FOR IMMEDIATE RELEASE

NEWS RELEASE   Contacts: Gastar Exploration Ltd. Michael A. Gerlich, Chief Financial Officer 713-739-1800 / mgerlich@gastar.com Investor Relations Counsel: Lisa Elliott / Anne Pearson DRG&L: 713-529-6600 lelliott@drg-l.com / apearson@drg-l.com

   

GASTAR EXPLORATION LTD. REPORTS

FOURTH QUARTER 2011 RESULTS

 

HOUSTON, March 8, 2012 – Gastar Exploration Ltd. (NYSE Amex: GST) (“Gastar”) today reported financial and operating results for the three- and twelve-month periods ended December 31, 2011.

 

Net loss attributable to Gastar’s common shareholders for the fourth quarter of 2011 was $1.0 million, or $0.02 per diluted share. This compares to a net loss of $2.9 million, or $0.06 per share, for the fourth quarter of 2010. Results in both periods were impacted by non-cash unrealized natural gas hedging gains or losses. For the fourth quarter of 2011, excluding the impact of an unrealized natural gas hedging gain of $1.3 million, adjusted net loss attributable to common shareholders was $2.3 million, or $0.04 per share. For the fourth quarter of 2010, excluding the impact of an unrealized natural gas hedging loss of $2.7 million, litigation settlement expense of $0.6 million and other special items, adjusted net income was $325,000, or $0.01 per share. (See the accompanying reconciliation of net income (loss) and earnings per share to these non-GAAP financial measures at the end of this news release.)

 

Our net cash flow provided by operations before working capital changes for the fourth quarter of 2011 was $2.5 million compared to net cash flow used in operations of $14.6 million for the fourth quarter of 2010. Net cash flow provided by operations before working capital changes for full-year 2011 was $12.8 million, versus net cash flow used in operations of $6.5 million for full-year 2010. Our cash flow from operations before working capital changes and as adjusted for 2010 litigation settlement expense and other special items was $2.5 million for the fourth quarter of 2011 versus $4.0 million in the fourth quarter of 2010. Full year 2011 cash flow before working capital and adjusted for special items was $12.8 million compared to $10.9 million for 2010. (See the accompanying reconciliation of cash flow before working capital changes and as adjusted for special items to these non-GAAP financial measures at the end of this news release.)

 

Natural gas and oil revenues increased 4% to $9.8 million in the fourth quarter of 2011, up from $9.4 million in the fourth quarter of 2010. The increase was the result of a 21% increase in realized commodity prices, partially offset by a 14% decrease in volumes. Average daily production was 22.1 million cubic feet of natural gas equivalent (MMcfe) per day for the fourth quarter of 2011, compared to 25.8 MMcfe per day for the same period in 2010. Lower production volumes in the fourth quarter of 2011 were the result of natural declines from our natural gas wells in East Texas and Wyoming, partially offset by higher Marcellus Shale sales in the fourth quarter. As previously reported, Marcellus Shale production rates were curtailed in the fourth quarter due to unscheduled down time coupled with high line pressures on the third-party operated gathering system in West Virginia. Average daily production in the fourth quarter of 2011 increased 6% from the third quarter 2011 production of 20.9 MMcfe per day.

 

 

During the fourth quarter of 2011, approximately 80% of our natural gas production was hedged with downside price protection. The realized effect of hedging on natural gas sales in the fourth quarter of 2011 was an increase of $3.2 million in revenues and resulted in an increase in total price received from $2.66 per thousand cubic feet (Mcf) to $4.36 per Mcf. We continue to maintain an active hedging program covering a portion of our estimated future natural gas production.

 

Lease operating expense (LOE) was $2.7 million in the fourth quarter of 2011 compared to $1.5 million in the fourth quarter of 2010. LOE for the fourth quarter of 2011 includes an increase in workover costs of $1.2 million primarily related to East Texas. LOE per Mcf equivalent (Mcfe) of production increased to $1.32 in the fourth quarter of 2011 from $0.62 in the fourth quarter of 2010 of which $0.58 per Mcfe is associated with workover costs.

