Escalera Resources 10Q 2009 Q2 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 June 30, 2009


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 1-33571

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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yeso 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 filer o	Smaller reporting Companyo
	(Do not check if a smaller 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 July 15, 2009 9,244,239

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


	Page #
PART I. Financial Information:

Item 1. Financial Statements

Consolidated Balance Sheets as of June 30, 2009 (Unaudited) and December 31, 2008		3

Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2009 and 2008 (Unaudited)		4

Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2009 and 2008 (Unaudited)		5

Notes to Consolidated Financial Statements (Unaudited)		6

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		16

Item 3. Quantitative and Qualitative Disclosures About Market Risk		27

Item 4. Controls and Procedures		28

PART II. Other Information:

Item 1. Legal Proceedings		28

Item 1A. Risk Factors		28

Item 4. Submission of Matters to a Vote of Security Holders		28

Item 6. Exhibits		28

Signatures		30

Exhibit 31.1
Exhibit 31.2
Exhibit 32

PART I. FINANCIAL INFORMATION


ITEM 1.		FINANCIAL STATEMENTS

DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED BALANCE SHEETS

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


	June 30,			December 31,
	2009			2008
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	3,898		$	—
Cash held in escrow		608			605
Accounts receivable		8,496			21,381
Assets from price risk management		5,982			14,290
Other current assets		3,045			3,513

Total current assets		22,029			39,789


Oil and gas properties and equipment, successful efforts method:
Developed properties		156,063			133,516
Wells in progress		10,902			18,518
Gas transportation pipeline		5,465			5,465
Undeveloped properties		2,915			2,907
Corporate and other assets		2,043			1,920

		177,388			162,326
Less accumulated depreciation, depletion and amortization		(44,350	)		(35,253	)

Net properties and equipment		133,038			127,073

Assets from price risk management		3,047			5,029
Other assets		84			98

TOTAL ASSETS	$	158,198		$	171,989


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	9,251		$	35,488
Accrued expenses		4,891			6,794
Liabilities from price risk management		974			—
Term loan		3,750			—
Accrued production taxes		3,851			3,017
Capital lease obligations, current portion		528			522
Other current liabilities		308			282

Total current liabilities		23,553			46,103

Line of credit		38,750			24,639
Asset retirement obligation		4,194			4,208
Liabilities from price risk management		2,203			—
Deferred tax liability		2,991			2,470
Capital lease obligations, long-term portion		813			1,078
Other long-term liabilities		436			616

Total liabilities		72,940			79,114


Preferred stock, $0.10 par value; 10,000,000 shares authorized; 1,610,000 shares issued and outstanding as of June 30, 2009 and December 31, 2008		37,972			37,972

Stockholders’ equity:
Common stock, $0.10 par value; 50,000,000 shares authorized; 9,233,756 and 9,192,356 shares issued and outstanding as of June 30, 2009 and December 31, 2008, respectively		924			919
Additional paid-in capital		35,846			35,122
Retained earnings		1,075			2,172
Accumulated other comprehensive income		9,441			16,690

Total stockholders’ equity		47,286			54,903


TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	158,198		$	171,989

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

DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED STATEMENTS OF OPERATIONS

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


	Three months ended June 30,						Six months ended June 30,
	2009			2008			2009			2008

Revenues
Oil and gas sales	$	10,492		$	11,526			20,992		$	17,777
Transportation revenue		1,583			723			3,170			1,087
Price risk management activities		(2,152	)		1,370			(3,292	)		2,022
Other income, net		117			170			210			219


Total revenues		10,040			13,789			21,080			21,105


Costs and expenses
Production costs		1,989			2,076			3,601			3,092
Production taxes		753			1,534			1,642			2,334
Exploration expenses including dry hole costs		29			50			55			531
Pipeline operating costs		1,087			659			1,654			747
General and administrative		1,427			1,302			3,101			2,209
Depreciation, depletion and amortization		4,715			2,979			9,097			3,994


Total costs and expenses		10,000			8,600			19,150			12,907


Income from operations		40			5,189			1,930			8,198

Interest expense, net		(392	)		—			(644	)		(64	)


Income (loss) before income taxes		(352	)		5,189			1,286			8,134

Benefit (provision) for deferred income taxes		110			(1,916	)		(521	)		(2,999	)


NET INCOME (LOSS)	$	(242	)	$	3,273		$	765		$	5,135


Preferred stock dividends		931			931			1,862			1,862


Net income (loss) attributable to common stock	$	(1,173	)	$	2,342		$	(1,097	)	$	3,273


Net income (loss) per common share:
Basic	$	(0.13	)	$	0.26		$	(0.12	)	$	0.36

Diluted	$	(0.13	)	$	0.26		$	(0.12	)	$	0.36


Weighted average shares outstanding:
Basic		9,233,725			9,152,023			9,217,902			9,150,064

Diluted		9,233,725			9,161,258			9,217,902			9,153,696

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

DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in thousands of dollars)
(Unaudited)


	Six months ended June 30,
	2009			2008
Cash flows from operating activities:
Net income	$	765		$	5,135
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion, amortization and accretion of asset retirement obligation		9,147			4,116
Abandonment of non-producing properties		6			140
Provision for deferred taxes		521			2,999
Employee stock option expense		693			240
Directors fees paid in stock		77			—
Change in fair value of derivative contracts		6,218			(2,022	)
Revenue from carried interest		(954	)		—
Gain on sale of producing property		(140	)		(66	)
Changes in current assets and liabilities:
Decrease (Increase) in deposit held in escrow		(3	)		106
Decrease (Increase) in accounts receivable		14,137			(6,363	)
Decrease (Increase) in other current assets		(99	)		(1,638	)
Increase (Decrease) in accounts payable		(13,369	)		2,446
Increase (Decrease) in accrued expenses		(1,007	)		3,717
Increase in accrued production taxes		834			1,660


NET CASH PROVIDED BY OPERATING ACTIVITIES		16,826			10,470


Cash flows from investing activities:
Additions of producing properties and equipment, net		(28,315	)		(24,209	)
Additions of corporate and non-producing properties		(15	)		(275	)
Payment of acquisition related costs		(320	)		—


NET CASH USED IN INVESTING ACTIVITIES		(28,650	)		(24,484	)


Cash flows from financing activities:
Principal payments on capital lease obligations		(259	)		—
Exercise of stock options		—			277
Issuance of stock under Company stock plans		5			—
Tax withholdings related to net share settlement of restricted stock awards		(23	)		—
Preferred stock dividends		(1,862	)		(1,862	)
Net borrowings (repayments) on credit facility		17,861			15,739


NET CASH PROVIDED BY FINANCING ACTIVITIES		15,722			14,154


Change in cash and cash equivalents		3,898			140

Cash and cash equivalents at beginning of period		—			125


CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	3,898		$	265


Supplemental disclosure of cash and non-cash transactions:
Cash paid for interest	$	1,233		$	162
Interest capitalized	$	643		$	293
Adjustment to joint interest partners’ well costs associated with unitization of Catalina	$	1,252		$	9,939
Additions to developed properties included in current liabilities	$	6,832		$	5,607
Share-based compensation expense	$	770		$	240

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 2008 consolidated financial statements and quarterly report dated June 30, 2009 have been reclassified to conform to the 2009 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, 2008, 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, 2008 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 implemented this Statement with the one-year deferral. Beginning January 1, 2009, the Company adopted the provisions for nonfinancial assets and nonfinancial liabilities. The adoption of SFAS 157-2 did not have a material impact on the Company’s financial position, results of operations or cash flows.

In April 2009, the FASB issued FASB Staff Position (“FSP”) FAS 157-4, Determining Fair Value when the Volume and Level of Activity for the Asset or Liability have Significantly Decreased and Identifying Transactions that are not Orderly(“FSP 157-4”). FSP 157-4 affirms that the objective of fair value when the market for an asset is not active, is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date under current market conditions. The FSP provides guidance for estimating fair value when the volume and level of market activity for an asset or liability have significantly decreased and determining whether a transaction was orderly. This FSP applies to all fair value measurements when appropriate. The Company adopted FSP 157-4 effective April 1, 2009. The adoption of FSP 157-4 did not have a material impact on its 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 Company adopted the provisions of SFAS 161 effective January 1, 2009. See Note 3 for the Company’s disclosures about its derivative instruments and hedging activities.

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 Company adopted SFAS 141(R) effective January 1, 2009. The adoption of SFAS 141(R) did not have a material impact on the Company’s 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 Company adopted SFAS 160 effective January 1, 2009. The adoption of SFAS 160 did not have a material impact on the Company’s financial position, results of operations or cash flows.

In June 2008, the FASB issued FASB Staff Position No. EITF 03-06-1 “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”). FSP EITF 03-06-1 provides guidance as to whether instruments granted in share-based payment transactions are participating securities prior to vesting, and therefore, need to be included in computing earnings per share under the two-class method provided under FASB No. 128 – Earnings Per Share. The Company adopted this standard effective January 1, 2009. The adoption of FSP EITF 03-06-1 did not have a material impact on the Company’s financial position, results of operations or cash flows.

