Attached files
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| EX-21 - EXHIBIT 21 - Gas Natural Inc. | v430286_ex21.htm |
| EX-32 - EXHIBIT 32 - Gas Natural Inc. | v430286_ex32.htm |
| EX-14 - EXHIBIT 14 - Gas Natural Inc. | v430286_ex14.htm |
| EX-31.1 - EXHIBIT 31.1 - Gas Natural Inc. | v430286_ex31-1.htm |
| EX-31.2 - EXHIBIT 31.2 - Gas Natural Inc. | v430286_ex31-2.htm |
| EX-23.1 - EXHIBIT 23.1 - Gas Natural Inc. | v430286_ex23-1.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, 2015
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. ¨
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, 2015 was $97,777,406.
The number of shares outstanding of the registrant’s common stock as of March 11, 2016 was 10,507,734 shares.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive proxy statement for the 2016 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, 2015.
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.
Clarion River. Clarion River Gas Company.
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.
EWD. Energy West Development, Inc.
Energy West Montana. Energy West Montana, Inc.
EWW. 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.
Lightning Pipeline. Lightning Pipeline Company, Inc.
LNG. Liquefied Natural Gas.
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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.
NYSE. New York Stock Exchange.
NYSE MKT. NYSE MKT LLC
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.
Walker Gas. Walker Gas & Oil Company, Inc.
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Table of Contents
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Forward-Looking Statements
This Form 10-K contains forward-looking statements within the meaning of the federal securities laws. Statements that are not historical facts, including statements about our beliefs and expectations, are forward-looking statements. Forward-looking statements include statements preceded by, followed by or that include the words “may,” “could,” “would,” “should,” “believe,” “expect,” “anticipate,” “plan,” “estimate,” “target,” “project,” “intend,” or similar expressions. These statements include, among others, statements regarding our current expectations, estimates and projections about future events and financial trends affecting the financial condition and operations of our business. Forward-looking statements are only predictions and not guarantees of performance and speak only as of the date they are made. We undertake no obligation to update any forward-looking statement in light of new information or future events.
Although we believe that the expectations, estimates and projections reflected in the forward-looking statements are based on reasonable assumptions when they are made, we can give no assurance that these expectations, estimates and projections can be achieved. We believe the forward-looking statements in this Form 10-K are reasonable; however, you should not place undue reliance on any forward-looking statement, as they are based on current expectations. Future events and actual results may differ materially from those discussed in the forward-looking statements. Factors that could cause actual results to differ materially from our expectations include, but are not limited to:
| · | fluctuating energy commodity prices, |
| · | the possibility that regulators may not permit us to pass through all of our costs to our customers, |
| · | the impact of the FERC and state public service commission statutes, regulations, and actions, including allowed rates of return, and the resolution of other regulatory matters such as the pending PUCO Stipulation and Recommendation, |
| · | 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 us, |
| · | the ability to control costs, including the costs associated with the derivative suits and other actions against us, |
| · | 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 projects, including the refinancing of our credit agreements. |
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(dollars in thousands)
Energy West was originally incorporated in Montana in 1909 and was reorganized as a holding company in 2009. On July 9, 2010, we changed our name to Gas Natural Inc. and reincorporated from Montana to Ohio.
Gas Natural Inc. is a natural gas company, primarily operating local distribution companies in four states and serving approximately 67,800 customers in total. We report results in three primary business segments.
| · | Natural Gas. Representing the majority of our revenue, we annually distribute approximately 21 Bcf of natural gas to approximately 67,800 customers through regulated utilities operating in Maine, Montana, North Carolina and Ohio. Our natural gas utility subsidiaries include Bangor Gas Company (Maine), Brainard (Ohio), Cut Bank Gas (Montana), Energy West Montana (Montana), Frontier Natural Gas (North Carolina), NEO (Ohio) and Orwell (Ohio). |
| · | Marketing and Production. Annually, we market approximately 1.5 Bcf of natural gas to a regulated utility in Wyoming and to commercial and industrial customers in Montana and Ohio through our EWR and GNR subsidiaries. Our EWR subsidiary also manages midstream supply and production assets for transportation customers and utilities. EWR owns or manages for EWD, 160 natural gas producing wells and gas gathering assets located in Glacier and Toole Counties in Montana. See Note 13 – Property, Plant & Equipment in the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K for the year ended December 31, 2015 (our “Annual Report”). |
| · | Corporate and Other. Corporate and other encompasses the results of our corporate acquisitions, equity transactions and discontinued operations. Included in corporate and other are costs associated with business development and acquisitions, dividend income, recognized gains or losses from the sale of marketable securities, activity from Lone Wolfe which serves as an insurance agent for us and other businesses in the energy industry, and the results of our discontinued operations from the sales of EWW, the Shoshone and Glacier pipelines, and Independence. |
For financial information about each of our segments, see Note 19 – Segment Reporting in the Notes to the Consolidated Financial Statements in our Annual Report.
Corporate Structural Revisions and Pending Financing Agreements
In February 2016, we proposed to create a wholly-owned subsidiary under which each of our nine regulated entities will be held. This will streamline our corporate structure to facilitate greater focus on the four regulatory jurisdictions in which we operate, as well as to simplify our financing arrangements. With the new structure, which is subject to regulatory approval, the regulated entities will be segregated from non-regulated operations. We also announced that we reached an agreement with our lenders to refinance and consolidate our debt within our parent company. The long-term debt agreements include proposed issuance of up to $50,000 of senior notes, with maturities and interest rates to be determined upon closing, subject to prevailing market conditions at that time. Additionally, we will establish a $42,000 five-year revolving credit facility and finance a lease buyout of approximately $7,000 over a term of four years. Closing on the debt agreements is subject to negotiation of terms, requested regulatory approvals and other closing conditions. Upon closing, proceeds from the new debt facilities will replace our five existing loan facilities and provide additional cash for operational purposes.
Implementation of Enterprise Resource Planning System
In 2014, we began the implementation of our new ERP system. The new system should enhance our overall operations through integrating and stream-lining our business processes. We deployed this ERP system during the second half of 2015 at all except two of our subsidiaries. We expect to complete deployment and integration of the ERP system during the first half of 2016.
Sale of EWW and the Shoshone & Glacier Pipelines
On October 10, 2014, we executed a stock purchase agreement for the sale of all of the stock of our wholly owned subsidiary, EWW, to Cheyenne Light, Fuel and Power Company (“Cheyenne”). EWW has historically been included in our natural gas operations segment. In conjunction with this sale, our EWD subsidiary entered into an asset purchase agreement for the sale 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 our 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. On July 1, 2015, the transaction was completed and we received proceeds, net of costs to sell, of $14,223 for the sale of EWW and $1,185 for the sale of the Pipeline Assets. We recorded gains on the sales of $4,869 and $499 for EWW and the Pipeline Assets, respectively, in discontinued operations. See Note 4 – Discontinued Operations in the Notes to the Consolidated Financial Statements of this Annual Report for more information regarding these transactions.
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Our 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 of EWW and the Pipeline Assets and were formerly eliminated through the consolidation process.
Disposals of Other Assets
On December 11, 2015, we sold to Kentucky Frontier Gas, LLC nearly all of the assets and liabilities of our Kentucky subsidiary PGC, for proceeds of $1,900, which resulted in a loss on the transaction of $341, based on the carrying value of our assets and our costs to sell the assets.
In November 2015, we sold nearly all of the assets and liabilities of our Pennsylvania utilities, Clarion and Walker, to Utility Pipeline, LTD for proceeds of $848, which resulted in a gain on the transaction of $415.
On October 15, 2015, we sold an office building in Mentor, Ohio for net proceeds of $1,220, which resulted in a loss on the transaction of $409, based on the carrying value of the property of $1,760 and the costs to sell the property. This represents substantially all of the assets of our 8500 Station Street subsidiary.
The completion of these divestitures is part of our strategy to monetize non-core assets so that we may direct our energies and resources to operations that we believe have higher growth potential. The sale of these assets does not constitute a strategic shift that will have a major effect on our operations or financial results and, as such, the disposals are not classified as discontinued operations in our consolidated financial statements. These gains and losses related to our disposals were recorded in other income in the accompanying Consolidated Statement of Comprehensive Income for the year ended December 31, 2015. See Note 5 – Disposals in the Notes to the Consolidated Financial Statements of this Annual Report for more information regarding these transactions.
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. The audit was initiated on June 21, 2014. 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. It focused on several specific areas, including the calculation of the GCR, gas supply management and retention, internal controls within the Ohio utilities, 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. On October 30, 2015, the PUCO staff entered into a stipulation and recommendation with the Ohio utilities, which has yet to be adopted by the PUCO. We have made significant internal changes to our organization to address the issues raised in the audit report, and we have identified 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 and 2015, the United States experienced falling oil prices, and during 2015 experienced the lowest oil prices since 2008. 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.
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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 capital and resources into improvements and expansion projects at our core utilities in order to organically grow our customer count, gas volumes, market penetration and market share. Under regulation, our rates are established to yield a revenue requirement based on a allowed return on the investment in property used and useful in public service (rate base), plus reimbursement of all necessary and proper operating expenses, taxes, interest, and depreciation. Our 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. |
Our natural gas operations are located in Maine, Montana, North Carolina and Ohio. Our revenues from natural gas operations are generated under tariffs regulated by those states. Approximately 93%, 93%, and 89% of our revenue was from regulated gas distribution operations for the years ended December 31, 2015, 2014 and 2013, 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 1% of our natural gas revenue for 2015. 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.
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. 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.
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 78,000 people. Our Maine operations provide service to approximately 5,900 residential, commercial and industrial customers. We offer transportation services to approximately 62 customers through special pricing contracts. These customers accounted for approximately 14% of the revenue of our Maine operations in 2015. Our industrial customers in Maine are related to the paper industry, which has been impacted by recent declines in the distribution of paper periodicals.
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 31,400 customers.
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The primary gas supply marketers for our Montana natural gas distribution operations are Jefferson Energy Trading, LLC 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 280,000 people. Our North Carolina operations provide service to approximately 3,200 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
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 Ohio operations provide service to approximately 27,300 residential, commercial and industrial customers.
Our Ohio 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. 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, 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 1.5 Bcf of natural gas annually to a regulated utility in Wyoming and to commercial and industrial customers in Montana and Ohio 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 owns or manages for EWD, 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 us a partial natural hedge when market prices of natural gas are significantly greater than the cost of production. The gas production from these wells and assets provided approximately 22% of the volume requirements for EWR in our Montana market for the year ended December 31, 2015. These wells are relatively shallow and we have not yet explored the deeper formations on our production properties.
Our EWR subsidiary owns a 24.5% interest in Kykuit, a developer and operator of oil, gas and mineral leasehold estates located in Montana. We account for our investment in Kykuit using the equity method. We have invested approximately $2,160 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, 2015, we are obligated to invest no more than an additional $79 over the life of the venture. Other investors in Kykuit include Richard M. Osborne, our 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 ours and our former chief financial officer and a director of John D. Oil and Gas Company; and Gregory J. Osborne, our chief executive officer and member of our board of directors 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, our investment in Kykuit is completely impaired.
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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.
During 2015, we sold EWW and our Glacier and Shoshone pipelines. EWW represented all of our utility operations in Wyoming. The Glacier and 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 and 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.
See Note 4 – Discontinued Operations in the Notes to the Consolidated Financial Statements of this Annual Report for more information regarding our discontinued operations.
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 as an energy source for space and water heating.
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 | |
| 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 |
Our marketing and production operations compete principally with other natural gas marketing firms doing business in Montana, Wyoming and Ohio.
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, LLC 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 above sections captioned “Marketing and Production” and “Natural Gas Operations.”
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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 MPUC, MPSC, NCUC and the PUCO. 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 in this Annual Report.
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, revenues, 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 our 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.
Maine
Our Maine operations generate 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. It was appealed by the Office of the Public Advocate and Verso Bucksport Power and has now been heard and decided before the Maine Supreme Court. The case was decided in favor of our Maine utility, with the utility base rates remaining in place, and is now final.
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.
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Our Montana utilities’ 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 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 our margin rates until 2019. 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. See Note 10 – Regulatory Assets and Liabilities Operations in the Notes to the Consolidated Financial Statements of this Annual Report for more information.
Ohio
Our Ohio operations are regulated by the PUCO. 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 NEO’s 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.
Holding Company Organization and Ring-Fencing Measures
We are organized as a holding company 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 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 and North Carolina must meet certain notice and financial requirements prior to paying dividends, and that our Maine and North Carolina utilities, which are currently subsidiaries of Energy West, be converted to direct subsidiaries of Gas Natural upon the earlier of the expiration or refinance of Energy West’s debt, unless segregating the Maine and North Carolina operations would be detrimental to our Montana customers. In that event, Energy West would have the opportunity to request a waiver of the spin-off requirement from the MPSC.
In February 2016, we proposed to create a wholly-owned subsidiary under which each of our nine regulated entities will be held. We have submitted our proposal to the regulatory body in each of the jurisdictions in which we have regulated operations for approval. See “Recent Events - Corporate Structural Revisions and Pending Financing Agreements” for further detail.
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 Maine and North Carolina. 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. Certificates of public convenience and necessity are not required in Ohio or Montana.
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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 Maine or Ohio; 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 a 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 public 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.
Our business and that of our subsidiaries in all segments is sensitive to fluctuations in temperature. In any given period, sales volumes reflect the impact of weather, in addition to other factors. We do not have a weather normalization adjustment in our rates and, as a result, our revenue is sensitive to fluctuations in temperature. 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) and we typically experience losses in warmer months of the year, which coincide with 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.
We had a total of 206 employees as of December 31, 2015, of which 182 are full time, 186 are employed by our natural gas operations and 20 are employed by our marketing and production or corporate operations. Our natural gas operations include 15 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, and we expect to renegotiate the contracts with our unions during the second quarter of 2016. We believe that we have a good relationship with our employees and unions.
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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 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.
(dollars in thousands)
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 FERC and public utility commissions in states where we operate regulate many aspects of our distribution and transmission operations. State regulatory agencies set the rates that we may charge customers, which effectively limits the rate of return we are permitted to realize. Our ability to obtain rate increases and rate supplements to maintain the current rate of return and/or recover costs depends upon regulatory discretion. There can be no assurance that we will be able to obtain rate increases or rate supplements or continue to receive the current authorized rates of return, which could negatively impact our financial condition and results of operations. The state utility regulatory agencies also regulate our public utilities’ gas purchases, construction and maintenance of facilities, the terms of service to our customers, safety and various other aspects of our distribution operations. The 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 that could impact our earnings and cash flow.
The regulatory agencies that oversee our utility operations retrospectively review 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 would 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 the period of 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 $1,027, primarily fees paid to JDOG Marketing, and fines of $76. 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 our Ohio GCR filings, business structure, and internal controls. On October 30, 2015, the PUCO staff entered into a Stipulation and Recommendation with Brainard, NEO and Orwell. The Stipulation and Recommendation outlines various terms and conditions, primarily regarding the maintenance and implementation of additional processes and procedures for the Company’s Ohio GCR filings. The PUCO has yet to adopt, reject or comment on any actions it may take as a result of this Stipulation and Recommendation. Depending on the PUCO’s actions, we could be subject to additional civil fines, restrictions, changes or limitations to, or cessation of, existing operations in Ohio, which would adversely affect our financial condition, results of operations, cash flow and stock price.
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We currently are involved in shareholder derivative lawsuits and other related 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 actual 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. 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, 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, our former chief financial officer and a former director of ours. 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. The parties are currently engaged in discovery. A more detailed description of these lawsuits and others is contained in the section captioned Legal Proceedings in Part I, Item 3, in this Annual Report.
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 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) our financial statements and internal controls and (iv) various entities affiliated with our former chief executive officer, Richard M. Osborne. The SEC has requested we preserve all documents relating to these matters. We received a subpoena to produce documents from the staff of the SEC dated May 29, 2015, in connection with this matter. We are complying with these requests and intend to cooperate fully with the SEC.
We cannot predict the outcome of these lawsuits and the investigation or for how long they will remain active. Regardless of the outcome, the pending lawsuits, investigation, and any other related litigation, proceedings, or investigations that may be brought against us or our current or former officers and directors in the future could be time consuming, result in significant expense and divert the attention and resources of our management and other key employees from the operation of our business. Moreover, negative developments with respect to the pending lawsuits 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, our former chairman and chief executive officer, filed various lawsuits against us and certain of our officers and directors. A more detailed description of these lawsuits is contained in in the section captioned Legal Proceedings in Part I, Item 3 in this Annual Report.
The expenses related to continuing to defend litigation initiated by Richard M. 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.
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Storing and transporting natural gas involves inherent risks that could cause us to incur significant financial losses.
There are inherent hazards and operational 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. Given the impact of variable and volatile weather patterns 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, our earnings and cash flow.
The increased cost of purchasing natural gas during periods in which natural gas prices are rising significantly could adversely impact our earnings and cash flow.
The rates we are permitted to charge allow us to recover our cost of purchasing natural gas. In general, the various regulatory agencies allow us to recover the costs of natural gas purchased for customers on a dollar-for-dollar basis (in the absence of disallowances), without a profit component. We periodically adjust customer rates for increases and decreases in the cost of gas purchased by us for sale to our customers. Under the regulatory approved gas cost recovery pricing mechanisms, the gas commodity 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 uncollectible accounts receivable as a result of customer defaults on payment 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. In 2014 and 2015, the United States experienced falling oil prices, lowering the average price of residential heating oil at the end of 2015 to some of the lowest levels in four years. 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. During periods of slow or little economic growth, energy conversation efforts often increase and the amount of uncollectible customer accounts increases. In addition, our industrial customers may encounter particularized economic hardships in their industries as a result of stagnant national demand, diminishing utility for their products, bankruptcies, consolidations of operations in response to market weakness, and other structural changes. These factors may reduce our earnings and cash flow.
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Changes in the market price and transportation costs of natural gas could result in financial losses that would negatively impact our results of operations.
We are exposed to the impact of market fluctuations in the price and transportation costs of natural gas. We purchase and store gas for distribution later in the year. We enter into agreements to buy or sell physical gas at a fixed price. We also enter into natural gas commodity swap agreements as the fixed price payor. 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 bankruptcy of some energy companies, downturns in the economy, the volatility of natural gas prices in North America, public debate over climate change and the evolution of alternative energy sources, companies in regulated and unregulated energy businesses have generally been under increased scrutiny by regulators, participants in the capital markets and debt rating agencies. As a result of such disruptions in the market, our cost of borrowing may increase or access to capital markets may be adversely affected. In addition, the FASB or the SEC may enact new accounting standards that could impact the way we are required to record revenue, expenses, assets and liabilities. State utility regulatory agencies could also enact more stringent rules or standards with respect to rates, cost recovery, safety, construction, maintenance or other aspects of our operations. Further, federal, state, and local governing bodies could revise or reinterpret current laws and regulations or make changes in enforcement practices. We cannot predict or control what effect proposed regulations, events in the energy markets or other future actions of governing bodies, regulatory agencies or others in response to such events may have on our earnings or access to the capital markets.
We acquired interests in our natural gas wells by quitclaim deed and cannot guarantee that we hold clear title to our interests or that our interests will not be challenged in the future.
We have an ownership interest in 160 natural gas producing wells in Montana, which provide our marketing and production operations a partial natural hedge when market prices of natural gas are greater than the cost of production. The gas production from these wells provided approximately 22% of the volume requirements for EWR’s Montana market for 2015. We acquired our interests in the wells in 2002 and 2003 by quitclaim deed conveying interests in certain oil and gas leases for the wells. Because the sellers conveyed their interests by quitclaim, we received no warranty or representation from them that they owned their interests free and clear from adverse claims by third parties or other title defects. We have no title insurance, guaranty or warranty for our interests in the wells. Further, the wells may be subject to prior, unregistered agreements, or transfers which have not been recorded.
Accordingly, we cannot guarantee that we hold clear title to our interests or that our interests will not be challenged in the future. If our interests were challenged, expenses for curative title work, litigation or other dispute resolution mechanisms may be incurred. Loss of our interests would reduce or eliminate our production operations and reduce or eliminate the partial natural hedge that our marketing and production subsidiary currently enjoys as a result of our production capabilities. For all of these reasons, a challenge to our ownership could negatively impact our earnings, profits and results of operations.
We are subject to numerous environmental laws and regulations that may increase our cost of operations, impact our business plans and expose us to environmental liabilities.
Environmental regulations that may affect our present and future operations include regulation of air emissions, water quality, wastewater discharges, solid waste and hazardous waste. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals, and can result in increased capital expenditures and operating costs. Both public officials and private individuals may seek to enforce applicable environmental laws and regulations. We cannot predict the outcome (financial or operational) of any related litigation that may arise.
We may be a responsible party for environmental clean-up at sites identified by a regulatory body in the future. If that occurs, we cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean-up costs. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liabilities on all potentially responsible parties.
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We cannot be sure that existing environmental regulations will not be revised or that new regulations intended to protect the environment will not be adopted or become applicable to us. Revised or additional regulations that result in increased compliance costs or additional operating restrictions could have a material adverse effect on our results of operations.
We have a net deferred tax asset of $5,700 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 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 $5,700 at December 31, 2015. We may continue to depreciate approximately $81,686 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 need for a valuation allowance on our deferred tax asset 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 $5,700 net deferred tax asset over the remaining useful life of the asset. A write down in the deferred tax asset or expiration of the asset before it is utilized would adversely affect our operating results and financial position.
Failure to maintain effective internal controls in accordance with Section 404 of the Sarbanes-Oxley Act could have a material adverse effect on our business and stock price.
Section 404 of the Sarbanes-Oxley Act of 2002 contains provisions requiring us to assess the effectiveness of internal control for financial reporting, as well as attestation and reporting by independent auditors on our internal control over financial reporting in addition to 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 operations could give rise to risk in cybersecurity attacks.
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 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. Failure to integrate this new ERP system in a timely manner could disrupt our operations and significantly increase our costs. We acquired the ERP system under three lease agreements with terms extending from 30 to 36 months under which we are obligated to pay material amounts of rent. See “Contractual Obligations,” in Part II, Item 7.
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We face a variety of risks associated with acquiring and integrating new business operations.
The growth 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 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, |
| · | ascertain, prior to the consummation of an acquisition, whether we will be required to take write-downs or write-offs, or make restructuring and impairment charges or other charges, |
| · | satisfy the terms and conditions of any state or federal regulatory approvals required for an acquisition, |
| · | effectively integrate the operations of any acquired assets or businesses with our existing operations, |
| · | 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 acquire 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.
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. Our long-term ability to continue paying dividends will depend on our ability to generate commensurate earnings from our utility operations and control costs. In both 2014 and 2015, our net income per share was less than our per share dividend paid for the year.
Financial covenants contained in our credit facilities place constraints on our business and may adversely affect our growth, business, earnings, cash flow, liquidity, ability to pay dividends, 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. In addition, we are subject to the risk that we will not be able to refinance our existing indebtedness that matures in 2017 on favorable terms, if at all. There are no assurances that we will be able to refinance or otherwise repay our 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 PUCO. The application of these provisions may inhibit a non-negotiated merger or other business combination, which, in turn, could adversely affect the market price of our common stock.
The value of our common stock may decline significantly if we do not maintain our listing on the NYSE 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 our security analysts’ coverage 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 a debt service reserve accounts of $948 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 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 MPSC has imposed ring-fencing restrictions on distributions 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 15 – Stockholders’ Equity in the Notes to the Consolidated Financial Statements in this Annual Report for more information.
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 and to acquire and integrate new business operations, either of which could have a material adverse effect on our business, results of operations and financial condition.
We have entered into 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, our 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.
On October 23, 2015, we entered into a loan agreement and promissory note with NIL Funding Corporation (“NIL Funding”). Pursuant to the note and loan agreement, NIL Funding loaned us $3,000, bearing an annual interest rate of 6.95%, and a maturity date of April 20, 2016. We used the proceeds from this loan primarily for interim general corporate cash needs.
On April 6, 2015, we entered into a loan agreement and promissory note with NIL Funding. Pursuant to the note and loan agreement, NIL Funding loaned Gas Natural $5,000, bearing an annual interest rate of 7.5%, and a maturity date of October 3, 2015. On July 27, 2015, the NIL Funding credit facility was paid off and extinguished.
For more information regarding our related party transactions, see Note 18 – Related Party Transactions in the Notes to the Consolidated Financial Statements in this Annual Report.
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 260 miles of transmission and distribution lines and related metering and regulating equipment in Maine.
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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 630 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 490 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
We maintain facilities for our Ohio operations located in Cleveland, Lancaster, Mentor, Orwell and Strasburg. 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. Our Lancaster, Mentor, Orwell and Strasburg sites serve as office and service space. We own the Lancaster and Strasburg sites and we lease the Mentor and Orwell sites under long-term lease agreements. We own approximately 1,380 miles of transmission and distribution lines and related metering and regulating equipment in Ohio.
(dollars in thousands)
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. In our opinion, the outcome to these legal actions will not have a material adverse effect on our financial condition, cash flows or results of operations.
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 us 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. The parties are currently conducting discovery in this lawsuit.
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, our former chief financial officer. The suit, in which we are named as a nominal defendant, seeks the recovery of unspecified damages allegedly sustained by us, 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 M. 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. On June 4, 2015, the trial judge assigned to the case adopted in full the report and recommendation, the objections filed by the defendants, and the responses from the plaintiffs. The parties engaged in settlement mediation on February 25, 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 deductible, which we have reached. Although we believe these insurance proceeds are available, we may incur costs and expenses related to this suit that are not covered by insurance which may be substantial. Any unfavorable outcome could adversely impact our business and results of operations.
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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. 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. On August 11, 2015, the Montana Supreme Court agreed with us that Mr. Harrington’s employment was governed by Ohio law, and as such he could not take advantage of Montana’s Wrongful Discharge from Employment Act. However, the Montana Supreme Court also held the trial court erred in determining it lacked jurisdiction over the case, finding the trial court should have retained jurisdiction and applied Ohio law to Mr. Harrington’s claims. As Ohio is an “at will” state, we believe there are no claims under Ohio law and the case will ultimately be dismissed by the trial court on remand. On September 28, 2015, Mr. Harrington filed a motion to amend complaint to assert new causes of action not previously alleged including claims for misrepresentation, constructive fraud based on alleged representations, slander, and mental pain and suffering. We answered the amended complaint to preserve our defenses, we have also opposed Mr. Harrington’s motion to amend. On December 14, 2015, we filed a motion to dismiss the Montana action in its entirety on the basis that the forum is not appropriate. Our motion to dismiss is now fully briefed and is awaiting ruling by the court. We continue to believe Mr. Harrington’s claims under both Montana and Ohio law are without merit and we will continue to vigorously defend this case on all grounds.
On June 13, 2014, Richard M. Osborne, 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 sought an order requiring us to provide him with “the minutes and any corporate resolutions for the past five years.” We had provided Mr. Osborne with all the board minutes he requested that had 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 claimed he was entitled to receive. 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 April 28, 2015, Mr. Osborne refiled this lawsuit in a different court, the Cuyahoga County Court of Common Pleas, captioned “Richard M. Osborne and Richard M. Osborne Trust, Under Restated and Amended Trust Agreement of January 13, 1995 v. Gas Natural Inc., et al.,” Case No. 15CV844836. Mr. Osborne is again seeking the board minutes at issue in the previously dismissed lawsuit and minutes that have been prepared subsequently. We believe the lawsuit, like its prior iteration, is wholly without merit and will vigorously contest it. In addition, we have filed a counterclaim against Mr. Osborne seeking to have him declared a vexatious litigator. If successful, Mr. Osborne will only be able to initiate new litigation against us after receiving permission from the court in which the case would be pending. This case has been stayed, pending the results of Case No. 14CV1512, described below, which is currently pending in the Court of Common Pleas in Lake County, Ohio.
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 earn-out 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 chief executive officer, (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 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, Case No. 14CV1512, against us and our board members. In the re-filed lawsuit, among other things, Mr. Osborne (1) demands payment of an earn-out 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 $1,000, 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 have each filed motions for summary judgement which are awaiting the ruling of the court. We believe that Mr. Osborne’s claims in this lawsuit are wholly without merit and will vigorously defend this case on all grounds.
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On March 12, 2015, Cobra Pipeline Co., Ltd (“Cobra”) filed a lawsuit against us in the United States District Court for the Northern District of Ohio captioned “Cobra Pipeline Co., Ltd. v. Gas Natural Inc., et al.,” Case No. 1:15-CV-00481. Mr. Osborne owns and controls Cobra. Cobra’s complaint alleged that it uses a service to track the locations of its vehicles via GPS monitoring. Cobra alleged that we and other defendants accessed and intercepted vehicle tracking data, after we knew or should have known that our authority to do so had ended. The complaint alleged claims under the Stored Communications Act, the Wiretap Act, and various state-law claims. On September 17, 2015, the court granted defendants’ motion for summary judgment and dismissed Cobra’s complaint in its entirety. On October 19, 2015, Cobra filed its Notice of Appeal to the Sixth Circuit Court of Appeals. That appeal remains pending.
