, LLC and Cobra Pipeline Company, Ltd. Filed as, and incorporated herein by reference to, Exhibit 10.1 to Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on October 9, 2013 |
| |
| 10.57 | | Lease Agreement dated October 7, 2013, between 8500 Station Street LLC and OsAir, Inc. Filed as, and incorporated herein by reference to, Exhibit 10.2 to Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on October 9, 2013 |
| |
| 10.58 | | Lease Agreement dated December 18, 2013, between Orwell Natural Gas Company and Cobra Pipeline Co., LLC. Filed as, and incorporated herein by reference to, Exhibit 10.1 to Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on December 24, 2013 |
| |
| 14 | | Code of Business Conduct. Filed as, and incorporated herein by reference to, Exhibit 14 to the Registrant’s Annual Report on Form 10-K for the year ended June 30, 2007, as filed with the Securities and Exchange Commission on September 27, 2007 |
| |
| 16 | | Letter from ParenteBeard LLC to the Securities and Exchange Commission, dated December 20, 2013. Filed as, and incorporated herein by reference to, Exhibit 16.1 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on December 20, 2013 |
| |
| 21* | | List of Company Subsidiaries |
| |
| 23.1* | | Consent of Independent Registered Public Accounting Firm, MaloneBailey LLP |
| |
| 23.2* | | Consent of Independent Registered Public Accounting Firm, ParenteBeard LLC |
| |
| 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 |
| |
| 101.INS* | | XBRL Instance Document |
| |
| 101.SCH* | | XBRL Taxonomy Extension Schema Document |
| |
| 101.CAL* | | XBRL Taxonomy Extension Calculation Linkbase Document |
| |
| 101.LAB* | | XBRL Taxonomy Extension Label Linkbase Document |
| |
| 101.PRE* | | XBRL Taxonomy Extension Presentation Linkbase Document |
| † | Management contract or compensatory plan or arrangement |
53
(c) FINANCIAL STATEMENT SCHEDULE
Schedule I – Condensed financial information of registrant
Gas Natural Inc. (Parent Company Only)
Condensed Financial Statements
| | | | | | | | |
| | | December 31, | |
| | | 2013 | | | 2012 | |
BALANCE SHEETS | | | | | | | | |
ASSETS | | | | | | | | |
Current assets | | $ | 8,376,229 | | | $ | 235,519 | |
Investments | | | 89,104,692 | | | | 75,417,951 | |
Accounts receivable | | | 250,000 | | | | | |
Property, plant, & equipment, net | | | 306,738 | | | | 611,575 | |
Deferred tax asset, less current portion | | | 435,983 | | | | 278,469 | |
Restricted cash | | | - | | | | 750,939 | |
Prepayments | | | 179,598 | | | | | |
Other assets | | | 840 | | | | - | |
| | | | | | | | |
Total assets | | $ | 98,654,080 | | | $ | 77,294,453 | |
| | | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
Current liabilities | | $ | 694,217 | | | $ | 654,764 | |
Intercompany payable, net | | | 480,088 | | | | 295,565 | |
Stockholders’ equity | | | 97,479,775 | | | | 76,344,124 | |
| | | | | | | | |
Total liabilities and capitalization | | $ | 98,654,080 | | | $ | 77,294,453 | |
| | | | | | | | |
| |
| | | Year Ended December 31, | |
| | | 2013 | | | 2012 | |
STATEMENT OF COMPREHENSIVE INCOME | | | | | | | | |
Operating expenses | | $ | 946,222 | | | $ | 250,045 | |
| | | | | | | | |
Operating loss | | | (946,222) | | | | (250,045) | |
Other income (expense) | | | (523,990) | | | | (804,775) | |
Interest expense | | | - | | | | - | |
| | | | | | | | |
Income before income taxes and income from unconsolidated subsidiaries | | | (1,470,212) | | | | (1,054,820) | |
Income from unconsolidated subsidiaries | | | 7,738,256 | | | | 4,377,406 | |
Income tax benefit (expense) | | | 403,235 | | | | 396,731 | |
| | | | | | | | |
Net income | | $ | 6,671,279 | | | $ | 3,719,317 | |
Other comprehensive income, net of tax of $22,951 and 8,913, respectively | | | 39,120 | | | | (14,616) | |
| | | | | | | | |
Comprehensive income | | $ | 6,710,399 | | | $ | 3,704,701 | |
| | | | | | | | |
54
Gas Natural Inc. (Parent Company Only)
Condensed Financial Statements, continued
| | | | | | | | |
| | | Year Ended December 31, | |
| | | 2013 | | | 2012 | |
STATEMENTS OF CASH FLOWS | | | | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | | | |
Net income | | $ | 6,671,279 | | | $ | 3,719,317 | |
Income from unconsolidated subsidiaries | | | (7,738,256) | | | | (4,377,406) | |
Depreciation expense | | | 12,670 | | | | 3,931 | |
Stock based compensation | | | 2,962 | | | | 60,009 | |
Deferred income taxes | | | (158,629) | | | | (256,291) | |
Other assets | | | (62,122) | | | | 7,245 | |
Other liabilities | | | 108,736 | | | | 432,430 | |
| | | | | | | | |
Net cash used in operating activities | | | (1,163,360) | | | | (410,765) | |
CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | | | |
Capital expenditures | | | (75,309) | | | | (615,506) | |
Purchase of marketable securities | | | - | | | | - | |
Repayment of intercompany loans | | | - | | | | - | |
Investment in subsidiaries | | | (6,845,497) | | | | (1,887,288) | |
Dividends received from subsidiaries | | | 3,600,000 | | | | 4,485,892 | |
| | | | | | | | |
Net cash (used in) provided by investing activities | | | (3,320,806) | | | | 1,983,098 | |
CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | | | |
Debt issuance costs | | | (840) | | | | - | |
Restricted cash – debt service | | | 750,939 | | | | (750,939) | |
Exercise of stock options | | | 159,500 | | | | - | |
Proceeds from issuance of common stock | | | 16,721,104 | | | | - | |
Dividends paid | | | (5,005,827) | | | | (4,432,920) | |
| | | | | | | | |
Net cash (used in) provided by financing activities | | | 12,624,876 | | | | (5,183,859) | |
Net increase (decrease) in cash and cash equivalents | | | 8,140,710 | | | | (3,611,526) | |
Cash and cash equivalents, beginning of period | | | 235,519 | | | | 3,847,045 | |
| | | | | | | | |
Cash and cash equivalents, end of period | | $ | 8,376,229 | | | $ | 235,519 | |
| | | | | | | | |
Basis of Presentation
Pursuant to rules and regulations of the SEC, the unconsolidated condensed financial statements of Gas Natural Inc. do not reflect all of the information and notes normally included with financial statements prepared in accordance with accounting principles generally accepted in the United States of America. Therefore, these condensed financial statements should be read in conjunction with the consolidated financial statements and related notes included in this Form 10-K.
Gas Natural Inc. has accounted for the earnings of its subsidiaries under the equity method in these unconsolidated condensed financial statements.
Common Dividends from Subsidiaries
Common stock cash dividends paid to Gas Natural Inc. by its subsidiaries were as follows:
| | | | | | | | |
| | | Years Ended December 31, | |
| | | 2013 | | | 2012 | |
Energy West, Inc. | | $ | 3,600,000 | | | $ | 4,350,000 | |
Great Plains Natural Gas Company | | | - | | | | 98,759 | |
Lightning Piepeline Company, Inc. | | | - | | | | 37,133 | |
| | | | | | | | |
Total | | $ | 3,600,000 | | | $ | 4,485,892 | |
| | | | | | | | |
55
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: March 31, 2014
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) | | March 31, 2014 |
| | |
/s/ Thomas J. Smith Thomas J. Smith | | Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer) | | March 31, 2014 |
| | |
/s/ W.E. Argo W.E. Argo | | Director | | March 31, 2014 |
| | |
/s/ Wade F. Brooksby Wade F. Brooksby | | Director | | March 31, 2014 |
| | |
/s/ Richard Greaves Richard Greaves | | Director | | March 31, 2014 |
| | |
/s/ John R. Male John R. Male | | Director | | March 31, 2014 |
| | |
/s/ Gregory J. Osborne Gregory J. Osborne | | Director | | March 31, 2014 |
| | |
/s/ Michael T. Victor Michael T. Victor | | Director | | March 31, 2014 |
56
CONSOLIDATED FINANCIAL STATEMENTSOF
GAS NATURAL INC.AND SUBSIDIARIES
TABLEOF CONTENTS
F-1
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Gas Natural Inc.
We have audited the accompanying consolidated balance sheet of Gas Natural Inc. and subsidiaries (the “Company”) as of December 31, 2013 and the related consolidated statements of comprehensive income, changes in stockholders’ equity, and cash flows for the year then ended. In connection with our audit of the consolidated financial statements, we have also audited the financial statement schedule listed in the accompanying index as of and for the year ended December 31, 2013. These consolidated financial statement and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and financial statement schedule based on our audits.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether 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 audit 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Gas Natural Inc. and subsidiaries as of December 31, 2013 and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.
Also, in our opinion, the financial statement schedule as of and for the year ended December 31, 2013, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
We also audited the adjustments described in Note 4 that were applied to the 2012 financial statements to reflect the discontinued operations presentation. In our opinion, such adjustments are appropriate and have been properly applied. We were not engaged to audit, review, or apply any procedures to the financial statements of the Company for the year ended December 31, 2012, other than those adjustments, and, accordingly, we do not express an opinion or any other form of assurance on the 2012 financial statements taken as a whole.
/s/ MaloneBailey LLP
Houston, Texas
March 31, 2014
F-2
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Gas Natural Inc.
We have audited, before the effects of the adjustments for the discontinued operations described in Note 4, the consolidated balance sheet of Gas Natural Inc. (“the Company”) as of December 31, 2012, and the related consolidated statements of comprehensive income, changes in stockholders’ equity, and cash flows for the year then ended (the 2012 financial statements before the effects of the adjustments discussed in Note 4 are not presented herein). In connection with our audit of the consolidated financial statements, we have also audited the financial statement schedule listed in the accompanying index as of and for the year ended December 31, 2012. The 2012 consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether 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 audit 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 audit provides a reasonable basis for our opinion.
In our opinion, the 2012 consolidated financial statements, before the effects of the adjustments for the discontinued operations described in Note 4, present fairly, in all material respects, the financial position of Gas Natural Inc. as of December 31, 2012, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.
We were not engaged to audit, review, or apply any procedures to the adjustments for the discontinued operations described in Note 4 and, accordingly, we do not express an opinion or any other form of assurance about whether such adjustments are appropriate and have been properly applied. Those adjustments were audited by MaloneBailey, LLP.
Also, in our opinion, the financial statement schedule as of and for the year ended December 31, 2012, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
/s/ ParenteBeard LLC
Pittsburgh, Pennsylvania
April 1, 2013
F-3
Gas Natural Inc. and Subsidiaries
Consolidated Balance Sheets
| | | | | | | | |
| | | December 31, | |
| | | 2013 | | | 2012 | |
| ASSETS | | | | | | | | |
CURRENT ASSETS | | | | | | | | |
Cash and cash equivalents | | $ | 13,147,381 | | | $ | 3,435,117 | |
Marketable securities | | | 406,134 | | | | 344,346 | |
Accounts receivable | | | | | | | | |
Trade, less allowance for doubtful accounts of $1,986,531 and $1,350,338, respectively | | | 13,440,565 | | | | 11,406,807 | |
Related parties | | | 146,225 | | | | 522,557 | |
Unbilled gas | | | 7,729,560 | | | | 4,612,258 | |
Note receivable – related parties, current portion | | | 1,938 | | | | 10,998 | |
Inventory | | | | | | | | |
Natural gas | | | 5,464,744 | | | | 4,938,078 | |
Materials and supplies | | | 2,413,745 | | | | 1,779,944 | |
Prepaid income taxes | | | 727,427 | | | | 501,763 | |
Prepayments and other | | | 1,064,845 | | | | 2,153,922 | |
Recoverable cost of gas purchases | | | 1,298,299 | | | | 2,329,524 | |
Deferred tax asset | | | 1,225,032 | | | | 813,846 | |
Discontinued operations | | | 34,151 | | | | 3,117,349 | |
| | | | | | | | |
Total current assets | | | 47,100,046 | | | | 35,966,509 | |
| | |
PROPERTY, PLANT, & EQUIPMENT, NET | | | 133,520,286 | | | | 116,429,042 | |
| | |
OTHER ASSETS | | | | | | | | |
Notes receivable – related parties, less current portion | | | 93,727 | | | | 24,411 | |
Regulatory assets | | | | | | | | |
Property taxes | | | 25,000 | | | | 307,732 | |
Income taxes | | | 452,645 | | | | 452,645 | |
Rate case costs | | | 130,228 | | | | 176,250 | |
Debt issuance costs, net of amortization | | | 1,388,124 | | | | 1,798,720 | |
Goodwill | | | 16,267,377 | | | | 14,891,377 | |
Customer relationships, net of amortization | | | 3,230,333 | | | | 616,500 | |
Investment in unconsolidated affiliate | | | 351,724 | | | | 321,731 | |
Restricted cash | | | 1,137,442 | | | | 3,150,847 | |
Other assets | | | 46,683 | | | | 327,695 | |
| | | | | | | | |
Total other assets | | | 23,123,283 | | | | 22,067,908 | |
| | | | | | | | |
TOTAL ASSETS | | $ | 203,743,615 | | | $ | 174,463,459 | |
| | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
F-4
Gas Natural Inc. and Subsidiaries
Consolidated Balance Sheets
| | | | | | | | |
| | | December 31, | |
| | | 2013 | | | 2012 | |
| LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES | | | | | | | | |
Checks in excess of amounts on deposit | | $ | 843,634 | | | $ | 720,340 | |
Line of credit | | | 24,529,799 | | | | 23,859,755 | |
Accounts payable | | | | | | | | |
Trade | | | 12,418,701 | | | | 8,982,051 | |
Related parties | | | 559,933 | | | | 47,929 | |
Notes payable, current portion | | | 3,502,190 | | | | 633,498 | |
Contingent consideration, current portion | | | 671,638 | | | | - | |
Accrued liabilities | | | | | | | | |
Taxes other than income | | | 3,173,640 | | | | 2,528,940 | |
Vacation | | | 95,806 | | | | 115,956 | |
Employee benefit plans | | | 178,789 | | | | 145,496 | |
Interest | | | 169,581 | | | | 191,263 | |
Deferred payments received from levelized billing | | | 2,469,665 | | | | 2,633,220 | |
Customer deposits | | | 761,022 | | | | 744,974 | |
Related parties | | | - | | | | 595,240 | |
Obligation under capital lease, current portion | | | 177,570 | | | | 167,518 | |
Over-recovered gas purchases | | | 793,184 | | | | 1,185,034 | |
Other current liabilities | | | 1,482,375 | | | | 690,511 | |
Discontinued operations | | | 45,855 | | | | 1,420,897 | |
| | | | | | | | |
Total current liabilities | | | 51,873,382 | | | | 44,662,622 | |
| | |
LONG-TERM LIABILITIES | | | | | | | | |
Deferred investment tax credits | | | 134,255 | | | | 155,317 | |
Deferred tax liability | | | 9,055,166 | | | | 4,596,629 | |
Asset retirement obligation | | | 2,026,353 | | | | 1,850,379 | |
Customer advances for construction | | | 1,016,671 | | | | 1,009,232 | |
Regulatory liability for income taxes | | | 83,161 | | | | 83,161 | |
Regulatory liability for gas costs | | | - | | | | 20,745 | |
Obligation under capital lease, less current portion | | | 1,862,938 | | | | 2,040,508 | |
Contingent consideration, less current portion | | | 13,362 | | | | - | |
