Quarterly Report (10-q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2013

¨	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

DOUBLE EAGLE PETROLEUM 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 x No ¨

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

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

Large accelerated filer	¨	Accelerated filer	¨

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

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

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

Class		Shares outstanding as of November 1, 2013
Common stock, $.10 par value		11,351,412

DOUBLE EAGLE PETROLEUM CO.

FORM 10-Q

TABLE OF CONTENTS

		Page #

PART I. Financial Information:

	Item 1. Financial Statements
	Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012 (Unaudited)	3
	Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2013 and 2012 (Unaudited)	4
	Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2013 and 2012 (Unaudited)	5
	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2013 and 2012 (Unaudited)	6
	Notes to Consolidated Financial Statements (Unaudited)	7

	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	14

	Item 4. Controls and Procedures	23

PART II. Other Information:

	Item 1. Legal Proceedings	23

	Item 2. Unregistered sales of equity securities and use of proceeds	24

	Item 6. Exhibits	25

Signatures		26

PART I. FINANCIAL INFORMATION

ITEM	1 . FINANCIAL STATEMENTS

DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED BALANCE SHEETS

(Amounts in thousands of dollars except share data)

(Unaudited)

ASSETS	September 30, 2013			December 31, 2012
Current assets:
Cash and cash equivalents	$	3,804		$	4,070
Cash held in escrow		283			565
Accounts receivable		4,649			6,608
Assets from price risk management		3,174			6,742
Other current assets		3,207			3,024
Total current assets		15,117			21,009
Oil and gas properties and equipment, successful efforts method:
Developed properties		233,910			225,382
Wells in progress		8,591			10,963
Gas transportation pipeline		5,510			5,510
Undeveloped properties		2,704			2,734
Corporate and other assets		2,041			2,068
		252,756			246,657
Less accumulated depreciation, depletion and amortization		(125,207	)		(109,606	)
Net properties and equipment		127,549			137,051
Assets from price risk management		951			682
Other assets		58			68
TOTAL ASSETS	$	143,675		$	158,810

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	7,150		$	11,052
Accrued production taxes		2,984			1,906
Other current liabilities		219			200
Total current liabilities		10,353			13,158

Credit facility		47,450			47,450
Asset retirement obligation		8,788			8,494
Deferred tax liability		4,429			7,896
Other long-term liabilities		123			370
Total liabilities		71,143			77,368
Preferred stock, $0.10, par value; 10,000,000 shares authorized;
1,610,000 shares issued and outstanding as of September 30, 2013 and December 31, 2012		37,972			37,972
Stockholders’ equity:
Common stock, $0.10 par value; 50,000,000 shares authorized;
11,369,302 issued and 11,341,552 shares outstanding at September 30, 2013 and 11,305,043 shares issued and 11,279,268 outstanding at December 31, 2012		1,134			1,128
Additional paid-in-capital		43,156			45,405
Accumulated deficit		(9,730	)		(3,063	)
Total stockholders’ equity		34,560			43,470
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	143,675		$	158,810

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

DOUBLE EAGLE PETROLEUM 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,
	2013			2012			2013			2012
Revenues
Oil and gas sales	$	7,599		$	6,498		$	23,634		$	17,742
Transportation revenue		914			1,276			2,751			3,763
Price risk management activities		630			(1,827	)		1,264			2,705
Other income, net		(2	)		(46	)		506			(23	)
Total revenues		9,141			5,901			28,155			24,187
Costs and expenses
Production costs		3,150			2,766			9,346			8,682
Production taxes		886			783			2,851			1,921
Exploration expenses including dry hole costs		52			62			122			638
Pipeline operating costs		1,238			1,184			3,950			3,633
General and administrative		983			1,513			3,946			4,736
Impairment and abandonment of equipment and properties		(36	)		21			1,500			330
Depreciation, depletion and amortization		5,178			4,779			15,631			14,186
Total costs and expenses		11,451			11,108			37,346			34,126
Income (loss) from operations		(2,310	)		(5,207	)		(9,191	)		(9,939	)
Interest expense, net		(488	)		(516	)		(943	)		(1,369	)
Income (loss) before income taxes		(2,798	)		(5,723	)		(10,134	)		(11,308	)
Benefit (provision) for deferred income taxes		946			2,155			3,467			4,043
Net income (loss)	$	(1,852	)	$	(3,568	)	$	(6,667	)	$	(7,265	)
Preferred stock dividends		930			930			2,792			2,792
Net loss attributable to common stock	$	(2,782	)	$	(4,498	)	$	(9,459	)	$	(10,057	)
Net loss per common share:
Basic	$	(0.25	)	$	(0.40	)	$	(0.84	)	$	(0.89	)
Diluted	$	(0.25	)	$	(0.40	)	$	(0.84	)	$	(0.89	)
Weighted average shares outstanding:
Basic		11,341,277			11,255,229			11,324,653			11,240,945
Diluted		11,341,277			11,255,229			11,324,653			11,240,945

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

DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Amounts in thousands of dollars)

(Unaudited)

	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013			2012
Net income (loss)	$	(1,852	)	$	(3,568	)	$	(6,667	)	$	(7,265	)
Other comprehensive income, net of tax		—			—			—			—
Comprehensive income (loss)	$	(1,852	)	$	(3,568	)	$	(6,667	)	$	(7,265	)

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

DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED ST ATEMENTS OF CASH FLOWS

(Amounts in thousands of dollars)

(Unaudited)

	Nine months ended September 30,
	2013			2012
Cash flows from operating activities:
Net loss	$	(6,667	)	$	(7,265	)
Adjustments to reconcile net loss to net cash from operating activities:
Depreciation, depletion, amortization and accretion of asset retirement obligation		15,822			14,328
Impairment and abandonment of equipment and properties		1,500			330
Dry hole costs		—			462
Provision for deferred benefit		(3,467	)		(4,042	)
Stock-based compensation expense		570			1,234
Change in fair value of derivative contracts		3,071			8,082
Settlement on asset retirement obligation		—			(2	)
Loss on sale of working interest in non-producing property		12			16
Changes in current assets and liabilities:
Decrease (increase) in deposit held in escrow		282			(1	)
Decrease in accounts receivable		1,959			937
Decrease in other current assets		283			369
Decrease in accounts payable and accrued expenses		(4,160	)		(1,202	)
Increase in accrued production taxes		1,078			384
NET CASH PROVIDED BY OPERATING ACTIVITIES		10,283			13,630
Cash flows from investing activities:
Payments to acquire producing properties and equipment, net		(7,729	)		(20,530	)
Payment to acquire corporate and non-producing properties		(7	)		(24	)
NET CASH USED IN INVESTING ACTIVITIES		(7,736	)		(20,554	)
Cash flows from financing activities:
Tax withholdings related to net share settlement of restricted stock awards		(21	)		(24	)
Dividends on preferred stock		(2,792	)		(2,792	)
Net borrowings (repayments) on credit facility		—			4,200
NET CASH USED IN FINANCING ACTIVITIES		(2,813	)		1,384
Change in cash and cash equivalents		(266	)		(5,540	)
Cash and cash equivalents at beginning of period		4,070			8,678
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	3,804		$	(3,138	)
Supplemental disclosure of cash and non-cash transactions:
Cash paid for interest	$	1,254		$	961
Interest capitalized	$	67		$	226
Additions to developed properties included in current liabilities	$	2,523		$	2,246

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

DOUBLE EAGLE PETROLEUM 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 Double Eagle Petroleum Co. (“Double Eagle” 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.

