UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

For the quarterly period ended June 30, 2014

or

For the transition period from                  to                 

Commission File Number 1-33571

ESCALERA RESOURCES CO.

(Exact name of registrant as specified in its charter)

303-794-8445

(Registrant’s telephone number, including area code)

Double Eagle Petroleum Co.

(Former name)

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 Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T 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 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 checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

ESCALERA RESOURCES CO.

FORM 10-Q

TABLE OF CONTENTS

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ESCALERA RESOURCES CO.

CONSOLIDATED BALANCE SHEETS

(Amounts in thousands of dollars except share data)

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The accompanying notes are an integral part of the consolidated financial statements.

ESCALERA RESOURCES CO.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Amounts in thousands of dollars except share and per share data)

(Unaudited)

The accompanying notes are an integral part of the consolidated financial statements.

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ESCALERA RESOURCES CO.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in thousands of dollars)

(Unaudited)

The accompanying notes are an integral part of the consolidated financial statements.

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ESCALERA RESOURCES CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Amounts in thousands of dollars except share and per share data)

(Unaudited)

Basis of presentation

The accompanying unaudited interim consolidated financial statements and related notes were prepared by Escalera Resources Co.  (“Escalera Resources” or the “Company”), formerly named Double Eagle Petroleum Co., in accordance with accounting principles generally accepted in the United States of America for interim financial reporting and were prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Certain information and note disclosures normally included in the annual audited consolidated financial statements have been condensed or omitted as allowed by such rules and regulations. These consolidated financial statements include all of the adjustments, which, in the opinion of management, are necessary for a fair presentation of the financial position and results of operations. All such adjustments are of a normal recurring nature only. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full fiscal year.

The accounting policies followed by the Company are set forth in Note 1 to the Company’s consolidated financial statements in its Annual Report on Form 10-K for the year ended December 31, 2013, and are supplemented throughout the notes to this Quarterly Report on Form 10-Q.   The unaudited interim consolidated financial statements presented herein should be read in conjunction with the consolidated financial statements and notes thereto included in the Annual Report on Form 10-K for the year ended December 31, 2013 filed with the SEC on March 13, 2014.  

Principles of consolidation

The unaudited interim consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, Petrosearch Energy Corporation and Eastern Washakie Midstream LLC (“EWM”). The Company has an agreement with EWM under which the Company pays a fee to EWM to gather, compress and transport gas produced at the Catalina Unit, in the eastern Washakie Basin of Wyoming. This fee is also eliminated in consolidation.

Basic earnings per share is calculated by dividing net income (loss) attributable to common stock by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share incorporates the treasury stock method to measure the dilutive impact of potential common stock equivalents by including the effect of outstanding vested and unvested stock options and unvested stock awards in the average number of shares of common stock outstanding during the period. Income (loss) attributable to common stock is calculated as net income (loss) less dividends paid on the Company’s Series A Preferred Stock at a quarterly rate of $0.5781 per share. The Company declared and paid cash dividends of $931 for each of the three months ended June 30, 2014 and 2013 and $1,862 for each of the six months ended June 30, 2014 and 2013.  

The following is the calculation of basic and diluted weighted average shares outstanding and earnings per share of common stock for the periods indicated:

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The following options and unvested restricted shares, which could be potentially dilutive in future periods, were not included in the computation of diluted net income per share because the effect would have been anti-dilutive for the periods indicated:

As of June 30, 2014, the Company had $45,950 outstanding on its $150,000 revolving line of credit. On April 24, 2014, the Company’s credit facility agreement was amended to reduce its borrowing base from $55,000 to $48,500 with subsequent monthly borrowing base reductions of $1,000 on the first day of each month through the next borrowing base redetermination date of October 1, 2014 (at which time the borrowing base will be $42,500).   The Company repaid principal of $2,000 during the second quarter of 2014.       

The credit facility has been used to fund the development of the Catalina Unit and other non-operated projects in the Atlantic Rim, development projects on the Pinedale Anticline in the Green River Basin of Wyoming, and the Company’s Niobrara exploration project in the Atlantic Rim.  

The credit facility is collateralized by the Company’s natural gas and oil producing properties. Any balance outstanding on the credit facility is due October 24, 2016

Borrowings under the revolving line of credit bear interest daily at an annual rate equal to (a) the highest of the Federal Funds rate for such day, plus 0.5%, the Prime Rate for such day or the One-Month Eurodollar Rate for such day plus (b) a margin ranging between 0.75% and 2.75% (annualized) depending on the level of funds borrowed. The average interest rate on the facility at June 30, 2014, including the impact of the Company’s interest rate swaps, was 3.5%. For the three months ended June 30, 2014 and 2013, the Company incurred interest expense on the credit facility of $420 and $417, respectively, and for the six months ended June 30, 2014 and 2013, $824 and $825, respectively. Of the total interest incurred, the Company capitalized interest costs of $14 and $11 for the three months ended June 30, 2014 and 2013, respectively, and $31 and $56 for the six months ended June 30, 2014 and 2013, respectively.

Under the credit facility, the Company is subject to both financial and non-financial covenants. The financial covenants, as defined in the credit agreement, include maintaining (i) a current ratio of 1.0 to 1.0; (ii) a ratio of earnings before interest, taxes, depreciation, depletion, amortization, exploration and other non-cash items (“EBITDAX”) to interest plus dividends of greater than 1.5 to 1.0; and (iii) a funded debt to EBITDAX ratio of less than 3.5 to 1.0. As of June 30, 2014, the Company was in compliance with all financial and non-financial covenants under the credit facility. If the covenants are violated and the Company is unable to negotiate a waiver or amendment thereof, the lenders would have the right to declare an event of default, terminate the remaining commitment and accelerate all principal and interest outstanding.

Commodity Contracts

The Company’s primary market exposure is to adverse fluctuations in the price of natural gas. The Company uses derivative instruments, primarily swaps and costless collars, to manage the price risk associated with its gas production, and the resulting impact on cash flow, net income and earnings per share. The Company does not use derivative instruments for speculative purposes.

The extent of the Company’s risk management activities is controlled through policies and procedures that involve senior management and were approved by the Company’s board of directors. Senior management is responsible for proposing hedging recommendations, executing the approved hedging plan, overseeing the risk management process including methodologies used for valuation and risk measurement and presenting policy changes to the Company’s board of directors. The Company’s board of directors is responsible for approving risk management policies and for establishing the Company’s overall risk tolerance levels. The duration of the various derivative instruments depends on senior management’s view of market conditions, available contract prices and the Company’s operating strategy. Under the Company’s credit agreement, the Company can hedge up to 90% of the projected proved developed producing reserves for the next 12-month period, and up to 80% of the projected proved developed producing reserves for the 24-month period thereafter.

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The Company accounts for its derivative instruments as mark-to-market derivative instruments. Under mark-to-market accounting, derivative instruments are recognized as either assets or liabilities at fair value on the Company’s consolidated balance sheets, and changes in fair value are recognized in the price risk management activities line on the consolidated statements of operations. Realized gains and losses resulting from the contract settlement of derivatives are also recorded in the price risk management activities line on the consolidated statements of operations.

On the consolidated statements of cash flows, the cash flows from these instruments are classified as operating activities.

Derivative instruments expose the Company to counterparty credit risk. The Company enters into these contracts with third parties and financial institutions that it considers to be creditworthy. In addition, the Company’s master netting agreements reduce credit risk by permitting the Company to net settle for transactions with the same counterparty.

As with most derivative instruments, the Company’s derivative contracts contain provisions which may allow for another party to require security from the counterparty to ensure performance under the contract. The security may be in the form of, but not limited to, a letter of credit, security interest or a performance bond. As of June 30, 2014, no party to any of the Company’s derivative contracts has required any form of security guarantee.

The Company had the following commodity volumes under derivative contracts as of June 30, 2014:

Interest Rate Swap

As of June 30, 2014, the Company had the following interest rate swap in place with a third party to manage the risk associated with the floating interest rate on its credit facility:

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The table below contains a summary of all of the Company’s derivative positions reported on the consolidated balance sheet as of June 30, 2014 presented gross of any master netting arrangements:

The before-tax effect of derivative instruments not designated as hedging instruments on the consolidated statements of operations for the three and six months ended June 30, 2014 and 2013 was as follows:

Refer to Note 5 for additional information regarding the valuation of the Company’s derivative instruments.

Assets and Liabilities Measured on a Recurring Basis

The Company’s financial instruments, including cash and cash equivalents, accounts receivable and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Company’s credit facility also approximates fair value as it bears interest at a floating rate.

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). A three-level valuation hierarchy has been established to allow readers to understand the transparency of inputs in the valuation of an asset or liability as of the measurement date. The three levels are defined as follows:

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The following table provides a summary as of June 30, 2014 of assets and liabilities measured at fair value on a recurring basis:

The Company did not have any transfers of assets or liabilities between Level 1, Level 2 or Level 3 of the fair value measurement hierarchy during the six months ended June 30, 2014.

Derivative instruments

The Company determines its estimates of the fair values of derivative instruments using a market approach based on several factors, including quoted prices in active markets, market-corroborated inputs, such as NYMEX forward-strip pricing, the credit rating of each counterparty, and the Company’s own credit rating.

In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of sufficient credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.

At June 30, 2014, the Company had various types of derivative instruments, which included swaps and costless collars. The natural gas derivative markets and interest rate swap markets are highly active. Although the Company’s economic hedges are valued using public indices, the instruments themselves are traded with third party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.

Refer to Note 4 for additional information regarding the Company’s derivative instruments.  

Credit facility

The recorded value of the Company’s credit facility approximates its fair value as it bears interest at a floating rate.

Concentration of credit risk

Financial instruments that potentially subject the Company to credit risk consist of accounts receivable and derivative financial instruments. Substantially all of the Company’s receivables are within natural gas and oil industry, including those from a third party gas marketing company. Collectability is dependent upon the financial wherewithal of each counterparty as well as the general economic conditions of the industry. The receivables are not collateralized.

The Company currently uses two counterparties for its derivative financial instruments. The Company continually reviews the credit worthiness of its counterparties, which are generally other energy companies or major financial institutions. In addition, the Company uses master netting agreements which allow the Company, in the event of default, to elect early termination of all

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contracts with the defaulting counterparty. If the Company chooses to elect early termination, all asset and liability positions with the defaulting counterparty would be “net settled” at the time of election. “Net settlement” refers to a process by which all transactions between counterparties are resolved into a single amount owed by one party to the other.

The Company reviews the carrying values of its long-lived assets annually or whenever events or changes in circumstances indicate that such carrying values may not be recoverable. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis. The fair value of impaired assets is determined based on quoted market prices in active markets, if available, or upon the present values of expected future cash flows using discount rates commensurate with the risks involved in the asset group. The impairment analysis performed by the Company may utilize Level 3 inputs. The long-lived assets of the Company consist primarily of proved natural gas and oil properties and undeveloped leaseholds.

We recorded proved property impairment expense in the three months ended June 30, 2014 and 2013 of $90, and $376, respectively, and $765 and $1,415 in the six months ended June 30, 2014 and 2013, respectively.  In 2014, we wrote-off a non-operated property in the Atlantic Rim.   Production from the wells at this property has been limited and the operator has indicated that it intends to plug and abandon wells in this area beginning in 2014.  Impairment expense in the three and six months ended June 30, 2013 was primarily related to the write-off of capital costs incurred on its Niobrara exploration well.

The Company also expensed $315 and $96 during the three months ended June 30, 2014 and 2013, respectively, and $315 and $121 during the six months ended June 30, 2014 and 2013, respectively, related to undeveloped leaseholds. The 2014 write-off primarily related to expiring undeveloped acreage in Nebraska and Wyoming.  

The Company recognized stock-based compensation expense totaling $178 and $383 for the three and six months ended June 30, 2014, respectively, and $234 and $516, for the three and six months ended June 30, 2013, respectively.

Compensation expense related to stock options is calculated using the Black-Scholes valuation model. Expected volatilities are based on the historical volatility of the Company’s common stock over a period consistent with that of the expected terms of the options. The expected terms of the options are estimated based on factors such as vesting periods, contractual expiration dates, historical trends in the Company’s common stock price and historical exercise behavior. The risk-free rates for periods within the contractual life of the options are based on the yields of U.S. Treasury instruments with terms comparable to the estimated option terms.

A summary of stock option activity under the Company’s various stock option plans as of June 30, 2014 and changes during the six months ended June 30, 2014 is presented below:

The Company measures the fair value of stock awards based upon the fair market value of its common stock on the date of grant and recognizes the resulting compensation expense ratably over the associated service period, which is generally the vesting term of the stock awards. The Company recognizes the compensation expenses, net of an estimated forfeiture rate, for only those shares expected to vest. The Company typically estimates forfeiture rates based on historical experience, while also considering the duration of the vesting term of the award.

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Nonvested stock awards as of June 30, 2014 and changes during the six months ended June 30, 2014 were as follows:

In March 2014, the Company’s board of directors granted long-term incentive shares to its chief executive officer (“CEO”) in conjunction with his appointment as an officer. The Compensation Committee of the Board approved two restricted stock awards, under which the Company granted the CEO an aggregate of 528,634 shares of restricted stock, which are included in the table above.  One-third of the shares awarded will vest at the end of three years if the CEO is continuously employed by the Company during such period, and the remaining two-thirds of the shares awarded will vest at the end of three years if the CEO is continuously employed by the Company during such period and certain performance goals related to reserve growth and the Company’s common stock price are achieved, as defined for purposes of the awards.  The Company used a simplified binomial model to estimate the fair value of the performance and market based component of the award.  If the CEO ultimately achieves the service requirements and full performance objectives determined by the agreement, the associated total stock-based compensation expense would be approximately $881, based on the grant date fair value.  The Company’s stock-based compensation expense for the three and six months ended June 30, 2014 includes approximately $58 and $64, respectively, related to these plans.

The Company is required to record income tax expense for financial reporting purposes and applies an estimated effective tax rate (“ETR”) for calculating income tax provisions for interim periods. For the six months ended June 30, 2014 the Company used a ETR of 10.4%. The Company’s ETR for the six months ended June 30, 2014 differs from the U.S. federal statutory tax rate of 35% primarily as a result of the impact of recording a valuation allowance on its net deferred tax assets.  

The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of June 30, 2014, the Company made no provision for interest or penalties related to uncertain tax positions. The Company files income tax returns in the U.S. federal jurisdiction and various states. There are currently no federal or state income tax examinations of the Company underway for these jurisdictions. Furthermore, the Company is no longer subject to U.S. federal income tax examinations by the Internal Revenue Service for tax years before 2007 and for state and local tax authorities for tax years before 2006.

In 2007, the stockholders of the Company approved an amendment to the Company’s Articles of Incorporation to provide for the issuance of 10,000,000 shares of preferred stock, and the Company subsequently completed a public offering of 1,610,000 shares of 9.25% Series A Cumulative Preferred Stock (the “Series A Preferred Stock”) at a price of $25.00 per share.

Holders of the Series A Preferred Stock are entitled to receive, when and as declared by the Company’s Board of Directors, dividends at a rate of 9.25% per annum ($2.3125 per annum per share). The Series A Preferred Stock does not have any stated maturity date and will not be subject to any sinking fund or mandatory redemption provisions except, under certain circumstances, upon a change of ownership or control.   The Company may redeem the Series A Preferred Stock for cash at its option, in whole or from time to time in part, at a redemption price of $25.00 per share, plus accrued and unpaid dividends (whether or not earned or declared) to the redemption date.

The shares of Series A Preferred Stock are classified outside of permanent equity on the consolidated balance sheets due to the change of control redemption provision applicable to such shares. Following a change of ownership or control of the Company by a person or entity in which the common stock of the Company is no longer traded on a national exchange, the Company will be required to redeem the Series A Preferred Stock within 90 days after the date on which the change of ownership or control occurred for cash. In the event of liquidation, the holders of the Series A Preferred Stock will have the right to receive $25.00 per share, plus all accrued and unpaid dividends, before any payments are made to the holders of the Company’s common stock.

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Private placement of common stock

On March 24, 2014, the Company accepted subscription agreements for a private offering of its common stock.  The gross proceeds from the private offering were $4,825, or $4,158 net of placement agent and legal fees.  The offering was effected through a private placement transaction with accredited investors. The Company plans to use the net proceeds of the private offering to fund working capital needs, capital expenditures, acquisitions of interests in natural gas and oil assets, and for general corporate purposes.   On April 7, 2014, the Company issued a total of 2,018,826 shares of common stock at a price of $2.39 per share to investors in such private placement transaction.  

Three related parties to the Company purchased $775 of common stock through this private offering, including $350 by its chief executive officer prior to becoming an officer of the Company.  The Company also reimbursed the CEO for $118 of costs he incurred related to the offering and business development as part of the private placement agreement.

Commitments

In May 2014, the Company entered into a letter agreement to jointly initiate the development, construction and operations of a gas-to-liquids ("GTL") plant to be located in Wyoming (the "GTL Plant"). The Company will jointly own Escalera GTL, LLC (“EGTL”) with Wyoming GTL, LLC ("WYGTL"), through which the initial phase of the GTL Plant will be executed. Under the Letter Agreement, WYGTL assigned all development and engineering plans, contracts, rights, technical relationships, among other rights (collectively, the "Rights") to EGTL, and the Company will advance up to $2,000 to EGTL.  EGTL will use the funds for feasibility studies and completion of the initial engineering and development plans for the GTL Plant.

The Letter Agreement will terminate on November 26, 2014 if a definitive agreement between the Company and WYGTL has not been completed. In the event a definitive agreement is not executed within the required period, WYGTL will reimburse the Company for any portion of the $2,000 funded to EGTL, and EGTL will assign all rights back to WYGTL.  Under the letter agreement, WYGTL will initially own 90% of the GTL plant, with the Company owning the remaining 10%.

For the Company’s participation in EGTL, we anticipate being granted the right to supply up to 75% of the natural gas feedstock for the GTL Plant once it is operational, which is not expected for at least five years.  Based on WYGTL's plans for the GTL Plant, the estimated amount of gas to be supplied by us would be up to approximately 35-38 Bcf annually. Additionally, the Company intends to participate in the net margin generated from the conversion of the gas it supplies to the GTL Plant in return for entering into a long-term gas supply contract.  

As of June 30, 2014, the Company had advanced $0 under the agreement.  The Company advanced $788 in July 2014.  

Legal proceedings

From time to time, the Company is involved in various legal proceedings, which are subject to the uncertainties inherent in any litigation. The Company is defending itself vigorously in all such matters, and while the ultimate outcome and impact of any proceeding cannot be predicted with certainty, management believes that the resolution of any proceeding will not have a material adverse effect on the Company’s financial condition or results of operations.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The terms “Escalera Resources,” “Company,” “we,” “our,” and “us” refer to Escalera Resources Co. and its subsidiaries, as a consolidated entity, unless the context suggests otherwise. Unless the context suggests otherwise, the amounts set forth herein are in thousands, except units of production, dollar per unit of production, ratios, and share or per share amounts.

FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q and other publicly available documents, including those incorporated herein and therein by reference, contain, and our management may from time to time make “forward-looking statements” within the meaning of the U.S. Private Securities Litigation Reform Act of 1995 (“PSLRA”). We make these forward-looking statements in reliance on the safe harbor protections provided under Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934, as amended, and the PSLRA.  All statements, other than statements of historical facts, included in this Quarterly Report on Form 10-Q that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements.  When used in this report, the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “forecast,” “intend,” “may,” “plan,” “project,” “should,” and words or phrases of similar import, as they relate to the Company or its subsidiaries or management, are intended to identify forward-looking statements.  These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including without limitation the Risk Factors set forth in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013 and the following factors:

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We may also make material acquisitions or divestitures or enter into financing or other transactions. None of these events can be predicted with certainty, and the possibility of such events occurring is not taken into consideration in the forward-looking statements.

New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to publicly update or revise any such forward-looking statements, whether as a result of new information, future events, or otherwise.

Company Overview

We are an independent energy company currently engaged in the exploration, development, production and sale of natural gas and crude oil, primarily in the Rocky Mountain Basins of the western United States. We were incorporated in Wyoming in 1972 and reincorporated in Maryland in 2001.  Our board of directors appointed a new chief executive officer, Charles F. Chambers, effective April 1, 2014, and in conjunction with this change, we changed our name to Escalera Resources Co. from Double Eagle Petroleum Co. Our common stock and Series A Cumulative Preferred are both publicly traded on the NASDAQ Global Select Market under the symbols “ESCR” and “ESCRP”, respectively (previously “DBLE” and “DBLEP”, respectively).  Our corporate offices are located at 1675 Broadway, Suite 2200, Denver, Colorado 80202, telephone number (303) 794-8445.  Our executive offices are located at 675 Bering, Suite 850, Houston, TX 77057.  Our website is www.escaleraresources.com.

Our objective is to increase long-term shareholder value by profitably growing our reserves, production, revenues, and cash flow. To meet this objective, we primarily focus on: (i) selectively pursuing strategic acquisitions of abundant, low cost natural gas assets that are currently undervalued or underutilized; (ii) identifying alternative ways to enhance the value of our natural gas reserves; (iii) investment in and enhancement of existing production wells and field facilities on operated and non-operated properties in the Atlantic Rim; (iv) continued participation in the development of tight sands gas wells at the Mesa Units on the Pinedale Anticline; and (v) pursuit of high quality exploration and strategic development projects with potential for providing long-term drilling inventories that we believe will generate above average returns. 

Our current production primarily consists of natural gas from our two core properties.  We have coalbed methane (“CBM”) reserves and production in the Atlantic Rim area of the eastern Washakie Basin and tight gas reserves and production on the Pinedale Anticline in the Green River Basin of Wyoming.

Our Atlantic Rim and Pinedale Anticline assets operate under federal exploratory unit agreements among the working interest partners. Unitization is a type of sharing arrangement by which owners of operating and non-operating working interests pool their property interests in a producing area to form a single operating unit. Units are designed to improve efficiency and economics of developing and producing an area. The share that each interest owner receives is based upon the respective acreage contributed by each owner in the participating area (“PA”) that surround the producing wells as a percentage of the entire acreage of the PA.  

Recent Developments

In May 2014, we entered into a letter agreement to jointly initiate the development, construction and operations of a gas-to-liquids ("GTL") plant to be located in Wyoming (the "GTL Plant"). We will jointly own Escalera GTL, LLC (“EGTL”) with Wyoming GTL, LLC ("WYGTL"), through which the initial phase of the GTL Plant will be executed. Under the letter agreement, WYGTL assigned all development and engineering plans, contracts, rights, technical relationships, among other rights (collectively, the "Rights") to EGTL, and we will advance up to $2,000 to EGTL.  EGTL will use the funds for feasibility studies and completion of the initial engineering and development plans for the GTL Plant.

The letter agreement will terminate on November 26, 2014 if a definitive agreement between us and WYGTL has not been completed. In the event a definitive agreement is not executed within the required period, WYGTL will reimburse us for any portion of the $2,000 funded to EGTL, and EGTL will assign all rights back to WYGTL.  Under the letter agreement, WYGTL will initially own 90% of the GTL plan and we will own the remaining 10%.

For our participation in EGTL, we anticipate being granted the right to supply up to 75% of the natural gas feedstock for the GTL Plant once it is operational, which is not expected for at least for five years.  Based on WYGTL's plans for the GTL Plant, the estimated amount of gas to be supplied by us would be up to approximately 35-38 Bcf annually. Additionally, we intend to participate

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in the net margin generated from the conversion of the gas we supply to the GTL Plant in return for entering into a long-term gas supply contract.  

Management believes this arrangement provides significant opportunity for the Company to enhance the pricing ultimately realized from its natural gas production.  As of June 30, 2014, $0 of the $2,000 commitment had been expended. In July 2014, we advanced $788 to EGTL.  

RESULTS OF OPERATIONS

Three Months Ended June 30, 2014 Compared to the Three Months Ended June 30, 2013

The following analysis provides comparison of the three months ended June 30, 2014 and the three months ended June 30, 2013.

Natural gas and oil sales

Natural gas and oil sales increased 10% to $9,320, which was largely attributed to a 15% increase in the Colorado Interstate Gas (“CIG”) market price, which is the index on which most of our natural gas volumes are sold. As shown in the table below, our average realized natural gas price decreased 3% to $3.87 per Mcf.    Our realized natural gas price for the three months ended June 30, 2014 was lower than the prevailing market prices due to the realized losses from the commodity derivatives that settled during the period.   

We calculate our average realized natural gas price by summing (1) production revenues received from third parties for the sale of our gas, which is included within natural gas and oil sales on the consolidated statements of operations, and (2) realized gain (loss) on our commodity derivatives, which is included within price risk management activities, net on the consolidated statements of operations, totaling $(533) and $1,037 for the three months ended June 30, 2014 and 2013, respectively.

Our total net production decreased 5% to 2.2 Bcfe for the three months ended June 30, 2014 primarily due to lower production from our non-operated properties at the Spyglass Hill Unit and on the Pinedale Anticline.

Our total average daily net production at the Atlantic Rim increased 4% to 18,393 Mcfe.  Our Atlantic Rim production comes from two operating units: the Catalina Unit and the Spyglass Hill Unit (which includes the Sun Dog, Doty Mountain, and Grace Point PAs). We operate the Catalina Unit and have non-operated working interests in the Spyglass Hill Unit.

Average daily net production at our Catalina Unit increased 13% to 13,459 Mcfe.  We experienced a series of equipment challenges in late 2012 and early 2013, which resulted in decreased production volumes in the three months ended June 30, 2013.  Production recovered somewhat throughout the second half of 2013 and into 2014.   The recovered production was partially offset by normal field declines.  

Average daily production, net to our interest, at the Spyglass Hill Unit decreased 15% to 4,934 Mcfe.   Although the operator drilled 27 new wells in the Spyglass Hill Unit in 2013, we have not realized an increase in production volumes due to infrastructure constraints in the unit.  The operator has informed us that in 2014, they are working to increase injection capacity and enhance the gathering system.  We plan to participate in the drilling of 48 additional wells in the Spyglass Hill Unit in 2014.  The operator expects to complete 23 of these wells by the end of the third quarter of 2014.  The remaining 25 wells will be drilled in the third and fourth quarter of 2014.  This drilling program will satisfy the minimum well requirement through August 2015 as set in the federal exploratory agreement governing the Spyglass Hill Unit.  

On the Pinedale Anticline, our average daily net production decreased 31% to 3,856 Mcfe as a result of normal production decline, which is no longer offset by initial production from new wells.  The initial production rates from wells in this field start strong and then decline quickly.  We expect that year over year, we will have significant decreases due to only one new well coming on in 2014.  With the completion of this well in June 2014, the Mesa “B” PA is fully drilled and we expect the operator to shift its efforts to drilling and development of Mesa “A” PA and once fully drilled, the operator is expected to move onto the Mesa “C” PA in 2016.  The drilling in the Mesa “A” PA is not expected to have a material impact on our production as we only have a small overriding royalty interest in the Mesa “A” wells.  

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Transportation and gathering revenue

We receive fees for gathering and transporting third-party gas through our intrastate gas pipeline, which connects the Catalina Unit with the interstate pipeline system owned by Southern Star Central Gas Pipeline, Inc.  Transportation and gathering revenue increased 10% to $940 for the three months ended June 30, 2014, due to the increase in Catalina production volumes as compared to the prior year period.   

Price risk management activities

We recorded a net loss on our derivative contracts of $751.  This consisted of an unrealized non-cash loss of $218, which represents the change in the fair value of our commodity derivatives at June 30, 2014 based on the expected future prices of the related commodities, and a net realized loss of $533 related to the cash settlement of our economic hedges.

Natural gas and oil production costs, production taxes, depreciation, depletion and amortization

Well production costs decreased 3% to $3,174 and production costs on a per Mcfe basis increased 2%, or $0.03, to $1.48.  Production costs on a per Mcfe basis were higher due to the decrease in production volumes, as a portion of our production costs are fixed, or partially fixed.

Production taxes increased 10% to $1,130 for the three months ended June 30, 2014 and production taxes, on a per Mcfe basis, also increased $0.08 to $0.53 per Mcfe.  We are required to pay taxes on the revenue generated upon the physical sale of our gas to counterparties, which, on average, represent about 12% of natural gas sales.  Production taxes in 2013 were lower both in total and on a per Mcfe basis, as a portion of our revenue was generated from the settlement of commodity derivatives, which is not subject to production taxes.  In 2014, we realized a loss on our commodity derivatives, yet paid taxes on the prevailing market price.    

Total depreciation, depletion and amortization expenses (“DD&A”) decreased 6% to $4,939, and depletion and amortization related to producing assets decreased 8% to $4,737.  Expressed on a per Mcfe basis, depletion and amortization related to producing assets decreased 3%, or $0.06, to $2.20.   The decrease in DD&A in total and on a per Mcfe basis was the result of a lower depletion rate at the Pinedale Anticline.  This was offset, in part, by an increase in the depletion rate in 2014 for the Catalina Unit due to a decrease in our reserves, which were estimated to be lower in our year-end reserve report as a result of revisions to the economic lives of the major fields.

Impairment and abandonment of equipment and properties

We recorded impairment and abandonment expense in the three months ended June 30, 2014 of $405, primarily related to the write-off of expiring undeveloped acreage in Wyoming and Nebraska.  

In 2013, we recorded impairment expense of $472, of which $376 related to the exploration well completed in the first quarter of 2013.  

General and administrative expenses

General and administrative expenses increased 25% to $1,688, primarily due to a $216 increase in salary and salary-related costs due to the establishment of our Houston office and also a severance payout resulting from terminating our international initiatives.  We also had a $148 increase in legal fees.  These increases were offset, in part, by a $56 decrease in stock-based compensation expense.  

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Income taxes

We recorded an income tax benefit of $289 for the three months ended June 30, 2014.  Our effective tax rate (“ETR”) was 10.4%, which differs from the U.S. federal statutory tax rate of 35%, primarily as a result of the impact of recording a valuation allowance on our net deferred tax assets.  

Six Months Ended June 30, 2014 Compared to the Six Months Ended June 30, 2013

The following analysis provides comparison of the six months ended June 30, 2014 and the six months ended June 30, 2013.

Natural gas and oil sales

Natural gas and oil sales increased 24% to $19,886, which was attributed to a 37% increase in the CIG market price, partially offset by a 6% decrease in production volumes.  As shown in the table below, our average realized natural gas price increased 4% to $4.02 per Mcf, due to the increase in the CIG market price.  Our realized natural gas price for the six months ended June 30, 2014 was lower than the prevailing market prices due to realized losses from the commodity derivatives that settled during the period.   

The calculation of the average realized price in the table below includes realized gain (loss) on our commodity derivatives, which is included within price risk management activities, net on the consolidated statements of operations, totaling $(1,475) and $2,906 for the six months ended June 30, 2014 and 2013, respectively.

Our total net production decreased 6% to 4.4 Bcfe due primarily to lower production from our non-operated properties in the Atlantic Rim and Pinedale Anticline.  

Our total average daily net production at the Atlantic Rim decreased 2% to 18,686 Mcfe due to decreased production in the Spyglass Hill Unit.   Average daily net production at the Catalina Unit increased 1% to 13,685 Mcfe. We experienced a series of equipment challenges in late 2012 and early 2013, which resulted in decreased production volumes for the six months ended June 30, 2013.  Production recovered somewhat throughout the second half of 2013 and into 2014.   The recovered production was partially offset by normal field declines.  

Average daily production, net to our interest, at the Spyglass Hill Unit decreased 10% to 5,001 Mcfe. Although the operator drilled 27 new wells in the Spyglass Hill Unit in 2013, we have not realized an increase in production volumes due to infrastructure constraints in the unit.  

On the Pinedale Anticline, our average daily net production decreased 25% to 3,997 Mcfe as a result of normal production decline, which is no longer offset by strong initial production rates of new wells.  The initial production rates from wells in this field are very strong and then decline quickly.  We expect that year over year, we will have significant decreases due to only one new well coming on in 2014.    With the completion of this well in June 2014, the Mesa “B” PA is fully drilled and we expect the operator to shift its efforts to drilling and development of Mesa “A” PA and once fully drilled, the operator is expected to move onto the Mesa “C” PA in 2016.  The drilling in the Mesa “A” PA is not expected to have a material impact on our production as we only have a small overriding royalty interest in the Mesa “A” wells.  

Transportation and gathering revenue

Transportation and gathering revenue increased 4% to $1,904 for the six months ended June 30, 2014, due to the increase in Catalina production volumes.  

Price risk management activities

We recorded a net loss on our derivative contracts of $3,267.  This consisted of an unrealized non-cash loss of $1,792, which represents the change in the fair value of our commodity derivatives at June 30, 2014 based on the expected future prices of the related commodities, and a net realized loss of $1,475 related to the cash settlement of our economic hedges.

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Natural gas and oil production costs, production taxes, depreciation, depletion and amortization

Well production costs increased 4% to $6,472 and production costs on a per Mcfe basis increased 11%, or $0.15, to $1.48.  The overall increase in production costs was driven by a $501 increase in production costs at the Catalina Unit.  In the first quarter of 2013, we deferred certain maintenance activities at the Catalina Unit as we focused on an exploration project.  The production costs incurred at the Catalina Unit for the six months ended June 30, 2014 of $1.07 per Mcfe are comparable to average historical rates.  Production costs on a per Mcfe basis were also higher due to the decrease in production volumes, as a portion of our production costs are fixed, or partially fixed.

Production taxes increased 20% to $2,364 for the six months ended June 30, 2014 and production taxes, on a per Mcfe basis, increased $0.12 to $0.54 per Mcfe.  We are required to pay taxes on the revenue generated upon the physical sale of our gas to counterparties.  Production taxes were higher both in total and on a per Mcfe basis primarily due to the 37% increase in the average market prices for natural gas.  

Total DD&A decreased 3% to $10,189, and depletion and amortization related to producing assets decreased 2% to $10,006.  Expressed on a per Mcfe basis, depletion and amortization related to producing assets increased 4%, or $0.09, to $2.29.  Our depletion rate was higher in 2014 on a per Mcfe basis for the Catalina Unit due to a decrease in our reserves, which were estimated to be lower in our year-end reserve report as a result revisions to the economic lives of the major fields.