 

Depreciation, depletion and amortization (DD&A) was $4.4 million in the fourth quarter of 2011, up from $3.2 million in the fourth quarter of 2010. The DD&A rate for the fourth quarter of 2011 was $2.17 per Mcfe compared to $1.37 per Mcfe for the same period in 2010. The fourth quarter 2011 DD&A rate includes $0.52 per Mcfe, or $1.1 million, of additional DD&A expense resulting from a reclassification of $63.8 million of unproved property cost in East Texas to the proved property pool during the latest quarter. The reclass was the result of the recent decline in natural gas prices and the associated planned reduction in 2012 dry gas drilling activity in East Texas.

 

General and administrative (G&A) expense was $2.8 million in the fourth quarter of 2011, down from $3.0 million for the fourth quarter of 2010, and includes non-cash stock-based compensation expense of $609,000 for the fourth quarter of 2011 and $413,000 for the fourth quarter of 2010.

 

Operations Review and Update

 

Capital expenditures during 2011 totaled $85.4 million and resulted in net reserve additions of 77.1 billion cubic feet of natural gas equivalent (Bcfe) for a finding cost of $1.11 per Mcfe.

 

Marcellus Shale

 

For the fourth quarter 2011, net production from the Marcellus Shale area averaged approximately 5.2 MMcfe per day, compared to 0.3 MMcfe per day for the fourth quarter of 2010 and 2.9 MMcfe per day in the third quarter of 2011.

 

In late November 2011 in Marshall County, West Virginia, the four-well Corley pad (40.5% working interest) was placed on production and in late December 2011, the three-well Simms pad (50.0% working interest) commenced production. As a result of the new wells, the net year-end exit rate for the Marcellus Shale area was approximately 10.4 MMcfe per day. Liquids production yields continue to average about 20 to 25 barrels of condensate and 45 to 50 barrels of natural gas liquids (NGLs) per million cubic feet of natural gas produced. Production from Marshall County continues to be constrained by third party gathering system issues related to condensate handling, dehydration limitations and high line pressures. The condensate handling issue was resolved in early March 2012 and the dehydration and high line pressure issues are expected to be resolved some time in April 2012.

 

 

Fracture stimulation operations have now been completed on the three-well Hall pad (40.2% working interest) and on the five-well Hendrickson pad (40.2% working interest). First production from the Hall wells commenced mid-January 2012 and the Hendrickson wells are anticipated to be on production in April 2012. Drilling operations are now complete on the five-well Burch Ridge pad (50.0% working interest) and the three-well Accettolo pad (50% working interest). Fracture stimulation operations are scheduled to commence on the Accettolo pad in April 2012 to be followed by the Burch Ridge pad.

 

In Butler County, Pennsylvania, we participated in seven non-operated wells (19.2% working interest). Three of the seven wells were placed on sales on December 1, 2011 but were subsequently shut-in to accommodate the fracture stimulation of the remaining four wells in January 2012. Fracture stimulation operations have been completed and the four wells were placed on production in February 2012. The remaining three wells should be returned to production by April 2012.

 

Our year-end 2011 proved reserves attributable to the Marcellus Shale were approximately 84.0 Bcfe, a significant increase from year-end 2010 reserves of 2.8 Bcfe. Marcellus Shale proved reserves at year-end 2011 represented approximately 70% of our total proved reserves and were comprised of approximately 33% of oil and NGLs reserves. Approximately 51% of the Marcellus Shale year-end 2011 reserves are proved developed.

 

Capital expenditures net to Gastar for the fourth quarter of 2011 in the Marcellus Shale were $19.9 million after realization of approximately $22.4 million of joint venture drilling carry benefit during the quarter associated with the Atinum Joint Venture. As of December 31, 2011, Atinum had funded its entire $40.0 million drilling carry obligation, resulting in Atinum earning a 50% interest in the joint venture assets.

