Escalera Resources Co. - FORM 10-Q

Attached files

file	filename
EXCEL - IDEA: XBRL DOCUMENT - Escalera Resources Co.	Financial_Report.xls
EX-32 - EXHIBIT 32 - Escalera Resources Co.	c18505exv32.htm
EX-31.2 - EXHIBIT 31.2 - Escalera Resources Co.	c18505exv31w2.htm
EX-31.1 - EXHIBIT 31.1 - Escalera Resources Co.	c18505exv31w1.htm

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended June 30, 2011


o		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 (State or other jurisdiction of incorporation or organization)		83-0214692 (I.R.S. employer identification no.)


1675 Broadway, Suite 2200, Denver, Colorado (Address of principal executive offices)		80202 (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 þ No o

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 þ No o

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 o		Accelerated filer o		Non-accelerated filer o (Do not check if a small reporting company)		Small reporting company þ

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

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


Class Common stock, $.10 par value		Outstanding as of July 31, 2011 11,197,591

DOUBLE EAGLE PETROLEUM CO.
FORM 10-Q
TABLE OF CONTENTS


	Page #

PART I. Financial Information:

Item 1. Financial Statements

Consolidated Balance Sheets as of June 30, 2011 and December 31, 2010 (Unaudited)		3

Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2011 and 2010 (Unaudited)		4

Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2011 and 2010 (Unaudited)		5

Notes to Consolidated Financial Statements (Unaudited)		6

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk		23

Item 4. Controls and Procedures		23

PART II. Other Information:

Item 1. Legal Proceedings		24

Item 1A. Risk Factors		24

Item 6. Exhibits		25

Signatures		27

Exhibit 31.1
Exhibit 31.2
Exhibit 32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT

PART I. FINANCIAL INFORMATION


ITEM 1.		FINANCIAL STATEMENTS

DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED BALANCE SHEETS

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

(Unaudited)


	June 30,			December 31,
	2011			2010
ASSETS
Current assets:
Cash and cash equivalents	$	4,882		$	2,605
Cash held in escrow		564			615
Accounts receivable		5,646			5,396
Assets from price risk management		5,291			9,622
Other current assets		3,795			3,653

Total current assets		20,178			21,891


Oil and gas properties and equipment, successful efforts method:
Developed properties		192,307			188,143
Wells in progress		3,683			4,039
Gas transportation pipeline		5,465			5,465
Undeveloped properties		3,000			3,062
Corporate and other assets		2,001			1,982

		206,456			202,691
Less accumulated depreciation, depletion and amortization		(81,616	)		(72,226	)

Net properties and equipment		124,840			130,465

Assets from price risk management		397			—
Other assets		148			161

TOTAL ASSETS	$	145,563		$	152,517


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	5,567		$	10,830
Accrued production taxes		3,822			2,757
Capital lease obligations, current portion		273			545
Other current liabilities		128			282

Total current liabilities		9,790			14,414

Line of credit		32,000			32,000
Asset retirement obligation		5,922			5,848
Deferred tax liability		9,384			9,578

Total liabilities		57,096			61,840


Preferred stock, $0.10 par value; 10,000,000 shares authorized; 1,610,000 shares issued and outstanding as of June 30, 2011 and December 31, 2010		37,972			37,972

Stockholders’ equity:
Common stock, $0.10 par value; 50,000,000 shares authorized; 11,203,747 issued and 11,191,775 shares outstanding as of June 30, 2011 and 11,165,305 issued and 11,155,080 outstanding as of December 31, 2010, respectively		1,118			1,116
Additional paid-in capital		45,089			44,583
Retained earnings		1,638			1,438
Accumulated other comprehensive income		2,650			5,568

Total stockholders’ equity		50,495			52,705


TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	145,563		$	152,517

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 June 30,						Six months ended June 30,
	2011			2010			2011			2010

Revenues
Oil and gas sales	$	11,393		$	7,608			22,303		$	18,657
Transportation revenue		1,221			1,401			2,453			2,889
Price risk management activities, net		2,068			103			929			7,925
Other income, net		210			280			305			357


Total revenues		14,892			9,392			25,990			29,828


Costs and expenses
Production costs		2,769			2,397			5,343			4,339
Production taxes		1,090			1,010			2,146			2,309
Exploration expenses including dry hole costs		120			28			172			66
Pipeline operating costs		1,020			971			2,001			2,119
General and administrative		1,362			1,392			2,920			2,925
Impairment and abandonment of equipment and properties		—			80			73			80
Depreciation, depletion and amortization		4,718			4,530			9,391			9,070


Total costs and expenses		11,079			10,408			22,046			20,908


Income (loss) from operations		3,813			(1,016	)		3,944			8,920

Interest expense, net		(257	)		(385	)		(644	)		(750	)


Income (loss) before income taxes		3,556			(1,401	)		3,300			8,170

(Provision) benefit for deferred income taxes		(1,342	)		512			(1,238	)		(2,945	)


NET INCOME (LOSS)	$	2,214		$	(889	)	$	2,062		$	5,225


Preferred stock dividends		931			931			1,862			1,862


Net income (loss) attributable to common stock	$	1,283		$	(1,820	)	$	200		$	3,363


Net income (loss) per common share:
Basic	$	0.11		$	(0.16	)	$	0.02		$	0.30

Diluted	$	0.11		$	(0.16	)	$	0.02		$	0.30

Weighted average shares outstanding:
Basic		11,189,472			11,116,476			11,182,021			11,111,092

Diluted		11,211,031			11,116,476			11,199,569			11,111,092

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

DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in thousands of dollars)

(Unaudited)


	Six months ended June 30,
	2011			2010
Cash flows from operating activities:
Net income	$	2,062		$	5,225
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion, amortization and accretion of asset retirement obligation		9,474			9,125
Abandonment of non-producing properties and leases		73			80
Provision for deferred taxes		1,238			2,945
Stock-based compensation expense		525			496
Non-cash gain on transfer of asset retirement obligation to third party		—			(164	)
Change in fair value of derivative contracts		(418	)		(6,482	)
Revenue from carried interest		(117	)		(1,282	)
Gain on sale of producing property		(141	)		(142	)
Changes in current assets and liabilities:
Decrease (Increase) in deposit held in escrow		51			(2	)
Decrease (Increase) in accounts receivable		(250	)		784
Decrease (Increase) in other current assets		271			(728	)
Increase (Decrease) in accounts payable and accrued expenses		(2,221	)		196
Increase in accrued production taxes		1,065			667


NET CASH PROVIDED BY OPERATING ACTIVITIES		11,612			10,718


Cash flows from investing activities:
Payments to acquire producing properties and equipment, net		(7,155	)		(6,652	)
Payments to acquire corporate and non-producing properties		(30	)		(439	)
Sale of corporate assets		—			7


NET CASH USED IN INVESTING ACTIVITIES		(7,185	)		(7,084	)


