Attached files
| file | filename |
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| EX-3.1 - EXHIBIT 3.1 - Gas Natural Inc. | v402967_ex3-1.htm |
| EX-21 - EXHIBIT 21 - Gas Natural Inc. | v402967_ex21.htm |
| EX-31.1 - EXHIBIT 31.1 - Gas Natural Inc. | v402967_ex31-1.htm |
| EX-23.2 - EXHIBIT 23.2 - Gas Natural Inc. | v402967_ex23-2.htm |
| EX-31.2 - EXHIBIT 31.2 - Gas Natural Inc. | v402967_ex31-2.htm |
| EX-23.1 - EXHIBIT 23.1 - Gas Natural Inc. | v402967_ex23-1.htm |
| EXCEL - IDEA: XBRL DOCUMENT - Gas Natural Inc. | Financial_Report.xls |
| EX-32 - EXHIBIT 32 - Gas Natural Inc. | v402967_ex32.htm |
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, 2014
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 | (I.R.S. Employer |
| incorporation or organization) | Identification No.) |
| 1375 East 9th St, Suite 3100 | |
| Cleveland, Ohio | 44114 |
| (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. x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
| Large accelerated filer ¨ | Accelerated filer x |
| Non-accelerated filer ¨ (Do not check if a smaller reporting company) | Smaller Reporting Company ¨ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No x
The aggregate market value of the registrant’s common stock held by non-affiliates as of June 30, 2014 was $106,590,580.
The number of shares outstanding of the registrant’s common stock as of March 6, 2015 was 10,451,678 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive proxy statement for the 2015 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, 2014.
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.
ERP. Enterprise Resource Planning.
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.
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.
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Lightning Pipeline. Lightning Pipeline Company, Inc.
LNG. Liquefied Natural Gas.
Lone Wolfe. Lone Wolfe Insurance, LLC.
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.
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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Table of Contents
| iii |
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, |
| · | the outcome of the shareholder derivative suits and other actions, including claims brought by our former chairman and CEO, that have been brought against the Company, |
| · | the ability to control costs, including the costs associated with the derivative suits and other actions against the Company, |
| · | 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 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 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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Gas Natural Inc. is a natural gas company, primarily operating local distribution companies in six states and serving approximately 68,000 customers in total. We report results in three primary business segments.
| · | Natural Gas. Representing the majority of our revenue, we annually distribute approximately 26 Bcf of natural gas to approximately 68,000 customers through regulated utilities operating in Kentucky, Maine, Montana, North Carolina, Ohio, and Pennsylvania. Our natural gas utility subsidiaries include Bangor Gas Company (Maine), Brainard (Ohio), Cut Bank Gas (Montana), Energy West (Montana), Frontier Natural Gas (North Carolina), NEO (Ohio), Orwell (Ohio and Pennsylvania), PGC (Kentucky). |
| · | Marketing & Production. Annually, we market approximately 1.3 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 55% gross working interest (average 46% net revenue interest) in 160 natural gas producing wells and gas gathering assets located in Glacier and Toole Counties in Montana. |
| · | Corporate & 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 discontinued operations from the sales of Energy West Wyoming, the Shoshone and Glacier pipelines, and Independence. |
For financial information about each of our segments, please see Note 23 – Segments of Operations in the notes to our consolidated financial statements of our Annual Report on Form 10-K for the year ended December 31, 2014.
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
Implementation of Enterprise Resource Planning System
In 2014, we began the implementation of our new Enterprise Resource Planning (ERP) system. The new system should enhance our overall operations through integrating and stream-lining our business processes. We expect to go-live with the initial phase of the project in the second half of 2015.
Sale of Energy West Wyoming and the Shoshone & Glacier Pipelines
On October 10, 2014, we executed a stock purchase agreement for the sale of all of the stock of EWW to Cheyenne Light, Fuel and Power Company and an asset purchase agreement for the sale of the Pipeline Assets to Black Hills Exploration and Production, Inc.. Upon close of the transactions, we will receive approximately $15.8 million for the sale of EWW and approximately $1.2 million for the sale of the Pipeline Assets subject to customary purchase price adjustments. See Note 4 – Discontinued Operations for more information regarding these transactions.
Sale of Clarion & Walker
On January 14, 2015, we entered into an asset purchase agreement with Utility Pipeline, LTD to sell substantially all of the assets and liabilities of our Pennsylvania utilities, Clarion and Walker. Under the agreement, we will receive $0.9 million. The agreement contains customary representations, warranties, covenants and indemnification provisions. The consummation of the transaction is dependent upon the satisfaction or waiver of a number of customary closing conditions, the receipt of approval from the PaPUC and the consent of certain of our lenders. We expect this transaction to be finalized in the second quarter of 2015. See Note 5 – Held for Sale for more information regarding these transactions.
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Rehmann Report
An investigative audit was required in the Opinion and Order issued by the PUCO on November 13, 2013 concerning our Ohio utilities and their affiliates and related entities. On January 23, 2015, Rehmann Corporate Investigative Services filed its report on its investigative audit of our Ohio utilities with the PUCO. The full report can be found on the PUCO’s website, www.puco.ohio.gov, under case number 14-0205-GA-COI. The audit was initiated on June 21, 2014. It focused on several specific areas, including the calculation of the gas cost recovery rates (GCR), gas supply management and retention, internal controls within the companies, corporate and management structure, and related party transactions. The examination focused primarily on past practices and procedures, however, as anticipated the audit report contains various recommendations to ensure that our utilities are operating in the best interests of their ratepayers going forward. We have made, and are still making, significant internal changes to our organization to address the issues raised in the audit report as well as address additional opportunities to improve our operations.
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 it an abundant energy source for the foreseeable future. In 2014, the United States has experienced falling oil prices, lowering the average price of residential heating oil to some of the lowest levels in four years. Despite these lower prices, natural gas continues to be a more economical energy source providing the same energy output for a fraction of the cost. Given the current environment, we expect that natural gas will maintain a favorable competitive position compared with other fossil fuels. 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 cleaner burning attributes of natural gas, we believe environmental regulations may enhance this competitive outlook.
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 invest substantial capital and resources into capital improvements and expansion projects at our core utilities in order to organically grow our customer count, gas volumes, market penetration and market share. 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 our capital investments. In addition, our strategic plan includes the redeployment of assets to focus resources where we can create better shareholder value. |
| · | 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 shareholders by attaining our regulated allowable return on equity as established by our regulators. |
| · | Acquisition Strategy. We regularly evaluate gas utilities of varying sizes for potential bolt-on acquisitions to increase our market penetration or service areas by acquiring operations in or near our current service territories with minimal corporate platform expansion. We also explore acquisition opportunities in new markets that could provide significant growth to our operations and customer base. For these potential acquisitions, we examine under-performing operations in more mature gas markets whose performance and profitability can be increased, smaller operations that are part of larger holding companies that can be grown, or operations in geographic areas that have historically relied on alternate heating fuels that can be converted to natural gas. In addition, we also evaluate potential acquisitions of natural gas related non-utility operations such as gathering, storage and marketing operations that will complement our existing operations. |
Our natural gas operations are located in Kentucky, Maine, Montana, North Carolina, Ohio, and Pennsylvania. Our revenues from natural gas operations are generated under tariffs regulated by those states. Approximately 93%, 89%, and 91% of our revenue was from regulated gas distribution operations for the years ended December 31, 2014, 2013, and 2012, respectively. We believe that this geographically diverse customer base enhances the stability of our 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 0.9% of our natural gas revenue for 2014. Our sales to large commercial and industrial customers are not concentrated in any one industry segment but vary across several industry segments, reflecting the diverse nature of the communities we serve.
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In many states, including all of our service territories, the tariff rates of natural gas utilities are established to allow the utility to earn revenue sufficient to recover operating and maintenance costs, plus 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. 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 1,800 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 the communities of Bangor, Brewer, Old Town, Orono, Bucksport, Hermon, Veazie and Lincoln. Our service area in these communities has a population of approximately 74,000 people. Our Maine operations provide service to approximately 5,400 residential, commercial and industrial customers. We offer transportation services to approximately 42 customers through special pricing contracts. These customers accounted for approximately 11% of the revenue of our Maine operations in 2014.
In Maine, our primary gas supply marketer is Emera Energy Services. We receive our gas supply from the Maritimes & Northeast Pipeline transmission system. Our supply contract is on a full requirements basis with Emera Energy Services.
Montana
Our operations in Montana provide natural gas service to customers in Cascade, Gallatin, and Glacier counties. The population of our service area is approximately 87,000 people. Our Montana operations provide service to approximately 31,200 customers.
The primary gas supply marketers for our Montana natural gas distribution operations are Jefferson Energy Trading and Tenaska Marketing Ventures.
Our Montana operation uses 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, Watauga, Wilkes, and Yadkin counties. This service area has a population of approximately 281,000 people. Our North Carolina operations provide service to approximately 2,900 residential, commercial and transportation customers.
In North Carolina, our primary gas supply marketer is BP. We receive our gas supply from the Transcontinental Gas Pipe Line Company transmission system.
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 Allegheny, Armstrong, Butler, Clarion, Elk, Forest, Indiana, Jefferson and Venango counties. This service area has a population of approximately 1.8 million people. Together, our Ohio and Pennsylvania operations provide service to approximately 27,100 residential, commercial and industrial customers.
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Our Ohio and Pennsylvania utilities receive gas supply from various sources, including BP Energy, Compass Energy Gas Services LLC, Constellation Energy, Exelon Energy Company, Mid-American Natural Resources, and Sequent Energy Management. In addition, the Pennsylvania utilities have local production gas supply purchase agreements with GNR. 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, Orwell Trumbull Pipeline (Cobra and Orwell Trumbull are both companies owned or controlled by Richard M. Osborne, the father of our chief executive officer and our former chairman and chief executive officer), and Spelman.
Our Spelman subsidiary, an Ohio regulated intrastate pipeline company, operates pipelines located in Ohio. The Ohio pipeline transports natural gas to new markets where natural gas service was previously not available. It also connects this area to markets served by our Ohio subsidiaries.
We market approximately 1.3 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 55% gross working interest (average 46% 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 26% of the volume requirements for EWR in our Montana market for the year ended December 31, 2014. These wells are relatively shallow and we have not yet explored the deeper formations on our production properties.
The Company’s EWR subsidiary 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 as it could provide a supply of natural gas in close proximity to our natural gas operations in Montana. Our obligations to make additional investments in Kykuit are limited under our agreement with the other Kykuit investors. At December 31, 2014, we are obligated to invest no more than an additional $0.1 million over the life of the venture. Other investors in Kykuit include Richard M. Osborne, father of the Company’s chief executive officer and the Company’s former chairman and chief executive officer; John D. Oil and Gas Company, a publicly held gas exploration company, which is also the managing member of Kykuit; Thomas J. Smith, a former director of the Company and its former chief financial officer and a director of John D. Oil and Gas Company; and Gregory J. Osborne, chief executive officer and a director of the Company and the former president and director of John D. Oil and Gas Company. Due to significant doubts regarding the recoverability of Kykuit’s leaseholds on unproven oil and gas properties coupled with the bankruptcy of the managing member, the Company believes its investment in Kykuit to be completely impaired.
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. 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.
In 2014, we entered into agreements to sell EWW and the Glacier & Shoshone Pipelines. EWW represented all of our utility operations in Wyoming. The Glacier & Shoshone Pipelines made up the entirety of our Pipeline Operations segment. The assets and liabilities as well as results of operations of both EWW and the Glacier & Shoshone Pipelines have been reclassified to discontinued operations and are now included in the Corporate and Other segment.
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.
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Natural Gas Operations
Our natural gas operations generally face competition in the distribution and sale 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.
| State | Competition | |
| Kentucky | Columbia Gas of Kentucky, Delta Gas, Kentucky Frontier Gas | |
| Maine | Northern Utilities Inc., Maine Natural Gas, various fuel oil distributors, electric providers | |
| 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 |
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 major supply areas to our customers. We maintain a portfolio of both fixed price and market price contracts for our gas cost recovery customers. This portfolio includes a supply mixture of both interstate natural gas as well as locally produced natural gas. In addition, we may also use natural gas commodity swap agreements. We use contracts and swap agreements to protect profit margins on future obligations and for protection in the volatile natural gas markets. 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.
State Regulation
Our utility operations are subject to regulation by the KPSC, MPUC, MPSC, NCUC, PUCO, and the PaPUC. 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, see Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates.
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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. PGC’s 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 rate plan framework. Because heating oil and other alternative fuels are historically prevalent in Maine and because Bangor Gas Company entered the market in 1999 with few customers and sizeable start-up costs, the MPUC established a rate plan for Bangor Gas Company that was based upon the costs of distribution of alternative fuels. The goal of this alternative rate plan framework was to allow Bangor Gas Company to compete as a start-up gas utility with distributors of alternative fuels.
The MPUC approved a seven year extension to our alternative rate plan in September 2014. However, it was appealed by the Office of the Public Advocate and Verso Bucksport Power and is before the Maine Supreme Court to be heard. The case is expected to be decided in 2015. In the meantime, our current rate structure is what was approved by the MPUC in September 2014.
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 Montana, 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 the NCUC agreed to extend the rate plan in place at the time of the acquisition 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 was satisfied with the continuance of these rates. In 2014, Frontier Natural Gas and the NCUC public staff entered into a stipulation under which, among other items, the public staff agreed to not request a change in these margin rates until 2019. See Note 11 – Regulatory Assets and Liabilities for more information. The margin rate consists of the tariff rate less benchmark gas costs. The North Carolina regulatory framework incorporates a purchased-gas commodity cost adjustment mechanism that allows Frontier Natural Gas to adjust rates periodically to recover changes in its wholesale gas costs.
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Ohio and Pennsylvania
Our Ohio and Pennsylvania operations are regulated by the PUCO and the PaPUC. Our Ohio utilities operate under a traditional rate base regulatory mechanism. However, only NEO has tariff rates established 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.
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.
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 in 2009, 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 Energy West subsidiary, 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 NCUC have both expressed reluctance to permit the spin-off required by the MPSC and WPSC. 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, NCUC and WPSC have issued ring-fencing and regulatory compliance requirements that Energy West and its regulated subsidiaries must continue to meet on an on-going basis.
In connection with the WPSC approval of our acquisition of the Ohio and Pennsylvania utilities in 2010, 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 continues to assert 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 prevent us from completing the transaction. In October 2014, we entered into a transaction to sell the stock of EWW which requires the approval of the WPSC. Once the WPSC approves the sale of EWW and the transaction is completed, we will no longer have any operations in Wyoming and the WPSC will no longer hold general jurisdiction over our operations. 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.
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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, and Pennsylvania. 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. 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 and North Carolina. 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. 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
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.
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.
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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 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 will further skew our sales volumes.
We had a total of 229 employees as of December 31, 2014 of which 205 are full time, 210 are employed by our natural gas operations and 19 are employed by our marketing and production or corporate operations. Our natural gas operations include 17 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.
We file or furnish annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and file or furnish amendments to those reports pursuant to Section 13(a) or 15(d) of the Exchange Act and Section 16 reports with the Securities and Exchange Commission (“SEC”). The public can obtain copies of these materials by visiting the SEC's Public Reference Room at 100 F Street, NE, Washington DC 20549 or by accessing the SEC's website at http://www.sec.gov. The public may obtain information on the operation of the SEC's Public Reference Room by calling (800) SEC-0330. In addition, as soon as reasonably practicable after such materials are filed with or furnished to the SEC, we make copies available to the public free of charge through our website at www.egas.net. However, our website and any contents thereof should not be considered to be incorporated by reference into this document or any other documents we file or furnish to the SEC.
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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 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. 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. Significant disallowances could affect our earnings and cash flow.
The PUCO examined NEO and Orwell under the GCR mechanism. NEO’s audit covered the GCR mechanism from September 2009 through February 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 our recovery of $1.0 million, primarily fees paid to JDOG Marketing, and fines of $76,000. In addition, the order called for an investigative and forensic audit of NEO, Orwell and all affiliated and related companies and their internal management controls to be undertaken by an outside auditor. The results of this audit were released on January 23, 2015. The report made various recommendations primarily, regarding the Company’s Ohio GCR filings, business structure, and internal controls. The PUCO has yet to comment on any actions it may take as a result of this report. Depending on the PUCO’s actions, 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. 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. The consolidated action 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 and unjust enrichment 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 former chairman and chief executive officer, and Thomas J. Smith, a former director of the Company and its former chief financial officer. The suit seeks 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 and other relief. 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.
On March 26, 2014, the board formed a special committee in response to a shareholder demand letter. The letter demanded the board take legal action to remedy alleged conduct detailed in the November 13, 2013 PUCO Opinion and Order.
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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, including the outcome of the investigation of the special committee, 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 and investigation 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 the foregoing matters. 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 and investigation could harm our business and financial condition, results of operation or cash flows.
We currently are involved in litigation with Richard M. Osborne, our former chairman and chief executive officer, that could result in significant expense to defend.
Beginning on June 13, 2014, Richard M. Osborne, father of our chief executive officer and our former chairman and chief executive officer, has filed various lawsuits against us and certain of our officers and directors. A more detailed description of these lawsuits is contained in “Legal Proceedings” in this Annual Report on Form 10-K.
The expenses related to continuing to defend litigation initiated by Mr. Osborne 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 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.
Operational issues beyond our control could have an adverse effect on our business.
We operate in geographically dispersed areas. Our ability to provide natural gas depends both on our own operations and facilities and those of third parties, including local gas producers and natural gas pipeline operators from whom we receive our natural gas supply. The loss of use or destruction of our facilities or the facilities of third parties due to extreme weather conditions, breakdowns, war, acts of terrorism or other occurrences could greatly reduce potential earnings and cash flows and increase our costs of repairs and replacement of assets. Our losses may not be fully recoverable through insurance or customer rates.
Storing and transporting natural gas involves inherent risks that could cause us to incur significant financial losses.
There are inherent hazards and operation risks in gas distribution activities, such as leaks, accidental explosions and mechanical problems that could cause the loss of human life, significant damage to property, environmental pollution, impairment of operations, and substantial losses to us. The location of pipelines and storage facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. These activities may subject us to litigation and administrative proceedings that could result in substantial monetary judgments, fines or penalties against us. To the extent that the occurrence of any of these events is not fully covered by insurance, they could adversely affect our earnings and cash flow.
Our earnings and cash flow are sensitive to decreases in customer consumption resulting from warmer than normal temperatures and customer conservation.
Our 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.
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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 industrial customers use natural gas in the production of their products. During economic downturns, these customers may see a decrease in demand for their products, which in turn may lead to a decrease in the amount of natural gas they require for production. In addition, during periods of slow or little economic growth, energy conservation efforts often increase and the amount of uncollectible customer accounts increases. These factors may reduce earnings and cash flow.
Changes in the market price and transportation costs of natural gas could result in financial losses that would negatively impact our results of operations.
We are exposed to the impact of market fluctuations in the price and transportation costs of natural gas. We purchase and store gas for distribution later in the year. We enter into agreements to buy or sell gas at a fixed price. We also enter into natural gas commodity swap agreements as the fixed price participant. 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 these 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.
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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 26% of the volume requirements for Energy West Resource’s Montana market for 2014. 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.
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 $7.8 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 $7.8 million at December 31, 2014. We may continue to depreciate approximately $81.7 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 $7.8 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.
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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.
Compliance with Section 404 is both costly and challenging. 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.
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.
Failure to effectively implement our new enterprise resource planning (ERP) system could have a material adverse effect on our business and stock price.
In 2014, we began the implementation of a new ERP system that will integrate our business processes and we believe that it will improve our overall operations. This new system will require a large amount of our capital and other resources. Failure to properly implement this new ERP system in a timely manner or at all could disrupt our operations and significantly increase our costs.
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.
| 14 |
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.
Risks Related To Our Common Stock
Future issuances of our common stock may dilute the interests of existing shareholders.
We have issued shares of our common stock and may issue additional shares of our common stock to finance acquisitions and in connection with equity offerings. For example, in 2013 we consummated a 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.
Our ability to pay dividends on our common stock is limited.
We cannot assure that we will continue to pay dividends at our current 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 paying 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.
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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. The NYSE MKT rules contain requirements with respect to corporate governance, communications with shareholders, the trading price of shares of our common stock, and various other matters. We believe we are in compliance with NYSE 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, the 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, Structure and Management Risks
Our credit facilities contain restrictive covenants that may reduce our flexibility, and adversely affect our business, earnings, cash flow, liquidity and financial condition.
The terms of our credit facilities impose significant restrictions on our ability and, in some cases, the ability of our subsidiaries, to take a number of actions that we may otherwise desire to take, including:
| · | requiring us to dedicate a substantial portion of our cash flow from operations to the payment of principal and interest on our indebtedness, thereby reducing the availability of cash flow for working capital, capital expenditures and other business activities, |
| · | requiring us to meet certain financial tests, which may affect our flexibility in planning for, or reacting to, changes in our business and the industries in which we operate, |
| · | 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 $948,137 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.
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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. Further, our subsidiaries are legally distinct from us, and although they are wholly-owned and controlled by us, our ability to obtain distributions from them by way of dividends, interest or other payments (including intercompany loans) is subject to restrictions imposed by their term loans and credit facilities (under which they are borrowers and we are a guarantor). For example:
| · | we may cause our Maine, Montana, and North Carolina 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 trailing twelve month period do not exceed 70% of their net income for that same period. |
Additionally, the Montana and Wyoming Public Service Commissions have imposed ring-fencing restrictions on distributions from Energy West and its Montana, Maine, and North Carolina subsidiaries to Gas Natural. The most restrictive of these provisions arose from the November 25, 2014 MPSC Order regarding the temporary increase to our BOA line of credit which restricts the payment of dividends from Energy West and its Montana, Maine, and North Carolina subsidiaries to Gas Natural.
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 of Note 18 – Stockholders’ Equity in the notes to our consolidated financial statements for more information.
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. 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. In October 2014, we entered into a transaction to sell the stock of EWW which requires the approval of the WPSC. Once the WPSC approves the sale of EWW and the transaction is completed, we will no longer have any operations in Wyoming and the WPSC will no longer hold general jurisdiction over our operations. Until the jurisdictional issue is resolved or the sale of EWW is finalized, the WPSC continues to assert jurisdiction over the holding company.
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.
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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 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 transactions with related parties, and shareholders and potential investors in Gas Natural may not value these transactions in the same manner as those with unrelated parties.
We have entered into agreements and transactions with Richard M. Osborne, father of the Company’s chief executive officer and the Company’s former chairman and chief executive officer. In the future we will continue to perform as required under these agreements until they expire and alternative sources are found to replace the services provided. For more information on our related party transactions, see “Certain Relationships and Related Transactions” on page 31 of our definitive proxy statement for the 2014 annual meeting filed with the SEC on May 30, 2014.
Kentucky
In Jackson, Kentucky, we lease a 1,800 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 250 miles of transmission and distribution lines and related metering and regulating equipment in Maine.
Montana
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 638 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.
North Carolina
Our North Carolina natural gas operations are headquartered in Elkin, North Carolina. We own a 12,000 square foot building that has a combination of office, shop and warehouse space. We own approximately 484 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.
Ohio and Western Pennsylvania
We maintain facilities for our Ohio and Western Pennsylvania operations located in Cleveland, Lancaster, Mentor, Orwell, Strasburg, and Newton Falls, Ohio. In Cleveland, we lease 5,300 square feet of space under a long-term lease agreement which serves as the primary office for our chief executive officer, chief financial officer and certain other corporate employees. In Mentor, Ohio we own a 51,000 square foot office building. We use approximately 11,000 square feet as the offices for personnel associated with our Ohio subsidiaries and lease out the remaining capacity of the building. 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 long-term lease agreements with related parties. We own approximately 1,344 miles of transmission and distribution lines and related metering and regulating equipment in Ohio and Western Pennsylvania.
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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 our shareholders, 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). 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.
The consolidated action contains claims against various of our current or former directors or officers alleging, among other things, violations of federal securities laws, breaches of fiduciary duty, waste of corporate assets and unjust enrichment, 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, our former chairman and chief executive officer, and Thomas J. Smith, one of our directors and our former chief financial officer. The suit seeks the recovery of unspecified damages allegedly sustained by the Company, which is named as a nominal defendant, corporate reforms, disgorgement, restitution, the recovery of plaintiffs’ attorney’s fees and other relief.
We, along with the other defendants, filed a motion to dismiss the consolidated action in its entirety on May 8, 2014. The motion to dismiss was based on, among other things, the failure of the plaintiffs to make demand on our board of directors to address the alleged wrongdoing prior to filing their lawsuits and the failure to state viable claims against various individual defendants. Richard Osborne, individually, is now represented by counsel independent of all other defendants in the case and submitted a filing in support of the motion to dismiss on his own behalf.
On September 24, 2014, the magistrate judge assigned to the case issued a report and recommendation in response to the motion to dismiss. The magistrate judge recommended that the plaintiffs’ claims against the individual defendants with respect to the “unjust enrichment” allegation in the complaint be dismissed. The magistrate judge recommended that all other portions of the motion to dismiss be denied. The report and recommendation, the objections filed by the defendants, and the responses from the plaintiffs will all be reviewed by the trial judge assigned to the case who will then either adopt the report and recommendation in full, reject it in full, or adopt in part and modify in part. The parties engaged in a settlement mediation on February 26, 2015. The parties failed to reach a settlement, but discussions are ongoing.
At this time we are unable to provide an estimate of any possible future losses that we may incur in connection to this suit. We carry insurance that we believe will cover any negative outcome associated with this action. This insurance carries a $250,000 deductible, which we have reached. Although we believe these 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 25, 2013, one of our 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 he was terminated in violation of a 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 our Ohio corporate offices. On March 20, 2013, we 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 court asked the parties to file comprehensive statements of fact and scheduled a hearing on the motion to dismiss on July 1, 2014. On July 1, 2014, the court conducted a hearing, made extensive findings on the record, and issued an Order finding in our favor and dismissing all of Mr. Harrington’s claims. On July 21, 2014, Mr. Harrington appealed the dismissal to the Montana Supreme Court where the matter is presently pending awaiting full briefing by the parties. We continue to believe Mr. Harrington’s claims under Montana law are without merit, and will continue to vigorously defend this case on all grounds.
