Escalera Resources (ESCR) 8-K Double Eagle Petroleum Reports Third Quarter Results and Operations Update

Exhibit 99.1

Double Eagle Petroleum Company
1675 Broadway, Suite 2200 Denver, Colorado, 80202· 1-303-794-8445 · Fax: 1-303-794-8451

Denver, Colorado — FOR RELEASE AT 5:00 PM EASTERN DAYLIGHT TIME
Date: November 2, 2011

Double Eagle Petroleum Reports Third Quarter Results and Operations Update

Denver, Colorado — Double Eagle Petroleum Co. (NASDAQ: DBLE)reported today its financial results for the third quarter ended September 30, 2011. The Company had net income attributable to common stock of $2,906,000, or $0.26 per share, for the third quarter of 2011 as compared to $1,932,000, or $0.17 per share, for the third quarter of 2010. The increase in net income in the third quarter of 2011 was attributed to the following:

• $4,642,000 pre-tax unrealized non-cash gain on the Company’s economic hedges;

• 20% increase in realized natural gas price; and

• 4% increase in production.

The Company’s third quarter 2010 results included pre-tax proceeds of $3,841,000 received as a litigation settlement.

Clean earnings, a non-GAAP metric, totaled $5,693,000 for the third quarter of 2011, or $0.51 per share, as compared to $6,866,000, or $0.62 per share, for the third quarter of 2010. Clean earnings excludes the effects on net income of non-cash charges, including depreciation, depletion and amortization expense, unrealized gains/losses related to the Company’s economic hedges, as well as share-based compensation expense. Clean earnings also excludes the impact of income taxes, as the Company does not expect to pay income tax in the foreseeable future due to its net operating loss carryforwards. Please see the table at the end of this release for the reconciliation of clean earnings to GAAP.

Production

Total natural gas and crude oil production increased 4% to 2.4 Bcfe for the quarter ended September 30, 2011 as compared to the same period a year ago. The production increase was driven by higher production volume from the Company’s non-operated Atlantic Rim properties. The operator of these properties added additional water injection capacity at the Sun Dog Unit in early 2011, which resulted in improved production from certain wells. In addition, the Company benefited from higher working interests in both units for part of the 2011 period as compared to the prior year, as we completed our purchase of additional working interests in the Sun Dog and Doty Mountain Units in late July 2010.

At the Catalina Unit, production decreased to 1.2 Bcf for the quarter ended September 30, 2011 from 1.4 Bcf in the third quarter of 2010. Management believes the decrease is primarily the result of the field’s normal production decline. Production from the Mesa Units in the Pinedale Anticline increased 3% from the third quarter of 2010.

Revenue

Production-related revenue increased 21% to $12,922,000 for the third quarter of 2011, as compared to $10,665,000 for the third quarter of 2010. The production-related revenue included gains of $161,000 and $1,715,000 for the quarters ended September 30, 2011 and 2010, respectively, for the settlement of certain derivative instruments, which are not accounted for as cash flow hedges. Production-related revenue improved quarter over quarter due to an increase in the Company’s realized natural gas price and the increase in total production. This was offset by the decline in Catalina Unit production, which also resulted in lower transportation revenue to the Company.

The Company’s realized natural gas price increased to $4.64 per Mcf in the third quarter of 2011 as compared to $3.86 per Mcf in the third quarter of 2010. The realized gas price includes the impact of realized gains/losses on derivative instruments. Excluding the realized gains/losses on hedges, the Company’s average realized natural gas price was $3.60 and $3.12 for the third quarter of 2011 and 2010, respectively. The Company has historically entered into forward sales contracts, collars and fixed price swaps to manage the price risk associated with its natural gas production. All of the contracts the Company enters into are at no up-front cost to the Company. The table below summarizes the Company’s current open derivative contracts:

	Remaining
	Contractual		Daily				Price
Type of Contract	Volume (mcf)(1)		Production (mcf)		Term	Price	Index(2)
Fixed Price Swap		488,000		8,000	01/11-12/11	$7.07	CIG
Costless Collar		150,000		5,000	12/09-11/11	$4.50 floor	NYMEX
						$9.00 ceiling
Fixed Price Swap		1,830,000		5,000	01/12-12/12	$5.10	NYMEX
Fixed Price Swap		3,660,000		10,000	01/12-12/12	$5.05	NYMEX
Fixed Price Swap		2,190,000		6,000	01/13-12/13	$5.16	NYMEX
Costless Collar		2,190,000		6,000	01/13-12/13	$5.00 floor	NYMEX
						$5.35 ceiling
Total		10,508,000

(1)	As of November 1, 2011.
(2)	CIG refers to the Colorado Interstate Gas price as quoted on the first day of each month. NYMEX refers to quoted prices on the New York Mercantile Exchange.

Production Costs and Other Expenses

The Company’s production costs for the third quarter of 2011 increased 2% to $1.24 per Mcfe as compared to $1.21 per Mcfe a year ago. The increase in production costs was primarily driven by higher production costs from the Sun Dog Unit, partially offset by lower repair and maintenance expense at the Catalina Unit.

The Company continued to hold its general and administrative expenses flat, totaling $1,513,000 and $1,540,000 for the quarter ended September 30, 2011 and 2010, respectively.

Liquidity

In October 2011, the Company amended its credit facility to increase the revolving line of credit to $150 million ($60 million borrowing base) and to extend the maturity date of the facility to October 2016. The Company had $32 million outstanding as of September 30, 2011 with an average interest rate of 3.18%. The Company’s borrowing base was reaffirmed as of October 1, 2011.

Please refer to the Company’s Form 10-Q, which will be filed with the Securities and Exchange Commission on November 3, 2011, for a more detailed discussion of the Company’s results.

Operations Update

Atlantic Rim Coal Bed Methane

The Company has completed the drilling of 13 gross (12.72 net) and 2 gross (net) water injection wells, along with the related gathering system, as part of its 2011 drilling program. The Company has commenced hydraulic fracturing operations and it expects to complete the fracturing of all wells by November 15. The addition of the 12.72 net additional wells represents an increase of approximately 25% in total net producing wells in the Catalina Unit. Upon completion of the 2011 drilling program, the Company will have 111 approved drilling permits remaining for future drilling locations. There are also 76 additional potential locations for which the Company has not yet filed for permits.

Atlantic Rim Niobrara

The Company commenced drilling the first Niobrara appraisal well in the Atlantic Rim on October 28, 2011, in which it has a 93% working interest. The well will be drilled vertically to approximately 9400 feet, testing multiple zones including the Shannon, Niobrara (4 potential benches over 1500 feet), Dakota and Frontier formations. The well bore design will allow for either a vertical or horizontal completion. The Company believes that the suite of logs and sidewall cores for the appraisal well will provide valuable information on the appropriate completion operations for this well and additional data for identifying future drilling locations.

The location of this well was selected after reprocessing 25 square miles of 3D seismic and evaluating log data for wells drilled in the area. The Company is also planning to shoot 15-25 square miles of additional 3D seismic in 2012 to further high-grade the deep and CBM Atlantic Rim opportunities. The Company has already identified 20 potential locations of future Niobrara wells, filed for three permits and staked 15 Niobrara locations to avoid future Bureau of Land Management permitting delays. The locations for future drilling will be refined after evaluating the data from the appraisal well and the new seismic data from the 2012 seismic program.

High Road Prospect, Powder River Basin, Wyoming

The Company will participate for a 40% before payout working interest (32% after payout) in its internally generated High Road prospect, a well targeting the Minnelusa formation at 9,700 feet. The well is approximately 20 miles southeast of Gillette, Wyoming. The well will be operated by True Oil Company and offsets a well that has produced a cumulative 575,000 barrels of oil. Drilling is expected to commence in the fourth quarter of 2011. This prospect has four additional locations and water flood potential if successful.

Earnings Conference Call

Double Eagle will host a conference call to discuss results on Thursday, November 3, 2011 at 11:00 a.m. Eastern Daylight Time (9 a.m. Mountain). Those wanting to listen and participate in the Q&A portion can call (800) 434-1335 and use conference code 434981#.

A replay of this conference call will be available for one week by calling (800) 704-9804 and using pass code * then 434981#.

SUMMARY STATEMENT OF OPERATIONS
(In thousands, except per share data)

	Three months ended						Nine months ended
	September 30,			September 30,			September 30,			September 30,
	2011			2010			2011			2010
Revenues
Oil and gas sales	$	11,540		$	7,601		$	33,843		$	26,258
Transportation revenue		1,221			1,349			3,674			4,238
Price risk management activities		4,803			3,263			5,732			11,188
Proceeds from the Madden Deep settlement		—			3,841			—			3,841
Other income, net		469			108			774			465
Total revenues		18,033			16,162			44,023			45,990
Expenses
Lease operating expenses		3,018			2,828			8,361			7,167
Production taxes		1,084			1,180			3,230			3,489
Pipeline operating expenses		1,016			987			3,017			3,106
Exploration expenses including dry holes		67			56			239			122
Impairment of properties and surrendered leases		—			—			73			80
Total expenses		5,185			5,051			14,920			13,964
Gross Margin Percentage		71.2	%		68.7	%		66.1	%		69.6	%
General and administrative		1,513			1,540			4,433			4,465
Depreciation, depletion and amortization expense		4,926			4,701			14,317			13,771
Other expense, net		(352	)		(422	)		(997	)		(1,172	)
Pre-tax income		6,057			4,448			9,356			12,618
Provision for deferred taxes		(2,221	)		(1,586	)		(3,459	)		(4,531	)
Net Income		3,836			2,862			5,897			8,087
Preferred stock requirements		930			930			2,792			2,792
Net income attributable to common stock	$	2,906		$	1,932		$	3,105		$	5,295
Net income per common share:
Basic	$	0.26		$	0.17		$	0.28		$	0.48
Diluted	$	0.26		$	0.17		$	0.28		$	0.48
Weighted average shares outstanding:
Basic		11,197,681			11,128,802			11,187,298			11,117,060
Diluted		11,226,724			11,128,802			11,207,517			11,117,060