 

For 2012, we have budgeted $103.0 million for drilling, completion, infrastructure, lease acquisition and seismic costs in the Marcellus Shale. Of that amount, $88.9 million will be devoted to drilling activities in the liquids-rich window of the Marcellus Shale and is expected to fund drilling and completion costs of 20 gross (10 net) new operated Marcellus Shale horizontal wells in Marshall County, along with the completion of 10 gross (4.5 net) additional operated Marcellus horizontal wells that were drilled and awaiting completion as of year-end 2011.

 

East Texas

 

In East Texas, fourth quarter 2011 net production from the Hilltop area averaged 15.5 MMcfe per day, down from 23.8 MMcfe per day in the fourth quarter of 2010. The lower volumes reflect natural declines in field production that were not offset by incremental production from newly completed wells.

 

Fourth quarter 2011 production volumes were down from the 16.6 MMcfe per day produced in the third quarter of 2011 due to no new wells being drilled or completed during the period and spending being limited in East Texas to recompletion and workover activity. While natural gas prices remain low, we plan to continue to limit capital activity in East Texas.

 

We will also closely watch the growing activity by other operators on nearby and adjacent acreage to develop various oil formations that may potentially underlie our acreage in East Texas. We believe it is most prudent at this time to allow other operators to more fully identify the potential of these oil plays and better develop drilling and completion techniques to economically produce these zones prior to our devoting additional capital to oil projects in East Texas. Nevertheless, we are encouraged by the developments we have observed.

 

 

At December 31, 2011, proved reserves attributable to the Hilltop area were approximately 34.3 Bcfe, representing approximately 29% of our total proved reserves and of which 100% is proved developed reserves.

 

Capital expenditures in for the fourth quarter of 2011 in East Texas were $3.4 million. In 2012, we have budgeted $6.6 million for East Texas, primarily for lease renewals and recompletions.

 

Production Guidance

 

In our news release in January, we estimated first quarter 2012 production to be in a range of 26 MMcfe per day to 28 MMcfe per day. Based on current operations, we are increasing our first quarter guidance to 27 MMcfe per day to 29 MMcfe per day of which 12 to 15% will be liquids production. Gastar’s operated production and sales in West Virginia have been impacted during the first quarter by issues with condensate handling, dehydration limitations and high line pressures on the third-party operated gathering system. An increase of dehydration capacity on the gathering system partially resolved some of the curtailment issues, and the condensate issues have been addressed. Additional compression is scheduled to be added in April, which should reduce line pressure resulting in higher production rates from existing wells. We believe the lower line pressure could result in increases in condensate and NGLs yields.

 

J. Russell Porter, Gastar's President and CEO, stated, “We are pleased with the significant progress we made in 2011 to demonstrate the value of our Marcellus Shale acreage, as confirmed by the 138% increase in our proved reserves and the 223% increase in our PV-10 value. In 2012, we believe that we will be able to convert our Marcellus Shale holdings into meaningful cash flow as we dramatically increase our production volumes and percentage of high value condensate, oil and NGLs.”

 

Liquidity and Capital Budget

 

At December 31, 2011, we had cash and cash equivalents of $10.6 million and a net working capital deficit of approximately $17.9 million. The working capital deficit includes $19.5 million of advances from non-operators, of which $1.5 million will be applied to Gastar’s net future share of costs pursuant to the carried interest provisions of the Atinum Joint Venture.

 

Availability under our revolving credit facility was $20.0 million at December 31, 2011. Effective March 5, 2012, the borrowing base under the Revolving Credit Facility was increased from $50.0 million to $100.0 million, resulting in current availability under the Revolving Credit Facility of $73.0 million.

 

Capital expenditures for 2012, excluding acquisitions, are projected to be approximately $134.2 million. We expect to spend $103.0 million in the Marcellus Shale, $6.6 million in East Texas, $19.8 million on a new Mid-Continent oil-focused venture and $4.8 million for capitalized interest and other costs. We plan on funding this capital activity through existing cash balances, internally generated cash flow from operating activities, borrowings under the Revolving Credit Facility and possible future at-the-market (“ATM”) issuances of Gastar USA Series A Preferred Stock.