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On June 13, 2014, Richard M. Osborne, father of our chief executive officer and our former chairman and chief executive officer, filed a lawsuit against us and our corporate secretary captioned, “Richard M. Osborne and Richard M. Osborne Trust, Under Restated and Amended Trust Agreement of February 24, 2012 v. Gas Natural, Inc. et al.,” Case No. 14CV001210 which was filed in the Court of Common Pleas in Lake County, Ohio. In this lawsuit, Mr. Osborne seeks an order requiring us to provide him with “the minutes and any corporate resolutions for the past five years.” We have provided Mr. Osborne with all the board minutes he requested that have been approved by the board. On October 29, 2014, Mr. Osborne filed an amended complaint in this matter demanding minutes of the committees of the board of directors and additional board minutes which he claims he is entitled to receive. Mr. Osborne has also filed requests for discovery in this lawsuit. On November 17, 2014, the defendants moved to dismiss Mr. Osborne’s amended complaint for failure to state a claim upon which relief can be granted, and for summary judgment. On February 11, 2015, the Court granted defendants’ motion, dismissing the case except for one allegation in one paragraph of Mr. Osborne’s amended complaint: that we failed to produce minutes of any board meeting that occurred between June 1, 2014 and June 13, 2014. The Court held in abeyance its ruling on this issue, to give Mr. Osborne 30 days to conduct discovery limited to determining whether any board meetings occurred during that two-week period. On February 13, 2015, Mr. Osborne voluntarily dismissed his Complaint, without prejudice.
On June 26, 2014, Mr. Osborne filed a lawsuit against us and our board of directors captioned “Richard M. Osborne, Richard M. Osborne Trust, Under Restated and Amended Trust Agreement of February 24, 2012 and John D. Oil and Gas Marketing Company, LLC v. Gas Natural, Inc. et al.,” Case No. 14CV001290, filed in the Court of Common Pleas in Lake County, Ohio. In this lawsuit, among other things, Mr. Osborne (1) demanded payment of an earnout associated with our purchase of assets from John D. Marketing, (2) alleged that the board of directors breached its fiduciary duties, primarily by removing Mr. Osborne as chairman of the board and CEO, (3) sought injunctive relief to restrain our board members from “taking any actions on behalf of Gas Natural until they are in compliance with the law and the documents governing corporate governance,” and (4) asked the Court to enjoin the 2014 annual meeting scheduled to take place on July 30, 2014, and to delay it until such time that the board of directors would be “in compliance with the law and corporate governance.”
Mr. Osborne dismissed the above lawsuit on July 15, 2014, without prejudice, as the parties started to engage in settlement negotiations in an attempt to resolve the dispute. After settlement negotiations broke down, Mr. Osborne refiled the lawsuit on July 28, 2014, against us and our board members. In the re-filed lawsuit, among other things, Mr. Osborne (1) demands payment of an earnout amount associated with our purchase of assets from John D. Marketing, (2) alleges that the board of directors breached its fiduciary duties by removing Mr. Osborne as chairman and chief executive officer, (3) seeks to enforce a July 15, 2014 term sheet, where the parties memorialized certain discussions they had in connection with their efforts to resolve the dispute arising out of the lawsuit, which included a severance payment of $1.0 million, and (4) seeks to invalidate the results of the July 30, 2014 shareholder meeting and asks the court to order us to hold a new meeting at a later date. Mr. Osborne is also seeking compensatory and punitive damages. The parties are currently conducting discovery in this lawsuit. We believe that Mr. Osborne’s claims in this lawsuit are wholly without merit and will vigorously defend this case on all grounds.
As disclosed above, on June 26, 2014, Mr. Osborne filed a lawsuit against us in the Court of Common Pleas in Lake County, Ohio. In the lawsuit, Mr. Osborne sought injunctive relief delaying the 2014 annual meeting scheduled to take place on July 30, 2014. While that suit was pending, on July 9, 2014, Mr. Osborne mailed the first of several letters to our shareholders, criticizing our board and seeking the shareholders’ support in replacing them. On July 15, 2014, Mr. Osborne dismissed without prejudice his Lake County lawsuit, but he refiled it on July 28, 2014. He did not again seek to enjoin the annual shareholder meeting, which occurred as scheduled two days later. Instead, he requests in his complaint that the Lake County court void the election of directors at the July 30, 2014 meeting and order us to conduct another shareholder meeting for the purpose of electing directors no later than February 2015, which the Court has not done. Mr. Osborne’s refiled lawsuit remains pending. Mr. Osborne wrote two additional letters, dated August 12, 2014, and September 9, 2014, which he mailed to our shareholders in mid-September. In the letters Mr. Osborne continued to criticize our board and management.
Mr. Osborne did not file his letters with the Securities and Exchange Commission and we believe that his letters violated Section 14(a) of the Securities Exchange Act and related regulations that require shareholder solicitations to be filed with the SEC. On October 2, 2014, we filed a suit against Mr. Osborne captioned “Gas Natural Inc. v. Richard M. Osborne” in the United States District Court Northern District of Ohio (Case No. 1:14-cv-2181). In this case we sought to enjoin Mr. Osborne from sending additional letters to our shareholders without complying with applicable Federal securities laws. The court held a hearing on October 8, 2014, and the judge granted the injunction, requiring Mr. Osborne to file with the SEC any letters he writes to shareholders so long as his action in Lake County seeking to invalidate the July 30, 2014 meeting is pending. Mr. Osborne has appealed the ruling. We believe his appeal is wholly without merit and will vigorously contest it.
In our 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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Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Our Common Stock
Our common stock trades on the NYSE 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 12/31/14 | High | Low | ||||||
| First Quarter | $ | 10.27 | $ | 7.92 | ||||
| Second Quarter | $ | 11.35 | $ | 9.98 | ||||
| Third Quarter | $ | 13.17 | $ | 10.25 | ||||
| Fourth Quarter | $ | 11.74 | $ | 10.75 | ||||
| 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 | ||||
Holders of Record
As of March 4, 2015, there were approximately 188 record owners of our common stock. We estimate that approximately 6,693 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, 2013 through December 31, 2014. Starting in 2015, we will switch to a quarterly dividend schedule.
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. On November 25, 2014, the MPSC, in an order regarding the increase of our BOA line of credit, issued a ring-fencing provision restricting the ability of Energy West and its Montana, Maine, and North Carolina operating subsidiaries to pay dividends to the parent company. For additional information on loan covenants and restrictions contained in our debt documents, please see Management Discussion and Analysis of Financial Condition and Results of Operations - Capital Sources and Liquidity.
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.
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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, 2009 to December 31, 2014.
| 2009 | 2010 | 2011 | 2012 | 2013 | 2014 | |||||||||||||||||||
| Gas Natural Inc. | $ | 100.00 | $ | 106.92 | $ | 121.33 | $ | 104.42 | $ | 94.95 | $ | 136.99 | ||||||||||||
| S&P 500 Index - Total Returns | 100.00 | 115.06 | 117.49 | 136.30 | 180.44 | 205.14 | ||||||||||||||||||
| S&P 500 Utilities Index | 100.00 | 105.46 | 126.46 | 128.09 | 145.02 | 187.04 | ||||||||||||||||||
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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) | 2014 (1) | 2013 (2) | 2012 (3)(4) | 2011 (4) | 2010 | |||||||||||||||
| Revenue | $ | 132,570 | $ | 109,400 | $ | 81,394 | $ | 86,365 | $ | 82,668 | ||||||||||
| Income from continuing operations | $ | 2,729 | $ | 5,852 | $ | 3,195 | $ | 4,065 | $ | 4,851 | ||||||||||
| Income from discontinued operations | 1,033 | 819 | 524 | 1,305 | 946 | |||||||||||||||
| Net income | $ | 3,762 | $ | 6,671 | $ | 3,719 | $ | 5,370 | $ | 5,797 | ||||||||||
| Basic and diluted earnings per share: | ||||||||||||||||||||
| Continuing operations | $ | 0.26 | $ | 0.63 | $ | 0.39 | $ | 0.50 | $ | 0.77 | ||||||||||
| Discontinued operations | 0.10 | 0.08 | 0.07 | 0.16 | 0.15 | |||||||||||||||
| Net income per share | $ | 0.36 | $ | 0.71 | $ | 0.46 | $ | 0.66 | $ | 0.92 | ||||||||||
| Dividend declared per weighted average common share | $ | 0.50 | $ | 0.55 | $ | 0.54 | $ | 0.54 | $ | 0.56 | ||||||||||
| Weighted average shares outstanding - basic | 10,478,312 | 9,339,002 | 8,163,814 | 8,151,935 | 6,292,717 | |||||||||||||||
| Weighted average shares outstanding - diluted | 10,478,817 | 9,339,722 | 8,169,679 | 8,159,827 | 6,300,972 | |||||||||||||||
| Plant, property, & equipment, net | $ | 142,011 | $ | 124,588 | $ | 107,413 | $ | 86,076 | $ | 67,119 | ||||||||||
| Total assets | $ | 214,004 | $ | 203,732 | $ | 174,463 | $ | 156,411 | $ | 137,728 | ||||||||||
| Non-current liabilities | $ | 56,352 | $ | 54,361 | $ | 53,426 | $ | 36,580 | $ | 24,977 | ||||||||||
| Capitalization | $ | 136,031 | $ | 137,678 | $ | 120,045 | $ | 106,117 | $ | 95,660 | ||||||||||
| (1) | In 2014, due to the pending sale of EWW and the Glacier and Shoshone pipelines, the Company has reclassified the results of operations and financial position of these entities to discontinued operations. All prior periods have been reclassified to match the current year’s presentation. See Note 4 – Discontinued Operations to the notes to our consolidated financial statements. |
| (2) | In 2013, the Company completed the purchase of substantially all the assets of JDOG Marketing. See Note 3 – Acquisitions to the notes to our consolidated financial statements. |
| (3) | 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. |
| (4) | In 2013, the Company sold its Independence subsidiary. The results of operations and financial position for this subsidiary for the years presented 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. |
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
This discussion should be read in conjunction with the consolidated financial statements, notes and tables included elsewhere in this Form 10-K. Management’s discussion and analysis contains forward-looking statements that are provided to assist in the understanding of anticipated future performance. However, future performance involves risks and uncertainties which may cause actual results to differ materially from those expressed in the forward-looking statements. See “Forward-Looking Statements”.
Executive Overview
Gas Natural is a natural gas company, primarily operating local distribution companies in six states and serving approximately 68,000 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), Frontier Natural Gas (North Carolina), Northeast Ohio Natural Gas Corporation (Ohio), Orwell Natural Gas Company (Ohio and Pennsylvania), and Public Gas Company (Kentucky). Approximately 93%, 89%, and 91% of our revenues in 2014, 2013, and 2012, respectively, were derived from our natural gas utility operations. Each of these entities is regulated in their respective states and operates under tariffs which allow them to collect revenue sufficient to recover their operating costs and earn a reasonable rate of return on their “rate base”.
Our operations also include the marketing and production of natural gas. Our marketing and production subsidiaries are Energy West Resources (Montana & Wyoming) and Gas Natural Resources (Ohio and Pennsylvania). Our marketing and production subsidiaries obtain gas from interstate pipelines, local producers, and from small production wells in which it owns an interest. This gas is then sold to commercial and industrial customers that are the end users of the commodity. In 2014, our marketing and production subsidiaries marketed approximately 1.3 Bcf of natural gas in four states.
The following summarizes the critical events that impacted our results of operations during the year ended December 31, 2014:
Gross margin increased by $1,482,000 in 2014, primarily as a result of:
| · | Customer count related to our continuing operations increased by 4.6%. |
| · | Colder weather throughout our service territories. |
| · | A net charge to gas costs in the 2014 period of $686,000 which consists of a true-up of ($301,000) to the accrual contained in the 2013 disallowance amount, offset by additional costs disallowed by the PUCO in 2014 of $987,000. The 2013 period included a disallowance of gas costs of $1,502,000. |
| · | Decrease in our Marketing and Production segment’s gross margin due to the loss of our LNG customer to pipeline competition. |
Net income decreased $2,909,000 primarily due to:
| · | Increases in legal fees of $1,868,000 related primarily to the legal proceedings discussed in Note 24 – Commitments and Contingencies to the notes of our consolidated financial statements have caused general and administrative expenses to increase significantly in 2014 as compared to 2013. |
| · | General and administrative expenses also increased as a result of $569,000 in consulting and auditing fees related to improving and auditing our internal control environment. |
| · | Amortization of the regulatory asset created from the stipulation that the Company’s Frontier subsidiary entered into with the Public Staff - North Carolina Utilities Commission (Docket No G-40, Sub 124), totaled expense of $245,000. Please refer to Note 11 – Regulatory Assets and Liabilities – Deferred Costs to the notes of our consolidated financial statements for further information about the stipulation and regulatory asset. |
| · | Increases in our provision for doubtful accounts include $1,056,000 in expense resulting from a ruling not in our favor in a large industrial customer’s Chapter 11 bankruptcy proceeding. |
| · | The charge related to the impairment of our remaining investment in Kykuit totaled $350,000. |
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| · | Increases in expense in 2014 from the unrealized loss of $62,000 related to our contingent consideration liability arising from the 2013 purchase of JDOG Marketing. The 2013 period included an unrealized gain related to the contingent consideration liability of $1,565,000. The 2013 gain was partially offset by an impairment loss of $726,744 related to the goodwill acquired in the purchase of JDOG Marketing. |
The following additional significant events occurred during the year ended December 31, 2014:
| · | Temporarily increased the borrowing capacity under our line of credit by $10.0 million, conditional upon certain regulatory restrictions by the MPSC. |
| · | Entered into agreements to sell EWW and the Glacier & Shoshone pipelines. |
| · | Began implementation of our new ERP system. We expect to go-live in the second half of 2015. |
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.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operation are based upon consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and disclosure of contingent assets and liabilities, if any, at the date of the financial statements. We analyze our estimates, including those related to regulatory assets and liabilities, income taxes and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements. See Note 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, 2014, our total regulatory assets were $6.2 million and our total regulatory liabilities were $2.0 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, and Pennsylvania 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.
A significant regulatory asset/liability relates to the recoverable/refundable costs of gas purchases. We account for purchased gas costs in accordance with procedures authorized by the state regulatory agencies, under which purchased gas costs that are different from those provided for in present rates are accumulated and recovered or credited through future rate changes.
Our gas cost recoveries are monitored closely by the regulatory commissions in all of the states in which we operate. The gas cost recoveries are adjusted monthly in four of the six states in which we operate, and 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.
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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, 2014 and December 31, 2013. A 10% change in our unbilled revenue at December 31, 2014 would have impacted our gross margin by $152,000.
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. The fair values of our derivative instruments are estimated based on the difference between the fixed commodity price designated in the agreement and the commodity futures price for the settlement period at the measurement date.
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 $7.8 million as of December 31, 2014 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 limited our tax depreciation in tax years 2007 through 2012. We have approximately $20.0 million of carryover tax basis as of December 31, 2014 and will recognize potential future federal and state income tax benefits of approximately $7.8 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 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.
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Management reevaluates the valuation allowance annually based on future taxable income projections, and adjusts the deferred tax asset valuation allowance, if based on the weight of available evidence, it is more-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 $4.7 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 97.5% of the remaining benefit in the next eight years, with 2.5% 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, 2014 indicated that each of our reporting units were fully recoverable and that no impairment was present. See Note 6– Goodwill to the notes of our consolidated financial statements.
The amounts recorded as goodwill in the consolidated balance sheets at December 31, 2014 and 2013 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 shows the goodwill balances allocated to our PGC and GNR subsidiaries as well as the excess of their fair values over their carrying values as of December 31, 2014:
| Goodwill | Fair Value | Carrying Value | % By Which Fair Value | |||||||||||||
| Operating Unit | ($000s) | ($000s) | ($000s) | Exceeds Carrying Value | ||||||||||||
| PGC Subsidiary | $ | 283 | $ | 1,934 | $ | 1,850 | 4.54 | % | ||||||||
| GNR Subsidiary | 1,376 | 4,116 | 4,078 | 0.93 | % | |||||||||||
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 PGC subsidiary, 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 PGC subsidiary was (1) for discounted cash flow method, the weighted average cost of capital was 7.25% and the perpetuity growth rate was 2.5%, (2) for the guideline public company method, we applied an even weighting to each of the values indicated by operating revenue, operating EBITDA and property, plant, and equipment.
When testing goodwill impairment of the GNR subsidiary, 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 GNR subsidiary was (1) for discounted cash flow method, the weighted average cost of capital was 14.5% and the perpetuity growth rate was 2.5%, (2) for the guideline public company method, we applied an even weighting to each of the values indicated by operating revenue, and operating EBITDA.
Lease Commitments
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 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. The capital lease obligation is amortized over the life of the lease.
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For build-to-suit leases, the Company evaluates its level of risk during asset’s construction or development period. If the Company determines that it bears substantially all of the risk during this period, it establishes an asset and liability for costs incurred on the project. Once the build-to-suit asset is complete, the Company assesses whether the arrangement qualifies for sales recognition under the sale-leaseback accounting guidance. If a lease does not meet the criteria to qualify as a sale-leaseback transaction, the established asset and liability remain on the Company's consolidated balance sheet. This asset is then depreciated over the life of the lease and the liability is reduced by the non-interest portion of the lease payments.
Results of Operations
The following discussion of financial condition and results of operations should be read in conjunction with the Consolidated Financial Statements and Notes thereto and other financial information included elsewhere in this Form 10-K.
Year Ended December 31, 2014 Compared with Year Ended December 31, 2013
| Year Ended December 31, | Amount Change | |||||||||||
| ($ in thousands) | 2014 | 2013 | Favorable (Unfavorable) | |||||||||
| Revenue | $ | 132,570 | $ | 109,400 | $ | 23,170 | ||||||
| Cost of sales | 87,718 | 66,030 | (21,688 | ) | ||||||||
| Gross margin | 44,852 | 43,370 | 1,482 | |||||||||
| Operating expenses | ||||||||||||
| Distribution, general & administrative | 24,770 | 21,308 | (3,462 | ) | ||||||||
| Maintenance | 1,225 | 1,142 | (83 | ) | ||||||||
| Depreciation amortization & accretion | 6,656 | 5,609 | (1,047 | ) | ||||||||
| Taxes other than income | 3,928 | 3,672 | (256 | ) | ||||||||
| Provision for doubtful accounts | 1,112 | 726 | (386 | ) | ||||||||
| Contingent consideration loss (gain) | 62 | (1,565 | ) | (1,627 | ) | |||||||
| Goodwill impairment | - | 726 | 726 | |||||||||
| Total operating expense | 37,753 | 31,618 | (6,135 | ) | ||||||||
| Operating income | 7,099 | 11,752 | (4,653 | ) | ||||||||
| Other income (expense) | 404 | 300 | 104 | |||||||||
| Interest expense | (3,226 | ) | (3,176 | ) | (50 | ) | ||||||
| Income before income taxes | 4,277 | 8,876 | (4,599 | ) | ||||||||
| Income tax expense | (1,548 | ) | (3,024 | ) | 1,476 | |||||||
| Income from continuing operations | 2,729 | 5,852 | (3,123 | ) | ||||||||
| Discontinued operations, net of tax | 1,033 | 819 | 214 | |||||||||
| Net income | $ | 3,762 | $ | 6,671 | $ | (2,909 | ) | |||||
Revenues — Revenues increased by $23,170,000 to $132,570,000 for the year ended December 31, 2014 compared to $109,400,000 for 2013. In our natural gas operation segment, the $25,819,000 increase was attributable to 1) colder weather in the majority of the markets we serve leading to a higher consumption of natural gas, 2) higher prices for natural gas passed through to customers of our regulated subsidiaries, and 3) growth in our customer base. This increase was partially offset by a decrease in revenue of $2,650,000 from our Marketing & Production segment. Revenue from our LNG business decreased by $4,778,000 due to the loss of our LNG customer to pipeline competition in April 2014. Revenue from our western marketing operations decreased by $293,000 due to lower sales volumes. Offsetting these is the increase in revenue from our GNR subsidiary of $2,341,000 representing a full year of operations and the revenue increase from our production operation of $80,000.
Gross margin — Gross margin increased by $1,482,000 to $44,852,000 for the year ended December 31, 2014 compared to $43,370,000 for the year ended 2013. Our Natural Gas Operations segment’s margin increased $2,700,000 due to increased sales volumes from continued customer growth in Maine, North Carolina and Ohio, amplified by colder weather in all of our markets. Gross margin from our Marketing & Production segment decreased $1,217,000 primarily due to higher costs of natural gas used to supply fixed price sales contracts, the loss of our LNG customer to pipeline completion, and the loss of NEO and Orwell as customers. Please refer to Note 6 – Goodwill to the notes of our consolidated financial statements for further details.
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Operating expenses — Operating expenses increased by $6,135,000 to $37,753,000 for the year ended December 31, 2014 compared to $31,618,000 for the prior year period. Distribution, general and administrative expense increased by $3,462,000 due to 1) increased legal fees of $1,868,000 stemming primarily from the legal proceedings discussed in Note 24 – Commitments and Contingencies to the notes of our consolidated financial statements; 2) an increase of $569,000 in consulting and auditing fees related to improving and testing our internal control environment; 3) increases in corporate payroll and benefits of $564,000; and 4) the write-off of $336,000 of construction work in progress relating to a software conversion project that has been terminated. Depreciation expense increased by $1,047,000 due to higher capital expenditures and the amortization of the regulatory asset by Frontier of $245,000. Taxes other than income increased by $256,000 primarily due to higher property, payroll and other taxes in our Ohio subsidiaries. The 2014 period included $1,056,000 in the Provision for doubtful accounts resulting from a ruling against us in a large industrial customer’s chapter 11 bankruptcy proceedings. See Note 2 - Significant Accounting Policies – Receivables to the notes of our consolidated financial statements for further detail. The 2014 period included a net unrealized holding loss of $62,000 related to the earn-out provision in the JDOG Marketing purchase, compared to a net unrealized holding gain of $1,565,000 in 2013. These increases were partially offset by a $726,000 impairment to goodwill in the 2013 period.
Other income (expense) — Other income (expense) increased by $104,000 to $404,000 for the year ended December 31, 2014 compared to $300,000 for the year ended December 31, 2013. The increase was primarily due to a $183,000 gain on the sale of marketable securities, a decrease in acquisition expense of $265,000 year over year, a decrease of $309,000 in S-3 costs and an increase in interest income of $172,000. This was partially offset by a $350,000 loss related to the impairment of our Kykuit investment and a $151,000 loss on derivative assets.
Interest expense — Interest expense increased $50,000 to $3,226,000 for the year ended December 31, 2014 compared to $3,176,000 for the year ended December 31, 2013. This change was primarily due to an increase of $4.4 million in the average outstanding principle balances on our line of credit that is almost entirely offset by a decrease of $2.4 million in the average outstanding principle balances on our notes payable and a decrease in average LIBOR, the basis for our floating interest rates, during the year.
Income tax expense — Income tax expense decreased by $1,476,000 to $1,548,000 for the year ended December 31, 2014 compared to $3,024,000 for the same period in 2013. The decrease is primarily due to the decrease in pre-tax income from continuing operations. In addition, the 2014 and 2013 periods each included a tax benefit from the true-up to the prior year’s tax return of $71,000 and $103,000, respectively. Our effective tax rate was 39.3% for 2014 and 37.5% for 2013. The 2013 period included a tax benefit of $336,000 related to a change in the state effective tax rates as discussed in Note 20 - Income Taxes to the notes of our consolidated financial statements.
Income from Discontinued Operations — The 2014 and 2013 results of the Company’s Energy West Wyoming subsidiary, Pipeline Operations segment, and Propane Operations segment have been classified as discontinued operations. See Note 4 – Discontinued Operations to the notes of our consolidated financial statements for further information regarding this topic.
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Year Ended December 31, 2013 Compared with Year Ended December 31, 2012
| Year Ended December 31, | Amount Change | |||||||||||
| ($ in thousands) | 2013 | 2012 | Favorable (Unfavorable) | |||||||||
| Revenue | $ | 109,400 | $ | 81,394 | $ | 28,006 | ||||||
| Cost of sales | 66,030 | 44,506 | (21,524 | ) | ||||||||
| Gross margin | 43,370 | 36,888 | 6,482 | |||||||||
| Operating expenses | ||||||||||||
| Distribution, general & administrative | 21,308 | 18,512 | (2,796 | ) | ||||||||
| Maintenance | 1,142 | 995 | (147 | ) | ||||||||
| Depreciation amortization & accretion | 5,609 | 4,498 | (1,111 | ) | ||||||||
| Taxes other than income | 3,672 | 3,188 | (484 | ) | ||||||||
| Provision for doubtful accounts | 726 | 952 | 226 | |||||||||
| Contingent consideration loss (gain) | (1,565 | ) | - | 1,565 | ||||||||
| Goodwill impairment | 726 | - | (726 | ) | ||||||||
| Total operating expense | 31,618 | 28,145 | (3,473 | ) | ||||||||
| Operating income | 11,752 | 8,743 | 3,009 | |||||||||
| Other income (expense) | 300 | (891 | ) | 1,191 | ||||||||
| Interest expense | (3,176 | ) | (2,700 | ) | (476 | ) | ||||||
| Income before income taxes | 8,876 | 5,152 | 3,724 | |||||||||
| Income tax expense | (3,024 | ) | (1,957 | ) | (1,067 | ) | ||||||
| Income from continuing operations | 5,852 | 3,195 | 2,657 | |||||||||
| Discontinued operations, net of tax | 819 | 524 | 295 | |||||||||
| Net income | $ | 6,671 | $ | 3,719 | $ | 2,952 | ||||||
Revenues — Revenues increased by $28,006,000 to $109,400,000 for the year ended December 31, 2013 compared to $81,394,000 for the year 2012. Approximately $22,617,000 of the increase was attributable to colder weather in the majority of the markets we serve leading to a higher consumption of natural gas, higher prices for natural gas passed through to customers of our regulated subsidiaries, and growth in our customer base. In addition, $4,080,000 and $716,000 of the increase was due to a full year of operations from our LNG line of business and PGC subsidiary, respectively. Sales from our newly-acquired marketing company, GNR, of $1,947,000 were partially offset by a decrease in revenue of $1,353,000 by our existing marketing operations.
