Escalera Resources Co. - FORM 10-Q

Attached files

file	filename
EX-32 - EX-32 - Escalera Resources Co.	escr-20150930xex32.htm
EX-31.2 - EX-31.2 - Escalera Resources Co.	escr-20150930ex312fe8d66.htm
EX-31.1 - EX-31.1 - Escalera Resources Co.	escr-20150930ex311e18562.htm

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended September 30, 2015


◻	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)

None

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

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

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

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


Large accelerated filer	◻	Accelerated filer	◻
Non-accelerated filer	◻(Do not check if a smaller reporting company)	Smaller reporting company	☒

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

Indicate by checkmark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13, or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ◻ No ☒

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 October 31, 2015
Common stock, $.10 par value		14,303,444

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ESCALERA RESOURCES CO.

FORM 10-Q

TABLE OF CONTENTS


		Page
PART I. Financial Information:

	Item 1. Financial Statements	3

	Consolidated Balance Sheets as of September 30, 2015 (unaudited) and December 31, 2014	3
	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2015 and 2014 (Unaudited)	4
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2015 and 2014 (Unaudited)	5
	Notes to Consolidated Financial Statements (Unaudited)	6

	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	18

	Item 3. Quantitative and Qualitative Disclosures About Market Risk	30

	Item 4. Controls and Procedures	30

PART II. Other Information:

	Item 1. Legal Proceedings	31

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	32

	Item 6. Exhibits	33

Signatures		34

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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)


	September 30,
	2015			December 31,
ASSETS	(unaudited)		2014
Current assets:
Cash and cash equivalents	$	2,452	$	5,933
Cash held in escrow		283		283
Accounts receivable, net		1,962		4,181
Assets from price risk management		6,738		3,546
Other current assets		1,053		2,131
Total current assets		12,488		16,074

Oil and gas properties and equipment, successful efforts method:
Developed properties		177,626		243,245
Wells in progress		2,653		4,039
Gas transportation pipeline		5,510		5,510
Undeveloped properties		1,647		1,967
Corporate and other assets		1,426		1,468
		188,862		256,229
Less accumulated depreciation, depletion and amortization		(122,446)		(149,573)
Net properties and equipment		66,416		106,656
Assets from price risk management		1,614		3,442
Other assets		2,432		1,707
TOTAL ASSETS	$	82,950	$	127,879

LIABILITIES, PREFERRED STOCK AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	7,934	$	9,689
Accrued production taxes		2,409		2,418
Credit facility, current		36,886		47,515
Total current liabilities		47,229		59,622

Asset retirement obligation		7,915		8,853
Other long-term liabilities		—		526
TOTAL LIABILITIES		55,144		69,001

Preferred stock, $0.10 par value; 10,000,000 shares authorized; 1,610,000 shares issued and outstanding at September 30, 2015 and December 31, 2014		37,972		37,972
Stockholders' equity:
Common stock, $0.10 par value; 50,000,000 shares authorized; 14,295,944 issued and outstanding at September 30, 2015, and 14,266,453 issued and outstanding at December 31, 2014		1,430		1,427
Additional paid-in capital		43,564		43,200
Accumulated deficit		(55,160)		(23,721)
Total stockholders' (deficit)/equity		(10,166)		20,906
TOTAL LIABILITIES, PREFERRED STOCK AND STOCKHOLDERS' EQUITY	$	82,950	$	127,879

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

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ESCALERA RESOURCES CO.

CONSOLIDATED STATEMENTS OF OPERATIONS

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

(Unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Revenues:
Natural gas and oil sales	$	2,471	$	7,550	$	10,190	$	27,436
Transportation and gathering revenue		559		828		1,771		2,732
Price risk management activities		2,476		1,633		5,042		(1,634)
Other income		(404)		21		(89)		207
Total revenues		5,102		10,032		16,914		28,741

Costs and expenses:
Production costs		2,660		3,296		8,694		9,768
Production taxes		244		898		1,078		3,262
Exploration expenses including dry hole costs		11		28		60		84
Pipeline operating costs		469		958		1,926		3,268
Impairment and abandonment of equipment and properties		23		355		21,824		1,435
General and administrative		1,352		1,522		4,250		5,292
Depreciation, depletion and amortization		2,002		4,946		8,702		15,135

Total costs and expenses		6,761		12,003		46,534		38,244

Loss from operations		(1,659)		(1,971)		(29,620)		(9,503)

Interest expense, net		621		592		1,617		1,397
Provision for gas-to-liquids advance		—		—		202		—

Loss before income taxes		(2,280)		(2,563)		(31,439)		(10,900)

Deferred income tax benefit		—		42		—		911

Net loss	$	(2,280)	$	(2,521)	$	(31,439)	$	(9,989)

Preferred stock dividends (including undeclared and unpaid in 2015)		(930)		(930)		(2,792)		(2,792)

Net loss attributable to common stock	$	(3,210)	$	(3,451)	$	(34,231)	$	(12,781)
Net loss per common share:
Basic and diluted	$	(0.22)	$	(0.24)	$	(2.40)	$	(0.96)
Weighted average shares outstanding:
Basic and diluted		14,302,801		14,262,170		14,284,817		13,363,747

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)


	Nine Months Ended September 30,
	2015		2014
Cash flows from operating activities:
Net loss	$	(31,439)	$	(9,989)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion of asset retirement obligation		8,901		15,320
Amortization of loan fees		—		258
Impairment and abandonment of equipment and properties		21,824		1,435
Gain on settlement of asset retirement obligation		—		(80)
Gain on sale of corporate assets and non-producing properties		—		(94)
Settlement of asset retirement obligation		(62)		(344)
Settlement on price risk management		(129)		—
Benefit for deferred income taxes		—		(911)
Change in fair value of derivative contracts		(1,364)		1,305
Stock-based compensation expense		368		601
Loss on sale of producing property		135		—
Changes in current assets and liabilities:
Decrease in accounts receivable		1,910		503
Decrease (increase) in other current assets		18		(154)
(Decrease) increase in accounts payable and accrued expenses		(361)		422
Increase in accrued production taxes		399		1,282
NET CASH PROVIDED BY OPERATING ACTIVITIES		200		9,554
Cash flows from investing activities:
Sale of producing properties and equipment, undeveloped properties, and corporate assets, net		11,025		361
Payments to acquire and develop producing properties and equipment, net		(4,038)		(2,324)
Payments to acquire corporate and non-producing properties		(167)		(285)
Advance for gas-to-liquids plant initiative		—		(871)
NET CASH (USED IN) PROVIDED BY INVESTING ACTIVITIES		6,820		(3,119)
Cash flows from financing activities:
Net proceeds from sale of common stock		—		4,158
Dividends paid on preferred stock		—		(2,792)
Net repayment on credit facility		(10,500)		(2,435)
Payment of loan financing costs		2		(895)
Tax withholdings related to net share settlement of restricted stock awards		(3)		(44)
NET CASH USED IN FINANCING ACTIVITIES		(10,501)		(2,008)

Change in cash and cash equivalents		(3,481)		4,427
Cash and cash equivalents at beginning of period		5,933		2,799
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	2,452	$	7,226

Supplemental disclosure of cash and non-cash transactions:
Cash paid for interest	$	1,692	$	1,317
Interest capitalized	$	104	$	42
Additions to developed properties included in current liabilities	$	2,234	$	3,424
Current assets transferred to purchaser in sale of producing properties	$	309	$	—
Liabilities assumed by purchaser in sale of producing properties	$	1,285	$	—

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

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ESCALERA RESOURCES CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

1.Summary of Significant Accounting Policies

Basis of presentation

The accompanying unaudited interim consolidated financial statements and related notes were prepared by Escalera Resources Co. (“Escalera Resources” or the “Company”), in accordance with accounting principles generally accepted in the United States of America for interim financial reporting and were prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Certain information and note disclosures normally included in the annual audited consolidated financial statements have been condensed or omitted as allowed by such rules and regulations. These consolidated financial statements include all of the adjustments, which, in the opinion of management, are necessary for a fair presentation of the financial position and results of operations. All such adjustments are of a normal recurring nature only. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full fiscal year.

The accounting policies followed by the Company are set forth in Note 1 to the Company’s consolidated financial statements in its Annual Report on Form 10-K for the year ended December 31, 2014, and are supplemented in the notes to this Quarterly Report on Form 10-Q. The unaudited interim consolidated financial statements presented herein should be read in conjunction with the consolidated financial statements and notes thereto included in the Annual Report on Form 10-K for the year ended December 31, 2014 filed with the SEC on April 15, 2015.

Ability to Continue as a Going Concern

The consolidated financial statements included in this Quarterly Report on Form 10-Q have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The consolidated financial statements do not reflect any adjustments that might result if the Company is unable to continue as a going concern. The Company’s long-term debt is reflected as a current liability on the consolidated balance sheets (see Note 4) as a result of several defaults under the Company’s credit facility that have occurred since the fourth quarter of 2014.

As described further in Note 2 below, on November 5, 2015 the Company filed a voluntary petition (the “Bankruptcy Petition”) in the United States Bankruptcy Court for the District of Colorado (the “Bankruptcy Court”) seeking relief under the provisions of Chapter 11 of Title 11 of the United States Code (the “Bankruptcy Code”).

The Company’s filing of the Bankruptcy Petition constitutes an additional event of default under the Company’s credit facility. As noted below, the Company anticipates filing a plan of reorganization by November 24, 2015, however, there can be no assurance regarding the Company’s ability to successfully confirm and consummate a plan of reorganization, or any other alternative restructuring transactions, including a sale of all or substantially all of its assets that satisfies the conditions of the Bankruptcy Code and is authorized by the Bankruptcy Court.

