1.Business Description and Summary of Significant Accounting Policies

Description of Operations

Escalera Resources Co. (“Escalera Resources” or the “Company”), formerly named Double Eagle Petroleum Co., is an independent energy company engaged in the exploration, development, production and sale of natural gas and oil, primarily in the Rocky Mountain basins of the western United States. Escalera Resources was incorporated in the State of Wyoming in January 1972 and reincorporated in the State of Maryland in February 2001.

Going Concern

The accompanying consolidated financial statements have been prepared on a going concern basis. The Company has reported net operating losses for the past three years, which may impact the Company’s access to capital. There is also uncertainty regarding both the outcome of the Company’s borrowing base redetermination during the second quarter of 2015 as a result of the recent decrease in commodity prices, as well as the Company’s ability to obtain additional financing. These factors raise substantial doubt about the Company’s ability to continue as a going concern. The accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of recorded asset amounts or amounts of liabilities that might result from the outcome of this uncertainty.

The Company is currently looking for potential merger candidates which may offer improved opportunities to obtain capital to develop its natural gas and oil properties, acquire natural gas properties and to cure any borrowing base deficiencies that result from the next borrowing base redetermination. The Company is also focused on maintaining production while efficiently managing, and in some cases reducing, its operating and general and administrative expenses. Additionally, the Company is also evaluating asset divestiture opportunities to provide capital to reduce its indebtedness.

Principles of Consolidation and Basis of Presentation

The consolidated financial statements include the accounts of the Company and its wholly-owned operating subsidiaries, Petrosearch Energy Corporation and Eastern Washakie Midstream Pipeline 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. This fee is eliminated in consolidation.

The Company has no interests in any unconsolidated entities, nor does it have any unconsolidated special purpose entities.

Certain reclassifications have been made to amounts reported in previous years to conform to the 2014 presentation. Such reclassifications had no effect on net income.

Cash and Cash Equivalents

Cash and cash equivalents consist of all cash balances and any highly liquid investments with an original maturity of 90 days or less. The carrying amount approximates fair value due to the short maturity of these instruments.

Cash Held in Escrow

The Company has received deposits representing partial prepayments of the expected capital expenditures from third party working interest owners in the Table Top Unit #1 exploration project. The unexpended portion of the deposits at December 31, 2014 and 2013 totaled $283.

Accounts Receivable

The Company records estimated oil and gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners in accounts receivable. Management periodically reviews accounts receivable amounts for collectability and records its allowance for uncollectible receivables under the specific identification method. The Company did not record any allowance for uncollectible receivables in 2014, 2013 or 2012.

Revenue Recognition and Gas Balancing

The Company recognizes oil and gas revenues for its ownership percentage of total production under the entitlement method, whereby the working interest owner records revenue based on its share of entitled production, regardless of whether the Company has taken its ownership share of such volumes. An over-produced owner would record the excess of the amount taken over its entitled share as a reduction in revenues and a payable while the under-produced owner records revenue and a receivable for the imbalance amount. The Company’s imbalance position with various third party operators at December 31, 2014 resulted in an imbalance receivable of 115 MMcf, or $334, which is included in accounts receivable, net, on the consolidated balance sheet, and an imbalance payable of 256 MMcf, or $966, which is included in accounts payable and accrued expenses on the consolidated balance sheet.

Oil and Gas Producing Activities

The Company uses the successful efforts method of accounting for its oil and gas producing activities. Under this method of accounting, all property acquisition costs and costs of exploration and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not establish proved reserves in sufficient quantities to render the well economic, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive. The Company limits the total amount of unamortized capitalized costs for each property to the value of future net revenues, based on expected future prices and costs.

Geological and geophysical costs and the costs of carrying and retaining unproved leaseholds are expensed as incurred. Costs of production and general corporate activities are expensed in the period incurred.

Depreciation, depletion and amortization (“DD&A”) of capitalized costs for producing oil and gas properties is calculated on a field-by-field basis using the units-of-production method, based on proved oil and gas reserves. DD&A takes into consideration restoration, dismantlement and abandonment costs, net of any anticipated proceeds for equipment salvage. The Company has historically based the fourth quarter depletion calculation on the respective year-end reserve report and used this methodology in computing the fourth quarter 2014 depletion expense.

