Escalera Resources 10Q 2008 Q3 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended September 30, 2008


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

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

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

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

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

Yesþ Noo

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


Large accelerated filero	Accelerated filerþ	Non-accelerated filero	Small reporting Companyo
		(Do not check if a small reporting company)

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 Common stock, $.10 par value		Outstanding as of November 1, 2008 9,170,910

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


	Page #
PART I. Financial Information:

Item 1. Financial Statements

Consolidated Balance Sheet as of September 30, 2008 (Unaudited) and December 31, 2007		2

Consolidated Statement of Operations for the Three and Nine Months Ended September 30, 2008 and 2007 (Unaudited)		3

Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2008 and 2007 (Unaudited)		4

Notes to Consolidated Financial Statements (Unaudited)		5

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		11

Item 3. Quantitative and Qualitative Disclosures About Market Risk		21

Item 4. Controls and Procedures		22

PART II. Other Information:

Item 1. Legal Proceedings		22

Item 1A. Risk Factors		22

Item 6. Exhibits		23

Signatures		24

Exhibit 31.1
Exhibit 31.2
Exhibit 32

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED BALANCE SHEET

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


	September 30,			December 31,
	2008			2007
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	684		$	125
Cash held in escrow		615			719
Accounts receivable		17,943			3,664
Assets from price risk management		7,568			—
Other current assets		1,947			586

Total current assets		28,757			5,094


Oil and gas properties and equipment, successful efforts method:
Developed properties		116,645			61,394
Wells in progress		9,621			29,768
Gas transportation pipeline		5,465			5,465
Undeveloped properties		3,169			3,147
Corporate and other assets		1,955			1,585

		136,855			101,359
Less accumulated depreciation, depletion and amortization		(32,022	)		(24,785	)

Net properties and equipment		104,833			76,574

Deferred tax asset		—			2,873
Assets from price risk management		4,175			—
Other assets		—			56

TOTAL ASSETS	$	137,765		$	84,597


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	20,736		$	8,584
Accrued expenses		8,969			2,079
Liabilities from price risk management		—			474
Accrued production taxes		2,833			969

Total current liabilities		32,538			12,106

Line of credit		17,966			3,445
Asset retirement obligation		2,067			1,449
Liabilities from price risk management		—			1,001
Deferred tax liability		1,681			—

Total liabilities		54,252			18,001


Preferred stock, $0.10 par value; 10,000,000 shares authorized; 1,610,000 shares issued and outstanding as of September 30, 2008 and December 31, 2007		37,972			37,972


Stockholders’ equity:
Common stock, $0.10 par value; 50,000,000 shares authorized; 9,168,031 and 9,148,105 shares issued and outstanding as of September 30, 2008 and December 31, 2007, respectively		917			915
Additional paid-in capital		34,501			33,670
Retained earnings (accumulated deficit)		764			(4,486	)
Accumulated other comprehensive income (loss)		9,359			(1,475	)

Total stockholders’ equity		45,541			28,624


TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	137,765		$	84,597

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

DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED STATEMENT OF OPERATIONS
(Amounts in thousands of dollars except share and per share data)
(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007

Revenues
Oil and gas revenue	$	11,662		$	3,779		$	29,439		$	11,812
Transportation and gathering revenue		1,283			242			2,370			675
Price risk management activities		1,020			—			3,042			—
Other income, net		41			62			258			203


Total revenues		14,006			4,083			35,109			12,690


Costs and expenses
Production costs		1,982			844			5,074			3,910
Production taxes		1,419			470			3,753			1,471
Exploration expenses including dry holes		391			5,314			922			5,592
Pipeline operating costs		636			165			1,383			250
General and administrative		1,652			1,105			3,861			2,880
Depreciation, depletion and amortization		3,462			1,349			7,456			4,094
Impairment of equipment and properties		—			2,033			—			2,124


Total costs and expenses		9,542			11,280			22,449			20,321


Income (loss) from operations		4,464			(7,197	)		12,660			(7,631	)

Interest (expense) income, net		—			180			(64	)		25


Income (loss) before income taxes		4,464			(7,017	)		12,596			(7,606	)

Provision for deferred taxes		(1,557	)		2,225			(4,554	)		2,544


NET INCOME (LOSS)	$	2,907		$	(4,792	)	$	8,042		$	(5,062	)


Preferred stock dividends		(930	)		(879	)		(2,792	)		(879	)

Net Income (loss) attributable to common stock	$	1,977		$	(5,671	)	$	5,250		$	(5,941	)


Net income (loss) per common share:
Basic	$	0.22		$	(0.62	)	$	0.57		$	(0.65	)

Diluted	$	0.22		$	(0.62	)	$	0.57		$	(0.65	)


Weighted average shares outstanding:
Basic		9,167,977			9,148,105			9,156,079			9,103,339

Diluted		9,167,977			9,148,105			9,156,215			9,103,339

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

DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED STATEMENT OF CASH FLOWS

(Amounts in thousands of dollars)

(Unaudited)


	Nine Months Ended September 30,
	2008			2007
Cash flows from operating activities:
Net income (loss)	$	8,042		$	(5,062	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion of asset retirement obligation		7,998			4,116
Abandonment of non-producing properties		188			5,176
Impairment of equipment and properties		—			2,124
Provision for deferred taxes		4,554			(2,544	)
Directors fees paid in stock		90			91
Non-cash employee stock option expense		464			286
Non-cash gain on derivative contracts		(2,384	)		—
Gain on sales of producing property and equipment		(66	)
Gain on sale of working interest in non-producing property		—			(98	)
Changes in current assets and liabilities:
Decrease in deposit held in escrow		104			44
Decrease (increase) in accounts receivable		(11,832	)		194
Increase in other current assets		(1,361	)		(965	)
Increase (decrease) in accounts payable		6,610			(4,023	)
Increase in accrued expenses		829			663
Increase in accrued production taxes		1,864			542


NET CASH PROVIDED BY OPERATING ACTIVITIES		15,100			544


Cash flows from investing activities:
Sale of producing property and equipment		747			—
Additions of producing properties and equipment		(26,904	)		(22,733	)
Additions of corporate and non-producing properties		(392	)		(719	)
Proceeds from sale of non-producing properties		—			244


NET CASH USED IN INVESTING ACTIVITIES		(26,549	)		(23,208	)


Cash flows from financing activities:
Net proceeds from sale of common stock		—			9,990
Net proceeds from sale of preferred stock		—			37,967
Dividends paid on preferred stock		(2,792	)		(879	)
Net borrowings (payments) on line of credit		14,521			(13,221	)
Exercise of options		279			27


NET CASH PROVIDED BY FINANCING ACTIVITIES		12,008			33,884


Change in cash and cash equivalents		559			11,220

Cash and cash equivalents at beginning of period		125			611


CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	684		$	11,831


Supplemental disclosure of cash and non-cash transactions:
Cash paid for interest	$	390		$	333
Interest capitalized	$	515		$	273
Receivables from joint interest partners	$	2,447		$	—
Stock-based compensation expense	$	554		$	376
Additions to developed properties included in current liabilities	$	16,511		$	2,471

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

DOUBLE EAGLE PETROLEUM CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Amounts in thousands of dollars except share and per share data)
(Unaudited)

Summary of Significant Accounting Policies

Basis of presentation

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

Certain amounts in the 2007 consolidated financial statements have been reclassified to conform to the 2008 consolidated financial statement presentation. Such reclassifications had no effect on net income.

The accounting policies followed by the Company are set forth in Note 1 to the Company’s consolidated financial statements in the Form 10-K for the year ended December 31, 2007, and are supplemented throughout the notes to this quarterly report on Form 10-Q.

The interim consolidated financial statements presented herein should be read in conjunction with the consolidated financial statements and notes thereto for the year ended December 31, 2007 included in the Form 10-K filed with the SEC.