Principles of consolidation

The unaudited interim consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, Petrosearch Energy Corporation and Eastern Washakie Midstream LLC (“EWM”). The Company has an agreement with EWM under which the Company pays a fee to EWM to gather, compress and transport gas produced at the Catalina Unit, in the eastern Washakie Basin of Wyoming. This fee is eliminated in consolidation.

Recent accounting pronouncements

In August 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-15, “Interest – Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements”, which is effective beginning in the first quarter 2016, and will be applied retrospectively. ASU 2015-15 amends ASU 2015-03 as the previous standard did not address presentation or subsequent measurement of debt issuance costs related to line-of-credit agreements. The

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Company does not expect the adoptions of this ASU to have a material impact on its consolidated financial statements.

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

2.Voluntary Reorganization under Chapter 11 Proceedings

On November 5, 2015, the Company filed a Bankruptcy Petition in the Bankruptcy Court seeking relief under the provisions of the Bankruptcy Code. The Company’s Chapter 11 case is being administered as In re Escalera Resources Co., Case No. 15-22395-TBM (the “Bankruptcy Case”). The Company intends to continue to operate its business as “debtor-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. The Company will account for the bankruptcy in accordance with ASC 852, Reorganizations, starting with the quarterly period ending December 31, 2015.

By certain “first day” motions filed in the Bankruptcy Case, the Company obtained Bankruptcy Court approval (on an interim basis) for the use of cash collateral, the payment of employee wages, health benefits and certain other employee obligations, and the payment of amounts due for certain joint-interest-billings. A final hearing on the motions to approve the use of cash collateral and to satisfy certain other obligations to certain third parties will be held on November 30, 2015.

In connection with the Bankruptcy Case, the Company has an agreement for the use of cash collateral with the Company’s lenders. In accordance with the terms of this cash collateral agreement, the Company expects to file a plan of reorganization (the “Plan”) by November 24, 2015 based on the term sheet included with the cash collateral agreement (the “Term Sheet”). The Plan provides for the restructuring of the Company’s operations, debts and capital structure.

Subject to certain exceptions, under the Bankruptcy Code, the filing of the Bankruptcy Petition automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Company or its property to recover, collect or secure a claim arising prior to the date of the Bankruptcy Petition. Accordingly, although the filing of the Bankruptcy Petition triggered additional events of default on the Company’s debt obligations, the Company’s lenders and other creditors are stayed from taking any actions against the Company as a result of such defaults, subject to certain limited exceptions permitted by the Bankruptcy Code. Absent an order of the Bankruptcy Court, substantially all of the Company’s prepetition liabilities are subject to settlement under the Bankruptcy Code.

For the duration of the Company’s Chapter 11 proceedings, the Company’s operations and ability to develop and execute its business plan are subject to the risks and uncertainties associated with the Chapter 11 process. As a result of these risks and uncertainties, the number of the Company’s outstanding shares and shareholders, assets, liabilities, officers and/or directors could be significantly different following the outcome of the Chapter 11 proceedings, and the description of the Company’s operations, properties and capital plans included in this quarterly report may not accurately reflect its operations, properties and capital plans following the Chapter 11 process. Among other things, the Term Sheet referenced above contemplates that all outstanding common and preferred stock will be cancelled and that the holders thereof will not have any interest in the Company under the contemplated plan of reorganization.

Also, among other things and subject to certain exceptions, under the Bankruptcy Code, the Company may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Company of performing its future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. Counterparties to such rejected contracts or leases may assert unsecured claims in the Bankruptcy Court against the applicable Company’s estate for such damages. Generally, the assumption of an executory contract or unexpired

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lease requires the Company to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease with the Company in this quarterly report, including where applicable a quantification of the Company’s obligations under any such executory contract or unexpired lease with the Company is qualified by any overriding rejection rights the Company has under the Bankruptcy Code. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and the Company expressly preserves all of its rights with respect thereto.

There can be no assurances regarding the Company’s ability to successfully develop, confirm and consummate one or more plans of reorganization or other alternative restructuring transactions, including a sale of all or substantially all of its assets that satisfies the conditions of the Bankruptcy Code and is authorized by the Bankruptcy Court.

3.Earnings per share

Basic earnings per share is calculated by dividing net income (loss) attributable to common stock by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share incorporates the treasury stock method to measure the dilutive impact of potential common stock equivalents by including the effect of outstanding vested and unvested stock options and unvested stock awards in the average number of shares of common stock outstanding during the period. Income (loss) attributable to common stock is calculated as net income (loss) less the cumulative dividends, including dividends in arrears, related to the Company’s Series A Preferred Stock, at a quarterly rate of $0.5781 per share. The Series A Preferred Stock dividends for the three and nine months ended September 30, 2015, which were undeclared and unpaid for both periods, totaled $930 and $2,792, respectively. The Company declared and paid cash dividends of $930 and $2,792 for the three months and nine months ended September 30, 2014, respectively.

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 September 30,				For the Nine Months Ended September 30,
	2015		2014		2015		2014
Net loss	$	(2,280)	$	(2,521)	$	(31,439)	$	(9,989)
Preferred stock dividends (including undeclared and unpaid in 2015)		(930)		(930)		(2,792)		(2,792)
Loss attributable to common stock	$	(3,210)	$	(3,451)	$	(34,231)	$	(12,781)
Weighted average shares:
Weighted average shares - basic		14,302,801		14,262,170		14,284,817		13,363,747
Dilutive effect of stock options outstanding at the end of period		—		—		—		—
Weighted average shares - fully diluted		14,302,801		14,262,170		14,284,817		13,363,747
Net loss per share:
Basic and diluted	$	(0.22)	$	(0.24)	$	(2.40)	$	(0.96)

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 September 30,		For the Nine Months Ended September 30,
	2015	2014	2015	2014
Anti-dilutive stock options and unvested stock awards	77,009	114,245	63,242	116,322

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4.Credit Facility

As of September 30, 2015, the Company had a credit agreement (the “Credit Agreement”) in place ($33,500 borrowing base) with an outstanding balance of $36,886, which resulted in a borrowing base deficiency of $3,386. The Company has historically utilized its credit facilities to fund the development of the Catalina Unit and other non-operated projects in the Atlantic Rim, and development projects on the Pinedale Anticline in the Green River Basin of Wyoming.

The Credit Agreement is collateralized by the Company’s natural gas and oil producing properties. Any balance outstanding under the original terms of the credit facility was due on August 29, 2017, however, the Company is currently in default due to various events of default discussed below, including the Company’s Chapter 11 proceedings.

Under the Credit Agreement, the Company is subject to both financial and non-financial covenants. The financial covenants, as defined in the Credit Agreement, include maintaining (i) a current ratio of 1.0 to 1.0; (ii) a ratio of earnings before interest, taxes, depreciation, depletion, amortization, exploration and other non-cash items (“EBITDAX”) to interest plus dividends of greater than 1.5 to 1.0; and (iii) a funded debt, less unencumbered cash, to EBITDAX ratio of less than 4.0 to 1.0.

As of September 30, 2015, the Company was in violation of each of the aforementioned financial covenants and had also previously triggered two additional events of default, under the Credit Agreement: (1) the Company’s independent registered public accounting firm included a going concern explanatory paragraph in its audit opinion in our consolidated financial statements for the year ended December 31, 2014, and (2) the Company had not fully paid its ad valorem taxes assessed in 2014 (which were due in May 2015) for certain of its properties.

The Company has shown the outstanding balance under the credit facility as a current liability on the consolidated balance sheets as of September 30, 2015 and December 31, 2014 as a result of these violations and the lender’s right to declare and event of default, terminate the remaining commitment and accelerate all principal and interest outstanding.

As of September 30, 2015, borrowings under the credit facility incurred interest daily based on the Company’s interest rate election of either the Base Rate or LIBOR Rate. Under the Base Rate option, interest is calculated at an annual rate equal to the highest of (a) the base rate for Dollar loans for such day, Federal Funds rate for such day, plus 0.5%, or the LIBOR for such day plus (b) a margin ranging between 0.75% and 1.75% (annualized) depending on the level of funds borrowed. Under the LIBOR Rate option, interest is calculated at an annual rate equal to LIBOR, plus a margin ranging between 1.75% and 2.75% (annualized) depending on the level of funds borrowed. In addition to the standard interest charge, the Company is subject to an additional penalty rate of 2.0% (annualized) as a result of the aforementioned events of default. The average interest rate on the facility at September 30, 2015 was 5.35%. Under the Amendment, the Company may no longer elect the LIBOR Rate option. The interest will be converted to the Base Rate after the expiration of the current interest rate elections.

For the three months ended September 30, 2015 and 2014, the Company incurred interest expense on its credit facilities of $563 and $6,603, respectively, and for the nine months ended September 30, 2015 and 2014, $1,422 and $1,427, respectively. Of the total interest incurred, the Company capitalized interest costs of $58 and $10 for the three months ended September 30, 2015 and 2014, respectively, and $104 and $42 for the nine months ended September 30, 2015 and 2014, respectively.

On November 5, 2015 the Company filed the Bankruptcy Petition. As described in Note 2 above, the Company had an agreement with its lenders for the use of cash collateral when the Bankruptcy Petition was filed, which, along with the Term Sheet, provides key terms for a plan of reorganization. This restructuring is ultimately dependent upon the Company’s ability to file, confirm and consummate a plan of reorganization with the Bankruptcy Court.

5.Derivative Instruments

Commodity Contracts

The Company’s primary market exposure is adverse fluctuations in the price of natural gas and, to a lesser extent, oil. The Company uses derivative instruments, primarily swaps and costless collars, to manage the price risk

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associated with its production, and the resulting impact on cash flow, net income and earnings per share. The Company does not use derivative instruments for speculative purposes.