| | | | | | | | |
Total long-term liabilities | | | 14,191,906 | | | | 9,755,971 | |
| | |
NOTES PAYABLE, less current portion | | | 40,198,552 | | | | 43,700,742 | |
| | |
COMMITMENTS AND CONTINGENCIES (see Note 17) | | | | | | | | |
| | |
STOCKHOLDERS’ EQUITY | | | | | | | | |
Preferred stock; $0.15 par value, 1,500,000 shares authorized, no shares issued or outstanding | | | - | | | | - | |
Common stock; $0.15 par value, 15,000,000 shares authorized, 10,451,678 and 8,369,752 shares issued and outstanding, respectively | | | 1,567,752 | | | | 1,255,463 | |
Capital in excess of par value | | | 63,468,969 | | | | 44,256,493 | |
Accumulated other comprehensive income | | | 104,909 | | | | 65,789 | |
Retained earnings | | | 32,338,145 | | | | 30,766,379 | |
| | | | | | | | |
Total stockholders’ equity | | | 97,479,775 | | | | 76,344,124 | |
| | | | | | | | |
TOTAL CAPITALIZATION | | | 137,678,327 | | | �� | 120,044,866 | |
| | | | | | | | |
TOTAL LIABILITIES AND CAPITALIZATION | | $ | 203,743,615 | | | $ | 174,463,459 | |
| | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
F-5
Gas Natural Inc. and Subsidiaries
Consolidated Statements of Comprehensive Income
| | | | | | | | |
| | | Year Ended December 31, | |
| | | 2013 | | | 2012 | |
REVENUES | | | | | | | | |
Natural gas operations | | $ | 106,264,609 | | | $ | 81,305,951 | |
Marketing and production | | | 12,167,241 | | | | 7,493,361 | |
Pipeline operations | | | 402,914 | | | | 401,933 | |
| | | | | | | | |
Total revenues | | | 118,834,764 | | | | 89,201,245 | |
| | |
COST OF SALES | | | | | | | | |
Natural gas purchased | | | 61,236,772 | | | | 42,485,803 | |
Marketing and production | | | 10,052,865 | | | | 5,953,156 | |
| | | | | | | | |
Total cost of sales | | | 71,289,637 | | | | 48,438,959 | |
| | | | | | | | |
| | |
GROSS MARGIN | | | 47,545,127 | | | | 40,762,286 | |
| | |
OPERATING EXPENSES | | | | | | | | |
Distribution, general, and administrative | | | 23,477,984 | | | | 20,815,855 | |
Maintenance | | | 1,317,792 | | | | 1,191,038 | |
Depreciation and amortization | | | 6,135,160 | | | | 5,026,142 | |
Accretion | | | 175,974 | | | | 161,298 | |
Contingent consideration gain | | | (1,565,000) | | | | - | |
Goodwill impairment | | | 725,744 | | | | - | |
Taxes other than income | | | 4,003,468 | | | | 3,478,897 | |
| | | | | | | | |
Total operating expenses | | | 34,271,122 | | | | 30,673,230 | |
| | | | | | | | |
| | |
OPERATING INCOME | | | 13,274,005 | | | | 10,089,056 | |
Loss from unconsolidated affiliate | | | (5,007) | | | | (8,620) | |
Other income, net | | | 924,586 | | | | 424,221 | |
Acquisition expense | | | (272,094) | | | | (959,267) | |
Stock sale expense | | | (309,432) | | | | (274,213) | |
Interest expense | | | (3,178,606) | | | | (2,700,193) | |
| | | | | | | | |
Income before income taxes | | | 10,433,452 | | | | 6,570,984 | |
Income tax expense | | | (3,391,898) | | | | (2,650,569) | |
| | | | | | | | |
INCOME FROM CONTINUING OPERATIONS | | | 7,041,554 | | | | 3,920,415 | |
| | |
Discontinued operations, net of income taxes (See Note 4) | | | (370,275) | | | | (201,098) | |
| | | | | | | | |
| | |
NET INCOME | | $ | 6,671,279 | | | $ | 3,719,317 | |
| | | | | | | | |
| | |
BASIC & DILUTED EARNINGS (LOSS) PER SHARE: | | | | | | | | |
Continuing operations | | $ | 0.75 | | | $ | 0.48 | |
Discontinued operations | | | (0.04) | | | | (0.02) | |
| | | | | | | | |
Net income per share | | $ | 0.71 | | | $ | 0.46 | |
| | | | | | | | |
| | |
Weighted average dividends declared per common share | | $ | 0.55 | | | $ | 0.54 | |
| | | | | | | | |
| | |
COMPREHENSIVE INCOME: | | | | | | | | |
Net income | | $ | 6,671,279 | | | $ | 3,719,317 | |
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX | | | | | | | | |
Unrealized gain (loss) on available for sale securities, net of tax of $22,951 and $8,913, respectively | | | 39,120 | | | | (14,616) | |
| | | | | | | | |
| | |
COMPREHENSIVE INCOME | | $ | 6,710,399 | | | $ | 3,704,701 | |
| | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
F-6
Gas Natural Inc. and Subsidiaries
Consolidated Statements of Changes in Stockholders’ Equity
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Common
Shares | | | Common
Stock | | | Capital In
Excess Of Par
Value | | | Accumulated
Other
Comprehensive
Income | | | Retained
Earnings | | | Total | |
BALANCE AT DECEMBER 31, 2011 | | | 8,154,301 | | | $ | 1,223,145 | | | $ | 41,978,799 | | | $ | 80,405 | | | $ | 31,489,678 | | | $ | 74,772,027 | |
| | | | | | |
Net income | | | - | | | | - | | | | - | | | | - | | | | 3,719,317 | | | | 3,719,317 | |
Other comprehensive loss, net | | | - | | | | - | | | | - | | | | (14,616) | | | | - | | | | (14,616) | |
Stock issued for services | | | 4,500 | | | | 675 | | | | 49,927 | | | | - | | | | - | | | | 50,602 | |
Stock based compensation | | | - | | | | - | | | | 9,406 | | | | - | | | | - | | | | 9,406 | |
Purchase of Loring Pipeline | | | 210,951 | | | | 31,643 | | | | 2,218,361 | | | | - | | | | - | | | | 2,250,004 | |
Dividends declared | | | - | | | | - | | | | - | | | | - | | | | (4,442,616) | | | | (4,442,616) | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | |
BALANCE AT DECEMBER 31, 2012 | | | 8,369,752 | | | | 1,255,463 | | | | 44,256,493 | | | | 65,789 | | | | 30,766,379 | | | | 76,344,124 | |
| | | | | | |
Net income | | | - | | | | - | | | | - | | | | - | | | | 6,671,279 | | | | 6,671,279 | |
Other comprehensive income, net | | | - | | | | - | | | | - | | | | 39,120 | | | | - | | | | 39,120 | |
Exercise of stock options | | | 20,000 | | | | 3,000 | | | | 156,500 | | | | - | | | | - | | | | 159,500 | |
Stock based compensation | | | - | | | | - | | | | 2,962 | | | | - | | | | - | | | | 2,962 | |
Purchase of JDOG Marketing | | | 256,926 | | | | 38,539 | | | | 2,602,660 | | | | - | | | | - | | | | 2,641,199 | |
Common stock issued | | | 1,805,000 | | | | 270,750 | | | | 16,450,354 | | | | - | | | | - | | | | 16,721,104 | |
Dividends declared | | | - | | | | - | | | | - �� | | | | - | | | | (5,099,513) | | | | (5,099,513) | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | |
BALANCE AT DECEMBER 31, 2013 | | | 10,451,678 | | | $ | 1,567,752 | | | $ | 63,468,969 | | | $ | 104,909 | | | $ | 32,338,145 | | | $ | 97,479,775 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
F-7
Gas Natural Inc. and Subsidiaries
Consolidated Statements of Cash Flows
| | | | | | | | |
| | | Year Ended December 31, | |
| | | 2013 | | | 2012 | |
CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | | | |
Net income | | $ | 6,671,279 | | | $ | 3,719,317 | |
Less loss from discontinued operations | | | (370,275) | | | | (201,098) | |
| | | | | | | | |
Income from continuing operations | | | 7,041,554 | | | | 3,920,415 | |
Adjustments to reconcile income from continuing operations to net cash provided by operating activities: | | | | | | | | |
Depreciation and amortization | | | 6,135,160 | | | | 5,026,142 | |
Accretion | | | 175,974 | | | | 161,298 | |
Amortization of debt issuance costs | | | 418,204 | | | | 275,858 | |
Stock based compensation | | | 2,962 | | | | 60,009 | |
(Gain) loss on sale of assets | | | (158,321) | | | | 54,154 | |
Loss from unconsolidated affiliate | | | 5,007 | | | | 8,620 | |
Unrealized holding loss on contingent consideration | | | (1,565,000) | | | | — | |
Goodwill impairment | | | 725,744 | | | | — | |
Investment tax credit | | | (21,062) | | | | (21,062) | |
Deferred income taxes | | | 4,024,683 | | | | 2,261,345 | |
Changes in assets and liabilities | | | | | | | | |
Accounts receivable, including related parties | | | (1,757,282) | | | | (2,555,988) | |
Unbilled gas | | | (3,117,302) | | | | (379,404) | |
Natural gas inventory | | | (526,666) | | | | 1,810,861 | |
Accounts payable, including related parties | | | 3,101,920 | | | | 896,823 | |
Recoverable/refundable cost of gas purchases | | | 639,375 | | | | (834,814) | |
Prepayments and other | | | 1,086,478 | | | | (1,432,597) | |
Other assets | | | (431,153) | | | | 1,051,267 | |
Other liabilities | | | 876,068 | | | | (1,163,368) | |
| | | | | | | | |
Net cash provided by operating activities of continuing operations | | | 16,656,343 | | | | 9,139,559 | |
CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | | | |
Capital expenditures | | | (24,103,789) | | | | (20,654,184) | |
Proceeds from sale of fixed assets | | | 968,772 | | | | 48,485 | |
Proceeds from related party notes receivable | | | 8,681 | | | | 10,255 | |
Purchase of Public Gas Company, Inc. | | | — | | | | (1,551,477) | |
Cash acquired in acquisition | | | — | | | | 502 | |
Investment in unconsolidated affiliate | | | (35,000) | | | | — | |
Restricted cash – capital expenditures fund | | | 1,264,624 | | | | (1,322,065) | |
Customer advances for construction | | | 23,802 | | | | 128,381 | |
Contributions in aid of construction | | | 1,105,973 | | | | 134,076 | |
| | | | | | | | |
Net cash used in investing activities of continuing operations | | | (20,766,937) | | | | (23,206,027) | |
CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | | | |
Proceeds from lines of credit | | | 22,519,000 | | | | 51,390,754 | |
Repayments of lines of credit | | | (21,848,956) | | | | (50,690,999) | |
Proceeds from notes payable | | | — | | | | 12,989,552 | |
Repayments of notes payable | | | (633,498) | | | | (7,920) | |
Payments of capital lease obligations | | | (167,518) | | | | — | |
Debt issuance costs | | | (7,607) | | | | (1,204,987) | |
Proceeds from issuance of common shares | | | 16,721,104 | | | | — | |
Exercise of stock options | | | 159,500 | | | | — | |
Restricted cash – debt service fund | | | 748,781 | | | | (878,875) | |
Dividends paid | | | (5,005,827) | | | | (4,432,920) | |
| | | | | | | | |
Net cash provided by financing activities of continuing operations | | | 12,484,979 | | | | 7,164,605 | |
DISCONTINUED OPERATIONS | | | | | | | | |
Operating cash flows | | | (394,427) | | | | (522,559) | |
Investing cash flows | | | 2,345,993 | | | | (46,306) | |
Financing cash flows | | | (613,687) | | | | 401,000 | |
| | | | | | | | |
Net cash provided by (used in) discontinued operations | | | 1,337,879 | | | | (167,865) | |
| | | | | | | | |
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | | | 9,712,264 | | | | (7,069,728) | |
Cash and cash equivalents, beginning of period | | | 3,435,117 | | | | 10,504,845 | |
| | | | | | | | |
CASH AND CASH EQUIVALENTS, END OF PERIOD | | $ | 13,147,381 | | | $ | 3,435,117 | |
| | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
F-8
Gas Natural Inc. and Subsidiaries
Consolidated Statements of Cash Flows
| | | | | | | | |
| | | Year Ended December 31, | |
| | | 2013 | | | 2012 | |
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION | | | | | | | | |
Cash paid for interest | | $ | 2,806,051 | | | $ | 2,286,902 | |
Cash refunded for income taxes, net | | | (4,050) | | | | (989,503) | |
| | |
NONCASH INVESTING AND FINANCING ACTIVITIES | | | | | | | | |
Shares issued to purchase JDOG Marketing | | $ | 2,641,199 | | | $ | - | |
Contingent consideration issued to purchase JDOG Marketing | | | 2,250,000 | | | | - | |
Plant, property and equipment acquired from JDOG Marketing purchase | | | 21,600 | | | | - | |
Customer relationships acquired from JDOG Marketing purchase | | | 2,800,000 | | | | - | |
Goodwill acquired from JDOG Marketing purchase | | | 2,101,744 | | | | - | |
Note receivable effectively settled in JDOG Marketing acquisition | | | 32,145 | | | | - | |
Capital expenditures included in accounts payable | | | 1,798,014 | | | | 745,402 | |
Shares issued to purchase Loring Pipeline | | | - | | | | 2,250,004 | |
Capital assets exchanged to settle payables | | | 82,584 | | | | - | |
Capital assets acquired through trade-in | | | 23,500 | | | | - | |
Accrued dividends | | | 470,326 | | | | 376,639 | |
Capitalized interest | | | 15,226 | | | | 21,147 | |
Customer advances for construction moved to contribution in aid of construction | | | 16,364 | | | | - | |
The accompanying notes are an integral part of these consolidated financial statements.
F-9
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 – Summary of Business
Nature of Business
Gas Natural Inc. (the “Company”) is the parent company of Brainard, Energy West, GNR, Independence, GNSC, Great Plains, Lightning Pipeline and PGC. Brainard is a natural gas utility company with operations in Ohio. Energy West is the parent company of multiple entities that are natural gas utility companies with regulated operations in Maine, Montana, North Carolina and Wyoming as well as non-regulated operations in Maine, Montana and Wyoming. GNR is a natural gas marketing company that markets gas in Ohio and Pennsylvania. GNSC manages gas procurement, transportation, and storage for Brainard and subsidiaries of Lightning Pipeline and Great Plains. Great Plains is the parent company of NEO, a regulated natural gas distribution company with operations in Ohio. NEO is the parent company of 8500 Station Street, a property management company responsible for the Company’s headquarters building, and Kidron, a small natural gas well company in Ohio. Lightning Pipeline is the parent company of Orwell, a regulated natural gas distribution company with operations in Ohio, and Spelman, a natural gas pipeline company in Ohio and Kentucky. Clarion River and Walker Gas are divisions of Orwell and are regulated natural gas distribution companies with operations in Pennsylvania. PGC is a regulated natural gas distribution company in Kentucky. The Company currently has four reporting segments:
| | |
• Natural Gas Operations | | Annually distribute approximately 36 Bcf of natural gas to approximately 72,000 customers through regulated utilities operating in Kentucky, Maine, Montana, North Carolina, Ohio, Pennsylvania and Wyoming. |
| |
• Marketing and Production Operations | | Annually markets approximately 1.5 Bcf of natural gas to commercial and industrial customers in Montana, Wyoming, Ohio, and Pennsylvania through our EWR and GNR subsidiaries. Our EWR subsidiary also manages midstream supply and production assets for transportation customers and utilities. EWR owns an average 51% gross working interest (average 43% net revenue interest) in 160 natural gas producing wells and gas gathering assets located in Glacier and Toole Counties in Montana. |
| |
• Pipeline Operations | | The Shoshone interstate and Glacier gathering natural gas pipelines located in Montana and Wyoming are owned through the subsidiary, EWD. Certain natural gas producing wells owned by EWD are being managed and reported under the marketing and production operations. |
| |
• Corporate and Other | | Encompasses costs associated with business development and acquisitions, dispositions of subsidiary entities, results of discontinued operations, dividend income, recognized gains or losses from the sale of marketable securities, and activity from Lone Wolfe which serves as an insurance agent for the Company and other businesses in the energy industry. |
F-10
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Energy West was originally incorporated in Montana in 1909 and was reorganized as a holding company in 2009 to facilitate future acquisitions and corporate-level financing to support the Company’s growth strategy. On July 9, 2010, the Company changed its name to Gas Natural Inc. and reincorporated from Montana to Ohio. Moving the incorporation to Ohio enhances the Company’s flexibility and provides a more efficient platform from which to operate and grow.
