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 September 30, 2014 

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”), 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.

Certain prior year amounts have been reclassified to conform to the current year presentation.

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 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, 2013 filed with the SEC on March 13, 2014, as amended on Form 10-K/A filed with the SEC on September 12, 2014.  

Recent Accounting Pronouncements

 In August 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (“ASU No. 2014-15”) that will require management to evaluate whether there are conditions and events that raise substantial doubt about the Company’s ability to continue as a going concern within one year after the financial statements are issued on both an interim and annual basis. Management will be required to provide certain footnote disclosures if it concludes that substantial doubt exists or when its plans to alleviate substantial doubt about the Company’s ability to continue as a going concern. ASU No. 2014-15 becomes effective for annual periods beginning in 2016 and for interim reporting periods starting in the first quarter of 2017. The Company plans to adopt ASU No 2014-15 for its Annual Report on Form 10-K for the year ended December 31, 2016 and is in the process of evaluating the impact on its financial statement disclosures. 

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.

 

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

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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 $930 for each of the three months ended September 30, 2014 and 2013 and $2,792 for each of the nine months ended September 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:

 

 

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

Effective August 29, 2014, the Company replaced its existing credit facility with a new $250,000 credit agreement with Societe Generale.  Under the new agreement, the Company’s borrowing base was increased to $50,000.  As of September 30, 2014, the Company had $45,015 outstanding on the facility.  The Company paid the lender and its financial advisor structuring fees and legal expenses totaling $895 in connection with facilitating the credit agreement, which will be amortized as part of interest expense over the term of the loan.  

The Company has utilized its credit facilities 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 August 28, 2017. 

Borrowings under the new credit facility bear 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

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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. 

The average interest rate on the new facility at September 30, 2014 was 3.1%.  

For the three months ended September 30, 2014 and 2013, the Company incurred interest expense on its credit facilities of $603 and $407, respectively, and for the nine months ended September 30, 2014 and 2013, $1,427 and $1,232, respectively. Of the total interest incurred, the Company capitalized interest costs of $10 and $11 for the three months ended September 30, 2014 and 2013, respectively, and $42 and $67 for the nine months ended September 30, 2014 and 2013, respectively.

In accordance with the new 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, less unencumbered cash, to EBITDAX ratio of less than 4.0 to 1.0. As of September 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.

 

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 (loss) and earnings (loss) 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.  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, 2013. 

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.

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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 September 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 September 30, 2014:

 

 

 

 

 

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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 September 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 nine months ended September 30, 2014 and 2013 was as follows:

 

 

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(1)Included in price risk management activities on the consolidated statements of operations. Price risk management activities totaled $1,633 and $630 for the three months ended September 30, 2014 and 2013, respectively and $(1,634) and $1,264 for the nine months ended September 30, 2014 and 2013, respectively.

 

In conjunction with the Company entering into a new credit agreement, the Company closed out its commodity and interest rate derivative positions held with its former lender on August 29, 2014.  The Company realized a gain of $1,343 on its commodity derivatives and a $315 loss on its interest rate swap.  These settlements are included in the table above. 

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

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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:

 

 

 

 

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

 

 

 

 

 

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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 nine months ended September 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 September 30, 2014, 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.

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 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. 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.

Proved property impairment expense in the three months ended September 30, 2014 and 2013 totaled $0, and $(36), respectively, and $765 and $1,379 in the nine months ended September 30, 2014 and 2013, respectively. In the first quarter of 2014, the Company 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

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this area beginning in 2014. Impairment expense in the three and nine months ended September 30, 2013 was primarily related to the write-off of capital costs incurred on its Niobrara exploration well.

The Company also expensed $355 and $0 during the three months ended September 30, 2014 and 2013, respectively, and $670 and $121 during the nine months ended September 30, 2014 and 2013, respectively, related to undeveloped leaseholds. The 2014 write-off primarily related to expiring undeveloped acreage in Nebraska and Wyoming.

