Genie Energy Ltd. - Quarter Report: 2015 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2015

or

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 1-35327

GENIE ENERGY LTD.

(Exact Name of Registrant as Specified in its Charter)

(973) 438-3500

(Registrant’s telephone number, including area code)  

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 ☒  No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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 ☒  No ☐

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 definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.): Yes ☐  No ☒

As of November 2, 2015, the registrant had the following shares outstanding:

GENIE ENERGY LTD.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

GENIE ENERGY LTD.

 
CONSOLIDATED BALANCE SHEETS

See accompanying notes to consolidated financial statements.

GENIE ENERGY LTD.

CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)

See accompanying notes to consolidated financial statements.

GENIE ENERGY LTD.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

See accompanying notes to consolidated financial statements. 

GENIE ENERGY LTD.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

See accompanying notes to consolidated financial statements.

GENIE ENERGY LTD.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 1—Basis of Presentation

The accompanying unaudited consolidated financial statements of Genie Energy Ltd. and its subsidiaries (the “Company” or “Genie”) have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three and nine months ended September 30, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015. The balance sheet at December 31, 2014 has been derived from the Company’s audited financial statements at that date but does not include all of the information and footnotes required by U.S. GAAP for complete financial statements. For further information, please refer to the consolidated financial statements and footnotes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014, as filed with the U.S. Securities and Exchange Commission (the “SEC”).

The Company owns 99.3% of its subsidiary, Genie Energy International Corporation (“GEIC”), which owns 100% of Genie Retail Energy (“GRE”) and 92% of Genie Oil and Gas, Inc. (“GOGAS”). Genie’s principal businesses consist of the following:

GRE has outstanding deferred stock units granted to officers and employees that represent an interest of 3.9% of the equity of GRE.

In the consolidated statements of operations, expense relating to Afek’s oil and gas exploration activities of $1.6 million and $3.5 million in the three and nine months ended September 30, 2014, respectively, previously included in “Research and development expense”, were reclassified to “Exploration expense” to conform to the current year’s presentation.

Seasonality and Weather

The weather and the seasons, among other things, affect GRE’s revenues. Weather conditions have a significant impact on the demand for natural gas used for heating and electricity used for heating and cooling. Typically, colder winters increase demand for natural gas and electricity, and hotter summers increase demand for electricity. Milder winters and/or summers have the opposite effects. Natural gas revenues typically increase in the first quarter due to increased heating demands and electricity revenues typically increase in the third quarter due to increased air conditioning use. Approximately 59% and 49% of GRE’s natural gas revenues for the relevant years were generated in the first quarter of 2014 and 2013, respectively, when demand for heating was highest. Although the demand for electricity is not as seasonal as natural gas (due, in part, to usage of electricity for both heating and cooling), approximately 20% and 31% of GRE’s electricity revenues for the relevant years were generated in the third quarter of 2014 and 2013, respectively. Because of dramatic increases in wholesale electricity prices in January and February 2014, the retail electricity prices that GRE and many other variable rate electricity suppliers charged to their customers also increased sharply. As a result, approximately 45% of GRE’s electricity revenues in 2014 were generated in the first quarter of 2014. The Company’s revenues and operating income are subject to material seasonal variations, and the interim financial results are not necessarily indicative of the estimated financial results for the full year.

Note 2—Fair Value Measurements

The following table presents the balance of assets and liabilities measured at fair value on a recurring basis:

(1) – quoted prices in active markets for identical assets or liabilities

(2) – observable inputs other than quoted prices in active markets for identical assets and liabilities

(3) – no observable pricing inputs in the market

The Company’s derivative contracts consist of natural gas and electricity put and call options and swaps. The underlying asset in the Company’s put and call options is a forward contract. The Company’s swaps are agreements whereby a floating (or market or spot) price is exchanged for a fixed price over a specified period. The Company’s derivatives were classified as Level 1, Level 2 or Level 3. The Level 1 derivatives were valued using quoted prices in active markets for identical contracts. The Level 2 derivatives were valued using observable inputs based on quoted market prices in active markets for similar contracts. The fair value of the Level 3 derivatives was based on the value of the underlying contracts, estimated in conjunction with the counterparty and could not be corroborated by the market.

The Company’s subsidiary, GOGAS, issued a stock option in June 2011 to Michael Steinhardt, the Chairman of the Board of IEI, at an exercise price of $5.0 million. The expiration date was April 9, 2015. The expiration date was extended for one month, and on May 9, 2015, the option was exercised (see Note 6). At December 31, 2014, the fair value of the GOGAS stock option was nil.

The following table summarizes the change in the balance of the Company’s assets measured at fair value on a recurring basis using significant unobservable inputs (Level 3). There were no liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three and nine months ended September 30, 2015 and 2014.

Fair Value of Other Financial Instruments

The estimated fair value of the Company’s other financial instruments was determined using available market information or other appropriate valuation methodologies. However, considerable judgment is required in interpreting this data to develop estimates of fair value. Consequently, the estimates are not necessarily indicative of the amounts that could be realized or would be paid in a current market exchange.

Restricted cash—short-term, certificates of deposit, prepaid expenses, other current assets, advances from customers, due to IDT Corporation and other current liabilities. At September 30, 2015 and December 31, 2014, the carrying amounts of these assets and liabilities approximated fair value because of the short period to maturity. The fair value estimate for restricted cash—short-term was classified as Level 1 and certificates of deposit, prepaid expenses, other current assets, advances from customers, due to IDT Corporation and other current liabilities were classified as Level 2 of the fair value hierarchy.

Restricted cash—long-term. At September 30, 2015 and December 31, 2014, the carrying amount of restricted cash—long-term approximated fair value. The fair value was estimated based on the anticipated cash flows once the restrictions are removed, which was classified as Level 3 of the fair value hierarchy.

Other assets and other liabilities. At September 30, 2015 and December 31, 2014, other assets included an aggregate of $1.5 million in notes receivable. The carrying amounts of the notes receivable and other liabilities approximated fair value. The fair value of the notes receivable and other liabilities were estimated based on the Company’s assumptions, and were classified as Level 3 of the fair value hierarchy.

Note 3—Derivative Instruments

The primary risk managed by the Company using derivative instruments is commodity price risk, which is accounted for in accordance with Accounting Standards Codification 815—Derivatives and Hedging. Natural gas and electricity put and call options and swaps are entered into as hedges against unfavorable fluctuations in market prices of natural gas and electricity. The Company does not apply hedge accounting to these options or swaps, therefore the changes in fair value are recorded in earnings. By using derivative instruments to mitigate exposures to changes in commodity prices, the Company exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company minimizes the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties. At September 30, 2015 and December 31, 2014, GRE’s swaps and options were traded on the New York Mercantile Exchange.

The summarized volume of GRE’s outstanding contracts and options as of September 30, 2015 was as follows (MWh – Megawatt hour and Dth – Decatherm):

The fair value of outstanding derivative instruments recorded as assets in the accompanying consolidated balance sheets were as follows:

The fair value of outstanding derivative instruments recorded as liabilities in the accompanying consolidated balance sheets were as follows:

The effects of derivative instruments on the consolidated statements of operations were as follows:

Note 4 —Afek Oil and Gas Exploration Activities

In April 2013, the Government of Israel finalized the award to Afek of an exclusive three year petroleum exploration license covering 396.5 square kilometers in the southern portion of the Golan Heights. In 2013, Afek completed preliminary geophysical work including electromagnetic and gravimetric surveys and reprocessing of the 2D seismic data to characterize the subsurface prior to drilling exploration wells. Afek subsequently began the analysis of the acquired data internally and with outside oil exploration experts.

In early 2014, Afek submitted a permit application to the Northern Regional Planning and Building Committee to conduct a ten-well exploration drilling program to further characterize the resource in its license area. In July 2014, the Committee voted to approve the up to ten-well exploratory drilling program, and subsequently issued the requisite permits. In October 2014, the High Court of Justice in Israel issued an interim order to halt Afek’s drilling program until it could rule on a petition filed by the Israel Union for Environmental Defense and some local residents challenging the issuance of the drilling permit. In December 2014, the Court ruled against the petitioners, and lifted its interim order.

