Escalera Resources (ESCR) 10-Q 2012 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2012

or

¨ 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	83-0214692
(State or other jurisdiction of incorporation or organization)	(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.    Yes  x    No  ¨

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).    Yes  x    No  ¨

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 filer	¨	Accelerated filer	x
Non-accelerated filer	¨  (Do not check if a small reporting company)	Smaller reporting Company	¨

Indicate by checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Class	Shares outstanding as of October 31, 2012
Common stock, $.10 par value	11,289,250

DOUBLE EAGLE PETROLEUM CO.

FORM 10-Q

TABLE OF CONTENTS

	Page #
PART I. Financial Information:
Item 1. Financial Statements
Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011 (Unaudited)		2
Consolidated Statements of Operations for the Three and Nine Months Ended September  30, 2012 and 2011 (Unaudited)		3
Consolidated Statements of Comprehensive Income (Loss) for the Three and Nine Months Ended September  30, 2012 and 2011 (Unaudited)		4
Consolidated Statements of Cash Flows for the Nine Months Ended September  30, 2012 and 2011 (Unaudited)		5
Notes to Consolidated Financial Statements (Unaudited)		6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		15
Item 3. Quantitative and Qualitative Disclosures About Market Risk		25
Item 4. Controls and Procedures		25
PART II. Other Information:
Item 1. Legal Proceedings		26
Item 1A. Risk Factors		26
Item 6. Exhibits		26
Signatures		28

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED BALANCE SHEETS

(Amounts in thousands of dollars except share data)

(Unaudited)

	September 30, 2012			December 31, 2011
ASSETS
Current assets:
Cash and cash equivalents	$	3,138		$	8,678
Cash held in escrow		565			564
Accounts receivable		3,932			4,869
Assets from price risk management		6,676			10,022
Other current assets		3,428			4,206
Total current assets		17,739			28,339
Oil and gas properties and equipment, successful efforts method:
Developed properties		215,946			209,774
Wells in progress		12,234			8,182
Gas transportation pipeline		5,510			5,482
Undeveloped properties		2,790			2,921
Corporate and other assets		2,068			2,075
		238,548			228,434
Less accumulated depreciation, depletion and amortization		(103,631	)		(91,070	)
Net properties and equipment		134,917			137,364
Assets from price risk management		1,167			4,812
Other assets		4,263			79
TOTAL ASSETS	$	158,086		$	170,594
LIABILITIES, PREFERRED STOCK AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	6,718		$	12,162
Liabilities from price risk management		375			—
Accrued production taxes		2,974			2,590
Other current liabilities		181			47
Total current liabilities		10,248			14,799
Credit facility		46,200			42,000
Asset retirement obligation		6,451			6,300
Liabilities from price risk management		155			—
Deferred tax liability		9,272			13,314
Other long term liabilities		426			—
Total liabilities		72,752			76,413
Preferred stock, $0.10 par value; 10,000,000 shares authorized; 1,610,000 shares issued and outstanding as of September 30, 2012 and December 31, 2011		37,972			37,972
Stockholders' equity:
Common stock, $0.10 par value; 50,000,000 shares authorized; 11,276,016 issued and 11,255,380 shares outstanding as of September 30, 2012 and 11,232,542 issued and 11,215,658 outstanding as of December 31, 2011, respectively		1,126			1,122
Additional paid-in capital		46,891			45,685
Retained earnings		(655	)		9,402
Total stockholders' equity		47,362			56,209
TOTAL LIABILITIES, PREFERRED STOCK AND STOCKHOLDERS' EQUITY	$	158,086		$	170,594

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

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DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED STATEMENTS OF OPERATIONS

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

(Unaudited)

	Three months ended September 30,						Nine months ended September 30,
	2012			2011			2012			2011
Revenues
Oil and gas sales	$	6,498		$	11,540		$	17,742		$	33,843
Transportation revenue		1,276			1,221			3,763			3,674
Price risk management activities, net		(1,827	)		4,803			2,705			5,732
Proceeds from Madden Deep settlement		—			—			—			—
Other income, net		(46	)		469			(23	)		774
Total revenues		5,901			18,033			24,187			44,023
Costs and expenses
Production costs		2,766			3,018			8,682			8,361
Production taxes		783			1,084			1,921			3,230
Exploration expenses including dry hole costs		62			67			638			239
Pipeline operating costs		1,184			1,016			3,633			3,017
General and administrative		1,513			1,513			4,736			4,433
Impairment and abandonment of equipment and properties		21			—			330			73
Depreciation, depletion and amortization		4,779			4,926			14,186			14,317
Total costs and expenses		11,108			11,624			34,126			33,670
Income (loss) from operations		(5,207	)		6,409			(9,939	)		10,353
Interest expense, net		(516	)		(352	)		(1,369	)		(997	)
Income (loss) before income taxes		(5,723	)		6,057			(11,308	)		9,356
Benefit (provision) for deferred income taxes		2,155			(2,221	)		4,043			(3,459	)
NET INCOME (LOSS)	$	(3,568	)	$	3,836		$	(7,265	)	$	5,897
Preferred stock dividends		930			930			2,792			2,792
Net income (loss) attributable to common stock	$	(4,498	)	$	2,906		$	(10,057	)	$	3,105
Net income (loss) per common share:
Basic	$	(0.40	)	$	0.26		$	(0.89	)	$	0.28
Diluted	$	(0.40	)	$	0.26		$	(0.89	)	$	0.28
Weighted average common shares outstanding:
Basic		11,255,229			11,197,681			11,240,945			11,187,298
Diluted		11,255,229			11,226,724			11,240,945			11,207,517

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

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DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Amounts in thousands of dollars)

(Unaudited)

	Three months ended September 30,						Nine months ended September 30,
	2012			2011			2012			2011
Net income (loss)	$	(3,568	)	$	3,836		$	(7,265	)	$	5,897
Other comprehensive income (loss), net of tax
Change in derivative instrument fair value		—			430			—			423
Reclassification to earnings		—			(1,472	)		—			(4,384	)
Total other comprehensive income (loss), net of tax	$	—		$	(1,042	)	$	—		$	(3,961	)
Comprehensive income (loss)	$	(3,568	)	$	2,794		$	(7,265	)	$	1,936

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

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DOUBLE EAGLE PETROLEUM CO.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in thousands of dollars)

(Unaudited)

	Nine months ended September 30,
	2012			2011
Cash flows from operating activities:
Net income	$	(7,265	)	$	5,897
Adjustments to reconcile net income to net cash from operating activities:
Depreciation, depletion, amortization and accretion		14,328			14,444
of asset retirement obligation
Impairment and Abandonment of non-producing properties		330			73
Dry hole costs		462			—
Provision (benefit) for deferred taxes		(4,042	)		3,459
Stock-based compensation expense		1,234			767
Change in fair value of derivative contracts		8,082			(4,993	)
Settlement on asset retirement obligation		(2	)		—
Revenue from carried interest		—			(117	)
Loss (gain) on sale of producing property		16			(582	)
Changes in current assets and liabilities:
Decrease (Increase) in deposit held in escrow		(1	)		51
Decrease in accounts receivable		937			322
Decrease (Increase) in other current assets		369			230
Increase (Decrease) in accounts payable and accrued expenses		(1,202	)		(46	)
Increase (Decrease) in accrued production taxes		384			(723	)
NET CASH PROVIDED BY OPERATING ACTIVITIES		13,630			18,782
Cash flows from investing activities:
Sale of oil and gas properties and equipment		—			371
Payments to acquire producing properties and equipment, net		(20,530	)		(12,491	)
Payments to acquire corporate and non-producing properties		(24	)		(98	)
NET CASH USED IN INVESTING ACTIVITIES		(20,554	)		(12,218	)
Cash flows from financing activities:
Principal payments on capital lease obligations		—			(408	)
Tax withholdings related to net share settlement of restricted stock awards		(24	)		(17	)
Dividends paid on preferred stock		(2,792	)		(2,792	)
Net borrowings (repayments) on credit facility		4,200			—
NET CASH PROVIDED BY FINANCING ACTIVITIES		1,384			(3,217	)
Change in cash and cash equivalents		(5,540	)		3,347
Cash and cash equivalents at beginning of period		8,678			2,605
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	(3,138	)	$	5,952
Supplemental disclosure of cash and non-cash transactions:
Cash paid for interest	$	961		$	744
Interest capitalized		226			93
Additions to developed properties included in current liabilities		2,246			4,014

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

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DOUBLE EAGLE PETROLEUM CO.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(Unaudited)

1. Summary of Significant Accounting Policies

Basis of presentation

The accompanying unaudited interim consolidated financial statements and related notes were prepared by Double Eagle Petroleum Co. (“Double Eagle” or the “Company”) in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) for interim financial reporting and were prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Certain information and note disclosures normally included in the annual audited consolidated financial statements 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 2011 consolidated financial statements have been reclassified to conform to the 2012 unaudited interim 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 Annual Report on Form 10-K for the year ended December 31, 2011, and are supplemented throughout the notes to this Quarterly Report on Form 10-Q.