Certain amounts in the 2012 consolidated financial statements have been reclassified to conform to the 2013 consolidated financial statement presentation. Such reclassifications had no effect on net income.

The accounting policies followed by the Company are set forth in Note 1 to the Company’s consolidated financial statements in the Annual Report on Form 10-K for the year ended December 31, 2012, and are supplemented throughout the notes to this Quarterly Report on Form 10-Q.

The unaudited interim consolidated financial statements presented herein should be read in conjunction with the consolidated financial statements and notes thereto included in the Annual Report on Form 10-K for the year ended December 31, 2012.

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”). In 2006, the Company sold transportation assets located in the Catalina Unit, at cost, to EWM in exchange for an intercompany note receivable bearing interest of 5% per annum, maturing on January 31, 2028. The note and related interest are fully eliminated in consolidation. In addition, the Company has an agreement with EWM under which the Company pays a fee to EWM to gather, compress and transport gas produced at the Catalina Unit. This fee is also eliminated in consolidation.

Recently adopted accounting pronouncements

In January 2013, the Financial Accounting Standards Board issued Accounting Standards Update No. 2013-01 (“ASU No. 2013-01”), ASU No. 2013-01 clarifies that the scope of Accounting Standards Update No. 2011-11 , Disclosures about Offsetting Assets and Liabilities (“ASU No. 2011-11”), would apply to derivatives including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset or are subject to a master netting arrangement or similar agreement. ASU No. 2011-11, issued in December 2011, requires that entities disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an agreement similar to a master netting arrangement. In addition, the standard requires disclosure of collateral received and posted in connection with master netting agreements or similar arrangements. The Company adopted ASU No. 2013-01 effective January 1, 2013, and it did not have an effect on the Company’s consolidated financial statements.

2 .	Earnings per share

Basic earnings per share is calculated by dividing net income (loss) attributable to common stock by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share incorporates the treasury stock method to measure the dilutive impact of potential common stock equivalents by including the effect of outstanding vested and unvested stock options and unvested stock awards in the average number of shares of common stock outstanding during the period. Income attributable to common stock is calculated as net income less dividends paid on the Company’s Series A Preferred Stock. The Company declared and paid cash dividends of $930 ($.5781 per share of preferred stock) for each of the three months ended September 30, 2013 and 2012 and $2,792 for the each of the nine months ended September 30, 2013 and 2012.

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,
	2013			2012			2013			2012
Net income (loss)	$	(1,852	)	$	(3,568	)	$	(6,667	)	$	(7,265	)
Preferred stock dividends		930			930			2,792			2,792
Net loss attributable to common stock	$	(2,782	)	$	(4,498	)	$	(9,459	)	$	(10,057	)
Weighted average shares:
Weighted average shares—basic		11,341,277			11,255,229			11,324,653			11,240,945
Dilution effect of stock options outstanding at the end of period		—			—			—			—
Weighted average shares—diluted		11,341,277			11,255,229			11,324,653			11,240,945
Net loss per common share:
Basic	$	(0.25	)	$	(0.40	)	$	(0.84	)	$	(0.89	)
Diluted	$	(0.25	)	$	(0.40	)	$	(0.84	)	$	(0.89	)

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,
		2013	2012		2013	2012
Anti-dilutive shares		75,978	83,617		56,395	74,557

3.	Credit Facility

As of September 30, 2013, the Company had a $150,000 revolving line of credit in place with a $60,000 borrowing base. The credit facility is collateralized by the Company’s oil and gas producing properties. Any balance outstanding on the credit facility is due October 24, 2016.

As of September 30, 2013, the outstanding balance of $47,450 on the credit facility has been used to fund the development of the Catalina Unit and other non-operated projects in the Atlantic Rim, development projects in the Pinedale Anticline, and the Company’s Niobrara exploration project.

Borrowings under the revolving line of credit bear interest at a daily rate equal to (a) the highest of the Federal Funds rate, plus 0.5%, the Prime Rate or the Adjusted Eurodollar Rate plus (b) a margin ranging between 0.75% and 2.75% depending on the level of funds borrowed. The average interest rate on the facility at September 30, 2013, including the impact of our interest rate swaps, was 3.3%. For the three months ended September 30, 2013 and 2012, the Company incurred interest expense on the credit facility of $407 and $363, respectively, and for the nine months ended September 30, 2013 and 2012, $1,232 and $1,027, respectively. Of the total interest incurred, the Company capitalized interest costs of $11 and $77 for the three months ended September 30, 2013 and 2012, respectively, and $67 and $226 for the nine months ended September 30, 2013 and 2012, respectively.

Under the credit facility, the Company is subject to both financial and non-financial covenants. The financial covenants, as defined in the credit agreement, include maintaining (i) a current ratio of 1.0 to 1.0; (ii) a ratio of earnings before interest, taxes, depreciation, depletion, amortization, exploration and other non-cash items (“EBITDAX”) to interest plus dividends of greater than 1.5 to 1.0; and (iii) a funded debt to EBITDAX ratio of less than 3.5 to 1.0. As of September 30, 2013, the Company was in compliance with all financial and non-financial covenants under the credit facility. If the covenants are violated and the Company is unable to negotiate a waiver or amendment thereof, the lenders would have the right to declare an event of default, terminat e the remaining commitment and accelerate all principal and interest outstanding.

4 .	Derivative Instruments

Commodity Contracts

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

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

The Company accounts for its derivative instruments as mark-to-market derivative instruments. Under mark-to-market accounting, derivative instruments are recognized as either assets or liabilities at fair value on the Company’s consolidated 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, 2013, 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, 2013:

Type of Contract	Remaining Contractual Volume (Mcf)	Term	Price			Price Index (1)
Fixed Price Swap	552,000	01/13-12/13	$	5.16		NYMEX
Costless Collar	552,000	01/13-12/13	$	5.00	floor	NYMEX
			$	5.35	ceiling
Costless Collar	540,000	01/13-12/13	$	3.25	floor	NYMEX
			$	4.00	ceiling
Fixed Price Swap	1,825,000	01/14-12/14	$	4.27		NYMEX
Fixed Price Swap	1,800,000	01/14-12/14	$	4.20		NYMEX
Costless Collar	1,800,000	01/14-12/14	$	4.00	floor	NYMEX
			$	4.50	ceiling
Fixed Price Swap	3,000,000	01/15-12/15	$	4.28		NYMEX

Total	10,069,000

(1)

New York Mercantile Exchange (“NYMEX”).

