Escalera Resources (ESCR) 10-Q 2009 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, 2009

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).o Yeso No

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

Large accelerated filero Accelerated filerþ Non-accelerated filero(Do not check if a small reporting company) Small reporting Companyo

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 May 1, 2009
Common stock, $.10 par value		9,233,756

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, 2009 (Unaudited) and December 31, 2008		2
Consolidated Statements of Income for the Quarter Ended March 31, 2009 and 2008 (Unaudited)		3
Consolidated Statements of Cash Flows for the Quarter Ended March 31, 2009 and 2008 (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		22
Item 4. Controls and Procedures		22
PART II. Other Information:
Item 1. Legal Proceedings		22
Item 1A. Risk Factors		22
Item 6. Exhibits		23
Signatures		25
Exhibit 31.1
Exhibit 31.2
Exhibit 32

1

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)

	March 31,			December 31,
	2009			2008
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	2,171		$	—
Cash held in escrow		607			605
Accounts receivable		9,432			21,381
Assets from price risk management		11,167			14,290
Other current assets		3,475			3,513
Total current assets		26,852			39,789
Oil and gas properties and equipment, successful efforts method:
Developed properties		151,792			133,516
Wells in progress		10,444			18,518
Gas transportation pipeline		5,465			5,465
Undeveloped properties		2,916			2,907
Corporate and other assets		1,921			1,920
		172,538			162,326
Less accumulated depreciation, depletion and amortization		(39,635	)		(35,253	)
Net properties and equipment		132,903			127,073
Assets from price risk management		4,322			5,029
Other assets		90			98
TOTAL ASSETS	$	164,167		$	171,989
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	7,776		$	35,488
Accrued expenses		7,382			6,794
Term loan		3,750			—
Accrued production taxes		3,521			3,017
Capital lease obligations, current portion		525			522
Other current liabilities		307			282
Total current liabilities		23,261			46,103
Line of credit		38,750			24,639
Asset retirement obligation		3,983			4,208
Liabilities from price risk management		954			—
Deferred tax liability		3,101			2,470
Capital lease obligations, long-term portion		946			1,078
Other long-term liabilities		513			616
Total liabilities		71,508			79,114
Preferred stock, $0.10 par value; 10,000,000 shares authorized; 1,610,000 shares issued and outstanding as of March 31, 2009 and December 31, 2008		37,972			37,972
Stockholders’ equity:
Common stock, $0.10 par value; 50,000,000 shares authorized; 9,230,877 and 9,192,356 shares issued and outstanding as of March 31, 2009 and December 31, 2008, respectively		923			919
Additional paid-in capital		35,544			35,122
Retained earnings		2,248			2,172
Accumulated other comprehensive income		15,972			16,690
Total stockholders’ equity		54,687			54,903
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	164,167		$	171,989

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

2

DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED STATEMENTS OF INCOME

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

(Unaudited)

	Three months ended March 31,
	2009			2008
Revenues
Oil and gas sales	$	10,500		$	6,251
Transportation revenue		1,587			364
Price risk management activities		(1,140	)		652
Other income, net		93			49
Total revenues		11,040			7,316
Costs and expenses
Production costs		1,884			1,021
Production taxes		889			800
Exploration expenses including dry hole costs		26			481
Pipeline operating costs		295			83
General and administrative		1,674			908
Depreciation, depletion and amortization		4,382			1,014
Total costs and expenses		9,150			4,307
Income from operations		1,890			3,009
Interest expense, net		(252	)		(64	)
Income before income taxes		1,638			2,945
Provision for deferred income taxes		(631	)		(1,082	)
NET INCOME	$	1,007		$	1,863
Preferred stock dividends		931			931
Net Income attributable to common stock	$	76		$	932
Net income per common share:
Basic	$	0.01		$	0.10
Diluted	$	0.01		$	0.10
Weighted average shares outstanding:
Basic		9,201,913			9,148,105
Diluted		9,201,913			9,148,933

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

3

DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in thousands of dollars)

(Unaudited)

	Three months ended March 31,
	2009			2008
Cash flows from operating activities:
Net income	$	1,007		$	1,863
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion, amortization and accretion of asset retirement obligation		4,406			1,118
Abandonment of non-producing properties		5			40
Provision for deferred taxes		631			1,082
Employee stock option expense		430			98
Directors fees paid in stock		38			—
Change in fair value of derivative contracts		4,066			(652	)
Revenue from carried interest		(563	)		—
Gain on sale of producing property		(70	)		—
Changes in current assets and liabilities:
Decrease (Increase) in deposit held in escrow		(2	)		139
Decrease (Increase) in accounts receivable		11,949			(2,147	)
Decrease (Increase) in other current assets		38			(7	)
Increase (Decrease) in accounts payable		(12,242	)		1,290
Decrease in accrued expenses		(2,847	)		(767	)
Increase in accrued production taxes		89			406
NET CASH PROVIDED BY OPERATING ACTIVITIES		6,935			2,463
Cash flows from investing activities:
Additions of producing properties and equipment, net		(21,429	)		(10,801	)
Additions of corporate and non-producing properties		(15	)		(202	)
Payment of acquisition related costs		(102	)		—
NET CASH USED IN INVESTING ACTIVITIES		(21,546	)		(11,003	)
Cash flows from financing activities:
Principal payments on capital lease obligations		(129	)		—
Issuance of stock under Company stock plans		4			—
Tax withholdings related to net share settlement of restricted stock awards		(23	)		—
Dividends on preferred stock		(931	)		(931	)
Net borrowings (repayments) on line of credit		17,861			9,523
NET CASH PROVIDED BY FINANCING ACTIVITIES		16,782			8,592
Change in cash and cash equivalents		2,171			52
Cash and cash equivalents at beginning of period		—			125
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	2,171		$	177
Supplemental disclosure of cash and non-cash transactions:
Cash paid for interest	$	643		$	67
Interest capitalized	$	300		$	106
Rebill to joint interest partners for well costs associated with unitization of Catalina	$	—		$	11,426
Additions to developed properties included in current liabilities	$	8,758		$	3,900
Share-based compensation expense	$	468		$	98

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

4

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 2008 consolidated financial statements have been reclassified to conform to the 2009 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 Form 10-K for the year ended December 31, 2008, 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, 2008 included in the Form 10-K filed with the SEC.

Recently adopted accounting pronouncements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 157 — Fair Value Measurements (“SFAS 157”). The statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. In February 2008, the FASB issued Staff Position No. FAS 157-2, which proposed a one-year deferral for the implementation of SFAS 157 for nonfinancial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis (less frequent than annually). On January 1, 2008, the Company implemented this Statement with the one-year deferral. Beginning January 1, 2009, the Company adopted the provisions for nonfinancial assets and nonfinancial liabilities. The adoption of SFAS 157-2 did not have a material impact on the Company’s financial position, results of operations or cash flows.