Recently adopted accounting pronouncements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 157 — Fair Value Measurements (“SFAS 157”). The statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. In February 2008, the FASB issued Staff Position No. FAS 157-2 which proposed a one year deferral for the implementation of SFAS 157 for nonfinancial assets and liabilities that are recognized or disclosed at fair value on a nonrecurring basis (less frequent than annually). On January 1, 2008, the Company elected to implement this Statement with the one-year deferral. Given the nature of the Company’s current financial instruments, the adoption of SFAS No. 157 did not have a material impact on the Company’s financial position, results of operations or cash flows. Beginning January 1, 2009, we will adopt the provisions for nonfinancial assets and nonfinancial liabilities that are not required or permitted to be measured at fair value on a recurring basis. The Company is in the process of evaluating this standard with respect to its effect on nonfinancial assets and liabilities and has not yet determined the impact that it will have on its financial statements upon full adoption in 2009.

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. The Company adopted SFAS No. 159 on January 1, 2008. The adoption of SFAS No. 159 did not have a material effect on our financial condition, results of operations or cash flows as the Company did not elect this fair value option.

New accounting pronouncements

In November 2007, the FASB issued Statement of Financial Accounting Standards No. 141(R) - Business Combinations (“SFAS 141(R)”). SFAS 141(R) changes the accounting for business combinations both at the acquisition date and in subsequent reporting periods. SFAS 141(R) requires the acquiring company to measure almost all assets acquired and liabilities assumed in the acquisition at fair value as of the acquisition date. The standard is effective for fiscal years beginning on or after December 15, 2008 and should be applied prospectively with the exception of income taxes which should be applied retrospectively for all business combinations. Early adoption is prohibited. The adoption of SFAS 141(R) is not expected to have a material impact on the Company’s financial position, results of operations or cash flows.

In November 2007, the FASB issued Statement of Financial Accounting Standards No. 160 - Non-controlling Interests in Consolidated Financial Statements, an amendment to ARB NO. 51 (“SFAS 160”). SFAS 160 requires non-controlling interests in a subsidiary to be initially measured at fair value and classified as a separate component of equity. The standard is effective for fiscal years beginning on or after December 15, 2008 and should be applied prospectively with the exception of the presentation and disclosure requirements which should be applied retrospectively if comparative financial statements are presented. Early adoption is prohibited. The adoption of SFAS 160 is not expected to have a material impact on the Company’s financial position, results of operations or cash flows.

In March 2008, the FASB issued Statement of Financial Accounting Standards No. 161 — Disclosures about Derivative Instruments and Hedging Activities (“SFAS 161”). SFAS 161 does not change current accounting treatment of derivatives, but requires expanded disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items (if any) are accounted for, and how they affect the Company’s financial position, financial performance and cash flows. The standard is effective for fiscal years and interim periods beginning after November 15, 2008 and early adoption is encouraged.

In May 2008, the FASB issued Statement of Financial Accounting Standards No. 162,The Hierarchy of Generally Accepted Accounting Principles(“SFAS 162”). SFAS 162 identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements that are presented in conformity with U.S. generally accepted accounting principles. The Statement becomes effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to the auditing literature. The adoption of SFAS 162 will not have an impact on the Company’s financial position, results of operations or cash flows.

2. Earnings per share

Basic earnings per share of common stock (“EPS”) is calculated by dividing net income (loss) attributable to common stock by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share is calculated by dividing net income (loss) attributable to common stock by the weighted average number of shares of common stock and potential common stock equivalents outstanding during the period, if dilutive. Potential common stock equivalents include incremental shares of common stock issuable upon the exercise of stock options and employee stock awards. Income attributable to common stock is calculated as net income (loss) less dividends paid on the Series A Preferred Stock. We declared and paid cash dividends of $930 ($.5781 per share) and $879 on the Series A Preferred Stock for the three months ended September 30, 2008 and 2007, respectively, and $2,792 and $879 for the nine month periods ended September 30, 2008 and 2007, respectively.

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


	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2008		2007			2008		2007
Net income (loss) attributable to common stock	$	1,977	$	(5,671	)	$	5,250	$	(5,941	)


Weighted average shares:
Weighted average shares — basic		9,167,977		9,148,105			9,156,079		9,103,339
Dilution effect of stock options outstanding at the end of period		—		—			136		—

Weighted average shares — diluted		9,167,977		9,148,105			9,156,215		9,103,339


Earnings per share:
Basic	$	0.22	$	(0.62	)	$	0.57	$	(0.65	)

Diluted	$	0.22	$	(0.62	)	$	0.57	$	(0.65	)

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


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2008		2007		2008		2007

Options to purchase common stock		151,702		7,624		124,245		26,096

Fair Value of Financial Instruments

Effective January 1, 2008, the Company adopted the provisions of SFAS No. 157, Fair Value Measurements, for all financial instruments. SFAS 157 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows:

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

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

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

The following describes the valuation methodologies we use to measure financial instruments at fair value.

Line of Credit

The recorded value of the Company’s credit facility approximates fair value as it bears interest at a floating rate.

Derivative Instruments

The Company uses derivative financial instruments to mitigate exposures to oil and gas production cash-flow risks caused by fluctuating commodity prices. At September 30, 2008, the types of derivative instruments utilized by the Company included fixed price delivery contracts, futures, swaps, options and costless collars.

The Company has entered into fixed delivery contracts for the sale of natural gas which expire at various dates through October 2009. Certain of these fixed delivery contracts are recorded using cash flow hedge accounting, under which the change in fair value is initially reported as a component of accumulated other comprehensive income and is subsequently reclassified into earnings as the contracts settle. The settlements are recorded within the oil and gas revenue line on the statement of operations. For the three and nine months ended September 30, 2008, these contracts settled for a gain of $177 and a loss of $1,298, respectively.

At September 30, 2008, the Company also had economic hedges which were recorded at fair value and marked to market, with the changes in the fair value subsequent to the initial measurement flowing through earnings. The change in fair value is recorded in the price risk management line on the statement of operations. The unrealized gain on the economic hedges totaled $362 and $2,384 for the three and nine months ended September 30, 2008. Upon settlement of the mark-to-market derivative instruments, the realized gain/loss is also recorded in the price risk management line. The realized gain related to the mark-to-market hedges was $658 for both the three and nine months ended September 30, 2008.

Although the Company’s cash flow and economic hedges are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company’s has classified these instruments as Level 2.

The following table provides a summary of the fair values of assets and liabilities measured on a recurring basis under SFAS No. 157:


	Level 1		Level 2		Level 3		Total

Assets
Derivative instruments	$	—	$	11,743	$	—	$	11,743

Total assets at fair value	$	—	$	11,743	$	—	$	11,743


Liabilities
Derivative instruments	$	—	$	—	$	—	$	—

Total liabilities at fair value	$	—	$	—	$	—	$	—

Impairment of Long-Lived Assets

The Company reviews the carrying values of its long-lived assets whenever events or changes in circumstances indicate that such carrying values may not be recoverable. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to the estimated fair value. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis. The fair value of impaired assets is determined based on quoted market prices in active markets, if available, or upon the present values of expected future cash flows using discount rates commensurate with the risks involved in the asset group. The long-lived assets of the Company, which are subject to periodic evaluation, consist primarily of oil and gas properties and undeveloped leaseholds. The Company recognized an impairment charge of $0 and $2,033 during the three months ended September 30, 2008 and 2007, respectively, and $0 and $2,124 during the nine months ended September 30, 2008 and 2007, respectively.

Suspended Well Costs

FASB Staff Position FAS 19-1 (FSP 19-1),Accounting for Suspended Well Costs, was effective for the first reporting period beginning after April 4, 2005. FSP 19-1 concludes that, for companies using the successful efforts method of accounting, exploratory well costs should continue to be capitalized when a well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the well. Since adopting FSP 19-1, the Company continually evaluates all existing capitalized exploratory well costs. During the three months ended September 30, 2008 and 2007, the Company wrote off $0 and $4,388 of capitalized costs, respectively and for the nine months ended September 30, 2008 and 2007, the Company wrote-off $0 and $4,388 of capitalized costs, respectively.