The extent of the Company’s risk management activities is controlled through policies and procedures that involve senior management and were approved by the Company’s board of directors (the “Board”). Senior management is responsible for proposing hedging recommendations, executing the approved hedging plan, overseeing the risk management process including methodologies used for valuation and risk measurement and presenting policy changes to the Board. The Board is responsible for approving risk management policies and for establishing the Company’s overall risk tolerance levels. The duration of the various derivative instruments depends on senior management’s view of market conditions, available contract prices and the Company’s operating strategy. As of September 30, 2015, in accordance with the Company’s current credit agreement, the Company has hedged at least 85% of its projected production through 2016 based on its third-party prepared reserve report at December 31, 2014.

The Company accounts for its derivative instruments as mark-to-market derivative instruments. Under mark-to-market accounting, derivative instruments are recognized as either assets or liabilities at fair value on the Company’s consolidated balance sheets, and changes in fair value are recognized in the price risk management activities line on the consolidated statements of operations. Realized gains and losses resulting from the contract settlement of derivatives are also recorded in the price risk management activities line on the consolidated statements of operations.

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

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

As with most derivative instruments, the Company’s derivative contracts contain provisions which may allow for another party to require security from the counterparty to ensure performance under the contract. The security may be in the form of, but not limited to, a letter of credit, security interest or a performance bond. As of September 30, 2015, no party to any of the Company’s derivative contracts has required any form of security guarantee.

The Company had the following commodity volumes under derivative contracts as of September 30, 2015:


Type of Contract	Remaining Contractual Volume (Bbls)	Term	Price ($/Bbl)(1)
Fixed price swap	3,300	10/15-12/15	$	91.44
Total contracted oil volumes	3,300

Type of Contract	Remaining Contractual Volume (Mcf)	Term	Price ($/Mcf)(2)
Three-way costless collar	1,650,000	10/15-12/15	$	3.25	put (short)
			$	3.85	put (long)
			$	4.08	call (short)
Total 2015 contracted volumes	1,650,000

Fixed price swap	1,830,000	01/16-12/16	$	4.07
Fixed price swap	3,660,000	01/16-12/16	$	4.15
Total 2016 contracted volumes	5,490,000

Total contracted natural gas volumes	7,140,000

(1)

New York Mercantile Exchange (“NYMEX”) Light Sweet Crude Oil (“WTI”).

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(2)

NYMEX Henry Hub Natural Gas (“NG”).

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


	Balance Sheet Location	As of September 30, 2015		As of December 31, 2014
Assets
Commodity derivatives	Assets from price risk management - current	$	6,738	$	3,546
	Assets from price risk management - long-term		1,614		3,442
Total derivative assets		$	8,352	$	6,988

The before-tax effect of derivative instruments for the three and nine months ended September 30, 2015 and 2014 were as follows:


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2015		2014		2015		2014
Unrealized gain (loss) on commodity contracts (1)	$	1,181	$	175	$	1,364	$	(1,617)
Realized gain (loss) on commodity contracts (1)		1,295		1,458		3,678		(17)
Unrealized loss on interest rate swap (2)		—		315		—		312
Realized loss on interest rate swap (2)		—		(360)		—		(495)
Total activity for derivatives not designated as hedging instruments	$	2,476	$	1,588	$	5,042	$	(1,817)

(1)

Included in price risk management activities on the consolidated statements of operations. Price risk management activities totaled $2,476 and $1,633 for the three months ended September 30, 2015 and 2014, and $5,042 and $(1,634) for the nine months ended September 30, 2015 and 2014, respectively.

(2)

Included in interest expense, net on the consolidated statements of operations. The Company has not entered into an interest rate swap agreement since its refinancing in August 2014.

Refer to Note 6 for additional information regarding the valuation of the Company’s derivative instruments.

Liquidation of Natural Gas and Oil Hedges

In connection with the Company’s filing of the Bankruptcy Petition described above in Note 2, the Company has an agreement with the lenders under the Credit Agreement for the use of cash collateral. In connection with this agreement for the use of cash collateral, the Company liquidated its 2016 natural gas hedges (total contracted volumes of 5,490,000 Mcf) on October 30, 2015 resulting in net cash proceeds of $8,047.

In connection with the sale of the Pinedale Anticline assets on July 31, 2015 (see Note 13), the Company liquidated a portion of its contracted oil volumes (3,000 Bbls) for cash proceeds of $129, which was used to pay down its outstanding borrowings under the Credit Agreement.

6.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

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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.

The following tables provides a summary of assets and liabilities measured at fair value on a recurring basis:


	Fair Value Measurements as of September 30, 2015
	Level 1		Level 2		Level 3		Total
Assets
Derivative instruments - Commodity forward contracts	$	—	$	8,352	$	—	$	8,352
Total assets at fair value	$	—	$	8,352	$	—	$	8,352


	Fair Value Measurements as of December 31, 2014
	Level 1		Level 2		Level 3		Total
Assets
Derivative instruments - Commodity forward contracts	$	—	$	6,988	$	—	$	6,988
Total assets at fair value	$	—	$	6,988	$	—	$	6,988

The Company did not have any transfers of assets or liabilities between Level 1, Level 2 or Level 3 of the fair value measurement hierarchy during the three and nine months ended September 30, 2015.

Derivative instruments

The Company determines its estimates of the fair values of derivative instruments using a market approach based on several factors, including quoted prices in active markets, market-corroborated inputs, such as NYMEX forward-strip pricing, the credit rating of each counterparty, and the Company’s own credit rating.

In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments. Additionally, when applicable the Company considers its own credit quality and financial resources and ability to meet its potential repayment obligations associated with the derivative transactions.

At September 30, 2015, the Company had various types of derivative instruments, which consists of swaps and costless collars. The natural gas and oil derivative markets are highly active. Although the Company’s economic hedges are valued using public indices, the instruments themselves are traded with third party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.

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

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Assets and liabilities measured on a non-recurring basis

Proved oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication the carrying costs may not be recoverable. The fair value of impaired proved properties is determined based on quoted market prices in active markets, if available, or using Level 3 inputs and the income valuation technique, which converts future estimated cash flow amounts to a single present value amount, to measure the fair value of proved properties through an application of discount rates, price forecasts and operating and development cost assumptions selected by the Company’s management. As of September 30, 2015, there were no assets or liabilities measured at fair value on a non-recurring basis.

Concentration of credit risk

Financial instruments that potentially subject the Company to credit risk consist of accounts receivable and derivative financial instruments. Substantially all of the Company’s receivables are within the natural gas and oil industry, including those from a third party gas marketing company. Collectability is dependent upon the financial wherewithal of each counterparty as well as the general economic conditions of the industry. The receivables are not collateralized.

The Company currently uses two counterparties for its derivative financial instruments. The Company continually reviews the credit worthiness of its counterparties, which are generally other energy companies or major financial institutions. In addition, the Company uses master netting agreements which allow the Company, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If the Company chooses to elect early termination, all asset and liability positions with the defaulting counterparty would be “net settled” at the time of election. “Net settlement” refers to a process by which all transactions between counterparties are resolved into a single amount owed by one party to the other.

7.Impairment of Long-Lived Assets

The Company reviews the carrying values of its long-lived assets annually or whenever events or changes in circumstances indicate that such carrying values may not be recoverable. See Note 6 for discussion of the Company’s fair value methodology.

Proved property impairment expense was $0 for both the three months ended September 30, 2015 and 2014, and $21,504 and $765 for the nine months ended September 30, 2015 and 2014, respectively. The impairment expense recorded in the second quarter of 2015, included $21,030 of expense related to its Pinedale Anticline assets as a result of the sale of these assets on July 31, 2015 (see Note 13 for discussion of the Pinedale Anticline asset sale). The impairment was determined based on the net book value for the Pinedale Anticline assets, reduced by the expected net sale proceeds of the assets after the associated expected selling costs. The remaining impairment expense recognized during the first nine months of 2015 was primarily due to an increase in estimated field abandonment costs (and thus the associated asset carrying value) at the Company’s Main Fork Unit property. In 2014, the Company wrote-off a non-operated property in the Atlantic Rim, as production from the wells at this property had been limited and the operator began plugging and abandoning these wells.

The Company also expensed $23 and $355 during the three months ended September 30, 2015 and 2014, respectively, and $320 and $670 during the nine months ended September 30, 2015 and 2014, respectively, related to expiring undeveloped acreage in Wyoming, as the Company determined that these leases would not be developed before their expiration.

8.Compensation Plans

The Company recognized stock-based compensation expense totaling $82 and $368 for the three and nine months ended September 30, 2015, respectively, and $218 and $601 for the three and nine months ended September 30, 2014, respectively.

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Compensation expense related to stock options is calculated using the Black-Scholes valuation model. Expected volatilities are based on the historical volatility of the Company’s common stock over a period consistent with that of the expected terms of the options. The expected terms of the options are estimated based on factors such as vesting periods, contractual expiration dates, historical trends in the Company’s common stock price and historical exercise behavior. The risk-free rates for periods within the contractual life of the options are based on the yields of U.S. Treasury instruments with terms comparable to the estimated option terms.