On October 29, 2015, Orwell filed a lawsuit against Richard M. Osborne in the Lake County Court of Common Pleas, captioned “Orwell National Gas Company vs. Osborne Sr., Richard M.,” Case No. 15CV001877. The complaint alleges that Richard M. Osborne, while the chairman, president and chief executive officer of Orwell, Great Plains Exploration, Inc., John D. Oil & Gas Company, and GNSC fraudulently presented demands for payment to GNSC and Orwell, claiming that payments were due for natural gas purchased from Great Plains and John D. Oil & Gas Company from January 2012 through September 2013. Richard M. Osborne ultimately obtained two checks from Orwell in the total amount of $202. Orwell’s complaint states a claim of theft and seeks liquidated damages in the amount of these checks. Mr. Osborne filed his answer to the complaint on March 10, 2016, and this matter is currently pending before the Lake County Court.
Orwell filed a complaint and motion for preliminary injunction against Ohio Rural Natural Gas Co-Op (“Ohio Rural”) and Richard M. Osborne, captioned “Orwell Natural Gas Company v. Ohio Rural Natural Gas Co-Op, et al.,” filed November 30, 2015 in the Lake County Court of Common Pleas, Case No. 15CV002063, alleging that Ohio Rural and Richard M. Osborne acted in concert to convert, for the use of their own supply, natural gas supply lines owned and operated by Orwell. The complaint alleges that on November 20, 2015, Ohio Rural and Richard M. Osborne tampered with and severed gas lines owned by Orwell on Tin Man Road in Mentor, Ohio, terminated Orwell’s service to approximately 50 independently owned businesses, and converted Orwell’s lines for their own use. The complaint states claims for conversion, unjust enrichment and civil remedy against criminal act, and seeks compensatory and liquidated damages. On December 23, 2015, Ohio Rural filed a motion to dismiss, which is currently pending before the court. Also on November 30, 2015, Orwell filed a case with the PUCO on the same grounds, captioned “In the Matter of Orwell Natural Gas Company, Brainard Gas Corporation and Northeast Ohio Natural Gas Corporations’ Request for Injunctive Relief,” Case No. 15-2015-GA-UNC, given the PUCO’s jurisdiction regarding pipeline safety issues.
In addition to the foregoing, we are involved in other proceedings before the PUCO involving entities owned or controlled by Richard M. Osborne, our former chairman, president, and chief executive officer. On or about March 12, 2015, a demand for arbitration, captioned “Orwell-Trumbull Pipeline Company, LLC v. Orwell Natural Gas Company,” Case No: 01-15-0002-9137, was filed with the American Arbitration Association by Orwell Trumbull Pipeline Company, LLC (“OTPC”) with respect to a dispute under the Natural Gas Transportation Service Agreement between it and Orwell and Brainard. OTCP claims Orwell is in breach of the exclusivity provisions in the Agreement. Orwell filed several counterclaims, including claims for breach of contract, fraud, and unjust enrichment. On March 31, 2015, Orwell filed a complaint on the same grounds with the PUCO captioned “Orwell Natural Gas Company v. Orwell-Trumbull Pipeline Company LLC”, Case Number, 15-0637-GA-CSS, which was ultimately consolidated with PUCO case numbers 15-0475-GA-CSS, and 14-1654-GA-CSS, to address issues regarding the operation of and contract rights for utilities on the Orwell Trumbull Pipeline. The PUCO held a hearing on November 3rd and 4th, 2015. The parties’ final briefs were filed on January 8, 2015, and are currently pending before the PUCO.
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Item 4. Mine Safety Disclosures.
Not applicable.
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 over the last two years.
| Year Ended 12/31/15 | High | Low | ||||||
| First Quarter | $ | 11.03 | $ | 9.35 | ||||
| Second Quarter | $ | 10.45 | $ | 9.80 | ||||
| Third Quarter | $ | 10.30 | $ | 7.01 | ||||
| Fourth Quarter | $ | 9.44 | $ | 6.50 | ||||
| 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 | ||||
Holders of Record
As of March 11, 2016, there were approximately 187 record owners of our common stock. We estimate that approximately 8,800 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. Beginning in 2015, we began making quarterly dividends and paid $0.135 per share in April, July, October and December 2015.
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. For additional information on loan covenants and restrictions contained in our debt documents, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations - Capital Sources and Liquidity, in this Annual Report.
Payment of future cash dividends, if any, and their amounts, will be dependent upon a number of factors, including those restrictions above, our earnings, financial requirements, number of shares of capital stock outstanding and other factors deemed relevant by our board of directors.
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, 2010 to December 31, 2015.
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| 2010 | 2011 | 2012 | 2013 | 2014 | 2015 | |||||||||||||||||||
| Gas Natural Inc. | $ | 100.00 | $ | 113.47 | $ | 97.66 | $ | 88.81 | $ | 128.12 | $ | 91.96 | ||||||||||||
| S&P 500 Index - Total Returns | 100.00 | 102.11 | 118.45 | 156.82 | 178.28 | 180.75 | ||||||||||||||||||
| S&P 500 Utilities Index | 100.00 | 119.92 | 121.46 | 137.51 | 177.36 | 168.77 | ||||||||||||||||||
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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 Notes to the Consolidated Financial Statements included elsewhere in this Annual Report.
| Years Ended December 31, | ||||||||||||||||||||
| ($ in thousands, except share and per share data) | 2015 | 2014 (1) | 2013 (2) | 2012 (3) | 2011 (3) | |||||||||||||||
| Revenue | $ | 112,361 | $ | 132,570 | $ | 109,400 | $ | 81,394 | $ | 86,365 | ||||||||||
| Income from continuing operations | $ | 1,169 | $ | 2,729 | $ | 5,852 | $ | 3,195 | $ | 4,065 | ||||||||||
| Income from discontinued operations | 3,519 | 1,033 | 819 | 524 | 1,305 | |||||||||||||||
| Net income | $ | 4,688 | $ | 3,762 | $ | 6,671 | $ | 3,719 | $ | 5,370 | ||||||||||
| Basic and diluted earnings per share: | ||||||||||||||||||||
| Continuing operations | $ | 0.11 | $ | 0.26 | $ | 0.63 | $ | 0.39 | $ | 0.50 | ||||||||||
| Discontinued operations | 0.34 | 0.10 | 0.08 | 0.07 | 0.16 | |||||||||||||||
| Net income per share | $ | 0.45 | $ | 0.36 | $ | 0.71 | $ | 0.46 | $ | 0.66 | ||||||||||
| Dividend declared per weighted average common share | $ | 0.54 | $ | 0.50 | $ | 0.55 | $ | 0.54 | $ | 0.54 | ||||||||||
| Weighted average shares outstanding - basic | 10,496,979 | 10,478,312 | 9,339,002 | 8,163,814 | 8,151,935 | |||||||||||||||
| Weighted average shares outstanding - diluted | 10,498,456 | 10,478,817 | 9,339,722 | 8,169,679 | 8,159,827 | |||||||||||||||
| Plant, property, & equipment, net | $ | 142,416 | $ | 142,011 | $ | 124,588 | $ | 107,413 | $ | 86,076 | ||||||||||
| Total assets | $ | 197,689 | $ | 214,004 | $ | 203,732 | $ | 174,463 | $ | 156,411 | ||||||||||
| Non-current liabilities | $ | 56,718 | $ | 56,352 | $ | 54,361 | $ | 53,426 | $ | 36,580 | ||||||||||
| Capitalization | $ | 130,198 | $ | 136,031 | $ | 137,678 | $ | 120,045 | $ | 106,117 | ||||||||||
| 1) | In 2014, due to the pending sale of EWW and the Glacier and Shoshone pipelines, we 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 the Consolidated Financial Statements included elsewhere in this Annual Report. |
| 2) | In 2013, we completed the purchase of substantially all the assets of JDOG Marketing. See Note 3 – Acquisitions to the Notes to the Consolidated Financial Statements included elsewhere in this Annual Report. |
| 3) | In 2013, we sold our Independence subsidiary. The results of operations and financial position for this subsidiary for the years presented have been reclassified to discontinued operations. See Note 4 – Discontinued Operations to the Notes to the Consolidated Financial Statements included elsewhere in this Annual Report. |
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
(dollars in thousands, except per share amounts)
This discussion should be read in conjunction with our Consolidated Financial Statements and the Notes to the Consolidated Financial Statements included elsewhere in this Annual Report. 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” included in this Annual Report.
Executive Overview
We are a natural gas company, primarily operating local distribution companies in four states and serving approximately 67,800 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) and Orwell Natural Gas Company (Ohio). 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. Approximately 93%, 93% and 89%, of our revenues in 2015, 2014 and 2013, respectively, were derived from our natural gas utility operations.
Our operations also include the marketing and production of natural gas. Our marketing and production subsidiaries are Energy West Resources (Montana and Wyoming) and Gas Natural Resources (Ohio). 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 regulated utilities, commercial and industrial customers that are the end users of the commodity. In 2015, our marketing and production subsidiaries marketed approximately 1.5 Bcf of natural gas in three states.
As part of this discussion and analysis of our operating results we refer to increases and decreases in 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. In any given period, sales volumes reflect the impact of weather, in addition to other factors. We do not have a weather normalization adjustment in our rates and as a result, our revenue is sensitive to fluctuations in temperature. Colder temperatures generally result in increased sales, while warmer temperatures generally result in reduced sales.
We recorded gains on our discontinued operations during 2015 related to the sale of EWW of $4,869 and the sale of the Pipeline Assets of $499. The following summarizes the critical events that impacted our results of continuing operations during the year ended December 31, 2015:
Gross margin decreased due to:
| · | the executed stipulation with the PUCO Staff in the second quarter of 2015, which related to the most recent gas cost recovery audits in Ohio and specified a disallowance of gas costs of $693 over amounts previously accrued, |
| · | the lower sales volumes in our Montana market caused lower gross margin in 2015, compared to 2014, |
| · | volumes used in the unbilled revenue calculation in our North Carolina market were adjusted downward $234 in 2015, compared to 2014, |
| · | an adjustment to deferred gas costs in our Clarion River and Walker Gas divisions in Ohio lowered gross margin by $184 in the third quarter of 2015, and |
| · | a partially offsetting increase in gross margin in our Maine market due to the activation of the Loring pipeline and the higher sales volumes in 2015, compared to 2014. |
Operating expenses increased as a result of the following:
| · | increases related to personnel costs of $764, legal fees of $675, depreciation, amortization and accretion of $600, and property taxes of $192 in 2015 compared to 2014, |
| · | we incurred operating expenses related to the implementation of our new ERP system, including general and administrative expense of $606, maintenance expense of $265 depreciation of $163 and interest expense of $237, and |
| · | our provision for doubtful accounts decreased by $834 in 2015 compared to 2014, offsetting the increases in operating expenses listed above. In 2014 we wrote-off of uncollectible accounts of $1,056 related to the unfavorable ruling in a large industrial customer’s Chapter 11 bankruptcy proceeding. |
In addition, we recorded a net charge to other income of $335 for our loss on the disposals of assets at our Clarion, Walker and PGC utilities, and the sale of an office building in Mentor, Ohio.
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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.
Gas Prices and Revenues
Due to the price volatility of gas and our ability to pass our cost of gas on to our customers, we believe that revenue is not a reliable metric for analyzing our results of operations from period to period. As a result solely of changes in gas prices, our revenue may materially increase or decrease, in both absolute amounts and on a percentage basis, without a comparable change in sales volumes or gross margin. We consider gross margin to be a better measure of comparative performance than revenues. However, gas prices and revenues can impact our working capital requirements; see "Operating Cash Flow" below.
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 U.S. GAAP. 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 in the Notes to the Consolidated Financial Statements included in this Annual Report for a complete list of our significant accounting policies.
Regulatory Accounting
Our accounting policies historically reflect the effects of the rate-making process. Our regulated natural gas segment continues to be cost-of-service rate regulated, and we believe the application of ASC 980 - Regulated Operations 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, 2015, our total regulatory assets were $3,992 and our total regulatory liabilities were $1,738. A write-off of our 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 Maine, Montana, North Carolina and Ohio, 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 three of the four states in which we operate, and semi-annually in the other one. In addition, all of the states in which we operate require us to submit gas procurement plans, which we closely follow. 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 our 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 we record the estimated unbilled revenue amounts as revenue and a receivable, and we reverse the prior month’s estimate. Likewise, we record associated gas costs as cost of revenue and a payable, and we reverse prior month’s estimate. 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, 2015 and 2014. A 10% change in our unbilled revenue at December 31, 2015, would have impacted our gross margin by $177.
Fair Value of Financial Instruments
We measure certain of our assets and liabilities at fair value. The fair values of marketable securities are estimated based on the 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. The fair value measure of our contingent consideration liability has significant unobservable inputs, including our weighted average cost of capital, our credit spread above the risk free rate and our forecasted future cash flows. A significant increase (decrease) in these inputs could result in a significant increase (decrease) in the fair value measure.
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 $5,700 as of December 31, 2015, related to the carryover tax basis of Frontier Utilities and Penobscot Natural Gas, which we 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 $14,676 of carryover tax basis remaining as of December 31, 2015, and will recognize potential future federal and state income tax benefits of approximately $5,700 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, we have recorded a valuation allowance of approximately $1,564 on the state deferred tax assets associated with the carryover tax basis of our subsidiaries acquired in 2007.
Management reevaluates the valuation allowance annually based on future taxable income projections and adjusts our deferred tax asset valuation allowance, if based on the weight of available evidence, it is more-likely-than not that we will realize some or all of our deferred tax assets. If the projections indicate that we are unable to use all or a portion of our net deferred tax assets, we will adjust the valuation allowance to income tax expense. Our 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, we have recorded a valuation allowance of approximately $4,913 on our state deferred tax asset associated with state net operating losses.
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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 98% of the remaining benefit in the next eight years, with 2% 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. Our impairment evaluations as of December 31, 2015, indicated that our goodwill is fully recoverable. During 2015, we sold the assets of our PGC subsidiary and recorded an impairment loss on goodwill of $284 based on the carrying value of our assets and our estimated costs to sell the assets, which is included in the computation of our loss on the sale of PGC. See Note 6– Goodwill in the Notes to the Consolidated Financial Statements included in this Annual Report.
The schedule below shows the goodwill balances allocated to our Ohio and GNR subsidiaries as well as the excess of their fair values over their carrying values as of December 31, 2015, if any:
| Enterprise | Effect on enterprise fair value of: | |||||||||||||||||||
| Enterprise | Carrying | 1% increase in weighted | 1% decline in | |||||||||||||||||
| Operating Unit | Goodwill | Fair Value | Value | average cost of capital | residual growth rate | |||||||||||||||
| Ohio subsidiaries | $ | 13,439 | $ | 62,271 | $ | 56,908 | $ | (5,450 | ) | $ | (4,400 | ) | ||||||||
| GNR subsidiary | 1,376 | 4,180 | 3,917 | (150 | ) | (100 | ) | |||||||||||||
| Cut Bank subsidiary | 1,057 | 1,717 | 1,098 | (100 | ) | (100 | ) | |||||||||||||
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 our subsidiaries, the enterprise value calculations were 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 were (1) weighted average cost of capital of 7.0-13.5%; (2) perpetuity growth rate of 2.5%; and (3) operating EBITDA forecasts. Applying significantly different assumptions or valuation methods could result in different results from these impairment tests.
Lease Commitments
Each time we enter a new lease or materially modify an existing lease we evaluate its classification as either a capital lease or an operating lease. The classification of a lease as capital or operating affects whether and how the transaction is reflected in our balance sheet, as well as our recognition of rental payments as rent or interest expense. These evaluations require us to make estimates of, among other things, the remaining useful life and residual value of leased properties, appropriate discount rates and future cash flows that may be realized from the leased properties. Incorrect assumptions or estimates may result in misclassification of our leases. Other aspects of our lease accounting policies relate to the accounting for sale-leaseback transactions, including the appropriate amortization any deferred gains or losses. Our lease accounting policies involve significant judgments based upon our experience, including judgments about current valuations and estimated useful lives. In the future we may need to revise our assessments to incorporate information which is not known at the time of our previous assessments, and such revisions could increase or decrease our depreciation expense related to properties that we lease, result in a change in classification of some of our leases or decrease the carrying values of some of our assets.
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Results of Operations
The following discussion of financial condition and results of operations should be read in conjunction with the Consolidated Financial Statements and Notes thereto and other financial information included elsewhere in this Annual Report.
Year Ended December 31, 2015, Compared with Year Ended December 31, 2014
| Year Ended December 31, | Amount Change | |||||||||||
| ($ in thousands) | 2015 | 2014 | Favorable (Unfavorable) | |||||||||
| Revenue | $ | 112,361 | $ | 132,570 | $ | (20,209 | ) | |||||
| Cost of sales | 68,126 | 87,718 | 19,592 | |||||||||
| Gross margin | 44,235 | 44,852 | (617 | ) | ||||||||
| Operating expenses | ||||||||||||
| Distribution, general and administrative | 26,226 | 24,770 | (1,456 | ) | ||||||||
| Maintenance | 1,422 | 1,225 | (197 | ) | ||||||||
| Depreciation, amortization and accretion | 7,257 | 6,657 | (600 | ) | ||||||||
| Taxes other than income | 4,119 | 3,927 | (192 | ) | ||||||||
| Provision for doubtful accounts | 278 | 1,112 | 834 | |||||||||
| Contingent consideration loss (gain) | (75 | ) | 62 | 137 | ||||||||
| Total operating expense | 39,227 | 37,753 | (1,474 | ) | ||||||||
| Operating income | 5,008 | 7,099 | (2,091 | ) | ||||||||
| Other income (expense) | 182 | 404 | (222 | ) | ||||||||
| Interest expense | (3,604 | ) | (3,226 | ) | (378 | ) | ||||||
| Income before income taxes | 1,586 | 4,277 | (2,691 | ) | ||||||||
| Income tax expense | (417 | ) | (1,548 | ) | 1,131 | |||||||
| Income from continuing operations | 1,169 | 2,729 | (1,560 | ) | ||||||||
| Discontinued operations, net of tax | 3,519 | 1,033 | 2,486 | |||||||||
| Net income | $ | 4,688 | $ | 3,762 | $ | 926 | ||||||
Discontinued operations, net of tax —The 2015 and 2014 results of our EWW subsidiary, historically included in the Natural Gas Operations segment, and the results of our pipeline operations segment have also been classified as discontinued operations as a result of a sale agreement executed on October 10, 2014. In addition, the 2015 and 2014 results of our propane operations segment have been classified as discontinued operations as a result of the sale of the assets of Independence in November 2013. See Note 4 – Discontinued Operations in the Notes to the Consolidated Financial Statements included in this Annual Report for further detail. Our income from discontinued operations, net of tax, for 2015 was $3,519 or $0.34 per share, compared to $1,033 or $0.10 per share for 2014. Income from discontinued operations, net of tax, in 2015 primarily consisted of a net gain recorded on the sale of EWW of $4,869 and the net gain for the sale of the Pipeline Assets of $499.
Income from continuing operations — Income from continuing operations for 2015 was $1,169, or $0.11 per share, compared to income from continuing operations of $2,729 or $0.26 per share for 2014. Income from continuing operations decreased by $1,560 primarily due to: 1) increases in personnel related costs of $764 that occurred because we had fewer projects under construction during 2015, and therefore capitalized less labor; 2) increased legal fees of $675 related to our ongoing legal matters; 3) increases in our expenses related to the implementation of our new ERP system, including operating expenses of $871, depreciation of $163 and interest expense of $237; 4) a charge of $693 in the second quarter of 2015 for additional disallowed gas cost beyond amounts accrued from the stipulation with the PUCO Staff in the most recent gas cost recovery audit in Ohio; and 5) an offsetting increase to revenues from the Loring pipeline, customer growth and colder weather in our Maine market. Loss from our gas marketing and production operations decreased by $1,320, primarily as a result of a decrease in bad debt expense of $834 during 2015 because during the 2014 period because our marketing operation in Montana wrote-off $1,056 of uncollectible receivables resulting from an unfavorable ruling in a large industrial customer’s Chapter 11 bankruptcy proceedings. Additionally, we experienced a decrease of $1,131 in our income tax expenses based on our income before taxes, which declined for the reasons listed above. Loss from our corporate and other segment decreased by $136, primarily as a result of a decrease in our operating expenses of $534 that occurred because distribution, general and administrative expenses that were allocated to our EWW subsidiary were reallocated to corporate in 2014 when we reclassified that subsidiary as discontinued operations.
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Revenues — Revenues decreased by $20,209 to $112,361 during 2015 compared to $132,570 during 2014. Revenue from natural gas operations decreased by $19,075 due primarily to: 1) a decrease in the price of natural gas passed through to our customers in our Ohio, North Carolina and Montana markets; 2) decreased sales volumes due to warmer weather in our Montana market; 3) a decrease of $534 related to a downward adjustment to volumes used to calculate unbilled revenue in our North Carolina market in 2015, and partially offset by; 4) increases in revenue in Maine of $1,775 and $527 for transportation services to customers and the Loring pipeline, respectively. Our Loring pipeline began transportation services in September 2014. Revenue from our marketing and production operation decreased by $1,134 due to the loss of our LNG customer to pipeline competition and significantly lower prices for volumes produced in our production operation.
Gross margin — Gross margin decreased by $617 to $44,235 for 2015 compared to $44,852 for 2014. Our natural gas operation’s margins decreased $358, due primarily to: 1) a charge of $693 recorded in the second quarter of 2015 for additional disallowed gas cost beyond amounts accrued from the PUCO Staff stipulation in the gas cost recovery audit in Ohio; 2) lower sales in our Montana market due to warmer weather; 3) volumes used in the unbilled revenue calculation in our North Carolina market were adjusted downward $234 in 2015, compared to 2014, and partially offset by; 4) increased margin from the Loring pipeline and customer growth and colder weather in our Maine market. Gross margin from our marketing & production operations decreased $259, primarily due to the loss of our LNG customer to pipeline competition and the lower prices for volumes produced in our production operation.
Operating expenses — Operating expenses increased by $1,474 to $39,227 for 2015 compared to $37,753 for the same period in 2014. Distribution, general and administrative expenses increased $1,456 primarily due an increases in personnel related costs of $764 that occurred because we had fewer projects under construction during 2015, and therefore capitalized less labor, and we experienced increased legal fees of $675. Additionally, we incurred general and administrative expenses of $248 for training related to our new ERP system and we recorded amortization of a deferred loss on the sale-leaseback transaction for our ERP system of $358. These increases in general and administrative expenses were offset by a decrease of $824 in other professional services. Depreciation and amortization expense increased by $600 primarily due to an increase in amortization expense of $245 related to our regulatory asset in Frontier and as a result of an increase of $163 related to our ERP system assets placed in service during 2015. Taxes other than income increased by $192 due to property tax increases. Provision for doubtful accounts decreased $834 during 2015 because during the 2014 period, our marketing operation in Montana wrote-off $1,056 of uncollectible receivables resulting from an unfavorable ruling in a large industrial customer’s Chapter 11 bankruptcy proceedings.
Other income (expense) — Other income (expense) decreased by $222 to $182 for 2015 compared to $404 for 2014. During 2015, changes in other income were the result of: 1) a net loss on the disposals of our Clarion, Walker, PGC and 8500 Station Street assets of $335; 2) a decrease in rental income of $156; 3) a decrease of approximately $132 in management fee income that we earned for operating natural gas facilities for third parties, and; 4) a decrease in interest income of $150 due to interest income allowed on deferred gas costs in our North Carolina market in 2014 that did not recur in 2015. These decreases in other income (expense) were partially offset by a charge in 2014 to impair our investment in Kykuit, which did not recur in 2015, and as a result in unrealized gains on our commodity swap contracts.
Interest expense — The following table presents changes in our interest expense during the years ended December 31, 2015 and 2014, respectively. Our interest expense increased in 2015, compared to 2014, as a result of the completion and implementation of our build-to-suit ERP system and the related capital lease payments, and as a result of debt issue costs related to our short term loans with NIL Funding.
| Year Ended December 31, | ||||||||||||
| 2015 | 2014 | Change | ||||||||||
| Interest related to current borrowings | $ | 603 | $ | 601 | $ | 2 | ||||||
| Interest related to long-term notes payable | 2,018 | 2,019 | (1 | ) | ||||||||
| Interest related to capital leases | 267 | 122 | 145 | |||||||||
| Amortization of debt issue costs | 656 | 420 | 236 | |||||||||
| Other | 60 | 64 | (4 | ) | ||||||||
| Total interest expense | $ | 3,604 | $ | 3,226 | $ | 378 | ||||||
Income tax expense — Income tax expense decreased by $1,131 to $417 for 2015 compared to $1,548 for 2014. The decrease is primarily due to a decrease in our income before income taxes. Our effective tax rate decreased to 38.1% for 2015 compared to 39.3% for 2014 as a result of a change in the proportion of our pre-tax income by state.
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Year Ended December 31, 2014, Compared with Year Ended December 31, 2013
| Year Ended December 31, | Amount Change | |||||||||||
| ($ 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 | 6,657 | 5,609 | (1,048 | ) | ||||||||
| Taxes other than income | 3,927 | 3,672 | (255 | ) | ||||||||
| 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 to $132,570 for 2014 compared to $109,400 for 2013. In our natural gas operation segment, the $25,820 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 from our marketing and production segment. Revenue from our LNG business decreased by $4,778 due to the loss of our LNG customer to pipeline competition in April 2014. Revenue from our western marketing operations decreased by $293 due to lower sales volumes. Offsetting these is the increase in revenue from our GNR subsidiary of $2,341 representing a full year of operations and the revenue increase from our production operation of $80.
Gross margin — Gross margin increased by $1,482 to $44,852 for 2014 compared to $43,370 for 2013. Our natural gas operations segment’s margin increased $2,700 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 and production segment decreased $1,218 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. Refer to Note 6 – Goodwill in the Notes to the Consolidated Financial Statements included in this Annual Report for further details.
Operating expenses — Operating expenses increased by $6,135 to $37,753 for the year ended December 31, 2014 compared to $31,618 for the prior year period. Distribution, general and administrative expense increased by $3,462 due to 1) increased legal fees of $1,868 stemming primarily from the legal proceedings discussed in Note 20 – Commitments and Contingencies in the Notes to the Consolidated Financial Statements included in this Annual Report; 2) an increase of $569 in consulting and auditing fees related to improving and testing our internal control environment; 3) increases in corporate payroll and benefits of $564; and 4) the write-off of $336 of construction work in progress relating to a software conversion project that has been terminated. Depreciation expense increased by $1,048 due to higher capital expenditures and the amortization of the regulatory asset by Frontier of $245. Taxes other than income increased by $255 primarily due to higher property, payroll and other taxes in our Ohio subsidiaries. The 2014 period included $1,056 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 in the Notes to the Consolidated Financial Statements included in this Annual Report for further detail. The 2014 period included a net unrealized holding loss of $62 related to the earn-out provision in the JDOG Marketing purchase, compared to a net unrealized holding gain of $1,565 in 2013. These increases were partially offset by a $726 impairment to goodwill in the 2013 period.
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Other income (expense) — Other income (expense) increased by $104 to $404 for the year ended December 31, 2014, compared to $300 for the year ended December 31, 2013. The increase was primarily due to a $184 gain on the sale of marketable securities, a decrease in acquisition expense of $265 year over year, a decrease of $309 in S-3 costs and an increase in interest income of $172. This was partially offset by a $350 loss related to the impairment of our Kykuit investment and a $151 loss on derivative assets.
Interest expense — Interest expense increased $50 to $3,226 for the year ended December 31, 2014, compared to $3,176 for the year ended December 31, 2013. This change was primarily due to an increase of $4,410 in the average outstanding principle balances on our line of credit that is almost entirely offset by a decrease of $2,472 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 to $1,548 for the year ended December 31, 2014 compared to $3,024 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 and $103, respectively. Our effective tax rate was 39.3% for 2014 and 37.5% for 2013. The 2013 period included a tax benefit of $336 related to a change in the state effective tax rates as discussed in Note 17 - Income Taxes in the Notes to the Consolidated Financial Statements included in this Annual Report.
Discontinued operations, net of tax — The 2014 and 2013 results of our EWW subsidiary, pipeline operations segment, and propane operations segment have been classified as discontinued operations. See Note 4 – Discontinued Operations in the Notes to the Consolidated Financial Statements included in this Annual Report for further information regarding this topic.