DD&A of oil and gas properties for the years ended December 31, 2014, 2013 and 2012 was $19,063, $20,560 and $19,828, respectively.

The Company invests in unevaluated oil and gas properties for the purpose of future exploration and development of proved reserves. The costs of unproved leases which become productive are reclassified to proved properties when proved reserves are discovered on the property. Unproved oil and gas interests are carried at the lower of cost or estimated fair market value and are not subject to amortization.

The following table reflects the net changes in capitalized exploratory well costs during the years ended December 31, 2014, 2013 and 2012. Amounts do not include costs capitalized and subsequently expensed in the same annual period.


	2014		2013		2012
Beginning balance at January 1,	$	-	$	-	$	4,170
Additions to capitalized exploratory well costs pending the determination of proved reserves		-		-		6,650
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		-		-		(6,390)
Capitalized exploratory well costs charged to expense		-		-		(4,430)
Ending balance at December 31,	$	-	$	-	$	-

Asset Retirement Obligations

Legal obligations associated with the retirement of long-lived assets result from the acquisition, construction, development and normal use of the asset. The Company’s asset retirement obligations relate primarily to the dismantlement, removal, site reclamation and similar activities associated with its oil and natural gas properties and related production facilities, lines and other equipment used in the field operations.

The initial estimated retirement obligation of properties is recognized as a liability with an associated increase in oil and gas properties for the asset retirement cost, and then depleted over the life of the asset. The Company utilizes the income valuation technique to determine the fair value of the liability at the point of inception by taking into account (1) the cost of abandoning oil and gas wells, which is based on the Company’s historical experience for similar work, or estimates from independent third-parties; (2) the economic lives of its properties, which is based on estimates from reserve engineers; (3) the inflation rate; and (4) the credit adjusted risk-free rate, which takes into account the Company’s credit risk and the time value of money. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. The liability is periodically adjusted to reflect (1) new liabilities incurred; (2) liabilities settled during the period; (3) accretion expense and (4) revisions to estimated future cash flow requirements. For the years ended December 31, 2014, 2013 and 2012, an expense of $254, $276 and $188, respectively, was recorded as accretion expense on the liability and included in production costs on the consolidated statement of operations. In addition, the Company recognized a gain of $80 in 2014, related to the settlement of our asset retirement obligation at a Texas property.

Impairment of Long-Lived Assets

The long-lived assets of the Company consist primarily of proved oil and gas properties and undeveloped leaseholds. The Company reviews the carrying values of its oil and gas properties and undeveloped leaseholds 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. The impairment analysis performed by the Company may utilize Level 3 inputs.

The Company recorded proved property impairment expense of $758, $4,962 and $4,901 for the years ended December 31, 2014, 2013 and 2012, 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 these wells. The impairment expense in 2013 and 2012, primarily related to the Company’s Niobrara exploration well.

The Company recognized a non-cash charge on undeveloped leaseholds during the years ended December 31, 2014, 2013 and 2012 of $950, $30 and $87, respectively. In 2014, the Company wrote- off non-producing leases in Nebraska and Wyoming, which expire in 2015, as there is no plan to develop this acreage.

Gas Transportation Pipeline

Depreciation on the Company’s pipeline facilities is calculated using the straight-line method over a 25 year estimated useful life, and totaled $221 for each of the years ended December 31, 2014 and 2013. The useful life may be limited to the useful life of current and future recoverable reserves serviced by the pipeline. The Company evaluated the expected useful life of the pipeline assets as of December 31, 2014, and determined that the assets are expected to be utilized for at least the estimated useful life used in the depreciation calculation.

Corporate and Other Assets

Office facilities, equipment and vehicles are recorded at cost. Depreciation is recorded using the straight-line method over the estimated useful lives of 10 years for office facilities, 3 to 10 years for office equipment, and 5 years for vehicles. The Company sold its Casper office building in July 2014, which resulted in a gain of $77. Depreciation expense for the years ended December 31, 2014, 2013 and 2012 was $135, $161 and $167, respectively.