In February 2015, Afek initiated drilling on its first exploratory well pursuant to its up to ten-well exploratory program. To date, Afek has completed drilling two wells and has nearly completed drilling its third well. In addition, the design of the flow test program has been completed. Afek is in the process of seeking the final approval to begin testing multiple target zones on one of the completed wells. The results of the flow tests in combination with the results from Afek’s cuttings, logs, core samples, and other drilling instrumentation will eventually serve as the basis for a third party reserve estimate. Preliminary results are consistent with the assumptions underlying the exploratory program, and indicate the presence of hydrocarbons within the formation. The volume of the resources and to what extent they may be extractable cannot yet be determined. The resources do not constitute proved, probable or possible reserves.

On November 2, 2015, the Northern Regional Planning and Building Committee proposed issuance of a two-year extension of Afek’s drilling permit commencing a 60-day public comment period. If the permits are finalized, the extension could cover the remainder of Afek’s exploratory program of up to ten wells.

The Company accounts for Afek’s oil and gas activities under the successful efforts method of accounting. Under this method, the costs of drilling exploratory wells and exploratory-type stratigraphic test wells are capitalized, pending determination of whether the well has found proved reserves. Other exploration costs are charged to expense as incurred. Unproved properties are assessed for impairment, and if considered impaired, are charged to expense when such impairment is deemed to have occurred.

At September 30, 2015, capitalized exploratory well costs of unproved properties were $17.6 million. The Company recognized exploration expense of $1.5 million and $1.6 million in the three months ended September 30, 2015 and 2014, respectively, and $4.4 million and $3.5 million in the nine months ended September 30, 2015 and 2014, respectively.

Note 5 — Investment in American Shale Oil, LLC

The Company accounts for its ownership interest in AMSO, LLC using the equity method since the Company has the ability to exercise significant influence over its operating and financial matters, although it does not control AMSO, LLC. AMSO, LLC is a variable interest entity, however, the Company has determined that it is not the primary beneficiary, as the Company does not have the power to direct the activities of AMSO, LLC that most significantly impact AMSO, LLC’s economic performance.

Except as set forth below, AMSO was responsible for funding 20% of the initial $50 million of AMSO, LLC’s expenditures, and is responsible for funding 35% of the approved expenditures between $50 million and $100 million, and 40% of the costs of the one-time payment for conversion of AMSO, LLC’s research, development and demonstration lease to a commercial lease, in the event AMSO, LLC’s application for conversion is approved, with the remaining amounts of such expenditures to be funded by Total S.A. (“Total”). All other expenditures are to be borne in proportion to equity ownership. The percentages for expenditures are subject to proportional adjustment in connection with certain changes in the equity ownership of AMSO LLC. At September 30, 2015, the cumulative contributions of AMSO and Total to AMSO, LLC were $81.6 million. AMSO’s allocated share of the net loss of AMSO, LLC is included in “Equity in the net loss of AMSO, LLC” in the accompanying consolidated statements of operations.

AMSO has the right to decide at each capital call whether or not to fund AMSO, LLC, and will make a determination at each such time. AMSO did not fund the capital calls for any quarter from the fourth quarter of 2013 through the second quarter of 2015. AMSO funded an aggregate of $0.3 million in the third and fourth quarters of 2015, which was 38% of its share of the capital calls. In the period from January 2014 through October 2015, Total funded an aggregate of $4.2 million for AMSO’s share of the capital calls that AMSO did not fund. Because of AMSO’s decisions not to fund all of its share of AMSO, LLC’s expenditures, AMSO’s ownership interest in AMSO, LLC was reduced to 41.9% and Total’s ownership interest increased to 58.1%. In addition, AMSO’s share of future funding of AMSO, LLC up to a cumulative $100 million was reduced to 29.4% and Total’s share increased to 70.6%. AMSO is evaluating its options with respect to funding AMSO, LLC in 2016, and funding of less than its full share would result in further dilution of its interest in AMSO, LLC.

The agreements with Total provide for varying consequences for AMSO’s failure to fund its share at different stages of the project, including dilution of AMSO’s interest in AMSO, LLC or paying interest to Total for expenditures they fund on behalf of AMSO. Either Total or AMSO may terminate its obligations to make capital contributions and withdraw as a member of AMSO, LLC. Even if AMSO were to withdraw its interest in AMSO, LLC, it will remain liable for its share of expenditures for safety and environmental reclamation related to events occurring prior to its withdrawal.

The following table summarizes the change in the balance of the Company’s investment in AMSO, LLC:

At September 30, 2015 and at December 31, 2014, the liability for equity loss in AMSO, LLC was included in “Accrued expenses” in the consolidated balance sheet.

In part because of AMSO’s decisions not to fund all of its share of AMSO, LLC’s expenditures, AMSO, LLC allocated its net loss beginning January 2014 as follows: the first $11.8 million of losses were allocated to Total, then it allocates remaining losses proportionately such that over time AMSO and Total’s capital accounts as a percentage of AMSO, LLC’s total capital will equal their ownership interests.

Summarized unaudited statements of operations of AMSO, LLC are as follows:

Note 6—Equity

Changes in the components of equity were as follows:

Dividend Payments

On August 14, 2015, May 15, 2015 and February 15, 2015, the Company paid a quarterly Base Dividend of $0.1594 per share on its Series 2012-A Preferred Stock (“Preferred Stock”) for the second quarter of 2015, the first quarter of 2015 and the fourth quarter of 2014, respectively. On October 19, 2015, the Company’s Board of Directors declared a quarterly Base Dividend of $0.1594 per share on the Preferred Stock for the third quarter of 2015. The dividend will be paid on or about November 16, 2015 to stockholders of record as of the close of business on November 4, 2015. The aggregate dividends declared and paid in the nine months ended September 30, 2015 and 2014 were $1.1 million and $1.0 million, respectively.

On May 22, 2015 and March 31, 2015, the Company paid a quarterly dividend of $0.06 per share on its Class A common stock and Class B common stock for the first quarter of 2015 and for fourth quarter of 2014, respectively. The aggregate dividends declared and paid in the nine months ended September 30, 2015 and 2014 were $3.0 million and nil, respectively. On August 6, 2015, the Company announced that its Board of Directors had suspended dividends on the Company’s common stock for the current time.

Exercise of GOGAS stock option

On May 9, 2015, Michael Steinhardt exercised his option to acquire interests in GOGAS subsidiaries. Mr. Steinhardt and an affiliate received interests of approximately 1.5% in each of Afek, Genie Mongolia and IEI. In addition, Mr. Steinhardt and the affiliate received an approximately 1.7% interest in AMSO. The exercise price of $5.0 million was paid $2.5 million in cash and $2.5 million in promissory notes due in November 2015. The notes bear interest at 0.43% per annum, and are secured by 50% of the shares received in the exercise. At September 30, 2015, the notes receivable were included in “Receivables for issuance of equity” in the consolidated balance sheet.

Subsidiary Equity Grant Reclassified to Liability

IDT Energy had the right to issue shares of the Company’s Class B common stock or pay cash to satisfy its obligations to issue common stock of IDT Energy upon the vesting of the deferred stock units it had previously granted to officers and employees of the Company. IDT Energy elected to pay cash for the remaining deferred stock units that vested in June and July 2015. The Company paid cash in the amount of $1.2 million in August 2015 to satisfy its obligation to issue common stock of IDT Energy.

Stock-Based Compensation

On May 5, 2015, the Company’s stockholders approved an amendment and restatement to the Company’s 2011 Stock Option and Incentive Plan that increased the number of shares of the Company’s Class B common stock available for the grant of awards thereunder by an additional 180,000 shares. At May 7, 2015, the Company had 1.3 million shares of Class B common stock reserved for award under its 2011 Stock Option and Incentive Plan and 0.2 million shares were available for future grants.

On May 5, 2015, the Compensation Committee of the Company’s Board of Directors approved the grant of deferred stock units in GRE to certain of the Company’s officers and employees. Howard S. Jonas, the Company’s Chairman and Chief Executive Officer, was granted deferred stock units representing 2.8% of the outstanding equity in GRE, Avi Goldin, the Company’s Chief Financial Officer and Executive Vice President - Finance was granted deferred stock units representing 0.2% of the outstanding equity in GRE, Michael Stein, the Company’s Executive Vice President and the Chief Executive Officer and a Director of GRE was granted deferred stock units representing 0.3% of the outstanding equity in GRE, and other employees were granted deferred stock units representing an aggregate of 0.6% of the outstanding equity in GRE. The deferred stock units vest in equal amounts on the first, second and third anniversaries of the date of grant. The fair value of the GRE deferred stock units on the date of grant was $4.0 million, which is being recognized on a straight-line basis over the vesting period.

