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

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

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 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 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)		Smaller 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 October 31, 2011 11,204,020

 

 

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, 2011 and December 31, 2010 (Unaudited)			2
Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2011 and 2010 (Unaudited)			3
Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2011 and 2010 (Unaudited)			4
Notes to Consolidated Financial Statements (Unaudited)			5
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			24
PART II. Other Information:
Item 1. Legal Proceedings			24
Item 1A. Risk Factors			25
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			25
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.

(Unaudited)

		September 30,				December 31,
		2011				2010
ASSETS
Current assets:
Cash and cash equivalents		$	5,952			$	2,605
Cash held in escrow			564				615
Accounts receivable			5,074				5,396
Assets from price risk management			6,481				9,622
Other current assets			4,840				3,653
Total current assets			22,911				21,891
Oil and gas properties and equipment, successful efforts method:
Developed properties			194,226				188,143
Wells in progress			9,039				4,039
Gas transportation pipeline			5,475				5,465
Undeveloped properties			3,068				3,062
Corporate and other assets			2,001				1,982
			213,809				202,691
Less accumulated depreciation, depletion and amortization			(86,543	)			(72,226	)
Net properties and equipment			127,266				130,465
Assets from price risk management			2,142				—
Other assets			142				161
TOTAL ASSETS		$	152,461			$	152,517
LIABILITIES, PREFERRED STOCK AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses		$	10,184			$	10,830
Accrued production taxes			2,034				2,757
Capital lease obligations, current portion			137				545
Other current liabilities			119				282
Total current liabilities			12,474				14,414
Credit facility			32,000				32,000
Asset retirement obligation			6,475				5,848
Deferred tax liability			10,939				9,578
Total liabilities			61,888				61,840
Preferred stock, $0.10 par value; 10,000,000 shares authorized; 1,610,000 shares issued and outstanding as of September 30, 2011 and December 31, 2010			37,972				37,972
Stockholders’ equity:
Common stock, $0.10 par value; 50,000,000 shares authorized; 11,210,903 issued and 11,198,204 shares outstanding as of September 30, 2011 and 11,165,305 issued and 11,155,080 outstanding as of December 31, 2010, respectively			1,119				1,116
Additional paid-in capital			45,331				44,583
Retained earnings			4,543				1,438
Accumulated other comprehensive income			1,608				5,568
Total stockholders’ equity			52,601				52,705
TOTAL LIABILITIES, PREFERRED STOCK AND STOCKHOLDERS’ EQUITY		$	152,461			$	152,517

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

DOUBLE EAGLE PETROLEUM CO.

(Unaudited)

		Three months ended September 30,								Nine months ended September 30,
		2011				2010				2011				2010
Revenues
Oil and gas sales		$	11,540			$	7,601			$	33,843			$	26,258
Transportation revenue			1,221				1,349				3,674				4,238
Price risk management activities, net			4,803				3,263				5,732				11,188
Proceeds from Madden Deep settlement			—				3,841				—				3,841
Other income, net			469				108				774				465
Total revenues			18,033				16,162				44,023				45,990
Costs and expenses
Production costs			3,018				2,828				8,361				7,167
Production taxes			1,084				1,180				3,230				3,489
Exploration expenses including dry hole costs			67				56				239				122
Pipeline operating costs			1,016				987				3,017				3,106
General and administrative			1,513				1,540				4,433				4,465
Impairment and abandonment of equipment and properties			—				—				73				80
Depreciation, depletion and amortization			4,926				4,701				14,317				13,771
Total costs and expenses			11,624				11,292				33,670				32,200
Income from operations			6,409				4,870				10,353				13,790
Interest expense, net			(352	)			(422	)			(997	)			(1,172	)
Income before income taxes			6,057				4,448				9,356				12,618
Provision for deferred income taxes			(2,221	)			(1,586	)			(3,459	)			(4,531	)
NET INCOME		$	3,836			$	2,862			$	5,897			$	8,087
Preferred stock dividends			930				930				2,792				2,792
Net income attributable to common stock		$	2,906			$	1,932			$	3,105			$	5,295
Net income per common share:
Basic		$	0.26			$	0.17			$	0.28			$	0.48
Diluted		$	0.26			$	0.17			$	0.28			$	0.48
Weighted average common shares outstanding:
Basic			11,197,681				11,128,802				11,187,298				11,117,060
Diluted			11,226,724				11,128,802				11,207,517				11,117,060

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

DOUBLE EAGLE PETROLEUM CO.