The unaudited interim consolidated financial statements presented herein should be read in conjunction with the consolidated financial statements and notes thereto included in the Annual Report on Form 10-K for the year ended December 31, 2011 filed with the SEC.

Principles of consolidation

The unaudited interim consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, Petrosearch Energy Corporation (“Petrosearch”) and Eastern Washakie Midstream LLC (“EWM”). In 2006, the Company sold transportation assets located in the Catalina Unit, at cost, to EWM 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. This fee related to gas gathering is also eliminated in consolidation.

Recently adopted accounting pronouncements

The Company adopted Accounting Standards Update No. 2011-05 (“ASC No. 2011-05”), an update to ASC Topic 220,Comprehensive Income, effective January 1, 2012. The update amended current guidance to require companies to present total comprehensive income either in a single, continuous statement of comprehensive income or in two separate, but consecutive, statements. Under the single-statement approach, entities must include the components of net income, a total for net income, the components of other comprehensive income (“OCI”) and a total for comprehensive income. Under the two-statement approach, entities must report an income statement and, immediately following, a statement of OCI. ASC No. 2011-05 required retrospective application. The Company also adopted ASC No. 2011-12, which defers until further notice ASC No. 2011-05’s requirement that items that are reclassified from other comprehensive income to net income be presented on the face of the financial statements. The Company has elected to use the two-statement approach. The adoption of these updates affected presentation only, and had no impact on the Company’s financial position, results of operation or cash flows.

2. Earnings per share

Basic earnings per share (“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 to measure the dilutive impact of potential common stock equivalents by including the effect of outstanding vested and unvested stock options and unvested stock awards in the average number of shares of common stock outstanding during the period. Income attributable to common stock is calculated as net income less dividends paid on

6

the Company’s Series A Preferred Stock. The Company declared and paid cash dividends of $930 ($.5781 per share of preferred stock) for the three months ended September 30, 2012 and 2011, respectively, and $2,792 for the nine months ended September 30, 2012 and 2011.

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2012			2011		2012			2011
Net income (loss)	$	(3,568	)	$	3,836	$	(7,265	)	$	5,897
Preferred stock dividends		930			930		2,792			2,792
Income (loss) attributable to common stock	$	(4,498	)	$	2,906	$	(10,057	)	$	3,105
Weighted average common shares:
Weighted average common shares - basic		11,255,229			11,197,681		11,240,945			11,187,298
Dilution effect of stock options/awards outstanding at the end of period		—			29,043		—			20,219
Weighted average common shares - diluted		11,255,229			11,226,724		11,240,945			11,207,517
Net income (loss) per common share:
Basic	$	(0.40	)	$	0.26	$	(0.89	)	$	0.28
Diluted	$	(0.40	)	$	0.26	$	(0.89	)	$	0.28

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:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Anti-dilutive shares		83,617		57,425		74,557		83,864

3. Derivative Instruments

Commodity Contracts

The Company’s primary market exposure is to adverse fluctuations in the price of natural gas. The Company uses derivative instruments, primarily forward contracts, costless collars and swaps, to manage the price risk associated with its 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 extent of the Company’s risk management activities is controlled through policies and procedures that involve senior management and were approved by the Company’s Board of Directors. Senior management is responsible for proposing hedging recommendations, executing the approved hedging plan, overseeing the risk management process including methodologies used for valuation and risk measurement and presenting policy changes to the Board. The Company’s Board of Directors is responsible for approving risk management policies and for establishing the Company’s overall risk tolerance levels. The duration of the various derivative instruments depends on senior management’s view of market conditions, available contract prices and the Company’s operating strategy. Under the Company’s credit agreement, the Company can hedge up to 90% of the projected proved developed producing reserves for the next 12 month period, and up to 80% of the projected proved producing reserves for the 24 month period thereafter.

In 2012, the Company accounted for all of its derivative instruments as mark-to-market derivative instruments. Under mark-to-market accounting, derivative instruments are recognized as either assets or liabilities at fair value on the Company’s consolidated balance sheets and changes in fair value are recognized in the price risk management activities line on the consolidated statements of operations. Realized gains and losses resulting from the contract settlement of mark-to-market derivatives also are recorded in the price risk management activities line on the consolidated statements of operations.

In 2011, the Company had one derivative instrument that was accounted for as a cash flow hedge. Derivative instruments that are designated and qualify as cash flow hedges are recorded at fair value on the consolidated balance sheets, and the effective portion of the change in fair value is reported as a component of accumulated other comprehensive income (“AOCI”) and is subsequently reclassified into oil and gas sales on the consolidated statements of operations as the contracts settle. The last derivative instrument that the Company accounted for under cash flow hedge accounting settled in December 2011.

7

On the consolidated statements of cash flows, the cash flows from the derivative 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 creditworthy. 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, the Company’s 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, among other things, a letter of credit, security interest or a performance bond. As of September 30, 2012, no party to any of the Company’s derivative contracts had required any form of security guarantee.

The Company had the following commodity volumes under derivative contracts as of September 30, 2012:

Type of Contract	Remaining Contractual Volume (MMcf)		Term		Contract Price	Price Index (1)
Fixed Price Swap		460		01/12-12/12	$5.10		NYMEX
Fixed Price Swap		920		01/12-12/12	$5.05		NYMEX
Fixed Price Swap		450		08/12-12/12	$3.00		NYMEX
Fixed Price Swap		2,190		01/13-12/13	$5.16		NYMEX
Costless Collar		2,190		01/13-12/13	$5.00 floor $5.35 ceiling		NYMEX
Costless Collar		2,160		01/13-12/13	$3.25 floor $4.00 ceiling		NYMEX
Total		8,370

(1) New York Mercantile Exchange (“NYMEX”).

The Company entered into two additional derivative contracts subsequent to September 30, 2012. Please refer to Note 11 for the derivative contract terms.

Interest Rate Swaps

As of September 30, 2012, the Company had the following interest rate swaps in place with a third party to manage the risk associated with the floating interest rate on its credit facility:

Type of Contract	Contractual Amount		Term		Rate (LIBOR)			Effective Interest Rate (1)
Interest Rate Swap	$	30,000		7/12/11-12/31/12		0.578	%		3.08	%
Interest Rate Swap	$	30,000		12/31/12-9/30/16		1.050	%		3.55	%

(1) In accordance with its credit facility, the Company pays interest amounts based upon the Eurodollar LIBOR rate or Prime rate and plus a spread ranging from 0.75% to 2.75% depending on its outstanding borrowings. The effective rate shown reflects the interest rate based on the outstanding borrowings at September 30, 2012.

Under the interest rate swap terms, the Company swapped its floating LIBOR interest rate for a fixed LIBOR interest rate. These contracts were not designated as fair value hedges or cash flow hedges and are recorded at fair value on the consolidated balance sheets. Changes in fair value, both realized and unrealized, are recognized in interest expense, net on the consolidated statements of operations. On the consolidated statements of cash flows, the cash flows from the interest rate swap are classified as operating activities.

The table below contains a summary of all the Company’s derivative positions reported on the consolidated balance sheet as of September 30, 2012, presented gross of any master netting arrangements:

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Derivatives not designated as hedging instruments under ASC 815	Balance Sheet Location	Fair Value
Assets
Commodity derivatives	Assets from price risk management - current	$	6,676
	Assets from price risk management - long term		1,167
Liabilities
Commodity derivatives	Liabilities from price risk management - current	$	(375	)
	Liabilities from price risk management - long term		(155	)
Interest rate swap	Other current liabilities		(181	)
	Other long term liabilities		(426	)
Total		$	6,706

The before-tax effect of derivative instruments in cash flow hedging relationships on the consolidated statements of operations for the three and nine months ended September 30, 2012 and 2011, related to the Company’s commodity derivatives was as follows:

Derivatives Designated as Cash Flow Hedging Instruments	Amount of Gain Recognized in OCI on Derivative for
under ASC 815	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Commodity contracts	$	—	$	614	$	—	$	855

Location of Gain Reclassified
from AOCI			Amount of Gain Reclassified from AOCI into Income
into Income (effective portion)	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
Oil and gas sales	$	—	$	2,322	$	—	$	6,915

	Three and Nine Months Ended September 30,
	2012		2011
Location of Gain/Loss Recognized in Income (Ineffective) Portion and Amount Excluded from Effectiveness Testing		N/A	$	—

The before-tax effect of derivative instruments not designated as hedging instruments on the consolidated statements of operations for the three and nine months ended September 30, 2012 and 2011 was as follows:

9

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Unrealized gain (loss) on commodity contracts1	$	(4,993	)	$	4,642		$	(7,522	)	$	5,060
Realized gain on commondity contracts1		3,166			161			10,227			672
Unrealized loss on interest rate swap2		(226	)		(67	)		(560	)		(67	)
Realized loss on interest rate swap2		(26	)		(27	)		(75	)		(27	)
Total activity for derivatives not designated as hedging instruments	$	(2,079	)	$	4,709		$	2,070		$	5,638

(1) Included in price risk management activities, net on the consolidated statements of operations. Price risk management activities totaled $(1,827) and $4,803 for the three months ended September 30, 2012 and 2011, respectively, and $2,705 and $5,732 for the nine months ended September 30, 2012 and 2011, respectively.