 

 

Preferred Share Issuances

 

During the fourth quarter ended December 31, 2011, Gastar USA issued 554,044 preferred shares for net proceeds of $10.5 million resulting in year-end 2011 total preferred shares issued of 1,364,543 for net proceeds of $27.4 million. For the period January 1 to March 2, 2012, Gastar USA issued an additional 1,472,142 preferred shares for net proceeds of $28.0 million.

 

Conference Call

 

Gastar’s management team will hold a conference call at 10:00 a.m. Eastern Time (9:00 a.m. Central Time) on Friday, March 9, 2012 to discuss these results. To participate in the call, dial 480-629-9771 and ask for the Gastar conference call. A replay will be available and will be accessible through March 16, 2012. To access the replay, dial 303-590-3030 and enter the pass code 4521332#.

 

The call will also be webcast live over the Internet at www.gastar.com. To listen to the live call on the Internet, please visit Gastar’s web site at least 10 minutes early to register and download any necessary audio software. An archive will be available shortly after the call. For more information, please contact Donna Washburn at DRG&L at 713-529-6600 or e-mail dmw@drg-l.com.

 

About Gastar

 

Gastar is an independent energy company engaged in the exploration, development and production of natural gas and oil in the United States. Our principal business activities include the identification, acquisition, and subsequent exploration and development of natural gas and oil properties with an emphasis on unconventional natural gas reserves, such as shale resource plays. We are currently pursuing the development of liquids-rich natural gas in the Marcellus Shale in the Appalachia area of West Virginia and, to a lesser extent, central and southwestern Pennsylvania. We also hold prospective acreage in the deep Bossier gas play in the Hilltop area of East Texas and conduct limited coal bed methane development activities within the Powder River Basin of Wyoming and Montana. For more information, visit our web site at www.gastar.com.

 

 

Safe Harbor Statement and Disclaimer

 

This news release includes “forward looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward looking statements give our current expectations, opinion, belief or forecasts of future events and performance. A statement identified by the use of forward looking words including “may,” “expects,” “projects,” “anticipates,” “plans,” “believes,” “estimate,” “will,” “should,” and certain of the other foregoing statements may be deemed forward-looking statements. Although Gastar believes that the expectations reflected in such forward-looking statements are reasonable, these statements involve risks and uncertainties that may cause actual future activities and results to be materially different from those suggested or described in this news release. These include risks inherent in natural gas and oil drilling and production activities, including risks of fire, explosion, blowouts, pipe failure, casing collapse, unusual or unexpected formation pressures, environmental hazards, and other operating and production risks, which may temporarily or permanently reduce production or cause initial production or test results to not be indicative of future well performance or delay the timing of sales or completion of drilling operations; delays in receipt of drilling permits; risks with respect to natural gas and oil prices, a material decline in which could cause Gastar to delay or suspend planned drilling operations or reduce production levels; risks relating to the availability of capital to fund drilling operations that can be adversely affected by adverse drilling results, production declines and declines in natural gas and oil prices; risks relating to unexpected adverse developments in the status of properties; risks relating to the absence or delay in receipt of government approvals or fourth party consents; and other risks described in Gastar’s Annual Report on Form 10-K and other filings with the SEC, available at the SEC’s website at www.sec.gov. Our actual sales production rates can vary considerably from tested initial production rates depending upon completion and production techniques and our primary areas of operations are subject to natural steep decline rates. By issuing forward looking statements based on current expectations, opinions, views or beliefs, Gastar has no obligation and, except as required by law, is not undertaking any obligation, to update or revise these statements or provide any other information relating to such statements.

 

Gastar’s capital budget is subject to revision and reevaluation dependent upon future developments including drilling results, availability of crews, supplies and production capacity, weather delays, significant changes in commodities prices or drilling costs.