Reserves

During the quarter ended September 30, 2008, the Company engaged a third party reservoir engineering firm to evaluate the Company’s reserves as of June 30, 2008. The reserve estimates are developed using geological and engineering data and interests and burden information developed by the Company. Reserve estimates are inherently imprecise and are continually subject to revisions based on production history, results of additional exploration and development, prices of oil and gas, and other factors. The reserve study resulted in an increase of 9.6 Bcfe of proved reserves from December 31, 2007. Total proved reserves at June 30, 2008 were 83.3 Bcfe. The updated reserve amounts have been used in the calculation of depreciation, depletion and amortization for the three months ended September 30, 2008, as well as in the impairment analysis for the third quarter

Income Taxes

At September 30, 2008, the Company had a net operating loss carry forward for income tax reporting purposes of approximately $28.8 million that will begin to expire in 2021. Although Double Eagle is required to record income tax expense for financial reporting purposes, the Company does not anticipate any payments of current tax liabilities in the near future.

The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of September 30, 2008, the Company made no provision for interest or penalties related to uncertain tax positions. The Company files income tax returns in the U.S. federal jurisdiction and various states. There are currently no federal or state income tax examinations underway for these jurisdictions. Furthermore, the Company is no longer subject to U.S. federal income tax examinations by the Internal Revenue service for tax years before 2003 and for state and local tax authorities for years before 2002. The Company’s tax years of 2003 and forward are subject to examination by federal and state taxing authorities.

Line of Credit

The Company has a $50 million revolving line of credit collateralized by oil and gas producing properties. The borrowing base increased to $35 million from $25 million, pursuant to the debt modification agreement dated July 1, 2007, and all outstanding balances on the line of credit mature on July 31, 2010. As of September 30, 2008, 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 3.875%, and the balance outstanding of $18.0 million was used to fund capital expenditures primarily in the Atlantic Rim units and the Pinedale Anticline. Our expenditures in the Atlantic Rim were for the continued development of the Catalina Unit, for which we are the operator, and for our non-operated properties in the Doty Mountain and Sun Dog Units.

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, as defined, of at least 1.0 to 1.0. As of September 30, 2008, we were in compliance with all the covenants. If our covenants are violated, and we are unable to negotiate a waiver or amendment thereof, the lender would have the right to declare an event of default, terminate the remaining commitment and accelerate all principal and interest outstanding.

For the three months ended September 30, 2008 and 2007, we recognized no interest expense on our line of credit. We capitalized interest costs of $222 and $16 for the three months ended September 30, 2008 and 2007, respectively. For the nine months ended September 30, 2008 and 2007, interest expense on our line of credit totaled $0 and $155, respectively. We capitalized interest costs of $515 and $273 for the nine months ended September 30, 2008 and 2007, respectively.

Series A Cumulative Preferred Stock

In the third quarter of 2007, the Company completed a public offering of 1,610,000 shares of 9.25% Series A Cumulative Preferred Stock at a price to the public of $25.00 per share.

Holders of the Series A Preferred Stock are entitled to receive, when and as declared by the Board of Directors, dividends at a rate of 9.25% per annum ($2.3125 per annum per share). The Series A Preferred Stock does not have any stated maturity date and will not be subject to any sinking fund or mandatory redemption provisions, except, under some circumstances upon a Change of Ownership or Control. Except pursuant to the special redemption upon a Change or Ownership or Control, we may not redeem the Series A Preferred Stock prior to June 30, 2012. On or after June 30, 2012, we may redeem the Series A Preferred Stock for cash at our option, in whole or from time to time in part, at a redemption price of $25.00 per share, plus accrued and unpaid dividends (whether or not earned or declared) to the redemption date. The shares of Series A Preferred Stock are classified outside of permanent equity on the accompanying Consolidated Balance Sheets due to the following redemption provision. Following a Change of Ownership or Control of us by a person or entity, other than by a “Qualifying Public Company,” we will be required to redeem the Series A Preferred Stock within 90 days after the date on which the Change of Ownership or Control occurred for cash, at the following price per share, plus accrued and unpaid dividends.


Redemption Date on or Before	Redemption Price
June 30, 2009	$	25.75
June 30, 2010	$	25.50
June 30, 2011	$	25.25
June 30, 2012 or thereafter	$	25.00

In the event of liquidation, the holders of the Series A Preferred Stock will have the right to receive $25.00 per share, plus all accrued and unpaid dividends, before any payments are made to the holders of our common stock.

Comprehensive Income

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


	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2008		2007			2008		2007
Net income (loss) attributable to common stock	$	1,977	$	(5,671	)	$	5,250	$	(5,941	)
Change in derivative instrument fair value, net of tax benefit of $0		15,573		—			9,536		—
Reclassification to earnings		177		—			1,298		—

Comprehensive income (loss)	$	17,727	$	(5,671	)	$	16,084	$	(5,941	)

The components of accumulated other comprehensive loss were as follows:


	September 30,		December 31,
	2008		2007
Net change in derivative instrument fair value, net of tax benefit of $0 and $0	$	9,359	$	(1,475	)

Total accumulated other comprehensive gain (loss), net	$	9,359	$	(1,475	)

The Company did not record a tax benefit on the change in derivative instrument fair value due as the tax benefit is not likely to be realized given the Company’s operating loss carryforwards and timing of the derivative contract settlements.

10.

Cash Held in Escrow

The Company has received deposits representing partial prepayments of the expected capital expenditures from third party working interest owners in the Table Top Unit #1 (Christmas Meadows) exploration project. The unexpended portion of the deposits at September 30, 2008 and December 31, 2007 totaled $615 and $719, respectively.

11.

Accounts Receivable

The Company had an accounts receivable balance of $17.9 million at September 30, 2008. The balance includes approximately $2.4 million of amounts due from our joint interest partners at the Catalina Unit relating to the recovery of prior capital expenditures incurred by the Company, which resulted from the decrease in our working interest associated with the formation of the Catalina Unit participating area in December 2007. The remaining balance consisted primarily of normal production receivables from third party operators, joint interest billings for operating expenses and capital expenditures incurred during the 2008 drilling program.

12.

Intercompany Transactions

The Company sold transportation assets located in the Catalina Unit, at cost, to Eastern Washakie Midstream, LLC (“EWM”), a wholly owned subsidiary, in exchange for an intercompany note receivable bearing interest of 5% per annum, maturing on January 31, 2028. The note and related interest are fully eliminated in consolidation.

In addition, the Company has an agreement with EWM, under which the Company pays a fee to EWM to gather and compress gas produced at the Catalina Unit. Our share of the fee related to gas gathering is eliminated in consolidation.

13.

Commitments and Contingent Liabilities

Litigation

Double Eagle Petroleum Co.; Antelope Energy Company LLC; E. Cecile Martin f/k/a Cecile Hurt; Hurt Properties, L.P.; James R. Hurt; John D. Traut, LLC; and Newfield Exploration Company vs. Burlington Resources Oil & Gas Company, LP, a division of ConocoPhillips Company; ConocoPhillips Company, a Delaware corporation.The Company, along with other plaintiffs, filed a lawsuit on August 24, 2007, in the District Court of Fremont County, Wyoming, against BR and other defendants who own working interests in the Madden Deep Unit. The Company and the other plaintiffs in the case are asserting that, under the gas balancing agreement, they are entitled to receive either monetary damages or their respective shares of the natural gas produced from the Madden Deep Unit over at least the period February 1, 2002 through June 30, 2007. The Company has recognized the sales and has recorded a related account receivable of $292, net of allowance for uncollectible amounts, for the period November 1, 2006 through June 30, 2007. The ultimate outcome of this lawsuit cannot be determined at this time and, as a result, the Company has not recognized any amount of sales proceeds for the period February 1, 2002 through October 30, 2006. Sulfur sales are not subject to a gas balancing agreement, and, accordingly, we received the proceeds for our share of sulfur sales dating back to February 2002 and continue to receive our respective share on an on-going basis.