In May 2009, the FASB issued Statement of Financial Accounting Standards No. 165,Subsequent Events, (“SFAS 165”). SFAS 165 establishes general standards of accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. Among other things, SFAS 165 requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for that date. The Company adopted the provisions of SFAS 165 effective April 1, 2009. See Note 15 for the Company’s disclosures about subsequent events.

In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1,Interim Disclosures about Fair Value of Financial Instruments(“FSP 107-1”). FSP 107-1 requires an entity to provide the annual disclosures required by FASB Statement No. 107,Disclosures about Fair Value of Financial Instruments, in its interim financial statements. The Company adopted the provisions of FSP 107-1 effective April 1, 2009. The Company has incorporated the disclosures required by FSP 107-1 in Notes 1 and 4 herein.

New accounting pronouncements

In December 2008, the SEC announced final approval of new requirements for reporting oil and gas reserves. Among the changes to the disclosure requirements is a broader definition of reserves, which allows consideration of new technologies. In addition, oil and gas reserves will be reported using an average price based on the prior 12-month period, rather than year-end prices, and companies can disclose their probable and possible reserves to investors. The new rule is expected to be effective for years ending on or after December 31, 2009. The Company is in the process of evaluating the effect of these new requirements, and has not yet determined the impact that it will have on its financial statements upon full adoption on December 31, 2009.

In June 2009, the FASB issued Statement of Financial Accounting Standards No. 168 — The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles- a replacement of FASB Statement No. 162 (“SFAS 168”). SFAS 168 establishes the FASB Accounting Standards Codification as the single source of authoritative US generally accepted accounting principles recognized by the FASB to be applied to nongovernmental entities. SFAS 168 is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The adoption of SFAS 168 will not have an impact on the Company’s financial position, results of operations or cash flows.

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 incorporates the treasury stock method, and 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 $931 ($.5781 per share) on the Series A Preferred Stock for the three months ended June 30, 2009 and 2008, and $1,862 for the six months ended June 30, 2009 and 2008.

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 June 30,					For the Six Months Ended June 30,
	2009			2008		2009			2008
Net income (loss)	$	(242	)	$	3,273	$	765		$	5,135
Preferred stock dividends		931			931		1,862			1,862

Income (loss) attributable to common stock	$	(1,173	)	$	2,342	$	(1,097	)	$	3,273

Weighted average shares:
Weighted average shares — basic		9,233,725			9,152,023		9,217,902			9,150,064
Dilution effect of stock options outstanding at the end of period		—			9,235		—			3,632

Weighted average shares — diluted		9,233,725			9,161,258		9,217,902			9,153,696


Income (loss) per common share:
Basic	$	(0.13	)	$	0.26	$	(0.12	)	$	0.36

Diluted	$	(0.13	)	$	0.26	$	(0.12	)	$	0.36

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 per share because the effect would have been anti-dilutive for the periods indicated:


	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2009		2008		2009		2008

Anti-dilutive shares		87,931		35,560		87,931		15,586

Derivative Instruments

On January 1, 2009, the Company adopted SFAS No. 161, which requires enhanced disclosures regarding an entity’s derivative and hedging activities as provided below.

The Company’s primary market exposure is to adverse fluctuations in the prices of natural gas. The Company uses derivative instruments, primarily forwards, costless collars and swaps, to manage the price risk associated with equity gas production, and the resulting impact on cash flow, net income, and earnings per share. The Company does not use derivative instruments for speculative purposes.

The Company recognizes its derivative instruments as either assets or liabilities at fair value on our consolidated balance sheet, except for certain instruments which qualify for accounting treatment exception under “normal purchases and normal sales”. See additional discussion of these instruments below. The Company accounts for the commodity forward contracts that do not qualify for this exception as either cash flow hedges or mark to market derivative instruments. On the cash flow statement, the cash flows from these instruments are classified as operating activities.

Derivative instruments expose the Company to counterparty credit risk. The Company enters into these contracts with third parties and financial institutions that it considers to be credit worthy. In addition, the Company’s master netting agreements reduce credit risk by permitting the Company to net settle for transactions with the same counterparty.

As with most derivative instruments, our derivative contracts contain provisions which may allow for another party to require security from the counterparty to ensure performance under the contract. The security may be in the form of, but not limited to, a letter of credit, security interest or a performance bond.

Cash flow hedges

Derivative instruments that are designated and qualify as cash flow hedges are recorded at fair value on the balance sheet and the effective portion of the change in fair value is reported as a component of accumulated other comprehensive income and is subsequently reclassified into the oil and gas sales line on the consolidated statement of operations as the contracts settle. As of June 30, 2009, the Company expects approximately $6,393 of unrealized gains, included in its Accumulated Other Comprehensive Income (“AOCI”) to be reclassified into earnings in one year or less, as the contracts settle.

Mark to market hedging instruments

Unrealized gains and losses resulting from derivatives not designated as cash flow hedges are recorded at fair value on the balance sheet and changes in fair value are recognized in the price risk management activities line on the consolidated statement of operations currently. Realized gains and losses resulting from the contract settlement of derivatives not designated as cash flow hedges also are recorded in the price risk management activities line on the consolidated statement of operations.

The Company had the following commodity forward contracts outstanding as of June 30, 2009:


	Contract Settlement Date
	2009		2010		2011
Natural gas forward purchase contracts:
Dollar value	$	11,691	$	18,834	$	20,644
Average rate	$	7.19	$	4.30	$	7.07
Volume (MMcf)		1,626		4,380		2,920

In July 2009, the Company entered into two separate 24-month NYMEX costless collars, each for 5,000 Mcf per day. The term of the first contract is from August 1, 2009 through July 31, 2011, with a $4.50 floor price and a $7.90 ceiling price. The term of the second contract is from December 1, 2009 through November 30, 2011, with a $4.50 floor price and a $9.00 ceiling price.

The table below contains a summary of all the Company’s derivative positions reported on the consolidated balance sheet as of June 30, 2009, presented gross of any master netting arrangements:


Derivatives designated as hedging
instruments under SFAS 133	Balance Sheet Location	Fair Value
Assets
Commodity derivatives	Assets from price risk management — current	$	5,982
	Liabilities from price risk management — current		411
	Assets from price risk management — long term		3,047

Total		$	9,440


Derivatives not designated as
hedging instruments under SFAS 133	Balance Sheet Location	Fair Value
Liabilities
Commodity derivatives	Liabilities from price risk management — current	$	(1,385	)
	Liabilities from price risk management — long term		(2,203	)

Total		$	(3,588	)

The before-tax effect of derivative instruments in cash flow hedging relationships on the consolidated statement of operations for the three and six months ended June 30, 2009 was as follows:

Gain (Loss) Recognized in

OCI¹ on Derivative

Gain Reclassified from

Gain Recognized in Income (Effective Portion

(effective portion)

Accumulated OCI¹ into Income

and Amount excluded from Effectiveness Testing)

Three months

Six months

Three months

Six months

Three months

Six months

ended

June 30, 2009

Location

June 30, 2009

Location

June 30, 2009

Cash flow hedges:

Commodity contracts

(1,268

)

2,161

Oil and gas sales

5,263

9,410

Oil and gas sales

—

¹Other comprehensive income (“OCI”).

The before-tax effect of derivative instruments not designated as hedging instruments on the consolidated statement of operations for the three and six months ended June 30, 2009 was as follows:


Loss Recognized in Income on Derivative

	Three months			Six months
	ended			ended
Location	June 30, 2009			June 30, 2009

Price Risk Management Activites	$	(2,152	)	$	(3,292	)

Normal purchases and normal sales

Under SFAS No. 133, the fixed delivery contracts for production from Sun Dog and Doty Mountain at the Atlantic Rim and the Pinedale Anticline qualify for as “normal purchases and normal sales,” so long as it is probable both at inception and throughout the life of the contract that the contract will result in physical delivery and will not net settle. As of June 30, 2009, the Company believes that physical delivery will be met on all of these contracts. Under the “normal purchase and normal sale” accounting treatment, the Company records the revenue upon contract settlement in oil and gas sales on the consolidated statement of income.

Refer to Note 4 for additional information regarding the valuation of the Company’s derivative instruments.

Fair Value Measurements

Effective January 1, 2009, the Company adopted SFAS 157 for its nonfinancial assets and nonfinancial liabilities measured on a non-recurring basis. The Company adopted SFAS No. 157 for financial assets and liabilities in 2008. 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 the Company uses for its fair value measurements.

Cash and cash equivalents

Cash and cash equivalents include all cash balances and any highly liquid investments with an original maturity of 90 days or less. The carrying amount approximates fair value because of the short maturity of these instruments.