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NATURAL GAS OPERATIONS
Income Statement
| Years Ended December 31, | ||||||||||||
| ($ in thousands) | 2015 | 2014 | 2013 | |||||||||
| Natural gas operations | ||||||||||||
| Operating revenues | $ | 103,978 | $ | 123,053 | $ | 97,233 | ||||||
| Gas purchased | 60,380 | 79,097 | 55,977 | |||||||||
| Gross margin | 43,598 | 43,956 | 41,256 | |||||||||
| Operating expenses | 35,746 | 32,074 | 29,393 | |||||||||
| Operating income | 7,852 | 11,882 | 11,863 | |||||||||
| Other income | 147 | 890 | 767 | |||||||||
| Income before interest and taxes | 7,999 | 12,772 | 12,630 | |||||||||
| Interest expense | (2,782 | ) | (2,619 | ) | (2,566 | ) | ||||||
| Income before income taxes | 5,217 | 10,153 | 10,064 | |||||||||
| Income tax expense | (1,741 | ) | (3,661 | ) | (3,243 | ) | ||||||
| Net income | $ | 3,476 | $ | 6,492 | $ | 6,821 | ||||||
Operating Revenues
| Years Ended December 31, | ||||||||||||
| ($ in thousands) | 2015 | 2014 | 2013 | |||||||||
| Full service distribution revenues | ||||||||||||
| Residential | $ | 45,409 | $ | 54,355 | $ | 40,897 | ||||||
| Commercial | 43,120 | 55,481 | 43,321 | |||||||||
| Other | 153 | 82 | 81 | |||||||||
| Total full service distribution | 88,682 | 109,918 | 84,299 | |||||||||
| Transportation | 14,145 | 11,984 | 11,783 | |||||||||
| Bucksport | 1,151 | 1,151 | 1,151 | |||||||||
| Total operating revenues | $ | 103,978 | $ | 123,053 | $ | 97,233 | ||||||
Utility throughput
| Years Ended December 31, | ||||||||||||
| (in MMcf) | 2015 | 2014 | 2013 | |||||||||
| Full service distribution | ||||||||||||
| Residential | 5,094 | 5,427 | 4,645 | |||||||||
| Commercial | 4,306 | 4,909 | 4,547 | |||||||||
| Total full service | 9,400 | 10,336 | 9,192 | |||||||||
| Transportation | 10,610 | 10,444 | 11,558 | |||||||||
| Bucksport | 597 | 5,441 | 14,301 | |||||||||
| Total volumes | 20,607 | 26,221 | 35,051 | |||||||||
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Year Ended December 31, 2015, Compared with Year Ended December 31, 2014
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, | 2015 Compared to | |||||||||||||||||||
| Normal | 2015 | 2014 | Normal | 2014 | ||||||||||||||||
| Great Falls, MT | 7,520 | 6,916 | 7,882 | (8.03 | )% | (12.26 | )% | |||||||||||||
| Bangor, ME | 6,968 | 8,058 | 7,859 | 15.64 | % | 2.53 | % | |||||||||||||
| Elkin, NC | 4,720 | 3,831 | 4,459 | (18.83 | )% | (14.08 | )% | |||||||||||||
| Lancaster, OH | 5,491 | 5,281 | 6,049 | (3.82 | )% | (12.70 | )% | |||||||||||||
Revenues and Gross Margin
Revenues decreased by $19,075 to $103,978 for 2015 compared to $123,053 for 2014. This decrease is the result of the following factors:
| 1) | Revenues from our Ohio market decreased $8,046. Revenue to full service customers decreased $7,942, primarily due to lower prices paid for natural gas passed on to our customers, along with a decrease of volumes sold to full service customers of 222 MMcf due to warmer weather. |
| 2) | Revenue from our Montana market decreased $6,533 primarily caused by a volume decrease of 474 MMcf during 2015 compared to 2014, due to warmer weather in 2015. A decrease in prices paid for natural gas passed on to our customers also contributed to the decreased revenue. |
| 3) | Revenue from our North Carolina market decreased by $3,332 due to 1) the $534 decrease from the adjustment to sales volumes used in our unbilled revenue calculation in the second quarter of 2015; 2) lower prices paid for natural gas passed through to customers; and 3) a decrease in sales volumes of 192 MMcf due to warmer weather. |
| 4) | We sold our PGC assets during 2015, and revenue from our Kentucky market where PGC operated decreased $466 during 2015 compared to 2014. |
| 5) | Revenue from our Maine market decreased $698. The decrease from 2014 is due to price decreases and a volume decrease of 59 MMcf, or $3,000 from full service customers. This decrease was offset by an increase of $1,775 for transportation services to customers and an increase in revenue of $527 from the Loring pipeline, which began transportation services in September 2014. |
Gas purchases decreased by $18,717 to $60,380 for 2015, compared to $79,097 for 2014. This decrease is primarily due to lower gas costs passed through to customers in our Ohio, North Carolina and Montana markets as well as decreases in sales volumes in our Montana markets. In addition to lower gas costs, the following items impacted our 2015 gas purchases: 1) in the second quarter of 2015, we recorded $693 for additional disallowed gas costs over amounts previously accrued from the PUCO Staff stipulation in the gas cost recovery audit in Ohio, and 2) in the third quarter of 2015, we recorded a $184 adjustment to gas costs in our Clarion River and Walker Gas divisions. Our gas costs are passed on dollar for dollar to our customers under tariffs regulated by the various 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 decreased by $358 to $43,598 for 2015 compared to $43,956 for 2014. Gross margin in our Ohio market decreased by $546, as a result of an adjustment for $693 of additional disallowed gas cost in the second quarter of 2015. Gross margin in our Montana markets decreased by $352 due to lower sales volumes caused by warmer weather. Gross margin in our North Carolina market decreased by $442 due to the $234 adjustment in the second quarter of 2015 to decrease the lower volumes used in the unbilled revenue calculation and as a result of lower sales volumes noted above. Kentucky decreased gross margin by $179. Partially offsetting these, gross margin in our Maine market increased by $1,161 due to the startup of the Loring pipeline and more favorable pricing arrangements.
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Earnings
The natural gas operations segment’s net income for 2015 was $3,476 or $0.33 per share, compared to earnings of $6,492, or $0.62 per share for 2014.
Operating expenses increased by $3,672 to $35,746 for 2015 compared to $32,074 for 2014. Distribution, general and administrative expenses increased by $2,576 due to: 1) increases in personnel related expenses of $1,029 that occurred because we had fewer projects under construction during 2015, and therefore capitalized less labor; and 2) increases in expenses of $248 for training related to our new ERP system and we recorded amortization of a deferred loss on the sale-leaseback transaction for our ERP system of $354. Depreciation and amortization expense increased by $699, of which $245 was a result of increased amortization of a regulatory asset at Frontier and $161 was a result of our ERP system placed in service during 2015. Taxes other than income increased by $206 due to increased property taxes. Increases in our depreciation and property taxes are a result of additions to our plant, property and equipment during 2014 and 2015.
Other income decreased by $743 to $147 for 2015 compared to $890 for 2014. We experienced a decrease in rental income of $156, a decrease of approximately $132 in management fee income that we earned for operating natural gas facilities for third parties, and interest income decreased by $150 due to interest income allowed on deferred gas costs in our North Carolina market in 2014 that did not recur in 2015.
Income tax expense decreased by $1,920 to $1,741 for 2015 compared to $3,661 for 2014, primarily due to the decrease in pre-tax income in 2015 compared to the 2014 period.
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 to $123,053 for the year ended December 31, 2014, compared to $97,233 for the same period in 2013. This increase is the result of the following factors:
| 1) | Revenue from our Montana market increased $4,740 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 by $6,240. Revenue from full service customers increased $6,011 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 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 of additional revenue. |
| 4) | Revenue from our Kentucky markets increased $311 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. |
| 33 |
Gas purchased increased by $23,120 to $79,097 for the year ended December 31, 2014, compared to $55,977 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) to the accrual contained in the 2013 disallowance amount, offset by additional disallowed gas costs in 2014 of $987 for a net charge of $686. Included in the 2013 results is a charge of $1,502 for the disallowance of gas costs resulting from a previous gas cost recovery audit by the PUCO.
Gross margin increased by $2,700 to $43,956 for the year ended December 31, 2014, compared to $41,256 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 of the increase, Maine and North Carolina for $862, and Kentucky for $131. These increases in margin were offset partially by a decrease in margin in our Montana natural gas operations of $481.
Earnings
The natural gas operations segment’s income for the year ended December 31, 2014, was $6,492, or $0.62 per share, compared to $6,821, or $0.73 per share for the year ended December 31, 2013.
Operating expenses increased by $2,681 to $32,074 for 2014, compared to $29,393 for 2013. Distribution, general and administrative expenses increased by $1,326 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. Depreciation expense increased $989 due to the increased capital expenditures and the amortization of the regulatory asset in Frontier of $245. Other taxes increased $279 due primarily to increased property and payroll taxes in our Ohio subsidiaries.
Other income increased by $123 to $890 for 2014 compared to $767 for 2013. Interest income increased by $176 primarily due to interest income allowed on deferred gas costs in our North Carolina market. Gains on disposal of property decreased $39 for 2014 compared to 2013. Income from service sales in 2014 decreased by $62 compared to 2013. Additionally, we had no acquisition related costs in 2014, compared to $47 related to the purchase of an office building asset in 2013.
Interest expense increased by $53 to $2,619 for 2014 compared to $2,566 for 2013. This increase was primarily due to increased borrowing on the line of credit resulting in $134 of additional interest expense and $51 of 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 less interest. In addition, decreased principal balances on our debt and capital lease obligation resulted in $15 and $38 less interest, respectively, compared to 2013.
Income tax expense increased by $418 to $3,661 for 2014 compared to $3,243 for 2013 due primarily to the increase in pre-tax income. Both 2014 and 2013 included a true-up of the prior year’s tax return for a benefit of $75 and $95, respectively. The 2013 period included a tax benefit related to a change in the state effective tax rates as discussed in Note 17 – Income Taxes in the Notes to the Consolidated Financial Statements included in this Annual Report.
| 34 |
Marketing & Production
Income Statement
| Years Ended December 31, | ||||||||||||
| ($ in thousands) | 2015 | 2014 | 2013 | |||||||||
| Marketing and production | ||||||||||||
| Operating revenues | $ | 8,383 | $ | 9,517 | $ | 12,167 | ||||||
| Gas purchased | 7,746 | 8,621 | 10,053 | |||||||||
| Gross margin | 637 | 896 | 2,114 | |||||||||
| Operating expenses | 814 | 2,478 | 501 | |||||||||
| Operating income (loss) | (177 | ) | (1,582 | ) | 1,613 | |||||||
| Other income (loss) | 103 | (502 | ) | 151 | ||||||||
| Income (loss) before interest and taxes | (74 | ) | (2,084 | ) | 1,764 | |||||||
| Interest expense | (135 | ) | (121 | ) | (142 | ) | ||||||
| Income (loss) before income taxes | (209 | ) | (2,205 | ) | 1,622 | |||||||
| Income tax benefit (expense) | 96 | 772 | (586 | ) | ||||||||
| Net income (loss) | $ | (113 | ) | $ | (1,433 | ) | $ | 1,036 | ||||
Year Ended December 31, 2015, Compared with Year Ended December 31, 2014
Revenues and Gross Margin
Revenues decreased by $1,134 to $8,383 for 2015 compared to $9,517 for 2014. Revenue from our LNG business decreased by $1,389 due to the loss of our LNG customer to pipeline competition in 2014. Our GNR subsidiary contributed revenue of $3,222, which is a decrease of $1,067 from 2014 due primarily to lower prices charged to customers. Revenue from our production operation decreased by $501 due to significantly lower prices for volumes produced. Offsetting these is an increase in revenue from our EWR marketing operation by $1,823 due primarily to the sales of gas to EWW after that entity was sold to Cheyenne.
Gross margin decreased by $259 to $637 for 2015 compared to $896 for 2014. Gross margin from our LNG business decreased by $213 as a result of the loss of our LNG customer. Gross margin from our EWR production operation decreased by $180 due the lower prices on volumes produced. Gross margin on EWR marketing operations increased by $69 due to higher margins per unit on volumes sold.
Earnings
The marketing and production segment’s loss for 2015 was $113, or $0.01 per share, compared to a loss of $1,433, or $0.14 per share for 2014.
Operating expenses decreased by $1,664 to $814 for 2015 compared to $2,478 for 2014. Our professional fees expenses declined by $261 during 2015, as compared to 2014. Additionally, during 2014, we wrote off $1,056 in uncollectible accounts expense resulting from an unfavorable ruling in a large industrial customer’s Chapter 11 bankruptcy proceedings.
Other income (expense) increased by $605 to income of $103 for 2015 compared to expense of $502 for 2014, because in 2014 we impaired our investment in Kykuit, which did not recur in 2015, and as a result of an increase in unrealized gains on our commodity swap contracts.
Income tax benefit decreased by $676 to $96 for 2015 compared to $772 for 2014, primarily due to the increase in pre-tax income in 2015, compared to 2014.
| 35 |
Year Ended December 31, 2014, Compared with Year Ended December 31, 2013
Revenues and Gross Margin
Revenues decreased by $2,650 to $9,517 for 2014 compared to $12,167 for 2013. Revenue from our LNG business decreased by $4,778 due to the loss of our LNG customer to pipeline competition in 2014. Revenues from our existing gas marketing operation decreased by $294, due primarily to lower sales volumes. Offsetting these, our GNR subsidiary’s revenue increased by $2,342 as a result of its first full year in operation and revenue from our production operation increased by $80.
Gross margin decreased by $1,218 to $896 for 2014 compared to $2,114 for 2013. Gross margin from our gas marketing operation decreased by $630 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 and GNR’s margin decreased by $250 in 2014 due to the loss NEO and Orwell as customers. Refer to Note 6 – Goodwill in the Notes to the Consolidated Financial Statements included in this Annual Report for further details. Margin from our production operation decreased by $9.
Earnings
The marketing and production segment’s loss for the year ended December 31, 2014 was $1,433, or $0.14 per share, compared to income of $1,036, or $0.12 per share for the year ended December 31, 2013.
Operating expenses increased by $1,977 to $2,478 for 2014, compared to $501 for 2013. Our GNR subsidiary was responsible for $1,053 of increased expenses in 2014, compared to 2013. The 2014 period included a full year of operating results, compared to seven months of 2013. The year ended December 31, 2013, included an unrealized holding gain on the contingent consideration liability of $1,565, partially offset by a goodwill impairment expense of $726. Expenses from our existing western marketing and production operations increased by $925 due primarily to the increase in bad debt expense of $1,056, resulting from a ruling against us in a large industrial customer’s Chapter 11 bankruptcy proceedings. See Note 2 - Significant Accounting Policies – Receivables in the Notes to the Consolidated Financial Statements included in this Annual Report for further detail.
Other income decreased by $653 to a loss of $502 for 2014, compared to income of $151 for 2013. During 2014, we recorded an expense of $350 related to the impairment of our investment in Kykuit. See Note 7 - Investment in Unconsolidated Affiliate in the Notes to the Consolidated Financial Statements included in this Annual Report. During 2014, we also recorded a mark to market loss of $151 related to natural gas swap contracts and the 2013 period includes a gain on the sale of compressed natural gas equipment of $154.
Interest expense decreased by $21 to an expense of $121 for 2014 compared to expense of $142 for 2013.
Income tax expense decreased by $1,358 to a benefit of $772 for 2014 compared to expense of $586 for the same period in 2013. Both 2014 and 2013 each included a tax benefit from the true-up to the prior year's tax return of $8 and $6 respectively, accounting for a decrease in expense of $2. The remaining decrease is due primarily to the decrease in pre-tax income.
| 36 |
Corporate & Other
Our corporate and other reporting segment is intended primarily to encompass the results of corporate acquisitions, other equity transactions, and certain other income and expense items associated with our holding company functions as well as the results of our discontinued operations. Therefore, it does not have standard revenues, gas purchase costs, or gross margin.
Income Statement
| Years Ended December 31, | ||||||||||||
| ($ in thousands) | 2015 | 2014 | 2013 | |||||||||
| Corporate and other | ||||||||||||
| Operating revenues | $ | - | $ | - | $ | - | ||||||
| Gas purchased | - | - | - | |||||||||
| Gross Margin | - | - | - | |||||||||
| Operating expenses | 2,667 | 3,201 | 1,724 | |||||||||
| Operating loss | (2,667 | ) | (3,201 | ) | (1,724 | ) | ||||||
| Other income (expense) | (68 | ) | 16 | (618 | ) | |||||||
| Loss before interest and taxes | (2,735 | ) | (3,185 | ) | (2,342 | ) | ||||||
| Interest expense | (687 | ) | (486 | ) | (468 | ) | ||||||
| Loss before income taxes | (3,422 | ) | (3,671 | ) | (2,810 | ) | ||||||
| Income tax benefit | 1,228 | 1,341 | 805 | |||||||||
| Loss from continuing operations | (2,194 | ) | (2,330 | ) | (2,005 | ) | ||||||
| Discontinued operations, net of tax | 3,519 | 1,033 | 819 | |||||||||
| Net income (loss) | $ | 1,325 | $ | (1,297 | ) | $ | (1,186 | ) | ||||
Years Ended December 31, 2015, 2014 and 2013
Results of our corporate and other segment for the year ended December 31, 2015, include administrative costs of $2,667, interest expense of $687, corporate expenses of $68, offset by an income tax benefit of $1,228, for a loss from continuing operations of $2,194, or $0.21 per share. Loss from our corporate and other segment from continuing operations decreased by $136, primarily as a result of a decrease in our operating expenses of $534 that occurred because distribution, general and administrative expenses that were allocated to our EWW subsidiary were reallocated to corporate in 2014 when we reclassified that subsidiary as discontinued operations.
Results of our corporate and other segment for the year ended December 31, 2014, include administrative costs of $3,201, interest expense of $486, a gain on marketable securities of $184, acquisition related costs of $7, corporate expenses of $171, offset by an income tax benefit of $1,341, and interest and other income of $10, for a loss from continuing operations of $2,330, or $0.22 per share.
Results of corporate and other operations for the year ended December 31, 2013, include administrative costs of $1,724, acquisition related costs of $225, costs related to expenses for our former chief executive officer’s stock sale of $309, corporate expenses of $98, interest expense of $468, offset by an income tax benefit of $805, and interest and other income of $14, for a loss from continuing operations of $2,005, or $0.21 per share.
Discontinued Operations
As a result of the sale of our Independence subsidiary in 2013 and the sale of our EWW subsidiary and Glacier & Shoshone pipelines in 2015, the results of the operations for these items have been reclassified to discontinued operations in our corporate and other operating segment. See Note 4 – Discontinued Operations in the Notes to the Consolidated Financial Statements included in this Annual Report for more information regarding these sales.
| 37 |
RELATED PARTY TRANSACTIONS
In the ordinary course of operations, we incur expenses for natural gas purchases, general and administrative expenses, and pipeline construction purchases from companies owned or controlled by Richard M. Osborne, our former chairman and chief executive officer. For more information, see Note 18 – Related Party Transactions in the Notes to the Consolidated Financial Statements included in this Annual Report for more information regarding all of our related party transactions.
Capital Sources and Liquidity
Our principal liquidity requirements are to meet our operating and financing expenses and to fund our capital expenditures and working capital requirements. Our principal sources of liquidity to meet these requirements are:
| · | our cash balance; |
| · | our operating cash flow; |
| · | our revolving credit facility; |
| · | our potential to borrow from related parties, as further described below under the heading “Financing Cash Flow”; |
| · | our potential to issue debt and equity securities; and |
| · | our potential to finance or sell assets we own. |
We believe that the primary risks we currently face with respect to our operating cash flow are:
| · | our ability to refinance our credit facility that matures in April 2017; |
| · | decreased demand for our natural gas as a result of competition in our markets; |
| · | the negative impact on our working capital requirements of volatile natural gas prices and the potential for natural gas prices to increase; |
| · | decreased demand for natural gas used for heating as a result of warmer than average temperatures; and |
| · | decreased demand for natural gas used for heating as a result of increased energy efficiency in new homes and appliances. |
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, 2015 and 2014, we had approximately $2,728 and $1,586 of cash on hand, respectively. The results of our EWW and Independence subsidiaries and Glacier & Shoshone pipeline operations are presented separately as discontinued operations. We do not expect the disposition of these subsidiaries and assets to have a material negative impact on our liquidity.
Our ability to maintain liquidity depends upon our revolving line of credit with Bank of America, N.A. ("Bank of America"), which had a balance of $15,750 and $28,761 at December 31, 2015 and 2014, respectively. The decrease in the balance of our revolving line of credit is primarily a result of our cash proceeds from the sale of EWW and the Pipeline Assets, as well as decreased capital expenditures in 2015, as compared to 2014.
During 2015, we entered into two short term loan agreements with NIL Funding. On October 23, 2015, we entered into a loan agreement and promissory note for $3,000 with NIL Funding. Under the note and loan agreement, we make monthly interest payments to NIL Funding and the principal balance of the note is due upon maturity. We made a principal payment of $1,000 on the note during December 2015. On April 6, 2015, we entered into a $5,000 loan agreement and promissory note with NIL Funding that had a maturity date of October 3, 2015. On July 27, 2015, the NIL Funding credit facility was paid off and extinguished. NIL Funding is a related party of ours. See Note 18 – Related Party Transactions in the Notes to the Consolidated Financial Statements in this Annual Report for more information regarding our related party transactions.
We made capital expenditures of $9,567, $21,613 and $23,517 for 2015, 2014, and 2013 respectively. We finance our capital expenditures by the use of our operating cash flow and our Bank of America revolving line of credit. Long-term debt was $39,721 and $40,263 at December 31, 2015 and 2014, respectively, including the amounts due within one year.
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| For the Years Ended December 31, | ||||||||||||
| 2015 | 2014 | 2013 | ||||||||||
| Cash Flows from Continuing Operations | ||||||||||||
| Cash provided by operating activities | $ | 9,424 | $ | 11,146 | $ | 15,439 | ||||||
| Cash used in investing activities | (4,195 | ) | (18,679 | ) | (20,192 | ) | ||||||
| Cash provided by (used in) financing activities | (19,303 | ) | (5,003 | ) | 12,485 | |||||||
| Increase (decrease) in cash | $ | (14,074 | ) | $ | (12,536 | ) | $ | 7,732 | ||||
| Cash Flows from Discontinued Operations | ||||||||||||
| Cash provided by operating activities | $ | 845 | $ | 1,924 | $ | 658 | ||||||
| Cash provided by (used in) investing activities | 14,371 | (511 | ) | 1,738 | ||||||||
| Cash used in financing activities | - | (32 | ) | (590 | ) | |||||||
| Increase in cash | $ | 15,216 | $ | 1,381 | $ | 1,806 | ||||||
Operating Cash Flow
Cash provided by operating activities was $9,424, $11,146 and $15,439 for the years ended December 31, 2015, 2014 and 2013, respectively. Cash provided by operating activities decreased during the year ended December 31, 2015, as compared to the prior year primarily as a result of decreases in the price of natural gas and lower sales volumes, which caused a $6,482 decrease in cash outflows from accounts payable as a result of less accounts payable outstanding at the end of 2015, compared to 2014, partially offset by a $2,184 increase in cash received from accounts receivable and $1,697 increase in cash received from natural gas and propane inventory as a result of lower balances outstanding at the end of 2015, compared to 2014. 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 $3,123, a $2,977 increase in our net regulatory assets and liabilities, a $2,528 decrease in unbilled revenue, a $1,458 increase in payments of other liabilities, a $1,296 increase in accounts receivable collections, a $1,294 increase in accounts payable payments, and a $1,100 increase in prepayments.
Investing Cash Flow
Cash used in investing activities was $4,195, $18,679 and $20,192 for the years ended December 31, 2015, 2014 and 2013, respectively. The changes in our cash used in investing activities was driven primarily by our cash used for capital expenditures and partially offset by cash provided by contributions in aid of construction.
Capital Expenditures
Our capital expenditures totaled $9,567, $21,613 and $23,517 for the years ended December 31, 2015, 2014 and 2013, 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 2015 and 2014 included $1,482 and $948 in capital expenditures related to our new ERP system that were not financed under a lease agreement. Additionally, in 2013 we purchased an office building in Mentor, Ohio for $1,853, which amount is included in our capital expenditures.
The table below presents our capital expenditures for the years ended December 31, 2015, 2014 and 2013, and provides our estimate of cash requirements for capital expenditures for the year ended December 31, 2016:
| ($ in thousands) | Years Ended December 31, | |||||||||||
| 2015 | 2014 | 2013 | ||||||||||
| Natural gas operations | $ | 9,383 | $ | 21,531 | $ | 23,242 | ||||||
| Marketing & production | 3 | 60 | 217 | |||||||||
| Corporate & other | 181 | 22 | 58 | |||||||||
| Total capital expenditures | $ | 9,567 | $ | 21,613 | $ | 23,517 | ||||||
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We have budgeted for $4,707 of capital expenditures in 2016 in our natural gas operations segment, which 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 years ended December 31, 2015 and 2014, was $19,303 and $5,003, respectively. Cash provided by financing activities was $12,485 for the year ended December 31, 2013. Major items affecting financing cash flows for the year ended December 31, 2015 from the year ended December 31, 2014 include: a net increase of $17,242 in the repayment of our line of credit, a net increase in borrowings from notes payable of $4,921, and an increase of $1,667 in payments of capital lease obligations. Major items affecting financing cash flows for the year ended December 31, 2014 from the year ended December 31, 2013 include: a $16,721 decrease in proceeds from the issuance of common shares, a $3,561 net increase in proceeds from the line of credit, a $2,830 net increase in the repayment of our notes payable, a $653 increase in payments of dividends, and $617 decrease in the release of restricted cash balances.
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. 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. Our ability to maintain liquidity depends upon our revolving line of credit with Bank of America, which had a balance of $15,750 and $28,761 at December 31, 2015 and 2014, respectively. Additionally, at December 31, 2015, we had a short-term note payable with a principal balance of $2,000 with NIL Funding. The weighted average interest rate on our outstanding short term borrowings during the years ended December 31, 2015, 2014 and 2013, was 2.95%, 2.45%, and 2.42%, respectively, and the weighted average interest rate on our current borrowings outstanding as of December 31, 2015 and 2014, was 2.71% and 2.44%, 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 $39,721 and $40,263 at December 31, 2015 and 2014, respectively, including the amounts due within one year.
Bank of America Credit Agreement and Line of Credit
Our Energy West subsidiary has a credit facility with the Bank of America (“Credit Facility”) that provides for a revolving credit facility with a maximum borrowing capacity of $30,000, due April 1, 2017. On November 26, 2014, we entered into an amendment temporarily increasing the borrowing capacity by $10,000 to a maximum of $40,000 until July 1, 2015, and the additional capacity was repaid prior to that date. The MPSC restricted draws on the line of credit to only Energy West and its subsidiary companies. This revolving credit facility includes an annual commitment fee ranging from 25 to 45 basis points of the unused portion of the facility and accrues interest based on our option of two indices - a base rate, which is defined as a daily rate based on the highest of the prime rate, the Federal Funds Rate plus 50 basis points or the daily LIBOR rate plus 100 basis points, or LIBOR plus 175 to 225 basis points. At December 31, 2015, we did not have any base rate borrowings.
Our average borrowings under the revolving credit facility during the years ended December 31, 2015 and 2014, were $19,838 and $23,397, respectively. The maximum borrowings were $30,911 and $31,061 during the years ended December 31, 2015 and 2014, respectively, which balances occurred during the first and fourth quarters of the year, respectively. The minimum borrowings were $15,750 and $19,061 during the years ended December 31, 2015 and 2014, respectively, which balances occurred during the third and second quarters of the year, respectively. Total borrowings under the revolving credit facility were $15,750 and $28,761, and bore interest at a weighted average outstanding rate of 2.17% and 2.44%, at December 31, 2015 and 2014, respectively. After considering outstanding letters of credit of $155, a total of $14,095 was available to us for loans and letters of credit under the revolving credit facility as of December 31, 2015.
In addition, Energy West has a $10,000 term loan with Bank of America with a maturity date of April 1, 2017 (the "Term Loan"). The Term Loan portion of the Credit Facility bears interest at a rate of LIBOR plus 175 to 225 basis points and contains an interest rate swap provision that allows for the interest rate to be fixed in the future, but we have not exercised that provision. The Term Loan amortizes at a rate of $125 per quarter. At December 31, 2015 and 2014, the Term Loan bore interest at 2.17%, and had a balance of $8,375 and $8,875, respectively.
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.
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The credit facility restricts Energy West’s ability to pay dividends and make distributions, redemptions and repurchases of stock during the preceding 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.
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, (iii) certain indebtedness of Energy West’s subsidiaries, (iv) certain subordinated indebtedness, (v) certain hedging obligations and (vi) other indebtedness not to exceed $1,000.
NIL Funding
On October 23, 2015, we entered into a loan agreement and promissory note for $3,000 with NIL Funding. The note bears interest at an annual rate of 6.95% and matures on April 20, 2016. Under the note and loan agreement, we make monthly interest payments to NIL Funding and the principal balance of the note is due upon maturity. We made a principal payment of $1,000 on the note during December 2015. Our loan agreement with NIL Funding restricts our ability to incur additional borrowings, make new investments, consummate a merger or acquisition and dispose of assets. In an event of default, as defined under the loan agreement, NIL Funding may, at its option, require us to immediately pay the outstanding principal balance of the note as well as any and all interest and other payments due or convert any part of the amounts due and unpaid to shares of our common stock at a conversion price of 95% of the previous day’s closing price on the NYSE MKT. NIL Funding is a related party of ours. See Note 18 – Related Party Transactions in the Notes to the Consolidated Financial Statements in this Annual Report for more information regarding our related party transactions.
On April 6, 2015, we entered into a loan agreement and promissory note with NIL Funding. Pursuant to the note and loan agreement, NIL Funding loaned Gas Natural $5,000, bearing an annual interest rate of 7.5%, and a maturity date of October 3, 2015. On July 27, 2015, the NIL Funding credit facility was paid off and extinguished.
Senior Unsecured Notes of Energy West
On June 29, 2007, Energy West authorized the sale of $13,000 aggregate principal amount of its 6.16% Senior Unsecured Notes with Allstate/CUNA, due June 29, 2017. In connection with our sale of EWW and the Pipeline Assets, during the fourth quarter of 2015 we committed to repay the portion of notes payable to Allstate/CUNA that was allocated to EWW and EWD on February 12, 2016, including a prepayment penalty of $310. Additionally, we wrote off the unamortized debt issue costs that were allocated to EWW and EWD’s portion of the debt, totaling $103. These amounts were recognized within discontinued operations, net of tax on our Consolidated Statements of Comprehensive Income. See Note 4 – Discontinued Operations in the Notes to the Consolidated Financial Statements in this Annual Report for more information regarding our discontinued operations.
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 MPSC 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 $10,000.
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Sun Life Assurance Company of Canada
On May 2, 2011, we and our Ohio subsidiaries, NEO, Orwell and Brainard, issued a $15,334, 5.38% Senior Secured Guaranteed Fixed Rate Note due June 1, 2017 ("Fixed Rate Note"). Additionally, Great Plains issued a $3,000, Senior Secured Guaranteed Floating Rate Note that was repaid on May 3, 2014. Payments for these notes prior to maturity are interest-only.
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.
The Fixed Rate Note is a joint obligation of our holding company and our Ohio subsidiaries, and is guaranteed by Gas Natural Inc., Lightning Pipeline and Great Plains (together with the Ohio subsidiaries, the “Obligors”). Prepayment of this note prior to maturity is subject to a 50 basis point make-whole premium. This note received approval from the PUCO on March 30, 2011. The note is governed by a note purchase agreement. Under the note purchase agreement, we are required to make monthly interest payments and the principal is due at maturity.
On October 24, 2012, Orwell, NEO, and Brainard issued a Senior Secured Guaranteed Note (“Senior Note”) in the amount of $2,990. 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 our non-regulated Ohio subsidiaries.
The Sun Life covenants restrict certain cash balances and requires a debt service reserve account to be maintained to cover approximately one year of interest payments. The total balance in the debt service reserve accounts was $948 at December 31, 2015 and 2014, and is included in restricted cash on our Consolidated Balance Sheets. The debt service reserve account cannot be used for operating cash needs.
The Fixed 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.
The Fixed Rate Note requires 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 us and all of our subsidiaries, on a consolidated basis. The note generally defines 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 U.S. GAAP, but excluding any extraordinary non-operating income or loss and any gain or loss from non-operating transactions. The notes also require that we do 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 us and all of our subsidiaries.
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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 and NCUC. One of the ring fencing provisions issued by the MPSC requires that of the $30,000 line of credit available, $11,200 must be used or available to be used exclusively by Energy West Montana. The remaining $18,800 balance of the line of credit is available for use by Energy West and its other Montana, North Carolina and Maine subsidiaries. Energy West and Energy West Montana are required to provide monthly financial reports to the MPSC. We continue to monitor our compliance under these ring fencing provisions on a monthly basis. As of December 31, 2015, we had available $9,168 to be drawn on the Bank of America line of credit after giving effect to the $11,200 allocation to Energy West Montana.
On November 24, 2014, the MPSC issued an order directing, in part, that Energy West require Gas Natural to repay an intercompany payable to Energy West by December 24, 2014. In addition, the MPSC order restricted Energy West and its Montana, Maine, and North Carolina operating subsidiaries from paying dividends to Gas Natural until persuasive evidence could be presented that Energy West was on a sound financial footing and that effect had been given to the MPSC’s ring-fencing conditions; the strongest indication being the absence of ongoing balances owed to Energy West by Gas Natural. On April 9, 2015, Energy West filed a request to reinstate Energy West and its Montana, Maine, and North Carolina operating subsidiaries ability to pay dividends to Gas Natural. On July 22, 2015, the MPSC issued an order allowing for the reinstatement of the dividends. They also approved a special dividend to be declared from the proceeds from the sale of Energy West’s subsidiaries EWW and Pipeline assets.
Ring fencing provisions also subject us to certain restrictions on our capital structure. The MPSC requires Energy West to maintain a debt to equity ratio of no more than 52%. The total restricted net assets of our consolidated subsidiaries related to debt covenants and the ring fencing is $76,233, or 79.8% of our net assets of $95,489 as of December 31, 2015. We believe we are in compliance with all ring fencing provisions.
Corporate Structural Revisions and Pending Financing Agreements
In February 2016, we proposed to create a wholly-owned subsidiary under which each of our nine regulated entities will be held. This will streamline our corporate structure to facilitate greater focus on the four regulatory jurisdictions in which we operate, as well as to simplify our financing arrangements. With the new structure, which is subject to regulatory approval, the regulated entities will be segregated from non-regulated operations. We also announced that we reached an agreement with our lenders to refinance and consolidate our debt within our parent company. The long-term debt agreements include proposed issuance of up to $50,000 of senior notes, with maturities and interest rates to be determined upon closing, subject to prevailing market conditions at that time. Additionally, we will establish a $42,000 five-year revolving credit facility and finance a lease buyout of approximately $7,000 over a term of four years. Closing on the debt agreements is subject to negotiation of terms, requested regulatory approvals and other closing conditions. Upon closing, proceeds from the new debt facilities will replace our five existing loan facilities and provide additional cash for operational purposes.
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Contractual Obligations
Contractual obligations that require cash payment over future periods at December 31, 2015, were as follows:
| Payments due in years ended December 31, | ||||||||||||||||||||
| Total | 2016 | 2017 - 2018 | 2019 - 2020 | Thereafter | ||||||||||||||||
| Line of credit (1) | $ | 15,750 | $ | 15,750 | $ | - | $ | - | $ | - | ||||||||||
| Related party note payable | 2,000 | 2,000 | - | - | - | |||||||||||||||
| Notes payable | 39,721 | 5,012 | 34,709 | - | - | |||||||||||||||
| Operating leases | 2,072 | 265 | 501 | 423 | 883 | |||||||||||||||
| Capital leases | 8,778 | 3,130 | 4,448 | 600 | 600 | |||||||||||||||
| Build-to-suit lease (2) | 2,041 | 612 | 1,429 | - | - | |||||||||||||||
| Natural gas purchase obligations (3) | 2,536 | 2,078 | 458 | - | - | |||||||||||||||
| Pipeline & storage capacity obligations (3) | 30,753 | 1,781 | 3,292 | 2,656 | 23,024 | |||||||||||||||
| Total | $ | 103,651 | $ | 30,628 | $ | 44,837 | $ | 3,679 | $ | 24,507 | ||||||||||
(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 2016.
(2) Build-to-suit lease is related to the third phase of our new ERP system, and will be evaluated for sale leaseback treatment upon its completion in 2016. The asset to be leased is not yet complete and as such actual amounts due may vary from the amounts presented.
(3) Some of our natural gas purchase and capacity obligations are based on future market pricing. Cash payment estimates for these obligations are based on our price in effect as of December 31, 2015.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements 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 in the Notes to the Consolidated Financial Statements included in this Annual Report.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
(dollars in thousands, except per MMBtu)
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. As such, actual results may differ from the analyses presented below.
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.
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The following table summarizes the commodity swap contracts we have entered into as of December 31, 2015. 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.
| Product | Type | Contract Period | Volume | Price per MMBtu | ||||||
| AECO Canada - CGPR 7A Natural Gas | Swap | 4/1/15 - 3/31/16 | 500 MMBtu/Day | $ | 2.420 | |||||
| AECO Canada - CGPR 7A Natural Gas | Swap | 11/1/15 - 3/31/16 | 500 MMBtu/Day | $ | 2.260 | |||||
At December 31, 2015, the fair value of our derivative instruments was a liability of approximately $54. 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 10% change in natural gas futures prices would have increased or decreased this liability by approximately $5.
Interest Rate Risk
At December 31, 2015, we had approximately $15,750 of borrowings outstanding on our line of credit and $8,375 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. A hypothetical 100 basis point change in interest rates on the 2015 monthly average principle balance of these borrowings would have an annual effect on income before taxes of approximately $286.
Item 8. Financial Statements and Supplementary Data.
Our Consolidated Financial Statements are included in Item 15 of this Annual Report.
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, 2015, 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, 2015.
Management’s Report on Internal Control over Financial Reporting
Our management 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. GAAP 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. 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, including our chief executive officer and chief financial officer, concluded that our internal control over financial reporting was effective as of December 31, 2015.
Our independent registered public accounting firm, Malone Bailey, LLP has issued an audit report on the effectiveness of our internal controls over financial reporting as of December 31, 2015, which is included in this Annual Report.
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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 2015, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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 prepared a report with the assistance of legal counsel and financial and regulatory advisors evaluating the allegations and the board evaluated the report. Insurance coverage was not available for costs associated with this review and report. We incurred substantial costs and expenses related to the investigation that are not covered by insurance.
SEC Investigation
We 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) our financial statements and internal controls and (iv) various entities affiliated with our former chairman and chief executive officer, Richard M. Osborne. On May 29, 2015, we received a subpoena regarding a formal investigation, case number C-08186-A. The SEC has requested we preserve all documents relating to these matters. We are complying with this request and intend 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 Business Conduct and Ethics,” and “Audit Committee Report” in the Proxy Statement for our 2016 Annual Meeting.
Item 11. Executive Compensation.
Information required by this item is incorporated by reference to the material appearing under the headings “Compensation Discussion and Analysis,” “Director Compensation” and “Executive Compensation,” in the Proxy Statement for our 2016 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 Certain Beneficial Owners and Management,” and “Securities Authorized for Issuance Under Equity Compensation Plans” in the Proxy Statement for our 2016 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 2016 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 2016 Annual Meeting.
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Item 15. Exhibits, Financial Statement Schedules.
(a) Financial Statements
| Page No. | ||
| Report of Independent Registered Public Accounting Firm – MaloneBailey, LLP | F-2 | |
| Consolidated Balance Sheets | F-3 | |
| Consolidated Statements of Comprehensive Income | F-5 | |
| Consolidated Statements of Changes in Stockholders’ Equity | F-6 | |
| Consolidated Statements of Cash Flows | F-7 | |
| Notes to Consolidated Financial Statements | F-9 | |
| Schedule I – Condensed Financial Information of Registrant for the years ended December 31, 2015, 2014 and 2013 | 57 | |
| Schedule II – Valuation and Qualifying Accounts | * |
*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 | |
| 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 Energy 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 Energy 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 Energy 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 and 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 Energy 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 and Exchange Commission on January 11, 2010 | |
| 3.1 | Amendment to Articles of Incorporation of Gas Natural Inc., dated December 9, 2014. Filed as, and incorporated herein by reference to Exhibit 3.1 to the Registrant’s Annual Report on Form 10-K, as filed with the Securities and Exchange Commission on March 12, 2015. | |
| 3.2 | Gas Natural Inc. Amended and Restated Code of Regulations, dated December 2, 2015. 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 December 3, 2015 | |
| 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 |
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| 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 | 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 | |
| 10.8 | 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 | |
| 10.9 | 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 | |
| 10.10 | 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 | |
| 10.11 | 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 | |
| 10.12 | First Amendment and Joinder to Note Purchase Agreement, dated May 3, 2011, by and among Great Plains Natural Gas Company and Lightning Pipeline Company, Inc., Spelman Pipeline Holdings LLC, Kidron Pipeline, LLC, Gas Natural Service Company, LLC and Gas Natural Inc. and Sun Life Assurance Company of Canada, as the purchaser. Filed as, and incorporated herein by reference to, Exhibit 10.4 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on May 5, 2011 |
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| 10.13 | 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 | |
| 10.14 | 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 | |
| 10.15 | 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 | |
| 10.16 | 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 | |
| 10.17† | 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 | |
| 10.18† | 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 | |
| 10.19 | Reaffirmation and First Amendment to Credit Facility, dated November 2, 2011, by and among Energy West, Incorporated, Energy West Propane, Inc., Energy West Resources, Inc., Energy West Development, Inc. 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 November 4, 2011 | |
| 10.20 | 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 | |
| 10.21 | 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 | |
| 10.22 | Amended and Restated Credit Agreement dated September 20, 2012, by and among Energy West, Incorporated and the Bank of America, N.A., as agent for various participating banks. Filed as, and incorporated herein by reference to, Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on September 26, 2012 |
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| 10.23 | 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 | |
| 10.24 | 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 | |
| 10.25 | 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 | |
| 10.26 | 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 | |
| 10.27 | 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 | |
| 10.28 | 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 | |
| 10.29 | 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 | |
| 10.30 | 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 | |
| 10.31 | 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 |
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| 10.32 | 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 | |
| 10.33 | 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 | |
| 10.34 | 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 | |
| 10.35 | 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 | |
| 10.36 | 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 | |
| 10.37 | 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 | |
| 10.38 | 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 | |
| 10.39 | 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 | |
| 10.40 | 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 8-K, as filed with the Securities and Exchange Commission on June 6, 2013 | |
| 10.41 | 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 8-K, as filed with the Securities and Exchange Commission on June 6, 2013 | |
| 10.42 | 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 8-K, as filed with the Securities and Exchange Commission on June 6, 2013 |
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| 10.43 | 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 8-K, as filed with the Securities and Exchange Commission on June 6, 2013 | |
| 10.44 | 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 8-K, as filed with the Securities and Exchange Commission on June 6, 2013 | |
| 10.45 | 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 8-K, as filed with the Securities and Exchange Commission on June 6, 2013 | |
| 10.46 | 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 | |
| 10.47 | 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 | |
| 10.48 | 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 | |
| 10.49 | 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 | |
| 10.50 | 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 | |
| 10.51† | 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 | |
| 10.52† | 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 | |
| 10.53† | 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 | |
| 10.54† | 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 | |
| 10.55† | 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 |
| 54 |
| 10.56† | 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 | |
| 10.57 | 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 | |
| 10.58 | 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 | |
| 10.59 | 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 | |
| 10.60 | 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 | |
| 10.61 | Loan Agreement, dated April 6, 2015, between NIL Funding Corporation 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 April 13, 2015 | |
| 10.62 | Promissory Note, dated April 6, 2015, between NIL Funding Corporation and Gas Natural 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 April 13, 2015 | |
| 10.63 | Asset Purchase Agreement, dated as of August 5, 2015, by and among Kentucky Frontier Gas, LLC, and Public Gas 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 August 11, 2015 | |
| 10.64 | Loan Agreement, dated as of October 23, 2015, by and among NIL Funding Corporation 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 October 26, 2015 | |
| 10.65 | Promissory Note, dated October 23, 2015, in the original principal amount of $3 million, issued by Gas Natural Inc. to NIL Funding Corporation. 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 26, 2015 | |
| 10.66 | Joinder and Limited Waiver to Note Purchase Agreement, dated December 14, 2015, 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., 8500 Station Street LLC, Gas Natural Resources LLC, Lone Wolfe Insurance, LLC, 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 December 16, 2015 | |
| 10.67 | Addendum to Pledge Agreement, dated December 14, 2015, by and among Lone Wolfe Insurance, LLC, 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 December 16, 2015 |
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| 10.68 | Addendum to Security Agreement, dated December 14, 2015, by and among Lone Wolfe Insurance, LLC, 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 December 16, 2015 | |
| 14* | Code of Business Conduct for Directors, Officers and Employees, dated September 9, 2015. | |
| 21* | List of Company Subsidiaries | |
| 23* | Consent of Independent Registered Public Accounting Firm, MaloneBailey 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 |
| 56 |
(c) Financial Statement Schedule
Schedule I - Condensed financial information of registrant
GAS NATURAL INC.
(PARENT COMPANY ONLY)
Condensed Financial Statements
| (amounts in thousands) | December 31, | |||||||
| 2015 | 2014 | |||||||
| BALANCE SHEETS | ||||||||
| ASSETS | ||||||||
| Cash and cash equivalents | $ | 296 | $ | 147 | ||||
| Investments | 93,448 | 86,460 | ||||||
| Accounts receivable | - | 235 | ||||||
| Prepayments | 283 | - | ||||||
| Intercompany receivable, net | 6,378 | 6,173 | ||||||
| Discontinued operations | - | 8,349 | ||||||
| Property, plant, & equipment, net | 343 | 187 | ||||||
| Deferred tax asset, non-current | 989 | 1,156 | ||||||
| Other assets | 73 | 2 | ||||||
| Total assets | $ | 101,810 | $ | 102,709 | ||||
| LIABILITIES AND CAPITALIZATION | ||||||||
| Current liabilities | $ | 6,347 | $ | 6,375 | ||||
| Related party note payable | 2,000 | - | ||||||
| Capital lease liability | 3,702 | - | ||||||
| Notes payable | 10 | 23 | ||||||
| Stockholders' equity | 89,751 | 96,311 | ||||||
| Total liabilities and capitalization | $ | 101,810 | $ | 102,709 | ||||
| 57 |
GAS NATURAL INC.
(PARENT COMPANY ONLY)
Condensed Financial Statements, continued
| (amounts in thousands) | Year Ended December 31, | |||||||||||
| 2015 | 2014 | 2013 | ||||||||||
| STATEMENTS OF COMPREHENSIVE INCOME | ||||||||||||
| Operating expenses | $ | 2,339 | $ | 2,431 | $ | 946 | ||||||
| Operating loss | (2,339 | ) | (2,431 | ) | (946 | ) | ||||||
| Other income (expense) | - | 180 | (524 | ) | ||||||||
| Interest expense | (301 | ) | (13 | ) | - | |||||||
| Loss before income taxes and income from unconsolidated subsidiaries | (2,640 | ) | (2,264 | ) | (1,470 | ) | ||||||
| Income from unconsolidated subsidiaries | 2,827 | 4,199 | 6,919 | |||||||||
| Income tax benefit | 982 | 795 | 403 | |||||||||
| Income from continuing operations | 1,169 | 2,730 | 5,852 | |||||||||
| Discontinued operations | 3,519 | 1,033 | 819 | |||||||||
| Net income | $ | 4,688 | $ | 3,763 | $ | 6,671 | ||||||
| Other comprehensive income | ||||||||||||
| Unrealized gain (loss) on available for sale securities, net of tax of $8 and $23, for the years ended December 31, 2014 and 2013, respectively | - | 15 | 39 | |||||||||
| Unrealized loss on available for sale securities transferred to earnings, net of tax of $64 for the year ended December 31, 2014 | - | (120 | ) | - | ||||||||
| Total other comprehensive income | - | (105 | ) | 39 | ||||||||
| Comprehensive income | $ | 4,688 | $ | 3,658 | $ | 6,710 | ||||||
| 58 |
GAS NATURAL INC.
(PARENT COMPANY ONLY)
Condensed Financial Statements, continued
| (amounts in thousands) | Year Ended December 31, | |||||||||||
| 2015 | 2014 | 2013 | ||||||||||
| STATEMENTS OF CASH FLOWS | ||||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||||||
| Net income | $ | 4,688 | $ | 3,762 | $ | 6,671 | ||||||
| Less income from discontinued operations | 3,519 | 1,033 | 819 | |||||||||
| Income from continuing operations | 1,169 | 2,729 | 5,852 | |||||||||
| Income from unconsolidated subsidiaries | (2,827 | ) | (4,199 | ) | (6,919 | ) | ||||||
| Depreciation expense | 44 | 19 | 13 | |||||||||
| Amortization of debt issue costs | 153 | - | - | |||||||||
| Stock based compensation | 161 | 317 | 3 | |||||||||
| Deferred income taxes | 110 | (423 | ) | (159 | ) | |||||||
| Intercompany accounts receivable/accounts payable | 4,232 | (1,063 | ) | 193 | ||||||||
| Other assets | (48 | ) | 392 | (62 | ) | |||||||
| Other liabilities | 850 | 567 | (84 | ) | ||||||||
| Net cash provided by (used in) operating activities | 3,844 | (1,661 | ) | (1,163 | ) | |||||||
| CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||
| Capital expenditures | (106 | ) | (71 | ) | (75 | ) | ||||||
| Investment in subsidiaries | (1,236 | ) | (3,879 | ) | (6,585 | ) | ||||||
| Dividends received from subsidiaries | 3,205 | 3,000 | 3,600 | |||||||||
| Net cash (used in) provided by investing activities | 1,863 | (950 | ) | (3,060 | ) | |||||||
| CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||
| Repayments of long-term debt | (6 | ) | (3 | ) | - | |||||||
| Repayments of capital lease liabilities | (1,657 | ) | - | - | ||||||||
| Proceeds from related party notes payable | 8,000 | - | - | |||||||||
| Repayments of related party notes payable | (6,000 | ) | - | - | ||||||||
| Debt issuance costs | (225 | ) | (2 | ) | (1 | ) | ||||||
| Restricted cash - debt service | - | - | 751 | |||||||||
| Exercise of stock options | - | 46 | 160 | |||||||||
| Proceeds from issuance of common stock | - | - | 16,721 | |||||||||
| Dividends paid | (5,670 | ) | (5,659 | ) | (5,006 | ) | ||||||
| Net cash (used in) provided by financing activities | (5,558 | ) | (5,618 | ) | 12,625 | |||||||
| DISCONTINUED OPERATIONS | ||||||||||||
| Operating cash flows | - | - | - | |||||||||
| Investing cash flows | - | - | (261 | ) | ||||||||
| Net cash provided by (used in) discontinued operations | - | - | (261 | ) | ||||||||
| Net increase (decrease) in cash and cash equivalents | 149 | (8,229 | ) | 8,141 | ||||||||
| Cash and cash equivalents, beginning of period | 147 | 8,376 | 235 | |||||||||
| Cash and cash equivalents, end of period | $ | 296 | $ | 147 | $ | 8,376 | ||||||
| 59 |
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 U.S. GAAP. Therefore, these condensed financial statements should be read in conjunction with the consolidated financial statements and related notes included in this Annual Report.
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:
| (amounts in thousands) | Years Ended December 31, | |||||||||||
| 2015 | 2014 | 2013 | ||||||||||
| Energy West, Inc. | $ | 3,050 | $ | 3,000 | $ | 3,600 | ||||||
| Gas Natural Resources, LLC | 150 | - | - | |||||||||
| Lone Wolfe Insurance, LLC | 5 | - | - | |||||||||
| Total | $ | 3,205 | $ | 3,000 | $ | 3,600 | ||||||
| 60 |
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 D. Henthorne | ||
| Gregory J. Osborne | James E. Sprague | Jed D. Henthorne | ||
| Chief Executive Officer | Chief Financial Officer | Corporate Controller | ||
| (Principal Executive Officer) | (Principal Financial Officer) | (Principal Accounting Officer) | ||
| Date: March 15, 2016 | Date: March 15, 2016 | Date: March 15, 2016 | ||
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/ Michael R. Winter | Chairman of the Board | March 15, 2016 | ||
| Michael R. Winter | ||||
| /s/ Michael B. Bender | Director | March 15, 2016 | ||
| Michael B. Bender | ||||
| /s/ James P. Carney | Director | March 15, 2016 | ||
| James P. Carney | ||||
| /s/ Richard K. Greaves | Director | March 15, 2016 | ||
| Richard K. Greaves | ||||
| /s/ Robert B. Johnston | Director | March 15, 2016 | ||
| Robert B. Johnston | ||||
| /s/ Gregory J. Osborne | Chief Executive Officer (Principal Executive Officer) | March 15, 2016 | ||
| Gregory J. Osborne |
| 61 |
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 (collectively, the “Company”) as of December 31, 2015 and 2014, and the related consolidated statements of comprehensive income, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2015. 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 December 31, 2015 and 2014, and for each of the three years in the period ended December 31, 2015. We also have audited the Company’s internal control over financial reporting as of December 31, 2015, 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, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the financial statement schedule as of December 31, 2015 and 2014, and for each of the three years in the period ended December 31, 2015, 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, 2015, based on the criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
/s/ MaloneBailey, LLP
Houston, Texas
March 15, 2016
| F-2 |
Gas Natural Inc. and Subsidiaries
Consolidated Balance Sheets
(in thousands)
| December 31, | ||||||||
| 2015 | 2014 | |||||||
| ASSETS | ||||||||
| CURRENT ASSETS | ||||||||
| Cash and cash equivalents | $ | 2,728 | $ | 1,586 | ||||
| Accounts receivable | ||||||||
| Trade, less allowance for doubtful accounts of $506 and $371, respectively | 10,635 | 12,111 | ||||||
| Related parties | 188 | 235 | ||||||
| Unbilled gas | 6,995 | 7,631 | ||||||
| Inventory | ||||||||
| Natural gas | 4,063 | 5,302 | ||||||
| Materials and supplies | 2,271 | 2,301 | ||||||
| Regulatory assets, current | 2,469 | 4,098 | ||||||
| Other current assets | 2,174 | 2,857 | ||||||
| Discontinued operations | - | 11,654 | ||||||
| Total current assets | 31,523 | 47,775 | ||||||
| PROPERTY, PLANT, & EQUIPMENT, NET | 142,416 | 142,011 | ||||||
| OTHER ASSETS | ||||||||
| Regulatory assets, non-current | 1,523 | 2,055 | ||||||
| Goodwill | 15,872 | 16,156 | ||||||
| Customer relationships, net of amortization | 2,625 | 2,928 | ||||||
| Restricted cash | 1,898 | 1,898 | ||||||
| Other assets | 1,832 | 1,181 | ||||||
| Total other assets | 23,750 | 24,218 | ||||||
| TOTAL ASSETS | $ | 197,689 | $ | 214,004 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
| F-3 |
Gas Natural Inc. and Subsidiaries
Consolidated Balance Sheets
(in thousands, except share data)
| December 31, | ||||||||
| 2015 | 2014 | |||||||
| LIABILITIES AND CAPITALIZATION | ||||||||
| CURRENT LIABILITIES | ||||||||
| Line of credit | $ | 15,750 | $ | 28,761 | ||||
| Accounts payable | ||||||||
| Trade | 8,784 | 14,115 | ||||||
| Related parties | 192 | 170 | ||||||
| Notes payable, current portion | 5,012 | 542 | ||||||
| Note payable to related party | 2,000 | - | ||||||
| Derivative instruments | 54 | 3,023 | ||||||
| Accrued liabilities | 5,837 | 4,974 | ||||||
| Regulatory liability, current | 487 | 925 | ||||||
| Build-to-suit liability | 2,041 | 5,597 | ||||||
| Other current liabilities | 5,325 | 2,691 | ||||||
| Discontinued operations | - | 544 | ||||||
| Total current liabilities | 45,482 | 61,342 | ||||||
| LONG-TERM LIABILITIES | ||||||||
| Deferred tax liability | 12,295 | 10,538 | ||||||
| Regulatory liability, non-current | 1,251 | 1,090 | ||||||
| Capital lease liability, non-current | 5,177 | 1,675 | ||||||
| Other long-term liabilities | 3,286 | 3,328 | ||||||
| Total long-term liabilities | 22,009 | 16,631 | ||||||
| NOTES PAYABLE, less current portion | 34,709 | 39,721 | ||||||
| COMMITMENTS AND CONTINGENCIES (see Note 20) | ||||||||
| 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 shares; Issued and outstanding: 10,504,734 and 10,492,511 shares as of December 31, 2015 and 2014, respectively | 1,575 | 1,573 | ||||||
| Capital in excess of par value | 63,985 | 63,826 | ||||||
| Retained earnings | 29,929 | 30,911 | ||||||
| Total stockholders’ equity | 95,489 | 96,310 | ||||||
| TOTAL CAPITALIZATION | 130,198 | 136,031 | ||||||
| TOTAL LIABILITIES AND CAPITALIZATION | $ | 197,689 | $ | 214,004 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
| F-4 |
Gas Natural Inc. and Subsidiaries
Consolidated Statements of Comprehensive Income
(in thousands, except per share data)
| Year Ended December 31, | ||||||||||||
| 2015 | 2014 | 2013 | ||||||||||
| REVENUES | ||||||||||||
| Natural gas operations | $ | 103,978 | $ | 123,053 | $ | 97,233 | ||||||
| Marketing and production | 8,383 | 9,517 | 12,167 | |||||||||
| Total revenues | 112,361 | 132,570 | 109,400 | |||||||||
| COST OF SALES | ||||||||||||
| Natural gas purchased | 60,380 | 79,097 | 55,977 | |||||||||
| Marketing and production | 7,746 | 8,621 | 10,053 | |||||||||
| Total cost of sales | 68,126 | 87,718 | 66,030 | |||||||||
| GROSS MARGIN | 44,235 | 44,852 | 43,370 | |||||||||
| OPERATING EXPENSES | ||||||||||||
| Distribution, general, and administrative | 26,226 | 24,770 | 21,308 | |||||||||
| Maintenance | 1,422 | 1,225 | 1,142 | |||||||||
| Depreciation, amortization and accretion | 7,257 | 6,657 | 5,609 | |||||||||
| Taxes other than income | 4,119 | 3,927 | 3,672 | |||||||||
| Provision for doubtful accounts | 278 | 1,112 | 726 | |||||||||
| Contingent consideration loss (gain) | (75 | ) | 62 | (1,565 | ) | |||||||
| Goodwill impairment | - | - | 726 | |||||||||
| Total operating expenses | 39,227 | 37,753 | 31,618 | |||||||||
| OPERATING INCOME | 5,008 | 7,099 | 11,752 | |||||||||
| Loss from unconsolidated affiliate | - | (352 | ) | (5 | ) | |||||||
| Gain on sale of marketable securities | - | 184 | - | |||||||||
| Acquisition expense | - | (7 | ) | (272 | ) | |||||||
| Stock sale expense | - | - | (309 | ) | ||||||||
| Other income, net | 182 | 579 | 886 | |||||||||
| Interest expense | (3,604 | ) | (3,226 | ) | (3,176 | ) | ||||||
| Income before income taxes | 1,586 | 4,277 | 8,876 | |||||||||
| Income tax expense | (417 | ) | (1,548 | ) | (3,024 | ) | ||||||
| INCOME FROM CONTINUING OPERATIONS | 1,169 | 2,729 | 5,852 | |||||||||
| Discontinued operations, net of income taxes (See Note 4) | 3,519 | 1,033 | 819 | |||||||||
| NET INCOME | $ | 4,688 | $ | 3,762 | $ | 6,671 | ||||||
| BASIC & DILUTED EARNINGS (LOSS) PER SHARE: | ||||||||||||
| Continuing operations | $ | 0.11 | $ | 0.26 | $ | 0.63 | ||||||
| Discontinued operations | 0.34 | 0.10 | 0.08 | |||||||||
| Net income per share | $ | 0.45 | $ | 0.36 | $ | 0.71 | ||||||
| Weighted average dividends declared per common share | $ | 0.54 | $ | 0.50 | $ | 0.55 | ||||||
| COMPREHENSIVE INCOME: | ||||||||||||
| Net income | $ | 4,688 | $ | 3,762 | $ | 6,671 | ||||||
| OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX | ||||||||||||
| Unrealized gain on available for sale securities, net of tax of $8 and $23, for the years ended December 31, 2014 and 2013, respectively | - | 15 | 39 | |||||||||
| Accumulated unrealized gain on available for sale securities transferred to earnings, net of tax of $64 for the year ended December 31, 2014 | - | (120 | ) | - | ||||||||
| Other comprehensive income (loss), net of tax | - | (105 | ) | 39 | ||||||||
| COMPREHENSIVE INCOME | $ | 4,688 | $ | 3,657 | $ | 6,710 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
| F-5 |
Gas Natural Inc. and Subsidiaries
Consolidated Statements of Changes in Stockholders' Equity
(in thousands, except share data)
| Accumulated | ||||||||||||||||||||||||
| Capital In | Other | |||||||||||||||||||||||
| Common | Common | Excess Of | Comprehensive | Retained | ||||||||||||||||||||
| Shares | Stock | Par Value | Income | Earnings | Total | |||||||||||||||||||
| BALANCE AT DECEMBER 31, 2012 | 8,369,752 | $ | 1,255 | $ | 44,256 | $ | 66 | $ | 30,766 | $ | 76,343 | |||||||||||||
| Net income | - | - | - | - | 6,671 | 6,671 | ||||||||||||||||||
| Other comprehensive income, net | - | - | - | 39 | - | 39 | ||||||||||||||||||
| Exercise of stock options | 20,000 | 3 | 157 | - | - | 160 | ||||||||||||||||||
| Stock compensation | - | - | 3 | - | - | 3 | ||||||||||||||||||
| Purchase of JDOG Marketing | 256,926 | 39 | 2,603 | - | - | 2,642 | ||||||||||||||||||
| Common stock issued | 1,805,000 | 271 | 16,450 | - | - | 16,721 | ||||||||||||||||||
| Dividends declared | - | - | - | - | (5,099 | ) | (5,099 | ) | ||||||||||||||||
| BALANCE AT DECEMBER 31, 2013 | 10,451,678 | 1,568 | 63,469 | 105 | 32,338 | 97,480 | ||||||||||||||||||
| Net income | - | - | - | - | 3,762 | 3,762 | ||||||||||||||||||
| Other comprehensive loss, net | - | - | - | (105 | ) | - | (105 | ) | ||||||||||||||||
| Exercise of stock options | 5,000 | 1 | 45 | - | - | 46 | ||||||||||||||||||
| Stock compensation | 35,833 | 4 | 312 | - | - | 316 | ||||||||||||||||||
| Dividends declared | - | - | - | - | (5,189 | ) | (5,189 | ) | ||||||||||||||||
| BALANCE AT DECEMBER 31, 2014 | 10,492,511 | 1,573 | 63,826 | - | 30,911 | 96,310 | ||||||||||||||||||
| Net income | - | - | - | - | 4,688 | 4,688 | ||||||||||||||||||
| Stock compensation | 12,223 | 2 | 159 | - | - | 161 | ||||||||||||||||||
| Dividends declared | - | - | - | - | (5,670 | ) | (5,670 | ) | ||||||||||||||||
| BALANCE AT DECEMBER 31, 2015 | 10,504,734 | $ | 1,575 | $ | 63,985 | $ | - | $ | 29,929 | $ | 95,489 | |||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
| F-6 |
Gas Natural Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(amounts in thousands)
| Year Ended December 31, | ||||||||||||
| 2015 | 2014 | 2013 | ||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||||||
| Net income | $ | 4,688 | $ | 3,762 | $ | 6,671 | ||||||
| Less income from discontinued operations | 3,519 | 1,033 | 819 | |||||||||
| Income from continuing operations | 1,169 | 2,729 | 5,852 | |||||||||
| Adjustments to reconcile income from continuing operations to net cash provided by operating activities: | ||||||||||||
| Depreciation and amortization | 7,236 | 6,605 | 5,551 | |||||||||
| Accretion | 21 | 52 | 58 | |||||||||
| Amortization of debt issuance costs | 656 | 420 | 418 | |||||||||
| Provision for doubtful accounts | 278 | 1,112 | 726 | |||||||||
| Amortization of deferred loss on sale-leaseback | 358 | - | - | |||||||||
| Stock based compensation | 161 | 317 | 3 | |||||||||
| Gain on sale of marketable securities | - | (184 | ) | - | ||||||||
| Gain on sale of assets | (118 | ) | (28 | ) | (158 | ) | ||||||
| Loss from unconsolidated affiliate | - | 352 | 5 | |||||||||
| Unrealized holding loss (gain) on contingent consideration | (75 | ) | 62 | (1,565 | ) | |||||||
| Change in fair value of derivative financial instruments | (96 | ) | 151 | - | ||||||||
| Investment tax credit | (21 | ) | (21 | ) | (21 | ) | ||||||
| Deferred income taxes | 2,171 | 2,136 | 4,025 | |||||||||
| Goodwill impairment | - | - | 726 | |||||||||
| Changes in assets and liabilities | ||||||||||||
| Accounts receivable, including related parties | 1,293 | (891 | ) | (2,187 | ) | |||||||
| Unbilled gas | 658 | (481 | ) | (3,009 | ) | |||||||
| Natural gas inventory | 1,239 | (458 | ) | (389 | ) | |||||||
| Accounts payable, including related parties | (4,665 | ) | 1,817 | 3,111 | ||||||||
| Regulatory assets and liabilities | (1,283 | ) | (1,938 | ) | 1,039 | |||||||
| Prepayments and other | (645 | ) | (24 | ) | 1,076 | |||||||
| Other assets | (35 | ) | 235 | (464 | ) | |||||||
| Other liabilities | 1,122 | (817 | ) | 642 | ||||||||
| Net cash provided by operating activities of continuing operations | 9,424 | 11,146 | 15,439 | |||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||
| Capital expenditures | (9,567 | ) | (21,613 | ) | (23,517 | ) | ||||||
| Proceeds from sale of fixed assets | 4,054 | 173 | 969 | |||||||||
| Proceeds from sale of marketable securities | - | 422 | - | |||||||||
| Proceeds from note receivable | 92 | 3 | 9 | |||||||||
| Investment in unconsolidated affiliate | - | - | (35 | ) | ||||||||
| Restricted cash – capital expenditures fund | - | 57 | 1,264 | |||||||||
| Customer advances for construction | 33 | 17 | 12 | |||||||||
| Contributions in aid of construction | 1,193 | 2,262 | 1,106 | |||||||||
| Net cash used in investing activities of continuing operations | (4,195 | ) | (18,679 | ) | (20,192 | ) | ||||||
| CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||
| Proceeds from lines of credit | 14,150 | 24,850 | 22,519 | |||||||||
| Repayments of lines of credit | (27,161 | ) | (20,619 | ) | (21,849 | ) | ||||||
| Proceeds from notes payable | 8,000 | 102 | - | |||||||||
| Repayments of notes payable | (6,542 | ) | (3,565 | ) | (633 | ) | ||||||
| Payments of capital lease obligations | (1,845 | ) | (178 | ) | (168 | ) | ||||||
| Debt issuance costs | (235 | ) | (111 | ) | (8 | ) | ||||||
| Proceeds from issuance of common shares | - | - | 16,721 | |||||||||
| Exercise of stock options | - | 45 | 160 | |||||||||
| Restricted cash – debt service fund | - | 132 | 749 | |||||||||
| Dividends paid | (5,670 | ) | (5,659 | ) | (5,006 | ) | ||||||
| Net cash provided by (used in) financing activities of continuing operations | (19,303 | ) | (5,003 | ) | 12,485 | |||||||
| DISCONTINUED OPERATIONS | ||||||||||||
| Operating cash flows | 845 | 1,924 | 658 | |||||||||
| Investing cash flows | 14,371 | (511 | ) | 1,738 | ||||||||
| Financing cash flows | - | (32 | ) | (590 | ) | |||||||
| Net cash provided by discontinued operations | 15,216 | 1,381 | 1,806 | |||||||||
| NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | 1,142 | (11,155 | ) | 9,538 | ||||||||
| Cash and cash equivalents, beginning of period | 1,586 | 12,741 | 3,203 | |||||||||
| CASH AND CASH EQUIVALENTS, END OF PERIOD | $ | 2,728 | $ | 1,586 | $ | 12,741 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
| F-7 |
Gas Natural Inc. and Subsidiaries
Consolidated Statements of Cash Flows
| Year Ended December 31, | ||||||||||||
| 2015 | 2014 | 2013 | ||||||||||
| SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION | ||||||||||||
| Cash paid for interest, net of amounts capitalized | $ | 3,011 | $ | 2,730 | $ | 2,806 | ||||||
| Cash refunded for income taxes, net | (79 | ) | (234 | ) | (4 | ) | ||||||
| NONCASH INVESTING AND FINANCING ACTIVITIES | ||||||||||||
| Assets acquired under build-to-suit agreement | $ | 5,245 | $ | 5,597 | $ | - | ||||||
| Capital expenditures included in accounts payable | 226 | 1,047 | 1,798 | |||||||||
| Capital assets exchanged to settle payables | - | 322 | 83 | |||||||||
| Capital assets acquired through trade-in | - | 103 | 24 | |||||||||
| Capital additions acquired through debt | - | 26 | - | |||||||||
| Customer advances for construction moved to contribution in aid of construction | 3 | 10 | 16 | |||||||||
| Accrued dividends | - | - | 470 | |||||||||
| Restricted cash received from customer as security deposit | - | 950 | - | |||||||||
| Capitalized interest | 549 | 621 | 6 | |||||||||
| Customer relationships acquired from JDOG Marketing purchase | - | - | 2,800 | |||||||||
| Shares issued to purchase JDOG Marketing | - | - | 2,641 | |||||||||
| Contingent consideration issued to purchase JDOG Marketing | - | - | 2,250 | |||||||||
| Goodwill acquired from JDOG Marketing purchase | - | - | 2,102 | |||||||||
| Note receivable effectively settled in JDOG Marketing acquisition | - | - | 32 | |||||||||
| Plant, property and equipment acquired from JDOG Marketing purchase | - | - | 22 | |||||||||
The accompanying notes are an integral part of these consolidated financial statements.
| F-8 |
GAS NATURAL INC. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(DOLLAR AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
Note 1 – Summary of Business
Nature of Business
Energy West was originally incorporated in Montana in 1909 and was reorganized as a holding company in 2009. On July 9, 2010, we changed our name to Gas Natural Inc. (the “Company,” “we,” “us,” or “our”) and reincorporated from Montana to Ohio. We are a natural gas company with operations in four states. Gas Natural 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. 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. We have three operating and reporting segments:
| · | Natural Gas. Representing the majority of our revenue, we annually distribute approximately 21 Bcf of natural gas to approximately 67,800 customers through regulated utilities operating in Maine, Montana, North Carolina and Ohio. Our natural gas utility subsidiaries include Bangor Gas Company (Maine), Brainard (Ohio), Cut Bank Gas (Montana), Energy West Montana (Montana), Frontier Natural Gas (North Carolina), NEO (Ohio) and Orwell (Ohio). |
| · | Marketing and Production. Annually, we market approximately 1.5 Bcf of natural gas to commercial and industrial customers in Montana, Wyoming and Ohio through our EWR and GNR subsidiaries. Our EWR subsidiary also manages midstream supply and production assets for transportation customers and utilities. EWR owns or manages for EWD, 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 and Other. Corporate and other encompasses the results of our corporate acquisitions, equity transactions and discontinued operations. Included in corporate and other are costs associated with business development and acquisitions, dividend income, recognized gains or losses from the sale of marketable securities, activity from Lone Wolfe which serves as an insurance agent for us and other businesses in the energy industry, and the results of our discontinued operations from the sales of EWW, the Shoshone and Glacier pipelines, and Independence. |
Note 2 - Significant Accounting Policies
Basis of Presentation
The accompanying consolidated financial statements have been prepared in accordance with U.S. GAAP. The consolidated financial statements include the accounts and transactions of Gas Natural 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.
| F-9 |
Effects of Regulation
We follow 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 in which we operate. 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 U.S. GAAP 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.
We use estimates to measure certain deferred charges and deferred credits related to items subject to approval of the various public service commissions with jurisdiction over us. Estimates are also used in determining our 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.
We make acquisitions that involve combining the assets and liabilities of the acquired company with us. The assets and liabilities acquired are reported at their fair value at the date of acquisition. We may make estimates when we measure the fair value of acquired assets and liabilities.
Our estimates could change in the near term and could significantly impact our results of operations and financial position.
Fair Value Measurements
We measure certain of our assets and liabilities at fair value. The fair values of marketable securities are estimated based on the 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. The fair value measure of our contingent consideration liability has significant unobservable inputs, including our weighted average cost of capital, our credit spread above the risk free rate and our forecasted future cash flows. A significant increase (decrease) in these inputs could result in a significant increase (decrease) in the fair value measure.
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.
For build-to-suit leases, we evaluate our level of risk during the asset’s construction or development period. If we determine that we bear substantially all of the risk during this period, we establish an asset and liability for the total project costs with the liability reduced by any project costs paid directly by us. Once the build-to-suit asset is complete, we assess whether the arrangement qualifies for sales recognition under the sale-leaseback accounting guidance. If the lease meets the criteria to qualify as a sale-leaseback transaction, then the asset and liability are removed from our consolidated balance sheet at the time of the sale and accounted for as either a capital or an operating lease. If it does not meet the criteria to qualify as a sale-leaseback transaction, then the asset and liability remain on our consolidated balance sheet and the transaction is treated as a financing. If the lease is treated as sale-leaseback, we evaluate the fair value of the property sold compared to the sale price of the assets and defer any profit or loss on the sale.
Revenue Recognition
Revenues are recognized in the period that services are provided or products are delivered. We record gas distribution revenues for gas delivered to residential and commercial customers but not billed at the end of the accounting period. We periodically collect revenues subject to possible refunds pending final orders from regulatory agencies. When this occurs, we recognize a liability for such refunds.
| F-10 |
Stock-Based Compensation
We account 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
We file our income tax returns on a consolidated basis. Rate-regulated operations record cumulative increases in deferred taxes as income taxes recoverable from customers. We use 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. We do not have any unrecognized tax benefits that would have a material impact to our consolidated financial statements for any open tax years. No adjustments were recognized for uncertain tax positions for the three years ended December 31, 2015.
We recognize interest and penalties related to unrecognized tax benefits in operating expense. As of December 31, 2015 and 2014, there were no unrecognized tax benefits nor interest or penalties accrued related to unrecognized tax benefits, nor were any interest or penalties recognized during the three years ended December 31, 2015.
We, or one or more of our subsidiaries, files income tax returns in the U.S. federal jurisdiction and various state jurisdictions. The tax years after 2012 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 is primarily comprised of unrealized holding gains or losses on available-for-sale securities. These gains or losses are excluded from net income and reported separately in our accompanying Consolidated Balance Sheets and Consolidated Statements of Changes in Stockholders’ Equity as accumulated other comprehensive income.
During the year ended December 31, 2014, we sold all of our available-for-sale securities. We recognized a gain on the sale of approximately $184. An unrealized gain of approximately $120, net of tax, was reclassified from accumulated 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.
Earnings per Share
We compute basic earnings per share using the two class method because our restricted stock awards participate equally with common shares in the distribution of earnings. Diluted earnings per share reflect the potential dilution from the exercise or conversion of outstanding stock options and unvested restricted stock awards into common stock.
Cash and Cash Equivalents
We consider all highly liquid investments with original maturities of three months or less, at the date of acquisition, to be cash equivalents. We may have balances of cash and cash equivalents that exceed federally insurable limits.
Marketable Securities
Our securities investments that we intend 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 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 Statements of Comprehensive Income.
| F-11 |
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, we record an allowance for doubtful accounts based on the amount of probable losses in our existing accounts receivable. The allowance for doubtful accounts 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 may change from period to period and the allowance for doubtful accounts could potentially cause a negative material impact to the income statement and working capital.
Two of our 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 and includes transportation and storage costs.
Recoverable/Refundable Costs of Gas Purchases
We account for purchased gas costs in accordance with procedures authorized by the utility commissions in the states in which we operate. 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 we operate 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 natural gas producing reserves on properties located in northern Montana. EWD also owns an interest in certain natural gas producing properties located in northern Montana. We are depleting these reserves using the units-of-production method. The production activities are being accounted for using the successful efforts method. We are not the operator of any of the natural gas producing wells on these properties and we do not have 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.
Capitalized Interest
We capitalize the portion of our interest expense that is attributable under U.S. GAAP to our more significant construction projects over the duration of the respective construction periods. Capitalized interest is amortized to depreciation and amortization expense over the estimated useful life of the corresponding asset. During the years ended December 31, 2015 and 2014, we capitalized interest of $549 and $621, respectively. We did not capitalize any interest during the year ended December 31, 2013.
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 wholly or partially refunded. As of December 31, 2015 and 2014, $1,027 and $994, respectively, was included in other long-term liabilities for customer advances to be refunded to customers.
| F-12 |
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. We test goodwill for impairment annually, or more often if events or changes in circumstances indicate that the carrying value of our goodwill may be more than the fair value. We test for goodwill impairment using a two-step approach. In the first step of the review process, we compare the estimated fair value of the reporting unit with its carrying value. If the estimated fair value of the reporting unit is less than its carrying value, we recognize an impairment loss for the excess, if any, of the carrying value over the implied fair value of the reporting unit's goodwill amount.
We recognize an acquired intangible asset 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. Our customer relationships are amortized over an average useful life of 13 years. Accumulated amortization for our customer relationships was approximately $860 and $557 at December 31, 2015 and 2014, respectively. Amortization expense for customer relationships for the years ended December 31, 2015, 2014 and 2013, was $303, $303 and $186, respectively. We expect that our amortization expense related to our intangible assets will be $303 for each of the next five years.
Debt Issuance Costs
Debt issuance costs are fees and other direct incremental costs we incurred in obtaining debt financing and are recognized as assets in the accompanying consolidated balance sheets. At December 31, 2015 and 2014, we had $555 and $1,079, respectively, of debt issuance costs, net of accumulated amortization included in other assets on our Consolidated Balance Sheets. We recognized interest expense related to the amortization of debt issuance costs of $656, $420, and $418, respectively, for the years ended December 31, 2015, 2014 and 2013. During 2015, we paid $235 of debt issuance costs related to the increase in our Bank of America revolving credit facility availability and our short term loans with NIL Funding Corporation (“NIL Funding”). In connection with our sale of EWW and the Pipeline Assets, during the fourth quarter of 2015 we committed to repay the portion of notes payable to Allstate/CUNA that was allocated to EWW and EWD on February 12, 2016. Accordingly, we wrote off the unamortized debt issuance costs that were allocated to EWW and EWD’s portion of the debt, totaling $103. This amount was recognized within discontinued operations, net of tax on our Consolidated Statement of Comprehensive Income during 2015. See Note 14 – Credit Facilities and Long-Term Debt for more information regarding our debt agreements.
We estimate that we will recognize amortization of debt issuance costs of $344 in 2016 and $157 in 2017.
Investment in Unconsolidated Affiliate
We use the equity method of accounting for equity investments in entities when we do not control the investee, but can exert significant influence over the financial and operating policies of the investee. Under the equity method, we record our share of the investee’s underlying net income or loss as non-operating income in our Consolidated Statements of Comprehensive Income with a corresponding increase or decrease in the investment account. Distributions received from the investee reduce our investment balance.
Restricted Cash
At December 31, 2015 and 2014, we had a restricted cash balance of $1,898. Of this amount, $948 at both December 31, 2015 and 2014, is related to our Sun Life debt covenants. See the Sun Life Debt Covenant section of Note 14 – Credit Facilities and Long-Term Debt for more information regarding these restricted funds. The remaining restricted cash of $950 at December 31, 2015 and 2014, is related to a customer deposit that is refundable to the customer upon termination of the related gas transportation service agreement. We are restricted from using these funds unless and until a default under this agreement has occurred, or otherwise agreed to by the parties to the agreement. This customer filed for protection under Chapter 11 of the Federal Bankruptcy Code and we applied $450 of the restricted cash to open accounts receivable balances in January 2016. This deposit is included in other long-term liabilities on our Consolidated Balance Sheets as a result of the long-term nature of the contract.
Impairment of Long-Lived Assets
We evaluate our 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. We measure the recoverability of assets to be held and used 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.
| F-13 |
Asset Retirement Obligations
We record 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, and amortized over the related asset’s useful life. 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 accretion of the asset retirement liability is allocated to operating expense using a systematic and rational method.
Derivatives and Hedging Activities
We recognize all of our derivative instruments as either assets or liabilities in the statement of financial position at fair value. We may account for changes in the fair value of a derivative instrument as a hedge if it meets certain qualifications and we have designated it as such. We must designate hedging instruments based upon the exposure being hedged, and recognize gains and losses related to hedges in our consolidated balance sheets. We recognize gains and losses related to derivative instruments that are not designated as hedging instruments in our consolidated statements of comprehensive income during the current period.
We primarily manage commodity price risk related to natural gas by using derivative instruments. We enter forward contracts and commodity price swaps with fixed pricing to protect profit margins on future obligations to deliver gas at fixed prices or to protect our 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. Our commodity price swaps do not meet any of the hedging exemption criteria under ASC 815 and are accounted for as derivatives.
Discontinued Operations
We present discontinued operations in our consolidated financial statements when we believe that the disposition of assets constitutes a strategic shift that will have a major effect on our operations or financial results. The results of prior periods are reclassified to conform to the current year presentation. Corporate overhead is not allocated to discontinued operations and any overhead that was allocated to the discontinued operations in prior periods is reclassified to our corporate and other segment. We do not allocate interest expense to discontinued operations unless debt is to be assumed by the buyer of our discontinued operations or debt is to be repaid as a result of the disposal of our discontinued operations.
Recent Accounting Pronouncements
In February 2016, the FASB issued ASU 2016-02, Leases, which requires recognition of lease assets and lease liabilities on the balance sheet and disclosure of key information about leasing arrangements. The standard will become effective for interim and annual periods beginning after December 15, 2018, with early adoption permitted. The guidance is required to be adopted at the earliest period presented using a modified retrospective approach. We are currently evaluating the impact this standard will have on our consolidated financial statements and whether we will adopt the guidance early.
In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes, which stipulates all deferred tax assets and liabilities are to be classified and presented in the balance sheet as non-current items. The guidance is effective for interim and annual periods beginning after December 15, 2016, with early adoption permitted, and may be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. We are currently evaluating whether we will early adopt this standard.
In September 2015, the FASB issued ASU 2015-16, Business Combinations: Simplifying the Accounting for Measurement-Period Adjustments, which requires acquirers to recognize adjustments to provisional amounts identified during the reporting period in which adjustments to business combination accounting are determined. Acquirers should record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. Application of the standard, which should be applied prospectively, is required for the annual and interim periods beginning after December 15, 2015. Early adoption is permitted. The new standard may have an impact on our consolidated financial statements in the event of a business combination.
In July 2015, the FASB issued ASU 2015-11, Simplifying the Measurement of Inventory, which is intended to simplify the subsequent measurement of inventories by replacing the current lower of cost or market test with a lower of cost and net realizable value test. The guidance applies only to inventories for which cost is determined by methods other than last-in first-out and the retail inventory method. Application of the standard, which should be applied prospectively, is required for the annual and interim periods beginning after December 15, 2016. Early adoption is permitted. We expect that the adoption of this standard will not have a material impact on our consolidated financial statements.
| F-14 |
In April 2015, the FASB issued ASU 2015-3, Simplifying the Presentation of Debt Issuance Costs, which requires debt issuance costs to be presented in the balance sheet as a reduction of the associated debt liability. This update is effective for interim and annual reporting periods beginning after December 15, 2015, and requires retrospective application. The adoption of this update is not expected to cause any material changes to our consolidated financial statements other than the reclassification of debt issuance costs from assets to a reduction of liabilities in our consolidated balance sheets.
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. We are currently evaluating the impact of the pending adoption of ASU 2014-09 on the consolidated financial statements.
Note 3 – Acquisitions
Acquisition of John D. Oil and Gas Marketing
On June 1, 2013, we and our 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, our former chairman and chief executive officer, is the sole trustee of the Osborne Trust. We believe the natural gas marketing business complements our existing natural gas distribution business in Ohio. In addition, JDOG Marketing currently conducts natural gas marketing in Montana and Wyoming, which we believe allowed it to integrate the Ohio marketing operations into our operations with minimal increases in staff or overhead. Costs related to this acquisition totaled $613 and were expensed as incurred. We recorded the consideration given, assets received, and liabilities assumed at their fair market value as of this date.
Under the purchase agreement, we issued to JDOG Marketing 256,926 shares of our common stock. These shares had an acquisition date fair value of $2,641. There were no underwriting discounts or commissions in connection with the issuance, as no underwriters were used to facilitate the acquisition. The shares were not registered under the Securities Act of 1933, as amended (the “Act”), in reliance on the exemption from registration provided by Section 4(2) of the Act.
In addition, the purchase agreement provided 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, 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 will be 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 settled annually in validly issued, fully paid and non-assessable shares of our common stock. The share price used to determine the number of shares to be issued for each earn-out payment will be the average closing price of our common stock for the 20 trading days preceding issuance of our common stock for such earn-out payment. We estimated the acquisition date fair value of this liability to be $2,250. The fair value of this liability is remeasured on a recurring basis. Our estimate of the total liability at December 31, 2015 and 2014 was $672 and $747, respectively. As of December 31, 2015 and 2014, $672 of the contingent consideration was included in other current liabilities, and at December 31, 2014, $75 was included in other long-term liabilities on our Consolidated Balance Sheets. See Note 8 – Fair Value Measurements for details regarding this valuation. We estimated a first year earn-out liability of $672 and do not believe we owe an earn-out liability for years two and three. We do 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. Richard M. Osborne believes that JDOG Marketing is entitled to the first year earn-out. Richard M. Osborne and JDOG Marketing have filed a suit against us for the earn-out payment. See Note 20 – Commitments and Contingencies for more information.
We 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. We used the net book value of property, plant, and equipment received, of $22, as this closely approximated the fair value. We computed the present value of expected net cash flows associated with the acquired customer contracts to approximate the assets’ fair values of $2,800. These customer contracts represent established and ongoing contracts to provide natural gas to the former customers of JDOG Marketing that we acquired as part of the acquisition. We will amortize these customer contracts over their 10 year estimated useful lives. We 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, we also effectively settled a note due from JDOG Marketing for $32 and settled an operating lease. As a result of the purchase, $2,102 was allocated to goodwill. We do not expect any of the goodwill to be deductible for tax purposes.
| F-15 |
The results of GNR are included in our marketing and production operations reporting segment. GNR contributed $3,222, $4,288 and $1,947 to our revenues for the years ended December 31, 2015, 2014 and 2013, respectively, and contributed $115, $(99) and $765 to our net income, respectively.
Historically, we have been a party to transactions with JDOG Marketing primarily for the purchase of natural gas. See Note 18 – Related Party Transactions for more information regarding our transactions with JDOG Marketing prior to the acquisition.
Acquisition of 8500 Station Street
On March 5, 2013, we purchased the Matchworks Building in Mentor, Ohio for $1,853 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, our former chairman and chief executive officer. The acquisition of the Matchworks Building was approved by the independent members of our board of directors. We formed a subsidiary, 8500 Station Street, to operate the property. We accounted for the transaction as an asset purchase and as such recorded the land and building purchased as property, plant and equipment on our Consolidated Balance Sheet in the amounts of $245 and $1,608, respectively. These amounts were allocated based on the assets’ relative fair values. During 2015, we sold the Matchworks building. See Note 5 – Disposals for more information regarding that transaction.
Note 4 – Discontinued Operations
The following table presents the carrying amounts of the major classes of assets and liabilities included in our discontinued operations as presented on our Consolidated Balance Sheet as of December 31, 2014. There were no items remaining on our Consolidated Balance Sheet as of December 31, 2015, related to discontinued operations.
| F-16 |
| Year ended December 31, 2014 | ||||||||||||
| EWW/Pipelines | Independence | Total | ||||||||||
| Current Assets: | ||||||||||||
| Cash and cash equivalents | $ | 257 | $ | - | $ | 257 | ||||||
| Accounts receivable, net | 1,003 | 2 | 1,005 | |||||||||
| Unbilled gas | 735 | - | 735 | |||||||||
| Inventory | 181 | - | 181 | |||||||||
| Prepayments and other | 71 | - | 71 | |||||||||
| Regulatory assets, current | 250 | - | 250 | |||||||||
| Total current assets | 2,497 | 2 | 2,499 | |||||||||
| Non-Current Assets: | ||||||||||||
| Property, plant & equipment, net | 8,967 | - | 8,967 | |||||||||
| Regulatory assets, non-current | 156 | - | 156 | |||||||||
| Other assets | 32 | - | 32 | |||||||||
| Total non-current assets | 9,155 | - | 9,155 | |||||||||
| Total discontinued assets | $ | 11,652 | $ | 2 | $ | 11,654 | ||||||
| Current Liabilities: | ||||||||||||
| Accounts payable | $ | 29 | $ | 1 | $ | 30 | ||||||
| Accrued liabilities | 334 | - | 334 | |||||||||
| Other current liabilities | 123 | 16 | 139 | |||||||||
| Total current liabilities | 486 | 17 | 503 | |||||||||
| Non-Current Liabilities: | ||||||||||||
| Customer advances for construction | 41 | - | 41 | |||||||||
| Total discontinued liabilities | $ | 527 | $ | 17 | $ | 544 | ||||||
The following table presents the amounts of the major line items that are included in discontinued operations, net of income tax that are presented on our Consolidated Statements of Comprehensive Income.
| Years ended December 31, | ||||||||||||
| 2015 | 2014 | 2013 | ||||||||||
| EWW/Pipeline assets | ||||||||||||
| Revenues | $ | 4,609 | $ | 10,927 | $ | 9,434 | ||||||
| Cost of sales | (2,534 | ) | (6,697 | ) | (5,260 | ) | ||||||
| Distribution, general & administrative | (780 | ) | (1,503 | ) | (1,443 | ) | ||||||
| Maintenance | (81 | ) | (175 | ) | (176 | ) | ||||||
| Depreciation & amortization | - | (542 | ) | (702 | ) | |||||||
| Taxes other than income | (169 | ) | (321 | ) | (332 | ) | ||||||
| Other income | 6 | 28 | 38 | |||||||||
| Interest expense | (412 | ) | (1 | ) | (2 | ) | ||||||
| Pretax income from discontinued operations | 639 | 1,716 | 1,557 | |||||||||
| Gain on the sale of EWW/Pipeline Assets | 5,368 | - | - | |||||||||
| Income tax expense | (2,458 | ) | (643 | ) | (368 | ) | ||||||
| Income from discontinued operations of EWW/Pipeline Assets | $ | 3,549 | $ | 1,073 | $ | 1,189 | ||||||
| Independence | ||||||||||||
| Loss from discontinued operations of Independence | (30 | ) | (40 | ) | (370 | ) | ||||||
| Discontinued operations, net of income tax | $ | 3,519 | $ | 1,033 | $ | 819 | ||||||
| F-17 |
EWW and the Glacier & Shoshone Pipelines
On October 10, 2014, we executed a stock purchase agreement for the sale of all of the stock of our wholly-owned subsidiary, EWW, to Cheyenne Light, Fuel and Power Company (“Cheyenne”). EWW has historically been included in our natural gas operations segment. In conjunction with this sale, our EWD 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 our pipeline segment. As a result of EWW and the Pipeline Asset’s classification as discontinued operations, their results have been included in our corporate and other segment for all periods presented. On July 1, 2015, the transaction was completed and we received proceeds, net of costs to sell, of $14,223 for the sale of EWW and $1,185 for the sale of the Pipeline Assets. We recorded gains on the sales of $4,869 and $499 for EWW and the Pipeline Assets, respectively, in discontinued operations. In connection with our sale of EWW and the Pipeline Assets, during the fourth quarter of 2015 we committed to repay the portion of notes payable to Allstate/CUNA that was allocated to EWW and EWD on February 12, 2016, including a prepayment penalty of $310. Additionally, we wrote off the unamortized debt issue costs that were allocated to EWW and EWD’s portion of the debt, totaling $103. These amounts were recognized within interest expense related to the EWW/Pipeline Assets in the table above, and within discontinued operations, net of tax on our Consolidated Statements of Comprehensive Income. See Note 14 – Credit Facilities and Long-Term Debt for more information regarding our debt agreements.
Our subsidiary, EWR, continues 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. Additionally, 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. During 2015, we received $1,550 from Black Hills for gas and transportation under these ongoing agreements, and we recorded revenue of $1,832 related to these transactions in our income from continuing operations. These transactions are a continuation of transactions that were conducted prior to the sales of EWW and the Pipeline Assets and were eliminated through the consolidation process until their sale to third parties.
| F-18 |
Independence
On November 6, 2013, we closed on the sale of Independence to Blue Ridge Energies, LLC (“Blue Ridge”) for a total of $2,342. We recorded a loss on sale of $8 in the fourth quarter of 2013. We have reclassified the results of operations and financial position for Independence to the discontinued operations sections of our consolidated financial statements. Independence was our only subsidiary included in our propane segment. Independence’s results have been included in our corporate and other segment for all periods presented as a result of its classification as discontinued operations. We do not have any material continuing cash flows or other contractual obligations associated with this sales transaction.
Note 5 – Disposals
We have recently completed certain divestitures as part of our strategy to monetize non-core assets so that we may direct our energies and resources on operations that we believe have higher growth potential. The sale of these assets does not constitute a strategic shift that will have a major effect on our operations or financial results and as such, the disposals are not classified as discontinued operations in our consolidated financial statements.
On October 15, 2015, we sold an office building in Mentor, Ohio for net proceeds of $1,220, which resulted in a loss on the transaction of $409, based on the carrying value of the property of $1,760 and the costs to sell the property. This represents substantially all of the assets of our 8500 Station Street subsidiary. We recorded this loss in other income in the accompanying Consolidated Statements of Comprehensive Income for the year ended December 31, 2015. Including the loss on the sale transaction, 8500 Station Street experienced a pre-tax loss of $469, which is included in our pre-tax income from continuing operations for the year ended December 31, 2015. Our 8500 Station Street subsidiary has historically been reported as a component of our natural gas operations segment and contributed $161 and $80 to our pre-tax income from continuing operations for the years ended December 31, 2014 and 2013, respectively.
In November 2015, we sold nearly all of the assets and liabilities of our Clarion and Walker Pennsylvania utilities to Utility Pipeline, LTD for proceeds of $848, which resulted in a gain on the transaction of $415. Including the gain on the sale transaction, Clarion and Walker contributed $350 to our pre-tax income from continuing operations for the year ended December 31, 2015. Clarion and Walker have historically been reported as a component of our natural gas operations segment and collectively contributed $213 and $46 to our pre-tax income/(loss) from continuing operations for the years ended December 31, 2014 and 2013, respectively.
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 | |||
| Unbilled gas | 22 | |||
| Inventory | 4 | |||
| Prepayments and other | 5 | |||
| Regulatory assets, current | 203 | |||
| Total current assets | 283 | |||
| Non-Current Assets: | ||||
| Property, plant & equipment, net | 407 | |||
| Goodwill | 112 | |||
| Total non-current assets | 519 | |||
| Total assets held for sale | $ | 802 | ||
| Current Liabilities: | ||||
| Accounts payable | 36 | |||
| Accrued liabilities | 22 | |||
| Other current liabilities | 3 | |||
| Total liabilities held for sale | $ | 61 | ||
| F-19 |
On December 11, 2015, we sold to Kentucky Frontier Gas, LLC nearly all the assets and liabilities of our subsidiary PGC in Kentucky, for proceeds of $1,900, which resulted in a loss on the transaction of $341, based on the carrying value of our assets and our costs to sell the assets. These losses were recorded in other income in the accompanying Consolidated Statement of Comprehensive Income for the year ended December 31, 2015. Including the loss on the sale transaction, PGC experienced a pre-tax loss of $626, which is included in our pre-tax income from continuing operations for the year ended December 31, 2015. PGC has historically been reported as a component of our natural gas operations segment and accounted for losses of $225 and $31 included in our pre-tax income from continuing operations for the years ended December 31, 2014 and 2013, respectively. At December 31, 2014, the balance of PGC’s assets that were sold during 2015 included inventory of $47, deferred purchased gas costs of $66, property plant and equipment, net, of $2,090 and goodwill of $284.
Note 6 - Goodwill
In June 2013, we and our wholly-owned Ohio subsidiary, GNR, finalized our purchase of substantially all the assets and certain liabilities of JDOG Marketing. We accounted for this transaction as a business combination and as a result recognized $2,102 of goodwill. See Note 3 – Acquisitions for more information regarding this transaction. We used many estimates in the determination of the acquisition date fair value of JDOG Marketing, including the amount of future sales between GNR and two of our 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 our NEO and Orwell subsidiaries for failure to terminate natural gas purchase agreements with JDOG Marketing. As a result of these fines, we have ceased all future purchases by NEO and Orwell of natural gas from GNR. We are 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 our marketing and production segment. We calculated this impairment charge using both a discounted cash flow method and a guideline public company method.
The schedule below presents the changes in the carrying amount of goodwill for the years ended December 31, 2015 and 2014:
| Natural Gas | Marketing and Production | Total | ||||||||||
| Balance as of December 31, 2013 | $ | 14,891 | $ | 1,376 | $ | 16,267 | ||||||
| Goodwill reclassified to assets held for sale | (111 | ) | - | (111 | ) | |||||||
| Balance as of December 31, 2014 | 14,780 | 1,376 | $ | 16,156 | ||||||||
| Goodwill reclassified to assets held for sale | (284 | ) | - | (284 | ) | |||||||
| Balance as of December 31, 2015 | $ | 14,496 | $ | 1,376 | $ | 15,872 | ||||||
| F-20 |
The following table presents our gross goodwill balance and accumulated impairment loss as of December 31, 2015 and 2014.
| December 31, | ||||||||
| 2015 | 2014 | |||||||
| Goodwill, gross | ||||||||
| Natural gas | $ | 14,496 | $ | 14,780 | ||||
| Marketing and production | 2,102 | 2,102 | ||||||
| Total goodwill, gross | 16,598 | 16,882 | ||||||
| Accumulated impairment loss | ||||||||
| Natural gas | - | - | ||||||
| Marketing and production | (726 | ) | (726 | ) | ||||
| Total accumulated impairment loss | (726 | ) | (726 | ) | ||||
| Goodwill, net | $ | 15,872 | $ | 16,156 | ||||
Note 7 - Investment in Unconsolidated Affiliate
Our EWR subsidiary, which is part of our marketing and production segment, owns a 24.5% interest in Kykuit, a developer and operator of oil, gas and mineral leasehold estates located in Montana. We account for the investment in Kykuit using the equity method. We have invested $2,160 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, 2015, we are obligated to invest no more than an additional $79 over the life of the venture. Other investors in Kykuit include Richard M. Osborne, our 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 ours and our former chief financial officer and a director of John D. Oil and Gas Company; and Gregory J. Osborne, chief executive officer and a member of our board of directors 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, we impaired the balance of our investment in Kykuit in 2014. This expense is included in our loss from unconsolidated affiliate in the accompanying Consolidated Statement of Comprehensive Income for the year ended December 31, 2014.
Note 8 – Fair Value Measurements
We follow 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.
We categorize our fair value measurements within the hierarchy based on the lowest level input that is significant to the fair value measurement in its entirety. The following table presents the amount and level in the fair value hierarchy of each of our assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2015 and 2014.
| F-21 |
| December 31, 2015 | ||||||||||||||||
| Level 1 | Level 2 | Level 3 | TOTAL | |||||||||||||
| LIABILITIES: | ||||||||||||||||
| Contingent consideration | $ | - | $ | - | $ | 672 | $ | 672 | ||||||||
| Commodity swap contracts | $ | - | $ | 54 | $ | - | $ | 54 | ||||||||
| December 31, 2014 | ||||||||||||||||
| Level 1 | Level 2 | Level 3 | TOTAL | |||||||||||||
| LIABILITIES: | ||||||||||||||||
| Contingent consideration | $ | - | $ | - | $ | 747 | $ | 747 | ||||||||
| Commodity swap contracts | $ | - | $ | 3,023 | $ | - | $ | 3,023 | ||||||||
The fair value of our 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.
Commodity Swaps Contracts
We value our commodity swap contracts, which are categorized in Level 2 of the fair value hierarchy, by comparing the futures price at the measurement date of the natural gas commodity specified in the contract to the fixed price that we will pay. See Note 9 – Derivative Financial Instruments for more information regarding our commodity swap contracts.
Contingent Consideration Liability
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. The purchase agreement for the transaction provided for contingent “earn-out” payments in the form of validly issued, fully paid and non-assessable shares of the Company’s common stock for a period of five years after the closing of the transaction if the acquired business achieved a minimum annual EBITDA target of $810. If the acquired business’s actual EBITDA for a given year is less than the target EBITDA, then no earn-out payment is due and payable for that period. If the acquired business’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 multiplied by $575 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 indeterminate.
We have recorded a liability for an earn-out payment for the year ended December 31, 2013. We do not believe an 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. Richard M. Osborne, our former chairman and chief executive officer believes that JDOG Marketing is entitled to the earn-out. Richard M. Osborne and JDOG Marketing have filed a suit against us for the earn-out payment for 2013. In addition, the acquired business did not achieve the minimum annual EBITDA target in 2014 or 2015. See Note 20 – Commitments and Contingencies for more information about the litigation between us and Richard M. Osborne.
Valuation of the contingent consideration liability for financial statement purposes was conducted by an independent third-party valuation firm. We reviewed the inputs and assumptions used in the valuation for reasonableness in the course of the valuation process and those inputs and assumptions were updated to reflect changes in our business environment.
| F-22 |
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 | ||||||||
| 2015 | 2014 | |||||||
| Balance January 1st | $ | 747 | $ | 685 | ||||
| Total (gains) losses for period: | ||||||||
| Included in net income | (75 | ) | 62 | |||||
| Included in other comprehensive income | - | - | ||||||
| Balance December 31st | $ | 672 | $ | 747 | ||||
The change in fair value included in net income in the table above is reflected in our contingent consideration loss (gain) in our accompanying Consolidated Statements of Comprehensive Income and is the result of an unrealized holding loss (gain) associated with the change in the fair value of our contingent consideration liability.
The following table summarizes quantitative information used in determining the fair value of our 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, 2015 | ||||||||||
| Contingent Consideration | $ | 672 | Monte Carlo analysis | Forecasted annual EBITDA | $500-$600 | |||||
| Weighted avg cost of capital | 14.0% - 14.0% | |||||||||
| U.S. Treasury yields | 0.7% - 1.1% | |||||||||
| Discounted cash flow | U.S. Treasury yields | 0.7% - 1.1% | ||||||||
| Credit spread | 2.0% - 2.4% | |||||||||
| December 31, 2014 | ||||||||||
| Contingent Consideration | $ | 747 | Monte Carlo analysis | Forecasted annual EBITDA | $500 - $700 | |||||
| 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 | 2.1% - 2.7% | |||||||||
The fair value measure of our contingent consideration liability has significant unobservable inputs, including our weighted average cost of capital, our credit spread above the risk free rate and our GNR subsidiary’s forecasted future cash flows. A significant increase (decrease) in these inputs could result in a significant increase (decrease) in the fair value measure.
Note 9 – Derivative Financial Instruments
We enter 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 we will pay for specified notional quantities of natural gas. We have not designated any of these commodity swaps contracts as hedging instruments.
| F-23 |
The following table summarizes our commodity swap contracts outstanding as of December 31, 2015. We will pay the fixed price listed based on the volumes denoted in the table below in exchange for a variable payment from a counterparty 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 | ||||||||||||
| AECO Canada - CGPR 7A Natural Gas | Swap | 4/1/15 - 3/31/16 | 500 MMBtu/Day | $ | 2.420 | |||||||||||
| AECO Canada - CGPR 7A Natural Gas | Swap | 11/1/15 - 3/31/16 | 500 MMBtu/Day | $ | 2.260 | |||||||||||
We included in cost of sales in the accompanying Consolidated Statements of Comprehensive Income, $2,759 of losses on commodity swap agreements not designated as hedging instruments for the year ended December 31, 2015, related to our regulated utilities. (Gains)/losses on commodity swap agreements not designated as hedging instruments for non-regulated subsidiaries were $(96) and $151 for the years ended December 31, 2015 and 2014, respectively. We did not have any commodity swap agreements during 2013. As of December 31, 2015 and 2014, we included $54 and $3,023 of unrealized losses on our commodity swap contracts that are not designated as hedging instruments in derivative instruments in the accompanying Consolidated Balance Sheets.
Note 10 – Regulatory Assets and Liabilities
The following table summarizes the components of our regulatory asset and liability balances at December 31, 2015 and 2014.
| December 31, | ||||||||||||||||
| 2015 | 2014 | |||||||||||||||
| Current | Long-term | Current | Long-term | |||||||||||||
| REGULATORY ASSETS | ||||||||||||||||
| Recoverable cost of gas purchases | $ | 1,936 | $ | - | $ | 692 | $ | - | ||||||||
| Deferred costs | 490 | 1,226 | 491 | 1,715 | ||||||||||||
| Deferred loss on commodity swaps | - | - | 2,872 | - | ||||||||||||
| Income taxes | - | 297 | - | 297 | ||||||||||||
| Rate case costs | 43 | - | 43 | 43 | ||||||||||||
| Total regulatory assets | $ | 2,469 | $ | 1,523 | $ | 4,098 | $ | 2,055 | ||||||||
| REGULATORY LIABILITIES | ||||||||||||||||
| Over-recovered gas pruchases | $ | 487 | $ | - | $ | 925 | $ | - | ||||||||
| Income taxes | - | 83 | - | 83 | ||||||||||||
| Asset retirement costs | - | 1,168 | - | 1,007 | ||||||||||||
| Total regulatory liabilities | $ | 487 | $ | 1,251 | $ | 925 | $ | 1,090 | ||||||||
Recoverable Cost of Gas Purchases/Over-recovered Gas Purchases
We account for purchased gas costs in accordance with procedures authorized by the utility commissions in the states in which we operate. 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). We generally recover or credit these amounts through rates within one year. The regulatory commissions in all of the states in which we operate closely monitor gas cost recovery mechanisms, and gas cost recoveries are subject to periodic audits or other review processes.
Deferred Costs
On June 27, 2014, our 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 $2,450 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 a 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 rates, exclusive of cost of gas, for the same five year period.
| F-24 |
Unrealized Loss on Commodity Swaps
Our regulated subsidiaries defer recognition of unrealized losses and gains on their commodity swap derivative instruments as regulatory assets and liabilities, respectively. We recognize unrealized losses and gains as a component of cost of sales – natural gas purchased on our Consolidated Statement of Comprehensive Income during the period in which they are settled and recovered through rates. The regulatory asset on our Consolidated Balance Sheet at December 31, 2014, was recovered during 2015.
Income Taxes
Both the regulatory asset and regulatory liability related to income taxes is included in our rate base and upon which we earn a return.
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 | % | ||||||
We accrue these liabilities 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, 2015, none of the assets included in these asset classes have been retired.
Other Regulatory Assets
Our rate case costs do not earn a return and will be amortized over a period of 2 to 3 years.
| F-25 |
Note 11 – Earnings per Share
| Year Ended December 31, | ||||||||||||
| 2015 | 2014 | 2013 | ||||||||||
| Numerator: | ||||||||||||
| Income from continuing operations | $ | 1,169 | $ | 2,729 | $ | 5,852 | ||||||
| Income from discontinued operations | 3,519 | 1,033 | 819 | |||||||||
| Net income | $ | 4,688 | $ | 3,762 | $ | 6,671 | ||||||
| Denominator: | ||||||||||||
| Basic weighted average common shares outstanding | 10,496,979 | 10,478,312 | 9,339,002 | |||||||||
| Dilutive effect of stock options | - | - | 720 | |||||||||
| Dilutive effect of restricted stock awards | 1,476 | 505 | - | |||||||||
| Diluted weighted average common shares outstanding | 10,498,455 | 10,478,817 | 9,339,722 | |||||||||
| Basic & diluted earnings per share of common stock: | ||||||||||||
| Continuing operations | $ | 0.11 | $ | 0.26 | $ | 0.63 | ||||||
| Discontinued operations | 0.34 | 0.10 | 0.08 | |||||||||
| Net income | $ | 0.45 | $ | 0.36 | $ | 0.71 | ||||||
We compute basic earnings per share by dividing net income by the weighted average number of common shares outstanding during the period. We compute diluted earnings per share by adjusting the weighted average outstanding shares, assuming conversion of all potentially dilutive shares, using the treasury stock method. 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, 2015, 2014 and 2013. Unvested restricted stock awards are treated as participating securities because they participate equally in dividends and earnings with other common shares.
Note 12 – Property, Plant & Equipment
Components of property, plant, and equipment were as follows:
| December 31, | ||||||||
| 2015 | 2014 | |||||||
| Gas transmission & distribution facilities | $ | 144,977 | $ | 162,912 | ||||
| Land | 6,074 | 3,774 | ||||||
| Buildings & leasehold improvements | 9,746 | 11,213 | ||||||
| Transportation equipment | 5,749 | 3,809 | ||||||
| Other equipment | 17,232 | 15,180 | ||||||
| Producing natural gas properties | 4,032 | 3,900 | ||||||
| Construction work in progress | 4,878 | 8,646 | ||||||
| Property, plant & equipment | 192,688 | 209,434 | ||||||
| Accumulated depreciation, depletion & amortization | (50,237 | ) | (58,049 | ) | ||||
| 142,451 | 151,385 | |||||||
| Assets held for sale | (35 | ) | (407 | ) | ||||
| Discontinued operations | - | (8,967 | ) | |||||
| Property, plant & equipment, net | $ | 142,416 | $ | 142,011 | ||||
At December 31, 2015 and 2014, we reflected in our Consolidated Balance Sheets $9,852 and $6,525 of property, plant and equipment related to our new ERP system. At December 31, 2014, we included all these assets in construction work in progress and as of December 31, 2015, two of three phases of that project were completed and $7,521 of the related assets were classified as other equipment under a capital lease, while the balance related to phase three remained in construction work in progress. See Note 20 - Commitments and Contingencies for information regarding our capital leases. The cost basis and accumulated depreciation of assets recorded under capital leases, which are included in property, plant, and equipment on our Consolidated Balance Sheets are as follows as of December 31, 2015 and 2014:
| F-26 |
| December 31, | ||||||||
| 2015 | 2014 | |||||||
| Gas transmission & distribution facilities | $ | 6,320 | $ | 6,320 | ||||
| Other equipment | 7,521 | - | ||||||
| Capital lease assets, gross | 13,841 | 6,320 | ||||||
| Accumulated depreciation | (1,467 | ) | (903 | ) | ||||
| Capital lease assets, net | $ | 12,374 | $ | 5,417 | ||||
We recorded depreciation expense on assets under capital leases of $564, $401 and $401, for the years ended December 31, 2015, 2014 and 2013, respectively.
Producing Natural Gas Properties
In order to provide a stable source of natural gas for a portion of its requirements, EWR and EWD own two natural gas production properties and three gathering systems located in north central Montana. We deplete the cost of the gas properties using the units-of-production method. As of December 31, 2015 and 2014, we estimated, based on reserve estimates provided by an independent reservoir engineer, the net gas reserves at 1.5 Bcf (unaudited) and 2.1 Bcf (unaudited), respectively, and that the gas reserves had net present values of $686 and $2,696 respectively, after applying a 10% discount (unaudited). The net book value of the gas properties was $782 and $864 at December 31, 2015 and 2014, respectively.
We deplete the wells based upon production at approximately 13%, 10% and 10% per year as of December 31, 2015, 2014 and 2013, respectively. For the years ended December 31, 2015, 2014 and 2013, EWR’s portion of the daily gas production was 318 Mcf, 395 Mcf and 422 Mcf per day, or 16.2%, 20.0% and 19.0% 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, 2015, 2014 and 2013, EWD’s portion of the daily gas production was 114 Mcf, 107 Mcf and 129 Mcf per day, or 5.8%, 5.5% and 5.8% of EWR’s volume requirements, respectively.
For the years ended December 31, 2015, 2014 and 2013, EWR and EWD’s combined portion of the estimated daily gas production from the reserves was 432 Mcf, 502 Mcf and 550 Mcf, or 22.0%, 26.0% and 25.0% of our volume requirements in our Montana market, respectively. The wells are operated by an independent third party operator who also has an ownership interest in the properties.
Note 13 – Asset Retirement Obligations
We have identified but not recognized ARO liabilities related to gas transmission and distribution assets resulting from easements over property that we do not own. These easements are generally perpetual and only require retirement action upon abandonment or cessation of use of the property for the specified purpose. We cannot estimate an ARO liability for such easements as we intend to utilize these properties indefinitely. In the event that we decide to abandon or cease the use of a particular easement, an ARO liability will be recorded at that time.
Our recognized asset retirement obligations represent the estimated costs to retire certain natural gas producing wells. The following schedule presents our recognized asset retirement obligations, included in other long-term liabilities in our Consolidated Balance Sheets as of December 31, 2015 and 2014.
| 2015 | 2014 | |||||||
| Balance, January 1st | $ | 1,197 | $ | 1,145 | ||||
| Accretion expense | 21 | 52 | ||||||
| Balance, December 31st | $ | 1,218 | $ | 1,197 | ||||
| F-27 |
We have no assets that are legally restricted for purposes of settling our AROs. As of December 31, 2014, we included $49 of capitalized ARO costs, net of accumulated depreciation, in property, plant and equipment. As of December 31, 2015, our ARO costs were fully depreciated.
Note 14 – Credit Facilities and Long-Term Debt
The following table presents our outstanding borrowings at December 31, 2015 and 2014.
| December 31, | ||||||||
| 2015 | 2014 | |||||||
| Current borrowings | ||||||||
| 6.95% NIL Funding fixed rate note to related party, due April 20, 2016 | $ | 2,000 | $ | - | ||||
| LIBOR plus 1.75 to 2.25%, Bank of America line of credit, due April 1, 2017 | 15,750 | 28,761 | ||||||
| Total current borrowings | $ | 17,750 | $ | 28,761 | ||||
| Long-term notes payable | ||||||||
| LIBOR plus 1.75 to 2.25%, Bank of America amortizing term loan, due April 1, 2017 | $ | 8,375 | $ | 8,875 | ||||
| 6.16%, Allstate/CUNA Senior unsecured note, due June 29, 2017 | 13,000 | 13,000 | ||||||
| 5.38%, Sun Life fixed rate note, due June 1, 2017 | 15,334 | 15,334 | ||||||
| 4.15% Sun Life senior secured guaranteed note, due June 1, 2017 | 2,990 | 2,990 | ||||||
| Vehicle and equipment financing loans | 22 | 64 | ||||||
| Total long-term notes payable | 39,721 | 40,263 | ||||||
| Less: current portion | 5,012 | 542 | ||||||
| Long-term notes payable, less current portion | $ | 34,709 | $ | 39,721 | ||||
The weighted average interest rate on our current borrowings was 2.95%, 2.45%, and 2.42% during 2015, 2014, and 2013, respectively, and the weighted average interest rate on our current borrowings outstanding as of December 31, 2015 and 2014, was 2.71% and 2.44%, respectively.
The following table presents the aggregate future maturities of our long-term notes payable outstanding as of December 31, 2015.
| Amounts due in years ending December 31, | ||||
| 2016 | $ | 5,012 | ||
| 2017 | 34,706 | |||
| 2018 | 3 | |||
| Total | $ | 39,721 | ||
Bank of America
Our Energy West subsidiary has a credit facility with the Bank of America (“Credit Facility”) that provides for a revolving credit facility with a maximum borrowing capacity of $30,000, due April 1, 2017. On November 26, 2014, we entered into an amendment temporarily increasing the borrowing capacity by $10,000 to a maximum of $40,000 until July 1, 2015, and the additional capacity was repaid prior to that date. In an order approving this temporary increase in borrowing capacity, the MPSC stated that any amounts borrowed under this increase in excess of $5,000 would first require the approval of the MPSC. This revolving credit facility includes an annual commitment fee ranging from 25 to 45 basis points of the unused portion of the facility and accrues interest based on our option of two indices - a base rate, which is defined as a daily rate based on the highest of the prime rate, the Federal Funds Rate plus 50 basis points or the daily LIBOR rate plus 100 basis points, or LIBOR plus 175 to 225 basis points. At December 31, 2015, we did not have any base rate borrowings. The weighted average outstanding interest rate on our revolving line of credit as of December 31, 2015 and 2014, was 2.17% and 2.44%, respectively. After considering outstanding letters of credit of $155, a total of $14,095 was available to us for loans and letters of credit under the revolving credit facility as of December 31, 2015.
| F-28 |
In addition, Energy West has a $10,000 term loan with Bank of America with a maturity date of April 1, 2017 (the "Term Loan"). The Term Loan portion of the Credit Facility bears interest at a rate of LIBOR plus 175 to 225 basis points and contains an interest rate swap provision that allows for the interest rate to be fixed in the future, but we have not exercised that provision. The Term Loan amortizes at a rate of $125 per quarter. At December 31, 2015 and 2014, the Term Loan bore interest at 2.17%, and had a balance of $8,375 and $8,875, respectively.
The Bank of America revolving credit agreement and term loan contain various covenants, which require 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 Bank of America agreements establish limits on Energy West’s ability to incur additional borrowings, pay dividends, redeem or repurchase stock, consummate a merger or acquisition and dispose of assets.
NIL Funding
On October 23, 2015, we entered into a loan agreement and promissory note for $3,000 with NIL Funding. Under the note and loan agreement, we make monthly interest payments to NIL Funding and the principal balance of the note is due upon maturity. We made a principal payment of $1,000 on the note during December 2015. Our loan agreement with NIL Funding restricts our ability to incur additional borrowings, make new investments, consummate a merger or acquisition and dispose of assets. In an event of default, as defined under the loan agreement, NIL Funding may, at its option, require us to immediately pay the outstanding principal balance of the note as well as any and all interest and other payments due or convert any part of the amounts due and unpaid to shares of our common stock at a conversion price of 95% of the previous day’s closing price on the NYSE MKT. NIL Funding is a related party of ours. See Note 18 – Related Party Transactions for further details.
On April 6, 2015, we entered into a loan agreement and promissory note with NIL Funding. Pursuant to the note and loan agreement, NIL Funding loaned Gas Natural $5,000, bearing an annual interest rate of 7.5%, and a maturity date of October 3, 2015. On July 27, 2015, the NIL Funding credit facility was paid off and extinguished.
Allstate/CUNA
In connection with our sale of EWW and the Pipeline Assets, during the fourth quarter of 2015 we committed to repay $4,500, plus a prepayment penalty of $310 for the portion of notes payable to Allstate/CUNA that was allocated to EWW and EWD on February 12, 2016. Additionally, we wrote off the unamortized debt issue costs that were allocated to EWW and EWD’s portion of the debt, totaling $103. These amounts were recognized within discontinued operations, net of tax on our Consolidated Statements of Comprehensive Income. See Note 4 – Discontinued Operations for more information regarding our discontinued operations.
The Allstate/CUNA senior unsecured note is an obligation of Energy West. 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 fixed rate note is a joint obligation of Gas Natural Inc., NEO, Orwell and Brainard, and is guaranteed by Gas Natural Inc., Lightning Pipeline and Great Plains (the “Obligors”). This note received approval from the PUCO on March 30, 2011. The note is governed by a note purchase agreement. Under the note purchase agreement, we are required to make monthly interest payments and the principal is due at maturity. Prepayment of this note prior to maturity is subject to a 50 basis point make-whole premium.
The Sun Life senior secured guaranteed note is a joint obligation of NEO, Orwell, and Brainard and is guaranteed by our non-regulated Ohio subsidiaries.
| F-29 |
The Sun Life covenants restrict certain cash balances and requires a debt service reserve account to be maintained to cover approximately one year of interest payments. The total balance in the debt service reserve account was $948 at both December 31, 2015 and 2014, and is included in restricted cash on our Consolidated Balance Sheets. The debt service reserve account cannot be used for operating cash needs. The Sun Life agreements establish limits on the Obligors’ ability to incur additional borrowings, pay dividends, redeem or repurchase stock, consummate a merger or acquisition and dispose of assets. We received consent from Sun Life, under its covenant restrictions, approving the sale of Independence prior to the finalization of the transaction. 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. An event of default, if not cured or waived, 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 any collateral that secures the indebtedness incurred under the notes.
On May 31, 2014, we loaned $3,100 to Great Plains, one of the Obligors under the note purchase agreements. The loan was not evidenced by a promissory note and pledged to Sun Life as required by certain covenants in the note purchase agreement. On July 8, 2015, Great Plains executed a $3,100 revolving note payable to us, which was pledged to Sun Life. Concurrently, we entered into a limited waiver to the note purchase agreement with Sun Life, curing the breach of the covenants.
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 notes also require that we do not permit indebtedness to exceed 60% of capitalization at any time. The interest coverage ratio and the debt to capitalization ratio are measured with respect to the Obligors on a consolidated basis and also with respect to us and all of our subsidiaries on a consolidated basis.
We believe that we were in compliance with all of our debt covenants as of December 31, 2015.
Note 15 – Stockholders’ Equity
Stock Repurchase Plan
Our common stock trades on the NYSE MKT Equities under the symbol EGAS. The Board of Directors approved a stock repurchase plan whereby we may buy back up to 448,500 shares of our common stock. As of December 31, 2015, we have not repurchased any stock.
Stock Compensation
The 2012 Incentive and Equity Award Plan (“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 Equity Award Plan provides for 500,000 shares authorized for issuance.
During 2015, we granted 12,223 common shares to our directors under the Equity Award Plan, with an aggregate market value of $120, based on the closing prices of our common shares on the dates of the awards. The weighted average grant date fair value was $9.81 per share and we recognized an aggregate compensation expense of $120 on the grant dates because shares granted to directors vest immediately. An additional 3,000 shares with a value of $22 were earned during 2015 and granted to directors in 2016. As of December 31, 2015, there were 451,944 shares available to issue under the Equity Award Plan.
On March 26, 2014, the board of directors granted an award of our common stock to each of our directors. The total number of shares awarded was 30,833 with a grant date fair value of $307. 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 board of directors granted 5,000 shares of restricted stock to Gregory J. Osborne, our chief executive officer member of our board of directors. These shares had a grant date fair value of $11.64 per share or $58 in aggregate, based upon the closing price of our common shares on the date of the award. During the years ended December 31, 2015 and 2014, we recorded $19 and $9, respectively, of compensation expense related to the vesting of the restricted stock. At December 31, 2015, $30 remained unvested 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.
| F-30 |
| Restricked Stock | ||||
| Awards | ||||
| Outstanding, December 31, 2014 | 5,000 | |||
| Granted | - | |||
| Vested | (1,667 | ) | ||
| Forfeited | - | |||
| Outstanding, December 31, 2015 | 3,333 | |||
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 our common stock by providing written notice to us. The plan authorized the issuance of 250,000 shares to non-employee directors in lieu of fees. As of December 31, 2015, no shares had been issued under the plan.
Restrictions on Dividends
Our subsidiaries are subject to several restrictions on the amounts that they can distribute to our holding company. In addition to the debt covenants discussed in Note 14 – Credit Facilities and Long-Term Debt, the MPUC, MPSC and NCUC 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 our holding company, which limits the funds available to be paid as dividends to our shareholders. On November 24, 2014, the MPSC issued an order directing, in part, that Energy West and its Montana, Maine, and North Carolina operating subsidiaries were restricted from paying dividends to Gas Natural until persuasive evidence could be presented that Energy West was on a sound financial footing and that effect had been given to the MPSC’s ring-fencing conditions; the strongest indication being the absence of ongoing balances owed to Energy West by Gas Natural. On April 9, 2015, Energy West filed a request to reinstate Energy West and its Montana, Maine, and North Carolina operating subsidiaries ability to pay dividends to Gas Natural. On July 22, 2015, the MPSC issued an order allowing for the reinstatement of the dividends. They also approved a special dividend to be declared from the proceeds from the sale of Energy West’s subsidiaries EWW and the Shoshone and Glacier pipeline assets.
At December 31, 2015, $76,233 of $95,489, or 79.8%, of our total net assets were restricted by our debt covenants and ring fencing restrictions.
Note 16 – Employee Benefit Plans
We have a defined contribution plan (the "401k Plan") that covers substantially all of our employees. The plan provides for an annual contribution of 3% of all employees’ salaries and an additional contribution of 10% of each participant’s elective deferrals which is invested in shares of our common stock under the 401k Plan. We recognized $462, $549 and $440 of contributions to the 401k Plan for the years ended December 31, 2015, 2014 and 2013, respectively.
We sponsored a defined postretirement health benefit plan (the "Retiree Health Plan") providing health and life insurance benefits to eligible retirees. We discontinued contributions in 2006 and are no longer required to fund the Retiree Health Plan. The Plan pays eligible retirees (post-65 years of age) a monthly stipend 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. As of December 31, 2015 and 2014, the value of plan assets was $102 and $133, respectively. The assets remaining in the trust will be used to fund the plan until these assets are exhausted.
| F-31 |
Note 17 – Income Taxes
Significant components of the deferred tax assets and liabilities are as follows:
| December 31, | ||||||||||||||||
| 2015 | 2014 | |||||||||||||||
| Current | Long-term | Current | Long-term | |||||||||||||
| Deferred tax assets: | ||||||||||||||||
| Allowance for doubtful accounts | $ | 190 | $ | - | $ | 142 | $ | - | ||||||||
| Contributions in aid of construction | - | 342 | - | 2,481 | ||||||||||||
| Asset retirement obligations | - | 448 | - | - | ||||||||||||
| Other nondeductible accruals | 33 | - | 46 | - | ||||||||||||
| Recoverable purchase gas costs | 182 | - | 217 | - | ||||||||||||
| Net operating loss carryforwards | - | 12,455 | - | 13,256 | ||||||||||||
| Property tax | - | - | 158 | - | ||||||||||||
| Other | 12 | 627 | 451 | - | ||||||||||||
| Total deferrred tax assets | 417 | 13,872 | 1,014 | 15,737 | ||||||||||||
| Deferred tax liabilities: | ||||||||||||||||
| Recoverable purchase gas costs | 720 | - | 379 | - | ||||||||||||
| Property, plant and equipment | - | 18,439 | - | 17,376 | ||||||||||||
| Unrealized gain on securities available for sale | - | 581 | - | 549 | ||||||||||||
| Amortization of intangibles | - | 247 | - | 738 | ||||||||||||
| Other | - | 371 | - | 1,115 | ||||||||||||
| Total deferrred tax liabilities | 720 | 19,638 | 379 | 19,778 | ||||||||||||
| Net deferred tax asset (liability) before valuation allowance | (303 | ) | (5,766 | ) | 635 | (4,041 | ) | |||||||||
| Less: valuation allowance | - | (6,529 | ) | - | (6,497 | ) | ||||||||||
| Total deferred tax asset (liability) | $ | (303 | ) | $ | (12,295 | ) | $ | 635 | $ | (10,538 | ) | |||||
Our current deferred tax assets and current deferred tax liabilities are included in other current assets and other current liabilities, respectively, on our Consolidated Balance Sheets.
| F-32 |
Income tax expense from continuing operations consists of the following:
| Year Ended December 31, | ||||||||||||
| 2015 | 2014 | 2013 | ||||||||||
| Current income tax expense (benefit): | ||||||||||||
| Federal | $ | 468 | $ | 49 | $ | (344 | ) | |||||
| State | 227 | 11 | 121 | |||||||||
| Total current income tax expense (benefit) | 695 | 60 | (223 | ) | ||||||||
| Deferred income tax expense: | ||||||||||||
| Federal | 2,043 | 1,988 | 3,692 | |||||||||
| State | 128 | 138 | (200 | ) | ||||||||
| Total deferred income tax expense | 2,171 | 2,126 | 3,492 | |||||||||
| Total income taxes before credits | 2,866 | 2,186 | 3,269 | |||||||||
| Investment tax credit, net | (21 | ) | (21 | ) | (21 | ) | ||||||
| Total income tax expense | 2,845 | 2,165 | 3,248 | |||||||||
| Income tax expense from discontinued operations | (2,428 | ) | (617 | ) | (224 | ) | ||||||
| Income tax expense from continuing operations | $ | 417 | $ | 1,548 | $ | 3,024 | ||||||
A reconciliation of taxes computed at the statutory federal rate to our effective tax is as follows:
| Year Ended December 31, | ||||||||||||
| 2015 | 2014 | 2013 | ||||||||||
| Tax expense at federal statutory rate | $ | 2,561 | $ | 2,015 | $ | 3,373 | ||||||
| State income tax, net of federal tax expense | 307 | 307 | 348 | |||||||||
| Amortization of deferred investment tax credits | (21 | ) | (21 | ) | (21 | ) | ||||||
| Change in valuation allowance | 24 | (398 | ) | (238 | ) | |||||||
| Permanent differences | 38 | 25 | 135 | |||||||||
| State rate change | 7 | 149 | (346 | ) | ||||||||
| Other | (71 | ) | 88 | (3 | ) | |||||||
| Total income tax expense | 2,845 | 2,165 | 3,248 | |||||||||
| Income tax expense from discontinued operations | (2,428 | ) | (617 | ) | (224 | ) | ||||||
| Income tax expense from continuing operations | $ | 417 | $ | 1,548 | $ | 3,024 | ||||||
| F-33 |
The following table presents the changes in our valuation allowance for deferred tax assets during the last two years.
| Balance at Beginning of Year | Additions/ (Reversals) Recorded in the Provision for Income Taxes | Other Changes | Balance at End of Year | |||||||||||||
| Year Ended December 31, 2015 | $ | 6,497 | $ | 32 | $ | — | $ | 6,529 | ||||||||
| Year Ended December 31, 2014 | $ | 5,699 | $ | 798 | $ | — | $ | 6,497 | ||||||||
| Year Ended December 31, 2013 | $ | 4,175 | $ | 1,524 | $ | — | $ | 5,699 | ||||||||
In 2013, due to the increasing disparity between the tax rates and rules for state income taxes in the states in which we operate, we changed from using a blended effective tax rate for all of our 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 as noted on the state rate change line item above. Our 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 approximately $98,000, 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 $1,971 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 $1,762. Combining the $(238) from the change in valuation allowance line item above, results in total expense from the change in valuation allowance of $1,524.
We have approximately $19,590 in federal and $82,442 in state net operating loss carryovers as of December 31, 2015. The net operating losses begin to expire in 2024. Due to acquisitions and changes in ownership, these net operating loss carryovers are subject to limitations set forth in Section 382 of the Internal Revenue Code. We maintain a valuation allowance of $52 on the portion of our federal net operating loss carryforward related to our acquisition of Cut Bank Gas in 2009. We maintain a state deferred tax asset valuation allowance of $4,913 against our state net operating loss carryover. In addition, we have approximately $14,676 of carryover tax basis as of December 31, 2015, against which we have a valuation allowance of $1,564 related to the carryover tax basis of the subsidiaries, since the carryover tax basis is subject to Section 382 of the Internal Revenue Code. We will maintain the valuation allowance against our deferred tax assets until such time that sufficient positive evidence exists to support a conclusion that it is more likely than not that we will realize those deferred tax assets. We consider the scheduled reversal of deferred tax liabilities, projected future results of operations, and tax planning strategies when making this assessment. If we determine that we will be able to realize our deferred tax assets in the future in excess of their net recorded amount, an adjustment to the deferred tax assets would result in an increase in income in the period that such a determination is made. Likewise, if we determine that we will not be able to realize a portion of our deferred tax assets, an adjustment to our deferred tax assets would result in a charge to income in the period that such a determination is made.
We follow the applicable provisions of ASC 740 to recognize, measure, and disclose uncertain tax positions in the financial statements. Tax positions must meet a more-likely-than-not recognition threshold to be recognized in our consolidated financial statements and in subsequent periods. During the three years ended December 31, 2015, we did not recognize any adjustments for uncertain tax benefits.
The tax years after 2012 remain open to examination by the major taxing jurisdictions in which we operate, although we do not expect to make material changes to unrecognized tax positions within the next twelve months.
Note 18 – Related Party Transactions
On October 23, 2015, we entered into a loan agreement and promissory note for $3,000 with NIL Funding. The note bears interest at an annual rate of 6.95% and matures on April 20, 2016. Under the note and loan agreement, we make monthly interest payments to NIL Funding and the principal balance of the note is due upon maturity. We made a principal payment of $1,000 on the note during December 2015. Our loan agreement with NIL Funding restricts our ability to incur additional borrowings, make new investments, consummate a merger or acquisition and dispose of assets. In an event of default, as defined under the loan agreement, NIL Funding may, at its option, require us to immediately pay the outstanding principal balance of the note as well as any and all interest and other payments due or convert any part of the amounts due and unpaid to shares of our common stock at a conversion price of 95% of the previous day’s closing price on the NYSE MKT. See Note 16 – Credit Facilities and Long-Term Debt for more information regarding our credit facilities.
| F-34 |
On April 6, 2015, we entered into a loan agreement and promissory note with NIL Funding. Pursuant to the note and loan agreement, NIL Funding loaned Gas Natural $5,000, bearing an annual interest rate of 7.5%, and a maturity date of October 3, 2015. On July 27, 2015, the NIL Funding credit facility was paid off and extinguished.
NIL Funding is an affiliate of The InterTech Group, Inc. (“InterTech”). The Chairperson and Chief Executive Officer of InterTech is Anita G. Zucker. Ms. Zucker, as trustee of the Article 6 Marital Trust, under the First Amended and Restated Jerry Zucker Revocable Trust dated April 2, 2007, beneficially owns 940,000 shares, or 8.94%, of our outstanding common stock, as of February 9, 2015. Two members of Gas Natural’s Board of Directors, Robert Johnston and Michael Bender, also currently serve as Executive Vice President and Chief Strategy Officer and Director, Corporate Secretary and Corporate Counsel, respectively, of InterTech.
We are party to certain agreements and transactions with Richard M. Osborne, our former chairman and chief executive officer, and companies owned or controlled by Richard M. Osborne.
Acquisition of 8500 Station Street
On March 5, 2013, we purchased the Matchworks Building in Mentor, Ohio for $1,853 from McKay Real Estate Corporation, Matchworks, LLC, and Nathan Properties, LLC (collectively, the “Sellers”) by and through Mark E. Dottore as Receiver in the United States District Court. The Sellers are entities owned or controlled by Richard M. Osborne. The acquisition of the Matchworks Building was approved by the independent members of our board of directors. See Note 3 - Acquisitions for details regarding this transaction.
On October 15, 2015, we sold the Matchworks Building for net proceeds of $1,220, which resulted in a loss on the transaction of $409, based on the carrying value of the property of $1,760 and the costs to sell the property. See Note 5 – Disposals for details regarding this transaction.
Acquisition of John D. Oil and Gas Marketing
On June 1, 2013, we and our 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 is the sole trustee of the Osborne Trust. The acquisition of JDOG Marketing was approved by the independent members of our board of directors and our shareholders. See Note 3 – Acquisitions for details regarding this transaction.
Lease Agreements
We had an agreement to lease a pipeline from JDOG Marketing through December 31, 2016. This pipeline and corresponding lease were acquired by us in the acquisition of JDOG Marketing. Lease expense resulting from this agreement was $6 for the year ended December 31, 2013, which amount is included in the natural gas purchases for that year, as presented below. 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. Pursuant to the agreement, 8500 Station Street leased to OsAir approximately 6,472 square feet of office space located at 8500 Station Street, Mentor, Ohio 44060, at a rent of $6 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 and at December 31, 2015 and 2014, we are owed $29 of past due rent.
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. 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 per month for the time period commencing on December 18, 2013 and ending on February 29, 2016, at which time the lease was terminated.
| F-35 |
Accounts Receivable and Accounts Payable
The table below presents amounts due from and due to related parties, including companies owned or controlled by Richard M. Osborne, at December 31, 2015 and 2014.
| Accounts Receivable | Accounts Payable | |||||||||||||||
| at December 31, | December 31, | |||||||||||||||
| 2015 | 2014 | 2015 | 2014 | |||||||||||||
| Cobra Pipeline | $ | 117 | $ | 179 | $ | 121 | $ | 68 | ||||||||
| Orwell Trumbell Pipeline | - | - | 15 | 102 | ||||||||||||
| Great Plains Exploration | - | 1 | 8 | - | ||||||||||||
| Big Oats Oil Field Supply | - | 5 | - | - | ||||||||||||
| John D. Oil and Gas Company | 7 | 7 | 48 | - | ||||||||||||
| OsAir | 41 | 35 | - | - | ||||||||||||
| Other | 23 | 8 | - | - | ||||||||||||
| Total related party balances included in continuing operations | $ | 188 | $ | 235 | $ | 192 | $ | 170 | ||||||||
The tables below present the effects on our Consolidated Statements of Comprehensive Income with related parties, including companies owned or controlled by Richard M. Osborne, for the years ended December 31, 2015, 2014 and 2013.
| Year Ended December 31, 2015 | ||||||||||||||||
| Natural Gas Purchases | Rent, Supplies, Consulting and Other Purchases | Natural Gas Sales | Rental Income and Other Sales | |||||||||||||
| Cobra Pipeline | $ | 1,084 | $ | 26 | $ | - | $ | - | ||||||||
| Orwell Trumbell Pipeline | 767 | - | 1 | - | ||||||||||||
| Great Plains Exploration | 359 | - | - | - | ||||||||||||
| Big Oats Oil Field Supply | - | - | 3 | - | ||||||||||||
| John D. Oil and Gas Company | 426 | - | 1 | - | ||||||||||||
| OsAir | - | - | 7 | - | ||||||||||||
| Other | - | - | 10 | 7 | ||||||||||||
| Total | $ | 2,636 | $ | 26 | $ | 22 | $ | 7 | ||||||||
| 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 | $ | - | $ | 18 | $ | 105 | $ | 13 | ||||||||||
| Orwell Trumbell Pipeline | 788 | - | - | 2 | 37 | |||||||||||||||
| Great Plains Exploration | 612 | - | - | 13 | 5 | |||||||||||||||
| Big Oats Oil Field Supply | - | 255 | 94 | 5 | 1 | |||||||||||||||
| John D. Oil and Gas Company | 738 | - | - | 1 | 42 | |||||||||||||||
| OsAir | 176 | - | 6 | 4 | 52 | |||||||||||||||
| Lake Shore Gas Storage | 162 | - | - | - | - | |||||||||||||||
| Other | 76 | - | 23 | 21 | 3 | |||||||||||||||
| Total | $ | 3,671 | $ | 255 | $ | 141 | $ | 151 | $ | 153 | ||||||||||
| F-36 |
| 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 | $ | - | $ | 17 | $ | 5 | $ | - | ||||||||||
| Cobra Pipeline | 843 | 264 | 20 | 158 | - | |||||||||||||||
| Orwell Trumbell Pipeline | 795 | - | - | 1 | 34 | |||||||||||||||
| Great Plains Exploration | 857 | 1 | 1 | 9 | 48 | |||||||||||||||
| Big Oats Oil Field Supply | - | 2,968 | 624 | 4 | 5 | |||||||||||||||
| John D. Oil and Gas Company | 912 | 6 | - | 1 | 29 | |||||||||||||||
| OsAir | 242 | 13 | 92 | 5 | 73 | |||||||||||||||
| Other | 86 | - | 44 | 20 | 45 | |||||||||||||||
| Total | $ | 4,686 | $ | 3,252 | $ | 798 | $ | 203 | $ | 234 | ||||||||||
We accrued a liability of $170 and $111 due to companies controlled by Richard M. Osborne for natural gas used and transportation charges due to us as of December 31, 2015 and 2014, 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.
We incurred expenses of $309 during the year ended December 31, 2013, when Richard M. Osborne sold shares of our common stock. These expenses are recorded in the accompanying income statement as stock sale expense.
In addition, we had related party natural gas imbalances of $256 and $98 at December 31, 2015 and 2014, respectively, which were included in our natural gas inventory balance. These amounts represent quantities of natural gas due to us from natural gas transportation companies controlled by Richard M. Osborne.
Note 19 – Segment Reporting
Our Chief Operating Officer has been identified as the chief operating decision maker because he has final authority over performance assessment and resource allocation decisions. Our reportable segments are based on our method of internal reporting, which generally segregates the strategic business units due to differences in services and regulation. We primarily separate our state regulated utility businesses from non-regulated marketing and production businesses, and our corporate level operations. We have regulated natural gas utility businesses in the states of Maine, Montana, North Carolina and Ohio that form our natural gas segment. We have non-regulated natural gas marketing and production businesses in Montana and Ohio that together form our marketing and production segment. Our corporate operations, our Lone Wolf insurance subsidiary, and our discontinued operations together form our corporate and other segment. Transactions between reportable segments are accounted for on an accrual basis, and are eliminated. Intercompany eliminations between segments consist primarily of gas sales from the marketing and production operations to the natural gas operations, intercompany accounts receivable and payable, equity, and investments in subsidiaries. See Note 4 – Discontinued Operations for more information regarding our previously reported pipeline and propane segments.
| F-37 |
The following tables set forth summarized financial information for our natural gas, marketing and production, and corporate and other operations segments for the years ended December 31, 2015, 2014 and 2013.
| Year Ended December 31, 2015 | Natural Gas | Marketing & Production | Corporate & Other | Consolidated | ||||||||||||
| OPERATING REVENUES | $ | 104,003 | $ | 12,132 | $ | - | $ | 116,135 | ||||||||
| Intersegment eliminations | (25 | ) | (3,749 | ) | - | (3,774 | ) | |||||||||
| Total operating revenue | 103,978 | 8,383 | - | 112,361 | ||||||||||||
| COST OF SALES | 60,405 | 11,495 | - | 71,900 | ||||||||||||
| Intersegment eliminations | (25 | ) | (3,749 | ) | - | (3,774 | ) | |||||||||
| Total cost of sales | 60,380 | 7,746 | - | 68,126 | ||||||||||||
| GROSS MARGIN | 43,598 | 637 | - | 44,235 | ||||||||||||
| OPERATING EXPENSES | ||||||||||||||||
| Distribution, general and administrative | 23,537 | 312 | 2,667 | 26,516 | ||||||||||||
| Maintenance | 1,419 | 3 | - | 1,422 | ||||||||||||
| Depreciation and amortization | 6,770 | 466 | - | 7,236 | ||||||||||||
| Accretion | 3 | 18 | - | 21 | ||||||||||||
| Taxes other than income | 4,104 | 15 | - | 4,119 | ||||||||||||
| Intersegment eliminations | (87 | ) | - | - | (87 | ) | ||||||||||
| Total operating expenses | 35,746 | 814 | 2,667 | 39,227 | ||||||||||||
| OPERATING INCOME (LOSS) | 7,852 | (177 | ) | (2,667 | ) | 5,008 | ||||||||||
| Other income (expense) | 147 | 103 | (68 | ) | 182 | |||||||||||
| Interest expense | (2,782 | ) | (135 | ) | (687 | ) | (3,604 | ) | ||||||||
| Income (loss) before taxes | 5,217 | (209 | ) | (3,422 | ) | 1,586 | ||||||||||
| Income tax benefit (expense) | (1,741 | ) | 96 | 1,228 | (417 | ) | ||||||||||
| INCOME (LOSS) FROM CONTINUING OPERATIONS | 3,476 | (113 | ) | (2,194 | ) | 1,169 | ||||||||||
| Discontinued operations, net of income tax | - | - | 3,519 | 3,519 | ||||||||||||
| NET INCOME (LOSS) | $ | 3,476 | $ | (113 | ) | $ | 1,325 | $ | 4,688 | |||||||
| Capital expenditures | $ | 9,383 | $ | 3 | $ | 181 | $ | 9,567 | ||||||||
| F-38 |
| Year Ended December 31, 2014 | Natural Gas | Marketing & Production | Corporate & Other | Consolidated | ||||||||||||
| OPERATING REVENUES | $ | 123,379 | $ | 17,605 | $ | - | $ | 140,984 | ||||||||
| Intersegment eliminations | (326 | ) | (8,088 | ) | - | (8,414 | ) | |||||||||
| Total operating revenue | 123,053 | 9,517 | - | 132,570 | ||||||||||||
| COST OF SALES | 79,423 | 16,709 | - | 96,132 | ||||||||||||
| Intersegment eliminations | (326 | ) | (8,088 | ) | - | (8,414 | ) | |||||||||
| Total cost of sales | 79,097 | 8,621 | - | 87,718 | ||||||||||||
| GROSS MARGIN | 43,956 | 896 | - | 44,852 | ||||||||||||
| OPERATING EXPENSES | ||||||||||||||||
| Distribution, general and administrative | 20,976 | 1,833 | 3,176 | 25,985 | ||||||||||||
| Maintenance | 1,225 | - | - | 1,225 | ||||||||||||
| Depreciation and amortization | 6,071 | 515 | 19 | 6,605 | ||||||||||||
| Accretion | 7 | 45 | - | 52 | ||||||||||||
| Taxes other than income | 3,898 | 23 | 6 | 3,927 | ||||||||||||
| Unrealized holding loss | - | 62 | - | 62 | ||||||||||||
| Intersegment eliminations | (103 | ) | - | - | (103 | ) | ||||||||||
| Total operating expenses | 32,074 | 2,478 | 3,201 | 37,753 | ||||||||||||
| OPERATING INCOME (LOSS) | 11,882 | (1,582 | ) | (3,201 | ) | 7,099 | ||||||||||
| Other income (expense) | 890 | (502 | ) | 16 | 404 | |||||||||||
| Interest expense | (2,619 | ) | (121 | ) | (486 | ) | (3,226 | ) | ||||||||
| Income (loss) before taxes | 10,153 | (2,205 | ) | (3,671 | ) | 4,277 | ||||||||||
| Income tax benefit (expense) | (3,661 | ) | 772 | 1,341 | (1,548 | ) | ||||||||||
| INCOME (LOSS) FROM CONTINUING OPERATIONS | 6,492 | (1,433 | ) | (2,330 | ) | 2,729 | ||||||||||
| Discontinued operations, net of income tax | - | - | 1,033 | 1,033 | ||||||||||||
| NET INCOME (LOSS) | $ | 6,492 | $ | (1,433 | ) | $ | (1,297 | ) | $ | 3,762 | ||||||
| Capital expenditures | $ | 21,531 | $ | 60 | $ | 22 | $ | 21,613 | ||||||||
| F-39 |
| Year Ended December 31, 2013 | Natural Gas | Marketing & Production | Corporate & Other | Consolidated | ||||||||||||
| OPERATING REVENUES | $ | 97,259 | $ | 20,260 | $ | - | $ | 117,519 | ||||||||
| Intersegment eliminations | (26 | ) | (8,093 | ) | - | (8,119 | ) | |||||||||
| Total operating revenue | 97,233 | 12,167 | - | 109,400 | ||||||||||||
| COST OF SALES | 56,003 | 18,146 | - | 74,149 | ||||||||||||
| Intersegment eliminations | (26 | ) | (8,093 | ) | - | (8,119 | ) | |||||||||
| Total cost of sales | 55,977 | 10,053 | - | 66,030 | ||||||||||||
| GROSS MARGIN | 41,256 | 2,114 | - | 43,370 | ||||||||||||
| OPERATING EXPENSES | ||||||||||||||||
| Distribution, general and administrative | 19,561 | 801 | 1,770 | 22,132 | ||||||||||||
| Maintenance | 1,139 | 3 | - | 1,142 | ||||||||||||
| Depreciation and amortization | 5,081 | 457 | 13 | 5,551 | ||||||||||||
| Accretion | 7 | 51 | - | 58 | ||||||||||||
| Unrealized holding gain | - | (1,565 | ) | - | (1,565 | ) | ||||||||||
| Goodwill impairment | - | 726 | - | 726 | ||||||||||||
| Taxes other than income | 3,619 | 28 | 25 | 3,672 | ||||||||||||
| Intersegment eliminations | (14 | ) | - | (84 | ) | (98 | ) | |||||||||
| Total operating expenses | 29,393 | 501 | 1,724 | 31,618 | ||||||||||||
| OPERATING INCOME (LOSS) | 11,863 | 1,613 | (1,724 | ) | 11,752 | |||||||||||
| Other income (expense) | 767 | 151 | (618 | ) | 300 | |||||||||||
| Interest expense | (2,566 | ) | (142 | ) | (468 | ) | (3,176 | ) | ||||||||
| Income (loss) before taxes | 10,064 | 1,622 | (2,810 | ) | 8,876 | |||||||||||
| Income tax benefit (expense) | (3,243 | ) | (586 | ) | 805 | (3,024 | ) | |||||||||
| INCOME (LOSS) FROM CONTINUING OPERATIONS | 6,821 | 1,036 | (2,005 | ) | 5,852 | |||||||||||
| Discontinued operations, net of income tax | - | - | 819 | 819 | ||||||||||||
| NET INCOME (LOSS) | $ | 6,821 | $ | 1,036 | $ | (1,186 | ) | $ | 6,671 | |||||||
| Capital expenditures | $ | 23,242 | $ | 217 | $ | 58 | $ | 23,517 | ||||||||
| F-40 |
| Natural Gas Operations | Marketing & Produrction Operations | Corporate & Other Operations | Consolidated | |||||||||||||
| December 31, 2015 | ||||||||||||||||
| Total assets | $ | 228,549 | $ | 8,571 | $ | 100,822 | $ | 337,942 | ||||||||
| Intersegment eliminations | (87,978 | ) | (3,946 | ) | (48,329 | ) | (140,253 | ) | ||||||||
| Total assets | $ | 140,571 | $ | 4,625 | $ | 52,493 | $ | 197,689 | ||||||||
| December 31, 2014 | ||||||||||||||||
| Total assets | $ | 214,030 | $ | 9,193 | $ | 100,781 | $ | 324,004 | ||||||||
| Intersegment eliminations | (68,715 | ) | (2,714 | ) | (38,571 | ) | (110,000 | ) | ||||||||
| Total assets | $ | 145,315 | $ | 6,479 | $ | 62,210 | $ | 214,004 | ||||||||
Note 20 – Commitments and Contingencies
Lease Commitments
Operating Leases
We lease certain properties including land, office buildings, and other equipment under non-cancelable operating leases. We incurred lease expense related to operating leases for the years ended December 31, 2015, 2014 and 2013, of $319, $258 and $222, respectively.
Capital Leases
During 2012, we entered into an agreement with United States Power Fund, L.P. whereby we lease 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 per year through 2022; an annual $120 facility service fee to be paid as long as the leased assets remain in place on the property, and a throughput charge of $0.0125 per Mcf moved through the leased pipeline, in excess of certain base amounts. There were no throughput charge payments made during the three years ended December 31, 2015, as we did not exceed the base amounts specified in the lease. During the years ended December 31, 2015 and 2014, we paid $120 for services related to this lease. There were no facility service fees paid in 2013.
ERP System Lease
During 2014, we began construction of a new ERP system that for accounting purposes qualified as a build-to-suit lease. We determined that during the application development stage we assumed substantially all of the project’s risk and as such we were the owner of the asset during this period, under U.S. GAAP. Accordingly, we recorded $6,525 of construction work in progress and a $5,597 build-to-suit liability line item on our Consolidated Balance Sheet as of December 31, 2014, related to this project. Upon completion of the first two (of three) phases of the ERP implementation project during the fourth quarter of 2015, we determined that the lease qualifies for sales recognition under sale-leaseback accounting guidance. We expect to complete the third phase of the ERP implementation project during the first half of 2016. During the fourth quarter of 2015, we determined that the lease governing our future use of the assets is a capital lease and we recorded property, plant and equipment and a capital lease liability of $7,521, based on the present value of our minimum lease payments. We removed the build-to-suit liability and the related assets from our consolidated balance sheet and we deferred a loss on the sale of the software assets of $2,037 that will be amortized over the three year life of the lease. During the fourth quarter of 2015, we recorded $358 for amortization of our deferred loss, depreciation of $163 and interest expense of $237 related to our capital lease payments. Our ERP system leases have terms that extend from 30 to 36 months, and we intend to exercise a purchase option at the end of the lease terms at a price to be negotiated at that time.
| F-41 |
The following schedule presents the future minimum lease payments under our non-cancelable long-term lease agreements as of December 31, 2015.
Future Minimum Lease Payments
| Operating Leases | Build-to-Suit (1) | Capital Leases | ||||||||||
| 2016 | $ | 265 | $ | 612 | $ | 3,130 | ||||||
| 2017 | 259 | 817 | 3,130 | |||||||||
| 2018 | 242 | 612 | 1,318 | |||||||||
| 2019 | 214 | - | 300 | |||||||||
| 2020 | 209 | - | 300 | |||||||||
| Thereafter | 883 | - | 600 | |||||||||
| Total minimum lease payments | $ | 2,072 | $ | 2,041 | 8,778 | |||||||
| Less: Interest portion | 725 | |||||||||||
| Total liability | $ | 8,053 | ||||||||||
(1) Build-to-suit lease is related to the third phase of our new ERP system, and will be evaluated for sale leaseback treatment upon its completion in 2016. The asset to be leased is not yet complete and as such actual amounts due may vary from the amounts presented.
Our current capital lease obligations as of December 31, 2015 and 2014, of $2,876 and $188, respectively, are included in other current liabilities and our long-term capital lease obligations of $5,177 and $1,675, respectively, are included in long-term liabilities in our Consolidated Balance Sheets. During the years ended December 31, 2015, 2014 and 2013, we recognized $267, $122 and $132, respectively, of interest expense related to our capital leases.
Long-term Contracts
The following table presents our future minimum obligations under non-cancellable long-term contracts at December 31, 2015.
Future Minimum Long-term Contractual Obligations
| Nova Gas | Transcontinental Gas | Maritimes & | Jefferson Energy | |||||||||||||||||
| Transmission, Ltd. | Pipe Line Company, LLC | Northeast Pipeline, LLC | Trading, LLC | Other | ||||||||||||||||
| 2016 | $ | 899 | $ | 297 | $ | 576 | $ | 2,078 | $ | 9 | ||||||||||
| 2017 | 899 | 297 | 576 | 458 | 5 | |||||||||||||||
| 2018 | 861 | 297 | 357 | - | - | |||||||||||||||
| 2019 | 674 | 297 | 357 | - | - | |||||||||||||||
| 2020 | 674 | 297 | 357 | - | - | |||||||||||||||
| Thereafter | 1,309 | 21,715 | - | - | - | |||||||||||||||
| Total | $ | 5,316 | $ | 23,200 | $ | 2,223 | $ | 2,536 | $ | 14 | ||||||||||
We have various contracts for pipeline capacity to ensure that we are able to meet our customers’ demands for natural gas. Each of the contractual obligations above were estimated using the pricing in effect on December 31, 2015, except our obligation with Maritimes & Northeast Pipeline, LLC, which contract has a provision for fixed pricing. We have three contracts with Nova Gas Transmission, Ltd. that have expiration dates between October 2018 and October 2023. Our contract with Transcontinental Gas Pipe Line Company, LLC expires in February 2094 and our contract with Jefferson Energy Trading, LLC expires in March 2017. One of our contracts with Maritimes & Northeast Pipeline, LLC expires December 2019, and we are in a two year renewal period for a second contract that expires in December 2017. During 2015, we paid an aggregate of $5,902 for our commitments under these contracts and an additional contract for natural gas purchases that is not included in our estimate of our future minimum long-term contractual obligations because that contract will expire in March 2016.
| F-42 |
None of the preceding long-term contracts have been recognized on our Consolidated Balance Sheets.
Regulatory Matters
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 than what we paid and recommended an adjustment to the GCR calculations that would result in a liability for NEO and Orwell to its customers.
In July 2013, after a hearing with the PUCO and its staff, we determined it was probable that the GCR adjustments recommended by the staff would be adopted by the PUCO and as a result we recorded a contingent liability in our financial statements for the period ended June 30, 2013. Based on the PUCO staff’s calculations and management’s assessment, we accrued an additional $944 to establish a total liability to our customers of $1,173 as our 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 $1,027. 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, our former chairman and chief executive officer during the periods covered by these audits.
Immediately following the release of the Opinion and Order, we examined NEO and Orwell’s GCRs for these disallowed cost in periods subsequent to the companies’ audit periods. As a result, we adjusted our accrual for costs disallowed by the PUCO by $329. The above referenced GCR cases are final and the time for appeal has expired.
In April 2014, 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 on January 23, 2015. The full report can be found on the PUCO’s website, www.puco.ohio.gov, under case number 14-0205-GA-C01. The Ohio Consumers’ Counsel intervened in the docket. On October 30, 2014, a stipulation and recommendation was filed in the docket that set forth the understanding of NEO, Orwell, Brainard and the commission staff regarding changes in policies and process, which is available in the 14-0205-GA-COI docket (the “Stipulation”). The PUCO has not yet taken any action on the Stipulation.
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 approximately two year period ending June 30, 2014. The 2014 PUCO staff report identified additional disallowed costs and errors in the GCR calculation. As a result, we adjusted our contingent liability to settle this matter to $174, which is included as a component of cost of sales – natural gas purchased for 2014. During the second quarter of 2015, we reached a settlement with the PUCO staff, which was not opposed by the Ohio Consumers’ Counsel, whereby approximately $1,200 will be refunded to our customers through our GCR. As a result of this settlement, we recorded a charge of $693 to cost of sales – natural gas purchased for 2015. The PUCO approved the settlement and the time for appeal has now expired, making the settlement final.
Legal Proceedings
From time to time, we are involved in lawsuits that have arisen in the ordinary course of business. We are contesting each of these lawsuits vigorously and believe we have defenses to the allegations that have been made.
| F-43 |
Richard M. Osborne Suits
On June 13, 2014, Richard M. Osborne, 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 sought an order requiring us to provide him with “the minutes and any corporate resolutions for the past five years.” We had provided Mr. Osborne with all the board minutes he requested that had 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 claimed he was entitled to receive. 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 April 28, 2015, Mr. Osborne refiled this lawsuit in a different court, the Cuyahoga County Court of Common Pleas, captioned “Richard M. Osborne and Richard M. Osborne Trust, Under Restated and Amended Trust Agreement of January 13, 1995 v. Gas Natural Inc., et al.,” Case No. 15CV844836. Mr. Osborne is again seeking the board minutes at issue in the previously dismissed lawsuit and minutes that have been prepared subsequently. We believe the lawsuit, like its prior iteration, is wholly without merit and will vigorously contest it. In addition, we have filed a counterclaim against Mr. Osborne seeking to have him declared a vexatious litigator. If successful, Mr. Osborne will only be able to initiate new litigation against us after receiving permission from the court in which the case would be pending. This case has been stayed, pending the results of Case No. 14CV1512, described below, which is currently pending in the Court of Common Pleas in Lake County, Ohio.
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 earn-out 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 chief executive officer, (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 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, Case No. 14CV1512, against us and our board members. In the re-filed lawsuit, among other things, Mr. Osborne (1) demands payment of an earn-out 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 $1,000, 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 have each filed motions for summary judgement which are awaiting the ruling of the court. We believe that Mr. Osborne’s claims in this lawsuit are wholly without merit and will vigorously defend this case on all grounds.
On March 12, 2015, Cobra Pipeline Co., Ltd (“Cobra”) filed a lawsuit against us in the United States District Court for the Northern District of Ohio captioned “Cobra Pipeline Co., Ltd. v. Gas Natural Inc., et al.,” Case No. 1:15-CV-00481. Mr. Osborne owns and controls Cobra. Cobra’s complaint alleged that it uses a service to track the locations of its vehicles via GPS monitoring. Cobra alleged that we and other defendants accessed and intercepted vehicle tracking data, after we knew or should have known that our authority to do so had ended. The complaint alleged claims under the Stored Communications Act, the Wiretap Act, and various state-law claims. On September 17, 2015, the court granted defendants’ motion for summary judgment and dismissed Cobra’s complaint in its entirety. On October 19, 2015, Cobra filed its Notice of Appeal to the Sixth Circuit Court of Appeals. That appeal remains pending.
On October 29, 2015, Orwell filed a lawsuit against Richard M. Osborne in the Lake County Court of Common Pleas, captioned “Orwell National Gas Company vs. Osborne Sr., Richard M.,” Case No. 15CV001877. The complaint alleges that Richard M. Osborne, while the chairman, president and chief executive officer of Orwell, Great Plains Exploration, Inc., John D. Oil & Gas Company, and GNSC fraudulently presented demands for payment to GNSC and Orwell, claiming that payments were due for natural gas purchased from Great Plains and John D. Oil & Gas Company from January 2012 through September 2013. Richard M. Osborne ultimately obtained two checks from Orwell in the total amount of $202. Orwell’s complaint states a claim of theft and seeks liquidated damages in the amount of these checks. Mr. Osborne filed his answer to the complaint on March 10, 2016, and this matter is currently pending before the Lake County Court.
Orwell filed a complaint and motion for preliminary injunction against Ohio Rural Natural Gas Co-Op (“Ohio Rural”) and Richard M. Osborne, captioned “Orwell Natural Gas Company v. Ohio Rural Natural Gas Co-Op, et al.,” filed November 30, 2015 in the Lake County Court of Common Pleas, Case No. 15CV002063, alleging that Ohio Rural and Richard M. Osborne acted in concert to convert, for the use of their own supply, natural gas supply lines owned and operated by Orwell. The complaint alleges that on November 20, 2015, Ohio Rural and Richard M. Osborne tampered with and severed gas lines owned by Orwell on Tin Man Road in Mentor, Ohio, terminated its service to approximately 50 independently owned businesses, and converted it for their own personal use. The complaint states claims for conversion, unjust enrichment and civil remedy against criminal act, and seeks compensatory and liquidated damages. On December 23, 2015, Ohio Rural filed a motion to dismiss, which is currently pending before the court. Also on November 30, 2015, Orwell filed a case with the PUCO on the same grounds, captioned “In the Matter of Orwell Natural Gas Company, Brainard Gas Corporation and Northeast Ohio Natural Gas Corporations’ Request for Injunctive Relief,” Case No. 15-2015-GA-UNC, given the PUCO’s jurisdiction regarding pipeline safety issues.
| F-44 |
In addition to the foregoing, we are involved in other proceedings before the PUCO involving entities owned or controlled by Richard M. Osborne, our former chairman, president, and chief executive officer. On or about March 12, 2015, a demand for arbitration, captioned “Orwell-Trumbull Pipeline Company, LLC v. Orwell Natural Gas Company,” Case No: 01-15-0002-9137, was filed with the American Arbitration Association by Orwell Trumbull Pipeline Company, LLC (“OTPC”) with respect to a dispute under the Natural Gas Transportation Service Agreement between it and Orwell and Brainard. OTCP claims Orwell is in breach of the exclusivity provisions in the Agreement. Orwell filed several counterclaims, including claims for breach of contract, fraud, and unjust enrichment. On March 31, 2015, Orwell filed a complaint on the same grounds with the PUCO captioned “Orwell Natural Gas Company v. Orwell-Trumbull Pipeline Company LLC,” Case Number, 15-0637-GA-CSS, which was ultimately consolidated with PUCO case numbers 15-0475-GA-CSS and 14-1654-GA-CSS, to address issues regarding the operation of and contract rights for utilities on the Orwell Trumbull Pipeline. The PUCO held a hearing on November 3rd and 4th, 2015. The parties’ final briefs were filed on January 8, 2015, and are currently pending before the PUCO.
Shareholders Suit
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 us 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. The parties are currently conducting discovery in this lawsuit.
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, our former chief financial officer. The suit, in which we are named as a nominal defendant, seeks the recovery of unspecified damages allegedly sustained by us, 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 M. 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. On June 4, 2015, the trial judge assigned to the case adopted in full the report and recommendation, the objections filed by the defendants, and the responses from the plaintiffs. The parties engaged in settlement mediation on February 25, 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 deductible, which we have reached. Although we believe these insurance proceeds are available, we may incur costs and expenses related to this suit that are not covered by insurance which may be substantial. Any unfavorable outcome could adversely impact our business and results of operations.
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Harrington Employment Suit
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. 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. On August 11, 2015, the Montana Supreme Court agreed with us that Mr. Harrington’s employment was governed by Ohio law, and as such he could not take advantage of Montana’s Wrongful Discharge from Employment Act. However, the Montana Supreme Court also held the trial court erred in determining it lacked jurisdiction over the case, finding the trial court should have retained jurisdiction and applied Ohio law to Mr. Harrington’s claims. As Ohio is an “at will” state, we believe there are no claims under Ohio law and the case will ultimately be dismissed by the trial court on remand. On September 28, 2015, Mr. Harrington filed a motion to amend complaint to assert new causes of action not previously alleged including claims for misrepresentation, constructive fraud based on alleged representations, slander, and mental pain and suffering. We answered the amended complaint to preserve our defenses, we have also opposed Mr. Harrington’s motion to amend. On December 14, 2015, we filed a motion to dismiss the Montana action in its entirety on the basis that the forum is not appropriate. Our motion to dismiss is now fully briefed and is awaiting ruling by the court. We continue to believe Mr. Harrington’s claims under both Montana and Ohio law are without merit and we 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 prepared a report with the assistance of legal counsel and financial and regulatory advisors evaluating the allegations and the board evaluated the report. Insurance coverage was not available for costs associated with this review and report. We incurred substantial costs and expenses related to the investigation that are not covered by insurance.
SEC Investigation
We 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) our financial statements and internal controls and (iv) various entities affiliated with our former chairman and chief executive officer, Richard M. Osborne. On May 29, 2015, we received a subpoena regarding a formal investigation, case number C-08186-A. The SEC has requested we preserve all documents relating to these matters. We are complying with this request and intend to cooperate fully with the SEC.
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Note 21 – Accounts Receivable
Changes in, and balances of, the allowance for doubtful accounts receivable were as follows:
| Balance at Beginning of Period | Amounts Charged/ (Credited) To Expense | Amounts Charged Off, Net of Recoveries | Balance at End of Period | |||||||||||||
| Year Ended December 31, 2015 | ||||||||||||||||
| Deducted from accounts receivable for doubtful accounts | $ | 371 | $ | 278 | $ | 143 | $ | 506 | ||||||||
| Year Ended December 31, 2014 | ||||||||||||||||
| Deducted from accounts receivable for doubtful accounts | $ | 1,978 | $ | 1,112 | $ | 2,719 | $ | 371 | ||||||||
| Year Ended December 31, 2013 | ||||||||||||||||
| Deducted from accounts receivable for doubtful accounts | $ | 1,343 | $ | 726 | $ | 91 | $ | 1,978 | ||||||||
During 2013, a large industrial customer of ours entered bankruptcy proceedings. We believed that we had an administrative claim for the unreserved portion of our accounts receivable and that we were likely to collect the amount. In June 2014, the bankruptcy court denied our administrative claim on the customer and, as a result, we wrote off $1,056 of accounts receivable. This receivable was related to our marketing and production operating segment.
Note 22 – Accrued Liabilities
The following table summarizes the components of our accrued liabilities balances at December 31, 2015 and 2014.
| December 31, | ||||||||
| 2015 | 2014 | |||||||
| Deferred payments received from levelized billing | $ | 3,107 | $ | 2,360 | ||||
| Taxes other than income | 1,861 | 2,083 | ||||||
| Interest | 446 | 201 | ||||||
| Accrued liabilities to related parties | 170 | 111 | ||||||
| Employee benefits | 149 | 123 | ||||||
| Vacation | 104 | 96 | ||||||
| Accrued liabilities | $ | 5,837 | $ | 4,974 | ||||
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Note 23 – Unaudited Quarterly Results of Operations
| 2015 Quarter Ended | ||||||||||||||||
| December 31, | September 30, | June 30, | March 31, | |||||||||||||
| Revenue | $ | 29,498 | $ | 13,084 | $ | 16,046 | $ | 53,733 | ||||||||
| Gross margin | 12,309 | 6,861 | 7,500 | 17,565 | ||||||||||||
| Income tax benefit (expense) | (74 | ) | 1,312 | 1,012 | (2,667 | ) | ||||||||||
| Income (loss) from continuing operations | 729 | (2,264 | ) | (1,713 | ) | 4,417 | ||||||||||
| Discontinued operations, net of tax | (526 | ) | 3,395 | 213 | 437 | |||||||||||
| Net income (loss) and comprehensive income (loss) | 203 | 1,131 | (1,500 | ) | 4,854 | |||||||||||
| Basic and diluted earnings per share | ||||||||||||||||
| Continuing operations | $ | 0.07 | $ | (0.22 | ) | $ | (0.16 | ) | $ | 0.42 | ||||||
| Discontinued operations | (0.05 | ) | 0.32 | 0.02 | 0.04 | |||||||||||
| Net income (loss) per share | $ | 0.02 | $ | 0.10 | $ | (0.14 | ) | $ | 0.46 | |||||||
| 2014 Quarter Ended | ||||||||||||||||
| December 31, | September 30, (1) | June 30, | March 31, | |||||||||||||
| Revenue | $ | 36,959 | $ | 13,615 | $ | 20,500 | $ | 61,496 | ||||||||
| Gross margin | 12,037 | 7,015 | 8,392 | 17,408 | ||||||||||||
| Income tax benefit (expense) | (647 | ) | 1,008 | 850 | (2,759 | ) | ||||||||||
| Income (loss) from continuing operations | 1,198 | (1,514 | ) | (1,492 | ) | 4,537 | ||||||||||
| Discontinued operations, net of tax | 451 | 35 | 65 | 482 | ||||||||||||
| Net income (loss) | 1,649 | (1,479 | ) | (1,427 | ) | 5,019 | ||||||||||
| Comprehensive income (loss) | 1,651 | (1,589 | ) | (1,423 | ) | 5,018 | ||||||||||
| 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 | ||||||
(1) We classified our EWW subsidiary and the Pipeline Assets as discontinued operations during the third quarter of 2014. All prior periods have been restated to match this presentation.
During the fourth quarter of 2015, we recognized in other income a $415 gain on the sale of Clarion and Walker, a $409 loss on the sale of an office building in Mentor, Ohio, a loss of $341 on the sale of PGC, and a charge to discontinued operations for $413 related to the prepayment of debt. See Note 4 – Discontinued Operations and Note 5 – Disposals for more information about these transactions. We also recorded amounts related to the implementation of our ERP system: $513 for training and maintenance, $358 of amortization of our deferred loss on the sale-leaseback transaction, depreciation of $163, and interest expense of $237.
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