 

Year-end pre-tax discounted present value of proved reserves, or PV-10, is a non-GAAP financial measure as defined by the SEC. It differs from Standardized Measure of Discounted Future Net Cash Flows (“SMOG”) in that PV-10 excludes the discounted value of estimated future income taxes. We believe that the presentation of PV-10 is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account corporate future income taxes and our current tax structure. We further believe investors and creditors use PV-10 as a basis for comparison of the relative size and value of our reserves as compared with other companies. The discounted value of future income taxes will be evaluated and estimated in connection with the completion of Gastar’s 2011 financial statements and a reconciliation of PV-10 to SMOG will be included in Gastar’s Form 10-K.

 

- Financial Tables Follow -

 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

 

		For the Three Months Ended December 31,								For the Year Ended December 31,
		2011				2010				2011				2010
		(in thousands, except share and per share data)
REVENUES:
Natural gas		$	8,207			$	9,155			$	33,391			$	30,812
Oil			709				247				3,416				742
NGLs			853				-				1,092				-
Total natural gas, oil and NGLs revenues			9,769				9,402				37,899				31,554
Unrealized natural gas hedge gain (loss)			1,309				(2,679	)			2,336				11,214
Total revenues			11,078				6,723				40,235				42,768
EXPENSES:
Production taxes			236				70				620				370
Lease operating expenses			2,685				1,473				8,630				6,679
Transportation, treating and gathering			1,147				1,146				4,501				4,654
Depreciation, depletion and amortization			4,419				3,238				15,216				9,306
Accretion of asset retirement obligation			142				104				534				396
General and administrative expense			2,789				3,020				11,365				14,638
Litigation settlement expense			-				594				-				21,744
Total expenses			11,418				9,645				40,866				57,787
LOSS FROM OPERATIONS			(340	)			(2,922	)			(631	)			(15,019	)
OTHER INCOME (EXPENSE):
Interest expense			(26	)			(30	)			(113	)			(150	)
Investment income and other			3				4				10				1,347
Unrealized warrant derivative gain			-				-				-				205
Foreign transaction gain (loss)			(1	)			4				(6	)			353
LOSS BEFORE PROVISION FOR INCOME TAXES			(364	)			(2,944	)			(740	)			(13,264	)
Provision for income tax expense (benefit)			-				-				-				(804	)
NET LOSS		$	(364	)		$	(2,944	)		$	(740	)		$	(12,460	)
Dividend on preferred stock attributable to non-controlling interest			605				-				1,024				-
NET LOSS ATTRIBUTABLE TO GASTAR EXPLORATION LTD.		$	(969	)		$	(2,944	)		$	(1,764	)		$	(12,460	)
NET LOSS PER COMMON SHARE ATTRIBUTABLE TO GASTAR EXPLORATION LTD. COMMON SHAREHOLDERS:
Basic		$	(0.02	)		$	(0.06	)		$	(0.03	)		$	(0.25	)
Diluted		$	(0.02	)		$	(0.06	)		$	(0.03	)		$	(0.25	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic			63,305,419				52,066,371				63,003,579				49,813,617
Diluted			63,305,419				52,066,371				63,003,579				49,813,617

 

 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

 

CONSOLIDATED BALANCE SHEETS

 