7.Compensation Plans

The Company recognized stock-based compensation expense totaling $218 and $601 for the three and nine months ended September 30, 2014, respectively, and $54 and $570, for the three and nine months ended September 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 September 30, 2014 and changes during the nine months ended September 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 September 30, 2014 and changes during the nine months ended September 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 nine months ended September 30, 2014 includes approximately $58 and $122, respectively, related to these plans.

8.Income Taxes

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 nine months ended September 30, 2014 the Company used an ETR of 8.4%. The Company’s ETR for the nine months ended September 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 September 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 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.

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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 as other than 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. 

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.

10.Commitments and Contingencies

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").  If a definitive agreement is reached, 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, the Company anticipates 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.

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As of September 30, 2014, the Company had advanced $871 under the agreement, which is included in other current assets on the consolidated statement of operations.  To the extent that a definitive agreement is not executed with WYGTL, the Company believes that the reimbursement by WYGTL for amounts advanced under the letter agreement is fully collectible.

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 and amended Form 10-K/A 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. 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.

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Our current production primarily consists of natural gas from our two core properties in Wyoming. 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. 

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.

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"). If a definitive agreement is reached, 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.

Currently the letter agreement will terminate on November 26, 2014 if a definitive agreement between us and WYGTL has not been completed. We are in the process of negotiating an extension on the letter agreement to January 31, 2015. 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 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 September 30, 2014, $871 of the $2,000 commitment had been advanced.  To the extent that a definitive agreement is not executed with WYGTL, we believe that the reimbursement by WYGTL for amounts advanced under the letter agreement is fully collectible.

Recent Developments

On August 29, 2014, we replaced our existing credit facility with a $250 million credit facility with Societe Generale.  The new credit facility increased our borrowing base to $50 million and extended the maturity date to August 2017.   The new facility also has a more flexible covenant structure than our previous credit facility, which management believes to be essential as we expand our business. 

RESULTS OF OPERATIONS

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

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

Natural gas and oil sales

Natural gas and oil sales decreased 1% to $7,550, due to an 11% decrease in natural gas production, primarily at our Atlantic Rim and Pinedale Anticline properties.  The decrease in production volumes was partially offset by a  12% increase in the Colorado Interstate Gas (“CIG”) market price, which is the index on which most of our natural gas volumes are sold. 

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As shown in the table below, our average realized natural gas price decreased 6% to $3.61 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 gain on our commodity derivatives, which is included within price risk management activities, net on the consolidated statements of operations, totaling $115 and $1,658 for the three months ended September 30, 2014 and 2013, respectively. The 2014 net realized gain on commodity contracts considered in the average realized price calculation, excluded the $1,343 gain realized on the settlement of our commodity contracts with the prior lender on our credit facility. 

 

 

Our total net production decreased 11% to 2.0 Bcfe for the three months ended September 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 decreased 10% to 16,414 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 decreased 11% to 11,462 Mcfe.   During the third quarter 2014, we experienced a power outage and equipment interruption due to a lightning strike and as a result certain wells were briefly shut-in.  CBM wells are highly sensitive to water build-up when shut-in, even for short periods of time.  We are currently in the process of dewatering these wells and expect normal production to resume by the end of the first quarter of 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 8% to 4,952 Mcfe.  Although the operator drilled 50 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. The operator has informed us that it plans to drill nine additional wells in 2014. 

On the Pinedale Anticline, our average daily net production decreased 14% to 4,096 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 are very strong and then decline quickly. The operator drilled the final well in this field in early 2014, and therefore we expect to see significant decreases as there is no new production to offset this decline.  The operator has shifted 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. At the Mesa “C” PA, we have an approximate 6% reversionary carried interest, and expect our production to increase once Mesa “C” is developed. 

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 9% to $828 for the three months ended September 30, 2014, due to the decrease in Catalina production volumes as compared to the prior year period.

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Price risk management activities

We recorded a net gain on our derivative contracts of $1,633. This consisted of an unrealized non-cash gain of $175, which represents the change in the fair value of our commodity derivatives at September 30, 2014 based on the expected future prices of the related commodities, and a net realized gain of $1,458 related to the cash settlement of our economic hedges.  The net realized gain includes $1,343 settlement to close-out our commodity contracts position with the lender on our previous credit facility. 