Cash flows from financing activities:
Principal payments on capital lease obligations		(272	)		(265	)
Issuance of stock under Company stock plans		—			6
Tax withholdings related to net share settlement of restricted stock awards		(16	)		(3	)
Preferred stock dividends		(1,862	)		(1,862	)
Net borrowings (repayments) on credit facility		—			(3,000	)


NET CASH USED IN FINANCING ACTIVITIES		(2,150	)		(5,124	)


Change in cash and cash equivalents		2,277			(1,490	)

Cash and cash equivalents at beginning of period		2,605			5,682


CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	4,882		$	4,192


Supplemental disclosure of cash and non-cash transactions:
Cash paid for interest	$	699		$	824
Interest capitalized	$	64		$	87
Additions to developed properties included in current liabilities	$	1,572		$	4,128

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)

Summary of Significant Accounting Policies

Basis of presentation

The accompanying unaudited consolidated financial statements were prepared by Double Eagle Petroleum Co. (“Double Eagle” or the “Company”) 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 prepared in accordance with accounting principles generally accepted in the United States of America 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 2010 consolidated financial statements have been reclassified to conform to the 2011 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, 2010, and are supplemented throughout the notes to this Quarterly Report on Form 10-Q.

The interim consolidated financial statements presented herein should be read in conjunction with the consolidated financial statements and notes thereto for the year ended December 31, 2010 included in the Annual Report on Form 10-K filed with the SEC.

Principles of consolidation

The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, Petrosearch Energy Corporation (“Petrosearch”) and Eastern Washakie Midstream LLC (“EWM”). In August 2009, the Company acquired Petrosearch, which has operations in Texas and Oklahoma. 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 and compress gas produced at the Catalina Unit. The Company’s fee related to gas gathering is also eliminated in consolidation.

New accounting pronouncements

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2011-04 (“ASC 2011-04”), an update to ASC Topic 820, Fair Value Measurements and Disclosures. This update amends current guidance to achieve common fair value measurement and disclosure requirements in U.S. GAAP and International Financial Reporting Standards. The update also includes instances where a particular principle or requirement for measuring fair value or disclosing information about fair value measurements has changed. ASC Update 2011-04 is effective for interim and annual periods beginning after December 15, 2011. The adoption of ASC Update 2011-04 is not expected to have a material impact on the Company’s financial position, results of operations or cash flows.

In June 2011, the FASB issued Accounting Standards Update No. 2011-05 (“ASC No. 2011-05”), an update to ASC Topic 220, Comprehensive Income. The update amends current guidance to require companies to present total comprehensive income either in a single, continuous statement of comprehensive income or in two separate, but consecutive, statements. Under the single-statement approach, entities must include the components of net income, a total for net income, the components of other comprehensive income and a total for comprehensive income. Under the two-statement approach, entities must report an income statement and, immediately following, a statement of other comprehensive income. Under both methods, entities must also display adjustments for items reclassified from other comprehensive income to net income in both net income and other comprehensive income. ASC Update 2011-05 is effective for interim and annual periods beginning after December 15, 2011. The adoption of ASC Update 2011-05 will affect the Company’s financial statement presentation only, and will have no impact on the Company’s financial position, results of operations or cash flows.

Earnings per share

Basic earnings per share of common stock (“EPS”) is calculated by dividing net income (loss) attributable to common stock by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share incorporates the treasury stock method, and is calculated by dividing net income (loss) attributable to common stock by the weighted average number of shares of common stock and potential common stock equivalents outstanding during the period, if dilutive. Potential common stock equivalents include incremental shares of common stock issuable upon the exercise of stock options and employee stock awards. Income attributable to common stock is calculated as net income less dividends paid on the Series A Preferred Stock. The Company declared and paid cash dividends of $931 and $1,862 ($.5781 per share) for each of the each of the three and six months ended June 30, 2011 and 2010.

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 June 30,					For the Six Months Ended June 30,
	2011		2010			2011		2010
Net income (loss)	$	2,214	$	(889	)	$	2,062	$	5,225
Preferred stock dividends		931		931			1,862		1,862

Income (loss) attributable to common stock	$	1,283	$	(1,820	)	$	200	$	3,363

Weighted average shares:
Weighted average shares — basic		11,189,472		11,116,476			11,182,021		11,111,092
Dilution effect of stock options outstanding at the end of period		21,559		—			17,548		—

Weighted average shares — diluted		11,211,031		11,116,476			11,199,569		11,111,092


Income (loss) per common share:
Basic	$	0.11	$	(0.16	)	$	0.02	$	0.30

Diluted	$	0.11	$	(0.16	)	$	0.02	$	0.30

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 June 30,				For the Six Months Ended June 30,
	2011		2010		2011		2010

Anti-dilutive shares		32,109		82,360		37,918		93,529

Derivative Instruments

The Company’s primary market exposure is to adverse fluctuations in the prices 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 hedge recommendations, execution of the approved hedging plan, oversight of the risk management process including methodologies used for valuation and risk measurement and presenting policy changes to the Board. 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 ensuing 24 month period.

The Company recognizes its derivative instruments as either assets or liabilities at fair value on its consolidated balance sheets, and accounts for the derivative instruments as either cash flow hedges or mark to market derivative instruments. On the 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 that 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 June 30, 2011, no party to any of the Company’s derivative contracts has required any form of security guarantee.

Cash flow hedges

Derivative instruments that are designated and qualify as cash flow hedges are recorded at fair value on the consolidated balance sheets, and the effective portion of the change in fair value is reported as a component of accumulated other comprehensive income (“AOCI”) and is subsequently reclassified into oil and gas sales on the consolidated statements of operations as the contracts settle. As of June 30, 2011, the Company expected approximately $4,243 of unrealized gains before taxes included in AOCI to be reclassified into oil and gas sales in one year or less as the contracts settle.

Mark to market hedging instruments

Unrealized gains and losses resulting from derivatives not designated as cash flow hedges are recorded at fair value on the consolidated balance sheets and changes in fair value are recognized in price risk management activities, net on the consolidated statements of operations. Realized gains and losses resulting from the contract settlement of derivatives not designated as cash flow hedges also are recorded within price risk management activities, net on the consolidated statement of operations.