(2) Included in interest expense, net on the consolidated statements of operations.

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

4. Fair Value of Financial Instruments

Assets and Liabilities Measured on a Recurring Basis

The Company’s financial instruments, including cash and cash equivalents, accounts receivable and accounts payable are carried at cost, which approximates fair value due to the short-term maturity of these instruments. The recorded value of the Company’s credit facility also approximates fair value as it bears interest at a floating rate.

Fair value is defined as 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 (exit price). A three-level valuation hierarchy has been established to allow readers to understand the transparency of inputs in 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 table provides a summary as of September 30, 2012 of assets and liabilities measured at fair value on a recurring basis:

	Level 1		Level 2		Level 3		Total
Assets
Derivative instruments -
Commodity forward contracts	$	—	$	7,843	$	—	$	7,843
Total assets at fair value	$	—	$	7,843	$	—	$	7,843
Liabilities
Derivative instruments -
Commodity forward contracts	$	—	$	530	$	—	$	530
Interest rate swap	$	—	$	607	$	—	$	607
Total liabilities at fair value	$	—	$	1,137	$	—	$	1,137

The Company did not have any transfers of assets or liabilities between Level 1, Level 2 or Level 3 of the fair value measurement hierarchy during the three and nine months ended September 30, 2012.

The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the table above:

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Derivative instruments

The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit rating. The Company also performs an internal valuation to evaluate the reasonableness of third party quotes.

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.

As of September 30, 2012, the Company had various types of derivative instruments, which included costless collars and swaps. The natural gas derivative markets and interest rate swap markets are highly active. Although the Company’s 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.

Concentration of credit risk

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

The Company currently uses two counterparties for its derivative financial instruments. The Company continually reviews the credit worthiness of its counterparties, which are generally other energy companies or major financial institutions. In addition, the Company uses master netting agreements which allow the Company, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If the Company chooses to elect early termination, all asset and liability positions with the defaulting counterparty would be “net settled” at the time of election. “Net settlement” refers to a process by which all transactions between counterparties are resolved into a single amount owed by one party to the other.

Assets and Liabilities Measured on a Non-recurring Basis

The Company utilizes fair value on a non-recurring basis to perform impairment tests as required on its property and equipment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property and equipment. 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 impairment analysis performed by the Company may utilize Level 3 inputs.

5. Impairment of Long-Lived Assets

The long-lived assets of the Company consist primarily of proved oil and gas properties and undeveloped leaseholds. The Company reviews the carrying values of its long-lived assets annually or whenever events or changes in circumstances indicate that such carrying values may not be recoverable. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets, generally on a field-by-field basis.

In the three and nine months ended September 30, 2012, the Company recorded impairment expense of $0 and $301, respectively, related to wells that were plugged and abandoned at a non-operated property. The Company did not record any proved property impairment expense in the three and nine months ended September 30, 2011. The Company wrote off $21 and $29 during the three and nine months ended September 30, 2012 and $0 and $73, respectively, in the three and nine months ended September 30, 2011 related to expired undeveloped leaseholds.

6. Compensation Plans

The Company recognized stock-based compensation expense of $414 and $1,234 during the three and nine months ended September 30, 2012, respectively, as compared to $242 and $767 in the three and nine months ended September 30, 2011, respectively.

Compensation expense related to stock options is calculated using the Black-Scholes valuation model. Expected volatilities are based on the historical volatility of the Company’s common stock over a period consistent with that of the

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expected terms of the options. The expected terms of the options are estimated based on factors such as vesting periods, contractual expiration dates, historical trends in the Company’s common stock price and historical exercise behavior. The risk-free rates for periods within the contractual life of the options are based on the yields of U.S. Treasury instruments with terms comparable to the estimated option terms.

A summary of stock option activity under the Company’s stock option plans as of September 30, 2012 and changes during the nine months ended September 30, 2012 is presented below:

	Shares			Weighted- Average Exercise Price		Weighted- Average Remaining Contractual Term (in years)		Aggregate Intrinsic Value
Options:
Outstanding at January 1, 2012		517,458		$	12.02		3.5
Granted		—
Exercised		—
Cancelled/expired		(98,108	)	$	16.14
Outstanding at September 30, 2012		419,350		$	11.06		3.11	$	108
Exercisable at September 30, 2012		291,437		$	11.97		2.90	$	57

The Company measures the fair value of 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 the compensation expenses net of a forfeiture rate and recognizes the compensation expenses 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 September 30, 2012 and changes during the nine months ended September 30, 2012 were as follows:

	Shares			Weighted- Average Grant Date Fair Value
Stock Awards:
Outstanding at January 1, 2012		542,122		$	6.59
Granted		140,673		$	5.92
Vested		(43,475	)	$	5.98
Forfeited/returned		(74,291	)	$	6.78
		��
Nonvested at September 30, 2012		565,029		$	6.44

In the fourth quarter of 2011, the Company adopted a Long-Term Incentive Plan (“LTIP”), under which the executive officers of the Company may earn up to an aggregate of 476,906 shares of common stock of the Company. The executive officers may earn one-third of the shares by continued employment with the Company through December 31, 2013. The remaining two-thirds may be earned through increases in the Company’s adjusted net asset value, as defined in the LTIP. If the Company ultimately achieves the service requirements and performance objectives determined by the LTIP, the associated total stock-based compensation expense is expected to be approximately $3.1 million, based on the grant date fair value. The compensation expense recorded by the Company in the three and nine months ended September 30, 2012, included $164 and $468, respectively, related to the LTIP.

7. Income Taxes

The Company 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 due to its net operating loss carryforwards.

The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of September 30, 2012, the Company made no provision for interest or penalties related to uncertain tax positions. The

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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 2007 and for state and local tax authorities for tax years before 2006.

8. Credit Facility

As of September 30, 2012, the Company had a $150 million revolving line of credit in place with $60 million available for borrowing based on several factors, including the current borrowing base and the commitment levels by participating banks. The credit facility is collateralized by the Company’s oil and gas producing properties. Any balance outstanding on the credit facility is due October 24, 2016.

As of September 30, 2012, the balance outstanding of $46,200 on the credit facility has been used to fund the development of the Catalina Unit and other non-operated projects in the Atlantic Rim, development projects in the Pinedale Anticline, and the Company’s Niobrara exploration project.

Borrowings under the revolving line of credit bear interest at a daily rate equal to the greater of (a) the Federal Funds rate, plus 0.5%, the Prime Rate or the Adjusted Eurodollar Rate plus (b) a margin ranging between 0.75% and 2.75% depending on the level of funds borrowed. The average interest rate on the facility at September 30, 2012, including the impact of our interest rate swaps, was 3.1%. The Company incurred interest expense related to the credit facility of $363 and $260 for the three months ended September 30, 2012 and 2011, respectively, and $1,027 and $818 for the nine months ended September 30, 2012 and 2011, respectively. The Company capitalized interest costs of $77 and $29 for the three months ended September 30, 2012 and 2011, respectively, and $226 and $93 for the nine months ended September 30, 2012 and 2011, respectively.

Under the credit facility, the Company is subject to both financial and non-financial covenants. The financial covenants, as defined in the credit agreement, include maintaining (i) a current ratio of 1.0 to 1.0; (ii) a ratio of earnings before interest, taxes, depreciation, depletion, amortization, exploration and other non-cash items (“EBITDAX”) to interest plus dividends, of greater than 1.5 to 1.0; and (iii) a funded debt to EBITDAX ratio of less than 3.5 to 1.0. As of September 30, 2012, the Company was in compliance with all financial and non-financial covenants. If the covenants are violated and the Company is 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.