Interest Rate Swap

As of September 30, 2013, the Company had the following interest rate swap in place with a third party to manage the risk associated with the floating interest rate on its credit facility:

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

(1)

In accordance with its credit facility, the Company pays interest at a daily rate equal to (a) the higher of the Federal Funds rate, plus 0.5%, the Prime Rate or the Adjusted Eurodollar LIBOR rate, plus (b) a spread ranging from 0.75% to 2.75% depending on its outstanding borrowings. The effective interest rate shown reflects the interest rate based on the outstanding borrowings at September 30, 2013.

The table below contains a summary of all of the Company’s derivative positions reported on the consolidated balance sheet as of September 30, 2013, presented gross of any master netting arrangements:

Derivatives not designated as hedging instruments under ASC 815	Balance Sheet Location	Fair Value
Assets
Commodity derivatives	Assets from price risk management - current	$	3,182
	Assets from price risk management - long term		951
Liabilities
Commodity derivatives	Assets from price risk management - current	$	(8	)
Interest rate swap	Other current liabilities		(219	)
	Other long term liabilities		(123	)
Total		$	3,783

The before-tax effect of derivative instruments not designated as hedging instruments on the consolidated statements of operations for the three and nine months ended September 30, 2013 and 2012 was as follows:

	Amount of Gain (Loss) Recognized in Three Months Ended September 30,						Amount of Gain (Loss) Recognized in Nine Months Ended September 30,
	2013			2012			2013			2012
Unrealized loss on commodity contracts ¹	$	(1,028	)	$	(4,993	)	$	(3,299	)	$	(7,522	)
Realized gain on commodity contracts ¹		1,658			3,166			4,563			10,227
Unrealized gain (loss) on interest rate swap ²		(92	)		(226	)		228			(560	)
Realized loss on interest rate swap ²		(68	)		(26	)		(197	)		(75	)
Total activity for derivatives not designated as hedging instruments	$	470		$	(2,079	)	$	1,295		$	2,070

	¹ Included in price risk management activities on the consolidated statements of operations. Price risk management activities totaled $630 and $(1,827) for the three months ended September 30, 2013 and 2012, respectively, and $1,264 and $2,705 for the nine months ended September 30, 2013 and 2012, respectively.

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

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

5.	Fair Value of Financial Instruments

Assets and Liabilities Measured on a Recurring Basis

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

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

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

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

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

The following table provides a summary as of September 30, 2013 of assets and liabilities measured at fair value on a recurring basis:


	Level 1		Level 2		Level 3		Total
Assets
Derivative instruments -
Commodity forward contracts	$	—	$	4,125	$	—	$	4,125
Total assets at fair value	$	—	$	4,125	$	—	$	4,125
Liabilities
Derivative instruments -
Interest rate swap	$	—	$	342	$	—	$	342
Total liabilities at fair value	$	—	$	342	$	—	$	342

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, 2013.

The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above:

Derivative instruments

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

In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.

At September 30, 2013, the Company had various types of derivative instruments, which included costless collars and swaps. The natural gas derivative markets and interest rate swap markets are highly active. Although the Company’s economic hedges are valued using public indices, the instruments themselves are traded with third party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.

Credit facility

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

Concentration of credit risk

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

The Company currently uses two counterparties for its derivative financial instruments. The Company continually reviews the credit worthiness of its counterparties, which are generally other energy companies or major financial institutions. In addition, 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.

Assets and Liabilities Measured on a Non-recurring Basis

The Company utilizes fair value on a non-recurring basis to perform impairment tests as required on its property and equipment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property and equipment. The fair value of impaired assets is determined based on quoted market prices in active markets, if available, or upon the present values of expected future cash flows using discount rates commensurate with the risks involved in the asset group. The impairment analysis performed by the Company may utilize Level 3 inputs.

Based upon management’s analysis of formation attributes and its estimate of the present value of the future cash flows from its Niobrara exploration well, as of September 30, 2013, the Company does not believe it will recover the full amount of capitalized costs of this well and has written the well down to its estimated fair value. Refer to Note 6 for additional information regarding the impairment expense related to this well.

The following table provides a summary as of September 30, 2013 of assets measured at fair value on a nonrecurring basis:

	Level 1		Level 2		Level 3		Total
Assets
Oil and gas properties -
Niobrara exploration well	$	—	$	—	$	6,390	$	6,390
Total assets at fair value	$	—	$	—	$	6,390	$	6,390

6.	Impairment of Long-Lived Assets

The Company reviews the carrying values of its long-lived assets annually or whenever events or changes in circumstances indicate that such carrying values may not be recoverable. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis. The fair value of impaired assets is determined based on quoted market prices in active markets, if available, or upon the present values of expected future cash flows using discount rates commensurate with the risks involved in the asset group. The impairment analysis performed by the Company may utilize Level 3 inputs. The long-lived assets of the Company consist primarily of proved oil and gas properties and undeveloped leaseholds.

The Company completed an exploration well targeting the Niobrara, Dakota and Frontier formations in 2012. Upon completion, the Company determined that it did not expect to recover the full amount of capitalized costs associated with this exploration well, and wrote-off a portion of the capitalized costs in the fourth quarter of 2012. The Company incurred $(36) and $1,379 of additional costs related to this well in the three and nine months ended September 30, 2013, respectively, which were charged to impairment expense consistent with the Company’s 2012 year-end assessment. During the three months ended September 30, 2013, the Company sold recovered injection fluid that had been injected into the ground during the fracture stimulation stage of completing the well. The cost of the injection fluid is capitalized as part of a well’s cost. In instances where the Company is able to recover these costs, it reduces the amount of capital costs associated with the well. As the Company had already written down the well to the value of its estimated future cash flows, the Company recorded the proceeds from the sale as an offset to impairment expense. There was no change to the Company’s estimate of future cash flow during 2013. In the three and nine months ended September 30, 2012, the Company recorded impairment expense of $0 and $301, respectively, related to wells that were plugged and abandoned at a non-operated property. The Company also wrote off $0 and $121 during the three and nine months ended September 30, 2013, respectively, and $21 and $29 during the three and nine months ended September 30, 2012, respectively, related to expired undeveloped leaseholds and the write-off of other non-core assets.

7.	C ompensation Plans

The Company recognized stock-based compensation expense totaling $54 and $570 for the three and nine months ended September 30, 2013, respectively, and $414 and $1,234 for the three and nine months ended September 30, 2012, respectively.