The Company had the following commodity volumes under derivative contracts as of June 30, 2011:


	Contract Settlement Date
	2011		2012		2013

Natural Gas forward purchase contracts:
Volume (MMcf)		2,392		5,490		4,380

The table below contains a summary of all the Company’s derivative positions reported on the consolidated balance sheet as of June 30, 2011, presented gross of any master netting arrangements:


Derivatives designated as hedging
instruments under ASC 815	Balance Sheet Location	Fair Value
Assets
Commodity derivatives	Assets from price risk management - current	$	4,243

Total		$	4,243


Derivatives not designated as hedging
instruments under ASC 815	Balance Sheet Location	Fair Value
Assets
Commodity derivatives	Assets from price risk management - current	$	1,048
	Assets from price risk management - long term	$	397

Total		$	1,445

The before-tax effect of derivative instruments in cash flow hedging relationships on the consolidated statements of operations for the three months and six months ended June 30, 2011 and 2010, related to the Company’s commodity derivatives was as follows:

Derivatives Designated as Cash Flow Hedging Instruments under ASC 815


	Amount of Gain (Loss) Recognized in OCI ¹on Derivatives for the
	Three months ended June 30,				Six months ended June 30,
	2011		2010		2011		2010

Commodity contracts	$	128	$	791	$	242	$	2,814


Location of Gain Reclassified	Amount of Gain Reclassified from AOCI into Income
from AOCI into Income	Three months ended June 30,				Six months ended June 30,
(effective portion)	2011		2010		2011		2010

Oil and gas sales	$	2,252	$	—	$	4,594	$	—


	Three and six months ended
	2011		2010
Location of Gain Recognized in Income (Ineffective) Portion and Amount Excluded from Effectiveness Testing		N/A		N/A


¹		Other comprehensive income (“OCI”).

The before-tax effect of derivative instruments not designated as hedging instruments on the consolidated statements of operations for the three and six months ended June 30, 2011 and 2010 was as follows:


	Amount of Gain Recognized in Income on Derivatives for the
	Three Months Ended June 30,					Six Months Ended June 30,
	2011		2010			2011		2010

Unrealized gain (loss) on price risk management activities²	$	1,900	$	(1,563	)	$	418	$	6,482
Realized gain (loss) on price risk management activities ²		168		1,666			511		1,443

Total price risk management activites	$	2,068	$	103		$	929	$	7,925


²		Included in price risk management activities, net on the consolidated statements of operations.

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

Fair Value Accounting

The Company records certain of its assets and liabilities on the consolidated balance sheets at fair value. 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 to 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 of the fair values 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	$	—	$	5,688	$	—	$	5,688

Total assets at fair value	$	—	$	5,688	$	—	$	5,688

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 six months ended June 30, 2011.

The following describes the valuation methodologies the Company uses for its fair value measurements.

Cash and cash equivalents

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

Derivative instruments

The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit rating. The Company also performs an internal valuation to ensure the reasonableness of third party quotes.

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 June 30, 2011, the types of derivative instruments utilized by the Company included costless collars and swaps. The natural gas derivative markets are highly active. Although the Company’s cash flow and 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.

Asset retirement obligations

The Company estimates asset retirement obligations pursuant to the provisions of FASB ASC Topic 410, “Asset Retirement and Environmental Obligations.” The income valuation technique is utilized by the Company to determine the fair value of the liability at the point of inception by taking into account (1) the cost of abandoning oil and gas wells, which is based on the Company’s historical experience for similar work, or estimates from independent third parties; (2) the economic lives of its properties, which is based on estimates from reserve engineers; (3) the inflation rate; and 4) the credit adjusted risk-free rate, which takes into account the Company’s credit risk and the time value of money. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. There were no asset retirement obligations measured at fair value within the consolidated balance sheet at June 30, 2011.

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 the third party that markets most of the Company’s natural gas. Collectability is dependent upon the financial wherewithal of each individual company as well as the general economic conditions of the industry. The receivables are not collateralized.

The Company currently uses three 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.

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 did not record any proved property impairment expense in the three and six months ended June 30, 2011 and 2010. The Company wrote off $0 and $73 in the three and six months ended June 30, 2011 and $80 and $80 in each of the three and six months ended June 30, 2010 related to expired undeveloped leaseholds.

Compensation Plans

The Company recognized stock-based compensation expense of $250 and $525 during the three and six months ended June 30, 2011, respectively, as compared to $220 and $496 in the three and six months ended June 30, 2010, respectively.

Compensation expense related to stock options is calculated using the Black Scholes valuation model. Expected volatilities are based on the historical volatility of Double Eagle’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 June 30, 2011 and changes during the six months ended June 30, 2011 is presented below:


						Weighted-
						Average
				Weighted-		Remaining
				Average		Contractual		Aggregate
				Exercise		Term (in		Intrinsic
	Shares			Price		years)		Value
Options:
Outstanding at January 1, 2011		556,339		$	12.94		4.4
Granted		26,659		$	5.10
Exercised		(1,200	)	$	4.50
Cancelled/expired		(50,000	)	$	17.95

Outstanding at June 30, 2011		531,798		$	12.10		3.9	$	575


Exercisable at June 30, 2011		296,363		$	13.23		3.4	$	186

The Company measures the fair value of the 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 these compensation costs net of a forfeiture rate and recognizes the compensation costs 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 June 30, 2011 and changes during the six months ended June 30, 2011 were as follows:


				Weighted-
				Average
				Grant Date
	Shares			Fair Value
Stock Awards:
Outstanding at January 1, 2011		83,304		$	8.40
Granted		15,279		$	5.73
Vested		(38,923	)	$	4.76
Forfeited/returned		—		$	—

Nonvested at June 30, 2011		59,660		$	10.10

As part of the acquisition of Petrosearch in 2009, the Company assumed all outstanding warrants to purchase common stock that had been issued by Petrosearch prior to the merger. At June 30, 2011, the Company had 8,660 warrants with an exercise price of $21.25 that expire December 2011. The warrants had no intrinsic value at June 30, 2011.

Income Taxes

Double Eagle is required to record income tax expense for financial reporting purpose. 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 June 30, 2011, 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 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.

Credit Facility

At June 30, 2011, the Company had a $75 million revolving line of credit in place with a $60 million borrowing base. The credit facility is collateralized by the Company’s oil and gas producing properties. As of June 30, 2011, the balance outstanding on the credit facility of $32,000 has been used to fund the past three years of development of the Catalina Unit and other non-operated projects in the Atlantic Rim, as well as projects in the Pinedale Anticline. Any balance outstanding on the facility matures on January 31, 2013.

Borrowings under the revolving line of credit bear interest at a daily rate equal to the greater of (a) the Federal Funds rate, plus 0.5%, the Prime Rate or the Eurodollar LIBOR Rate plus 1%, plus (b) a margin ranging between 1.25% and 2.0% depending on the level of funds borrowed. The interest rate on the facility at June 30, 2011 was 2.87%. For the three months ended June 30, 2011 and 2010, the Company incurred interest expense of $232 and $353, respectively, related to the credit facility and $558 and $713 for the six months ended June 30, 2011 and 2010, respectively. The Company capitalized interest costs of $29 and $37 for the three months ended June 30, 2011 and 2010, respectively, and $64 and $87 for the six months ended June 30, 2011 and 2010, respectively.

Under the facility, the Company is subject to both financial and non-financial covenants. The financial covenants include maintaining (i) a current ratio, as defined in the agreement, 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 June 30, 2011, the Company was in compliance with all financial covenants. If the Company violates the covenants, and is unable to negotiate a waiver or amendment thereof, the lender would have the right to declare an event of default, terminate the remaining commitment and accelerate all principal and interest outstanding.