A summary of stock option activity under the Company’s various stock option plans as of September 30, 2015 and changes during the nine months ended September 30, 2015 is presented below:



		Weighted-
		Average
		Exercise
	Shares	Price
Options:
Outstanding at January 1, 2015	369,543	$	2.36
Cancelled/expired	(143,553)	$	2.89
Outstanding at September 30, 2015	225,990	$	1.91
Exercisable at September 30, 2015	76,787	$	4.42

The Company measures the fair value of stock awards based upon the fair market value of its common stock on the date of grant and recognizes the resulting compensation expense ratably over the associated service period, which is generally the vesting term of the stock awards. The Company recognizes the compensation expenses, net of an estimated forfeiture rate, for only those shares expected to vest. The Company typically estimates forfeiture rates based on historical experience, while also considering the duration of the vesting term of the award.

Nonvested stock awards as of September 30, 2015 and changes during the nine months ended September 30, 2015 were as follows:


		Weighted-
		Average
		Grant Date
	Shares	Fair Value
Outstanding at January 1, 2015	814,121	$	2.30
Granted	40,385	$	0.33
Vested	(99,685)	$	2.42
Forfeited/returned	(85,481)	$	2.55
Nonvested at September 30, 2015	669,340	$	2.13

In March 2014, the Company’s board of directors granted long-term incentive shares to its chief executive officer (“CEO”) in conjunction with his appointment as an officer. The Compensation Committee of the Board approved two restricted stock awards, under which the Company granted the CEO an aggregate of 528,634 shares of restricted stock, which are included in the table above. One-third of the shares awarded will vest at the end of three years if the CEO is continuously employed by the Company during such period, and the remaining two-thirds of the shares awarded will vest at the end of three years if the CEO is continuously employed by the Company during such period and certain performance goals related to reserve growth and the Company’s common stock price are achieved, as defined for purposes of the awards. The Company used a simplified binomial model to estimate the fair value of the

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performance and market based component of the award. The Company’s stock-based compensation for the three and nine months ended September 30, 2015 includes approximately $56 and $170, respectively, and $58 and $122 for the three and nine months ended September 30, 2014, respectively, related to these plans.

9.Income Taxes

The Company is required to record income tax expense for financial reporting purposes and apply an estimated effective tax rate for calculating income tax provisions for interim periods. The Company has not recorded any income tax expense/(benefit) for the three and nine months ended September 30, 2015 as a result of the Company recording a valuation allowance on its net deferred tax assets due to the uncertainty of the realization of these assets. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which the use of such net operating losses are allowed.

The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of September 30, 2015, the Company made no provision for interest or penalties related to uncertain tax positions. The Company files income tax returns in the U.S. federal jurisdiction and various states. There are currently no federal or state income tax examinations of the Company underway for these jurisdictions. Furthermore, the Company is no longer subject to U.S. federal income tax examinations by the Internal Revenue Service for tax years before 2012 and for state and local tax authorities for tax years before 2011.

10.Equity

Preferred stock

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

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

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

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

(i)

The dividend rate increases to the penalty rate of 12% per annum, commencing on the first day after the dividend payment date on which a Dividend Default occurs and for each subsequent dividend payment date thereafter until the second consecutive dividend payment date following such time as the Company has paid all accumulated accrued and unpaid dividends on the Series A Preferred Shares in full in cash, at which time the dividend rate will revert to the standard rate of 9.25% per annum.

(ii)

On the next dividend payment date following the dividend payment date on which a Dividend Default occurs, and continuing until the second consecutive dividend payment date following such time as the

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Company has paid all accumulated accrued and unpaid dividends on the Series A Preferred Shares in full in cash, the Company must pay all dividends on the Series A Preferred Shares, including all accumulated accrued and unpaid dividends, on each dividend payment date either in cash or, if not paid in cash by issuing to the holders thereof (A) if its common shares are then subject to a National Market Listing, as defined, fully-tradable, registered common shares with a value equal to the amount of dividends being paid, calculated based on the then current market value of the common shares, plus cash in lieu of any fractional common share; or (B) if the common shares are not then subject to a value equal to the amount of dividends being paid, calculated based on the stated $25.00 liquidation preference of the Series A Preferred Shares, plus cash in lieu of any fractional Series A Preferred Share (and dividends on any such Series A Preferred Shares upon issuance shall accrue at the penalty rate of 12% per annum and accumulate until such time as the dividend rate shall revert to the stated rate of 9.25% per annum).

In 2015, the Board elected to suspend the Series A Preferred Stock dividend payment for the quarter ended March 31, 2015 and to suspend the dividend indefinitely beginning with the quarter ended June 30, 2015. As of September 30, 2015, the total arrearage on the Company’s Series A Preferred Stock was $2,792, or $1.1562 per share.

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

As a result of the Company’s Bankruptcy Case, the Series A Preferred Stock was delisted from Nasdaq in November 2015 and no longer met the National Market Listing requirement.

The Company has a significant amount of indebtedness that is senior to its existing Series A Preferred Stock in its capital structure. As noted in Note 2 above, the Term Sheet contemplates that the Company’s Series A Preferred Stock will be cancelled and that the holders thereof will receive nothing in connection with the Company’s reorganization.

Common Stock

The Company has a significant amount of indebtedness, and its Series A Preferred Stock, that are both senior to its existing common stock in its capital structures As noted in Note 2 above, the Term Sheet contemplates that the Company’s common stock will be cancelled and that the holders thereof will receive nothing in connection with the Company’s reorganization and the holders in the shares receive nothing.

11.Termination of Contemplated Acquisition of Atlantic Rim Assets

On June 16, 2015, the Company entered into Purchase and Sale Agreements (the “PSAs”) with Warren Resources, Inc. and its subsidiaries (collectively, the “Seller”), pursuant to which the Company had planned to acquire certain of the Seller’s interests primarily adjacent to the Company’s Catalina Unit. The transaction was subject to, among other things, the Company’s ability to obtain significant financing for the transaction and was to close before September 1, 2015. The Company was unable to obtain sufficient debt funding for the acquisition. The Company revised its offer for the properties on October 22, 2015, the Seller indicated that it would not accept the revised offer and negotiations were terminated.

12.Contingencies

Legal proceedings

From time to time, the Company is involved in various legal proceedings, which are subject to the uncertainties inherent in any litigation, including the matters below. The Company is defending itself vigorously in all such matters, and while the ultimate outcome and impact of any proceeding cannot be predicted with certainty, management believes that the resolution of any proceeding will not have a material adverse effect on the Company’s financial condition or results of operations.

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Gas-to-liquids project

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

The Letter Agreement expired effective January 31, 2015, as the Company was unable to agree on terms for a definitive agreement with WYGTL, as contemplated by the Letter Agreement. In accordance with the provisions of the Letter Agreement, the Company requested WYGTL to repay to the Company the total amount advanced, or $1,362. The Company filed a lawsuit in the State of Colorado on March 24, 2015, against WYGTL for breach of the Letter Agreement terms, seeking recovery of the total amount advanced under the Letter Agreement. On April 14, 2015, WYGTL filed a lawsuit against the Company in the U.S. District Court for Colorado, an action entitled Alan Eugene Humphrey and Wyoming GTL, LLC v. Escalera Resources Co., alleging the Company breached its contract with WYGTL, among other claims. The Company does not believe this case has merit and is defending the case vigorously. The Company subsequently filed counterclaims against WYGTL on May 5, 2015 in United States District Court seeking recovery of the total advances, and dismissed its original action filed in the State of Colorado.

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

As a result of the Company’s Bankruptcy Case, the GTL related litigation has been stayed.

Former employee lawsuits

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

As a result of the Company’s Bankruptcy Case, the former employee lawsuits have been stayed.

13.Divestitures

On July 31, 2015, the Company completed the sale of its interests in the Mesa Units located on the Pinedale Anticline in southwestern Wyoming. The sale resulted from the Company’s efforts to reduce its debt levels, as agreed upon with the credit facility’s lenders. The assets were sold for $12,000, less closing adjustments, of which cash proceeds of $10,500 were repaid on the Company’s credit facility following the closing of the transaction. The effective date of the sale was April 1, 2015. The results of operations for the three and nine months ended September 30, 2015 reflect revenues and expenses related to these properties through July 31, 2015. Total producing assets of $48,101, net of the previously recognized impairment, and accumulated depreciation, depletion and amortization of ($35,633) were previously reclassified to assets held for sale during the second quarter 2015.

14.Subsequent Events

See Note 2, “Voluntary Reorganization under Chapter 11 Proceedings” for information on the Company’s Voluntary Reorganization under Chapter 11 and proposed key terms for a plan of reorganization, Note 5, “Derivative Instruments” for information on the termination of the Company’s derivative contracts as a result of the Bankruptcy Petition, and Note 10, “Equity” for information on the likely impact to the Company’s equity holders.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q and other publicly available documents, including those incorporated herein and therein by reference, contain, and our management may from time to time make “forward-looking statements” within the meaning of the U.S. Private Securities Litigation Reform Act of 1995 (“PSLRA”). We make these forward-looking statements in reliance on the safe harbor protections provided under Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934, as amended, and the PSLRA. All statements, other than statements of historical facts, included in this Quarterly Report on Form 10-Q that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. When used in this report, the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “forecast,” “intend,” “may,” “plan,” “project,” “should,” and words or phrases of similar import, as they relate to the Company or its subsidiaries or management, are intended to identify forward-looking statements. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including without limitation the Risk Factors set forth in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2014 and the following factors:

risks and uncertainties associated with the Chapter 11 process, including our inability to file a plan of reorganization in accordance with the term sheet accompanying the Company’s agreed upon use of cash collateral with its lenders, our ability to obtain confirmation of, and ultimately consummate, such plan of reorganization, or our ability to develop, confirm and consummate any other alternative plan of reorganization which may be necessary;

inability to maintain our relationship with suppliers, customers, employees and other third parties as a result of our Chapter 11 filing;

further declines, volatility of and weakness in natural gas or oil prices, particularly in light of the liquidation of our 2016 hedges;

the possible loss of each holder’s equity investment in the Company, both preferred and common, as a result of the contemplated reorganization;

our ability to comply with the covenants and restrictions of our credit facility or our ability to obtain waivers from the lenders on our credit facility for the covenants we are not in compliance with, or those we may not be in compliance with in the future;

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

our future capital requirements and availability of capital resources to fund capital expenditures;

the 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;

the shortage or high cost of equipment, qualified personnel and other oil field services;

general economic conditions, tax rates or policies, interest rates and inflation rates;

incorrect estimates of required capital expenditures;

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

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

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

our ability to successfully identify, execute, integrate and profitably operate any future acquisitions;

industry and market changes, including the impact of consolidations and changes in competition;

our ability to manage the risk associated with operating in one major geographic area;

weather, changes in climate conditions and other natural phenomena;

the credit worthiness of third parties with which we enter into hedging and business agreements;

numerous uncertainties inherent in estimating quantities of proved natural gas and oil reserves and actual future production rates and associated costs; and

the outcome of any future litigation or similar disputes and the impact on any such outcome or related settlements.