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

A summary of stock option activity under the Company’s various stock option plans as of September 30, 2013 and changes during the nine months ended September 30, 2013 is presented below:

Options:	Shares		Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value
Outstanding at January 1, 2013	419,350		$	11.06	2.9
Granted	—
Exercised	—
Cancelled/expired	(78,592	)	$	12.07
Outstanding at September 30, 2013	340,758		$	10.83	2.8	$	—
Exercisable at September 30, 2013	311,047		$	11.34	2.8	$	—

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 a forfeiture rate and recognizes the compensation expenses 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, 2013 and changes during the nine months ended September 30, 2013 were as follows:

Stock Awards:	Shares		Weighted- Average Grant Date Fair Value
Outstanding at January 1, 2013	533,981		$	6.33
Granted	80,001		$	4.18
Vested	(67,239	)	$	4.48
Forfeited/returned	(87,742	)	$	6.02
Nonvested at September 30, 2013	459,001		$	6.28

In the fourth quarter of 2011, the Company adopted a Long-Term Incentive Plan (“LTIP”), under which the executive officers of the Company may earn shares for both continuous employment (one-third of the total shares) and through increases in the Company’s adjusted net asset value, as defined in the LTIP (two-thirds of the total shares). As of September 30, 2013, there were 405,262 nonvested shares of common stock outstanding under the LTIP. If the Company ultimately achieves the service requirements and performance objectives determined by the LTIP, the associated total stock-based compensation expense would be approximately $2.7 million, based on the grant date fair value. The total compensation expense recorded by the Company related to the LTIP was $(16) and $218 for the three and nine months ended September 30, 2013, respectively, and $164 and $468 for the three and nine months ended September 30, 2012, respectively. Compensation expense was negative in the three months ended September 30, 2013 due to the forfeiture of shares by the Company’s former chief financial officer, who left the Company in August 2013. As of September 30, 2013, the Company did not expect that it would meet the LTIP performance objectives and therefore it did not record any stock-based compensation expense associated with the performance shares component of the LTIP in 2013. The shares granted under the LTIP are included as nonvested shares in the stock awards table above.

8.	Income Taxes

The Company is required to record income tax expense for financial reporting purposes. The Company does not anticipate any payments of current tax liabilities in the near future due to its net operating loss carryforwards.

The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of September 30, 2013, the Company made no provision for interest or penalties related to uncertain tax positions. The Company files income tax returns in the U.S. federal jurisdiction and various states. There are currently no federal or state income tax examinations of the Company underway for these jurisdictions. Furthermore, the Company is no longer subject to U.S. federal income tax examinations by the Internal Revenue Service for tax years before 2007 and for state and local tax authorities for tax years before 2006.

9.	Preferred Stock

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

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

The shares of Series A Preferred Stock are classified outside of permanent equity on the consolidated balance sheets due to the change of control redemption provision applicable to such shares. Following a change of ownership or control of the Company by a person or entity in which the common stock of the Company is no longer traded on a national exchange, the Company will be required to redeem the Series A Preferred Stock within 90 days after the date on which the change of ownership or control

occurred for cash. In the event of liquidation, the holders of the Series A Preferred Stock will have the right to receive $25.00 per share, plus all accrued and unpaid dividends, before any payments are made to the holders of the Company’s common stock.

10.	Contingencies

Legal proceedings

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

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

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

FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q and other publicly available documents, including those incorporated herein and therein by reference, contain, and our management may from time to time make “forward-looking statements” within the meaning of the U.S. Private Securities Litigation Reform Act of 1995 (“PSLRA”). We make these forward-looking statements in reliance on the safe harbor protections provided under Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934, as amended, and the PSLRA. All statements, other than statements of historical facts, included in this Quarterly Report on Form 10-Q that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. When used in this report, the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “forecast,” “intend,” “may,” “plan,” “project,” “should,” and words or phrases of similar import, as they relate to the Company or its subsidiaries or management, are intended to identify forward-looking statements. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including without limitation the Risk Factors set forth in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2012 and the following factors:

·	A sustained decline in natural gas or oil prices;

·	The actions of third party co-owners of interests in properties in which we also own an interest, and in particular those which we do not operate or control;

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

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

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

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

·	General economic conditions, tax rates or policies, interest rates and inflation rates;

·	Our ability to maintain adequate liquidity in connection with low natural gas prices;

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

·	Incorrect estimates of required capital expenditures;

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

·	The volumes of production from our oil and gas development properties, which may be dependent upon issuance by federal and state governments, or agencies thereof, of drilling, environmental and other permits;

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

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

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

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

·	Weather, climate change and other natural phenomena;

·	Our ability and the ability of our partners to continue to develop the Atlantic Rim project;

·	The creditworthiness of third parties with which we enter into hedging and business agreements;

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

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

·	The volatility of our stock price; and

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

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

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

Company Overview

We are an independent energy company engaged in the exploration, development, production and sale of natural gas and crude oil, primarily in the Rocky Mountain Basins of the western United States. We were incorporated in Wyoming in 1972 and reincorporated in Maryland in 2001. Our common stock is publicly traded on the NASDAQ Global Select Market under the symbol “DBLE” and our Series A Cumulative Preferred Stock is traded on the NASDAQ Global Select Market under the symbol “DBLEP”. Our corporate offices are located at 1675 Broadway, Suite 2200, Denver, Colorado 80202, telephone number (303) 794-8445. Our website is www.dble.com.

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

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

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

Our Atlantic Rim production comes from two operating units: the Catalina Unit and the Spyglass Hill Unit (which includes the Sun Dog and Doty Mountain PAs). We operate the Catalina Unit and have working interests in the Spyglass Hill Unit. In the fourth quarter of 2012, we exercised our preferential right to acquire additional working interest in the Catalina Unit and Spyglass Hill Unit. The purchase was effective August 1, 2012; however because the transaction did not close until the fourth quarter of 2012, the results of operations for the third quarter of 2012 do not include the impact of our higher working interest. The table below summarizes our change in working interest:

Participating Area	Working Interest Acquired			Working Interest Following Purchase
Catalina		14.33	%		85.53	%
Sun Dog		8.73	%		28.59	%
Doty Mountain		8.73	%		26.73	%

RESULTS OF OPERATIONS

Three Months Ended September 30, 2013 Compared to the Three Months Ended September 30, 2012

The following analysis provides a comparison of the three months ended September 30, 2013 and the three months ended September 30, 2012.

Oil and gas sales

Oil and gas sales increased 17% to $7,599, which was attributed to a 26% increase in the Colorado Interstate Gas (“CIG”) market price, which is the index on which most of our natural gas volumes are sold. This was offset by an 11% decrease in our production volumes as compared to the same prior-year period, as discussed below.

As shown in the table below, our average realized natural gas price increased 6% to $3.83 per Mcf due to the aforementioned increase in CIG market price. In both years, we realized a natural gas price that was higher than the prevailing market prices due to the derivatives we had in place. Certain of our derivative contracts are collars, which allow us to realize some upside as natural gas prices rise. In addition, our production volume is greater than our hedged volume, and therefore, we also realized a benefit from the increase in the CIG price in the three months ended September 30, 2013.