Gross margin — Gross margin increased by $6,482,000 to $43,370,000 for the year ended December 31, 2013 compared to $36,888,000 for the same period in 2012. Gross margin from our natural gas operations increased $5,908,000 due to colder weather and growth in customers and margin in our North Carolina, Maine and Ohio markets. Gross margin was also favorably impacted by $616,000 due to the addition of our GNR subsidiary and $197,000 from a full year of operations of our LNG business in 2013, offset by a decrease in gross margin of $239,000 by our existing marketing operations.
Operating expenses — Operating expenses increased by $3,473,000 to $31,618,000 for the year ended December 31, 2013 compared to $28,145,000 for the prior year period. Operating expenses increased primarily due to: (1) increases in salaries and professional services; (2) increased operating expenses from the Loring pipeline of $669,000; (3) increases in depreciation expense of $1,095,000 related to higher capital expenditures; (4) increased property taxes in our Montana and Maine subsidiaries of $435,000; (5) a goodwill impairment expense in 2013 of $726,000; (6) the write-off of $117,000 of construction work in progress relating to a software conversion project that had been terminated; and (7) a full year of expenses associated with our subsidiary PGC added additional expense of $208,000. These increases were partially offset by a net unrealized holding gain of $1,565,000 related to the JDOG Marketing earn-out provision.
Other income (expense) — Other income (expense) increased by $1,191,000 to income of $300,000 for the year ended December 31, 2013 compared to a loss $891,000 for the same period in 2012. The increase was primarily due to increased service sales in 2013 of $362,000, a decrease in acquisition expenses of $687,000, and a gain on the sale of compressed natural gas equipment of $154,000. This was partially offset by an increase in stock sale expense of $35,000 related to our former CEO’s stock sales completed in the fourth quarter of 2013.
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Interest expense — Interest expense increased by $476,000 for the year ended December 31, 2013 compared to the year ended December 31, 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 2012, 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 average $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 $1,067,000 to $3,024,000 for the year ended December 31, 2013 compared to $1,957,000 for the same period in 2012. The increase is primarily due to an 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 $91,000 and $160,000, respectively, resulting in an increase in tax expense of $69,000. Our effective tax rate was 37.5% for 2013 and 37.7% in 2012. The 2013 period included a tax benefit of $336,007 related to a change in the state effective tax rates as discussed in Note 20 - Income Taxes to the notes of our consolidated financial statements.
Income from Discontinued Operations — The 2013 and 2012 results of the Company’s Energy West Wyoming subsidiary, Pipeline Operations segment, and Propane Operations segment have been classified as discontinued operations. See Note 4 – Discontinued Operations to the notes of our consolidated financial statements for further information regarding this topic.
Net Income by Service Area
The components of net income (loss) for years ended December 31, 2014, 2013 and 2012 are:
| Years Ended December 31, | ||||||||||||
| ($ in thousands) | 2014 | 2013 | 2012 | |||||||||
| Natural Gas operations | ||||||||||||
| Energy West Montana (MT) | $ | 1,215 | $ | 1,345 | $ | 798 | ||||||
| Frontier Natural Gas (NC) | 2,229 | 2,503 | 2,103 | |||||||||
| Bangor Gas (ME) | 2,188 | 2,383 | 1,439 | |||||||||
| Ohio Companies (OH and PA) | 967 | 633 | 229 | |||||||||
| Public Gas (KY) | (107 | ) | (44 | ) | (100 | ) | ||||||
| Total Natural Gas operations | $ | 6,492 | $ | 6,820 | $ | 4,469 | ||||||
| Marketing & Production Operations | (1,434 | ) | 1,037 | 600 | ||||||||
| Corporate & Other | (2,329 | ) | (2,005 | ) | (1,874 | ) | ||||||
| Income from continuing operations | 2,729 | 5,852 | 3,195 | |||||||||
| Discontinued Operations | ||||||||||||
| Energy West Wyoming (WY) | 907 | 1,034 | 608 | |||||||||
| Pipeline operations | 166 | 155 | 117 | |||||||||
| Propane operations | (40 | ) | (370 | ) | (201 | ) | ||||||
| Income/loss from discontinued operations | 1,033 | 819 | 524 | |||||||||
| Consolidated net income | $ | 3,762 | $ | 6,671 | $ | 3,719 | ||||||
The following sections highlight our results by operating segment.
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NATURAL GAS OPERATIONS
| Income Statement | ||||||||||||
| Years Ended December 31, | ||||||||||||
| ($ in thousands) | 2014 | 2013 | 2012 | |||||||||
| Natural Gas Operations | ||||||||||||
| Operating revenues | $ | 123,053 | $ | 97,233 | $ | 73,901 | ||||||
| Gas purchased | 79,097 | 55,977 | 38,553 | |||||||||
| Gross margin | 43,956 | 41,256 | 35,348 | |||||||||
| Operating expenses | 32,074 | 29,395 | 26,157 | |||||||||
| Operating income | 11,882 | 11,861 | 9,191 | |||||||||
| Other income | 890 | 767 | 345 | |||||||||
| Income before interest and taxes | 12,772 | 12,628 | 9,536 | |||||||||
| Interest expense | (2,619 | ) | (2,566 | ) | (2,198 | ) | ||||||
| Income before income taxes | 10,153 | 10,062 | 7,338 | |||||||||
| Income tax expense | (3,661 | ) | (3,242 | ) | (2,869 | ) | ||||||
| Net income | $ | 6,492 | $ | 6,820 | $ | 4,469 | ||||||
| Operating Revenues | ||||||||||||
| Years Ended December 31, | ||||||||||||
| ($ in thousands) | 2014 | 2013 | 2012 | |||||||||
| Full Service Distribution Revenues | ||||||||||||
| Residential | $ | 54,355 | $ | 40,904 | $ | 31,500 | ||||||
| Commercial | 55,481 | 43,321 | 30,466 | |||||||||
| Other | 82 | 81 | 103 | |||||||||
| Total full service distribution | 109,918 | 84,306 | 62,069 | |||||||||
| Transportation | 11,984 | 11,783 | 10,680 | |||||||||
| Bucksport | 1,151 | 1,151 | 1,151 | |||||||||
| Total operating revenues | $ | 123,053 | $ | 97,240 | $ | 73,900 | ||||||
| Utility Throughput | ||||||||||||
| Years Ended December 31, | ||||||||||||
| (in MMcf) | 2014 | 2013 | 2012 | |||||||||
| Full Service Distribution | ||||||||||||
| Residential | 5,427 | 4,645 | 3,922 | |||||||||
| Commercial | 4,909 | 4,547 | 3,748 | |||||||||
| Total full service | 10,336 | 9,192 | 7,670 | |||||||||
| Transportation | 10,444 | 11,558 | 10,301 | |||||||||
| Bucksport | 5,441 | 14,301 | 14,144 | |||||||||
| Total Volumes | 26,221 | 35,051 | 32,115 | |||||||||
| 32 |
Year Ended December 31, 2014 Compared with Year Ended December 31, 2013
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 | Percent (Warmer) Colder | |||||||||||||||||||
| December 31, | 2014 Compared to | |||||||||||||||||||
| Normal | 2014 | 2013 | Normal | 2013 | ||||||||||||||||
| Great Falls, MT | 7,508 | 7,882 | 7,350 | 4.98 | % | 7.24 | % | |||||||||||||
| Bangor, ME | 7,047 | 7,859 | 7,786 | 11.52 | % | 0.94 | % | |||||||||||||
| Elkin, NC | 4,292 | 4,459 | 4,320 | 3.89 | % | 3.22 | % | |||||||||||||
| Youngstown, OH | 6,334 | 6,754 | 6,337 | 6.63 | % | 6.58 | % | |||||||||||||
| Jackson, KY | 4,380 | 4,965 | 4,711 | 13.36 | % | 5.39 | % | |||||||||||||
Revenues and Gross Margin
Revenues increased by $25,820,000 to $123,053,000 for the year ended December 31, 2014 compared to $97,233,000 for the same period in 2013. This increase is the result of the following factors:
| 1) | Revenue from our Montana market increased $4,740,000 on a volume increase of 298 MMcf in the year ended December 31, 2014 compared to the year ended December 31, 2013 due to colder weather and higher prices for natural gas passed through to customers. |
| 2) | Revenue from our Ohio market increased $6,240,000. Revenue from full service customers increased $6,011,000 in 2014 compared to 2013 due to higher prices for natural gas passed through to customers and a volume increase of 492 MMcf resulting from a 5% increase in customers and colder weather. |
| 3) | Revenue from our Maine and North Carolina markets increased $14,527,000 on a volume increase from full service and transportation customers of 153 MMcf in 2014 compared to 2013 due to higher prices for natural gas passed through to customers and customer growth of 20%. The increase in the volumes from customer growth was offset by the loss of a large customer in our Maine market in the last half of 2014.The Loring Pipeline, which began serving customers in October 2014 added $145,000 of additional revenue. |
| 4) | Revenue from our Kentucky markets increased $311,000 on a volume increase from full service residential customers of 30 MMcf in 2014 compared to 2013 due to colder weather and 4.5% customer growth. |
Gas purchased increased by $23,119,000 to $79,097,000 for the year ended December 31, 2014 compared to $55,977,000 in 2013. The increase is due to higher prices for natural gas in 2014 compared to 2013 combined with the higher volume throughput for our full service distribution customers. Related to the in-progress PUCO audit of our gas cost recovery mechanisms in Ohio, included in the 2014 results is a true-up of ($301,000) to the accrual contained in the 2013 disallowance amount, offset by additional disallowed gas costs in 2014 of $987,000 for a net charge of $686,000. Included in the 2013 results is a charge of $1,502,000 for the disallowance of gas costs resulting from a previous gas cost recovery audit by the PUCO.
Gross margin increased by $2,701,000 to $43,957,000 for the year ended December 31, 2014 compared to $41,256,000 for the same period in 2013 due to customer growth in our Maine, North Carolina and Ohio markets and colder weather in all of our service territories. Ohio accounted for $2,188,000 of the increase, Maine and North Carolina for $862,000, and Kentucky for $131,000. These increases in margin were offset partially by a decrease in margin in our Montana natural gas operations of $481,000.
Earnings
The Natural Gas Operations segment’s income for the year ended December 31, 2014 was $6,492,000, or $0.62 per diluted share, compared to $6,820,000, or $0.73 per diluted share for the year ended December 31, 2013.
| 33 |
Operating expenses increased by $2,679,000 to $32,074,000 for the year ended December 31, 2014 compared to $29,395,000 for the same period in 2013. Distribution, general and administrative expenses increased by $1,326,000 due primarily to the increases in allocations of corporate expenses related to the hiring of new corporate personnel and to improving and auditing our internal control environment as discussed above. Depreciation expense increased $989,000 due to the increased capital expenditures and the amortization of the regulatory asset in Frontier of $245,000. Other taxes increased $279,000 due primarily to increased property and payroll taxes in our Ohio subsidiaries.
Other income increased by $123,000 to $890,000 for the year ended December 31, 2014 compared to $767,000 for the same period in 2013. Interest income increased $176,000 primarily due to interest income allowed on deferred gas costs in our North Carolina market. Gains on disposal of property decreased $39,000 for the year ended December 31, 2014 compared to 2013. Income from service sales in 2014 decreased by $62,000 compared to 2013. Additionally, acquisition related costs in 2014 were $0, compared to $47,000 related to the purchase of the Matchworks building asset in 2013.
Interest expense increased by $53,000 to $2,619,000 for the year ended December 31, 2014 compared to $2,566,000 for the same period in 2013. This increase was primarily due to increased borrowing on the line of credit resulting in $134,000 of additional interest expense and $51,000 increased interest expense related to the change in estimate of the recoverable purchased gas costs in our Ohio markets. Partially offsetting these increases, the payoff of the senior secured guaranteed floating rate note on May 3, 2014 resulted in $83,000 less interest. In addition, decreased principal balances on the Bank of America term loan and the capital lease obligation resulted in $15,000 and $38,000 less interest, respectively, compared to the 2013 period.
Income tax expense increased by $419,000 to $3,661,000 for the year ended December 31, 2014 compared to $3,242,000 for the same period in 2013 due primarily to the increase in pre-tax income. The 2014 and 2013 periods, each included a true-up of the prior year’s tax return for a benefit of $75,000 and $95,000, respectively. The 2013 period included a tax benefit related to a change in the state effective tax rates as discussed in Note 20 – Income Taxes to the notes of our consolidated financial statements.
Year Ended December 31, 2013 Compared with Year Ended December 31, 2012
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 | Percent (Warmer) Colder | |||||||||||||||||||
| December 31, | 2013 Compared to | |||||||||||||||||||
| Normal | 2013 | 2012 | Normal | 2012 | ||||||||||||||||
| Great Falls, MT | 7,496 | 7,350 | 6,828 | (1.95 | )% | 7.64 | % | |||||||||||||
| 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 | % | |||||||||||||
Revenues and Gross Margin
Revenues increased by $23,332,000 to $97,233,000 for the year ended December 31, 2013 compared to $73,901,000 for the same period in 2012. This increase is the result of the following factors:
| 1) | Revenue from our Montana market increased $2,100,000 on a volume increase of 377 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. |
| 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. |
| 34 |
Gas purchased increased by $17,424,000 to $55,977,000 for the year ended December 31, 2013 compared to $38,553,000 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 $5,908,000 to $41,256,000 for the year ended December 31, 2013 compared to $35,348,000 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, PGC for $330,000, and Montana for $107,000.
Earnings
The Natural Gas Operations segment’s income for the year ended December 31, 2013 was $6,820,000, or $0.73 per diluted share, compared to $4,469,000, or $0.55 per diluted share for the year ended December 31, 2012.
Operating expenses increased by $3,238,000 to $29,395,000 for the year ended December 31, 2013 compared to $26,157,000 for the same period in 2012. Distribution, general and administrative expenses increased by $1,643,000 due to increases in salaries and professional services. Operating expenses from the newly-acquired Loring pipeline increased $669,000. Depreciation expense increased $929,000 due to the increased capital expenditures. Other taxes increased $508,000 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 $422,000 to $767,000 for the year ended December 31, 2013 compared to $345,000 for the same period in 2012. Income from service sales in 2013 increased by $463,000 compared to 2012. Additionally, acquisition related costs in 2013 totaled $47,000 less than those incurred in 2012.
Interest expense increased by $368,000 to $2,566,000 for the year ended December 31, 2013 compared to $2,198,000 for the same period in 2012. This increase was primarily due to higher average outstanding principle balances on our total borrowings during 2013 as compared to 2012 partially offset by a decrease in the average LIBOR rate between the two years.
Income tax expense increased by $373,000 to $3,242,000 for the year ended December 31, 2013 compared to $2,869,000 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 $95,000 related to the true-up of the prior year’s tax return, while the 2012 period included expense of $230,000, for an increase in expense of $325,000. The 2013 period included a tax benefit related to a change in the state effective tax rates as discussed in Note 20 – Income Taxes to the notes of our consolidated financial statements.
| 35 |
Marketing & Production
| Income Statement | ||||||||||||
| Years Ended December 31, | ||||||||||||
| ($ in thousands) | 2014 | 2013 | 2012 | |||||||||
| Marketing and Production | ||||||||||||
| Operating revenues | $ | 9,517 | $ | 12,167 | $ | 7,493 | ||||||
| Gas Purchased | 8,621 | 10,053 | 5,953 | |||||||||
| Gross Margin | 896 | 2,114 | 1,540 | |||||||||
| Operating expenses | 2,478 | 500 | 805 | |||||||||
| Operating income | (1,582 | ) | 1,614 | 735 | ||||||||
| Other income (loss) | (502 | ) | 151 | (6 | ) | |||||||
| Income (loss) before interest and taxes | (2,084 | ) | 1,765 | 729 | ||||||||
| Interest expense | (121 | ) | (142 | ) | (134 | ) | ||||||
| Income (loss) before income taxes | (2,205 | ) | 1,623 | 595 | ||||||||
| Income tax benefit (expense) | 771 | (586 | ) | 5 | ||||||||
| Net Income (Loss) | $ | (1,434 | ) | $ | 1,037 | $ | 600 | |||||
Year Ended December 31, 2014 Compared with Year Ended December 31, 2013
Revenues and Gross Margin
Revenues decreased by $2,650,000 to $9,517,000 for the year ended December 31, 2014 compared to $12,167,000 for the same period in 2013. Revenue from our LNG business decreased by $4,778,000 due to the loss of our LNG customer to pipeline competition in 2014. Revenues from our existing gas marketing operation decreased by $294,000, due primarily to lower sales volumes. Offsetting these, our GNR subsidiary’s revenue increased by $2,342,000 as a result of its first full year in operation and revenue from our production operation increased by $80,000.
Gross margin decreased by $1,218,000 to $896,000 for the year ended December 31, 2014 compared to $2,114,000 for the same period in 2013. Gross margin from our gas marketing operation decreased by $630,000 in 2014 compared to 2013 due to higher costs of natural gas used to supply fixed price sales contracts, and the lower sales volumes. Gross margin from our LNG business decreased by $329,000 and GNR’s margin decreased by $250,000 due to the loss NEO and Orwell as customers. Please refer to Note 6 – Goodwill to the notes of our consolidated financial statements for further details. Margin from our production operation decreased by $9,000.
Earnings
The Marketing & Production segment’s loss for the year ended December 31, 2014 was $1,434,000, or $0.14 per diluted share, compared to income of $1,037,000, or $0.12 per diluted share for the year ended December 31, 2013.
Operating expenses increased by $1,978,000 to $2,478,000 for the year ended December 31, 2014 compared to $500,000 for the same period in 2013. Our GNR subsidiary was responsible for $1,053,000 of increased expenses in the 2014 period compared to 2013. The 2014 period included a full year of operating results. The 2013 period included an unrealized holding gain on the contingent consideration liability of $1,565,000, partially offset by a goodwill impairment expense of $726,000. Expenses from our existing western Marketing & Production operations increased by $925,000 due primarily to the increase in bad debt expense of $1,056,000 resulting from a ruling against us in a large industrial customer’s chapter 11 bankruptcy proceedings. See Note 2 - Significant Accounting Policies – Receivables to the notes of our consolidated financial statements for further detail.
Other income decreased by $653,000 to a loss of $502,000 for the year ended December 31, 2014 compared to income of $151,000 for the same period in 2013. The 2014 period includes an expense of $350,000 related to the impairment of our investment in Kykuit. See Note 7 - Investment in Unconsolidated Affiliate to the notes of our consolidated financial statements. The 2014 period also includes a mark to market loss of $151,000 related to natural gas swap contracts and the 2013 period includes a gain on the sale of compressed natural gas equipment of $154,000.
| 36 |
Interest expense decreased by $21,000 to an expense of $121,000 for the year ended December 31, 2014 compared to expense of $142,000 for the same period in 2013.
Income tax expense decreased by $1,357,000 to a benefit of $771,000 for the year ended December 31, 2014 compared to expense of $586,000 for the same period in 2013. The 2014 and 2013 periods each included a tax benefit from the true-up to the prior year's tax return of $8,000 and $6,000 respectively, accounting for a decrease in expense of $2,000. The remaining decrease is due primarily to the decrease in pretax income.
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 western 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 & 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 $500,000 for the year ended December 31, 2013 compared to $805,000 for the same period in 2012. Our 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 & 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 primarily due to a gain on the sale of compressed natural gas equipment of $154,000 in 2013.
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. 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 $235,000. The remaining increase is due to an increase in pre-tax income.
| 37 |
Corporate & Other
Our Corporate and Other reporting segment is intended primarily to encompass the results of corporate acquisitions, other equity transactions, and certain other income and expense items associated with Gas Natural’s holding company functions as well as the results of our discontinued operations. Therefore, it does not have standard revenues, gas purchase costs, or gross margin.
| Income Statement | ||||||||||||
| Years Ended December 31, | ||||||||||||
| ($ in thousands) | 2014 | 2013 | 2012 | |||||||||
| Corporate and Other | ||||||||||||
| Operating revenues | $ | - | $ | - | $ | - | ||||||
| Gas Purchased | - | - | - | |||||||||
| Gross Margin | - | - | - | |||||||||
| Operating expenses | 3,201 | 1,724 | 1,183 | |||||||||
| Operating loss | (3,201 | ) | (1,724 | ) | (1,183 | ) | ||||||
| Other income (expense) | 16 | (618 | ) | (1,231 | ) | |||||||
| Loss before interest and taxes | (3,185 | ) | (2,342 | ) | (2,414 | ) | ||||||
| Interest expense | (486 | ) | (467 | ) | (367 | ) | ||||||
| Loss before income taxes | (3,671 | ) | (2,809 | ) | (2,781 | ) | ||||||
| Income tax benefit | 1,342 | 805 | 907 | |||||||||
| Loss from continuing operations | (2,329 | ) | (2,004 | ) | (1,874 | ) | ||||||
| Discontinued operations | 1,033 | 819 | 524 | |||||||||
| Net Loss | $ | (1,296 | ) | $ | (1,185 | ) | $ | (1,350 | ) | |||
Years Ended December 31, 2014, 2013, and 2012
Results of our Corporate & Other segment for the year ended December 31, 2014 include administrative costs of $3,201,000, interest expense of $486,000, a gain on marketable securities of $183,000, acquisition related costs of $7,000, corporate expenses of $170,000, offset by an income tax benefit of $1,342,000, and interest and other income of $10,000, for a loss from continuing operations of $2,329,000, or $0.22 per diluted share.
Results of corporate and other operations for the year ended December 31, 2013 include administrative costs of $1,724,000, acquisition related costs of $225,000, costs related to expenses for our former CEO’s stock sale of $309,000, corporate expenses of $98,000, interest expense of $467,000, offset by an income tax benefit of $805,000, and interest and other income of $14,000, for a loss from continuing operations of $2,004,000, or $0.21 per diluted share.
Results of corporate and other operations for the year ended December 31, 2012 include administrative costs of $1,183,000, acquisition costs of $805,000, costs related to expenses for our CEO’s stock sale of $274,000, corporate expenses of $163,000, interest expense of $367,000, offset by interest income of $12,000 and income tax benefit of $907,000 for a loss from continuing operations of $1,874,000, or $0.23 per diluted share.
Loss from discontinued operations
As a result of the sale of our Independence subsidiary in 2013 and the impending sale of our Energy West Wyoming subsidiary and Glacier & Shoshone pipelines, the results of the operations for these items have been reclassified to discontinued operations in our Corporate & Other operating segment. See Note 4 – Discontinued Operations to the notes of our consolidated financial statements for more information regarding these sales.
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, father of the Company’s chief executive officer and the Company’s former chairman and chief executive officer. For more information, see Note 21 – Related Party Transactions to the notes of our consolidated financial statements for more information regarding all of the Company’s related party transactions.
| 38 |
Capital Sources and Liquidity
Sources and Uses of Cash
Operating activities provide our primary source of cash and are supplemented by our revolving line of credit. At December 31, 2014 and 2013, we had approximately $1.6 million and $12.7 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 our Energy West Wyoming and Independence subsidiaries and Glacier & Shoshone pipeline operations 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 $28.8 million and $24.5 million at December 31, 2014 and 2013, respectively. This increase is primarily attributable to capital expenditures in our Maine and North Carolina markets due to expansion and higher gas costs in all of our regions.
We made capital expenditures of $21.6 million, $23.5 million and $19.9 million for the years ended December 31, 2014, 2013, and 2012 respectively. We finance our capital expenditures on an interim basis by the use of our operating cash flow and our 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 $40.3 million and $43.7 million at December 31, 2014 and December 31, 2013, respectively, including the amount due within one year.
| For the Years Ended December 31, | ||||||||||||
| 2014 | 2013 | 2012 | ||||||||||
| Cash Flows from Continuing Operations | ||||||||||||
| Cash provided by operating activities | $ | 11,146,000 | $ | 15,439,000 | $ | 7,603,000 | ||||||
| Cash used in investing activities | (18,679,000 | ) | (20,192,000 | ) | (22,554,000 | ) | ||||||
| Cash provided by (used in) financing activities | (5,003,000 | ) | 12,485,000 | 7,165,000 | ||||||||
| Increase (decrease) in cash | $ | (12,536,000 | ) | $ | 7,732,000 | $ | (7,786,000 | ) | ||||
| Cash Flows from Discontinued Operations | ||||||||||||
| Cash provided by operating activities | $ | 1,924,000 | $ | 658,000 | $ | 884,000 | ||||||
| Cash provided by (used in) investing activities | (511,000 | ) | 1,738,000 | (699,000 | ) | |||||||
| Cash provided by (used in) financing activities | (33,000 | ) | (590,000 | ) | 401,000 | |||||||
| Increase in cash | $ | 1,380,000 | $ | 1,806,000 | $ | 586,000 | ||||||
Operating Cash Flow
Cash provided by operating activities was $11.1 million for the year ended December 31, 2014, $15.4 million for the year ended December 31, 2013, and $7.6 million for the year ended December 31, 2012. Major items affecting operating cash flows for the year ended December 31, 2014 from the year ended December 31, 2013 include: a decrease in income from continuing operations of $3.1 million, a $3.0 million increase in our net regulatory assets and liabilities, a $2.5 million decrease in unbilled revenue, a $1.5 million increase in payments of other liabilities, a $1.3 million increase in accounts receivable collections, a $1.3 million increase in accounts payable payments, and a $1.1 million increase in prepayments. Major items affecting operating cash flows for the year ended December 31, 2013 from the year ended December 31, 2012 include: an increase in income from continuing operations of $2.7 million, a $2.4 million net increase in unbilled revenue, a $2.4 million decrease in prepayments, a $2.2 million increase in accounts payable, an increase of $2.1 million in purchases of inventory, a $2.1 million decrease in payments of other liabilities, a $1.5 million decrease in payments for other assets, an increase in accounts receivable collections of $1.5 million, and a $1.3 million increase in our net regulatory assets and liabilities.
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Investing Cash Flow
Cash used in investing activities was $18.7 million for the year ended December 31, 2014, $20.2 million for the year ended December 31, 2013, and $22.6 million for the year ended December 31, 2012. The decrease in cash used by investing activities for the years ended December 31, 2014 and 2013 include: a $1.9 million decrease in capital expenditures, a $1.2 million increase in contributions in aid of construction receipts, and $0.4 million cash inflow related to the sale of marketable securities in 2014 offset by a decrease of $1.2 million in the amount of restricted cash released related to capital expenditures and a $0.8 million decrease in the proceeds from the sale of fixed assets. The decrease in cash used by investing activities for the years ended December 31, 2013 and 2012 include: increased capital expenditures of $3.6 million offset by a $2.6 million increase in released from restricted cash related to capital expenditures, a $1.6 million decrease in expenditures related to the 2012 purchase of Public Gas, a $1.1 million increase in cash inflows from contributions in aid of construction, and a $0.9 million increase in proceeds from the sale of fixed assets.