In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161 — Disclosures about Derivative Instruments and Hedging Activities (“SFAS 161”). SFAS 161 does not change current accounting treatment of derivatives, but requires expanded disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items (if any) are accounted for, and how they affect the Company’s financial position, financial performance and cash flows. The Company adopted the provisions of SFAS 161 effective January 1, 2009. See note 3 for the Company’s disclosures about its derivative instruments and hedging activities.

In November 2007, the FASB issued Statement of Financial Accounting Standards No. 141(R) — Business Combinations (“SFAS 141(R)”). SFAS 141(R) changes the accounting for business combinations both at the acquisition date and in subsequent reporting periods. SFAS 141(R) requires the acquiring company to measure almost all assets acquired and liabilities assumed in the acquisition at fair value as of the acquisition date. The Company adopted SFAS 141(R) effective January 1, 2009. The adoption of SFAS 141(R) did not have a material impact on the Company’s position, results of operations or cash flows.

In November 2007, the FASB issued Statement of Financial Accounting Standards No. 160 — Non-controlling Interests in Consolidated Financial Statements, an amendment to ARB NO. 51 (“SFAS 160”). SFAS 160 requires non-controlling interests in a subsidiary to be initially measured at fair value and classified as a separate component of equity. The Company adopted SFAS 160 effective January 1, 2009. The adoption of SFAS 160 did not have a material impact on the Company’s financial position, results of operations or cash flows.

5

In June 2008, the FASB issued FASB Staff Position No. EITF 03-06-1 “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”). FSP EITF 03-06-1 provides guidance as to whether instruments granted in share-based payment transactions are participating securities prior to vesting, and therefore, need to be included in computing earnings per share under the two-class method provided under FASB No. 128 — Earnings Per Share. We adopted this standard effective January 1, 2009. The adoption of FSP EITF 03-06-1 did not have a material impact on the Company’s financial position, results of operations or cash flows.

New accounting pronouncements

In May 2008, the FASB issued Statement of Financial Accounting Standards No. 162,The Hierarchy of Generally Accepted Accounting Principles(“SFAS 162”). SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements that are presented in conformity with U.S. generally accepted accounting principles. The Statement becomes effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to the auditing literature. The adoption of SFAS 162 is not expected to have an impact on the Company’s financial position, results of operations or cash flows.

In December 2008, the SEC announced final approval of new requirements for reporting oil and gas reserves. Among the changes to the disclosure requirements is a broader definition of reserves, which allows consideration of new technologies. In addition, oil and gas reserves will be reported using an average price based on the prior 12-month period, rather than year-end prices, and allow companies to disclose their probable and possible reserves to investors. The new rule is expected to be effective for years ending on or after December 31, 2009. The Company is in the process of evaluating the effect of these new requirements, and has not yet determined the impact that it will have on its financial statements upon full adoption on December 31, 2009.

In April 2009, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) FAS 157-4,Determining Fair Value when the Volume and Level of Activity for the Asset or Liability have Significantly Decreased and Identifying Transactions that are not Orderly(“FSP 157-4”), which is effective for the Company for the quarterly period beginning April 1, 2009. FSP 157-4 affirms that the objective of fair value when the market for an asset is not active, is 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 under current market conditions. The FSP provides guidance for estimating fair value when the volume and level of market activity for an asset or liability have significantly decreased and determining whether a transaction was orderly. This FSP applies to all fair value measurements when appropriate. The Company does not expect that the adoption of FSP 157-4 will have a material impact on its financial position, results of operations or cash flows.

In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1,Interim Disclosures about Fair Value of Financial Instruments(“FSP 107-1”), which is effective for the Company for the quarterly period beginning April 1, 2009. FSP 107-1 requires an entity to provide the annual disclosures required by FASB Statement No. 107,Disclosures about Fair Value of Financial Instruments, in its interim financial statements. The Company will provide the additional disclosures required by FSP 107-1 in its quarterly report on Form 10-Q for the period ending June 30, 2009.

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 (loss) less dividends paid on the Series A Preferred Stock. We declared and paid cash dividends of $931 ($.5781 per share) and $931 on the Series A Preferred Stock for the quarters ended March 31, 2009 and 2008, respectively.

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,
	2009		2008
Net income	$	1,007	$	1,863
Preferred stock dividends		931		931
Income attributable to common stock	$	76	$	932
Weighted average shares:
Weighted average shares — basic		9,201,913		9,148,105
Dilution effect of stock options outstanding at the end of period		—		828
Weighted average shares — diluted		9,201,913		9,148,933
Earnings per common share:
Basic	$	0.01	$	0.10
Diluted	$	0.01	$	0.10

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,
	2009		2008
Anti-dilutive shares		90,809		10,902

3. Derivative Instruments

On January 1, 2009, the Company adopted SFAS No. 161, which requires enhanced disclosures regarding an entity’s derivative and hedging activities as provided below.

The Company’s primary market exposure is to adverse fluctuations in the prices of natural gas. The Company uses derivative instruments, primarily forwards, costless collars and swaps, to manage the price risk associated with equity 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 Company recognizes its derivative instruments as either assets or liabilities at fair value on our consolidated balance sheet, except for certain instruments which qualify for accounting treatment exception under “normal purchases and normal sales”. See additional discussion of these instruments below. The Company accounts for the commodity forward contracts that do not qualify for this exception as either cash flow hedges or mark to market derivative instruments. On the cash flow statement, 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 credit worthy. 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, our 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. The Company was in an overall asset position with each of counterparties at March 31, 2009, and neither party in any of our derivative contracts has required any form of security guarantee.

Cash flow hedges

Derivative instruments that are designated and qualify as cash flow hedges are recorded at fair value on the balance sheet and the effective portion of the change in fair value is reported as a component of accumulated other comprehensive income and is subsequently reclassified into the oil and gas sales line on the consolidated statement of income as the contracts settle. As of March 31, 2009, the Company expects approximately $11,167 of unrealized gains, included in its Accumulated Other Comprehensive Income (“AOCI”) to be reclassified into earnings in one year or less, as the contracts settle.

7

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 balance sheet and changes in fair value are recognized in the price risk management activities line on the consolidated statement of income currently. Realized gains and losses resulting form 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 income.