We calculate our average realized natural gas price by summing (1) production revenues received from third parties for the sale of our gas, which is included within oil and gas sales on the consolidated statements of operations, and (2) realized gains on our economic hedges, which is included within price risk management activities on the consolidated statements of operations, totaling $1,658 and $3,166 for the three months ended September 30, 2013 and 2012, respectively.

	Three Months Ended September 30,						Percent Volume Change			Percent Price Change
	2013			2012
Product:	Volume	Average Price		Volume	Average Price
Gas (Mcf)	2,214,855	$	3.83	2,497,785	$	3.60		-11	%		6	%
Oil (Bbls)	7,976	$	96.60	7,995	$	83.55		0	%		16	%
Mcfe	2,262,711	$	4.09	2,545,755	$	3.80		-11	%		8	%

Our total net production decreased 11% to 2.3 Bcfe for the three months ended September 30, 2013 due primarily to lower production at the Catalina Unit, as well as small decreases in production volumes from our non-operated properties.

Our total average daily net production at the Atlantic Rim decreased 11% to 18,175 Mcfe. Although we had a net decrease in production in both the Catalina and Spyglass Hill units, we benefited from our purchase of additional working interest in both units in the fourth quarter of 2012.

Average daily net production at our Catalina Unit decreased 16% to 12,923 Mcfe, which primarily resulted from a series of equipment challenges over the past year, including a compressor failure and unscheduled maintenance on several injection pumps, which resulted in wells being off-line for periods of time. CBM wells, by nature, produce significant amounts of water. When wells are off-line, they have to be dewatered before production can recover. In addition, we completed a well workover program in the three months ended September 30, 2013, during which we fractured 12 existing wells to pursue hydrocarbons in the Almond formation. This program also required these wells to be off-line during the workover period. We also continue to experience normal production decline for the older wells within the field. Although production was lower in the third quarter of 2013 as compared to the same prior-year period, we did realize an 8% increase in average daily net production from the three months ended June 30, 2013.

Average daily production, net to our interest, at the Spyglass Hill Unit increased 4% to 5,252 Mcfe, due to our increased working interest. However, total production from the Spyglass Hill Unit decreased for the three months ended September 30, 2013. CBM wells can become saturated with water when they are not producing or properly maintained. We believe the decrease in total production is primarily due to delayed maintenance by the former operator. The current operator, Warren Resources Inc., drilled and completed 27 new wells in the third quarter of 2013 in the Doty Mountain PA. We do not expect the new wells to have an impact on production in 2013 due to incomplete compression and gathering systems and challenges handling water production.

In the Pinedale Anticline, average daily net production decreased 16% to 4,747 Mcfe due to normal production declines. The Company expects this decline to be partially offset by 11 new wells brought online in the first nine months of 2013.

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 28% to $914 for the three months ended September 30, 2013, primarily due to the decrease in Catalina production volumes. In addition, as a result of our increased working interest in the Catalina Unit, third party working interest decreased, and therefore the gathering fees were lower.

Price risk management activities

We recorded a net gain on our derivative contracts not designated as cash flow hedges of $630. This consisted of an unrealized non-cash loss of $1,028, which represents the change in the fair value on our economic hedges at September 30, 2013 based on the expected future prices of the related commodities, and a net realized gain of $1,658 related to the cash settlement of some of our economic hedges.

Oil and gas production costs, depreciation, depletion and amortization


	Three Months Ended September 30,
	2013			2012
	(in dollars per Mcfe)
Average price	$	4.09		$	3.80

Production costs		1.39			1.09
Production taxes		0.39			0.31
Depletion and amortization		2.25			1.84
Total operating costs		4.03			3.24
Gross margin	$	0.06		$	0.56
Gross margin percentage		1	%		15	%

Well production costs increased 14% to $3,150 and production costs in dollars per Mcfe increased 28%, or $0.30 to $1.39. The increase in total production costs is partially due to our increased working interest in the Atlantic Rim. Also, we had higher transportation costs at the Spyglass Hill Unit, which was driven by the cost of natural gas, as power is generated by natural gas in the unit. The Spyglass Hill Unit, due to numerous drilling, completion and infrastructure difficulties, has a higher production cost per Mcfe rate as compared to the Catalina Unit. Because production from the Spyglass Hill made up a larger percentage of our total production during the year, we experienced an increase in production costs on a per Mcfe basis. Production costs on a per mcfe basis were higher also due to the decrease in production volumes, as a portion of our production costs are fixed, or partially fixed.

Production taxes increased 13% to $886 for the three months ended September 30, 2013 and production taxes, on a dollars per Mcfe basis, also increased $0.08 to $0.39 per Mcfe. We are required to pay taxes on the proceeds received upon the physical sale of our gas

to counterparties. Production taxes were higher in total and on a per Mcfe basis primarily due to the increase in the market prices for natural gas.

Total depreciation, depletion and amortization expenses (“DD&A”) increased 8% to $5,178, and depletion and amortization related to producing assets increased 9% to $5,082. Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased 22%, or $0.41 to $2.25. Our depletion rate was higher in 2013 for the Catalina Unit, due to a decrease in our reserves, which were estimated to be lower in our year-end reserve report, primarily due to the decrease in pricing as calculated in accordance with SEC rules.

Impairment and abandonment of equipment and properties

We recorded impairment and abandonment expense in the three months ended September 30, 2013 of $(36), due to a recovery of injection fluid used in fracture stimulation of our Niobrara exploration well, which we completed in 2012. Upon completion of this well, we determined that we did not expect to recover the full amount of capitalized costs associated with the well and wrote-off a portion of the capitalized costs in the fourth quarter of 2012, and all additional costs incurred related to this well in 2013. The cost of the injection fluid is capitalized as part of a well’s total cost. In instances where we are able to recover these costs, we reduce the amount of capital costs associated with the well. As we had already written down the well to the value of its estimated future cash flows, we recorded the proceeds from the sale to impairment expense. There was no change to our estimate of future cash flow during 2013. Upon recovery, the injection fluid was resold for proceeds of $36.

General and administrative expenses

General and administrative expenses decreased 35% to $983, primarily due to a $360 decrease in non-cash stock-based compensation expense resulting from lower expense related to our long term incentive plan, as management no longer expects the performance-based awards to vest, and also due to the forfeiture of shares by our former Chief Financial Officer that left the Company in August 2013. Additionally, several executive stock grants fully vested at the end of 2012 and therefore we did not have any associated expense in 2013. In addition, our salary and salary-related expenses decreased by $87, largely due to lower estimated year-end executive bonuses. There were no other material changes to general and administrative expenses during the three months ended September 30, 2013.

Interest expense, net

Interest expense decreased to $488 for the three months ended September 30, 2013, as compared to $516 for the three months ended September 30, 2012. Interest expense in the 2013 period included an unrealized non-cash loss on our interest rate swap of $92, whereas the non-cash loss in the 2012 period was $226. The decrease in interest expense was offset by additional interest expense on our bank credit facility of $44 due to an increase in outstanding borrowings and a small increase in our average interest rate.