9. Series A Cumulative Preferred Stock and Stockholder’s Equity

In 2007, the stockholders of the Company approved an amendment to the Company’s Articles of Incorporation to provide for the issuance of 10,000,000 shares of preferred stock, and the Company subsequently completed a public offering of 1,610,000 shares of 9.25% Series A Cumulative Preferred Stock at a price 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 certain circumstances upon a change of ownership or control. 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 consolidated balance sheets due to the following change of control 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. 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.

ATM Offering

In August 2011, the Company entered into an At-The-Market issuance sales agreement (“ATM”), which allows the Company to offer and sell shares of its common stock from time to time at an aggregate offering price of up to $20 million. The Company’s sales agent may make sales of the Company’s common stock in privately negotiated transactions or in any method permitted by law deemed to be an ATM offering as defined in Rule 415 promulgated under the Securities Act of 1933, as amended, at negotiated prices, at prices prevailing at the time of sale or at prices related to such prevailing market prices, including sales made directly on the NASDAQ Global Select Market or sales made through a market

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maker other than on an exchange. The Company’s sales agent will make all sales using commercially reasonable efforts consistent with its normal sales and trading practices. The Company has no obligation to sell any shares in the ATM offering and may terminate the ATM offering at any time. No shares have been sold to date. The ATM agreement expires in August 2013.

10. Contingencies

Legal proceedings

From time to time, the Company is involved in various legal proceedings, including the matters discussed below. These proceedings are subject to the uncertainties inherent in any litigation. The Company is defending itself vigorously in all such matters, and while the ultimate outcome and impact of any proceeding cannot be predicted with certainty, management believes that the resolution of any proceeding will not have a material adverse effect on the Company’s financial condition or results of operations.

On December 18, 2009, Tiberius Capital, LLC (“Plaintiff”), a stockholder of Petrosearch prior to the Company’s acquisition (the “Acquisition”) of Petrosearch pursuant to a merger between Petrosearch and a wholly-owned subsidiary of the Company, filed a claim in the District Court for the Southern District of New York against Petrosearch, the Company, and the individuals who were officers and directors of Petrosearch prior to the Acquisition. In general, the claims against the Company and Petrosearch are that Petrosearch inappropriately denied dissenters’ rights of appraisal under the Nevada Revised Statutes to its stockholders in connection with the Acquisition, that the defendants violated various sections of the Securities Act of 1933 and the Securities Exchange Act of 1934, and that the defendants caused other damages to the stockholders of Petrosearch. The Second Circuit Court of Appeals affirmed the District Court’s dismissal of the claims on June 13, 2012.

11. Subsequent Events

Acquisition of Atlantic Rim Working Interest

On October 9, 2012, the Company exercised its preferential right to acquire additional working interest in the Catalina Unit and Spy Glass Hill Unit (which includes the former Sun Dog and Doty Mountain Units) from Anadarko Petroleum Corporation (“Anadarko”). The Company had previously signed a Purchase and Sales Agreement with Anadarko to acquire 100% of Anadarko’s working interest in the Spy Glass Hill and Catalina Units’ acreage; however, the joint operating agreements governing the Catalina and Spy Glass Hill Units give preferential purchase rights to the other working interest owners in the event a working interest owner sells its assets. The other major owner in these Units exercised its preferential right, reducing the amount of additional working interest acquired by the Company.

As a result of the transaction, the Company’s working interest increased as follows:

• The Catalina Unit participating area increased from approximately 71% to 86%;

• The Sun Dog participating area increased from approximately 21% to 30%; and

• The Doty Mountain participating area increased from 18% to 27%.

The estimated purchase price was as follows:

Consideration given:
Cash	$	4,873
Total consideration given	$	4,873

The Company prepaid $4,200 of the total purchase price in the third quarter of 2012. The prepaid amount is classified as other assets on the consolidated balance sheet. The effective date of this transaction is August 1, 2012. The Company’s results for the three and nine months ended September 30, 2012 do not include the impact of this acquisition, except for transaction-related costs totaling $57.

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Additional Derivative Instruments

In October 2012, the Company entered into two new commodity contracts, as summarized below (volume is expressed in MMcf and contracts are indexed to NYMEX).

Type of Contract	Remaining Contractual Volume		Term		Price
Fixed Price Swap		1,825		01/14-12/14	$	4.27
Costless Collar		1,800		01/14-12/14	$	4.00 floor
					$	4.50 ceiling
Total		3,625

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. Unless the context suggests otherwise, the amounts set forth herein are in thousands, except units of production, ratios, share or per share amounts.

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 Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934, as amended, and 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 Part I, “Item 1A. Risk Factors” in our Form 10-K for the year ended December 31, 2011, the Risk Factor in Part II, Item IA of this Quarterly Report on Form 10-Q and the following factors:

• A sustained decline in natural gas or oil prices;

• The changing political and regulatory environment in which we operate;

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

• Our ability to increase our natural gas and oil reserves;

• The shortage or high cost of equipment, qualified personnel and other oil field services;

• General economic conditions, tax rates or policies, interest rates and inflation rates;

• Our ability to maintain adequate liquidity in connection with low natural gas prices;

• Our ability to enter into favorable hedging arrangements;

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

• Incorrect estimates of required capital expenditures;

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

• Changes in or compliance with laws and regulations, particularly those relating to drilling, derivatives, and safety and protection of the environment such as initiatives related to drilling and well completion techniques including hydraulic fracturing;

• The volumes of production from our oil and gas development properties, which may be dependent upon issuance by federal and state governments, or agencies thereof, of drilling, environmental and other permits;

• Our ability to market and find reliable and economic transportation for our gas;

• Our ability to successfully identify, execute, integrate and profitably operate any future acquisitions;

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

• The actions of third party co-owners of interests in properties in which we also own an interest, and in particular those which we do not operate or control;

• Our ability to manage the risk associated with operating in one major geographic area;

• Weather, climate change and other natural phenomena;

• Our ability and the ability of our partners to continue to develop the Atlantic Rim project;

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

• Our ability to interpret 2-D and 3-D seismic data;

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

• 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. We were incorporated in Wyoming in 1972 and reincorporated in Maryland in 2001. Our common stock is publicly traded on the NASDAQ Global Select Market under the symbol “DBLE” and our Series A Cumulative Preferred Stock is traded on the NASDAQ Global Select Market under the symbol “DBLEP”. Our corporate offices are located at 1675 Broadway, Suite 2200, Denver, Colorado 80202, telephone number (303) 794-8445. Our website is www.dble.com.

Our objective is to increase long-term shareholder value by profitably growing our reserves, production, revenues, and cash flow. To meet this objective, we primarily focus on: (i) new coal bed methane (“CBM”) gas development drilling; (ii) enhancement of existing production wells and field facilities on operated and non-operated properties in the Atlantic Rim; (iii) continued participation in the development of tight sands gas wells at the Mesa Units on the Pinedale Anticline; (iv) expansion of our midstream business; (v) pursuit of high quality exploration and strategic development projects with potential for providing long-term drilling inventories that generate high returns and (vi) selectively pursuing strategic acquisitions or mergers.

Our Pinedale Anticline and Atlantic Rim assets operate under federal exploratory unit agreements among 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. The PA, and the associated working interest, may change as more wells and acreage are added to the PA.

RESULTS OF OPERATIONS

Three Months Ended September 30, 2012 Compared to the Three Months Ended September 30, 2011

The following analysis provides a comparison of the three months ended September 30, 2012 and the three months ended September 30, 2011.

Oil and gas sales

Oil and gas sales decreased 44% to $6,498, primarily due to a 30% decrease in the Colorado Interstate Gas (“CIG”) market price, which is the index on which most of our natural gas volumes are sold. In addition, the decrease was partially due to the consolidated statement of operations classification of our settlements on derivative instruments. For the three months ended September 30, 2011, one of our derivative instruments was classified as a cash flow hedge, and the settlements related to this contract totaling $2,322 were included within oil and gas sales on the consolidated statement of operations. In the three months ended September 30, 2012, all of our derivative instrument settlements were included within price risk management activities on the consolidated statement of operations. The decrease in the natural gas market price was offset by a 5% increase in production volumes, discussed below.

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As shown in the table on the following page, our average realized natural gas price decreased 22% to $3.60 per Mcf due to the decrease in the CIG market price, offset by the derivative instruments in place during the period. We calculate our average realized natural gas price by summing (1) production revenues received from third parties for the sale of our gas, which is included within oil and gas sales on the consolidated statements of operations, (2) realized gain (loss) on our economic hedges, which is included within price risk management activities, net on the consolidated statements of operations, totaling $3,166 and $161 for the three months ended September 30, 2012 and 2011, respectively, and (3) in 2011 only, the settlement of our cash flow hedges, which were included within oil and gas sales on the consolidated statements of operations. We did not have any cash flow hedges in the three months ended September 30, 2012.

	Three Months Ended September 30,								Percent Volume Change			Percent Price Change
	2012				2011
	Volume		Average Price		Volume		Average Price
Product:
Gas (Mcf)		2,497,785	$	3.60		2,381,239	$	4.64		5	%		-22	%
Oil (Bbls)		7,995	$	83.55		7,278	$	91.15		10	%		-8	%
Mcfe		2,545,755	$	3.80		2,424,907	$	4.83		5	%		-21	%

Our total net production increased 5% to 2.5 Bcfe, primarily due to higher production volumes from the Catalina and Pinedale Anticline units, offset by a decrease at the Spy Glass Hill Unit, discussed as follows.

Our total average daily net production at the Atlantic Rim increased 8% to 20,519 Mcfe. Our Atlantic Rim production comes from two operating units: the Catalina Unit and the Spy Glass Hill Unit (which includes the Sun Dog PA and Doty Mountain PA). We operate the Catalina Unit and have working interests in the Spy Glass Hill Unit.

• Average daily net production at our Catalina Unit increased 16% to 15,466 Mcfe, primarily due to the addition of the 13 new wells we drilled as part of our 2011 drilling program. Our working interest in 12 of the 13 new wells is 100% as they are located outside the previously established PA (as compared to 71.20% for wells in the previously established PA). Although the addition of these new wells resulted in an overall production increase, we had a compressor failure in September 2012, which resulted in decreased production from the new wells. Management expects the compressor to be running and production from the new wells to recover in the fourth quarter of 2012. The production increase was also offset by normal production declines from the older wells within the field.

• Average daily production, net to our interest, in the Spy Glass Hill Unit decreased 11% to 5,053 Mcfe. Management believes this is due to the operator delaying maintenance and winding down activity as it planned to sell its interest in these assets.

Average daily net production in the Pinedale Anticline increased 3% to 5,636 Mcfe as the operator brought 14 new wells on-line for production during the first nine months of 2012, in addition to bringing eight wells on-line in the fourth quarters of 2011.

Transportation and gathering revenue

We receive 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. Transportation and gathering revenue increased 5% to $1,276 for the three months ended September 30, 2012 due to additional transportation revenue generated by the increased production volume from the Catalina Unit.

Price risk management activities

We recorded a net loss on our derivative contracts not designated as cash flow hedges of $(1,827). This consisted of an unrealized non-cash loss of $(4,993), which represents the change in the fair value on our economic hedges at September 30, 2012, and a net realized gain of $3,166 related to the cash settlement of certain of our economic hedges.

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Oil and gas production expenses, depreciation, depletion and amortization

	Three Months Ended September 30,
	2012			2011
	(in dollars per Mcfe)
Average price	$	3.80		$	4.83
Production costs		1.09			1.24
Production taxes		0.31			0.45
Depletion and amortization		1.84			1.99
Total operating costs		3.24			3.68
Gross margin	$	0.56		$	1.15
Gross margin percentage		15	%		24	%

Production costs, on a dollars per Mcfe basis, is calculated by dividing production costs, as stated on the consolidated statements of operations, by total production volumes during the period. This calculation excludes certain gathering costs incurred by our subsidiary, Eastern Washakie Midstream LLC, which are eliminated in consolidation. Well production costs decreased 8% to $2,766 and production costs in dollars per Mcfe decreased 12%, or $0.15, to $1.09. The decrease in production costs was primarily the result of a decrease in production costs at the Spy Glass Hill Unit. The Company believes the operating costs were lower in this unit due to the operator decreasing maintenance-related expenditures as well as decreasing the overhead costs allocated to this unit, as it planned to sell its interest in these assets. Our production costs at the Catalina Unit increased in total and on a per Mcfe basis due primarily to higher compression, power and water hauling costs related to the addition of the 13 new wells completed in late 2011.

We are required to pay taxes on the proceeds received upon the physical sale of our gas to counterparties. Production taxes decreased 28% to $783, and production taxes, on a dollars per Mcfe basis, decreased 31%, or $0.14, to $0.31 per Mcfe. Production taxes were lower in total and on a per Mcfe basis primarily due to the lower market prices for natural gas.

Total depreciation, depletion and amortization expenses (“DD&A”) decreased 3% to $4,779, and depletion and amortization related to producing assets decreased 3% to $4,681. Expressed in dollars per Mcfe, depletion and amortization related to producing assets decreased 8%, or $0.15, to $1.84 per Mcfe primarily due to a decrease in the depletion rate at the Catalina Unit, as additional reserves were added related to the new wells completed in late 2011.

Pipeline operating costs

Pipeline operating costs increased 17% to $1,184, primarily due to higher compression costs. In the three months ended September 30, 2011, certain of our compressor leases were accounted for as capital leases with the related expense being recorded in DD&A. In the three months ended September 30, 2012, all of our compressor leases were classified as operating leases with the related expense being recorded in pipeline operating costs.

General and administrative expenses

General and administrative expenses remained consistent, totaling $1,513 during both the three months ended September 30, 2012 and 2011. Non-cash stock-based compensation expense increased $172 for the three months ended September 30, 2012, due to the adoption of our Long Term Incentive Plan on September 30, 2011. This increase was offset by a decrease in bank fees and salary and salary-related expense.

Income taxes

We recorded an income tax benefit of $2,155. Our effective tax rate for the three months ended September 30, 2012 was 34.2%, which was lower than the three months ended September 30, 2011 period primarily due to a decrease in permanent income tax difference related to stock option expense. 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/benefit on taxable income for the remainder of 2012 at an expected federal and state rate of approximately 35.3%.

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Nine Months Ended September 30, 2012 Compared to the Nine Months Ended September 30, 2011

The following analysis provides a comparison of the nine months ended September 30, 2012 and the nine months ended September 30, 2011.

Oil and gas sales

Oil and gas sales decreased 48% to $17,742, primarily due to a 40% decrease in the CIG, market price. In addition, the decrease was partially due to the classification of our settlements of derivative instruments on the consolidated statement of operations. For the nine months ended September 30, 2011, one of our derivative instruments was classified as a cash flow hedge, and the settlements related to this contract totaling $6,915 were included within oil and gas sales on the consolidated statement of operations. This contract settled in December 2011. For the nine months ended September 30, 2012, all of our derivative instrument settlements were included within price risk management activities on the consolidated statement of operations. The decrease in the natural gas market price was offset by an 8% increase in production volumes, discussed below.

As shown in the table below, our average realized natural gas price decreased 27% to $3.49 per Mcf due to the decrease in the CIG market price, offset by the derivative settlements during the period. Our calculation of the average realized natural gas price includes realized gains on our economic hedges, which is included within price risk management activities, net on the consolidated statements of operations, totaling $10,227 and $161 for the nine months ended September 30, 2012 and 2011, respectively.

	Nine Months Ended September 30,								Percent Volume Change			Percent Price Change
	2012				2011
	Volume		Average Price		Volume		Average Price
Product:
Gas (Mcf)		7,425,420	$	3.49		6,872,931	$	4.75		8	%		-27	%
Oil (Bbls)		24,466	$	83.16		20,668	$	89.14		18	%		-7	%
Mcfe		7,572,216	$	3.69		6,996,939	$	4.93		8	%		-26	%

Our total net production increased 8% to 7.6 Bcfe, due to an increase in production volumes at each of our key development fields, discussed as follows.

Our total average daily net production at the Atlantic Rim increased 8% to 20,395 Mcfe due to:

• Average daily net production at our Catalina Unit increased 11% to 14,991 Mcfe, primarily due to the addition of the 13 new wells we drilled as part of our 2011 drilling program. Production from these new wells increased throughout most of 2012 due to dewatering. However, in September 2012, we experienced a compressor failure, which resulted in decreased production from these wells. Management expects the compressor to be running and for production from the new wells to recover in the fourth quarter of 2012. The production increase from our new wells was offset by normal production declines for the older wells within the field.

• Average daily production, net to our interest, in the Spy Glass Hill Unit remained consistent totaling 5,404 Mcfe for the nine months ended September 30, 2012 and 5,394 Mcfe for the nine months ended September 30, 2011.

Average daily net production in the Pinedale Anticline increased 12% to 5,779 Mcfe, as the operator brought 14 new wells on-line for production through the first nine months of 2012, in addition to bringing eight wells on-line in the fourth quarters of 2011.

Transportation and gathering revenue

Transportation and gathering revenue increased 2% to $3,763 due to additional transportation revenue generated by the increased production volume from the Catalina Unit.

Price risk management activities

We recorded a net gain on our derivative contracts not designated as cash flow hedges of $2,705. This consisted of an unrealized non-cash loss $(7,522), which represents the change in the fair value on our economic hedges at September 30, 2012, and a net realized gain of $10,227 related to the cash settlement of certain of our economic hedges.