Stock Repurchase Program

On March 11, 2013, the Board of Directors of the Company approved a stock repurchase program for the repurchase of up to 7.0 million shares of the Company’s Class B common stock. There were no repurchases under this program in the nine months ended September 30, 2015. At September 30, 2015, 6.9 million shares remained available for repurchase under the stock repurchase program.

Variable Interest Entities

In 2011, an employee of IDT Corporation (“IDT”) until his employment was terminated effective December 30, 2011, incorporated Citizens Choice Energy, LLC (“CCE”), which is a REP that resells electricity and natural gas to residential and small business customers in the State of New York. Tari Corporation (“Tari”), which is owned by the former employee, is the sole owner of CCE. In addition, DAD Sales, LLC (“DAD”), which is 100% owned by Tari, used a network of independent door-to-door sales agents to obtain customers for CCE. In December 2012, DAD ceased to acquire customers for CCE. The Company provided CCE, DAD and Tari with substantially all of the cash required to fund their operations. The Company determined that since the acquisition of the interest in CCE, DAD and Tari, it had the power to direct the activities of these entities that most significantly impact their economic performance and it has the obligation to absorb losses of CCE, DAD and Tari that could potentially be significant to CCE, DAD and Tari on a stand-alone basis. The Company therefore determined that it is the primary beneficiary of CCE, DAD and Tari, and as a result, the Company consolidates CCE, DAD and Tari within its GRE segment. The Company does not own any interest in CCE, DAD or Tari and thus the net income or loss incurred by CCE, DAD and Tari was attributed to noncontrolling interests in the accompanying consolidated statements of operations.

Net income (loss) amounts related to CCE, DAD and Tari and aggregate net funding repaid to (provided by) the Company by CCE, DAD and Tari were as follows:

Summarized combined balance sheet amounts related to CCE, DAD and Tari are as follows:

The assets of CCE, DAD and Tari may only be used to settle obligations of CCE, DAD and Tari, and may not be used for other consolidated entities. The liabilities of CCE, DAD and Tari are non-recourse to the general credit of the Company’s other consolidated entities.

Note 7—Earnings (Loss) Per Share

Basic earnings (loss) per share is computed by dividing net income (loss) attributable to all classes of common stockholders of the Company by the weighted average number of shares of all classes of common stock outstanding during the applicable period. Diluted earnings (loss) per share is computed in the same manner as basic earnings (loss) per share, except that the number of shares is increased to include restricted stock still subject to risk of forfeiture and to assume exercise of potentially dilutive stock options using the treasury stock method, unless the effect of such increase is anti-dilutive.

The weighted-average number of shares used in the calculation of basic and diluted earnings (loss) per share attributable to the Company’s common stockholders consists of the following:

The following shares were excluded from the diluted loss per share computation because their inclusion would have been anti-dilutive:

The diluted loss per share equals basic loss per share in the nine months ended September 30, 2015 and in the three and nine months ended September 30, 2014 because the Company had a net loss and the impact of the assumed exercise of stock options and vesting of restricted stock would have been anti-dilutive.

An entity affiliated with Lord (Jacob) Rothschild has a one-time option, subject to certain conditions and exercisable between November 2017 and February 2018, to exchange its GOGAS shares for shares of the Company with equal fair value as determined by the parties. The number of shares issuable in such an exchange is not currently determinable. If this option is exercised, the shares issued by the Company may dilute the earnings per share in future periods.

An employee of the Company, pursuant to the terms of his employment agreement, has the option to exchange his equity interests in IEI, Afek, Genie Mongolia and any equity interest that he may acquire in other entities that the Company may create, for shares of the Company.

Employees and directors of the Company that were previously granted restricted stock of Afek and Genie Mongolia have the right to exchange the restricted stock, upon vesting of such shares, into shares of the Company’s Class B common stock. GRE has the right, at its option, to satisfy its obligations to issue common stock of GRE upon the vesting of the deferred stock units it granted in July 2015 to officers and employees of the Company in shares of the Company’s Class B common stock or cash. These exchanges and issuances, if elected, would be based on the relative fair value of the shares exchanged or to be issued. The number of shares of the Company’s stock issuable in an exchange is not currently determinable. If shares of the Company’s stock are issued upon such exchange, the Company’s earnings per share may be diluted in future periods.

Note 8—Related Party Transactions

On October 28, 2011, the Company was spun-off by IDT, its former parent company, (the “Spin-Off”). The Company entered into various agreements with IDT prior to the Spin-Off including an agreement for certain services to be performed by the Company and IDT. Following the Spin-Off, the charges for services provided by IDT are included in “Selling, general and administrative” expense in the consolidated statements of operations. Also, the Company provides specified administrative services to certain of IDT’s foreign subsidiaries. The charges for these services reduce the Company’s “Selling, general and administrative” expenses.

Note 9—Business Segment Information

The Company owns 99.3% of its subsidiary, GEIC, which owns 100% of GRE and 92% of GOGAS. The Company has three reportable business segments: GRE, GOGAS and Afek. GRE operates REPs including IDT Energy and Residents Energy, and energy brokerage and marketing services. Its REP businesses resell electricity and natural gas to residential and small business customers primarily in the Eastern United States. GOGAS is an oil and gas exploration company. The GOGAS segment is comprised of early stage oil shale projects including (1) an 88.4% interest in Genie Mongolia, an oil shale exploration project in Central Mongolia, (2) a 98.3% interest in AMSO, which holds and manages a 41.9% interest in AMSO, LLC, an oil shale development project in Colorado, and (3) an 86.1% interest in IEI, an oil shale development project in Israel. The Company has an 86.9% interest in Afek, which operates an oil and gas exploration project in the southern portion of the Golan Heights in Northern Israel. GRE has outstanding deferred stock units granted to officers and employees that represent an interest of 3.9% of the equity of GRE. Corporate costs include unallocated compensation, consulting fees, legal fees, business development expenses and other corporate-related general and administrative expenses. Corporate does not generate any revenues, nor does it incur any direct cost of revenues.

Afek was included in the GOGAS segment from its inception until December 31, 2014. Beginning in the first quarter of 2015, Afek is a separate reportable segment. Comparative results have been reclassified and restated as if Afek was a separate segment in all periods presented.

The Company’s reportable segments are distinguished by types of service, customers and methods used to provide their services. The operating results of these business segments are regularly reviewed by the Company’s chief operating decision maker.

The accounting policies of the segments are the same as the accounting policies of the Company as a whole. The Company evaluates the performance of its business segments based primarily on income (loss) from operations. There are no significant asymmetrical allocations to segments.

Operating results for the business segments of the Company were as follows:

Total assets for the business segments of the Company were as follows:

Note 10—Commitments and Contingencies

Legal Proceedings

On March 13, 2014, named plaintiff, Anthony Ferrare, commenced a putative class-action lawsuit against IDT Energy, Inc. in the Court of Common Pleas of Philadelphia County, Pennsylvania. The complaint was served on IDT Energy on July 16, 2014. The named plaintiff filed the suit on behalf of himself and other former and current electric customers of IDT Energy in Pennsylvania with variable rate plans, whom he contends were injured as a result of IDT Energy’s allegedly unlawful sales and marketing practices. On August 7, 2014, IDT Energy removed the case to the United States District Court for the Eastern District of Pennsylvania. On October 20, 2014, IDT Energy moved to stay or, alternatively, dismiss the complaint, as amended, by the named plaintiff. On November 10, 2014, the named plaintiff opposed IDT Energy’s motion to dismiss and IDT Energy filed a reply memorandum of law in further support of its motion to dismiss. On June 10, 2015, the Court granted IDT Energy’s motion to stay and denied its motion to dismiss without prejudice. IDT Energy believes that the claims in this lawsuit are without merit and intends to vigorously defend the action.

