Escalera Resources (ESCR) 10-Q 2014 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2014

or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-33571

ESCALERA RESOURCES CO.

(Exact name of registrant as specified in its charter)

MARYLAND	83-0214692
(State or other jurisdiction of incorporation or organization)	(I.R.S. employer identification no.)
1675 Broadway, Suite 2200, Denver, Colorado	80202
(Address of principal executive offices)	(Zip code)

303-794-8445

(Registrant’s telephone number, including area code)

Double Eagle Petroleum Co.

(Former name)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	¨	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	x

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

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

Class	Shares outstanding as of May 8, 2014
Common stock, $.10 par value	14,083,724

ESCALERA RESOURCES CO.

FORM 10-Q

TABLE OF CONTENTS

		Page #
PART I. Financial Information:
	Item 1. Financial Statements	3
	Consolidated Balance Sheets as of March 31, 2014 (unaudited) and December 31, 2013	3
	Consolidated Statements of Operations for the Three Months Ended March 31, 2014  and 2013 (Unaudited)	4
	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2014  and 2013 (Unaudited)	5
	Notes to Consolidated Financial Statements (Unaudited)	6
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	14
	Item 4. Controls and Procedures	21
PART II. Other Information:
	Item 1. Legal Proceedings	22
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	22
	Item 6. Exhibits	23
Signatures

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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)

ASSETS	March 31, 2014 (unaudited)			December 31, 2013
Current assets:
Cash and cash equivalents	$	6,666		$	2,799
Cash held in escrow		283			283
Accounts receivable, net		6,068			5,111
Assets from price risk management		—			205
Other current assets		3,256			3,130
Total current assets		16,273			11,528
Oil and gas properties and equipment, successful efforts method:
Developed properties		238,330			238,332
Wells in progress		2,061			2,342
Gas transportation pipeline		5,510			5,510
Undeveloped properties		2,705			2,705
Corporate and other assets		2,041			2,041
		250,647			250,930
Less accumulated depreciation, depletion and amortization		(135,768	)		(130,518	)
Net properties and equipment		114,879			120,412
Assets from price risk management		694			402
Other assets		58			58
TOTAL ASSETS	$	131,904		$	132,400
LIABILITIES, PREFERRED STOCK AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	8,002		$	7,327
Liabilities from price risk management		1,626			—
Accrued production taxes		3,058			2,275
Other current liabilities		231			222
Total current liabilities		12,917			9,824
Credit facility		47,950			47,450
Asset retirement obligation		8,168			8,420
Liabilities from price risk management		133			97
Deferred tax liability		657			1,236
Other long-term liabilities		44			90
Total liabilities		69,869			67,117
Preferred stock, $0.10 par value; 10,000,000 shares authorized; 1,610,000 shares issued    and outstanding as of March 31, 2014 and December 31, 2013		37,972			37,972
Stockholders' equity:
Common stock, $0.10 par value; 50,000,000 shares authorized; issued 12,228,769 and 12,143,942 outstanding at March 31, 2014 and 11,517,261 issued and 11,452,473 outstanding at December 31, 2013		1,214			1,145
Common stock, to be issued $.10 par value; 2,018,826 shares		202			—
Additional paid-in capital		45,419			42,302
Subscriptions receivable		(2,250	)		—
Accumulated deficit		(20,522	)		(16,136	)
Total stockholders' equity		24,063			27,311
TOTAL LIABILITIES, PREFERRED STOCK AND STOCKHOLDERS' EQUITY	$	131,904		$	132,400

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

3

ESCALERA RESOURCES CO.

CONSOLIDATED STATEMENTS OF OPERATIONS

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

(Unaudited)

	Three Months Ended March, 31,
	2014			2013
Revenues
Oil and gas sales	$	10,566		$	7,533
Transportation and gathering revenue		964			979
Price risk management activities		(2,516	)		(2,804	)
Other income		139			5
Total revenues		9,153			5,713
Costs and expenses
Production costs		3,298			2,908
Production taxes		1,234			942
Exploration expenses including dry hole costs		34			24
Pipeline operating costs		1,195			1,514
Impairment and abandonment of equipment and properties		675			1,064
General and administrative		2,082			1,616
Depreciation, depletion and amortization		5,250			5,222
Total costs and expenses		13,768			13,290
Loss from operations		(4,615	)		(7,577	)
Interest expense, net		350			332
Loss before income taxes		(4,965	)		(7,909	)
Benefit for deferred income taxes		579			2,733
Net loss	$	(4,386	)	$	(5,176	)
Preferred stock dividends		931			931
Net loss attributable to common stock	$	(5,317	)	$	(6,107	)
Net loss per common share:
Basic	$	(0.45	)	$	(0.54	)
Diluted	$	(0.45	)	$	(0.54	)
Weighted average shares outstanding:
Basic		11,719,549			11,305,881
Diluted		11,719,549			11,305,881

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)

	Three Months Ended March 31,
	2014			2013
Cash flows from operating activities:
Net loss	$	(4,386	)	$	(5,176	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion of asset retirement obligation		5,312			5,283
Impairment and abandonment of equipment and properties		675			1,064
Gain on settlement of asset retirement obligation		(92	)		—
Settlement of asset retirement obligation		(239	)		—
Benefit for deferred income taxes		(579	)		(2,733	)
Change in fair value of derivative contracts		1,538			4,636
Stock-based compensation expense		205			282
Loss on sale of producing property		—			10
Changes in current assets and liabilities:
Decrease in deposit held in escrow		—			283
Decrease (increase) in accounts receivable		(957	)		1,285
Decrease (increase) in other current assets		(126	)		91
(Decrease) increase in accounts payable and accrued expenses		781			(2,710	)
Increase in accrued production taxes		783			422
NET CASH PROVIDED BY OPERATING ACTIVITIES		2,915			2,737
Cash flows from investing activities:
Payments to acquire and develop producing properties and equipment, net		(1,148	)		(2,137	)
Payments to acquire corporate and non-producing properties		—			(2	)
NET CASH USED IN INVESTING ACTIVITIES		(1,148	)		(2,139	)
Cash flows from financing activities:
Net proceeds from sale of common stock		2,575			—
Dividends paid on preferred stock		(931	)		(931	)
Net borrowings on credit facility		500			—
Tax withholdings related to net share settlement of restricted stock awards		(44	)		(17	)
NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES		2,100			(948	)
Change in cash and cash equivalents		3,867			(350	)
Cash and cash equivalents at beginning of period		2,799			4,070
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	6,666		$	3,720
Supplemental disclosure of cash and non-cash transactions:
Cash paid for interest	$	405		$	269
Interest capitalized	$	17		$	45
Additions to developed properties included in current liabilities	$	865		$	2,772
Common stock issuance costs, not yet paid	$	668		$	-

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.

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

Principles of consolidation

The unaudited interim consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, Petrosearch Energy Corporation and Eastern Washakie Midstream LLC (“EWM”). The Company has an agreement with EWM under which the Company pays a fee to EWM to gather, compress and transport gas produced at the Catalina Unit. This fee is also 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 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 attributable to common stock is calculated as net income less dividends paid on the Company’s Series A Preferred Stock. The Company declared and paid cash dividends of $931 ($0.5781 per share of preferred stock) for each of the three months ended March 31, 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:

	For the Three Months Ended March 31,
	2014			2013
Net loss	$	(4,386	)	$	(5,176	)
Preferred stock dividends		(931	)		(931	)
Loss attributable to common stock	$	(5,317	)	$	(6,107	)
Weighted average shares:
Weighted average shares - basic		11,719,549			11,305,881
Dilutive effect of stock options outstanding at the end of period		—			—
Weighted average shares - fully diluted		11,719,549			11,305,881
Net income (loss) per share:
Basic	$	(0.45	)	$	(0.54	)
Diluted	$	(0.45	)	$	(0.54	)

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

	For the Three Months Ended March 31,
	2014		2013
Potential common shares		26,731		36,185

3. Credit Facility

As of March 31, 2014, the Company had a $150,000 revolving line of credit in place with a $55,000 borrowing base. The credit facility is collateralized by the Company’s oil and gas producing properties. Any balance outstanding on the credit facility is due October 24, 2016.

As of March 31, 2014, the outstanding balance of $47,950 on the credit facility has been used to fund the development of the Catalina Unit and other non-operated projects in the Atlantic Rim, development projects in the Pinedale Anticline, and the Company’s Niobrara exploration project.

Borrowings under the revolving line of credit bear interest at a daily rate equal to (a) the highest of the Federal Funds rate for such day, plus 0.5%, the Prime Rate for such day or the One-Month Eurodollar Rate for such day plus (b) a margin ranging between 0.75% and 2.75% depending on the level of funds borrowed. The average interest rate on the facility at March 31, 2014, including the impact of our interest rate swaps, was 3.4%. For the three months ended March 31, 2014 and 2013, the Company incurred interest expense on the credit facility of $404 and $409, respectively. Of the total interest incurred, the Company capitalized interest costs of $17 and $45 for the three months ended March 31, 2014 and 2013, respectively.

Under the credit facility, the Company is subject to both financial and non-financial covenants. The financial covenants, as defined in the credit agreement, include maintaining (i) a current ratio of 1.0 to 1.0; (ii) a ratio of earnings before interest, taxes, depreciation, depletion, amortization, exploration and other non-cash items (“EBITDAX”) to interest plus dividends of greater than 1.5 to 1.0; and (iii) a funded debt to EBITDAX ratio of less than 3.5 to 1.0. As of March 31, 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.

On April 24, 2014, the Company’s credit facility agreement was amended to reduce its borrowing base to $48,500 with subsequent monthly borrowing base reductions of $1,000 on the first day of each month through the next borrowing base redetermination date of October 1, 2014 (at which time the borrowing base will be $42,500).   The first of such repayments was made on May 1, 2014.  

4. Derivative Instruments

Commodity Contracts

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

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

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

7

balance sheets, and changes in fair value are recognized in the price risk management activities line on the consolidated statements of operations. Realized gains and losses resulting from the contract settlement of derivatives are also recorded in the price risk management activities line on the consolidated statements of operations.