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Oil and gas production expenses, depreciation, depletion and amortization

	Nine Months Ended September 30,
	2012			2011
	(in dollars per Mcfe)
Average price	$	3.69		$	4.93
Production costs		1.15			1.19
Production taxes		0.25			0.46
Depletion and amortization		1.85			2.00
Total operating costs		3.25			3.65
Gross margin	$	0.44		$	1.28
Gross margin percentage		12	%		26	%

Well production costs increased 4% to $8,682, whereas production costs in dollars per Mcfe decreased 3%, or $0.04 to $1.15 per Mcfe. The overall increase in production costs was driven primarily by increased production costs at the Catalina Unit due to higher compression, power and water hauling costs due to the addition of the 13 new wells completed in late 2011. The increase at Catalina was partially offset by lower operating and transportation costs at the Spy Glass Hill Unit. The Company believes the operating costs were lower in this unit due to the operator decreasing maintenance-related expenditures as well as decreasing the overhead costs allocated to this unit, as it planned to sell these assets. Production costs on a per mcfe basis were lower due to the overall increase in production volumes.

Production taxes decreased 41% to $1,921, and production taxes, on a dollars per Mcfe basis, decreased 46%, or $0.21, to $0.25 per Mcfe. Production taxes were lower in total and on a per Mcfe basis primarily due to the decrease in the market prices for natural gas. In addition, we recorded an adjustment to production taxes related to allowable transportation deductions.

Total DD&A remained consistent totaling $14,186 and $14,317 for the nine months ended September 30, 2012 and 2011, respectively, and depletion and amortization related to producing assets totaled $13,895 and $14,008 for the nine months ended September 30, 2012 and 2011, respectively Expressed in dollars per Mcfe, depletion and amortization related to producing assets decreased 8%, or $0.15, to $1.85 for the nine months ended September 30, 2012 per Mcfe primarily due to a decrease in the depletion rate at the Catalina Unit, as additional reserves were added related to the new wells completed in late 2011.

Exploration expenses, including dry hole costs

In the first quarter of 2012, we participated in drilling an exploratory well in the High Road Prospect near Gillette, Wyoming. The well reached total depth in February 2012 and the results of geological testing showed no economically producible hydrocarbons existed. We recorded $462 of dry hole expense related to this well.

Pipeline operating costs

Pipeline operating costs increased 20% to $3,633, primarily due to higher compression costs. In 2011, certain of our compressor leases were accounted for as capital leases with the related expense being recorded in DD&A. In the first half of 2012, all of our compressor leases were classified as operating leases.

General and administrative expenses

General and administrative expenses increased 7% to $4,736, due to a $467 increase in non-cash stock-based compensation expenses primarily related to our Long Term Incentive Plan, which was adopted September 30, 2011. This increase was offset by a $104 decrease in bank fees and a $46 decrease in Board of Directors training-related expenses.

Income taxes

We recorded an income tax benefit of $4,043. Our effective tax rate for the nine months ended September 30, 2012 was 34.2%, which was lower than the nine months ended September 30, 2011 period primarily due to a decrease in permanent income tax difference related to stock options. 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/benefit on taxable income for the remainder of 2012 at an expected federal and state rate of approximately 35.3%.

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Recent Developments

On October 9, 2012, we exercised our preferential right to acquire additional working interest in the Catalina Unit and Spy Glass Hill Unit (which includes the former Sun Dog and Doty Mountain Units) from Anadarko Petroleum Corporation (“Anadarko”). We had previously signed a Purchase and Sales Agreement with Anadarko to acquire 100% of Anadarko’s working interest in the Spyglass Hill and Catalina Units’ acreage, however, the joint operating agreements governing the Catalina and Spy Glass Hill Units give preferential purchase rights to the other working interest owners in the event a working interest owner sells its assets. The other major owner in these Units exercised its preferential right, which reduced the amount of ownership we acquired from the original Purchase and Sale Agreement. This purchase will expand our presence in one of our key development areas.

As a result of the transaction, our working interest increased as follows:

• The Catalina Unit participating area increased from approximately 71% to 86%;

• The Sun Dog participating area increased from approximately 21% to 30%; and

• The Doty Mountain participating area increased from 18% to 27%.

The total purchase price was $4,873, of which we prepaid $4,200 in the third quarter of 2012. The effective date of this transaction is August 1, 2012. Our results for the three and nine months ended September 30, 2012 do not include the impact of this acquisition, except for transaction-related costs totaling $57.

In the fourth quarter of 2012, we sold certain of our undeveloped Wyoming leases to a private company for cash proceeds of $1.6 million.

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. The primary uses of our liquidity and capital resources have been in the development and exploration of oil and gas properties. In the past, these sources of liquidity and capital have been sufficient to meet our needs and finance the growth of our business.

We currently have a $150 million credit facility in place with a $60 million borrowing base. At September 30, 2012, we had $46.2 million outstanding on our credit facility. We expect that the remaining availability of $13.8 million, coupled with our expected cash flow to be sufficient to meet future financial covenants, develop new reserves, maintain our current facilities, and complete the remaining estimated $3 million to $6 million of capital expenditures budgeted as part of our 2012 capital expenditure program (see “Capital Requirements” on the following page).

The Company currently has an effective Form S-3 shelf registration statement on file with the SEC, which has $150 million of securities available for issuance and provides us the ability to raise additional funds through registered offerings of equity, debt or other securities. Under the shelf registration, we have an At-The-Market issuance sales agreement (“ATM”) in place, which allows us to offer and sell shares of our common stock from time to time, up to an aggregate offering price of $20 million. We have not sold any shares under the ATM to date. The ATM is in effect through August 2013. At this time, we have \no intention to use the ATM, as we believe we have adequate cash flow from operations and availability under our credit facility to meet our operating and capital needs.

Depending on the timing and amounts of future projects, we may need to seek additional sources of capital. We can provide no assurance that we will be able to do so on favorable terms or at all. We may issue equity or debt in private placements or obtain additional debt financing, which may be secured by our oil and gas properties, or unsecured.

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

	September 30, 2012			December 31, 2011
	(unaudited)
Financial Position Summary
Cash and cash equivalents	$	3,138		$	8,678
Working capital	$	7,491		$	13,540
Balance outstanding on credit facility	$	46,200		$	42,000
Stockholders’ equity and preferred stock	$	85,334		$	94,181
Ratios
Debt to total capital ratio (1)		35.1	%		30.8	%
Total debt to equity ratio		97.5	%		74.7	%

(1) Total capital includes the $46,200 outstanding on our credit facility, our preferred stock and stockholder’s equity.

Our working capital balance decreased 45% to $7,491 at September 30, 2012 as compared to $13,540 at December 31, 2011. The decrease in working capital is primarily the result of the decline in natural gas prices coupled with payments of accounts payable and accrued expenses related to our 2011 drilling program. In the third quarter of 2012, we drew down on our credit facility by $4,200 million to prepay a portion of our Atlantic Rim working interest purchase, which totaled $4,873. Please see “Recent Developments” for more information regarding this transaction.

Cash flow activities

The table below summarizes our cash flows for the nine months ended September 30, 2012 and 2011, respectively:

	Nine Months Ended September 30,
	2012			2011
	(unaudited)
Cash provided by (used in):
Operating activities	$	13,630		$	18,782
Investing activities		(20,554	)		(12,218	)
Financing activities		1,384			(3,217	)
Net change in cash	$	(5,540	)	$	3,347

During the nine months ended September 30, 2012, net cash provided by operating activities was $13,630, as compared to $18,782 in the same prior-year period. The primary sources of cash during the nine months ended September 30, 2012 were a net loss of $(7,265), which was net of non-cash charges of $14,328 related to DD&A and accretion expense, non-cash stock-based compensation expense of $1,234 and a non-cash net loss on derivative contracts of $8,082. Our cash flow from operations was lower in the 2012 period primarily due to a 27% decrease in our average realized natural gas price. During the nine months ended September 30, 2011, we had a $7.07 CIG fixed price swap for 8,000 Mcf per day. We entered into this hedge in 2008, when the future prices of natural gas were significantly higher than they are today. For 2012, we currently have 20,000 Mcf per day hedged at between $3.00 and $5.10, based upon NYMEX pricing. Our cash flow from operations in 2012 included $10,227 of income from cash settlements on our derivative instruments, as compared to $7,587 in the same prior year period. In addition to our lower derivative contract prices, the average CIG price has decreased 40% as compared to the same prior year period.