On June 20, 2014, the Pennsylvania Attorney General’s Office (“AG”) and the Acting Consumer Advocate (“OCA”) filed a Joint Complaint against IDT Energy, Inc. with the Pennsylvania Public Utility Commission (“PUC”). In the Joint Complaint, the AG and the OCA allege, among other things, various violations of Pennsylvania’s Unfair Trade Practices and Consumer Protection Law, the Telemarketing Registration Act and the Pennsylvania PUC’s regulations. IDT Energy has reached an agreement in principle on a settlement with the AG and the OCA to terminate the litigation with no admission of liability or finding of wrongdoing by IDT Energy. On August 4, 2015, IDT Energy, the AG, and the OCA filed a Joint Petition to the Pennsylvania PUC seeking approval of the settlement terms. Under the settlement, IDT Energy will agree to issue additional refunds to its Pennsylvania customers who had variable rates for electricity supply in January, February and March of 2014. IDT Energy will also agree to implement certain modifications to its sales, marketing and customer service processes, along with additional compliance and reporting requirements. The settlement must be approved by the Pennsylvania PUC, which is not expected until 2016.

On July 2, 2014, named plaintiff, Louis McLaughlin, filed a putative class-action lawsuit against IDT Energy, Inc. in the United States District Court for the Eastern District of New York, contending that he and other class members were injured as a result of IDT Energy’s allegedly unlawful sales and marketing practices. The named plaintiff filed the suit on behalf of himself and two subclasses: all IDT Energy customers who were charged a variable rate for their energy from July 2, 2008, and all IDT Energy customers who participated in IDT Energy’s rebate program from July 2, 2008. On December 19, 2014, IDT Energy filed a motion to dismiss the complaint. The named plaintiff filed opposition papers to IDT Energy’s motion to dismiss on March 13, 2015, and on April 10, 2015, IDT Energy filed its reply in further support of its motion to dismiss. The parties are now awaiting a decision from the Court. IDT Energy believes that the claims in this lawsuit are without merit and intends to vigorously defend the action.

On July 15, 2014, named plaintiff, Kimberly Aks, commenced a putative class-action lawsuit against IDT Energy, Inc. in New Jersey Superior Court, Essex County, contending that she and other class members were injured as a result of IDT Energy’s alleged unlawful sales and marketing practices. The named plaintiff filed the suit on behalf of herself and all other New Jersey residents who were IDT Energy customers at any time between July 11, 2008 and the present. On November 6, 2014, the Court denied IDT Energy’s motion to dismiss the complaint. The parties are currently engaged in discovery. IDT Energy believes that the claims in this lawsuit are without merit and intends to vigorously defend the action.

At September 30, 2015, the Company had an aggregate of $2.5 million accrued for the complaints and lawsuits described above.

In addition to the above, the Company may from time to time be subject to legal proceedings that arise in the ordinary course of business. Although there can be no assurance in this regard, the Company does not expect any of those legal proceedings to have a material adverse effect on the Company’s results of operations, cash flows or financial condition.

Purchase Commitments

The Company had purchase commitments of $10.1 million at September 30, 2015.

Renewable Energy Credits

GRE must obtain a certain percentage or amount of its power supply from renewable energy sources in order to meet the requirements of renewable portfolio standards in the states in which it operates. This requirement may be met by obtaining renewable energy credits that provide evidence that electricity has been generated by a qualifying renewable facility or resource. At September 30, 2015, GRE had commitments to purchase renewable energy credits of $33.4 million.

Tax Audits

The Company is subject to audits in various jurisdictions for various taxes. Amounts asserted by taxing authorities or the amount ultimately assessed against the Company could be greater than accrued amounts. Accordingly, additional provisions may be recorded in the future as revised estimates are made or underlying matters are settled or resolved. Imposition of assessments as a result of tax audits could have an adverse effect on the Company’s results of operations, cash flows and financial condition.

Letters of Credit

At September 30, 2015, the Company had letters of credit outstanding totaling $7.5 million primarily for the benefit of regional transmission organizations that coordinate the movement of wholesale electricity and for certain utility companies. The letters of credit outstanding at September 30, 2015 expire as follows: $5.8 million in the twelve months ending September 30, 2016 and $1.7 million in the twelve months ending September 30, 2017.

Performance Bonds

GRE has performance bonds issued through a third party for the benefit of various states in order to comply with the states’ financial requirements for REPs. At September 30, 2015, GRE had aggregate performance bonds of $11.9 million outstanding.

Other Contingencies

Since 2009, IDT Energy has been a party to a Preferred Supplier Agreement with BP Energy Company (“BP”). The agreement’s termination date has been extended to November 30, 2015. The Company is negotiating with BP and expects to have a new agreement in place by November 30, 2015. Under the arrangement, IDT Energy purchases electricity and natural gas at market rate plus a fee. IDT Energy’s obligations to BP are secured by a security interest in deposits or receivables from utilities in connection with their purchase of IDT Energy’s customer receivables, and in any cash deposits or letters of credit posted in connection with any collateral accounts with BP. IDT Energy’s ability to purchase electricity and natural gas under this agreement is subject to satisfaction of certain conditions including the maintenance of certain covenants. At September 30, 2015, the Company was in compliance with such covenants. At September 30, 2015, restricted cash—short-term of $0.4 million and trade accounts receivable of $26.4 million were pledged to BP as collateral for the payment of IDT Energy’s trade accounts payable to BP of $9.0 million at September 30, 2015.

Note 11—Revolving Line of Credit

As of April 23, 2012, the Company and IDT Energy entered into a Loan Agreement with JPMorgan Chase Bank for a revolving line of credit for up to a maximum principal amount of $25.0 million. The proceeds from the line of credit may be used to provide working capital and for the issuance of letters of credit. The Company agreed to deposit cash in a money market account at JPMorgan Chase Bank as collateral for the line of credit equal to the greater of (a) $10.0 million or (b) the sum of the amount of letters of credit outstanding plus the outstanding principal under the revolving note. The Company is not permitted to withdraw funds or exercise any authority over the required balance in the collateral account. The principal outstanding will bear interest at the lesser of (a) the LIBOR rate multiplied by the statutory reserve rate established by the Board of Governors of the Federal Reserve System plus 1.0% per annum, or (b) the maximum rate per annum permitted by whichever of applicable federal or Texas laws permit the higher interest rate. Interest is payable at least every three months and all outstanding principal and any accrued and unpaid interest is due on the maturity date of April 30, 2016. The Company pays a quarterly unused commitment fee of 0.08% per annum on the difference between $25.0 million and the average daily outstanding principal balance of the note. In addition, as of April 23, 2012, GEIC issued a Corporate Guaranty to JPMorgan Chase Bank whereby GEIC unconditionally guarantees the full payment of all indebtedness of the Company and IDT Energy under the Loan Agreement. At September 30, 2015 and December 31, 2014, there were no amounts borrowed under the line of credit, and cash collateral of $10.0 million was included in “Restricted cash—short-term” in the consolidated balance sheet. In addition, at September 30, 2015 and December 31, 2014, letters of credit of $7.5 million and $7.6 million, respectively, were outstanding.

Note 12— Recently Adopted Accounting Standard and Recently Issued Accounting Standards Not Yet Adopted

In August 2015, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) specifying that entities would not be precluded from applying the normal purchases and normal sales exception to derivative accounting to forward contracts for the physical delivery of electricity in nodal energy markets that result in parties incurring locational marginal pricing charges or credits. The ASU states that the use of locational marginal pricing by an independent system operator (“ISO”) to determine a transmission charge or credit in a nodal energy market would not constitute a net settlement of a forward contract for the purchase or sale of electricity, even when legal title to the electricity is conveyed to the ISO during transmission. As a result, these contracts could meet the physical delivery criterion in U.S. GAAP and qualify for the normal purchases and normal sales exception to derivative accounting if they meet all of the other criteria. This ASU was effective in August 2015. The adoption of this ASU did not affect the Company’s financial position, results of operations or cash flows.

In May 2014, the FASB and the International Accounting Standards Board jointly issued a comprehensive new revenue recognition standard that will supersede most of the current revenue recognition guidance under U.S. GAAP and International Financial Reporting Standards (“IFRS”). The goals of the revenue recognition project were to clarify and converge the revenue recognition principles under U.S. GAAP and IFRS and to develop guidance that would streamline and enhance revenue recognition requirements. The Company will adopt this standard on January 1, 2018. Entities have the option of using either a full retrospective or modified retrospective approach for the adoption of the standard. The Company is evaluating the impact that the standard will have on its consolidated financial statements.

In July 2015, the FASB issued an ASU that simplifies the subsequent measurement of inventory. The amendments in this ASU do not apply to inventory that is measured using last-in, first-out or the retail inventory method. The ASU changes the measurement of inventory to the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The Company measures its natural gas inventory at weighted average cost. The Company will adopt the amendments in this ASU on January 1, 2017. The Company is evaluating the impact that the ASU will have on its consolidated financial statements.