Impairment and abandonment of equipment and properties

We recorded impairment and abandonment expense in the six months ended June 30, 2014 of $1,080, of which $675 was due to the write-off of a non-operated property in the Atlantic Rim.  Production from these wells has been limited, and the operator has indicated that it intends to plug and abandon wells in this area beginning in 2014.   Additionally, we wrote off $256 due to the write-off of expiring undeveloped acreage in Wyoming and Nebraska.  

In 2013, we recorded impairment expense of $1,536, of which $1,415 related to the exploration well completed in the first quarter of 2013.  

General and administrative expenses

General and administrative expenses increased 27% to $3,770, primarily due to severance related expenses of $691 we recorded as a result of the termination of our former chief executive officer.  The severance expense will be paid over a two year period beginning October 1, 2014.  We also reimbursed a consulting company owned by Mr. Chambers for $107 of expenses incurred for business development activities performed on behalf of the Company.  In addition, we had an increase in legal fees of $269, which was offset by a decrease in salary and salary-related expenses of $287 due to a reduction in headcount prior to the establishment of our Houston office.  Our stock-based compensation expense was lower in the first half of 2014 as there was not a long-term incentive plan in place for executives during most of the first quarter.  

Income taxes

We recorded an income tax benefit of $869 for the six months ended June 30, 2014.  Our ETR was 10.4%, which differs from the U.S. federal statutory tax rate of 35%, primarily as a result of the impact of recording a valuation allowance on our net deferred tax assets.  

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OVERVIEW OF FINANCIAL CONDITION AND LIQUIDITY

Liquidity and Capital Resources

Our sources of liquidity and capital resources historically have been net cash provided by operating activities, funds available under our credit facilities and proceeds from offerings of equity securities. The primary uses of our liquidity and capital resources have been in the development and exploration of oil and gas properties. In the past, these sources of liquidity and capital have been sufficient to meet our needs and finance the growth of our business.

At June 30, 2014, we had a $150,000 credit facility in place with a $46,500 borrowing base. We had $45,950 outstanding on our credit facility as of June 30, 2014.  On April 24, 2014, our credit facility agreement was amended to reduce our borrowing base from $55,000 to $48,500 with subsequent monthly borrowing base reductions of $1,000 on the first day of each month through the next borrowing base redetermination date of October 1, 2014 (at which time the borrowing base will be $42,500).  As of August 1, 2014, we had made a total of four monthly $1,000 repayments.  

On March 24, 2014, we accepted subscription agreements for a private offering of our common stock.  The gross proceeds were $4,825, or $4,158 net of placement agent and legal fees.  The offering was effected through a private placement transaction with accredited investors. We are using the net proceeds of the private offering to fund working capital needs, capital expenditures, including the GTL initiative, and for general corporate purposes.  

We expect 2014 cash flow from operations to be sufficient to make the required payments on our credit facility, meet our financial covenants and maintain our current facilities.  However, the reduction of the borrowing base on our credit facility does limit our ability to further develop our assets, as our capital expenditures would need to be fully funded by cash flow from operations, or we would need to secure other sources of capital.  We have received a non-binding commitment letter from an international financial institution for an initial $50,000 borrowing base credit facility to replace our existing credit facility.  We are currently working to finalize the new credit facility agreement based on this commitment letter.  As we do not yet have a binding agreement in place, there can be no assurance that we will be able to close on a new credit facility under the terms set forth in the prospective lender’s commitment to us, on other terms that are acceptable to us, or at all. 

Depending on the outcome of our refinancing effort and timing and amounts of future projects, we may need to seek additional sources of capital. We can provide no assurance that we will be able to do so on favorable terms or at all.  We may issue additional equity or debt in private placements or obtain additional debt financing, which may be secured by our natural gas and oil properties, or unsecured.

Information about our financial position is presented in the following table:

Our working capital balance decreased to $1,321 at June 30, 2014 as compared to $1,704 at December 31, 2013, which was primarily the result of $4,000 of our outstanding credit facility balance being classified as current due to the amended terms our credit agreement, discussed above.  Our working capital balance frequently fluctuates primarily due to the timing and amounts of capital expenditures and changes in fair value of the current portion of outstanding derivative contracts.  As a result of the increase in the future natural gas prices at June 30, 2014 as compared to December 31, 2013, all of our current outstanding hedges were also in a liability position.  These decreases in working capital were offset by the receipt of $4,158 of the private placement net proceeds as of June 30, 2014.  

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Cash flow activities

The table below summarizes our cash flows for the six months ended June 30, 2014 and 2013, respectively:

During the six months ended June 30, 2014, net cash provided by operating activities was $6,012, as compared to $6,755 in the same prior-year period. The cash we generated in the six months ended June 30, 2014 resulted from a net loss of $(7,758), which was net of non-cash charges of $10,311 related to DD&A and accretion expense, a $1,795 unrealized net loss related to the change in fair value of our derivative contracts and $1,080 of impairment expense.  During the six months ended June 30, 2014, we spent $294 to complete the reclamation of our Texas waterflood property.  

Our operating cash flow is sensitive to many variables, the most significant of which is the price of natural gas. Our hedging program helps to mitigate cash flow fluctuations due to price volatility.  Taking into account our derivative instruments, for the six months ended June 30, 2014, our income before income taxes and cash flow would have increased by approximately $302 for each $0.50 change per Mcf in natural gas prices.  We realized a loss on our derivative of derivatives of $(1,475) versus a cash gain of $2,906 during the six months ended June 30, 2014 and 2013, respectively.  Despite the recognition of the loss on derivatives during the 2014 period, our average realized natural gas price was 11% higher in the six months ended June 30, 2014 as compared to the same prior-year period due to the overall increase in the CIG market price.  

During the six months ended June 30, 2014, net cash used in investing activities was $2,334, as compared to $5,319 in the same prior-year period. Our 2014 capital spending was primarily related to payment of costs associated with the Spyglass Hill and Mesa “B” 2013 drilling programs.  In the first six months of 2013, our spending primarily related to completion of our Niobrara exploration well and non-operated drilling in the Pinedale Anticline.    

Cash provided by financing activities was $752 for the six months ended June 30, 2014, as compared to cash used in financing activities of $1,883 for the six months ended June 30, 2013.  In 2014, we completed an offering of our common stock through a private placement for gross proceeds of $4,825, or $4,158 net of the placement agent and legal fees related to the offering.  This cash inflow was partially offset by a $1,500 net repayment on our credit facility as required by the April 2014 amendment to our credit facility, discussed previously.  We also paid cash dividends on our Series A Preferred Stock, totaling $1,862 in each period.  

Credit Facility

Our credit facility is collateralized by our natural gas and oil producing properties and other assets. At June 30, 2014, we had $45,950 outstanding on the facility. We have depended on our credit facility over the past five years to supplement our operating cash flow in the development of the Company-operated Catalina Unit and other non-operated projects in the Atlantic Rim, including two purchases of additional working interests in this field, projects on the Pinedale Anticline, and the drilling of our Niobrara exploration well.  

Borrowings under the revolving line of credit bear interest daily at an annual rate equal to (a) the highest of the Federal Funds rate on such day, plus 0.5%, the Prime Rate on such day or the One-Month Eurodollar Rate on such day plus (b) a margin ranging between 0.75% and 2.75% (annualized) depending on the level of funds borrowed. The average interest rate on the facility at June 30, 2014, including the impact of our interest rate swaps, was 3.5%.  On April 24, 2014, our credit facility agreement was amended to reduce our borrowing base from $55,000 to $48,500 with subsequent monthly borrowing base reductions of $1,000 on the first day of each month through the next borrowing base redetermination date of October 1, 2014 (at which time the borrowing base will be $42,500).  All of the remaining balance outstanding on the on the credit facility is due on October 24, 2016.  

We are subject to a variety of financial and non-financial covenants under this facility. As of June 30, 2014, we were in compliance with all covenants under the facility. If any of the covenants are violated, and we are unable to negotiate a waiver or amendment thereof, the lender would have the right to declare an event of default, terminate the remaining commitment, accelerate all principal and interest outstanding, and foreclose on our assets.

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Capital Requirements

We have budgeted approximately $6,000 for our capital projects in 2014, primarily for participation in 48 new wells in the Spyglass Hill Unit.  We expect approximately 23 of the new well in the Spyglass Hill unit to be drilled and completed by the end of the third quarter of 2014.  The remaining 25 wells will be drilled in the third and fourth quarters of 2014.  We also plan to replace certain compressor equipment at the Catalina Unit, which we expect will provide for lower future operating costs.  Spending in the first half of 2014 related to these projects was insignificant.  

As noted under Recent Developments, we also expect to advance up to $2,000 to EGTL for use in feasibility studies and completion of the initial engineering and development plans for the GTL Plant.

DERIVATIVE INSTRUMENTS

Contracted gas volumes

Changes in the market price of oil and natural gas can significantly affect our profitability and cash flow. We have entered into various derivative instruments to mitigate the risk associated with downward fluctuations in the natural gas price. Typically, these derivative instruments have consisted of swaps and costless collars. The duration and size of our various derivative instruments varies, and depends on our view of market conditions, available contract prices and our operating strategy.

Our outstanding derivative instruments as of June 30, 2014 are summarized below (volume and daily production are expressed in Mcf). All contracts are indexed to the NYMEX. The prevailing market prices in the Rockies, including CIG which is the index on which most of our gas volumes are sold, tend to be sold at a discount relative to other U.S. natural gas markets, including NYMEX. This discount is typically referred to as a “basis differential” and reflects, to some extent, the costs associated with transporting the natural gas in the Rockies to markets in the other regions. It also reflects the general excess supply and lack of pipeline capacity in the region.

Interest rate swap

We have a $30,000 fixed rate swap contract with a third party in place as a hedge against the floating interest rate on our credit facility. Under the hedge contract terms, we locked in the Eurodollar LIBOR portion of the interest calculation at approximately 1.050% for this tranche of our outstanding debt, which based on our level of outstanding debt at June 30, 2014, translates to an interest rate on this tranche of approximately 3.8%.  The contract is effective through September 30, 2016.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2013, and to the Notes to the Consolidated Financial Statements included in Part I, Item 1 of this report.

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In accordance with the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Financial and Accounting Officer), of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on this evaluation, our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Financial and Accounting Officer) have concluded that our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and such information was accumulated and communicated to our management, as appropriate, to allow timely decisions regarding required disclosure.

There has been no change in our internal control over financial reporting that occurred during the six months ended June 30, 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

From time to time, we are involved in various legal proceedings. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters, and while the ultimate outcome and impact of any proceeding cannot be predicted with certainty, our management believes that the resolution of any proceeding will not have a material adverse effect on our financial condition or results of operations.

Effective March 24, 2014, we accepted subscription agreements for a private offering of our common stock.  The gross proceeds from the private offering were $4,825,000, or $4,158,000 net of placement agent and legal fees. The offering was effected through a private placement transaction with 28 accredited investors. We plan to use the net proceeds of the private offering to fund working capital needs, capital expenditures, acquisitions of interests in oil and natural gas assets, and for general corporate purposes.   On April 7, 2014, we issued a total of 2,018,826 shares of common stock at a price of $2.39 per share to investors in such private placement transaction.  No additional shares will be sold as part of this offering.

We made no repurchases of our common stock in the second quarter of 2014.

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The following exhibits are filed as part of this report:

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SIGNATURES

Pursuant to the requirements 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.

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EXHIBIT INDEX

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