Derivative instruments

The Company considers several factors in determining its estimate of fair value, including quoted market prices in active markets, the credit rating of each counterparty, and the Company’s own credit rating.

In consideration of counterparty credit risk, the Company assessed the possibility of whether each counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.

At June 30, 2009, the types of derivative instruments utilized by the Company included fixed price delivery contracts and swaps. The natural gas derivative markets are highly active. 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 has classified these instruments as Level 2.

Credit facility

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

Asset retirement obligations

The Company recognizes an estimated liability for future costs associated with the abandonment of our oil and gas properties. The Company’s asset retirement obligation is measured using primarily Level 3 inputs. The significant unobservable inputs include the cost of abandoning oil and gas wells, the economic lives of our properties, the inflation rate, and the credit adjusted risk-free rate. The Company bases its estimate of the liability on its historical experience and current estimated costs.

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	$	—	$	9,029	$	—	$	9,029

Total assets at fair value	$	—	$	9,029	$	—	$	9,029


Liabilities
Derivative instruments	$	—	$	3,177	$	—	$	3,177
Asset retirement obligation	$	—	$	—		4,194	$	4,194

Total liabilities at fair value	$	—	$	3,177	$	4,194	$	7,371

A reconciliation of the Company’s asset retirement obligation liability is below:


December 31, 2008 asset retirement obligation	$	4,208

Liabilities incurred		8
Liabilities settled		(256	)
Accretion expense, included in earnings (1)		50
Change in ownership interest		184


June 30, 2009 asset retirement obligation	$	4,194


(1)		The accretion expense recorded during the period is recorded in the production costs line item on the consolidated statement of operations and totaled $26 and $50 in the three and six months ended June 30, 2009, respectively.

Concentration of Credit Risk

Financial instruments which potentially subject the Company to credit risk consist of our accounts receivable and our derivative financial instruments. Substantially all of the Company’s receivables are within the oil and gas industry, including those from a third party marketing company. Collectability is dependent upon the financial wherewithal of each individual company as well as the general economic conditions of the industry. The receivables are not collateralized.

At June 30, 2009 the Company’s derivative financial instruments were held with two counterparties. The Company continually reviews the credit-worthiness of its counterparties. The Company’s derivative instruments are part of master netting agreements, which reduces credit risk by permitting the Company to net settle for transactions with the same counterparty.

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 did not recognize any impairment charges during the three months ended June 30, 2009 and 2008 and in the six months ended June 30, 2009 and 2008.

Stock-Based Compensation

The Company recognized stock-based compensation expense of $302 and $770 during the three and six months ended June 30, 2009, respectively, as compared to $142 and $240 in the three and six months ended June 30, 2008, respectively.

Compensation expense related to stock options is calculated using the Black Scholes valuation model. Expected volatilities are based on the historical volatility of Double Eagle’s stock over a period consistent with that of the expected terms of the options. The expected terms of the options are estimated based on factors such as vesting periods and contractual expiration dates. The risk-free rates for periods within the contractual life of the options are based on the yields of U.S. Treasury instruments with terms comparable to the estimated option terms.

A summary of stock option activity under our various stock option plans as of June 30, 2009 and changes during the six months ended June 30, 2009 are presented below:


						Weighted-
						Average
				Weighted-		Remaining
				Average		Contractual		Aggregate
				Exercise		Term (in		Intrinsic
	Shares			Price		years)		Value
Options:
Outstanding at January 1, 2009		626,897		$	15.68		5.1
Granted		50,500		$	7.79
Exercised		—
Cancelled/expired		(20,000	)	$	15.75

Outstanding at June 30, 2009		657,397		$	15.07		4.9	$	—


Exerciseable at June 30, 2009		205,679		$	14.42		3.1	$	—

The Company measures the fair value of the stock awards based upon the fair market value of its common stock on the date of grant and recognizes the resulting compensation expense ratably over the associated service period, which is generally the vesting term of the stock awards. The Company recognizes these compensation costs net of a forfeiture rate and recognizes the compensation costs for only those shares expected to vest. The Company typically estimates forfeiture rates based on historical experience, while also considering the duration of the vesting term of the award.

Nonvested stock awards as of June 30, 2009 and changes during the six months ended June 30, 2009 were as follows:


				Weighted-
				Average
				Grant
				Date
	Shares			Fair Value
Stock Awards:
Outstanding at January 1, 2009		94,762		$	14.70
Granted		37,572		$	3.48
Vested		(44,406	)	$	5.03
Forfeited/returned		—

Nonvested at June 30, 2009		87,928		$	14.79

Income Taxes

At June 30, 2009, the Company had a net operating loss carry forward for income tax reporting purposes of approximately $30.3 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 June 30, 2009, 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 2004 and for state and local tax authorities for years before 2003. The Company’s tax years of 2004 and forward are subject to examination by federal and state taxing authorities.

Credit Facility

During the first quarter of 2009, the Company renegotiated its $50 million revolving line of credit into a $75 million credit facility collateralized by its oil and gas producing properties and other Company assets, with the borrowing base being increased to $45 million from $35 million. Under the agreement, $5 million of the $45 million borrowing base represents a term loan that, if drawn upon, must be repaid on or before July 31, 2009, and the remaining $40 million of available borrowing base is a revolving line of credit. Any outstanding balance on the line of credit matures on July 31, 2010. As of June 30, 2009, the Company had $3,750 outstanding on the term loan, and $38,750 outstanding on the revolving line of credit. The outstanding balances were used to fund capital expenditures, primarily on the Company’s Catalina Unit expansion and other non-operated projects in the Atlantic Rim, as well as projects in the Pinedale Anticline.

Borrowings under the revolving line of credit bear interest at the greater of (i) 4.5% or (ii) a daily rate equal to the greater of (a) the Federal Funds rate, plus 0.5%, the Prime Rate or the Eurodollar Rate plus 1%, plus (b) a margin ranging between 1.25% and 2.0% depending on the level of funds borrowed. Borrowings under the term loan will bear interest consistent with the revolving line of credit except that the floor rate is 5.5%. As of June 30, 2009, the interest rate on the term loan was 6.75% and the interest rate on the line of credit was 4.5%. For the three and six months ended June 30, 2009 and 2008, the Company recognized interest expense of $284 and $0, respectively, related to the credit facility. The Company capitalized interest costs of $343 and $188 for the three months ended June 30, 2009 and 2008, respectively, and $643 and $293 for the six months ended June 30, 2009 and 2008, respectively.

Under the facility, the Company is subject to both financial and non-financial covenants. The financial covenants include maintaining a current ratio, as defined, of 1.0 to 1.0, as well as a ratio of earnings before interest, taxes, depreciation, depletion, and amortization (“EBITDA”) to interest plus dividends, of 1.5 to 1.0. As of June 30, 2009, the Company’s current ratio was .99 to 1.0 and as a result was not in compliance with the current ratio covenant. The lenders waived the current ratio covenant until September 30, 2009. Management believes it is probable that the Company will be in compliance with all covenant assessment dates through June 30, 2010. If the Company had been 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.

Effective July 22, 2009, the Company amended its credit facility to terminate the $5 million term loan and to increase the revolving line of credit from $40 million to $45 million. As a result of the amendment, the $3.75 million outstanding under the term loan was rolled into the revolving credit line and is no longer due July 31, 2009. Any balance outstanding on the revolving line of credit matures July 31, 2010.

Series A Cumulative Preferred Stock

In 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 of Ownership or Control, the Company may not redeem the Series A Preferred Stock prior to June 30, 2012. On or after June 30, 2012, the Company may redeem the Series A Preferred Stock for cash at its 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 the Company by a person or entity, other than by a “Qualifying Public Company,” the Company 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, 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 the Company’s common stock.

10.

Comprehensive Income (Loss)

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


	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2009			2008			2009			2008
Net income (loss) attributable to common stock	$	(1,173	)	$	2,342		$	(1,097	)	$	3,273
Change in derivative instrument fair value, net of tax benefit of $0		(1,268	)		(2,366	)		2,161			(6,391	)
Reclassification to earnings		(5,263	)		930			(9,410	)		1,475

Comprehensive income (loss)	$	(7,704	)	$	906		$	(8,346	)	$	(1,643	)

The components of accumulated other comprehensive income were as follows:


	June 30,		December 31,
	2009		2008
Net change in derivative instrument fair value, net of tax benefit of $0 and $0	$	9,441	$	16,690

Total accumulated other comprehensive gain, net	$	9,441	$	16,690

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.

11.

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 exploration project. The unexpended portion of the deposits at June 30, 2009 and December 31, 2008 totaled $608 and $605, respectively.

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. The Company’s share of the fee related to gas gathering is eliminated in consolidation.

13.

Proposed Merger

On March 30, 2009, the Company entered into a definitive agreement to merge Petrosearch Energy Corporation (“Petrosearch”) with a wholly-owned subsidiary of the Company. The merger is structured as an all-stock transaction, subject to closing adjustments, and will be accounted for as a purchase. In the merger, assuming no closing adjustments are made, the holders of Petrosearch stock, including the holders of preferred stock on an as-converted basis, are expected to receive 0.0433 shares of Double Eagle common stock for each share of Petrosearch common stock and Petrosearch preferred stock, on an as converted basis, plus cash for any fractional shares of Double Eagle common stock they would otherwise receive in the merger. The estimated purchase price of Petrosearch is $9.3 million and the Company expects to issue 1,792,741 shares to Petrosearch stockholders.

The merger is subject to approval by Petrosearch stockholders. A special meeting of the stockholders of Petrosearch is scheduled for August 4, 2009. If approved, the merger is expected to close in the third quarter of 2009. The disclosures in this Form 10-Q reflect the Company as a stand-alone entity and do not reflect the impact of the proposed merger.

14.

Contingencies

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 (“BR”); 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.

15.

Subsequent Events

In addition, as of June 30, 2009, the Company was not in compliance with its current ratio covenant. The lenders have waived the current ratio covenant until September 30, 2009. Management believes it is probable that the Company will be in compliance with the current ratio covenant at all assessment dates through June 30, 2010, and therefore the outstanding balance on the credit facility has been classified as long-term.

On July 22, 2009, the Company entered into two separate 24-month NYMEX costless collars, each for 5,000 Mcf per day. The term of the first contract is from August 1, 2009 through July 31, 2011, with a $4.50 floor price and a $7.90 ceiling price. The term of the second contract is from December 1, 2009 through November 30, 2011, with a $4.50 floor price and a $9.00 ceiling price.

The Company has evaluated subsequent events through the date of issuance, July 30, 2009, of this quarterly report on Form 10-Q, and noted no other events, other than noted above, that require recognition or disclosure at June 30, 2009.


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 subsidiaries, 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-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 on Form 10-K for the year ended December 31, 2008, including the following:

•

Our ability to continue to develop our Atlantic Rim project;

•

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;

•

The changing political environment in which we operate

•

Incorrect estimates of required capital expenditures;

•

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

•

Our ability to increase our natural gas and oil reserves;

•

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

•

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

•

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

•

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

•

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;

•

The credit worthiness of third parties with which we enter into business agreements;

•

General economic conditions, including the current financial crisis, tax rates or policies and inflation rates;

•

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

•

Weather and other natural phenomena;

•

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

•

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

•

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

•

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

•

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 also may 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 July 30, 2007 on the NASDAQ Capital Market, under the symbol “DBLEP”. On September 30, 2007, our Preferred Stock began trading on the NASDAQ Global Select Market. 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 website iswww.dble.us.

Our objective is to increase long-term stockholder value by implementing our corporate strategy of economically growing our reserves and production through the development of our existing core properties, partnering on selective exploration projects, and pursuing strategic acquisitions that expand or complement our existing operations. 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.

Following are summary comments of our performance in several key areas during the three and six months ended June 30, 2009(Amounts in thousands of dollars, except amounts per unit of production):

	•		*Average Daily Production*

			During the three months ended June 30, 2009, our total average daily net production increased 60% to 26,209 Mcfe as compared to average daily production of 16,419 Mcfe during the same prior-year period. Total average daily net production increased 96% to 25,777 in the first six months of 2009, as compared to 13,148 Mcfe in the first half of 2008. The changes in production by major operating area are discussed below.

			Atlantic Rim.During the three months ended June 30, 2009, average daily net production at the Atlantic Rim increased 78% to 19,724 Mcfe, as compared to 11,109 Mcfe during the three months ended June 30, 2008. This increase was primarily the result of the production from a total of 30 new wells at the Catalina Unit; 10 of which were drilled in 2007 and came on-line for production in the third quarter of 2008, and the remaining 20 wells were drilled in 2008 and were brought on-line during the fourth quarter of 2008 and the first quarter of 2009. During the three months ended June 30, 2009, average daily net production at our Catalina Unit increased 73% to 17,283 Mcfe, as compared to 10,002 Mcfe during the same prior-year period. The increase in production from the new wells in the Catalina Unit was partially offset by reduced production from certain existing wells due to workovers performed in the second quarter. Average daily production, net to our interest, at the Sun Dog and Doty Mountain units increased 121% to 2,441 Mcfe, as compared to average daily production of 1,107 Mcfe in the same period of 2008. The increase was due primarily to production from approximately 50 Sun Dog Unit wells which were drilled as part of the 2007 and 2008 drilling programs, and nine new wells drilled at the Doty Mountain Unit during the 2008 drilling program.

			Average daily net production at the Atlantic Rim increased 130% to 18,766 Mcfe in the six months ended June 30, 2009, as compared to 8,165 Mcfe during the same prior-year period. The increase was primarily the result of the production from a total of 43 new wells at the Catalina Unit; 23 of which were drilled in 2007 and came on-line for production in the second and third quarter of 2008, and the remaining 20 wells were drilled in 2008 and were brought on-line during the fourth quarter of 2008 and the first quarter of 2009. During the six months ended June 30, 2009, average daily net production at our Catalina Unit increased 130% to 16,935 Mcfe, as compared to 7,359 Mcfe during the same prior-year period. Average daily production at the Sun Dog and Doty Mountain units increased 127% to 1,831 Mcfe as compared to 806 Mcfe in the six months ended June 30, 2008.

			Pinedale Anticline. Average daily production at the Pinedale Anticline increased 30% to 5,153 Mcfe for the three months ended June 30, 2009, as compared to 3,961 Mcfe in the same 2008 period. The increase in production is due to volume added from 12 new wells in the third quarter of 2008 and eight new wells in the second quarter of 2009. The operator expects to bring an additional eight wells on-line for production in the third and fourth quarters of 2009.

			During the six months ended June 30, 2009, average daily production at the Pinedale Anticline increased 54% to 5,648 Mcfe as compared to 3,661 Mcfe in the six months ended June 30, 2008, due to the added production from the wells brought on-line in the third quarter of 2008 and second quarter of 2009 as discussed above.

			Madden Deep Unit. During the three and six months ended June 30, 2009, our average daily net production at the Madden Deep Unit was 513 Mcfe and 451 Mcfe, respectively, as compared to 455 Mcfe and 328 Mcfe in the three and six months ended June 30, 2008, respectively. The sour gas plant experienced operational issues during the first quarter of 2008, which resulted in lower production. The sour gas plant was fully operational during the first half of 2009.

	•		*Oil and Gas Sales*

			During the three months ended June 30, 2009, oil and gas sales decreased 9% to $10,492, as compared to $11,526 during the same 2008 period. Although net production volumes increased at all significant properties, as discussed above, oil and gas sales was negatively impacted by lower realized average gas prices. During the three months ended June 30, 2009, the average CIG price decreased 70% as compared to the same prior-year period. In comparison, our average gas price received decreased 42%, to $4.34 from $7.54 for the same period. The overall average decrease in the gas price that we experienced was less than the average CIG price decrease due primarily to the hedging instruments we had in place during the period. See additional comments in “Contracted Volumes” below.

			Oil and gas sales increased 18% to $20,992 for the six months ended June 30, 2009, as compared to $17,777 during the same prior year period. The increase in oil and gas sales was attributed to higher production volumes at each of our significant properties, as discussed above. Although production volumes increased 60% over the first half of 2008, our total oil and gas sales was negatively impacted by lower realized average gas prices. During the six months ended June 30, 2009, the average CIG gas price decreased 65% as compared to the same 2008 period. In comparison, the average gas price we received decreased 29%, to $5.10 from $7.23 as compared to the same prior-year period. The overall average decrease in price that we experienced was less than the average CIG price decrease due primarily to the hedging instruments we had in place during the period.

OVERVIEW OF FINANCIAL CONDITION AND LIQUIDITY

Liquidity and Capital Resources

Our sources of liquidity and capital resources historically have been net cash provided by operating activities, funds available under our credit facilities and proceeds from offerings of equity securities. We believe that the liquidity available from these sources will meet the anticipated short and long-term requirements of the Company, including the capital requirements and contractual obligations noted below. However, we can give no assurances that these historical sources of liquidity and capital resources will be available for future development projects, and we may be required to seek additional or alternative financing sources.

Credit Facility

As of June 30, 2009, the Company had a $75 million credit facility in place, with a $45 million borrowing base, collateralized by its oil and gas producing properties and other assets. Under this facility, $5 million of the $45 million borrowing base represented a term loan, which if drawn upon, was to be repaid by July 31, 2009, and the remaining $40 million of available borrowing base was a revolving line of credit. Any outstanding balance on the revolving line of credit matures on July 31, 2010. The interest rate on this credit facility varies based on prevailing market rates and our level of outstanding borrowings, with a minimum floor rate of 4.5%.