Capital Expenditures
Our capital expenditures totaled $21.6 million, $23.5 million and $19.9 million for the years ended December 31, 2014, 2013, and 2012, respectively. 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 service areas. Capital expenditures for 2014 also included $0.9 million in expenditures related to the new enterprise resource planning system. Also included in capital expenditures for 2013 is $1.6 million for the acquisition of the Matchworks Building in Mentor, Ohio. Additionally, included in capital expenditures for 2012 are $2.3 million for the acquisition of the Loring Pipeline.
The table below details our capital expenditures for the years ended December 31, 2014, 2013 and 2012 and provides an estimate of our cash requirements for capital expenditures for the year ended December 31, 2015:
| Estimated Future Cash | ||||||||||||||||
| ($ in thousands) | Years Ended December 31, | Requirements for | ||||||||||||||
| 2014 | 2013 | 2012 | December 31, 2015 | |||||||||||||
| Natural Gas Operations | $ | 21,530 | $ | 23,242 | $ | 17,687 | $ | 8,105 | ||||||||
| Marketing & Production | 60 | 217 | 1,393 | - | ||||||||||||
| Corporate & Other | 22 | 58 | 856 | 75 | ||||||||||||
| Total Capital Expenditures | $ | 21,612 | $ | 23,517 | $ | 19,936 | $ | 8,180 | ||||||||
Expected capital expenditures in 2015 in our Natural Gas Operations segment will primarily focus on the continued expansion of our natural gas utilities service areas. These expenditures will have an emphasis on our Maine, North Carolina and Ohio markets.
Financing Cash Flow
Cash used in financing activities for the year ended December 31, 2014 was $5.0 million. Cash provided by financing activities was $12.5 million for the year ended December 31, 2013, and $7.2 million for the year ended December 31, 2012. Major items affecting financing cash flows for the year ended December 31, 2014 from the year ended December 31, 2013 include: a $16.7 million decrease in proceeds from the issuance of common shares, a $3.6 million net increase in proceeds from the line of credit, a $2.9 million increase in the repayment of our notes payable, a $0.7 increase in payments of dividends, and $0.6 million decrease in the release of restricted cash balances. The change in financing cash flows for the year ended December 31, 2013 from the year ended December 31, 2012 is due primarily to: $16.7 million in proceeds from the issuance of common shares, a $13.0 million decrease in proceeds from notes payable, a $1.6 million increase in the release of restricted cash related to our debt service fund, a decrease in debt issuance costs of $1.2 million, $0.8 million increase in long term debt and capital lease payments, and $0.6 million additional dividends paid.
Historically, to the extent that cash flows from operating activities are not sufficient to fund our expenditure requirements, including costs of gas purchased and capital expenditures, we have used our revolving line of credit. 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 $28.8 million and $24.5 million at December 31, 2014 and 2013, respectively. We periodically repay our short-term borrowings under the Bank of America revolving line of credit by using the net proceeds from the sale of long-term debt and equity securities. Long-term debt was $40.3 million and $43.7 million at December 31, 2014 and 2013, respectively, including the amounts due within one year.
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The following discussion describes our credit facilities as of December 31, 2014.
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.
In November 2014, Bank of America, with the approval of the MPSC, agreed to temporarily increase our maximum borrowing capacity under the revolving line of credit by $10.0 million to a maximum borrowing capacity of $40.0 million. The MPSC restricted borrowing on this increased borrowing capacity to $5.0 million unless Energy West receives express permission from the commission. In addition, the MPSC restricted draws on the line of credit to only Energy West and its subsidiary companies and suspended all dividend payments from Energy West and our Maine, Montana, and North Carolina subsidiaries to the holding company.
The Credit Agreement includes an annual commitment fee ranging from 25 to 45 basis points of the unused portion of the Credit Agreement and interest on the amounts outstanding at the LIBOR rate plus 175 to 225 basis points.
The following table represents borrowings under the Bank of America revolving line of credit for each of the fiscal quarters and the years ended December 31, 2014 and 2013.
| ($ in thousands) | First | Second | Third | Fourth | Full | |||||||||||||||
| Quarter | Quarter | Quarter | Quarter | Year | ||||||||||||||||
| Year Ended December 31, 2014 | ||||||||||||||||||||
| Minimum borrowing | $ | 21,930 | $ | 19,061 | $ | 19,261 | $ | 24,761 | $ | 19,061 | ||||||||||
| Maximum borrowing | 25,130 | 23,630 | 24,261 | 31,061 | 31,061 | |||||||||||||||
| Average borrowing | 23,368 | 20,227 | 21,702 | 27,906 | 23,397 | |||||||||||||||
| 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 | |||||||||||||||
For the years ended December 31, 2014, 2013, and 2012, the weighted average interest rate on the revolving credit facility was 2.45%, 2.42% and 3.33%, respectively, resulting in $573,000, $455,000, and $500,000 of interest expense, respectively. The balance on the revolving credit facility was $28.8 million and $24.5 million at December 31, 2014 and 2013, respectively. The $28.8 million of borrowings as of December 31, 2014, leaves the remaining borrowing capacity on the line of credit at $11.2 million through July 1, 2015, and $1.2 million thereafter.
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. Generally, 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 $40.3 million at December 31, 2014, with $0.5 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, 2014, the Company had not exercised the interest rate swap provision for the fixed interest rate.
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For the year ended December 31, 2014, 2013, and 2012, the weighted average interest rate was 2.15%, 2.19%, and 2.14%, respectively, resulting in interest expense of $201,000, $216,000, and $56,000, respectively. The balance outstanding on the Term Loan at December 31, 2014 was $8.9 million.
Senior Unsecured Notes of Energy West
On June 29, 2007, Energy West authorized the sale of $13.0 million 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, 2014, 2013, and 2012.
Sun Life Assurance Company of Canada
On May 2, 2011, the Company and its Ohio subsidiaries, NEO, Orwell and Brainard, 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").
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.
The Fixed Rate Note, in the amount of $15.3 million, is a joint obligation of the Company and its Ohio subsidiaries, and is guaranteed by the Company, Lightning Pipeline and Great Plains (together with the Ohio subsidiaries, 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. This note was repaid on May 3, 2014.
The use of proceeds for both notes extinguished existing amortizing bank debt and other existing indebtedness, funded 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 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, 2014, 2013, and 2012, the interest expense on the Fixed Rate Note was $825,000 per year. For the years ended December 31, 2014, 2013, and 2012, the weighted average interest rate on the Floating Rate Note was 4.10%, 4.13%, and 4.31%, resulting in $41,000, $124,000, and $129,000 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 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 has an interest rate of 4.15%, compounded semi-annually, and 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, 2014, 2013, and 2012, interest expense related to the Senior Note was $123,000, $123,000, and $24,000, respectively.
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% 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.
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The 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 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.
The Ohio subsidiaries 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.
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.
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The Fixed Rate Note and Floating Rate Note require an interest coverage ratio of at least 2.0 to 1.0, measured quarterly on a trailing four quarter basis. 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 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 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 total balance in our debt service reserve accounts was $948,000 and $1,080,000 at December 31, 2014 and 2013, 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.
Ring Fencing Restrictions
In addition to the financial covenants under our credit facilities, the ring fencing provisions required by our regulatory commissions impose additional limitations on our liquidity. Specifically, usage of the Bank of America line of credit is regulated by ring fencing provisions from the MPSC, MPUC, NCUC and WPSC. One of the ring fencing provisions issued by the MPSC requires that of the $30.0 million line of credit available, $11.2 million must be used or available to be used exclusively by Energy West Montana. The remaining $18.8 million balance of the line of credit is available for use by Energy West and its other Montana, Wyoming, North Carolina and Maine subsidiaries.
Energy West and Energy West Montana are required to provide monthly financial reports to the MPSC. On April 18, 2014, Energy West reported to the MPSC it had temporarily violated the $11.2 million allocation of the line of credit for use by Energy West Montana. On April 11, 2014 we discovered that the full $11.2 million was not available for Energy West Montana’s exclusive use, and instead that there was a deficiency of $913,000. Energy West immediately corrected the deficiency by April 18, 2014. The MPSC found Energy West and Energy West Montana violated portions of its order and issued a monetary fine of $17,000 on September 18, 2014.
In November 2014, our maximum borrowing capacity under the revolving line of credit was temporarily increased by $10.0 million to a maximum borrowing capacity of $40.0 million. The MPSC restricted borrowing on this increased borrowing capacity to $5.0 million unless Energy West receives express permission from the commission. In addition, the uncommitted $5.0 million of borrowing capacity increase does not count toward the $11.2 million requirement which must be used or available for Energy West.
We continue to monitor our compliance under these ring fencing provisions on a monthly basis. The amount available to be drawn on the Bank of America line of credit after giving effect to the $11.2 million allocation to Energy West Montana was $1.1 million at December 31, 2014. We believe we are currently in compliance with all ring fencing provisions.
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Contractual Obligations
Contractual obligations that require cash payment over future periods at December 31, 2014 were as follows:
| Payments due in years ended December 31, | ||||||||||||||||||||
| Total | 2015 | 2016 - 2017 | 2018 - 2019 | Thereafter | ||||||||||||||||
| Line of credit (1) | $ | 28,760,799 | $ | 28,760,799 | $ | - | $ | - | $ | - | ||||||||||
| Notes payable | 40,198,552 | 500,000 | 39,698,552 | - | - | |||||||||||||||
| Operating leases | 2,191,773 | 273,854 | 482,310 | 440,908 | 994,701 | |||||||||||||||
| Capital leases | 2,400,000 | 300,000 | 600,000 | 600,000 | 900,000 | |||||||||||||||
| Build-to-suit lease (2) | 6,929,992 | 2,405,890 | 4,318,144 | 205,958 | - | |||||||||||||||
| Natural gas purchase obligations (3) | 23,790,487 | 22,973,162 | 817,325 | - | - | |||||||||||||||
| Pipeline & storage capacity obligations | 6,640,025 | 2,621,497 | 2,490,332 | 1,528,196 | - | |||||||||||||||
| Total | $ | 110,911,628 | $ | 57,835,202 | $ | 48,406,662 | $ | 2,775,062 | $ | 1,894,701 | ||||||||||
| (1) | The principle balance on our line of credit is not due until 2017, however due to its classification as a current liability it has been included as a contractual obligation due in 2015. |
| (2) | Build-to-suit lease is related to our new ERP system. |
| (3) | Some of our natural gas purchase obligations are based on future market pricing. Cash payment estimates for these obligations are based on commodity futures pricing for those denoted in the purchase contract. Natural gas purchase obligations are shown net of the impact of our commodity swap agreements. |
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 in Note 2 – Significant Accounting Policies to the notes of our consolidated financial statements.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
We are subject to certain market risks, including commodity price risk and interest rate risk. The adverse effects of potential changes in these market risks are discussed below. The sensitivity analyses presented do not consider the effects that such adverse changes may have on overall economic activity nor do they consider additional actions management may take to mitigate our exposure to such changes. Actual results may differ.
Commodity Price Risk
We seek to protect against natural gas price fluctuations by limiting the aggregate level of net open positions that are exposed to market price changes. In order to limit our commodity price risk exposure, we have entered into natural gas commodity swap contracts for fixed pricing on specified quantities of expected future purchases of gas.
The following table summarizes the commodity swap contracts we have entered into as of November 13, 2014. We will pay the price for the approximate volumes denoted in the table below and will receive from a counterparty the denoted market price for these volumes, settled monthly.
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| Product | Type | Contract Period | Volume | Price per MMBtu | ||||||||||||
| CIG - Rockies - IFERC Natural Gas | Swap | 1/01/15 - 3/31/15 | 500 MMBtu/Day | $ | 3.980 | |||||||||||
| CIG - Rockies - IFERC Natural Gas | Swap | 1/01/15 - 3/31/15 | 500 MMBtu/Day | $ | 4.075 | |||||||||||
| AECO Canada - CGPR 7A Natural Gas | Swap | 1/01/15 - 3/31/15 | 501 MMBtu/Day | $ | 3.560 | |||||||||||
| IFERC Gas Market Report at Algonquin Citygate Natural Gas | Swap | 1/01/15 - 3/31/15 | 3600 MMBtu/Day | $ | 13.000 | |||||||||||
| IFERC Gas Market Report at Algonquin Citygate Natural Gas | Swap | 4/1/15 - 4/30/15 | 2500 MMBtu/Day | $ | 13.000 | |||||||||||
| IFERC Gas Market Report at Algonquin Citygate Natural Gas | Swap | 5/1/15 - 5/31/15 | 1390 MMBtu/Day | $ | 13.000 | |||||||||||
| IFERC Gas Market Report at Algonquin Citygate Natural Gas | Swap | 6/1/15 - 6/30/15 | 950 MMBtu/Day | $ | 13.000 | |||||||||||
| IFERC Gas Market Report at Algonquin Citygate Natural Gas | Swap | 7/1/15 - 7/31/15 | 890 MMBtu/Day | $ | 13.000 | |||||||||||
At December 31, 2014, the fair value of our derivative instruments was a liability of approximately $3.0 million. This valuation is based upon the price of the respective natural gas future at the valuation date as compared to the fixed price as stated in the swap agreement. A hypothetical decrease of 10% in natural gas futures prices would have increased this liability by approximately $0.4 million to $3.4 million. However, since a large portion of the liability represents swap agreements entered into by our regulated subsidiaries that would defer this unrealized change in value as a regulatory asset, the unrealized loss on derivative instruments reflected in our income before taxes would have been approximately $0.1 million.
Interest Rate Risk
At December 31, 2014, we had approximately $28.8 million of borrowings outstanding on our line of credit and $8.9 million of borrowings outstanding on our amortizing term loan. Both of these instruments are exposed to market risk due to fluctuations in their variable interest rate based on LIBOR. A hypothetical 100 basis point change in LIBOR charged on the 2014 monthly average principle balance of these borrowings would have an annual effect on income before taxes of approximately $0.3 million.
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Item 8. Financial Statements and Supplementary Data.
Our Consolidated Financial Statements begin on page F-1 of this Annual Report on Form 10-K.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
As of December 31, 2014, 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, 2014.
Management’s Report on Internal Control over Financial Reporting
Management of Gas Natural is responsible for establishing and maintaining an adequate system of internal control over financial reporting as such term is defined in Exchange Act Rule 13a-15(f). Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with U.S. generally accepted accounting principles defined in the Exchange Act.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
We carried out an evaluation under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, of the effectiveness of our internal control over financial reporting. In making this evaluation, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission for the “Internal Control – Integrated Framework” (2013). Based on that evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2014.
Our independent registered public accounting firm, Malone Bailey, has issued an audit report on the effectiveness of our internal controls over financial reporting as of December 31, 2014, which is included in this Form 10-K.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting during the last fiscal quarter of calendar year 2014, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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Special Committee of the Board Investigation
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 has retained legal counsel and financial and regulatory advisors and is in the process of investigating and evaluating the allegations in order to determine the position Gas Natural will take with respect to the letter. Although the Company believes that insurance proceeds are available for a portion of the cost of the investigation, the Company will incur costs and expenses related to the investigation that are not covered by insurance, which may be substantial.
SEC Investigation
The Company received a letter from the Chicago Regional Office of the SEC dated March 3, 2015 stating that the staff of the SEC is conducting an investigation regarding (i) audits by the PUCO and Rehmann Corporate Investigative Services, (ii) the determination and calculation of the GCR, (iii) the Company’s financial statements and internal controls and (iv) various entities affiliated with our former CEO, Richard M. Osborne. The SEC has requested we preserve all documents relating to these matters. The Company is complying with this request and intends to cooperate fully with the SEC.
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Item 10. Directors, Executive Officers and Corporate Governance.
Information required by this item is incorporated by reference to the material appearing under the headings “The Board of Directors,” “Executive Officers,” “Section 16(a) Beneficial Ownership Reporting Compliance,” “Code of Ethics,” and “Audit Committee Report” in the Proxy Statement for our 2015 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 2015 Annual Meeting.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
Information required by this item is incorporated by reference to the material appearing under the heading “Security Ownership of Principal Shareholders and Management,” and “Equity Compensation Plan Information” in the Proxy Statement for our 2015 Annual Meeting.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Information required by this item is incorporated by reference to the material appearing under the heading “Certain Relationships and Related Transactions” and “Director Independence” in the Proxy Statement for our 2015 Annual Meeting.
Item 14. Principal Accounting Fees and 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 2015 Annual Meeting.
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Item 15. Exhibits, Financial Statement Schedules.
(a) Financial Statements
*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.
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(b) Exhibit Index
Exhibit Number |
Description | |
| 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 | |
| 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 | |
| 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 | |
| 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 | |
| 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 | |
| 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 | |
| 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 | |
| 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 | |
| 3.1* | Amendment to Articles of Incorporation of Gas Natural Inc., dated December 9, 2014. | |
| 3.2 | Amendment No. 1 to the Code of Regulations of Gas Natural Inc., dated August 4, 2014. Filed as, and incorporated herein by reference to, Exhibit 3.2 to the Registrant’s Form 8-K, as filed with the Securities and Exchange Commission on August 7, 2014 |
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| 10.1† | 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 | |
| 10.2 | 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 | |
| 10.3 | 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 | |
| 10.4 | 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 | |
| 10.5 | 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 | |
| 10.6 | 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 | |
| 10.7 | 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 | |
| 10.8 | 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 | |
| 10.9 | 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 | |
| 10.10 | 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 | |
| 10.11 | 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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| 10.12 | 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 | |
| 10.13 | 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 | |
| 10.14 | 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 | |
| 10.15 | 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 | |
| 10.16 | 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 | |
| 10.17 | 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 | |
| 10.18 | 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 | |
| 10.19 | 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 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on December 28, 2012 | |
| 10.20† | 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 | |
| 10.21† | 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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| 10.22 | 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 | |
| 10.23 | 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 | |
| 10.24 | 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 | |
| 10.25 | 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 | |
| 10.26 | 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 | |
| 10.27 | 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 | |
| 10.28 | 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 | |
| 10.29 | 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 | |
| 10.30 | 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 | |
| 10.31 | 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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| 10.32 | 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 | |
| 10.33 | 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 | |
| 10.34 | 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 | |
| 10.35 | 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 | |
| 10.36 | 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 | |
| 10.37 | 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 | |
| 10.38 | 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 | |
| 10.39 | 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 | |
| 10.40† | 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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| 10.41 | 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 | |
| 10.42 | 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 | |
| 10.43 | 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 | |
| 10.44 | 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 | |
| 10.45 | 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 | |
| 10.46 | 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 | |
| 10.47 | 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 | |
| 10.48 | 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 | |
| 10.49 | 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 | |
| 10.50 | 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 | |
| 10.51 | 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 | |
| 10.52 | 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 |
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| 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 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 | |
| 10.54 | 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 | |
| 10.55 | 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 | |
| 10.56 | 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 | |
| 10.57 | 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 | |
| 10.58 | Lease Agreement dated April 17, 2013, between Gas Natural Inc. and Varilease Finance, Inc.. 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 April 29, 2014 | |
| 10.59 | Schedule No. 01 to Lease Agreement dated April 17, 2013, between Gas Natural Inc. and Varilease Finance, 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 April 29, 2014 | |
| 10.60 | Amendment No. 1 to Schedule No. 01 to Lease Agreement dated April 23, 2014, between Gas Natural Inc. and Varilease Finance, Inc.. 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 April 29, 2014 | |
| 10.61† | Employment Agreement, dated July 21, 2014, between Gas Natural Inc. and Gregory J. Osborne. 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 July 24, 2014 | |
| 10.62† | Restricted stock award Agreement, dated July 21, 2014, between Gas Natural Inc. and Gregory J. Osborne. 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 July 24, 2014 | |
| 10.63† | Employment Agreement, dated July 27, 2014, between Gas Natural Inc. and Kevin J. Degenstein. 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 July 29, 2014 | |
| 10.64 | Stock Purchase Agreement, dated October 10, 2014, among Energy West, Incorporated, Energy West Wyoming, Incorporated and Cheyenne Light, Fuel and Power Company. 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 14, 2014 | |
| 10.65 | Asset Purchase Agreement, dated October 10, 2014, between Energy West Development, Inc. and Black Hills Exploration and Production Inc. 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 14, 2014 |
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| 10.66 | First Amendment to Amended and Restated Credit Agreement dated November 26, 2014, 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 December 3, 2014 | |
| 10.67 | Note Agreement, dated November 26, 2014, by and among Energy West, Incorporated and Bank of America, N.A. 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 December 3, 2014 | |
| 10.68† | Employment Agreement, dated December 29, 2014, between Gas Natural Inc. and Jed Henthorne. 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 January 2, 2015 | |
| 10.69† | Amendment to Employment Agreement, dated December 29, 2014, between Gas Natural Inc. and James E. Sprague. 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 January 2, 2015 | |
| 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 Baker Tilly Virchow Krause, LLP 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, Baker Tilly Virchow Krause, LLP | |
| 31* | Certifications pursuant to SEC Release No. 33-8238, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |
| 32* | Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |
| 101.INS* | XBRL Instance Document | |
| 101.SCH* | XBRL Taxonomy Extension Schema Document | |
| 101.CAL* | XBRL Taxonomy Extension Calculation Linkbase Document | |
| 101.DEF* | XBRL Taxonomy Extension Definition 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 | |
| * | Filed herewith |
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(c) Financial Statement Schedule
Schedule I - Condensed financial information of registrant
GAS NATURAL INC.
(PARENT COMPANY ONLY)
Condensed Financial Statements
| December 31, | ||||||||
| 2014 | 2013 | |||||||
| BALANCE SHEETS | ||||||||
| ASSETS | ||||||||
| Cash and cash equivalents | $ | 146,734 | $ | 8,376,229 | ||||
| Investments | 86,460,140 | 81,069,987 | ||||||
| Accounts receivable | 235,000 | 250,000 | ||||||
| Prepayments | - | 179,598 | ||||||
| Intercompany receivable, net | 6,173,128 | - | ||||||
| Discontinued operations | 8,348,892 | 8,034,705 | ||||||
| Property, plant, & equipment, net | 186,649 | 306,738 | ||||||
| Deferred tax asset, non-current | 1,155,949 | 435,983 | ||||||
| Other assets | 1,967 | 840 | ||||||
| Total assets | $ | 102,708,459 | $ | 98,654,080 | ||||
| LIABILITIES AND CAPITALIZATION | ||||||||
| Current liabilities | $ | 6,375,333 | $ | 694,217 | ||||
| Intercompany payable, net | - | 480,088 | ||||||
| Notes payable | 22,509 | - | ||||||
| Stockholders' equity | 96,310,617 | 97,479,775 | ||||||
| Total liabilities and capitalization | $ | 102,708,459 | $ | 98,654,080 | ||||
| 59 |
GAS NATURAL INC.
(PARENT COMPANY ONLY)
Condensed Financial Statements, continued
| Year Ended December 31, | ||||||||||||
| 2014 | 2013 | 2012 | ||||||||||
| STATEMENT OF COMPREHENSIVE INCOME | ||||||||||||
| Operating expenses | $ | 2,431,228 | $ | 946,222 | $ | 250,045 | ||||||
| Operating loss | (2,431,228 | ) | (946,222 | ) | (250,045 | ) | ||||||
| Other income (expense) | 179,569 | (523,990 | ) | (804,775 | ) | |||||||
| Interest expense | (13,232 | ) | - | - | ||||||||
| Income before income taxes and income from unconsolidated subsidiaries | (2,264,891 | ) | (1,470,212 | ) | (1,054,820 | ) | ||||||
| Income from unconsolidated subsidiaries | 4,198,743 | 6,919,118 | 3,853,577 | |||||||||
| Income tax benefit (expense) | 795,314 | 403,235 | 396,731 | |||||||||
| Income from continuing operations | 2,729,166 | 5,852,141 | 3,195,488 | |||||||||
| Discontinued operations | 1,032,611 | 819,138 | 523,829 | |||||||||
| Net income | $ | 3,761,777 | $ | 6,671,279 | $ | 3,719,317 | ||||||
| Other comprehensive income | ||||||||||||
| Unrealized gain (loss) on available for sale securities, net of tax of $7,689, $22,951 and $8,913, respectively | 14,811 | 39,120 | (14,616 | ) | ||||||||
| Unrealized gain on available for sale securities transferred to earnings, net of tax of $63,651 | (119,720 | ) | - | - | ||||||||
| Total other comprehensive income | (104,909 | ) | 39,120 | (14,616 | ) | |||||||
| Comprehensive income | $ | 3,656,868 | $ | 6,710,399 | $ | 3,704,701 | ||||||
| 60 |
GAS NATURAL INC.