		December 31,
		2011				2010
		(in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	10,647			$	7,439
Accounts receivable, net of allowance for doubtful accounts of $551 and $571, respectively			10,706				4,034
Commodity derivative contracts			19,385				10,229
Prepaid expenses			1,243				1,191
Total current assets			41,981				22,893
PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, full cost method of accounting:
Unproved properties, excluded from amortization			78,302				162,230
Proved properties			514,357				345,042
Total natural gas and oil properties			592,659				507,272
Furniture and equipment			1,629				1,175
Total property, plant and equipment			594,288				508,447
Accumulated depreciation, depletion and amortization			(308,548	)			(293,332	)
Total property, plant and equipment, net			285,740				215,115
OTHER ASSETS:
Restricted cash			50				50
Commodity derivative contracts			4,130				8,482
Deferred charges, net			535				508
Drilling advances and other assets			2,067				304
Total other assets			6,782				9,344
TOTAL ASSETS		$	334,503			$	247,352
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable		$	17,693			$	8,294
Revenue payable			4,137				4,331
Accrued interest			144				138
Accrued drilling and operating costs			4,647				1,490
Advances from non-operators			19,523				783
Commodity derivative contracts			6,479				1,991
Commodity derivative premium payable			4,725				3,451
Accrued litigation settlement liability			800				3,164
Other accrued liabilities			1,723				2,024
Total current liabilities			59,871				25,666
LONG-TERM LIABILITIES:
Long-term debt			30,000				-
Commodity derivative contracts			1,163				1,521
Commodity derivative premium payable			-				4,725
Accrued litigation settlement liability			-				800
Asset retirement obligation			8,275				7,249
Total long-term liabilities			39,438				14,295
Commitments and contingencies
SHAREHOLDERS' EQUITY:
Common stock, no par value; unlimited shares authorized; 64,706,750 and 64,179,115 shares issued and outstanding at December 31, 2011 and 2010, respectively			316,346				316,346
Additional paid-in capital			25,376				23,200
Accumulated deficit			(133,919	)			(132,155	)
Total shareholders' equity			207,803				207,391
Non-controlling interest:
Preferred stock of subsidiary, aggregate liquidation preference $34,114 at December 31, 2011			27,391				-
Total equity			235,194				207,391
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY		$	334,503			$	247,352

 

 

 

 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES 

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

		Years Ended December 31,
		2011				2010
		(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss		$	(740	)		$	(12,460	)
Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities:
Depreciation, depletion and amortization			15,216				9,306
Stock-based compensation			2,612				2,765
Unrealized natural gas hedge gain			(2,336	)			(11,214	)
Realized loss (gain) on derivative contracts			(1,735	)			1,437
Amortization of deferred financing costs and debt discount			249				283
Accretion of asset retirement obligation			534				396
Unrealized warrant derivative gain			-				(205	)
Dividend on preferred stock attributable to non-controlling interest			(1,024	)			-
Litigation settlement payable			-				3,150
Changes in operating assets and liabilities:
Accounts receivable			(6,672	)			1,565
Commodity derivative contracts			(54	)			1,232
Prepaid expenses			(100	)			(522	)
Accrued taxes payable			-				(1,420	)
Accounts payable and accrued liabilities			4,303				(385	)
Net cash provided by (used in) operating activities			10,253				(6,072	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Development and purchase of natural gas and oil properties			(73,718	)			(58,512	)
Advances to operators			(8,392	)			(300	)
Acquisition of natural gas and oil properties			-				(28,887	)
Proceeds from sale of natural gas and oil properties			-				49,197
Proceeds from non-operators			18,740				98
Purchase of furniture and equipment			(454	)			(308	)
Purchase of term deposit			-				(4,855	)
Net cash used in investing activities			(63,824	)			(43,567	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of common shares, net of issuance costs			-				52,537
Proceeds from revolving credit facility			71,000				42,000
Repayment of revolving credit facility			(41,000	)			(42,000	)
Repayment of short-term loan			-				(17,000	)
Proceeds from issuance of preferred stock, net of issuance costs			27,391				-
Deferred financing charges			(276	)			(27	)
Other			(336	)			(298	)
Net cash provided by financing activities			56,779				35,212
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS			3,208				(14,427	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD			7,439				21,866
CASH AND CASH EQUIVALENTS, END OF PERIOD		$	10,647			$	7,439

 

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

PRODUCTION AND PRICES

 

		For the Three Months Ended								For the Years Ended
		December 31,								December 31,
		2011				2010				2011				2010
Production:
Natural gas (MMcf)			1,881				2,350				7,318				7,593
Oil (MBbl)			9				3				40				10
NGLs (MBbl)			16				-				21				-
Total production (MMcfe)			2,035				2,369				7,684				7,654
Total (MMcfed)			22.1				25.8				21.1				21.0
Average sales price per unit:
Natural gas per Mcf, excluding impact of realized hedging activities		$	2.66			$	3.01			$	3.21			$	3.51
Natural gas per Mcf, including impact of realized hedging activities		$	4.36			$	3.90			$	4.56			$	4.06
Oil per Bbl		$	76.22			$	77.09			$	85.11			$	72.63
NGLs per Bbl		$	52.35			$	-			$	52.47			$	-