(Unaudited)

		Nine months ended September 30,
		2011				2010
Cash flows from operating activities:
Net income		$	5,897			$	8,087
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion, amortization and accretion of asset retirement obligation			14,444				13,862
Abandonment of non-producing properties			73				80
Provision for deferred taxes			3,459				4,489
Stock-based compensation expense			767				726
Non-cash gain on transfer of asset retirement obligation to third party			—				(164	)
Change in fair value of derivative contracts			(4,993	)			(8,030	)
Revenue from carried interest			(117	)			(1,727	)
Gain on sale of oil and gas properties			(582	)			(213	)
Changes in current assets and liabilities:
Decrease (Increase) in deposit held in escrow			51				(3	)
Decrease in accounts receivable			322				1,218
Decrease (Increase) in other current assets			230				(392	)
Increase (Decrease) in accounts payable and accrued expenses			(46	)			2,350
Increase (Decrease) in accrued production taxes			(723	)			968
NET CASH PROVIDED BY OPERATING ACTIVITIES			18,782				21,251
Cash flows from investing activities:
Sale of oil and gas properties and equipment			371				7
Payments to acquire producing properties and equipment, net			(12,491	)			(11,466	)
Payments to acquire corporate and non-producing properties			(98	)			(843	)
Purchase of additional Atlantic Rim working interest			—				(7,761	)
NET CASH USED IN INVESTING ACTIVITIES			(12,218	)			(20,063	)
Cash flows from financing activities:
Principal payments on capital lease obligations			(408	)			(399	)
Issuance of stock under Company stock plans			—				7
Tax withholdings related to net share settlement of restricted stock awards			(17	)			(3	)
Dividends paid on preferred stock			(2,792	)			(2,792	)
NET CASH PROVIDED BY FINANCING ACTIVITIES			(3,217	)			(3,187	)
Change in cash and cash equivalents			3,347				(1,999	)
Cash and cash equivalents at beginning of period			2,605				5,682
CASH AND CASH EQUIVALENTS AT END OF PERIOD		$	5,952			$	3,683
Supplemental disclosure of cash and non-cash transactions:
Cash paid for interest		$	744			$	1,302
Cash paid for income taxes			—				41
Interest capitalized			93				124
Additions to developed properties included in current liabilities			4,014				733

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

DOUBLE EAGLE PETROLEUM CO.

(Unaudited)

1.

Summary of Significant Accounting Policies

Basis of presentation

The accompanying unaudited 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 (“U.S. GAAP”) 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 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. This 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.

2.

Earnings Per Share

Basic earnings per share of common stock (“EPS”) is calculated by dividing net income attributable to common stock by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per common share incorporates the treasury stock method, and is calculated by dividing net income 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 to holders of Series A Preferred Stock cash dividends of $930 and $2,792 ($.5781 per share) for each of the each of the three and nine months ended September 30, 2011 and 2010, respectively.

The following is the calculation of basic and diluted weighted average shares outstanding and earnings per common share for the periods indicated:

		Three Months Ended September 30,								Nine Months Ended September 30,
		2011				2010				2011				2010
Net income		$	3,836			$	2,862			$	5,897			$	8,087
Preferred stock dividends			930				930				2,792				2,792
Income attributable to common stock		$	2,906			$	1,932			$	3,105			$	5,295
Weighted average common shares:
Weighted average common shares — basic			11,197,681				11,128,802				11,187,298				11,117,060
Dilution effect of stock options/awards outstanding at the end of period			29,043				—				20,219				—
Weighted average common shares — diluted			11,226,724				11,128,802				11,207,517				11,117,060
Net income per common share:
Basic		$	0.26			$	0.17			$	0.28			$	0.48
Diluted		$	0.26			$	0.17			$	0.28			$	0.48

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 of common stock because the effect would have been anti-dilutive for the periods indicated:

		Three Months Ended September 30,								Nine Months Ended September 30,
		2011				2010				2011				2010
Anti-dilutive shares			57,425				76,873				83,864				79,897

3.

Derivative Instruments

Commodity Contracts

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 or trading 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, and 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 is not limited to, a letter of credit, security interest or a performance bond. As of September 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 as cash flow hedges and qualify for hedge accounting 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 September 30, 2011, the Company expected approximately $2,535 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 September 30, 2011:

		Contract Settlement Date
		2011				2012				2013
Natural Gas forward purchase contracts:
Volume (MMcf)			1,041				5,490				4,380

Interest Rate Swap

In July 2011, the Company entered into a $30 million fixed rate swap contract with a third party to manage the risk associated with the floating interest rate on its credit facility. The contract is effective through December 31, 2012. In accordance with its credit facility, the Company pays interest amounts based upon the Eurodollar LIBOR rate, plus 1%, and plus a spread ranging from 1.25% to 2.0% depending on its outstanding borrowings. Under the interest rate swap terms, the Company swapped its floating LIBOR interest rate for a fixed LIBOR rate of 0.578%. This contract was not designated as a fair value hedge and is recorded at fair value on the consolidated balance sheets and changes in fair value, both realized and unrealized, are recognized in interest expense, net on the consolidated statements of operations. On the statements of cash flows, the cash flows from the interest rate swap are classified as operating activities.