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

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

FORWARD-LOOKING STATEMENTS

This Quarterly Report onForm 10-Q includes “forward-looking statements” as defined by the Securities and Exchange Commission, or SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in thisForm 10-Q that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including without limitation the Risk Factors set forth in our Annual Report onForm 10-K for the year ended December 31, 2007 including the following:

•

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

•

Our ability to maintain adequate liquidity in connection with low oil and gas prices;

•

Weather and other natural phenomena;

•

The volumes of production from our oil and gas development properties, which may be dependent upon issuance by federal, state, and tribal governments, or agencies thereof, of drilling, environmental and other permits, and the availability of specialized contractors, work force, and equipment;

•

Our future capital requirements and availability of capital resources to fund capital expenditures;

•

General economic and political conditions, including the current financial market volatility, tax rates or policies and inflation rates;

•

Changes in or compliance with laws and regulations, particularly those relating to taxation, safety and protection of the environment;

•

Increases in the cost of drilling, completion and gas collection or other costs of production and operations;

•

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

•

Revisions to estimates of required capital expenditures;

•

Our ability to increase our natural gas and oil reserves;

•

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

•

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

•

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

•

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

•

Unexpected changes in credit worthiness of third-parties that we enter into business agreements with;

•

Industry and market changes, including the impact of consolidations and changes in competition;

•

The effect of accounting policies issued periodically by accounting standard-setting bodies;

•

The actions of third party co-owners of interests in properties in which we also own an interest;

•

The cost and effects on our business, including insurance, resulting from terrorist actions or natural disasters and responses to such actions or events;

•

The volatility of our stock price; and

•

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

We may also make material acquisitions or divestitures or enter into financing transactions. None of these events can be predicted with certainty and the possibility of their occurring is not taken into consideration in the forward-looking statements.

New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly any such forward -looking statements, whether as a result of new information, future events, or otherwise.

Business Overview and Strategy

We are an independent energy company engaged in the exploration, development, production and sale of natural gas and crude oil, primarily in Rocky Mountain Basins of the western United States. Double Eagle was incorporated in the State of Wyoming in January 1972 and reincorporated in the State of Maryland in February 2001. From 1995 to 2006, our common shares were publicly traded on the NASDAQ Capital Market under the symbol “DBLE”. On December 15, 2006, our common shares began trading on the NASDAQ Global Select Market. Our Series A Cumulative Preferred Stock (“Preferred Stock”) was issued and began trading on the NASDAQ Capital Market, under the symbol “DBLEP” on July 3, 2007 and began trading, under the symbol “DBLEP” on the NASDAQ Global Select Market on September 30, 2007. Our executive offices are located at 1675 Broadway, Suite 2200, Denver, Colorado 80202, and the telephone number there is (303)794-8445. Our operations offices are located at 777 Overland Trail, Casper, Wyoming 82601, and the telephone number there is (307) 237-9330.

Our objectives are to increase stockholder value, provide a positive and rewarding work environment for employees, and profitably operate and expand our assets. We plan to achieve these objectives by economically expanding our reserves, increasing and enhancing production of our existing properties, selectively pursuing strategic acquisitions, expanding our midstream business, and leveraging the experience of our employees. Our operations are currently focused on two core properties located in southwestern Wyoming where we have coal bed methane reserves and production in the Atlantic Rim area of the Eastern Washakie Basin, and tight sands gas reserves and production in the Pinedale Anticline. The operations in the Pinedale Anticline and Atlantic Rim operate under federal exploratory unit agreements between the working interest partners. Unitization is a type of sharing arrangement by which owners of operating and non-operating working interests pool their property interests in a producing area to form a single operating unit. Units are designed to improve efficiency and economics of developing and producing an area. The share that each interest owner receives is based upon the respective acreage contributed by each owner in the participating area (“PA”) that surround the producing wells as a percentage of the entire acreage of the PA. This PA, and the associated working interest, will change as more wells and acreage are added to the PA. Effective December 21, 2007, as a result of the expansion of our operated acreage in the Atlantic Rim, the Catalina Unit PA was formed. During 2007, we drilled 33 producing wells in the Catalina Unit, all of which were completed and in production at September 30, 2008. The PA includes our original 14 Cow Creek Unit wells and the 33 new wells drilled. With the formation of the Catalina Unit PA, the Company’s working interest was reduced from 100% to 73.84%. This working interest is applied to the production revenue, operating costs as well as the capital costs incurred. The Company recovered costs from the other working interest owners participating in the PA, in proportion to their working interests, which were originally recorded by the Company at our then 100% working interest.

Following are summary comments of our performance in several key areas during the three and nine months ended September 30, 2008(Amounts in thousands of dollars, except amounts per unit of production):

•

Average Daily Production

During the three months ended September 30, 2008, our total average daily net production increased 149% to 20,769 Mcfe as compared to average daily production of 8,329 Mcfe during the same prior year period. Total average daily production during the nine months ended September 30, 2008 increased 88% to 15,707 Mcfe as compared to average daily production of 8,368 Mcfe during the same prior year period. The fluctuations in production by major operating area are discussed below.

Atlantic Rim.During the three months ended September 30, 2008, average daily net production at the Atlantic Rim increased 202% to 14,929 Mcfe, as compared to 4,948 Mcfe during the same prior year period. This increase is the result of the production from 33 new wells which came on-line at our Catalina Unit properties during the first nine months of 2008. Average daily net production at our Catalina Unit increased 226% to 13,863 Mcfe, as compared to 4,248 Mcfe during the same prior year period. Average daily production, net to our interest, at the Sun Dog and Doty Mountain units increased 52% to 1,066 Mcfe, as compared to average daily production of 700 Mcfe during the same prior year period. The increase was due to production from 58 new Sun Dog Unit wells which were drilled as part of the 2007 drilling program. The operator at the Sun Dog Unit has informed us that it plans to bring one additional well on-line drilled during the 2007 drilling program in the fourth quarter of 2008. The operator has also informed us that it is in process of drilling up to 62 wells as part of its 2008 drilling program.

During the nine months ended September 30, 2008, average daily net production at the Atlantic Rim increased 121% to 10,436 Mcfe, as compared to 4,714 Mcfe during the nine months ended September 30, 2007. The increase was primarily the result of the production from 33 new wells which came on-line at our Catalina Unit properties during the first nine months of 2008. Average daily net production at our Catalina Unit increased 133% to 9,543 Mcfe, as compared to 4,099 Mcfe during the same prior year period. Average daily production at the Sun Dog and Doty Mountain units increased 45% to 893 Mcfe from 615 Mcfe in the nine months ended September 30, 2007.

Pinedale Anticline. Average daily production at the Pinedale Anticline increased 115% to 4,164 Mcfe for the quarter ended September 30, 2008, as compared to 1,933 Mcfe in the third quarter of 2007. The increase was primarily due to the addition of 22 new Mesa wells that were brought on-line in the first nine months of 2008. The operator at the Mesa Units has informed us that it is in the process of drilling up to 12 wells as part of the 2008 drilling program.

During the nine months ended September 30, 2008, average daily production at the Pinedale Anticline increased 70% to 3,830 Mcfe as compared to 2,248 Mcfe in the nine months ended September 30, 2007, due to the added production from the wells brought on-line in the first nine months of 2008 as noted above.

Madden Deep Unit. During the three and nine months ended September 30, 2008, our average daily net production at the Madden Deep Unit was 423 Mcfe and 360 Mcfe, respectively compared to 290 Mcfe and 538 Mcfe in three and nine months ended September 30, 2007, respectively. The Madden Deep Unit experienced significant workovers in the third quarter of 2007, which resulted in decreased production. Such issues did not occur in the third quarter of 2008, resulting in an increase in average daily production of 46%. The decrease in the average daily production in the nine months ended September 30, 2008 was due largely to operational issues at the sour gas plant in the first half of 2008.

•

Oil and Gas Sales

During the quarter ended September 30, 2008, net oil and gas sales increased 209% to $11,662, as compared to $3,779 during the same prior year period. Total revenue was impacted both by realized higher average gas prices and increased production volumes as discussed above. During the quarter ended September 30, 2008, the average CIG price increased 123% as compared to the same prior year period. In comparison, our average gas price received increased 31%, to $6.27 from $4.79, for the same period. The overall average increase in price that we experienced was less than the average CIG price increase due primarily to the fixed price contracts we have in place. See additional comments in “Contracted Volumes” below.

During the nine months ended September 30, 2008, net oil and gas sales increased 149% to $29,439, as compared to $11,812 during the same prior year period. Total revenue was impacted both by higher average gas prices and increased production volumes as discussed above. During the nine months ended September 30, 2008, the average CIG gas price increased 84% as compared to the same prior year period. The average gas price we received increased 35%, to $6.80 from $5.05 as compared to the same prior year period. The overall average increase in price that we experienced was less than the average CIG price increase due primarily to the fixed price contracts we have in place.

•

Cash Flow from Operations

During the nine months ended September 30, 2008, we generated cash from operations of $15,100, as compared to cash flow of $544 in the nine months ended September 30, 2007. The increase was primarily the result of increased production and a higher realized gas price during the nine months ended September 30, 2008.

OVERVIEW OF FINANCIAL CONDITION AND LIQUIDITY

Liquidity and Capital Resources

We believe that we have sufficient liquidity and capital resources to continue our strategic plan, including continued development of our major natural gas projects in the Atlantic Rim and the Pinedale Anticline, as well as pursuit of exploration/development projects (see Capital Requirements below). We intend to use capital resources made available from future operating cash flow and through our $50 million bank line of credit ($35 million borrowing base) to fund this activity. We may also consider additional offerings of securities. Although we believe that we would be able to secure additional financing if required, we can provide no assurance that we will be able to do so or as to the terms of any additional financing. We also believe that cash provided by operating activities and amounts available under the revolving credit facility will be sufficient to meet our Series A Preferred Stock dividend requirements during the remainder of 2008 of approximately $931.

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


	September 30,			December 31,
	2008			2007
Financial Position Summary
Cash and cash equivalents	$	684		$	125
Working capital	$	(3,781	)	$	(7,012	)
Line of credit outstanding	$	17,966		$	3,445
Stockholders’ equity	$	45,541		$	28,624
Ratios
Long-term debt to total capital ratio		28.3	%		10.7	%
Total debt to equity ratio		39.5	%		12.0	%

During the nine months ended September 30, 2008, our negative working capital decreased to $(3,781) compared to negative working capital of $(7,012) at December 31, 2007. The increased working capital is primarily the result of a $14,279 increase in accounts receivable, primarily associated with amounts due from our joint interest partners at the Catalina Unit for their respective working interest percentage of current costs incurred as part of our 2008 drilling program. Also, an increase in our assets from price risk management of $7,568 contributed to the higher working capital balance. This increase resulted from the increased fair value of the new economic hedges we have entered into since the prior year-end. This was offset by a $19,042 increase in our accounts payable and accrued liabilities primarily related to capital expenditures from the 2008 drilling program. 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 nine months ended September 30, 2008:


	Nine Months Ended September 30,
	2008			2007
Cash provided by (used in):
Operating Activities	$	15,100		$	544
Investing Activities		(26,549	)		(23,208	)
Financing Activities		12,008			33,884

Net change in cash	$	559		$	11,220

During the nine months ended September 30, 2008, net cash provided by operating activities was $15,100 compared to $544 in the same prior year period. During the nine months ended September 30, 2008, the primary sources of cash were $8,042 of net income, which was net of non-cash charges of $7,998 related to depreciation, depletion, and amortization expenses (“DD&A”) and accretion expense, and stock-based compensation expense of $554. In addition, we had an increase of $7,439 in accounts payable and accrued expenses related to operations and an increase of $4,554 in deferred taxes. These increases were partially offset by the increase in accounts receivable from operations of $11,832 and the non-cash gain on derivative contracts of $2,384

During the nine months ended September 30, 2008, net cash used in investing activities was $(26,549), as compared to $(23,208) in the same prior year period. During the first nine months of 2008 we invested in drilling and completion costs and power and compression infrastructure at our operated properties in the Catalina Unit as well as our share of costs for non-operated development wells in the Atlantic Rim and Pinedale Anticline from the 2007 drilling program.

During the nine months ended September 30, 2008, net cash provided by financing activities decreased to $12,008, as compared to $33,884 in the same prior year period. The net cash provided by financing activities was lower in the nine months ended September 30, 2008 due to the receipt of approximately $38 million in net proceeds from a public offering of Series A Preferred Stock in July 2007, combined with higher draws on our revolving line of credit to fund expenditures related to the 2007 and 2008 drilling programs. This was partially offset by three quarterly dividend payments totaling $2,792. Dividends will continue to be paid on a quarterly basis on the Series A Preferred Stock in the future at a rate of $931 per quarter.

Off-Balance Sheet Arrangements

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

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

Capital Requirements

Our net capital expenditures for 2008 are expected to be approximately $40-$60 million for new coal bed gas development drilling in the Atlantic Rim and new development drilling the Pinedale Anticline, depending on project participation, timing and resource availability. In addition to development of our reserves in our core areas, we believe in engaging in exploratory efforts that may lead to new core areas in the future. The 2008 budget does not include the impact of any potential future exploration projects, or ongoing exploration or development activities, including the Table Top Unit #1 project. We continually evaluate our opportunities, and if a potential opportunity is identified that complements our identified areas of expertise, it may be pursued. We believe that the amounts available under our $50 million bank line of credit ($35 million borrowing base), and net cash provided by operating activities, will provide us with sufficient funds to maintain our current facilities and complete our 2008 capital expenditure program. We may also consider offerings of securities to raise additional capital.

Line of Credit

As of September 30, 2008, the outstanding balance on the line of credit was $17,966 and the interest rate, calculated in accordance with the agreement at 1.125% below the posted Wall Street Journal Prime Rate, was 3.875% compared to 6.625% at September 30, 2007.

We are subject to certain financial and non-financial covenants with respect to the above credit facility, including a requirement to maintain a current ratio, plus the line of credit availability, of at least 1.0 to 1.0. As of September 30, 2008, we were in compliance with all such covenants. Should any of the covenants with respect to this credit facility be violated, and if we were unable to negotiate a waiver or amendment thereof, the lender would have the right to declare an event of default, terminate the remaining commitment and accelerate all principal and interest outstanding.

For the three and nine months ended September 30, 2008, we recognized no interest expense with respect to the above credit lines, and capitalized interest totaled $222 and $515, respectively.

RESULTS OF OPERATIONS

Three months ended September 30, 2008 compared to the three months ended September 30, 2007

Oil and gas sales volume and price comparisons


	Three Months Ended September 30,								Percent			Percent
	2008				2007				Volume			Price
	Volume		Average Price		Volume		Average Price		Change			Change
Product:
Gas (Mcf)		1,876,642	$	6.27		749,497	$	4.79		150	%		31	%
Oil (Bbls)		5,685	$	98.42		2,798	$	66.91		103	%		47	%
Mcfe		1,910,752	$	6.45		766,285	$	4.93		149	%		31	%

Our average gas price realized for the three months ended September 30, 2008 is calculated by summing 1) cash received from third parties for sale of our gas, included in the oil and gas revenue line item on the statement of operations, 2) settlement of our cash flow hedges included within oil and gas revenue on the statement of operations and 3) realized gain/loss on our economic hedges, which due to accounting rules is included in our price risk management activities line on the statement of operations, totaling $658 and $0, for the three months ended September 30, 2008 and 2007, respectively. This amount is divided by the total gas volume for the period.