(PARENT COMPANY ONLY)
Condensed Financial Statements, continued
| Year Ended December 31, | ||||||||||||
| STATEMENTS OF CASH FLOWS | 2014 | 2013 | 2012 | |||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||||||
| Net income | $ | 3,761,777 | $ | 6,671,279 | $ | 3,719,317 | ||||||
| Less income from discontinued operations | 1,032,611 | 819,138 | 523,829 | |||||||||
| Income from continuing operations | 2,729,166 | 5,852,141 | 3,195,488 | |||||||||
| Income from unconsolidated subsidiaries | (4,198,743 | ) | (6,919,118 | ) | (3,853,577 | ) | ||||||
| Depreciation expense | 19,246 | 12,670 | 3,931 | |||||||||
| Stock based compensation | 316,986 | 2,962 | 60,009 | |||||||||
| Deferred income taxes | (422,972 | ) | (158,629 | ) | (256,291 | ) | ||||||
| Other assets | 391,631 | (62,122 | ) | 7,245 | ||||||||
| Other liabilities | (496,704 | ) | 108,736 | 426,667 | ||||||||
| Net cash used in operating activities | (1,661,390 | ) | (1,163,360 | ) | (416,528 | ) | ||||||
| CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||
| Capital expenditures | (70,662 | ) | (75,309 | ) | (615,506 | ) | ||||||
| Investment in subsidiaries | (3,879,121 | ) | (6,584,908 | ) | (1,887,288 | ) | ||||||
| Dividends received from subsidiaries | 3,000,000 | 3,600,000 | 4,485,892 | |||||||||
| Net cash (used in) provided by investing activities | (949,783 | ) | (3,060,217 | ) | 1,983,098 | |||||||
| CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||
| Repayments of long-term debt | (3,033 | ) | - | - | ||||||||
| Debt issuance costs | (1,952 | ) | (840 | ) | - | |||||||
| Restricted cash - debt service | - | 750,939 | (750,939 | ) | ||||||||
| Exercise of stock options | 45,761 | 159,500 | - | |||||||||
| Proceeds from issuance of common stock | - | 16,721,104 | - | |||||||||
| Dividends paid | (5,659,098 | ) | (5,005,827 | ) | (4,432,919 | ) | ||||||
| Net cash (used in) provided by financing activities | (5,618,322 | ) | 12,624,876 | (5,183,858 | ) | |||||||
| DISCONTINUED OPERATIONS | ||||||||||||
| Operating cash flows | - | - | - | |||||||||
| Investing cash flows | - | (260,589 | ) | - | ||||||||
| Net cash provided by (used in) discontinued operations | - | (260,589 | ) | - | ||||||||
| Net increase (decrease) in cash and cash equivalents | (8,229,495 | ) | 8,140,710 | (3,617,288 | ) | |||||||
| Cash and cash equivalents, beginning of period | 8,376,229 | 235,519 | 3,852,807 | |||||||||
| Cash and cash equivalents, end of period | $ | 146,734 | $ | 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.
| 61 |
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, | ||||||||||||
| 2014 | 2013 | 2012 | ||||||||||
| Energy West, Inc. | $ | 3,000,000 | $ | 3,600,000 | $ | 4,350,000 | ||||||
| Great Plains Natural Gas Company | - | - | 98,759 | |||||||||
| Lightning Piepeline Company, Inc. | - | - | 37,133 | |||||||||
| Total | $ | 3,000,000 | $ | 3,600,000 | $ | 4,485,892 | ||||||
| 62 |
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/ Gregory J. Osborne | /s/ James E. Sprague | /s/ Jed Henthorne | ||
| Gregory J. Osborne | James E. Sprague | Jed Henthorne | ||
| Chief Executive Officer and Director | Chief Financial Officer | Corporate Controller | ||
| (principal executive officer) | (principal finance officer) | (principal accounting officer) | ||
| Date: March 12, 2015 | Date: March 12, 2015 | Date: March 12, 2015 |
KNOW ALL THESE PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints James E. Sprague, 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/ W.E. Argo | Chairman of the Board | March 12, 2015 | ||
| W.E. Argo | ||||
| /s/ Michael B. Bender | Director | March 12, 2015 | ||
| Michael B. Bender | ||||
| /s/ Wade F. Brooksby | Director | March 12, 2015 | ||
| Wade F. Brooksby | ||||
| /s/ Richard K. Greaves | Director | March 12, 2015 | ||
| Richard K. Greaves | ||||
| /s/ Michael T. Victor | Director | March 12, 2015 | ||
| Michael T. Victor | ||||
| /s/ Michael R. Winter | Director | March 12, 2015 | ||
| Michael R. Winter |
| 63 |
CONSOLIDATED FINANCIAL STATEMENTS OF
GAS NATURAL INC. AND SUBSIDIARIES
TABLE OF CONTENTS
| F-1 |
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders
Gas Natural Inc.
We have audited the accompanying consolidated balance sheets of Gas Natural Inc. and subsidiaries (the “Company”) as of December 31, 2014 and 2013, and the related consolidated statements of comprehensive income, changes in stockholders’ equity, and cash flows for the years 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 years ended December 31, 2014 and 2013. We also have audited the Company’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these consolidated financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule and an opinion on the Company’s internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Gas Natural Inc. and its subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for the years 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 years ended December 31, 2014 and 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. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control — Integrated Framework 2013 issued by the Committee of Sponsoring Organizations of the Treadway Commission.
| F-2 |
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 12, 2015
| F-3 |
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 statements of comprehensive income, changes in stockholders’ equity, and cash flows of Gas Natural Inc. (the “Company”) for the year ended December 31, 2012 (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 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 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 results of Gas Natural Inc.’s 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 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/ Baker Tilly Virchow Krause, LLP
Pittsburgh, Pennsylvania
April 1, 2013
| F-4 |
Gas Natural Inc. and Subsidiaries
Consolidated Balance Sheets
| December 31, | ||||||||
| 2014 | 2013 | |||||||
| ASSETS | ||||||||
| CURRENT ASSETS | ||||||||
| Cash and cash equivalents | $ | 1,585,926 | $ | 12,741,197 | ||||
| Marketable securities | - | 406,134 | ||||||
| Accounts receivable | ||||||||
| Trade, less allowance for doubtful accounts of $370,909 and $1,978,358, respectively | 12,111,026 | 12,305,657 | ||||||
| Related parties | 234,610 | 146,225 | ||||||
| Unbilled gas | 7,630,852 | 7,172,062 | ||||||
| Note receivable, current portion | 2,070 | 1,938 | ||||||
| Inventory | ||||||||
| Natural gas | 5,301,895 | 4,996,065 | ||||||
| Materials and supplies | 2,300,990 | 2,285,722 | ||||||
| Prepaid income taxes | 431,681 | 727,427 | ||||||
| Prepayments and other | 986,941 | 970,574 | ||||||
| Regulatory assets, current | 4,097,822 | 1,209,982 | ||||||
| Deferred tax asset | 635,195 | 1,225,032 | ||||||
| Assets held for sale | 802,436 | - | ||||||
| Discontinued operations | 11,653,934 | 12,032,203 | ||||||
| Total current assets | 47,775,378 | 56,220,218 | ||||||
| PROPERTY, PLANT, & EQUIPMENT, NET | 142,011,085 | 124,587,645 | ||||||
| OTHER ASSETS | ||||||||
| Notes receivable, less current portion | 90,345 | 93,727 | ||||||
| Regulatory assets, non-current | 2,055,404 | 452,047 | ||||||
| Debt issuance costs, net of amortization | 1,079,447 | 1,388,124 | ||||||
| Goodwill | 16,155,672 | 16,267,377 | ||||||
| Customer relationships, net of amortization | 2,927,500 | 3,230,333 | ||||||
| Investment in unconsolidated affiliate | - | 351,724 | ||||||
| Restricted cash | 1,897,677 | 1,137,442 | ||||||
| Other assets | 11,404 | 3,160 | ||||||
| Total other assets | 24,217,449 | 22,923,934 | ||||||
| TOTAL ASSETS | $ | 214,003,912 | $ | 203,731,797 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
| F-5 |
Gas Natural Inc. and Subsidiaries
Consolidated Balance Sheets
| December 31, | ||||||||
| 2014 | 2013 | |||||||
| LIABILITIES AND CAPITALIZATION | ||||||||
| CURRENT LIABILITIES | ||||||||
| Checks in excess of amounts on deposit | $ | 194,524 | $ | 842,443 | ||||
| Line of credit | 28,760,799 | 24,529,799 | ||||||
| Accounts payable | ||||||||
| Trade | 14,115,367 | 12,355,605 | ||||||
| Related parties | 170,319 | 559,933 | ||||||
| Notes payable, current portion | 542,201 | 3,502,190 | ||||||
| Contingent consideration, current | 671,638 | 671,638 | ||||||
| Derivative instruments | 3,023,271 | - | ||||||
| Accrued liabilities | 4,860,663 | 5,751,594 | ||||||
| Accrued liabilities - related parties | 111,133 | - | ||||||
| Customer deposits, current | 634,090 | 667,479 | ||||||
| Obligation under capital lease, current | 188,224 | 177,570 | ||||||
| Regulatory liability, current | 925,175 | 793,184 | ||||||
| Build-to-suit liability | 5,597,287 | - | ||||||
| Other current liabilities | 940,643 | 1,464,646 | ||||||
| Liabilities held for sale | 61,416 | - | ||||||
| Discontinued operations | 544,432 | 574,889 | ||||||
| Total current liabilities | 61,341,182 | 51,890,970 | ||||||
| LONG-TERM LIABILITIES | ||||||||
| Deferred investment tax credits | 113,193 | 134,255 | ||||||
| Deferred tax liability | 10,538,394 | 9,055,166 | ||||||
| Asset retirement obligation | 1,196,518 | 1,145,052 | ||||||
| Customer advances for construction | 993,681 | 987,265 | ||||||
| Regulatory liability, non-current | 1,089,850 | 964,462 | ||||||
| Customer deposits | 949,540 | - | ||||||
| Obligation under capital lease, less current | 1,674,714 | 1,862,938 | ||||||
| Contingent consideration, less current | 75,362 | 13,362 | ||||||
| Total long-term liabilities | 16,631,252 | 14,162,500 | ||||||
| NOTES PAYABLE, less current portion | 39,720,860 | 40,198,552 | ||||||
| COMMITMENTS AND CONTINGENCIES (see Note 24) | - | |||||||
| STOCKHOLDERS’ EQUITY | ||||||||
| Preferred stock; $0.15 par value; 1,500,000 shares authorized, no shares issued or outstanding | - | - | ||||||
| Common stock; $0.15 par value; | ||||||||
| Authorized: 30,000,000 and 15,000,000 shares, respectively; | ||||||||
| Issued: 10,487,511 and 10,451,678 shares, respectively; | ||||||||
| Outstanding: 10,487,511 and 10,451,678 shares, respectively | 1,573,127 | 1,567,752 | ||||||
| Capital in excess of par value | 63,826,341 | 63,468,969 | ||||||
| Accumulated other comprehensive income | - | 104,909 | ||||||
| Retained earnings | 30,911,150 | 32,338,145 | ||||||
| Total stockholders’ equity | 96,310,618 | 97,479,775 | ||||||
| TOTAL CAPITALIZATION | 136,031,478 | 137,678,327 | ||||||
| TOTAL LIABILITIES AND CAPITALIZATION | $ | 214,003,912 | $ | 203,731,797 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
| F-6 |
Gas Natural Inc. and Subsidiaries
Consolidated Statements of Comprehensive Income
| Year Ended December 31, | ||||||||||||
| 2014 | 2013 | 2012 | ||||||||||
| REVENUES | ||||||||||||
| Natural gas operations | $ | 123,052,554 | $ | 97,233,112 | $ | 73,900,481 | ||||||
| Marketing and production | 9,517,287 | 12,167,241 | 7,493,361 | |||||||||
| Total revenues | 132,569,841 | 109,400,353 | 81,393,842 | |||||||||
| COST OF SALES | ||||||||||||
| Natural gas purchased | 79,096,553 | 55,977,154 | 38,552,607 | |||||||||
| Marketing and production | 8,620,826 | 10,052,865 | 5,953,156 | |||||||||
| Total cost of sales | 87,717,379 | 66,030,019 | 44,505,763 | |||||||||
| GROSS MARGIN | 44,852,462 | 43,370,334 | 36,888,079 | |||||||||
| OPERATING EXPENSES | ||||||||||||
| Distribution, general, and administrative | 24,769,623 | 21,308,592 | 18,512,126 | |||||||||
| Maintenance | 1,225,491 | 1,142,261 | 995,072 | |||||||||
| Depreciation and amortization | 6,604,569 | 5,550,753 | 4,337,196 | |||||||||
| Accretion | 51,466 | 57,912 | 161,298 | |||||||||
| Taxes other than income | 3,928,018 | 3,671,930 | 3,188,071 | |||||||||
| Provision for doubtful accounts | 1,112,115 | 726,434 | 951,655 | |||||||||
| Contingent consideration loss (gain) | 62,000 | (1,565,000 | ) | - | ||||||||
| Goodwill impairment | - | 725,744 | - | |||||||||
| Total operating expenses | 37,753,282 | 31,618,626 | 28,145,418 | |||||||||
| OPERATING INCOME | 7,099,180 | 11,751,708 | 8,742,661 | |||||||||
| Loss from unconsolidated affiliate | (351,724 | ) | (5,007 | ) | (8,620 | ) | ||||||
| Gain on sale of marketable securities | 183,371 | - | - | |||||||||
| Acquisition expense | (7,197 | ) | (272,094 | ) | (959,267 | ) | ||||||
| Stock sale expense | - | (309,432 | ) | (274,213 | ) | |||||||
| Other income, net | 579,214 | 886,832 | 351,446 | |||||||||
| Interest expense | (3,226,096 | ) | (3,176,155 | ) | (2,699,720 | ) | ||||||
| Income before income taxes | 4,276,748 | 8,875,852 | 5,152,287 | |||||||||
| Income tax expense | (1,547,582 | ) | (3,023,711 | ) | (1,956,799 | ) | ||||||
| INCOME FROM CONTINUING OPERATIONS | 2,729,166 | 5,852,141 | 3,195,488 | |||||||||
| Discontinued operations, net of income taxes (See Note 4) | 1,032,611 | 819,138 | 523,829 | |||||||||
| NET INCOME | $ | 3,761,777 | $ | 6,671,279 | $ | 3,719,317 | ||||||
| BASIC & DILUTED EARNINGS (LOSS) PER SHARE: | ||||||||||||
| Continuing operations | $ | 0.26 | $ | 0.63 | $ | 0.39 | ||||||
| Discontinued operations | 0.10 | 0.08 | 0.07 | |||||||||
| Net income per share | $ | 0.36 | $ | 0.71 | $ | 0.46 | ||||||
| Weighted average dividends declared per common share | $ | 0.50 | $ | 0.55 | $ | 0.54 | ||||||
| COMPREHENSIVE INCOME: | ||||||||||||
| Net income | $ | 3,761,777 | $ | 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 $7,689, $22,951 and $8,913, respectively | 14,811 | 39,120 | (14,616 | ) | ||||||||
| Accumulated unrealized gain on available for sale securities transferred to earnings, net of tax of $63,651 | (119,720 | ) | - | - | ||||||||
| Other comprehensive income (loss), net of tax | (104,909 | ) | 39,120 | (14,616 | ) | |||||||
| COMPREHENSIVE INCOME | $ | 3,656,868 | $ | 6,710,399 | $ | 3,704,701 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
| F-7 |
Gas Natural Inc. and Subsidiaries
Consolidated Statements of Changes in Stockholders' Equity
| Accumulated | ||||||||||||||||||||||||
| Capital In | Other | |||||||||||||||||||||||
| Common | Common | Excess Of | Comprehensive | Retained | ||||||||||||||||||||
| Shares | Stock | Par Value | Income | 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 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 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 | ||||||||||||||||||
| Net income | - | - | - | - | 3,761,777 | 3,761,777 | ||||||||||||||||||
| Other comprehensive loss, net | - | - | - | (104,909 | ) | - | (104,909 | ) | ||||||||||||||||
| Exercise of stock options | 5,000 | 750 | 45,012 | - | - | 45,762 | ||||||||||||||||||
| Stock compensation | 30,833 | 4,625 | 312,360 | - | - | 316,985 | ||||||||||||||||||
| Dividends declared | - | - | - | - | (5,188,772 | ) | (5,188,772 | ) | ||||||||||||||||
| BALANCE AT DECEMBER 31, 2014 | 10,487,511 | $ | 1,573,127 | $ | 63,826,341 | $ | - | $ | 30,911,150 | $ | 96,310,618 | |||||||||||||
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, | ||||||||||||
| 2014 | 2013 | 2012 | ||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||||||
| Net income | $ | 3,761,777 | $ | 6,671,279 | $ | 3,719,317 | ||||||
| Less income from discontinued operations | 1,032,611 | 819,138 | 523,829 | |||||||||
| Income from continuing operations | 2,729,166 | 5,852,141 | 3,195,488 | |||||||||
| Adjustments to reconcile income from continuing operations to net cash provided by operating activities: | ||||||||||||
| Depreciation and amortization | 6,604,569 | 5,550,753 | 4,337,196 | |||||||||
| Accretion | 51,466 | 57,912 | 161,298 | |||||||||
| Amortization of debt issuance costs | 419,953 | 418,204 | 275,858 | |||||||||
| Provision for doubtful accounts | 1,112,115 | 726,434 | 951,655 | |||||||||
| Stock based compensation | 316,985 | 2,962 | 60,009 | |||||||||
| Gain on sale of marketable securities | (183,371 | ) | - | - | ||||||||
| Loss (gain) on sale of assets | (28,293 | ) | (158,320 | ) | 61,495 | |||||||
| Loss from unconsolidated affiliate | 351,724 | 5,007 | 8,620 | |||||||||
| Unrealized holding loss (gain) on contingent consideration | 62,000 | (1,565,000 | ) | - | ||||||||
| Change in fair value of derivative financial instruments | 150,885 | - | - | |||||||||
| Investment tax credit | (21,062 | ) | (21,062 | ) | (21,062 | ) | ||||||
| Deferred income taxes | 2,135,786 | 4,024,683 | 2,261,345 | |||||||||
| Goodwill impairment | - | 725,744 | - | |||||||||
| Changes in assets and liabilities | ||||||||||||
| Accounts receivable, including related parties | (891,338 | ) | (2,187,452 | ) | (3,667,888 | ) | ||||||
| Unbilled gas | (480,942 | ) | (3,009,029 | ) | (569,950 | ) | ||||||
| Natural gas inventory | (457,611 | ) | (388,858 | ) | 1,700,367 | |||||||
| Accounts payable, including related parties | 1,817,098 | 3,111,116 | 907,843 | |||||||||
| Regulatory assets & liabilities | (1,938,386 | ) | 1,039,063 | (258,212 | ) | |||||||
| Prepayments and other | (24,243 | ) | 1,076,550 | (1,372,244 | ) | |||||||
| Other assets | 234,751 | (464,339 | ) | 1,006,239 | ||||||||
| Other liabilities | (815,380 | ) | 642,788 | (1,435,500 | ) | |||||||
| Net cash provided by operating activities of continuing operations | 11,145,872 | 15,439,297 | 7,602,557 | |||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||
| Capital expenditures | (21,612,680 | ) | (23,516,923 | ) | (19,935,982 | ) | ||||||
| Proceeds from sale of fixed assets | 172,142 | 968,772 | 39,485 | |||||||||
| Proceeds from sale of marketable securities | 421,875 | - | - | |||||||||
| Proceeds from note receivable | 3,250 | 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 | 57,441 | 1,264,624 | (1,322,065 | ) | ||||||||
| Customer advances for construction | 16,900 | 12,028 | 150,920 | |||||||||
| Contributions in aid of construction | 2,262,047 | 1,105,974 | 54,532 | |||||||||
| Net cash used in investing activities of continuing operations | (18,679,025 | ) | (20,191,844 | ) | (22,553,830 | ) | ||||||
| CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||
| Proceeds from lines of credit | 24,850,000 | 22,519,000 | 51,390,754 | |||||||||
| Repayments of lines of credit | (20,619,000 | ) | (21,848,956 | ) | (50,690,999 | ) | ||||||
| Proceeds from notes payable | 102,000 | - | 12,989,552 | |||||||||
| Repayments of notes payable | (3,565,224 | ) | (633,498 | ) | (7,920 | ) | ||||||
| Payments of capital lease obligations | (177,570 | ) | (167,518 | ) | - | |||||||
| Debt issuance costs | (111,275 | ) | (7,607 | ) | (1,204,987 | ) | ||||||
| Proceeds from issuance of common shares | - | 16,721,104 | - | |||||||||
| Exercise of stock options | 45,762 | 159,500 | - | |||||||||
| Restricted cash – debt service fund | 131,864 | 748,781 | (878,875 | ) | ||||||||
| Dividends paid | (5,659,098 | ) | (5,005,827 | ) | (4,432,920 | ) | ||||||
| Net cash provided by (used in) financing activities of continuing operations | (5,002,541 | ) | 12,484,979 | 7,164,605 | ||||||||
| DISCONTINUED OPERATIONS | ||||||||||||
| Operating cash flows | 1,924,330 | 658,105 | 883,724 | |||||||||
| Investing cash flows | (511,434 | ) | 1,738,076 | (698,503 | ) | |||||||
| Financing cash flows | (32,473 | ) | (590,059 | ) | 401,000 | |||||||
| Net cash provided by discontinued operations | 1,380,423 | 1,806,122 | 586,221 | |||||||||
| NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | (11,155,271 | ) | 9,538,554 | (7,200,447 | ) | |||||||
| Cash and cash equivalents, beginning of period | 12,741,197 | 3,202,643 | 10,403,090 | |||||||||
| CASH AND CASH EQUIVALENTS, END OF PERIOD | $ | 1,585,926 | $ | 12,741,197 | $ | 3,202,643 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
| F-9 |
Gas Natural Inc. and Subsidiaries
Consolidated Statements of Cash Flows
| Year Ended December 31, | ||||||||||||
| 2014 | 2013 | 2012 | ||||||||||
| SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION | ||||||||||||
| Cash paid for interest | $ | 2,730,385 | $ | 2,806,051 | $ | 2,286,902 | ||||||
| Cash refunded for income taxes, net | (233,740 | ) | (4,050 | ) | (989,503 | ) | ||||||
| NONCASH INVESTING AND FINANCING ACTIVITIES | ||||||||||||
| Assets acquired under build-to-suit agreement | $ | 5,597,314 | $ | - | $ | - | ||||||
| Capital expenditures included in accounts payable | 1,047,211 | 1,798,014 | 745,402 | |||||||||
| Restricted cash received from customer as security deposit | 949,540 | - | - | |||||||||
| Capital assets exchanged to settle payables | 321,971 | 82,584 | - | |||||||||
| Capital assets acquired through trade-in | 103,154 | 23,500 | - | |||||||||
| Capital additions acquired through debt | 25,543 | |||||||||||
| Capitalized interest | 24,965 | 6,003 | 21,147 | |||||||||
| Customer advances for construction moved to contribution in aid of construction | 10,483 | 16,364 | - | |||||||||
| Customer relationships acquired from JDOG Marketing purchase | - | 2,800,000 | - | |||||||||
| Shares issued to purchase JDOG Marketing | - | 2,641,199 | - | |||||||||
| Contingent consideration issued to purchase JDOG Marketing | - | 2,250,000 | - | |||||||||
| Goodwill acquired from JDOG Marketing purchase | - | 2,101,744 | - | |||||||||
| Accrued dividends | - | 470,326 | 376,639 | |||||||||
| Note receivable effectively settled in JDOG Marketing acquisition | - | 32,145 | - | |||||||||
| Plant, property and equipment acquired from JDOG Marketing purchase | - | 21,600 | - | |||||||||
| Shares issued to purchase Loring Pipeline | - | - | 2,250,004 | |||||||||
The accompanying notes are an integral part of these consolidated financial statements.
| F-10 |
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO THE 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, Lone Wolfe, 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, and North Carolina as well as non-regulated operations in Maine and Montana. GNR is a natural gas marketing company that markets gas in Ohio and Pennsylvania. 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, 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. 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 three reporting segments:
| · | Natural Gas Operations | Annually distributes approximately 26 Bcf of natural gas to approximately 68,000 residential, commercial, and industrial customers through regulated utilities operating in Kentucky, Maine, Montana, North Carolina, Ohio, and Pennsylvania. Approximately 93%, 89%, and 91% of the Company’s revenue was derived from its regulated natural gas operations for the years ended December 31, 2014, 2013, and 2012, respectively. |
| · | Marketing & Production | Annually markets approximately 1.3 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 55% gross working interest (average 46% net revenue interest) in 160 natural gas producing wells and gas gathering assets located in Glacier and Toole Counties in Montana. |
| · | Corporate & Other | Encompasses costs associated with business development and acquisitions, dispositions of subsidiary entities and 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. |
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.
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 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 the FASB Accounting Standards Codification, sometimes referred to as the Codification or ASC.
| F-11 |
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 retirement obligations, contingent consideration liability, loss contingencies, 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.
| F-12 |
For build-to-suit leases, the Company evaluates its level of risk during the asset’s construction or development period. If the Company determines that it bears substantially all of the risk during this period, it establishes an asset and liability for the total project costs with the liability reduced by any project costs paid directly by the Company. Once the build-to-suit asset is complete, the Company assesses whether the arrangement qualifies for sales recognition under the sale-leaseback accounting guidance. If the lease meets the criteria to qualify as a sales-lease back transaction, then the asset and liability are removed from the Company’s consolidated balance sheet. If it does not meet the criteria to qualify as a sale-leaseback transaction, then the asset and liability remain on the Company's consolidated balance sheet and the transaction is treated as a financing.
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 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, 2014, 2013 and 2012.
The Company recognizes interest and penalties related to unrecognized tax benefits in operating expense. As of December 31, 2014 and 2013, there were no unrecognized tax benefits nor interest or penalties accrued related to unrecognized tax benefits. For the years ended December 31, 2014, 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 2010 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.
| F-13 |
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.
Receivables
Accounts receivable are generated from sales and delivery of natural gas as measured by inputs from meter reading devices. Trade accounts receivable are carried at the expected net realizable value. There is 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.
At December 31, 2013, included in the accounts receivable, trade line item on the accompanying Consolidated Balance Sheet was $1,059,224, net of allowance for doubtful accounts of $1,421,000, due from a large industrial customer in bankruptcy proceedings. The Company believed that it had an administrative claim for the unreserved portion and that it was likely to collect the amount. In June 2014, the bankruptcy court denied the Company’s administrative claim on the customer. The Company’s claim is now considered that of an unsecured creditor and as such the Company believes that it is unlikely that it will collect any of the previously unreserved amounts. As a result, the Company has written-off the remaining balance of the receivable. This receivable was related to the Company’s Marketing & Production operating segment. The impact of the amount written-off is reflected in the Provision for doubtful accounts line of the Company’s Consolidated Statement of Comprehensive Income. Total write-offs of receivables for the years ended December 31, 2014, 2013, and 2012 were $2,717,844, $161,674, and $213,855, respectively.
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.
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. 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.
| F-14 |
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.