During the nine months ended September 30, 2012, net cash used in investing activities was $20,554, as compared to $12,218 in the same prior-year period. During the nine months ended September 30, 2012, our spending primarily related to our Niobrara exploration well, which was spud in October 2011 and reached its total depth of 9,450 feet in February 2012. As of September 30, 2012, we had incurred approximately $7.5 million related to this well, and expect to incur additional completion costs in the fourth quarter of 2012. In addition in October 2012, we acquired additional working interest in our Atlantic Rim properties. Although the transaction closed subsequent to September 30, 2012, we prepaid $4,200 of the total $4,873 purchase price. Lastly, we made payments related to our 2011 drilling program at Catalina and the drilling program at the Pinedale Anticline. The capital expenditures in the nine months ended September 30, 2011 primarily related to non-operated drilling in the Pinedale Anticline.

During the nine months ended September 30, 2012, we had net cash provided by financing activities of $1,384 as compared to net cash used of $3,217 in the same prior-year period. In the nine months ended September 30, 2012, we drew down $4,200 on our credit facility, primarily to make a prepayment on our Atlantic Rim purchase. We expended cash of $2,792 to make our quarterly dividend payments in both the nine months ended September 30, 2012. Dividends are expected to

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continue to be paid on a quarterly basis on the Series A Preferred Stock in the future at a rate of $931 per quarter. In the first half of 2011, we also had $408 of capital lease payments, whereas in 2012, we did not have any equipment leases classified as capital leases.

Credit Facility

At September 30, 2012, we had a $150 million credit facility in place with a $60 million borrowing base. The credit facility is collateralized by our oil and gas producing properties and other assets. On September 30, 2012, we had $46.2 million outstanding on the facility. We have depended on our credit facility over the past four years to supplement our operating cash flow in the development of the Company-operated Catalina Unit and other non-operated projects in the Atlantic Rim, including working interest purchases in this field in both 2010 and in 2012, development projects in the Pinedale Anticline, and the drilling of our Niobrara exploration well.

Borrowings under the revolving line of credit bear interest at a daily rate equal to the greater of (a) the Federal Funds rate, plus 0.5%, the Prime Rate or the Adjusted Eurodollar Rate, plus (b) a margin ranging between 0.75% and 2.75% depending on the level of funds borrowed. As of September 30, 2012, the average interest rate on the outstanding debt was 3.1%. We have locked in the floating interest rate on our credit facility for a $30 million tranche of our outstanding balance. Under the contract terms, we have locked in the Eurodollar LIBOR portion of the interest calculation at approximately 0.578% through December 31, 2012, and at approximately 1.050% from December 31, 2012 through September 30, 2016, which, based on our current level of outstanding debt translates to an interest rate of approximately 3.08% and 3.55%, respectively. Any balance outstanding is due on October 24, 2016.

We are subject to a number of financial and non-financial covenants under this facility. As of September 30, 2012, we were in compliance with all covenants under the facility. If any of the covenants are violated, and we are unable to negotiate a waiver or amendment thereof, the lender would have the right to declare an event of default, terminate the remaining commitment and accelerate all principal and interest outstanding.

Our lending banks conduct an assessment of our available borrowing base semi-annually on April 1 and October 1. If natural gas prices continue to decrease for extended periods of time, our borrowing base could be reduced, thus limiting the future amounts of funds under the current facility. This may impact our ability to develop future reserves, or require that we seek alternative sources of capital. Upon any downward adjustment of the borrowing base, if the outstanding borrowings are in excess of the revised borrowing base, we may have to repay our indebtedness in excess of the borrowing base immediately, or in six monthly installments, or pledge additional properties as collateral. We may not have sufficient funds to make such repayments or additional properties to pledge as collateral.

Capital Requirements

For 2012, we budgeted approximately $15 to $20 million for our development and exploration programs in the Atlantic Rim and Pinedale Anticline. The 2012 capital budget includes our participation in drilling approximately 15 new wells at the Mesa Units and our purchase of additional working interest in our Atlantic Rim properties. In the fourth quarter of 2012, we also began completing our Niobrara exploration well, which had reached total depth in February 2012. We expect to fund our 2012 capital expenditures with cash provided by operating activities and funds made available through our credit facility. Our 2012 capital budget does not include the impact of potential future exploration projects or possible acquisitions, which we continually evaluate.

Contractual Obligations

The impact that our contractual obligations as of September 30, 2012 are expected to have on our liquidity and cash flows in future periods is:

	Total		Less than one year		1 - 3 Years		3 - 5 Years		More than 5 Years
Credit facility(a)	$	46,200	$	—	$	—	$	46,200	$	—
Interest on credit facility(b)		6,424		1,553		3,178		1,693		—
Operating leases		2,455		2,186		269		—		—
Total contractual cash commitments	$	55,079	$	3,739	$	3,447	$	47,893	$	—

(a) The amount listed reflects the balance outstanding as of September 30, 2012. In October 2012, we drew an additional $4,200 to fund our purchase of additional interests in the Atlantic Rim. Any balance outstanding is due on October 24, 2016.

(b) Assumes the interest rate on our credit facility is consistent with that of September 30, 2012, which includes the impact of our $30 million fixed rate swaps.

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Off-Balance Sheet Arrangements

As of September 30, 2012, we did not have any off-balance sheet arrangements, as defined in Item 303(a)(4)(ii) of SEC regulation S-K.

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 had no interest in any unconsolidated SPEs or VIEs at any time during any of the periods presented.

DERIVATIVE INSTRUMENTS

Contracted Gas Volumes

Changes in the market price of oil and natural gas can significantly affect our profitability and cash flow. We have entered into various derivative instruments to mitigate the risk associated with downward fluctuations in the natural gas price. Historically, these derivative instruments have consisted of fixed delivery contracts, swaps, and costless collars. The duration and size of our various derivative instruments varies, and depends on our view of market conditions, available contract prices and our operating strategy.

Our outstanding derivative instruments as of September 30, 2012 are summarized below (volume and daily production are expressed in Mcf). All contracts are indexed to the New York Mercantile Exchange (“NYMEX”). The prevailing market prices in the Rockies, including CIG which is the index on which most of our gas volumes are sold, tend to be sold at a discount relative to other U.S. natural gas markets. This discount is typically referred to as a “basis differential” and reflects, to some extent, of the costs associated with transporting the natural gas in the Rockies to markets in other regions. It is also reflects the general excess supply and lack of pipeline capacity in the region.

	Remaining Contractual
Type of Contract	Volume (MMcf)		Term		Contract Price
Fixed Price Swap		460		01/12-12/12	$5.10
Fixed Price Swap		920		01/12-12/12	$5.05
Fixed Price Swap		450		08/12-12/12	$3.00
Fixed Price Swap		2,190		01/13-12/13	$5.16
Costless Collar		2,190		01/13-12/13	$5.00 floor
					$5.35 ceiling
Costless Collar		2,160		01/13-12/13	$3.25 floor
					$4.00 ceiling
Total		8,370

In addition, in October 2012, we entered in to two additional NYMEX contracts, as summarized below.

Type of Contract	Remaining Contractual Volume (MMcf)		Term		Price
Fixed Price Swap		1,825		01/14-12/14	$4.27
Costless Collar		1,800		01/14-12/14	$4.00 floor
					$4.50 ceiling
Total		3,625

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Interest rate swap

We have entered in to two fixed rate swap contracts with a third party to lock in the interest rate on a $30 million tranche of our debt through September 30, 2016. Under the hedge contract terms, we locked in the Eurodollar LIBOR portion of the interest calculation at approximately 0.578% through December 31, 2012 and 1.050% for the period December 31, 2012 through September 30, 2016. Based on our current level of funds borrowed, these contracts translate to interest rates of approximately 3.08% and 3.55%, respectively.

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, 2011, 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. Taking in account our derivative instruments, for the three months ended September 30, 2012, our income before income taxes would have changed by $292 for each $0.50 change per Mcf in natural gas prices and $7 for each $1.00 change per Bbl in crude oil prices.

The primary objective of our commodity price risk management policy is to preserve and enhance the value of our gas production. We have entered into natural gas derivative contracts to manage our exposure to natural gas price volatility. Our derivative instruments typically consist of forward sales contracts, swaps and costless collars, which allow us to effectively “lock in” a portion of our future production of natural gas at prices that we consider favorable to us at the time we enter into the contracts. These derivative instruments which have differing expiration dates are summarized in the table presented above under “Derivative Instruments”.

Interest Rate Risks

At September 30, 2012, we had a total of $46.2 million outstanding under our $150 million credit facility ($60 million borrowing base). 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 average interest rate for the period, calculated in accordance with the agreement, was 3.1%. Because the interest rate is variable and reflects current market conditions, the carrying value approximates the fair value. Assuming no change in the amount outstanding at September 30, 2012, the annual impact on interest expense for every 1.0% change in the average interest rate would be approximately $162 before taxes (including the impact of our interest rate swap). Any balance outstanding on the credit facility matures on October 24, 2016.