 

NON-GAAP FINANCIAL INFORMATION AND RECONCILIATION

 

We use both GAAP and certain non-GAAP financial measures to assess performance. Generally, a non-GAAP financial measure is a numerical measure of a company’s performance, financial position or cash flows that either excludes or includes amounts that are not normally excluded or included in the most directly comparable measure calculated and presented in accordance with GAAP. Our management believes that these non-GAAP measures provide useful supplemental information to investors in order that they may evaluate our financial performance using the same measures as management. These non-GAAP financial measures should not be considered as a substitute for, or superior to, measures of financial performance prepared in accordance with GAAP. In evaluating these measures, investors should consider that the methodology applied in calculating such measures may differ among companies and analysts. A reconciliation is provided below outlining the differences between these non-GAAP measures and the directly related GAAP measures.

 

Reconciliation of Net Income (Loss) to Net Income (Loss) Excluding Special Items:

 

		For the Three Months Ended December 31,								For the Year Ended December 31,
		2011				2010				2011				2010
		(in thousands, except share and per share data)
NET LOSS ATTRIBUTABLE TO GASTAR EXPLORATION LTD. AS REPORTED		$	(969	)		$	(2,944	)		$	(1,764	)		$	(12,460	)
SPECIAL ITEMS:
Unrealized natural gas hedge (gain) loss			(1,309	)			2,679				(2,336	)			(11,214	)
Litigation settlement expense			-				594				-				21,744
Unrealized warrant derivative (gain) loss			-				-				-				(205	)
Foreign transaction gain			1				(4	)			6				(353	)
Provision for income tax expense (benefit)			-				-				-				(804	)
ADJUSTED NET INCOME (LOSS) ATTRIBUTABLE TO GASTAR EXPLORATION LTD.		$	(2,277	)		$	325			$	(4,094	)		$	(3,292	)
ADJUSTED NET INCOME (LOSS) PER SHARE ATTRIBUTABLE TO GASTAR EXPLORATION LTD. COMMON SHAREHOLDERS:
Basic		$	(0.04	)		$	0.01			$	(0.06	)		$	(0.07	)
Diluted		$	(0.04	)		$	0.01			$	(0.06	)		$	(0.07	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic			63,305,419				52,066,371				63,003,579				49,813,617
Diluted			63,305,419				52,600,673				63,003,579				49,813,617

 

 

Reconciliation of Cash Flow from Operations Before Working Capital Changes and Special Items:

 

		For the Three Months Ended December 31,								For the Year Ended December 31,
		2011				2010				2011				2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss		$	(364	)		$	(2,944	)		$	(740	)		$	(12,460	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization			4,419				3,238				15,216				9,306
Impairment of natural gas and oil properties			-				-				-				-
Stock-based compensation			609				413				2,612				2,765
Unrealized natural gas hedge (gain) loss			(1,309	)			2,679				(2,336	)			(11,214	)
Realized (gain) loss on derivative contracts			(432	)			(167	)			(1,735	)			1,437
Amortization of deferred financing costs and debt discount			56				63				249				283
Accretion of asset retirement obligation			142				104				534				396
Unrealized warrant derivative gain			-				-				-				(205	)
Dividend on preferred stock attributable to non-controlling interest			(605	)			-				(1,024	)			-
Litigation settlement payable			-				(18,000	)			-				3,150
Cash flow from (used in) operations before working capital changes (1)			2,516				(14,614	)			12,776				(6,542	)
Litigation settlement expense adjusted for payable			-				18,594				-				18,594
Early extinguishment of debt			-				-				-				-
Foreign transaction gain			1				(4	)			6				(353	)
Provision for income tax benefit			-				-				-				(804	)
Adjusted cash flow from operations for special items		$	2,517			$	3,976			$	12,782			$	10,895

 

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