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 $557,500 and $254,667 at December 31, 2014 and 2013, respectively. Amortization expense for customer relationships for the years ended December 31, 2014, 2013, and 2012 was $302,833, $186,167 and $22,833. The following table shows the Company’s estimated amortization related to its intangible assets over the next five years.
| Estimated intangible asset amortization expense for the years ended December 31, | ||||
| 2015 | $ | 302,833 | ||
| 2016 | 302,833 | |||
| 2017 | 302,833 | |||
| 2018 | 302,833 | |||
| 2019 | 302,833 | |||
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
For equity investments in which the Company does not control the investee, but can exert significant influence over the financial and operating policies of the investees, the Company uses the equity method of accounting. Under this accounting treatment, the Company’s share of the investee’s underlying net income or loss is recorded as non-operating income on the Company’s Consolidated Statement of Comprehensive Income with a corresponding increase or decrease in the investment account. Distributions received from the investment reduce the Company’s investment balance.
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 be recognized is measured as the amount by which the carrying value of the assets exceeds their fair value. As of December 31, 2014 and 2013, 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 in the accompanying Consolidated Balance Sheets. The Company amortizes this amount added to property, plant, and equipment. The accretion of the asset retirement liability is allocated to operating expense using a systematic and rational method.
| F-15 |
Derivatives and Hedging Activities
ASC 815 - Derivatives and Hedging requires companies to recognize all of its derivative instruments as either assets or liabilities in the statement of financial position at fair value. The accounting for changes in the fair value of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and further, on the type of hedging relationship. For those derivative instruments that are designated and qualify as hedging instruments, a company must designate the hedging instrument, based upon the exposure being hedged, as a fair value hedge, cash flow hedge, or a hedge of a net investment in a foreign operation. For derivative instruments not designated as hedging instruments, the gain or loss is recognized in the statement of financial performance during the current period.
The Company is exposed to certain risks relating to its ongoing business operations. The primary risk managed by using derivative instruments is commodity price risk related to natural gas. Forward contracts and commodity price swaps with fixed pricing are entered into by the Company to protect profit margins on future obligations to deliver gas at fixed prices or to protect its regulated utility customers from possible adverse price fluctuations in the market. These forward contracts usually qualify as a “normal purchase” or “normal sale” and are exempt from derivative accounting treatment. The Company’s commodity price swaps do not meet any of the exemption criteria under ASC 815 and are accounted for as derivatives. At December 31, 2014, none of the Company’s derivatives were accounted for as hedging instruments.
Recent Accounting Pronouncements
In May 2014, the FASB issued ASU 2014-09 Revenue from Contracts with Customers, which supersedes nearly all existing revenue recognition guidance under U.S. GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing U.S. GAAP. This pronouncement is effective for annual reporting periods beginning after December 15, 2016 and is to be applied using one of two retrospective application methods, with early application not permitted. The Company is currently evaluating the impact of the pending adoption of ASU 2014-09 on the consolidated financial statements.
In April 2014, the FASB issued ASU 2014-08 Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity, which amends the prior guidance of the reclassification of components of an entity to discontinued operations under U.S. GAAP. Under the amended guidance, a disposal of a component of an entity or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has or will have a major effect on an entity’s operations and financial results. The amendment also removes requirements relating to the cessation of operations, cash flows and significant continuing involvement with the discontinued component. This pronouncement is effective for annual and interim periods beginning after December 15, 2014 with early adoption permitted. This update is to be applied prospectively on components classified as held for sale after the adoption date. The Company has chosen to early adopt ASU 2014-08 effective September 30, 2014.
Note 3 – Acquisitions
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, father of the Company’s chief executive officer and the Company’s former 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 allowed 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. 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.
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.
| F-16 |
In addition, the purchase agreement provides for contingent “earn-out” payments for a period of five years after the closing of the transaction if GNR 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 GNR’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 GNR’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. The Company’s estimate of the total liability at December 31, 2014 was $747,000. See Note 8 – Fair Value Measurements for details regarding this valuation. The Company calculated first and second year earn-out payments of $671,638 and $0, respectively, as its best estimate for financial reporting purposes. This amount is included in the Contingent consideration, current portion line of the Company’s Consolidated Balance Sheets. The Company does not believe a first year earn-out payment is due to JDOG Marketing as a result of payments made by the Ohio utilities to JDOG Marketing during 2013 that were disallowed by the PUCO. Mr. Osborne believes that JDOG Marketing is entitled to the first year earn-out. Mr. Osborne and JDOG Marketing have filed a suit against the Company for the earn-out payment. See Note 24 – Commitments and Contingencies for more information.
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 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. This amount was approximately $21,600. 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 fair value of these contracts was $2.8 million. 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, $2.1 million was allocated to goodwill. The Company expects none of the goodwill to be deductible for tax purposes.
The results of GNR are included in the Company’s Marketing and Production Operations reporting segment. GNR contributed $4.3 million and $1.9 million to the Company’s revenues for the years ended December 31, 2014 and 2013, respectively, and a loss of $99,000 and income of $765,000 to the Company’s net income, respectively.
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 and an operating lease agreement. Both of the note receivable and the lease agreement were effectively settled with the completion of the transaction. See Note 21 – Related Party Transactions for more information regarding the Company’s transactions with JDOG Marketing prior to the acquisition.
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, father of the Company’s chief executive officer and the Company’s former 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 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 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.
| F-17 |
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 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 acquisition provided the Company with 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.
| F-18 |
Note 4 – Discontinued Operations
The following table reconciles the carrying amounts of the major classes of assets and liabilities to the Company’s discontinued operations as presented on its Consolidated Balance Sheet.
| December 31, | ||||||||
| 2014 | 2013 | |||||||
| Current Assets: | ||||||||
| Cash and cash equivalents | $ | 257,358 | $ | 406,184 | ||||
| Accounts receivable, net | 1,002,918 | 971,308 | ||||||
| Unbilled gas | 735,122 | 557,498 | ||||||
| Inventory | 181,197 | 748,482 | ||||||
| Prepayments and other | 71,101 | 99,219 | ||||||
| Regulatory assets, current | 250,031 | 88,318 | ||||||
| Total current assets | 2,497,727 | 2,871,009 | ||||||
| Non-Current Assets: | ||||||||
| Property, plant & equipment, net | 8,966,965 | 8,960,986 | ||||||
| Regulatory assets, non-current | 155,826 | 155,826 | ||||||
| Other assets | 33,416 | 44,382 | ||||||
| Total non-current assets | 9,156,207 | 9,161,194 | ||||||
| Total discontinued assets | $ | 11,653,934 | $ | 12,032,203 | ||||
| Current Liabilities: | ||||||||
| Checks in excess of amounts on deposit | $ | - | $ | 1,192 | ||||
| Accounts payable | 29,657 | 62,131 | ||||||
| Accrued liabilities | 334,664 | 429,961 | ||||||
| Other current liabilities | 139,318 | 52,200 | ||||||
| Total current liabilities | 503,639 | 545,484 | ||||||
| Non-Current Liabilities: | ||||||||
| Customer advances for construction | 40,793 | 29,405 | ||||||
| Total discontinued liabilities | $ | 544,432 | $ | 574,889 | ||||
| F-19 |
The following table reconciles the carrying amounts of the major line items constituting the pretax profit of discontinued operations to the after-tax profit or loss of discontinued operations that are presented on the Consolidated Statement of Comprehensive Income.
| Year Ended December 31, | ||||||||||||
| 2014 | 2013 | 2012 | ||||||||||
| Revenues | $ | 10,927,150 | $ | 13,130,554 | $ | 12,422,318 | ||||||
| Cost of sales | (6,696,602 | ) | (7,855,827 | ) | (7,279,787 | ) | ||||||
| Distribution, general & administrative | (1,559,021 | ) | (2,643,821 | ) | (2,666,911 | ) | ||||||
| Maintenance | (175,509 | ) | (239,321 | ) | (263,559 | ) | ||||||
| Depreciation & amortization | (541,777 | ) | (925,389 | ) | (989,535 | ) | ||||||
| Taxes other than income | (326,214 | ) | (395,145 | ) | (363,802 | ) | ||||||
| Other income (expense) | 23,597 | 5,098 | 89,048 | |||||||||
| Interest expense | (1,603 | ) | (25,268 | ) | (23,615 | ) | ||||||
| Pretax income from discontinued operations | 1,650,021 | 1,050,881 | 924,157 | |||||||||
| Loss on sale of discountinued operations | - | (7,915 | ) | - | ||||||||
| Total pretax income from discontinued operations | 1,650,021 | 1,042,966 | 924,157 | |||||||||
| Income tax expense | (617,410 | ) | (223,828 | ) | (400,328 | ) | ||||||
| Income from discontinued operations | $ | 1,032,611 | $ | 819,138 | $ | 523,829 | ||||||
Energy West Wyoming and the Glacier & Shoshone Pipelines
On October 10, 2014, the Company executed a stock purchase agreement for the sale of all of the stock of its wholly-owned subsidiary, Energy West Wyoming, Inc. (“EWW”), to Cheyenne Light, Fuel and Power Company (“Cheyenne”). EWW has historically been included in the Company’s Natural Gas Operations segment. In conjunction with this sale, the Company’s Energy West Development, Inc. subsidiary, entered into an asset purchase agreement for the sale of the of the transmission pipeline system known as the Shoshone Pipeline and the gathering pipeline system known as the Glacier Pipeline and certain other assets directly used in the operation of the pipelines (together the “Pipeline Assets”) to Black Hills Exploration and Production, Inc. (“Black Hills”), an affiliate of Cheyenne. The Pipeline Assets have historically comprised the entirety of the Company’s Pipeline segment. As a result of EWW and the Pipeline Asset’s classification as discontinued operations, their results have been included in Corporate & Other segment for all periods presented. The Company will receive approximately $15.8 million for the sale of EWW and approximately $1.2 million for the sale of the Pipeline Assets. These amounts are subject to adjustments based upon the working capital on the closing of the transaction and any amendments to the disclosure schedules to the agreement that result in losses to EWW or the Pipeline Assets. The agreements contain customary representations, warranties, covenants and indemnification provisions. The consummation of the transactions depend upon the satisfaction or waiver of a number of customary closing conditions, the receipt of regulatory approvals and the consent of certain of the Company’s lenders. In addition, Cheyenne and Black Hills have the right to terminate the agreements in the event that the amendments to the disclosure schedules to the purchase agreements are reasonably likely to result in losses to EWW and the Pipeline Assets, collectively, in excess of $750,000. The Company expects to close the transactions sometime in the second or third quarter of 2015.
Upon completion of the transactions, the Company’s subsidiary, EWR, will continue to conduct some business with both EWW and Black Hills relating to the Pipeline Assets. EWW will continue to purchase natural gas from EWR under an established gas purchase agreement through the first quarter of 2017. Concurrently, EWR will continue to use EWW’s transmission system under a standing transportation agreement through the first quarter of 2017. Finally, EWR will continue to use the Pipeline Assets’ transmission systems under a standing transportation agreement through October 2017. These transactions are a continuation of transactions that were conducted prior to the sales EWW and the Pipeline Assets and have been eliminated through the consolidation process.
Independence
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. The Company recorded a loss on sale of $7,915 in the fourth quarter of 2013. 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 segment. As a result of its classification as discontinued operations, its results have been included in Corporate & Other segment for all periods presented. The Company has no material continuing cash flows or other contractual obligations associated with this sales transaction.
| F-20 |
Note 5 – Assets and Liabilities Held for Sale
At December 31, 2014, the Company was involved in final negotiations for the sale of its Pennsylvania utilities, Clarion and Walker, to Utility Pipeline, LTD. Clarion and Walker have historically been reported as a component of the Company’s Natural Gas Operations segment and have, collectively, contributed $212,774, $46,092, and $56,388 to the Company’s pre-tax income from continuing operations for the years ended December 31, 2014, 2013, and 2012, respectively. The Company does not believe that the sale of Clarion and Walker constitutes a strategic shift that will have a major effect on its operations or financial results and as such, neither of the subsidiaries have classified as discontinued operations in the Company’s financial statements, but instead have been classified as assets and liabilities held for sale at December 31, 2014. See Note 25 – Subsequent Events for more information regarding this transaction.
The following table summarizes the major classes of asset and liabilities classified as held for sale at December 31, 2014.
| December 31, | ||||
| 2014 | ||||
| Current Assets: | ||||
| Accounts receivable, net | 49,069 | |||
| Unbilled gas | 22,151 | |||
| Inventory | 3,622 | |||
| Prepayments and other | 5,401 | |||
| Regulatory assets, current | 203,241 | |||
| Total current assets | 283,484 | |||
| Non-Current Assets: | ||||
| Property, plant & equipment, net | 407,247 | |||
| Goodwill | 111,705 | |||
| Total non-current assets | 518,952 | |||
| Total assets held for sale | $ | 802,436 | ||
| Current Liabilities: | ||||
| Accounts payable | 36,184 | |||
| Accrued liabilities | 21,632 | |||
| Other current liabilities | 3,600 | |||
| Total liabilities held for sale | $ | 61,416 | ||
Note 6 - 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. See Note 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 purchasing 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 an Opinion and Order related to the 2012 NEO and Orwell 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 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 GNR 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 led to the 2013 goodwill impairment charge included in the Company’s Marketing & Production segment. This impairment charge was calculated using both a Discounted Cash Flow method and a Guideline Public Company method.
| F-21 |
The schedule below describes the changes in carrying amount of goodwill for the years ended December 31, 2014 and 2013:
| Marketing & | ||||||||||||
| Natural Gas | Production | Total | ||||||||||
| Balance as of December 31, 2012 | $ | 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 | ||||||
| Classified as asset held for sale | (111,705 | ) | - | (111,705 | ) | |||||||
| Balance as of December 31, 2014 | $ | 14,779,672 | $ | 1,376,000 | $ | 16,155,672 | ||||||
The following table shows the Company’s gross goodwill balance and accumulated impairment loss as of the balance sheet dates.
| December 31, | ||||||||
| 2014 | 2013 | |||||||
| Goodwill, gross | ||||||||
| Natural Gas | $ | 14,779,672 | $ | 14,891,377 | ||||
| Marketing & Production | 2,101,744 | 2,101,744 | ||||||
| Total goodwill, gross | 16,881,416 | 16,993,121 | ||||||
| Accumulated impairment loss | ||||||||
| Natural Gas | - | - | ||||||
| Marketing & Production | (725,744 | ) | (725,744 | ) | ||||
| Total accumulated impairment loss | (725,744 | ) | (725,744 | ) | ||||
| Goodwill, net | $ | 16,155,672 | $ | 16,267,377 | ||||
Note 7 - Investment in Unconsolidated Affiliate
The Company’s EWR subsidiary 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 as it could provide a supply of natural gas in close proximity to our natural gas operations in Montana. Our obligations to make additional investments in Kykuit are limited under our agreement with the other Kykuit investors. At December 31, 2014, we are obligated to invest no more than an additional $0.1 million over the life of the venture. Other investors in Kykuit include Richard M. Osborne, father of the Company’s chief executive officer and the Company’s former chairman and chief executive officer; John D. Oil and Gas Company, a publicly held gas exploration company, which is also the managing member of Kykuit; Thomas J. Smith, a former director of the Company and its former chief financial officer and a director of John D. Oil and Gas Company; and Gregory J. Osborne, chief executive officer and a director of the Company and the former president and director of John D. Oil and Gas Company. Due to significant doubts regarding the recoverability of Kykuit’s leaseholds on unproven oil and gas properties coupled with the bankruptcy of the managing member, the Company believes its investment in Kykuit to be completely impaired. As a result, an impairment expense was recorded reducing the investments value to $0 at December 31, 2014. This expense is included in the Loss from unconsolidated affiliate line of the Consolidated Statement of Comprehensive Income.
| F-22 |
Note 8 – 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, 2014 and 2013.
| December 31, 2014 | ||||||||||||||||
| Level 1 | Level 2 | Level 3 | TOTAL | |||||||||||||
| LIABILITIES: | ||||||||||||||||
| Contingent consideration | $ | - | $ | - | $ | 747,000 | $ | 747,000 | ||||||||
| Commodity swap contracts | $ | - | $ | 3,023,271 | $ | - | $ | 3,023,271 | ||||||||
| 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 | ||||||||
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. 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 fair values of marketable securities are estimated based on closing share prices on the open market at the measurement date for those investments. Cost basis is determined by specific identification of securities sold.
The commodity swap contracts, categorized in level 2 of the fair value hierarchy, are valued by comparing the futures price at the measurement date of the natural gas commodity specified in the contract to the fixed price to be paid by the Company. See Note 10 – Derivative Financial Instruments for more information regarding the commodity swap contracts.
The contingent consideration liability categorized in level 3 of the fair value hierarchy arose as a result of the JDOG Marketing acquisition. See Note 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.
| F-23 |
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 Liability | ||||||||
| 2014 | 2013 | |||||||
| Balance January 1st | $ | 685,000 | $ | - | ||||
| Transfers into level 3 | - | - | ||||||
| Transfers out of level 3 | - | - | ||||||
| Total (gains) losses for period: | ||||||||
| Included in net income | 62,000 | (1,565,000 | ) | |||||
| Included in other comprehensive income | - | - | ||||||
| Purchases | - | - | ||||||
| Sales | - | - | ||||||
| Settlements | - | - | ||||||
| Issuances | - | 2,250,000 | ||||||
| Balance December 31st | $ | 747,000 | $ | 685,000 | ||||
The change in fair value included as a part of net income in the table above is reflected in the Contingent consideration loss (gain) line of the Company’s Consolidated Statement of Comprehensive Income and is the result of an unrealized holding loss (gain) associated with the change in the fair value of the Company’s contingent consideration liability.
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 | Valuation Techniques | Unobservable Input | Range | |||||||||
| December 31, 2014 | ||||||||||||
| Contingent Consideration | $ | 747,000 | Monte Carlo analysis | Forecasted annual EBITDA | $0.5 - $0.7 million | |||||||
| Weighted avg cost of capital | 14.0% - 14.0% | |||||||||||
| U.S. Treasury yields | 0.3% -1.1% | |||||||||||
| Discounted cash flow | U.S. Treasury yields | 0.3% -1.1% | ||||||||||
| Credit spread | 2.3% - 3.8% | |||||||||||
| December 31, 2013 | ||||||||||||
| 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.
| F-24 |
Note 9 – Marketable Securities
The following is a summary of available-for-sale securities at December 31, 2013.
| December 31, 2013 | ||||||||||||||||
| Investment | Unrealized | Unrealized | Estimated | |||||||||||||
| at cost | gains | losses | fair value | |||||||||||||
| Common stock | $ | 238,504 | $ | 167,630 | $ | - | $ | 406,134 | ||||||||
During the year ended December 31, 2014, the Company sold all of its available-for-sale securities. The Company received $0.5 million in proceeds which resulted in a gain on sale of approximately $0.2 million. All unrealized gains and losses on these securities have been included in Other comprehensive income on the Company’s Consolidated Statement of Comprehensive Income net of tax. An unrealized gain of approximately $0.1 million, net of tax, was reclassified from Other comprehensive income to a component of Net income during the period as a result of the sale. This amount represented the complete cumulative net unrealized gain on these securities. During the years ended December 31, 2013 and 2012, the Company did not sell any of its marketable securities and there were no gross realized gains or losses.
Note 10 – Derivative Financial Instruments
The Company has entered into commodity swap contracts in order to reduce the commodity price risk related to natural gas prices. These commodity swap contracts set a fixed price that the Company will ultimately pay for quantities of natural gas specified in the contracts. The Company has not designated any of these commodity swaps contracts as hedging instruments.
The following table summarizes the commodity swap contracts entered into by the Company as of December 31, 2014. The Company will pay the fixed price listed for the volumes denoted in the table below. In exchange it will receive from a counterparty a variable payment based on the market price for the natural gas product listed for these volumes. These payments are settled monthly.
| Product | Type | Contract Period | Volume | Price per MMBtu | ||||||||||||
| CIG - Rockies - IFERC Natural Gas | Swap | 1/1/15 - 3/31/15 | 500 MMBtu/Day | $ | 3.980 | |||||||||||
| CIG - Rockies - IFERC Natural Gas | Swap | 1/1/15 - 3/31/15 | 500 MMBtu/Day | $ | 4.075 | |||||||||||
| AECO Canada - CGPR 7A Natural Gas | Swap | 1/1/15 - 3/31/15 | 501 MMBtu/Day | $ | 3.560 | |||||||||||
| IFERC Gas Market Report at Algonquin Citygate Natural Gas | Swap | 1/1/15 - 3/31/15 | 3600 MMBtu/Day | $ | 13.000 | |||||||||||
| IFERC Gas Market Report at Algonquin Citygate Natural Gas | Swap | 4/1/15 - 4/30/15 | 2500 MMBtu/Day | $ | 13.000 | |||||||||||
| IFERC Gas Market Report at Algonquin Citygate Natural Gas | Swap | 5/1/15 - 5/31/15 | 1390 MMBtu/Day | $ | 13.000 | |||||||||||
| IFERC Gas Market Report at Algonquin Citygate Natural Gas | Swap | 6/1/15 - 6/30/15 | 950 MMBtu/Day | $ | 13.000 | |||||||||||
| IFERC Gas Market Report at Algonquin Citygate Natural Gas | Swap | 7/1/15 - 7/31/15 | 890 MMBtu/Day | $ | 13.000 | |||||||||||
The table below summarizes the amount of unrealized loss recognized as a component of Net income from the commodity swap contracts.
| Year Ended December 31, | ||||||||||||
| 2014 | 2013 | 2012 | ||||||||||
| Unrealized loss on commodity swap contracts not designated as hedging instruments | $ | 3,023,271 | $ | - | $ | - | ||||||
| Deferred unrealized loss on commodity swap contracts (1) | (2,872,386 | ) | - | - | ||||||||
| Unrealized loss included in Other income, net | $ | 150,885 | $ | - | $ | - | ||||||
| (1) | Unrealized losses on commodity swap agreements incurred by the Company’s regulated subsidiaries have been deferred as a regulatory asset on the Company’s Consolidated Balance Sheet. See Note 11 - Regulatory Assets and Liabilities. |
| F-25 |
The table below shows the line item in the Company’s Consolidated Balance Sheets where the fair value of the commodity swap contracts is included.
Fair Value of Derivative Instruments
| Liabilities | ||||||||||
| December 31, | ||||||||||
| Balance Sheet Location | 2014 | 2013 | ||||||||
| Derivatives not designated as hedging instruments | ||||||||||
| Commodity swap contracts | Derivative instruments | $ | 3,023,271 | $ | - | |||||
Note 11 – Regulatory Assets and Liabilities
The following table summarizes the components of the Company’s regulatory asset and liability balances at December 31, 2014 and 2013.
| December 31, | ||||||||||||||||
| 2014 | 2013 | |||||||||||||||
| Current | Long-term | Current | Long-term | |||||||||||||
| REGULATORY ASSETS | ||||||||||||||||
| Recoverable cost of gas purchases | $ | 692,117 | $ | - | $ | 1,209,982 | $ | - | ||||||||
| Deferred costs | 489,996 | 1,715,006 | - | - | ||||||||||||
| Deferred loss on commodity swaps | 2,872,385 | - | - | - | ||||||||||||
| Income taxes | - | 296,819 | - | 296,819 | ||||||||||||
| Property taxes | - | - | - | 25,000 | ||||||||||||
| Rate case costs | 43,324 | 43,579 | - | 130,228 | ||||||||||||
| Total regulatory assets | $ | 4,097,822 | $ | 2,055,404 | $ | 1,209,982 | $ | 452,047 | ||||||||
| REGULATORY LIABILITIES | ||||||||||||||||
| Over-recovered gas pruchases | $ | 925,175 | $ | - | $ | 793,184 | $ | - | ||||||||
| Income taxes | - | 83,161 | - | 83,161 | ||||||||||||
| Asset retirement costs | - | 1,006,689 | - | 881,301 | ||||||||||||
| Total regulatory liabilities | $ | 925,175 | $ | 1,089,850 | $ | 793,184 | $ | 964,462 | ||||||||
Recoverable Cost of Gas Purchases/Over-recovered 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 (recoverable cost of gas purchases) or credited through future rate changes (over-recovered gas purchases). These amounts are generally recovered or credited through rates within one year. The gas cost recovery mechanisms 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.
Deferred Costs
On June 27, 2014, the Company’s Frontier Natural Gas subsidiary entered into a stipulation with the Public Staff of the North Carolina Utilities Commission (Docket No G-40, Sub 124), in which the subsidiary agreed, among other items, to reclassify $2.5 million from its recoverable cost of gas purchases asset account to a deferred gas cost asset account. This amount represents a portion of deferred expenses related to the subsidiary’s January and February 2014 gas purchases on which it will not earn return. The stipulation calls for amortization of this amount as operating expense over a five year period beginning July 1, 2014. Under the stipulation, the Public Staff agreed to not request a change in Frontier Natural Gas’s base margin rates, exclusive of cost of gas, for the same five-year period.
| F-26 |
Deferred Loss on Commodity Swaps
The Company’s regulated subsidiaries defer recognition of unrealized losses and gains on its commodity swap derivative instruments as regulatory assets and liabilities, respectively. Deferred losses and gains are recognized as a component of Cost of sales – natural gas purchased on the Company’s Consolidated Statement of Comprehensive Income during the period in which they are settled and recovered through rates. The regulatory asset on the Company’s Consolidated Balance Sheet at December 31, 2014 will be recovered by the end of July 2015.
Income Taxes
The regulatory asset related to income taxes earns a return equal to that of the Company’s rate base and will be recovered through rates. The regulatory liability related to income taxes will be credited to our customers.
Asset Retirement Costs
As a result of regulatory action by the PUCO, Orwell and Brainard accrue an estimated liability for removing certain classes of utility plant long-lived assets at the end of their useful lives. The liability is equal to a set percent of the asset’s historic cost according to the following table:
| Percent of Asset Cost | ||||||||
| Orwell | Brainard | |||||||
| Mains | 15 | % | 20 | % | ||||
| Meter/regulator stations | 10 | % | ||||||
| Service lines | 75 | % | ||||||
These liabilities are accrued over the useful lives of the assets with the corresponding expense included as a portion of depreciation expense. Upon retirement of any assets included in these asset classes, any costs incurred to retire the asset will be recorded against this regulatory liability. Any costs in excess of the liability will be expensed as incurred and any residual liability in excess of incurred costs to retire the asset will act to reduce Orwell and Brainard’s future rates. As of December 31, 2014, none of the assets included in these asset classes have been retired.
Other Regulatory Assets
The rate case costs do not earn a return and will be amortized over a period of 2 to 3 years. The regulatory asset for property tax was recovered in rates over a ten-year period starting January 1, 2004.