The Company had the following commodity forward contracts outstanding as of March 31, 2009:

	Contract Settlement Date
	2009		2010		2011
Natural Gas forward purchase contracts:
Dollar value	$	20,594	$	18,834	$	20,644
Average rate	$	6.96	$	4.30	$	7.07
Volume (MMcf)		2,961		4,380		2,920

The table below contains a summary of all the Company’s derivative positions reported on the consolidated balance sheet as of March 31, 2009, presented gross of any master netting arrangements:

Derivatives designated as hedging
instruments under SFAS 133	Balance Sheet Location	Fair Value
Assets
Commodity derivatives	Assets from price risk management — current	$	11,649
	Assets from price risk management — long term		4,322
Total		$	15,971

Derivatives not designated as
hedging instruments under SFAS 133	Balance Sheet Location	Fair Value
Liabilities
Commodity derivatives	Assets from price risk management — current	$	(482	)
	Liabilities from price risk management — long term		(954	)
Total		$	(1,436	)

The derivative gains and losses in the consolidated statement of income for the three months ended March 31, 2009, related to the Company’s commodity derivatives were as follows:

			Location of Gain			Location of Gain
Derivatives Designated			Reclassified from	Amount of Gain		Recognized in Income
as Cash Flow	Amount of Gain		Accumulated OCI	Reclassified from		(Ineffective Portion and
Hedging Instruments	Recognized in		into Income	Accumulated OCI		Amount Excluded from
under SFAS 133	OCI on Derivative		(effective portion)	into Income		Effectiveness testing)
Commodity contracts	$	15,972	Oil and gas sales	$	4,147		N/A

8

Derivatives not
Designated as	Location of Loss	Amount of Loss
Hedging Instruments	Recognized in Income	Recognized in
under SFAS 133	on Derivative	Income on Derivative
Commodity contracts	Price risk management activities	$	(1,140	)

Normal purchases and normal sales

Under SFAS No. 133, the fixed delivery contracts for production from Sun Dog and Doty Mountain at the Atlantic Rim and the Pinedale Anticline qualify for as “normal purchases and normal sales,” so long as it is probable both at inception and throughout the life of the contract that the contract will result in physical delivery and will not net settle. As of March 31, 2009, the Company believes that physical delivery will be met on all of these contracts. Under the “normal purchase and normal sale” accounting treatment, the Company records the revenue upon contract settlement in oil and gas sales on the consolidated statement of income.

4. Fair Value of Financial Instruments

Effective January 1, 2009, the Company adopted SFAS 157 for its nonfinancial assets and nonfinancial liabilities measured on a non-recurring basis. The Company adopted SFAS No. 157 for financial assets and liabilities in 2008. SFAS 157 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows:

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

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

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

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

Derivative instruments

The Company uses derivative financial instruments to mitigate exposures to oil and gas production cash-flow risks caused by fluctuating commodity prices. At March 31, 2009, the types of derivative instruments utilized by the Company included fixed price delivery contracts and swaps.

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.

Asset retirement obligations

The Company recognizes an estimated liability for future costs associated with the abandonment of our oil and gas properties. The Company’s asset retirement obligation is measured using primarily Level 3 inputs. The significant unobservable inputs include the cost of abandoning oil and gas wells, the economic lives of our properties, the inflation rate, and the credit adjusted risk-free rate. The Company bases its estimate of the liability on its historical experience and current estimated costs.

9

The following table provides a summary of the fair values of assets and liabilities measured on a recurring basis under SFAS No. 157:

	Level 1		Level 2		Level 3		Total
Assets
Derivative instruments	$	—	$	15,489	$	—	$	15,489
Total assets at fair value	$	—	$	15,489	$	—	$	15,489
Liabilities
Derivative instruments	$	—	$	954	$	—	$	954
Asset retirment obligation	$	—	$	—		3,983	$	3,983
Total liabilities at fair value	$	—	$	954	$	3,983	$	4,937

A reconciliation of the Company’s asset retirement obligation liability is below:

December 31, 2008 asset retirement obligation	$	4,208
Liabilities incurred		7
Liabilities settled		(256	)
Accretion expense		24
March 31, 2009 asset retirement obligation	$	3,983

The accretion expense recorded during the period is recorded in the production costs line item on the consolidated statement of income.

5. Impairment of Long-Lived Assets

The Company reviews the carrying values of its long-lived assets 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 the 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 long-lived assets of the Company, which are subject to periodic evaluation, consist primarily of oil and gas properties and undeveloped leaseholds. The Company did not recognize any impairment charges during the quarters ended March 31, 2009 and 2008.

6. Stock-based Compensation

The Company recognized stock-based compensation expense of $468 during the quarter ended March 31, 2009, as compared to $98 in the quarter ended March 31, 2008.

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 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 and contractual expiration dates. 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.

10

A summary of stock option activity under our various stock option plans as of March 31, 2009 and changes during the three months ended March 31, 2009 is presented below:

						Weighted-
						Average
				Weighted-		Remaining
				Average		Contractual		Aggregate
				Exercise		Term		Intrinsic
	Shares			Price		(in years)		Value
Options:
Outstanding at January 1, 2009		626,897		$	15.68		5.1
Granted		50,500		$	7.79
Exercised		—
Cancelled/expired		(14,000	)	$	14.10
Outstanding at March 31, 2009		663,397		$	15.11		5.1	$	—
Exerciseable at March 31, 2009		188,679		$	16.26		3.4	$	—

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 recognize 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 recognize 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 March 31, 2009 and changes during the three months ended March 31, 2009 were as follows:

				Weighted-
				Average
				Grant Date
	Shares			Fair Value
Stock Awards:
Outstanding at January 1, 2009		94,762		$	14.70
Granted		37,572		$	3.48
Vested		(41,527	)	$	4.44
Forfeited/returned		—		$	—
Nonvested at March 31, 2009		90,807		$	14.75

7.	Income Taxes
	At March 31, 2009, the Company had a net operating loss carry forward for income tax reporting purposes of approximately $30.3 million that will begin to expire in 2021. Although Double Eagle is required to record income tax expense for financial reporting purposes, the Company does not anticipate any payments of current tax liabilities in the near future.

The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of March 31, 2009, 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 2004 and for state and local tax authorities for years before 2003. The Company’s tax years of 2004 and forward are subject to examination by federal and state taxing authorities.

8. Credit Facility

Effective February 26, 2009, the Company renegotiated its $50 million revolving line of credit into a $75 million credit facility collateralized by its oil and gas producing properties and other Company assets, with the borrowing base being increased to $45 million from $35 million. Under the agreement, $5 million of the $45 million borrowing base represents a term loan that, if drawn upon, must be repaid on or before July 31, 2009, and the remaining $40 million of available borrowing base is a revolving line of credit. Any outstanding balance on the line of credit matures on July 31, 2010. As of March 31, 2009, the Company had $3,750 outstanding on the term loan, and $38,750 outstanding on the revolving line of credit. The outstanding balances were used to fund capital expenditures primarily on the Company’s Catalina Unit expansion and other non-operated projects in the Atlantic Rim, as well as projects in the Pinedale Anticline.

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Borrowings under the revolving line of credit will bear interest at the greater of (i) 4.5% or (ii) 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 level of funds borrowed. Borrowings under the term loan will bear interest consistent with the revolving line of credit except that the floor rate is 5.5%. As of March 31, 2009, the interest rate on the term loan was 6.75% and the interest rate on the line of credit was 6.0%. For the quarters ended March 31, 2009 and 2008, the Company recognized interest expense of $0 and $0, respectively, on the credit facility. The Company capitalized interest costs of $300 and $106 for the quarters ended March 31, 2009 and 2008, respectively.

Under the facility, the Company is subject to both financial and non-financial covenants. The financial covenants have been modified to include maintaining a current ratio, as defined, of 1.0 to 1.0, beginning June 30, 2009, as well as a ratio of earnings before interest, taxes, depreciation, depletion, and amortization (“EBITDA”) to interest plus dividends, of 1.5 to 1.0. As of March 31, 2009, the Company was in compliance with all of the covenants, and management believes it is probable that we will be in compliance with the current ratio covenant at the June 30, 2009 assessment date. If these 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.

9. Series A Cumulative Preferred Stock

In the third quarter of 2007, the Company completed a public offering of 1,610,000 shares of 9.25% Series A Cumulative 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 or 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 accompanying Consolidated Balance Sheets due to the following redemption provision. Following a Change of Ownership or Control of us 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, 2009	$	25.75
June 30, 2010	$	25.50
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.

10. Comprehensive Income (Loss)

The components of comprehensive loss were as follows:

	For the Quarter Ended March 31,
	2009			2008
Net income attributable to common stock	$	76		$	1,863
Change in derivative instrument fair value, net of tax benefit of $0		(4,865	)		(4,025	)
Reclassification to earnings		4,147			545
Comprehensive loss	$	(642	)	$	(1,617	)

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The components of accumulated other comprehensive loss were as follows:

	March 31,		December 31,
	2009		2008
Net change in derivative instrument fair value, net of tax benefit of $0 and $0	$	15,972	$	16,690
Total accumulated other comprehensive gain, net	$	15,972	$	16,690

The Company did not record a tax benefit on the change in derivative instrument fair value due as the tax benefit is not likely to be realized given the Company’s operating loss carryforwards and timing of the derivative contract settlements.

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 (Christmas Meadows) exploration project. The unexpended portion of the deposits at March 31, 2009 and December 31, 2008 totaled $607 and $605, respectively.

12.	Intercompany Transactions
	The Company sold transportation assets located in the Catalina Unit, at cost, to Eastern Washakie Midstream, LLC (“EWM”), a wholly-owned subsidiary, 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 share of the fee related to gas gathering is eliminated in consolidation.

13. Proposed Merger

On March 30, 2009, the Company entered into a definitive agreement to merge Petrosearch Energy Corporation (“Petrosearch”) with a wholly-owned subsidiary of the Company. The merger is structured as an all-stock transaction, subject to closing adjustments, and will be accounted for as a purchase. In the merger, assuming no closing adjustments are made, the holders of Petrosearch stock, including the holders of preferred stock on an as-converted basis, are expected to receive 0.0433 shares of Double Eagle common stock for each share of Petrosearch common stock and Petrosearch preferred stock, on an as converted basis, plus cash for any fractional shares of Double Eagle common stock they would otherwise receive in the merger. The estimated purchase price of Petrosearch is $9.8 million and the Company expects to issue 1,792,741 shares to Petrosearch stockholders.

The merger is subject to regulatory review and approval by Petrosearch stockholders. Upon approval, the merger is expected to close in the second or third quarter of 2009. The disclosures in this Form 10-Q reflect the Company as a stand-alone entity and do not reflect the impact of the proposed merger.

14. Contingencies

Litigation

Double Eagle Petroleum Co.; Antelope Energy Company LLC; E. Cecile Martin f/k/a Cecile Hurt; Hurt Properties, L.P.; James R. Hurt; John D. Traut, LLC; and Newfield Exploration Company vs. Burlington Resources Oil & Gas Company, LP, a division of ConocoPhillips Company; ConocoPhillips Company, a Delaware corporation.The Company, along with other plaintiffs, filed a lawsuit on August 24, 2007, in the District Court of Fremont County, Wyoming, against BR and other defendants who own working interests in the Madden Deep Unit. The Company and the other plaintiffs in the case are asserting that, under the gas balancing agreement, they are entitled to receive either monetary damages or their respective shares of the natural gas produced from the Madden Deep Unit over at least the period February 1, 2002 through June 30, 2007. The Company has recognized the sales and has recorded a related account receivable of $292, net of allowance for uncollectible amounts, for the period November 1, 2006 through June 30, 2007. The ultimate outcome of this lawsuit cannot be determined at this time and, as a result, the Company has not recognized any amount of sales proceeds for the period February 1, 2002 through October 30, 2006. Sulfur sales are not subject to a gas balancing agreement, and, accordingly, we received the proceeds for our share of sulfur sales dating back to February 2002 and continue to receive our respective share on an on-going basis.

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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.

FORWARD-LOOKING STATEMENTS

This Quarterly Report onForm 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 thisForm 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 onForm 10-K for the year ended December 31, 2008, including the following:

• The changing political environment in which we operate

• Our ability to continue to develop our Atlantic Rim project;

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

• Our ability to maintain adequate liquidity;

• Incorrect estimates of required capital expenditures;

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

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

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

• The volumes of production from our oil and gas development properties, which may be dependent upon issuance by federal, state, and tribal 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 successfully integrate and profitably operate any future acquisitions;

• The possibility that we may be required to take impairment charges to reduce the carrying value of some of our long-lived assets when indicators of impairment emerge;

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

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

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

• General economic conditions, including the current financial crisis, tax rates or policies and inflation rates;

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

• Weather and other natural phenomena;

• 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;

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

• The cost and effects on our business, including insurance, resulting from terrorist actions or natural disasters and responses to such actions or events;

• The volatility of our stock price; and

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

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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. Double Eagle was incorporated in the State of Wyoming in January 1972 and reincorporated in the State of Maryland in February 2001. From 1995 to 2006, our common shares were publicly traded on the NASDAQ Capital Market under the symbol “DBLE”. On December 15, 2006, our common shares began trading on the NASDAQ Global Select Market. Our Series A Cumulative Preferred Stock (“Preferred Stock”) was issued and began trading on July 30, 2007 on the NASDAQ Capital Market, under the symbol “DBLEP”. On September 30, 2007, our Preferred Stock began trading on the NASDAQ Global Select Market. Our executive offices are located at 1675 Broadway, Suite 2200, Denver, Colorado 80202, and the telephone number there is (303)794-8445. Our operations offices are located at 777 Overland Trail, Casper, Wyoming 82601, and the telephone number there is (307) 237-9330. Our website iswww.dble.us.

Our objective is to increase long-term stockholder value by implementing our corporate strategy of economically growing our reserves and production through the development of our existing core properties, partnering on selective exploration projects, and pursuing strategic acquisitions that expand or complement our existing operations. Our operations are currently focused on two core properties located in southwestern Wyoming, where we have coal bed methane reserves and production in the Atlantic Rim area of the Eastern Washakie Basin, and tight sands gas reserves and production in the Pinedale Anticline. 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.

Following are summary comments of our performance in several key areas during the quarter ended March 31, 2009(Amounts in thousands of dollars, except amounts per unit of production):

• Average Daily Production

During the quarter ended March 31, 2009, our total average daily net production increased 157% to 25,340 Mcfe as compared to average daily production of 9,877 Mcfe during the same prior-year period. The changes in production by major operating area are discussed below.

Atlantic Rim.During the quarter ended March 31, 2009, average daily net production at the Atlantic Rim increased 241% to 17,797 Mcfe, as compared to 5,220 Mcfe during the first quarter of 2008. This increase is primarily the result of the production from a total of 43 new wells at the Catalina Unit; 23 of which were drilled in 2007 and came on-line for production in the second and third quarters of 2008, and the remaining 20 wells were drilled in 2008 and were brought on-line during the fourth quarter of 2008 and the first quarter of 2009. Average daily net production at our Catalina Unit increased 252% to 16,583 Mcfe, as compared to 4,715 Mcfe during the same prior-year period. Average daily production, net to our interest, at the Sun Dog and Doty Mountain units increased 140% to 1,214 Mcfe, as compared to average daily production of 505 Mcfe during the first quarter of 2008. The increase was due to production from 109 new Sun Dog Unit wells which were drilled as part of the 2007 and 2008 drilling programs, and nine new wells drilled at the Doty Mountain Unit during the 2008 drilling program.

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Pinedale Anticline. Average daily production at the Pinedale Anticline increased 83% to 6,148 Mcfe for the quarter ended March 31, 2009, as compared to 3,361 Mcfe in the first quarter of 2008. The increase was primarily due to the addition of 22 new Mesa wells that were brought on-line in the second and third quarters of 2008. The operator at the Mesa Units has informed us that it is in the process of drilling up to 20 new wells, which are expected to come on-line at a rate of four new wells in May, four in August, four in September, two in October, and six in November 2009.

Madden Deep Unit. During the quarter ended March 31, 2009, our average daily net production at the Madden Deep Unit increased 93% to 388 Mcfe, as compared to 201 Mcfe in the quarter ending March 31, 2008. The sour gas plant experienced operational issues during the first quarter of 2008, which resulted in lower production. The sour gas plant was fully operational during the first quarter of 2009.

• Oil and Gas Sales

During the quarter ended March 31, 2009, net oil and gas sales increased 68% to $10,500, as compared to $6,251 during the first quarter of 2008. Total revenue increased due to the higher production volumes discussed above, but was negatively impacted by lower realized average gas prices. During the quarter ended March 31, 2009, the average CIG price decreased 60% as compared to the same prior-year period. In comparison, our average gas price received decreased 12%, to $5.90 from $6.69 for the same period. The overall average decrease in price that we experienced was less than the average CIG price decrease due primarily to the hedging instruments we had in place during the period. See additional comments in “Contracted Volumes” below.

• Cash Flow from Operations

During the quarter ended March 31, 2009, we generated cash flow from operations of $6,935, as compared to cash flow of $2,463 in the quarter ended March 31, 2008. The increase was primarily the result of increased production.

OVERVIEW OF FINANCIAL CONDITION AND LIQUIDITY

Liquidity and Capital Resources

We believe that we have sufficient liquidity and capital resources to continue our long-term strategic plan, including our 2009 capital program (see Capital Requirements below). We intend to use capital resources made available from future operating cash flow and through our $75 million credit facility ($45 million borrowing base, including a $5 million term loan) to fund this activity. We also may consider additional offerings of securities. Although we believe that we would be able to secure additional financing if required, we can provide no assurance that we will be able to do so or what the terms of any additional financing would be.

Information about our financial position is presented in the following table (amounts in thousands, except ratios):

	March 31,			December 31,
	2009			2008
Financial Position Summary
Cash and cash equivalents	$	2,171		$	—
Working capital	$	3,591		$	(6,314	)
Balance outstanding on credit facility	$	42,500		$	24,639
Stockholders’ equity	$	54,687		$	54,903
Ratios
Debt to total capital ratio		31.4	%		21.0	%
Total debt to equity ratio		77.7	%		44.9	%

During the quarter ended March 31, 2009, our working capital increased to $3,591 compared to negative working capital of $(6,314) at December 31, 2008. The increased working capital is primarily the result of a $27,712 decrease in accounts payable due to payments we made to vendors in the first quarter of 2009 related to drilling costs incurred in the fourth quarter of 2009. This was partially offset by an $11,949 decrease in our accounts receivable balance and a $3,123 decrease in current price risk management assets since December 31, 2008. The decrease in the accounts receivable balance was due to cash receipts from our joint interest partners at the Catalina Unit for their respective working interest percentage of costs incurred as part of the 2008 drilling program.

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Cash flow activities

The table below summarizes our cash flows for the quarters ended March 31, 2009 and 2008, respectively:

	Quarter ended March 31,
	2009			2008
Cash provided by (used in):
Operating Activities	$	6,935		$	2,463
Investing Activities		(21,546	)		(11,003	)
Financing Activities		16,782			8,592
Net change in cash	$	2,171		$	52

During the quarter ended March 31, 2009, net cash provided by operating activities was $6,935 compared to $2,463 in the same prior-year period. During the quarter ended March 31, 2009, the primary sources of cash were $1,007 of net income, which was net of non-cash charges of $4,406 related to depreciation, depletion, and amortization expenses (“DD&A”) and accretion expense, a non-cash loss on the change in fair value of our derivatives of $4,066 and non-cash stock-based compensation expense of $468. In addition, we had a decrease in accounts receivable from operations of $11,949. These changes were offset partially by a decrease of $15,089 in accounts payable and accrued expenses related to operations and an increase of $631 in deferred taxes.

During the quarter ended March 31, 2009, net cash used in investing activities was $21,546, as compared to $11,003 in the same prior-year period. During the first quarter of 2009, our capital expenditures were primarily related to the completion of the 2008 drilling program at our operated properties in the Catalina Unit as well as our share of costs for non-operated development wells in the Atlantic Rim and Pinedale Anticline. We also had cash outflows of $102 related to the proposed merger of Petrosearch Energy Corp (“Petrosearch”). The Company entered into a definitive agreement to merge with Petrosearch on March 30, 2009. The proposed merger is structured as an all-stock transaction, subject to closing adjustments, and requires approval by the stockholders of Petrosearch. Refer to Note 13 in the Notes to the Consolidated Financial Statements for additional details regarding the potential Petrosearch merger.

During the quarter ended March 31, 2009, net cash provided by financing activities increased to $16,782, as compared to $8,592 in the same prior-year period. The net cash provided by financing activities was higher in the first quarter of 2009, as compared to the first quarter of 2008, due to higher draws on our credit facility to fund the 2008 drilling activity incurred in the fourth quarter of 2008. This was partially offset by the first quarter dividend payment totaling $931. Dividends are expected to be paid on a quarterly basis on the Series A Preferred Stock in the future at a rate of $931 per quarter.

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.

From time to time, we enter into contracts that might be construed as off-balance sheet obligations but are normal in the day-to-day course of business in the oil and gas industry. Those contracts are the forward sales contracts discussed in “Contracted Volumes” below. We do not believe we will be affected by these contracts materially differently than other similar companies in the energy industry.

Line of Credit

Effective February 26, 2009, the Company renegotiated its $50 million revolving line of credit into a $75 million credit facility collateralized by its oil and gas producing properties and other assets, and the borrowing base increased to $45 million from $35 million. Under the modified agreement, $5 million of the $45 million borrowing base represents a term loan, which if drawn upon, becomes due July 31, 2009, and the remaining $40 million of available borrowing base will be a revolving line of credit. Any outstanding balance on the revolving line of credit matures on July 31, 2010. The interest rate on the new credit facility will vary based on prevailing market rates and our level of outstanding borrowings, with a minimum floor rate of 4.5%.

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As of March 31, 2009, the outstanding balance on our credit facility was $42.5 million ($38.75 million on the revolving line of credit and $3.75 million on the term loan). The interest rate, calculated in accordance with the agreement, was 6.0% on the revolving line of credit and 6.75% on the term loan. This compared to an interest rate of 4.125% at March 31, 2008.

We are subject to certain financial and non-financial covenants with respect to the above credit facility, including a requirement to maintain a current ratio, plus the line of credit availability, of at least 1.0 to 1.0 beginning June 30, 2009, and a ratio of earnings before interest, taxes, depreciation, depletion, and amortization (“EBITDA”), to interest, plus dividends of 1.5 to 1.0. As of March 31, 2008, we were in compliance with all such covenants. Management also believes that it is probable that we will be able to meet the current ratio covenant at June 30, 2009. Should any of the covenants with respect to this credit facility be violated, and if we were 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.

For the quarters ended March 31, 2009 and 2008, we recognized interest expense of $0 and $0, respectively, on the credit facility. We capitalized interest costs of $300 and $106 for the quarters ended March 31, 2009 and 2008, respectively.

Capital Requirements

Our net capital expenditures for 2009 are expected to be approximately $10-$20 million for production enhancement projects in the Catalina, Sun Dog and Doty Mountain Units and continued participation in the development drilling at the Pinedale Anticline. The 2009 budget does not include the impact of any potential future exploration projects, or ongoing exploration or development activities, or potential acquisitions, including Petrosearch. We believe that the amounts available under our $75 million credit facility ($40 million borrowing base, plus $5 term loan), and net cash provided by operating activities, will provide us with sufficient funds to meet future financial covenants, develop new reserves, maintain our current facilities, and complete our 2009 capital expenditure program. We also may consider offerings of securities to raise additional capital.

Contractual Obligations

The impact that our contractual obligations as of March 31, 2009 are expected to have on our liquidity and cash flows in future periods is:

	Payments due by period
			One year		2 – 3		4 – 5		More than
	Total		or less		Years		Years		5 Years
Credit facility (a)	$	42,500	$	3,750	$	38,750	$	—	$	—
Interest on line of credit (b)		3,209		2,421		788		—		—
Capital lease commitments		2,070		753		1,317		—		—
Operating lease commitments		7,029		1,557		3,138		2,334		—
Total contractual cash commitments	$	54,808	$	8,481	$	43,993	$	2,334	$	—

(a)	The amount listed reflects the balance outstanding as of March 31, 2009. Any balance outstanding on our revolving line of credit at July 31, 2010, will be due at that time.
(b)	Assumes the interest rate on our credit facility is consistent with that of March 31, 2009.

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RESULTS OF OPERATIONS

Quarter ended March 31, 2009 compared to the quarter ended March 31, 2008

Oil and gas sales volume and price comparisons

	Quarter Ended March 31,								Percent			Percent
	2009				2008				Volume			Price
	Volume		Average Price		Volume		Average Price		Change			Change
Product:
Gas (Mcf)		2,234,415	$	5.90		865,988	$	6.69		158	%		-12	%
Oil (Bbls)		7,696	$	30.68		5,464	$	83.34		41	%		-63	%
Mcfe		2,280,591	$	5.89		898,772	$	6.96		154	%		-15	%

Our average gas price realized for the quarter ended March 31, 2009 is calculated by summing 1) production revenue received from third parties for sale of our gas, which is included in the oil and gas sales line item on the consolidated statement of income 2) settlement of our cash flow hedges included within oil and gas sales on the consolidated statement of income and 3) realized gain/loss on our economic hedges, which is included in our price risk management activities line on the consolidated statement of income, totaling $2,926 and $0, for the quarters ended March 31, 2009 and 2008, respectively. This amount is divided by the total Mcfe volume for the period.

For the quarter ended March 31, 2009, total net production increased 154% to 2,281 MMcfe, as compared to the quarter ended March 31, 2008. The increase in volumes was due largely to the addition of production wells at the Atlantic Rim and Pinedale Anticline, offset somewhat by the decrease of our working interest in the Catalina Unit. As a result of the 2008 drilling program, the Catalina Unit participating area expanded, and our working interest decreased from 73.84% to 68.35%. Our interest will continue to change as the Unit expands further.

During the quarter ended March 31, 2009, average daily net production at the Atlantic Rim increased 241% to 17,797 Mcfe, as compared to 5,220 Mcfe during the same prior-year period, largely resulting from the addition of 43 new wells which were on-line at our Catalina Unit properties during the period. Twenty-three of the 43 wells were drilled during the 2007 drilling program and came on-line in the second quarter of 2008, and 20 wells that were drilled during the 2008 drilling program came on-line during the fourth quarter of 2008 and first quarter of 2009. Average daily net production at our Catalina Unit increased 252% to 16,583 Mcfe, as compared to 4,715 Mcfe during the first quarter of 2008. Average daily production, net to our interest, at the Sun Dog and Doty Mountain units increased 140% to 1,214 Mcfe, as compared to average daily production of 505 during the same prior-year period. The increase was due to the addition of 109 wells at the Sun Dog Unit’s from the 2007 and 2008 drilling programs, and nine new wells at the Doty Mountain Unit from the 2008 drilling program.

Average daily production in the Pinedale Anticline increased 83% during the quarter ended March 31, 2009, to 6,148 Mcfe, as compared to 3,361 Mcfe in the same prior-year period. Twenty-two new wells were brought online during the first nine months of 2008, resulting in the increased production. The operator at the Mesa Units has informed us that it is in process of drilling up to 20 additional wells, which are expected to come on-line at a rate of four wells in May, four wells in August, four wells in September, two wells in October, and six wells in November 2009.

During the quarter ended March 31, 2009, the average daily production at the Madden Unit was 388 Mcfe compared to 201 Mcfe in the same prior-year period. The sour gas plant experienced significant operational issues during the first quarter of 2008, which limited the output of natural gas. The sour gas plant was fully operational during the first quarter of 2009.

For the quarter ended March 31, 2009, oil and gas revenue increased 68% to $10,500, as compared to the same prior-year period. This increase was primarily volume driven, due to increased production at each of our major fields, as discussed above. The increase in production volumes was partially offset by a decrease in our average gas price realized. During the quarter ended March 31, 2009, our average gas price realized decreased 12%, to $5.90 from $6.69, as compared to a decrease of 60% in the average CIG index price. Our realized average price did not decrease consistent with the CIG index prices due to the hedging instruments in place during the quarter. See additional comments under “Contracted Volumes” below.

Transportation and gathering revenue

During the quarter ended March 31, 2009, transportation and gathering revenue increased 336% to $1,587 from $364. The Company receives 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 increase in revenue is due to an increase in the fee charged to third parties and higher production volumes at the Catalina Unit discussed above.

Price risk management activities

We recorded a net loss on our derivative contracts that did not qualify for cash flow hedge accounting of $1,140 for the quarter ended March 31, 2009, as compared to a gain of $652 for the quarter ended March 31, 2008. This amount consists of an unrealized loss of $4,066, which represents a change in the fair value of our mark-to-market derivative instruments at March 31, 2009, and a net realized gain of $2,926 related to the settlements of some of our economic hedges.

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Oil and gas production expenses, depreciation, depletion and amortization

	Quarter Ended March 31,
	2009			2008
	(in dollars per mcfe)
Average price	$	5.89		$	6.96
Production costs		0.83			1.14
Production taxes		0.39			0.89
Depletion and amortization		1.88			1.03
Total operating costs		3.10			3.06
Gross margin	$	2.79		$	3.90
Gross margin percentage		47	%		56	%

During the quarter ended March 31, 2009, well production costs increased 98% to $2,020, as compared to $1,021 during the same prior-year period, and production costs in dollars per Mcfe decreased 27%, or $0.31 to $0.83, as compared to the same prior-year period. The increase in total production costs is primarily due to the increase in the number of operated wells at the Catalina, Sun Dog and Doty Mountain Units. The decrease in well production costs on a per Mcfe basis is largely attributed to operating efficiencies we continue to realize as our production volumes increase, particularly at the Company-operated Catalina Unit.

Depreciation, depletion, and amortization (“DD&A”) for the quarter ended March 31, 2009 increased 332% to $4,382, as compared to $1,014 in the same prior-year period, and depletion and amortization related to producing assets increased 364% to $4,280, as compared to $922 in the same prior-year period. The increase was largely due to the higher capital balances at the Catalina, Sun Dog, Doty Mountain and Mesa Units resulting from the 2008 drilling program, and increased production levels. Our DD&A expense at the Catalina Unit continues to run especially high, as the engineering estimates of proved developed reserves on these coal-bed methane wells does not reflect what we believe to be the true economic life of the wells. This results in higher DD&A expense at the beginning of the well’s productive life. Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased 83%, or $0.85, to $1.88, as compared to the same prior-year period.

Pipeline operating costs

During the quarter ended March 31, 2009, pipeline operating costs increased to $295 from $83. The increase is due to the expansion of the Catalina Unit and related transportation assets, and compressor rental costs. During the fourth quarter of 2008, the Company sold back certain compressor equipment to the original vendor and will lease the equipment going forward. Certain of these leases are accounted for as operating leases with the rental expense being recorded as pipeline operating costs.

General and administrative

General and administrative expenses increased 84% to $1,674 for the quarter ended March 31, 2009, as compared to $908 for the quarter ended March 31, 2008. The increase was primarily due to higher stock-based compensation expense of $370 due to additional grants to employees and outside directors, additional salary and salary-related expenses of approximately $90 primarily associated with headcount additions in the second, third and fourth quarters of 2008, and salary increases, and $259 of expenses related to the proposed acquisition of Petrosearch Energy Corporation.

Income taxes

During the quarter ended March 31, 2009, we recorded income tax expense of $631 compared to income tax expense of $1,082 during the same prior-year period. Our effective tax rate for the quarter ended March 31, 2009 was 38.5% compared to 36.7% for the first quarter of 2008. The rate is higher for the 2009 period due to permanent income tax differences related to stock option expense in 2009. 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 2009 at an expected federal and state rate of approximately 35.0%.

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CONTRACTED VOLUMES

Changes in the market price of oil and natural gas can significantly affect our profitability and cash flow. We have a Company hedging policy in place to mitigate exposures to oil and gas production cash-flow risk caused by downward fluctuations in commodity prices. At March 31, 2009, we had derivative instruments in effect for approximately 67% of our total daily net production. At March 31, 2009, all of our outstanding derivative instruments are indexed to the Colorado Interstate Gas (“CIG”) index.

Our outstanding forward sales contracts as of March 31, 2009 are summarized below (volume and daily production are expressed in Mcf):

FORWARD SALES CONTRACTS

	Remaining
	Contractual		Daily
Property	Volume		Production		Term		Price
Catalina		61,000		1,000		06/07-05/09	$	5.47
		91,000		1,000		07/07-06/09	$	5.84
		182,000		2,000		07/07-06/09	$	5.69
		214,000		1,000		11/07-10/09	$	5.66
Atlantic Rim		122,000		1,000		08/07-07/09	$	6.15
Pinedale Anticline		91,000		1,000		07/07-06/09	$	6.41
Company Total		761,000

The Company also has entered into various other derivative instruments to protect prices on future production. The terms of our other hedging instruments are summarized as follows (volume and daily production are expressed in Mcf):

	Remaining
	Contractual		Daily
Type of Contract	Volume		Production		Term		Price
Fixed Price Swap		2,200,000		8,000		1/09-12/09	$	7.34
Fixed Price Swap		4,380,000		12,000		1/10-12/10	$	4.30
Fixed Price Swap		2,920,000		8,000		1/11-12/11	$	7.07
Total		9,500,000

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, 2008, 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 quarter ended March 31, 2009, our income before income taxes would have changed by $211 for each $0.50 change per Mcf in natural gas prices and $7 for each $1.00 change per Bbl in crude oil prices.

We have entered into natural gas derivative contracts to manage our exposure to natural gas price volatility. Our derivative instruments include both fixed price delivery contracts for a portion of the production from the Atlantic Rim and the Pinedale Anticline as well as fixed price swaps, allowing us to effectively “lock in” a portion of our future production of natural gas at prices that we considered favorable to Double Eagle at the time we entered into the contract. At March 31, 2009, we had derivative contracts in effect for approximately 67% of our total daily net production. These derivative instruments which have differing expiration dates, are summarized in the table presented above under Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contracted Volumes.”

Interest Rate Risks

At March 31, 2009 we had a total of $42,500 outstanding under our $75 million credit facility. The borrowing base of $45 million in total consists of a $40 million borrowing base related to the revolving line of credit and a $5 million term loan. At March 31, 2009, we had $38,750 outstanding under our revolving line of credit and $3,750 million outstanding on our term loan. 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 minimum interest rate is 4.5%. As the interest rate is variable and reflective of current market conditions, the carrying value approximates the fair value. Assuming no change in the amount outstanding at March 31, 2009, the annual impact on interest expense for every 1.0% change in the average interest rate would be approximately $425 before taxes. As of March 31, 2009, the interest rate on the line of credit, calculated in accordance with the agreement, was 6.75% on the term loan and 6.0% on the revolving line of credit.

ITEM 4. CONTROLS AND PROCEDURES

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

There has been no change in our internal control over financial reporting that occurred during the quarter ended March 31, 2009 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

Reference is made to “Notes to Consolidated Financial Statements (Unaudited)) — Commitments and Contingent Liabilities” in Part I, Item 1 of this Form 10-Q and incorporated by reference in this Part II, Item 1.

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 2008 Annual Report on Form 10-K filed with the Securities and Exchange Commission, which we incorporate by reference herein.

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ITEM 6. EXHIBITS

The following exhibits are filed as part of this report:

Exhibit			Description
	2.1		Agreement and Plan of Merger dated March 30, 2009 by and among Double Eagle Petroleum Co., DBLE Acquisition Corporation, and Petrosearch Energy Corporation and Form of Voting Agreement (incorporated by reference from Exhibit 2.1 and 2.2 of the Company’s Current Report of Form 8-K dated March 31, 2009).
	3.1	(a)	Articles of Incorporation filed with the Maryland Secretary of State on January 23, 2001 (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 filed with the Maryland Secretary of State on February 15, 2001 concerning the Articles of Incorporation (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)	Articles of Merger filed with the Maryland Secretary of State on February 15, 2001 (incorporated by reference from Exhibit 3.1(c) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).
	3.1	(d)	Certificate of Correction filed with the Maryland Secretary of State (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	(e)	Certificate of Correction to the Articles of Incorporation, filed with the Maryland Department of Assessments and Taxation on June 1, 2007 (incorporated by reference from Exhibit 3.3 of the Company’s Current Report of Form 8-K dated June 29, 2007).
	3.1	(f)	Articles of Amendment, 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	(g)	Articles Supplementary, filed with the Maryland Department of Assessments and Taxation on June 29, 2007 (incorporated by reference from Exhibit 3.2 of the Company’s Current report of Form 8-K dated June 29, 2007).
	3.1	(h)	Articles Supplementary of Junior Participating Preferred Stock, Series B, 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).
	3.2	(a)	Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Annual Report on Form 10-KSB, filed for the year ended August 31, 2001).
	3.2	(b)	Bylaws of the Company, as amended and restated on March 14, 2007 (incorporated by reference from Exhibit 3.2 of the Company’s Current report on Form 8-K, filed on March 14, 2007).
	3.2	(c)	Second Amendment and Restated Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Current report on Form 8-K dated 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)	Shareholder Rights Agreement, dated as of August 24, 2007 (incorporated herein by reference to the Company’s Current report on Form 8-A filed on August 24, 2007).

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Exhibit			Description
	4.1	(c)	Articles Supplementary, filed with the Maryland Department of Assessments and Taxation on June 29, 2007 (incorporated by reference from Exhibit 3.2 of the Company’s Current report on Form 8-K dated June 29, 2007).
	4.1	(d)	Articles Supplementary of Junior Participating Preferred Stock, Series B, 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).
	10.1		Credit Agreement dated February 26, 2009 between Double Eagle Petroleum Co. and Bank of Oklahoma, N.A. et.al; Promissory Term Note dated February 26, 2009 between Double Eagle Petroleum Co. and Bank of Oklahoma N.A.; and Revolving Notes dated February 26, 2009 between Double Eagle Petroleum Co. and Bank of Oklahoma, N.A. et.al; (incorporated by reference from Exhibit 10.1, 10.2, and 10.3 of the Company’s Current report of Form 8-K dated March 3, 2009).
	31.1		Certification of Chief Executive Officer (Principal Executive Officer) pursuant to Rule 13a — 14(a) and Rule 15a —14(a) of the Securities Exchange Act, as amended.
	31.2		Certification of Chief Financial Officer (Principal Accounting Officer) pursuant to Rule 13a — 14(a) and Rule 15a — 14(a) of the Securities Exchange Act, as amended.
	32		Certification of Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Accounting Officer) pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes — Oxley Act of 2002.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	DOUBLE EAGLE PETROLEUM CO. (Registrant)
Date: May 7, 2009	By:	/s/ Richard D. Dole
		Richard D. Dole
		Chief Executive Officer (Principal Executive Officer)
Date: May 7, 2009	By:	/s/ Kurtis S. Hooley
		Kurtis S. Hooley
		Chief Financial Officer (Principal Accounting Officer)

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EXHIBIT INDEX

Exhibit Number			Description
	2.1		Agreement and Plan of Merger dated March 30, 2009 by and among Double Eagle Petroleum Co., DBLE Acquisition Corporation, and Petrosearch Energy Corporation and Form of Voting Agreement (incorporated by reference from Exhibit 2.1 and 2.2 of the Company’s Current Report of Form 8-K dated March 31, 2009).
	3.1	(a)	Articles of Incorporation filed with the Maryland Secretary of State on January 23, 2001 (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 filed with the Maryland Secretary of State on February 15, 2001 concerning the Articles of Incorporation (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)	Articles of Merger filed with the Maryland Secretary of State on February 15, 2001 (incorporated by reference from Exhibit 3.1(c) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).
	3.1	(d)	Certificate of Correction filed with the Maryland Secretary of State (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	(e)	Certificate of Correction to the Articles of Incorporation, filed with the Maryland Department of Assessments and Taxation on June 1, 2007 (incorporated by reference from Exhibit 3.3 of the Company’s Current Report of Form 8-K dated June 29, 2007).
	3.1	(f)	Articles of Amendment, 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	(g)	Articles Supplementary, filed with the Maryland Department of Assessments and Taxation on June 29, 2007 (incorporated by reference from Exhibit 3.2 of the Company’s Current report of Form 8-K dated June 29, 2007).
	3.1	(h)	Articles Supplementary of Junior Participating Preferred Stock, Series B, 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).
	3.2	(a)	Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Annual Report on Form 10-KSB, filed for the year ended August 31, 2001).
	3.2	(b)	Bylaws of the Company, as amended and restated on March 14, 2007 (incorporated by reference from Exhibit 3.2 of the Company’s Current report on Form 8-K, filed on March 14, 2007).
	3.2	(c)	Second Amendment and Restated Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Current report on Form 8-K dated June 11, 2007).

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Exhibit Number			Description
	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)	Shareholder Rights Agreement, dated as of August 24, 2007 (incorporated herein by reference to the Company’s Current report on Form 8-A filed on August 24, 2007)
	4.1	(c)	Articles Supplementary, filed with the Maryland Department of Assessments and Taxation on June 29, 2007 (incorporated by reference from Exhibit 3.2 of the Company’s Current report on Form 8-K dated June 29, 2007).
	4.1	(d)	Articles Supplementary of Junior Participating Preferred Stock, Series B, 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).
	10.1		Credit Agreement dated February 26, 2009 between Double Eagle Petroleum Co. and Bank of Oklahoma, N.A. et.al; Promissory Term Note dated February 26, 2009 between Double Eagle Petroleum Co. and Bank of Oklahoma N.A.; and Revolving Notes dated February 26, 2009 between Double Eagle Petroleum Co. and Bank of Oklahoma, N.A. et.al; (incorporated by reference from Exhibit 10.1, 10.2, and 10.3 of the Company’s Current report of Form 8-K dated March 3, 2009).
	31.1		Certification of Chief Executive Officer (Principal Executive Officer) pursuant to Rule 13a — 14(a) and Rule 15a — 14(a) of the Securities Exchange Act, as amended.
	31.2		Certification of Chief Financial Officer (Principal Accounting Officer) pursuant to Rule 13a — 14(a) and Rule 15a — 14(a) of the Securities Exchange Act, as amended.
	32		Certification of Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Accounting Officer) pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes — Oxley Act of 2002.

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