Note 2 – Significant Accounting Policies
Basis of Presentation
The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States. These principles are set by the FASB. The FASB sets GAAP to ensure the consistent reporting of the Company’s financial condition, results of operations and cash flows. References to GAAP issued by the FASB in these footnotes are to theFASB Accounting Standards Codification, sometimes referred to as the Codification or ASC.
Principles of Consolidation
The consolidated financial statements include the accounts and transactions of the Company and its wholly-owned subsidiaries as well as the proportionate share of assets, liabilities, revenues, and expenses of certain producing natural gas properties. All intercompany transactions and balances have been eliminated.
Reclassifications
Certain reclassifications of prior year reported amounts have been made for comparative purposes. Such reclassifications are not considered material and had no effect on net income.
Effects of Regulation
The Company follows the provisions of ASC 980—Regulated Operations and the accompanying 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 balance sheet (regulatory assets) and recorded as expenses in the periods when those same amounts are reflected in rates. Additionally, regulators can impose liabilities upon a regulated company for amounts previously collected from customers and for amounts that are expected to be refunded to customers which are recorded as liabilities in the balance sheet (regulatory liabilities).
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 determining amounts for the Company’s allowances for doubtful accounts, unbilled gas, asset
F-11
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
retirement obligations, contingent consideration liability, and 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, and other assumptions.
The Company makes acquisitions which involve combining the assets and liabilities of the acquired company with our Company. The assets and liabilities acquired are reported at their fair value at the date of acquisition. Measuring this fair value may require the use of estimates.
Such estimates could change in the near term and could significantly impact the Company’s results of operations and financial position.
Fair Value Measurements
For assets and liabilities measured at fair value, fair value is 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. 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.
Leases
Leases are categorized as either operating or capital leases at inception. Operating lease costs are recognized on a straight-line basis over the term of the lease. For capital leases, an asset and a corresponding liability are established for the present value at the beginning of the lease term of minimum lease payments during the lease term, excluding any executory costs. If the present value of the minimum lease payments exceeds the fair value of the leased property at lease inception, the amount measured initially as the asset and obligation shall be the fair value. The capital lease obligation is amortized over the life of the lease.
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 liabilities 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.
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
F-12
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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, 2013 and 2012.
The Company recognizes interest and penalties related to unrecognized tax benefits in operating expense. As of December 31, 2013 and 2012, there were no unrecognized tax benefits nor interest or penalties accrued related to unrecognized tax benefits. For the years ended December 31, 2013 and 2012, 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 after 2009 for federal and state returns remain open to examination by the major taxing jurisdictions in which we operate.
Comprehensive Income
Comprehensive income includes net income and other comprehensive income (loss), which for the Company is primarily comprised of unrealized holding gains or losses on available-for-sale securities. These gains or losses are excluded from the computing of net income and reported separately in shareholders’ equity as Accumulated other comprehensive income.
Earnings per Share
Basic earnings per share are computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect the potential dilution from the exercise or conversion of outstanding stock options and restricted stock awards into common stock.
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 cash equivalents which may exceed federally insurable limits and which may, at times, significantly exceed balance sheet amounts.
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 accompanying 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 recorded in the accompanying Consolidated Statement of Comprehensive Income.
F-13
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Receivables
The accounts receivable are generated from sales and delivery of natural gas and propane as measured by inputs from meter reading devices. Trade accounts receivable are carried at the expected net realizable value. There is credit 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.
Two of the Company’s utilities in Ohio, Orwell and NEO collect from their customers, through rates, an amount 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 PUCO and the rate per Mcf is adjusted as necessary.
The Company’s bad debt expense for the years ended December 31, 2013 and 2012 was $797,867 and $958,561, respectively. The Company wrote-off $161,674 and $213,855 for the years ended December 31, 2013 and 2012, 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 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 utility commissions in the states in which it operates. 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. The gas cost recoveries are monitored closely by the regulatory commissions in all of the states in which the Company operates and are subject to periodic audits or other review processes.
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 have been omitted.
Contributions in Aid of 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.
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GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Goodwill and Other Intangible Assets
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 the Company performs in the fourth quarter, or if events or changes in circumstances indicate that goodwill may be impaired. The Company tests for goodwill impairment using a two-step approach. A recoverability test at the reporting unit level must be performed during the first step. If the asset is not recoverable, the second step calculates the impairment loss, if any.
The Company recognizes an acquired intangible apart from goodwill whenever the intangible arises from contractual or other legal rights, or whenever it can be separated or divided from the acquired entity and sold, transferred, licensed, rented or exchanged, either individually or in combination with a related contract, asset or liability. Such intangibles are amortized on a straight-line basis over their estimated useful lives unless the estimated useful life is determined to be indefinite. Accumulated amortization for Customer relationships was approximately $254,667 at December 31, 2013. Amortization expense for Customer relationships for the year ended December 31, 2013 was approximately $186,167.
Regulatory Assets and Liabilities
The regulatory asset for property tax is recovered in rates over a ten-year period starting January 1, 2004. The income taxes earn a return equal to that of the Company’s rate base. The rate case costs do not earn a return. Regulatory assets will be recovered over a period of approximately three to twenty years. Regulatory liabilities will be refunded over a period of approximately five to twenty years.
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 amortized as interest expense over the term of the related debt.
Investment in Unconsolidated Affiliate
EWR owns a 24.5% interest in Kykuit, a developer and operator of oil, gas and mineral leasehold estates located in Montana. The Company is accounting for the investment in Kykuit using the equity method. The Company has invested approximately $2.2 million in Kykuit and may invest additional funds in the future as Kykuit could provide 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. At December 31, 2013, we are obligated to invest no more than an additional $0.1 million over the life of the venture. Other investors in Kykuit include our chairman and chief executive officer, Richard M. Osborne, and John D. Oil and Gas Company, a publicly held gas exploration company, which is also the managing member of Kykuit. Additional investors include Thomas J. Smith, a director and our chief financial officer, and a director of John D. Oil and Gas Company, and Gregory J. Osborne, a director and chief operating officer and former president and 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 loss to
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GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
be recognized is measured as the amount by which the carrying value of the assets exceeds their fair value. As of December 31, 2013 and 2012, management does not consider the value of any of its long-lived assets to be impaired.
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 or acquired. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in carrying value of a property associated with the capitalization of an asset retirement cost is included in “Property, plant and equipment, net” in the accompanying Consolidated Balance Sheets. The Company 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.
Derivatives and Hedging Activities
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 which states that unless these contracts qualify for treatment as a “normal purchase or normal sale,” they are to be reflected in the balance sheet as assets or liabilities at fair value as of the balance sheet date. Changes in these fair values are reported in the Consolidated Statement of Comprehensive Income.
For the years ended December 31, 2013 and 2012, all of the Company’s fixed contracts for purchase or sale of gas at fixed prices and volumes qualified for treatment as a “normal purchase” or “normal sale”.
Recently Adopted Accounting Pronouncements
ASU No. 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities”
In January 2013, the FASB issued ASU 2013-01, which clarifies which instruments and transactions are subject to the offsetting disclosure requirements established by ASU 2011-11. The new ASU addresses preparer concerns that the scope of the disclosure requirements under ASU 2011-11 was overly broad and imposed unintended costs that were not commensurate with estimated benefits to financial statement users. In choosing to narrow the scope of the offsetting disclosures, the FASB determined that it could make them more operable and cost effective for preparers while still giving financial statement users sufficient information to analyze the most significant presentation differences between financial statements prepared in accordance with U.S. GAAP and those prepared under IFRSs. ASU 2013-01 became effective for fiscal years beginning on or after January 1, 2013. The adoption of this ASU did not have a material impact on the accompanying financial statements.
ASU 2013-02, “Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income”
In February 2013, the FASB issued ASU 2013-02 to amend the guidance in the FASB ASC Topic 220, entitled Comprehensive Income. The goal behind development of the ASU 2013-02 amendments is to improve the transparency of reporting reclassifications out of accumulated other comprehensive income. Other comprehensive income includes gains and losses that are initially excluded from net income for an accounting period. Those gains and losses are later reclassified out of accumulated other comprehensive income into net
F-16
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
income when realized. The amendments to FASB ASC 220 do not change current requirements for reporting net income or other comprehensive income in the financial statements. Essentially, all of the information required to be displayed or disclosed in financial statements already are required to be disclosed in the financial statements. The adoption of this ASU did not have a material impact on the accompanying financial statements, but did require additional disclosure.
Note 3 – Acquisitions
Acquisition of Public Gas Company, Inc.
On April 1, 2012 the Company purchased 100% of the stock of PGC from Kentucky Energy Development, LLC for the price of $1.6 million. PGC is a regulated natural gas distribution company serving approximately 1,600 customers in the State of Kentucky in the counties of Breathitt, Jackson, Johnson, Lawrence, Lee, Magoffin, Morgan and Wolf. The costs related to the transaction were $51,187 and were expensed during 2012. The Company completed the transaction as it provided the opportunity to expand its presence into Kentucky.
The Company applied the acquisition method to the business combination and valued each of the assets acquired (cash, accounts receivable, and property, plant and equipment) and liabilities assumed (accounts payable) at fair value as of the acquisition date. The cash, accounts receivable and accounts payable were deemed to be recorded at fair value as of the acquisition date. The Company determined the fair value of property, plant and equipment to be historical book value which is the rate base as PGC is a regulated natural gas distribution company and is required to report to the KPSC. The Company also recorded deferred taxes based on the timing difference related to depreciation. As a result of the purchase, $142,971 was allocated to goodwill. During 2012, this amount was adjusted to $283,425 resulting from adjustments to deferred income taxes and deferred gas cost existing at the time of acquisition. This is reported in the Natural Gas Operations segment. The Company expects none of the goodwill to be deductible for tax purposes.
The estimated fair value of the assets acquired and liabilities assumed is reflected in the following table at the date of acquisition.
| | | | |
| | | Fair Value at
April 1, 2012 | |
Current assets | | $ | 69,634 | |
Property, plant and equipment | | | 1,577,592 | |
Goodwill | | | 283,425 | |
| | | | |
Total assets acquired | | | 1,930,651 | |
Current liabilities | | | 184,770 | |
Long-term liabilities | | | 194,403 | |
| | | | |
Total liabilities assumed | | | 379,173 | |
| | | | |
Net assets acquired | | $ | 1,551,478 | |
| | | | |
Acquisition of Loring Pipeline lease and related property
On April 17, 2012, the Company entered into an agreement with United States Power Fund, L.P. (“USPF”) to place a bid at a public auction on certain assets that were being foreclosed upon by USPF. Those assets included various parcels of land as well as a leasehold interest in a pipeline corridor easement running from Searsport to Limestone, Maine. The assets were owned by Loring BioEnergy, LLC (“LBE”) and were being foreclosed upon by USPF due to LBE’s default on a loan that it had obtained from USPF. On June 4, 2012 the Company attended
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GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
the public foreclosure auction and was the successful bidder with a bid of $4.5 million. The transaction closed on September 25, 2012. At that time, the Company issued 210,951 shares of its common stock in addition to transferring $2,250,000 of cash it had placed into escrow prior to the auction to USPF. The lease agreement calls for lease payments of $300,000 per year for the next ten years, an annual service fee of $120,000 and a charge of $0.0125 per Mcf moved on the pipeline.
In accordance with U.S. GAAP, the assets acquired do not constitute a business and the Company has accounted for the transaction as a group of assets which included both fixed assets and leased fixed assets. The purchase price was allocated to the assets purchased based on the relative fair value of each asset (including the leased assets) to the total fair value of all the assets. Land, buildings, generators and equipment purchased totaled $605,352. Leased pipeline and leased pipeline easements acquired totaled $6,320,000. The Company has determined that the fixed asset lease is a capital lease because the present value of the lease payments, discounted at an appropriate discount rate, exceeded 90% of the fair market value of the assets. The lease obligation for the $300,000 per year was recorded at the present value of the minimum lease payments of $2,208,026.
Acquisition of 8500 Station Street
On March 5, 2013, the Company purchased the Matchworks Building in Mentor, Ohio for $1.9 million from McKay Real Estate Corporation, Matchworks, LLC, and Nathan Properties, LLC (collectively, the “Sellers”) by and through Mark E. Dottore as Receiver in the United States District Court. The Sellers are entities owned or controlled by Richard M. Osborne, the Company’s chairman and chief executive officer. The acquisition of the Matchworks Building was approved by the independent members of the Company’s board of directors. A subsidiary of Gas Natural, 8500 Station Street, was formed to operate the property. The Company accounted for the transaction as an asset purchase and as such recorded the land and building purchased as Property, plant and equipment on its Consolidated Balance Sheets in the amounts of $244,859 and $1,607,915, respectively. These amounts were allocated based on the assets’ relative fair values.
Acquisition of John D. Oil and Gas Marketing
On June 1, 2013, the Company and its wholly-owned Ohio subsidiary, GNR, completed the acquisition of substantially all of the assets and certain liabilities of JDOG Marketing, an Ohio company engaged in the marketing of natural gas. The Osborne Trust is the majority owner of JDOG Marketing. Richard M. Osborne, the Company’s chairman and chief executive officer, is the sole trustee of the Osborne Trust. The Company believes the natural gas marketing business complements its existing natural gas distribution business in Ohio. In addition, it currently conducts natural gas marketing in Montana and Wyoming, which the Company believes allows it to integrate the Ohio marketing operations into Gas Natural with minimal increases in staff or overhead. Costs related to this acquisition totaled $0.6 million and were expensed as incurred.
Pursuant to the terms of the purchase agreement, the consummation of the transaction depended upon the satisfaction or waiver of a number of certain customary closing conditions, the receipt of regulatory approvals and the consent of certain of Gas Natural’s lenders. In addition, the transaction was subject to the approval of Gas Natural’s shareholders, and the receipt of a fairness opinion by an independent investment banking firm. All of these conditions were satisfied and the acquisition was completed on June 1, 2013. In accordance with U.S. GAAP, the consideration given, assets received, and liabilities assumed by the Company were recorded at their fair market value as of this date.