As of June 30, 2009, the outstanding balance on our credit facility was $42.5 million ($38.75 million on the revolving line of credit and $3.75 million on the term loan). The interest rate, calculated in accordance with the agreement, was 4.5% on the revolving line of credit and 6.75% on the term loan. This compared to an interest rate of 3.875% at June 30, 2008.

Effective July 22, 2009, the Company amended its credit facility to terminate the $5 million term loan and to increase the revolving line of credit from $40 million to $45 million. As a result of the amendment, the $3.75 million outstanding under the term loan was rolled into the revolving line of credit and is no longer due July 31, 2009. Any balance outstanding on the revolving line of credit matures July 31, 2010. No changes were made to the interest rate as part of this amendment.

Under our credit facility, we are subject to certain financial and non-financial covenants. The financial covenants include maintaining a current ratio, as defined, of 1.0 to 1.0, as well as a ratio of earnings before interest, taxes, depreciation, depletion, and amortization (“EBITDA”) to interest plus dividends, of 1.5 to 1.0. As of June 30, 2009, our current ratio was .99 to 1.0 and as a result, we were not in compliance with the current ratio covenant. The lenders waived the current ratio covenant until September 30, 2009. Management believes it is probable that we will be in compliance with all covenants at all assessment dates through June 30, 2010. If we had been unable to negotiate a waiver or amendment thereof, the lenders 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 six months ended June 30, 2009 and 2008, we recognized interest expense of $284 and $0, respectively, related to the credit facility. The Company capitalized interest costs of $343 and $188 for the three months ended June 30, 2009 and 2008, respectively, and $643 and $293 for the six months ended June 30, 2009 and 2008, respectively

We are actively engaged in negotiations with our current lending group to bring in additional lenders, and to extend the maturity date of our credit facility past July 31, 2010. Although we expect to finalize a new agreement by the end of 2009, we can provide no assurance that we will be able to do so or what the terms of the financing will be. We also may consider additional offerings of securities.

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


	June 30,			December 31,
	2009			2008
Financial Position Summary
Cash and cash equivalents	$	3,898		$	—
Working capital	$	(1,524	)	$	(6,314	)
Balance outstanding on credit facility	$	42,500		$	24,639
Stockholders’ equity and preferred stock	$	85,258		$	92,875
Ratios
Debt to total capital ratio		33.3	%		21.0	%
Total debt to equity ratio		49.8	%		26.5	%

During the six months ended June 30, 2009, our negative working capital balance decreased to $(1,524) compared to negative working capital of $(6,314) at December 31, 2008. The increased working capital balance is primarily the result of a $28,140 decrease in accounts payable and accrued expenses due to payments we made to vendors in the first quarter of 2009 related to drilling costs incurred in the fourth quarter of 2008. This was partially offset by a $12,885 decrease in our accounts receivable balance and an $8,308 decrease in current price risk management assets since December 31, 2008. The decrease in the accounts receivable balance was due to cash receipts from our joint interest partners at the Catalina Unit for their respective working interest percentage of costs incurred as part of the 2008 drilling program. The decrease in current price risk management assets is due primarily to the settlement of derivative contracts we had in place at December 31, 2008.

Cash flow activities

The table below summarizes our cash flows for the six months ended June 30, 2009 and 2008, respectively:


	Six Months Ended June 30,
	2009			2008
Cash provided by (used in):
Operating Activities	$	16,826		$	10,470
Investing Activities		(28,650	)		(24,484	)
Financing Activities		15,722			14,154

Net change in cash	$	3,898		$	140

Net cash provided by operating activities was $16,826 for the six months ended June 30, 2009, compared to $10,470 in the same prior-year period. During the six months ended June 30, 2009, the primary sources of cash were $765 of net income, which was net of non-cash charges of $9,147 related to depreciation, depletion, and amortization expenses (“DD&A”) and accretion expense, an unrealized non-cash loss on the change in fair value of our derivatives of $6,218 and non-cash stock-based compensation expense of $770. In addition, we had a decrease in accounts receivable from operations of $14,137 primarily related to the collection of receivables from our joint interest partners for capital expenditures at the Catalina Unit. These changes were offset partially by a decrease of $14,376 in accounts payable and accrued expenses related to operations.

During the six months ended June 30, 2009, net cash used in investing activities was $28,650, as compared to $24,484 in the same prior-year period. During the first half of 2009, our capital expenditures were primarily related to the completion of the 2008 drilling program 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. We also had cash outflows of $320 related to the proposed merger of Petrosearch Energy Corp (“Petrosearch”). The Company entered into a definitive agreement to merge with Petrosearch on March 30, 2009. The proposed merger is structured as an all-stock transaction, subject to closing adjustments, and requires approval by the stockholders of Petrosearch. Refer to Note 13 in the Notes to the Consolidated Financial Statements for additional details regarding the potential Petrosearch merger.

During the six months ended June 30, 2009, net cash provided by financing activities increased to $15,722, as compared to $14,154 in the same prior-year period. Borrowings on our line of credit increased to $17,861 during the six months ended June 30, 2009 from $15,739 in same 2008 period, and were primarily used to fund the 2008 drilling activity incurred in the fourth quarter of 2008. Borrowings were partially offset in both 2009 and 2008 by the first and second quarter dividend payments totaling $1,862. Dividends are expected to be paid on a quarterly basis on the Series A Preferred Stock in the future at a rate of approximately $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 2009 are expected to be approximately $10-$20 million for production enhancement projects in the Catalina, Sun Dog and Doty Mountain Units and continued participation in the development drilling at the Pinedale Anticline. The 2009 budget does not include the impact of any potential future exploration projects, or ongoing exploration or development activities, or potential acquisitions, including Petrosearch. We believe that the amounts available under our newly amended credit facility, and net cash provided by operating activities, will provide us with sufficient funds to meet future financial covenants, develop new reserves, maintain our current facilities, and complete our 2009 capital expenditure program.

Contractual Obligations

The expected impact that our contractual obligations as of June 30, 2009 will have on our liquidity and cash flows in future periods is:


	Payments due by period
			One year		2 – 3		4 – 5		More than
	Total		or less		Years		Years		5 Years
Credit facility (a)	$	42,500	$	3,750	$	38,750	$	—	$	—
Interest on credit facility (b)		1,940		1,790		150		—		—
Capital lease commitments		1,882		753		1,129		—		—
Operating lease commitments		6,647		1,567		3,137		1,943		—

Total contractual cash commitments	$	52,969	$	7,860	$	43,166	$	1,943	$	—


(a)		Effective July 22, 2009, we amended our credit facility to terminate the $5 million term loan and to increase the revolving line of credit from $40 million to $45 million. As a result of the amendment, the $3.75 million outstanding under the term loan was rolled into the revolving line of credit and is not longer due July 31, 2009. Under the amended agreement, any balance outstanding on our revolving line of credit at July 31, 2010, will be due at that time.

(b)		Assumes the interest rate on our revolving line of credit is consistent with that of June 30, 2009.

RESULTS OF OPERATIONS

Three months ended June 30, 2009 compared to the three months ended June 30, 2008

Oil and gas sales volume and price comparisons


	Three Months Ended June 30,								Percent			Percent
	2009				2008				Volume			Price
	Volume		Average Price		Volume		Average Price		Change			Change
Product:
Gas (Mcf)		2,342,787	$	4.34		1,472,469	$	7.54		59	%		-42	%
Oil (Bbls)		7,039	$	46.03		3,613	$	116.15		95	%		-60	%
Mcfe		2,385,021	$	4.40		1,494,147	$	7.71		60	%		-43	%

Our average gas price realized for the three months ended June 30, 2009 is calculated by summing 1) production revenue received from third parties for sale of our gas, which is included in the oil and gas sales line item on the consolidated statement of operations, 2) settlement of our cash flow hedges included within oil and gas sales on the consolidated statement of operations and 3) realized gain/loss on our economic hedges, which is included in our price risk management activities line on the consolidated statement of operations, totaling $0 and $0, for the three months ended June 30, 2009 and 2008, respectively. This amount is divided by the total Mcfe volume for the period.

For the three months ended June 30, 2009, total net production increased 60% to 2,385 MMcfe, as compared to the three months ended June 30, 2008. The increase in volumes was due largely to the addition of production wells at the Atlantic Rim and Pinedale Anticline, offset somewhat by the decrease of our working interest and work-over activity in the Catalina Unit. As a result of the 2008 drilling program, the Catalina Unit participating area expanded, and our working interest decreased from 73.84% to 68.35%. Our interest will continue to change as the Unit expands further.