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

Derivatives designated as hedging
instruments under ASC 815		Balance Sheet Location		Fair Value
Assets
Commodity contracts		Assets from price risk management - current		$	2,535
Total				$	2,535

Derivatives not designated as
hedging instruments under ASC 815		Balance Sheet Location		Fair Value
Assets
Commodity contracts		Assets from price risk management - current		$	3,946
		Assets from price risk management - long term		$	2,142
Interest rate swap		Other current liabilities		$	67
Total				$	6,155

		The before-tax effect of derivative instruments in cash flow hedging relationships on the consolidated statements of operations for the three months and nine months ended September 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 Recognized in OCI 1 on Derivatives for the
		Three months ended September 30,								Nine months ended September 30,
		2011				2010				2011				2010
Commodity contracts		$	614			$	2,599			$	855			$	5,413

Location of Gain Reclassified		Amount of Gain Reclassified from AOCI into Income
from AOCI into Income		Three months ended September 30,								Nine months ended September 30,
(effective portion)		2011				2010				2011				2010
Oil and gas sales		$	2,322			$	—			$	6,915			$	—

		Three and nine months
		ended September 30,
		2011				2010
Location of Gain Recognized in Income (Ineffective) Portion and Amount Excluded from Effectiveness Testing			N/A				N/A

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, 2011 and 2010 was as follows:

		Amount of Gain (Loss) Recognized in Income on Derivatives for the
		Three Months Ended September								Nine Months Ended September
		2011				2010				2011				2010
Unrealized gain on commodity contracts 2		$	4,642			$	1,548			$	5,060			$	8,030
Realized gain on commondity contracts 2			161				1,715				672				3,158
Unrealized loss on interest rate swap 3			(67	)			—				(67	)			—
Realized loss on interest rate swap 3			(27	)			—				(27	)			—
Total activity for derivatives not designated as hedging instruments		$	4,709			$	3,263			$	5,638			$	11,188

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

4.

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 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 of the fair values as of September 30, 2011 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		$	—			$	8,623			$	—			$	8,623
Total assets at fair value		$	—			$	8,623			$	—			$	8,623
Liabilities
Derivative instruments -
Interest rate swap						$	67			$	—			$	67
Total liabilities at fair value		$	—			$	67			$	—			$	67

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, 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 September 30, 2011, the Company had various types of derivative instruments utilized by the Company, which included costless collars and swaps. The natural gas derivative markets and interest rate swap 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 Company uses the income valuation technique to determine the fair value of the liability at the point of inception by taking into account (1) the cost of abandoning oil and gas wells, which is based on the Company’s historical experience for similar work, or estimates from independent third parties; (2) the economic lives of its properties, which is based on estimates from reserve engineers; (3) the inflation rate; and (4) the credit adjusted risk-free rate, which takes into account the Company’s credit risk and the time value of money. Given the unobservable nature of these 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 September 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 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 has no past due receivables from any of its counterparties.

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.

5.

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 pre-tax 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 nine months ended September 30, 2011 and 2010. The Company wrote off $0 and $73 in the three and nine months ended September 30, 2011, respectively, and $0 and $80 in the three and nine months ended September 30, 2010, respectively, related to expired undeveloped leaseholds.

6.

Compensation Plans

The Company recognized stock-based compensation expense of $242 and $767 during the three and nine months ended September 30, 2011, respectively, as compared to $230 and $726 in the three and nine months ended September 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 September 30, 2011 and changes during the nine months ended September 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			(2,540	)		$	4.58
Cancelled/expired			(55,800	)		$	17.62
Outstanding at September 30, 2011			524,658			$	12.08				3.6			$	210
Exercisable at September 30, 2011			293,523			$	13.72				3.2			$	67

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 September 30, 2011 and changes during the nine months ended September 30, 2011 were as follows:

						Weighted-
						Average
						Grant Date
		Shares				Fair Value
Stock Awards:
Outstanding at January 1, 2011			83,304			$	8.40
Granted			525,195			$	6.46
Vested			(44,738	)		$	5.30
Forfeited/returned			—			$	—
Nonvested at September 30, 2011			563,761			$	6.84

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 September 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 September 30, 2011.

Long Term Incentive Plan

On September 30, 2011, the Company adopted a Long-Term Incentive Plan (“LTIP”), which operates under the Company’s 2010 Stock Incentive Plan. Under the LTIP, the executive officers of the Company may earn up to an aggregate of 486,657 shares of common stock of the Company. The executive officers may earn one-third of the shares by continued employment with the Company through December 31, 2013. The remaining two-thirds may be earned through increases in the Company’s implied net asset value, as defined. If the Company ultimately achieves the service requirements and performance objectives determined by the LTIP, the associated total share-based compensation expense is expected to be approximately $3.1 million, based on the grant date fair value.. The Company did not recognize any expense related to the LTIP during the three and nine months ended September 30, 2011.

7.

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 September 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.

8.

Credit Facility

At September 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 September 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.

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. 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 locked in the Eurodollar LIBOR portion of the interest calculation at approximately 0.578% for this tranche of its outstanding debt, which based on the Company’s current level of outstanding debt, translates to a an interest rate on this tranche of approximately 3.08%. The contract is effective July 6, 2011 through December 31, 2012.

The average interest rate on the facility at September 30, 2011 was 3.18%. For the three months ended September 30, 2011 and 2010, the Company incurred interest expense related to the credit facility of $260 and $405, respectively, and $818 and $1,118 for the nine months ended September 30, 2011 and 2010, respectively. The Company capitalized interest costs of $29 and $37 for the three months ended September 30, 2011 and 2010, respectively, and $93 and $124 for the nine months ended September 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 September 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.

Subsequent to September 30, 2011, the Company amended its existing credit facility to increase the revolving line of credit to $150 million ($60 million borrowing base) and extended the maturity date of the facility from January 31, 2013 to October 24, 2016. The amendment also lowered the interest rate margin for the level of funds borrowed to between 0.75% and 1.75%.

9.

Preferred Stock and Stockholder’s Equity

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 change of control 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.
		ATM Offering

In August 2011, the Company entered into an at market issuance sales agreement (“ATM”), which allows the Company to offer and sell shares of its common stock from time to time at an aggregate offering price of up to $20 million. The Company’s sales agent may make sales of the Company’s common stock in privately negotiated transactions or in any method permitted by law deemed to be an ATM offering as defined in Rule 415 promulgated under the Securities Act of 1933, as amended, at negotiated prices, at prices prevailing at the time of sale or at prices related to such prevailing market prices, including sales made directly on the NASDAQ Global Select Market or sales made through a market maker other than on an exchange. The Company’s sales agent will make all sales using commercially reasonable efforts consistent with its normal sales and trading practices. The Company has no obligation to sell any shares in the ATM offering and may terminate the ATM offering at any time. No shares were sold in the third quarter of 2011.

10.

Comprehensive Income (Loss)

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

		For the Three Months Ended September 30,								For the Nine Months Ended September 30,
		2011				2010				2011				2010
Net income attributable to common stock		$	2,906			$	1,932			$	3,105			$	5,295
Change in derivative instrument fair value, net of tax expense1			1,280				1,675				2,954				3,438
Reclassification to earnings			(2,322	)			—				(6,915	)			—
Comprehensive income (loss)		$	1,864			$	3,607			$	(856	)		$	8,733

The components of accumulated other comprehensive income were as follows:

		September 30,				December 31,
		2011				2010
Net change in derivative instrument fair value, net of tax expense of $927 and $3,027		$	1,608			$	5,568
Total accumulated other comprehensive income, net		$	1,608			$	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 September 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 matter 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 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 and filed its appellate brief and appendix with the Second Circuit Court of Appeals on August 11, 2011. The Company filed its brief on October 13, 2011 supporting the District Court’s March 31, 2011 opinion and judgment dismissing the case.

13.

Subsequent Events

On October 24, 2011, the Company amended its credit facility to increase the revolving line of credit to $150 million ($60 million borrowing base) and extended the maturity date of the facility to October 24, 2016. The amendment also lowered the interest rate margin for the level of funds borrowed to between 0.75% and 1.75%. The Company paid approximately $260 in one-time financing fees related to amending this facility.

The Company has noted no additional events, other than noted above, that require recognition or disclosure at September 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 Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934, as amended, and 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 our Annual Report on Form 10-K for the year ended December 31, 2010 and in this Quarterly Report on Form 10-Q for the quarter ended September 30, 2011.

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, may change as more wells and acreage are added to the PA.

OVERVIEW OF FINANCIAL CONDITION AND LIQUIDITY

Liquidity and Capital Resources

In the third quarter of 2011, we entered into an at market issuance sales agreement (“ATM”), which allows us to offer and sell shares of our common stock from time to time, up to an aggregate offering price of up to $20 million. As of September 30, 2011, we had not sold any shares in the ATM offering. On October 24, 2011, we amended and extended our credit facility, which increased the value of the facility to $150 million ($60 million borrowing base) through October 24, 2016. We currently believe that the amounts available under our credit facility, 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). We believe the addition of the ATM will give us added flexibility to meet future liquidity needs and pursue new strategic acquisitions and ventures as they arise. 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. 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 registered offerings of equity, debt or other securities. We are conducting the ATM offering under the shelf registration statement. We also 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 as of September 30, 2011 and December 31, 2010 is presented in the following table:

		September 30,				December 31,
		2011				2010
Financial Position Summary
Cash and cash equivalents		$	5,952			$	2,605
Working capital		$	10,437			$	7,477
Balance outstanding on credit facility		$	32,000			$	32,000
Stockholders’ equity and preferred stock		$	90,573			$	90,677
Ratios
Debt to total capital ratio			26.1	%			26.1	%
Total debt to equity ratio			60.8	%			60.7	%

Our working capital increased to $10,437, primarily due to the positive cash flow effect of our hedging program, which resulted in us having more cash on hand at September 30, 2011 as compared to the prior year-end. Additionally, we experienced a decrease in our accounts payable and accrued liabilities balances from our December 31, 2010 balance 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. This was offset somewhat by an increase in accounts payable and accrued liabilities related to our 2011 drilling program and decrease in our current assets from price risk management as a result of the settlement of derivative contracts in the first nine months of 2011.

Cash flow activities

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

		Nine Months Ended September 30,
		2011				2010
Cash provided by (used in):
Operating Activities		$	18,782			$	21,251
Investing Activities			(12,218	)			(20,063	)
Financing Activities			(3,217	)			(3,187	)
Net change in cash		$	3,347			$	(1,999	)

Net cash provided by operating activities decreased 12% to $18,782 for the nine months ended September 30, 2011 as compared to $21,251 for the nine months ended September 30, 2010. The primary sources of cash during the nine months ended September 30, 2011 were $5,897 of net income, which was net of non-cash charges of $14,444 related to depreciation, depletion, and amortization expenses (“DD&A”) and accretion expense, and non-cash share-based compensation expense of $767. In addition, in the nine months ended September 30, 2011, we had an increase of $3,459 in the provision for deferred income taxes. These increases were partially offset by the non-cash gain on derivative contracts of $4,993. Net income during the nine months ended September 30, 2011 included $7,587 of income from cash settlements on our derivative instruments. The majority of the settlement revenue was generated by our $7.07 CIG fixed price swap for 8,000 Mcf per day. We entered into this hedge in 2008, when the outlook for natural gas prices was significantly higher than it is today. While we do have 15,000 Mcf per day hedged in 2012, the prices we have secured are approximately $2 lower per Mcf. The difference in price will result in lower realized cash flow. Cash flow from operations in the 2010 period included cash proceeds of $4,061 that we received from many of the defendants in a lawsuit brought by us through which we sought to recover either monetary damages or our respective share of natural gas produced by our interest in the Madden Deep Unit.

Net cash used in investing activities decreased 39% to $12,218 for the nine months ended September 30, 2011 as compared to 20,063 for the nine months ended September 30, 2012. Our capital expenditures in the first nine months of 2011 primarily related to non-operated drilling in the Pinedale Anticline, and also include some expenditures related to our 2011 drilling program at the Catalina Unit, which includes 13 production wells and two injection wells. Twelve of the 13 production wells are exploratory wells located outside the current PA, where we hold 100% of the leases on the acreage and therefore we will bear 100% of the cost of these wells. Our drilling program began in July 2011 and will continue through year-end. We expect to begin realizing production from these wells during the fourth quarter of 2011 or the first quarter of 2012. In the third quarter of 2011, we sold our interest in our Nevada properties for cash proceeds of $371. We had impaired these properties in 2008, as we had no plans to develop the leases and there had been no oil and gas findings in the area. We retained a small overriding royalty interest in these Nevada properties. In 2010, we purchased working interest in the Atlantic Rim for total cost of approximately $7,761.

Our net cash used in financing activities remained consistent in the 2011 and 2010 periods, totaling $3,217 for the nine months ended September 30, 2011, which was primarily comprised of the first, second and third quarter dividend payments to our preferred shareholders totaling $2,792. We expect to continue to pay dividends on a quarterly basis on the Series A Preferred Stock at a rate of $931 per quarter. We were able to maintain our credit facility balance during the period despite commencing our drilling program, primarily due to the timing of non-operator drilling and from the benefit from our derivative instruments referenced above.

Credit Facility

At September 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 September 30, 2011, the outstanding balance on our credit facility was $32,000. 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 in July 2011. Based upon our current level of outstanding debt, this fixes the interest rate for this tranche at approximately 3.08%. The average interest rate on the facility as of September 30, 2011, calculated in accordance with the agreement, was 3.18%, compared to an interest rate of 4.5% at September 30, 2010. For the three months ended September 30, 2011 and 2010, we incurred interest expense of $260 and $405, respectively, related to the credit facility and $818 and $1,118 for the nine months ended September 30, 2011 and 2010, respectively. We capitalized interest costs of $29 and $37 for the three months ended September 30, 2011 and 2010, respectively, and $93 and $124 for the nine months ended September 30, 2011 and 2010, respectively.

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 September 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. Our borrowing base was reaffirmed as of October 1, 2011 at the existing $60 million.

On October 24, 2011, we amended our credit facility to increase the revolving line of credit to $150 million and extend the maturity date of the facility to October 24, 2016. The amendment also lowered the interest rate margin for the level of funds borrowed to between 0.75% and 1.75%. We paid approximately $260 in one-time financing fees related to amending this facility.

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 are in process of drilling 13 coal bed methane (“CBM”) production wells within the Catalina Unit. We are also participating in approximately 16 new wells at the Mesa Units. Lastly, in October 2011, we began drilling one exploratory well located in the Atlantic Rim into the Niobrara formation. Our 2011 capital budget does not include the impact of potential future exploration projects or possible acquisitions, which we continually evaluate.

Contractual Obligations

Our contractual obligations as of September 30, 2011 are:

						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)			1,380				1,032				348				—				—
Capital leases			188				188				—				—				—
Operating leases			4,981				2,599				2,257				125				—
Total contractual cash commitments		$	38,549			$	3,819			$	34,605			$	125			$	—

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 had no interest in any unconsolidated SPEs or VIEs at any time during any of the periods presented.

RESULTS OF OPERATIONS

Three Months Ended September 30, 2011 Compared to the Three Months Ended September 30, 2010

The following analysis provides comparison of the three months ended September 30, 2011 and the three months ended September 30, 2010.

Oil and gas sales

Oil and gas sales increased 52% to $11,540, which was largely attributed to cash we received upon settlement of our cash flow hedge, totaling $2,322. In addition, the average CIG market price, which is the index on which most of our gas volumes are sold, rose 10% and production volumes increased 4%, resulting in higher oil and gas sales.

As shown in the following table, our average realized natural gas price increased 20% to $4.64 due to both the increase in the CIG market price and the derivative instruments in place during the quarter. 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; (2) settlement of our cash flow hedges included within oil and gas sales on the consolidated statements 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 $161 and $1,715, for the three months ended September 30, 2011 and 2010, respectively.

		Three Months Ended September 30,																Percent				Percent
		2011								2010								Volume				Price
		Volume				Average Price				Volume				Average Price				Change				Change
Product:
Gas (Mcf)			2,381,239			$	4.64				2,300,050			$	3.86				4	%			20	%
Oil (Bbls)			7,278			$	91.15				6,751			$	63.31				8	%			44	%
Mcfe			2,424,907			$	4.83				2,340,556			$	3.98				4	%			21	%

Our total net production increased 4% to 2.4 Bcfe, primarily due to 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.

Our total average daily net production at the Atlantic Rim increased 1% to 19,002 Mcfe. Our Atlantic Rim production comes from three operating units, the Catalina Unit, the Sun Dog Unit and the Doty Mountain Unit. We operate the Catalina Unit.

•

Average daily net production at our Catalina Unit decreased 5% to 13,332 Mcfe, largely due to what management believes to be the normal production decline for wells within the field. We are currently in the process of drilling 13 new production wells in the Catalina Unit,. Twelve of the 13 new wells are located outside the current PA, and our working interest in these wells will be 100% (as compared to 72.35% for wells in the current PA). We expect to begin realizing production from the development and exploratory wells in the fourth quarter of 2011 or the first quarter of 2012.

•

Average daily production, net to our interest, at the Sun Dog and Doty Mountain units increased 18% to 5,670 Mcfe, which was primarily attributed to better production from certain Sun Dog wells due to additional water injection capacity added in the first quarter of 2011 and a small increase in certain Doty Mountain wells due to fracture stimulation. We also benefited from higher working interest in both units for part of the period as compared to the prior year, as we completed our purchase of additional working interests in the Sun Dog and Doty Mountain Units in late July 2010. Our working interest increased in the Sun Dog Unit to 20.46% from 8.89%, and the Doty Mountain Unit to 18.00% from 16.5%.

Average daily net production in the Pinedale Anticline increased 3% to 5,498 Mcfe, as the operator brought 11 new wells on-line for production during the second and third quarter of 2011. The operator of the Mesa Units has informed us that it expects to complete six additional wells in the fourth quarter of 2011.

Transportation 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 10% to $1,221 due to the decrease in production volumes at the Catalina Unit discussed above.

Price risk management activities

We recorded a net gain on our derivative contracts not designated as cash flow hedges of $4,803. This consisted of an unrealized non-cash gain of $4,642, which represents the change in the fair value on our economic hedges at September 30, 2011 based on the expected future prices of the related commodities, and a net realized gain of $161 related to the cash settlement of some of our economic hedges.

Proceeds from Madden Deep settlement

During the third quarter of 2010, we recorded revenue of $3,841 as a settlement we received from many of the defendants in a lawsuit we sought to recover either monetary damages or our respective share of natural gas produced by our interest in the Madden Deep Unit during the period February 1, 2002 through June 30, 2007. As part of the settlement, we received cash proceeds of $4,061. Prior to the litigation settlement, we had not recognized any amount of sales proceeds related to natural gas from the Madden Deep Unit for the period February 1, 2002 through October 30, 2006. For the period from November 1, 2006 through June 30, 2007, we had recognized the sales and had recorded a related account receivable of $292, net of allowance for uncollectible amounts.

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

		Three Months Ended September 30,
		2011				2010
		(in dollars per Mcfe)
Average price		$	4.83			$	3.98
Production costs			1.24				1.21
Production taxes			0.45				0.50
Depletion and amortization			1.99				1.96
Total operating costs			3.68				3.67
Gross margin		$	1.15			$	0.31
Gross margin percentage			24	%			8	%

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 our subsidiary, Eastern Washakie Midstream LLC, which are eliminated in consolidation. Well production costs increased 7% to $3,018 and production costs in dollars per Mcfe increased 2%, or $0.03 to $1.24, driven by additional production costs from the Sun Dog Unit. This increase was partially offset by lower repair and maintenance costs at the Catalina Unit.

Production taxes decreased 8% to $1,084 and production taxes, on a dollars per Mcfe basis, decreased 10%, or $0.05 to $0.45. We are required to pay taxes on the proceeds received upon the sale of our gas to counterparties. Although we had higher physical oil and gas sales in 2011 as compared to the prior year, in 2010 we also paid production taxes on the revenue from one of our derivative instruments due to the contractual terms of that agreement.

DD&A increased 5% to $4,926 and depletion and amortization related to producing assets also increased 5% to $4,827. Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased 2%, or $0.03, to $1.99, as compared to the same prior-year period.

General and administrative expenses

General and administrative expenses decreased 2% to $1,513, as we experienced a $77 decrease in legal fees, primarily driven by less activity related to the litigation that resulted from the 2009 Petrosearch acquisition, and a $61 decrease in consulting fees. These decreases were offset by a $114 increase in salary and salary-related expenses due primarily to a salary increase in the first quarter of 2011 and the accrual for bonuses earned in 2011 to date under the Company’s annual bonus program.

Income taxes

We recorded an income tax expense of $2,221. Our effective tax rate for the third quarter of 2011 was 36.6%, which was slightly 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 35.3%.

Nine Months Ended September 30, 2011 Compared to the Nine Months Ended September 30, 2010

The following analysis provides comparison of the nine months ended September 30, 2011 and the nine months ended September 30, 2010.

Oil and gas sales

Oil and gas sales increased 29% to $33,843, due primarily to our hedging program, which provided cash of $6,915 from the settlement of our cash flow hedges during the first nine months of 2011. In addition, we experienced a 2% increase in production volumes in the first nine months of 2011 as compared to the same prior-year period. These increases were offset by a 1% decrease in the average CIG market price, which is the index on which most of our gas volumes are sold.

As shown in the following table, our average realized gas price increased 14% to $4.75. 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 $6,915 of cash flow hedge settlements included in oil and gas sales noted above, we also realized settlements on our economic hedges totaling $672 during the 2011 period. For the nine months ended September 30, 2010, our hedges accounted for a total of $3,158.

		Nine Months Ended September 30,																Percent				Percent
		2011								2010								Volume				Price
		Volume				Average Price				Volume				Average Price				Change				Change
Product:
Gas (Mcf)			6,872,931			$	4.75				6,712,176			$	4.18				2	%			14	%
Oil (Bbls)			20,668			$	89.14				19,579			$	69.71				6	%			28	%
Mcfe			6,996,939			$	4.93				6,829,650			$	4.31				2	%			14	%

Total net production increased 2% to 7.0 Bcfe, as 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.

Average daily net production at the Atlantic Rim increased 4% to 18,888 Mcfe, which is further broken out below:

•

Average daily net production at our Catalina Unit decreased 8% to 13,494 Mcfe per day, largely due to 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 54% to 5,394 Mcfe per day, 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. This increase also is attributed to better production from certain Sun Dog wells due to additional water injection capacity added in the first quarter of 2011 and a small increase in certain Doty Mountain wells due to fracture stimulation.

Average daily net production in the Pinedale Anticline remained consistent during the 2011 and 2010 periods, totaling 5,175 Mcfe per day in the nine months ended September 30, 2011. The operator of the Mesa Units brought an additional 11 wells on-line during the second and third quarters of 2011, although this did not result in an overall increase in production. Management believes that the operator is continuing to manage the production flow from the field due to the low gas prices in the Rocky Mountain region.

The average daily net production at the Madden Unit decreased 31% to 492 Mcfe, primarily because the 2010 production results reflect a one-time gas balancing adjustment from the operator recorded in the second quarter of 2010.

Transportation 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 revenue decreased 13% to $3,674, which was driven by lower pipeline throughput from the Catalina Unit.

Price risk management activities

We recorded a net gain on our derivative contracts not designated as cash flow hedges of $5,732, which consisted of an unrealized non-cash gain of $5,060, which represents the change in the fair value on our economic hedges at September 30, 2011, based on the future expected prices of the related commodities, and a net realized gain of $672 related to the cash settlement of some of our economic hedges.

Proceeds from Madden Deep settlement

During the third quarter of 2010, we reached a settlement with many of the defendants in the lawsuit brought by the Company through which we sought to recover payment for natural gas produced by our interest in the Madden Deep Unit during the period February 1, 2002 through June 30, 2007. As part of the settlement, we received cash proceeds of $4,061. Prior to the litigation settlement, we had not recognized any amount of sales proceeds related to natural gas from the Madden Deep Unit for the period February 1, 2002 through October 30, 2006. For the period from November 1, 2006 through June 30, 2007, we had recognized the sales and had recorded a related account receivable of $292, net of allowance for uncollectible amounts.

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

		Nine Months Ended September 30,
		2011				2010
		(in dollars per Mcfe)
Average price		$	4.93			$	4.31
Production costs			1.19				1.05
Production taxes			0.46				0.51
Depletion and amortization			2.00				1.97
Total operating costs			3.65				3.53
Gross margin		$	1.28			$	0.78
Gross margin percentage			26	%			18	%

Well production costs increased 17% to $8,361, and production costs in dollars per Mcfe increased 13%, or $0.14 to $1.19. 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. In addition, because production from the Sun Dog and Doty Mountain units, which have historically yielded lower margins than many of our other 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. This increase was partially offset by lower repair and maintenance costs at the Catalina Unit.

During the nine months ended September 30, 2011, production taxes decreased 7% to $3,230, and production taxes, on a dollars per Mcfe basis, decreased 10%, or $0.05 to $0.46. We are required to pay taxes on the proceeds received upon the sale of our gas to counterparties. Although we had higher physical oil and gas sales in 2011 as compared to the prior year, in 2010 we also paid production taxes on the revenue from one of our derivative instruments due to the contractual terms of that agreement.

DD&A increased 4% to $14,317 and depletion and amortization related to producing assets also increased 4% to $14,008. Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased 2%, or $0.03, to $2.00, as compared to the same prior-year period.

General and administrative expenses

General and administrative expenses remained consistent, totaling $4,433. During the period, 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 $75 decrease in audit and tax fees, a $155 decrease in legal fees and a $71 decrease in rental expense in Texas due to expiration of office leases assumed in the Petrosearch acquisition. These decreases were offset by a $89 increase expense related to our Board of Directors due to the expansion of our Board and Board training expenses, an increase in bank fees of $78 due to an increase in the unused portion of our credit facility, and a $65 increase in salary and salary-related expenses due primarily to an accrual for bonuses earned in 2011 to date under the Company’s annual bonus program. In 2010 we had recovered an outstanding receivable that had previously been written off totaling $155.

Income taxes

We recorded income tax expense of $3,459. Our effective tax rate for the period was 36.6%, which was slightly 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 35.3%.

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. 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 September 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			736,000				8,000				01/11-12/11			$	7.07			CIG
Costless Collar			305,000				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			10,911,000

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

Interest rate swap

We have 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 September 30, 2011, our income before income taxes would have increased by $605 for each $0.50 increase per Mcf in natural gas prices and decreased by $290 for each $0.50 decrease per Mcf in natural gas prices due to the contracted volumes discussed above. Our net income before income taxes would have increased $6 for each $1.00 change per Bbl in crude oil prices for the three months ended September 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 Gas Volumes”.

Interest Rate Risks

At September 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. 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 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 September 30, 2011, this resulted in a fixed interest rate of 3.08% for the $30 million tranche of our outstanding debt. The contract is effective July 6, 2011 through December 31, 2012.

The average interest rate for the three months ended September 30, 2011, calculated in accordance with the agreement, was 3.18%. Assuming no change in the amount outstanding at September 30, 2011, the annual impact on interest expense for every 1.0% change in the average interest rate would be approximately $20 before taxes.

On October 24, 2011, we amended our existing facility to increase the revolving line of credit to $150 million ($60 million borrowing base) and extend the maturity date of the facility to October 24, 2016. The amendment also lowered the interest rate margin for the level of funds borrowed.

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 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 SEC rules and forms.

There has been no change in our internal control over financial reporting that occurred during the quarter ended September 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

From time to time, we are involved in various legal proceedings, including, but not limited to, the matters discussed below. 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.

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 and filed its appellate brief and appendix with the Second Circuit Court of Appeals on August 11, 2011. We filed a brief on October 13, 2011 supporting the District Court’s March 31, 2011 opinion and judgment dismissing Tiberius’s case.

ITEM 1A.		RISK FACTORS

The following risk factors should be considered in addition to our Risk Factors reported in Item 1A of Part I of our 2010 Annual Report on Form 10-K for the year ended December 31, 2010.

Management will have broad discretion as to the use of the proceeds from any shares offered as part of the ATM offering, and we may not use the proceeds effectively.

Our management will have broad discretion as to the application of the net proceeds from the ATM offering and could use them for purposes other than those contemplated at the time of the offering. Our stockholders may not agree with the manner in which our management chooses to allocate and spend the net proceeds. Moreover, our management may use the net proceeds for corporate purposes that may not increase our profitability or market value.

Substantial future sales of our securities in the public market may depress our stock price and make it difficult for investors to recover the full value of these investment in our shares.

As of October 31, 2011, we had 11,204,020 shares of common stock outstanding. Additionally, if all options outstanding as of such date which are not antidilutive are exercised prior to their expiration, 20,219 additional shares of common stock could become freely tradable. Sales of substantial amounts of our securities in the public market could adversely affect the prevailing market price of our common stock and also could make it more difficult for us to raise funds through the sale of additional securities.

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 2011:

										Total Number of Shares				Maximum Number of
										Purchased as Part of				Shares that May Yet Be
		Total Number of Shares				Average Price Paid per				Publically Announced				Purchased Under the
Period		Purchased				Share				Plans or Programs				Plans or Programs
July 2011			—				—				—				—
August 2011			—				—				—				—
September 2011			727	(1)		$	8.57				—				—

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).

Exhibit				Description:
	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 Exhibit 4.1 of 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).
	10.1	(b)		At Market Issuance Sales Agreement, dated August 23, 2011, by and between Double Eagle Petroleum Co. and McNicoll, Lewis & Vlak LLC. (incorporated by reference from Exhibit 10.1, of the Company’s Current report of Form 8-K dated August 24, 2011).
	10.1	(c)		Third Amendment to Amended and Restated Credit Agreement, dated October 24, 2011 (incorporated by reference from Exhibit 10.1, of the Company’s Current report of Form 8-K dated October 24, 2011).
	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.