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GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table shows the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition.
| | | | |
| | | Fair Value at
June 1, 2013 | |
Assets acquired: | | | | |
Property, plant and equipment | | $ | 21,600 | |
Customer relationships | | | 2,800,000 | |
Goodwill | | | 2,101,744 | |
| | | | |
Total assets acquired | | | 4,923,344 | |
| |
Less liabilities assumed: | | | | |
Current liabilities | | | 669,396 | |
Long-term liabilities | | | 1,580,604 | |
| | | | |
Total liabilities assumed | | | 2,250,000 | |
| |
Less effective settlement of pre-existing relationships: | | | | |
Settlement of note receivable | | | 32,145 | |
| | | | |
Net assets acquired from John D Marketing acquisition | | $ | 2,641,199 | |
| | | | |
Under the purchase agreement, Gas Natural issued to JDOG Marketing 256,926 shares of the Company’s common stock. These shares had an acquisition date fair value of $2,641,199. There were no underwriting discounts or commissions in connection with the issuance, as no underwriters were used to facilitate the acquisition. The shares were not registered under the Securities Act of 1933, as amended (the “Act”), in reliance on the exemption from registration provided by Section 4(2) of the Act.
In addition, the purchase agreement provides for contingent “earn-out” payments for a period of five years after the closing of the transaction if the acquired business achieves an annual EBITDA target in the amount of $810,432, which was JDOG Marketing’s EBITDA for the year ended December 31, 2011. If JDOG Marketing’s actual EBITDA for a given year is less than the target EBITDA, then no earn-out payment will be due and payable for that particular period. If JDOG Marketing’s actual EBITDA for a given year meets or exceeds the target EBITDA, then an earn-out payment in an amount equal to actual EBITDA divided by target EBITDA times $575,000 will have been earned for that year. Due to the earn-out structure, the maximum amount that could be earned over the five year period is unlimited.
Earn-out payments are to be settled annually in validly issued, fully paid and non-assessable shares of the Company’s common stock. The share price to be used to determine the number of shares to be issued for each earn-out payment will be the average closing price of Gas Natural’s common stock for the 20 trading days preceding issuance of Gas Natural’s common stock for such earn-out payment. The Company estimated the acquisition date fair value of this liability to be $2,250,000, of which $669,396 was classified as current. The fair value of this liability is remeasured on a recurring basis. SeeNote 7 – Fair Value Measurements for details regarding this valuation.
The Company has calculated the earn-out payment for the year ended December 31, 2013 as $671,638. This earn-out amount is included in the Contingent consideration, current portion line of the Company’s Consolidated Balance Sheet and is expected to be settled in the second quarter of 2014.
The Company applied the acquisition method to the business combination and valued each of the assets acquired (property, plant and equipment and customer relationships) and liabilities assumed (earn-out liability) at fair
F-19
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
value as of the acquisition date. The Company used the net book value of property, plant, and equipment received as this closely approximated the fair value. The Company used the present value of expected net cash flows associated with the acquired customer contracts to approximate the assets’ fair values. These customer contracts represent established and ongoing contracts to provide natural gas to the former customers of JDOG Marketing acquired by the Company as part of the acquisition. These customer contracts will be fully amortized over their 10 year estimated useful lives. The Company recorded the fair value of the earn-out liability as the present value of estimated future earn-out payments as of the acquisition date. In addition to the assets acquired and liabilities assumed in the transaction, the Company also effectively settled a note due from JDOG Marketing. As a result of the purchase, $2,101,744 was allocated to goodwill. The Company expects none of the goodwill to be deductible for tax purposes.
The results of JDOG Marketing are included in the Company’s Marketing and Production Operations reporting segment. For the year ended December 31, 2013, JDOG Marketing contributed $1,946,745 to the Company’s revenues and $764,568 to the Company’s net income.
The following unaudited information is provided to present a summary of the combined results of the Company’s operations with JDOG Marketing as if the acquisition had been completed as of the beginning of the reporting periods. Adjustments were made to eliminate any inter-company transactions in the periods presented.
| | | | | | | | |
| | | Years ended December 31, | |
| | | 2013 | | | 2012 | |
| | | (Pro Forma) | | | (Pro Forma) | |
Revenues | | $ | 120,326,778 | | | $ | 98,233,417 | |
| | | | | | | | |
Net income | | $ | 7,082,270 | | | $ | 4,996,567 | |
| | | | | | | | |
Basic and diluted earnings (loss) per share | | $ | 0.76 | | | $ | 0.61 | |
| | | | | | | | |
Historically, the Company has been a party to transactions with JDOG Marketing primarily for the purchase of natural gas. In addition to these purchases, the Company also had a note receivable outstanding from JDOG Marketing included in the Notes receivable – related parties line items on the Consolidated Balance Sheets and an operating lease agreement the cost of which was included in the Distribution, general, and administrative line of the Consolidated Statement of Comprehensive Income. Both of these relationships were effectively settled with the completion of the transaction. SeeNote 15 – Related Party Transactions for more information regarding all of the Company’s transactions with JDOG Marketing prior to the acquisition.
Note 4 – Discontinued Operations
On November 6, 2013, the Company closed on the sale of Independence to Blue Ridge Energies, LLC (“Blue Ridge”) for a total of $2.3 million. This sale resulted in the Company recording a loss on sale of approximately $8,000 in the fourth quarter of 2013. This amount is included in the Discontinued operations line of the Company’s Consolidated Statement of Comprehensive Income. The results of operations and financial position for Independence have been reclassified to the discontinued operations sections of the Company’s consolidated financial statements. Independence was the Company’s only subsidiary included in its Propane Operations reporting segment. As a result of it being classified as discontinued operations, it results have been included in Corporate and Other operating segment for all periods presented. The remaining assets and liabilities associated with Independence on the Company’s books at December 31, 2013 include various prepaid expenses, accounts payable, and accrued liabilities. The Company expects each of these items to be settled in the near term. The Company has no material continuing cash flows or other contractual obligations associated with this sales transaction.
F-20
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table details the revenue and loss from discontinued operations associated with Independence for the years ended December 31, 2013 and 2012.
| | | | | | | | |
| | | Year Ended December 31, | |
| | | 2013 | | | 2012 | |
Independence revenues | | $ | 3,696,143 | | | $ | 4,614,915 | |
| | |
Independence pretax loss | | $ | (514,634) | | | $ | (494,541) | |
Independence income tax benefit | | | 144,359 | | | | 293,443 | |
| | | | | | | | |
Loss from discontinued operations | | $ | (370,275) | | | $ | (201,098) | |
| | | | | | | | |
Basic and diluted loss from discontinued operations per share | | $ | (0.04) | | | $ | (0.02) | |
| | | | | | | | |
Note 5 – Goodwill
In June 2013, the Company finalized its purchase of substantially all the assets and certain liabilities of JDOG Marketing. The Company accounted for this transaction as a business combination and as a result recognized $2.1 million of goodwill. SeeNote 3 – Acquisitions for more information regarding this transaction. The Company used many estimates in the determination of the acquisition date fair value of JDOG Marketing. One of these estimates was related to future sales between GNR, the Company’s subsidiary absorbing JDOG Marketing in the business combination, and two of the Company’s Ohio natural gas utility subsidiaries, NEO and Orwell.
In November 2013, the PUCO released its Opinion and Order related to the 2012 NEO and Orwell GCR audits. SeeNote 17 – Commitments and Contingencies for more information regarding these GCR audits. This Opinion and Order, amongst other things, fined the Company’s NEO and Orwell subsidiaries for failure to terminate natural gas purchase agreements with JDOG Marketing as previously ordered. As a result of these fines, the Company has ceased all future purchases by NEO and Orwell of natural gas from GNR. The Company is unsure if it will be able to replace these lost sales volumes with sales to other sources. This change in forecast negatively affected the calculated enterprise value of GNR and has led to a goodwill impairment charge for a portion of the goodwill previously recorded. This impairment charge was calculated using both a Discounted Cash Flow method and a Guideline Public Company method.
The schedule below describes the changes in carrying amount of goodwill for the years 2013 and 2012:
| | | | | | | | | | | | |
| | | Natural Gas
Operations | | | Marketing &
Production
Operations | | | Total | |
Balance as of January 1, 2012 | | $ | 14,607,952 | | | $ | - | | | $ | 14,607,952 | |
Acquisition of PGC | | | 283,425 | | | | - | | | | 283,425 | |
| | | | | | | | | | | | |
Balance as of December 31, 2012 | | $ | 14,891,377 | | | $ | - | | | $ | 14,891,377 | |
| | | | | | | | | | | | |
| | | |
Balance as of January 1, 2013 | | $ | 14,891,377 | | | $ | - | | | $ | 14,891,377 | |
Acquisition of JDOG Marketing | | | - | | | | 2,101,744 | | | | 2,101,744 | |
GNR Impairment loss | | | - | | | | (725,744) | | | | (725,744) | |
| | | | | | | | | | | | |
Balance as of December 31, 2013 | | $ | 14,891,377 | | | $ | 1,376,000 | | | $ | 16,267,377 | |
| | | | | | | | | | | | |
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GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 6 – Marketable Securities
The Company’s marketable securities as of December 31, 2013 and 2012 consisted solely of common stock classified as available-for-sale securities. The Company did not hold any held-to-maturity or trading securities as of December 31, 2013 or 2012. As of December 31, 2013 and 2012, the Company did not hold any securities in an unrealized loss position.
The following is a summary of available-for-sale securities at December 31, 2013 and 2012.
| | | | | | | | | | | | | | | | |
| | | December 31, 2013 | |
| | | Investment
at cost | | | Unrealized
gains | | | Unrealized
losses | | | Estimated
fair value | |
Common stock | | $ | 238,504 | | | $ | 167,630 | | | $ | - | | | $ | 406,134 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | | December 31, 2012 | |
| | | Investment
at cost | | | Unrealized
gains | | | Unrealized
losses | | | Estimated
fair value | |
Common stock | | $ | 238,504 | | | $ | 105,842 | | | $ | - | | | $ | 344,346 | |
| | | | | | | | | | | | | | | | |
The Company did not sell any of its marketable securities and there were no gross realized gains or losses for the years ended December 31, 2013 and 2012.
Note 7 – Fair Value Measurements
The Company follows a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to measurements involving unobservable inputs (Level 3). The three levels of the fair value hierarchy are as follows:
Level 1 inputs – observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.
Level 2 inputs – other inputs that are directly or indirectly observable in the marketplace.
Level 3 inputs – unobservable inputs which are supported by little or no market activity.
The level in the fair value hierarchy within which a fair value measurement falls is based on the lowest level input that is significant to the fair value measurement in its entirety.
The following table shows the amount and level in the fair value hierarchy of each of the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2013 and 2012.
| | | | | | | | | | | | | | | | |
| | | December 31, 2013 | |
| | | Level 1 | | | Level 2 | | | Level 3 | | | TOTAL | |
ASSETS: | | | | | | | | | | | | | | | | |
Available-for-sale securities | | $ | 406,134 | | | $ | - | | | $ | - | | | $ | 406,134 | |
| | | | | | | | | | | | | | | | |
LIABILITIES: | | | | | | | | | | | | | | | | |
Contingent consideration | | $ | - | | | $ | - | | | $ | 685,000 | | | $ | 685,000 | |
| | | | | | | | | | | | | | | | |
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GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| | | | | | | | | | | | | | | | |
| | | December 31, 2012 | |
| | | Level 1 | | | Level 2 | | | Level 3 | | | TOTAL | |
ASSETS: | | | | | | | | | | | | | | | | |
Available-for-sale securities | | $ | 344,346 | | | $ | - | | | $ | - | | | $ | 344,346 | |
| | | | | | | | | | | | | | | | |
The fair value of financial instruments including cash and cash equivalents, notes and accounts receivable and notes and accounts payable are not materially different from their carrying amounts. The fair values of marketable securities are estimated based on closing share price on the quoted market price for those investments. Cost basis is determined by specific identification of securities sold. Under the fair value hierarchy, the fair value of cash and cash equivalents is classified as a Level 1 measurement and the fair value of notes payable are classified as Level 2 measurements.
The contingent consideration liability categorized in level 3 of the fair value hierarchy arose as a result of the JDOG Marketing acquisition. SeeNote 3 – Acquisitions for more information regarding this transaction.
Valuation of the contingent consideration liability categorized under level 3 of the fair value hierarchy was conducted by an independent third-party valuation firm. Inputs and assumptions used in the valuation were reviewed for reasonableness by the Company in the course of the valuation process and have been updated to reflect changes in the Company’s business environment.
The following table reconciles the beginning and ending balances of the contingent consideration liability categorized under level 3 of the fair value hierarchy.
Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
| | | | |
| | | Contingent
Consideration | |
Opening balance December 31, 2012 | | $ | - | |
| |
Transfers into level 3 | | | - | |
Transfers out of level 3 | | | - | |
Total (gains) losses for period: | | | | |
Included in net income | | | (1,565,000) | |
Included in other comprehensive income | | | - | |
Purchases | | | - | |
Sales | | | - | |
Settlements | | | - | |
Issuances | | | 2,250,000 | |
| | | | |
| |
Closing balance December 31, 2013 | | $ | 685,000 | |
| | | | |
The gain included as a part of net income in the table above is included in the Contingent consideration gain line of the Company’s Consolidated Statement of Comprehensive Income and is the result of an unrealized holding gain associated with the change in the fair value of the Company’s contingent consideration liability.
F-23
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes quantitative information used in determining the fair value of the Company’s liabilities categorized in level 3 of the fair value hierarchy.
Quantitative Information about Level 3 Fair Value Measures
| | | | | | | | | | |
| | | Fair Value at
December 31,
2013 | | | Valuation
Techniques | | Unobservable Input | | Range |
Contingent Consideration | | $ | 685,000 | | | Monte Carlo analysis | | Forecasted annual EBITDA | | $0.4 - $0.6 million |
| | | | | | | | Weighted avg cost of capital | | 15.0% - 15.0% |
| | | | | | | | U.S. Treasury yields | | 0.1% - 1.3% |
| | | | |
| | | | | | Discounted cash flow | | U.S. Treasury yields | | 0.1% - 1.3% |
| | | | | | | | Credit spread | | 1.3% - 3.3% |
The significant unobservable inputs used in the fair value measure of the Company’s contingent consideration liability are its weighted average cost of capital, various U.S. Treasury yields, and the Company’s credit spread above the risk free rate. Significant increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) fair value measure. An additional significant unobservable input for this fair value measure is the Company’s forecasted annual EBITDA related to its GNR subsidiary. A significant increase (decrease) in this input would result in a significant increase (decrease) in the fair value measure.
Note 8 – Earnings per Share
| | | | | | | | |
| | | Year Ended December 31, | |
| | | 2013 | | | 2012 | |
Numerator: | | | | | | | | |
Income from continuing operations | | $ | 7,041,554 | | | $ | 3,920,415 | |
Income (loss) from discontinued operations | | | (370,275) | | | | (201,098) | |
| | | | | | | | |
Net income | | $ | 6,671,279 | | | $ | 3,719,317 | |
| | | | | | | | |
Denominator: | | | | | | | | |
Basic weighted average common shares outstanding | | | 9,339,002 | | | | 8,163,814 | |
Dilutive effect of stock options | | | 720 | | | | 5,865 | |
| | | | | | | | |
Diluted weighted average common shares outstanding | | | 9,339,722 | | | | 8,169,679 | |
| | | | | | | | |
Basic & diluted earnings (loss) per share of common stock: | | | | | | | | |
Continuing operations | | $ | 0.75 | | | $ | 0.48 | |
Discontinued operations | | | (0.04) | | | | (0.02) | |
| | | | | | | | |
Net income | | $ | 0.71 | | | $ | 0.46 | |
| | | | | | | | |
There were no shares or share equivalents that would have been anti-dilutive and therefore excluded in the calculation of diluted earnings per share for the years ended December 31, 2013 and 2012.
