Escalera Resources (ESCR) 10-Q 2009 Q3 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 September 30, 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
(State or other jurisdiction of
incorporation or organization) 83-0214692
(I.R.S. employer
identification no.)

1675 Broadway, Suite 2200, Denver, Colorado 80202
(Address of principal executive offices) (Zip code)

303-794-8445
(Registrant’s telephone number, including area code)

None
(Former name, former address, and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. 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 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 October 15, 2009
Common stock, $.10 par value	11,046,455

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

	Page #
PART I. Financial Information:
Item 1. Financial Statements
Consolidated Balance Sheets as of September 30, 2009 (Unaudited) and December 31, 2008		3
Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2009 and 2008 (Unaudited)		4
Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2009 and 2008 (Unaudited)		5
Notes to Consolidated Financial Statements (Unaudited)		6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		17
Item 3. Quantitative and Qualitative Disclosures About Market Risk		28
Item 4. Controls and Procedures		29
PART II. Other Information:
Item 1. Legal Proceedings		29
Item 1A. Risk Factors		29
Item 6. Exhibits		29
Signatures		31
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)

	September 30,			December 31,
	2009			2008
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	3,075		$	—
Cash held in escrow		610			605
Accounts receivable		7,330			21,381
Assets from price risk management		2,174			14,290
Other current assets		3,467			3,513
Total current assets		16,656			39,789
Oil and gas properties and equipment, successful efforts method:
Developed properties		160,368			133,516
Wells in progress		8,797			18,518
Gas transportation pipeline		5,465			5,465
Undeveloped properties		2,838			2,907
Corporate and other assets		1,914			1,920
		179,382			162,326
Less accumulated depreciation, depletion and amortization		(48,898	)		(35,253	)
Net properties and equipment		130,484			127,073
Assets from price risk management		2,599			5,029
Other assets		134			98
TOTAL ASSETS	$	149,873		$	171,989
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	5,065		$	35,488
Accrued expenses		5,222			6,794
Liabilities from price risk management		3,833			—
Line of credit — current		34,000			—
Accrued production taxes		3,843			3,017
Capital lease obligations, current portion		530			522
Other current liabilities		308			282
Total current liabilities		52,801			46,103
Line of credit		—			24,639
Asset retirement obligation		4,866			4,208
Liabilities from price risk management		469			—
Deferred tax liability		2,951			2,470
Capital lease obligations, long-term portion		679			1,078
Other long-term liabilities		359			616
Total liabilities		62,125			79,114
Preferred stock, $0.10 par value; 10,000,000 shares authorized; 1,610,000 shares issued and outstanding as of September 30, 2009 and December 31, 2008		37,972			37,972
Stockholders’ equity:
Common stock, $0.10 par value; 50,000,000 shares authorized; 11,035,972 and 9,192,356 shares issued and outstanding as of September 30, 2009 and December 31, 2008, respectively		1,104			919
Additional paid-in capital		43,250			35,122
Retained earnings		561			2,172
Accumulated other comprehensive income		4,861			16,690
Total stockholders’ equity		49,776			54,903
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	149,873		$	171,989

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 September 30,						Nine months ended September 30,
	2009			2008			2009			2008
Revenues
Oil and gas sales	$	9,669		$	11,662		$	30,661		$	29,439
Transportation revenue		1,489			1,283			4,659			2,370
Price risk management activities		(378	)		1,020			(3,670	)		3,042
Other income, net		86			41			296			258
Total revenues		10,866			14,006			31,946			35,109
Costs and expenses
Production costs		1,934			1,722			5,535			4,814
Production taxes		879			1,419			2,521			3,753
Exploration expenses including dry hole costs		38			391			93			922
Pipeline operating costs		1,032			896			2,686			1,643
General and administrative		1,579			1,652			4,680			3,861
Impairment of properties and surrendered leases		82			—			82			—
Depreciation, depletion and amortization		4,681			3,462			13,778			7,456
Total costs and expenses		10,225			9,542			29,375			22,449
Income from operations		641			4,464			2,571			12,660
Interest expense, net		(265	)		—			(909	)		(64	)
Income before income taxes		376			4,464			1,662			12,596
Benefit (provision) for deferred income taxes		40			(1,557	)		(481	)		(4,554	)
NET INCOME	$	416		$	2,907		$	1,181		$	8,042
Preferred stock dividends		930			930			2,792			2,792
Net income (loss) attributable to common stock	$	(514	)	$	1,977		$	(1,611	)	$	5,250
Net income (loss) per common share:
Basic	$	(0.05	)	$	0.22		$	(0.17	)	$	0.57
Diluted	$	(0.05	)	$	0.22		$	(0.17	)	$	0.57
Weighted average shares outstanding:
Basic		10,315,270			9,167,977			9,587,711			9,156,079
Diluted		10,315,270			9,167,977			9,587,711			9,156,215

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)

	Nine months ended September 30,
	2009			2008
Cash flows from operating activities:
Net income	$	1,181		$	8,042
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion, amortization and accretion of asset retirement obligation		13,855			7,998
Abandonment of non-producing properties		82			188
Provision for deferred taxes		481			4,554
Employee stock option expense		945			464
Directors fees paid in stock		126			90
Change in fair value of derivative contracts		7,018			(2,384	)
Revenue from carried interest		(1,351	)		—
Gain on sale of producing property		(211	)		(66	)
Changes in current assets and liabilities:
Decrease (Increase) in deposit held in escrow		(5	)		104
Decrease (Increase) in accounts receivable		15,219			(11,832	)
Decrease (Increase) in other current assets		(131	)		(1,361	)
Increase (Decrease) in accounts payable		(15,356	)		6,610
Increase (Decrease) in accrued expenses		(3,205	)		829
Increase in accrued production taxes		826			1,864
NET CASH PROVIDED BY OPERATING ACTIVITIES		19,474			15,100
Cash flows from investing activities:
Sale of producing property and equipment		—			747
Additions of producing properties and equipment, net		(29,640	)		(26,904	)
Additions of corporate and non-producing properties		(140	)		(392	)
Net cash received from Petrosearch acquisition		7,733			—
Payment of Petrosearch transaction costs		(513	)		—
NET CASH USED IN INVESTING ACTIVITIES		(22,560	)		(26,549	)
Cash flows from financing activities:
Principal payments on capital lease obligations		(391	)		—
Exercise of stock options		—			279
Issuance of stock under Company stock plans		6			—
Tax withholdings related to net share settlement of restricted stock awards		(23	)		—
Preferred stock dividends		(2,792	)		(2,792	)
Net borrowings (repayments) on credit facility		9,361			14,521
NET CASH PROVIDED BY FINANCING ACTIVITIES		6,161			12,008
Change in cash and cash equivalents		3,075			559
Cash and cash equivalents at beginning of period		—			125
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	3,075		$	684
Supplemental disclosure of cash and non-cash transactions:
Cash paid for interest	$	1,761		$	390
Interest capitalized	$	903		$	515
Adjustment to joint interest partners’ well costs associated with unitization of Catalina	$	1,162		$	2,447
Additions to developed properties included in current liabilities	$	4,962		$	16,511
Share-based compensation expense	$	1,071		$	554
Issuance of common stock in connection with the acquisition of Petrosearch	$	7,260		$	—
Fair value of asset received in connection with the acquisition of Petrosearch	$	9,151		$	—
Fair value of liabilities assumed in connection with the acquisition of Petrosearch	$	1,018		$	—

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 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 June 2009, the Financial Accounting Standards Board (“FASB”) issued ASC 105 (formerly SFAS 168),The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles(“ASC 105”). ASC 105 has become the source of authoritative U.S. GAAP recognized by the FASB to be applied by nongovernment entities. It also modifies the GAAP hierarchy to include only two levels of GAAP; authoritative and non-authoritative. The Company adopted ASC 105 effective July 1, 2009. Pursuant to the provisions of ASC 105, the Company has updated references to GAAP in its financial statements issued for the period ended September 30, 2009. The adoption of ASC 105 did not have an impact on the Company’s financial position, results of operations or cash flows.

New accounting pronouncements

In August 2009, the FASB issued Accounting Standards Update No. 2009-05 (“ASC Update 2009-05”), an update to ASC 820,Fair Value Measurements and Disclosures.This update provides amendments to reduce potential ambiguity in financial reporting when measuring the fair value of liabilities. Among other provisions, this update provides clarification that in circumstances, in which a quoted price in an active market for the identical liability is not available, a reporting entity is required to measure fair value using one or more of the valuation techniques described in ASC Update 2009-05. ASC Update 2009-05 will become effective for the Company’s annual financial statements for the year ended December 31, 2009. The adoption of ASC Update 2009-05 is not expected to have a material 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 companies can disclose their probable and possible reserves in SEC filings. 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.

6

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 $930 ($.5781 per share) on the Series A Preferred Stock for the three months ended September 30, 2009 and 2008, and $2,792 for the nine months ended September 30, 2009 and 2008.

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

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2009			2008		2009			2008
Net income (loss)	$	416		$	2,907	$	1,181		$	8,042
Preferred stock dividends		930			930		2,792			2,792
��
Income (loss) attributable to common stock	$	(514	)	$	1,977	$	(1,611	)	$	5,250
Weighted average shares:
Weighted average shares — basic		10,315,270			9,167,977		9,587,711			9,156,079
Dilution effect of stock options outstanding at the end of period		—			—		—			136
Weighted average shares — diluted		10,315,270			9,167,977		9,587,711			9,156,215
Income (loss) per common share:
Basic	$	(0.05	)	$	0.22	$	(0.17	)	$	0.57
Diluted	$	(0.05	)	$	0.22	$	(0.17	)	$	0.57

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

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2009		2008		2009		2008
Anti-dilutive shares		107,800		151,702		103,771		124,245

3. Acquisition of Petrosearch Energy Corporation

On August 6, 2009 (“Effective Closing Date”), the Company acquired 100% of the common and preferred shares of Petrosearch Energy Corporation (“Petrosearch”) in exchange for approximately 1.8 million shares of Double Eagle common stock, valued at approximately $7.3 million, and cash consideration of $873, for a total purchase price of approximately $8.1 million. Effective with the acquisition, each Petrosearch shareholder received .0433 shares of Double Eagle common stock and $0.0211 for each share of Petrosearch common stock and Petrosearch preferred stock, on an as converted basis, such shareholder held. As result of the merger, Petrosearch became a wholly-owned subsidiary of the Company. Richard Dole, who is and was, at the time of the merger, Chairman, President and Chief Executive Officer of Double Eagle and Petrosearch, will continue to serve as Chairman, President and Chief Executive Officer. The Board of Directors of Double Eagle will consist of five directors, four existing directors of Double Eagle and one future director to be designated by Petrosearch.

Petrosearch is an independent crude oil and natural gas exploration and production company, with properties in Texas and Oklahoma. Petrosearch had approximately $8,606 in cash and cash equivalents at the time of acquisition. The Company believes that the acquisition of Petrosearch will enhance the Company’s ability to finance its current operations and future developmental projects, thereby providing an opportunity to increase reserves. Petrosearch contributed revenue of $24 and earnings of $(41) for the period from August 6 to September 30, 2009.

7

The aggregate purchase price is estimated as follows:

Aggregrate value of Double Eagle common stock issued	$	7,260
Cash consideration given to Petrosearch shareholders		873
Purchase Price	$	8,133

The acquisition of Petrosearch has been accounted for under the purchase method of accounting. Under the purchase method of accounting, the purchase price is allocated to the assets acquired and liabilities assumed based on their estimated fair values. The allocation of the purchase price has been prepared based on preliminary estimates of fair values and is subject to revision

Cash and cash equivalents	$	8,606
Accounts receivables, net of allowance		5
Prepaid expense & other current assets		134
Oil and gas properties		350
Goodwill		56
Accounts payable and other current liabilities		(378	)
Asset retirement obligation		(640	)
	$	8,133

The Company has recorded a full valuation allowance against the deferred tax assets of Petrosearch. The Company is still in process of determining the fair value of the tax assets or liabilities assumed. The fair value will be reflected as soon as possible, and may result in a measurement period adjustment. Such adjustment could be material.

Of the total estimated purchase price, approximately $56 has preliminarily been allocated to goodwill. Goodwill represents the excess of the purchase price of an acquired business over the fair value of the underlying net tangible and intangible assets. Goodwill is not amortized, rather, the goodwill will be tested for impairment, at least annually, or more frequently if there is an indication of impairment. The goodwill resulting from this acquisition is not deductible for tax purposes.

Transaction costs related to the merger totaled $513, and are recorded on the statement of operations within the general and administrative expenses line on the statement of operations.

Supplemental Pro Forma Results

The following pro forma financial information represents the combined results for the Company and Petrosearch for the nine months ended September 30, 2009 and 2008 as if the acquisition had occurred on January 1, 2009 and January 1, 2008. The pro forma financial information includes adjustments to reflect Petrosearch as if its crude oil and natural gas properties had been accounted for under the successful efforts method of accounting, not the full cost method of accounting. The pro forma financial information is not intended to represent or be indicative of the consolidated results of operations or financial condition of the Company that would have been reported had the acquisition been completed as of the dates presented, and should not be taken as representative of the future consolidated results of operations or financial condition of the Company.

	For the nine months ended September 30,
	2009			2008
Net revenues	$	32,014		$	36,467
Operating income (loss)	$	(1,200	)	$	8,567
Net income (loss) attributable to common shareholders	$	(4,071	)	$	11,242
Basic and diluted net income (loss) per share	$	(0.37	)	$	1.03

8

4. 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 sales, 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, 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.

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 (“AOCI”) and is subsequently reclassified into the oil and gas sales line on the consolidated statement of operations as the contracts settle. As of September 30, 2009, the Company expects approximately $2,261 of unrealized gains, included in its AOCI to be reclassified into earnings 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 balance sheet and changes in fair value are recognized in the price risk management activities line on the consolidated statement of operations currently. 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 September 30, 2009:

	Contract Settlement Date
	2009		2010		2011
Natural gas forward purchase contracts:
Volume (MMcf)		1,382		8,030		5,650

9

The table below contains a summary of all the Company’s derivative positions reported on the consolidated balance sheet as of September 30, 2009, 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	$	2,174
	Liabilities from price risk management — current		87
	Assets from price risk management — long term		2,599
	Liabilities from price risk management — long term		1,472
Total		$	6,332

Derivatives not designated as hedging
instruments under ASC 815	Balance Sheet Location	Fair Value
Liabilities
Commodity derivatives	Liabilities from price risk management — current	$	(3,920	)
	Liabilities from price risk management — long term		(1,941	)
Total		$	(5,861	)

The before-tax effect of derivative instruments in cash flow hedging relationships on the consolidated statement of operations for the three and nine months ended September 30, 2009 was as follows:

	Gain (Loss) Recognized in
	OCI1 on Derivative					Gain Reclassified from
	(effective portion)					Accumulated OCI1 into Income
	Three months			Nine months			Three months		Nine months
	ended			ended			ended		ended
	Sep-09			Sep-09		Location	Sep-09		Sep-09
Cash flow hedges:
Commodity contracts	$	(826	)	$	1,335	Oil and gas sales	$	3,754	$	13,164

Gain Recognized in Income (Effective Portion
and Amount excluded from Effectiveness Testing)
	Three months		Nine months
	ended		ended
Location	Sep-09		Sep-09
Oil and gas sales	$	—	$	—

¹ Other comprehensive income (“OCI”).

10

The before-tax effect of derivative instruments not designated as hedging instruments on the consolidated statement of operations for the three and nine months ended September 30, 2009 was as follows:

Loss Recognized in Income on Derivative
Location	Three months ended Sep-09			Nine months ended Sep-09
Price Risk Management Activites	$	(378	)	$	(3,670	)

Normal purchases and normal sales

During the three and nine months ended September 30, 2009, the Company had fixed delivery contracts for production from Sun Dog and Doty Mountain at the Atlantic Rim and the Pinedale Anticline that qualified for accounting under the normal purchases and normal sales exception. Physical delivery contracts may meet the criteria for this accounting exception 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. Under the normal purchases and normal sales accounting treatment, the Company records the revenue upon contract settlement in oil and gas sales on the consolidated statement of operations. All of the Company’s contracts that qualified for this treatment had settled at September 30, 2009.

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

5. Fair Value Measurements

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

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

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

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

The following 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 considers several factors in determining its estimate of fair value, including quoted market prices in active markets, the credit rating of each counterparty, and the Company’s own credit rating.

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

At September 30, 2009, the types of derivative instruments utilized by the Company included fixed price delivery contracts 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.

11

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.

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	$	—	$	4,773	$	—	$	4,773
Total assets at fair value	$	—	$	4,773	$	—	$	4,773
Liabilities
Derivative instruments	$	—	$	4,302	$	—	$	4,302
Asset retirement obligation	$	—	$	—		4,866	$	4,866
Total liabilities at fair value	$	—	$	4,302	$	4,866	$	9,168

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

December 31, 2008 asset retirement obligation	$	4,208
Additional liabilites assumed through acquisition of Petrosearch	$	640
Liabilities incurred		13
Liabilities settled		(256	)
Accretion expense, included in earnings (1)		77
Change in ownership interest		184
September 30, 2009 asset retirement obligation	$	4,866

(1) The accretion expense recorded during the period is recorded in the production costs line item on the consolidated statement of operations and totaled $27 and $77 in the three and nine months ended September 30, 2009, respectively.

Concentration of Credit Risk

Financial instruments which potentially subject the Company to credit risk consist of the Company’s accounts receivable and our derivative financial instruments. Substantially all of the Company’s receivables are within the oil and gas industry, including those from a 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.

At September 30, 2009 the Company’s derivative financial instruments were held with two counterparties. The Company continually reviews the credit-worthiness of its counterparties. The Company’s derivative instruments are part of master netting agreements, which reduces credit risk by permitting the Company to net settle for transactions with the same counterparty.

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6. 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 three months ended September 30, 2009 and 2008 or in the nine months ended September 30, 2009 and 2008.

7. Stock-Based Compensation

The Company recognized stock-based compensation expense of $301 and $1,071 during the three and nine months ended September 30, 2009, respectively, as compared to $314 and $554 in the three and nine months ended September 30, 2008, respectively.

Compensation expense related to stock options is calculated using the Black Scholes valuation model. Expected volatilities are based on the historical volatility of Double Eagle’s 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.

A summary of stock option activity under the Company’s various stock option plans as of September 30, 2009 and changes during the nine months ended September 30, 2009 are presented below:

						Weighted-
						Average
				Weighted-		Remaining
				Average		Contractual		Aggregate
				Exercise		Term (in		Intrinsic
	Shares			Price		years)		Value
Options:
Outstanding at January 1, 2009		626,897		$	15.68		5.1
Granted		50,500		$	7.79
Exercised		—
Cancelled/expired		(29,500	)	$	15.83
Outstanding at September 30, 2009		647,897		$	15.06		4.9	$	—
Exerciseable at September 30, 2009		211,179		$	16.35		3.0	$	—

The Company measures the fair value of the restricted stock awards based upon the fair market value of its common stock on the date of grant and recognizes the resulting compensation expense ratably over the associated service period, which is generally the vesting term of the stock awards. The Company recognizes these compensation costs net of a forfeiture rate and recognizes the compensation costs for only those shares expected to vest. The Company typically estimates forfeiture rates based on historical experience, while also considering the duration of the vesting term of the award.

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Nonvested restricted stock awards as of September 30, 2009 and changes during the nine months ended September 30, 2009 were as follows:

				Weighted-
				Average
				Grant Date
	Shares			Fair Value
Restricted Stock Awards:
Outstanding at January 1, 2009		94,762		$	14.70
Granted		79,500		$	4.16
Vested		(54,889	)	$	4.98
Forfeited/returned		—
Nonvested at September 30, 2009		119,373		$	12.15

As part of the acquisition of Petrosearch, the Company assumed all outstanding warrants to purchase common stock that had been issued by Petrosearch prior to the merger. At September 30, 2009, the Company had three tranches of warrants outstanding; 14,691 warrants with an exercise price of $46.19 that expire in February 2010; 10,310 warrants with an exercise price of $34.64 that expire November 2010; and 8,660 warrants with an exercise price of $21.25 that expire December 2011. The warrants have no intrinsic value at September 30, 2009.

8. Income Taxes

At September 30, 2009, the Company had a net operating loss carry forward for income tax reporting purposes of approximately $33.3 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 September 30, 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.

9. Credit Facility

The Company has a $75 million revolving line of credit collateralized by its oil and gas producing properties, with a $45 million borrowing base. Prior to July 22, 2009, the borrowing base consisted of a $5 million term loan and a $40 revolving line of credit. Effective July 22, 2009, the Company amended the credit facility to terminate the $5 million term loan and to increase the revolving line of credit from $40 million to $45 million. At September 30, 2009, the balance outstanding on the revolving line of credit was $34 million. Any balance outstanding on the revolving line of credit matures July 31, 2010.

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.

Borrowings under the revolving line of credit 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 the level of funds borrowed. As of September 30, 2009, the interest rate on the line of credit was 4.5%. The Company recognized interest expense related to the credit facility of $216 and $0, for the three months ended September 30, 2009 and 2008, respectively, and $500 and $0 for the nine months ended September 30, 2009 and 2008, respectively. The Company capitalized interest costs of $260 and $222 for the three months ended September 30, 2009 and 2008, respectively, and $903 and $515 for the nine months ended September 30, 2009 and 2008, respectively.

Under the facility, the Company is subject to both financial and non-financial covenants. The financial covenants include maintaining a current ratio, as defined, of 1.0 to 1.0, 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 September 30, 2009, 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 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 accompanying 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, 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.

11. Comprehensive Income (Loss)

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

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2009			2008		2009			2008
Net income (loss) attributable to common stock	$	(514	)	$	1,977	$	(1,611	)	$	5,250
Change in derivative instrument fair value, net of tax benefit of $0		(826	)		15,573		1,335			9,536
Reclassification to earnings		(3,754	)		177		(13,164	)		1,298
Comprehensive income (loss)	$	(5,094	)	$	17,727	$	(13,440	)	$	16,084

The components of accumulated other comprehensive income were as follows:

	September 30,		December 31,
	2009		2008
Net change in derivative instrument fair value, net of tax benefit of $0 and $0	$	4,861	$	16,690
Total accumulated other comprehensive gain, net	$	4,861	$	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.

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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 September 30, 2009 and December 31, 2008 totaled $610 and $605, respectively.

13. 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 paid to EWM related to gas gathering is eliminated in consolidation.

14. Contingencies

Legal Proceedings

From time to time, the Company is involved in claims, proceedings and litigation, including the following:

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 (“BR”); 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.

15. Subsequent Events

The Company has evaluated subsequent events through the date of issuance, October 29, 2009, of this quarterly report on Form 10-Q, and noted no additional events that require recognition or disclosure at September 30, 2009.

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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 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 our Annual Report on Form 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;

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

• 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;

• 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;

• The ability of third-party operators in projects in which we own an interest, to continue to develop these projects;

• 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;

• 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.

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.

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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 is www.dble.com.

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 three and nine months ended September 30, 2009(Amounts in thousands of dollars, except amounts per unit of production):

• Average Daily Production

During the three months ended September 30, 2009, our total average daily net production increased 21% to 25,052 Mcfe as compared to average daily production of 20,769 Mcfe during the same prior-year period. Total average daily net production increased 63% to 25,533 in the first nine months of 2009, as compared to 15,707 Mcfe in the first nine months of 2008. The changes in production by major operating area are discussed below.

Atlantic Rim.During the three months ended September 30, 2009, average daily net production at the Atlantic Rim increased 18% to 17,585 Mcfe, as compared to 14,929 Mcfe during the three months ended September 30, 2008. This increase was primarily the result of the production from 20 new wells at the Catalina Unit from the 2008 drilling program. During the three months ended September 30, 2009, average daily net production at our Catalina Unit increased 11% to 15,391 Mcfe, as compared to 13,863 Mcfe during the same prior-year period. The Company continued to perform well workovers on certain existing wells in the Catalina Unit during the third quarter of 2009, which caused these wells to be off-line for periods of time and offset production from the new wells. Average daily production, net to our interest, at the Sun Dog and Doty Mountain units increased 106% to 2,194 Mcfe, as compared to average daily production of 1,066 Mcfe in the same period of 2008. The increase was due primarily to production from over 40 Sun Dog Unit wells which were drilled as part of the 2007 and 2008 drilling program, and increased production from the existing wells at the Doty Mountain Unit due to production enhancement projects.

Average daily net production at the Atlantic Rim increased 76% to 18,368 Mcfe in the nine months ended September 30, 2009, as compared to 10,436 Mcfe during the same prior-year period. The increase was 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 quarter 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. During the nine months ended September 30, 2009, average daily net production at our Catalina Unit increased 72% to 16,415 Mcfe, as compared to 9,543 Mcfe during the same prior-year period. Average daily production at the Sun Dog and Doty Mountain units increased 119% to 1,953 Mcfe as compared to 893 Mcfe in the nine months ended September 30, 2008.

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Pinedale Anticline. Average daily production net at the Pinedale Anticline increased 29% to 5,384 Mcfe for the three months ended September 30, 2009, as compared to 4,164 Mcfe in the same 2008 period. The increase in production is due to volume added from 16 new wells that were brought on-line in the first nine months of 2009. The operator expects to bring on one additional well for production in the fourth quarter of 2009. During the nine months ended September 30, 2009, average daily net production at the Pinedale Anticline increased 45% to 5,559 Mcfe as compared to 3,830 Mcfe in the nine months ended September 30, 2008.

Madden Deep Unit. During the three and nine months ended September 30, 2009, our average daily net production at the Madden Deep Unit was 597 Mcfe and 500 Mcfe, respectively, as compared to 423 Mcfe and 360 Mcfe in the three and nine months ended September 30, 2008, respectively. The sour gas plant experienced operational issues during the first quarter of 2008, which resulted in lower production for the nine months ended September 30, 2008. The sour gas plant was fully operational during the first nine months 2009.

• Oil and Gas Sales

During the three months ended September 30, 2009, oil and gas sales decreased 17% to $9,669, as compared to $11,662 during the same 2008 period. Although net production volumes increased at all significant properties, as discussed above, oil and gas sales were negatively impacted by lower realized average gas prices. During the three months ended September 30, 2009, the average CIG price decreased 52% as compared to the same prior-year period. In comparison, our average gas price received decreased 32%, to $4.27 from $6.27 for the same period. The overall average decrease in the gas 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.

Oil and gas sales increased 4% to $30,661 for the nine months ended September 30, 2009, as compared to $29,439 during the same prior year period. The increase in oil and gas sales was attributed to higher production volumes at each of our significant properties, as discussed above. Although production volumes increased 63% over the nine months ended September 30, 2008, our total oil and gas sales were negatively impacted by lower realized average gas prices. During the nine months ended September 30, 2009, the average CIG gas price decreased 62% as compared to the same 2008 period. In comparison, the average gas price we received decreased 29%, to $4.83 from $6.80 as compared to the same prior-year 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.

• Acquisition of Petrosearch Energy Corporation

On August 6, 2009, we completed our acquisition of Petrosearch Energy Corporation (“Petrosearch”) in exchange for 1.8 million shares of Double Eagle common stock and cash consideration of $873. Upon closing of the acquisition, Petrosearch became a wholly-owned subsidiary of the Company. Through the acquisition, we obtained approximately $8.6 million of cash, as well as oil and gas properties valued at approximately $350. We believe the acquisition has enhanced our financial position and will provide financing for our current operations and future development projects, thereby providing the potential to increase reserves.

OVERVIEW OF FINANCIAL CONDITION AND LIQUIDITY

Liquidity and Capital Resources

Our sources of liquidity and capital resources historically have been net cash provided by operating activities, funds available under our credit facilities and proceeds from offerings of equity securities. We believe that the liquidity available from these sources will meet the anticipated short and long-term requirements of the Company, including the capital requirements and contractual obligations noted below. However, we can give no assurances that these historical sources of liquidity and capital resources will be available for future development projects, and we may be required to seek additional or alternative financing sources.

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Credit Facility

At September 30, 2009, the Company had a $75 million credit facility in place, with a $45 million borrowing base, collateralized by its oil and gas producing properties and other assets. Any outstanding balance on the revolving line of credit matures on July 31, 2010, as has been classified as a current liability on the consolidated balance sheet. The interest rate on this credit facility varies based on prevailing market rates and our level of outstanding borrowings, with a minimum floor rate of 4.5%.

As of September 30, 2009, the outstanding balance on our credit facility was $34 million. The interest rate, calculated in accordance with the agreement, was 4.5%. This compared to an interest rate of 3.875% at September 30, 2008.

Under our credit facility, we are subject to certain financial and non-financial covenants. The financial covenants include maintaining a current ratio, as defined, of 1.0 to 1.0, 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. The Company was in compliance with all financial covenants at September 30, 2009. 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.

We recognized interest expense related to the credit facility of $216 and $0, for the three months ended September 30, 2009 and 2008, respectively, and $500 and $0 for the nine months ended September 30, 2009 and 2008, respectively. The Company capitalized interest costs of $260 and $222 for the three months ended September 30, 2009 and 2008, respectively, and $903 and $515 for the nine months ended September 30, 2009 and 2008, respectively

We are actively negotiating an extension of our credit facility with our current lending group. Management believes the discussions have been positive and that it is highly likely an agreement will be reached in the fourth quarter of 2009 to extend our agreement out until at least 2012. Although we expect to finalize a new agreement by the end of 2009, we can provide no assurance that we will be able to do so or what the terms of the financing will be. We also may consider additional offerings of securities.

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

	September 30,			December 31,
	2009			2008
Financial Position Summary
Cash and cash equivalents	$	3,075		$	—
Working capital	$	(36,145	)	$	(6,314	)
Balance outstanding on credit facility	$	34,000		$	24,639
Stockholders’ equity and preferred stock	$	87,578		$	92,875
Ratios
Debt to total capital ratio		28.0	%		21.0	%
Total debt to equity ratio		38.8	%		26.5	%

During the nine months ended September 30, 2009, our negative working capital balance decreased to $(36,145), as the $34,000 balance on our line of credit has been classified as current due to its maturity on July 31, 2010. Also during the nine month period, our accounts receivable balance decreased by $14,051 and the current price risk management assets decreased by $12,116. 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. The decrease in current price risk management assets is due primarily to the settlement of derivative contracts we had in place at December 31, 2008. These changes were offset somewhat by a $31,995 decrease in accounts payable and accrued expenses due to payments we made to vendors in the first quarter of 2009 related to drilling costs incurred in the fourth quarter of 2008.

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Cash flow activities

The table below summarizes our cash flows for the nine months ended September 30, 2009 and 2008, respectively:

	Nine Months Ended September 30,
	2009			2008
Cash provided by (used in):
Operating Activities	$	19,474		$	15,100
Investing Activities		(22,560	)		(26,549	)
Financing Activities		6,161			12,008
Net change in cash	$	3,075		$	559

Net cash provided by operating activities was $19,474 for the nine months ended September 30, 2009, compared to $15,100 in the same prior-year period. During the nine months ended September 30, 2009, the primary sources of cash were $1,181 of net income, which was net of non-cash charges of $13,855 related to depreciation, depletion, and amortization expenses (“DD&A”) and accretion expense, an unrealized non-cash loss on the change in fair value of our derivatives of $7,018 and non-cash stock-based compensation expense of $1,071. In addition, we had a decrease in accounts receivable from operations of $15,219 primarily related to the collection of receivables from our joint interest partners for capital expenditures at the Catalina Unit. These changes were offset partially by a decrease of $18,561 in accounts payable and accrued expenses related to operations.

During the nine months ended September 30, 2009, net cash used in investing activities totaled $22,560, as compared to $26,549 in the same prior-year period. During the first nine months 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. During the third quarter of 2009, we acquired Petrosearch in exchange for 1.8 million shares of Double Eagle common stock and cash consideration of $873. We assumed 100% of the assets and liabilities of Petrosearch, including cash and cash equivalents totaling $8,606. The net cash to the Company from this acquisition was $7,733. We also had cash outflows of $513 for transaction costs related to the acquisition. Refer to Note 3 in the Notes to the Consolidated Financial Statements for additional details regarding the Petrosearch acquisition.

During the nine months ended September 30, 2009, net cash provided by financing activities decreased to $6,161, as compared to $12,008 in the same prior-year period. Borrowings on our line of credit decreased to $9,361 during the nine months ended September 30, 2009 from $14,521 in same 2008 period, as we used the net cash received from the Petrosearch acquisition to repay a portion of the outstanding balance on our line of credit during the third quarter of 2009. The borrowings during the period were primarily used to fund the 2008 drilling activity incurred in the fourth quarter of 2008. The borrowings were partially offset in both 2009 and 2008 by dividend payments on our Series A Preferred Stock in each of the first three quarters, at a rate of approximately $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.

Capital Requirements

Our net capital expenditures for the projects in 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 did not include the impact of the Petrosearch merger, nor does it include the impact of any potential future exploration projects or other potential acquisitions. We believe that the amounts available under our credit facility 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.

21

Contractual Obligations

The expected impact that our contractual obligations as of September 30, 2009 will have on our liquidity and cash flows in future periods is:

	Payments due by period
			One year		2 - 3		4 - 5		More than 5
	Total		or less		Years		Years		Years
Credit facility (a)	$	34,000	$	34,000	$	—	$	—	$	—
Interest on credit facility (b)		1,292		1,292		—		—		—
Capital lease commitments		1,694		753		941		—		—
Operating lease commitments		6,256		1,568		3,137		1,551		—
Total contractual cash commitments	$	43,242	$	37,613	$	4,078	$	1,551	$	—

(a)	Under the amended agreement, any balance outstanding on our revolving line of credit at July 31, 2010, will be due at that time. The Company is currently negotiating an extension of this maturity date.
(b)	Assumes the interest rate on our revolving line of credit is consistent with that of September 30, 2009.

RESULTS OF OPERATIONS

Three months ended September 30, 2009 compared to the three months ended September 30, 2008

Oil and gas sales volume and price comparisons

	Three Months Ended September 30,								Percent			Percent
	2009				2008				Volume			Price
	Volume		Average Price		Volume		Average Price		Change			Change
Product:
Gas (Mcf)		2,261,180	$	4.27		1,876,642	$	6.27		20	%		-32	%
Oil (Bbls)		7,271	$	59.88		5,685	$	98.42		28	%		-39	%
Mcfe		2,304,806	$	4.38		1,910,752	$	6.45		21	%		-32	%

Our average gas price realized for the three months ended September 30, 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 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 in our price risk management activities line on the consolidated statement of operations, totaling $422 and $658, for the three months ended September 30, 2009 and 2008, respectively. This amount is divided by the total Mcfe volume for the period.

For the three months ended September 30, 2009, total net production increased 21% to 2,305 MMcfe, as compared to the three months ended September 30, 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 and lost production from workover activity 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 69.31%. Our interest will continue to change as the Unit expands further.

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During the three months ended September 30, 2009, average daily net production at the Atlantic Rim increased 18% to 17,585 Mcfe, as compared to 14,929 Mcfe during the same prior-year period, largely resulting from the addition of 20 new wells which were on-line at our Catalina Unit properties during the 2009 period. The 20 new wells were drilled during the 2008 drilling program and came on-line during the fourth quarter of 2008 and first quarter of 2009. During the three months ended September 30, 2009, average daily net production at our Catalina Unit increased 11% to 15,391 Mcfe, as compared to 13,863 Mcfe during the same period of 2008. The increase in production from the new wells in the Catalina Unit was partially offset by reduced production from certain existing wells, as the Company performed well workovers and production enhancements during the third quarter of 2009. Management scheduled these workovers during a time of low spot gas prices, thus minimizing the impact of the wells being off-line on revenues and cash flows. We expect to bring on the three remaining wells drilled as part of the 2008 drilling program during the fourth quarter of 2009 or first quarter of 2010. During the three months ended September 30, 2009, average daily production, net to our interest, at the Sun Dog and Doty Mountain units increased 106% to 2,194 Mcfe, as compared to average daily production of 1,066 during the same prior-year period. The increase was due to the addition of over 40 new wells at the Sun Dog Unit from the 2007 and 2008 drilling programs, and increased production from existing wells within the Doty Mountain Unit from production enhancement projects. Our working interest in the Sun Dog Unit has also increased to 8.89% from approximately 4.5%, which also contributed to the increase in net production.

Average daily production in the Pinedale Anticline increased 29% during the three months ended September 30, 2009, to 5,384 Mcfe, as compared to 4,164 Mcfe in the same prior-year period. The increase was primarily due to the addition of 16 new wells in the second and third quarter of 2009. Although there has been an increase in production due to the new wells in the Mesa Unit, the operator has indicated that it intends to keep production volumes in this field constant due to the low gas prices in the Rocky Mountain region, and therefore we have not realized the full benefit of having these new wells on-line for production. The operator has also informed us that it intends to bring one additional well on-line for production in the fourth quarter.

During the quarter ended September 30, 2009, the average daily production at the Madden Unit increased 41% to 597 Mcfe as compared to 423 Mcfe in the same prior-year period.

For the three months ended September 30, 2009, oil and gas sales decreased 17% to $9,669, as compared to the same prior-year period. Although we experienced favorable growth in net production volumes at all significant properties, as discussed above, oil and gas sales were negatively impacted by lower realized average gas prices. During the three months ended September 30, 2009, our average gas price realized decreased 32%, to $4.27 from $6.27, as compared to a decrease of 52% 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 September 30, 2009, transportation and gathering revenue increased 16% to $1,489 from $1,283. 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 was driven by higher production volumes at the Catalina Unit.

Price risk management activities

We recorded a net loss on our mark-to-market derivative contracts of $378 for the three months ended September 30, 2009, as compared to a gain of $1,020 for the three months ended September 30, 2008. This amount includes a realized gain of $422 from the settlement of these derivative instruments during the period and an unrealized non-cash decrease in the fair value of our outstanding mark-to-market derivative instruments at September 30, 2009 of $800.

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

	Three Months Ended September 30,
	2009			2008
	(in dollars per Mcfe)
Average price	$	4.38		$	6.45
Production costs		0.84			0.90
Production taxes		0.38			0.74
Depletion and amortization		1.99			1.76
Total operating costs		3.21			3.40
Gross margin	$	1.17		$	3.05
Gross margin percentage		27	%		47	%

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Production costs, on a dollars per Mcfe basis, is calculated by dividing production costs, as stated on the consolidated statement of operations, by total production volumes during the period. This calculation excludes certain gathering costs incurred by the Company’s subsidiary, Eastern Washakie Midstream, which are eliminated in consolidation. During the three months ended September 30, 2009, well production costs increased 12% to $1,934 as compared to $1,722 during the same prior-year period, and production costs in dollars per Mcfe decreased 7%, or $0.06 to $0.84, as compared to the same prior-year period. The increase in production costs during the third quarter of 2009 was primarily related to higher workover costs, as the Company performed workovers and well enhancement projects during the period. The decrease in well production costs on a per Mcfe basis was largely attributed to operating efficiencies we continue to realize as our production volumes increase, particularly at the Company-operated Catalina Unit.

During the three months ended September 30, 2009, production taxes decreased 38% to $879, as compared to $1,419 in the three months ended September 30, 2008, and production taxes, on a dollars per Mcfe basis, decreased 49%, or $0.36 to $0.38, as compared to the same prior-year period. The Company is required to pay taxes on the proceeds received upon the sale of our gas to counterparties. In periods of low market prices, a larger portion of our revenue is related to cash received from the settlement of financial derivative instruments we have in place, rather than the cash received for the physical sale of our gas in the open market. This results in an overall reduction in production taxes, as well as a reduction of production taxes expressed on a dollars per Mcfe basis.

Depreciation, depletion, and amortization (“DD&A”) for the three months ended September 30, 2009 increased 35% to $4,681, as compared to $3,462 in the same prior-year period, and depletion and amortization related to producing assets increased 36% to $4,578, as compared to $3,361 in the same prior-year period. The increase was largely due to the higher capital balances at the Catalina, Sun Dog, and Doty Mountain from the 2008 drilling programs and at the Mesa Unit from the 2008 and 2009 drilling programs, 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 $0.23 to $1.99 per Mcfe, as compared to the prior period.

Pipeline operating costs

During the three months ended September 30, 2009, pipeline operating costs increased 15% to $1,032 from $896 in the same prior-year period. 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 leased 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 expenses

General and administrative expenses decreased 4% to $1,579 for the three months ended September 30, 2009, as compared to $1,652 for the three months ended September 30, 2008. The decrease was primarily related to lower board of director’s compensation expense of $236, and lower professional service fees of $107 due to the mid-year reserve study and compensation study performed in 2008 that did not recur in 2009. These decreases were offset by additional salary and salary-related expenses of approximately $198 related to headcount additions and salary increases and $131 of transaction costs related to our acquisition of Petrosearch Energy Corporation

Income taxes

During the three months ended September 30, 2009, we recorded an income tax benefit of $40 compared to income tax expense of $1,557 during the same prior-year period. Excluding the effect of our 2008 book to tax true-up, our effective tax rate for the three months ended September 30, 2009 was 40.2% compared to 34.9% for the same 2008 period. The rate is higher for the 2009 period due to the impact of permanent income tax differences related to stock options. 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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Nine months ended September 30, 2009 compared to the nine months ended September 30, 2008

Oil and gas sales volume and price comparisons

	Nine Months Ended September 30,								Percent			Percent
	2009				2008				Volume			Price
	Volume		Average Price		Volume		Average Price		Change			Change
Product:
Gas (Mcf)		6,838,382	$	4.83		4,215,099	$	6.80		62	%		-29	%
Oil (Bbls)		22,006	$	45.40		14,672	$	97.18		50	%		-53	%
Mcfe		6,970,418	$	4.88		4,303,671	$	6.99		62	%		-30	%

Our average gas price realized for the nine months ended September 30, 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 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 in our price risk management activities line on the consolidated statement of operations, totaling $3,348 and $658, for the nine months ended September 30, 2009 and 2008, respectively. This amount is divided by the total Mcfe volume for the period.

For the nine months ended September 30, 2009, total net production increased 62% to 6,970 MMcfe, as compared to the nine months ended September 30, 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 69.31%. Our interest will continue to change as the Unit expands further.

During the nine months ended September 30, 2009, average daily net production at the Atlantic Rim increased 76% to 18,368 Mcfe, as compared to 10,436 Mcfe during the same prior-year period, largely resulting from the addition of 43 new wells which were on-line at our Catalina Unit during the 2009 period. Twenty-three of the 43 wells were drilled during the 2007 drilling program and came on-line in the second and third 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 72% to 16,415 Mcfe, as compared to 9,543 Mcfe during the same period of 2008. The increase in production from the new wells at the Catalina Unit was partially offset by reduced production from certain existing wells, as the Company performed well workovers and production enhancements during the second and third quarters of 2009. Management scheduled these workovers during a time of low spot gas prices, thus minimizing the impact of the wells being off-line on revenues and cash flows. Average daily production, net to our interest, at the Sun Dog and Doty Mountain units increased 119% to 1,953 Mcfe, as compared to average daily production of 893 Mcfe during the same prior-year period. The increase was due to the addition of over 80 new wells at the Sun Dog Unit from the 2007 and 2008 drilling programs, and increased production from existing wells at the Doty Mountain Unit from production enhancement projects. Our working interest in the Sun Dog Unit has also increased to 8.89% from approximately 4.5%, which also contributed to the increase in net production.

Average daily net production in the Pinedale Anticline increased 45% during the nine months ended September 30, 2009, to 5,559 Mcfe, as compared to 3,830 Mcfe in the same prior-year period. The increase was primarily due to the addition of 16 new wells in the second and third quarter of 2009, which were drilled in the fall of 2008 and first quarter of 2009. Although there has been an increase in production due to the new wells in the Mesa Unit, the operator has indicated that it intends to keep production volumes in this field constant due to the low gas prices in the Rocky Mountain region, and therefore we have not realized the full benefit of having these wells on-line for production.

During the nine months ended September 30, 2009, the average daily production at the Madden Unit increased 39% to 500 Mcfe, as compared to 360 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 nine months of 2009.

For the nine months ended September 30, 2009, oil and gas sales increased 4% to $30,661, as compared to the same prior-year period. Although we experienced favorable growth in net production volume at all significant properties during the first nine months of 2009, as discussed above, the oil and gas sales were negatively impacted by lower realized average gas prices. During the nine months ended September 30, 2009, our average gas price realized decreased 29%, to $4.83 from $6.80, as compared to a decrease of 62% 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.

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Transportation and gathering revenue

During the nine months ended September 30, 2009, transportation and gathering revenue increased 97% to $4,659 from $2,370. 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 mark-to-market derivative contracts of $3,670 for the nine months ended September 30, 2009, as compared to a gain of $3,042 for the nine months ended September 30, 2008. This amount consists of a net realized gain of $3,348 related to the settlement of our economic hedges, and an unrealized loss of $7,018, which represents the change in fair value of our outstanding mark-to-market derivative instruments at September 30, 2009.

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

	Nine Months Ended September 30,
	2009			2008
	(in dollars per Mcfe)
Average price	$	4.88		$	7.43
Production costs		0.79			1.12
Production taxes		0.36			0.98
Depletion and amortization		1.93			1.59
Total operating costs		3.08			3.69
Gross margin	$	1.80		$	3.74
Gross margin percentage		37	%		50	%

Production costs, on a dollars per Mcfe basis, is calculated by dividing production costs, as stated on the consolidated statement of operations, by total production volumes during the period. This calculation excludes certain gathering costs incurred by the Company’s subsidiary, Eastern Washakie Midstream, which are eliminated in consolidation. During the nine months ended September 30, 2009, well production costs increased 15% to $5,535, as compared to $4,814 during the same prior-year period, and production costs in dollars per Mcfe decreased 29%, or $0.33 to $0.79, as compared to the same 2008 period. The increase in total production costs is primarily due to the increase in the number of producing wells at the Catalina, Sun Dog and Doty Mountain Units and an increase in well workover costs at the Catalina Unit. 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.

During the nine months ended September 30, 2009, production taxes decreased 33% to $2,521, as compared to $3,753 in the first nine months of 2008, and production taxes expressed on a dollars per Mcfe basis decreased 63%, or $0.62 to $0.36, as compared to the same prior-year period. The Company is required to pay taxes on the proceeds received upon the sale of our gas to counterparties. In periods of low market prices, a larger portion of our revenue is related to cash received from the settlement of financial derivative instruments we have in place, rather than the cash received for the physical sale of our gas in the open market. This results in an overall reduction in production taxes, as well as a reduction of production taxes on a dollars per Mcfe basis.

Depreciation, depletion, and amortization (“DD&A”) for the nine months ended September 30, 2009 increased 85% to $13,778, as compared to $7,456 in the same prior-year period, and depletion and amortization related to producing assets increased 88% to $13,456, as compared to $7,166 in the same prior-year period. The increase was largely due to the higher capital balances at the Catalina, Sun Dog, and Doty Mountain Units from the 2008 drilling programs and at the Mesa Units resulting from the 2008 and 2009 drilling programs, 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 18%, or $0.34, to $1.93, as compared to the same prior-year period.

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Pipeline operating costs

During the nine months ended September 30, 2009, pipeline operating costs increased to $2,686 from $1,643 in the same prior year period. 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 leased 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 expenses

General and administrative expenses increased 21% to $4,680 for the nine months ended September 30, 2009, as compared to $3,861 for the nine months ended September 30, 2008. The increase was primarily due to higher non-cash stock-based compensation expense of $517 due to additional grants to employees, additional salary and salary-related expenses of $419 in the third and fourth quarters of 2008, and $513 of transaction costs related to our acquisition of Petrosearch in the third quarter of 2009. These increases were offset by lower board of directors cash compensation costs of $241 and lower software fees of $122 related to our 2008 accounting system implementation.

Income taxes

During the nine months ended September 30, 2009, we recorded income tax expense of $481 compared to income tax expense of $4,554 during the same prior-year period. Excluding the effect of our 2008 book to tax true-up, our effective tax rate for the nine months ended September 30, 2009 was 40.2% compared to 36.2% for the same 2008 period. The rate is higher for the 2009 period due to the impact of permanent income tax differences related to stock option 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 2009 at an expected federal and state rate of approximately 35.0%.

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.

Our outstanding forward sales contract as of September 30, 2009 is summarized below (volume and daily production are expressed in Mcf):

	Remaining
	Contractual		Daily						Price
Property	Volume		Production		Term		Price		Index (1)
Catalina		31,000		1,000		11/07-10/09	$	5.66	CIG

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The Company also has entered into various other derivative instruments to protect prices on future production. The terms of our other hedging instruments at September 30, 2009 are summarized as follows (volume and daily production are expressed in Mcf):

	Remaining
	Contractual		Daily				Price
Type of Contract	Volume		Production		Term	Price	Index
Fixed Price Swap		736,000		8,000	1/09-12/09	$7.34	CIG
Fixed Price Swap		4,380,000		12,000	1/10-12/10	$4.30	CIG
Costless Collar		3,345,000		5,000	8/09-7/11	$4.50 floor $7.90 ceiling	NYMEX
Costless Collar		3,650,000		5,000	12/09-11/11	$4.50 floor $9.00 ceiling	NYMEX
Fixed Price Swap		2,920,000		8,000	1/11-12/11	$7.07	CIG
Total		15,031,000

(1) Colorado Interstate Gas Index (“CIG”).

Refer to Note 4 in the Notes to the Consolidated Financial Statements for additional discussion on the accounting treatment of our derivative contracts.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Due to the acquisition of Petrosearch in the third quarter of 2009, we have added a new critical accounting policy regarding business combinations as described in more detail immediately below. For a listing of our other critical accounting policies, please refer to 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.

Business Combinations

We are required to allocate the purchase price of acquired companies to the tangible and intangible assets acquired, liabilities assumed, including oil and gas properties and tax assets, and liabilities based on their estimated fair values. We engage an independent reserve engineer to assist us in determining the fair values of crude oil and natural gas properties acquired, and other third-party specialists as needed to assess the fair value of other assets and liabilities assumed. This valuation requires management to make significant estimates and assumptions, especially with respect to the oil and gas properties.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risks

Our major market risk exposure is in the pricing applicable to our natural gas and oil production. Pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. natural gas production. Pricing for oil production and natural gas has been volatile and unpredictable for several years. The prices we receive for production depend on many factors outside of our control. For the three months ended September 30, 2009, our income before income taxes would have changed by $453 for each $0.50 change per Mcf in natural gas prices and $6 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, 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. 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 September 30, 2009, we had a balance of $34 million outstanding under our $75 million credit facility, with a $45 million borrowing base. 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 September 30, 2009, the annual impact on interest expense for every 1.0% change in the average interest rate would be approximately $340 before taxes. As of September 30, 2009, the interest rate on the line of credit, calculated in accordance with the agreement, was 4.5%. Any balance outstanding on the revolving line of credit matures July 31, 2010.

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ITEM 4. CONTROLS AND PROCEDURES

In accordance with Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934, as amended, 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 September 30, 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.

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).

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Exhibit			Description:
	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).
	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).
	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: October 29, 2009	By:	/s/ Richard D. DoleRichard D. Dole
		Chief Executive Officer
		(Principal Executive Officer)
Date: October 29, 2009	By:	/s/ Kurtis S. HooleyKurtis 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).
	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).

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Exhibit Number			Description
	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).
	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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