Escalera Resources (ESCR) 10-Q 2011 Q1 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2011

or

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

For the transition period from                    to                    

Commission File Number 1-33571

DOUBLE EAGLE PETROLEUM CO.

(Exact name of registrant as specified in its charter)

MARYLAND	83-0214692
(State or other jurisdiction of	(I.R.S. employer
incorporation or organization)	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.

Yesþ Noo

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).

Yeso Noo

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 filero	Accelerated filero	Non-accelerated filero	Small reporting Companyþ
		Do not check if a small reporting company)

Indicate by checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yeso Noþ

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

Class	Outstanding as of April 30, 2011
Common stock, $.10 par value	11,188,989

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

	Page #
PART I. Financial Information:
Item 1. Financial Statements
Consolidated Balance Sheets as of March 31, 2011 and December 31, 2010 (Unaudited)		3
Consolidated Statements of Operations for the Quarter Ended March 31, 2011 and 2010 (Unaudited)		4
Consolidated Statements of Cash Flows for the Quarter Ended March 31, 2011 and 2010 (Unaudited)		5
Notes to Consolidated Financial Statements (Unaudited)		6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		14
Item 3. Quantitative and Qualitative Disclosures About Market Risk		21
Item 4. Controls and Procedures		21
PART II. Other Information:
Item 1. Legal Proceedings		21
Item 1A. Risk Factors		22
Item 6. Exhibits		22
Signatures		24
Exhibit 31.1
Exhibit 31.2
Exhibit 32

2

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

DOUBLE EAGLE PETROLEUM CO.

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

(Unaudited)

	March 31,			December 31,
	2011			2010
ASSETS
Current assets:
Cash and cash equivalents	$	3,345		$	2,605
Cash held in escrow		605			615
Accounts receivable		4,819			5,396
Assets from price risk management		6,913			9,622
Other current assets		3,594			3,653
Total current assets		19,276			21,891
Oil and gas properties and equipment, successful efforts method:
Developed properties		189,376			188,143
Wells in progress		4,530			4,039
Gas transportation pipeline		5,465			5,465
Undeveloped properties		3,011			3,062
Corporate and other assets		1,997			1,982
		204,379			202,691
Less accumulated depreciation, depletion and amortization		(76,899	)		(72,226	)
Net properties and equipment		127,480			130,465
Other assets		155			161
TOTAL ASSETS	$	146,911		$	152,517
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	5,481		$	7,295
Accrued expenses		1,614			3,535
Liabilities from price risk management		36			—
Accrued production taxes		3,218			2,757
Capital lease obligations, current portion		410			545
Other current liabilities		205			282
Total current liabilities		10,964			14,414
Credit facility		32,000			32,000
Asset retirement obligation		5,875			5,848
Liabilities from price risk management		964			—
Deferred tax liability		9,023			9,578
Total liabilities		58,826			61,840
Preferred stock, $0.10 par value; 10,000,000 shares authorized; 1,610,000 shares issued and outstanding as of March 31, 2010 and December 31, 2009		37,972			37,972
Stockholders’ equity:
Common stock, $0.10 par value; 50,000,000 shares authorized; 11,185,757 and 11,175,532 shares issued and outstanding at March 31, 2011 and 11,165,305 shares issued and 11,155,080 outstanding at December 31, 2010, respectively		1,118			1,116
Additional paid-in capital		44,848			44,583
Retained earnings		355			1,438
Accumulated other comprehensive income		3,792			5,568
Total stockholders’ equity		50,113			52,705
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	146,911		$	152,517

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

3

DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in thousands of dollars except share and per share data)

(Unaudited)

	Three months ended
	March 31,
	2011			2010
Revenues
Oil and gas sales	$	10,910		$	11,049
Transportation revenue		1,232			1,487
Price risk management activities		(1,139	)		7,822
Other income, net		95			77
Total revenues		11,098			20,435
Costs and expenses
Production costs		2,574			1,943
Production taxes		1,056			1,300
Exploration expenses including dry hole costs		52			38
Impairment and abandonment of equipment and properties		73			—
Pipeline operating costs		981			1,149
General and administrative		1,558			1,534
Depreciation, depletion and amortization		4,673			4,540
Total costs and expenses		10,967			10,504
Income (loss) from operations		131			9,931
Interest expense, net		(387	)		(365	)
Income (loss) before income taxes		(256	)		9,566
Benefit (provision) for deferred income taxes		104			(3,457	)
NET INCOME (LOSS)	$	(152	)	$	6,109
Preferred stock dividends		931			931
Net income (loss) attributable to common stock	$	(1,083	)	$	5,178
Net income (loss) per common share:
Basic	$	(0.10	)	$	0.47
Diluted	$	(0.10	)	$	0.47
Weighted average shares outstanding:
Basic		11,174,487			11,105,646
Diluted		11,174,487			11,105,646

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

4

DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands of dollars)

(Unaudited)

	Three months ended March 31,
	2011			2010
Cash flows from operating activities:
Net income (loss)	$	(152	)	$	6,109
Adjustments to reconcile net income (loss) to net cash from operating activities:
Depreciation, depletion, amortization and accretion of asset retirement obligation		4,713			4,560
Abandonment of non-producing properties		73			—
Provision for deferred taxes		(104	)		3,457
Employee stock option expense		220			227
Directors fees paid in stock		55			49
Change in fair value of derivative contracts		1,482			(8,045	)
Revenue from carried interest		(422	)		(716	)
Gain on sale of producing property		(71	)		(72	)
Changes in current assets and liabilities:
Decrease (Increase) in deposit held in escrow		10			(1	)
Decrease in accounts receivable		577			236
Decrease (Increase) in other current assets		68			(424	)
Increase (Decrease) in accounts payable		(1,186	)		1,661
Increase in accrued expenses		70			1,948
Increase in accrued production taxes		461			703
NET CASH PROVIDED BY OPERATING ACTIVITIES		5,794			9,692
Cash flows from investing activities:
Additions of producing properties and equipment, net		(3,943	)		(5,737	)
Additions of corporate and non-producing properties		(37	)		(116	)
NET CASH USED IN INVESTING ACTIVITIES		(3,980	)		(5,853	)
Cash flows from financing activities:
Principal payments on capital lease obligations		(135	)		(143	)
Issuance of stock under Company stock plans		—			5
Tax withholdings related to net share settlement of restricted stock awards		(8	)		(3	)
Dividends on preferred stock		(931	)		(931	)
Net repayments on credit facility		—			(3,000	)
NET CASH USED IN FINANCING ACTIVITIES		(1,074	)		(4,072	)
Change in cash and cash equivalents		740			(233	)
Cash and cash equivalents at beginning of period		2,605			5,682
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	3,345		$	5,449
Supplemental disclosure of cash and non-cash transactions:
Cash paid for interest	$	394		$	448
Interest capitalized	$	35		$	50
Additions to developed properties included in current liabilities	$	2,488		$	3,092
Share-based compensation expense	$	275		$	276
`

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

5

DOUBLE EAGLE PETROLEUM CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Amounts in thousands of dollars except share and per share data)
(Unaudited)

1. Summary of Significant Accounting Policies

Basis of presentation

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

Certain amounts in the 2010 consolidated financial statements have been reclassified to conform to the 2011 consolidated financial statement presentation. Such reclassifications had no effect on net income.

The accounting policies followed by the Company are set forth in Note 1 to the Company’s consolidated financial statements in the Annual Report on Form 10-K for the year ended December 31, 2010, and are supplemented throughout the notes to this Quarterly Report on Form 10-Q.

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

Principles of consolidation

The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, Petrosearch Energy Corporation (“Petrosearch”) and Eastern Washakie Midstream LLC (“EWM”) (collectively, the “Company”). In August 2009, the Company acquired Petrosearch, which has operations in Texas and Oklahoma. In 2006, the Company sold transportation assets located in the Catalina Unit, at cost, to EWM in exchange for an intercompany note receivable bearing interest of 5% per annum, maturing on January 31, 2028. The note and related interest are fully eliminated in consolidation. In addition, the Company has an agreement with EWM under which the Company pays a fee to EWM to gather and compress gas produced at the Catalina Unit. The Company’s fee related to gas gathering is also eliminated in consolidation.

2. Earnings per share

Basic earnings per share of common stock (“EPS”) is calculated by dividing net income (loss) attributable to common stock by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share incorporates the treasury stock method, and is calculated by dividing net income (loss) attributable to common stock by the weighted average number of shares of common stock and potential common stock equivalents outstanding during the period, if dilutive. Potential common stock equivalents include incremental shares of common stock issuable upon the exercise of stock options and employee stock awards. Income attributable to common stock is calculated as net income less dividends paid on the Series A Preferred Stock. The Company declared and paid cash dividends of $931 ($.5781 per share) for each of the quarters ended March 31, 2011 and 2010.

6

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

	For the Quarter Ended March 31,
	2011			2010
Net income (loss)	$	(152	)	$	6,109
Preferred stock dividends		931			931
Net income (loss) attributable to common stock	$	(1,083	)	$	5,178
Weighted average shares:
Weighted average shares — basic		11,174,487			11,105,646
Dilution effect of stock options outstanding at the end of period		—			—
Weighted average shares — diluted		11,174,487			11,105,646
Net income (loss) per common share:
Basic	$	(0.10	)	$	0.47
Diluted	$	(0.10	)	$	0.47

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

	For the Quarter Ended March 31,
	2011		2010
Anti-dilutive shares		68,250		81,116

3. Derivative Instruments

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

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

The Company recognizes its derivative instruments as either assets or liabilities at fair value on its consolidated balance sheets, and accounts for the derivative instruments as either cash flow hedges or mark to market derivative instruments. On the statements of cash flows, the cash flows from these instruments are classified as operating activities.

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

As with most derivative instruments, the Company’s derivative contracts contain provisions which may allow for another party to require security from the counterparty to ensure performance under the contract. The security may be in the form of, but not limited to, a letter of credit, security interest or a performance bond. As of March 31, 2011, no party to any of the Company’s derivative contracts has required any form of security guarantee.

7

Cash flow hedges

Derivative instruments that are designated and qualify as cash flow hedges are recorded at fair value on the consolidated balance sheets, and the effective portion of the change in fair value is reported as a component of accumulated other comprehensive income (“AOCI”) and is subsequently reclassified into oil and gas sales on the consolidated statements of operations as the contracts settle. As of March 31, 2011 the Company expected approximately $6,367 of unrealized gains before taxes included in its 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 the price risk management activities line 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 in the price risk management activities line on the consolidated statement of operations.

The Company had the following commodity volumes under derivative contracts as of March 31, 2011:

	Contract Settlement Date
Natural Gas forward purchase contracts:	2011		2012		2013
Volume (MMcf)		4,030		3,660		4,380

In April 2011, the Company entered into an additional derivative contract. Refer to Note 14 for additional detail regarding this contract.

The table below contains a summary of all the Company’s derivative positions reported on the consolidated balance sheet as of March 31, 2011, presented gross of any master netting arrangements:

Derivatives designated as hedging
instruments under ASC 815	Balance Sheet Location	Fair Value
Assets
Commodity derivatives	Assets from price risk management — current	$	6,367
Total		$	6,367

Derivatives not designated as
hedging instruments under ASC 815	Balance Sheet Location	Fair Value
Assets
Commodity derivatives	Assets from price risk management — current	$	546
Liabilities
Commodity derivatives	Liabilities from price risk management — current	$	(36	)
	Liabilities from price risk management — long term		(964	)
Total		$	(454	)

8

The before-tax effect of derivative instruments in cash flow hedging relationships on the consolidated statements of income for the three months ended March 31, 2011 and 2010, related to the Company’s commodity derivatives was as follows:

Derivatives Designated as Cash Flow Hedging Instruments under ASC 815

	Amount of Gain (Loss) Recognized
	in OCI1 on Derivatives for the
	Three Months Ended March 31,
	2011		2010
Commodity contracts	$	114	$	2,023

¹ Other comprehensive income (“OCI”).

	Amount of Gain Reclassified from
Location of Gain Reclassified	AOCI into Income for the
from AOCI into Income	Three Months Ended March 31,
(effective portion)	2011		2010
Oil and gas sales	$	2,342	$	—

	Three Months Ended March 31,
	2011		2010
Location of Gain/Loss 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 months ended March 31, 2011 and 2010 was as follows:

	Amount of Loss Recognized in Income
	on Derivatives for the
Location of Gain/Loss Recognized	Three Months Ended March 31,
in Income on Derivatives	2011			2010
Price risk management activities	$	(1,139	)	$	7,822

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

4. Fair Value of Financial Instruments

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

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

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

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

9

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 March 31, 2011, the types of derivative instruments utilized by the Company included costless collars and swaps. The natural gas derivative markets are highly active. Although the Company’s cash flow and economic hedges are valued using public indices, the instruments themselves are traded with third party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.

Credit facility

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

Asset retirement obligations

The Company estimates asset retirement obligations pursuant to the provisions of FASB ASC Topic 410, “Asset Retirement and Environmental Obligations.” The income valuation technique is utilized by the Company to determine the fair value of the liability at the point of inception by taking into account (1) the cost of abandoning oil and gas wells, which is based on the Company’s historical experience for similar work, or estimates from independent third parties; (2) the economic lives of its properties, which is based on estimates from reserve engineers; (3) the inflation rate; and 4) the credit adjusted risk-free rate, which takes into account the Company’s credit risk and the time value of money. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. There were no asset retirement obligations measured at fair value within the consolidated balance sheet at March 31, 2011.

The following table provides a summary of the fair values of assets and liabilities measured at fair value:

	Level 1		Level 2		Level 3		Total
Assets
Derivative instruments — Commodity forward contracts	$	—	$	6,913	$	—	$	6,913
Total assets at fair value	$	—	$	6,913	$	—	$	6,913
Liabilities
Derivative instruments — Commodity forward contracts	$	—	$	1,000	$	—	$	1,000
Total liabilities at fair value	$	—	$	1,000	$	—	$	1,000

The Company did not have any transfers of assets or liabilities between Level 1, Level 2 or Level 3 of the fair value measurement hierarchy during the three months ended March 31, 2011.

10

Concentration of credit risk

Financial instruments which 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 the Company’s third party marketing company. Collectability is dependent upon the financial wherewithal of each individual company as well as the general economic conditions of the industry. The receivables are not collateralized.

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

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 pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis. The fair value of impaired assets is determined based on quoted market prices in active markets, if available, or upon the present values of expected future cash flows using discount rates commensurate with the risks involved in the asset group. The impairment analysis performed by the Company may utilize Level 3 inputs. The long-lived assets of the Company consist primarily of proved oil and gas properties and undeveloped leaseholds. The Company did not record any proved property impairment expense in the quarters ended March 31, 2011 or 2010. The Company wrote off $73 and $0 related to expired undeveloped leaseholds during the quarters ended March 31, 2011 and 2010.

6. Compensation Plans

The Company recognized stock-based compensation expense totaling $275 for the quarter ended March 31, 2011, and $276 for the quarter ended March 31, 2010.

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 March 31, 2011 and changes during the three months ended March 31, 2011 is presented below:

						Weighted-
						Average
				Weighted-		Remaining
				Average		Contractual		Aggregate
				Exercise		Term (in		Intrinsic
Options:	Shares			Price		years)		Value
Outstanding at January 1, 2011		556,339		$	12.94		4.4
Granted		26,659		$	5.10
Exercised		—
Cancelled/expired		(50,000	)	$	17.95
Outstanding at March 31, 2011		532,998		$	12.08		4.1	$	646
Exercisable at March 31, 2011		282,063		$	13.69		3.7	$	206

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 the compensation expenses net of a forfeiture rate and recognizes the compensation expenses for only those shares expected to vest. The Company typically estimates forfeiture rates based on historical experience, while also considering the duration of the vesting term of the award.

11

Nonvested stock awards as of March 31, 2011 and changes during the three months ended March 31, 2011 were as follows:

				Weighted-
				Average
				Grant Date
Stock Awards:	Shares			Fair Value
Outstanding at January 1, 2011		83,304		$	8.40
Granted		15,279		$	5.73
Vested		(22,133	)	$	4.82
Forfeited/returned		—		$	—
Nonvested at March 31, 2011		76,450		$	8.90

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 March 31, 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 March 31, 2011.

7. Income Taxes

Double Eagle is required to record income tax expense for financial reporting purpose, however, 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 March 31, 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 March 31, 2011, the Company had a $75 million revolving line of credit in place with $60 million available for borrowing based on several factors, including its current borrowing base and the commitment levels by participating banks. The Company amended the credit facility effective March 8, 2011 to increase the borrowing availability on the facility from $55 million to $60 million.

The credit facility is collateralized by the Company’s oil and gas producing properties. As of March 31, 2011, the balance outstanding on the credit facility of $32,000 has been used to fund the past three years of development of the Catalina Unit and other non-operated projects in the Atlantic Rim, as well as projects in the Pinedale Anticline. Any balance outstanding on the facility matures on January 31, 2013.

Borrowings under the revolving line of credit bear interest at a daily rate equal to the greater of (a) the Federal Funds rate, plus 0.5%, the Prime Rate or the Eurodollar Rate plus 1%, plus (b) a margin ranging between 1.25% and 2.0% depending on the level of funds borrowed. The amendment to the facility in March 2011 removed the 4.5% interest rate floor. The interest rate on the facility at March 31, 2011 was 2.89%. For the quarters ended March 31, 2011 and 2010, the Company incurred interest expense of $326 and $360, respectively, on the credit facility. The Company capitalized interest costs of $35 and $50 for the quarters ended March 31, 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 March 31, 2011, the Company was in compliance with all financial covenants. If the covenants are violated, and the Company 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.

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10. Series A Cumulative Preferred Stock

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

Holders of the Series A Preferred Stock are entitled to receive, when and as declared by the Board of Directors, dividends at a rate of 9.25% per annum ($2.3125 per annum per share). The Series A Preferred Stock does not have any stated maturity date and will not be subject to any sinking fund or mandatory redemption provisions, except, under some circumstances, upon a change of ownership or control. Except pursuant to the special redemption upon a change of ownership or control, the Company may not redeem the Series A Preferred Stock prior to June 30, 2012. On or after June 30, 2012, the Company may redeem the Series A Preferred Stock for cash at its option, in whole or from time to time in part, at a redemption price of $25.00 per share, plus accrued and unpaid dividends (whether or not earned or declared) to the redemption date. The shares of Series A Preferred Stock are classified outside of permanent equity on the consolidated balance sheets due to the following redemption provision. Following a change of ownership or control of the Company by a person or entity, other than by a “Qualifying Public Company,” the Company will be required to redeem the Series A Preferred Stock within 90 days after the date on which the change of ownership or control occurred for cash, at the following price per share, plus accrued and unpaid dividends.

Redemption Date on or Before	Redemption Price
June 30, 2011	$	25.25
June 30, 2012 or thereafter	$	25.00

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.

11. Comprehensive Income (Loss)

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

	For the Quarter Ended March 31,
	2011			2010
Net income (loss) attributable to common stock	$	(1,083	)	$	5,178
Change in derivative instrument fair value, net of tax benefit of $452 and tax expense of $771, respectively		566			1,252
Reclassification to earnings		(2,342	)		—
Comprehensive income (loss)	$	(2,859	)	$	6,430

The components of accumulated other comprehensive income were as follows:

	March 31,		December 31,
	2011		2010
Net change in derivative instrument fair value, net of tax of $2,575 and $3,027, respectively	$	3,792	$	5,568
Total accumulated other comprehensive income, net	$	3,792	$	5,568

12. 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 March 31, 2011 and December 31, 2010 totaled $605 and $615, respectively.

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13. Contingencies

Legal proceedings

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

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

14. Subsequent Events

In April 2011, the Company entered into an additional fixed price swap for 5,000 Mcf per day at $5.10 NYMEX per Mcf. The contract is for the period January 2012 through December 2012.

The Company has noted no additional events, other than noted above, that require recognition or disclosure at March 31, 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, share or per share amounts.

FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q includes “forward-looking statements” as defined by the Securities and Exchange Commission, or SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Form 10-Q that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including without limitation the Risk Factors set forth in Part I, “Item 1A. Risk Factors” in our Form 10-K for the year ended December 31, 2010 and the following factors:

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

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

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

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

• The changing political environment in which we operate;

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

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• The volumes of production from our oil and gas development properties, which may be dependent upon issuance by federal and state governments, or agencies thereof, of drilling, environmental and other permits, and the availability of specialized contractors, work force, and equipment;

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

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

• Incorrect estimates of required capital expenditures;

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

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

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

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

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

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

• Weather, climate change and other natural phenomena;

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

• The volatility of our stock price;

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

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

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

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

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

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

Business Overview and Strategy

We are an independent energy company engaged in the exploration, development, production and sale of natural gas and crude oil, primarily in Rocky Mountain Basins of the western United States. We were incorporated in Wyoming in 1972 and reincorporated in Maryland in 2001. From 1995 to 2006, our common stock was publicly traded on the NASDAQ Capital Market under the symbol “DBLE”. In December 2006, our common stock began trading on the NASDAQ Global Select Market under the same symbol. Our Series A Cumulative Preferred Stock (“Preferred Stock”) was issued on the NASDAQ Capital Market under the symbol “DBLEP” in July 2007 and began trading on the NASDAQ Global Select Market in September 2007. Our corporate offices are located at 1675 Broadway, Suite 2200, Denver, Colorado 80202, telephone number (303) 794-8445. Our website is www.dble.com.

Our objective is to increase long-term shareholder value by profitably growing our reserves, production, revenues, and cash flow by focusing primarily on: (i) new coal bed methane gas development drilling; (ii) enhancement of existing production wells and field facilities on operated and non-operated properties in the Atlantic Rim; (iii) continued participation in the development of tight sands gas wells at the Mesa Fields on the Pinedale Anticline; (iv) expansion of our midstream business; (v) pursuit of high quality exploration and strategic development projects with potential for providing long-term drilling inventories that generate high returns, including the Niobrara formation in the Atlantic Rim and other properties in which we have interests and (vi) selectively pursuing strategic acquisitions.

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

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OVERVIEW OF FINANCIAL CONDITION AND LIQUIDITY

Liquidity and Capital Resources

We believe that the amounts available under our $75 million credit facility ($60 million credit availability), combined with our net cash from operating activities, will provide us with sufficient funds to meet future financial covenants, develop new reserves, maintain our current facilities, and complete our 2011 capital expenditure program (see “Capital Requirements” on the following page). Depending on the timing and amounts of future projects, we may be required to seek additional sources of capital. We can provide no assurance that we will be able to do so on favorable terms or at all. The Company currently has an effective Form S-3 shelf registration statement on file with the SEC, which has $150 million of securities available for issuance and provides us the ability to raise additional funds through private placements or registered offerings of equity. We also may be required to secure additional debt.

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

	March 31,			December 31,
	2011			2010
	(unaudited)
Financial Position Summary
Cash and cash equivalents	$	3,345		$	2,605
Working capital	$	8,312		$	7,477
Balance outstanding on credit facility	$	32,000		$	32,000
Stockholders’ equity and preferred stock	$	88,085		$	90,677
Ratios
Debt to total capital ratio(1)		26.6	%		26.1	%
Total debt to equity ratio		63.9	%		60.7	%

(1) Total capital includes the $32,000 outstanding on our credit facility, our preferred stock and stockholder’s equity.

We continued to increase our working capital balance in the first quarter of 2011, which grew to $8,312 at March 31, 2011 from $7,477 at December 31, 2010. The higher working capital is primarily the result of a decrease in our accounts payable and accrued liability balances due to the seasonal slow-down in drilling and workover activity. This was offset somewhat by a decrease in our current assets from price risk management due to the settlement of derivative contracts in the first quarter of 2011.

Cash flow activities

The table below summarizes our cash flows for the quarters ended March 31, 2011 and 2010, respectively:

	Quarter ended March 31,
	2011			2010
	(unaudited)
Cash provided by (used in):
Operating activities	$	5,794		$	9,692
Investing activities		(3,980	)		(5,853	)
Financing activities		(1,074	)		(4,072	)
Net change in cash	$	740		$	(233	)

During the quarter ended March 31, 2011, net cash provided by operating activities was $5,794, as compared to $9,692 in the same prior-year period. Although we had a net loss of $(152) for the quarter ended March 31, 2011, it was net of non-cash charges of $4,713 related to depreciation, depletion, and amortization expenses (“DD&A”) and accretion expense, a non-cash loss on derivative contracts of $1,482 and non-cash stock-based compensation expense of $275. We used more cash in the quarter ended March 31, 2011 to maintain lower accounts payable and accrued expenses balances as compared to March 31, 2010. We realized a higher natural gas price in the first quarter of 2011, as compared to 2010, due to our hedging program, which offset the cash used to reduce our accounts payable and accrued expense balances.

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During the quarter ended March 31, 2011, net cash used in investing activities was $3,980, as compared to $5,853 in the same prior-year period. Drilling and workover activity in the Atlantic Rim slowed in the fourth quarter of 2010 and first quarter of 2011, as compared to the fourth quarter of 2009 and first quarter of 2010 and as a result, our cash outflow related to capital expenditures decreased as compared to the prior year. The capital expenditures in the first quarter of 2011 primarily related to non-operated drilling in the Pinedale Anticline.

During the quarter ended March 31, 2011, we had net cash used by financing activities of $1,074, as compared to $4,072 in the same prior-year period. In the first quarter of 2011, we maintained the current debt balance throughout the quarter, whereas in 2010, we repaid $3,000 of the outstanding balance on credit facility. We expended cash in the first quarter of 2011 and 2010 to make our quarterly dividend payment totaling $931 in each period. Dividends are expected to continue to be paid on a quarterly basis on the Series A Preferred Stock in the future at a rate of $931 per quarter.

Credit Facility

Effective March 8, 2011, the Company amended its $75 million credit facility to increase our borrowing availability to $60 million from $55 million, collateralized by our oil and gas properties. The amendment also eliminated the 4.5% interest floor on the facility. As of March 31, 2011, the outstanding balance on our credit facility was $32,000. The interest rate as of March 31, 2011, calculated in accordance with the agreement, was 2.89%, compared to an interest rate of 4.5% at March 31, 2010. For the quarters ended March 31, 2011 and 2010, we incurred interest expense of $326 and $360, respectively, on the credit facility. We capitalized interest costs of $35 and $50 for the quarters ended March 31, 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 March 31, 2011, we were in compliance with all covenants under the facility. If any of the covenants are violated, and the Company 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.

Our borrowing base is subject to redetermination each April 1 and October 1, beginning October 1, 2011. We currently have a borrowing base in excess of our current borrowing availability.

Capital Requirements

For 2011, we have budgeted approximately $20 to $30 million for our development and exploration programs, which include our assets in the Atlantic Rim and Pinedale Anticline. We intend to drill in the Atlantic Rim in the second half of 2011, with up to 20 coal bed methane (“CBM”) production wells within the Catalina Unit. We also expect to participate in six new wells at the Mesa Units. We also have allocated capital in our 2011 capital budget for one or more exploratory wells into the Niobrara formation in the Atlantic Rim. We expect to fund our 2011 capital expenditures with cash provided by operating activities and funds made available through our credit facility. Our 2011 capital budget does not include the impact of potential future exploration projects or possible acquisitions, which we continually evaluate.

Contractual Obligations

The impact that our contractual obligations as of March 31, 2011 are expected to have on our liquidity and cash flows in future periods is:

			Less than		1 - 3		3 - 5		More than
	Total		one year		Years		Years		5 Years
Credit facility (a)	$	32,000	$	—	$	32,000	$	—	$	—
Interest on credit facility (b)		1,782		928		854		—		—
Capital leases		564		564		—		—		—
Operating leases		6,086		2,382		3,514		190		—
Total contractual cash commitments	$	40,432	$	3,874	$	36,368	$	190	$	—

(a)	The amount listed reflects the balance outstanding as of March 31, 2011. Any balance outstanding is due on January 31, 2013.
(b)	Assumes the interest rate on our credit facility is consistent with that of March 31, 2011.

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Off-Balance Sheet Arrangements

We do not participate in transactions that generate relationships with unconsolidated entities or financial partnerships. Such entities are often referred to as structured finance or special purpose entities (“SPEs”) or variable interest entities (“VIEs”). SPEs and VIEs can be established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. We were not involved in any unconsolidated SPEs or VIEs at any time during any of the periods presented in this Form 10-Q.

RESULTS OF OPERATIONS

Quarter Ended March 31, 2011 Compared to the Quarter Ended March 31, 2010

Oil and gas sales, production volume and price comparisons

	Quarter Ended March 31,								Percent			Percent
	2011				2010				Volume			Price
Product:	Volume		Average Price		Volume		Average Price		Change			Change
Gas (Mcf)		2,213,673	$	4.83		2,200,010	$	4.70		1	%		3	%
Oil (Bbls)		6,765	$	82.71		6,936	$	71.43		-2	%		16	%
Mcfe		2,254,263	$	4.99		2,241,624	$	4.83		1	%		3	%

For the quarter ended March 31, 2011, oil and gas sales decreased 1% to $10,910, as compared to the first quarter of 2010. The CIG market price, which is the index on which most of our gas volumes are sold, decreased 16% from the first quarter of 2010, which resulted in lower oil and gas sales in the first quarter of 2011. The decrease was partially offset by the cash received upon settlement of our cash flow hedges and by the small increase in production volumes, discussed in more detail below.

Our average realized natural gas price increased 3% to $4.83 for the quarter ended March 31, 2011, as compared to the first quarter of 2010. We calculate our average gas price by summing (1) production revenue received from third parties for the sale of our gas, which is included within oil and gas sales on the consolidated statements of operations; (2) settlement of our cash flow hedges included within oil and gas sales on the consolidated statement of operations; and (3) realized gain/ (loss) on our economic hedges, which is included within price risk management activities on the consolidated statements of operations, totaling $343 and $(223), for the quarters ended March 31, 2011 and 2010, respectively. Despite the decrease in the average CIG market price for the first quarter of 2011, we realized a higher natural gas price as a result of our hedging program. In addition to the $343 settlement on our hedges included in price risk management activities, we also realized cash flow hedge settlements of $2,342 included in oil and gas sales.

Our total net production remained constant quarter over quarter, totaling 2,254 Mcfe for the quarter ended March 31, 2011 and 2,242 MMcfe for the quarter ended March 31, 2010. We experienced an increase in production volumes at the Sun Dog and Doty Mountain Units, which offset the production decline at the Catalina Unit, as discussed below.

During the quarter ended March 31, 2011, average daily net production at the Atlantic Rim increased 2% to 18,606 Mcfe, as compared to 18,261 Mcfe during the same prior-year period. The production from the Atlantic Rim comes from three operating units, the Catalina Unit, the Sun Dog Unit and the Doty Mountain Unit. The Catalina Unit is operated by the Company.

• Average daily net production decreased 12% at our Catalina Unit to 13,722 Mcfe per day, as compared to 15,599 Mcfe per day during the first quarter of 2010. The decrease is largely the result of what management believes to be the normal production decline for wells within the field. Historically, production volumes in the Catalina Unit tend to be lower in the first quarter due to challenging weather and mud conditions, which can cause delays in routine well maintenance.

• Average daily net production at the Sun Dog and Doty Mountain Units increased 83% for the quarter ended March 31, 2011 to 4,884 Mcfe per day from 2,662 Mcfe per day in the prior-year quarter, largely due to our higher working interest in both units. We purchased additional working interests in the Sun Dog and Doty Mountain Units during the third quarter of 2010, which increased our working interest in the Sun Dog Unit to 20.46% from 8.89% prior to the purchase, and the Doty Mountain Unit to 18.00% from 16.5% prior to the purchase. The increase is also attributed in part to better production from certain Doty Mountain wells due to fracture stimulation.

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Average daily net production in the Pinedale Anticline decreased 1% during the quarter ended March 31, 2011, to 4,969 Mcfe, as compared to 5,014 Mcfe in the same prior-year period. The Pinedale field typically experiences a seasonal decline in the production in the first quarter of each year due to the operator’s decision to not complete wells during the coldest months of the year. The operator at the Mesa Units has informed us that it expects to complete 17 wells over the next two quarters. In addition, the operator has indicated that it will begin drilling six additional wells in 2011.

Transportation and gathering revenue

During the quarter ended March 31, 2011, transportation and gathering revenue decreased 17% to $1,232 from $1,487 for the quarter ended March 31, 2010. We receive fees for gathering and transporting third party gas through our intrastate gas pipeline, which connects the Catalina Unit with the interstate pipeline system owned by Southern Star Central Gas Pipeline, Inc. The decrease in revenue is due to the decrease in production volume at the Catalina Unit.

Price risk management activities

We recorded a net loss on our derivative contracts not designated as cash flow hedges of $1,139 for the quarter ended March 31, 2011, as compared to a gain of $7,822 for the quarter ended March 31, 2010. The net loss consisted of an unrealized non-cash loss of $1,482, which represents the change in the fair value on our economic hedges at March 31, 2011, based on the future expected prices of the related commodities, and a net realized gain of $343 related to the cash settlement of some of our economic hedges.

Oil and gas production expenses, depreciation, depletion and amortization

	Quarter Ended March 31,
	2011			2010
	(unaudited, in dollars per mcfe)
Average price	$	4.99		$	4.83
Production costs		1.14			0.87
Production taxes		0.47			0.58
Depletion and amortization		2.03			1.98
Total operating costs		3.64			3.43
Gross margin	$	1.35		$	1.40
Gross margin percentage		27	%		29	%

During the quarter ended March 31, 2011, well production costs increased 32% to $2,574, as compared to $1,943 during the same prior-year period, and production costs in dollars per Mcfe increased 31%, or $0.27 to $1.14, as compared to the same prior-year period. The increase in production costs in total was driven by additional production costs from the Sun Dog and Doty Mountain Units resulting from our increased working interests at these properties. Because production from the Sun Dog and Doty Mountain Units, which have historically yielded lower margins than many of our properties, made up a larger percentage of our total production during the quarter, we also experienced an increase in production costs on a per Mcfe basis.

Depreciation, depletion, and amortization (“DD&A”) for the quarter ended March 31, 2011 increased 3% to $4,673, as compared to $4,540 in the same prior-year period, and depletion and amortization related to producing assets also increased 3% to $4,568 as compared to $4,437 in the same prior-year period. Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased 3%, or $0.05, to $2.03, as compared to the same prior-year period.

Pipeline operating costs

During the quarter ended March 31, 2011, pipeline operating costs decreased 15% to $981 from $1,149 for the first quarter of 2010. The decrease is primarily attributed to a reduction in consulting costs. We incurred higher consulting costs in 2010 related to refiguring our compressor units.

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General and administrative expenses

General and administrative expenses increased 2% to $1,558 for the quarter ended March 31, 2011, as compared to $1,534 for the quarter ended March 31, 2010. In the first quarter of the 2011, we realized a decrease in legal fees of $51, a decrease in salary and salary-related expense of $36, and a reduction in office building rental expense of $26 due to the expiration of the Texas leases assumed in the Petrosearch merger in 2009. These decreases were offset by a $45 increase related to our Board of Directors expenses due to the expansion of our Board and expenses incurred related to Board training and conferences. The 2010 general and administrative expenses were net of a recovery of an old outstanding receivable that had previously been written off totaling $155.

Income taxes

During the quarter ended March 31, 2011, we recorded an income tax benefit of $104 compared to income tax expense of $3,457 during the same prior-year period. Our effective tax rate for the quarter ended March 31, 2011 was 40.4% compared to 36.1% for the first quarter of 2010. Our effective tax rate was higher in the 2011 period due to an increase in the proportion of permanent income tax differences related to stock option expense as compared to net income and an increase in non-deductible DD&A expense. Although we expect to continue to generate losses for federal income tax reporting purposes, our operations have resulted in a deferred tax position required under generally accepted accounting principles. We expect to recognize deferred income tax expense on taxable income for the remainder of 2011 at an expected federal and state rate of approximately 35.0%.

CONTRACTED VOLUMES

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 March 31, 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		2,200,000		8,000		01/11-12/11	$	7.07	CIG
Costless Collar		610,000		5,000		08/09-07/11	$	4.50 floor	NYMEX
							$	7.90 ceiling
Costless Collar		1,220,000		5,000		12/09-11/11	$	4.50 floor	NYMEX
							$	9.00 ceiling
Fixed Price Swap		3,660,000		10,000		01/12-12/12	$	5.05	NYMEX
Fixed Price Swap		2,190,000		6,000		01/13-12/13	$	5.16	NYMEX
Costless Collar		2,190,000		6,000		01/13-12/13	$	5.00 floor	NYMEX
							$	5.35 ceiling
Total		12,070,000

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

In April 2011, the Company entered into an additional fixed price swap for 5,000 Mcf per day at $5.10 NYMEX. The contract is for the period January 2012 through December 2012.

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

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.

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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 year ended March 31, 2011, our income before income taxes would have increased by $396 for each $0.50 increase per Mcf in natural gas prices and decreased by $102 for each $0.50 decrease per Mcf in natural gas prices due to the contracted volumes discussed above. Our income taxes would have increased $6 for each $1.00 change per Bbl in crude oil prices for the year ended March 31, 2011.

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

Interest Rate Risks

At March 31, 2011, we had a total of $32.0 million outstanding under our $75 million credit facility ($60 million borrowing availability). We pay interest on outstanding borrowings under our credit facility at interest rates that fluctuate based upon changes in our levels of outstanding debt and the prevailing market rates. The average interested rate for the period, calculated in accordance with the agreement, was 4.1%. Because the interest rate is variable and reflects current market conditions, the carrying value approximates the fair value. Assuming no change in the amount outstanding at March 31, 2011, the annual impact on interest expense for every 1.0% change in the average interest rate would be approximately $320 before taxes. Any balance outstanding on the credit facility matures on January 31, 2013.

ITEM 4. CONTROLS AND PROCEDURES

In accordance with the Securities Exchange Act of 1934 Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer, 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 and Chief Financial Officer have concluded that our disclosure controls and procedures were effective as of March 31, 2011.

There has been no change in our internal control over financial reporting that occurred during the quarter ended March 31, 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 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, which preserves the plaintiff’s right to appeal.

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ITEM 1A. RISK FACTORS

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

ITEM 6. EXHIBITS

The following exhibits are filed as part of this report:

Exhibit			Description:
	3.1	(a)	Articles of Incorporation of the Company (incorporated by reference from Exhibit 3.1(a) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).
	3.1	(b)	Certificate of Correction of the Company (incorporated by reference from Exhibit 3.1(b) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).
	3.1	(c)	Certificate of Correction of the Company (incorporated by reference from Exhibit 3 of the Company’s Quarterly Report on Form 10-QSB for the quarter ended November 30, 2001).
	3.1	(d)	Certificate of Correction to the Articles of Incorporation of the Company (incorporated by reference from Exhibit 3.3 of the Company’s Current Report of Form 8-K dated June 29, 2007).
	3.1	(e)	Articles of Amendment to the Articles of Incorporation of the Company, filed with the Maryland Department of Assessments and Taxation on June 26, 2007 (incorporated by reference from Exhibit 3.1 of the company’s Current Report on Form 8-K dated June 29, 2007).
	3.1	(f)	Articles Supplementary, (incorporated by reference from Exhibit 3.2 of the Company’s Current Report of Form 8-K dated June 29, 2007).
	3.1	(g)	Articles Supplementary of Junior Participating Preferred Stock, Series B of the Company, dated as of August 21, 2007 (incorporated by reference from Exhibit 3.1 of the Company’s Current Report of Form 8-K dated August 28, 2007).
	3.1	(h)	Amendment to Bylaws, Revised Article II, Section 9 (incorporated by reference from Exhibit 3.1 of the company’s Current Report on Form 8-K filed on March 5, 2010).
	3.2		Second Amended and Restated Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Current Report on Form 8-K filed on June 11, 2007).
	4.1	(a)	Form of Warrant Agreement concerning Common Stock Purchase Warrants (incorporated by reference from Exhibit 4.3 of the Amendment No. 1 to the Company’s Registration Statement on Form SB-2 filed on November 27, 1996, SEC Registration No. 333-14011).
	4.1	(b)	Rights Agreement between the Company and Computershare Trust Company, N.A. (incorporated herein by reference to the Company’s Current Report on Form 8-K filed on August 24, 2007)

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Exhibit			Description:
	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).
	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.

* Filed within this Form 10-Q.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	DOUBLE EAGLE PETROLEUM CO. (Registrant)
Date: May 5, 2011	By:	/s/ Richard D. Dole
		Richard D. Dole
		Chief Executive Officer (Principal Executive Officer)

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EXHIBIT INDEX

Exhibit Number			Description
	3.1	(a)	Articles of Incorporation of the Company (incorporated by reference from Exhibit 3.1(a) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).
	3.1	(b)	Certificate of Correction of the Company (incorporated by reference from Exhibit 3.1(b) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).
	3.1	(c)	Certificate of Correction of the Company (incorporated by reference from Exhibit 3 of the Company’s Quarterly Report on Form 10-QSB for the quarter ended November 30, 2001).
	3.1	(d)	Certificate of Correction to the Articles of Incorporation of the Company (incorporated by reference from Exhibit 3.3 of the Company’s Current Report of Form 8-K dated June 29, 2007).
	3.1	(e)	Articles of Amendment to the Articles of Incorporation of the Company, filed with the Maryland Department of Assessments and Taxation on June 26, 2007 (incorporated by reference from Exhibit 3.1 of the company’s Current Report on Form 8-K dated June 29, 2007).
	3.1	(f)	Articles Supplementary, (incorporated by reference from Exhibit 3.2 of the Company’s Current Report of Form 8-K dated June 29, 2007).
	3.1	(g)	Articles Supplementary of Junior Participating Preferred Stock, Series B of the Company, dated as of August 21, 2007 (incorporated by reference from Exhibit 3.1 of the Company’s Current Report of Form 8-K dated August 28, 2007).
	3.1	(h)	Amendment to Bylaws, Revised Article II, Section 9 -(incorporated by reference from Exhibit 3.1 of the company’s Current Report on Form 8-K filed on March 5, 2010).
	3.2		Second Amended and Restated Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Current Report on Form 8-K filed on June 11, 2007).
	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).
	4.1	(a)	Form of Warrant Agreement concerning Common Stock Purchase Warrants (incorporated by reference from Exhibit 4.3 of the Amendment No. 1 to the Company’s Registration Statement on Form SB-2 filed on November 27, 1996, SEC Registration No. 333-14011).
	4.1	(b)	Rights Agreement between the Company and Computershare Trust Company, N.A. (incorporated herein by reference to the Company’s Current report on Form 8-K filed on August 24, 2007)

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Exhibit Number			Description
	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).
	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.

* Filed with this report.

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