F-24
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 9 – Property Plant & Equipment
Components of property, plant, and equipment were as follows:
| | | | | | | | |
| | | December 31, | |
| | | 2013 | | | 2012 | |
Gas transmission & distribution facilities | | $ | 138,815,764 | | | $ | 125,067,279 | |
Land | | | 3,773,998 | | | | 3,530,639 | |
Buildings & leasehold improvements | | | 11,241,104 | | | | 9,029,773 | |
Transportation equipment | | | 3,449,615 | | | | 3,311,769 | |
Computer equipment | | | 3,844,776 | | | | 3,589,035 | |
Other equipment | | | 10,065,908 | | | | 8,751,626 | |
Construction work in progress | | | 10,762,534 | | | | 8,470,638 | |
Producing natural gas properties | | | 3,896,817 | | | | 3,911,404 | |
| | | | | | | | |
Property, plant & equipment | | | 185,850,516 | | | | 165,662,163 | |
Accumulated depreciation, depletion & amortization | | | (52,301,885) | | | | (47,034,673) | |
| | | | | | | | |
| | | 133,548,631 | | | | 118,627,490 | |
Discontinued operations | | | (28,345) | | | | (2,198,448) | |
| | | | | | | | |
Property, plant & equipment, net | | $ | 133,520,286 | | | $ | 116,429,042 | |
| | | | | | | | |
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 the gas properties using the units-of-production method. As of December 31, 2013 and 2012, management of the Company, considering reserve estimates provided by an independent reservoir engineer, estimated the net gas reserves at 2.3 Bcf (unaudited) and 2.1 Bcf (unaudited), respectively, and with net present values of $2,090,000 and $1,419,000, respectively, after applying a 10% discount (unaudited). The net book value of the gas properties totals $1,003,340 and $1,289,160 at December 31, 2013 and 2012, respectively.
The wells are depleted based upon production at approximately 10% and 10% per year as of December 31, 2013 and 2012, respectively. For the years ended December 31, 2013 and 2012, EWR’s portion of the daily gas production was 422 Mcf and 461 Mcf per day, or 19.0% and 15.5% 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, 2013 and 2012, EWD’s portion of the daily gas production was 129 Mcf and 132 Mcf per day, or 5.8% and 4.4% of EWR’s volume requirements, respectively.
For the years ended December 31, 2013 and 2012, EWR and EWD’s combined portion of the estimated daily gas production from the reserves was 550 Mcf and 593 Mcf, or 25.0% and 19.9% 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 10 – Asset Retirement Obligations
The Company, excluding Orwell and Brainard, 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
F-25
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
As a result of regulatory action by the PUCO related to prior audits, Orwell and Brainard accrue 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 equal to a percent of the asset cost according to the following table:
| | | | | | | | |
| | | Percent of Asset Cost | |
| | | Orwell | | | Brainard | |
Mains | | | 15% | | | | 20% | |
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:
| | | | | | | | |
| | | 2013 | | | 2012 | |
Balance, beginning of period | | $ | 1,850,379 | | | $ | 1,689,081 | |
Accretion expense | | | 175,974 | | | | 161,298 | |
| | | | | | | | |
| | |
Balance, end of period | | $ | 2,026,353 | | | $ | 1,850,379 | |
| | | | | | | | |
As of December 31, 2013 and 2012, the Company had capitalized ARO costs included in property, plant and equipment of $86,415 and $156,816, respectively.
Note 11 – Credit Facilities and Long-Term Debt
Lines of Credit
Bank of America
The Company has a revolving credit facility with the Bank of America with a maximum borrowing capacity of $30.0 million due April 1, 2017. This revolving credit facility includes an annual commitment fee ranging from 25 to 45 basis points of the unused portion of the facility and interest on the amounts outstanding at LIBOR plus 175 to 225 basis points. The Company had outstanding borrowings under this facility of $24.5 million and $23.9 million at December 31, 2013 and 2012, respectively. For the year ended December 31, 2013, the weighted average borrowing outstanding on the revolving line of credit was $19.0 million. For the years ended December 31, 2013 and 2012, the weighted average interest rate on the revolving credit facility was 2.42% and 3.33%, respectively.
Yadkin Valley
The Company had a $500,000 revolving credit facility with Yadkin Valley Bank with an interest rate based on the prime rate, with a floor of 4.5% and cap of 16.0% per annum. The debt was secured by a blanket lien on all assets owned or acquired by Independence. In November 2013, as part of the sale of Independence, the Company paid off this line of credit to remove the liens on the assets owned by the subsidiary. The Company had outstanding borrowings under this facility of $0.0 million and $0.4 million at December 31, 2013 and 2012, respectively. These amounts were included in the Discontinued operations line on the Company’s Consolidated Balance Sheets. For the years ended December 31, 2013 and 2012, the weighted average borrowing outstanding
F-26
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
on the revolving line of credit was $0.3 million and $0.4 million, respectively. The weighted average interest rate on the facility was 4.5% and 4.5% for the years ended December 31, 2013 and 2012, respectively.
Notes Payable
The following table details the Company’s outstanding long-term debt balances at December 31, 2013 and 2012.
| | | | | | | | |
| | | December 31, | |
| | | 2013 | | | 2012 | |
LIBOR plus 1.75 to 2.25%, Bank of America amortizing term loan, due April 1, 2017 | | $ | 9,375,000 | | | $ | 10,000,000 | |
6.16%, Allstate/CUNA Senior unsecured note, due June 29, 2017 | | | 13,000,000 | | | | 13,000,000 | |
5.38%, Sun Life fixed rate note, due June 1, 2017 | | | 15,334,000 | | | | 15,334,000 | |
LIBOR plus 3.85%, Sun Life floating rate note, due May 3, 2014 | | | 3,000,000 | | | | 3,000,000 | |
4.15% Sun Life senior secured guaranteed note, due June 1, 2017 | | | 2,989,552 | | | | 2,989,552 | |
Vehicle loan | | | 2,190 | | | | 10,688 | |
| | | | | | | | |
Total notes payable | | | 43,700,742 | | | | 44,334,240 | |
Less: current portion | | | 3,502,190 | | | | 633,498 | |
| | | | | | | | |
Notes payable, less current portion | | $ | 40,198,552 | | | $ | 43,700,742 | |
| | | | | | | | |
Bank of America
The Bank of America amortizing term loan is an obligation of Energy West. The term loan contains an interest rate swap provision that allows for the interest rate to be fixed in the future. The term loan is amortized at a rate of $125,000 per quarter, with the first principal payment having come due on December 31, 2012. As of December 31, 2013, the Company had not exercised the interest rate swap provision for the fixed interest rate. For the years ended December 31, 2013 and 2012, the weighted average interest rate on the term loan was 2.19% and 2.14% respectively resulting in $215,593 and $56,226 of interest expense.
Allstate/CUNA
The Allstate/CUNA senior unsecured note is an obligation of Energy West. Interest expense from the senior unsecured note was $800,800 for the years ended December 31, 2013 and 2012, respectively.
Sun Life
The Sun Life fixed rate note is a joint obligation of the Company, NEO, Orwell and Brainard, and is guaranteed by the Company, Lightning Pipeline and Great Plains. This note received approval from the PUCO on March 30, 2011. The note is governed by a note purchase agreement. Prepayment of this note prior to maturity is subject to a 50 basis point make-whole premium. For the years ended December 31, 2013 and 2012, interest expense related to the fixed rate note was $824,969 for each year.
The Sun Life floating rate note is an obligation of Great Plains and is guaranteed by the Company. Pricing for this note will reset on a quarterly basis to the then current yield of three month Libor. Prepayment of this note prior to maturity is at par. For the years ended December 31, 2013 and 2012, the weighted average interest rate on the floating rate note was 4.13% and 4.31% respectively resulting in $123,850 and $129,200 of interest expense.
F-27
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Sun Life senior secured guaranteed note is a joint obligation of NEO, Orwell, and Brainard and is guaranteed by the Company’s non-regulated Ohio subsidiaries. For the years ended December 31, 2013 and 2012, interest expense from the senior secured guaranteed note was $123,007 and $23,576, respectively.
The following table shows the aggregate future maturities of the Company’s notes payable.
| | | | |
Years Ending | | | |
2014 | | $ | 3,502,190 | |
2015 | | | 500,000 | |
2016 | | | 500,000 | |
2017 | | | 39,198,552 | |
2018 | | | - | |
Thereafter | | | - | |
| | | | |
Total | | | 43,700,742 | |
| | | | |
Debt Covenants
Bank of America
The Bank of America revolving credit agreement and term loan contain various covenants, which requires that Energy West and its subsidiaries maintain compliance with a number of financial covenants, including a limitation on investments in another entity by acquisition of any debt or equity securities or assets or by making loans or advances to such entity. In addition, Energy West must maintain a total debt to total capital ratio of not more than .55-to-1.00 and an interest coverage ratio of no less than 2.0-to-1.0. The credit facility restricted Energy West’s ability to create, incur or assume indebtedness except (i) indebtedness under the credit facility (ii) indebtedness incurred under certain capitalized leases including the capital lease related to the Loring pipeline, and purchase money obligations not to exceed $500,000, (iii) certain indebtedness of Energy West’s subsidiaries, (iv) certain subordinated indebtedness, (v) certain hedging obligations and (vi) other indebtedness not to exceed $1.0 million.
In addition, the Bank of America revolving credit agreement and term loan also restricts Energy West’s ability to pay dividends and make distributions, redemptions and repurchases of stock during any 60-month period to 80% of its net income over that period. In addition, no event of default may exist at the time such dividend, distribution, redemption or repurchase is made. Energy West is also prohibited from consummating a merger or consolidation or selling all or substantially all of its assets or stock except for (i) any merger consolidation or sale by or with certain of its subsidiaries, (ii) any such purchase or other acquisition by Energy West or certain of its subsidiaries and (iii) sales and dispositions of assets for at least fair market value so long as the net book value of all assets sold or otherwise disposed of in any fiscal year does not exceed 5% of the net book value of Energy West’s assets as of the last day of the preceding fiscal year.
Allstate/CUNA
The Allstate/CUNA senior unsecured notes contain various covenants, including a limitation on Energy West’s total dividends and distributions made in the immediately preceding 60-month period to 100% of aggregate consolidated net income for such period. The notes restrict Energy West from incurring additional senior indebtedness in excess of 65% of capitalization at any time and require Energy West to maintain an interest coverage ratio of more than 150% of the pro forma annual interest charges on a consolidated basis in two of the three preceding fiscal years.
F-28
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Sun Life
The Sun Life covenants restrict certain cash balances and require two main types of debt service reserve accounts to be maintained to cover approximately one year of interest payments. The total balance in the debt service reserve accounts was $1.1 million and $1.1 million at December 31, 2013 and 2012, respectively, and is included in restricted cash on the Company’s Consolidated Balance Sheets. The debt service reserve accounts cannot be used for operating cash needs. In addition, the Company was required to maintain a $750,000 reserve account where Sun Life was the beneficiary. In July 2013, this additional reserve account requirement was lifted and the cash became unrestricted.
The covenants also provide that any cash dividends, distributions, redemptions or repurchases of common stock may be made by the obligors to the holding company only if (i) the aggregate amount of all such dividends, distributions, redemptions and repurchases for the fiscal year do not exceed 70% of net income of the obligors for the four fiscal quarters then ending determined as of the end of each fiscal quarter, and (ii) there exists no other event of default at the time the dividend, distribution, redemption or repurchase is made. The inability of the obligors to pay a dividend to the holding company may impact the Company’s ability to pay a dividend to shareholders.
The obligors are also prohibited from creating, assuming or incurring additional indebtedness except for (i) obligations under certain financing agreements, (ii) indebtedness incurred under certain capitalized leases and purchase money obligations not to exceed $500,000 at any one time outstanding, (iii) indebtedness outstanding as of March 31, 2011, (iv) certain unsecured intercompany indebtedness and (v) certain other indebtedness permitted under the notes.
The covenants require, on a consolidated basis, an interest coverage ratio of at least 2.0 to 1.0, measured quarterly on a trailing four quarter basis. The notes generally define the interest coverage ratio as the ratio of EBITDA to gross interest expense. The note defines EBITDA as net income plus the sum of interest expense, any provision for federal, state, and local taxes, depreciation, and amortization determined on a consolidated basis in accordance with GAAP, but excluding any extraordinary non-operating income or loss and any gain or loss from non-operating transactions. The interest coverage ratio is measured with respect to the Obligors on a consolidated basis and also with respect to the Company and all of its subsidiaries on a consolidated basis. The notes also require that the Company does not permit indebtedness to exceed 60% of capitalization at any time. Like the interest coverage ratio, the ratio of debt to capitalization is measured on a consolidated basis for the Obligors and again on a consolidated basis with respect to the Company and all of its subsidiaries.
The notes prohibit the Company from selling or otherwise transferring assets except in the ordinary course of business and to the extent such sales or transfers, in the aggregate, over each rolling twelve month period, do not exceed 1% of our total assets. The Company received consent from Sun Life, under its covenant restrictions, approving the sale of Independence prior to the finalization of the transaction. Generally, the Company may consummate a merger or consolidation if there is no event of default and the provisions of the notes are assumed by the surviving or continuing corporation. The Company is also generally limited in making acquisitions in excess of 10% of our total assets.
An event of default, if not cured or waived, would require the Company to immediately pay the outstanding principal balance of the notes as well as any and all interest and other payments due. An event of default would also entitle Sun Life to exercise certain rights with respect to any collateral that secures the indebtedness incurred under the notes.
The Company believes it is in compliance with all of the covenants under its debt agreements.
F-29
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 12 – Stockholders’ Equity
Share Repurchase Plan
The Company’s common stock trades on the NYSE Amex Equities under the symbol “EGAS.”
The Board of Directors approved a stock repurchase plan whereby the Company has the ability to buy back up to 448,500 shares of the Company’s common stock. There was no share repurchase activity during the years ended December 31, 2013 and 2012.
Stock Compensation
2002 Stock Option Plan
The Energy West Incorporated 2002 Stock Option Plan expired on October 4, 2012 and provided for the issuance of up to 300,000 options to purchase the Company’s common stock to be issued to certain key employees. As of December 31, 2013 and 2012, there were 5,000 and 35,000 options outstanding, respectively. Pursuant to the plan, the options vest over four to five years and are exercisable over a five to ten-year period from date of issuance.
The fair value of each option grant was estimated on the grant date using the Black-Scholes option pricing model. No options were granted under this plan during the years ended December 31, 2013 and 2012.
2012 Incentive and Equity Award Plan
The 2012 Incentive and Equity Award Plan provides for the grant of options, restricted stock, performance awards, other stock-based awards and cash awards to certain eligible employees. The number of shares authorized for issuance under the plan is 500,000. Under the plan, the option price may not be less than 100% of the fair market value on the date of grant and the options may be exercisable up to a ten year period after the date of grant (five years in the case of an incentive stock option granted to a holder of 10% of the Company’s shares of common stock). Under the plan, awards tied to performance goals will be subject to a one-year minimum performance measurement period. As of December 31, 2013, no awards had been granted under the plan.
2012 Non-Employee Director Stock Award Plan
The 2012 Non-Employee Director Stock Award Plan allows each non-employee director to receive his or her fees in shares of the Company’s common stock by providing written notice to the Company. Under the plan, the election to participate will remain in effect until it is revoked or modified in writing by the director. The number of shares authorized for issuance under the plan is 250,000. As of December 31, 2013, no awards had been granted under the plan.