For the three months ended September 30, 2008, total net production increased 149% to 1,910,752 Mcfe as compared to the three months ended September 30, 2007. The increase in volumes was due largely to the addition of wells at the Atlantic Rim and Pinedale Anticline, offset somewhat by the decrease of our working interest in the Catalina Unit resulting from unitization.

Prior to December 21, 2007, we owned 100% of the working interest in the Cow Creek Unit. With the formation of the Catalina Unit and expansion of the participating area, which included the 14 wells in the original Cow Creek Unit as well as the new wells from the 2007 drilling program, our working interest decreased to 73.84% in the Catalina Unit. During the three months ended September 30, 2008, average daily net production at the Atlantic Rim increased 202% to 14,929 Mcfe, as compared to 4,948 Mcfe during the three months ended September 30, 2007, largely resulting from the addition of 33 new wells which were on-line at our Catalina Unit properties during the period. Average daily net production at our Catalina Unit increased 226% to 13,863 Mcfe, as compared to 4,248 Mcfe during the same prior year period. Average daily production, net to our interest, at the Sun Dog and Doty Mountain units increased 52% to 1,066 Mcfe, as compared to average daily production of 700 during the same prior year period. The increase was due to the addition of 58 wells from the Sun Dog Unit’s 2007 drilling program. The operator at Sun Dog Unit has informed us it expects to bring on one additional well during the fourth quarter of 2008. The operator has also informed us that it is in process of drilling up to 62 wells in the Sun Dog and Doty Mountain units as part of its 2008 drilling program.

During the three months ended September 30, 2008, average daily production in the Pinedale Anticline increased 115% to 4,164 Mcfe, as compared to 1,933 Mcfe in the same prior year period. Twenty two new wells were brought online during the first nine months of 2008, resulting in the increased production. The operator at the Mesa Units has informed us that it is in process of drilling up to 12 additional wells as part of the 2008 drilling program.

During the three months ended September 30, 2008, the average daily production at the Madden Unit was 423 Mcfe compared to 290 Mcfe in the same prior year period. Significant workovers occurred at the Madden Deep Unit during the three months ended September 30, 2007, which resulted in decreased production. Such issues were avoided in 2008, and thus the average daily production increased 46%.

For the three months ended September 30, 2008, oil and gas revenue increased 209% to $11,662, as compared to the same prior year period. This increase was due in part to the production increases discussed above, as well as an increase in our average gas price realized. During the three months ended September 30, 2008, our average gas price realized increased 31%, to $6.27 from $4.79, as compared to an increase of 123% in the average CIG index price. Our realized average price did not increase consistent with the CIG index prices due to the fixed price contracts in place during the quarter. See additional comments under “Contracted Volumes” below.

Transportation and gathering revenue

During the three months ended September 30, 2008, transportation and gathering revenue increased 430% to $1,283 from $242. The Company receives fees for gathering and transporting third party gas through our intrastate gas pipeline, which connects the Catalina Unit with the interstate pipeline system owned by Southern Star Central Gas Pipeline, Inc. The increase in revenue is due to an increase in the fee charged to third parties and higher production volumes at the Catalina Unit discussed above.

Price Risk Management

During the three months ended September 30, 2008, we recorded a net gain on our derivative contracts of $1,020. This amount consists of an unrealized gain of $362 which represents marking our mark-to-market derivative instruments to fair value at September 30, 2008, based on the future expected prices of the related commodities, and a net realized gain of $658 related to the settlements of some of our economic hedges.

Oil and gas production expenses, depreciation, depletion and amortization


	Three Months Ended September 30,
	2008			2007
	(in dollars per mcfe)
Average price	$	6.45		$	4.93

Production costs		1.04			1.10
Production taxes		0.74			0.61
Depletion and amortization		1.76			1.52

Total operating costs		3.54			3.23


Gross margin	$	2.91		$	1.70

Gross margin percentage		45	%		34	%

During the three months ended September 30, 2008, well production costs increased 135% to $1,982, as compared to $844 during the same prior year period, and production costs in dollars per Mcfe decreased 5%, or $0.06 to $1.04, as compared to the same prior year period. The decrease in well production costs on a per Mcfe basis is largely attributed to operating efficiencies gained from the increased production at the Company operated Catalina Unit, partially offset by increased production costs at our non-operated Doty Mountain Unit.

In the third quarter of 2008, we engaged a third party reservoir engineering firm to evaluate our reserves as of June 30, 2008. The study showed an overall increase in producing reserves of approximately 9.6 Bcfe from December 31, 2007. The updated reserve data was used in the calculation of DD&A for the three months ended September 30, 2008. During the three months ended September 30, 2008, DD&A increased 157% to $3,462 as compared to $1,349 in the same prior year period, and depletion and amortization related to producing assets increased 188% to $3,361 as compared to $1,165 in the same prior year period. The increase was largely due to an increase in capital expenditures at the Catalina, Sun Dog and Mesa units, increased production levels, and a decrease in the reserve estimates at the Sun Dog unit used in the calculation of DD&A. This increase was partially offset by an increase in the reserve estimates used in the calculation of DD&A at the Catalina and Mesa units, which lowered the period expense. Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased 16%, or $0.24, to $1.76, as compared to the same prior year period.

Pipeline operating costs

During the three months ended September 30, 2008, pipeline operating costs increased to $636 from $165. The increase is due to increased volume throughput and costs incurred with rental, transportation and maintenance expenses for the two temporary compressors installed in the Catalina Unit.

General and administrative

During the three months ended September 30, 2008, general and administrative expenses increased 50% to $1,652, as compared to $1,105 in the same prior year period. The increase was primarily due to increased costs related to our Board of Directors of $205, higher stock-based compensation expense of $114 due to additional grants to employees, additional salary and salary related expenses of approximately $72 primarily related to headcount additions, $61 related to our mid-year reserve study, and $53 of additional costs associated with the implementation of our new accounting software. These costs were offset by lower audit and accounting consulting expenses and bank fees.

Income taxes

During the three months ended September 30, 2008, we recorded income tax expense of $1,557 compared to an income tax benefit of $2,225 during the same prior year period. Our effective tax rate for the three months ended September 30, 2008 was 34.9% compared to 31.7% for the three months ended September 30, 2007. The rate is higher for the 2008 period due to permanent income tax differences related to stock option expense in 2008. Although we expect to continue to generate losses for federal income tax reporting purposes, our operations have resulted in a deferred tax position required under generally accepted accounting principles. We expect to recognize deferred income tax expense on taxable income for the remainder of 2008 at an expected federal and state rate of approximately 36.4%.

Nine months ended September 30, 2008 compared to the nine months ended September 30, 2007

Oil and gas sales volume and price comparisons


	Nine Months Ended September 30,								Percent			Percent
	2008				2007				Volume			Price
	Volume		Average Price		Volume		Average Price		Change			Change
Product:
Gas (Mcf)		4,215,099	$	6.80		2,224,437	$	5.05		89	%		35	%
Oil (Bbls)		14,762	$	97.18		9,998	$	58.34		48	%		67	%
Mcfe		4,303,671	$	6.99		2,284,425	$	5.17		88	%		35	%

Our average gas price realized for the nine months ended September 30, 2008 is calculated by summing 1) cash received from third parties for sale of our gas, included in the oil and gas revenue line item on the statement of operations, 2) settlement of our cash flow hedges included within oil and gas revenue on the statement of operations and 3) realized gain/losses on our economic hedges, which due to accounting rules is included in our price risk management activities line on the statement of operations. This amount is divided by the total gas volume for the period.

For the nine months ended September 30, 2008, total net production increased 88% to 4,303,671 Mcfe as compared to the nine months ended September 30, 2007. The increase in volumes is due largely to the addition of wells at the Atlantic Rim and Pinedale Anticline, offset somewhat by decreased production at the Madden Unit and the decrease of our working interest in the Catalina Unit resulting from unitization.