The following information should be read in conjunction with the accompanying consolidated financial statements and the associated notes thereto of this Quarterly Report, and the audited consolidated financial statements and the notes thereto and our Management’s Discussion and Analysis of Financial Condition and Results of Operations contained in our Annual Report on Form 10-K for the year ended December 31, 2014, as filed with the U.S. Securities and Exchange Commission (or SEC).

As used below, unless the context otherwise requires, the terms “the Company,” “Genie,” “we,” “us,” and “our” refer to Genie Energy Ltd., a Delaware corporation, and its subsidiaries, collectively.

Forward-Looking Statements

This Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, including statements that contain the words “believes,” “anticipates,” “expects,” “plans,” “intends,” and similar words and phrases. These forward-looking statements are subject to risks and uncertainties that could cause actual results to differ materially from the results projected in any forward-looking statement. In addition to the factors specifically noted in the forward-looking statements, other important factors, risks and uncertainties that could result in those differences include, but are not limited to, those discussed under Item 1A to Part I “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2014. The forward-looking statements are made as of the date of this report and we assume no obligation to update the forward-looking statements, or to update the reasons why actual results could differ from those projected in the forward-looking statements. Investors should consult all of the information set forth in this report and the other information set forth from time to time in our reports filed with the SEC pursuant to the Securities Act of 1933 and the Securities Exchange Act of 1934, including our Annual Report on Form 10-K for the year ended December 31, 2014.

Overview

We own 99.3% of our subsidiary, Genie Energy International Corporation, or GEIC, which owns 100% of Genie Retail Energy, or GRE, and 92% of Genie Oil and Gas, Inc., or GOGAS. Our principal businesses consist of the following:

GRE has outstanding deferred stock units granted to officers and employees that represent an interest of 3.9% of the equity of GRE.

As part of our ongoing business development efforts, we continuously seek out new opportunities, which may include complementary operations or businesses that reflect horizontal or vertical expansion from our current operations. Some of these potential opportunities are considered briefly and others are examined in further depth. In particular, we seek out acquisitions to expand the geographic scope and size of our REP businesses, and additional energy exploration projects to diversify our GOGAS unit’s operations, among geographies, technologies and resources.

Genie Retail Energy

Seasonality and Weather

The weather and the seasons, among other things, affect GRE’s revenues. Weather conditions have a significant impact on the demand for natural gas used for heating and electricity used for heating and cooling. Typically, colder winters increase demand for natural gas and electricity, and hotter summers increase demand for electricity. Milder winters and/or summers have the opposite effects. Natural gas revenues typically increase in the first quarter due to increased heating demands and electricity revenues typically increase in the third quarter due to increased air conditioning use. Approximately 59% and 49% of GRE’s natural gas revenues for the relevant years were generated in the first quarter of 2014 and 2013, respectively, when demand for heating was highest. Although the demand for electricity is not as seasonal as natural gas (due, in part, to usage of electricity for both heating and cooling), approximately 20% and 31% of GRE’s electricity revenues for the relevant years were generated in the third quarter of 2014 and 2013, respectively. Because of dramatic increases in wholesale electricity prices in January and February 2014, the retail electricity prices that GRE and many other variable rate electricity suppliers charged to their customers also increased sharply. As a result, approximately 45% of GRE’s electricity revenues in 2014 were generated in the first quarter of 2014. Our revenues and operating income are subject to material seasonal variations, and the interim financial results are not necessarily indicative of the estimated financial results for the full year.

Concentration of Customers and Associated Credit Risk

GRE reduces its REP customer credit risk by participating in purchase of receivable, or POR, programs for a majority of its receivables. In addition to providing billing and collection services, utility companies purchase GRE’s receivables and assume all credit risk without recourse to GRE. GRE’s primary credit risk is therefore nonpayment by the utility companies. Certain of the utility companies represent significant portions of our consolidated revenues and consolidated gross trade accounts receivable balance and such concentrations increase our risk associated with nonpayment by those utility companies.

The following table summarizes the percentage of consolidated revenues from customers by utility company that equal or exceed 10% of our consolidated revenues in the period (no other single utility company accounted for 10% or greater of our consolidated revenues in these periods):

na-less than 10% of consolidated revenue in the period

The following table summarizes the percentage of consolidated gross trade accounts receivable by utility company that equal or exceed 10% of consolidated gross trade accounts receivable at September 30, 2015 and December 31, 2014 (no other single utility company accounted for 10% or greater of our consolidated gross trade accounts receivable at September 30, 2015 or December 31, 2014):

na-less than 10% of consolidated gross trade accounts receivable

Winter 2014 Price Volatility and Customer Complaints

A confluence of issues in January and February 2014 associated with that winter’s polar vortex that were outside the ability of REPs to control, resulted in extraordinarily large spikes in the prices of wholesale electricity and natural gas in markets where GRE and other retail providers purchase their supply. These issues included sustained, extremely cold weather in much of GRE’s service area, short reserves of natural gas in the wholesale markets, delivery constrictions and unusually volatile commodity trading in the financial markets. Because of dramatic increases in wholesale electricity prices, the retail electricity prices that GRE and many other variable rate electricity suppliers charged to their customers also increased sharply in January and February 2014. These retail electricity price increases resulted in large numbers of customers filing informal and formal complaints to state utility commissions, state attorneys general, and state legislators. IDT Energy was served with several thousand formal and informal customer complaints to state utility commissions and state attorneys general related to the retail price increases. IDT Energy has responded to each customer complaint it has received and attempted to resolve each complaining customer’s concerns. IDT Energy also paid approximately $5 million in rebates to affected customers in the year ended December 31, 2014. IDT Energy was under no obligation to provide such rebates, but did so in order to mitigate the impact of the price increases on its customers notwithstanding that the underlying cause of the price increase was beyond IDT Energy’s control.

IDT Energy also received, and in most instances, responded to, formal and informal information requests from state utility commissions, state attorneys general, and state legislators related to the wholesale and retail electricity price increases in the winter of 2014. In addition, the Pennsylvania Attorney General’s Office and Pennsylvania’s Acting Consumer Advocate filed a Joint Complaint against IDT Energy with the Pennsylvania Public Utility Commission in connection with such events. On August 4, 2015, IDT Energy, the Attorney General’s Office, and the Acting Consumer Advocate filed a Joint Petition to the Pennsylvania Public Utility Commission seeking approval of their proposed settlement terms. IDT Energy has also been sued in separate putative class action suits in New York, New Jersey and Pennsylvania, partially related to the price increases during the winter of 2014. These matters are more fully discussed in Note 10 to the consolidated financial statements included in Item 1 to Part I “Financial Statements” in this Quarterly Report.

IDT Energy does not believe that it was at fault or acted in any way improperly with respect to the events of winter 2014. However, we cannot predict the outcome of the regulatory or putative class action litigation or the impact on us of these or other actions, or whether there will be other impacts from the conditions that existed in winter 2014. As noted above, IDT Energy is a party to a Joint Petition to the Pennsylvania Public Utility Commission seeking approval of proposed terms to settle the Pennsylvania regulatory matter.

Afek Oil and Gas, Ltd.

In 2013, the Government of Israel finalized the award to Afek of an exclusive three year petroleum exploration license covering 396.5 square kilometers in the southern portion of the Golan Heights. Afek has retained oil and gas exploration professionals and has contracted with internationally recognized vendors to provide the services required for its exploration program. In 2013, Afek completed preliminary geophysical work including electromagnetic survey and the reprocessing of 2D seismic data to characterize the subsurface prior to drilling exploration wells. Afek subsequently conducted initial analysis of the acquired data internally and with outside exploration experts. In addition, Afek submitted a permit application and was issued a permit by Israel’s Northern Regional Planning and Building Committee to conduct an up to ten-well exploratory drilling program. In connection with a petition filed by the Israel Union for Environmental Defense and certain local residents, Israel’s High Court of Justice issued an interim injunction against Afek, restricting Afek from building installations or changing the surface of the ground until the Court ruled on the petition. In December 2014, the High Court rejected the petition challenging the permits, and lifted its injunction on Afek’s exploratory program in Northern Israel.

