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ESCALERA RESOURCES CO. - 10-Q - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

August 14, 2014

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

FORWARD-LOOKING STATEMENTS



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

A decline in natural gas prices;

Our ability to increase our natural gas and oil reserves;

Our ability to obtain, or a decline in, oil or gas production;

Our future capital requirements and availability of capital resources to fund

capital expenditures;

The changing political and regulatory environment in which we operate;

The actions of third party co-owners of interests in properties in which we

also own an interest, and in particular those which we do not operate or

control;

Our ability to maintain adequate liquidity in connection with current natural

gas prices;

The shortage or high cost of equipment, qualified personnel and other oil

field services;

General economic conditions, tax rates or policies, interest rates and

inflation rates;

Incorrect estimates of required capital expenditures;

The amount and timing of capital deployment in new investment opportunities;

Changes in or compliance with laws and regulations, particularly those

relating to drilling, derivatives, and safety and protection of the environment such as initiatives related to drilling and well completion techniques including hydraulic fracturing;



The volumes of production from our natural gas and oil development

properties, which may be dependent upon issuance by federal and state governments, or agencies thereof, of drilling, environmental and other permits;



Our ability to market and find reliable and economic transportation for our gas;

Our ability to successfully identify, execute, integrate and profitably

operate any future acquisitions;

Industry and market changes, including the impact of consolidations and

changes in competition;

Our ability to manage the risk associated with operating in one major

geographic area;

Weather, changes in climate conditions and other natural phenomena;

Our ability and the ability of our partners to continue to develop the

Atlantic Rim project;

The credit worthiness of third parties with which we enter into hedging and

business agreements;

Our ability to interpret 2-D and 3-D seismic data;

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Numerous uncertainties inherent in estimating quantities of proved natural

gas and oil reserves and actual future production rates and associated costs;

The volatility of our stock price; and

The outcome of any future litigation or similar disputes and the impact on

any such outcome or related settlements.

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

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

Company Overview

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

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

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

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

Recent Developments

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

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

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

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

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

RESULTS OF OPERATIONS

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

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

Natural gas and oil sales

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

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

Three Months Ended June 30, 2014 2013 Percent Percent Average Average Volume Price Product: Volume Price Volume Price Change Change Gas (Mcf) 2,110,207 $ 3.87 2,220,819 $ 3.98 -5 % -3 % Oil (Bbls) 6,795 $ 91.92 7,830 $ 88.10 -13 % 4 % Mcfe 2,150,977 $ 4.09 2,267,799 $ 4.21 -5 % -3 %



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

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

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

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

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

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Transportation and gathering revenue

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

Price risk management activities

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

Natural gas and oil production costs, production taxes, depreciation, depletion and amortization Three Months Ended June 30, 2014 2013 (in dollars per Mcfe) Average price $ 4.09$ 4.21 Production costs 1.48 1.45 Production taxes 0.53 0.45 Depletion and amortization 2.20 2.26 Total operating costs 4.21 4.16 Gross margin $ (0.12 )$ 0.05 Gross margin percentage -3 % 1 %



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

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

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

Impairment and abandonment of equipment and properties

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

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

General and administrative expenses

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

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Income taxes

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

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

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

Natural gas and oil sales



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

The calculation of the average realized price in the table below includes realized gain (loss) on our commodity derivatives, which is included within price risk management activities, net on the consolidated statements of operations, totaling $(1,475) and $2,906 for the six months ended June 30, 2014 and 2013, respectively. Six Months Ended June 30, 2014 2013 Percent Percent Average Average Volume Price Product: Volume Price Volume Price Change Change Gas (Mcf) 4,289,650 $ 4.02 4,586,187 $ 3.86 -6 % 4 % Oil (Bbls) 13,155 $ 89.64 13,775 $ 89.27 -5 % 0 % Mcfe 4,368,580 $ 4.21 4,668,837 $ 4.06 -6 % 4 %



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

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

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

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

Transportation and gathering revenue

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

Price risk management activities

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

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Natural gas and oil production costs, production taxes, depreciation, depletion and amortization Six Months Ended June 30, 2014 2013 (in dollars per Mcfe) Average price $ 4.21 $ 4.06 Production costs 1.48 1.33 Production taxes 0.54 0.42 Depletion and amortization 2.29 2.20 Total operating costs 4.31 3.95 Gross margin $ (0.10 )$ 0.11 Gross margin percentage -2 % 3 %



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

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

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

Impairment and abandonment of equipment and properties

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

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

General and administrative expenses

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

Income taxes

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

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OVERVIEW OF FINANCIAL CONDITION AND LIQUIDITY

Liquidity and Capital Resources

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

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

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

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

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

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


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