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

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

As with most derivative instruments, the Company’s derivative contracts contain provisions which may allow for another party to require security from the counterparty to ensure performance under the contract. The security may be in the form of, but not limited to, a letter of credit, security interest or a performance bond. As of March 31, 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 March 31, 2014:

Type of Contract	Remaining Contractual Volume (Mcf)		Term	Price			Price Index (1)
Fixed Price Swap		1,375,000	01/14-12/14	$	4.27		NYMEX
Costless Collar		1,350,000	01/14-12/14	$	4.00	floor	NYMEX
				$	4.50	ceiling
Fixed Price Swap		1,350,000	01/14-12/14	$	4.20		NYMEX
Fixed Price Swap		405,000	01/14-12/14	$	4.17		NYMEX
Fixed Price Swap		3,000,000	01/15-12/15	$	4.28		NYMEX
Fixed Price Swap		3,600,000	01/15-12/15	$	4.15		NYMEX
Fixed Price Swap		1,830,000	01/16-12/16	$	4.07		NYMEX
Total		12,910,000

(1) New York Mercantile Exchange (“NYMEX”).

In April 2014, the Company entered into an additional swap contract with a third party for 3,660,000 Mcf at $4.15 per Mcf for the period January 1, 2016 through December 31, 2016.  

Interest Rate Swap

As of March 31, 2014, the Company had the following interest rate swap in place with a third party to manage the risk associated with the floating interest rate on its credit facility:

Type of Contract	Contractual Amount		Term	Rate (LIBOR)			Effective InterestRate(1)
Interest Rate Swap	$	30,000	12/31/12-9/30/16		1.050	%		3.55	%

(1) In accordance with its credit facility, the Company pays interest at a daily rate equal to (a) the higher of the Federal Funds rate for such day, plus 0.5%, the Prime Rate for such day or the One-Month Eurodollar LIBOR rate for such day, plus (b) a spread ranging from 0.75% to 2.75% depending on its outstanding borrowings. The effective interest rate shown reflects the interest rate based on the outstanding borrowings at March 31, 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 March 31, 2014 presented gross of any master netting arrangements:

	Balance Sheet Location	As of March 31, 2014			As of December 31, 2013
Assets
Commodity derivatives	Assets from price risk management - current	$	—		$	218
	Assets from price risk management - long term		694			402
Total derivative assets		$	694		$	620
Liabilities
Commodity derivatives	Liabilities from price risk management - current	$	(1,626	)	$	(13	)
	Liabilities from price risk management -long term		(134	)		(97	)
Interest rate swap	Other current liabilities		(231	)		(222	)
	Other long term liabilities		(44	)		(90	)
Total derivative liabilities		$	(2,035	)	$	(422	)

The before-tax effect of derivative instruments not designated as hedging instruments on the consolidated statements of operations for the three months ended March 31, 2014 and 2013 was as follows:

	Three Months Ended March 31,
	2014			2013
Unrealized loss on commodity contracts (1)	$	(1,575	)	$	(4,673	)
Realized gain (loss) on commodity contracts (1)		(941	)		1,869
Unrealized gain on interest rate swap (2)		37			37
Realized loss on interest rate swap (2)		(67	)		(63	)
Total activity for derivatives not designated as hedging instruments	$	(2,546	)	$	(2,830	)

(1) Included in price risk management activities on the consolidated statements of operations. Price risk management activities totaled $(2,516) and $(2,804) for the three months ended March 31, 2014 and 2013, respectively.

(2) Included in interest expense, net on the consolidated statements of operations.

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

5. Fair Value of Financial Instruments

Assets and Liabilities Measured on a Recurring Basis

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

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

· Level 1—Quoted prices (unadjusted) for identical assets or liabilities in active markets.

· Level 2—Quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and model-derived valuations whose inputs or significant value drivers are observable.

· Level 3—Unobservable inputs that reflect the Company’s own assumptions.

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The following table provides a summary as of March 31, 2014 of assets and liabilities measured at fair value on a recurring basis:

	Fair Value Measurements for the three months ended March 31, 2014
	Level 1		Level 2		Level 3		Total
Assets
Derivative instruments - Commodity forward contracts	$	—	$	694	$	—	$	694
Total assets at fair value	$	—	$	694	$	—	$	694
Liabilities
Derivative instruments - Commodity forward contracts	$	—	$	1,759	$	—	$	1,759
Derivative instruments - Interest rate swap		—		275		—		275
Total liabilities at fair value	$	—	$	2,034	$	—	$	2,034
	Fair Value Measurements for the year ended December 31, 2013
	Level 1		Level 2		Level 3		Total
Assets
Derivative instruments - Commodity forward contracts	$	—	$	607	$	—	$	607
Total assets at fair value	$	—	$	607	$	—	$	607
Liabilities
Derivative instruments - Commodity forward contracts	$	—	$	97	$	—	$	97
Derivative instruments - Interest rate swap		—		312		—		312
Total liabilities at fair value	$	—	$	409	$	—	$	409

The Company did not have any transfers of assets or liabilities between Level 1, Level 2 or Level 3 of the fair value measurement hierarchy during the three months ended March 31, 2014.

Derivative instruments

The Company determines its estimate of the fair value 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 substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.

At March 31, 2014, the Company had various types of derivative instruments, which included costless collars and swaps. The natural gas derivative markets and interest rate swap markets are highly active. Although the Company’s economic hedges are valued using public indices, the instruments themselves are traded with third party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.

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

Credit facility

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

Concentration of credit risk

Financial instruments that potentially subject the Company to credit risk consist of accounts receivable and derivative financial instruments. Substantially all of the Company’s receivables are within the oil and gas 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,

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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 oil and gas properties and undeveloped leaseholds.

We recorded impairment and abandonment expense in the three months ended March 31, 2014 of $675, due to the write-off of a non-operated property in the Atlantic Rim.  Production from the wells at this property has been limited and the operator has indicated that it intends to plug and abandon wells in this area beginning in 2014.  The Company also wrote off $0 and $25 during the three months ended March 31, 2014 and 2013, respectively, related to expired undeveloped leaseholds and the write-off of other non-core assets.

7. Compensation Plans

The Company recognized stock-based compensation expense totaling $205 for the three months ended March 31, 2014, and $282 for the three months ended March 31, 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 March 31, 2014 and changes during the three months ended March 31, 2014 is presented below:

	Shares			Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term (in years)		Aggregate Intrinsic Value
Options:
Outstanding at January 1, 2014		276,854		$	11.19		2.7
Granted		152,808		$	2.32
Exercised		—
Cancelled/expired		(5,111	)	$	12.07
Outstanding at March 31, 2014		424,551		$	7.99		3.4	$	—
Exercisable at March 31, 2014		265,751		$	11.32		2.4	$	—

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 March 31, 2014 and changes during the three months ended March 31, 2014 were as follows:

	Shares			Weighted- Average Grant Date Fair Value
Outstanding at January 1, 2014		40,915		$	4.12
Granted		841,160		$	2.27
Vested		(78,596	)	$	2.80
Forfeited/returned		(144,877	)	$	2.31
Nonvested at March 31, 2014		658,602		$	2.32

On March 24, 2014, the Company’s board of directors granted long-term incentive shares to its chief executive officer, Charles F. Chambers, in conjunction with his appointment. The Compensation Committee of the board approved two restricted stock awards, under which the Company granted Mr. Chambers 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 Mr. Chambers 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 Mr. Chambers is continuously employed by the Company during such period and certain performance goals related to reserve growth and our stock price are achieved, as defined for purpose of the awards.  The Company’s stock-based compensation expense for the three months ended March 31, 2014 includes approximately $6 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 three months ended March 31, 2014 the Company used a ETR of 11.7%. The Company’s ETR for the three months ended March 31, 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 March 31, 2014, the Company made no provision for interest or penalties related to uncertain tax positions. The Company files income tax returns in the U.S. federal jurisdiction and various states. There are currently no federal or state income tax examinations of the Company underway for these jurisdictions. Furthermore, the Company is no longer subject to U.S. federal income tax examinations by the Internal Revenue Service for tax years before 2007 and for state and local tax authorities for tax years before 2006.

9. Equity

Preferred stock

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

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

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

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Private placement of common stock

On March 24, 2014, the Company accepted subscription agreements for a private offering of its common stock.  The gross proceeds from the private offering were $4,825, or $4,158 net of placement agent and legal fees.  The offering was effected through a private placement transaction with accredited investors. The Company plans to use the net proceeds of the private offering to fund working capital needs, capital expenditures, acquisitions of interests in oil and natural gas 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.  As of March 31, 2014, we had received $2,575 of the proceeds from such private placement transaction.  The remaining receivable is shown on the Consolidated Balance Sheets as subscription receivable as of March 31, 2014.

Three related parties to the Company purchased $775 of common stock through this private offering, including $350 by Mr. Chambers, prior to becoming the Company’s CEO..  

10. Contingencies

Legal proceedings

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

· 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;

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

· Our ability to increase our natural gas and oil reserves;

· Our future capital requirements and availability of capital resources to fund capital expenditures;

· Incorrect estimates of required capital expenditures;

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

· The changing political and regulatory environment in which we operate;

· 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 oil and gas 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 oil and gas 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 or mergers; (ii) investment in and enhancement of existing production wells and field facilities on operated and non-operated properties in the Atlantic Rim; (iii) continued participation in the development of tight sands gas wells at the Mesa Units on the Pinedale Anticline; and (iv) pursuit of high quality exploration and strategic development projects with potential for providing long-term drilling inventories that generate high returns.  We are also currently looking to develop an international presence.  

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 Pinedale Anticline and Atlantic Rim 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

On March 24, 2014, we accepted subscription agreements for a private offering of our common stock.  The gross proceeds of $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 plan to use the net proceeds of the private offering to fund working capital needs, capital expenditures, acquisitions of interests in oil and natural gas assets, and for general corporate purposes.   On April 7, 2014, we issued a total of 2,018,826 shares of common stock at a price of $2.39 per share to investors in the private placement transaction.  As of March 31, 2014, we had received $2,575 of the proceeds.  The remaining receivable of $2,250 is shown on the Consolidated Balance Sheets as subscription receivable as of March 31, 2014.  

In April 2014, we entered into a memorandum of understanding to form an energy joint venture (“JV”) in Albania. The JV would seek to identify and acquire upstream oil and gas drilling opportunities along with related facilities and infrastructure in Albania. Subject to the negotiation and execution of any JV agreement(s), we do not expect any significant initial capital investments in the JV.

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RESULTS OF OPERATIONS

Three Months Ended March 31, 2014 Compared to the Three Months Ended March 31, 2013

The following analysis provides comparison of the three months ended March 31, 2014 and the three months ended March 31, 2013.

Oil and gas sales

Oil and gas sales increased 40% to $10,566, which was largely attributed to a 51% 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 increased 11% to $4.16 per Mcf due to the increase in the CIG market price. Our realized natural gas price for the three months ended March 31, 2014 was lower than the prevailing market prices due to 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 oil and gas 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 $(941) and $1,869 for the three months ended March 31, 2014 and 2013, respectively.

	Three Months Ended March 31,
	2014				2013				Percent			Percent
Product:	Volume		Average Price		Volume		Average Price		Volume Change			Price Change
Gas (Mcf)		2,179,443	$	4.16		2,365,368	$	3.75		-8	%		11	%
Oil (Bbls)		6,360	$	87.20		5,945	$	90.80		7	%		-4	%
Mcfe		2,217,603	$	4.34		2,401,038	$	3.92		-8	%		11	%

Our total net production decreased 8% to 2.2 Bcfe for the three months ended March 31, 2014 primarily due to lower production from the Catalina Unit and from our non-operated properties on the Pinedale Anticline.

Our total average daily net production at the Atlantic Rim decreased 7% to 18,981 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 8% to 13,912 Mcfe, which was primarily the result of the fields natural decline curve.  We experienced a series of equipment challenges in late 2012 and early 2013, including a compressor failure and unscheduled maintenance on several injection pumps, which resulted in wells being off-line for periods of time.  CBM wells, by nature, produce significant amounts of water.  When wells are off-line, they have to be dewatered before production can recover.  Management believes the wells have recovered from these challenges.  We completed a well workover program in the third quarter of 2013, during which we fractured 12 existing wells to pursue hydrocarbons in the Almond formation. The wells fractured during this program are responding as expected and we realized a sequential quarter-over-quarter increase of 3% in the first quarter of 2014, as compared to the fourth quarter of 2013.

Average daily production, net to our interest, at the Spyglass Hill Unit decreased 2% to 5,069 Mcfe, due to operational challenges handling water production. The operator drilled 27 new wells in the Spyglass Hill Unit in 2013, and while these wells were completed and hooked up in the fourth quarter of 2013, these wells have not added significant production to date.  The operator has informed us that in 2014, they are working to increase injection capacity andenhance 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 set in the federal exploratory agreement governing the Spyglass Hill Unit through August 2015.

On the Pinedale Anticline, our average daily net production decreased 18% to 4,139 Mcfe due to normal production declines.  We are currently participating in the completion of one additional well in the Mesa “B” PA.  With the completion of this well, the Mesa “B” PA will be fully drilled and we expect the operator to shift its efforts to drilling and development of Mesa “A” PA and once fully drilled, onto the Mesa “C” PA.  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

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 2% to $964 for the three months ended March 31, 2014, due to the decrease in Catalina production volumes.  

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Price risk management activities

We recorded a net loss on our derivative contracts of $2,516.  This consisted of an unrealized non-cash loss of $1,575, which represents the change in the fair value of our commodity derivatives at March 31, 2014 based on the expected future prices of the related commodities, and a net realized loss of $941 related to the cash settlement of our economic hedges.

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

	Three Months Ended March 31,
	2014			2013
	(in dollars per Mcfe)
Average price	$	4.34		$	3.92
Production costs		1.49			1.21
Production taxes		0.56			0.39
Depletion and amortization		2.33			2.13
Total operating costs		4.38			3.73
Gross margin	$	(0.04	)	$	0.19
Gross margin percentage		-1	%		5	%

Well production costs increased 13% to $3,298 and production costs on a per Mcfe basisincreased 23%, or $0.28, to $1.49.  The overall increase in production costs was driven by a $426 increase in productioncosts at the Catalina Unit.  In 2013, the Company deferred certain maintenance activities at the Catalina Unit as it focused on an exploration project.  The production costs incurred at the Catalina Unit for the three month ended March 31, 2014 of $1.06 per Mcfe are comparable to average historical rates.  Production costs on a per Mcfe basis was higher due to the decrease in production volumes, as a portion of our production costs are fixed, or partially fixed.

Production taxes increased 31% to $1,234 for the three months ended March 31, 2014 and production taxes, on a per Mcfe basis, also increased $0.17 to $0.56 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 51% increase in the average market prices for natural gas.  

Total depreciation, depletion and amortization expenses (“DD&A”) increased 1% to $5,250, and depletion and amortization related to producing assets increased 1% to $5,158.  Expressed on a per Mcfe basis, depletion and amortization related to producing assets increased 9%, or $0.20, to $2.33.  Our depletion rate was higher 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 the lower production volumes in 2012 and 2013 due to operational challenges.

Impairment and abandonment of equipment and properties

We recorded impairment and abandonment expense in the three months ended March 31, 2014 of $675, 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.  

In 2013, we recorded impairment expense of $1,039 related to a Niobrara exploration well completed in the first quarter of 2013.  Although the well is currently producing gas from the Niobrara formation, we have been unable to establish oil production from the well.  We are awaiting a permit that will allow us to begin producing natural gas from the Dakota and Frontier formations, which is expected in the third quarter of 2014.

General and administrative expenses

General and administrative expenses increased 29% to $2,082, 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.  In the first quarter of 2014, we also reimbursed a consulting company owned by Mr. Chambers for $91 of expenses incurred for business development activities performed on behalf of the Company.  In addition, we had an increase in legal fees of $121, which were offset by a decrease in salary and salary-related expenses of $287 due to a reduction in headcount.Salary and salary-related expenses decreased primarily due to the departure of our former chief financial officer in August 2013 and our former chief operating officer in January 2014.  In addition, our stock-based compensation expense was lower in the first quarter of 2014 as there were no grants under a long-term incentive plan in place during most of the quarter.  

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Income taxes

We recorded an income tax benefit of $579 for the three months ended March 31, 2014.  Our effective tax rate (“ETR”) was 11.7%, 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.

At March 31, 2014, we had a $150,000 credit facility in place with a $55,000 borrowing base. We had $47,950 outstanding on our credit facility as of March 31, 2014. On April 24, 2014, our credit facility agreement was amended to reduce our borrowing base 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).   We made the first of such repayments on May 1, 2014.  

While management believes cash on hand and cash flow from operations will be sufficient to make the required repayments on our credit facility, meet our financial covenants, maintain our current facilities and complete our 2014 capital expenditure program, we do not believe the amended facility gives us the flexibility we need to further develop our business.  We are actively seeking a replacement credit facility and we have received a non-binding indicative terms and conditions sheet (“Term Sheet”) from an international financial institution which would provide for a credit facility up to $70,000, of which $55,000 would be fully committed. As the Term Sheet is non-binding, there can be no assurance that we will be able to obtain a new credit facility under the terms set forth in the Term Sheet, on other terms that are acceptable to us, or at all.  

On March 24, 2014, we accepted subscription agreements for a private offering of our common stock.  The gross proceeds of $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 plan to use the net proceeds of the private offering to fund working capital needs, capital expenditures, acquisitions of interests in oil and natural gas assets, and for general corporate purposes.   On April 7, 2014, we issued a total of 2,018,826 shares of common stock at a price of $2.39 per share to investors in the private placement transaction.  As of March 31, 2014, we had received $2,575 of the proceeds.  The remaining receivable of $2,250 is shown on the Consolidated Balance Sheets as subscription receivable as of March 31, 2014.  

Depending on the 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 oil and gas properties, or unsecured.

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

	March 31,			December 31,
	2014			2013
	(unaudited)
Financial Position Summary
Cash and cash equivalents	$	6,666		$	2,799
Working capital	$	3,356		$	1,704
Balance outstanding on credit facility	$	47,950		$	47,450
Stockholders’ equity and preferred stock	$	62,035		$	65,283
Ratios
Debt to total capital ratio(1)		43.6	%		42.1	%
Total debt to equity ratio		199.3	%		173.7	%

(1) Total capital includes our preferred stock, stockholder’s equity and the $47,950 and $47,450 outstanding on our credit facility at March 31, 2014 and December 31, 2013, respectively,

Our working capital balance increased to $3,356 at March 31, 2014 as compared to $1,704 at December 31, 2013.  The increase in working capital was due to the receipt of $2,575 of the private placement proceeds as of March 31, 2014.  Our working capital balance frequently fluctuates primarily due to the timing and amounts of capital expenditures and changes in fair value of the current portion of outstanding derivative contracts.  As a result of the increase in the future natural gas prices at March 31, 2014 as compared to December 31, 2013, all of our current outstanding hedges were in a liability position, which offset the increase in working capital from the private placement by $1,828.  

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Cash flow activities

The table below summarizes our cash flows for the three months ended March 31, 2014 and 2013, respectively:

	Three Months Ended March 31,
	2014			2013
Cash provided by (used in):
Operating activities	$	2,915		$	2,737
Investing activities		(1,148	)		(2,139	)
Financing activities		2,100			(948	)
Net change in cash	$	3,867		$	(350	)

During the three months ended March 31, 2014, net cash provided by operating activities was $2,915, as compared to $2,737 in the same prior-year period. The primary sources of cash during the quarter ended March 31, 2014 was a net loss of $(4,386), which was net of non-cash charges of $5,312 related to DD&A and accretion expense, a $1,538 unrealized net loss related to the change in fair value of our derivative contracts and $675 of impairment expense.  During the quarter ended March 31, 2014, we spent $239 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 three months ended March 31, 2014, our income before income taxes and cash flow would have increased by approximately $304 for each $0.50 change per Mcf in natural gas prices.  We realized a loss on our derivative of derivatives of $(941) versus a cash gain of $1,869 during the three months ended March 31, 2014 and 2013, respectively.  Despite the recognition of the loss on derivatives during the 2014 period, our average realized natural gas price was 11% higher in the three months ended March 31, 2014 as compared to the same prior-year period due to the overall increase in the CIG market price.  

During the three months ended March 31, 2014, net cash used in investing activities was $1,148, as compared to $2,139 in the same prior-year period. Our 2014 capital spending was primarily related to payment of costs associated with the Spyglass Hill drilling program in 2013.  In the first three months of 2013, our spending primarily attributed to completion of our Niobrara exploration well.    

We had cash provided by financing activities of $2,100 for the three months ended March 31, 2014, as compared to cash used in financing activities of $948 for the three months ended March 31, 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 of March 31, 2014, the Company had a receivable for $2,250 of the total offering proceeds, which will be collected in the second quarter of 2014.  We expended cash in the first three months of 2014 and 2013 to make our quarterly dividend payment totaling $931 in each period. Dividends are expected to continue to be paid on a quarterly basis on the Series A Preferred Stock in the future at a rate of $931 per quarter.

Credit Facility

Our credit facility is collateralized by our oil and gas producing properties and other assets. At March 31, 2014, we had $47,950 outstanding on the facility. We have depended on our credit facility over the past five years to supplement our operating cash flow in the development of the Company-operated Catalina Unit and other non-operated projects in the Atlantic Rim, including two purchases of additional working interests in this field, projects on the Pinedale Anticline, and the drilling of our Niobrara exploration well.  

Borrowings under the revolving line of credit bear interest at a daily rate equal to (a) the highest of the Federal Funds rate on such day, plus 0.5%, the Prime Rate on such day or the One-Month Eurodollar Rate on such day plus (b) a margin ranging between 0.75% and 2.75% depending on the level of funds borrowed. The average interest rate on the facility at March 31, 2014, including the impact of our interest rate swaps, was 3.4%.  Any balance outstanding on the on the credit facility is due on October 24, 2016.  

We are subject to a variety of financial and non-financial covenants under this facility. As of March 31, 2014, we were in compliance with all covenants under the facility. If any of the covenants are violated, and we are unable to negotiate a waiver or amendment thereof, the lender would have the right to declare an event of default, terminate the remaining commitment, accelerate all principal and interest outstanding, and foreclose on our assets.

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Capital Requirements

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

DERIVATIVE INSTRUMENTS

Contracted gas volumes

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

Our outstanding derivative instruments as of March 31, 2014 are summarized below (volume and daily production are expressed in Mcf). All contracts are indexed to the NYMEX. The prevailing market prices in the Rockies, including CIG which is the index on which most of our gas volumes are sold, tend to be sold at a discount relative to other U.S. natural gas markets, including NYMEX. This discount is typically referred to as a “basis differential” and reflects, to some extent, the costs associated with transporting the natural gas in the Rockies to markets in the other regions. It also reflects the general excess supply and lack of pipeline capacity in the region.

Type of Contract	Remaining Contractual Volume (Mcf)		Term	Price			Price Index (1)
Fixed Price Swap		1,375,000	01/14-12/14	$	4.27		NYMEX
Costless Collar		1,350,000	01/14-12/14	$	4.00	floor	NYMEX
				$	4.50	ceiling
Fixed Price Swap		1,350,000	01/14-12/14	$	4.20		NYMEX
Fixed Price Swap		405,000	01/14-12/14	$	4.17		NYMEX
Fixed Price Swap		3,000,000	01/15-12/15	$	4.28		NYMEX
Fixed Price Swap		3,600,000	01/15-12/15	$	4.15		NYMEX
Fixed Price Swap		1,830,000	01/16-12/16	$	4.07		NYMEX
Total		12,910,000

In April 2014, we entered into an additional swap contract with a third party for 3,660,000 Mcf at $4.15 per Mcf for the period January 1, 2016 through December 31, 2016.    

Interest rate swap

We have a $30,000 fixed rate swap contract with a third party in place as a hedge against the floating interest rate on our credit facility. Under the hedge contract terms, we locked in the Eurodollar LIBOR portion of the interest calculation at approximately 1.050% for this tranche of our outstanding debt, which based on our level of outstanding debt at March 31, 2014, translates to an interest rate on this tranche of approximately 3.55%.  Based on the aforementioned decrease in our borrowing base, the effective interest rate on this swap is 3.8%.  The contract is effective through September 30, 2016.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

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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 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 three months ended March 31, 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM  1. LEGAL PROCEEDINGS

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

ITEM  2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

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

The table below summarizes repurchases of our common stock in the first quarter of 2014:

Period	Total Number of Shares Purchased (1)		AveragePricePaidper Share		TotalNumberofShares Purchasedas Part of Publically Announced Plans or Programs		Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
January 1 - 31, 2014		3,924	$	2.21		—		—
February 1 - 28 2014		14,909	$	2.19		—		—
March 1 - 31, 2014		1,006	$	2.43		—		—

(1) None of the shares were repurchased as part of publicly announced plans or programs. All such purchases were from employees for settlement of payroll taxes due at the time of restricted stock vesting. All repurchased shares were subsequently retired.

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ITEM  6. EXHIBITS

The following exhibits are filed as part of this report:

Exhibit	Description:
3.1(a)	Articles of Incorporation of the Company (incorporated by reference from Exhibit 3.1(a) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).
3.1(b)	Certificate of Correction of the Company (incorporated by reference from Exhibit 3.1(b) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).
3.1(c)	Certificate of Correction of the Company (incorporated by reference from Exhibit 3 of the Company’s Quarterly Report on Form 10-QSB for the quarter ended November 30, 2001).
3.1(d)	Certificate of Correction to the Articles of Incorporation of the Company (incorporated by reference from Exhibit 3.3 of the Company’s Current Report on Form 8-K dated June 29, 2007).
3.1(e)	Articles of Amendment to the Articles of Incorporation of the Company, filed with the Maryland Department of Assessments and Taxation on June 26, 2007 (incorporated by reference from Exhibit 3.1 of the company’s Current Report on Form 8-K dated June 29, 2007).
3.1(f)	Article of Amendment to the Articles of Incorporation of the Company (incorporated by reference from Exhibit 3.1 of the Company’s Current Report on Form 8-K/A dated March 25, 2014).
3.1(g)	Articles Supplementary of Series A Cumulative Preferred Stock (incorporated by reference from Exhibit 3.2 of the    Company’s Current Report on Form 8-K dated June 29, 2007).
3.1(h)	Articles of Amendment to Articles Supplementary 9.25% Series A Cumulative Preferred Stock (incorporated by reference from Exhibit 4.1 from the Company’s Annual Report on Form 10-K for the year ended December 31, 2013 filed on March 14, 2013).
3.1(i)	Articles Supplementary of Junior Participating Preferred Stock, Series B of the Company, dated as of August 21, 2007 (incorporated by reference from Exhibit 3.1 of the Company’s Current Report on Form 8-K dated August 28, 2007).
3.1(j)	Third Amended and Restated Bylaws of the Company (incorporated by reference from Exhibit 3.1 of the Company’s Current Report on Form 8-K dated April 3, 2014).
10.1(a)*	Employment Agreement dated March 24, 2014 between Double Eagle Petroleum Co. and Charles Chambers. .
10.1(b)*	Sixth Amendment to Amended and Restated Credit Agreement, dated April 24 2014 between the Company and Bank of Oklahoma, N.A., et al.
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Principal Accounting Officer and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*	Certification Pursuant to 18 U.S.C. Section 1150 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Scheme Document
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		ESCALERA RESOURCES CO. (Registrant)
Date: May 15, 2014	By:	/S/ Charles F. Chambers
		Charles F. Chambers
		Chief Executive Officer
		(Principal Executive Officer)

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EXHIBIT INDEX

Exhibit	Description:
3.1(a)	Articles of Incorporation of the Company (incorporated by reference from Exhibit 3.1(a) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).
3.1(b)	Certificate of Correction of the Company (incorporated by reference from Exhibit 3.1(b) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).
3.1(c)	Certificate of Correction of the Company (incorporated by reference from Exhibit 3 of the Company’s Quarterly Report on Form 10-QSB for the quarter ended November 30, 2001).
3.1(d)	Certificate of Correction to the Articles of Incorporation of the Company (incorporated by reference from Exhibit 3.3 of the Company’s Current Report on Form 8-K dated June 29, 2007).
3.1(e)	Articles of Amendment to the Articles of Incorporation of the Company, filed with the Maryland Department of Assessments and Taxation on June 26, 2007 (incorporated by reference from Exhibit 3.1 of the company’s Current Report on Form 8-K dated June 29, 2007).
3.1(f)	Article of Amendment to the Articles of Incorporation of the Company (incorporated by reference from Exhibit 3.1 of the Company’s Current Report on Form 8-K/A dated March 25, 2014).
3.1(g)	Articles Supplementary of Series A Cumulative Preferred Stock (incorporated by reference from Exhibit 3.2 of the    Company’s Current Report on Form 8-K dated June 29, 2007).
3.1(h)	Articles of Amendment to Articles Supplementary 9.25% Series A Cumulative Preferred Stock (incorporated by reference from Exhibit 4.1 from the Company’s Annual Report on Form 10-K for the year ended December 31, 2013 filed on March 14, 2013).
3.1(i)	Articles Supplementary of Junior Participating Preferred Stock, Series B of the Company, dated as of August 21, 2007 (incorporated by reference from Exhibit 3.1 of the Company’s Current Report on Form 8-K dated August 28, 2007).
3.1(j)	Third Amended and Restated Bylaws of the Company (incorporated by reference from Exhibit 3.1 of the Company’s Current Report on Form 8-K dated April 3, 2014).
10.1(a)*	Employment Agreement dated March 24, 2014 between Double Eagle Petroleum Co. and Charles Chambers. .
10.1(b)*	Sixth Amendment to Amended and Restated Credit Agreement, dated April 24 2014 between the Company and Bank of Oklahoma, N.A., et al.
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Principal Accounting Officer and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*	Certification Pursuant to 18 U.S.C. Section 1150 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Scheme Document
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document

* Filed within this Form 10-Q.

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