ITEM 4. CONTROLS AND PROCEDURES

In accordance with the Securities Exchange Act of 1934, and Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Financial and 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 Financial and 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 SEC rules and forms.

There has been no change in our internal control over financial reporting that occurred during the three months ended September 30, 2012 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

From time to time, we are involved in various legal proceedings, including, but not limited to, the matters discussed below. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters, and while the ultimate outcome and impact of any proceeding cannot be predicted with certainty, our management believes that the resolution of any proceeding will not have a material adverse effect on our financial condition or results of operations.

ITEM 1A. RISK FACTORS

Due to the Atlantic Rim purchase that closed subsequent to September 30, 2012, we have added a new risk factor, as described in more detail immediately below. For a listing of our other risk factors, please refer to Item 1A of Part I of our Annual Report on Form 10-K for the year ended December 31, 2011 filed with the SEC, which we incorporate by reference herein.

We do not control all of our operations and development projects.

Certain of our business activities are conducted through operating agreements under which we own partial interests in oil and natural gas wells. If we do not operate wells in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of underlying properties. On October 9, 2012, we exercised our preferential right to acquire additional working interest in the Spy Glass Hill Unit (which includes the former Sun Dog and Doty Mountain Units) from Anadarko Petroleum Corporation (“Anadarko”), the former operator. The federal exploratory agreement governing this Unit states that 25 wells must be drilled by June 2013, or the Unit will contract in June 2015. Undeveloped acreage that falls within the Unit boundaries is currently held by production and is not subject to expiration. However, if the Unit were to contract, any leases undeveloped at that time would expire and we would lose our opportunity to drill new wells and produce gas from those leases. This may have a material adverse effect on our results of operations and reserves. Management believes there is still ample time and opportunity for 25 wells to be drilled in the Unit by June 2013, however, the successor operator has not communicated its future development plans for the Spy Glass Hill Unit.

ITEM 6. EXHIBITS

The following exhibits are filed as part of this report:

Exhibit	Description:
3.1(a)	Articles of Incorporation of the Company (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 of the Company (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)	Certificate of Correction of the Company (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(d)	Certificate of Correction to the Articles of Incorporation of the Company (incorporated by reference from Exhibit 3.3 of the Company’s Current Report of Form 8-K dated June 29, 2007).
3.1(e)	Articles of Amendment to the Articles of Incorporation of the Company, 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(f)	Articles Supplementary of Series A Cumulative Preferred Stock, (incorporated by reference from Exhibit 3.2 of the Company’s Current Report of Form 8-K dated June 29, 2007).

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3.1(g)	Articles Supplementary of Junior Participating Preferred Stock, Series B of the Company, 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).
3.1(h)	Second Amended and Restated Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Current Report on Form 8-K filed June 11, 2007)
3.1(i)	Amendment to Bylaws, Revised Article II, Section 9 (incorporated by reference from Exhibit 3.1 of the company’s Current Report on Form 8-K filed on March 5, 2010).
10.1 (a)	Amended and Restated Employment Agreement dated March 30, 2012 between Double Eagle Petroleum Co. and Richard Dole (incorporated by reference from Exhibit 10.1 of the Company’s Current Report on Form 8-K dated April 3, 2012).
10.1 (b)	Amended and Restated Employment Agreement dated March 30, 2012 between Double Eagle Petroleum Co. and Kurtis Hooley (incorporated by reference from Exhibit 10.1 of the Company’s Current Report on Form 8-K dated April 3, 2012).
10.1 (c)	Amended and Restated Employment Agreement dated March 30, 2012 between Double Eagle Petroleum Co. and Ashley Jenkins (incorporated by reference from Exhibit 10.1 of the Company’s Current Report on Form 8-K dated April 3, 2012).
10.1 (d)	Amended and Restated Employment Agreement dated March 30, 2012 between Double Eagle Petroleum Co. and Clark Huffman (incorporated by reference from Exhibit 10.1 of the Company’s Current Report on Form 8-K dated April 3, 2012).
10.1 (e)	Purchase and Sale Agreement dated August 16, 2012 between Anadarko E&P Company
	LP as seller and Double Eagle Petroleum Co (incorporated by reference from Exhibit 10.1 of the Company’s Current Report on Form 8-K dated August 21, 2012)
10.1 (f)	Purchase and Sale Agreement dated August 16, 2012 between WGR Asset Holding Company LLC as seller and Double Eagle Petroleum Co (incorporated by reference from Exhibit 10.2 of the Company’s Current Report on Form 8-K dated August 21, 2012.)
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Principal Accounting Officer and Chief Operating Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*	Certification Pursuant to 18 U.S.C. Section 1150 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS**	XBRL Instance Document
101.SCH**	XBRL Taxonomy Extension Scheme Document
101.CAL**	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF**	XBRL Taxonomy Definition Linkbase Document
101.LAB**	XBRL Taxonomy Extension Label Linkbase Document
101.PRE**	XBRL Taxonomy Extension Presentation Linkbase Document

* Filed within this Form 10-Q.

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** Pursuant to Rule 406T of Regulation S-T, these Interactive Data Files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to the liability under these sections.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		DOUBLE EAGLE PETROLEUM CO. (Registrant)
Date: November 7, 2012	By :	/s/ Richard D. Dole
		Richard D. Dole
		Chief Executive Officer
		(Principal Executive Officer)

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EXHIBIT INDEX

Exhibit	Description:
3.1(a)	Articles of Incorporation of the Company (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 of the Company (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)	Certificate of Correction of the Company (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(d)	Certificate of Correction to the Articles of Incorporation of the Company (incorporated by reference from Exhibit 3.3 of the Company’s Current Report of Form 8-K dated June 29, 2007).
3.1(e)	Articles of Amendment to the Articles of Incorporation of the Company, 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(f)	Articles Supplementary of Series A Cumulative Preferred Stock, (incorporated by reference from Exhibit 3.2 of the Company’s Current Report of Form 8-K dated June 29, 2007).
3.1(g)	Articles Supplementary of Junior Participating Preferred Stock, Series B of the Company, 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).
3.1(h)	Second Amended and Restated Bylaws of the Company (incorporated by reference from Exhibit 3.2 of the Company’s Current Report on Form 8-K filed June 11, 2007)
3.1(i)	Amendment to Bylaws, Revised Article II, Section 9 (incorporated by reference from Exhibit 3.1 of the company’s Current Report on Form 8-K filed on March 5, 2010).
10.1 (a)	Amended and Restated Employment Agreement dated March 30, 2012 between Double Eagle Petroleum Co. and Richard Dole (incorporated by reference from Exhibit 10.1 of the Company’s Current Report on Form 8-K dated April 3, 2012).
10.1 (b)	Amended and Restated Employment Agreement dated March 30, 2012 between Double Eagle Petroleum Co. and Kurtis Hooley (incorporated by reference from Exhibit 10.1 of the Company’s Current Report on Form 8-K dated April 3, 2012).
10.1 (c)	Amended and Restated Employment Agreement dated March 30, 2012 between Double Eagle Petroleum Co. and Ashley Jenkins (incorporated by reference from Exhibit 10.1 of the Company’s Current Report on Form 8-K dated April 3, 2012).
10.1 (d)	Amended and Restated Employment Agreement dated March 30, 2012 between Double Eagle Petroleum Co. and Clark Huffman (incorporated by reference from Exhibit 10.1 of the Company’s Current Report on Form 8-K dated April 3, 2012).

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10.1 (e)	Purchase and Sale Agreement dated August 16, 2012 between Anadarko E&P Company LP as seller and Double Eagle Petroleum Co (incorporated by reference from Exhibit 10.1 of the Company’s Current Report on Form 8-K dated August 21, 2012)
10.1 (f)	Purchase and Sale Agreement dated August 16, 2012 between WGR Asset Holding Company LLC as seller and Double Eagle Petroleum Co (incorporated by reference from Exhibit 10.2 of the Company’s Current Report on Form 8-K dated August 21, 2012.)
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Principal Accounting Officer and Chief Operating Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*	Certification Pursuant to 18 U.S.C. Section 1150 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS**	XBRL Instance Document
101.SCH**	XBRL Taxonomy Extension Scheme Document
101.CAL**	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF**	XBRL Taxonomy Definition Linkbase Document
101.LAB**	XBRL Taxonomy Extension Label Linkbase Document
101.PRE**	XBRL Taxonomy Extension Presentation Linkbase Document

* Filed within this Form 10-Q.

** Pursuant to Rule 406T of Regulation S-T, these Interactive Data Files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to the liability under these sections.

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