SELECTED BALANCE SHEET DATA
(In thousands)

	September 30,		December 31,
	2011		2010		% Change
Total assets	$	152,461	$	152,517		0	%
Balance outstanding on credit facility		32,000		32,000		0	%
Total stockholders’ equity		52,601		52,705		0	%

SELECTED CASH FLOW DATA
(In thousands)

	Nine months ended September 30,
	2011			2010			% Change
Net cash provided by operating activities	$	18,782		$	21,251			-12	%
Net cash used in investing activities		(12,218	)		(20,063	)		-39	%
Net cash used in financing activities		(3,217	)		(3,187	)		1	%

SELECTED OPERATIONAL DATA

	Three months ended,
	September 30,		September 30,
	2011		2010		% Change
Total production (Mcfe)		2,424,907		2,340,556		4	%
Average price realized per Mcfe	$	4.83	$	3.98		21	%

Use of Non-GAAP Financial Measures

The Company believes that the presentation of “clean earnings” below provides a meaningful non-GAAP financial measure to help management and investors understand and compare operating results and business trends among different reporting periods on a consistent basis, independent of regularly reported non-cash charges. The measure also excludes the impact of income taxes because the Company does not expect to pay taxes in the near future due to its net operating loss carryforwards. The Company’s management also uses clean earnings in its planning and development of target operating models and to enhance its understanding of ongoing operations. Readers should not view clean earnings as superior to or an alternative to GAAP results or as being comparable to results reported or forecasted by other companies. Readers should refer to the reconciliation of GAAP net income with clean aernings for the three and nine months ended September 30, 2011 and 2010, respectively, contained below.

Reconciliation of Net Income to Clean Earnings
(In thousands, except per share data)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Net Income as reported	$	2,906		$	1,932		$	3,105		$	5,295
Add back non-cash items:
Provision for income taxes		2,221			1,586			3,459			4,531
Depreciation, depletion, amortization and accretion expense		4,969			4,737			14,444			13,862
Non-cash gain on derivatives (1)		(4,575	)		(1,548	)		(4,993	)		(8,030	)
Share-based compensation expense		242			230			767			726
Impairments and abandonments		—			—			73			80
Other non-cash items		(70	)		(71	)		(211	)		(213	)
Clean Earnings	$	5,693		$	6,866		$	16,644		$	16,251
Clean Earnings per Share	$	0.51		$	0.62		$	1.48		$	1.46

(1) Non-cash gain on derivatives is comprised of an unrealized loss (gain) from the Company’s mark-to-market derivative instruments (both commodity contracts and interest rate swaps), resulting from recording the instruments at fair value at each period end.

About Double Eagle

Double Eagle Petroleum Co. explores for, develops, and sells natural gas and crude oil, with natural gas constituting more than 95% of its production and reserves. The Company currently has development activities and opportunities in its Atlantic Rim coal bed methane and in the Pinedale Anticline in Wyoming. Also, exploration potential exists in its Niobrara acreage in Wyoming and Nebraska, which totals over 70,000 net acres.

# # #

This release may contain forward-looking statements regarding Double Eagle Petroleum Co.’s future and expected performance based on assumptions that the Company believes are reasonable. No assurances can be given that these statements will prove to be accurate. A number of risks and uncertainties could cause actual results to differ materially from these statements, including, without limitation, decreases in prices for natural gas and crude oil, unexpected decreases in gas and oil production, the timeliness, costs and results of development and exploration activities, unanticipated delays and costs resulting from regulatory compliance, and other risk factors described from time to time in the Company’s Forms 10-K and 10-Q and other reports filed with the Securities and Exchange Commission. Double Eagle undertakes no obligation to publicly update these forward-looking statements, whether as a result of new information, future events or otherwise.

Company Contact:
John Campbell, IR
(303) 794-8445
www.dble.com