Income taxes

We recorded an income tax benefit of $946. Our effective tax rate for the three months ended September 30, 2013 was 34.2%. Although we expect to continue to generate losses for federal income tax reporting purposes, our operations have resulted in a deferred tax position required under generally accepted accounting principles. We expect to recognize deferred income tax expense on taxable income for the remainder of 2013 at an expected federal and state rate of approximately 35.0%.

Nine Months Ended September 30, 2013 Compared to the Nine Months Ended September 30, 2012

The following analysis provides comparison of the nine months ended September 30, 2013 and the nine months ended September 30, 2012.

Oil and gas sales

Oil and gas sales increased 33% to $23,634, which was attributed to a 50% increase in the CIG market price, partially offset by an 8% decrease in production volumes. As shown in the table below, our average realized natural gas price increased 10% to $3.85 per Mcf also due to the increase in the CIG market price. In both years, we realized a natural gas price that was higher than the prevailing market prices due to the derivatives we had in place. Our calculation of our average realized gas price includes the realized gain (loss) on our economic hedges, which is included within price risk management activities, net on the consolidated statements of operations, totaling $4,563 and $10,227, for the nine months ended September 30, 2013 and 2012, respectively.

	Nine Months Ended September 30,						Percent Volume Change			Percent Price Change
	2013			2012
Product:	Volume	Average Price		Volume	Average Price
Gas (Mcf)	6,801,042	$	3.85	7,425,420	$	3.49		-8	%		10	%
Oil (Bbls)	21,751	$	91.96	24,466	$	83.16		-11	%		11	%
Mcfe	6,931,548	$	4.07	7,572,216	$	3.69		-8	%		10	%

Our total net production decreased 8% to 6.9 Bcfe due primarily to lower production from the Catalina Unit, as well as small decreases in production from our non-operated properties.

Our total average daily net production at the Atlantic Rim decreased 8% to 18,683 Mcfe. Although we had a net decrease in production in both the Catalina and Spyglass Hill units, we benefited from the additional working interest we had in these properties in 2013. Average daily net production at the Catalina Unit decreased 11% to 13,341 Mcfe, which primarily resulted from our wells being offline for periods of time, and the associated water build-up in our wells. We have experienced a series of equipment challenges over the past year, including a compressor failure and unscheduled maintenance on several injection pumps, and we also completed a well workover program in the third quarter of 2013, during which we fractured 12 existing wells to pursue hydrocarbons in the Almond formation. The wells fractured during this program are responding as expected and we expect production from the Catalina Unit to continue to increase during the last part of 2013.

Average daily production, net to our interest, at the Spyglass Hill Unit decreased 1% to 5,342 Mcfe. CBM wells can become saturated with water when they are not producing or properly maintained. We believe the production decrease is primarily due to delayed maintenance by the former operator. The operator drilled and completed 27 new wells in the third quarter of 2013 in the Doty Mountain PA. However, we do not expect the new wells to have an impact on production in 2013 due to incomplete compression and gathering systems.

Average daily net production in the Pinedale Anticline decreased 11% to 5,155 Mcfe due to normal production declines. The Company expects this decline to be partially offset by 11 new wells brought online in the first nine months of 2013.

Transportation and gathering revenue

Transportation and gathering revenue decreased 27% to $2,751, primarily due to the decrease in Catalina production volumes. In addition, as a result of our increased working interest in the Catalina Unit, third-party gathering fees were lower.

Price risk management activities

We recorded a net gain on our derivative contracts not designated as cash flow hedges of $1,264. This consisted of an unrealized non-cash loss of $3,299, which represents the change in the fair value on our economic hedges at September 30, 2013 based on the expected future prices of the related commodities, and a net realized gain of $4,563 related to the cash settlement of some of our economic hedges.

Other income, net

In 2009, we entered into an agreement that gave optional farm-in rights to a third party to re-enter the TTU #1 well located in the Main Fork Unit in Utah. We were notified in April 2013 that the third party was terminating the agreement and would not exercise its farm-in right. In accordance with the agreement, the third party paid to us a termination penalty of $500. We are working to obtain an extension of these leases. If we are unable to do so, the unit may be terminated and the well may be plugged in the first half of 2014.

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

	Nine Months Ended September 30,
	2013			2012
	(in dollars per Mcfe)
Average price	$	4.07		$	3.69

Production costs		1.35			1.15
Production taxes		0.41			0.25
Depletion and amortization		2.21			1.85
Total operating costs		3.97			3.25
Gross margin	$	0.10		$	0.44
Gross margin percentage		2	%		12	%

Well production costs increased 8% to $9,346 and production costs in dollars per Mcfe increased 17%, or $0.20 to $1.35. The increase in total production costs is partially due to our increased working interest in the Atlantic Rim. Also, we had higher transportation costs at the Spyglass Hill Unit, which was driven by the cost of natural gas, as power is generated by natural gas in the unit. The Spyglass Hill Unit, due to numerous drilling, completion and infrastructure difficulties, has a higher production cost per Mcfe rate as compared to the Catalina Unit. Because production from the Spyglass Hill made up a larger percentage of our total production during the year, we experienced an increase in production costs on a per Mcfe basis. Production costs on a per mcfe basis were higher also due to the decrease in production volumes, as a portion of our production costs are fixed, or partially fixed.

Production taxes increased to $2,851 for the nine months ended September 30, 2013, and production taxes, on a dollars per Mcfe basis, increased $0.16 to $0.41 per Mcfe. We are required to pay taxes on the proceeds received upon the physical sale of our gas to counterparties. Production taxes were higher in total and on a per Mcfe basis primarily due to the increase in the market prices for natural gas. In addition, production taxes during the nine months ended September 30, 2012 was net of an adjustment for allowable transportation deductions.

Total DD&A increased 10% to $15,631, and depletion and amortization related to producing assets also increased 10% to $15,342. Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased 19%, or $0.36 to $2.21. Our depletion rate was higher in 2013 for the Catalina Unit, due to a decrease in our reserves, which were estimated to be lower in our year-end reserve report, primarily due to the decrease in pricing as calculated in accordance with SEC rules.

Pipeline operating costs

Pipeline operating costs increased 9% to $3,950, which was primarily attributed to higher power charges.

Exploration expenses, including dry hole costs

In the first quarter of 2012, we participated in drilling an exploratory well in the High Road Prospect near Gillette, Wyoming. The results of geological testing showed no economically producible hydrocarbons existed and as a result the drilling costs of $462 were charged to dry hole expense. We did not have any material exploration expenses in the nine months ended September 30, 2013.

Impairment and abandonment of equipment and properties

We recorded impairment and abandonment expense in the nine months ended September 30, 2013 of $1,500, of which $1,379 related to the exploration well we completed in 2012, which targeted the Niobrara, Dakota and Frontier formations. Upon completion of this well, we determined that we did not expect to recover the full amount of capitalized costs associated with the well and wrote-off a portion of the capitalized costs in the fourth quarter of 2012. The additional costs incurred in 2013 related to this well were also charged to impairment expense consistent with our 2012 year-end assessment.

In the fourth quarter of 2013, we plan to continue to refine the previous well completions in an effort to isolate excess water production and maximize production. This will allow us to further access the well’s ultimate oil and gas reserves in place and recoverable volumes. We are currently awaiting regulatory approval to begin producing gas from the Dakota and Frontier gas formations.

General and administrative expenses

General and administrative expenses decreased 17% to $3,946, primarily due to a $664 decrease in non-cash stock-based compensation expense resulting from lower expense related to our long term incentive plan, as management no longer expects the performance-based awards to vest, and also due to the forfeiture of shares by our former Chief Financial Officer, whom left the Company in August 2013. Additionally, several executive stock grants fully vested at the end of 2012 and therefore we did not have any associated expense in 2013. In addition, our salary and salary-related expenses decreased by $133, largely due to lower estimated year-end executive bonuses.

Interest expense, net

Interest expense decreased to $943 for the nine months ended September 30, 2013, as compared to $1,369 for the nine months ended September 30, 2012. Interest expense in the 2013 period included an unrealized non-cash gain on our interest rate swap of $228, whereas we had a non-cash loss in 2012 of $560. The decrease in interest expense was offset by additional interest expense on our bank credit facility of $205 due to an increase in our average outstanding borrowings and a small increase in our average interest rate.

Income taxes

We recorded an income tax benefit of $3,467. Our effective tax rate was 34.2%.

OVERVIEW OF FINANCIAL CONDITION AND LIQUIDITY

Liquidity and Capital Resources

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

We currently have a $150,000 credit facility in place with a $60,000 borrowing base. At September 30, 2013, we had $47,450 outstanding on our credit facility. We expect that the remaining availability of $12,550, coupled with our expected cash flow from operations will be sufficient to meet future financial covenants, maintain our current facilities, and complete our 2013 capital expenditure program (see “Capital Requirements” below). Our future success in growing proved reserves and production will be highly dependent on the capital resources available to us, natural gas prices and our success in finding or acquiring additional reserves.

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

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

	September 30, 2013			December 31, 2012
	(unaudited)
Financial Position Summary
Cash and cash equivalents	$	3,804		$	4,070
Working capital	$	4,764		$	7,851
Balance outstanding on credit facility	$	47,450		$	47,450
Stockholders’ equity and preferred stock	$	72,532		$	81,442
Ratios
Debt to total capital ratio (1)		39.5	%		36.8	%
Total debt to equity ratio		137.3	%		109.2	%

(1)	Total capital includes the $47,450 outstanding on our credit facility, our preferred stock and stockholder ’s equity.

Our working capital balance decreased to $4,764 at September 30, 2013 as compared to $7,851 at December 31, 2012. Our working capital balance fluctuates primarily due to the timing and amounts of capital expenditures and changes in fair value of our outstanding derivative contracts. Our accounts payable and accrued expense balances decreased by $3,902, as our capital spending slowed in the first nine months of 2013 due to winter weather and wildlife stipulations. Our accounts receivable and price risk management assets were also lower at September 30, 2013.

Cash flow activities

The table below summarizes our cash flows for the nine months ended September 30, 2013 and 2012, respectively:

	Nine Months Ended September 30,
	2013			2012
Cash provided by (used in):
Operating activities	$	10,283		$	13,630
Investing activities		(7,736	)		(20,554	)
Financing activities		(2,813	)		1,384
Net change in cash	$	(266	)	$	(5,540	)

During the nine months ended September 30, 2013, net cash provided by operating activities was $10,283, as compared to $13,630 in the same prior-year period. Cash flow from operations was lower primarily due to the decrease in accounts payable and accrued expense balances resulting from the pay-down and timing of production costs. Our cash flow for the nine months ended September 30, 2013 includes cash of $500, which was paid to us by a third party as a penalty for terminating the farm-out agreement at the Main Fork Unit.

Our operating cash flow is sensitive to many variables, the most significant of which is the price of natural gas. Our hedging program helps to mitigate cash flow fluctuations due to price volatility. Taking into account our derivative instruments, for the nine months ended September 30, 2013, our income before income taxes and cash flow would have increased by approximately $1,300 for each $0.50 change per Mcf in natural gas prices. We realized cash from settlements of derivatives of $4,563 and $10,227 during the nine

months ended September 30, 2013 and 2012, respectively. Our average realized natural gas price was 10% higher in the nine months ended September 30, 2013 as compared to the same prior-year period.

During the nine months ended September 30, 2013, net cash used in investing activities was $7,736, as compared to $20,554 in the same prior-year period. During the first nine months of 2013, our capital spending was primarily related to expenditures to begin producing our Niobrara exploration well and non-operated drilling in the Pinedale Anticline and Atlantic Rim. In the first nine months of 2012, our spending was also largely related to the drilling of the Niobrara well. We also made payments in the first quarter of 2012 related to our 2011 drilling program at Catalina, which was completed late in the fourth quarter of 2011, and non-operated drilling in the Pinedale Anticline.

We had cash used in financing activities of $2,813 for the nine months ended September 30, 2013, as compared to cash provided by financing activities of $1,384 for the nine months ended September 30, 2012. In 2012, we drew down on our credit facility in the third quarter to help finance the exploration costs associated with our Niobrara exploration well. In 2013, management has focused on keeping capital expenditures within operating cash flow, and did not draw down any additional funds on its credit facility. We expended cash in the first half of 2013 and 2012 to make our quarterly dividend payment totaling $2,792 in each period. Dividends are expected to continue to be paid on a quarterly basis on the Series A Preferred Stock in the future at a rate of $931 per quarter.

Credit Facility

Our credit facility is collateralized by our oil and gas producing properties and other assets. At September 30, 2013, we had $47,450 outstanding on the facility. We have depended on our credit facility over the past five years to supplement our operating cash flow in the development of the Company-operated Catalina Unit and other non-operated projects in the Atlantic Rim, including two purchases of additional working interest in this field, projects in the Pinedale Anticline, and the drilling of our Niobrara exploration well.

We are subject to a variety of financial and non-financial covenants under this facility. As of September 30, 2013, we were in compliance with all covenants under the facility. If any of the covenants are violated, and we are unable to negotiate a waiver or amendment thereof, the lender would have the right to declare an event of default, terminate the remaining commitment, accelerate all principal and interest outstanding, and foreclose on our assets.

Our borrowing base was subject to redetermination on October 1, 2013. Although the October 1, 2013 redetermination is not yet complete, we do not expect a decrease in our borrowing base. If natural gas prices decrease for extended period of time, our borrowing base could be reduced, thus limiting the future amounts of funds under the current facility. Upon any downward adjustment of the borrowing base, if the outstanding borrowings are in excess of the revised borrowing base, we may have to repay our indebtedness in excess of the borrowing base immediately, or in six monthly installments, or pledge additional properties as collateral. We may not have sufficient funds to make such repayments or additional properties to pledge as collateral.

Capital Requirements

For 2013, we currently have budgeted approximately $11,000 for capital projects in the Atlantic Rim and Pinedale Anticline. We completed our well workover program in the Catalina Unit in the third quarter of 2013. Our workover program focused on opening up the Almond formation in 12 existing wells, which was previously unfractured. The program cost approximately $2,000. The wells are responding as expected, and we anticipate we will see increased production from these wells beginning in the fourth quarter. We also participated in the drilling and completion of 27 wells in the Spyglass Hill Unit. The operator completed the program in late September for an expected cost of $1,700. Production from these new wells is expected to be limited due to an incomplete gathering system. Additionally, at Mesa “B” PA, we are participating the drilling and the completion of final 13 well locations in the unit. Eleven of the thirteen well have been brought online during the year. The total cost of the program is expected to be approximately $4,000 to $5,000, net to our interest. We believe that we have the necessary capital, personnel and available drilling equipment to execute this development and exploration program.

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, 2013 are summarized below (volume and daily production are expressed in Mcf). All contracts are indexed to the New York Mercantile Exchange (“NYMEX”). The prevailing market prices in the Rockies, including CIG which is the index on which most of our gas volumes are sold, tend to be sold at a discount relative to other U.S. natural gas markets. This discount is typically referred to as a “basis differential” and reflects, to some extent, the costs associated with transporting the natural gas in the Rockies to markets in the other regions. It also reflects the general excess supply and lack of pipeline capacity in the region.

Type of Contract	Remaining Contractual Volume (Mcf)		Term		Price
Fixed Price Swap		552,000		01/13-12/13	$	5.16
Costless Collar		552,000		01/13-12/13	$	5.00	floor
					$	5.35	ceiling
Costless Collar		540,000		01/13-12/13	$	3.25	floor
					$	4.00	ceiling
Fixed Price Swap		1,825,000		01/14-12/14	$	4.27
Fixed Price Swap		1,800,000		01/14-12/14	$	4.20
Costless Collar		1,800,000		01/14-12/14	$	4.00	floor
					$	4.50	ceiling

Fixed Price Swap		3,000,000		01/15-12/15	$	4.28

Total		10,069,000

Interest rate swap

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2012, and to the Notes to the Consolidated Financial Statements included in Part I, Item 1 of this report.

ITEM 4.

CONTROLS AND PROCEDURES

In accordance with the Securities Exchange Act of 1934, 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 nine months ended September 30, 2013 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

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

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The table below summarizes repurchases of our common stock in the third quarter of 2013:

Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
July 1, 2013 to July 31, 2013	—			—	—	—
August 1, 2013 to August 31, 2013	—			—	—	—
September 1, 2013 to September 30, 2013	85	(1)	$	3.02	—	—
Total	85		$	3.02	—	—

(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.

ITEM 6.

EXHIBITS

The following exhibits are filed as part of this report:

Exhibit		Description:

3.1(a)		Articles of Incorporation of the Company (incorporated by reference from Exhibit 3.1(a) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).

3.1(b)		Certificate of Correction of the Company (incorporated by reference from Exhibit 3.1(b) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).

3.1(c)		Certificate of Correction of the Company (incorporated by reference from Exhibit 3 of the Company’s Quarterly Report on Form 10-QSB for the quarter ended November 30, 2001).

3.1(d)		Certificate of Correction to the Articles of Incorporation of the Company (incorporated by reference from Exhibit 3.3 of the Company’s Current Report on Form 8-K dated June 29, 2007).

3.1(e)		Articles of Amendment to the Articles of Incorporation of the Company, filed with the Maryland Department of Assessments and Taxation on June 26, 2007 (incorporated by reference from Exhibit 3.1 of the company’s Current Report on Form 8-K dated June 29, 2007).

3.1(f)		Articles Supplementary of Series A Cumulative Preferred Stock (incorporated by reference from Exhibit 3.2 of the Company’s Current Report on Form 8-K dated June 29, 2007).

3.1(g)		Articles of Amendment to Articles Supplementary 9.25% Series A Cumulative Preferred Stock (incorporated by reference from Exhibit 4.1 from the Company’s Annual Report on Form 10-K for the year ended December 31, 2012 filed on March 14, 2013).

3.1(h)		Articles Supplementary of Junior Participating Preferred Stock Series B of the Company dated as of August 21, 2007 (incorporated by reference from Exhibit 3.1 of the Company’s Current Report on Form 8-K dated August 28, 2007).

3.1(i)		Second Amended and Restated Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Current Report on Form 8-K filed June 11, 2007)

3.1(j)		Amendment to Bylaws, Revised Article II, Section 9 (incorporated by reference from Exhibit 3.1 of the Company’s Current Report on Form 8-K filed on March 5, 2010).

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.

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.

			DOUBLE EAGLE PETROLEUM CO. (Registrant)
Date: November 7,	2013	By:	/S/ Richard D. Dole
			Richard D. Dole
			Chief Executive Officer (Principal Executive Officer)

EXHIBIT INDEX

Exhibit		Description:

3.1(a)		Articles of Incorporation of the Company (incorporated by reference from Exhibit 3.1(a) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).

3.1(b)		Certificate of Correction of the Company (incorporated by reference from Exhibit 3.1(b) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).

3.1(c)		Certificate of Correction of the Company (incorporated by reference from Exhibit 3 of the Company’s Quarterly Report on Form 10-QSB for the quarter ended November 30, 2001).

3.1(d)		Certificate of Correction to the Articles of Incorporation of the Company (incorporated by reference from Exhibit 3.3 of the Company’s Current Report on Form 8-K dated June 29, 2007).

3.1(e)		Articles of Amendment to the Articles of Incorporation of the Company, filed with the Maryland Department of Assessments and Taxation on June 26, 2007 (incorporated by reference from Exhibit 3.1 of the company’s Current Report on Form 8-K dated June 29, 2007).

3.1(f)		Articles Supplementary of Series A Cumulative Preferred Stock (incorporated by reference from Exhibit 3.2 of the Company’s Current Report on Form 8-K dated June 29, 2007).

3.1(g)		Articles of Amendment to Articles Supplementary 9.25% Series A Cumulative Preferred Stock (incorporated by reference from Exhibit 4.1 from the Company’s Annual Report on Form 10-K for the year ended December 31, 2012 filed on March 14, 2013).

3.1(h)		Articles Supplementary of Junior Participating Preferred Stock, Series B of the Company, dated as of August 21, 2007 (incorporated by reference from Exhibit 3.1 of the Company’s Current Report on Form 8-K dated August 28, 2007).

3.1(i)		Second Amended and Restated Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Current Report on Form 8-K filed June 11, 2007)

3.1(j)		Amendment to Bylaws, Revised Article II, Section 9 (incorporated by reference from Exhibit 3.1 of the Company’s Current Report on Form 8-K filed on March 5, 2010).

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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