During the three months ended June 30, 2009, average daily net production at the Atlantic Rim increased 78% to 19,724 Mcfe, as compared to 11,109 Mcfe during the same prior-year period, largely resulting from the addition of 30 new wells which were on-line at our Catalina Unit properties during the 2009 period. Ten of the 30 new wells were drilled during the 2007 drilling program and came on-line in the third quarter of 2008, and 20 wells that were drilled during the 2008 drilling program came on-line during the fourth quarter of 2008 and first quarter of 2009. During the three months ended June 30, 2009, average daily net production at our Catalina Unit increased 73% to 17,283 Mcfe, as compared to 10,002 Mcfe during the same period of 2008. The increase in production from the new wells in the Catalina Unit was partially offset by reduced production from certain existing wells, as the Company performed well workovers and production enhancements during the second quarter of 2009. Management scheduled these workovers during a time of low spot gas prices, thus minimizing the impact of the wells being off-line on revenues and cash flows. We expect to bring on the three remaining wells drilled as part of the 2008 drilling program during the second half of 2009. During the six months ended June 30, 2009, average daily production, net to our interest, at the Sun Dog and Doty Mountain units increased 121% to 2,441 Mcfe, as compared to average daily production of 1,107 during the same prior-year period. The increase was due to the addition of approximately 50 new wells at the Sun Dog Unit from the 2007 and 2008 drilling programs, and nine new wells at the Doty Mountain Unit from the 2008 drilling program. Our working interest in the Sun Dog Unit has also increased to 8.89% from approximately 4.5% at June 30, 2009, which also contributed to the increase in net production.

Average daily production in the Pinedale Anticline increased 30% during the three months ended June 30, 2009, to 5,153 Mcfe, as compared to 3,961 Mcfe in the same prior-year period. The increase was primarily due to the addition of 12 new wells in the third quarter of 2008 and eight new wells in the second quarter of 2009, which were drilled in the fall of 2008. Although there has been an increase in production due to the new wells in the Mesa Unit, the operator has indicated that it intends to keep production volumes in this field fixed due to the low gas prices in the Rocky Mountain region, and therefore we have not realized the full benefit of having these new wells on-line for production. The operator has also informed us that it is in process of drilling up to 12 additional wells, 8 of which are expected to come on-line in 2009 at a rate of four wells in August and four wells in October.

During the quarter ended June 30, 2009, the average daily production at the Madden Unit increased 13% to 513 Mcfe as compared to 455 Mcfe in the same prior-year period.

For the three months ended June 30, 2009, oil and gas sales decreased 9% to $10,492, as compared to the same prior-year period. Although we experienced favorable growth in net production volume at all significant properties, as discussed above, oil and gas sales was negatively impacted by lower realized average gas prices. During the three months ended June 30, 2009, our average gas price realized decreased 42%, to $4.34 from $7.54, as compared to a decrease of 70% in the average CIG index price. Our realized average price did not decrease consistent with the CIG index prices due to the hedging instruments in place during the quarter. See additional comments under “Contracted Volumes” below.

Transportation and gathering revenue

During the three months ended June 30, 2009, transportation and gathering revenue increased 119% to $1,583 from $723. 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, as discussed above.

Price risk management activities

We recorded a net loss on our derivative contracts that did not qualify for cash flow hedge accounting of $2,152 for the three months ended June 30, 2009, as compared to a gain of $1,370 for the three months ended June 30, 2008. This amount represents an unrealized decrease in the fair value of our outstanding mark-to-market derivative instruments at June 30, 2009.

Oil and gas production expenses, production taxes, depreciation, depletion and amortization


	Three Months Ended June 30,
	2009			2008
	(in dollars per Mcfe)
Average price	$	4.40		$	7.71

Production costs		0.83			1.39
Production taxes		0.32			1.03
Depletion and amortization		1.93			1.93

Total operating costs		3.08			4.35


Gross margin	$	1.32		$	3.36

Gross margin percentage		30	%		44	%

Production costs, on a dollars per Mcfe basis, is calculated by dividing production costs, as stated on the consolidated statement of operations, by total production volumes during the period. This calculation excludes certain gathering costs incurred by the Company’s subsidiary, Eastern Washakie Midstream, which are eliminated in consolidation. During the three months ended June 30, 2009, well production costs decreased 4% to $1,989 as compared to $2,076 during the same prior-year period, and production costs in dollars per Mcfe decreased 40%, or $0.56 to $0.83, as compared to the same prior-year period. The decrease in well production costs on a per Mcfe basis was largely attributed to operating efficiencies we continue to realize as our production volumes increase, particularly at the Company-operated Catalina Unit.

During the three months ended June 30, 2009, production taxes decreased 51% to $753, as compared to $1,534 in the three months ended June 30, 2008, and production taxes, on a dollars per Mcfe basis, decreased 69%, or $0.71 to $0.32, as compared to the same prior-year period. The Company is required to pay taxes on the proceeds received upon the sale of our gas to counterparties. In periods of low market prices, a larger portion of our revenue is related to cash received from the settlement of financial derivative instruments we have in place, rather than the cash received for the physical sale of our gas in the open market. This results in an overall reduction in production taxes, as well as a reduction of production taxes expressed on a dollars per Mcfe basis.

Depreciation, depletion, and amortization (“DD&A”) for the three months ended June 30, 2009 increased 58% to $4,715, as compared to $2,979 in the same prior-year period, and depletion and amortization related to producing assets increased 59% to $4,598, as compared to $2,883 in the same prior-year period. The increase was largely due to the higher capital balances at the Catalina, Sun Dog, Doty Mountain and Mesa Units resulting from the 2008 drilling program, and increased production levels. Our DD&A expense at the Catalina Unit continues to run especially high, as the engineering estimates of proved developed reserves on these coal-bed methane wells does not reflect what we believe to be the true economic life of the wells. This results in higher DD&A expense at the beginning of the well’s productive life. Expressed in dollars per Mcfe, depletion and amortization related to producing assets remained consistent period over period at $1.93 per Mcfe.

Pipeline operating costs

During the three months ended June 30, 2009, pipeline operating costs increased 65% to $1,087 from $659. The increase is due to the expansion of the Catalina Unit and related transportation assets, and compressor rental costs. During the fourth quarter of 2008, the Company sold back certain compressor equipment to the original vendor and leased the equipment going forward. Certain of these leases are accounted for as operating leases with the rental expense being recorded as pipeline operating costs.

General and administrative expenses

General and administrative expenses increased 10% to $1,427 for the three months ended June 30, 2009, as compared to $1,302 for the three months ended June 30, 2008. The increase was primarily due to higher non-cash stock-based compensation expense of $160 due to additional grants to employees and outside directors, additional salary and salary-related expenses of approximately $132 primarily associated with headcount additions in the third and fourth quarters of 2008, and salary increases, and $123 of expenses related to the proposed acquisition of Petrosearch Energy Corporation. These increases were offset by an $85 reduction in software expenses related to our 2008 accounting system implementation, as well as $117 reduction in non-merger related legal fees.

Income taxes

During the three months ended June 30, 2009, we recorded an income tax benefit of $110 compared to income tax expense of $1,916 during the same prior-year period. Our effective tax rate for the three months ended June 30, 2009 was 40.5% compared to 36.9% for the same 2008 period. The rate is higher for the 2009 period due to the impact of permanent income tax differences compared to projected net income. 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 2009 at an expected federal and state rate of approximately 35.0%.

Six months ended June 30, 2009 compared to the six months ended June 30, 2008

Oil and gas sales volume and price comparisons


	Six Months Ended June 30,								Percent			Percent
	2009				2008				Volume			Price
	Volume		Average Price		Volume		Average Price		Change			Change
Product:
Gas (Mcf)		4,577,202	$	5.10		2,338,457	$	7.23		96	%		-29	%
Oil (Bbls)		14,736	$	38.25		9,077	$	96.40		62	%		-60	%
Mcfe		4,665,618	$	5.12		2,392,919	$	7.43		95	%		-31	%

Our average gas price realized for the six months ended June 30, 2009 is calculated by summing 1) production revenue received from third parties for sale of our gas, which is included in the oil and gas sales line item on the consolidated statement of operations, 2) settlement of our cash flow hedges included within oil and gas sales on the consolidated statement of operations and 3) realized gain/loss on our economic hedges, which is included in our price risk management activities line on the consolidated statement of operations, totaling $2,926 and $0, for the six months ended June 30, 2009 and 2008, respectively. This amount is divided by the total Mcfe volume for the period.

For the six months ended June 30, 2009, total net production increased 95% to 4,666 MMcfe, as compared to the six months ended June 30, 2008. The increase in volumes was due largely to the addition of production wells at the Atlantic Rim and Pinedale Anticline, offset somewhat by the decrease of our working interest in the Catalina Unit. As a result of the 2008 drilling program, the Catalina Unit participating area expanded, and our working interest decreased from 73.84% to 68.35%. Our interest will continue to change as the Unit expands further.