In July 2011, the Company entered into a $30 million fixed rate swap contract with a third party as a hedge against the floating interest rate on its credit facility. Under the hedge contract terms, the Company will effectively lock in the Eurodollar LIBOR portion of the interest calculation at approximately 0.578% for a portion of its outstanding debt. The contract is effective July 6, 2011 through December 31, 2012.

Series A Cumulative Preferred Stock

In 2007, the Company completed a public offering of 1,610,000 shares of 9.25% Series A Cumulative Preferred Stock (“Series A Preferred Stock”) at a price to the public of $25.00 per share.

Holders of the Series A Preferred Stock are entitled to receive, when and as declared by the 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 some circumstances, upon a change of ownership or control. Except pursuant to the special redemption upon a change of ownership or control, the Company may not redeem the Series A Preferred Stock prior to June 30, 2012. On or after June 30, 2012, 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 following redemption provision. Following a change of ownership or control of the Company by a person or entity, other than by a “Qualifying Public Company,” 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.

Comprehensive Income (Loss)

The components of comprehensive income (loss) were as follows:


	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2011			2010			2011			2010
Net income (loss) attributable to common stock	$	1,283		$	(1,820	)	$	200		$	3,363
Change in derivative instrument fair value, net of tax expense (benefit) ¹		1,110			511			1,676			1,763
Reclassification to earnings		(2,252	)		—			(4,594	)		—

Comprehensive income (loss)	$	141		$	(1,309	)	$	(2,718	)	$	5,126


(1)		The change in derivative instrument fair value is net of tax expense/(benefit) totaling $(982) and $280 for the three months ended June 30, 2011 and 2010, respectively. The change in derivative instrument fair value is net of tax expense/(benefit) totaling $(1,434) and $1,051 for the six months ended June 30, 2011 and 2010, respectively.

The components of accumulated other comprehensive income were as follows:


	June 30,		December 31,
	2011		2010
Net change in derivative instrument fair value, net of tax expense of $1,593 and $3,027	$	2,650	$	5,568

Total accumulated other comprehensive gain, net	$	2,650	$	5,568

11.

Cash Held in Escrow

The Company has received deposits representing partial prepayments of the expected capital expenditures from third party working interest owners in the Table Top Unit #1 exploration project. The unexpended portion of the deposits at June 30, 2011 and December 31, 2010 totaled $564 and $615, respectively.

12.

Contingencies

Legal proceedings

From time to time, the Company is involved in various legal proceedings, including the matters discussed below. 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.

On December 18, 2009, Tiberius Capital, LLC (“Plaintiff”), a stockholder of Petrosearch Energy Corporation (“Petrosearch”) prior to the Company’s acquisition (the “Acquisition”) of Petrosearch pursuant to a merger between Petrosearch and a wholly-owned subsidiary of the Company, filed a claim in the District Court for the Southern District of New York against Petrosearch, the Company, and the individuals who were officers and directors of Petrosearch prior to the Acquisition. In general, the claims against the Company and Petrosearch are that Petrosearch inappropriately denied dissenters’ rights of appraisal under the Nevada Revised Statutes to its stockholders in connection with the Acquisition, that the defendants violated various sections of the Securities Act of 1933 and the Securities Exchange Act of 1934, and that the defendants caused other damages to the stockholders of Petrosearch. The plaintiff was seeking monetary damage. On March 31, 2011, the District Court judge dismissed the case. The plaintiff filed a notice of appeal on April 29, 2011, which preserves the plaintiff’s right to appeal.

13.

Subsequent Events

In July 2011, the Company entered into a $30 million fixed rate swap contract with a third party as a hedge against the floating interest rate on its credit facility. Under the contract terms, the Company will effectively lock in the Eurodollar LIBOR portion of the interest calculation at approximately 0.578% for a portion of its outstanding debt. The contract is effective July 6, 2011 through December 31, 2012.

The Company has noted no additional events, other than noted above, that require recognition or disclosure at June 30, 2011.


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 includes “forward-looking statements” as defined by the Securities and Exchange Commission, or SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this 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. 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 Form 10-K for the year ended December 31, 2010 and the following factors:

•

Changes in or compliance with laws and regulations, particularly those relating to drilling, derivatives, taxation, safety and protection of the environment;

•

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

•

Our ability to increase our natural gas and oil reserves;

•

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

•

The changing political environment in which we operate;

•

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

•

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, and the availability of specialized contractors, work force, and equipment;

•

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

•

Our ability to maintain adequate liquidity in connection with low oil and gas prices;

•

Incorrect estimates of required capital expenditures;

•

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

•

Increases in the cost of drilling, completion and gas collection or other costs of production and operations;

•

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

•

Our ability to successfully integrate and profitably operate any future acquisitions;

•

The actions of third party co-owners of interests in properties in which we also own an interest;

•

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

•

Weather, climate change and other natural phenomena;

•

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

•

The volatility of our stock price;

•

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

•

The effect of accounting policies issued periodically by accounting standard-setting bodies;

•

Our ability to remedy any deficiencies that may be identified in the review of our internal controls; and

•

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

We also may make material acquisitions or divestitures or enter into financing transactions. None of these events can be predicted with certainty and the possibility of their 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 update publicly any such forward-looking statements, whether as a result of new information, future events, or otherwise.

Business Overview and Strategy

We are an independent energy company engaged in the exploration, development, production and sale of natural gas and crude oil, primarily in Rocky Mountain Basins of the western United States. We were incorporated in Wyoming in 1972 and reincorporated in Maryland in 2001. From 1995 to 2006, our common stock was publicly traded on the NASDAQ Capital Market under the symbol “DBLE”. In December 2006, our common stock began trading on the NASDAQ Global Select Market under the same symbol. Our Series A Cumulative Preferred Stock (“Preferred Stock”) was issued on the NASDAQ Capital Market under the symbol “DBLEP” in July 2007 and began trading on the NASDAQ Global Select Market in September 2007. 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 by focusing primarily on: (i) new coal bed methane gas development drilling; (ii) 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 Fields on the Pinedale Anticline; (iv) expansion of our midstream business; (v) pursuit of high quality exploration and strategic development projects with potential for providing long-term drilling inventories that generate high returns, including the Niobrara formation in the Atlantic Rim and other properties in which we have interests and (vi) selectively pursuing strategic acquisitions.

The operations in the Pinedale Anticline and Atlantic Rim operate under federal exploratory unit agreements between 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, will change as more wells and acreage are added to the PA.

OVERVIEW OF FINANCIAL CONDITION AND LIQUIDITY

Liquidity and Capital Resources

We believe that the amounts available under our $75 million credit facility ($60 million borrowing base), combined with our net cash from operating activities, will provide us with sufficient funds to meet future financial covenants, develop new reserves, maintain our current facilities, and complete our 2011 capital expenditure program (see “Capital Requirements” on the following page). Depending on the timing and amounts of future projects, we may be required 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. The Company currently has an effective Form S-3 shelf registration statement on file with the SEC, which has $150 million of securities available for issuance and provides us the ability to raise additional funds through private placements or registered offerings of equity. We also may be required to secure additional debt.

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


	June 30,			December 31,
	2011			2010

Financial Position Summary
Cash and cash equivalents	$	4,882		$	2,605
Working capital	$	10,388		$	7,477
Balance outstanding on credit facility	$	32,000		$	32,000
Stockholders’ equity and preferred stock	$	88,467		$	90,677
Ratios
Debt to total capital ratio		26.6	%		26.1	%
Total debt to equity ratio		63.4	%		60.7	%

During the six months ended June 30, 2011, our working capital increased to $10,388 compared to $7,477 at December 31, 2010. The higher working capital is primarily the result of a decrease in our accounts payable and accrued liabilities balances. Our accounts payable and accrued expense balance was lower in 2011 due to the timing of drilling activity in the Pinedale Anticline and our year-end 2010 balance included additional capital billings related to a PA adjustment at our non-operated Atlantic Rim properties. We also had greater cash and cash equivalents on hand at June 30, 2011. This was offset somewhat by a decrease in our current assets from price risk management due to the settlement of derivative contracts in the first six months of 2011 and higher production taxes.

Cash flow activities

The table below summarizes our cash flows for the six months ended June 30, 2011 and 2010, respectively:


	Six months ended June 30,
	2011			2010
	(unaudited)
Cash provided by (used in):
Operating activities	$	11,612		$	10,718
Investing activities		(7,185	)		(7,084	)
Financing activities		(2,150	)		(5,124	)

Net change in cash	$	2,277		$	(1,490	)

During the six months ended June 30, 2011, net cash provided by operating activities was $11,612, compared to $10,718 in the same prior-year period. The primary sources of cash during the six months ended June 30, 2011 were $2,062 of net income, which was net of non-cash charges of $9,474 related to depreciation, depletion, and amortization expenses (“DD&A”) and accretion expense, and non-cash stock-based compensation expense of $525. In addition, in the first six months of 2011, we had an increase of $1,238 in the provision for deferred income taxes, which we do not expect to have to pay in the near future due to our NOL carryforwards. We realized a higher natural gas price in the first half of 2011, as compared to 2010 due to our hedging program. This additional cash flow allowed us to use more cash to reduce our accounts payable and accrued expense balance in the six months ended June 30, 2011.

During the six months ended June 30, 2011, net cash used in investing activities was relatively constant, totaling $7,185 in the six months ended June 30, 2011 and $7,084 in the same prior-year period. Our capital expenditures in the first six months of 2011 primarily related to non-operated drilling in the Pinedale Anticline.

During the six months ended June 30, 2011, we had net cash used by financing activities of $2,150, as compared to $5,124 in the same prior-year period. In the first six months of 2011, we maintained the current debt balance throughout the period, whereas in 2010, we repaid $3,000 of the outstanding balance on credit facility. We expended cash in the first half of 2011 and 2010 to make our quarterly dividend payments totaling $1,862 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

At June 30, 2011, we had a $75 million credit facility in place, with $60 million borrowing base. The credit facility is collateralized by our oil and gas producing properties and other assets. As of June 30, 2011, the outstanding balance on our credit facility was $32,000. The interest rate as of June 30, 2011, calculated in accordance with the agreement, was 2.87%, compared to an interest rate of 4.5% at June 30, 2010. For the three months ended June 30, 2011 and 2010, we incurred interest expense of $232 and $353, respectively, related to the credit facility and $558 and $713 for the six months ended June 30, 2011 and 2010, respectively. We capitalized interest costs of $29 and $37 for the three months ended June 30, 2011 and 2010, respectively, and $64 and $87 for the six months ended June 30, 2011 and 2010, respectively.

In July 2011, we entered into a $30 million fixed rate swap contract with a third party as a hedge against the floating interest rate on our credit facility. Under the hedge contract terms, we have effectively locked in the Eurodollar LIBOR portion of the interest calculation at approximately 0.578% for a portion of our outstanding debt. Based upon our debt level at June 30, 2011, our interest rate would be fixed at approximately 3.08% for a $30 million tranche of our outstanding debt. The swap contract is effective July 6, 2011 through December 31, 2012.

We are subject to certain financial and non-financial covenants with respect to the above credit facility, including requirements to maintain (i) a current ratio, as defined in the agreement, of at least 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 June 30, 2011, we were in compliance with all covenants under the credit facility. If we violate any of the covenants, 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 and accelerate all principal and interest outstanding.

Our borrowing base is subject to redetermination each April 1 and October 1, beginning October 1, 2011.

Capital Requirements

For 2011, we have budgeted approximately $30 million for our development and exploration programs, which include our assets in the Atlantic Rim and Pinedale Anticline. We intend to drill in the Atlantic Rim in the second half of 2011, with 14 coal bed methane (“CBM”) production wells within the Catalina Unit. We expect to participate in approximately 16 new wells at the Mesa Units. We also have allocated capital in our 2011 capital budget for one exploratory well into the Niobrara formation in the Atlantic Rim. We are still waiting for permits for this well. We expect to fund our 2011 capital expenditures with cash provided by operating activities and funds made available through our credit facility. Our 2011 capital budget does not include the impact of potential future exploration projects or possible acquisitions, which we continually evaluate.

Contractual Obligations

The impact that our contractual obligations as of June 30, 2011 are expected to have on our liquidity and cash flows in future periods is:


			Less than		1 - 3		3- 5		More than
	Total		one year		Years		Years		5 Years
Credit facility (a)	$	32,000	$	—	$	32,000	$	—	$	—
Interest on credit facility (b)		1,556		931		625		—		—
Capital leases		376		376		—		—		—
Operating leases		5,539		2,491		2,890		158		—

Total contractual cash commitments	$	39,471	$	3,798	$	35,515	$	158	$	—


(a)		The amount listed reflects the balance outstanding as of June 30, 2011. Any balance outstanding on our credit facility at January 31, 2013, will be due at that time.

(b)		Assumes the interest rate on our credit facility is consistent with that of June 30, 2011.

Off-Balance Sheet Arrangements

We do not participate in transactions that generate relationships with unconsolidated entities or financial partnerships. Such entities are often referred to as structured finance or special purpose entities (“SPEs”) or variable interest entities (“VIEs”). SPEs and VIEs can be established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. We were not involved in any unconsolidated SPEs or VIEs at any time during any of the periods presented.

RESULTS OF OPERATIONS

Three months ended June 30, 2011 compared to the three months ended June 30, 2010

Oil and gas sales volume and price comparisons


	Three Months Ended June 30,								Percent			Percent
	2011				2010				Volume			Price
	Volume		Average Price		Volume		Average Price		Change			Change
Product:
Gas (Mcf)		2,278,019	$	4.80		2,212,115	$	3.99		3	%		20	%
Oil (Bbls)		6,625	$	93.50		5,892	$	75.00		12	%		25	%
Mcfe		2,317,769	$	4.99		2,247,466	$	4.13		3	%		21	%

For the three months ended June 30, 2011, oil and gas sales increased 50% to $11,393, as compared to the three months ended June 30, 2010. The increase is largely attributed to cash we received upon settlement of our cash flow hedge, totaling $2,252 for the three months ended June 30, 2011. In addition, the average CIG market price, which is the index on which most of our gas volumes are sold, rose 6% from the three months ended June 30, 2010 and production volumes increased 3%, both of which also resulted in higher oil and gas sales.

Our average realized natural gas price increased 20% to $4.80 for the three months ended June 30, 2011, as compared to the three months ended June 30, 2010. We calculate our average realized natural gas price by summing (1) production revenue received from third parties for the sale of our gas, which is included within oil and gas sales on the consolidated statements of operations; (2) settlement of our cash flow hedges included within oil and gas sales on the consolidated statement of operations; and (3) realized gain/ (loss) on our economic hedges, which is included within price risk management activities, net on the consolidated statements of operations, totaling $168 and $1,666, for the three months ended June 30, 2011 and 2010, respectively.

Our total net production increased 3% to 2,318 MMcfe for the quarter ended June 30, 2011 as compared to 2,247 MMcfe for the three months ended June 30, 2010. We experienced an increase in production volumes at the Sun Dog and Doty Mountain Units, which offset a production decline at the Catalina Unit, as discussed below.

During the three months ended June 30, 2011, our total average daily net production at the Atlantic Rim increased 8% to 19,053 Mcfe, as compared to 17,565 Mcfe during the same prior-year period. Our Atlantic Rim production comes from three operating units, the Catalina Unit, the Sun Dog Unit and the Doty Mountain Unit. The Catalina Unit is operated by the Company.

•

Average daily net production at our Catalina Unit decreased 8% to 13,431 Mcfe per day, as compared to 14,531 Mcfe per day during the same prior-year period. The decrease is largely the result of what management believes to be the normal production decline for wells within the field.

•

Average daily net production at the Sun Dog and Doty Mountain Units increased 85% for the three months ended June 30, 2011 to 5,622 Mcfe per day, as compared to 3,034 Mcfe per day in the same prior-year period, largely due to our higher working interest in both units. We purchased additional working interests in the Sun Dog and Doty Mountain Units during the third quarter of 2010, which increased our working interest in the Sun Dog Unit to 20.46% from 8.89%, and the Doty Mountain Unit to 18.00% from 16.5%. The increase is also attributed in part to better production from certain Doty Mountain wells due to fracture stimulation and additional water capacity at the Sun Dog Unit.

Average daily net production in the Pinedale Anticline remained relatively constant quarter over quarter, totaling 5,052 Mcfe for the three months ended June 30, 2011, as compared to 5,053 Mcfe in the same prior-year period. The operator brought seven new wells on-line for production during the quarter. The operator at the Mesa Units has informed us that it expects to complete 10 additional wells over the next two quarters. In addition, the operator has indicated that it expects to begin drilling 16 additional wells in 2011.

Transportation and gathering revenue

During the three months ended June 30, 2011, transportation and gathering revenue decreased 13% to $1,221 from $1,401 for the three months ended June 30, 2010. 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. The decrease in revenue is due to the lower production volume at the Catalina Unit.

Price risk management activities, net

We recorded a net gain on our derivative contracts not designated as cash flow hedges of $2,068 for the three months ended June 30, 2011, as compared to a gain of $103 for the same prior-year period. The net gain consisted of an unrealized non-cash gain of $1,900, which represents the change in the fair value on our economic hedges at June 30, 2011, based on the expected future prices of the related commodities, and a net realized gain of $168 related to the cash settlement of some of our economic hedges.

Oil and gas production expenses and depreciation, depletion and amortization


	Three Months Ended June 30,
	2011			2010
	(in dollars per Mcfe)
Average price	$	4.99		$	4.13

Production costs		1.19			1.07
Production taxes		0.47			0.45
Depletion and amortization		1.99			1.97

Total operating costs		3.65			3.49


Gross margin	$	1.34		$	0.64

Gross margin percentage		27	%		15	%

Production costs, on a dollars per Mcfe basis, is calculated by dividing production costs, as stated on the consolidated statements of operations, by total production volumes during the period. This calculation excludes certain gathering costs incurred by the Company’s subsidiary, Eastern Washakie Midstream LLC, which are eliminated in consolidation. During the three months ended June 30, 2011, well production costs increased 15% to $2,769, as compared to $2,397 during the same prior-year period, and production costs in dollars per Mcfe increased 11%, or $0.12 to $1.19, as compared to the same prior-year period. The increase in production costs was driven by additional production costs from the Sun Dog and Doty Mountain Units resulting from our increased working interests at these properties, which was purchased in July 2010. Because production from the Sun Dog and Doty Mountain Units, which have historically yielded lower margins than many of our properties, made up a larger percentage of our total production during the 2011 period, we also experienced an increase in production costs on a per Mcfe basis. This increase in production costs at the Sun Dog and Doty Mountain Units was partially offset by lower repair and maintenance costs at the Catalina Unit.

Depreciation, depletion, and amortization (“DD&A”) for the quarter ended June 30, 2011 increased 4% to $4,718, as compared to $4,530 in the same prior-year period, and depletion and amortization related to producing assets also increased 4% to $4,612 as compared to $4,428 in the same prior-year period. The increase in DD&A expense was primarily driven by higher production volumes. Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased 1%, or $0.02, to $1.99 as compared to the same prior-year period.

Pipeline operating costs

During the three months ended June 30, 2011, pipeline operating costs increased 5% to $1,020 from $971 for the three months ended June 30, 2010.

General and administrative expenses

General and administrative expenses decreased 2% to $1,362 for the three months ended June 30, 2011, as compared to $1,392 for the three months ended June 30, 2010. During the second quarter of 2011, we recovered from our insurance company approximately $101 of legal fees related to litigation resulting from our 2009 Petrosearch acquisition. This was offset by a $45 increase in bad debt expense and a $27 increase in director fees due to the addition of one independent director in the first quarter of 2011.

Income taxes

We recorded income tax expense of $1,342 during the three months ended June 30, 2011, as compared to an income tax benefit of $512 during the same prior-year period. Our effective tax rate for the three months ended June 30, 2011 was 37.55% compared to 36.0% for the second quarter of 2010. Our effective tax rate was higher in the 2011 period due to an increase in the proportion of permanent income tax differences related to stock option expense as compared to net income and an increase in non-deductible DD&A expense. 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 2011 at an expected federal and state rate of approximately 35.2%.

Six months ended June 30, 2011 compared to the six months ended June 30, 2010

Oil and gas sales volume and price comparisons


	Six Months Ended June 30,								Percent			Percent
	2011				2010				Volume			Price
	Volume		Average Price		Volume		Average Price		Change			Change
Product:
Gas (Mcf)		4,491,692	$	4.82		4,412,125	$	4.34		2	%		11	%
Oil (Bbls)		13,390	$	88.05		12,828	$	73.07		4	%		21	%
Mcfe		4,572,032	$	4.99		4,489,091	$	4.47		2	%		12	%

For the six months ended June 30, 2011, oil and gas sales increased 20% to $22,303, as compared to $18,657 during the first six months of 2010. The increase is attributed to our hedging program, which provided cash of $4,594 from the settlement of our cash flow hedges during the first six months of 2011. In addition, we experienced a 2% increase in production volumes in the first six months of 2011 as compared to the same prior-year period. These increases were offset by a 6% decrease in the average CIG market price, which is the index on which most of our gas volumes are sold.

Our average realized natural gas price increased 11% to $4.82 for six months ended June 30, 2011, as compared to the first six months of 2010. Despite the decrease in the average CIG market price during the 2011 period, we realized a higher natural gas price as a result of our hedging program. In addition to the $4,594 of cash flow hedge settlements included in oil and gas sales noted above, we also realized settlements on our economic hedges totaling $511 during the 2011 period. For the six months ended June 30, 2010 our hedges accounted for a total of $1,443.

Our total net production increased 2% to 4,572 MMcfe for the six months ended June 30, 2011 compared to 4,489 MMcfe for the same prior year period. We experienced an increase in production volumes at the Sun Dog and Doty Mountain Units, which offset the production decline at the Catalina Unit, as discussed below.

During the six months ended June 30, 2011, average daily net production at the Atlantic Rim increased 5% to 18,830 Mcfe, as compared to 17,911 Mcfe during the same prior-year period, which is further broken out below:

•

Average daily net production at our Catalina Unit decreased 10% to 13,576 Mcfe per day, as compared to 15,062 Mcfe per day during the first six months of 2010. The decrease is largely the result of what management believes to be the normal production decline for wells within the field.

•

Average daily net production at the Sun Dog and Doty Mountain Units increased 84% for the six months ended June 30, 2011 to 5,254 Mcfe per day from 2,849 Mcfe per day in the same prior-year period, largely due to our higher working interest in both units. We purchased additional working interests in the Sun Dog and Doty Mountain Units during the third quarter of 2010, which increased our working interest in the Sun Dog Unit to 20.46% from 8.89% prior to the purchase, and the Doty Mountain Unit to 18.00% from 16.5% prior to the purchase. The increase is also attributed in part to better production from certain Doty Mountain wells due to fracture stimulation and additional water injection capacity at the Sun Dog Unit.

Average daily net production in the Pinedale Anticline was relatively constant for the six months ended June 30, 2011, totaling 5,010 Mcfe per day, as compared to 5,034 Mcfe in the same prior-year period. The operator brought an additional seven wells on-line throughout the second quarter of 2011. The operator at the Mesa Units has informed us that it expects to complete 10 additional wells over the next two quarters. In addition, the operator has indicated that it expects to begin drilling 16 more wells in 2011.

Transportation and gathering revenue

During the six months ended June 30, 2011, transportation and gathering revenue decreased 15% to $2,453 from $2,889. 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. The decrease in revenue is due to the lower production volume at the Catalina Unit.

Price risk management activities, net

We recorded a net gain on our derivative contracts not designated as cash flow hedges of $929 for the six months ended June 30, 2011, as compared to a gain of $7,925 for the six months ended June 30, 2010. The net gain consisted of an unrealized non-cash gain of $418, which represents the change in the fair value on our economic hedges at June 30, 2011, based on the future expected prices of the related commodities, and a net realized gain of $511 related to the cash settlement of some of our economic hedges.

Oil and gas production expenses, and depreciation, depletion and amortization


	Six Months Ended June 30,
	2011			2010
	(in dollars per Mcfe)
Average price	$	4.99		$	4.47

Production costs		1.17			0.97
Production taxes		0.47			0.51
Depletion and amortization		2.01			1.97

Total operating costs		3.65			3.45


Gross margin	$	1.34		$	1.02

Gross margin percentage		27	%		23	%

During the six months ended June 30, 2011, well production costs increased 23% to $5,343, as compared to $4,339 during the same prior-year period, and production costs in dollars per Mcfe increased 21%, or $0.20 to $1.17, as compared to the same prior-year period. The increase in production costs in total was driven by additional production costs from the Sun Dog and Doty Mountain Units resulting from our increased working interests at these properties. In addition, because production from the Sun Dog and Doty Mountain Units, which have historically yielded lower margins than many of our properties, made up a larger percentage of our total production during the 2011 period, we experienced an increase in production costs on a per Mcfe basis.

DD&A increased 3% to $9,391 for the six months ended June 30, 2011, as compared to $9,097 for the six months ended June 30, 2010, and depletion and amortization related to producing assets also increased 4% to $9,180 as compared to $8,866 in the same prior-year period. The increase in DD&A expense was primarily driven by higher production volumes. Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased 2%, or $0.04, to $2.01 as compared to the same prior-year period.

Pipeline operating costs

During the six months ended June 30, 2011, pipeline operating costs decreased to $2,001 from $2,119 as compared to the same prior-year period.

General and administrative expenses

General and administrative expenses remained relatively constant period over period, totaling $2,920 and $2,925 for the six months ended June 30, 2011 and 2010, respectively. During the second quarter o f 2011, we recovered from our insurance company approximately $101 of legal fees related to litigation resulting from our 2009 Petrosearch acquisition. In addition, we realized a $77 decrease in audit and tax fees, a $78 decrease in legal fees and a $49 decrease in our directors and officers insurance as compared to the same prior year period. These decreases were offset by a $69 increase related to our Board of Directors expense due to the expansion of our Board and expenses incurred related to Board training and conferences, an increase in bank fees of $56 due to an increase in the unused portion of our credit facility and in 2010 we had recovered an outstanding receivable that had previously been written off totaling $155.

Income taxes

During the six months ended June 30, 2011, we recorded income tax expense of $1,238 compared to income tax expense of $2,945 during the same prior-year period. Our effective tax rate for the six months ended June 30, 2011 was 37.55% compared to 36.0% for the second quarter of 2010. Our effective tax rate was higher in the 2011 period due to an increase in the proportion of permanent income tax differences related to stock option expense as compared to net income and an increase in non-deductible DD&A expense. 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 2011 at an expected federal and state rate of approximately 35.2%.

CONTRACTED 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. Historically these derivative instruments have consisted of fixed delivery contracts, swaps, options 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 June 30, 2011 are summarized below (volume and daily production are expressed in Mcf):

Remaining

Contractual

Daily

Price

Type of Contract

Volume

Production

Term

Price

Index (1)

Fixed Price Swap

1,472,000

8,000

01/11-12/11

$7.07

CIG

Costless Collar

155,000

5,000

08/09-07/11

$4.50 floor

NYMEX

$7.90 ceiling

Costless Collar

765,000

5,000

12/09-11/11

$4.50 floor

NYMEX

$9.00 ceiling

Fixed Price Swap

1,830,000

5,000

01/12-12/12

$5.10

NYMEX

Fixed Price Swap

3,660,000

10,000

01/12-12/12

$5.05

NYMEX

Fixed Price Swap

2,190,000

6,000

01/13-12/13

$5.16

NYMEX

Costless Collar

2,190,000

6,000

01/13-12/13

$5.00 floor

NYMEX

$5.35 ceiling

Total

12,262,000


(1)		CIG refers to the Colorado Interstate Gas price as quoted on the first day of each month. NYMEX refers to quoted prices on the New York Mercantile Exchange.

Refer to Note 3 in the Notes to the Consolidated Financial Statements for additional discussion on the accounting treatment of our derivative contracts.

Subsequent to the end of the period ended June 30, 2011, we entered into a $30 million fixed rate swap contract with a third party as a hedge against the floating interest rate on our credit facility. which fixes the Eurodollar portion of our interest rate calculation at approximately 0.578%. The contract is in place through December 31, 2012.

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, 2010, and to the Notes to the Consolidated Financial Statements included in Part I, Item 1 of this report.


ITEM 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risks

Our major market risk exposure is in the pricing applicable to our natural gas and oil production. Pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. natural gas production. Pricing for oil production and natural gas has been volatile and unpredictable for several years. The prices we receive for production depend on many factors outside of our control. For the three months ended June 30, 2011, our income before income taxes would have increased by $548 for each $0.50 increase per Mcf in natural gas prices and decreased by $297 for each $0.50 decrease per Mcf in natural gas prices due to the contracted volumes discussed above. Our income taxes would have increased $6 for each $1.00 change per Bbl in crude oil prices for the three months ended June 30, 2011.

The primary objective of our commodity price risk management policy is to preserve and enhance the value of our equity gas production. We have entered into natural gas derivative contracts to manage our exposure to natural gas price volatility. Our derivative instruments typically consist of forward sales contracts, swaps and costless collars, which allow us to effectively “lock in” a portion of our future production of natural gas at prices that we consider favorable to us at the time we enter into the contract. These derivative instruments which have differing expiration dates, are summarized in the table presented above under “Contracted Volumes”.

Interest Rate Risks

At June 30, 2011, we had a total of $32,000 outstanding under our $75 million credit facility ($60 million borrowing availability). We pay interest on outstanding borrowings under our credit facility at interest rates that fluctuate based upon changes in our levels of outstanding debt and the prevailing market rates. The average interest rate for the three months ended June 30, 2011, calculated in accordance with the agreement, was 2.87%. Because the interest rate is variable and reflects current market conditions, the carrying value approximates the fair value. Assuming no change in the amount outstanding at June 30, 2011, the annual impact on interest expense for every 1.0% change in the average interest rate would be approximately $320 before taxes. Any balance outstanding on the credit facility matures on January 31, 2013.

In July 2011, we entered into a $30 million fixed rate swap contract with a third party as a hedge against the floating interest rate on our credit facility. Under the hedge contract terms, we have effectively locked in the Eurodollar LIBOR portion of the interest calculation at approximately 0.578% for a portion of our outstanding debt. Based upon our debt level at June 30, 2011, this would result in a fixed interest rate of 3.08% for a $30 million tranche of our outstanding debt. The contract is effective July 6, 2011 through December 31, 2012.


ITEM 4.		CONTROLS AND PROCEDURES

In accordance with the Securities Exchange Act of 1934 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 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 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 Securities and Exchange Commission rules and forms.

There has been no change in our internal control over financial reporting that occurred during the quarter ended June 30, 2011 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


ITEM 1A.		RISK FACTORS

There have been no material changes in our Risk Factors from those reported in Item 1A of Part I of our 2010 Annual Report on Form 10-K filed with the Securities and Exchange Commission, which we incorporate by reference herein.


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 of 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, (incorporated by reference from Exhibit 3.2 of the Company’s Current Report of Form 8-K dated June 29, 2007).

	3.1	(g)	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 of Form 8-K dated August 28, 2007).

	3.1	(h)	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).

	3.2		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 on June 11, 2007).

	4.1	(a)	Form of Warrant Agreement concerning Common Stock Purchase Warrants (incorporated by reference from Exhibit 4.3 of the Amendment No. 1 to the Company’s Registration Statement on Form SB-2 filed on November 27, 1996, SEC Registration No. 333-14011).

	4.1	(b)	Rights Agreement between the Company and Computershare Trust Company, N.A. (incorporated herein by reference to the Company’s Current Report on Form 8-K filed on August 24, 2007)

	10.1	(a)	Second Amendment to Amended and Restated Credit Agreement dated March 8, 2011 between Double Eagle Petroleum Co. and Bank of Oklahoma, N.A. et.al; (incorporated by reference from Exhibit 10.1, of the Company’s Current report of Form 8-K dated March 10, 2011).


Exhibit			Description:

	31.1	*	Certification of Principal Executive Officer and 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.LAB	**	XBRL Taxonomy Extension Label Linkbase Document

	101.PRE	**	XBRL Taxonomy Extension Presentation Linkbase Document


*		Filed within this Form 10-Q.

**		Pursuant to Rule 406T of Regulation S-T, these Interactive Data Files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to the liability under these sections.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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: August 4, 2011	By:	/s/ Richard D. Dole
		Richard D. Dole
		Chief Executive Officer (Principal Executive Officer)

EXHIBIT INDEX


Exhibit Number			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 of 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, (incorporated by reference from Exhibit 3.2 of the Company’s Current Report of Form 8-K dated June 29, 2007).

	3.1	(g)	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 of Form 8-K dated August 28, 2007).

	3.1	(h)	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).

	3.2		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 on June 11, 2007).

	4.1	(a)	Form of Warrant Agreement concerning Common Stock Purchase Warrants (incorporated by reference from Exhibit 4.3 of the Amendment No. 1 to the Company’s Registration Statement on Form SB-2 filed on November 27, 1996, SEC Registration No. 333-14011).

	4.1	(b)	Rights Agreement between the Company and Computershare Trust Company, N.A. (incorporated herein by reference to the Company’s Current Report on Form 8-K filed on August 24, 2007)

	10.1	(a)	Second Amendment to Amended and Restated Credit Agreement dated March 8, 2011 between Double Eagle Petroleum Co. and Bank of Oklahoma, N.A. et.al; (incorporated by reference from Exhibit 10.1, of the Company’s Current report of Form 8-K dated March 10, 2011).


Exhibit Number			Description:

	31.1	*	Certification of Principal Executive Officer and 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.LAB**			XBRL Taxonomy Extension Label Linkbase Document

101.PRE**			XBRL Taxonomy Extension Presentation Linkbase Document


*		Filed within this Form 10-Q.

**		Pursuant to Rule 406T of Regulation S-T, these Interactive Data Files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to the liability under these sections.

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