In February 2015, Afek initiated drilling on its first exploratory well pursuant to its up to ten-well exploratory program. To date, Afek has completed drilling two wells and has nearly completed drilling its third well. In addition, the design of the flow test program has been completed. Afek is in the process of seeking the final approval to begin testing multiple target zones on one of the completed wells. The results of the flow tests in combination with the results from Afek’s cuttings, logs, core samples, and other drilling instrumentation will eventually serve as the basis for a third party reserve estimate. Preliminary results are consistent with the assumptions underlying the exploratory program, and indicate the presence of hydrocarbons within the formation. Afek is optimistic about its program and is committed to additional analysis, flow testing, new seismic work and exploratory drilling at other sites in its license area. The volume of the resources and to what extent they may be extractable cannot yet be determined. The resources do not constitute proved, probable or possible reserves.

On November 2, 2015, the Northern Regional Planning and Building Committee proposed issuance of a two-year extension of Afek’s drilling permit commencing a 60-day public comment period. If the permits are finalized, the extension could cover the remainder of Afek’s exploratory program of up to ten wells.

We account for our oil and gas activities under the successful efforts method of accounting. Under this method, the costs of drilling exploratory wells and exploratory-type stratigraphic test wells are capitalized, pending determination of whether the well has found proved reserves. Other exploration costs are charged to expense as incurred. Unproved properties are assessed for impairment, and if considered impaired, are charged to expense when such impairment is deemed to have occurred.

Genie Mongolia

In April 2013, Genie Mongolia and the Petroleum Authority of Mongolia entered into an exclusive oil shale development agreement to explore and evaluate the commercial potential of oil shale resources in a 34,470 square kilometer area in Central Mongolia. The five year agreement allows Genie Mongolia to explore, identify and characterize the oil shale resource in the exclusive survey area and to conduct a pilot test using in-situ technology on appropriate oil shale deposits. In September 2014, Genie Mongolia signed a prospecting agreement with the Petroleum Authority of Mongolia covering an additional 25,000 square kilometers in Central Mongolia. In light of the progress achieved by Afek in Northern Israel and growth potential at GRE, we are sharpening our strategic focus on those two opportunities. Accordingly, we are scaling back operations in Mongolia.

Investment in American Shale Oil, LLC

AMSO, LLC holds a research, development and demonstration lease awarded by the U.S. Bureau of Land Management that covers an area of 160 acres in western Colorado (the RD&D Lease). The RD&D Lease runs for a ten-year period beginning on January 1, 2007, and is subject to an extension of up to five years if AMSO, LLC can demonstrate that a process leading to the production of commercial quantities of shale oil is diligently being pursued. If AMSO, LLC can demonstrate the economic and environmental viability of its technology, it will have the opportunity to submit a one-time payment pursuant to the applicable regulations and convert its RD&D Lease to a commercial lease on 5,120 acres, which overlap and are contiguous with the 160 acres covered by its RD&D Lease.

Except as set forth below, AMSO was responsible for funding 20% of the initial $50 million of AMSO, LLC’s approved expenditures, and is responsible for funding 35% of the approved expenditures between $50 million and $100 million, and 40% of the costs of the one-time payment for conversion of AMSO, LLC’s RD&D Lease to a commercial lease, in the event AMSO, LLC’s application for conversion is approved, with the remaining amounts of such expenditures to be funded by Total S.A., or Total. All other expenditures are to be borne in proportion to equity ownership. The percentages for expenditures are subject to proportional adjustment in connection with certain changes in the equity ownership of AMSO LLC. At September 30, 2015, the cumulative contributions of AMSO and Total to AMSO, LLC were $81.6 million. 

AMSO has the right to decide at each capital call whether or not to fund AMSO, LLC, and will make a determination at each such time. AMSO did not fund the capital calls for any quarter from the fourth quarter of 2013 through the second quarter of 2015. AMSO funded an aggregate of $0.3 million in the third and fourth quarters of 2015, which was 38% of its share of the capital calls. In the period from January 2014 through October 2015, Total funded an aggregate of $4.2 million for AMSO’s share of the capital calls that AMSO did not fund. Because of AMSO’s decisions not to fund all of its share of AMSO, LLC’s expenditures, AMSO’s ownership interest in AMSO, LLC was reduced to 41.9% and Total’s ownership interest increased to 58.1%. In addition, AMSO’s share of future funding of AMSO, LLC up to a cumulative $100 million was reduced to 29.4% and Total’s share increased to 70.6%. AMSO is evaluating its options with respect to funding AMSO, LLC in 2016, and funding of less than its full share would result in further dilution of its interest in AMSO, LLC.

The agreements with Total provide for varying consequences for AMSO’s failure to fund its share at different stages of the project, including dilution of AMSO’s interest in AMSO, LLC or paying interest to Total for expenditures they fund on behalf of AMSO. Either Total or AMSO may terminate its obligations to make capital contributions and withdraw as a member of AMSO, LLC. Even if AMSO were to withdraw its interest in AMSO, LLC, it will remain liable for its share of expenditures for safety and environmental reclamation related to events occurring prior to its withdrawal.

We account for our ownership interest in AMSO, LLC using the equity method since we have the ability to exercise significant influence over its operating and financial matters, although we do not control AMSO, LLC. AMSO, LLC is a variable interest entity, however, we have determined that we are not the primary beneficiary. In part because of AMSO’s decisions not to fund all of its share of AMSO, LLC’s expenditures, AMSO, LLC allocated its net loss beginning January 2014 as follows: the first $11.8 million of losses were allocated to Total, then it allocates any remaining losses proportionately such that over time AMSO and Total’s capital accounts as a percentage of AMSO, LLC’s total capital will equal their ownership interests.

Israel Energy Initiatives, Ltd.

IEI had an exclusive Shale Oil Exploration and Production License awarded in July 2008 by the Government of Israel. The license covered approximately 238 square kilometers in the south of the Shfela region in Central Israel. Under the terms of the license, IEI was to conduct a geological appraisal study across the license area, characterize the resource and select a location for a pilot plant. The initial term of the license was for three years until July 2011. The license was extended until July 2015 when it expired. IEI submitted its application for the construction and operation of its oil shale pilot test facility to the Jerusalem District Committee for Planning and Building, and on September 2, 2014, the Committee declined to issue IEI a permit to build and operate a pilot drilling project. IEI is currently evaluating its options to determine whether, and the best course of action, to move forward to exploit the abundant oil shale resource in Israel, and operations at IEI are currently on hold.

Critical Accounting Policies

Our consolidated financial statements and accompanying notes are prepared in accordance with accounting principles generally accepted in the United States of America, or U.S. GAAP. Our significant accounting policies are described in Note 1 to the consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2014. In addition, as described in Note 4 to the consolidated financial statements included in Item 1 to Part I “Financial Statements” in this Quarterly Report, we account for Afek’s oil and gas activities under the successful efforts method of accounting. The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities. Critical accounting policies are those that require application of management’s most subjective or complex judgments, often as a result of matters that are inherently uncertain and may change in subsequent periods. Our critical accounting policies include those related to the allowance for doubtful accounts, goodwill and income taxes. Management bases its estimates and judgments on historical experience and other factors that are believed to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. For additional discussion of our critical accounting policies, see our Management’s Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2014.

Recently Adopted Accounting Standard and Recently Issued Accounting Standards Not Yet Adopted

In August 2015, the Financial Accounting Standards Board, or FASB, issued an Accounting Standards Update, or ASU, specifying that entities would not be precluded from applying the normal purchases and normal sales exception to derivative accounting to forward contracts for the physical delivery of electricity in nodal energy markets that result in parties incurring locational marginal pricing charges or credits. The ASU states that the use of locational marginal pricing by an independent system operator, or ISO, to determine a transmission charge or credit in a nodal energy market would not constitute a net settlement of a forward contract for the purchase or sale of electricity, even when legal title to the electricity is conveyed to the ISO during transmission. As a result, these contracts could meet the physical delivery criterion in U.S. GAAP and qualify for the normal purchases and normal sales exception to derivative accounting if they meet all of the other criteria. This ASU was effective in August 2015. The adoption of this ASU did not affect our financial position, results of operations or cash flows.

In May 2014, the FASB and the International Accounting Standards Board jointly issued a comprehensive new revenue recognition standard that will supersede most of the current revenue recognition guidance under U.S. GAAP and International Financial Reporting Standards, or IFRS. The goals of the revenue recognition project were to clarify and converge the revenue recognition principles under U.S. GAAP and IFRS and to develop guidance that would streamline and enhance revenue recognition requirements. We will adopt this standard on January 1, 2018. Entities have the option of using either a full retrospective or modified retrospective approach for the adoption of the standard. We are evaluating the impact that the standard will have on our consolidated financial statements.