During the six months ended June 30, 2009, average daily net production at the Atlantic Rim increased 130% to 18,766 Mcfe, as compared to 8,165 Mcfe during the same prior-year period, largely resulting from the addition of 43 new wells which were on-line at our Catalina Unit during the 2009 period. Twenty-three of the 43 wells were drilled during the 2007 drilling program and came on-line in the second quarter of 2008, and 20 wells that were drilled during the 2008 drilling program came on-line during the fourth quarter of 2008 and first quarter of 2009. Average daily net production at our Catalina Unit increased 130% to 16,935 Mcfe, as compared to 7,359 Mcfe during the same period of 2008. The increase in production from the new wells at the Catalina Unit was partially offset by reduced production from certain existing wells, as the Company performed well workovers and production enhancements during the second quarter of 2009. Management scheduled these workovers during a time of low spot gas prices, thus minimizing the impact of the wells being off-line on revenues and cash flows. Average daily production, net to our interest, at the Sun Dog and Doty Mountain units increased 127% to 1,831 Mcfe, as compared to average daily production of 806 during the same prior-year period. The increase was due to the addition of approximately 85 wells at the Sun Dog Unit from the 2007 and 2008 drilling programs, and nine new wells at the Doty Mountain Unit from the 2008 drilling program. Our working interest in the Sun Dog Unit has also increased to 8.89% from approximately 4.5%, which also contributed to the increase in net production.

Average daily production in the Pinedale Anticline increased 54% during the six months ended June 30, 2009, to 5,648 Mcfe, as compared to 3,661 Mcfe in the same prior-year period. The increase was primarily due to the addition of 12 new wells in the third quarter of 2008 and 10 new wells in the second quarter of 2009, which were drilled in the fall of 2008. Although there has been an increase in production due to the new wells in the Mesa Unit, the operator has indicated that it intends to keep production volumes in this field fixed due to the low gas prices in the Rocky Mountain region, and therefore we have not realized the full benefit of having these wells on-line for production.

During the six months ended June 30, 2009, the average daily production at the Madden Unit increased 38% to 451 Mcfe, as compared to 328 Mcfe in the same prior-year period. The sour gas plant experienced significant operational issues during the first quarter of 2008, which limited the output of natural gas. The sour gas plant was fully operational during the first half of 2009.

For the six months ended June 30, 2009, oil and gas sales increased 18% to $20,992, as compared to the same prior-year period. Although we experienced favorable growth in net production volume at all significant properties during the first six months of 2009, as discussed above, oil and gas sales were negatively impacted by lower realized average gas prices. During the six months ended June 30, 2009, our average gas price realized decreased 29%, to $5.10 from $7.23, as compared to a decrease of 65% in the average CIG index price. Our realized average price did not decrease consistent with the CIG index prices due to the hedging instruments in place during the quarter. See additional comments under “Contracted Volumes” below.

Transportation and gathering revenue

During the six months ended June 30, 2009, transportation and gathering revenue increased 192% to $3,170 from $1,087. 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 activities

We recorded a net loss on our derivative contracts that did not qualify for cash flow hedge accounting of $3,292 for the six months ended June 30, 2009, as compared to a gain of $2,022 for the six months ended June 30, 2008. This amount consists of a net realized gain of $2,926 related to the settlement of our economic hedges, and an unrealized loss of $6,218, which represents the change in fair value of our outstanding mark-to-market derivative instruments at June 30, 2009.

Oil and gas production expenses, production taxes, depreciation, depletion and amortization


	Six Months Ended June 30,
	2009			2008
	(in dollars per Mcfe)
Average price	$	5.12		$	7.43

Production costs		0.77			1.29
Production taxes		0.35			0.98
Depletion and amortization		1.90			1.59

Total operating costs		3.02			3.86


Gross margin	$	2.10		$	3.57

Gross margin percentage		41	%		48	%

Production costs, on a dollars per Mcfe basis, is calculated by dividing production costs, as stated on the consolidated statement of operations, by total production volumes during the period. This calculation excludes certain gathering costs incurred by the Company’s subsidiary, Eastern Washakie Midstream, which are eliminated in consolidation. During the six months ended June 30, 2009, well production costs increased 17% to $3,601, as compared to $3,092 during the same prior-year period, and production costs in dollars per Mcfe decreased 40%, or $0.52 to $0.77, as compared to the same 2008 period. The increase in total production costs is primarily due to the increase in the number of producing wells at the Catalina, Sun Dog and Doty Mountain Units. The decrease in well production costs on a per Mcfe basis is largely attributed to operating efficiencies we continue to realize as our production volumes increase, particularly at the Company-operated Catalina Unit.

During the six months ended June 30, 2009, production taxes decreased 30% to $1,642, as compared to $2,334 in the first half of 2008, and production taxes expressed on a dollars per Mcfe basis decreased 64%, or $0.63 to $0.35, as compared to the same prior-year period. The Company is required to pay taxes on the proceeds received upon the sale of our gas to counterparties. In periods of low market prices, a larger portion of our revenue is related to cash received from the settlement of financial derivative instruments we have in place, rather than the cash received for the physical sale of our gas in the open market. This results in an overall reduction in production taxes, as well as a reduction of production taxes on a dollars per Mcfe basis.

Depreciation, depletion, and amortization (“DD&A”) for the six months ended June 30, 2009 increased 128% to $9,097, as compared to $3,994 in the same prior-year period, and depletion and amortization related to producing assets increased 133% to $8,879, as compared to $3,805 in the same prior-year period. The increase was largely due to the higher capital balances at the Catalina, Sun Dog, Doty Mountain and Mesa Units resulting from the 2008 drilling program, and increased production levels. Our DD&A expense at the Catalina Unit continues to run especially high, as the engineering estimates of proved developed reserves on these coal-bed methane wells does not reflect what we believe to be the true economic life of the wells. This results in higher DD&A expense at the beginning of the well’s productive life. Expressed in dollars per Mcfe, depletion and amortization related to producing assets increased 20%, or $0.31, to $1.90, as compared to the same prior-year period.

Pipeline operating costs

During the six months ended June 30, 2009, pipeline operating costs increased to $1,654 from $747. The increase is due to the expansion of the Catalina Unit and related transportation assets, and compressor rental costs. During the fourth quarter of 2008, the Company sold back certain compressor equipment to the original vendor and leased the equipment going forward. Certain of these leases are accounted for as operating leases with the rental expense being recorded as pipeline operating costs.

General and administrative expenses

General and administrative expenses increased 40% to $3,101 for the six months ended June 30, 2009, as compared to $2,209 for the six months ended June 30, 2008. The increase was primarily due to higher non-cash stock-based compensation expense of $530 due to additional grants to employees and outside directors, additional salary and salary-related expenses of approximately $222 primarily associated with headcount additions in the second, third and fourth quarters of 2008, and salary increases, and $382 of expenses related to the proposed acquisition of Petrosearch Energy Corporation. These increases were offset by lower software fees of $81 related to our 2008 accounting system implementation, and a $46 reduction of non-merger related legal fees.

Income taxes

During the six months ended June 30, 2009, we recorded income tax expense of $521 compared to income tax expense of $2,999 during the same prior-year period. Our effective tax rate for the six months ended June 30, 2009 was 40.5% compared to 36.9% for the same 2008 period. The rate is higher for the 2009 period due to the impact of permanent income tax differences compared to projected net income. 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 2009 at an expected federal and state rate of approximately 35.0%.

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 downward fluctuations in commodity prices. At June 30, 2009, all of our outstanding derivative instruments are indexed to the Colorado Interstate Gas (“CIG”) index.

Our outstanding forward sales contracts as of June 30, 2009 are summarized below (volume and daily production are expressed in Mcf):

FORWARD SALES CONTRACTS


	Remaining
	Contractual		Daily
Property	Volume		Production		Term		Price

Catalina		123,000		1,000		11/07-10/09	$	5.66
Atlantic Rim		31,000		1,000		08/07-07/09	$	6.15


Company Total		154,000

The Company also has entered into various other derivative instruments to protect prices on future production. The terms of our other hedging instruments at June 30, 2009 are summarized as follows (volume and daily production are expressed in Mcf):


	Remaining
	Contractual		Daily
Type of Contract	Volume		Production		Term		Price

Fixed Price Swap		1,472,000		8,000		1/09-12/09	$	7.34
Fixed Price Swap		4,380,000		12,000		1/10-12/10	$	4.30
Fixed Price Swap		2,920,000		8,000		1/11-12/11	$	7.07


Total		8,772,000

In July 2009, we entered into two separate 24-month NYMEX costless collars, each for 5,000 Mcf per day. Under a 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 periods of low prices. The term of the first contract is from August 1, 2009 through July 31, 2011, with a $4.50 floor price and a $7.90 ceiling price. The term of the second contract is from December 1, 2009 through November 30, 2011, with a $4.50 floor price and a $9.00 ceiling price.

Refer to Note 3 in the Notes to the Consolidated Financial Statements for additional discussion on the accounting treatment of our derivative contracts.

