UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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FORM 10-Q

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(Mark One)

For the quarterly period ended June 30, 2015 

or

For the transition period from _________to _______

Commission File Number 1-33571

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ESCALERA RESOURCES CO.

(Exact name of registrant as specified in its charter)

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303-794-8445

(Registrant’s telephone number, including area code)

None 

(Former name, former address, and former fiscal year, if changed since last report)

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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 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 checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ◻ No ☒ 

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

 

 

 

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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)

 

 

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

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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)

1.Summary of Significant Accounting Policies

Basis of presentation

The accompanying unaudited interim consolidated financial statements and related notes were prepared by Escalera Resources Co. (“Escalera Resources” or the “Company”), 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, 2014, and are supplemented in 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, 2014 filed with the SEC on April 15, 2015.  

Going Concern

The market price for natural gas and oil decreased significantly during the second half of 2014 with continued weakness into 2015. The decrease in the market prices for the Company’s production directly reduces its operating cash flow and indirectly impacts its other sources of potential liquidity.  Lower market prices for the Company’s production led to a decrease in the Company’s borrowing base during its spring 2015 borrowing base redetermination, resulting in a borrowing base deficiency of $3,515, as discussed in Note 3.  Although the Company’s lender has agreed to forbear from exercising certain rights and remedies relating to the Company’s obligation to repay this deficiency through September 1, 2015, there is uncertainty as to the Company’s ultimate ability to repay the deficiency from its cash flow or through obtaining alternative debt financing. Additionally, the Company has reported net operating losses for the past three years and for the three and six months ended June 30, 2015, which may impact the Company’s access to additional capital. Collectively, the negative impacts to the Company’s liquidity resulting from unfavorable industry conditions and increased uncertainty regarding its ability to repay its borrowing base deficiency or comply with the covenants contained in its credit agreement raises substantial doubt about the Company’s ability to continue as a going concern. The consolidated financial statements included in this Quarterly Report on Form 10-Q have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The consolidated financial statements do not reflect any adjustments that might result if the Company is unable to continue as a going concern. The Company’s long-term debt is reflected as a current liability on the consolidated balance sheets (as discussed in Note 3). The classification as a current obligation is based on the uncertainty regarding the Company’s ability to comply with certain covenants contained in its credit agreements during the next 12 months.  

The Company began implementing plans designated to improve its liquidity, including the elimination of capital projects for 2015 unless economic conditions improve; reducing operating and general and administrative costs; and continuing its efforts to sell certain non-core assets. In July 2015, the Company closed a transaction to sell its interests in oil and gas properties on the Pinedale Anticline for approximately $12.0 million (as discussed in Note 12).   

Even if the Company is successful at reducing its costs and increasing its liquidity through asset sales, the Company may not have sufficient liquidity to satisfy its debt service obligations, meet other financial obligations, and comply with covenants contained in the Company’s credit agreement.  The Company has engaged advisors to assist with the evaluation of its options to obtain alternative debit financing, improve its liquidity position and evaluate strategic alternatives. The strategic alternatives may include, but are not limited to, seeking a merger partner,  restructuring, amendment or refinancing of our outstanding debt through a private restructuring or reorganization under Chapter

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11 of the Bankruptcy Code, or a combination of such alternatives. However, there can be no assurances that the Company will be able to successfully restructure its indebtedness, improve its liquidity position, complete any strategic transactions or comply with debt covenant requirements for the remainder of 2015 or beyond.

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 eliminated in consolidation.

Recent accounting pronouncements

In July 2015, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) No. 2015-11, "Simplifying the Measurement of Inventory”, which is effective in the first quarter of 2017. ASU 2015-11 requires that inventory that is recorded using the first-in, first-out method to be measured at the lower of cost or net realizable value, which is defined as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The Company is currently evaluating the impact of ASU 2015-11 on its inventory valuation and results of operations.

In April 2015, the FASB issued ASU No. 2015-03, “Interest — Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs” (“ASU No. 2015-3”), which will be effective for the first quarter of 2016, and will be applied retrospectively. The amendment requires the costs for issuing debt to appear on the balance sheet as a direct deduction from the carrying amount of the debt liability.  The Company does not expect the adoption of this ASU to have a material impact on its consolidated financial statements.

2.Earnings per share

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 the cumulative dividends, including dividends in arrears, related to the Company’s Series A Preferred Stock at a quarterly rate of $0.5781 per share. The Series A Preferred Stock dividends for the three and six months ended June 30, 2015, which were undeclared and unpaid for both periods, totaled $931 and $1,862, respectively. The Company declared and paid cash dividends of $931 and $1,862 for the three months and six months ended June 30, 2014, respectively.     

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

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:

 

 

3.Credit Facility

As of June 30, 2015, the Company had a $250,000 credit agreement (the “Credit Agreement”) in place ($50,000 borrowing base) with an outstanding balance of $47,515. The Company has historically utilized its credit facilities to fund the development of the Catalina Unit and other non-operated projects in the Atlantic Rim, and development projects on the Pinedale Anticline in the Green River Basin of Wyoming. 

The Credit Agreement is collateralized by the Company’s natural gas and oil producing properties. Any balance outstanding on the credit facility is due August 29, 2017.

Under the Credit Agreement, 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, less unencumbered cash, to EBITDAX ratio of less than 4.0 to 1.0. 

As of June 30, 2015, the Company was in violation of each of the aforementioned financial covenants. In addition, as of this date, the Company had triggered two additional events of default, as defined by the Credit Agreement: (1) the Company’s independent registered public accounting firm included in its audit opinion for the year ended December 31, 2014, a going concern explanatory paragraph and (2) the Company had not fully paid its ad valorem taxes assessed in 2014 (which were due in May 2015) for certain of its properties. As a result of these violations, the lender has the right to declare an event of default, terminate the remaining commitment and accelerate all principal

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and interest outstanding. Accordingly, the outstanding balance under the credit facility is shown as a current liability on the consolidated balance sheets as of June 30, 2015 and December 31, 2014.