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. As of September 30, 2015, our common stock was publicly traded on the Nasdaq Capital Market under “ESCR” and our Series A Cumulative Preferred was publicly traded on the Nasdaq Global Select Market under the symbol “ESCRP”. On October 7, 2015 we voluntarily requested that our common stock be delisted from Nasdaq, as we did not meet Nasdaq’s continued listing requirements and did not anticipate being able to do so in the future. Our common stock currently trades on OTC Market’s OTC Pink marketplace under “ESCRQ”. As a result of our Chapter 11 filing, our Series A Preferred Stock was delisted from Nasdaq and currently trades on OTC Market’s OTC Pink marketplace under “ESCSQ”. Our corporate offices are located at 1675 Broadway, Suite 2200, Denver, Colorado 80202, telephone number (303) 794-8445. Our executive offices are located at 675 Bering Drive, Suite 850, Houston, TX 77057. Our website is www.escaleraresources.com.

Our current production primarily consists of natural gas from properties predominantly located in Wyoming, the most significant of which are coalbed methane (“CBM”) reserves and production in the Atlantic Rim area of the eastern Washakie Basin and tight gas reserves and production on the Pinedale Anticline in the Green River Basin. In July 2015, we sold our assets located on the Pinedale Anticline.

Business Strategy

The market price for natural gas and oil decreased significantly during the second half of 2014 with continued weakness into 2015. The decrease in the market prices for our production directly reduces our operating cash flow and indirectly impacts our other sources of potential liquidity. Lower market prices for our production and the sale of the Pinedale Assets

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led to a decrease in our borrowing base during our spring 2015 borrowing base redetermination, resulting in a borrowing base deficiency of $3,386. Given the unfavorable market conditions, coupled with our Chapter 11 filing and our depleting asset base, we are focused on the following near-term business strategies: (1) file, confirm and consummate a plan of reorganization meeting the requirements included in the term sheet (the “Term Sheet”) accompanying the use of cash collateral agreed upon with our lenders, (2) maintaining production while efficiently managing and significantly reducing our operating and general and administrative (“G&A”) costs, and (3) assist in any necessary transition to our successor company and/or operations as a result of the consummation of any reorganization. Among other things, the Term Sheet referenced above contemplates that all outstanding common and preferred stock will be cancelled and the holders thereof will not have any interest in the Company under the contemplated plan of reorganization.

Recent Developments

On November 5, 2015, we filed a voluntary petition (the “Bankruptcy Petition”) in the United States Bankruptcy Court for the District of Colorado (the “Bankruptcy Court”) seeking relief under the provisions of Chapter 11 of Title 11 of the United States Code (the “Bankruptcy Code”). We intend to continue to operate our business as “debtor-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

By certain “first day” motions filed in the Bankruptcy Case, we obtained Bankruptcy Court approval (on an interim basis) for the use of cash collateral, the payment of employee wages, health benefits and certain other employee obligations, and the payment of amounts due for certain joint-interest-billings. A final hearing on the motions to approve the use of cash collateral and to satisfy certain other obligations to certain third parties will be held on November 30, 2015.

In connection with the Bankruptcy Case, we have an agreement for the use of cash collateral with our lenders. In accordance with the terms of this cash collateral agreement, we expect to file a plan of reorganization (the “Plan”) by November 24, 2015 based on the Term Sheet. The Plan provides for the restructuring of the Company’s operations, debts and capital structure.

There can be no assurances regarding our ability to successfully confirm and consummate the Plan, or other alternative restructuring transactions, including a sale of all or substantially all of our assets that satisfies the conditions of the Bankruptcy Code and is authorized by the Bankruptcy Court.

For the duration of the Company’s Chapter 11 proceedings, our operations and ability to develop and execute our business plan are subject to the risks and uncertainties associated with the Chapter 11 process as described above in “Forward Looking Statements.” As a result of these risks and uncertainties, the number of our outstanding shares and shareholders, assets, liabilities, officers and/or directors could be significantly different following the outcome of the Chapter 11 proceedings, and the description of our operations, properties and capital plans included in this quarterly report may not accurately reflect our operations, properties and capital plans following the Chapter 11 process. Among other things, the Term Sheet referenced above contemplates that all outstanding common and preferred stock will be cancelled and that the holders thereof will receive nothing under a plan of reorganization. In other words, holders of our common and preferred stock will lose their investment in their shares.

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RESULTS OF OPERATIONS

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

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

Natural gas and oil sales

Natural gas and oil sales decreased 67% to $2,471, due to a 45% decrease in production volumes, primarily at our Atlantic Rim property, compounded by a 32% decrease in the Colorado Interstate Gas (“CIG”) market price, which is the index on which most of our natural gas volumes are sold.

As shown in the table below, our average realized natural gas price decreased 14% to $3.11 per Mcf. We calculate our average realized natural gas price by summing (1) production revenues received from third parties for the sale of our gas, which is included within natural gas and oil sales on the consolidated statements of operations, and (2) realized gains/(losses) on our commodity derivatives, which is included within price risk management activities, net on the consolidated statements of operations, totaling $1,166 and $115 for the three months ended September 30, 2015 and 2014, respectively. The 2015 and 2014 net realized gain and commodity contracts considered in the average realized price calculation, excluded the $129 and $1,343 gain realized for the three months ended September 30, 2015 and 2014, on the settlement of our commodity contracts.


	For the Three Months Ended September 30,
	2015			2014			Percent		Percent
Product:			Average			Average	Volume		Price
	Volume		Price	Volume		Price	Change		Change
Gas (Mcf)	1,082,341	$	3.11	1,964,356	$	3.61	(45)	%	(14)	%
Oil (Bbls)	3,053	$	87.65	6,629	$	86.91	(54)	%	1	%
Mcfe	1,100,659	$	3.30	2,004,130	$	3.82	(45)	%	(14)	%

Our total net production decreased 45% to 1.1 Bcfe for the three months ended September 30, 2015 primarily due to lower production from our properties in the Atlantic Rim.

Our total average daily net production at the Atlantic Rim decreased 40% to 9,884 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 participating areas (“PA”)). We operate the Catalina Unit and have non-operated working interests in the Spyglass Hill Unit.

Average daily net production at our Catalina Unit decreased 34% to 7,586 Mcfe. During the first quarter of 2015 we temporarily halted our well workovers due to depressed natural gas prices. In April 2015, we completed the change-out of our remaining electric powered compressors to natural gas powered compressors. In May 2015, we resumed our workover program, on a more strategic and targeted basis, with 17 workovers completed by the end of August 2015. Additionally, we experienced a decrease in production due to the field’s normal production decline.

Average daily production, net to our interest, at the Spyglass Hill Unit decreased 54% to 2,298 Mcfe. Although the operator drilled 59 new production wells in the Spyglass Hill Unit since the third quarter of 2013, we have not realized an increase in production volumes due to infrastructure constraints in the unit. In addition, a significant number of wells are offline within the Spyglass Hill Unit. The operator did commence a well workover program in the third quarter of 2015, which is

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expected to increase production in future periods. Additionally, during the third quarter 2015, the operator adjusted sales volume and revenue for its 2013 and 2014 drilling programs in accordance with the unit operating agreement. The drilling programs resulted in a decrease in net revenue as the Company’s net acreage decreased. No drilling is planned in this unit for 2015.

On the Pinedale Anticline, our average daily net production decreased 79% to 871 Mcfe as a result of the Pinedale Anticline sale and normal production decline. We completed the sale of our interests in the Pinedale assets on July 31, 2015. The effective date of this transaction is April 1, 2015, and net cash flow we received from these properties after that date was credited back to the buyer as a closing adjustment.

Transportation and gathering revenue

We receive fees for gathering and transporting third-party gas through our intrastate gas pipeline, which connects the Catalina Unit with the interstate pipeline system owned by Southern Star Central Gas Pipeline, Inc. Transportation and gathering revenue decreased 32% to $559 for the three months ended September 30, 2015, due to the decrease in Catalina production volumes as compared to the prior-year period.

Price risk management activities

We recorded a net gain on our derivative contracts of $2,476. This consisted of an unrealized non-cash gain of $1,181, which represents the change in the fair value of our commodity derivatives at September 30, 2015 based on the expected future prices of the related commodities, and a net realized gain of $1,295 related to the cash settlement of our economic hedges. The net realized gain included $129 settlement to close-out 3,000 Bbls of our oil commodity contract position.

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


	For the Three Months Ended September 30,
	2015			2014
	(in dollars per Mcfe)
Average price	$	3.30		$	3.82

Production costs		2.42			1.64
Production taxes		0.22			0.45
Depletion and amortization		1.74			2.43
Total operating costs		4.38			4.52
Gross margin (loss)	$	(1.08)		$	(0.70)
Gross margin (loss) percentage		(33)	%		(18)	%

Total well production costs decreased 19% to $2,660. Production costs on a per Mcfe basis increased 48%, or $0.78, to $2.42, primarily due to the decrease in production volumes, as a portion of our production costs are fixed, or partially fixed.

Production taxes decreased 73% to $244 for the three months ended September 30, 2015 and production taxes, on a per Mcfe basis, decreased $0.23 to $0.22 per Mcfe. We are required to pay taxes on the revenue generated upon the physical sale of our gas to counterparties, which represent approximately 12% of natural gas sales. Production taxes decreased due to the decline in oil and natural gas revenue. Production taxes in 2015 were lower both in total and on a per Mcfe basis, as a portion of our revenue was generated from the settlement of commodity derivatives, which is not subject to production taxes.

Total depreciation, depletion and amortization expenses (“DD&A”) decreased 60% to $2,002, and depletion and amortization related to producing assets decreased 61% to $1,917. Expressed on a per Mcfe basis, depletion and amortization related to producing assets decreased 28%, or $0.69, to $1.74. The decrease in DD&A on a per Mcfe basis was primarily the result of the completion of the Pinedale Anticline sale on July 31, 2015.

Pipeline operating costs

Pipeline operating costs decreased 51% to $469. In April 2015, we completed our project to change-out our electric powered compressors to natural gas powered compressors, which we believe to be more economic in a low commodity

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price environment. Our power charges and compression rental costs were lower during the three months ended September 30, 2015 as a result of this change.

Impairment and abandonment of equipment and properties

We recorded impairment and abandonment expense in the three months ended September 30, 2015 of $23, related to the write-off of expiring undeveloped acreage in Wyoming as we believe we will not be able to develop this acreage before such leases expire.

General and administrative expenses

G&A expenses decreased 11% to $1,352 from a $234 decrease in salary and salary-related expenses due to lower 2015 headcount and severance incurred in 2014, a decrease of $88 due to the reduction of our board size from six outside directors to three, and a $64 decrease in stock compensation expense. This was offset, in part, by an increase in consulting and other professional fees of $231.

Income taxes

We did not record an income tax benefit for the three months ended September 30, 2015, as we had a full valuation against our net deferred tax assets.

Nine Months Ended September 30, 2015 Compared to the Nine Months Ended September 30, 2014

The following analysis provides comparison of the nine months ended September 30, 2015 and the nine months ended September 30, 2014.

Natural gas and oil sales

Natural gas and oil sales decreased 63% to $10,190, due to a 34% decrease in production volumes, primarily at our Atlantic Rim property, compounded by a 42% decrease in the Colorado Interstate Gas (“CIG”) market price, which is the index on which most of our natural gas volumes are sold.

As shown in the table below, our average realized natural gas price decreased 20% to $3.09 per Mcf. We calculate our average realized natural gas price by summing (1) production revenues received from third parties for the sale of our gas, which is included within natural gas and oil sales on the consolidated statements of operations, and (2) realized gains/(losses) on our commodity derivatives, which is included within price risk management activities, net on the consolidated statements of operations, totaling $3,549 and $(1,360) for the nine months ended September 30, 2015 and 2014, respectively. The 2015 and 2014 net realized gain and commodity contracts considered in the average realized price calculation, excluded the $129 and $1,343 gain realized for the nine months ended September 30, 2015 and 2014, on the settlement of our commodity contracts.


	Nine Months Ended September 30,
	2015			2014			Percent		Percent
			Average			Average	Volume		Price
Product:	Volume		Price	Volume		Price	Change		Change
Gas (Mcf)	4,099,606	$	3.09	6,254,007	$	3.89	(34)	%	(20)	%
Oil (Bbls)	12,688	$	82.96	19,785	$	88.72	(36)	%	(6)	%
Mcfe	4,175,734	$	3.29	6,372,714	$	4.09	(34)	%	(20)	%

Our total net production decreased 34% to 4.2 Bcfe for the nine months ended September 30, 2015 primarily due to lower production from our properties in the Atlantic Rim.

Our total average daily net production at the Atlantic Rim decreased 35% to 11,598 Mcfe. Average daily net production at our Catalina Unit decreased 37% to 8,092 Mcfe. During the first four months of 2015, we had approximately 25 wells generating lower than expected production as a result of mechanical problems; however we deferred maintenance on these wells due to depressed natural gas prices and our plans to replace our electric powered compressors with more cost efficient natural gas powered compressors in order to reduce operating costs in the field. The compressor change-out was completed

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in late April 2015, and we began a strategic workover program focused on improving production from these wells in late May 2015. We also realized a decrease in production due to the normal field production decline.

Average daily production, net to our interest, at the Spyglass Hill Unit decreased 28% to 3,507 Mcfe. Although the operator drilled 59 new production wells in the Spyglass Hill Unit since the third quarter of 2013, we have not realized an increase in production volumes due to infrastructure constraints in the unit. In addition, a significant number of wells are offline within the Spyglass Hill Unit. The operator did commence a well workover program in the third quarter of 2015, which is expected to increase production in future periods. Additionally, during the third quarter of 2015 the operator adjusted sales volume and revenue for its 2013 and 2014 drilling programs in accordance with the unit operating agreement. The drilling programs resulted in a decrease in net revenue as the Company’s net acreage decreased. No drilling is planned in this unit for 2015.

On the Pinedale Anticline, our average daily net production decreased 39% to 2,449 Mcfe as a result of the Pinedale Anticline sale and normal production decline. The initial production rates from wells in this field are very strong and then decline quickly. The operator drilled the final well in the Mesa B Unit in early 2014, and therefore our production began to decline as we did not have any material interest in the new development in the area. We completed our sale of our interests in these Pinedale assets on July 31, 2015. The effective date of this transaction was April 1, 2015, and the net cash flow we received from these properties after that date was credited back to the buyer as a closing adjustment.

Transportation and gathering revenue

We receive fees for gathering and transporting third-party gas through our intrastate gas pipeline, which connects the Catalina Unit with the interstate pipeline system owned by Southern Star Central Gas Pipeline, Inc. Transportation and gathering revenue decreased 35% to $1,771 for the nine months ended September 30, 2015, due to the decrease in Catalina production volumes as compared to the prior-year period.

Price risk management activities

We recorded a net gain on our derivative contracts of $5,042. This consisted of an unrealized non-cash gain of $1,364, which represents the change in the fair value of our commodity derivatives at September 30, 2015 based on the expected future prices of the related commodities, and a net realized gain of $3,678 related to the cash settlement of our economic hedges. The net realized gain included $129 settlement to close-out 3,000 Bbls of our oil commodity contract position.

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


	For the Nine Months Ended September 30,
	2015			2014
	(in dollars per Mcfe)
Average price	$	3.29		$	4.09

Production costs		2.08			1.53
Production taxes		0.26			0.51
Depletion and amortization		2.02			2.33
Total operating costs		4.36			4.37
Gross margin (loss)	$	(1.07)		$	(0.28)
Gross margin (loss) percentage		(33)	%		(7)	%

Overall well production costs decreased 11% to $8,694, primarily due to the deferral of maintenance costs at both the Catalina Unit and the Spyglass Hill Unit. The Company delayed its maintenance program at the Catalina Unit to late May 2015 due to depressed commodity prices, the completion of its compressor change-out from electrical to natural gas, and also due to significant rainfall in the area during April and May 2015. Management believes that the operator of the Spyglass Hill Unit has delayed its maintenance activity for similar reasons, in addition to shifting its efforts to other properties as a result of its recent significant acquisition in the northeastern U.S. The Spyglass Hill Unit operator did commence a well workover program during the third quarter of 2015. Production costs on a per Mcfe basis increased 36%, or $0.55, to $2.08, primarily due to the decrease in production volumes, as a portion of our production costs are fixed, or partially fixed.

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Production taxes decreased 67% to $1,078 for the nine months ended September 30, 2015 and production taxes, on a per Mcfe basis, decreased $0.25 to $0.26 per Mcfe. We are required to pay taxes on the revenue generated upon the physical sale of our gas to counterparties, which represent approximately 12% of natural gas sales. Production taxes decreased due to the decline in oil and natural gas revenue. Production taxes in 2015 were lower both in total and on a per Mcfe basis, as a portion of our revenue was generated from the settlement of commodity derivatives, which is not subject to production taxes. In 2014, we realized a loss on our commodity derivatives, yet paid taxes on the prevailing commodity market prices.

Total DD&A decreased 43% to $8,702, and depletion and amortization related to producing assets decreased 43% to $8,440. Expressed on a per Mcfe basis, depletion and amortization related to producing assets decreased 13%, or $0.31, to $2.02. The decrease in DD&A on a per Mcfe basis was primarily the result of a lower depletion rate at the Catalina, Spyglass Hill, and Pinedale Units due to a decrease in our production. In addition, we stopped recording depletion on our Pinedale assets in June 2015 as the assets were sold.

Pipeline operating costs

Pipeline operating costs decreased 41% to $1,926. In April 2015, we completed our project to change-out our electric powered compressors to natural gas powered compressors, which we believe to be more economic in a low commodity price environment. Our power charges and compression rental costs were lower during the nine months ended September 30, 2015 as a result of this change.

Impairment and abandonment of equipment and properties

We recorded impairment and abandonment expense in the nine months ended September 30, 2015 of $21,824, of which $21,030 related to a write-down of our Pinedale assets to fair market value, as a result of our decision to sell these assets, which was completed in July 2015. The remaining impairment expense recognized during the nine months ended September 30, 2015 was primarily due to an increase in estimated field abandonment costs (and thus the associated asset carrying value) at the Main Fork Unit property and the write-off of expiring undeveloped acreage in Wyoming as we believe we will not be able to develop this acreage before such leases expire.

General and administrative expenses

G&A expenses decreased 20% to $4,250. In 2014, we recorded severance expense of $856 primarily related to the severance for our former chief executive officer; no severance-related expenses were incurred in 2015. Legal costs decreased by $116 due to the fewer corporate matters requiring legal services and our improved management of legal services. Additionally, stock-based compensation expense decreased by $165 as there were fewer outstanding awards during the nine months ended September 30, 2015. Director’s fees decreased $93 due to the reduction of our board size from six outside directors to three. These decreases were offset, in part, by an increase in financial advisory services and contract labor, both of which totaled $330.

Provision for gas-to-liquids advance

We recorded a provision of $202 in the first quarter of 2015 for the reimbursement of amounts advanced for the GTL plant by us in 2015. In May 2014, we entered into a Letter Agreement to jointly initiate the development, construction and operations of a GTL plant to be located in Wyoming. The Letter Agreement expired effective January 31, 2015 as we were unable to agree on terms for a definitive agreement with WYGTL, as contemplated by the Letter Agreement. In accordance with the provisions of the Letter Agreement, we requested WYGTL to repay to us the total amount we advanced, or $1,362. As the future collection of this amount is uncertain, we recorded a provision to fully allow for the outstanding advances during the first quarter of 2015.

Income taxes

We did not record an income tax benefit for the nine months ended September 30, 2015 as we had a full valuation against our net deferred tax assets.

OVERVIEW OF FINANCIAL CONDITION AND LIQUIDITY

Liquidity and Capital Resources

Our sources of liquidity and capital resources historically have been net cash provided by operating activities, funds available under our credit facilities and proceeds from offerings of equity securities. The primary uses of our liquidity and

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capital resources have been in the development and exploration of oil and gas properties. Since our Chapter 11 filing, our principal sources of liquidity have been limited to the liquidation of our 2016 natural gas hedges, cash flow from operations and other cash on hand. In addition to the cash requirements necessary to fund our ongoing operations, we expect to incur significant professional fees and other costs in connection with the administration of our Chapter 11 proceeding.

Although we believe our cash flow from operations and cash on hand (including the net cash proceeds from the liquidation of certain natural gas hedges in October 2015) will be adequate to meet the operating costs of our existing business and additional costs in connection with our Chapter 11 proceedings, there are no assurances that our cash flow from operations and cash on hand will be sufficient to allow us to continue as a going concern until a Chapter 11 plan is confirmed by the Bankruptcy Court or other alternative restructuring transaction is approved by the Bankruptcy Court and consummated. Our long-term liquidity requirements, the adequacy of our capital resources and our ability to continue as a going concern are difficult to predict at this time and ultimately cannot be determined until a Chapter 11 plan has been confirmed, if at all, by the Bankruptcy Court. If our future sources of liquidity are insufficient, we could face substantial liquidity constraints and be unable to continue as a going concern and will likely be required to significantly reduce, delay or eliminate capital expenditures, implement further cost reductions, seek other financing alternatives or seek the sale of some or all of our assets. Constraints on our capital expenditures, combined with delays in development of properties and significant cost cutting initiatives will adversely affect the value of our oil and natural gas properties, our financial condition and results of operations.

Credit Facility

As of September 30, 2015 we had a credit agreement in place with a $33,500 borrowing base with an outstanding balance of $36,886, which resulted in a borrowing base deficiency of $3,386. We have depended on our credit facilities over the past five years to supplement our operating cash flow in the development of the Company-operated Catalina Unit and other non-operated projects in the Atlantic Rim and projects in the Pinedale Anticline.

We are subject to both financial and non-financial covenants. The financial covenants, as defined in the Credit Agreement, include maintaining (1) a current ratio of 1.0 to 1.0; (2) a ratio of earnings before interest, taxes, depreciation, depletion, amortization, exploration and other non-cash items (“EBITDAX”) to interest plus dividends of greater than 1.5 to 1.0; and (3) a funded debt, less unencumbered cash, to EBITDAX ratio of less than 4.0 to 1.0. As of September 30, 2015, we were in violation of each of the aforementioned covenants.

In addition, we had previously triggered two additional events of default under the Credit Agreement: (1) our independent registered public accounting firm had included a going concern explanatory paragraph in its audit opinion in our consolidated financial statements for the year ended December 31, 2014, and (2) we have not fully paid our ad valorem taxes assessed in 2014 (due in May 2015) for certain of our properties.

On November 5, 2015, the Company filed a Bankruptcy Petition for reorganization under the Bankruptcy Code. The filing of the Bankruptcy Petition triggered an additional event of default under the Credit Agreement.

As of September 30, 2015, borrowings under the credit facility incurred interest daily based at our interest rate election of either the Base Rate or LIBOR Rate. Under the Base Rate option, interest is calculated at an annual rate equal to the highest of (a) the base rate for Dollar loans for such day, Federal Funds rate for such day, plus 0.5%, or the LIBOR for such day plus (b) a margin ranging between 0.75% and 1.75% (annualized) depending on the level of funds borrowed. Under the LIBOR Rate option, interest is calculated at an annual rate equal to LIBOR, plus a margin ranging between 1.75% and 2.75% (annualized) depending on the level of funds borrowed. In addition to the standard interest charge, we became subject to an additional penalty rate of 2.0% (annualized) effective May 19, 2015 as a result of the aforementioned events of default. The average interest rate on the facility at September 30, 2015 was 5.35%.

Other

In January 2015, we received notice from the Nasdaq Stock Market (“Nasdaq”) indicating that our common stock was subject to potential delisting from Nasdaq because our common stock had closed below the minimum $1.00 per share

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requirement for 30 consecutive days. In April 2015, we received an additional notice from Nasdaq indicating that our common stock was subject to delisting because the market value of our common stock was below the required $5,000 required for listing on the Global Select Market. On July 23, 2015, as a result of not complying with Nasdaq’s minimum $1.00 per share requirement, Nasdaq’s listing for our common stock was moved to the Nasdaq Capital Market. In August 2015, we received another notice from Nasdaq that we were no longer in compliance with the minimum stockholders’ equity requirement and were subject to delisting if we did not submit a plan to regain compliance with this requirement. On October 7, 2015, we voluntarily requested that our common stock be delisted from Nasdaq, as we did not meet continued listing requirements and did not anticipate being able to meet such requirements in the future. The trading of our common stock was subsequently moved to OTC Market’s OTC Pink marketplace. As a result of our Chapter 11 filing, our Series A Preferred Stock was delisted from Nasdaq and currently trades on OTC Market’s OTC Pink marketplace.

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


	September 30,			December 31,
	2015			2014
	(unaudited)
Financial Position Summary
Cash and cash equivalents	$	2,452		$	5,933
Working capital (deficit)	$	(34,741)		$	(43,548)
Balance outstanding on credit facility	$	36,886		$	47,515
Preferred Stock	$	37,972		$	37,972
Stockholders’ (deficit) equity	$	(10,166)		$	20,906
Ratios
Debt to total capital ratio (1)		57.0	%		44.7	%
Debt to equity ratio		(362.8)	%		227.3	%

(1)

Total capital includes our preferred stock, stockholder’s equity and the $36,886 and $47,515 outstanding on our credit facility at September 30, 2015 and December 31, 2014, respectively.

Working capital (deficit)

Our working capital (deficit) as of September 30, 2015, includes the impact of our debt reclassification to a current liability in 2014, due to the events of default described above. Excluding the impact of this reclassification, our working capital was lower as of September 30, 2015, primarily due to a $3,481 decrease in cash and a $2,219 decrease in accounts receivable as a result of lower production and natural gas prices, as well as a $1,078 decrease in other current assets. This was offset, in part, by a $3,192 increase in the fair value of our commodity derivatives and a decrease in accounts payable and accrued expenses of $1,755 as compared to December 31, 2014.

In connection with our Chapter 11 filing in November 2015, on October 30, 2015 we liquidated our 2016 natural gas hedges which resulted in net proceeds of $8,047. Following our Chapter 11 filing, we expect our working capital to continue to decrease as a result of the depressed natural gas prices and decreasing production. While we currently believe we have sufficient liquidity to file, confirm and consummate a plan of reorganization under the provisions of the Term Sheet, any unforeseen changes to anticipated timing and the ability to complete our restructuring may negatively impact our liquidity and prevent a restructuring.

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Cash flow activities

The table below summarized the nine months ended September 30, 2015 and 2014, respectively:


	For the Nine Months Ended September 30,
	2015		2014
Cash provided by (used in):
Operating activities	$	200	$	9,554
Investing activities		6,820		(3,119)
Financing activities		(10,501)		(2,008)
Net change in cash	$	(3,481)	$	4,427

During the nine months ended September 30, 2015, net cash provided by operating activities was $200, as compared to net cash provided by operating activities of $9,554 in the same prior-year period. The primary uses of cash during the nine months ended September 30, 2015 resulted from a net loss of $(31,439), which was net of non-cash charges of $21,824 primarily related to the impairment of our Pinedale assets, $8,901 related to DD&A and accretion expense, a $1,364 unrealized net gain related to the change in fair value of our derivative contracts and $368 in stock-based compensation expense. Our cash flow used in operations for the nine months ended September 30, 2015 resulted largely due to a decrease in production volumes of 34%, or approximately 2.2 Bcfe. In addition, our average realized price decreased $0.80 per Mcfe due to lower market prices and less favorable economic hedges.