 

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

 

 

Well production costs increased 5%  to $3,296 and production costs on a per Mcfe basis increased 18% or  $0.25, to $1.64. 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 1% to $898 for the three months ended September 30, 2014 and production taxes, on a per Mcfe basis, also increased $0.06 to $0.45 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 commodity market prices.  

Total depreciation, depletion and amortization expenses (“DD&A”) decreased 4% to $4,946, and depletion and amortization related to producing assets decreased 4% to $4,871. Expressed on a per Mcfe basis, depletion and amortization related to producing assets increased 8%, or $0.18, to $2.43. The increase in DD&A on a per Mcfe basis was the result of a higher depletion rate at the Catalina and Spyglass Hill Units due to a decrease in our reserves, which were estimated to be lower in our 2013 year-end reserve report as a result revisions to the economic lives of these major fields.

Pipeline operating costs 

Pipeline operating costs decreased 23% to $958.  Power charges were lower during the three months ended September 30, 2014 due to a refund of certain exempt sales taxes. 

 

 

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Impairment and abandonment of equipment and properties

We recorded impairment and abandonment expense in the three months ended September 30, 2014 of $355, primarily related to the write-off of expiring undeveloped acreage in Wyoming.

General and administrative expenses

General and administrative expenses increased 55% to $1,522, primarily due to a $155 increase in salary and salary-related costs due to the establishment of our Houston office and the appointment of two new officers.  In addition, stock-based compensation increased $166 as the 2013 expense was net of a forfeiture of LTIP shares due to the resignation of our former chief financial officer. We also had a $60 increase in legal expenses.  

Income taxes

We recorded an income tax benefit of $42 for the three months ended September 30, 2014. Our effective tax rate (“ETR”) was 8.35%, 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. 

Nine Months Ended September 30, 2014 Compared to the Nine Months Ended September 30, 2013

The following analysis provides comparison of the nine months ended September 30, 2014 and the nine months ended September 30, 2013.

Natural gas and oil sales

Natural gas and oil sales increased 16% to $27,436, which was attributed to a 26% increase in the CIG market price, partially offset by an 8% decrease in production volumes.

As shown in the table below, our average realized natural gas price increased 1% to $3.89 per Mcf. 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 $(1,360) and $4,563 for the nine months ended September 30, 2014 and 2013, respectively. The 2014 net realized gain on commodity contracts considered in the average realized price calculation excluded the $1,343 gain realized on the settlement of our commodity contracts with the lender on our previous credit facility. 

 

 

Our total net production decreased 8% to 6.4 Bcfe due primarily to lower production from our non-operated properties in the Pinedale Anticline.

Our total average daily net production at the Atlantic Rim decreased 5% to 17,838 Mcfe due to decreased production in the Spyglass Hill Unit. Average daily net production at the Catalina Unit decreased 3% to 12,936 Mcfe. During the third quarter 2014, we experienced a power outage and equipment interruption due to a lightning strike and as a result certain wells were briefly shut-in.  CBM wells are highly sensitive to water build-up when shut-in, even for short periods of time. We are currently in the process of dewatering these wells and expect normal production to resume by the end of the first quarter of 2015. We also realized a decrease due to the normal field production decline. The decrease was slightly offset by higher production volumes in the first half of 2014 as a result of our 2013 workover program. 

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Average daily production, net to our interest, at the Spyglass Hill Unit decreased 10% to 4,902 Mcfe. Although the operator drilled 50 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.

On the Pinedale Anticline, our average daily net production decreased 22% to 4,030 Mcfe as a result of normal production decline, which is no longer offset by initial production of 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 this field in early 2014, and therefore we expect to see significant decreases as there is no new production to offset this decline.  The operator has shifted 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 decreased  1% to $2,732 for the nine months ended September 30, 2014, due to the decrease in Catalina production volumes.