On July 31, 2015, the Company entered into a Forbearance Agreement and First Amendment to the Credit Agreement (the “Amendment”), which provides that the Company’s lenders will forbear from exercising certain rights under the Credit Agreement to (1) accelerate payments (other than the automatic acceleration that would occur under certain clauses of the credit agreement); (2) enforce security interests (other than after the occurrence of an automatic acceleration under certain clauses of the Credit Agreement); and (3) file or otherwise initiate an involuntary bankruptcy petition against the Company. The forbearance will be in effect until the earlier of September 1, 2015 or the date of the occurrence of any event of termination under the Amendment.  The additional financial covenant violations which occurred at June 30, 2015 are events of termination under the Amendment, and therefore the Company’s lender could elect to exercise any of the aforementioned rights available under the Credit Agreement. 

The Amendment also decreased the borrowing base on the credit facility from $50,000 to $44,000 in connection with the Company’s regularly scheduled spring 2015 semi-annual redetermination by its lender, which resulted in a borrowing base deficiency of $3,515. Under the Amendment, the lenders will also forbear from exercising certain rights under the credit facility relating to the borrowing base deficiency. Following the Pinedale asset sale (discussed further in Note 12), the Company’s borrowing base decreased to $33,500, as reduced by the cash proceeds from the sale. The borrowing base deficiency did not change materially as a result of the repayment of proceeds. 

As of June 30, 2015, borrowings under the credit facility incurred interest daily based on the Company’s interest rate election of either the Base Rate or LIBOR Rate. Under the Base Rate option, interest is calculated at an annual rate equal to the highest of (a) the base rate for Dollar loans for such day, Federal Funds rate for such day, plus 0.5%, or the LIBOR for such day plus (b) a margin ranging between 0.75% and 1.75% (annualized) depending on the level of funds borrowed. Under the LIBOR Rate option, interest is calculated at an annual rate equal to LIBOR, plus a margin ranging between 1.75% and 2.75% (annualized) depending on the level of funds borrowed. In addition to the standard interest charge, the Company is subject to an additional penalty rate of 2.0% (annualized) as a result of the aforementioned events of default. The average interest rate on the facility at June 30, 2015 was 5.1%. Under the Amendment, the Company may no longer elect the LIBOR Rate option. The interest will be converted to the Base Rate after the expiration of the current interest rate elections. 

For the three months ended June 30, 2015 and 2014, the Company incurred interest expense on its credit facilities of $490 and $420, respectively, and for the six months ended June 30, 2015 and 2014, $859 and $824, respectively. Of the total interest incurred, the Company capitalized interest costs of $27 and $14 for the three months ended June 30, 2015 and 2014, respectively, and $46 and $31 for the six months ended June 30, 2015 and 2014, respectively.

 

4.Derivative Instruments

Commodity Contracts

The Company’s primary market exposure is adverse fluctuations in the price of natural gas and, to a lesser extent, oil. The Company uses derivative instruments, primarily swaps and costless collars, to manage the price risk associated with its 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 (the “Board”). 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 Board. The Board 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. In accordance with the Company’s current credit agreement, the Company has hedged at least 85% of its projected production through 2016 based on its third-party prepared reserve report at December 31, 2014.

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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, 2015, 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, 2015:

 

 

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Subsequent to June 30, 2015, the Company unwound a portion of its contracted oil volumes (3,000 Bbls) for cash proceeds of $129, which was used to pay down its outstanding borrowings on its credit facility.  

The table below contains a summary of all of the Company’s derivative positions reported on the consolidated balance sheet as of June 30, 2015 presented gross of any master netting arrangements:

 

 

The before-tax effect of derivative instruments not designated as hedging for the three and six months ended June 30, 2015 and 2014 were as follows:

 

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

5.Fair Value of Financial 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 tables provides a summary 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 three and six months ended June 30, 2015.

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, when applicable the Company considers its own credit quality and financial resources and ability to meet its potential repayment obligations associated with the derivative transactions.

At June 30, 2015, the Company had various types of derivative instruments, which included swaps and costless collars. The natural gas and oil derivative 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.

Assets and liabilities measured on a non-recurring basis

Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication the carrying costs may not be recoverable.  The fair value of impaired proved properties is determined based on quoted market prices in active markets, if available, or using Level 3 inputs and the income valuation technique, which converts future estimated cash flow amounts to a single present value amount, to measure the fair value of proved properties through an application of discount rates, price forecasts and operating and development cost assumptions selected by the Company’s management. 

Proved properties classified as held for sale are valued using a market approach, based on an estimated selling price, less selling costs, as evidenced by the most current bid prices received from third parties, if available. If an estimated selling price is not available, the Company utilizes the income valuation technique discussed above. Using the market approach, the Company estimated the fair value of its Pinedale assets, which were classified as held for sale at June 30, 2015, to be $12,468 and as a result the Company recorded impairment expense of $21,030 for the three

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and six months ended June 30, 2015 related to these assets.  The Company classified the fair value of its Pinedale assets as Level 2.    

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 the 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 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.

6.Impairment of Long-Lived Assets

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. See Note 5 for discussion of the Company’s fair value methodology. 

Proved property impairment expense for the three months ended June 30, 2015 and 2014 totaled $21,409, and $90, respectively, and $21,504 and $765 for the six months ended June 30 2015 and 2014, respectively. The impairment expense recorded in the second quarter of 2015, included $21,030 of expense related to its Pinedale assets as a result of the sale of these assets on July 31, 2015 (see Note 12 for discussion of the Pinedale asset sale). The impairment was determined based on the net book value for the Pinedale assets, reduced by the fair market value of the assets and the associated expected selling costs. The remaining impairment expense recognized during the first six months of 2015 was primarily due to an increase in estimated field abandonment costs (and thus the associated asset carrying value) at the Company’s Main Fork Unit property.  In 2014, the Company wrote-off a non-operated property in the Atlantic Rim, as production from the wells at this property had been limited and the operator began plugging and abandoning these wells. 

The Company also expensed $99 and $315 during the three months ended June 30, 2015 and 2014, respectively, and $297 and $315 during the six months ended June 30, 2015 and 2014, respectively, related to expiring undeveloped acreage in Wyoming, as the Company determined there was no a longer a plan to develop this acreage.  

7.Compensation Plans

The Company recognized stock-based compensation expense totaling $147 and $286 for the three and six months ended June 30, 2015, respectively, and $178 and $383 for the three and six months ended June 30, 2014, 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.

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A summary of stock option activity under the Company’s various stock option plans as of June 30, 2015 and changes during the six months ended June 30, 2015 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.

Nonvested stock awards as of June 30, 2015 and changes during the six months ended June 30, 2015 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 for the three and six months ended June 30, 2015 includes approximately $57 and $114, respectively, and $58 and $64 for the three and six months ended June 30, 2014, respectively, related to these plans.

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8.Income Taxes

The Company is required to record income tax expense for financial reporting purposes and apply an estimated effective tax rate for calculating income tax provisions for interim periods. The Company has not recorded any income tax expense/(benefit) for the three and six months ended June 30, 2015 as a result of the Company recording a valuation allowance on its net deferred tax assets due to the uncertainty of the realization of these assets. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which the use of such net operating losses are allowed. Among other items, management considers the scheduled reversal of deferred tax liabilities, tax planning strategies asset dispositions and projected future taxable income. Some, or all, of this valuation allowance may be reversed in future periods against any potential future income.  

The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of June 30, 2015, 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 2011 and for state and local tax authorities for tax years before 2010.

9.Equity

Preferred stock

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 “Dividend Rate”). 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. 

 

If the Company fails to pay cash dividends on the Series A Preferred Stock in full for any six quarterly dividend periods, whether consecutive or non-consecutive (a “Dividend Default”), then:

 

 

In 2015, the Board elected to suspend the Series A Preferred Stock dividend payment for the quarter ended March 31 and to suspend the dividend indefinitely beginning with the quarter ended June 30, 2015. As of June 30, 2015, the total arrearage on the Company’s Series A Preferred Stock was $1,862, or $1.1562 per share. 

Holders of the Series A Preferred Stock generally have limited voting rights. However, if a Dividend Default occurs, or if the Company fails to maintain a National Market Listing for the Series A Preferred Stock, the holders of the Series A Preferred Stock, voting separately as a class, will have the right to elect two directors to serve on the Board in addition to those directors then serving on the Board until such time as the National Market Listing is obtained or the dividend arrearage is eliminated.

 

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10.Acquisition of Atlantic Rim Assets

On June 16, 2015, the Company entered into Purchase and Sale Agreements (the “PSAs”) with Warren Resources, Inc. and its subsidiaries (collectively, the “Seller”), pursuant to which the Company will acquire (1) all of the Seller’s shallow depth interests in its coalbed methane ("CBM") assets located in the Atlantic Rim area of the Washakie Basin in Carbon County, Wyoming, where the Company currently operates the Catalina Unit and has working interests in the Spyglass Hill Unit; (2) the Seller’s midstream assets located in the Spyglass Hill Unit currently utilized to transport CBM gas produced by certain of the assets being sold; and (3) 30% of the Seller’s interests in the operated deep rights in the Atlantic Rim. The total purchase price for the assets is $47,000, subject to customary post-closing adjustments, of which $42,000 is payable in cash at closing with the remainder payable on the first anniversary of closing pursuant to a second lien promissory note secured by the midstream assets. Under the PSAs the transaction effective date is April 1, 2015. 

The transaction is subject to, among other things, the Company obtaining significant financing for the transaction.  The Company’s ability to obtain such financing is uncertain.  The PSAs are non-exclusive and may be terminated by the Seller in the event that it sells the relevant assets to another party prior to the closing date under the PSAs. However, the Company has a preferential purchase right under the unit operating agreements for these properties, which would allow the Company to match the purchase price of another prospective buyer. In addition, each of the PSAs also may be terminated by the Company or the Seller if the transactions contemplated thereby have not been consummated on or before September 1, 2015, or if the closing conditions of the other party have not been satisfied and cannot be cured or by mutual written consent.

If the transaction were to be completed, the Company’s interest in the Catalina Unit would increase from approximately 86% to 98% and the Company’s interest in the Spyglass Hill Unit would increase from an average of 22% to 96%. The Company would begin operating the Spyglass Hill Unit (which is currently operated by the Seller) upon closing of the transaction and receiving the necessary approval to do so from the Bureau of Land Management.

11.Contingencies

Legal proceedings

From time to time, the Company is involved in various legal proceedings, which are subject to the uncertainties inherent in any litigation, including the matters below. 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. 

Gas-to-liquids project

In May 2014, the Company entered into a letter agreement (“Letter Agreement”) to jointly initiate the development, construction and operations of a gas-to-liquids ("GTL") plant to be located in Wyoming. Under the terms of the Letter Agreement, the Company advanced total of $1,362, of which $202 was advanced during the first quarter of 2015. These funds were advanced on behalf of Wyoming GTL, LLC and its affiliate (collectively "WYGTL") to partially fund the feasibility studies and completion of the initial engineering and development plans for the GTL plant. In return, WYGTL assigned all development and engineering plans, contracts, rights, technical relationships, among other rights (collectively, the "Rights") to the Company.

The Letter Agreement expired effective January 31, 2015, as the Company was unable to agree on terms for a definitive agreement with WYGTL, as contemplated by the Letter Agreement. In accordance with the provisions of the Letter Agreement, the Company requested WYGTL to repay to the Company the total amount advanced, or $1,362. The Company filed a lawsuit in the State of Colorado on March 24, 2015, against WYGTL for breach of the Letter Agreement terms, seeking recovery of the total amount advanced under the Letter Agreement. On April 14, 2015, WYGTL filed a lawsuit against the Company in the U.S. District Court for Colorado, an action entitled Alan Eugene Humphrey and Wyoming GTL, LLC v. Escalera Resources Co., alleging the Company breached its contract with WYGTL, among other claims. The Company does not believe the case has merit and is defending the

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case vigorously. The Company subsequently filed counterclaims against WYGTL on May 5, 2015 in United States District Court seeking recovery of the total advances, and dismissed its original action filed in the State of Colorado.

As the future collection of this receivable from WYGTL is uncertain, the Company has recorded a provision to fully reserve for the amount advanced for this project. The provision recorded during the first quarter of 2015 totaled $202, which fully provided for the advances made during the period.    

Former employee lawsuits

On January 29, 2015, two former employees each filed claims against the Company in the District Court of Harris, Texas, which generally assert breach of contract in connection with their termination from the Company (actions known as William A. Sidwell, III v. Escalera Resources Co. and Gregory Whiting v. Escalera Resources Co.). In April 2015, the Company filed certain counterclaims, including breach of fiduciary duty and business disparagement, against the former employees. A trial has been set for May 2016 in one of these suits. The Company does not believe the plaintiffs’ cases have merit and intends to vigorously defend the cases and pursue its counterclaims.

12.Divestitures

On July 31, 2015, the Company completed the sale of its interests in the Mesa Units located on the Pinedale Anticline in southwestern Wyoming. The sale was primarily contemplated to satisfy a requirement of the First Amendment to its credit facility to reduce the outstanding borrowings of the Company. The assets were sold for $12,000,  less closing adjustments, of which cash proceeds of $10,500 were repaid to its lenders following the closing of the transaction. The effective date of the sale was April 1, 2015. The results of operations for the three and six months ended June 30, 2015 reflect revenues and expenses related to these properties as the sale occurred subsequent to June 30, 2015. 

Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty that such a sale will take place within one year. Upon classification as held for sale, long-lived assets are no longer depreciated or depleted, and a measurement for impairment is performed to identify and expense any excess of carrying value over fair value less estimated costs to sell. See note 6 for further discussion of impairment related to the Pinedale assets for the three and six months ended June 30, 2015. 

Below is summary of the major classes of assets and liabilities classified as held for sale as of June 30, 2015:

 

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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, 2014 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 common stock is publicly traded on the NASDAQ Capital Market under the symbol “ESCR” and our Series A Cumulative Preferred is publicly traded on the NASDAQ Global Select Market under the symbol “ESCRP”. 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 Drive, Suite 850, Houston, TX 77057. Our website is www.escaleraresources.com.

Our current production primarily consists of natural gas from properties predominantly located in Wyoming, the most significant of which are 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. In July 2015, we sold our assets located on the Pinedale Anticline. 

Business Strategy

The market price for natural gas and oil decreased significantly during the second half of 2014 with continued weakness into 2015. The decrease in the market prices for our production directly reduces our operating cash flow and indirectly impacts our other sources of potential liquidity.  Lower market prices for our production led to a decrease in our borrowing base during our spring 2015 borrowing base redetermination, resulting in a borrowing base deficiency of $3,515.  Given

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the unfavorable market conditions, coupled with our depleting asset base, we are focused on the following near-term business strategies: (1) obtaining additional debt financing, likely through an alternative source, to provide the financing to complete our strategic acquisition of Atlantic Rim assets, cure our borrowing base deficiency and meet our working capital needs, (2) identifying potential merger candidates which we believe would offer capital to develop our natural gas and oil properties, (3) maintaining production while efficiently managing, and in some cases reducing, our operating and general and administrative (“G&A”) costs, and (4) evaluating asset divestiture opportunities which would allow us to reduce our indebtedness. The Company has explored raising additional capital in order to pursue its objective of acquiring and developing natural gas properties, however, given our current capital structure and the recent declines in natural gas and oil commodity prices, raising such capital is unlikely. Our current capital structure is prohibitive for raising capital due primarily to certain terms and provisions of our Series A Preferred Stock.   

Even if we are successful at reducing our costs and increasing our liquidity through asset sales, we may not have sufficient liquidity to satisfy our debt service obligations, meet other financial obligations, and comply with covenants contained in our credit agreement.  We have engaged advisors to assist with the evaluation of our options to obtain alternative debit financing, improve our liquidity position and evaluate strategic alternatives. These strategic alternatives may include, but are not limited to, seeking a merger partner, restructuring, amendment or refinancing of our outstanding debt through a private restructuring or reorganization under Chapter 11 of the Bankruptcy Code, or a combination of such alternatives. However, there can be no assurances that we will be able to successfully restructure our indebtedness, improve our liquidity position, complete any strategic transactions or comply with debt covenant requirements for the remainder of 2015 or beyond.

In the event we are able to obtain additional capital with which to make acquisitions and fund the development of our properties, our objective is to increase long-term shareholder value by profitably growing our reserves, production, revenues, and cash flow. To meet this objective, we would primarily focus on (1) selectively pursuing acquisitions of abundant, low cost natural gas assets that are currently undervalued or underutilized; (1)  identifying alternative ways to enhance the value of our natural gas reserves; (3)  investing in and enhancing our existing production wells and field facilities on operated and non-operated properties in the Atlantic Rim;  and (4)  pursuing high quality exploration and strategic development projects with potential for providing long-term drilling inventories that generate above average returns.

Recent Developments

On June 16, 2015, we entered into Purchase and Sale Agreements (the “PSAs”) with Warren Resources, Inc. and its subsidiaries (collectively, the “Seller”), pursuant to which we will acquire (1) all of the Seller’s shallow depth interests in its CBM assets located in the Atlantic Rim area of the Washakie Basin in Carbon County, Wyoming, where we currently operate the Catalina Unit and have working interests in the Spyglass Hill Unit; (2) the Seller’s midstream assets located in the Spyglass Hill Unit currently utilized to transport CBM gas produced by certain of the assets being sold; and (3) 30% of the Seller’s interests in the operated deep rights in the Atlantic Rim. If we are able to obtain financing to complete the transaction, our working interest in the Catalina Unit would increase from approximately 86% to 98% and our working interest in the Spyglass Hill Unit would increase from an average of 22% to 96%. We plan to begin operating the Spyglass Hill Unit (which is currently operated by the Seller) upon closing of the transaction and receiving the necessary approval to do so from the Bureau of Land Management. Management believes that the Company can realize numerous efficiencies by operating both Units within the Atlantic Rim play. The transaction will immediately increase our reserves and production, and is expected to increase operating cash flow based upon current natural gas prices.  Closing this transaction is largely dependent on our ability to obtain significant debt financing, as we do not have any additional borrowing capacity from our existing credit facility. Our ability to obtain such financing is uncertain. 

The total purchase price for the assets is $47,000, subject to customary post-closing adjustments, of which $42,000 is payable in cash at closing with the remainder payable on the first anniversary of closing pursuant to a second lien promissory note secured by the midstream assets. Under the PSAs, the transaction effective date is April 1, 2015. The PSAs may be terminated by the Seller if the transaction has not been consummated by September 1, 2015. 

As of June 30, 2015, we were in default on our credit facility as a result of (1) our failure to meet the financial covenants on the facility at both March 31, 2015 and June 30, 2015; (2) the inclusion of a going concern explanatory paragraph by our independent registered public accounting firm in its audit opinion for the year ended December 31, 2014; and (3) we

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have not fully paid our ad valorem taxes assessed in 2014 (which were due in May 2015) for certain of our properties. On July 31, 2015, we entered into a Forbearance Agreement and First Amendment to Credit Agreement (the “Amendment”), which provides that our lenders will forbear from exercising certain rights under the credit facility to (1) accelerate payments (other than the automatic acceleration that would occur under certain clauses of the credit agreement);  (2) enforce security interests (other than after the occurrence of an automatic acceleration under certain clauses of the credit agreement); and (3) file or otherwise initiate an involuntary bankruptcy petition against the Company. The forbearance will be in effect until the earlier of September 1, 2015 or the date of the occurrence of any event of termination under the Amendment. 

In connection with the Amendment, the borrowing base on our credit facility was reduced from $50,000 to $44,000 as a result of the most recently completed borrowing base redetermination. The redetermination resulted in a borrowing base deficiency of $3,515. We anticipate that if we are able to obtain additional debt financing for our Atlantic Rim asset purchase, we will also use proceeds from that funding to cure our borrowing base deficiency. 

Additionally, in accordance with the terms of the Amendment, on July 31, 2015 we completed a sale of our interests in the Mesa Units located on the Pinedale Anticline in southwestern Wyoming. The assets were sold for cash of $12,000, less closing adjustments, of which net proceeds of $10,500 were repaid to our lenders following the transaction. The effective date of the sale was April 1, 2015. The results of operations for the three and six months ended June 30, 2015 reflect revenues and expenses related to these properties as the sale occurred subsequent to June 30, 2015. The assets and liabilities directly related to the Pinedale assets were classified as held for sale as of June 30, 2015, and totaled $13,344 and $2,054, respectively. For the year ended December 31, 2014, our Pinedale assets accounted for 1.4 Bcfe, or 17%, of our production volumes and $5,966, or 17%, of our total natural gas and oil sales.    

RESULTS OF OPERATIONS 

Three Months Ended June 30, 2015 Compared to the Three Months Ended June 30, 2014 

The following analysis provides comparison of the three months ended June 30, 2015 and the three months ended June 30, 2014.  

Natural gas and oil sales

Natural gas and oil sales decreased 64% to $3,394, due to a 33% decrease in natural gas production, primarily at our Atlantic Rim and Pinedale Anticline properties, compounded by a  44% decrease 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 22% to $3.00 per Mcf. 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 gains/(losses) on our commodity derivatives, which is included within price risk management activities, net on the consolidated statements of operations, totaling $1,181 and $(533) for the three months ended June 30, 2015 and 2014, respectively. 

 

Our total net production decreased 34% to 1.4 Bcfe for the three months ended June 30, 2015 primarily due to lower production from our properties in the Atlantic Rim. 

Our total average daily net production at the Atlantic Rim decreased 38% to 11,486 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,

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and Grace Point participating areas (“PA”)). We operate the Catalina Unit and have non-operated working interests in the Spyglass Hill Unit.

Average daily net production at our Catalina Unit decreased 43% to 7,691 Mcfe. During the first quarter of 2015 we temporarily halted our well workovers due to depressed natural gas prices. In April 2015, we completed the change-out of our remaining electric powered compressors to natural gas powered compressors. In May 2015, we resumed our workover program, on a more strategic and targeted basis, with 13 workovers completed by the end of June 2015. We realized a decrease in production due to the normal field production decline. 

Average daily production, net to our interest, at the Spyglass Hill Unit decreased 23% to 3,795 Mcfe. Although the operator drilled 59 new production wells in the Spyglass Hill Unit since the third quarter of 2013, we have not realized an increase in production volumes due to infrastructure constraints in the unit. In addition, a significant number of wells are offline within the Spyglass Hill Unit. Management believes that the operator has shifted its efforts to other properties as a result of its recent significant acquisition in the northeastern U.S., economic conditions and the operator’s planned sale to us. No drilling is planned in this unit for 2015. 

On the Pinedale Anticline, our average daily net production decreased 22% to 3,018 Mcfe as a result of normal production decline, which was no longer offset by initial production from new wells. The initial production rates from wells in this field are very strong and then decline quickly. The operator drilled the final well in the Mesa B Unit in early 2014, and therefore our production began to decline as we did not have any material interest in the new development in the area. We completed the sale of our interests in the Pinedale assets on July 31, 2015. The effective date of this transaction is April 1, 2015, and the revenue and production associated with these properties after that date was credited back to the seller as a closing adjustment. 

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 decreased 40% to $563  for the three months ended June 30, 2015, due to the decrease 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 $212. This consisted of an unrealized non-cash loss of $1,393, which represents the change in the fair value of our commodity derivatives at June 30, 2015 based on the expected future prices of the related commodities, and a net realized gain of $1,181 related to the cash settlement of our economic hedges. 

Oil and gas production costs, production taxes, depreciation, depletion and amortization

 

Total well production costs decreased 11% to $2,837, primarily due to the deferral of maintenance costs at both the Catalina Unit and the Spyglass Hill Unit. The Company delayed its maintenance program at the Catalina Unit to late May 2015 due to depressed commodity prices, the completion of its compressor change-out from electrical to natural gas, and also due to significant rainfall in the area during April and May 2015. Management believes that the operator of the Spyglass Hill Unit has delayed its maintenance activity and shifted its efforts to other properties as a result of its recent significant acquisition in the northeastern U.S., economic conditions and the operator’s planned sale to us. Production costs on a per

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Mcfe basis increased 34%, or $0.51, to $1.99, primarily due to the decrease in production volumes, as a portion of our production costs are fixed, or partially fixed.

Production taxes decreased 69% to $350 for the three months ended June 30, 2015 and production taxes, on a per Mcfe basis, decreased $0.28 to $0.25 per Mcfe. We are required to pay taxes on the revenue generated upon the physical sale of our gas to counterparties, which represent approximately 12% of natural gas sales. Production taxes decreased due to the decline in oil and natural gas revenue. Production taxes in 2015 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 commodity market prices.