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, 2008, 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 three months ended June 30, 2009, our income before income taxes would have changed by $518 for each $0.50 change per Mcf in natural gas prices and $6 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, as well as fixed price swaps, 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. These derivative instruments 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 June 30, 2009, we had a total of $42,500 outstanding under our $75 million credit facility. The borrowing base of $45 million in total consisted of a $40 million borrowing base related to the revolving line of credit and a $5 million term loan. At June 30, 2009, we had $38,750 outstanding under our revolving line of credit and $3,750 outstanding on our term loan. We pay interest on outstanding borrowings under our credit facility at interest rates that fluctuate based upon changes in our levels of outstanding debt and the prevailing market rates. The minimum interest rate is 4.5%. 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 June 30, 2009, the annual impact on interest expense for every 1.0% change in the average interest rate would be approximately $425 before taxes. As of June 30, 2009, the interest rate on the line of credit, calculated in accordance with the agreement, was 6.75% on the term loan and 4.5% on the revolving line of credit.


ITEM 4.		CONTROLS AND PROCEDURES

In accordance with Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934, as amended, 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 quarter ended June 30, 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION


ITEM 1.		LEGAL PROCEEDINGS

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


ITEM 1A.		RISK FACTORS

There have been no material changes in our Risk Factors from those reported in Item 1A of Part I of our 2008 Annual Report on Form 10-K filed with the Securities and Exchange Commission, which we incorporate by reference herein.


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

On May 28, 2009, the Company held its annual shareholder meeting. During the meeting, stockholders elected Roy Cohee and Brent Hathaway as members of the Board of Directors of the Company for a three-year term and one-year term, respectively. The number of votes received for the election of Mr. Cohee was 7,285,895 or 90% of the total shares voted. Votes withheld totaled 1,803,894. The number of votes received for the election of Mr. Hathaway was 7,128,293 or 88% of the total shares voted. Votes withheld totaled 961,496. Mr. Cohee and Mr. Hathaway each will hold office until his term expires and respective successors are elected and have qualified or upon his resignation from the Board.


ITEM 6.		EXHIBITS

The following exhibits are filed as part of this report:


Exhibit			Description:

	2.1		Agreement and Plan of Merger dated March 30, 2009 by and among Double Eagle Petroleum Co., DBLE Acquisition Corporation, and Petrosearch Energy Corporation and Form of Voting Agreement (incorporated by reference from Exhibit 2.1 and 2.2 of the Company’s Current Report of Form 8-K dated March 31, 2009).

	3.1	(a)	Articles of Incorporation filed with the Maryland Secretary of State on January 23, 2001 (incorporated by reference from Exhibit 3.1(a) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).

	3.1	(b)	Certificate of Correction filed with the Maryland Secretary of State on February 15, 2001 concerning the Articles of Incorporation (incorporated by reference from Exhibit 3.1(b) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).


Exhibit			Description:

	3.1	(c)	Articles of Merger filed with the Maryland Secretary of State on February 15, 2001 (incorporated by reference from Exhibit 3.1(c) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).

	3.1	(d)	Certificate of Correction filed with the Maryland Secretary of State (incorporated by reference from Exhibit 3 of the Company’s Quarterly Report on Form 10-QSB for the quarter ended November 30, 2001).

	3.1	(e)	Certificate of Correction to the Articles of Incorporation, filed with the Maryland Department of Assessments and Taxation on June 1, 2007 (incorporated by reference from Exhibit 3.3 of the Company’s Current Report of Form 8-K dated June 29, 2007).

	3.1	(f)	Articles of Amendment, filed with the Maryland Department of Assessments and Taxation on June 26, 2007 (incorporated by reference from Exhibit 3.1 of the company’s Current report on Form 8-K dated June 29, 2007).

	3.1	(g)	Articles Supplementary, filed with the Maryland Department of Assessments and Taxation on June 29, 2007 (incorporated by reference from Exhibit 3.2 of the Company’s Current report of Form 8-K dated June 29, 2007).

	3.1	(h)	Articles Supplementary of Junior Participating Preferred Stock, Series B, dated as of August 21, 2007 (incorporated by reference from Exhibit 3.1 of the Company’s Current report of Form 8-K dated August 28, 2007).

	3.2	(a)	Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Annual Report on Form 10-KSB, filed for the year ended August 31, 2001).

	3.2	(b)	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).

	3.2	(c)	Second Amendment and Restated Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Current report on Form 8-K dated June 11, 2007).

	4.1	(a)	Form of Warrant Agreement concerning Common Stock Purchase Warrants (incorporated by reference from Exhibit 4.3 of the Amendment No. 1 to the Company’s Registration Statement on Form SB-2 filed on November 27, 1996, SEC Registration No. 333-14011).

	4.1	(b)	Shareholder Rights Agreement, dated as of August 24, 2007 (incorporated herein by reference to the Company’s Current report on Form 8-A filed on August 24, 2007).

	4.1	(c)	Articles Supplementary, filed with the Maryland Department of Assessments and Taxation on June 29, 2007 (incorporated by reference from Exhibit 3.2 of the Company’s Current report on Form 8-K dated June 29, 2007).

	4.1	(d)	Articles Supplementary of Junior Participating Preferred Stock, Series B, dated as of August 21, 2007 (incorporated by reference from Exhibit 3.1 of the Company’s Current report of Form 8-K dated August 28, 2007).

	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: July 30, 2009	By:	/s/ Richard D. Dole
		Richard D. Dole
		Chief Executive Officer (Principal Executive Officer)

Date: July 30, 2009	By:	/s/ Kurtis S. Hooley
		Kurtis S. Hooley
		Chief Financial Officer (Principal Accounting Officer)

EXHIBIT INDEX


Exhibit Number			Description

	2.1		Agreement and Plan of Merger dated March 30, 2009 by and among Double Eagle Petroleum Co., DBLE Acquisition Corporation, and Petrosearch Energy Corporation and Form of Voting Agreement (incorporated by reference from Exhibit 2.1 and 2.2 of the Company’s Current Report of Form 8-K dated March 31, 2009).

	3.1	(a)	Articles of Incorporation filed with the Maryland Secretary of State on January 23, 2001 (incorporated by reference from Exhibit 3.1(a) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).

	3.1	(b)	Certificate of Correction filed with the Maryland Secretary of State on February 15, 2001 concerning the Articles of Incorporation (incorporated by reference from Exhibit 3.1(b) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).

	3.1	(c)	Articles of Merger filed with the Maryland Secretary of State on February 15, 2001 (incorporated by reference from Exhibit 3.1(c) of the Company’s Annual Report on Form 10-KSB for the year ended August 31, 2001).

	3.1	(d)	Certificate of Correction filed with the Maryland Secretary of State (incorporated by reference from Exhibit 3 of the Company’s Quarterly Report on Form 10-QSB for the quarter ended November 30, 2001).

	3.1	(e)	Certificate of Correction to the Articles of Incorporation, filed with the Maryland Department of Assessments and Taxation on June 1, 2007 (incorporated by reference from Exhibit 3.3 of the Company’s Current Report of Form 8-K dated June 29, 2007).

	3.1	(f)	Articles of Amendment, filed with the Maryland Department of Assessments and Taxation on June 26, 2007 (incorporated by reference from Exhibit 3.1 of the company’s Current report on Form 8-K dated June 29, 2007).

	3.1	(g)	Articles Supplementary, filed with the Maryland Department of Assessments and Taxation on June 29, 2007 (incorporated by reference from Exhibit 3.2 of the Company’s Current report of Form 8-K dated June 29, 2007).

	3.1	(h)	Articles Supplementary of Junior Participating Preferred Stock, Series B, dated as of August 21, 2007 (incorporated by reference from Exhibit 3.1 of the Company’s Current report of Form 8-K dated August 28, 2007).

	3.2	(a)	Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Annual Report on Form 10-KSB, filed for the year ended August 31, 2001).

	3.2	(b)	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).

	3.2	(c)	Second Amendment and Restated Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Current report on Form 8-K dated June 11, 2007).

	4.1	(a)	Form of Warrant Agreement concerning Common Stock Purchase Warrants (incorporated by reference from Exhibit 4.3 of the Amendment No. 1 to the Company’s Registration Statement on Form SB-2 filed on November 27, 1996, SEC Registration No. 333-14011).


Exhibit Number			Description

	4.1	(b)	Shareholder Rights Agreement, dated as of August 24, 2007 (incorporated herein by reference to the Company’s Current report on Form 8-A filed on August 24, 2007)

	4.1	(c)	Articles Supplementary, filed with the Maryland Department of Assessments and Taxation on June 29, 2007 (incorporated by reference from Exhibit 3.2 of the Company’s Current report on Form 8-K dated June 29, 2007).

	4.1	(d)	Articles Supplementary of Junior Participating Preferred Stock, Series B, dated as of August 21, 2007 (incorporated by reference from Exhibit 3.1 of the Company’s Current report of Form 8-K dated August 28, 2007).

	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 Avg

Escalera Resources (ESCR) Inactive 10-Q2009 Q2 Quarterly report

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