Price risk management activities

We recorded a net loss on our derivative contracts of $1,634. This consisted of an unrealized non-cash loss of $1,617, which represents the change in the fair value of our commodity derivatives at September 30, 2014 based on the expected future prices of the related commodities, and a net realized loss of $17 related to the cash settlement of our economic hedges. The net realized loss was net of a $1,343 gain on the settlement of our commodity contracts position with the prior lender on previous credit facility. 

 

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

 

Well production costs increased 5% to $9,768 and production costs on a per Mcfe basis increased 13%, or $0.18, to $1.53. The overall increase in production costs was driven by a $600 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. In addition, we had higher production costs at the Catalina Unit as a result of an equipment outage due to a lightning strike in the third quarter of 2014.  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 14% to $3,262 for the nine months ended September 30, 2014 and production taxes, on a per Mcfe basis, increased $0.10 to $0.51 per Mcfe. We are required to pay taxes on the revenue generated upon the physical

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sale of our gas to counterparties. Production taxes were higher both in total and on a per Mcfe basis primarily due to the 26%  increase in the average market prices for natural gas.

Total DD&A decreased 3% to $15,135, and depletion and amortization related to producing assets decreased 3% to $14,866. Expressed on a per Mcfe basis, depletion and amortization related to producing assets increased 5%, or $0.12, to $2.33. 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 2013 year-end reserve report as a result revisions to the economic lives of the major fields.

Pipeline operating costs 

Pipeline operating costs decreased 17% to $3,268.  Power charges were lower during the nine months ended September 30, 2014 primarily due to a refund of certain exempt sales taxes. 

Impairment and abandonment of equipment and properties

We recorded impairment and abandonment expense in the nine months ended September 30, 2014 of $1,435, 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 $602 due to the write-off of expiring undeveloped acreage in Wyoming and Nebraska.

In 2013, we recorded impairment expense of $1,500, of which $1,379 related to the exploration well completed in the first quarter of 2013.

General and administrative expenses

General and administrative expenses increased 34% to $5,292, 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 expenses of $330, and an increase in salary and salary-related expenses of $106 due to an increase in headcount related to the establishment of our Houston office and the appointment of two additional Company officers.  

Income taxes

We recorded an income tax benefit of $911 for the nine months ended September 30, 2014. Our ETR was 8.4%, 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.

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.

Effective August 29, 2014, we replaced our existing credit facility with a new $250,000 credit agreement with Societe Generale.  Under the new agreement, our borrowing base was increased to $50,000.   As of September 30, 2014, the Company had $45,015 outstanding on the facility, which matures August 28, 2017.   

In March 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.

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We currently expect that the remaining availability on our credit facility of $4,985, coupled with our expected cash flow from operations will be sufficient to meet future financial covenants, maintain our current facilities, and complete our 2014 capital expenditure program.  Under our credit facility, we are subject to semi-annual borrowing base redeterminations and are currently in the process of completing our initial mid-year redetermination with our new lender. 

Our future success in growing proved reserves and production will be highly dependent on the capital resources available to us, natural gas prices and our success in finding or acquiring additional reserves. To grow our proved reserves, we will most likely need to issue equity or debt through public offerings, private placements or obtain additional debt financing, which may be secured by our oil and gas properties, or unsecured. The timing, structure, terms, size, and pricing of any such financing or transaction will depend on investor interest and market conditions. We can provide no assurance that we will be able to do so on favorable terms or at all. The Company currently has an effective Form S-3 shelf registration statement on file with the SEC, which contemplates up to $200,000 of securities available for issuance and provides us the ability to raise additional funds through registered offerings of equity, debt or other securities. Depending on the type of offering, amounts raised utilizing our S-3 may be limited as a percentage of the amount of our common equity held by non-affiliates. 

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

 

 

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Our working capital balance increased to $2,155 at September 30,  2014 as compared to $1,704 at December 31, 2013, which was primarily the result of the receipt of $4,158 of the private placement net proceeds received in March 2014, as well as cash proceeds of $1,028 received from the close-out of the hedge positions held with our former lender in August 2014.  This was offset by a $1,116 increase in current liabilities due to the change in the fair value of our outstanding commodity derivatives at September 30, 2014, a $2,174 increase in accounts payable and accrued expenses primarily due to increased drilling activity at the Spyglass Hill Unit, and a $1,282 increase in accrued production taxes due to the timing of when we make our annual ad valorem payments.   

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Cash flow activities

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

 

During the nine months ended September 30, 2014, net cash provided by operating activities was $9,554, as compared to $10,283 in the same prior-year period. The cash we generated in the nine months ended September 30, 2014 resulted from a net loss of $(9,989), which was net of non-cash charges of $15,320 related to DD&A and accretion expense, a $1,305 unrealized net loss related to the change in fair value of our derivative contracts and $1,435 of impairment expense. During the nine months ended September 30, 2014, we spent $344 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 nine months ended September 30, 2014, our income before income taxes and cash flow would have increased by approximately $462 for each $0.50 change per Mcf in natural gas prices. As noted previously, we closed-out our commodity and interest rate swap positions with the lender on our previous credit facility in the third quarter of 2014, for cash proceeds of $1,028, which is included in cash flow from operations for the 2014 period.   As required by our new credit facility, we also entered into new commodity hedge contracts at the onset of the new credit agreement at less favorable prices than the closed-out contracts.  As a result, cash flow generated from our hedges throughout the remainder of 2014 and 2015 is expected to be lower. 

During the nine months ended September 30, 2014, net cash used in investing activities was $3,119, as compared to $7,736 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. We also advanced $871 for the GTL project.  As discussed previously, if a definitive agreement is not reached with WYGTL, WYGTL will reimburse the Company for any portion of the $2,000 funded to EGTL, and EGTL will assign all rights back to WYGTL. In the first nine months of 2013, our spending primarily related to the completion of our Niobrara exploration well and non-operated drilling in the Pinedale Anticline.

Cash used by financing activities was $2,008 for the nine months ended September 30, 2014, as compared to cash used in financing activities of $2,813 for the nine months ended September 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. As discussed above, we replaced our previous credit facility we a new credit agreement with Societe Generale in August 2014.  The cash flow generated from our private placement transaction, was partially offset by a $2,435 net repayment of our outstanding debt during the first nine months of 2014.  We paid loans costs of $895 in connection with our new credit facility.  We also paid cash dividends on our Series A Preferred Stock, totaling $2,792 in each period.

Credit Facility

Our credit facility is collateralized by our natural gas and oil producing properties and other assets. At September 30, 2014, we had $45,015 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

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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 new credit facility bear 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 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. 

The average interest rate on the facility at September 30, 2014 was 3.1%. We are subject to an assessment of our borrowing base semi-annually on April 1 and October 1.

We are subject to a variety of financial and non-financial covenants under this facility. As of September 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.

Capital Requirements 

We had originally budgeted approximately $6,000 for our capital projects in 2014, primarily for participation in 32 new wells in the Spyglass Hill Unit (reduced form 47 in the operator’s initial drilling plans for 2014).  The operator has drilled and completed 23 of its planned wells in the Spyglass Hill Unit, and we expect to participate in nine additional wells planned in the fourth quarter of 2014.  We are also in the process of replacing certain compressor equipment at the Catalina Unit, which we expect to result in lower future operating costs. Due to the aforementioned revision, we expect our 2014 capital expenditures to be approximately $4.5 million.  We have incurred approximately $3,800 related to capital projects in the first nine months of 2014. 

We also have committed 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.    The agreement will terminate on November 26, 2014 if a definitive agreement between the Company and WYGTL has not been completed.  We are in the process of negotiating an extension on the letter agreement to January 31, 2015. If an agreement is not reached, WYGTL will reimburse the Company for any portion of the $2,000 funded to EGTL, and EGTL will assign all rights back to WYGTL. We had advanced approximately $871 through September 30, 2014. 

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.

 

 

 

 

 

 

 

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Our outstanding derivative instruments as of September 30, 2014 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.

 

 

 

 

 

 

 

 

 

 

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/A 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.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information under this Item.

ITEM 4.CONTROLS AND PROCEDURES

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

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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 September 30, 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.