During the nine months ended September 30, 2008, average daily net production at the Atlantic Rim increased 121% to 10,436 Mcfe, as compared to 4,714 Mcfe during the nine months ended September 30, 2007. The increased production is the primarily the result of 33 new wells which were brought on-line at the Catalina Unit during the first nine months of 2008. Average daily production at our Catalina Unit increased 133% to 9,543 Mcfe, as compared to 4,099 Mcfe during the same prior year period. Average daily production at our Sun Dog and Doty Mountain units increased 45% to 893 Mcfe, as compared to average daily production of 615 during the same prior year period. The increase was primarily due to 58 new wells brought online from the 2007 drilling program.

During the nine months ended September 30, 2008, average daily production in the Pinedale Anticline increased 70% to 3,830 Mcfe, as compared to 2,248 Mcfe in the same prior year period. The increase is primarily due to the addition of 22 new Mesa wells, which were brought on-line during the first nine months of 2008.

During the nine months ended September 30, 2008, the average daily production at Madden Unit was 360 Mcfe compared to 538 Mcfe in the same prior year period. The decrease in production was largely due to operational difficulties at the sour gas plant in the first half of 2008.

For the nine months ended September 30, 2008, oil and gas sales increased 149% to $29,439, as compared to the nine months ended September 30, 2007. This increase is due in part to the volume increase discussed above, as well as an increase in our average gas price realized. During the nine months ended September 30, 2008, our average gas price realized increased 35%, to $6.80 from $5.05, as compared to an increase of 84% in the average CIG index price. Our realized average price did not increase consistent with the CIG index prices due to our fixed price contracts in place during the quarter. See additional comments under “Contracted Volumes” below.

Transportation and gathering revenue

During the nine months ended September 30, 2008, transportation and gathering revenue increased 251% to $2,370 from $675 as compared to the nine months ended September 30, 2008. The Company receives a fee for gathering and transporting third party gas through our intrastate gas pipeline, which connects the Catalina Unit with the interstate pipeline system owned by Southern Star Central Gas Pipeline, Inc. The increase in revenue is due to an increase in the fee charged to third parties and higher production volumes at the Catalina Unit discussed above.

Price Risk Management

During the nine months ended September 30, 2008, we recorded a net gain on our derivative contracts of $3,042. This amount consists of an unrealized gain of $2,384 which represents marking our mark-to-market derivative instruments to fair value at September 30, 2008, based on the future expected prices of the related commodities, and a net realized gain of $658 related to the settlements of some mark-to-market contracts.

Oil and gas production expenses, depreciation, depletion and amortization


	Nine Months Ended September 30,
	2008			2007
	(in dollars per mcfe)
Average price	$	6.99		$	5.17

Production costs		1.18			1.71
Production taxes		0.87			0.64
Depletion and amortization		1.67			1.62

Total operating costs		3.72			3.97


Gross margin	$	3.27		$	1.20

Gross margin percentage		47	%		23	%

During the nine months ended September 30, 2008, well production costs increased 30% to $5,074, as compared to $3,910 during the same prior year period, and production costs in dollars per Mcfe decreased 31%, or $0.53 to $1.18, as compared to the same prior year period. The decrease in well production costs per Mcfe is attributed to increased operating efficiency and lower well work-over costs versus prior year period.

In the third quarter of 2008, we engaged a third party reservoir engineering firm to evaluate our reserves as of June 30, 2008. The study showed an overall increase in producing reserves of approximately 9.6 Bcfe from December 31, 2007. The updated reserve data was used in the calculation of DD&A for the three months ended September 30, 2008. During the nine months ended September 30, 2008, total DD&A increased 82% to $7,456 as compared to $4,094 in the same prior year period, and depletion and amortization related to producing assets increased 94% to $7,166 as compared to $3,697 in the same prior year period. The increase is largely due to an increase in capital expenditures at the Catalina, Sun Dog and Mesa units, increased production levels, and a decrease in the reserve estimates at the Sun Dog unit used in the calculation of DD&A. This increase was partially offset by an increase in the reserve estimates used in the calculation of DD&A at the Catalina and Mesa units, which caused a decrease in the expense recognized during the period. Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased 3%, or $0.05, to $1.67, as compared to the same prior year period.

Pipeline operating costs

During the nine months ended September 30, 2008 pipeline operating costs increased to $1,383 from $250. The increase is due to increased volume throughput, and costs incurred with rental, transportation and maintenance expenses for the two temporary compressors installed in the Catalina Unit.

General and administrative

General and administrative expenses increased 34% to $3,861 for the nine months ended September 30, 2008, as compared to $2,880 for the nine months ended September 30, 2007. The increase was primarily due to a $224 increase in Board of Director related costs, higher stock-based compensation expense of $179 due to additional grants to employees, $149 of additional costs related to implementation of our new accounting software, $145 of additional salary and salary related expenses due primarily to headcount additions, and $61 related to our mid-year reserve study. These costs were offset somewhat by lower audit costs and lower bank fees.

Income taxes

We recorded income tax expense of $4,554 for the nine months ended September 30, 2008 compared to an income tax benefit of $2,544 during the same prior year period. Our effective tax rate for the nine months ended September 30, 2008 was 36.2% compared to 33.4% for the nine months ended September 30, 2007. The rate is higher for the 2008 period due to the impact of permanent income tax differences relating to stock options recognized in 2008. Although we expect to continue to generate losses for federal income tax reporting purposes, our operations have resulted in a deferred tax position required under generally accepted accounting principles. We expect to recognize deferred income tax expense on taxable income for the remainder of 2008 at an expected federal and state rate of approximately 36.4%.

CONTRACTED VOLUMES

Changes in the market price of oil and natural gas can significantly affect our profitability and cash flow. We have a Company hedging policy in place to mitigate exposures to oil and gas production cash-flow risk caused by fluctuating commodity prices. At September 30, 2008, we had derivative instruments in effect for approximately 68% of our total current daily net production.

We have entered into various fixed delivery contracts for our production from the Atlantic Rim and the Pinedale Anticline. For the three months ended September 30, 2008, the weighted average price of our contracted volumes was higher than the weighted average price for the open market volumes and we recognized a gain $177 related to these fixed delivery contracts. For the nine months ended September 30, 2008, the weighted average price of our contracted volumes was lower than the weighted average price for the open market volumes. We recognized a loss on price risk management for the nine months ended September 30, 2008 of approximately $1,298. Gains and losses related to the settlement of our fixed price contracts are recorded within oil and gas revenue on the statement of operations.

Our outstanding forward sales contracts as of September 30, 2008 are summarized below (volume and daily production are expressed in Mcf):

FORWARD SALES CONTRACTS


	Remaining
	Contractual		Daily				Fixed
Property	Volume		Production		Term		Price/Mcf

Catalina		243,000		1,000		06/07-05/09	$	5.47
		273,000		1,000		07/07-06/09	$	5.84
		546,000		2,000		07/07-06/09	$	5.69
		396,000		1,000		11/07-10/09	$	5.66
Atlantic Rim		304,000		1,000		08/07-07/09	$	6.15
Pinedale Anticline		273,000		1,000		07/07-06/09	$	6.41


Company Total		2,035,000

The Company also has a NYMEX futures contract in place for 3,000 Mcf per day for the period November 2008 through March 2009. The instrument was entered into in an effort to limit the Company’s credit risk exposure during the winter months when prices historically rise.

