Escalera Resources (ESCR) 10-Q 2006 Q1 Quarterly report

U.S. 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 March 31, 2006

Commission File Number 0-6529

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

For the transition period from                                        to                                        

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.)

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

307-237-9330
(Issuer’s telephone number)

NOT APPLICABLE
(Former name, former address, and former fiscal year, if changed
since last report)

Check whether the issuer (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 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 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

Common stock, 8,628,604 shares having a par value of $.10 per share were outstanding as of April 24, 2006.

DOUBLE EAGLE PETROLEUM CO.

TABLE OF CONTENTS

	Page
PART I. FINANCIAL INFORMATION:
Item 1. Financial Statements
Balance Sheets as of March 31, 2006 (Unaudited) and December 31, 2005		4
Statements of Operations for the three months ended March 31, 2006 and 2005 (Unaudited)		5
Statements of Cash Flows for the three months ended March 31, 2006 and 2005 (Unaudited)		6
Notes to Financial Statements		7
Item 2. Management’s Discussion and Analysis of Financial Conditions and Results of Operations		13
Item 3. Quantitative and Qualitative Disclosures About Market Risk		19
Item 4. Controls and Procedures		19
PART II. OTHER INFORMATION
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		20
Item 6. Exhibits		20
Signatures		20
Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15a-14(a)
Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15a-14(a)
Certification of Chief Executive Officer and Chief Financial Officer Pursuant to Section 906

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

3

DOUBLE EAGLE PETROLEUM CO.

BALANCE SHEETS

At March 31, 2006 and December 31, 2005

	March 31,			December 31,
	2006			2005
ASSETS	(Unaudited)
Current assets
Cash and cash equivalents	$	1,136,882		$	1,430,977
Accounts receivable		2,414,587			4,247,573
Other current assets		134,393			217,703
Total current assets		3,685,862			5,896,253
Oil and gas properties and equipment, successful efforts method
Developed properties		41,944,832			41,145,800
Wells in progress		4,178,974			2,946,260
Gas Pipeline		5,378,589			5,378,589
Undeveloped properties		3,245,926			3,212,955
Corporate and other assets		990,627			748,432
		55,738,948			53,432,036
Less accumulated depreciation, depletion and impairment		(16,170,264	)		(15,173,628	)
Net properties and equipment		39,568,684			38,258,408
Other assets		56,079			56,079
Total assets	$	43,310,625		$	44,210,740
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable	$	1,316,048		$	2,009,527
Accrued expenses		1,603,850			5,033,521
Accrued production taxes		1,678,642			1,657,164
Total current liabilities		4,598,540			8,700,212
Noncurrent liabilities
Line of credit		4,500,000			3,000,000
Asset retirement obligation		519,272			513,272
Deferred tax liability		2,671,000			2,219,000
Total noncurrent liabilities		7,690,272			5,732,272
Total liabilities		12,288,812			14,432,484
Commitments and contingencies (Notes 3, 4 and 7)
Stockholders’ Equity
Common stock, $0.10 par value; 50,000,000 shares authorized; issued and outstanding 8,628,604 and 8,590,604 shares as of March 31, 2006 and December 31, 2005, respectively		862,860			859,060
Capital in excess of par value		22,502,425			22,100,867
Retained earnings		7,656,528			6,818,329
Total stockholders’ equity		31,021,813			29,778,256
Total liabilities and stockholders’ equity	$	43,310,625		$	44,210,740

See accompanying notes to financial statements

4

DOUBLE EAGLE PETROLEUM CO.

STATEMENTS OF OPERATIONS

For the Three Months Ended March 31, 2006 and 2005

(Unaudited)

	2006			2005
Revenues
Oil and gas sales	$	4,593,191		$	4,563,950
Other income		13,560			11,188
Total revenues		4,606,751			4,575,138
Costs and Expenses
Production costs		875,776			830,662
Production taxes		523,138			491,044
Exploration expenses including dry holes		31,588			77,734
General and administrative		868,394			589,432
Depreciation, depletion and amortization of oil and gas properties		996,635			983,344
Impairment of equipment and properties		—			357,000
Total costs and expenses		3,295,531			3,329,216
Income from operations		1,311,220			1,245,922
Other income (expense)		—			(6,854	)
Interest income (expense), net		(21,021	)		10,446
Income before income taxes		1,290,199			1,249,514
Provision for deferred taxes		(452,000	)		(425,000	)
Net income	$	838,199		$	824,514
Net income per common share – basic	$	.10		$	.10
Net income per common share – diluted	$	.10		$	.09
Weighted average shares outstanding – basic		8,616,693			8,534,682
Weighted average shares outstanding – diluted		8,655,616			8,755,847

See accompanying notes to financial statements

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DOUBLE EAGLE PETROLEUM CO.

STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2006 and 2005
(Unaudited)

	2006			2005
Cash flows from operating activities:
Net income	$	838,199		$	824,514
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion of asset retirement obligation		1,002,636			987,095
Abandonment of non-producing properties		299			17,176
Impairment of equipment		—			357,000
Deferred income taxes		452,000			425,000
Noncash employee stock option expense		112,357			—
Decrease (increase) in operating assets and liabilities:
Accounts receivable		1,832,986			21,456
Other current assets		83,310			(38,021	)
Accounts payable and accrued expenses		(825,148	)		(165,891	)
Accrued production taxes		21,478			56,993
Net cash provided by operating activities		3,518,117			2,485,322
Cash flows from investing activities:
Proceeds from sales of properties and assets		—			10,934
Other assets		—			(25,000	)
Additions of producing properties and equipment		(5,329,747	)		(3,292,527	)
Additions of corporate and non-producing properties		(275,465	)		(224,931	)
Net cash used in investing activities		(5,605,212	)		(3,531,524	)
Cash flows from financing activities:
Exercise of options and warrants		293,000			380,048
Borrowings on line of credit		1,500,000			—
Net cash provided by financing activities		1,793,000			380,048
Change in cash and cash equivalents		(294,095	)		(666,154	)
Cash and cash equivalents at beginning of period		1,430,977			3,669,950
Cash and cash equivalents at end of period	$	1,136,882		$	3,003,796
Supplemental disclosures of cash and non-cash transactions:
Cash paid for interest	$	69,063		$	—
Additions to developed properties included in current liabilities	$	1,460,000		$	2,474,000
Equity contributions related to non-qualified options	$	—		$	71,000

See accompanying notes to financial statements

6

DOUBLE EAGLE PETROLEUM CO.

NOTES TO FINANCIAL STATEMENTS

1.	Summary of Significant Accounting Policies
	The financial statements have been prepared by the Company without audit pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in the financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted as allowed by such rules and regulations, and management believes that the disclosures are adequate to make the information presented not misleading. These financial statements include all of the adjustments, which, in the opinion of management, are necessary to a fair presentation of financial position and results of operations. All such adjustments are of a normal and recurring nature only, except for the impairment charge noted below. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full fiscal year. These financial statements should be read in conjunction with the audited financial statements at December 31, 2005, included in the Company’s Annual Report on Form 10-K.
	New Accounting Pronouncements
	In February 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard 155 – Accounting for Certain Hybrid Financial Instruments (“SFAS 155”), which eliminates the exemption from applying SFAS 133 to interests in securitized financial assets so that similar instruments are accounted for similarly regardless of the form of the instruments. SFAS 155 also allows the election of fair value measurement at acquisition, at issuance, or when a previously recognized financial instrument is subject to a re-measurement event. Adoption is effective for all financial instruments acquired or issued after the beginning of the first fiscal year that begins after September 15, 2006. Early adoption is permitted. The adoption of SFAS 155 is not expected to have a material effect on our consolidated financial position, results of operations or cash flows.
	In March 2006, the FASB issued Statement of Financial Accounting Standard 156 – Accounting for Servicing of Financial Assets (“SFAS 156”), which requires all separately recognized servicing assets and servicing liabilities to be initially measured at fair value. SFAS 156 permits, but does not require, the subsequent measurement of servicing assets and servicing liabilities to be initially measured at fair value. Adoption is required as of the beginning of the first fiscal year that begins after September 15, 2006. Early adoption is permitted. The adoption of SFAS 156 is not expected to have a material effect on our consolidated financial position, results of operations or cash flows.
2.	Stock-Based Compensation and Shared Based Payments
	Double Eagle has outstanding stock options issued to certain employees under four stock-option plans, approved by the Company’s shareholders (collectively “the Stock Option Plans”). On occasion, the Board of Directors also grants stock options not covered under the plans approved by the shareholders to individuals that perform services for the Company. Options were granted with an exercise price equal to the market price of Double Eagle’s stock on the date of grant, vest annually over various periods from two to five years of continuous service, and expire ten years from the date of grant.

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DOUBLE EAGLE PETROLEUM CO.
NOTES TO FINANCIAL STATEMENTS (continued)

Effective January 1, 2006, Double Eagle adopted the provisions of Statement of Financial Accounting Standard No. 123(R), “Share-Based Payment,” (“SFAS No. 123(R)”) for its share-based compensation plans. Double Eagle previously accounted for these plans under the recognition and measurement principles of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” (“APB No. 25”), and related interpretations and disclosure requirements established by SFAS No. 123, “Accounting for Stock-Based Compensation,” as amended by SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure.”

Under APB No. 25, no compensation expense was recorded for Double Eagle’s stock options issued under the qualified plan. The pro forma effects on net earnings and earnings per share for qualified stock options were instead disclosed in a footnote to the financial statements. Under APB No. 25, compensation expense for non-qualified stock options with stock appreciation rights features were recorded utilizing the market price of Double Eagle’s stock at each period-end to determine the vested intrinsic value of the stock appreciation rights.

Under SFAS No. 123(R), share-based compensation cost is measured at fair value. Double Eagle utilizes the Black-Scholes valuation model to determine the fair value of each option award. 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, contractual expiration dates, historical trends in Double Eagle’s stock price, and historical exercise behavior. The risk-free rates for periods within the contractual life of the options are based on the yields of U.S. Treasury instruments with terms comparable to the estimated option terms. Share-based compensation expense recognized in earnings for the three months ended March 31, 2006 of $112,000 is reflected in “General and administrative” expense in the Condensed Consolidated Statements of Operations.

The following assumptions were used in estimating fair value for all options previously granted during the three months ended March 31, 2005:

Weighted-average volatility	53%
Expected dividends	0.0%
Expected term (in years)	3.0 to 8.0
Risk-free rate	3.5%

Compensation cost for equity-classified awards, such as Double Eagle’s stock options issued under the qualified plan, is measured at the grant date based on the fair value of the award and is recognized as an expense in earnings over the requisite service period using a graded vesting method. Total share-based compensation expense for equity-classified awards vested in the three months ended March 31, 2006 was $112,000. There was no impact on income tax expense. During the three months ended March 31, 2006, the Company recorded stock option exercises and stock option forfeitures/expirations, as shown in the following table. There were no qualified option grants during the reporting period.

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DOUBLE EAGLE PETROLEUM CO.
NOTES TO FINANCIAL STATEMENTS (continued)

A summary of equity-classified share options as of the beginning and end of the three months ended March 31, 2006, is presented below:

						Weighted-
				Weighted-		Average
				Average		Remaining
				Exercise		Contractual
Options	Shares			Price		Term (Years)
Outstanding at January 1, 2006		354,243		$	15.38		4.5
Stock Option Grants		—		$	—		—
Stock Option Exercises		(38,000	)	$	7.71		—
Stock Option Forfeitures / Expirations		(20,000	)	$	18.18		—
Outstanding at March 31, 2006		296,243		$	16.22		4.7
Exercisable at March 31, 2006		100,410		$	15.21		3.5

The total intrinsic value, or the difference between the exercise price and the market price on the date of exercise, of all options exercised during the quarterly period ended March 31, 2006 was approximately $431,000. Cash received from stock options exercised during the quarterly period ended March 31, 2006 was $293,000. Shares available for grant under the Stock Option Plans as of March 31, 2006 were 248,371.

Stock options outstanding and currently exercisable at March 31, 2006 are as follows:

	Options Outstanding						Options Exercisable
			Weighted Average
			Remaining		Weighted				Weighted
Range of	Number of		Contractual		Average		Number of		Average
exercise	Options		Life		Exercise		Options		Exercise
prices	Outstanding		(in years)		Price		Exercisable		Price
$    6.31— 14.83		136,743		5.5	$	13.48		64,410	$	13.29
18.01—19.44		159,500		3.3		18.69		36,000		18.66
		296,243		4.7	$	16.22		100,410	$	15.21

Total estimated unrecognized compensation cost from unvested stock options as of March 31, 2006 was approximately $ 2.2 million, which is expected to be recognized over a weighted average period of approximately 5.74 years.

Double Eagle adopted SFAS No. 123(R) using the modified prospective method. Under this transition method, compensation cost recognized in the three months ended March 31, 2006, includes the cost for options vested during the period which were granted prior to January 1, 2006, as determined under the provisions of SFAS No. 123(R). Share-based compensation costs for the

9

three months ended March 31, 2006 of $112,000 is reported in “General and administrative” expense in the Condensed Consolidated Statement of Operations. There was no cumulative effect of the impact of adoption of SFAS No. 123(R) on liability-classified awards to the condensed consolidated financial statements. Results for prior periods have not been restated.

The following table illustrates the effect on net earnings and earnings per share as if the fair-value recognition provisions of SFAS No. 123(R) were applied to all of its share-based compensation awards for the prior year period:

	Three months ended
	March 31, 2005
Net earnings, as reported	$	824,514
Add: Share-based employee compensation expense included in reported net earnings		6,400
Deduct: Total share-based employee compensation expense determined under the fair value based method for all awards		(189,000	)
Pro forma net earnings	$	641,914
Basic Earnings Per Share:
As reported	$	0.10
Pro forma	$	0.09
Diluted Earnings Per Share:
As reported	$	0.08
Pro forma	$	0.07

3.   Earnings per share

Basic earnings per share (“EPS”) is calculated by dividing net income (the numerator) by the weighted average number of shares of common stock outstanding during the period (the denominator). Diluted earnings per share incorporates 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.

10

The following is the calculation of basic and diluted weighted average shares outstanding and EPS for the indicated periods (000s omitted, except per share data):

	Three months ended
	March 31,
	2006		2005
Income (numerator)
Net Income – basic	$	838,199	$	824,514
Net Income — diluted	$	838,199	$	824,514
Weighted average shares (denominator)
Weighted average shares – basic		8,616,693		8,534,682
Dilutive effect of stock options outstanding at the end of period		38,923		221,165
Weighted average shares – diluted		8,656,616		8,755,847
Earnings per share:
Basic	$	0.10	$	0.10
Diluted	$	0.10	$	0.09

4. Impairment of Long-Lived Assets

SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” (“SFAS 144”) requires that an asset be evaluated for impairment when the carrying amount of an asset exceeds the sum of the undiscounted estimated future cash flows of the asset. In accordance with the provisions of SFAS 144, 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 evaluation, consist primarily of oil and gas properties. During the three month period ended March 31, 2005, the Company recognized a non-cash charge of $357,000 on electrical generating equipment at Cow Creek that was replaced in the second quarter of 2005. During the first quarter of 2006, the Company did not recognize any impairments.

During the quarter ended March 31, 2006, the Company completed work on a new transmission pipeline at Cow Creek. The newly operational pipeline is recorded at its total cost of $5,400,000. Depreciation is recorded using the straight line method over a 25 year estimated useful life.

5. Income Taxes

At December 31, 2005, the Company had a net operating loss carry forward for regular income tax reporting purposes of approximately $12.4 million that will begin expiring in 2007. Although Double Eagle records income tax expense for financial reporting purposes, we do not anticipate any payments of current tax liabilities in the near future as a result of our net operating loss carry forward.

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A reconciliation of the Company’s effective tax rate to the expected federal tax rate is as follows:

	For the three months ended
	March 31,
	2006			2005
Expected federal tax rate		35	%		34	%
Change in valuation allowance and other		—			—
Effective tax rate		35	%		34	%

6. Line of Credit

As part of its cash management program, the Company maintains a $9 million revolving line of credit collateralized by oil and gas producing properties. The interest rate on the line of credit is one half percent below the prime rate published in the Wall Street Journal. The interest rate on the line of credit was 7.25% at March 31, 2006. All outstanding balances on the line of credit mature on September 30, 2007. As of March 31, 2006, the Company had drawn down $4.5 million against the line of credit to fund capital expenditures.

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DOUBLE EAGLE PETROLEUM CO.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

Double Eagle Petroleum Co. (“Double Eagle” or the “Company”) is an independent energy company engaged in the exploration, development, and production of natural gas and crude oil in the Rocky Mountain Basins of the Western United States. Our principal properties are located in Southwestern Wyoming. We have tight gas reserves and production from the Pinedale Anticline and coal bed methane reserves and production in the Eastern Washakie Basin.

We intend to increase our reserves, production, revenues, and cash flow by focusing on: (i) new coal bed gas development and enhancement of field facilities on operated and non-operated properties in the Eastern Washakie Basin; (ii) continued participation in the development of the Mesa Field on the Pinedale Anticline; and, (iii) selective pursuit of high potential exploration projects where we have accumulated detailed geological knowledge and developed significant management expertise.

Following are summary comments of our performance in several key areas during the three months ended March 31, 2006:

• Average daily production decreased 21% to 7,121 mcfe per day during the first three months of 2006, as compared to 8,970 mcfe per day during the first three months of 2005. The decrease in production is attributed to reduced gas flow rates at Cow Creek and the Mesa field. At Cow Creek, well maintenance and repairs, completed during the second quarter, have increased average daily production by 33% to 4,800 mcf, net to the Company, from 3,600 mcf during the first quarter of 2006. At Mesa, the operator has represented to the Company that new drilling is scheduled later in 2006 to increase production.

• Oil and gas revenues remained essentially unchanged at $4.6 million during the three months ended March 31, 2006 from the same period in 2005. Revenues remained flat despite a 27% decrease in gas production due to a 26% increase in gas prices.

• Net cash provided by operating activities increased 41% to $3.5 million in the first three months of 2006 from $2.5 million in the first three months of 2005 primarily due to a reduction in accounts receivable.

• In early January, 2006, we began transporting our equity gas through our recently completed intrastate gas pipeline connecting the Cow Creek field with Southern Star Central Gas Pipeline, Inc. The 13-mile pipeline provides the Company with full access to the interstate gas markets from southern Wyoming. The pipeline was constructed at a cost of approximately $5.4 million and will provide reliable transportation for future development by the Company in the Eastern Washakie Basin.

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FACTORS AFFECTING FINANCIAL CONDITION AND LIQUIDITY

Liquidity and Capital Resources

During the three months ended March 31, 2006, our working capital deficit was reduced by $1.9 million to $0.9 million. The change reflects a $4.1 million reduction in accounts payable and accrued liabilities during the quarter. The reduction in current liabilities was funded by cash flow from operations and a $1.5 million draw on our line of credit. We believe that the capital resources available to the Company will be adequate to continue our strategic plan, including continued development of our major natural gas projects in the Eastern Washakie Basin and the Pinedale Anticline, as well as our pursuit of certain significant exploration projects including a conventional gas Madison test in the Cow Creek field and the completion of our exploratory deep test at Christmas Meadows. We anticipate capital resources to fund this activity will be available in part through future operating cash flow and in part through a new credit facility which is anticipated to be completed by the end of the second quarter.

At March 31, 2006, we had assets totaling $43.3 million. Our total capitalization was $35.5 million, 87% of which was represented by stockholders’ equity. During the first three months of 2006, net cash flow provided by operating activities was $3.5 million which represents a 41% increase over the same period in 2005. The cash flow increase in the current three month period is attributed primarily to an increase in working capital through the collection of receivables partially offset by a reduction in current liabilities. During the first three months of 2006, we invested $2.3 million in capital projects, of which, $1.5 million remained in current liabilities at March 31, 2006. In addition, we funded $4.8 million of development project costs incurred in 2005 that were included in current liabilities at December 31, 2005. The $5.6 million of cash expenditures during 2006 for capital projects were provided, in part, by advances from our line of credit.

During the first quarter of 2006, we invested $0.5 million to drill to the South Fillmore exploratory test which we anticipate will be completed later in the year. We also invested $1.1 million at our Cow Creek field in Carbon County, Wyoming, to open new coal seams and prepare to drill a Madison deep test. The 13-7A well, drilled in 2005, is being completed as a water injection well. We also expended an additional $0.3 million for our share of costs incurred by Anadarko at Doty Mountain for the drilling project which began in 2004. As the dewatering of the coal bed methane wells continues, we are not yet taking our share of production but intend to do so during the second quarter and transport the gas to markets available through our new pipeline. The Company is under produced as to its entitled production at March 31, 2006.

Off-Balance Sheet Financing

The Company has no off-balance sheet financing arrangements at March 31, 2006.

Capital Requirements

Our capital expenditures for the remaining three quarters of 2006 are expected to be approximately $21 million depending on project participation and resource availability. The projected spending will continue to focus on three primary areas: (i) new exploratory drilling for conventional gas reserves in the Eastern Washakie Basin and at Christmas Meadows; (ii) new coal bed gas development drilling in the Eastern Washakie Basin in the Catalina Unit which will include our Cow Creek field; and, (iii) selected new development and exploration projects through which we will attempt to pursue both unconventional and conventional gas accumulation. Since project spending is expected to exceed funds

14

available from current cash flow and existing cash reserves, we intend to utilize funds made available through a new credit facility.

We commenced two exploratory drilling projects in 2005, the Christmas Meadows prospect in Northeast Utah and a Madison test near our coalbed natural gas production at Cow Creek. At December 31, 2005, the combined cost of the two projects was $3.0 million. In the first quarter of 2006, we began drilling the Fillmore prospect, north of the Cow Creek field. The cost incurred to drill this well aggregated $.7 million during the quarter. We expect to complete all three of these projects in 2006 at an additional estimated cost of $3.3 million. We have also budgeted approximately $4.4 million to drill the Cow Creek Deep #2, and the Rattlesnake prospect. In the event that these exploratory wells are unsuccessful, we may be required to impair all or a portion of the costs incurred in 2005 and 2006.

Line of Credit

In October 2005, we renewed our $9 million line of credit with our bank. The line of credit is secured by our oil and gas properties, may be adjusted periodically for changes in reserves and production pricing and matures in September 2007. Interest on borrowings against the line of credit is assessed at 50 basis points below the Wall Street Journal’s prime rate, which results in a rate to the Company of 7.25% at March 31, 2006. As of March 31, 2006, the Company had drawn down $4.5 million against this line of credit. The Company is considering a new credit facility which would significantly increase available borrowings.

RESULTS OF OPERATIONS

Three months ended March 31, 2006 compared to three months ended March 31, 2005

Oil and gas sales volume and price comparisons for the indicated periods are set forth below.

	Three Months Ended March 31,								Percent			Percent
	2006				2005				Volume			Price
Product	Volume		Price		Volume		Price		Change			Change
Gas (mcf) (Mcf)		617,897	$	7.10		781,765	$	5.61		-21	%		+27	%
Oil (bbls)		3,836	$	54.04		4,262	$	41.65		-10	%		+30	%
Mcfe		640,911	$	7.17		807,336	$	5.65		-21	%		+27	%

Oil and gas sales remained essentially unchanged in the first three months of 2006, compared to the same period in 2005, at approximately $4.6 million. Gas production during the three months ended March 31, 2006, decreased by 21%. The decrease is primarily attributable to reductions in production at Cow Creek and Mesa. As of April 30, 2006, production at Cow Creek was increased by 33%, to 4,800 mcf per day, net to the Company, from 3,600 mcf per day during the first three months ended March 31, 2006. Stronger pricing in the period ended March 31, 2006, over the same period of a year ago allowed revenue to remain unchanged. Production decreased by 23% from the Mesa B and Mesa C fields primarily due to normal production decline. Similar to revenues, production costs and production taxes increased minimally during the period. However, production decreases resulted in significant increases in unit costs on a per mcfe basis. Depletion and depreciation expense for the period was comparable to the corresponding first quarter in 2005 despite a decrease in production. The per unit

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cost of depletion and depreciation increased in the first quarter of 2006 primarily as a result of additional capital spending at Cow Creek to provide support facilities for power, compression, and water injection, as well as new spending for pipeline transportation facilities. However, the gross margin per mcfe increased by 23% during the first three months of 2006.

	$ Per mcfe
	2006			2005
Average price	$	7.17		$	5.65
Production costs		1.37			1.03
Production taxes		.82			.61
Depreciation, depletion, amortization		1.56			1.22
Total operating costs		3.75			2.86
Gross margin	$	3.42		$	2.79
Gross margin percentage		48	%		49	%

Although we do not currently hedge our production prices, we have entered into fixed delivery contracts for approximately 28% of the current daily production at March 31, 2006. As of April 1, 2006, we had the following sales delivery contracts in effect on our production (Volume and Daily Production are expressed in mcfs):

Double Eagle Sales Contracts
	Contractual		Daily				Average
Property	Volume		Production		Term		Price ($)
Cow Creek		214,000		1,000		11/04-10/06	$	5.50
		365,000		1,000		04/05-03/07		6.00
Company Total		579,000

General and administrative expenses increased 47% to $868,000 in the first three months of 2006 compared to $589,000 in the first three months of 2005. The increase was attributed, in part, to the adoption of SFAS No.123(R) related to employee stock option expense totaling $112,000 which represents 40% of the increase in the first quarter. In addition, increases in professional fees for the implementation of Sarbanes-Oxley 404 totaling $81,000 represented 29% of the first quarter increase and, increased audit fees primarily associated with the Sarbanes-Oxley requirements to assess the adequacy and functionality of internal controls increased by $33,000 or 12% of the increase for the three months ended March 31, 2006.

Production costs increased 5% to $876,000 in the first three months of 2006 compared to $831,000 during the same period one year ago. The change represented a 33% increase, or $0.34 per mcfe to $1.37 in the first quarter of 2006 from $1.03 per mcfe in the first quarter of 2005. The production cost

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per unit increase is largely attributed to a 20% decrease in the current period production as compared to the same period of a year ago.

We anticipate an increase in production during the remainder of 2006 and, therefore, a reduction in production costs per mcfe for the duration of the year ended December 31, 2006.

During the three months ended March 31, 2006, we recorded an income tax expense of $452,000 compared to $425,000 during the three months end March 31, 2005. Although we expect to continue to generate losses for federal income tax reporting purposes, our sustained net operating income has resulted in a deferred tax position required under generally accepted accounting principles. We intend to recognize tax expense on operating income for the remainder of 2006 at an effective rate of approximately 35%. However, we do not anticipate any required payments for current tax liabilities in the near future.

Income from operations during the first three months of 2006 increased 3% to $1.29 million compared with $1.25 million during the same period in 2005. Similarly, net income increased by 2% during 2006, to $838,000 for the three months ending March 31, 2006 from $825,000 for the three months ending March 31, 2005.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our Financial Statements.

Reserve Estimates

Our estimates of oil and natural gas reserves, by necessity, are projections based on geological and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future oil and natural gas prices, future operating costs, severance and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our oil and gas properties and/or the rate of depletion of the oil and gas properties. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.

Many factors will affect actual net cash flows, including

• the amount and timing of actual production

• supply and demand for natural gas

• curtailments or increases in consumption by natural gas purchasers; and

• changes in governmental regulations or taxation

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Oil and Gas Properties

We use the successful efforts method of accounting for oil and gas producing activities. Under this method, acquisition costs for proved and unproved properties are capitalized when incurred. Exploration costs, including geological and geophysical costs, the costs of carrying and retaining unproved properties and exploratory dry hole drilling costs, are expensed. Development costs, including the costs to drill and equip development wells, and successful exploratory drilling costs that locate proved reserves, are capitalized. In addition, the Company limits the total amount of unamortized capitalized costs for each property to the value of future net revenues, based on current prices and costs. Depreciation, depletion and amortization of the capitalized costs for producing oil and gas properties are computed on the units-of-production method based on proved developed oil and gas reserves. Undeveloped properties are periodically reviewed for impairment based on management’s assessment of current market value.

Income Taxes

Deferred income taxes are provided on the difference between the tax basis of an asset or liability and its carrying amount in the financial statements. This difference will result in taxable income or deduction in future periods when the reported amount of the asset or liability is recovered or settled, respectively.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risks

At March 31, 2006, we had $4.5 million in outstanding debt. Amounts drawn against our $9 million line of credit bear interest at 50 basis points below the Wall Street Journal prime rate. The interest rate at March 31, 2006 was 7.25%.

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 natural gas and oil 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 three months ended March 31, 2006, our income before income taxes would have changed by $54,375 for each $0.10 change in natural gas prices and $3,370 for each $1.00 change in crude oil prices.

We do not currently enter into hedging of our production prices. However, we have entered into fixed delivery contracts for approximately 28% of the current daily production as of March 31, 2006. 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 – Results of Operations.”

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 report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2006 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

There has been no change in our internal control over financial reporting that occurred during the three months ended March 31, 2006 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

There were no unregistered sales of equity securities for the reporting period.

ITEM 6. EXHIBITS

Exhibit No.

31.1	Rule 13a-14(a)/15a-14(a) Certification of Chief Executive Officer
31.2	Rule 13a-14(a)/15a-14(a) Certification of Chief Financial Officer
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.

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: May 10, 2006	By:	/s/ David C. Milholm
		David C. Milholm
		Vice President of Finance and Chief Financial Officer (Principal Financial Officer)

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Exhibit Index

Exhibit No.

31.1	Rule 13a-14(a)/15a-14(a) Certification of Chief Executive Officer
31.2	Rule 13a-14(a)/15a-14(a) Certification of Chief Financial Officer
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.