Note 12 – Accrued Liabilities
The following table summarizes the components of the Company’s accrued liabilities balances at December 31, 2014 and 2013.
| December 31, | ||||||||
| 2014 | 2013 | |||||||
| Taxes other than income | $ | 2,082,690 | $ | 3,043,583 | ||||
| Vacation | 93,845 | 83,189 | ||||||
| Employee benefits | 123,171 | 161,440 | ||||||
| Interest | 200,502 | 169,581 | ||||||
| Deferred payments received from levelized billing | 2,360,455 | 2,293,801 | ||||||
| Accrued liabilities | $ | 4,860,663 | $ | 5,751,594 | ||||
| F-27 |
Note 13 – Restricted Cash
At December 31, 2014 and 2013, the Company had a restricted cash balance of $1.9 million and $1.1 million, respectively. Of these amounts, $0.9 million and $1.1 million at December 31, 2014 and 2013, respectively, are related to the Company’s Sun Life debt covenants. See the Sun Life Debt Covenant section of Note 17 – Credit Facilities and Long-Term Debt for more information regarding these restricted funds. The remaining $0.9 million at December 31, 2014 is related to a deposit paid in the first quarter of 2014 to Bangor Gas, a subsidiary of the Company, by Verso Bucksport Power LLC (“Verso”) as a required condition related to Verso acquiring the rights of H.Q. Energy Services (U.S.) Inc. under a gas transportation service agreement with Bangor Gas. Bangor Gas is restricted from using these funds unless and until a default under this agreement has occurred. This deposit will be refunded to Verso at the termination of the gas transportation service agreement.
Note 14 – Earnings per Share
| Year Ended December 31, | ||||||||||||
| 2014 | 2013 | 2012 | ||||||||||
| Numerator: | ||||||||||||
| Income from continuing operations | $ | 2,729,166 | $ | 5,852,141 | $ | 3,195,488 | ||||||
| Income from discontinued operations | 1,032,611 | 819,138 | 523,829 | |||||||||
| Net income | $ | 3,761,777 | $ | 6,671,279 | $ | 3,719,317 | ||||||
| Denominator: | ||||||||||||
| Basic weighted average common shares outstanding | 10,478,312 | 9,339,002 | 8,163,814 | |||||||||
| Dilutive effect of stock options | - | 720 | 5,865 | |||||||||
| Dilutive effect of restricted stock awards | 505 | - | - | |||||||||
| Diluted weighted average common shares outstanding | 10,478,817 | 9,339,722 | 8,169,679 | |||||||||
| Basic & diluted earnings per share of common stock: | ||||||||||||
| Continuing operations | $ | 0.26 | $ | 0.63 | $ | 0.39 | ||||||
| Discontinued operations | 0.10 | 0.08 | 0.07 | |||||||||
| Net income | $ | 0.36 | $ | 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, 2014, 2013 and 2012.
Note 15 – Property Plant & Equipment
Components of property, plant, and equipment were as follows:
| December 31, | ||||||||
| 2014 | 2013 | |||||||
| Gas transmission & distribution facilities | $ | 163,138,652 | $ | 138,812,125 | ||||
| Land | 3,773,998 | 3,773,998 | ||||||
| Buildings & leasehold improvements | 11,212,860 | 11,241,104 | ||||||
| Transportation equipment | 3,735,809 | 3,449,615 | ||||||
| Computer equipment | 3,876,106 | 3,844,776 | ||||||
| Other equipment | 11,150,519 | 10,065,908 | ||||||
| Producing natural gas properties | 3,900,455 | 3,900,455 | ||||||
| Construction work in progress | 8,646,219 | 10,762,535 | ||||||
| Property, plant & equipment | 209,434,618 | 185,850,516 | ||||||
| Accumulated depreciation, depletion & amortization | (58,049,321 | ) | (52,301,885 | ) | ||||
| 151,385,297 | 133,548,631 | |||||||
| Assets held for sale | (407,247 | ) | - | |||||
| Discontinued operations | (8,966,965 | ) | (8,960,986 | ) | ||||
| Property, plant & equipment, net | $ | 142,011,085 | $ | 124,587,645 | ||||
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, 2014 and 2013, management of the Company, considering reserve estimates provided by an independent reservoir engineer, estimated the net gas reserves at 2.1 Bcf (unaudited) and 2.3 Bcf (unaudited), respectively, and with net present values of $2.7 million and $2.1 million, respectively, after applying a 10% discount (unaudited). The net book value of the gas properties totals $0.9 million and $1.0 million at December 31, 2014 and 2013, respectively.
| F-28 |
The wells are depleted based upon production at approximately 10% and 10% per year as of December 31, 2014 and 2013, respectively. For the years ended December 31, 2014, 2013 and 2012, EWR’s portion of the daily gas production was 395 Mcf, 422 Mcf and 461 Mcf per day, or 20.0%, 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, 2014, 2013 and 2012, EWD’s portion of the daily gas production was 107 Mcf, 129 Mcf and 132 Mcf per day, or 5.5%, 5.8% and 4.4% of EWR’s volume requirements, respectively.
For the years ended December 31, 2014, 2013 and 2012, EWR and EWD’s combined portion of the estimated daily gas production from the reserves was 502 Mcf, 550 Mcf and 593 Mcf, or 26.0%, 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.
Build-to-suit Lease
Included as a component of Construction work in progress is a $6.5 million asset that represents the Company’s new build-to-suit lease enterprise resource planning (“ERP”) system. The Company has determined that during the application development stage it possesses substantially all of the project’s risk and as such should be considered the owner of the asset during this period. In addition, the Company has recorded a $5.6 million liability included in the Build-to-suit liability line item on its Condensed Consolidated Balance Sheet dated December 31, 2014 related to this project. Upon completion of the ERP project, the Company will assess whether the lease qualifies for sales recognition under sale-leaseback accounting guidance.
Note 16 – Asset Retirement Obligations
The Company has identified but not recognized ARO liabilities related to gas transmission and distribution assets resulting from easements over property not owned by the Company. These easements are generally perpetual and only require retirement action upon abandonment or cessation of use of the property for the specified purpose. The ARO liability is not estimable for such easements as the Company intends to utilize these properties indefinitely. In the event the Company decides to abandon or cease the use of a particular easement, an ARO liability would be recorded at that time.
The Company’s recognized asset retirement obligations represent the estimate costs to retire certain natural gas producing wells. The following schedule is a reconciliation of the Company’s recognized asset retirement obligations for the years ended December 31, 2014 and 2013.
| 2014 | 2013 | |||||||
| Balance, January 1st | $ | 1,145,052 | $ | 1,087,140 | ||||
| Accretion expense | 51,466 | 57,912 | ||||||
| Balance, December 31st | $ | 1,196,518 | $ | 1,145,052 | ||||
The Company has no assets legally restricted for purposes of settling its asset retirement obligations. As of December 31, 2014 and 2013, the Company had capitalized ARO costs included in property, plant and equipment of $48,954 and $86,415, respectively.
Note 17 – Credit Facilities and Long-Term Debt
Line of Credit
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. On November 26, 2014, the Company entered into an amendment temporarily increasing the borrowing capacity by $10.0 million to a maximum of $40.0 million. In an order approving this temporary increase in borrowing capacity, the MPSC stated that any amounts borrowed under this increase in excess of $5.0 million would first require the approval of the MPSC. Amounts borrowed under this temporary increase have a maturity date of July 1, 2015. 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 $28.8 million and $24.5 million at December 31, 2014 and 2013, respectively. For the year ended December 31, 2014, the weighted average borrowing outstanding on the revolving line of credit was $23.4 million. For the years ended December 31, 2014, 2013 and 2012, the weighted average interest rate on the revolving credit facility was 2.45%, 2.42% and 3.33%, respectively.
| F-29 |
Notes Payable
The following table details the Company’s outstanding long-term debt balances at December 31, 2014 and 2013.
| December 31, | ||||||||
| 2014 | 2013 | |||||||
| LIBOR plus 1.75 to 2.25%, Bank of America amortizing term loan, due April 1, 2017 | $ | 8,875,000 | $ | 9,375,000 | ||||
| 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 | ||||||
| 4.15% Sun Life senior secured guaranteed note, due June 1, 2017 | 2,989,552 | 2,989,552 | ||||||
| Vehicle and equipment financing loans | 64,509 | 2,190 | ||||||
| Total notes payable | 40,263,061 | 43,700,742 | ||||||
| Less: current portion | 542,201 | 3,502,190 | ||||||
| Notes payable, less current portion | $ | 39,720,860 | $ | 40,198,552 | ||||
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, 2014, the Company had not exercised the interest rate swap provision for the fixed interest rate. For the years ended December 31, 2014, 2013 and 2012, the weighted average interest rate on the term loan was 2.15%, 2.19% and 2.14%, respectively, resulting in $200,727, $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, 2014, 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, 2014, 2013 and 2012, interest expense related to the fixed rate note was $824,969 per year.
The Sun Life floating rate note is an obligation of Great Plains and is guaranteed by the Company. This note was repaid in May 2014. For the years ended December 31, 2014, 2013 and 2012, the weighted average interest rate on the floating rate note was 4.10%, 4.13% and 4.31% respectively resulting in $40,900, $123,850 and $129,200 of interest expense.
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, 2014, 2013 and 2012, interest expense from the senior secured guaranteed note was $123,007, $123,007 and $23,576, respectively.
| F-30 |
The following table shows the aggregate future maturities of the Company’s notes payable.
| Years Ending | ||||
| 2015 | $ | 542,201 | ||
| 2016 | 522,308 | |||
| 2017 | 39,198,552 | |||
| 2018 | - | |||
| 2019 | - | |||
| Thereafter | - | |||
| Total | $ | 40,263,061 | ||
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.
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 $0.9 million and $1.1 million at December 31, 2014 and 2013, 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.
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.
| F-31 |
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.
Note 18 – Stockholders’ Equity
Share Repurchase Plan
The Company’s common stock trades on the NYSE MKT 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. As of December 31, 2014, there has been no share repurchase activity.
Stock Compensation
During the years ended December 31, 2014, 2013 and 2012, the Company recorded $316,985, $2,962 and $9,406, respectively, of stock-based compensation expense. As of December 31, 2014, there was $49,544 of total unrecognized compensation cost related to stock-based compensation that will be recognized through July 21, 2017.
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. 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.
| F-32 |
A summary of the status of the outstanding stock options is as follows:
| Weighted | Aggregate | |||||||||||
| Number of | Average | Intrinsic | ||||||||||
| Shares | Exercise Price | Value | ||||||||||
| 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 | $ | - | |||||||
| Granted | - | $ | - | |||||||||
| Exercised | (5,000 | ) | $ | 8.44 | ||||||||
| Forfeited | - | $ | - | |||||||||
| Expired | - | $ | - | |||||||||
| Outstanding December 31, 2014 | - | $ | - | $ | - | |||||||
| Exerciseable December 31, 2014 | - | $ | - | $ | - | |||||||
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 and directors. The number of shares authorized for issuance under the plan is 500,000.
On March 26, 2014, in order to further align the directors’ interests with those of the Company’s shareholders, the board granted an award of the Company’s common stock to each current director of Gas Natural. The total number of shares awarded was 30,833 with a grant date fair value of $0.3 million. The award was not conditional on any future performance or event and as such, the award was fully expensed on the grant date. These shares were issued on April 3, 2014.
On July 21, 2014, in conjunction with his employment agreement, the Company granted 5,000 shares of restricted stock to Gregory J. Osborne, chief executive officer and a director of the Company. These shares had a grant date fair value of $58,200 and will vest ratably through July 21, 2017. During the vesting period, each restricted share has the same rights to dividend distributions and voting as any other common share of the Company.
| Restricked Stock | ||||
| Awards | ||||
| Outstanding, December 31, 2013 | - | |||
| Granted | 5,000 | |||
| Vested | - | |||
| Forfeited | - | |||
| Outstanding, December 31, 2014 | 5,000 | |||
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. The number of shares authorized for issuance under the plan is 250,000. As of December 31, 2014, no shares had been issued under the plan.
| F-33 |
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 in Note 17 – Credit Facilities and Long-Term Debt, the MPUC, MPSC, NCUC and WPSC have each placed ring fencing provisions over the subsidiary companies in their jurisdictions. 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.
The most limiting of the restrictions on the net assets of the Company’s subsidiaries are the Sun Life debt covenant restriction on distributions to the holding company from its obligors and the MPSC restriction, related to the November 25, 2014 BOA line of credit amendment, which restricts distributions to the holding company from Energy West and its Montana, Maine, or North Carolina subsidiaries.
The total restricted net assets of consolidated subsidiaries related to the Company’s debt covenants and ring fencing restrictions is $92.3 million, which accounts for 95.7% of Gas Natural Inc.’s net assets of $96.5 million at December 31, 2014.
Note 19 – 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, 2014, 2013 and 2012 was $492,047, $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 $57,245, $57,590 and $52,719 for the years ended December 31, 2014, 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, 2014, 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, 2014 and 2013, the value of plan assets was $132,717 and $155,750, respectively. The assets remaining in the trust will be used to fund the plan until these assets are exhausted.
| F-34 |
Note 20 – Income Taxes
Significant components of the deferred tax assets and liabilities are as follows:
| December 31, | ||||||||||||||||
| 2014 | 2013 | |||||||||||||||
| Current | Long-term | Current | Long-term | |||||||||||||
| Deferred tax assets: | ||||||||||||||||
| Allowance for doubtful accounts | $ | 141,701 | $ | - | $ | 724,534 | $ | - | ||||||||
| Contributions in aid of construction | - | 2,480,637 | - | 1,652,760 | ||||||||||||
| Other nondeductible accruals | 46,102 | - | 47,484 | - | ||||||||||||
| Recoverable purchase gas costs | 217,349 | - | 60,903 | - | ||||||||||||
| Net operating loss carryforwards | - | 13,255,842 | - | 7,733,763 | ||||||||||||
| Property tax | 157,683 | - | 154,146 | - | ||||||||||||
| Other | 451,213 | - | 754,235 | - | ||||||||||||
| Total deferrred tax assets | 1,014,048 | 15,736,479 | 1,741,302 | 9,386,523 | ||||||||||||
| Deferred tax liabilities: | ||||||||||||||||
| Recoverable purchase gas costs | 378,853 | - | 454,795 | - | ||||||||||||
| Property, plant and equipment | - | 17,375,812 | - | 11,402,464 | ||||||||||||
| Unrealized gain on securities available for sale | - | 549,046 | 61,475 | - | ||||||||||||
| Amortization of intangibles | - | 738,608 | - | 539,498 | ||||||||||||
| Other | - | 1,114,692 | - | 800,698 | ||||||||||||
| Total deferrred tax liabilities | 378,853 | 19,778,158 | 516,270 | 12,742,660 | ||||||||||||
| Net deferred tax asset (liability) before valuation allowance | 635,195 | (4,041,679 | ) | 1,225,032 | (3,356,137 | ) | ||||||||||
| Less: valuation allowance | - | (6,496,715 | ) | - | (5,699,029 | ) | ||||||||||
| Total deferred tax asset (liability) | 635,195 | (10,538,394 | ) | 1,225,032 | (9,055,166 | ) | ||||||||||
| Discontinued operations | - | - | - | - | ||||||||||||
| Net deferred tax asset (liability), continuing operations | $ | 635,195 | $ | (10,538,394 | ) | $ | 1,225,032 | $ | (9,055,166 | ) | ||||||
| F-35 |
Income tax expense from continuing operations consists of the following:
| Year Ended December 31, | ||||||||||||
| 2014 | 2013 | 2012 | ||||||||||
| Current income tax expense (benefit): | ||||||||||||
| Federal | $ | 49,270 | $ | (344,342 | ) | $ | (150,224 | ) | ||||
| State | 10,961 | 120,753 | 245,483 | |||||||||
| Total current income tax expense (benefit) | 60,231 | (223,589 | ) | 95,259 | ||||||||
| Deferred income tax expense: | ||||||||||||
| Federal | 1,987,409 | 3,692,413 | 2,030,525 | |||||||||
| State | 138,414 | (200,217 | ) | 252,403 | ||||||||
| Total deferred income tax expense | 2,125,823 | 3,492,196 | 2,282,928 | |||||||||
| Total income taxes before credits | 2,186,054 | 3,268,607 | 2,378,187 | |||||||||
| Investment tax credit, net | (21,062 | ) | (21,062 | ) | (21,062 | ) | ||||||
| Total income tax expense | 2,164,992 | 3,247,545 | 2,357,125 | |||||||||
| Income tax expense from discontinued operations | (617,410 | ) | (223,834 | ) | (400,326 | ) | ||||||
| Income tax expense from continuing operations | $ | 1,547,582 | $ | 3,023,711 | $ | 1,956,799 | ||||||
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, | ||||||||||||
| 2014 | 2013 | 2012 | ||||||||||
| Tax expense at statutory rate of 34% | $ | 2,015,101 | $ | 3,372,404 | $ | 2,065,991 | ||||||
| State income tax, net of federal tax expense | 307,099 | 348,151 | 228,051 | |||||||||
| Amortization of deferred investment tax credits | (21,062 | ) | (21,062 | ) | (21,062 | ) | ||||||
| Change in valuation allowance | (397,619 | ) | (237,557 | ) | (262,343 | ) | ||||||
| Permanent differences | 24,580 | 134,583 | 140,211 | |||||||||
| State rate change | 149,015 | (346,149 | ) | - | ||||||||
| Other | 87,878 | (2,825 | ) | 206,277 | ||||||||
| Total income tax expense | 2,164,992 | 3,247,545 | 2,357,125 | |||||||||
| Income tax expense from discontinued operations | (617,410 | ) | (223,834 | ) | (400,326 | ) | ||||||
| Income tax expense from continuing operations | $ | 1,547,582 | $ | 3,023,711 | $ | 1,956,799 | ||||||
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.
| F-36 |
The Company has approximately $22.5 million in federal net operating loss carryovers as of December 31, 2014. 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, 2014. The Company has recorded a state deferred tax asset valuation allowance of $4.7 million against the state net operating loss carryover. In addition, the Company has approximately $20.0 million of carryover tax basis as of December 31, 2014. 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.
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, 2014, 2013 and 2012, no adjustments were recognized for uncertain tax benefits.
The tax years after 2010 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 21 – Related Party Transactions
The Company is party to certain agreements and transactions with Richard M. Osborne, father of the Company’s chief executive officer and the Company’s former chairman and chief executive officer, and companies owned or controlled by Richard M. Osborne.
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, father of the Company’s chief executive officer and the Company’s former chairman and chief executive officer. The acquisition of the Matchworks Building was approved by the independent members of the Company’s board of directors. See Note 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, father of the Company’s chief executive officer and the Company’s former 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. See Note 3 – Acquisitions for details regarding this transaction.
| F-37 |
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. See Note 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. In September of 2014, OsAir was evicted from the office space for failure to make payment. At December 31, 2014, $29,150 of past due rent was still owed the Company.
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, father of the Company’s chief executive officer and the Company’s former 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, father of the Company’s chief executive officer and the Company’s former chairman and chief executive officer, at December 31, 2014 and 2013.
| Accounts Receivable | Accounts Payable | |||||||||||||||
| December 31, | December 31, | December 31, | December 31, | |||||||||||||
| 2014 | 2013 | 2014 | 2013 | |||||||||||||
| Cobra Pipeline | $ | 178,596 | $ | 131,208 | $ | 67,982 | $ | 76,909 | ||||||||
| Orwell Trumbell Pipeline | - | - | 102,231 | 122,693 | ||||||||||||
| Great Plains Exploration | 959 | 7,033 | 9 | 73,983 | ||||||||||||
| Big Oats Oil Field Supply | 4,752 | 4,945 | - | 179,447 | ||||||||||||
| John D. Oil and Gas Company | 6,854 | 91 | - | 82,188 | ||||||||||||
| OsAir | 35,329 | - | 97 | 16,703 | ||||||||||||
| Other | 8,120 | 2,948 | - | 8,010 | ||||||||||||
| Total related party balances | 234,610 | 146,225 | 170,319 | 559,933 | ||||||||||||
| Less amounts included in discontinued operations | - | - | - | - | ||||||||||||
| Total related party balances included in continuing operations | $ | 234,610 | $ | 146,225 | $ | 170,319 | $ | 559,933 | ||||||||
| F-38 |
The table below details transactions with related parties, including companies owned or controlled by Richard M. Osborne, father of the Company’s chief executive officer and the Company’s former chairman and chief executive officer, for the year ended December 31, 2014:
| Year Ended December 31, 2014 | ||||||||||||||||||||
| Natural Gas Purchases | Pipeline Construction Purchases | Rent, Supplies, Consulting and Other Purchases | Natural Gas Sales | Rental Income and Other Sales | ||||||||||||||||
| Cobra Pipeline | $ | 1,119,192 | $ | - | $ | 18,000 | $ | 104,623 | $ | 13,400 | ||||||||||
| Orwell Trumbell Pipeline | 788,026 | - | - | 1,956 | 37,124 | |||||||||||||||
| Great Plains Exploration | 611,187 | - | - | 13,073 | 5,200 | |||||||||||||||
| Big Oats Oil Field Supply | - | 254,752 | 93,741 | 5,181 | 850 | |||||||||||||||
| John D. Oil and Gas Company | 737,522 | - | - | 575 | 42,209 | |||||||||||||||
| OsAir | 176,116 | - | 6,317 | 3,788 | 52,045 | |||||||||||||||
| Lake Shore Gas Storage | 162,360 | - | - | - | - | |||||||||||||||
| Other | 76,282 | - | 22,808 | 22,240 | 1,676 | |||||||||||||||
| Total | $ | 3,670,685 | $ | 254,752 | $ | 140,866 | $ | 151,436 | $ | 152,504 | ||||||||||
The table below details transactions with related parties, including companies owned or controlled by Richard M. Osborne, father of the Company’s chief executive officer and the Company’s former 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, father of the Company’s chief executive officer and the Company’s former 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 | ||||||||||
| F-39 |
The Company also accrued a liability of $111,133 and $0 due to companies controlled by Richard M. Osborne, father of the Company’s chief executive officer and the Company’s former chairman and chief executive officer, for natural gas used and transportation charges through December 31, 2014 and 2013, 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, father of the Company’s chief executive officer and the Company’s former 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.
In addition, the Company had related party natural gas imbalances of $98,081 and $151,780 at December 31, 2014 and December 31, 2013, respectively, which were included in the Company’s natural gas inventory balance. These amounts represent quantities of natural gas due to the Company from natural gas transportation companies controlled by Richard M. Osborne, father of the Company’s chief executive officer and the Company’s former chairman and chief executive officer.
Note 22 – Unaudited Quarterly Results of Operations
| 2014 Quarter Ended | ||||||||||||||||
| December 31, | September 30, (1) | June 30, | March 31, | |||||||||||||
| Revenue | $ | 36,958,232 | $ | 13,614,971 | $ | 20,499,919 | $ | 61,496,719 | ||||||||
| Gross margin | 12,036,544 | 7,014,641 | 8,392,127 | 17,409,150 | ||||||||||||
| Income (loss) from continuing operations | $ | 1,200,689 | $ | (1,514,569 | ) | $ | (1,493,499 | ) | $ | 4,536,545 | ||||||
| Discontinued operations | 450,959 | 34,825 | 64,881 | 481,946 | ||||||||||||
| Net income (loss) | $ | 1,651,648 | $ | (1,479,744 | ) | $ | (1,428,618 | ) | $ | 5,018,491 | ||||||
| Basic and diluted earnings per share | ||||||||||||||||
| Continuing operations | $ | 0.11 | $ | (0.14 | ) | $ | (0.14 | ) | $ | 0.43 | ||||||
| Discontinued operations | 0.05 | - | - | 0.05 | ||||||||||||
| Net income (loss) per share | $ | 0.16 | $ | (0.14 | ) | $ | (0.14 | ) | $ | 0.48 | ||||||
| 2013 Quarter Ended | ||||||||||||||||
| December 31, (2) | September 30, (3) | June 30, (4) | March 31, | |||||||||||||
| Revenue | $ | 36,286,131 | $ | 13,617,328 | $ | 18,707,462 | $ | 40,789,432 | ||||||||
| Gross margin | 13,476,706 | 7,234,509 | 7,351,808 | 15,307,311 | ||||||||||||
| Income (loss) from continuing operations | $ | 2,797,734 | $ | (850,046 | ) | $ | (429,753 | ) | $ | 4,334,206 | ||||||
| Discontinued operations | 417,076 | (154,292 | ) | 102,837 | 453,517 | |||||||||||
| Net income (loss) | $ | 3,214,810 | $ | (1,004,338 | ) | $ | (326,916 | ) | $ | 4,787,723 | ||||||
| Basic and diluted earnings per share | ||||||||||||||||
| Continuing operations | $ | 0.27 | $ | (0.08 | ) | $ | (0.05 | ) | $ | 0.52 | ||||||
| Discontinued operations | 0.04 | (0.02 | ) | 0.01 | 0.05 | |||||||||||
| Net income (loss) per share | $ | 0.31 | $ | (0.10 | ) | $ | (0.04 | ) | $ | 0.57 | ||||||
| (1) | Company classified its Energy West Wyoming subsidiary and Glacier and Shoshone Pipeline Assets as discontinued operations. All prior periods have been restated to match this presentation. |
| (2) | Company recorded a goodwill impairment expense of $0.7 million and an unrealized gain on its contingent consideration liability of $1.6 million. |
| (3) | Company classified its Independence subsidiary as discontinued operations. All prior periods have been restated to match this presentation. |
| (4) | Company recorded a contingent liability of $0.9 million, related to the PUCO’s GCR audit of its Ohio utilities, reducing gross margin. |
| F-40 |
Note 23 – Segments of Operation
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 non-regulated marketing and production businesses, and its corporate level operations. See Note 4 – Discontinued Operations for more information regarding the Company’s previously reported Pipeline and Propane segments. The Company has regulated natural gas utility businesses in the states of Kentucky, Maine, Montana, North Carolina, Ohio, and Pennsylvania that form the Company’s Natural Gas segment. The Company has non-regulated natural gas marketing and production businesses in Montana and Ohio that together form the Company’s Marketing & Production segment. The Company’s Lone Wolf subsidiary, its holding company, and the Company’s discontinued operations together form its Corporate & Other segment. 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.
The following tables set forth summarized financial information for the Company’s Natural Gas, Marketing & Production, and Corporate & Other operating segments.
| Year Ended December 31, 2014 | Natural Gas | Marketing & Production | Corporate & Other | Consolidated | ||||||||||||
| OPERATING REVENUES | $ | 123,378,718 | $ | 17,605,367 | $ | - | $ | 140,984,085 | ||||||||
| Intersegment eliminations | (326,164 | ) | (8,088,080 | ) | - | (8,414,244 | ) | |||||||||
| Total operating revenue | 123,052,554 | 9,517,287 | - | 132,569,841 | ||||||||||||
| COST OF SALES | 79,422,717 | 16,708,906 | - | 96,131,623 | ||||||||||||
| Intersegment eliminations | (326,164 | ) | (8,088,080 | ) | - | (8,414,244 | ) | |||||||||
| Total cost of sales | 79,096,553 | 8,620,826 | - | 87,717,379 | ||||||||||||
| GROSS MARGIN | 43,956,001 | 896,461 | - | 44,852,462 | ||||||||||||
| OPERATING EXPENSES | ||||||||||||||||
| Distribution, general and administrative | 20,975,963 | 1,833,476 | 3,175,197 | 25,984,636 | ||||||||||||
| Maintenance | 1,224,998 | 493 | - | 1,225,491 | ||||||||||||
| Depreciation and amortization | 6,070,669 | 514,654 | 19,246 | 6,604,569 | ||||||||||||
| Accretion | 6,856 | 44,610 | - | 51,466 | ||||||||||||
| Taxes other than income | 3,898,337 | 23,367 | 6,314 | 3,928,018 | ||||||||||||
| Unrealized holding loss | - | 62,000 | - | 62,000 | ||||||||||||
| Intersegment eliminations | (102,898 | ) | - | - | (102,898 | ) | ||||||||||
| Total operating expenses | 32,073,925 | 2,478,600 | 3,200,757 | 37,753,282 | ||||||||||||
| OPERATING INCOME (LOSS) | 11,882,076 | (1,582,139 | ) | (3,200,757 | ) | 7,099,180 | ||||||||||
| Other income (expense) | 889,873 | (502,367 | ) | 16,158 | 403,664 | |||||||||||
| Interest expense | (2,619,294 | ) | (121,041 | ) | (485,761 | ) | (3,226,096 | ) | ||||||||
| Income (loss) before taxes | 10,152,655 | (2,205,547 | ) | (3,670,360 | ) | 4,276,748 | ||||||||||
| Income tax benefit (expense) | (3,661,125 | ) | 771,844 | 1,341,699 | (1,547,582 | ) | ||||||||||
| INCOME (LOSS) FROM CONTINUING OPERATIONS | 6,491,530 | (1,433,703 | ) | (2,328,661 | ) | 2,729,166 | ||||||||||
| Discontinued operations, net of income tax | - | - | 1,032,611 | 1,032,611 | ||||||||||||
| NET INCOME (LOSS) | $ | 6,491,530 | $ | (1,433,703 | ) | $ | (1,296,050 | ) | $ | 3,761,777 | ||||||
| Capital expenditures | $ | 21,530,449 | $ | 60,415 | $ | 21,816 | $ | 21,612,680 | ||||||||
| F-41 |
| Year Ended December 31, 2013 | Natural Gas | Marketing & Production | Corporate & Other | Consolidated | ||||||||||||
| OPERATING REVENUES | $ | 97,259,443 | $ | 20,260,001 | $ | - | $ | 117,519,444 | ||||||||
| Intersegment eliminations | (26,331 | ) | (8,092,760 | ) | - | (8,119,091 | ) | |||||||||
| Total operating revenue | 97,233,112 | 12,167,241 | - | 109,400,353 | ||||||||||||
| COST OF SALES | 56,003,485 | 18,145,625 | - | 74,149,110 | ||||||||||||
| Intersegment eliminations | (26,331 | ) | (8,092,760 | ) | - | (8,119,091 | ) | |||||||||
| Total cost of sales | 55,977,154 | 10,052,865 | - | 66,030,019 | ||||||||||||
| GROSS MARGIN | 41,255,958 | 2,114,376 | - | 43,370,334 | ||||||||||||
| OPERATING EXPENSES | ||||||||||||||||
| Distribution, general and administrative | 19,560,991 | 801,305 | 1,770,564 | 22,132,860 | ||||||||||||
| Maintenance | 1,139,496 | 2,765 | - | 1,142,261 | ||||||||||||
| Depreciation and amortization | 5,081,293 | 456,790 | 12,670 | 5,550,753 | ||||||||||||
| Accretion | 7,068 | 50,844 | - | 57,912 | ||||||||||||
| Unrealized holding gain | - | (1,565,000 | ) | - | (1,565,000 | ) | ||||||||||
| Goodwill impairment | - | 725,744 | - | 725,744 | ||||||||||||
| Taxes other than income | 3,619,304 | 28,113 | 24,513 | 3,671,930 | ||||||||||||
| Intersegment eliminations | (13,744 | ) | - | (84,090 | ) | (97,834 | ) | |||||||||
| Total operating expenses | 29,394,408 | 500,561 | 1,723,657 | 31,618,626 | ||||||||||||
| OPERATING INCOME (LOSS) | 11,861,550 | 1,613,815 | (1,723,657 | ) | 11,751,708 | |||||||||||
| Other income (expense) | 767,235 | 151,168 | (618,104 | ) | 300,299 | |||||||||||
| Interest expense | (2,566,310 | ) | (142,031 | ) | (467,814 | ) | (3,176,155 | ) | ||||||||
| Income (loss) before taxes | 10,062,475 | 1,622,952 | (2,809,575 | ) | 8,875,852 | |||||||||||
| Income tax benefit (expense) | (3,242,814 | ) | (586,326 | ) | 805,429 | (3,023,711 | ) | |||||||||
| INCOME (LOSS) FROM CONTINUING OPERATIONS | 6,819,661 | 1,036,626 | (2,004,146 | ) | 5,852,141 | |||||||||||
| Discontinued operations, net of income tax | - | - | 819,138 | 819,138 | ||||||||||||
| NET INCOME (LOSS) | $ | 6,819,661 | $ | 1,036,626 | $ | (1,185,008 | ) | $ | 6,671,279 | |||||||
| Capital expenditures | $ | 23,241,913 | $ | 217,201 | $ | 57,809 | $ | 23,516,923 | ||||||||
| F-42 |
| Year Ended December 31, 2012 | Natural Gas | Marketing & Production | Corporate & Other | Consolidated | ||||||||||||
| OPERATING REVENUES | $ | 73,925,318 | $ | 13,417,723 | $ | - | $ | 87,343,041 | ||||||||
| Intersegment eliminations | (24,837 | ) | (5,924,362 | ) | - | (5,949,199 | ) | |||||||||
| Total operating revenue | 73,900,481 | 7,493,361 | - | 81,393,842 | ||||||||||||
| COST OF SALES | 38,577,444 | 11,877,518 | - | 50,454,962 | ||||||||||||
| Intersegment eliminations | (24,837 | ) | (5,924,362 | ) | - | (5,949,199 | ) | |||||||||
| Total cost of sales | 38,552,607 | 5,953,156 | - | 44,505,763 | ||||||||||||
| GROSS MARGIN | $ | 35,347,874 | $ | 1,540,205 | $ | - | $ | 36,888,079 | ||||||||
| OPERATING EXPENSES | ||||||||||||||||
| Distribution, general and administrative | 17,904,439 | 449,665 | 1,109,677 | 19,463,781 | ||||||||||||
| Maintenance | 994,058 | 1,014 | - | 995,072 | ||||||||||||
| Depreciation and amortization | 4,034,452 | 268,202 | 34,542 | 4,337,196 | ||||||||||||
| Accretion | 113,106 | 48,192 | - | 161,298 | ||||||||||||
| Taxes other than income | 3,110,909 | 38,052 | 39,110 | 3,188,071 | ||||||||||||
| Total operating expenses | 26,156,964 | 805,125 | 1,183,329 | 28,145,418 | ||||||||||||
| OPERATING INCOME (LOSS) | $ | 9,190,910 | $ | 735,080 | $ | (1,183,329 | ) | $ | 8,742,661 | |||||||
| Other income (expense) | 346,048 | (6,051 | ) | (1,230,651 | ) | (890,654 | ) | |||||||||
| Interest expense | (2,198,888 | ) | (133,440 | ) | (367,391 | ) | (2,699,719 | ) | ||||||||
| Income (loss) before taxes | 7,338,070 | 595,589 | (2,781,371 | ) | 5,152,288 | |||||||||||
| Income tax benefit (expense) | (2,869,083 | ) | 4,542 | 907,742 | (1,956,799 | ) | ||||||||||
| INCOME (LOSS) FROM CONTINUING OPERATIONS | $ | 4,468,987 | $ | 600,131 | $ | (1,873,629 | ) | $ | 3,195,489 | |||||||
| Discontinued operations, net of income tax | - | - | 523,829 | 523,829 | ||||||||||||
| NET INCOME (LOSS) | $ | 4,468,987 | $ | 600,131 | $ | (1,349,800 | ) | $ | 3,719,318 | |||||||
| Capital expenditures | $ | 17,686,583 | $ | 1,393,040 | $ | 856,359 | $ | 19,935,982 | ||||||||
| F-43 |
| Natural Gas Operations | Marketing & Produrction Operations | Corporate & Other Operations | Consolidated | |||||||||||||
| December 31, 2014 | ||||||||||||||||
| Investment in unconsolidated affiliate | $ | - | $ | - | $ | - | $ | - | ||||||||
| Total assets | $ | 214,030,368 | $ | 9,192,830 | $ | 100,781,302 | $ | 324,004,500 | ||||||||
| Intersegment eliminations | (68,714,744 | ) | (2,714,405 | ) | (38,571,439 | ) | (110,000,588 | ) | ||||||||
| Total assets | $ | 145,315,624 | $ | 6,478,425 | $ | 62,209,863 | $ | 214,003,912 | ||||||||
| December 31, 2013 | ||||||||||||||||
| Investment in unconsolidated affiliate | $ | - | $ | 351,724 | $ | - | $ | 351,724 | ||||||||
| Total assets | $ | 184,085,665 | $ | 11,633,544 | $ | 94,981,858 | $ | 290,701,067 | ||||||||
| Intersegment eliminations | (53,772,095 | ) | (3,678,311 | ) | (29,518,864 | ) | (86,969,270 | ) | ||||||||
| Total assets | $ | 130,313,570 | $ | 7,955,233 | $ | 65,462,994 | $ | 203,731,797 | ||||||||
Note 24 – Commitments and Contingencies
Lease Commitments
Operating Leases
The Company leases certain properties including land, office buildings, and other equipment under non-cancelable operating leases. Lease expense resulting from operating leases for the years ended December 31, 2014, 2013 and 2012, totaled $184,008, $222,093 and $429,743, 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 lease payments of $300,000
per year through 2022. Additionally, the agreement calls for a $120,000 facility service fee to be paid by the Company each year,
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 2014, 2013 or 2012. During
the year end December 31, 2014, the Company paid $120,000 for services related to this lease. There were 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, 2014 and 2013:
| December 31, | ||||||||
| 2014 | 2013 | |||||||
| Gas transmission & distribution facilities | $ | 6,320,000 | $ | 6,320,000 | ||||
| Capital lease assets, gross | 6,320,000 | 6,320,000 | ||||||
| Accumulated depreciation | (902,857 | ) | (501,587 | ) | ||||
| Capital lease assets, net | $ | 5,417,143 | $ | 5,818,413 | ||||
Depreciation expense recorded in connection with assets under capital leases was $401,270, $401,270 and $100,317 for the years ended December 31, 2014, 2013 and 2012, respectively.
| F-44 |
The following schedule presents the future minimum lease payments under the Company’s lease agreements as of December 31, 2014.
| Future Minimum Lease Payments | ||||||||||||
| Operating Leases | Build-to-suit Lease (1) | Capital Leases | ||||||||||
| 2015 | $ | 277,634 | $ | 2,405,890 | $ | 300,000 | ||||||
| 2016 | 242,917 | 2,226,081 | 300,000 | |||||||||
| 2017 | 233,913 | 2,092,063 | 300,000 | |||||||||
| 2018 | 222,719 | 205,958 | 300,000 | |||||||||
| 2019 | 210,579 | - | 300,000 | |||||||||
| Thereafter | 994,701 | - | 900,000 | |||||||||
| Total minimum lease payments | $ | 2,182,463 | $ | 6,929,992 | 2,400,000 | |||||||
| Less: Interest portion | 537,062 | |||||||||||
| Liability | $ | 1,862,938 | ||||||||||
| (1) | Relates to the Company’s ERP system build-to-suit lease. See Note 15 – Property Plant & Equipment. |
Long-term Contracts
The following table summarizes the Company’s future minimum obligations under its long-term contracts at December 31, 2014.
| Future Minimum Long-term Contract Obligations | ||||||||||||||||
| Northwestern | Maritimes and | Gas Purchase | ||||||||||||||
| Energy | Trans-Canada | Northeast Pipeline | Contracts | |||||||||||||
| 2015 | $ | 1,434,680 | $ | 829,775 | $ | 357,042 | $ | 2,939,547 | ||||||||
| 2016 | 519,356 | 368,768 | 357,042 | 817,325 | ||||||||||||
| 2017 | 519,356 | 368,768 | 357,042 | - | ||||||||||||
| 2018 | 476,076 | 338,036 | 357,042 | - | ||||||||||||
| 2019 | - | - | 357,042 | - | ||||||||||||
| Thereafter | - | - | - | - | ||||||||||||
| Total | $ | 2,949,468 | $ | 1,905,347 | $ | 1,785,210 | $ | 3,756,872 | ||||||||
One of the Company’s subsidiaries 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.
The Company’s subsidiary, Bangor Gas, entered into an agreement with Maritimes and Northeast Pipeline for the transportation and storage of natural gas.
One of the Company’s subsidiaries has entered into long-term gas purchase agreements committing it to purchase gas through March of 2016 at a fixed spread above AECO pricing. Future commitments under these contracts have been estimated using AECO forward pricing for the periods covered by the agreements.
None of the preceding long-term contracts have been recognized on the Company’s Consolidated Balance Sheets.
Loss Contingency
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.
| F-45 |
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 a contingent liability in its financial statements for the period ended June 30, 2013. Based on the PUCO staff’s calculations and management’s assessment, the Company accrued an additional $0.9 million to establish a total liability to its customers of $1.2 million as its best estimate to resolve this matter.
On November 13, 2013, the PUCO issued an Opinion and Order related to the outstanding NEO and Orwell GCR cases; case numbers 12-209-GA-GCR and 12-212-GA-GCR. In it, the PUCO ordered adjustments to NEO and Orwell’s GCRs to disallow agent fees paid by the two companies to JDOG Marketing for natural gas procurement, disallow processing and treatment fees paid by NEO to Cobra for NEO’s natural gas supply being delivered through Cobra’s pipeline, and disallow certain excess costs associated with local production gas purchased by NEO and Orwell from JDOG Marketing. The total adjustment for the disallowance for these costs was approximately $1.0 million. Neo and Orwell ceased the inclusion of these disallowed costs in its GCR rates and their payment in the second half of 2013. Both JDOG Marketing and Cobra were companies controlled by Richard M. Osborne, father of the Company’s chief executive officer and the Company’s former chairman and chief executive officer during the periods covered by these audits.
Immediately following the release of the Opinion and Order, the Company examined NEO and Orwell’s GCRs for these disallowed cost in periods subsequent to the companies’ audit periods. As a result, the Company accrued a $0.5 million contingent liability in the fourth quarter of 2013 as its best estimate of these disallowed costs. The expense associated with this amount was partially offset by the $0.2 million over accrual of the expected audit period adjustments required by the PUCO.
In addition to the GCR adjustments called for in the November 2013 Opinion and Order, the PUCO ordered an investigative audit to be conducted of NEO, Orwell and all affiliated and related companies. These audits examined the companies’ corporate separation and management structures, internal regulatory and financial controls, compensation systems, gas purchasing transactions and practices related to GCR calculations, and financial and accounting statements filed with regulatory agencies. The audit was completed and filed with the PUCO and can be found under case number 14-0205-GA-COI. The PUCO has yet to act based on the audit report. Additionally, the Ohio Consumers’ Counsel has intervened and has requested additional documentation associated with the investigative audit. At this time, the Company cannot reasonably estimate the financial impact, if any, of any potential actions taken by the PUCO as a result of this report. Any actions taken by the PUCO as a result of this report could have a material adverse effect on the Company.
In 2014, the PUCO staff conducted an audit of NEO and Orwell’s GCR for the periods March 1, 2012 through June 30, 2014 and July 1, 2012 through June 30, 2014; case numbers 14-209-GA-GCR and 14-212-GA-GCR. These audits include the post audit periods discussed above. In addition to the disallowed costs previously identified in the November 2013 Opinion and Order, the 2014 PUCO staff report identified additional disallowed costs and errors in the GCR calculation. The Company does not agree with all of the disallowances as calculated in the PUCO staff report and intends to contest that some of these costs should be allowed as recoverable. The Company calculates that the total liability to NEO and Orwell due to its customers to be in the range of $0.2 million to $1.0 million. As a result, the Company adjusted its contingent liability to settle this mater to $0.2 million. This adjustment is included on the accompanying Consolidated Statement of Comprehensive Income for 2014 as a component of Cost of Sales – Natural gas purchased. New information may cause the Company to materially change this estimate in future periods.
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.
Richard M. Osborne Suits
On June 13, 2014, Richard M. Osborne, father of the Company’s chief executive officer and the Company’s former chairman and chief executive officer, filed a lawsuit against the Company and the Company’s corporate secretary captioned, “Richard M. Osborne and Richard M. Osborne Trust, Under Restated and Amended Trust Agreement of February 24, 2012 v. Gas Natural, Inc. et al.,” Case No. 14CV001210 which was filed in the Court of Common Pleas in Lake County, Ohio. In this lawsuit, Mr. Osborne seeks an order requiring the Company to provide him with “the minutes and any corporate resolutions for the past five years.” The Company has provided Mr. Osborne with all the board minutes he requested that have been approved by the board. On October 29, 2014, Mr. Osborne filed an amended complaint in this matter demanding minutes of the committees of the board of directors and additional board minutes which he claims he is entitled to receive. Mr. Osborne has also filed requests for discovery in this lawsuit. On November 17, 2014, the defendants moved to dismiss Mr. Osborne’s amended complaint for failure to state a claim upon which relief can be granted, and for summary judgment. On February 11, 2015, the Court granted defendants’ motion, dismissing the case except for one allegation in one paragraph of Mr. Osborne’s amended complaint: that the Company failed to produce minutes of any board meeting that occurred between June 1, 2014 and June 13, 2014. The Court held in abeyance its ruling on this issue, to give Mr. Osborne 30 days to conduct discovery limited to determining whether any board meetings occurred during that two-week period. On February 13, 2015, Mr. Osborne voluntarily dismissed his Complaint, without prejudice.
| F-46 |
On June 26, 2014, Mr. Osborne filed a lawsuit against Gas Natural and the Company’s board of directors captioned “Richard M. Osborne, Richard M. Osborne Trust, Under Restated and Amended Trust Agreement of February 24, 2012 and John D. Oil and Gas Marketing Company, LLC v. Gas Natural, Inc. et al.,” Case No. 14CV001290, filed in the Court of Common Pleas in Lake County, Ohio. In this lawsuit, among other things, Mr. Osborne (1) demanded payment of an earnout associated with Gas Natural’s purchase of assets from John D. Marketing, (2) alleged that the board of directors breached its fiduciary duties, primarily by removing Mr. Osborne as chairman of the board and chief executive officer, (3) sought injunctive relief to restrain the Company’s board members from “taking any actions on behalf of Gas Natural until they are in compliance with the law and the documents governing corporate governance,” and (4) asked the Court to enjoin the 2014 annual meeting that was scheduled to take place on July 30, 2014, and to delay it until such time that the board of directors would be “in compliance with the law and corporate governance.”
Mr. Osborne dismissed the above lawsuit on July 15, 2014, without prejudice, as the parties started to engage in settlement negotiations in an attempt to resolve the dispute. After settlement negotiations broke down, Mr. Osborne refiled the lawsuit on July 28, 2014, against Gas Natural and the Company’s board members. In the re-filed lawsuit, among other things, Mr. Osborne (1) demands payment of an earnout amount associated with Gas Natural’s purchase of assets from John D. Marketing, (2) alleges that the board of directors breached its fiduciary duties by removing Mr. Osborne as chairman and chief executive officer, (3) seeks to enforce a July 15, 2014 term sheet, where the parties memorialized certain discussions they had in connection with their efforts to resolve the dispute arising out of the lawsuit, which included a severance payment of $1.0 million, and (4) seeks to invalidate the results of the July 30, 2014 shareholder meeting and asks the court to order Gas Natural to hold a new meeting at a later date. Mr. Osborne is also seeking compensatory and punitive damages. The parties are currently conducting discovery in this lawsuit. Gas Natural believes that Mr. Osborne’s claims in this lawsuit are wholly without merit and will vigorously defend this case on all grounds.
As disclosed above, on June 26, 2014, Mr. Osborne filed a lawsuit against the Company in the Court of Common Pleas in Lake County, Ohio. In the lawsuit, Mr. Osborne sought injunctive relief delaying the 2014 annual meeting scheduled to take place on July 30, 2014. While that suit was pending, on July 9, 2014, Mr. Osborne mailed the first of several letters to the Company’s shareholders, criticizing the Company’s board and seeking the shareholders’ support in replacing them. On July 15, 2014, Mr. Osborne dismissed without prejudice his Lake County lawsuit, but he refiled it on July 28, 2014. He did not again seek to enjoin the annual shareholder meeting, which occurred as scheduled two days later. Instead, he requests in his complaint that the Lake County court void the election of directors at the July 30, 2014 meeting and order the Company to conduct another shareholder meeting for the purpose of electing directors no later than February 2015, which the Court has not done. Mr. Osborne’s refiled lawsuit remains pending. Mr. Osborne wrote two additional letters, dated August 12, 2014, and September 9, 2014, which he mailed to the Company’s shareholders in mid-September. In the letters Mr. Osborne continued to criticize the Company’s board and management.
Mr. Osborne did not file his letters with the Securities and Exchange Commission and the Company believes that his letters violated Section 14(a) of the Securities Exchange Act and related regulations that require shareholder solicitations to be filed with the SEC. On October 2, 2014, Gas Natural filed a suit against Mr. Osborne captioned “Gas Natural Inc. v. Richard M. Osborne” in the United States District Court Northern District of Ohio (Case No. 1:14-cv-2181). In this case the Company sought to enjoin Mr. Osborne from sending additional letters to the Company’s shareholders without complying with applicable Federal securities laws. The court held a hearing on October 8, 2014, and the judge granted the injunction, requiring Mr. Osborne to file with the SEC any letters he writes to shareholders so long as his action in Lake County seeking to invalidate the July 30, 2014 meeting is pending. Mr. Osborne has appealed the ruling. The Company believes his appeal is wholly without merit and will vigorously contest it.
Shareholders Suit
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 the Company’s 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). 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.
| F-47 |
The consolidated action 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 and unjust enrichment 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 former chairman and chief executive officer, and Thomas J. Smith, a director of the Company and its former chief financial officer. The suit seeks 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 and other relief.
Gas Natural and the other defendants filed a motion to dismiss the consolidated action in its entirety on May 8, 2014. The motion to dismiss was based on, among other things, the failure of the plaintiffs to make demand on Gas Natural’s board of directors to address the alleged wrongdoing prior to filing their lawsuits and the failure to state viable claims against various individual defendants. Richard Osborne, individually, is now represented by counsel independent of all other defendants in the case and submitted a filing in support of the motion to dismiss on his own behalf.
On September 24, 2014, the magistrate judge assigned to the case issued a report and recommendation in response to the motion to dismiss. The magistrate judge recommended that the plaintiffs’ claims against the individual defendants with respect to the “unjust enrichment” allegation in the complaint be dismissed. The magistrate judge recommended that all other portions of the motion to dismiss be denied. The report and recommendation, the objections filed by the defendants, and the responses from the plaintiffs will all be reviewed by the trial judge assigned to the case who will then either adopt the report and recommendation in full, reject it in full, or adopt in part and modify in part. The parties engaged in a settlement mediation on February 25, 2015. The parties failed to reach a settlement, but discussions are ongoing.
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 action. This insurance carries a $250,000 deductible, which the Company has reached. Although the Company believes these insurance proceeds are available, the Company 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 the Company’s business and results of operations.
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 he was terminated in violation of a 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 Gas Natural’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 court had asked the parties to file comprehensive statements of fact and scheduled a hearing on the motion to dismiss on July 1, 2014. On July 1, 2014, the court conducted a hearing, made extensive findings on the record, and issued an Order finding in favor of the Company and dismissing all of Mr. Harrington’s claims. On July 21, 2014, Mr. Harrington appealed the dismissal to the Montana Supreme Court where the matter is presently pending awaiting full briefing by the parties. The Company continues to believe Mr. Harrington’s claims under Montana law are without merit, and will continue to vigorously defend this case on all grounds.
Special Committee of the Board Investigation
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 has retained legal counsel and financial and regulatory advisors and is in the process of investigating and evaluating the allegations in order to determine the position Gas Natural will take with respect to the letter. Although the Company believes that insurance proceeds are available for a portion of the cost of the investigation, the Company will incur costs and expenses related to the investigation that are not covered by insurance, which may be substantial.
Note 25 – Subsequent Events
On January 14, 2015, the Company entered into an asset purchase agreement with Utility Pipeline, LTD to sell nearly all of the assets and liabilities of its Clarion and Walker subsidiaries. The Company will receive $0.9 million under the transaction. The agreement contains customary representations, warranties, covenants and indemnification provisions. The consummation of the transaction is dependent upon the satisfaction or waiver of a number of customary closing conditions, the receipt of regulatory approvals and the consent of certain of the Company’s lenders. The Company expects this transaction to be finalized in the second quarter of 2015.
| F-48 |
Exhibit |
||
| Number | Description | |
| 3.1 | Amendment to Articles of Incorporation of Gas Natural Inc., dated December 9, 2014. | |
| 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, Baker Tilly Virchow Krause, LLP | |
| 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. | |