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

Remaining

Contractual

Daily

Type of Contract

Volume

Production

Term

Price

Price Index (1)

Costless Collar

62,000

2,000

5/08-10/08

$6.50 floor/$10.00 ceiling

CIG

Costless Collar

453,000

3,000

11/08-3/09

$6.50 floor/$13.50 ceiling

CIG

Costless Collar

155,000

5,000

7/08-10/08

$10.00 floor/$17.00 ceiling

NYMEX

Option (2)

755,000

5,000

11/08-3/09

$8.23 floor

CIG

Fixed Price Swap

2,920,000

8,000

1/09-12/09

$7.34

CIG

Fixed Price Swap

2,920,000

8,000

1/11-12/11

$7.07

CIG

Total

7,265,000


(1)		NYMEX refers to quoted prices on the New York Mercantile Exchange. CIG refers to the Colorado Interstate Gas price as quoted on the first day of each month.

(2)		The $8.23 CIG floor is made up of two separate contracts, a $10.50 NYMEX floor and a $2.27 basis hedge.

The Company has entered into costless collars to partially protect the price received on the increased production volume coming from our Catalina Unit. Under the costless collar, the price of gas realized by the Company will float with the market price until it reaches either the price floor or price ceiling, at which time the Company will receive the applicable floor or ceiling price for the contracted volumes. This arrangement will allow the Company to take advantage of favorable changes in the market, while limiting the impact of a potential price decrease as seen in prior years. We also have entered into a basis economic hedge for 5,000 Mcf per day, locking in the basis differential between NYMEX and CIG at $2.27. This hedge coincides with a NYMEX floor for the period November 2008 through March 2009 and effectively turns our NYMEX floor into a CIG floor at $8.23. Finally, we have two fixed price swap contracts for calendar 2009 and 2011 for 8,000 Mcf per day at a CIG price of $7.34 and $7.07, respectively.

In October 2008, we entered into an additional collar for 3,000 Mcf per day with a CIG price floor of $8.85 and a price ceiling of $13.05. The contract is for the period November, 2008 through March, 2009.

For the three and nine months ended September 30, 2008, the Company recorded an unrealized gain on price risk management of $362 and $2,384 respectively, related to the above contracts. Upon settlement of the above mark-to-market instruments, the realized gain/loss is recorded in the price risk management line on the statement of operations. For the three and nine months ended September 30, 2008, the Company recorded a realized gain of $658.

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, 2007, 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

Commodity Price Risks

Our major market risk exposure is in the pricing applicable to our natural gas and oil production. Pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our U.S. natural gas production. Pricing for oil production and natural gas has been volatile and unpredictable for several years. The prices we receive for production depend on many factors outside of our control. For the quarter ended September 30, 2008, our income before income taxes would have changed by $258 for each $0.50 change per Mcf in natural gas prices and $5 for each $1.00 change per Bbl in crude oil prices.

We have entered into natural gas derivative contracts to manage our exposure to natural gas price volatility. Our derivative instruments include both fixed price delivery contracts for a portion of the production from the Atlantic Rim and the Pinedale Anticline as well as a natural gas futures contract, fixed price swaps and costless collars, allowing us to effectively “lock in” a portion of our future production of natural gas at prices that we considered favorable to Double Eagle at the time we entered into the contract. At September 30, 2008, we had derivative contracts in effect for approximately 68% of our total current daily net production. These fixed delivery contracts, which have differing expiration dates, are summarized in the table presented above under Item 2, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contracted Volumes.”

Interest Rate Risks

At September 30, 2008 we had $17,966 outstanding on our $50 million revolving credit line ($35 million borrowing base). We pay interest on outstanding borrowings under our revolving credit facility at interest rates that fluctuate based upon changes in the prime lending rate. As the interest rate is variable and reflective of current market conditions, the carrying value approximates the fair value. Assuming no change in the amount outstanding at September 30, 2008, the annual impact on interest expense for every 1.0% change in the average interest rate would be approximately $180 before taxes. As of September 30, 2008, 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 3.875%.

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 (Principal Executive Officer) and Chief Financial Officer (Principal Accounting Officer), of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on this evaluation, our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Accounting Officer) have concluded that our disclosure controls and procedures are effective to ensure that information we are required to disclose in reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms.

There has been no change in our internal control over financial reporting that occurred during the three months ended September 30, 2008 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Reference is made to “Notes to Consolidated Financial Statements (Unaudited)) — Commitments and Contingent Liabilities” in Part I, Item 1 of this Form 10-Q and incorporated by reference in this Part II, Item 1.

ITEM 1A. RISK FACTORS

The following additional or revised Risk Factors should be considered along with our Risk Factors reported in Item 1A of Part I of our 2007 Annual Report on Form 10-K filed with the Securities and Exchange Commission, which we incorporate by reference herein.

Declining economic conditions could negatively impact our business.

Our operations are affected by local, national and worldwide economic conditions. The consequences of a potential or prolonged recession may include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets. A lower level of economic activity might result in a decline in energy consumption, which may adversely affect our revenues and future growth. Instability in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise capital.

The trading volatility and price of our common stock may be affected by many factors.

Many factors affect the volatility and price of our common stock in addition to our operating results and prospects. The most important of these, some of which are outside our control, are the following:

•

The current financial crisis, which has caused significant market volatility worldwide;

•

Governmental action or inaction in light of key indicators of economic activity or events that can significantly influence U.S. financial markets, and media reports and commentary about economic or other matters, even when the matter in question does not directly relate to our business; and

•

Trading activity in our common stock, which can be a reflection of changes in the prices for oil and gas, or market commentary or expectations about our business and overall industry.

ITEM 6. EXHIBITS

The following exhibits are filed as part of this report:


Exhibit		Description:

	10.1	Employment Agreement between the Company and Richard Dole, dated September 4, 2008 (incorporated by reference from Exhibit 10.1 of the Company’s Current Report of Form 8-K dated September 9, 2008).

	10.2	Employment Agreement between the Company and Kurtis Hooley, dated September 4, 2008 (incorporated by reference from Exhibit 10.2 of the Company’s Current Report of Form 8-K dated September 9, 2008).

	10.3	Employment Agreement between the Company and D. Steven Degenfelder, dated September 4, 2008 (incorporated by reference from Exhibit 10.3 of the Company’s Current Report of Form 8-K dated September 9, 2008).

	10.4	Employment Agreement between the Company and Robert Reiner, dated September 4, 2008 (incorporated by reference from Exhibit 10.4 of the Company’s Current Report of Form 8-K dated September 9, 2008).

	10.5	Employment Agreement between the Company and Aubrey Harper, dated September 4, 2008 (incorporated by reference from Exhibit 10.5 of the Company’s Current Report of Form 8-K dated September 9, 2008).

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

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

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

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	DOUBLE EAGLE PETROLEUM CO. (Registrant)
Date: November 7, 2008	By:	/s/ Richard D. Dole
		Richard D. Dole
		Chief Executive Officer

Date: November 7, 2008	By:	/s/ Kurtis S. Hooley
		Kurtis S. Hooley
		Chief Financial Officer

EXHIBIT INDEX


Exhibit Number		Description

	10.1	Employment Agreement between the Company and Richard Dole, dated September 4 2008 (incorporated by reference from Exhibit 10.1 of the Company’s Current Report of Form 8-K dated September 9, 2008).

	10.2	Employment Agreement between the Company and Kurtis Hooley, dated September 4, 2008 (incorporated by reference from Exhibit 10.2 of the Company’s Current Report of Form 8-K dated September 9, 2008).

	10.3	Employment Agreement between the Company and D. Steven Degenfelder, dated September 4, 2008 (incorporated by reference from Exhibit 10.3 of the Company’s Current Report of Form 8-K dated September 9, 2008).

	10.4	Employment Agreement between the Company and Robert Reiner, dated September 4, 2008 (incorporated by reference from Exhibit 10.4 of the Company’s Current Report of Form 8-K dated September 9, 2008).

	10.5	Employment Agreement between the Company and Aubrey Harper, dated September 4, 2008 (incorporated by reference from Exhibit 10.5 of the Company’s Current Report of Form 8-K dated September 9, 2008).

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

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

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

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

Escalera Resources (ESCR) Inactive 10-Q2008 Q3 Quarterly report

Content analysis

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents