Escalera Resources (ESCR) 10-Q 2007 Q1 Quarterly report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For quarterly period ended March 31, 2007

or

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

For the transition period from                    to                    

Commission File Number 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 May 1, 2007
Common stock, $.10 par value	9,141,104

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

	Page
PART I. Financial Information:
Item 1. Financial Statements
Consolidated Balance Sheet as of March 31, 2007 (Unaudited) and December 31, 2006		2
Consolidated Statement of Operations for the Three Months Ended March 31, 2007 and 2006 (Unaudited)		3
Consolidated Statement of Cash Flows for the Three Months Ended March 31, 2007 and 2006 (Unaudited)		4
Notes to Consolidated Financial Statements		5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		8
Item 3. Quantitative and Qualitative Disclosures About Market Risk		14
Item 4. Controls and Procedures		15
PART II. Other Information:
Item 1A. Risk Factors		15
Item 6. Exhibits		15
Signatures		16
Certification of CEO Pursuant to Rule 13a-14(a)
Certification of CFO Pursuant to Rule 13a-14(a)
Certification of CEO & CFO Pursuant to 18 U.S.C. Section 1350

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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)

	March 31,			December 31,
	2007			2006
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	323		$	611
Cash held in escrow		1,319			707
Accounts receivable		5,030			5,047
Other current assets		859			809
Total current assets		7,531			7,174
Oil and gas properties and equipment, successful efforts method:
Developed properties		55,458			53,677
Wells in progress		17,821			13,839
Gas transportation pipeline		5,436			5,412
Undeveloped properties		3,077			3,313
Corporate and other assets		1,120			1,024
		82,912			77,265
Less accumulated depreciation, depletion and amortization		(21,464	)		(20,079	)
Net properties and equipment		61,448			57,186
Other assets		46			46
TOTAL ASSETS	$	69,025		$	64,406
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	5,015		$	7,964
Accrued expenses		6,404			5,125
Accrued production taxes		1,195			1,091
Total current liabilities		12,614			14,180
Line of credit		8,901			13,221
Asset retirement obligation		675			694
Deferred tax liability		3,439			3,269
Total liabilities		25,629			31,364
Stockholders’ equity:
Common stock, $0.10 par value; 50,000,000 shares authorized; 9,141,104 and 8,641,104 shares issued and outstanding as of March 31, 2007 and December 31, 2006, respectively		914			864
Additional paid-in capital		33,320			23,251
Retained earnings		9,162			8,927
Total stockholders’ equity		43,396			33,042
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	69,025		$	64,406

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

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DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED STATEMENT OF OPERATIONS

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

(Unaudited)

	Three Months Ended March 31,
	2007			2006
Revenues
Oil and gas sales	$	4,616		$	4,593
Transportation revenue		207			—
Other income, net		121			14
Total revenues		4,944			4,607
Costs and expenses
Production costs		1,465			876
Production taxes		567			523
Exploration expenses including dry hole costs		160			32
General and administrative		808			874
Depreciation, depletion and amortization		1,384			997
Total costs and expenses		4,384			3,302
Income from operations		560			1,305
Interest expense, net		(155	)		(15	)
Income before income taxes		405			1,290
Provision for deferred income taxes		(170	)		(452	)
NET INCOME	$	235		$	838
Net income per common share:
Basic	$	0.03		$	0.10
Fully diluted	$	0.03		$	0.10
Weighted average shares outstanding:
Basic		9,018,882			8,616,693
Fully diluted		9,026,483			8,655,616

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

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DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED STATEMENT OF CASH FLOWS

(Amounts in thousands of dollars)

(Unaudited)

	Three Months Ended March 31,
	2007			2006
Cash flows from operating activities:
Net income	$	235		$	838
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		1,390			997
Abandonment of non-producing properties		24			8
Provision for deferred income taxes		170			452
Non-cash employee stock option expense		73			112
Gain on sale of working interest in non-producing property		(98	)		—
Changes in current assets and liabilities:
Increase (decrease) in deposit held in escrow		(612	)		—
Decrease in accounts receivable		17			1,832
(Increase) decrease in other current assets		(50	)		83
(Decrease) increase in accounts payable		(3,229	)		42
Increase (decrease) in accrued expenses		1,564			(867	)
Increase in accrued production taxes		104			21
NET CASH (USED IN) PROVIDED BY OPERATING ACTIVITIES		(412	)		3,518
Cash flows from investing activities:
Additions of producing properties and equipment		(5,672	)		(5,330	)
Additions of corporate and non-producing properties		(174	)		(275	)
Proceeds from sale of non-producing properties		244			—
NET CASH USED IN INVESTING ACTIVITIES		(5,602	)		(5,605	)
Cash flows from financing activities:
Net proceeds from sale of common stock		10,046			—
Net (repayments) borrowings on line of credit		(4,320	)		1,500
Exercise of options		—			293
NET CASH PROVIDED BY FINANCING ACTIVITIES		5,726			1,793
Change in cash and cash equivalents		(288	)		(294	)
Cash and cash equivalents at beginning of period		611			1,431
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	323		$	1,137
Supplemental disclosure of cash and non-cash transactions:
Cash paid for interest	$	192		$	69
Interest capitalized	$	27		$	54
Additions to developed properties included in current liabilities	$	6,178		$	1,460
Stock option expense	$	73		$	112

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

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DOUBLE EAGLE PETROLEUM CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

1.	Summary of Significant Accounting Policies
	Basis of presentation
	The accompanying unaudited interim consolidated financial statements were prepared by Double Eagle Petroleum Co. (“Double Eagle” or the “Company”) pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Certain information and note disclosures normally included in the annual consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted as allowed by such rules and regulations. These consolidated financial statements include all of the adjustments, which, in the opinion of management, are necessary for a fair presentation of the financial position and results of operations. All such adjustments are of a normal recurring nature only. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full fiscal year.
	Certain amounts in the 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 herein 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 (“GAAP”), 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.
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). Fully 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.

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The following is the calculation of basic and fully diluted weighted average shares outstanding and EPS for the periods indicated:

	For the Three Months Ended March 31,
	2007		2006
Net income	$	235	$	838
Weighted average shares:
Weighted average shares — basic		9,018,882		8,616,693
Dilution effect of stock options outstanding at the end of period		7,601		38,923
Weighted average shares — fully diluted		9,026,483		8,655,616
Earnings per share:
Basic	$	0.03	$	0.10
Fully diluted	$	0.03	$	0.10

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:

	For the Three Months Ended March 31,
	2007		2006
Options to purchase common stock		37,260		—

3.	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.
4.	Income Taxes
	At March 31, 2007, the Company had a net operating loss carry forward for regular income tax reporting purposes of approximately $12.0 million that will begin 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 2002 through 2005.
	The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of March 31, 2007, the Company made no provisions for interest or penalties related to uncertain tax positions.

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5.	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 is $25 million and all outstanding balances on the line of credit mature on July 31, 2010.
	In January 2007, as described in Note 6, the net proceeds received from a public offering were used to pay down the outstanding balance on the Company’s revolving line of credit. The $8,901 outstanding balance on the line of credit at March 31, 2007 was used to fund capital expenditures. The interest rate, calculated in accordance with the agreement at 1.125% below the posted Wall Street Journal Prime Rate, was 7.125%, as compared to 7.25% in the same prior year period.
	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 March 31, 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 quarter ended March 31, 2007 and 2006, interest expense with respect to the above credit lines totaled $182 and $69, respectively, and capitalized interest totaled $27 and $54, respectively.
6.	Sale of Common 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. 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.
7.	Cash Held in Escrow
	The Company has received deposits representing partial prepayments of the expected total capital expenditures from third party working interest owners in the Christmas Meadows exploration project. The unexpended portion of the deposits at March 31, 2007 totaled $1,319.

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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 on Form 10-Q includes “forward-looking statements” as defined by the Securities and Exchange Commission, or SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Form 10-K 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 this Form 10-Q and the following:

• The cost and effects on our business of weather and other natural phenomena;

• General economic and political conditions, including governmental energy policies, tax rates or policies and inflation rates;

• 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;

• Our ability to meet growth projections;

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

• The issuance of drilling, environmental and other permits, by federal, state, and tribal governments, or agencies thereof, may affect the volume of production from our developed properties;

• Incorrect estimates of required capital expenditures;

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

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

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

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.

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Business Overview and Strategy

We are an independent energy company engaged in the exploration, development, production and sale of natural gas and crude oil, primarily in the 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 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 quarter ended March 31, 2007:

•	Average Daily Production
	During the quarter ended March 31, 2007, average daily production increased 19% to 8,506 Mcfe, as compared to 7,121 Mcfe during the same prior year period. The increase in production is due largely to increased production at the Atlantic Rim and Madden Deep, which was offset partially by decreased production at Pinedale.
	Atlantic Rim.During the quarter ended March 31, 2007, average daily production at the Atlantic Rim increased 24% to 4,677 Mcfe, as compared to 3,767 Mcfe during the same prior year period, due largely to increased production at Cow Creek and the recognition of revenues at Doty Mountain and Sun Dog Units. Average daily production at Cow Creek increased 8% to 4,054 Mcfe, as compared to 3,767 during the same prior year period. The Cow Creek Field experienced operational issues due to severe winter weather, which resulted in workovers during the first quarter of 2007 and the beginning of the second quarter. Thus, we expect production at Cow Creek to further increase when current workovers are completed during the second quarter of 2007. We began receiving and selling our share of Doty Mountain production in mid-2006. Currently, we are in an under-produced position for (i) prior years production at the Doty Mountain Unit; and (ii) prior years and current year production at the Sun Dog Unit. We believe we can make up the entire balance over the course of the next twelve months.
	Pinedale Anticline. During the quarter ended March 31, 2007, average daily production at Pinedale decreased 5% to 2,557 Mcfe, as compared to 2,681 Mcfe in the prior year. While the Mesa decreases are the result of normal production declines, the operator at the Mesa Units has informed us that it intends to continue new drilling projects in 2007 to better maintain or increase production levels. There are also additional wells to be hooked up when winter grazing regulations allow in 2007.
	Madden Deep Unit. During the quarter ended March 31, 2007, our average daily net production at the Madden Deep Unit was 652 Mcfe. Through unitization we acquired an interest in the Madden Sour Gas Participating Area in the Madden Deep Unit in late 2006, as well as an interest in the Lost Cabin Gas Processing Plant, at an initial cost of approximately $3.5 million.
•	Oil and Gas Sales
	During the quarter ended March 31, 2007, oil and gas sales increased to $4,616, as compared to $4,593 during the same prior year period. Total revenue was impacted largely by increased volumes (as discussed above), offset almost entirely by lower average gas prices. During the quarter ended March 31, 2007, average gas prices decreased 16%, from $7.17 to $6.03, due primarily to the effects of the severe hurricane season in late 2005.

OVERVIEW OF FINANCIAL CONDITION AND LIQUIDITY

Liquidity and Capital Resources

Overview

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 significant exploration/development projects (see Capital Requirements below). We anticipate capital resources to fund this activity will be made available through future operating cash flow and through our $50 million bank line of credit.

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We may also consider additional offerings of securities issued under our $200 million shelf registration statement (of which $190 million is available as of March 31, 2007). While 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.

Information about our financial position is presented in the following table for the periods indicated:

	March 31,			December 31,
	2007			2006
Financial Position Summary
Cash and cash equivalents	$	323		$	611
Working capital	$	(5,083	)	$	(7,006	)
Line of credit outstanding	$	8,901		$	13,221
Stockholders’ equity	$	43,396		$	33,042
Ratios
Long-term debt to total capital ratio		17.0	%		28.6	%
Total debt to equity ratio		20.5	%		40.0	%

During the quarter ended March 31, 2007, our working capital deficit decreased by $1,923 to $5,083, due primarily to a decrease in accounts payable largely related to the Christmas Meadows project. Additionally, 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. We believe that approach is more beneficial than maintaining a positive working capital balance.

Cash flow activities

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

	Three months ended March 31,
	2007			2006
Cash provided by (used in):
Operating Activities	$	(412	)	$	3,518
Investing Activities		(5,602	)		(5,605	)
Financing Activities		5,726			1,793
Net change in cash	$	(288	)	$	(294	)

During the quarter ended March 31, 2007, net cash used in operating activities was $412 versus net cash provided by operating activities of $3,518 in the same prior year period. Net income decreased $603, or 72%, due mainly to increased production costs incurred for gas purchase expense, lease operating expense, and workover expense. The increase in production cost per Mcfe is largely attributed to gas purchase expense of $195 for the purchase of volumes to fulfill the fixed delivery contracts at our Cow Creek Field. During the first quarter, production in the field fell below contractual volumes due to severe weather and related operational issues in the field. Management anticipates adequate volumes to fulfill the contracts as workovers in the field are completed and does not anticipate this expense going forward.

During the quarter ended March 31, 2007, net cash used in investing activities was $5,602, as compared to $5,605 in the same prior year period. Cash expenditures during the first quarter of 2007 for capital projects were provided primarily by advances from our line of credit. We invested (i) $1,893 at the Table Top Unit #1 well at the Christmas Meadows Prospect; (ii) $2,111 for our share of costs for non-operated development wells in the Pinedale Anticline and Atlantic Rim areas; and (iii) $1,779 for compression, power upgrades and further development of our operated Atlantic Rim properties. These costs were somewhat offset by the sale or transfers of non-operated leases.

During the quarter ended March 31, 2007, net cash provided by financing activities increased 219% to $5,726. 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. The net proceeds from this offering were used to pay down the outstanding balance on our revolving line of credit. Net repayments on our line of credit during the first quarter of 2007 totaled $4,320.

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”)

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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 include 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 capital expenditures for the remainder of 2007 are expected to be approximately $44 million, depending on project participation and resource availability. The projected spending will continue to focus on three primary areas: (i) ongoing exploratory drilling projects for conventional gas reserves in the Atlantic Rim; (ii) new coal bed gas development drilling in the Atlantic Rim; and (iii) new development drilling in the Pinedale Anticline. We believe that the amounts available under our $50 million bank line of credit and the possibility of offerings of securities, including securities issued under our $200 million shelf registration statement (approximately $190 million is available as of March 31, 2007), together with the net cash provided by operating activities, will provide us with sufficient funds to pursue development of new reserves, maintain our current facilities and complete our current capital expenditure program. Depending on the timing and amount of future projects, we may be required to seek additional sources of capital. While 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.

In addition to our ongoing Atlantic Rim, Pinedale and other projects, we currently have three exploratory/development drilling project:

• The South Fillmore exploratory prospect.In the third quarter of 2006, we completed drilling at the South Fillmore prospect, just north of the Cow Creek Field and are currently testing the well’s production potential.

• The Cow Creek Unit Deep #2 development 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. At 9,922 feet, we ran casing and are currently reworking the seismic data with the additional well data compiled. We expect to complete the drilling and testing of the Cow Creek Unit Deep #2 during 2007.

• The Christmas Meadows exploratory prospect.We reached the originally planned total depth at the Christmas Meadows exploratory test well in northeast Utah during the first quarter of 2007. The Table Top Unit #1 well at Christmas Meadows did not find reservoir rocks with sufficient permeability in the Cretaceous formation. We plan to contract a larger rig and continue to drill to test the Nugget sandstones at approximately 18,000 feet. We will also consider the possibility of attempting to drill to test the Madison carbonates at approximately 23,000 feet.

• At March 31, 2007, our combined cost on the above three projects was $13,768. In the event that these wells are unsuccessful, we may be required to impair all or a portion of the costs incurred.

Line of Credit

Effective August 1, 2006, we 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 is $25 million and all outstanding balances on the line of credit mature on July 31, 2010.

In January 2007, as described in Note 6 of our Notes to the Consolidated Financial Statements, the net proceeds received from a public offering were used to pay down the outstanding balance on the Company’s revolving line of credit. As of March 31, 2007, the $8,901 outstanding balance on the line of credit results from the funding of capital expenditures. The interest rate, calculated in accordance with the agreement at 1.125% below the posted Wall Street Journal Prime Rate, was 7.125%, as compared to 7.25% in the same prior year period.

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 March 31, 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

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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 quarter ended March 31, 2007 and 2006, interest expense with respect to the above credit lines totaled $182 and $69, respectively, and capitalized interest totaled $27 and $54, respectively.

RESULTS OF OPERATIONS

Quarter ended March 31, 2007 compared to the quarter ended March 31, 2006

Oil and gas sales volume and price comparisons

	Three Months Ended March 31,								Percent			Percent
	2007				2006				Volume			Price
	Volume		Average Price		Volume		Average Price		Change			Change
Product:
Gas (mcf)		743,529	$	5.95		617,897	$	7.10		20	%		-16	%
Oil (bbls)		3,668	$	52.40		3,836	$	54.04		-4	%		-3	%
Mcfe		765,537	$	6.03		640,913	$	7.17		19	%		-16	%

For the quarter ended March 31, 2007, total production increased 19% to 765,537, while oil and gas sales increased marginally to $4,616, 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 quarter ended March 31, 2007, average daily production at the Atlantic Rim increased 24% to 4,677 Mcfe as compared to 3,767 Mcfe during the same prior year period, due largely to increased production at Cow Creek and the recognition of our first production at Doty Mountain and Sun Dog Units. Average daily production at Cow Creek increased 8% to 4,054 Mcfe, as compared to 3,767 during the same prior year period. The Cow Creek Field experienced operational issues due to severe winter weather, which resulted in workovers during the first quarter of 2007. We expect production at Cow Creek to increase when the workovers are completed during the second quarter of 2007. We began receiving and selling our share of Doty Mountain production in mid-2006. Currently, we are in an under-produced position for (i) prior-year production at Doty Mountain; and (ii) prior-year and current production for the quarter ended March 31, 2007 at the Sun Dog Units. We believe we can make up the entire balance over the next 12 months. During the quarter ended March 31, 2007, average daily production in the Pinedale Anticline decreased 5% to 2,557 Mcfe, as compared to 2,681 Mcfe in the prior year. While the Mesa Units decreases are the result of normal production declines, the operator at the Mesa Unit has informed us that it intends to continue new drilling projects in 2007 to better maintain or increase production levels. The operator has also informed us that it intends to hook up additional wells as soon as winter grazing regulations allow in 2007. During the quarter ended March 31, 2007, average daily production at Madden Deep was 652 Mcfe. We began recognizing production from Madden Deep during the fourth quarter of 2006. During the quarter ended March 31, 2007, average gas prices decreased 16%, from $7.17 to $6.03, due primarily to the effects of the severe hurricane season in late 2005.

Transportation and other revenue

During the quarter ended March 31, 2007, we recorded $207 in transportation revenue for moving third party gas through our intrastate gas pipeline, which connects the Cow Creek Field with the pipeline system owned by Southern Star Central Gas Pipeline, Inc.

During the quarter ended March 31, 2007, we recorded $121 in other income, due largely to a gain on the sale of a 50% working interest in our Bad Water Creek Prospect to a third party, totaling $98.

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Oil and gas production expenses, depreciation, depletion and amortization

	Three Months Ended March 31,
	2007			2006
	(in dollars per mcfe)
Average price	$	6.03		$	7.17
Production costs		1.86			1.36
Production taxes		0.74			0.82
Depletion and amortization		1.70			1.43
Total operating costs		4.30			3.61
Gross margin	$	1.73		$	3.56
Gross margin percentage		29	%		50	%

During the quarter ended March 31, 2007, well production costs increased 64% to $1,426, as compared to $871 during the same prior year period, and production costs in dollars per Mcfe increased 37%, or $0.50 to $1.86, as compared to the same prior year period. The increase in production cost per Mcfe is largely attributed to gas purchase expense of $195, which was incurred to purchase volumes to fulfill the fixed delivery contracts at our Cow Creek Field and an increase of $157 in workovers at the Cow Creek Field. During the quarter ended March 31, 2007, production at our Cow Creek field fell below our contracted volumes due to operational issues experienced as a result of severe winter weather. We expect production from the Cow Creek Field to increase as workovers in the field are completed. We do not anticipate these additional expenses going forward.

During the quarter ended March 31, 2007, total depreciation, depletion and amortization expenses increased 39% to $1,384 as compared to $997 in the same prior year period, and depletion and amortization related to producing assets increased 43% to $1,303 as compared to $914 in the same prior year period. The increase is due primarily to production beginning at Doty Mountain and Sun Dog Units in mid-2006, and an increase in capital expenditures at the Mesa Units. Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased 19%, or $0.27, to $1.70, as compared to the same prior year period.

General and administrative

During the quarter ended March 31, 2007, general and administrative expenses decreased 8% to $808, as compared to $874 in the same prior year period. In a quarter over quarter comparison, professional consulting and auditor fees related to establishing and implementing our Sarbanes-Oxley compliance systems, stock option expense and reservoir engineering fees all decreased. These decreases were offset partially by an increase in salaries and related employee benefits resulting from the hiring of additional personnel.

Income taxes

During the quarter ended March 31, 2007, we recorded an income tax expense of $170 as compared to $452 during the same prior year period. Although we expect to continue to generate losses for federal income tax reporting purposes, our sustained net income from operations has resulted in a deferred tax position required under generally accepted accounting principles. We expect to recognize tax expense on income from operations for the remainder of 2007 at an enacted federal and state rate of approximately 35.5%. However, we do not anticipate any required payments for current tax liabilities in the near future.

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CONTRACTED VOLUMES

Although we do not currently hedge our production prices, we have entered into various fixed delivery contracts for most of the production from our Cow Creek Field, allowing us to effectively “lock in” a portion of our future production of natural gas at prices which we consider favorable. As of March 31, 2007, we had sales delivery contracts in effect for approximately 35% of our total current daily production (volume and daily production are expressed in Mcf):

	Remaining
	Contractual		Daily			Fixed
Property	Volume		Production		Term	Price/Mcf
Cow Creek		91,000		1,000	07/06 - 06/07	$	5.94
		91,000		1,000	07/06 - 06/07	$	6.32
		214,000		1,000	11/06 - 10/07	$	5.84
Company Total		396,000

In April 2007, we entered into a new fixed delivery contract, the terms of which are summarized as follows (volume and daily production are expressed in Mcf):

	Remaining
	Contractual		Daily			Fixed
Property	Volume		Production		Term	Price/Mcf
Cow Creek		1,460,000		2,000	07/07 - 06/09	$	5.69

Additionally, all of the above 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 March 31, 2007, the annual impact on interest expense for every 1.0% change in the average interest rate would be approximately $89 before taxes.

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 March 31, 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 7.125%, and the balance outstanding was $8.9 million.

Commodity Price Risks

Our major market risk exposure is in the pricing applicable to our natural gas and oil production. Pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. natural gas production. Pricing for oil 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 March 31, 2007, our income before income taxes would have changed by $326 for each $0.50 change per Mcf in natural gas prices and $3 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 our Cow Creek Field, allowing us to effectively “lock in” a portion of our future production of natural gas at prices which we considered favorable to Double Eagle at the time we entered into the contract. As of March 31, 2007 we had sales delivery contracts in effect for approximately 35% of our total current daily production. These fixed delivery contracts,

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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 March 31, 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 March 31, 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

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.

ITEM 6. EXHIBITS

The following exhibits are filed as part of this report:

Exhibit Number and Description:

3.2	Bylaws of the Company, as amended and restated on March 14, 2007 (incorporated by reference from Exhibit 3.2 of the Company’s Current Report on Form 8-K, filed on March 14, 2007).
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.
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.

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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 9, 2007	By:	/s/ Lonnie R. Brock
		Lonnie R. Brock
		Chief Financial Officer

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EXHIBIT INDEX

Exhibit Number	Description
Exhibit 3.2	Bylaws of the Company, as amended and restated on March 14, 2007 (incorporated by reference from Exhibit 3.2 of the Company’s Current Report on Form 8-K, filed on March 14, 2007).
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.