Escalera Resources (ESCR) 10-Q 2005 Q2 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 June 30, 2005

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)

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 checkmark whether the registrant is an accelerated filer (as determined in Rule 12b-2 of the Exchange Act).

Yeso Noþ

Common stock, 8,575,604 shares having a par value of $.10 per share were, outstanding as of July 28, 2005.

DOUBLE EAGLE PETROLEUM CO.

TABLE OF CONTENTS

			Page
PART I. FINANCIAL INFORMATION:
	Item 1. Financial Statements
		Balance Sheets as of June 30, 2005 (Unaudited) and December 31, 2004		4
		Statements of Operations for the three months and six months ended June 30, 2005 and 2004 (Unaudited)		5
		Statements of Cash Flows for the six months ended June 30, 2005 and 2004 (Unaudited)		6
		Notes to Financial Statements		7
	Item 2. Management’s Discussion and Analysis of Financial Conditions and Results of Operations			10
	Item 3. Quantitative and Qualitative Disclosures About Market Risk			17
	Item 4. Controls and Procedures			17
PART II. OTHER INFORMATION
	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			18
	Item 4. Submission of Matters to a Vote of Security Holders			18
	Item 6. Exhibits			19
	Signatures			20
Rule 13a-14(a)/15a-14(a) Certification of CEO
Rule 13a-14(a)/15a-14(a) Certification of CFO
Certification of CEO and CFO Pursuant to Section 906

2

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

3

DOUBLE EAGLE PETROLEUM CO.

BALANCE SHEETS

At June 30, 2005 and December 31, 2004

	June 30,			December 31,
	2005			2004
	(Unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	2,694,562		$	3,669,950
Accounts receivable		1,951,808			2,171,102
Other current assets		300,784			328,677
Total current assets		4,947,154			6,169,729
Properties and equipment
Developed properties		37,550,516			32,293,958
Undeveloped properties		3,189,072			3,026,168
Corporate and other		694,148			624,153
		41,433,736			35,944,279
Less accumulated depreciation, depletion, amortization, and impairment		(13,462,392	)		(11,185,792	)
Net properties and equipment		27,971,344			24,758,487
Other assets		66,079			41,125
Total assets	$	32,984,577		$	30,969,341
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Accounts payable		2,465,027		$	1,597,224
Accrued expenses		718,327			2,890,630
Accrued production taxes		1,182,999			971,710
Total current liabilities		4,366,353			5,459,564
Non current liabilities
Asset retirement obligation		419,802			406,865
Deferred tax liability		1,001,000			176,000
Total non current liabilities		1,420,802			582,865
Total liabilities		5,787,155			6,042,429
Stockholders’ equity
Common stock, $.10 par value; 50,000,000 shares authorized; issued and outstanding 8,575,604 shares at June 30, 2005 and 8,488,404 at June 30, 2004		857,560			848,840
Capital in excess of par value		21,885,617			21,224,393
Retained earnings		4,454,245			2,853,679
Total stockholders’ equity		27,197,422			24,926,912
Total liabilities and stockholders’ equity	$	32,984,577		$	30,969,341

See accompanying notes to financial statements.

4

DOUBLE EAGLE PETROLEUM CO.

STATEMENTS OF OPERATIONS

For the Three and Six Months Ended June 30, 2005 and 2004

(Unaudited)

	For the three months ended					For the six months ended
	June 30,			June 30,		June 30,			June 30,
	2005			2004		2005			2004
Revenues
Oil and gas sales	$	4,333,823		$	3,403,504	$	8,897,773		$	5,568,768
Other income		13,200			16,432		24,388			38,426
Total revenues		4,347,023			3,419,936		8,922,161			5,607,194
Costs and Expenses
Production costs		931,171			402,367		1,761,833			686,846
Production taxes		471,154			349,421		962,197			617,787
Exploration expenses including dry holes		25,221			84,752		85,778			98,742
Write-offs and abandonments		23,557			19,876		40,732			30,794
General and administrative		775,188			389,640		1,364,620			700,221
Depreciation, depletion and amortization of oil and gas properties		953,952			761,744		1,937,298			1,258,163
Impairment of equipment		—			71,462		357,000			71,462
Total costs and expenses		3,180,243			2,079,262		6,509,458			3,464,015
Income from operations		1,166,780			1,340,674		2,412,703			2,143,179
Other expense		—			—		(6,854	)
Interest income, net		9,334			1,133		19,779			6,951
Income before income taxes		1,176,114			1,341,807		2,425,628			2,150,130
Provision for deferred taxes		(400,000	)		—		(825,000	)		—
Net income	$	776,114		$	1,341,807	$	1,600,628		$	2,150,130
Net income per common share — basic	$	.09		$	.16	$	.19		$	.25
Net income per common share — diluted	$	.09		$	.16	$	.19		$	.25
Weighted average shares outstanding — basic		8,562,283			8,468,338		8,548,559			8,454,173
Weighted average shares outstanding — diluted		8,624,999			8,593,799		8,621,980			8,594,844

See accompanying notes to financial statements

5

DOUBLE EAGLE PETROLEUM CO.

STATEMENTS OF CASH FLOWS

For the Six Months Ended, 2005 and 2004

(Unaudited)

	Six Months Ended June 30,
	2005			2004
Cash Flows from Operating Activities
Net income	$	1,600,628		$	2,150,130
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion of asset retirement obligation		1,946,448			1,339,325
Abandonment of non-producing properties		40,732			30,794
Impairment of equipment		357,000			—
Deferred income taxes		825,000			—
Directors fees paid in stock		160,286			54,240
Other		6,854			—
Decrease (increase) in operating assets and liabilities:
Accounts receivable		219,294			(1,009,861	)
Other current assets		(27,893	)		(104,341	)
Accounts payable and accrued expenses		(357,500	)		99,953
Accrued production taxes		211,289			336,708
Net cash provided by operating activities		5,037,924			2,896,948
Cash Flows from investing activities
Proceeds from sales of properties and assets		10,933			—
Other assets		(24,954	)		(570,042	)
Additions of producing properties and equipment		(6,199,771	)		(4,070,315	)
Additions of corporate and non-producing properties		(309,116	)		(28,371	)
Net cash used in investing activities		(6,522,908	)		(4,668,728	)
Cash flows from financing activities
Exercise of options and warrants		509,595			645,212
Net cash provided by financing activities		509,595			645,212
Decrease in cash and cash equivalents		(975,389	)		(1,126,568	)
Cash and cash equivalents at beginning of period		3,669,950			2,920,846
Cash and cash equivalents at end of period	$	2,694,562		$	1,794,278
Supplemental disclosures of cash and non-cash transactions
Cash paid for interest	$	—		$	473
Additions to developed properties included in accounts payable		1,200,000			—
Additions to developed properties for retirement obligations	$	3,787		$	—
Directors fees paid in stock	$	160,286		$	54,240

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, 2004 included in the Company’s Annual Report on Form 10-KSB.
	Stock-Based Compensation
	The Company has elected to follow APB Opinion No. 25 and related interpretations in accounting for its stock options and grants to employees and directors since the alternative fair market value accounting provided under Statement of Financial Accounting Standards (SFAS) No. 123 requires use of grant valuation models that were not developed for use in valuing employee stock options and grants. Under APB Opinion No. 25, if the exercise price of the Company’s stock grants and options equal the fair value of the underlying stock on the date of grant, no compensation expenses are recognized.
	If compensation cost for the Company’s stock-based compensation plans had been determined based on the fair value at the grant dates for awards under those plans consistent with the method of SFAS No. 123, then the Company’s net income per share would have been adjusted to the pro forma amounts indicated below:

	For the three months ended						For the six months ended
	June 30,			June 30,			June 30,			June 30,
	2005			2004			2005			2004
Net income as reported	$	776,114		$	1,341,807		$	1,600,628		$	2,150,130
Add: stock-based compensation
Included in reported net income		6,400			6,400			12,800			12,800
Deduct: stock-based compensation
Cost under SFAS 123		(213,000	)		(111,607	)		(401,000	)		(125,707	)
Pro forma net income	$	569,514		$	1,236,600		$	1,212,428		$	2,037,223
Pro forma basic and diluted net income per share:
Reported net income per common share — basic		.09			.16			.19			.25
Reported net income per common share — diluted		.09			.16			.19			.25
Pro forma net income per common share — basic		.07			.14			.14			.24
Pro forma net income per common share — diluted		.06			.14			.14			.24

7

DOUBLE EAGLE PETROLEUM CO.

NOTES TO FINANCIAL STATEMENTS Continued

Pro forma information regarding net income is required by SFAS 123. Options granted were estimated using the Black-Scholes valuation model. The following weighted average assumptions were used for the six months ended June 30, 2005 and six months ended June 30, 2004.

	For the six months ended June 30,
	2005			2004
Volatility		42	%		53	%
Expected term of options (in years)		3-8			3-8
Dividend yield		0.00	%		0.00	%
Risk free interest rate		3.5	%		3.5	%

2.	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 stock outstanding during the period.
	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				Six months ended
	June 30,		June 30,		June 30,		June 30,
	2005		2004		2005		2004
Income (numerator)
Net Income — basic	$	776	$	1,342	$	1,601	$	2,150
Net Income — diluted	$	776	$	1,342	$	1,601	$	2,150
Weighted average shares (denominator):
Weighted average shares — basic		8,562		8,468		8,549		8,454
Dilution effect of stock options outstanding at the end of period		63		126		73		141
Weighted average shares — diluted		8,625		8,594		8,622		8,651
Earnings per share:
Basic	$	.09	$	.16	$	.19	$	.25
Diluted	$	.09	$	.16	$	.19	$	.25

8

3.	Impairment of Long-Lived Assets
	SFAS 144,Accounting for the Impairment or Disposal of Long-Lived Assets, 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 first quarter of 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.
4.	Income Taxes
	At December 31, 2004, the Company had a net operating loss carryforward for regular income tax reporting purposes of approximately $5 million, which will begin expiring in 2007. Although we record 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 loss carryforward.
	Reconciliation of the Company’s effective tax rate to the expected federal tax rate is as follows:

	For the six months ended June 30,
	2005			2004
Expected federal tax rate		34	%		34	%
Permanent differences — change in valuation allowance		—			(34	%)
Effective tax rate		34	%		0	%

5.

Subsequent Event

On July 27, 2005, the Company entered into an agreement with Southern Star Central Gas Pipeline, Inc. (Pipeline) to construct an Interconnect Point on Pipeline’s Skull Creek Rawlins Pipeline, approximately 12 miles north of the Company’s Cow Creek field in south central Wyoming. The Interconnect facility will serve as an alternative delivery point for the Company’s Cow Creek production. In accordance with the terms of the agreement, the Company has prepaid the estimated facilities cost of $334,000. Construction of the facilities is expected to be completed by October 1, 2005.

9

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 methane development and enhancement of our field facilities 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 highlights of our performance in several key areas during the six months ended June 30, 2005:

• Daily production increased 33% in 2005, from 6,420 mcfe per day in the first six months of 2004 to 8,512 mcfe per day in 2005. The increase in production is attributed to higher gas flow rates from the drilling and completion of successful wells in our Cow Creek field late in the second quarter of 2004, as well as new wells drilled late in 2004 and early in 2005 at the Mesa B field.

• Revenues increased 59% from $5.6 million during the six months ended June 30, 2004 to $9.0 million during the same period in 2005 as a result of a 33% increase in daily production volumes and 21% increase in gas prices.

• Net cash provided by operating activities increased 74%, from $2.90 million in the first six months of 2004 to $5.04 million in the first six months of 2005.

• We incurred $5.26 million in development costs during the first six months of 2005. The development spending related primarily to our coal bed methane locations in the Eastern Washakie Basin and to our participation in the development drilling on the Pinedale Anticline.

FACTORS AFFECTING FINANCIAL CONDITION AND LIQUIDITY

Liquidity and Capital Resources

During the first half of 2005, our working capital decreased from $710,000 at December 31, 2004 to $581,000 at June 30, 2005. We have no long-term debt at June 30, 2005. We anticipate that we will maintain adequate resources 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

10

pursuit of certain exploratory projects. Capital resources to fund this activity will be available through future operating cash flow and the availability of a bank line of credit. (See below)

At June 30, 2005, we had assets totaling $33.0 million. Our total capitalization was $27.2 million, 100% of which was represented by stockholders’ equity. During the first six months of 2005, net cash flow provided by operating activities was $5.04 million, which represents a 74% increase over the $2.90 million net cash flow provided by operating activities in the first six months of 2004. The cash flow increase in 2005 is attributed primarily to a 59% increase in oil and gas revenues, partially offset by higher operating costs and well workovers. During the first six months of 2005, we incurred $5.26 million of development costs, $1.2 million of which remained in current liabilities at June 30, 2005. In addition, we funded $2.15 million of development project costs incurred in 2004 that were included in accounts payable at December 31, 2004. The new development spending and the net reduction in current liabilities between year end 2004 and June 30, 2005 related to capital projects, were provided by cash flow from operations and existing cash reserves.

During the first six months of 2005, we incurred $1,583,000 in costs related to our participation in new development drilling in the Mesa B and C fields in the Pinedale Anticline which increased both our reserves and our production. Beginning in August, 2005, net production to us at Mesa B increased 1,200 mcf per day to 3,100 mcf per day, an increase of 78% over June 2005 production rates. We also spent $2,887,000 at our Cow Creek field in Carbon County, Wyoming which included the drilling of the 13-7A well to test the Deep Creek and Cow Creek Sandstone and improvements to gathering and power generation facilities. The 13-7A well has been completed and is currently being tested. Expenditures undertaken to improve our gathering system and power generation facilities at Cow Creek included $1,281,000 for the acquisition of new power generation equipment. We spent an additional $441,000 for our share of costs incurred by Anadarko at Doty Mountain for the drilling project which began in 2004. We are not yet taking our share of production while the dewatering of the coal bed methane wells continues.

Capital Requirements

Our total budgeted capital expenditures for the remainder of 2005 are expected to be approximately $9.5 million, depending on regulatory approvals and project feasibility analysis. The projected spending will continue to focus on three areas: (i) new development drilling in the Mesa B on the Pinedale Anticline, (ii) further spending to improve facilities and transportation at Cow Creek and (iii) selected new development and exploration projects which will attempt to pursue both unconventional and conventional gas accumulation. Should project spending exceed funds available from current cash flow and existing cash reserves, we intend to access the funds available through our line of credit.

Line of Credit

We maintain a line of credit with our banking affiliate secured by our oil and gas properties. Currently, we have $9 million of availability on the line of credit, which may be adjusted annually for changes in reserves and production pricing. Interest on future borrowings against the line of credit would be assessed at the bank’s prime rate. The line has been inactive since the last quarter of 2003. However, capital spending during the remainder of the year will likely require the Company to draw on the line of credit by year end.

11

RESULTS OF OPERATIONS

Six months ended June 30, 2005 compared to six months ended June 30, 2004

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

	Six months ended				Six months ended				Percent			Percent
	June 30, 2005				June 30, 2004				Volume			Price
Product	Volume		Price		Volume		Price		Change			Change
Gas (mcf)		1,494,352	$	5.72		1,111,053	$	4.73		+34	%		+21	%
Oil (bbls)		7,707	$	46.10		9,551	$	32.62		-19	%		+41	%
Mcfe		1,540,594	$	5.78		1,168,359	$	4.77		+32	%		+21	%

Oil and gas sales increased 59% in the first six months of 2005, compared to the same period in 2004, to $8,922,000 from $5,607,000. The increase is due primarily to a 32% net increase in gas and oil production. Approximately 62% of the increased production occurred at Cow Creek, which is our coal bed methane development project in the Eastern Washakie Basin in South Central Wyoming. The remainder of the increase was attributed to the Mesa B and Mesa C field in western Wyoming. Our average daily production increased to 8,512 mcfe in the first half of 2005 compared with average daily production of 6,420 mcfe during the same period in the previous year. Gas prices continue to remain firm during 2005. Our average gas price realized during the first half of 2005 was $5.78 per mcfe. In June 2005, the average gas price was $6.08 per mcfe. The increased revenues associated with increased production also brought about a corresponding increase in total operating costs and depletion expense. The gross margin per mcfe increased by 7.4% and the gross margin percentage decreased by 6%, during the first six months of 2005 compared to the first six months of 2004 as shown below:

	$ Per mcfe
	2005			2004
Average price		5.78			4.77
Production costs		1.14			.59
Production taxes		.62			.53
Depreciation, depletion, amortization		1.26			1.08
Total operating costs		3.02			2.20
Gross margin		2.76			2.57
Gross margin percentage		48	%		54	%

12

Although we do not currently hedge our production prices, we have entered into fixed delivery contracts for approximately 44% of the current daily production at June 30, 2005. As of July 1, 2005 we had the following sales delivery contracts in effect on our production (Volume and Daily Production are expressed in mcfs):

			Daily				Average
Property	Volume		Production		Term		Price ($)
Cow Creek		488,000		1,000		11/04-10/06		5.50
		107,500		500		2/05-1/06		5.30
		579,000		1,000		4/05-3/07		6.00
Total Cow Creek		1,174,500
Mesa		123,000		1,000		11/04-10/05		5.80
		107,500		500		2/05-1/06		5.30
Total Mesa		230,500
Company Total		1,405,000

Our “carried working interest” in Participating Area “C” in the Mesa Unit of the Pinedale Anticline was determined to have paid out in April 2004 by the operator, Wexpro Company. During 2005, we have recognized production from the participating area of approximately 24,000 mcf per month.

General and administrative expenses increased 95% to $1,365,000 in the first six months of 2005 compared to $700,000 in the first six months of 2004. The increase in costs in 2005 is associated with an increase in technical and administrative staff to administer expanded operations. In addition, the increase reflects the costs of a new office lease in the Denver downtown business district, professional fees, and shareholder expenses related to our increased activities in 2005.

Production costs increased 93% to $1.14 per mcfe in the first six months of 2005 compared to $.59 per mcfe during the same period one year ago. The increase was attributed in part to workover and pump and road repair projects totalling $338,000, or $.22 per mcfe. In addition, costs associated with the leasing of compressors and power generating equipment increased $222,000, or $.14 per mcfe over the same period in 2004. We have purchased and installed new compression and power generating equipment late in the second quarter of 2005 and anticipate a corresponding decrease in production costs during the second half of the year.

We have impaired the value of certain power generation equipment in the Cow Creek field. The power generation equipment has subsequently been replaced by more reliable and more efficient equipment. The equipment was sold in July 2005 at the anticipated net realizable value recognized in the first quarter of 2005 and, as a result, no loss on the equipment is required in the second quarter.

During the six months ended June 30, 2005, we recorded an income tax expense of $825,000 compared to no tax expense in the first six months of 2004. No income tax expense had been recognized as of June 30, 2004 because we had a deferred tax asset that had been fully provided for by an allowance at that time. 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

13

accepted accounting principles. Although we expect continued operating net income throughout 2005, we intend to recognize tax expense on that income at an effective rate of approximately 34%. We do not anticipate any required payments for current tax liabilities in the near future.

Despite the recognition of an unusual operating expense associated with an equipment write-down of $357,000 during the first quarter of 2005, income from operations during the first six months of 2005 increased 13% to $2,413,000 compared with $2,143,000 during the same period in 2004. We also recognized a provision for deferred tax of $825,000 in the first six months of 2005 compared to no provision for tax in 2004 during the same period. As a result of the non-cash expenses recorded for the equipment write-down, increased depreciation, depletion, amortization and deferred taxes, together with increased general and administrative and production costs, partially offset by oil and gas sales, net income decreased by 26% during the first six months of 2005, from $2,150,000 for the six months ending June 30, 2004 to $1,601,000 for the six months ending June 30, 2005.

Quarter ended June 30, 2005 compared with the quarter ended June 30, 2004

Oil and gas sales increased 27% in the second quarter to $4,334,000 in 2005 compared to $3,404,000 in the same period of 2004. The increase is attributed to higher levels of production and much stronger gas pricing in 2005 over the same period in 2004. Our average price increased to $5.91 per mcfe in 2005 from $4.76 per mcfe in 2004. Daily production increased 3% in the second quarter of 2005 compared with the second quarter of 2004 to 8,058 mcfe per day in 2005 from 7,850 mcfe per day in 2004. Production increases at Mesa B and Cow Creek in 2005 were largely offset by a decrease in production at Mesa C. Operating expenses increased significantly during the second quarter of 2005 compared to the second quarter of 2004 primarily due to higher levels of production as well as higher levels of workovers and equipment rentals at our Cow Creek field. The acquisition of new power generation equipment is expected to provide efficiency and cost savings over the use of rental equipment. The increase in depletion expense between the two periods reflects higher levels of production in 2005 as well as an increase in depletion rates associated with new capital investment. General and administrative expense increases in the second quarter of 2005 versus the second quarter of 2004 reflect increases in staffing and compensation, professional fees, and contract services. The increases in lease operating expenses, administration costs, and deferred taxes resulted in a 42% decrease in net income from $1,342,000 for the second quarter of 2004 to $776,000 for the second quarter of 2005.

New Accounting Pronouncements

In March 2005, the SEC issued Staff Accounting Bulletin (SAB) No. 107 on SFAS No. 123R. See “—Stock-Based Compensation’’ above. SAB No. 107 reinforces the flexibility allowed by SFAS No. 123R to choose an option pricing model, provides guidance on when it would be appropriate to rely exclusively on either historical or implied volatility in estimating expected volatility and provides examples and simplified approaches to determining the expected term. In April 2005, the SEC extended the date to adopt SFAS No. 123R from the first reporting period beginning on or after June 15, 2005 to the first reporting period of the first fiscal year beginning on or after June 15, 2005. The Company intends to adopt SFAS 123R beginning January 1, 2006.

In April 2005, the FASB issued staff position 19-1 (FSP 19-1) on accounting for suspended well costs. FSP 19-1 amends FASB Statement No. 19,Financial Accounting and Reporting by Oil and Gas Producing Companies, for companies using the successful efforts method of accounting. FSP 19-1 concludes that 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. FSP 19-

14

1 also requires certain disclosures with respect to capitalized exploratory well costs. FSP 19-1 is effective for the first reporting period beginning after April 4, 2005 and is to be applied prospectively to existing and newly capitalized exploratory well costs.

At June 30, 2005, we have no exploratory costs that have been capitalized for more than one year and do not believe that our financial position, results of operations or cash flows will be affected by this pronouncement.

In June 2005, the FASB issued Statement 154,Accounting Changes and Error Correctionswhich replaces APB Opinion 20 and FASB Statement 3. Statement 154 changes the requirements for the accounting and reporting of a change in accounting principle. Opinion 20 previously required that most voluntary changes in accounting principle be recognized by including the cumulative effect of the new accounting principle in net income of the period of the change. Statement 154 now requires retrospective application of changes in accounting principle to prior period financial statements, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. The Statement is effective for fiscal years beginning after December 15, 2005. We do not expect the adoption of this statement will have a material impact on our results of operations or financial position.

In March 2005, the FASB issued FASB Interpretation (FIN) No. 47, “Accounting for Conditional Asset Retirement Obligations.” This Interpretation clarifies the definition and treatment of conditional asset retirement obligations as discussed in FASB Statement No. 143, “Accounting for Asset Retirement Obligations.” A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of a company. FIN 47 states that a company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. This Interpretation is intended to provide more information about long-lived assets, more information about future cash outflows for these obligations and more consistent recognition of these liabilities. FIN 47 is effective for fiscal years ending after December 15, 2005. We do not believe that our financial position, results of operations or cash flows will be impacted by this Interpretation.

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,

15

classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected there from 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

• changes in governmental regulations or taxation

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, 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.

Stock Based Compensation

The Company accounts for its stock-based compensation using the intrinsic value recognition and measurement principles detailed in Accounting Principles Board’s Opinion No. 25 (“APB No. 25”). No stock-based compensation expense has been reflected in the Company’s financial statements for the options granted to its employees as these options had exercise prices equal to or higher than the market value of the underlying common stock on the date of grant. The Company uses the Black-Scholes option valuation model to calculate the required disclosures under SFAS 123. This model requires the Company to estimate a risk free interest rate and the volatility of the Company’s common stock price. The use of a different estimate for any one of these components could have a material impact on the amount of calculated compensation expense.

16

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risks

At June 30, 2005, we had no outstanding debt. Amounts drawn against our $9 million line of credit would bear interest at the prime rate of the lending bank.

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 six months ended June 30, 2005, our income before income taxes would have changed by $134,000 for each $0.10 change in natural gas prices and $7,000 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 44% of the current daily production as of June 30, 2005. 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

As of the end of the period covered by this report, we conducted an evaluation under the supervision and with the participation of the principal executive officer and principal financial officer of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d- 15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”). Based on this evaluation, the principal executive officer and principal financial officer concluded that our disclosure controls and procedures are effective to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission (“SEC”) rules and forms. There was no change in our internal control over financial reporting during our most recently completed fiscal quarter that has materially affected, or is reasonably likely to materially affect our internal control over financial reporting.

17

PART II. OTHER INFORMATION

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

On June 14, 2005, our Board of Directors granted 2,000 shares of our common stock to each of our four independent directors in consideration for services rendered to the Company. These shares were granted pursuant to our 2002 Stock Option Plan (the “Plan”). In addition, on June 14, 2005, our Board of Directors granted options to purchase an aggregate of 107,500 shares to various of our employees pursuant to the Plan. These options have an exercise price of $18.52 per share, expire on December 2010, and vest 20% each year beginning in 2006.

PLEASE DESCRIBE ANY OTHER ISSUANCES OF SHARES OR GRANTS OF OPTIONS DURING THE QUARTER.

These issuances and grants were made pursuant to exemptions from registration under the Securities Act of 1933, including but no limited to Section 4(2) of the Securities Act of 1933.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

At our annual meeting of stockholders held on June 14, 2005, the following proposals were approved by the votes indicated:

(1) The following persons were elected as the directors of the Company:

	Shares Voted For		Votes Withheld
Stephen H. Hollis		6,688,867		180,932
Thomas A. Prendergast		6,825,432		44,367
Roy G. Cohee		6,848,289		21,510
Richard D. Dole		6,848,169		21,630
Sigmund A. Balaban		6,847,829		21,970

(2) Proposal to amend our Articles of Incorporation to increase the number of authorized shares of our common stock from 10 million to 50 million shares:

Shares voting for	6,387,430
Shares voting against	451,430
Shares abstaining	30,939

(3) Proposal to ratify the selection of Hein + Associates LLP as our independent auditors for the year ending December 31, 2005:

Shares voting for	6,832,825
Shares voting against	24,314
Shares abstaining	12,660

18

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.

19

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

Date: August 12, 2005

20

EXHIBITS INDEX

Exhibit No.	Exhibit Description
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.