Industry Segment and Geographic Information

The Company operates in one industry segment, which is the exploration, development, production and sale of natural gas and oil. All of the Company’s operations are conducted in the continental United States. Consequently, the Company currently reports as a single industry segment. The services performed by the Company’s transportation and gathering subsidiary relate solely to production from the Catalina Unit. Segmentation of such net income would not provide a better understanding of the Company’s performance, and is not viewed by management as a discrete reporting segment. However, gross revenue and expense related to the transportation and gathering subsidiary are presented as separate line items in the accompanying consolidated statement of operations.

Debt issuance costs

Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method. Debt issuance costs of $822 and $209 were included in other assets on the consolidated balance sheets as of December 31, 2014 and 2013, respectively.

Income Taxes

Deferred income tax assets and liabilities are recognized for the future income tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective income tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income (loss) in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred income tax assets and liabilities of a change in income tax rates is recognized in income in the period that includes the enactment date. The measurement of deferred income tax assets is reduced, if necessary, by a valuation allowance if management believes that it is more likely than not that some portion or all of the net deferred tax assets will not be fully realized on future income tax returns. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income and tax planning strategies in making this assessment. The Company has recorded a valuation allowance of $1,202 against certain deferred tax assets as of December 31, 2014.

Earnings per Share

Basic earnings per share (“EPS”) is calculated by dividing net income (loss) attributable to common stock by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share incorporates the treasury stock method to measure the dilutive impact of potential common stock equivalents by including the effect of outstanding vested and unvested stock options and unvested stock awards in the average number of common shares 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. The Company declared and paid cash dividends of $3,723 ($.5781 per share of preferred stock) for each of the years ended December 31, 2014, 2013 and 2012.

The following table shows the calculation of basic and diluted weighted average shares outstanding and EPS for the periods indicated:


	For the year ended December 31,
	2014		2013		2012
Net loss	$	(7,585)	$	(13,073)	$	(10,327)
Preferred stock dividends		(3,723)		(3,723)		(3,723)
Loss attributable to common stock	$	(11,308)	$	(16,796)	$	(14,050)
Weighted average shares:
Weighted average shares - basic		13,603,904		11,332,129		11,250,513
Dilutive effect of stock options outstanding at the end of period		-		-		-
Weighted average shares - fully diluted		13,603,904		11,332,129		11,250,513

Net loss per share:
Basic and diluted	$	(0.83)	$	(1.48)	$	(1.25)

The following options and stock awards that could be potentially dilutive in future periods were not included in the computation of diluted net loss per share because the effect would have been anti-dilutive for the periods indicated:


	For the year ended December 31,
	2014	2013	2012

Anti-dilutive stock options and unvested stock awards	125,643	28,612	58,704

Stock-Based Compensation

The Company measures and recognizes compensation expense for all stock-based payment awards (including stock options and stock awards) made to employees and directors based on estimated fair value. Compensation expense for equity-classified awards is measured at the grant date based on the fair value of the award and is recognized as an expense in earnings over the requisite service period using a graded vesting method. Certain awards contain a performance condition and market condition, which are taken into account in estimating fair value.

Derivative Financial Instruments

The Company uses derivative instruments, primarily swaps and collars, to hedge risk associated with fluctuating commodity prices. The Company accounts for its derivatives instruments as mark-to-market instruments, which are recorded at fair value and included in the consolidated balance sheets as assets or liabilities with changes in fair value recorded in earnings. See Notes 4 and 6 for additional discussion of derivative activities.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities and disclosure on contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates of oil and gas reserve quantities provide the basis for calculation of depletion, depreciation, and amortization, and impairment, each of which represents a significant component of the consolidated financial statements.

Recently Issued 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. Until issuance of this pronouncement, the requirement to perform a going concern evaluation existed only in auditing standards. 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.

In April 2015, the FASB issued ASU No. 2015-03, Simplifying the Presentation of Debt Issuance Costs (“ASU No. 2015-03”) to simplify the presentation of debit issuance costs. Debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. ASU No. 2015-03 becomes effective for fiscal years beginning after December 15, 2015, and for interim reporting periods within those fiscal years. The Company plans to adopt ASU No 2015-03 for its Report on Form 10-Q for the quarter ended March 31, 2016. The adoption of ASC Update 2015-03 will affect the Company’s balance sheet presentation only, and will have no impact on the Company’s financial position, results of operations or cash flows.