In July 2015, the FASB issued an ASU that simplifies the subsequent measurement of inventory. The amendments in this ASU do not apply to inventory that is measured using last-in, first-out or the retail inventory method. The ASU changes the measurement of inventory to the lower of cost and net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. We measure GRE’s natural gas inventory at weighted average cost. We will adopt the amendments in this ASU on January 1, 2017. We are evaluating the impact that the ASU will have on our consolidated financial statements.

Results of Operations

We evaluate the performance of our operating business segments based primarily on income (loss) from operations. Accordingly, the income and expense line items below income (loss) from operations are only included in our discussion of the consolidated results of operations.

Three and Nine Months Ended September 30, 2015 Compared to Three and Nine Months Ended September 30, 2014

Genie Retail Energy Segment

Revenues. GRE’s electricity revenues increased in the three months ended September 30, 2015 compared to the same period in 2014 because of increases in electricity consumption and the average rate charged to customers. Electricity consumption increased 13.6% in the three months ended September 30, 2015 compared to the same period in 2014. The increase in electricity consumption was the result of an increase in meters served coupled with an increase in average consumption per meter. Average meters served increased 8.1% in the three months ended September 30, 2015 compared to the same period in 2014. Average consumption per meter increased 5.2% in the three months ended September 30, 2015 compared to the same period in 2014. The warmer summer in 2015 compared to 2014, and our focus on acquiring new meters in relatively high per meter consumption territories, drove the increases in electricity consumption and in average consumption per meter. The average rate charged to customers for electricity increased 2.3% in the three months ended September 30, 2015 compared to the same period in 2014.

GRE’s electricity revenues decreased in the nine months ended September 30, 2015 compared to the same period in 2014 because of decreases in both the average rate charged to customers and electricity consumption. The average rate charged to customers for electricity decreased 15.6% in the nine months ended September 30, 2015 compared to the same period in 2014. This decrease was mostly due to a decrease in the underlying commodity cost in the nine months ended September 30, 2015 compared to the same period in 2014. In the winter of 2014, there were extraordinarily large spikes in the prices of wholesale electricity and natural gas in markets where GRE and other REPs purchased their supply because of the polar vortex in January and February 2014 that is more fully discussed above. Electricity consumption decreased 13.0% in the nine months ended September 30, 2015 compared to the same period in 2014. The decrease in electricity consumption was primarily the result of a decrease in average consumption per meter, which decreased 17.4% in the nine months ended September 30, 2015 compared to the same period in 2014. The decrease was the result of higher usage in 2014 due to the prolonged cold temperatures as well as subsequent churn being concentrated in higher consuming meters. The decrease in electricity consumption was partially offset by an increase in average meters served, which increased 5.2% in the nine months ended September 30, 2015 compared to the same period in 2014.

GRE's natural gas revenues decreased in the three and nine months ended September 30, 2015 compared to the same periods in 2014 because of decreases in both the average rate charged to customers and natural gas consumption. The average rate charged to customers for natural gas decreased 10.1% and 20.6% in the three and nine months ended September 30, 2015, respectively, compared to the same periods in 2014. The decrease in the nine months ended September 30, 2015 compared to the same period in 2014 was mostly due to a significant decrease in the underlying commodity cost as described above. Natural gas consumption decreased 10.2% and 8.1% in the three and nine months ended September 30, 2015, respectively, compared to the same periods in 2014. The decrease in natural gas consumption was the result of decreases in average meters served, which decreased 1.7% and 7.7% in the three and nine months ended September 30, 2015, respectively, compared to the same periods in 2014. The decrease in natural gas consumption was also due to decreases in average consumption per meter of 8.7% and 0.5% in the three and nine months ended September 30, 2015, respectively, compared to the same periods in 2014. Natural gas consumption in 2014 was upwardly affected by the prolonged cold temperatures during the polar vortex in January and February 2014 and the subsequent churn was concentrated in higher consuming meters.

GRE’s customer base as measured by meters served consisted of the following:

Gross meter acquisitions in the three and nine months ended September 30, 2015 were 74,000 and 205,000, respectively, compared to 56,000 and 158,000 in the three and nine months ended September 30, 2014, respectively. GRE had success in selling “IDT Energy® SmartBudget” and other offerings with fixed rate characteristics. The increase was also partially due to an intentional slowing of customer acquisitions in the three and nine months ended September 30, 2014 in the territories most impacted by the rising wholesale commodity costs during the effects of the polar vortex.

Net meters served increased by 11,000 or 2.8% in the three months ended September 30, 2015 compared to a decrease of 2,000 or 0.6% in the three months ended September 30, 2014, and increased by 25,000 or 6.9% in the nine months ended September 30, 2015 compared to a decrease of 65,000 or 15.1% in the nine months ended September 30, 2014. The increases in net meters served were due to the increases in gross meter acquisitions, and in the nine months ended September 30, 2015 compared to the same period in 2014, a reduction in customer churn. Average monthly churn increased from 6.2% in the three months ended September 30, 2014 to 6.7% in the three months ended September 30, 2015, and decreased from 7.2% in the nine months ended September 30, 2014 to 6.3% in the nine months ended September 30, 2015. The increase in average monthly churn in the three months ended September 30, 2015 compared to the same period in 2014 reflected the accelerated pace of meter acquisitions in recent quarters. On average, newly acquired meters exhibit higher rates of churn than long tenured meters. The decrease in churn in the nine months ended September 30, 2015 compared to the same period in 2014 reflects a return to more normalized churn rates following the unusually high rates recorded in the first and second quarters of 2014 following that winter’s polar vortex. Churn rates were also favorably impacted by the successful introduction of the pricing plans with fixed rate characteristics.

GRE has applications pending to enter into additional utility service areas, primarily natural gas and dual meter territories, in various locations in the states where we currently operate and in other jurisdictions. We continue to evaluate additional, deregulation-driven opportunities in order to expand our business geographically.

The average rates of annualized energy consumption, as measured by residential customer equivalents, or RCEs, are presented in the chart below. An RCE represents a natural gas customer with annual consumption of 100 mmbtu or an electricity customer with annual consumption of 10 MWh. Because different customers have different rates of energy consumption, RCEs are an industry standard metric for evaluating the consumption profile of a given retail customer base.

The RCE increase at September 30, 2015 compared to September 30, 2014 primarily reflects the increase in electricity customers in New Jersey and Illinois utility territories that have relatively high per meter consumption rates compared to our full customer base.

Other revenue in the three and nine months ended September 30, 2015 and 2014 includes revenue earned by Diversegy, LLC, or Diversegy, and IDT Energy Network, LLC (formerly known as Epiq Energy, LLC), or IDT Energy Network, both of which were acquired in December 2013. Diversegy and IDT Energy Network earn commissions, entry fees and other fees from their retail energy advisory and brokerage business and network marketing business, respectively.

Direct Cost of Revenues and Gross Margin Percentage. GRE’s direct cost of revenues and gross margin percentage were as follows:

Direct cost of revenues for electricity increased in the three months ended September 30, 2015 compared to the same period in 2014 primarily because of the 13.6% increase in electricity consumption in the three months ended September 30, 2015 compared to the same period in 2014. This increase in electricity consumption was partially offset by a 6.0% decrease in the average unit cost of electricity in the three months ended September 30, 2015 compared to the same period in 2014. Gross margin on electricity sales increased in the three months ended September 30, 2015 compared to the same period in 2014 because the average rate charged to customers increased while the average unit cost of electricity decreased.

Direct cost of revenues for electricity decreased in the nine months ended September 30, 2015 compared to the same period in 2014 primarily because of the 30.2% decrease in the average unit cost of electricity in the nine months ended September 30, 2015 compared to the same period in 2014, as well as the 13.0% decrease in electricity consumption in the nine months ended September 30, 2015 compared to the same period in 2014. Gross margin on electricity sales increased in the nine months ended September 30, 2015 compared to the same period in 2014 because the average rate charged to customers decreased less than the average unit cost of electricity.

Direct cost of revenues for natural gas decreased in the three months ended September 30, 2015 compared to the same period in 2014 primarily because natural gas consumption decreased 10.2% in the three months ended September 30, 2015 compared to the same period in 2014. This decrease in natural gas consumption was partially offset by a 1.9% increase in the average unit cost of natural gas in the three months ended September 30, 2015 compared to the same period in 2014. Gross margin on natural gas sales decreased in the three months ended September 30, 2015 compared to the same period in 2014 because the average rate charged to customers decreased while the average unit cost of natural gas increased.

Direct cost of revenues for natural gas decreased in the nine months ended September 30, 2015 compared to the same period in 2014 primarily because the average unit cost of natural gas decreased 36.8% in the nine months ended September 30, 2015 compared to the same period in 2014 and natural gas consumption decreased 8.1% in the nine months ended September 30, 2015 compared to the same period in 2014. Gross margin on natural gas sales increased in the nine months ended September 30, 2015 compared to the same period in 2014 because the average rate charged to customers decreased less than the average unit cost of natural gas.

Other direct cost of revenues primarily consists of commission expense incurred by Diversegy and IDT Energy Network.

Selling, General and Administrative. The increase in selling, general and administrative expenses in the three and nine months ended September 30, 2015 compared to the same periods in 2014 was due to increases in customer acquisition costs and payroll and related expense. In addition, in the nine months ended September 30, 2015, the increase included an accrual of $2.7 million for regulatory and legal matters including outside counsel fees. These increases were partially offset by decreases in purchase of receivable fees and billing costs in the nine months ended September 30, 2015 compared to the same period in 2014. As a percentage of IDT Energy’s total revenues, selling, general and administrative expenses decreased from 26.4% in the three months ended September 30, 2014 to 25.4% in the three months ended September 30, 2015 and increased from 14.9% in the nine months ended September 30, 2014 to 24.6% in the nine months ended September 30, 2015.

Afek Segment

We have an 86.9% interest in Afek, which operates an exploration project in the southern portion of the Golan Heights in Northern Israel. Afek was included in the Genie Oil and Gas segment from its inception until December 31, 2014. Beginning in the first quarter of 2015, Afek is a separate reportable segment. Comparative results have been reclassified and restated as if Afek was a separate segment in all periods presented. Afek does not currently generate any revenues, nor does it incur any direct cost of revenues.

General and Administrative. General and administrative expenses increased in the three and nine months ended September 30, 2015 compared to the same periods in 2014 primarily because of increases in payroll expense and consulting and professional fees.

Exploration.  In 2014, Afek was issued a permit by Israel’s Northern Regional Planning and Building Committee to conduct an up to ten-well exploratory drilling program. In connection with a petition from the Israel Union for Environmental Defense and certain local residents, Israel’s High Court of Justice issued an interim injunction against Afek, restricting Afek from building installations or changing the surface of the ground until the Court ruled on the petition. In December 2014, the High Court rejected the petition challenging the permits, and lifted its injunction on Afek’s exploratory program in Northern Israel. In February 2015, Afek initiated drilling on its first exploratory well pursuant to its up to ten-well exploratory program. To date, Afek has completed drilling two wells and has nearly completed drilling its third well.

Genie Oil and Gas Segment

Genie Oil and Gas does not currently generate any revenues, nor does it incur any direct cost of revenues.

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General and Administrative. General and administrative expenses were substantially unchanged in the three months ended September 30, 2015 and 2014. General and administrative expenses decreased in the nine months ended September 30, 2015 compared to the same period in 2014 primarily because of decreases in travel, rent, consulting and professional expenses.

Research and Development. Research and development expenses consist of the following:

Genie Mongolia’s research and development expense in the three and nine months ended September 30, 2015 and 2014 related to the joint geological survey agreement with the Republic of Mongolia, which was executed in April 2013, to explore certain of that country’s oil shale deposits. In 2014, Genie Mongolia acquired approximately 40 kilometers of 2D seismic results and drilled in three different basins within the license areas. Genie Mongolia also continued surface mapping and other geophysical evaluation work within the areas.

During 2014, the environmental documents portion of IEI’s permit application for the construction and operation of its oil shale pilot test facility was under review by the Ministry of Environment. In addition, as per the required permitting process, IEI continued laboratory work, engineering work and associated preparation of environmental permit applications related to the planned pilot. IEI submitted its application for the construction and operation of its oil shale pilot test facility to the Jerusalem District Committee for Planning and Building, and on September 2, 2014, the Committee declined to issue IEI a permit to build and operate a pilot drilling project.

Equity in the Net Loss of AMSO, LLC. Equity in the net loss of AMSO, LLC was $0.1 million in the three and nine months ended September 30, 2015 and nil in the three and nine months ended September 30, 2014. AMSO has the right to decide at each capital call whether or not to fund AMSO, LLC, and will make a determination at each such time. AMSO did not fund the capital calls for any quarter from the fourth quarter of 2013 through the second quarter of 2015. AMSO funded an aggregate of $0.3 million in the third and fourth quarters of 2015, which was 38% of its share of the capital calls. In the period from January 2014 through October 2015, Total funded an aggregate of $4.2 million for AMSO’s share of the capital calls that AMSO did not fund. In part because of AMSO’s decisions not to fund all of its share of AMSO, LLC’s expenditures, AMSO, LLC allocated its net loss beginning January 2014 as follows: the first $11.8 million of losses were allocated to Total, then it allocates any remaining losses proportionately such that over time AMSO and Total’s capital accounts as a percentage of AMSO, LLC’s total capital will equal their ownership interests. AMSO, LLC’s net loss was $1.3 million and $4.0 million in the three and nine months ended September 30, 2015, respectively.

Corporate

Corporate does not generate any revenues, nor does it incur any direct cost of revenues. Corporate costs include unallocated compensation, consulting fees, legal fees, business development expenses and other corporate-related general and administrative expenses.

The decrease in general and administrative expenses in the three and nine months ended September 30, 2015 as compared to the same periods in 2014 was mostly due to a decrease in stock-based compensation expense, which decreased to $1.1 million in the three months ended September 30, 2015 from $4.7 million in the three months ended September 30, 2014 and decreased to $3.4 million in the nine months ended September 30, 2015 from $7.7 million in the nine months ended September 30, 2014. As a percentage of our consolidated revenues, Corporate general and administrative expenses decreased from 13.9% in the three months ended September 30, 2014 to 4.0% in the three months ended September 30, 2015 and from 5.4% in the nine months ended September 30, 2014 to 4.1% in the nine months ended September 30, 2015.

Consolidated

Selling, General and Administrative. On October 28, 2011, we were spun-off by IDT Corporation, or IDT, our former parent company (the Spin-Off). IDT charges us for services it provides pursuant to an agreement, and we charge IDT for specified administrative services that we provide to certain of IDT’s foreign subsidiaries. The amounts that IDT charged us, net of the amounts that we charged IDT, were $0.4 million and $1.1 million in the three months ended September 30, 2015 and 2014, respectively, and $1.2 million and $2.2 million in the nine months ended September 30, 2015 and 2014, respectively, which are included in consolidated selling, general and administrative expense.

Stock-based compensation expense included in consolidated selling, general and administrative expenses was $1.2 million and $4.1 million in the three and nine months ended September 30, 2015, respectively, compared to $4.9 million and $8.5 million in the same periods in 2014. The decrease in stock-based compensation expense was primarily due to unrecognized compensation cost that was fully recognized in the period from July 1, 2014 to December 31, 2014. At September 30, 2015, aggregate unrecognized compensation cost related to non-vested stock-based compensation was $13.9 million. The unrecognized compensation cost is recognized over the expected service period.

On May 5, 2015, the Compensation Committee of our Board of Directors approved the grant of deferred stock units in GRE to certain of our officers and employees. Howard S. Jonas, our Chairman and Chief Executive Officer, was granted deferred stock units representing 2.8% of the outstanding equity in GRE, Avi Goldin, our Chief Financial Officer and Executive Vice President - Finance was granted deferred stock units representing 0.2% of the outstanding equity in GRE, Michael Stein, our Executive Vice President and the Chief Executive Officer and a Director of GRE was granted deferred stock units representing 0.3% of the outstanding equity in GRE, and other employees were granted deferred stock units representing an aggregate of 0.6% of the outstanding equity in GRE. The deferred stock units vest in equal amounts on the first, second and third anniversaries of the date of grant. The fair value of the GRE deferred stock units on the date of grant was $4.0 million, which is being recognized on a straight-line basis over the vesting period.

The following is a discussion of our consolidated income and expense line items below income (loss) from operations: