Escalera Resources 10Q 2007 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 quarterly period ended September 30, 2007


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 0-6529

DOUBLE EAGLE PETROLEUM CO.

(Exact name of registrant as specified in its charter)


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

777 Overland Trail, P.O. Box 766, Casper, Wyoming 82602
(Address of principal executive offices) (Zip code)

307-237-9330
(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 checkmark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filero Accelerated filerþ Non-accelerated filero

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 November 1, 2007
Common stock, $.10 par value		9,148,105

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


	Page
PART I. Financial Information:

Item 1. Financial Statements

Consolidated Balance Sheet as of September 30, 2007 (Unaudited) and December 31, 2006		2

Consolidated Statement of Operations for the Three and Nine Months Ended September 30, 2007 and 2006 (Unaudited)		3

Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2007 and 2006 (Unaudited)		4

Notes to Consolidated Financial Statements (Unaudited)		5

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		10

Item 3. Quantitative and Qualitative Disclosures About Market Risk		20

Item 4. Controls and Procedures		21

PART II. Other Information:

Item 1. Legal Proceedings		21

Item 1A. Risk Factors		21

Item 6. Exhibits		22

Signatures		22

Exhibit 13.1
Exhibit 31.1
Exhibit 31.2
Exhibit 32

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED BALANCE SHEET

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


	September 30,			December 31,
	2007			2006
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	11,831		$	611
Cash held in escrow		663			707
Accounts receivable		4,434			5,047
Pipe Inventory		1,522			601
Other current assets		252			208

Total current assets		18,702			7,174


Oil and gas properties and equipment, successful efforts method:
Developed properties		54,980			53,677
Wells in progress		24,455			13,839
Gas transportation pipeline		5,465			5,412
Undeveloped properties		3,137			3,313
Corporate and other assets		1,509			1,024

		89,546			77,265
Less accumulated depreciation, depletion and amortization		(23,769	)		(20,079	)

Net properties and equipment		65,777			57,186

Other assets		56			46

TOTAL ASSETS	$	84,535		$	64,406


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	4,015		$	7,964
Accrued expenses		2,002			5,125
Accrued production taxes		1,633			1,091

Total current liabilities		7,650			14,180

Line of credit		—			13,221
Asset retirement obligation		697			694
Deferred tax liability		726			3,269

Total liabilities		9,073			31,364


Stockholders’ equity:
Preferred stock, $0.10 par value; 10,000,000 shares authorized; 1,610,000 and 0 shares issued and outstanding as of September 30, 2007 and December 31, 2006, respectively		161			—
Common stock, $0.10 par value; 50,000,000 shares authorized; 9,148,105 and 8,641,104 shares issued and outstanding as of September 30, 2007 and December 31, 2006, respectively		915			864
Additional paid-in capital		71,400			23,251
Retained earnings		2,986			8,927

Total stockholders’ equity		75,462			33,042


TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	84,535		$	64,406

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

DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED STATEMENT OF OPERATIONS

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

(Unaudited)


	Three months ended						Nine months ended
	September 30,			September 30,			September 30,			September 30,
	2007			2006			2007			2006

Revenues
Oil and gas sales	$	3,779		$	4,163		$	11,812		$	12,808
Transportation revenue		242			272			675			272
Other income, net		62			17			203			53


Total revenues		4,083			4,452			12,690			13,133


Costs and expenses
Production costs		1,009			849			4,160			2,532
Production taxes		470			509			1,471			1,527
Exploration expenses including dry holes		5,314			406			5,592			512
General and administrative		1,105			858			2,880			2,806
Depreciation, depletion and amortization		1,349			1,304			4,094			3,468
Impairment of equipment and properties		2,033			—			2,124			—


Total costs and expenses		11,280			3,926			20,321			10,845


Income (Loss) from operations		(7,197	)		526			(7,631	)		2,288

Interest (expense) income, net		180			(2	)		25			(67	)


Income (Loss) before income taxes		(7,017	)		524			(7,606	)		2,221

(Provision) Benefit for deferred taxes		2,225			(183	)		2,544			(777	)


NET INCOME (Loss)		(4,792	)		341			(5,062	)		1,444


Preferred stock requirements		(879	)		—			(879	)		—

NET INCOME (Loss) attributable to common stock	$	(5,671	)	$	341		$	(5,941	)	$	1,444


Earnings per share of common stock:
Basic	$	(0.62	)	$	0.04		$	(0.65	)	$	0.17

Diluted	$	(0.62	)	$	0.04		$	(0.65	)	$	0.17


Weighted average shares outstanding:
Basic		9,148,105			8,639,604			9,103,339			8,629,860

Diluted		9,148,105			8,666,900			9,103,339			8,660,696

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

DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED STATEMENT OF CASH FLOWS

(Amounts in thousands of dollars)

(Unaudited)


	Nine months ended September 30,
	2007			2006
Cash flows from operating activities:
Net income (loss)	$	(5,062	)	$	1,444
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion of asset retirement obligation		4,116			3,471
Abandonment of non-producing properties		5,176			287
Impairment of equipment and properties		2,124			—
Provision (benefit) for deferred taxes		(2,544	)		777
Directors fees paid in stock		91			97
Non-cash employee stock option expense		286			342
Gain on sale of working interest in non-producing property		(98	)		—
Changes in current assets and liabilities:
Decrease (Increase) in deposit held in escrow		44			(4,471	)
Decrease (Increase) in accounts receivable		194			1,969
Decrease (Increase) in pipe inventory		(921	)		(601	)
Decrease (Increase) in other current assets		(44	)		233
Increase (Decrease) in accounts payable		(4,023	)		(62	)
Increase (Decrease) in accrued expenses		663			3,651
Increase (Decrease) in accrued production taxes		542			224


NET CASH PROVIDED BY OPERATING ACTIVITIES		544			7,361


Cash flows from investing activities:
Additions of producing properties and equipment		(22,733	)		(13,466	)
Additions of corporate and non-producing properties		(719	)		(386	)
Proceeds from sale of non-producing properties		244			—


NET CASH USED IN INVESTING ACTIVITIES		(23,208	)		(13,852	)


Cash flows from financing activities:
Net proceeds from sale of common stock		9,990			—
Net proceeds from sale of preferred stock		37,967			—
Dividends paid on preferred stock		(879	)		—
Net payments on line of credit		(13,221	)		5,320
Settlement of Options		—			(104	)
Exercise of options		27			325


NET CASH PROVIDED BY FINANCING ACTIVITIES		33,884			5,541


Change in cash and cash equivalents		11,220			(950	)

Cash and cash equivalents at beginning of period		611			1,431


CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	11,831		$	481


Supplemental disclosure of cash and non-cash transactions:
Cash paid for interest	$	333		$	45
Interest capitalized	$	273		$	197
Additions to developed properties included in current liabilities	$	2,471		$	3,105
Additions to developed properties for retirement obligations	$	5		$	80

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

DOUBLE EAGLE PETROLEUM CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

Summary of Significant Accounting Policies

Basis of presentation

The accompanying unaudited 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. 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 2006 financial statements were reclassified to conform to the 2007 unaudited consolidated financial statement presentation.