Total depreciation, depletion and amortization expenses (“DD&A”) decreased 39% to $3,005, and depletion and amortization related to producing assets decreased 38% to $2,916. Expressed on a per Mcfe basis, depletion and amortization related to producing assets decreased 7%, or $0.16, to $2.04. The decrease in DD&A on a per Mcfe basis was primarily the result of a lower depletion rate at the Catalina, Spyglass Hill, and Pinedale Units due to a decrease in our production. In addition, we stopped recording depletion on our Pinedale assets in June 2015 as they were classified as held for sale. 

Pipeline operating costs 

Pipeline operating costs decreased 52% to $536. In April 2015, we completed our project to change-out our electric powered compressors to natural gas powered compressors, which we believe to be more economic in a low commodity price environment.  Our power charges and compression rental costs were lower during the three months ended June 30, 2015 as a result of this change. 

Impairment and abandonment of equipment and properties

We recorded impairment and abandonment expense in the three months ended June 30, 2015 of $21,508,  of which $21,030 related to a write-down of our Pinedale assets to fair market value, as a result of our decision to sell these assets, which was completed in July 2015.  The remaining impairment expense recognized during the three months ended June 30, 2015 was primarily due to an increase in estimated field abandonment costs (and thus the associated asset carrying value) at the Main Fork Unit property and the write-off of expiring undeveloped acreage in Wyoming as we determined there is no a longer a plan to develop this acreage. 

General and administrative expenses

G&A expenses decreased 27% to $1,234,  which primarily resulted from a $285 decrease in salary and salary-related expenses due to lower 2015 headcount and severance incurred in 2014, a $102 decrease in legal costs related to fewer corporate projects requiring legal services and improved management of legal services, and a decrease of $45 due to the reduction of our board size from six outside directors to four.  

Income taxes

We did not record an income tax benefit for the three months ended June 30, 2015 a result of recording a full valuation against our net deferred tax assets. 

Six Months Ended June 30, 2015 Compared to the Six Months Ended June 30, 2014 

The following analysis provides comparison of the six months ended June 30, 2015 and the six months ended June 30, 2014.  

Natural gas and oil sales

Natural gas and oil sales decreased 61% to $7,719, due to a 30% decrease in natural gas production, primarily at our Atlantic Rim and Pinedale Anticline properties, compounded by a  49% decrease 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 23% to $3.09 per Mcf. 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 gains/(losses) on our commodity derivatives, which is included within price risk management activities, net on the

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consolidated statements of operations, totaling $2,383 and $(1,475) for the six months ended June 30, 2015 and 2014, respectively. 

 

 

 

Our total net production decreased 30% to 3.1 Bcfe for the six months ended June 30, 2015 primarily due to lower production from our properties in the Atlantic Rim. 

Our total average daily net production at the Atlantic Rim decreased 33% to 12,470 Mcfe. Average daily net production at our Catalina Unit decreased 39% to 8,349 Mcfe. During the first four months of 2015, we had approximately 25 wells generating lower than expected production as a result of mechanical problems; however we deferred maintenance on these wells due to depressed natural gas prices and our plans to replace our electric powered compressors with more cost efficient natural gas powered compressors in order to reduce operating costs in the field. The compressor change-out was completed in late April 2015, and we began a strategic workover program focused on improving production from these wells in late May 2015. We also realized a decrease in production due to the normal field production decline. 

Average daily production, net to our interest, at the Spyglass Hill Unit decreased 18% to 4,121 Mcfe. Although the operator drilled 59 new production wells in the Spyglass Hill Unit since the third quarter of 2013, we have not realized an increase in production volumes due to infrastructure constraints in the unit. In addition, a significant number of wells are offline within the Spyglass Hill Unit. Management believes that the operator has shifted its efforts to other properties as a result of its recent significant acquisition in the northeastern U.S., economic conditions and the operator’s planned to sale to us. No drilling is planned in this unit for 2015.

On the Pinedale Anticline, our average daily net production decreased 19% to 3,250 Mcfe as a result of normal production decline, which was no longer offset by initial production from new wells. The initial production rates from wells in this field are very strong and then decline quickly. The operator drilled the final well in the Mesa B Unit in early 2014, and therefore our production began to decline as we did not have any material interest in the new development in the area. We completed our sale of our interests in these Pinedale assets on July 31, 2015. The effective date of this transaction was April 1, 2015, and the revenue and production associated with these properties after that date was credited back to the seller as a closing adjustment. 

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 decreased 36% to $1,212  for the six months ended June 30, 2015, due to the decrease in Catalina production volumes as compared to the prior-year period.

Price risk management activities

We recorded a net gain on our derivative contracts of $2,566. This consisted of an unrealized non-cash gain of $183, which represents the change in the fair value of our commodity derivatives at June 30, 2015 based on the expected future prices of the related commodities, and a net realized gain of $2,383 related to the cash settlement of our economic hedges. 

Oil and gas production costs, production taxes, depreciation, depletion and amortization

 

Overall well production costs decreased 7% to $6,034,  primarily due to the deferral of maintenance costs at both the Catalina Unit and the Spyglass Hill Unit. The Company delayed its maintenance program at the Catalina Unit to late May 2015 due to depressed commodity prices, the completion of its compressor change-out from electrical to natural gas, and also due to significant rainfall in the area during April and May 2015. Management believes that the operator of the Spyglass Hill Unit has delayed its maintenance activity and shifted its efforts to other properties as a result of its recent significant acquisition in the northeastern U.S., economic conditions and the operator’s planned sale to us. Production costs on a per Mcfe basis increased 32%, or $0.48, to $1.96, primarily due to the decrease in production volumes, as a portion of our production costs are fixed, or partially fixed.

Production taxes decreased 65% to $834 for the six months ended June 30, 2015 and production taxes, on a per Mcfe basis, decreased $0.27 to $0.27 per Mcfe. We are required to pay taxes on the revenue generated upon the physical sale of our gas to counterparties, which represent approximately 12% of natural gas sales. Production taxes decreased due to the decline in oil and natural gas revenue. Production taxes in 2015 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 commodity market prices.  

Total DD&A decreased 34% to $6,700, and depletion and amortization related to producing assets decreased 35% to $6,523. Expressed on a per Mcfe basis, depletion and amortization related to producing assets decreased 7%, or $0.17, to $2.12. The decrease in DD&A on a per Mcfe basis was primarily the result of a lower depletion rate at the Catalina, Spyglass Hill, and Pinedale Units due to a decrease in our production.  In addition, we stopped recording depletion on our Pinedale assets in June 2015 as they were classified as held for sale. 

Pipeline operating costs 

Pipeline operating costs decreased 37% to $1,457. In April 2015, we completed our project to change-out our electric powered compressors to natural gas powered compressors, which we believe to be more economic in a low commodity price environment.  Our power charges and compression rental costs were lower during the six months ended June 30, 2015 as a result of this change.

Impairment and abandonment of equipment and properties

We recorded impairment and abandonment expense in the six months ended June 30, 2015 of $21,801,  of which $21,030 related to a write-down of our Pinedale assets to fair market value, as a result of our decision to sell these assets, which was completed in July 2015. The remaining impairment expense recognized during the six months ended June 30, 2015 was primarily due to an increase in estimated field abandonment costs (and thus the associated asset carrying value) at the Main Fork Unit property and the write-off of expiring undeveloped acreage in Wyoming as we determined there is no a longer a plan to develop this acreage. 

General and administrative expenses

G&A expenses decreased 23% to $2,898. In 2014, we recorded severance expense of $856 primarily related to the severance for our former chief executive officer; no severance-related expenses were incurred 2015. Legal costs decreased by $122 due to the fewer corporate projects requiring legal services and improved management of legal services. Additionally, stock-based compensation expense decreased by $97 as there were fewer outstanding awards during the six months ended June 30, 2015. These decreases were offset, in part, by the increase in financial advisory services and contract labor of $178.

Provision for gas-to-liquids advance

We recorded a provision of $202 in the first quarter of 2015 for the reimbursement of amounts advanced for the GTL plant by us in 2015. In May 2014, we entered into a Letter Agreement to jointly initiate the development, construction and operations of a GTL plant to be located in Wyoming. The Letter Agreement expired effective January 31, 2015 as we were

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unable to agree on terms for a definitive agreement with WYGTL, as contemplated by the Letter Agreement. In accordance with the provisions of the Letter Agreement, we requested WYGTL to repay to us the total amount we advanced, or $1,362. As the future collection of this amount is uncertain, we have recorded a provision to fully allow for the outstanding advances as of June 30, 2015.   

Income taxes

We did not record an income tax benefit for the six months ended June 30, 2015 as a result of recording a full valuation against our net deferred tax assets. 

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.

Credit Facility

As of June 30, 2015 we had a $250,000 line of credit (the “Credit Agreement”) in place with a $50,000 borrowing base and an outstanding balance of $47,515. We have depended on our credit facilities 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 and projects in the Pinedale Anticline.

We are subject to both financial and non-financial covenants. The financial covenants, as defined in the Credit Agreement, include maintaining (1) a current ratio of 1.0 to 1.0; (2) 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 (3) a funded debt, less unencumbered cash, to EBITDAX ratio of less than 4.0 to 1.0. As of June 30, 2015, we were in violation of each of the aforementioned covenants.

In addition, we had triggered two additional events of default as of June 30, 2015, as defined by the Credit Agreement: (1) our independent registered public accounting firm had included in its audit opinion for the year ended December 31, 2014, a going concern explanatory paragraph and (2) we have not fully paid our ad valorem taxes assessed in 2014 (due in May 2015) for certain of our properties. As a result of these violations, the lender has the right to declare an event of default, terminate the remaining commitment and accelerate all principal and interest outstanding.

On July 31, 2015, we entered into the Amendment to the Credit Agreement, which provides that our lenders will forbear from exercising certain rights under the Credit Agreement to (1) accelerate payments (other than the automatic acceleration that would occur under certain clauses of the credit agreement), (2) enforce security interests (other than after the occurrence of an automatic acceleration under certain clauses of the credit agreement) and (3) file or otherwise initiate an involuntary bankruptcy petition against the Company. The forbearance will be in effect until the earlier of September 1, 2015 or the date of the occurrence of any event of termination under the agreement. The additional financial covenant violations which occurred at June 30, 2015 are events of termination under the Amendment, and therefore our lender could elect to exercise any of the aforementioned rights available under the Credit Agreement. 

The Amendment also decreased the borrowing base on the credit facility from $50,000 to $44,000 in connection with our regularly scheduled semi-annual redetermination, which resulted in a borrowing base deficiency of $3,515. Under the Amendment, the lenders will not take any actions in relation to the borrowing base deficiency until after September 1, 2015. Following the sale of our Pinedale assets, our borrowing base was $33,500 as reduced by cash proceeds repaid from the sale of $10,500. The borrowing base deficiency did not change materially as a result of the repayment of proceeds.  We are actively identifying options available to the Company to obtain additional financing to fund the previously announced acquisition of the Atlantic Rim assets, satisfy our borrowing base deficiency and provide working capital.

As of June 30, 2015, borrowings under the credit facility incurred interest daily based at our interest rate election of either the Base Rate or LIBOR Rate. Under the Base Rate option, interest is calculated at an annual rate equal to the highest of (a) the base rate for Dollar loans for such day, Federal Funds rate for such day, plus 0.5%, or the LIBOR for such day plus (b) a margin ranging between 0.75% and 1.75% (annualized) depending on the level of funds borrowed. Under the LIBOR

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Rate option, interest is calculated at an annual rate equal to LIBOR, plus a margin ranging between 1.75% and 2.75% (annualized) depending on the level of funds borrowed. In addition to the standard interest charge, we became subject to an additional penalty rate of 2.0% (annualized) effective May 19, 2015 as a result of the aforementioned events of default. The average interest rate on the facility at June 30, 2015 was 5.1%. Under the Amendment, we may no longer elect the LIBOR Rate option and interest will be charged at the Base Rate after the expiration of the current interest rate elections. 

Other

Our future success in growing proved reserves and production will be highly dependent on capital resources available to us, if any, natural gas prices and our success in finding or acquiring additional reserves. As part of our strategy, we are actively seeking additional debt financing to complete our acquisition of the Atlantic Rim assets, cure our borrowing base deficiency and meet our working capital needs. We also continue to explore merger and acquisition opportunities.  The timing, structure, terms, size, and pricing of any such financing or transaction will depend on prospective lender/investor interest and market conditions. We can provide no assurance that we will be able to do so on favorable terms or at all. We may issue equity or debt in private placements or obtain additional debt financing, which may be secured by our natural gas and oil properties, or unsecured.

In January 2015, we received notice from the Nasdaq Stock Market (“Nasdaq”) indicating that our common stock was subject to potential delisting from the Nasdaq because our common stock had closed below the minimum $1.00 per share requirement for 30 consecutive days. In April 2015, we received an additional notice from the Nasdaq indicating that our common stock was subject to delisting because the market value of our common stock was below the required $5,000 required for listing on the Global Select Market. On July 23, 2015, as a result of not complying with Nasdaq’s minimum $1.00 per share requirement, Nasdaq’s listing for our common stock was moved to the Nasdaq Capital Market. This move provides us until January 17, 2016 to regain compliance with the minimum bid price rule, which along with a market value in excess of $5,000, would make our common stock eligible for listing on the Global Select Market. 

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

 

 

Working capital (deficit)

Our working capital (deficit) as of June 30, 2015, includes the impact of our debt reclassification to a current liability, due to the events of default described above. Excluding the impact of this reclassification, our working capital was lower as of June 30, 2015, primarily due to a $2,548 decrease in cash and a $2,403 decrease in accounts receivable as a result of lower production and natural gas prices, as well as a $1,179 decrease in other current assets, as we reclassified a portion of our inventories to long-term.  This was offset by a $1,057 increase in the fair value of our commodity derivatives and a decrease in accounts payable and accrued expense of $1,797 as compared to December 31, 2014.

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We expect our working capital to continue to decrease as a result of the depressed natural gas prices and decreasing production. In an effort to preserve working capital, we have delayed payment of approximately $800 of ad valorem taxes assessed in 2014 (which were due in May 2015). Additionally, we have extended the timing of payment for certain operating expenses.  We do not currently have sufficient working capital to repay our borrowing base deficiency. 

 

Cash flow activities

The table below summarized the six months ended June 30, 2015 and 2014, respectively:

 

During the six months ended June 30, 2015, net cash provided by operating activities was $1,145, as compared to $6,012 in the same prior-year period.  The primary sources of cash during the six months ended June 30, 2015 resulted from a net loss of $(29,159), which was net of non-cash charges of $21,504 primarily related to the impairment of our Pinedale assets, $6,839 related to DD&A and accretion expense, a $183 unrealized net gain related to the change in fair value of our derivative contracts and $286 in stock-based compensation expense. Our cash flow from operations for the six months ended June 30, 2015 was lower, largely due to a decrease in production volumes of 30%, or approximately 1.3 Bcfe. In addition, our average realized price decreased $0.92 per Mcfe due to lower market prices and less favorable economic hedges. In an effort to preserve working capital, we have delayed payment of approximately $800 of ad valorem taxes assessed in 2014 (which were due in May 2015). Additionally, we have extended the timing of payment for certain operating expenses, which has positively impacted our cash flow from operations in the short-term. 

Our operating cash flow is highly sensitive to fluctuations in the price of natural gas. Our hedging program helps to mitigate fluctuations due to price volatility. However, the structure of the hedges in place in 2015 does not fully limit the downside of price fluctuations. Natural gas prices have fallen as compared to 2014, which will negatively impact our cash flow. Taking into account our economic hedges, for the six months ended June 30, 2015, our income before income taxes and cash flow would have decreased by approximately $1,320 for each $0.50 change per Mcf in natural gas prices.

During the six months ended June 30, 2015, net cash used in investing activities was $3,691, as compared to $2,334 in the same prior-year period. Our 2015 capital spending was primarily related to payment of costs associated with the 2014 drilling program at the Spyglass Hill Unit. In 2014, our capital spending was primarily related to payment of costs associated with the Spyglass Hill and Mesa “B” 2013 drilling programs.

Cash used by financing activities was $2 for the six months ended June 30, 2015, as compared to cash provided by financing activities of $752 for the six months ended June 30, 2014.  In 2014 we completed an offering of our common stock through a private placement for net proceeds of $4,158. In 2014, we also paid the first two quarterly dividend payments on our Series A Preferred Stock totaling $1,862. In 2015 we suspended the payment of dividends indefinitely. 

Capital Requirements 

The Company has historically assessed active and potential development projects to determine the best use for available capital. Such assessment has included analyzing the risk and estimated return for each proposed project, including our non-operated assets (primarily the Spyglass Hill Unit in the Atlantic Rim). Due to our current lack of liquidity and the current market and commodity price conditions, we have not budgeted for any capital projects in 2015, and we will assess any potential opportunities on an individual basis. If we are able to obtain additional debt financing and economic conditions were to improve, we may drill and complete up to five producing wells and two injection wells located in the Catalina Unit during the second half of 2015. The expected gross cost for this program would be approximately $6.5 million. Our interest in these wells will vary significantly depending upon our ability to complete the Atlantic Rim asset purchase. 

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We also continue to evaluate acquisition opportunities that we believe will complement our existing operations, offer economies of scale and/or provide further development, exploitation and exploration opportunities. In addition to potential acquisitions, we also may decide to divest certain non-core assets, enter into strategic partnerships or form joint ventures related to our assets that are not currently considered in our expected 2015 capital expenditures.

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, 2015 are summarized below (volume and daily production are expressed in Mcf). All of our natural gas contracts are indexed to the NYMEX. The prevailing natural gas 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.

 

 

As part of the Amendment to its Credit Agreement, we unwound a portion of its contracted oil volumes (3,000 Bbls) for cash proceeds of $129, which was used to pay down our outstanding borrowings on our credit facility. 

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, 2014, and to the Notes to the Consolidated Financial Statements included in Part I, Item 1 of this report.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are a smaller reporting company as defined by Rule 12b-2 of the Securities Exchange Act of 1934, as amended (“Exchange Act”) and are not required to provide the information under this Item.

ITEM 4.CONTROLS AND PROCEDURES

In accordance with 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 quarter ended June 30, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.