Our operating cash flow is highly sensitive to fluctuations in the price of natural gas. Our hedging program helps to mitigate fluctuations due to price volatility. However, the structure of the hedges in place in 2015 does not fully limit the downside of price fluctuations. Natural gas prices have fallen as compared to 2014, which will negatively impact our cash flow. Taking into account our economic hedges, for the nine months ended September 30, 2015, our income before income taxes and cash flow would have decreased by approximately $1,794 for each $0.50 change per Mcf in natural gas prices.

During the nine months ended September 30, 2015, net cash provided by investing activities was $6,820, as compared to net cash used in investing activities of $(3,119) in the same prior-year period. In 2015, we completed the sale of our Pinedale Anticline assets, resulting in an increase in cash of $10,762. In addition to the sale of the Nevada leases of $263. This was offset, in part, by capital spending primarily related to payment of costs associated with the 2014 drilling program at the Spyglass Hill Unit. In 2014, our capital spending was primarily related to payment of costs associated with the Spyglass Hill and Mesa “B” 2013 drilling programs.

Cash used in financing activities was $(10,501) for the nine months ended September 30, 2015, as compared to cash used in financing activities of $(2,008) for the nine months ended September 30, 2014. In 2015, we completed the sale of our Pinedale Anticline assets, of which $10,500 was used to repay amounts outstanding under our credit facility. In 2014 cash used in financing activities was the results of several activities, including; the repayment of amounts due under our prior credit facility, the payment of quarterly dividends on our Series A Preferred Stock, offset, in part, by proceeds from an offering of our common stock through a private placement and net proceeds from the refinancing of our then existing credit facility.

Capital Requirements

The Company has historically assessed active and potential development projects to determine the best use for available capital. Such assessment has included analyzing the risk and estimated return for each proposed project, including our non-operated assets (primarily the Spyglass Hill Unit in the Atlantic Rim). Due to our current lack of liquidity and the current market and commodity price conditions, we have not budgeted for any capital projects in 2015, and we will assess any potential opportunities on an individual basis. Constraints on our capital expenditures, combined with delays in development of properties and significant cost cutting initiatives will adversely affect the value or our natural gas and oil properties, our financial condition and results of operations.

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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 September 30, 2015 are summarized below (volume and daily production are expressed in Mcf). All of our natural gas contracts are indexed to the NYMEX. The prevailing natural gas market prices in the Rockies, including CIG which is the index on which most of our gas volumes are sold, tend to be sold at a discount relative to other U.S. natural gas markets, including NYMEX. This discount is typically referred to as a “basis differential” and reflects, to some extent, the costs associated with transporting the natural gas in the Rockies to markets in the other regions. It also reflects the general excess supply and lack of pipeline capacity in the region.


Type of Contract	Remaining Contractual Volume (Bbls)	Term	Price ($/Bbl)(1)
Fixed price swap	3,300	10/15-12/15	$	91.44
Total contracted oil volumes	3,300

Type of Contract	Remaining Contractual Volume (Mcf)	Term	Price ($/Mcf)(2)
Three-way costless collar	1,650,000	10/15-12/15	$	3.25	put (short)
			$	3.85	put (long)
			$	4.08	call (short)
Total 2015 contracted volumes	1,650,000

Fixed price swap	1,830,000	01/16-12/16	$	4.07
Fixed price swap	3,660,000	01/16-12/16	$	4.15
Total 2016 contracted volumes	5,490,000

Total contracted natural gas volumes	7,140,000

(1)

New York Mercantile Exchange (“NYMEX”) Light Sweet Crude Oil (“WTI”).

(2)

NYMEX Henry Hub Natural Gas (“NG”)

In connection with the Company’s filing of the Bankruptcy Petition described above in Note 2, the Company has an agreement with the lenders under the Credit Agreement for the use of cash collateral. In accordance with this agreement for the use of cash collateral, for the use of cash collateral, the Company terminated its 2016 natural gas hedges (total contracted volumes of 5,490,000 Mcf) on October 30, 2015 resulting in net cash proceeds of $8,047.

In connection with the sale of the Pinedale Anticline assets on July 31, 2015, the Company liquidated a portion of its contracted oil volumes (3,000 Bbls) for cash proceeds of $129, which was used to pay down its outstanding borrowings on its credit facility

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2014, and to the Notes to the Consolidated Financial Statements included in Part I, Item 1 of this report.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4.CONTROLS AND PROCEDURES

In accordance with the Exchange Act and Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Financial and Accounting Officer), of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on this evaluation, our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Financial and Accounting Officer) have concluded that our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and such information was accumulated and communicated to our management, as appropriate, to allow timely decisions regarding required disclosure.

There has been no change in our internal control over financial reporting that occurred during the quarter ended September 30, 2015 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, including the matters below, which are subject to the uncertainties inherent in any litigation. We are defending the Company vigorously in all such matters, and while the ultimate outcome and impact of any proceeding cannot be predicted with certainty, management believes that the resolution of any proceeding will not have a material adverse effect on the Company’s financial condition or results of operations.

Gas-to-liquids project

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

The Letter Agreement expired effective January 31, 2015, as we was unable to agree on terms for a definitive agreement with WYGTL, as contemplated by the Letter Agreement. In accordance with the provisions of the Letter Agreement, we requested WYGTL to repay to us the total amount advanced, or $1,362. We filed a lawsuit in the state of Colorado on March 24, 2015, against WYGTL for breach of the Letter Agreement terms, seeking recovery of the total amount advanced under the Letter Agreement. We were unable to serve WYGTL with the complaint due to unknown whereabouts of WYGTL’s owner. On April 14, 2015, WYGTL filed a lawsuit against the Company in the U.S. District Court for Colorado, an action entitled Alan Eugene Humphrey and Wyoming GTL, LLC v. Escalera Resources Co., alleging the Company breached its contract with WYGTL, among other claims. We do not believe the case has merit and are defending the case vigorously. We subsequently filed counterclaims against WYGTL on May 5, 2015 in United States District Court seeking recovery of the total advances, and dismissed our original action filed in the State of Colorado.

As a result of the Company’s Bankruptcy Case, the GTL related litigation has been stayed.

Former employee lawsuits

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

As a result of the Company’s Bankruptcy Case, the former employee lawsuits have been stayed.

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


Period	Total Number of Shares Purchased		Average Price Paid per Share	Total Number of Shares Purchased as Part of Publically Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
July 2015	3,977	(1)	$ 0.27	-	-
August 2015	-		-	-	-
September 2015	-		-	-	-

(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:
10.1		Employment Agreement dated March 24, 2014 between the Company and Charles Chambers (incorporated by reference from Form 10-Q for the quarter ended March 31, 2014).

10.1(a)		Purchase and Sale Agreement (Coalbed Methane Assets) dated June 16, 2015 between the Company and Warren Resources, Inc et al (incorporated by reference from Form 10 Q for the quarter ended June 30, 2015).

10.1(b)		Purchase and Sale Agreement (Midstream Assets) dated June 16, 2015 between the Company and Warren Energy Services LLC et al (incorporated by reference from Form 10 Q for the quarter ended June 30, 2015).

10.1(c)		Purchase and Sale Agreement (Deep Rights) dated June 16, 2015 between the Company and Warren Resources, Inc et al (incorporated by reference from Form 10 Q for the quarter ended June 30, 2015).

10.1(d)		Forbearance Agreement and First Amendment to Credit Agreement dated July 31, 2015 between the Company and its subsidiaries and Société Générale as administrative agent (incorporated by reference from Form 10 Q for the quarter ended June 30, 2015).

10.1(e)		Purchase Sale Agreement dated July 31, 2015 between the Company and Vanguard Operating, LLC as buyer (incorporated by reference from Form 10 Q for the quarter ended June 30, 2015).

10.1(f)		Amendment of Purchase and Sale Agreements and Letter Agreement dated August 28, 2015 between the Company and Warren Resources, Inc. and its subsidiaries (incorporated by reference from Form 8 K file on September 3, 2015).

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: November 23, 2015	By:	/S/ Charles F. Chambers
		Charles F. Chambers
		Chief Executive Officer
		(Principal Executive Officer)

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EXHIBIT INDEX


Exhibit		Description:
10.1		Employment Agreement dated March 24, 2014 between Double Eagle Petroleum Co. and Charles Chambers (incorporated by reference from Form 10-Q for the quarter ended March 31, 2014).

10.1(a)		Purchase and Sale Agreement (Coalbed Methane Assets) dated June 16, 2015 between the Company and Warren Resources, Inc et al (incorporated by reference from Form 10 Q for the quarter ended June 30, 2015).

10.1(b)		Purchase and Sale Agreement (Midstream Assets) dated June 16, 2015 between the Company and Warren Energy Services LLC et al (incorporated by reference from Form 10 Q for the quarter ended June 30, 2015).

10.1(c)		Purchase and Sale Agreement (Deep Rights) dated June 16, 2015 between the Company and Warren Resources, Inc et al (incorporated by reference from Form 10 Q for the quarter ended June 30, 2015).

10.1(d)		Forbearance Agreement and First Amendment to Credit Agreement dated July 31, 2015 between the Company and its subsidiaries and Société Générale as administrative agent (incorporated by reference from Form 10 Q for the quarter ended June 30, 2015).

10.1(e)		Purchase Sale Agreement dated July 31, 2015 between the Company and Vanguard Operating, LLC as buyer (incorporated by reference from Form 10 Q for the quarter ended June 30, 2015).

10.1(f)		Amendment of Purchase and Sale Agreements and Letter Agreement dated August 28, 2015 between the Company and Warren Resources, Inc. and its subsidiaries (incorporated by reference from Form 8 K file on September 3, 2015).

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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