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, 2006, and are supplemented throughout the notes to this quarterly report on Form 10-Q.

The interim consolidated financial statements presented should be read in conjunction with the financial statements and notes thereto for the year ended December 31, 2006 included in the Form 10-K filed with the SEC.

New accounting pronouncements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 157 – Fair Value Measurements (“SFAS 157”). The statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The adoption of SFAS 157 is not expected to have a material effect on the Company’s financial position, results of operations or cash flows.

In February 2007, the FASB issued Statement of Financial Accounting Standards No. 159 – The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115 (“SFAS 159”). The statement permits companies to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. The objective of SFAS 159 is to provide opportunities to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply hedge accounting provisions. SFAS 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS 159 will be effective for fiscal years beginning after November 15, 2007. The adoption of SFAS 159 is not expected to have a material effect on the Company’s financial position, results of operations or cash flows.

Earnings per share of common stock

Basic earnings per share of common stock (“EPS”) is calculated by dividing net income attributable to common stock by the weighted average number of shares of common stock outstanding during the period. Fully diluted earnings per share is calculated by dividing net income attributable to common stock by the weighted average number of shares of common stock outstanding adjusted for the dilutive impact of outstanding stock options by including the effect of outstanding vested and unvested options in the average number of common shares outstanding during the period. Income attributable to common stock is calculated as net income less dividends paid on the Series A Preferred Stock. We declared and paid cash dividends of $879 ($.5461 per share) on the Series A Preferred Stock for the three and nine month periods ended September 30, 2007.

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


	Three Months Ended September 30,					Nine Months Ended September 30,
	2007			2006		2007			2006
Net income (loss)	$	(4,792	)	$	341	$	(5,062	)	$	1,444

Preferred stock requirements		(879	)		—		(879	)		—

Income attributable to common stock	$	(5,671	)	$	341	$	(5,941	)	$	1,444

Weighted average shares:
Weighted average shares — basic		9,148,105			8,639,604		9,103,339			8,629,860
Dilution effect of stock options outstanding at the end of period		—			27,296		—			30,836

Weighted average shares — fully diluted		9,148,105			8,666,900		9,103,339			8,660,696



Earnings per share of common stock:
Basic	$	(0.62	)	$	0.04	$	(0.65	)	$	0.17

Fully diluted	$	(0.62	)	$	0.04	$	(0.65	)	$	0.17

The following options, 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:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006

Options to purchase common stock		7,624		—		26,096		—

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 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. For the three and nine month periods ended September 30, 2007, the Company recognized non-cash charges of $2,033 on the impairment of properties included in Developed Properties and, for the nine months ended September 30, 2007, $91 on undeveloped leaseholds.

The Mad #1 well was completed in the second quarter 2006 at approximately 3,300 feet in the Deep Creek Sandstone in the lower Mesaverde and, accordingly, capitalized as a Developed Property. The well initially produced, during the first two months of production, approximately 15,500 Mcf/month, with production dropping off to an average of 676 Mcf/month for the remainder of 2006. The well has produced minimally during 2007. The Company intends to temporarily plug the well at its current depth to production test the Haystack Mountain Formation above the current zone. If it is determined that the well is not capable of commercial production, the well will be used as an injection well, in the Catalina Unit. As a result, the Company has determined that $1,275 of capitalized costs (the difference between the current capitalized costs of the Mad #1 and the costs of a Catalina Unit water injection well) related to the Mad #1 is impaired, and that amount has been charged to expense in the quarter ended September 30, 2007.

During 2007, work was performed on the State 1-36 well to enhance the recoverability of its reserves. These efforts were not as successful as originally contemplated. Additionally, the property was shut-in due to a dispute related to the transportation agreement for the natural gas produced at this well, and that is expected to continue for the foreseeable future. As a result, the Company has determined that $693 of capitalized costs (capitalized costs net of salvage value) related to the State 1-36 is impaired, and that amount has been expensed in the quarter ended September 30, 2007.

Suspended Well Costs

FASB Staff Position FAS 19-1 (FSP 19-1),Accounting for Suspended Well Costs, was effective for the first reporting period beginning after April 4, 2005. FSP 19-1 concludes that, for companies using the successful efforts method of accounting, exploratory well costs should continue to be capitalized when a well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the well. Since adopting FSP 19-1, the Company continually evaluates all existing capitalized exploratory well costs. As a result, the Company determined that $4,388 of capitalized costs related to the Cow Creek Unit Deep #2 (CCU #2) well required write off in the quarter ended September 30, 2007.

Drilling was completed on the CCU #2 in August 2006. This well is treated as two wells for accounting purposes. At its current depth of 9,922 feet, the well passed the Mesaverde formation, a proved area known to be productive. The normal costs incurred to drill to the proved horizon are treated as development well costs, while the incremental costs to drill below the proved horizon are treated as exploratory well costs. The CCU #2 reached a depth of 2,020 feet (within the range at which the depth of the well would have reached the Mesaverde formation) at a cost of $1,655. The intent of the Company is, and has always been, to take this well deeper to test the Tensleep and, possibly, the Madison formations. It now appears that it will be some time in 2008 before a rig can be contracted and placed in operation on the CCU #2.

The following table reflects the net changes in capitalized exploratory well costs during the nine months ended September 30, 2007, and does not include amounts that were capitalized and subsequently expensed in the same period.


Beginning balance at January 1, 2007	$	11,541

Additions to capitalized exploratory well costs pending the determination of proved reserves		3,590
Reclassifications to wells, facilities and equipment based on the determination of proved reserves		(1,655	)
Capitalized exploratory well costs charged to expense		(4,388	)


Ending balance at September 30, 2007	$	9,088

The following table provides an aging of capitalized exploratory well costs based on the date the drilling was completed and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:


Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	5,929
Capitalized exploratory well costs that have been capitalized for a period greater than one year		3,159


Balance at September 30, 2007	$	9,088


Number of projects that have exploratory well costs that have been capitalized for a period greater than one year		2

The remaining amount of exploratory well costs that have been capitalized for greater than one year since the completion of drilling relates to two projects, both of which were capitalized during 2006. The two projects are the Table Top Unit #1 and South Fillmore PH State 16-1.

Drilling of the Table Top Unit #1 began in September 2006 ($1,446 of the amount of costs that have been capitalized for a period greater than one year in the table above relates to Table Top Unit #1) and reached the originally planned total depth of 15,760 feet during the first quarter of 2007. The drilling did not find reservoir rocks with sufficient permeability and operations were suspended to assess alternative approaches to completing the project. The Table Top Unit, as originally formed, was dissolved, and, having met the governmental permitting obligation for the Unit test, the time-frame has been extended for drilling the newly

formed Main Fork Unit until at least April 2009. The Company has further evaluated the structure and is working on plans to propose to its partners either to drill or farmout drilling to the deeper Nugget Sandstone. The Company anticipates re-entering this hole in mid-2008 after the winter weather has cleared from this high-elevation location.

The South Fillmore PH State 16-1 (South Fillmore) was completed during the third quarter of 2006 ($1,713 of the amount of costs that have been capitalized for a period greater than one year in the table above relates to South Fillmore). During testing of the well in the winter of 2006-2007, mechanical problems developed in the borehole. The Company plans to re-perforate the well early in 2008, with the intention of completing the well as a producer. In July 2007, GMT Exploration Company LLC drilled the SJ Fee 11-9 well ($665 of costs related to the GMT well are included above as capitalized for one year or less), in which the Company has a 50% working interest before payout and a 30% working interest after payout, one mile northwest of the initial South Fillmore well. The SJ Fee 11-9 well has been completed with a flow rate of approximately 2,250 Mcfe per day, and commercial gas sales are expected to begin in December 2007. Additionally, GMT is in the process of building a three-mile long pipeline to connect the SJ Fee 11-9 to a sales line. South Fillmore is within the same field as the GMT well and initially tested at a flow rate of about 1,260 Mcfe per day. The Company is currently evaluating the project and has plans to continue developing the area, including potentially drilling or participating in the drilling of additional wells.

Unsuccessful Exploratory Well

In August 2007, VF Neuhaus began drilling the Straight Flush #17-1 well in Huntington Valley, Nevada. Double Eagle had a 97.3% working interest in the well and further earned additional interests under six sections of land. No commercial deposits of oil and gas were identified and the well was plugged in October 2007. Costs incurred through September 30, 2007 of $752 were charged to expense as dry hole costs. In accordance with FASB’s Interpretation No. 36, the costs incurred after the balance sheet date must be charged to expense in the period following the balance sheet date, or, in this case, the fourth quarter of 2007. Thus, there will be an additional expense for this well for dry hole costs, estimated at approximately $900, recognized in the fourth quarter of 2007.

Income Taxes

At September 30, 2007, the Company has a net operating loss carryforward for income tax reporting purposes that begins expiring 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 adopted FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109 (“FIN 48”), on January 1, 2007. The adoption of this statement had no impact on the Company’s consolidated financial statements. We expect no material changes to unrecognized tax positions within the next 12 months.

The Company is subject to U.S. federal income tax and income tax from multiple state jurisdictions. The tax years remaining subject to examination by tax authorities are fiscal years 2003 through 2006.

The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of September 30, 2007, the Company made no provisions for interest or penalties related to uncertain tax positions.

Line of Credit

Effective August 1, 2006, the Company entered into a $50 million revolving line of credit collateralized by oil and gas producing properties, replacing the previously existing revolving line of credit. The borrowing base increased to $35 million from $25 million, pursuant to the debt modification agreement dated July 1, 2007, and all outstanding balances on the line of credit mature on July 31, 2010.

In July 2007, as described in Note 6, approximately $17 million of the total net proceeds received from a public offering of our 9.25% Series A Cumulative Preferred Stock were used to pay off the outstanding balance on the Company’s revolving line of credit. As of September 30, 2007, the outstanding balance on the line of credit was $0 and the interest rate, calculated in accordance with the agreement at 1.125% below the posted Wall Street Journal Prime Rate, was 6.625%, compared to 7.125% at September 30, 2006.

The Company is subject to certain financial and non-financial covenants with respect to the above credit facility, including a requirement to maintain a current ratio, plus the line of credit availability, of at least 1.0 to 1.0. As of September 30, 2007, the Company was in compliance with all such covenants. Should any of the covenants with respect to the above credit facility be violated, and, if the Company was unable to negotiate a waiver or amendment thereof, the lender would have the right to declare an event of default, terminate the remaining commitment and accelerate all principal and interest outstanding.

For the three and nine months ended September 30, 2007, interest expense with respect to the above credit lines totaled $16 and $428, respectively, and capitalized interest totaled $16 and $273, respectively.

Sale of Stock

On January 23, 2007, the Company completed a public offering of 500,000 shares of Common Stock at a price to the public of $21.55 per share. Net proceeds from the offering were approximately $10 million, after deducting underwriter fees and other offering expenses. The net proceeds from this offering were used to pay down the outstanding indebtedness on the Company’s revolving line of credit.

On July 5, 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. Net proceeds from the offering were approximately $38 million, after deducting underwriter discounts and offering expenses. A portion of the net proceeds from this offering was used to pay off the outstanding indebtedness on the Company’s revolving line of credit of approximately $17 million. The remaining proceeds were invested in short term investment accounts.

Cash Held in Escrow

The Company has received deposits representing partial prepayments of the expected capital expenditures from third party working interest owners in the Table Top Unit #1 (Christmas Meadows) exploration project. The unexpended portion of the deposits at September 30, 2007 totaled $663.

Intercompany Note Receivable

The Company sold transportation assets located in the Cow Creek Field, at cost, to Eastern Washakie Midstream, LLC, 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.

Commitments and Contingent Liabilities

Litigation

Double Eagle Petroleum Co.; Antelope Energy Company LLC; E. Cecile Martin f/k/a Cecile Hurt; Hurt Properties, L.P.; James R. Hurt; John D. Traut, LLC; and Newfield Exploration Company vs. Burlington Resources Oil & Gas Company, LP, a division of ConocoPhillips Company; ConocoPhillips Company, a Delaware corporation.On or about September 22, 2004, the Bureau of Land Management (“BLM”) formally approved the termination of the Long Butte Unit, in which the Company held an interest, and the blending of the Long Butte Unit into the Madden Deep Unit, effective February 1, 2002. On or about June 7, 2005, the BLM formally approved the 4^th Revision of the Sour Gas Paleozoic Interval Participating Area, also effective February 1, 2002. As a result, the Company and other parties acquired interests in the Madden Sour Gas Participating Area in the Madden Deep Unit and the Lost Cabin Gas Processing Plant, effective from February 1, 2002. Since then, the Company has been billed, and has paid, its share of the Cost Adjustment for the 4^th Revision, which included all costs for the period February 1, 2002 through October 30, 2006. The Company has not, however, been paid any of the proceeds generated by the sale of gas produced from the Madden Deep Unit over the period of February 1, 2002 through June 30, 2007. Burlington Resources (“BR”) began paying Double Eagle for its share of the sales beginning July 1, 2007. 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 they are entitled to receive either monetary damages or their respective shares of the gas produced from the Madden Deep Unit over at least the period February 1, 2002 through June 30, 2007. However, as we have been billed and paid our portion of operating costs since November 1, 2007; the Company has recognized the sales and has recorded a related account receivable of $584 for the period November 1, 2007 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.

10.

Accounts Receivable

In September 2007, a working interest partner in the Table Top Unit #1 declared Bankruptcy. As the working interest partner had not reached earn-in status on the Table Top Unit #1, its interest in the unit is expected to remain in the Company, resulting in the Company’s total interest in the unit being 39%. The accounts receivable of $420 was capitalized as the cost of the additional interest.

11.

Shareholders’ Rights Plan

On August 21, 2007, the Board of Directors of the Company adopted a Shareholder Rights Plan (Rights Plan). Under the Rights Plan, the Company issued a dividend of one Preferred Share Purchase Right for each outstanding share of common stock held by stockholders of record on September 4, 2007.

The Rights Plan is intended to safeguard against abusive takeover tactics that limit the ability of all shareholders to realize the long-term value of their investment in Double Eagle. The Rights Plan was not adopted in response to any specific takeover effort, and will not prevent a takeover, but should encourage anyone seeking to acquire Double Eagle to negotiate with the Board prior to attempting a takeover.

Each right initially entitles stockholders to purchase a fractional share of the Company’s Series B Junior Participating Preferred Stock at an exercise price of $45. However, the rights are not immediately exercisable and will become exercisable only upon the occurrence of certain events. If a person or group acquires, or announces a tender or exchange offer that would result in the acquisition of 20% or more of the Company’s common stock while the Rights Plan remains in place, then, unless the rights are redeemed by the Company for $.01 per right, the rights will become exercisable by all rights holders, except the acquiring person or group, for shares of the Company’s common stock having a value of twice the right’s then-current exercise price.

There are 75,000 shares of the Company’s Series B Junior Participating Preferred Stock, par value $.10, authorized with no shares outstanding at September 30, 2007.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

(Amounts in thousands of dollars, except amounts per unit of production)

The terms “Double Eagle”, “Company”, “we”, “our”, and “us” refer to Double Eagle Petroleum Co. and its subsidiary, as a consolidated entity, unless the context suggests otherwise.

FORWARD-LOOKING STATEMENTS

This Quarterly Report onForm 10-Q includes “forward-looking statements” as defined by the Securities and Exchange Commission, or SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in thisForm 10-Q that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including without limitation the Risk Factors set forth in our Annual Report onForm 10-K for the year ended December 31, 2006 including the following:

•

Our ability to continue to develop our coal bed methane projects in the Atlantic Rim;

•

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

•

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 meet growth projections;

•

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 financing;

•

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

•

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

•

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

•

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

•

General economic and political conditions, including 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; and

•

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

We may also 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.

The following discussion should be read in conjunction with Item 7. – Management’s Discussion and Analysis of Financial Condition and Results of Operations – included in our 2006 Annual Report on Form 10-K filed with the Securities and Exchange Commission.

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. Our principal properties are 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. Our current exploration activities involve properties in southwestern Wyoming, Nevada and other Rocky Mountain states.

Our objective is to increase stockholder value by pursuing our corporate strategy of economically growing reserves and production through the development of our existing properties, selectively pursuing high potential exploration projects where we have accumulated detailed geological knowledge, and selectively pursuing strategic acquisitions that may expand or complement our existing operations.

Following are summary comments of our performance in several key areas during the three and nine month periods ended September 30, 2007(Amounts in thousands of dollars, except amounts per unit of production):

Average Daily Production

During the three and nine month periods ended September 30, 2007, average daily production increased 1% to 8,329 Mcfe, and increased 5% to 8,368 Mcfe, as compared to average daily production of 8,247 Mcfe and 7,962 Mcfe, during the same prior year periods, respectively. The fluctuations in production by major operating area are discussed below.

Atlantic Rim.During the quarter ended September 30, 2007, average daily production at the Atlantic Rim decreased 4% to 4,948 Mcfe, as compared to 5,168 Mcfe during the same prior year period, due largely to decreased production at Cow Creek, partially offset by production at the Sun Dog Unit. Average daily production at Cow Creek decreased 10% to 4,248 Mcfe, as compared to 4,745 Mcfe during the same prior year period, due largely to workovers that occurred in the third quarter of 2007.

During the nine months ended September 30, 2007, average daily production at the Atlantic Rim increased 3% to 4,714 Mcfe, as compared to 4,595 Mcfe during the same prior year period, due largely to the initial recognition of revenues at Doty Mountain and Sun Dog Units, beginning during the second half of 2006. Average daily production at Cow Creek decreased 8% to 4,099 Mcfe, as compared to 4,452 Mcfe during the same prior year period, due largely to operational issues resulting from severe winter weather, which resulted in unscheduled workovers during the first half of 2007. However, the volumes came back on in the third quarter as workovers were completed. Workovers which occurred during the third quarter also contributed somewhat to the decreased production.

Pinedale Anticline. During the quarter ended September 30, 2007, average daily production at Pinedale decreased 14% to 1,933 Mcfe, as compared to 2,247 Mcfe in the prior year. These decreases are due to the shut-in of several Mesa wells during the third quarter of 2007, as well as normal production decline, offset somewhat by new wells that came on-line during the third quarter of 2007. The operator at the Mesa Units has informed us that it intends to drill an additional 34 wells from the last half of 2007 through the summer of 2008 to increase production levels.

During the nine months ended September 30, 2007, average daily production at Pinedale decreased 11% to 2,248 Mcfe, as compared to 2,532 Mcfe during the same prior year period. This decrease relates to the items discussed in the above comments.

Madden Deep Unit. During the three and nine months ended September 30, 2007, our average daily net production at the Madden Deep Unit was 290 Mcfe and 538 Mcfe, respectively. The decrease in third quarter production (as compared to the average daily production for the nine-month period) was largely due to workovers in the area and the resulting decreased production during the month of August. Through unitization, we acquired an interest in the Madden Sour Gas Participating Area in the Madden Deep Unit in late 2006, effective as of February 2002, as well as an interest in the Lost Cabin Gas Processing Plant, at an initial cost of approximately $2.5 million.

Oil and Gas Sales

During the quarter ended September 30, 2007, oil and gas sales decreased 9% to $3,779, as compared to $4,163 during the same prior year period. Total revenue was impacted largely by lower average gas prices, somewhat offset by the slight increase in volumes discussed above. Additionally, we began receiving and selling our share of Doty Mountain production in mid-2006 and our share of Sun Dog production during the third quarter of 2007. We are in an under-produced position for prior year’s production at the Doty Mountain Unit and began receiving make up gas on August 1, 2007. We are also in an under-produced position for prior and current year’s production at the Sun Dog Unit and began receiving our share of current production and make up gas on August 1, 2007. During the quarter ended September 30, 2007, the average CIG price decreased 47%, due largely to the effects of excess gas in storage. In comparison, our average gas price received only decreased 11%, from $5.38 to $4.79, for the same period, due primarily to the fixed delivery contracts we have in place. See additional comments in “Contracted Volumes” below.

During the nine months ended September 30, 2007, oil and gas sales decreased 8% to $11,812 as compared to $12,808 during the same prior year period. Total revenue was impacted largely by lower average gas prices, somewhat offset by the increase in volumes and imbalance activity discussed above. During the nine months ended September 30, 2007, the average CIG price decreased 29% due primarily to the effects on 2006 pricing of the severe hurricane season in late 2005, the effects on 2007 pricing of a two week shut-in of a storage facility for maintenance pipeline closures due to repairs and the factors discussed above. Our average price received only decreased 13%, from $5.78 to $5.05, for the same period, due primarily to the fixed delivery contracts we have in place. See additional comments in “Contracted Volumes” below.

OVERVIEW OF FINANCIAL CONDITION AND LIQUIDITY

Liquidity and Capital Resources

We believe that we have sufficient liquidity and capital resources to continue our strategic plan, including continued development of our major natural gas projects in the Atlantic Rim and the Pinedale Anticline, as well as our pursuit of our current exploration/development projects (see Capital Requirements below). We intend to use proceeds from the July Series A Preferred Stock offering (Note 6), capital resources made available through future operating cash flow and through our $50 million bank line

of credit ($35 million borrowing base) to fund this activity. We may also consider additional offerings of securities. Although we believe that we would be able to secure additional financing if required, we can provide no assurance that we will be able to do so or as to the terms of any additional financing. We also believe that cash provided by operating activities and amounts available under the revolving credit facility will be sufficient to meet our Series A Preferred Stock dividend requirements during the remainder of 2007 of approximately $931.

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


	September 30,			December 31,
	2007			2006
Financial Position Summary
Cash and cash equivalents	$	11,831		$	611
Working capital	$	11,052		$	(7,006	)
Line of credit outstanding	$	—		$	13,221
Stockholders’ equity	$	75,462		$	33,042

Ratios
Long-term debt to total capital ratio		0.0	%		28.6	%
Total debt to equity ratio		0.0	%		40.0	%

During the nine months ended September 30, 2007, our working capital was $11,052, due primarily to cash receipts from the July 2007 Preferred Stock offering. We often maintain a working capital deficit due to an agreement with our bank which allows us to apply any available cash balances to the outstanding line of credit on a daily basis, thereby minimizing our interest expense. However, since our outstanding line of credit was paid off in July with the proceeds from the Preferred Stock offering and we have cash available from the offering; we have positive working capital at September 30, 2007. It is anticipated that we will use the available cash to fund development activities in the fourth quarter and again be in a borrowed position on our line of credit by December 31, 2007.

Cash flow activities

The table below summarizes our cash flows for the periods indicated:


	Nine months ended September 30,
	2007			2006
Cash provided by (used in):
Operating Activities	$	544		$	7,361
Investing Activities		(23,208	)		(13,852	)
Financing Activities		33,884			5,541

Net change in cash	$	11,220		$	(950	)

During the nine months ended September 30, 2007, net cash provided by operating activities was $544 compared to $7,361 in the same prior year period. The change in net cash provided by operating activities resulted from a net loss for the period was $5,062 versus net income of $1,444 in the same prior year period. The net loss was primarily due to the write off of exploratory well costs for Cow Creek Unit Deep #2 (CCU #2) and Straight Flush 17-1, the impairment charges for Mad #1 and State 1-36, and, to a lesser extent, to a decrease in average natural gas price received and an increase in production costs in the first three quarters of 2007. The increase in production costs is largely attributed to gas purchase expense of $199, for the purchase of volumes to fulfill the fixed delivery contracts, an increase in operating costs of approximately $85 and workover costs of $641, both of which relate to the severe weather and related operational issues during the first half of 2007 and scheduled workovers during the third quarter of 2007 in the Cow Creek Field. Additionally, we were billed for and paid our share of Madden Deep lease operating expenses, beginning in the fourth quarter of 2006. Management does not anticipate the gas purchase expenses or this level of unscheduled workovers going forward.

During the nine months ended September 30, 2007, net cash used in investing activities was $23,208, as compared to $13,852 in the same prior year period. We invested (i) $2,849 at the Table Top Unit #1 well at the Christmas Meadows Prospect; (ii) $5,963 for our share of costs for non-operated development wells in the Pinedale Anticline and Atlantic Rim areas; (iii) $2,507 for our interest in the Madden Sour Gas Participating Area in the Madden Deep Unit and the Lost Cabin Gas Processing Plant; (iv) $11,247 for compression, power upgrades and further development of our operated properties in the Catalina Unit; and (v) $1,449 for undeveloped leases and our other non-operated properties. These costs were slightly offset by the sale or transfers of non-operated leases. Cash expenditures during the nine months ended September 30, 2007 for capital projects were provided primarily by advances from our line of credit and funds received from the July 2007 Series A Preferred Stock offering.

During the nine months ended September 30, 2007, net cash provided by financing activities increased to $33,884, as compared to $5,541 in the same prior year period. The increase was largely due to the receipt of approximately $10 million in net proceeds from a public offering of common stock completed in January 2007 and approximately $38 million in net proceeds from a public offering of Series A Preferred Stock completed in July 2007. The net proceeds from these offerings were used to pay down the outstanding balance on our revolving line of credit and fund capital projects. The excess funds are held in short-term investments. Net pay downs on our line of credit during the nine months ended September 30, 2007 totaled $13,221, and the first quarterly dividend of $879 was paid on September 28, 2007. Dividends will continue to be paid on a quarterly basis on the Series A Preferred Stock in the future at a rate of $931 per quarter.

Off-Balance Sheet Arrangements

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

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

Capital Requirements

Our net capital expenditures for the fourth quarter of 2007 are expected to be approximately $34 million, depending on project participation, timing and resource availability. The projected spending will continue to focus on three primary areas: (i) new coal bed gas development drilling in the Atlantic Rim; (ii) new development drilling in the Pinedale Anticline; and (iii) ongoing exploratory drilling projects for conventional gas reserves in Wyoming and Nevada. We believe that the amounts available under our $50 million bank line of credit ($35 million borrowing base), together with the funds made available through the July 2007 Series A Preferred Stock offering and net cash provided by operating activities, will provide us with sufficient funds to maintain our current facilities and complete our 2007 capital expenditure program.

In May 2007, the record of decision on the Atlantic Rim Environmental Impact Study (“EIS”), which allows for the drilling of up to 1,800 coal-bed methane wells and 200 conventional oil and gas wells in the Atlantic Rim area, was published in the Federal Register and we announced our plans for additional development drilling to commence in mid-July 2007. During June 2007, we were informed by the U.S. Bureau of Land Management (“BLM”) that three separate coalitions of conservation groups appealed, or were in the process of appealing, the approval of the EIS, and we agreed to delay our plans to drill in the Atlantic Rim until August 6, 2007. We have contracted a third party, with extensive coal bed methane drilling and operating experience, to manage this project on our behalf. Construction commenced, as planned, on August 6, 2007, and drilling commenced on August 15, 2007. As of November 1, 2007, 22 wells have been drilled and cased. We intend to have 33 new CBM wells hooked up (including the 22 already drilled and cased), with the successful ones producing around the end of the year. Once the new wells establish sufficient production, the Cow Creek Field will become a part of the Catalina Unit. Double Eagle will then have a 73.84% working interest in the Catalina Unit. Additionally, Anadarko expects to drill 69 additional CBM wells in the Sun Dog Unit within the Atlantic Rim in which Double Eagle will then have approximately an 8.4% working interest. Drilling in the Sun Dog Unit commenced during the third quarter of 2007.

In addition to our ongoing Atlantic Rim, Pinedale Anticline and other projects, at September 30, 2007, we had four exploratory/development drilling projects:

•

The South Fillmore exploratory prospect.The South Fillmore PH State 16-1 (South Fillmore) was completed during the third quarter of 2006. During testing of the well in the winter of 2006-2007, mechanical problems developed in the borehole. The Company plans to re-perforate the well early in 2008, with the intention of completing the well as a producer. In July 2007, GMT Exploration Company LLC drilled the SJ Fee 11-9 well, in which the Company has a 50% working interest before payout and a 30% working interest after payout, one mile northwest of the initial South Fillmore well. The SJ Fee 11-9 well has been completed with a flow rate of approximately 2,250 Mcfe per day, and commercial gas sales are expected to begin in December 2007. GMT is in the process of building a three-mile pipeline to connect the SJ Fee 11-9 to a sales line. South Fillmore is within the same field as the GMT well and initially tested at a flow rate of about 1,260 Mcfe per day. The Company is currently evaluating the project and has plans to continue developing the area, including potentially drilling or participating in the drilling of additional wells.

•

The Nevada exploratory prospect.In August 2007, VF Neuhaus began drilling the Straight Flush #17-1 well in Huntington Valley, Nevada. Double Eagle had a 97.3% working interest in the well and further earned additional interests under six sections of land. No commercial deposits of oil and gas were identified, and the well was plugged in October 2007. Costs incurred through September 30, 2007 of $752 were charged to expense as dry hole costs. In accordance with FASB’s Interpretation No. 36, the costs incurred after the balance sheet date must be charged to expense in the period following the balance sheet date, or, in this case, the fourth quarter of 2007. Thus, there will be an additional expense for this well for dry hole costs, estimated at approximately $900, recognized in the fourth quarter of 2007.

•

The Cow Creek Unit Deep #2 prospect. We began drilling the Cow Creek Unit Deep #2, a planned Madison test well near our coalbed natural gas production field at Cow Creek, in 2006 and have drilled to a depth of 9,922 feet. We have identified the crest of the structure and will steer the well 700 feet to the southwest, drilling to a total depth of approximately 12,100 feet, to test the Tensleep Sandstone and Madison Limestone at the top of this anticline. We expect to have a rig back on this location by mid-2008. Since adopting FSP 19-1, the Company continually evaluates all existing capitalized exploratory well costs. As a result, the Company determined that $4,388 of capitalized costs related to the Cow Creek Unit Deep #2 well required write off in the quarter ended September 30, 2007.

•

The Christmas Meadows exploratory prospect.Drilling of the Unit #1 began in September 2006 and reached the originally planned total depth of 15,760 feet during the first quarter of 2007. The drilling did not find reservoir rocks with sufficient permeability and operations were suspended to assess alternative approaches to completing the project. Having met the governmental permitting obligation for the Unit test, the time-frame for drilling has been extended and the newly formed Main Fork Unit will have a term remaining that lasts at least until April 2009. The Company has further evaluated the structure and is working on plans to propose to its partners either to drill or farmout drilling to the deeper Nugget Sandstone. The Company anticipates contracting a rig or farming out the drilling, and re-entering this hole in mid-2008, after the winter weather has cleared from this high-elevation location.

•

At September 30, 2007, our combined remaining exploratory costs on the above projects were $9,088. In the event that these wells are unsuccessful, we may be required to impair all or a portion of the remaining costs incurred.

Line of Credit

As of September 30, 2007, the outstanding balance on the line of credit was $0 and the interest rate, calculated in accordance with the agreement at 1.125% below the posted Wall Street Journal Prime Rate, was 6.625% compared to 7.125% at September 30, 2006.

On July 5, 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. Net proceeds from the offering were approximately $38 million, after deducting underwriter discounts and offering expenses. A portion of the net proceeds from this offering were used to pay off the outstanding indebtedness on the Company’s revolving line of credit of approximately $17 million. The remaining proceeds were invested in 60 day commercial paper and in our over-night investment account.

We are subject to certain financial and non-financial covenants with respect to the above credit facility, including a requirement to maintain a current ratio, plus the line of credit availability, of at least 1.0 to 1.0. As of September 30, 2007, we were in compliance with all such covenants. Should any of the covenants with respect to the above credit facility be violated, and if we were unable to negotiate a waiver or amendment thereof, the lender would have the right to declare an event of default, terminate the remaining commitment and accelerate all principal and interest outstanding.

RESULTS OF OPERATIONS

Three months ended September 30, 2007 compared to the three months ended September 30, 2006

Oil and gas sales volume and price comparisons


	Three Months Ended September 30,								Percent			Percent
	2007				2006				Volume			Price
	Volume		Average Price		Volume		Average Price		Change			Change
Product:
Gas (Mcf)		749,497	$	4.79		744,212	$	5.38		1	%		-11	%
Oil (Bbls)		2,798	$	66.91		2,413	$	64.57		16	%		4	%
Mcfe		766,285	$	4.93		758,690	$	5.49		1	%		-10	%

For the three months ended September 30, 2007, total production increased 1% to 766,285 Mcfe, while oil and gas sales decreased 9% to $3,779, when compared to the same prior year period. The slight increase in production is due largely to an increase in production at the Madden Deep Unit, offset somewhat by decreased production at the Atlantic Rim and the Pinedale Anticline. During the three months ended September 30, 2007, average daily production at the Atlantic Rim decreased 4% to 4,948 Mcfe as compared to 5,168 Mcfe during the same prior year period, due largely to decreased production at Cow Creek, offset by production at the Sun Dog Unit. We began recognizing our share of Sun Dog production in the fourth quarter of 2006 and are currently in an under-produced position for prior year’s and current year’s production. We began receiving our share of current production and make up gas on August 1, 2007 for the Sun Dog Unit. We are also in an under-produced position for prior year’s production at the Doty Mountain Unit and began receiving make up gas on August 1, 2007. Average daily production at Cow Creek decreased 10% to 4,248 Mcfe, as compared to 4,745 Mcfe during the same prior year period, due largely to workovers that occurred in the third quarter of 2007. During the three months ended September 30, 2007, average daily production in the Pinedale Anticline decreased 14% to 1,933 Mcfe, as compared to 2,247 Mcfe in the prior year. These decreases are due to the shut-in of several Mesa wells during the third quarter of 2007 by the operator due to low natural gas prices in the Rockies, as well as normal production declines, offset somewhat by new wells that came on-line during the third quarter of 2007. The operator at the Mesa Units has informed us that it intends to drill an additional 34 wells from the last half of 2007 through the summer of 2008 to increase production levels. During the three months ended September 30, 2007, average daily production at Madden Deep was 290 Mcfe. We began recognizing production from the Madden Deep Unit during the fourth quarter of 2006. The decrease in the third quarter production, compared to average daily production for the nine months ended September 30, 2007, of 538 Mcfe, was largely due to workovers in the area.

During the three months ended September 30, 2007, our average gas prices decreased 11%, from $5.38 to $4.79, as compared to a decrease of 47% in the average CIG index price. Our average price did not decrease as much as index due to our fixed price contracts in place during the quarter. See additional comments under “Contracted Volumes” below.

Transportation revenue

During the three months ended September 30, 2007, we recorded $242 in transportation revenue for moving third party gas through our intrastate gas pipeline, which connects the Cow Creek Field with the interstate pipeline system owned by Southern Star Central Gas Pipeline, Inc.

Oil and gas production expenses, depreciation, depletion and amortization


	Three Months Ended September 30,
	2007			2006
	(in dollars per Mcfe)
Average price	$	4.93		$	5.49

Production costs		1.32			1.12
Production taxes		0.61			0.67
Depletion and amortization		1.52			1.47

Total operating costs		3.45			3.26


Gross margin	$	1.48		$	2.23

Gross margin percentage		30	%		41	%

During the three months ended September 30, 2007, well production costs increased 19% to $1,009, as compared to $849 during the same prior year period, and production costs in dollars per Mcfe increased 18%, or $0.20 to $1.32, as compared to the same prior year period. The increase in production is largely attributed to an increase of $173 in transportation costs and lease operating expenses at our Madden Deep, Doty Mountain and Sun Dog Units (all of which began producing in the second half of 2006).

During the three months ended September 30, 2007, total depreciation, depletion and amortization expenses increased 3% to $1,349 as compared to $1,304 in the same prior year period, and depletion and amortization related to producing assets increased 5% to $1,165 as compared to $1,113 in the same prior year period. The increase is due primarily to production beginning at the Sun Dog and Madden Deep Units during the fourth quarter of 2006, and an increase in capital expenditures at the Mesa Units. Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased 3%, or $0.05, to $1.52, as compared to the same prior year period.

General and administrative

During the three months ended September 30, 2007, general and administrative expenses increased 29% to $1,105, as compared to $858 in the same prior year period. This increase is primarily due to increased compensation expense to board members, higher quarterly stock option expense and increases in external professional fees. These items were partially offset by the reduction of external financial consulting costs.

Income taxes

During the three months ended September 30, 2007, we recorded an income tax benefit of $2,225 as compared to an income tax expense of $183 during the same prior year period. 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 2007 at an expected federal and state rate of approximately 35.5%, which is different than the third quarter effective tax rate of approximately 31.7%. The rate differential from the statutory rate of 35.5% is the result of permanent income tax differences.

Nine months ended September 30, 2007 compared to the nine months ended September 30, 2006

Oil and gas sales volume and price comparisons


	Nine Months Ended September 30,								Percent			Percent
	2007				2006				Volume			Price
	Volume		Average Price		Volume		Average Price		Change			Change
Product:
Gas (Mcf)		2,224,437	$	5.05		2,113,057	$	5.78		5	%		-13	%
Oil (Bbls)		9,998	$	58.34		10,098	$	59.84		-1	%		-3	%
Mcfe		2,284,425	$	5.17		2,173,645	$	5.89		5	%		-12	%

For the nine months ended September 30, 2007, total production increased 5% to 2,284,425 Mcfe, while oil and gas sales decreased 8% to $11,812, when compared to the same prior year period. The increase in production is due largely to increased production at the Atlantic Rim and the Madden Deep Unit, which was offset partially by decreased production at the Pinedale Anticline. During the nine months ended September 30, 2007, average daily production at the Atlantic Rim increased 3% to 4,714 Mcfe as compared to 4,595 Mcfe during the same prior year period, due largely to the recognition of our first production at the Doty Mountain and Sun Dog Units, which began during the second half of 2006, offset somewhat by decreased production at Cow Creek. Currently, we are in an under-produced position for prior year’s production at the Doty Mountain Unit and began receiving make up gas on August 1, 2007. We are also in an under-produced position for prior and current year’s production at the Sun Dog Unit and began receiving our share of current production and make up gas on August 1, 2007. Also during the nine months ended September 30, 2007, average daily production at Cow Creek decreased 8% to 4,099 Mcfe, as compared to 4,452 Mcfe during the same prior year period. The Cow Creek Field experienced operational issues due to severe winter weather, which resulted in unscheduled workovers during the first half of 2007. Cow Creek production increased, as expected, late in the second quarter when the workovers were completed. Workovers during the third quarter also contributed somewhat to the decreased production.

During the nine months ended September 30, 2007, average daily production in the Pinedale Anticline decreased 11% to 2,248 Mcfe, as compared to 2,532 Mcfe in the prior year. The Mesa Units’ decrease is the result of shut-in production by the operator during the third quarter of 2007 due to low natural gas prices, as well as normal production declines, offset somewhat by new wells that came on-line during the second half of 2006 and the third quarter of 2007. The operator at the Mesa Units has informed us that it intends to drill an additional 34 wells from the last half of 2007 through the summer of 2008 to increase production levels. During the nine months ended September 30, 2007, average daily production at Madden Deep was 538 Mcfe. We began recognizing production from Madden Deep during the fourth quarter of 2006.

During the nine months ended September 30, 2007, our average gas prices decreased 13%, from $5.78 to $5.05, as compared to a 29% decrease in the average CIG index price. Our average price did not decrease as much as index due to our fixed price contracts in place. See additional comments in “Contracted Volumes” below.

Transportation and other revenue

During the nine months ended September 30, 2007, we recorded $675 in transportation revenue for moving third party gas through our intrastate gas pipeline, which connects the Cow Creek Field with the interstate pipeline system owned by Southern Star Central Gas Pipeline, Inc.

During the nine months ended September 30, 2007, we recorded $203 in other income, due largely to the first quarter gain on the sale of a 50% working interest in our Bad Water Creek Prospect to a third party, totaling $98, and the recognition of sulfur sales from the Lost Cabin Gas Processing Plant. Double Eagle acquired an interest in the Lost Cabin Gas Processing Plant through unitization in late 2006 and began receiving its share of sulfur sales in November 2006.

Oil and gas production expenses, depreciation, depletion and amortization


	Nine Months Ended September 30,
	2007			2006
	(in dollars per Mcfe)
Average price	$	5.17		$	5.89

Production costs		1.82			1.16
Production taxes		0.64			0.70
Depletion and amortization		1.62			1.34

Total operating costs		4.08			3.20


Gross margin	$	1.09		$	2.69

Gross margin percentage		21	%		46	%

During the nine months ended September 30, 2007, well production costs increased 64% to $4,160, as compared to $2,532 during the same prior year period, and production costs in dollars per Mcfe increased 57%, or $0.66, to $1.82, as compared to the same prior year period. The increase in production costs is largely attributed to an increase of $216 in transportation costs at our Madden Deep, Doty Mountain and Sun Dog Units (all of which began producing in the second half of 2006), gas purchase expense of $199, which was incurred to purchase volumes to fulfill the fixed delivery contracts at our Cow Creek Field and an increase of $726 in lease operating expenses and workovers at the Cow Creek Field. During the first quarter of 2007, production at our Cow Creek Field fell below our contracted volumes due to operational issues experienced as a result of severe winter weather. Volumes from the Cow Creek Field increased late in the second quarter as workovers in the field were completed.

During the nine months ended September 30, 2007, total depreciation, depletion and amortization expenses increased 18% to $4,094 as compared to $3,468 in the same prior year period, and depletion and amortization related to producing assets increased 27% to $3,697 as compared to $2,902 in the same prior year period. The increase is due primarily to production at Doty Mountain, Sun Dog and Madden Deep Units beginning the second half of 2006, and an increase in capital expenditures at the Mesa Units. Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased 21%, or $0.28, to $1.62, as compared to the same prior year period.

General and administrative

During the nine months ended September 30, 2007, general and administrative expenses increased 3% to $2,880, as compared to $2,806 in the same prior year period. This increase is due largely to increases in (1) salaries and related employee benefits from the hiring of additional personnel, (2) compensation expense to board members and (3) in legal and audit fees, somewhat offset by the reductions of (1) consulting expense relating to the implementation of our Sarbanes-Oxley systems, (2) stock option expense due to the departure of key personnel and (3) administrative expenses due to billings to joint interest partners during the second quarter.

Income taxes

During the nine months ended September 30, 2007, we recorded an income tax benefit of $2,544 as compared to an income tax expense of $777 during the same prior year period. 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 2007 at an expected federal and state rate of approximately 35.5%, which is different than the effective tax rate for the nine months ending September 30, 2007 of approximately 33.5%. The rate differential from the statutory rate of 35.5% is the result of permanent income tax differences.

CONTRACTED VOLUMES

Although we do not currently hedge our production prices, we entered into various fixed delivery contracts for our production from the Atlantic Rim and the Pinedale Anticline, allowing us to effectively “lock in” a portion of our production of natural gas at prices that we consider favorable. For the three and nine months ended September 30, 2007, the weighted average price of our contracted volumes exceeded the weighted average price for the open market volumes. The contracts resulted in additional revenue recognized by the Company, for the three and nine month periods, of $1.9 million and $3.8 million, respectively.

As of September 30, 2007, we had sales delivery contracts in effect for approximately 84% of our total current daily production (volume and daily production are expressed in Mcf):


	Remaining
	Contractual		Daily				Fixed
Property	Volume		Production		Term		Price/Mcf

Catalina		31,000		1,000		11/06-10/07	$	5.84
		609,000		1,000		06/07-05/09	$	5.47
		639,000		1,000		07/07-06/09	$	5.84
		1,278,000		2,000		07/07-06/09	$	5.69
Atlantic Rim		670,000		1,000		08/07-07/09	$	6.15
Pinedale Anticline		639,000		1,000		07/07-06/09	$	6.41

Company Total		3,866,000

We also entered into a new fixed delivery contract beginning November 1, 2007, to replace the contract above that expires on October 31, 2007, which keeps our total forward sales at November 1, 2007, at 84% of total current production, the terms of which are summarized as follows (volumes and daily production are expressed in Mcf):

Remaining

Contractual

Daily

Fixed

Property

Volume

Production

Term

Price/Mcf

Catalina

731,000

1,000

11/07-10/09

5.66

Additionally, the above Catalina contracted production volumes flow through our pipeline and are subject to a transportation agreement for which we receive a third party fee per Mcf.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2006, and to the Notes to the Consolidated Financial Statements included in Part I, Item 1 of this report.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risks

We pay interest on outstanding borrowings under our revolving credit facility at interest rates that fluctuate based upon changes in the prime lending rate. 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, 2007 of $0, the annual impact on interest expense for every 1.0% change in the average interest rate would be approximately $0 before taxes. However, if we have borrowings outstanding, for every $1 million of outstanding balance, a 1% increase in the interest rate will result in a $10 increase in annual interest expense.

Effective August 1, 2006, we entered into a $50 million revolving line of credit which replaced our previously existing revolving line of credit. As of September 30, 2007, the interest rate on the line of credit, calculated in accordance with the agreement at 1.125% below the posted Wall Street Journal Prime Rate, was 6.625%, and the balance outstanding was $0.

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 Rocky Mountain market prices applicable to our U.S. natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable for several years. The prices we receive for production depend on many factors outside of our control. For the quarter ended September 30, 2007, our income before income taxes would have changed by $60 for each $0.50 change per Mcf in natural gas prices and $2 for each $1.00 change per Bbl in crude oil prices.

Although we do not currently hedge our production prices, we have entered into various fixed delivery contracts for some of the production from the Atlantic Rim and the Pinedale Anticline, 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. As of September 30, 2007, we had sales delivery contracts in effect for approximately 84% of our total current daily production. These fixed delivery contracts, 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.”

ITEM 4. CONTROLS AND PROCEDURES

In accordance with the Securities Exchange Act of 1934 Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that because the material weakness relating to the Company’s timely and sufficient review of the information supplied by third party reserve engineers in the Company’s December 31, 2006 reserve report (previously identified in Item 9A, “Management’s Report on Internal Control over Financial Reporting” included in our Annual Report on Form 10-K for the year ended December 31, 2006) has not yet been remediated (for reasons described below), by definition our disclosure controls and procedures were ineffective as of September 30, 2007. Notwithstanding this material weakness, the Company’s management believes that the consolidated financial condition, results of operations and cash flow are fairly presented in this Form 10-Q.

In the first quarter of 2007, management designed and implemented enhanced control procedures to ensure the timely and sufficient review of information supplied by third party engineers. As this control is performed only on an annual basis at our fiscal year-end, the operating effectiveness of the remediated control has yet to be tested.

There has been no change in our internal control over financial reporting that occurred during the quarter ended September 30, 2007 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 were no material changes in our Risk Factors from those reported in Item 1A of Part I of our 2006 Annual Report on Form 10-K filed with the Securities and Exchange Commission, which we incorporate by reference herein. The Risk Factors in Item 1A of our 2006 Annual Report on Form 10-K should be read in conjunction with the Risk Factors reported in our Prospectus Supplement (to Prospectus Dated December 15, 2006) filed on June 29, 2007, and incorporated by reference herein.

ITEM 6. EXHIBITS

The following exhibits are filed as part of this report:

Exhibit Number and Description:

3.1

Amended Articles of Incorporation (incorporated by reference from Exhibit 3.1 of the Company’s Current Report on Form 8-K, filed on August 28, 2007).

4.2

Shareholder Rights Agreement (incorporated by reference from Exhibit 4.1 of the Company’s Current Report on Form 8-K, filed on August 24, 2007).

13.1

S-15 to S-21 of Prospectus Supplement (to Prospectus dated December 15, 2006) filed on June 29, 2007.

31.1

Certification of Chief 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 pursuant to Rule 13a-14(a) and Rule 15a-14(a) of the Securities Exchange Act, as amended.

Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

SIGNATURES

In accordance with 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: November 6, 2007	By:	/s/ Lonnie R. Brock
		Lonnie R. Brock
		Chief Financial Officer

EXHIBIT INDEX


Exhibit Number		Description

Exhibit 3.1		Amended Articles of Incorporation (incorporated by reference from Exhibit 3.1 of the Company’s Current Report on Form 8-K, filed on August 28, 2007).

Exhibit 4.2		Shareholder Rights Agreement (incorporated by reference from Exhibit 4.1 of the Company’s Current Report on Form 8-K, filed on August 24, 2007).

Exhibit 13.1		S-15 to S-21 of Prospectus Supplement (to Prospectus dated December 15, 2006) filed on June 29, 2007.

Exhibit 31.1		Certification of Chief Executive Officer pursuant to Rule 13a — 14(a) and Rule 15a — 14(a) of the Securities Exchange Act, as amended.

Exhibit 31.2		Certification of Chief Financial Officer pursuant to Rule 13a — 14(a) and Rule 15a — 14(a) of the Securities Exchange Act, as amended.

Exhibit 32		Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes — Oxley Act of 2002.

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	H.S. sophomore Good

Escalera Resources (ESCR) Inactive 10-Q2007 Q3 Quarterly report

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