F-30
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A summary of the status of the outstanding stock options is as follows:
| | | | | | | | | | | | |
| | | Number of
Shares | | | Weighted
Average
Exercise Price | | | Aggregate
Intrinsic
Value | |
| | | |
Outstanding December 31, 2011 | | | 35,000 | | | $ | 8.66 | | | | | |
Granted | | | - | | | $ | - | | | | | |
Exercised | | | - | | | $ | - | | | | | |
Expired | | | - | | | $ | - | | | | | |
| | | | | | | | | | | | |
| | | |
Outstanding December 31, 2012 | | | 35,000 | | | $ | 8.66 | | | $ | 31,550 | |
Granted | | | - | | | $- | | | | | | |
Exercised | | | (20,000) | | | $ | 7.98 | | | | | |
Expired | | | (10,000) | | | $ | 10.15 | | | | | |
| | | | | | | | | | | | |
| | | |
Outstanding December 31, 2013 | | | 5,000 | | | $ | 8.44 | | | $ | 0 | |
| | | | | | | | | | | | |
| | | |
Exerciseable December 31, 2013 | | | 5,000 | | | $ | 8.44 | | | $ | 0 | |
| | | | | | | | | | | | |
During the year ended December 31, 2013, 20,000 stock options were exercised in the amount of $159,500.
The following information applies to options outstanding at December 31, 2013:
| | | | | | | | | | | | | | | | |
Grant
Date | | Exercise
Price | | Number
Outstanding | | | Weighted
Average
Exercise
Price | | Weighted
Average
Remaining
Contractual
Life
(Years) | | Number
Exercisable | | | Weighted
Average
Exercise
Price |
| | | | | | |
6/3/2009 | | $8.44 | | | 5,000 | | | $8.44 | | 0.42 | | | 5,000 | | | $8.44 |
| | | | | | | | | | | | | | | | |
| | | | | 5,000 | | | | | | | | 5,000 | | | |
| | | | | | | | | | | | | | | | |
During the years ended December 31, 2013 and 2012, the Company recorded $3,231 and $9,406, respectively ($2,032 and $5,832, net of tax, respectively), of stock-based compensation expense. As of December 31, 2013 and 2012, there was $0 and $3,231 of total unrecognized compensation cost related to stock-based compensation, respectively.
Restrictions on Dividends
The Company’s subsidiaries are subject to several restrictions on the amounts that they can distribute to the holding company. In addition to the debt covenants discussed inNote 11 – Credit Facilities and Long-Term Debt, each of the Maine Public Service Commission, the Montana Public Service Commission, the North Carolina Utilities Commission and the Wyoming Public Service Commission have ring fencing provisions over the subsidiary companies in their jurisdiction. The ring fencing provisions and debt covenants act to limit the dividends and distributions of the various subsidiaries to the holding company, which limit the funds available to be paid as dividends to the Company’s shareholders.
F-31
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The most limiting of the restrictions placed on the Company’s subsidiaries is the Sun Life debt covenant restriction on distributions which limits distributions to the Company to 70% of net income of the obligors for the four fiscal quarters then ending.
The total restricted net assets of consolidated subsidiaries related to the Company’s debt covenants and ring fencing restrictions is $80,331,499, which accounts for 82.4% of Gas Natural Inc.’s net assets of $97,479,775 at December 31, 2013.
Note 13 – 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%. The expense related to the 401k Plan for the years ended December 31, 2013 and 2012 was $382,400 and $362,160, respectively.
The Company makes matching contributions in the form of Company common stock equal to 10% of each participant’s elective deferrals in the 401k Plan. The Company contributed shares of common stock valued at $57,590 and $52,719 for the years ended December 31, 2013 and 2012, 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, 2013 and 2012.
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. The Company discontinued contributions in 2006 and is no longer required to fund the Retiree Health Plan. As of December 31, 2013 and 2012, the value of plan assets was $155,750 and $163,313, respectively. The assets remaining in the trust will be used to fund the plan until these assets are exhausted.
F-32
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 14 – Income Taxes
Significant components of the deferred tax assets and liabilities are as follows:
| | | | | | | | | | | | | | | | |
| | | December 31, | |
| | | 2013 | | | 2012 | |
| | | Current | | | Long-term | | | Current | | | Long-term | |
Deferred tax assets: | | | | | | | | | | | | | | | | |
Allowance for doubtful accounts | | $ | 724,534 | | | $ | - | | | $ | 524,677 | | | $ | - | |
Contributions in aid of construction | | | - | | | | 1,652,760 | | | | - | | | | 742,152 | |
Other nondeductible accruals | | | 47,484 | | | | - | | | | 66,278 | | | | - | |
Recoverable purchase gas costs | | | 60,903 | | | | - | | | | 434,995 | | | | - | |
Net operating loss carryforwards | | | - | | | | 7,733,763 | | | | - | | | | 5,439,748 | |
Property tax | | | 154,146 | | | | - | | | | - | | | | 153,967 | |
Other | | | 754,235 | | | | - | | | | 709,778 | | | | 595,918 | |
| | | | | | | | | | | | | | | | |
| | | | |
Total deferred tax assets | | | 1,741,302 | | | | 9,386,523 | | | | 1,735,728 | | | | 6,931,785 | |
| | | | | | | | | | | | | | | | |
Deferred tax liabilities: | | | | | | | | | | | | | | | | |
Recoverable purchase gas costs | | | 454,795 | | | | - | | | | 867,075 | | | | - | |
Property, plant and equipment | | | - | | | | 11,402,464 | | | | - | | | | 6,962,154 | |
Unrealized gain on securities available for sale | | | 61,475 | | | | - | | | | 39,923 | | | | - | |
Amortization of intangibles | | | - | | | | 539,498 | | | | - | | | | 418,181 | |
Other | | | - | | | | 800,698 | | | | - | | | | 519,814 | |
| | | | | | | | | | | | | | | | |
| | | | |
Total deferred tax liabilities | | | 516,270 | | | | 12,742,660 | | | | 906,998 | | | | 7,900,149 | |
| | | | | | | | | | | | | | | | |
| | | | |
Net deferred tax asset (liability) before valuation allowance | | | 1,225,032 | | | | (3,356,137) | | | | 828,730 | | | | (968,930) | |
Less: valuation allowance | | | - | | | | (5,699,029) | | | | - | | | | (4,175,072) | |
| | | | | | | | | | | | | | | | |
| | | | |
Total deferred tax asset (liability) | | | 1,225,032 | | | | (9,055,166) | | | | 828,730 | | | | (5,144,002) | |
Discontinued operations | | | - | | | | - | | | | (14,884) | | | | 547,373 | |
| | | | |
Net deferred tax asset (liability), continuing operations | | $ | 1,225,032 | | | $ | (9,055,166) | | | $ | 813,846 | | | $ | (4,596,629) | |
| | | | | | | | | | | | | | | | |
Income tax expense from continuing operations consists of the following:
| | | | | | | | |
| | | Year Ended December 31, | |
| | | 2013 | | | 2012 | |
Current income tax expense (benefit): | | | | | | | | |
Federal | | $ | (344,342) | | | $ | (150,224) | |
State | | | 120,753 | | | | 245,483 | |
| | | | | | | | |
| | |
Total current income tax expense (benefit) | | | (223,589) | | | | 95,259 | |
| | |
Deferred income tax expense: | | | | | | | | |
Federal | | | 3,692,413 | | | | 2,030,525 | |
State | | | (200,217) | | | | 252,403 | |
| | | | | | | | |
| | |
Total deferred income tax expense | | | 3,492,196 | | | | 2,282,928 | |
| | | | | | | | |
| | |
Total income taxes before credits | | | 3,268,607 | | | | 2,378,187 | |
Investment tax credit, net | | | (21,062) | | | | (21,062) | |
| | | | | | | | |
Total income tax expense | | | 3,247,545 | | | | 2,357,125 | |
Discontinued operations | | | 144,353 | | | | 293,444 | |
| | | | | | | | |
| | |
Income tax expense from continuing operations | | $ | 3,391,898 | | | $ | 2,650,569 | |
| | | | | | | | |
F-33
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Income tax position differs from the amount computed by applying the Federal statutory rate to pre-tax income from continuing operations as demonstrated in the table below:
| | | | | | | | |
| | | Year Ended December 31, | |
| | | 2013 | | | 2012 | |
Tax expense at statutory rate of 34% | | $ | 3,372,404 | | | $ | 2,065,991 | |
State income tax, net of federal tax expense | | | 348,151 | | | | 228,051 | |
Amortization of deferred investment tax credits | | | (21,062) | | | | (21,062) | |
Change in valuation allowance | | | (237,557) | | | | (262,343) | |
Permanent differences | | | 134,583 | | | | 140,211 | |
State rate change | | | (346,149) | | | | - | |
Other | | | (2,825) | | | | 206,277 | |
| | | | | | | | |
| | |
Total income tax expense | | | 3,247,545 | | | | 2,357,125 | |
Discontinued operations | | | 144,353 | | | | 293,444 | |
| | | | | | | | |
| | |
Income tax expense from continuing operations | | $ | 3,391,898 | | | $ | 2,650,569 | |
| | | | | | | | |
In 2013, due to the increasing disparity between the tax rates and rules for state income taxes in the states in which the Company operates, the Company changed from using a blended effective tax rate for all its subsidiaries to calculating an effective tax rate for each subsidiary based on each subsidiary’s taxable income and the applicable state tax. This resulted in a decrease in the state effective rate for most subsidiaries offset by an increased effective rate for subsidiaries with operations in North Carolina and Kentucky, with the resulting tax benefit of $336,007 as noted on the “State rate change” line item above. The Company’s Frontier Utilities subsidiary operates in North Carolina and had gross deferred tax assets and net operating losses from the acquisition of Frontier Utilities in 2007 totaling $98.0 million, offset by a 100% valuation allowance of equal amount. Applying the increased effective rate for North Carolina caused an increase in deferred tax assets of $1,970,586 offset by an increase in the corresponding valuation allowance of the same amount. After including the effect of offsetting decreases from other states, the net increase to expense from applying the separate subsidiary effective rates to the valuation allowance is $1,761,514. Combining the ($237,557) from the “Change in valuation allowance” line item above, results in total expense from the change in valuation allowance of $1,523,957.
The Company has approximately $10.2 million in federal net operating loss carryovers as of December 31, 2013. The net operating losses begin to expire in 2024. Due to acquisitions and changes in ownership, these net operating loss carryovers are subject to Section 382 of the Internal Revenue Code. The Company has placed a valuation allowance of $96,000 on the portion relating to its acquisition of Cut Bank Gas in 2009. The Company has approximately $66.8 million of state net operating loss carryovers as of December 31, 2013. The Company has recorded a state deferred tax asset valuation allowance of $3.9 million against the state net operating loss carryover. In addition, the Company has approximately $26.8 million of carryover tax basis as of December 31, 2013. The Company has recorded a state deferred tax asset valuation allowance of $1.7 million related to 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.
In assessing the ability to realize the 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.
F-34
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 years ended December 31, 2013 and 2012, no adjustments were recognized for uncertain tax benefits.
The tax years after 2009 remain open to examination by the major taxing jurisdictions in which the Company operates, although no material changes to unrecognized tax positions are expected within the next twelve months.
During 2012, the Company filed Form 3115 with the Internal Revenue Service for an application for change in accounting method for customer recoveries in Ohio due to rate changes. This application has subsequently been approved by the IRS. Under the Company’s prior method of accounting for customer recoveries in Ohio, income was recognized before the “all events test” for income had been satisfied. At the point at which we were recognizing such income, we did not have a fixed right to such income. In our application, we proposed to apply the “all events test” for income to customer recoveries, such that income will now be recognized in connection with such item only when it has a fixed right to receive such income, and the amount can be determined with reasonable accuracy.
Note 15 – Related Party Transactions
The Company is party to certain agreements and transactions with Richard M. Osborne, the Company’s chairman and chief executive officer; companies owned or controlled by Richard M. Osborne; and other members of the Company’s management.
Acquisition of 8500 Station Street
On March 5, 2013, the Company purchased the Matchworks building in Mentor, Ohio for $1.9 million from McKay Real Estate Corporation, Matchworks, LLC, and Nathan Properties, LLC (collectively, the “Sellers”) by and through Mark E. Dottore as Receiver in the United States District Court. The Sellers are entities owned or controlled by Richard M. Osborne, the Company’s chairman and chief executive officer. The acquisition of the Matchworks Building was approved by the independent members of the Company’s board of directors. SeeNote 3 – Acquisitions for details regarding this transaction.
Acquisition of John D. Oil and Gas Marketing
On June 1, 2013, the Company and its wholly-owned Ohio subsidiary, GNR, completed the acquisition of substantially all of the assets and certain liabilities of JDOG Marketing, an Ohio company engaged in the marketing of natural gas. The Osborne Trust is the majority owner of JDOG Marketing. Richard M. Osborne, the Company’s chairman and chief executive officer, is the sole trustee of the Osborne Trust. The acquisition of JDOG Marketing was approved by the independent members of the Company’s board of directors and the Company’s shareholders. SeeNote 3 – Acquisitions for details regarding this transaction.
Notes Receivable
The Company had a note receivable due from JDOG Marketing, a company controlled by Richard M. Osborne, the Company’s chairman and chief executive officer. In connection with the acquisition of JDOG Marketing, the Company assumed the corresponding liability of this note, effectively settling the note at the close of the acquisition. The balance due at December 31, 2012 related to this note was $35,409, of which $10,998 was due within one year. SeeNote 3 – Acquisitions for details regarding the JDOG Marketing acquisition.
F-35
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company has a note receivable from one of its employees with an annual interest rate of 4%. Monthly payments are based on a 30 year amortization schedule with a balloon payment no later than December 1, 2017. As of December 31, 2013, the principal balance due was $95,665 of which $1,938 is due within one year.
Lease Agreements
The Company had an agreement to lease a pipeline from JDOG Marketing through December 31, 2016. This pipeline and corresponding lease were acquired by the Company in the acquisition of JDOG Marketing. Lease expense resulting from this agreement was $5,500 and $13,200 for the years ended December 31, 2013 and 2012, respectively. These amounts are included in the Natural Gas Purchased column below. There was no balance due at December 31, 2013 or 2012 to JDOG Marketing related to these lease payments. SeeNote 3 – Acquisitions for details regarding the JDOG Marketing acquisition.
On October 7, 2013, 8500 Station Street entered into a lease agreement with OsAir, Inc. (“OsAir”), an entity owned and controlled by Richard M. Osborne, the Company’s chairman and chief executive officer. Pursuant to the agreement, 8500 Station Street leases to OsAir approximately 6,472 square feet of office space located at 8500 Station Street, Mentor, Ohio 44060, at a rent of $5,500 per month for a period of three years starting from March 1, 2013. The lease agreement is not subject to renewal following the end of the term.
On December 18, 2013, Orwell entered into a lease agreement with Cobra Pipeline Co., LLC (“Cobra”), an entity owned and controlled by Richard M. Osborne, the Company’s chairman and chief executive officer. Pursuant to the lease agreement, Cobra leases to Orwell approximately 2,400 square feet of warehouse space located at 2412 Newton Falls Rd., Newton Falls, OH 44444, at a rent of $2,000 per month for the time period commencing on December 18, 2013 and ending on February 29, 2016. Following the end of the initial term, the lease agreement will continue on a month-to-month basis until either party decides to terminate it upon 30 days’ advance written notice to the other party.
Accounts Receivable and Accounts Payable
The table below details amounts due from and due to related parties, including companies owned or controlled by Richard M. Osborne, the Company’s chairman and chief executive officer, at December 31, 2013 and 2012.
| | | | | | | | | | | | | | | | |
| | | Accounts Receivable | | | Accounts Payable | |
| | | December 31, 2013 | | | December 31, 2012 | | | December 31, 2013 | | | December 31, 2012 | |
John D. Oil and Gas Marketing | | $ | - | | | $ | 3,282 | | | $ | - | | | $ | 40,518 | |
Cobra Pipeline | | | 131,208 | | | | 21,698 | | | | 76,909 | | | | - | |
Orwell Trumbell Pipeline | | | - | | | | 90,385 | | | | 122,693 | | | | - | |
Great Plains Exploration | | | 7,033 | | | | 142,740 | | | | 73,983 | | | | 9 | |
Big Oats Oil Field Supply | | | 4,945 | | | | 769 | | | | 179,447 | | | | 11,270 | |
Kykuit Resources | | | - | | | | 98,037 | | | | - | | | | - | |
John D. Oil and Gas Company | | | 91 | | | | - | | | | 82,188 | | | | - | |
Sleepy Hollow Oil & Gas | | | - | | | | 143,697 | | | | - | | | | - | |
Other | | | 2,948 | | | | 21,949 | | | | 24,713 | | | | - | |
| | | | | | | | | | | | | | | | |
Total related party balances | | | 146,225 | | | | 522,557 | | | | 559,933 | | | | 51,797 | |
Less amounts included in discontinued operations | | | - | | | | - | | | | - | | | | 3,868 | |
| | | | | | | | | | | | | | | | |
Total related party balances included in continuing operations | | $ | 146,225 | | | $ | 522,557 | | | $ | 559,933 | | | $ | 47,929 | |
| | | | | | | | | | | | | | | | |
F-36
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The table below details transactions with related parties, including companies owned or controlled by Richard M. Osborne, the Company’s chairman and chief executive officer, for the year ended December 31, 2013:
| | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, 2013 | |
| | | Natural Gas
Purchases | | | Pipeline
Construction
Purchases | | | Rent, Supplies,
Consulting and
Other Purchases | | | Natural Gas
Sales | | | Rental Income
and Other
Sales | |
John D. Oil and Gas Marketing | | $ | 951,120 | | | $ | - | | | $ | 16,599 | | | $ | 5,470 | | | $ | - | |
Cobra Pipeline | | | 842,620 | | | | 263,574 | | | | 20,000 | | | | 157,834 | | | | 381 | |
Orwell Trumbell Pipeline | | | 795,190 | | | | - | | | | - | | | | 1,260 | | | | 33,911 | |
Great Plains Exploration | | | 856,696 | | | | 854 | | | | 1,341 | | | | 9,310 | | | | 47,640 | |
Big Oats Oil Field Supply | | | - | | | | 2,967,705 | | | | 624,147 | | | | 3,996 | | | | 5,125 | |
John D. Oil and Gas Company | | | 911,507 | | | | 5,975 | | | | - | | | | 572 | | | | 29,356 | |
OsAir | | | 241,693 | | | | 13,200 | | | | 91,850 | | | | 4,866 | | | | 72,787 | |
Other | | | 86,987 | | | | 853 | | | | 44,334 | | | | 20,054 | | | | 45,299 | |
| | | | | | | | | | | | | | | | | | | | |
Total | | $ | 4,685,813 | | | $ | 3,252,161 | | | $ | 798,271 | | | $ | 203,362 | | | $ | 234,499 | |
| | | | | | | | | | | | | | | | | | | | |
The table below details transactions with related parties, including companies owned or controlled by Richard M. Osborne, the Company’s chairman and chief executive officer, for the year ended December 31, 2012:
| | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, 2012 | |
| | | Natural Gas
Purchases | | | Pipeline
Construction
Purchases | | | Rent, Supplies,
Consulting and
Other Purchases | | | Natural Gas
Sales | | | Rental Income
and Other
Sales | |
John D. Oil and Gas Marketing | | $ | 2,405,158 | | | $ | 9,870 | | | $ | 58,043 | | | $ | - | | | $ | 13,128 | |
Cobra Pipeline | | | 389,233 | | | | 5,390 | | | | 5,104 | | | | - | | | | 23,210 | |
Orwell Trumbell Pipeline | | | 526,785 | | | | 132 | | | | 19,547 | | | | 26,519 | | | | 4,785 | |
Great Plains Exploration | | | 506,503 | | | | - | | | | - | | | | 7,068 | | | | 10,643 | |
Big Oats Oil Field Supply | | | - | | | | 1,231,921 | | | | 256,607 | | | | 2,131 | | | | 7,068 | |
John D. Oil and Gas Company | | | 502,897 | | | | - | | | | - | | | | 575 | | | | - | |
Sleepy Hollow Oil & Gas | | | - | | | | - | | | | - | | | | - | | | | 5,113 | |
OsAir | | | 248,588 | | | | - | | | | 196,451 | | | | 2,479 | | | | 306 | |
Other | | | 135,927 | | | | - | | | | 127,171 | | | | 28,777 | | | | 411 | |
| | | | | | | | | | | | | | | | | | | | |
Total | | $ | 4,715,091 | | | $ | 1,247,313 | | | $ | 662,923 | | | $ | 67,549 | | | $ | 64,664 | |
| | | | | | | | | | | | | | | | | | | | |
The Company also accrued a liability of $0 and $595,240 due to companies controlled by Richard M. Osborne, the Company’s chairman and chief executive officer, for natural gas used through December 31, 2013 and 2012, respectively, which had not yet been invoiced. The related expense is included in the gas purchased line item in the accompanying statements of comprehensive income.
Richard M. Osborne, the Company’s chairman and chief executive officer, sold shares of common stock in which the Company incurred expenses of $309,432 and $274,213 for the years ended December 31, 2013 and 2012, respectively. These expenses are recorded in the accompanying income statement as stock sale expense.
F-37
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 16 – Segments of Operations
The Company classifies its segments to provide investors with a 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 federally regulated pipeline business. SeeNote 4 – Discontinued Operations for more information regarding the Company’s previously reported Propane Operations segment. The Company has regulated utility businesses in the states of Kentucky, Maine, Montana, North Carolina, Ohio, Pennsylvania and Wyoming and these businesses are aggregated together to form the natural gas operations. Transactions between reportable segments are accounted for on an 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 and payable, equity, and subsidiary investments.
F-38
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following tables set forth summarized financial information for the Company’s Natural Gas, Marketing and Production, Pipeline, and Corporate and Other operating segments.
| | | | | | | | | | | | | | | | | | | | |
Year Ended December 31,
2013 | | | | | | | | | | | | | | | |
| | | Natural Gas
Operations | | | Marketing &
Production
Operations | | | Pipeline
Operations | | | Corporate &
Other
Operations | | | Consolidated | |
| | | | | |
OPERATING REVENUES | | $ | 106,590,940 | | | $ | 20,260,001 | | | $ | 402,914 | | | $ | - | | | $ | 127,253,855 | |
Intersegment eliminations | | | (326,331) | | | | (8,092,760) | | | | - | | | | - | | | | (8,419,091) | |
| | | | | | | | | | | | | | | | | | | | |
Total operating revenue | | | 106,264,609 | | | | 12,167,241 | | | | 402,914 | | | | - | | | | 118,834,764 | |
| | | | | |
COST OF SALES | | | 61,563,103 | | | | 18,145,625 | | | | - | | | | - | | | | 79,708,728 | |
Intersegment eliminations | | | (326,331) | | | | (8,092,760) | | | | - | | | | - | | | | (8,419,091) | |
| | | | | | | | | | | | | | | | | | | | |
Total cost of sales | | | 61,236,772 | | | | 10,052,865 | | | | - | | | | - | | | | 71,289,637 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | |
GROSS MARGIN | | | 45,027,837 | | | | 2,114,376 | | | | 402,914 | | | | - | | | | 47,545,127 | |
| | | | | |
OPERATING EXPENSES | | | | | | | | | | | | | | | | | | | | |
Distribution, general and administrative | | | 21,476,833 | | | | 801,305 | | | | 105,249 | | | | 1,192,431 | | | | 23,575,818 | |
Maintenance | | | 1,305,897 | | | | 2,765 | | | | 9,130 | | | | - | | | | 1,317,792 | |
Depreciation and amortization | | | 5,603,639 | | | | 456,790 | | | | 62,061 | | | | 12,670 | | | | 6,135,160 | |
Accretion | | | 125,130 | | | | 50,844 | | | | - | | | | - | | | | 175,974 | |
Unrealized holding gain | | | - | | | | (1,565,000) | | | | - | | | | - | | | | (1,565,000) | |
Goodwill impairment | | | - | | | | 725,744 | | | | - | | | | - | | | | 725,744 | |
Taxes other than income | | | 3,910,335 | | | | 28,113 | | | | 40,507 | | | | 24,513 | | | | 4,003,468 | |
Intersegment eliminations | | | (13,744) | | | | - | | | | - | | | | (84,090) | | | | (97,834) | |
| | | | | | | | | | | | | | | | | | | | |
Total operating expenses | | | 32,408,090 | | | | 500,561 | | | | 216,947 | | | | 1,145,524 | | | | 34,271,122 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | |
OPERATING INCOME (LOSS) | | | 12,619,747 | | | | 1,613,815 | | | | 185,967 | | | | (1,145,524) | | | | 13,274,005 | |
| | | | | |
Other income (expense) | | | 804,989 | | | | 151,168 | | | | - | | | | (618,104) | | | | 338,053 | |
Interest expense | | | (2,881,218) | | | | (142,031) | | | | (25,877) | | | | (129,480) | | | | (3,178,606) | |
| | | | | | | | | | | | | | | | | | | | |
Income (loss) before taxes | | | 10,543,518 | | | | 1,622,952 | | | | 160,090 | | | | (1,893,108) | | | | 10,433,452 | |
| | | | | |
Income tax benefit (expense) | | | (3,346,726) | | | | (586,326) | | | | (39,161) | | | | 580,315 | | | | (3,391,898) | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | |
INCOME (LOSS) FROM CONTINUING OPERATIONS | | | 7,196,792 | | | | 1,036,626 | | | | 120,929 | | | | (1,312,793) | | | | 7,041,554 | |
Discontinued operations, net of income tax | | | - | | | | - | | | | - | | | | (370,275) | | | | (370,275) | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | |
NET INCOME (LOSS) | | $ | 7,196,792 | | | $ | 1,036,626 | | | $ | 120,929 | | | $ | (1,683,068) | | | $ | 6,671,279 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | |
Capital expenditures | | $ | 23,825,593 | | | $ | 217,201 | | | $ | 3,186 | | | $ | 57,809 | | | $ | 24,103,789 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | |
As of December 31, 2013 | | | | | | | | | | | | | | | | | | | | |
Investment in unconsolidated affiliate | | $ | - | | | $ | 351,724 | | | $ | - | | | $ | - | | | $ | 351,724 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | |
Total assets | | $ | 195,219,938 | | | $ | 11,633,544 | | | $ | 685,760 | | | $ | 83,173,644 | | | $ | 290,712,886 | |
Intersegment eliminations | | | (53,670,915) | | | | (3,678,311) | | | | (28,100) | | | | (29,591,945) | | | | (86,969,271) | |
| | | | | | | | | | | | | | | | | | | | |
Total assets | | $ | 141,549,023 | | | $ | 7,955,233 | | | $ | 657,660 | | | $ | 53,581,699 | | | $ | 203,743,615 | |
| | | | | | | | | | | | | | | | | | | | |
F-39
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, 2012 | | | | | | | | | | | | | | | |
| | | Natural Gas
Operations | | | Marketing &
Production
Operations | | | Pipeline
Operations | | | Corporate &
Other
Operations | | | Consolidated | |
OPERATING REVENUES | | $ | 81,630,788 | | | $ | 13,417,723 | | | $ | 401,933 | | | $ | - | | | $ | 95,450,444 | |
Intersegment eliminations | | | (324,837) | | | | (5,924,362) | | | | - | | | | - | | | | (6,249,199) | |
| | | | | | | | | | | | | | | | | | | | |
Total operating revenue | | | 81,305,951 | | | | 7,493,361 | | | | 401,933 | | | | - | | | | 89,201,245 | |
| | | | | |
COST OF SALES | | | 42,810,640 | | | | 11,877,518 | | | | - | | | | - | | | | 54,688,158 | |
Intersegment eliminations | | | (324,837) | | | | (5,924,362) | | | | - | | | | - | | | | (6,249,199) | |
| | | | | | | | | | | | | | | | | | | | |
Total cost of sales | | | 42,485,803 | | | | 5,953,156 | | | | - | | | | - | | | | 48,438,959 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | |
GROSS MARGIN | | $ | 38,820,148 | | | $ | 1,540,205 | | | $ | 401,933 | | | $ | - | | | $ | 40,762,286 | |
| | | | | |
OPERATING EXPENSES | | | | | | | | | | | | | | | | | | | | |
Distribution, general and administrative | | | 19,806,389 | | | | 449,665 | | | | 87,640 | | | | 472,161 | | | | 20,815,855 | |
Maintenance | | | 1,176,189 | | | | 1,014 | | | | 13,835 | | | | - | | | | 1,191,038 | |
Depreciation and amortization | | | 4,662,313 | | | | 268,202 | | | | 61,085 | | | | 34,542 | | | | 5,026,142 | |
Accretion | | | 113,106 | | | | 48,192 | | | | - | | | | - | | | | 161,298 | |
Taxes other than income | | | 3,366,238 | | | | 38,052 | | | | 35,497 | | | | 39,110 | | | | 3,478,897 | |
| | | | | | | | | | | | | | | | | | | | |
Total operating expenses | | | 29,124,235 | | | | 805,125 | | | | 198,057 | | | | 545,813 | | | | 30,673,230 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | |
OPERATING INCOME (LOSS) | | $ | 9,695,913 | | | $ | 735,080 | | | $ | 203,876 | | | $ | (545,813) | | | $ | 10,089,056 | |
| | | | | |
Other income (expense) | | | 418,822 | | | | (6,051) | | | | - | | | | (1,230,650) | | | | (817,879) | |
Interest expense | | | (2,512,444) | | | | (133,440) | | | | (13,528) | | | | (40,781) | | | | (2,700,193) | |
| | | | | | | | | | | | | | | | | | | | |
Income (loss) before taxes | | | 7,602,291 | | | | 595,589 | | | | 190,348 | | | | (1,817,244) | | | | 6,570,984 | |
| | | | | |
Income tax benefit (expense) | | | (3,135,445) | | | | 4,542 | | | | (97,523) | | | | 577,857 | | | | (2,650,569) | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | |
INCOME (LOSS) FROM CONTINUING OPERATIONS | | $ | 4,466,846 | | | $ | 600,131 | | | $ | 92,825 | | | $ | (1,239,387) | | | $ | 3,920,415 | |
| | | | | |
Discontinued operations, net of income tax | | | - | | | | - | | | | - | | | | (201,098) | | | | (201,098) | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | |
NET INCOME (LOSS) | | $ | 4,466,846 | | | $ | 600,131 | | | $ | 92,825 | | | $ | (1,440,485) | | | $ | 3,719,317 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | |
Capital expenditures | | $ | 18,381,644 | | | $ | 1,393,040 | | | $ | 23,141 | | | $ | 856,359 | | | $ | 20,654,184 | |
| | | | | | | | | | | | | | | | | | | | |
As of December 31, 2012 | | | | | | | | | | | | | | | | | | | | |
Investment in unconsolidated affiliate | | $ | - | | | $ | 321,731 | | | $ | - | | | $ | - | | | $ | 321,731 | |
| | | | | |
Total assets | | $ | 169,616,395 | | | $ | 8,786,247 | | | $ | 632,466 | | | $ | 68,443,708 | | | $ | 247,478,816 | |
Intersegment eliminations | | | (46,338,335) | | | | (447,549) | | | | (16,073) | | | | (26,213,400) | | | | (73,015,357) | |
| | | | | | | | | | | | | | | | | | | | |
Total assets | | $ | 123,278,060 | | | $ | 8,338,698 | | | $ | 616,393 | | | $ | 42,230,308 | | | $ | 174,463,459 | |
| | | | | | | | | | | | | | | | | | | | |
F-40
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 17 – Commitments and Contingencies
Lease Commitments
The following schedule presents the future minimum lease payments under the Company’s lease agreements as of December 31, 2013.
Future Minimum Lease Payments
| | | | | | | | |
| | | Operating Leases | | | Capital Leases | |
2014 | | $ | 253,833 | | | $ | 300,000 | |
2015 | | | 229,711 | | | | 300,000 | |
2016 | | | 125,906 | | | | 300,000 | |
2017 | | | 121,080 | | | | 300,000 | |
2018 | | | 120,633 | | | | 300,000 | |
Thereafter | | | 537,392 | | | | 1,200,000 | |
| | | | | | | | |
Total minimum lease payments required | | $ | 1,388,555 | | | | 2,700,000 | |
| | | | | | | | |
Less: Interest portion | | | | | | | (659,492) | |
| | | | | | | | |
Liability | | | | | | $ | 2,040,508 | |
| | | | | | | | |
Operating Leases
The Company leases certain properties including land, office buildings, and other equipment undernon-cancelable operating leases. Lease expense resulting from operating leases for the years ended December 31, 2013 and 2012, totaled $304,783 and $537,097, respectively.
Capital Leases
During 2012, the Company entered into an agreement with USPF whereby it is leasing certain pipeline and pipeline easement assets. The agreement contains an initial term of sixteen years, with the option to renew for two additional sixteen year terms. The lease calls for future lease payments of $300,000 per year through 2022. The first annual installment is due and payable within a 30 day period beginning on the first anniversary of the commencement date, and each subsequent annual installment is due and payable within the applicable 30 day period commencing on each subsequent anniversary, subject to the right of the Company to defer a portion of each annual installment if chosen.
The agreement calls for a $120,000 facility service fee to be paid by the Company each year within a 30 day period beginning on the first anniversary of the commencement date, as long as the leased assets remain in place on the property. Also included in the agreement is a throughput charge of $0.0125 per Mcf moved through the leased pipeline. There were no throughput charge payments made during 2013 or 2012. There was no facility service fees paid in 2013 or 2012.
The cost basis and accumulated depreciation of assets recorded under capital leases, which are included in Property, Plant, and Equipment on the Consolidated Balance Sheets are as follows as of December 31, 2013 and 2012:
| | | | | | | | |
| | | December 31, | |
| | | 2013 | | | 2012 | |
Gas transmission & distribution facilities | | | 6,320,000 | | | | 6,320,000 | |
| | | | | | | | |
Capital lease assets, gross | | | 6,320,000 | | | | 6,320,000 | |
Accumulated depreciation | | | (501,587) | | | | (100,317) | |
| | | | | | | | |
Capital lease assets, net | | | 5,818,413 | | | | 6,219,683 | |
| | | | | | | | |
F-41
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Depreciation expense recorded in connection with assets under capital leases was $401,270 and $100,317 for the years ended December 31, 2013 and 2012, respectively.
Long-term Contracts
The Company has a long-term contract with Northwestern Energy for pipeline and storage capacity which commits the Company to purchase certain blocks of pipeline capacity through 2018 at the interconnect with the TransCanada pipeline. The Company has a companion contract with TransCanada for pipeline capacity of equal quantities and terms. These agreements are based on current tariff prices as specified in the contracts. Neither of these contracts have been recognized on the Company’s Consolidated Balance Sheets.
The Company’s subsidiary, Bangor Gas, entered into an agreement with Maritimes and Northeast Pipeline for the transportation and storage of natural gas. This agreement has not been recognized on the Company’s Consolidated Balance Sheets.
The Company guarantees the gas supply obligations of its subsidiaries for up to $6.0 million of amounts purchased.
The future obligations under these pipeline, storage and gas purchase agreements at December 31, 2013 are as follows:
Future Minimum Long-term Contract Obligations
| | | | | | | | | | | | |
| | | Northwestern
Energy | | | Trans-Canada | | | Maritimes and
Northeast Pipeline | |
2014 | | $ | 1,517,892 | | | $ | 921,977 | | | $ | 575,622 | |
2015 | | | 1,434,680 | | | | 829,775 | | | | 357,042 | |
2016 | | | 519,356 | | | | 368,768 | | | | 357,042 | |
2017 | | | 519,356 | | | | 368,768 | | | | 357,042 | |
2018 | | | 476,076 | | | | 338,036 | | | | 357,042 | |
Thereafter | | | - | | | | - | | | | 357,042 | |
| | | | | | | | | | | | |
Total | | $ | 4,467,360 | | | $ | 2,827,324 | | | $ | 2,360,832 | |
| | | | | | | | | | | | |
Environmental Contingency
Included as part of our acquisition of Independence in 2011, the Company identified a piece of property that encountered a diesel fuel spill and required environmental cleanup. This property is currently used as a storage facility for the diesel fuel and propane that is utilized in daily operations. The Company has completed the voluntary remediation of the soil contaminants at the property and continues to monitor the site for additional contamination.
Approximately $24,000 and $25,000 was voluntarily incurred to evaluate and remediate the site during 2013 and 2012, respectively. The Company expects on-going monitoring and monitoring system removal costs for 2014 of approximately $7,000 if the site tests negative for further contaminants. If the property test positive for contamination, further voluntary remediation in 2014 could cost the Company up to a total of approximately $23,000. The Company will expense these voluntary remediation costs as incurred.
Legal Proceedings
From time to time, the Company is involved in lawsuits that have arisen in the ordinary course of business. The Company is contesting each of these lawsuits vigorously and believes it has defenses to the allegations that have been made.
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GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Shareholder Suits
Beginning on December 10, 2013, five putative shareholder derivative lawsuits were filed by five different individuals, in their capacity as shareholders of Gas Natural, in the United States District Court for the Northern District of Ohio, purportedly on behalf of Gas Natural and naming certain of our current and former executive officers and directors as individual defendants. These five shareholder lawsuits are captioned as follows: (1) Richard J. Wickham v. Richard M. Osborne, et al., (Case No. 1:13-cv-02718-LW); (2) John Durgerian v. Richard M. Osborne, et al., (Case No. 1:13-cv-02805-LW); (3) Joseph Ferrigno v. Richard M. Osborne, et al., (Case No. 1:13-cv-02822-LW); (4) Kyle Warner v. Richard M. Osborne, et al., (Case No. 1:14-cv-00007-LW) and (5) Gary F. Peters v. Richard M. Osborne, (Case No. 1:14-cv-0026-CAB).
Each lawsuit contains claims against various current or former directors or officers of the Company alleging, among other things, violations of federal securities laws, breaches of fiduciary duty, waste of corporate assets, unjust enrichment and insider selling arising primarily out of the Company’s acquisition of the Ohio utilities, services provided by JDOG Marketing and the acquisition of JDOG Marketing and the sale of the Company’s common stock by Richard M. Osborne, the Company’s chairman and chief executive officer, and Thomas J. Smith, our chief financial officer. The suits seek the recovery of unspecified damages allegedly sustained by Gas Natural, which is named as a nominal defendant, corporate reforms, disgorgement, restitution, the recovery of plaintiffs’ attorney’s fees, rescission of the acquisition of the Ohio utilities and John D. Marketing and other relief.
On February 6, 2014, the five lawsuits were consolidated solely for purposes of conducting limited pretrial discovery, and on February 21, 2014, the Court appointed lead counsel for all five lawsuits. No formal discovery has been conducted to date.
At this time the Company is unable to provide an estimate of any possible future losses that it may incur in connection to this suit. The Company carries insurance that it believes will cover any negative outcome associated with this case. This insurance carries a $250,000 deductible which the Company will be responsible for paying before any losses will be covered.
Harrington Employment Suit
On February 25, 2013, one of the Company’s former officers, Jonathan Harrington, filed a lawsuit captioned “Jonathan Harrington v. Energy West, Inc. and Does 1-4,” Case No. DDV-13-159 in the Montana Eighth Judicial District Court, Cascade County. Mr. Harrington claims that he was terminated in violation of Montana statute requiring just cause for termination. In addition, he alleges claims for negligent infliction of emotional distress and negligent slander. Mr. Harrington is seeking relief for economic loss, including lost wages and fringe benefits for a period of at least four years from the date of discharge, together with interest. Mr. Harrington is an Ohio resident and was employed in the Company’s Ohio corporate offices. On March 20, 2013, the Company filed a motion to dismiss the lawsuit on the basis that Mr. Harrington was an Ohio employee, not a Montana employee, and therefore the statute does not apply. The motion has been fully briefed but has not been ruled on by the Court. Likewise, Mr. Harrington has requested oral argument but the Court has not indicated whether such request will be granted. The Company believes his claims under Montana law are without merit, and intends to vigorously defend this case on all grounds.
PUCO Audits
The Company accounts for purchased gas costs in accordance with procedures authorized by the utility commissions in the states in which it operates. 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
F-43
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
future rate changes. The GCRs are monitored closely by the regulatory commissions in all of the states in which the Company operates and are subject to periodic audits or other review processes. The PUCO retrospectively audits the Ohio utility companies’ purchases of natural gas on an annual basis. The purpose of this GCR audit is to reconcile the differences, if any, between the amount the companies paid for natural gas and the amount the companies’ customers paid for natural gas.
2010 NEO & Orwell Audits
During the year ended December 31, 2010, the PUCO conducted audits of NEO and Orwell’s GCRs as filed from September 2007 through August 2009 and January 2008 through June 2010, respectively. In connection with the audits, the PUCO found that NEO had under-recovered gas costs of approximately $1.1 million and Orwell had over-recovered gas costs of approximately $1.0 million. The collection and repayment of the under-recovery and over-recovery for NEO and Orwell began in February, 2012, respectively. These adjustments appeared on the accompanying Consolidated Balance Sheets as part of “recoverable cost of gas purchases” and “over-recovered gas purchases.” The remaining balance in NEO’s recoverable cost of gas purchases was $234,253.42 and $707,002 at December 31, 2013 and 2012, respectively. The remaining balance in Orwell’s over-recovered gas purchases was $0 and $237,175 at December 31, 2013 and 2012, respectively.
2011 Brainard Audit
During the year ended December 31, 2011, the PUCO conducted an audit of Brainard’s rates as filed from July 2009 through June 2011. The PUCO issued an order requiring that Brainard refund approximately $104,000 with interest over twelve months to its customers. The Company initiated the refund commencing in October 2012. These adjustments appear on the accompanying Consolidated Balance Sheets as part of “over-recovered gas purchases.” The remaining balance in Brainard’s over-recovered gas purchases are $0 and $99,479 at December 31, 2013 and 2012, respectively.
2012 NEO & Orwell Audits
On January 23, 2012, the PUCO directed its staff to examine the compliance of NEO and Orwell under the GCR mechanism. In a non-binding report to the PUCO in February 2013, its staff asserted that NEO could have purchased natural gas from local producers for less and recommended an adjustment to the GCR calculations that would result in a liability for NEO and Orwell to its customers.
In July 2013, after a hearing with the PUCO and its staff, the Company determined it was probable that the GCR adjustments recommended by the staff would be adopted by the PUCO and as a result the Company recorded these liabilities in its financial statements for the period ended June 30, 2013. Based on the PUCO staff’s calculations and management’s assessment, a $943,550 liability to its customers was recorded as the Company’s best estimate of the required adjustment to NEO’s GCR and a liability for Orwell to its customers of $251,081.
On November 13, 2013, the PUCO issued an Opinion and Order in the NEO and Orwell GCR cases; case numbers 12-209-GA-GCR and 12-212-GA-GCR. The Order concluded that adjustments to NEO and Orwell’s GCRs were appropriate in the amounts of $0.8 million and $0.2 million, respectively. These adjustments represent disallowed agent fees paid by NEO and Orwell to JDOG Marketing for natural gas procurement, disallowed processing and compression fees paid by NEO to Cobra for NEO’s natural gas supply being delivered through Cobra’s pipeline, and certain excess costs associated with local production gas purchased by NEO and Orwell from JDOG Marketing. Both JDOG Marketing and Cobra were companies controlled by Richard M. Osborne, the Company’s chairman and chief executive officer, during the periods covered by these audits. The Company examined NEO and Orwell’s GCRs for the periods immediately following the companies’ audit periods through December 31, 2013. As a result, the Company calculates that a total liability to its NEO and Orwell customers to be in the range of $1.5 million to $1.9 million. As a result, the Company has accrued an
F-44
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
additional $0.3 million to increase its initial estimated liability to $1.5 million. New information may cause the Company to materially change this estimate in future periods. This accrual is included on the accompanying Consolidated Statement of Comprehensive Income for the year-ended 2013 as part of the Cost of goods sold – Natural gas purchased line item and as a reduction of the Recoverable cost of gas purchases line item on the accompanying December 31, 2013 Consolidated Balance Sheet.
In addition to the GCR adjustments, the PUCO’s Opinion and Order concluded that an investigative audit of NEO, Orwell and all affiliated and related companies should be undertaken by an outside auditor. The costs associated with these audits will be the responsibility of the Company. The costs associated with such an audit cannot be estimated at this time and as such no amount has been accrued. These costs may prove to be material once known.
The Opinion and Order also imposed civil forfeitures of $26,000 and $50,000 for NEO and Orwell, respectively. These civil forfeitures were due to failure to terminate purchase contracts between JDOG Marketing and the companies as ordered by the PUCO in a 2010 order and for Orwell’s failure to have appropriate tariffs on file for services provided.
Trade Receivables
Included in the accounts receivable, trade line item on the accompanying Consolidated Balance Sheets are $1,059,224 and $1,139,778, net of allowance for doubtful accounts of $1,421,000 and $774,000 at December 31, 2013 and December 31, 2012, respectively, for amounts due to the Company by a large industrial customer that is currently under Chapter 11 bankruptcy protection. All but $178,546 of the amounts were incurred after the customer’s petition for bankruptcy was filed and the Company believes it will ultimately receive payment as the customer emerges from bankruptcy protection.
Note 18 – Subsequent Events
The Company declared a dividend of $0.045 per share on January 30, 2014 that is payable to shareholders of record on February 14, 2014. There were 10,451,678 shares outstanding on February 14, 2014 resulting in a total dividend of $470,326 which was paid to shareholders on February 28, 2014.
The Company declared a dividend of $0.045 per share on February 28, 2014 that is payable to shareholders of record on March 14, 2014. There were 10,451,678 shares outstanding on March 14, 2014 resulting in a total dividend of $470,326 which was paid to shareholders on March 31, 2014.
The Company declared a dividend of $0.045 per share on March 26, 2014 that is payable to shareholders of record on April 15, 2014. There were 10,451,678 shares outstanding on April 15, 2014 resulting in a total dividend of $470,326 which will be paid to shareholders on April 30, 2014.
| | |
Exhibit Number | | Description |
| |
| 21 | | List of Company Subsidiaries |
| |
| 23.1 | | Consent of Independent Registered Public Accounting Firm, MaloneBailey LLP |
| |
| 23.2 | | Consent of Independent Registered Public Accounting Firm, ParenteBeard LLC |
| |
| 31.1 | | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| |
| 31.2 | | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| |
| 32 | | Certification of Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
F-45
