8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(D)

OF THE SECURITIES EXCHANGE ACT OF 1934

Date of Report (Date of earliest event reported): May 7, 2013 (May 7, 2013)

Commission File Number: 001-32714

Commission File Number: 001-35211

GASTAR EXPLORATION LTD.

GASTAR EXPLORATION USA, INC.

(Exact Name of Registrant as Specified in its Charter)

Alberta, Canada	98-0570897
Delaware	38-3531640
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
1331 Lamar Street, Suite 650
Houston, Texas	77010
(Address of principal executive offices)	(ZIP Code)

(713) 739-1800

(Registrant’s telephone number, including area code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

SECTION 7 – REGULATION FD

Item 7.01 Regulation FD Disclosure

Exhibit 99.1 to this Current Report sets forth certain information regarding Gastar Exploration USA, Inc. (“Gastar USA”), a subsidiary of Gastar Exploration Ltd. (the “Parent”).

In accordance with General Instruction B.2 of Form 8-K, the information presented herein under Item 7.01 and set forth in the attached Exhibit 99.1 shall not be deemed to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to the liability of that section, and is not to be incorporated by reference into any filing of Gastar USA or the Parent under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such a filing.

SECTION 9 – FINANCIAL STATEMENTS AND EXHIBITS

Item 9.01 Financial Statements and Exhibits

(d) Exhibits

The following is a list of exhibits furnished as part of this Form 8-K:

Exhibit No.	Description of Document
99.1	Information Regarding Gastar Exploration USA, Inc.

SIGNATURES

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

Date: May 7, 2013	GASTAR EXPLORATION LTD.
	By:	/s/ J. Russell Porter
		J. Russell Porter
		President and Chief Executive Officer
	GASTAR EXPLORATION USA, INC.
	By:	/s/ J. Russell Porter
		J. Russell Porter
		President

EXHIBIT INDEX

Exhibit No.	Description of Document
99.1	Information Regarding Gastar Exploration USA, Inc.

EX-99.1

Exhibit 99.1

This Exhibit 99.1 sets forth certain information regarding Gastar Exploration USA, Inc. (the “Company,” “Gastar,” “we,” us,” or “our”) and Gastar Exploration Ltd. (the “Parent”). Unless otherwise stated herein, pro forma financial, reserve and production information and 2013 estimates assume the successful completion of the Chesapeake Transaction (as defined herein) and related financing and the successful completion of the East Texas Divestiture (as defined herein) and use of proceeds therefrom.

We are proposing to acquire an additional significant position in the Hunton Limestone horizontal oil play from affiliates of Chesapeake Energy Corporation (“Chesapeake”) (the “Mid-Continent Acquisition”), which will complement our existing position and provide for additional future drilling opportunities. Additionally, we will be divesting all of our existing acreage in the deep Bossier play in the Hilltop area of East Texas (the “East Texas Divestiture”). Pro forma for these pending transactions, we will control a total of 70,600 net acres in the Marcellus Shale and 179,200 net acres in the Mid-Continent area, subject to election by our current operator to participate in the acquisition of approximately 12,800 net acres of the Chesapeake Mid-Continent acreage that is located within our existing Mid-Continent areas of mutual interest with our current operator (“AMI”).

The Mid-Continent Acquisition and the East Texas Divestiture are expected to close on June 7, 2013 and June 5, 2013, respectively, subject to satisfaction of customary closing conditions and adjustments.

Our Properties

The following table presents summary data for each of our primary areas of development as of March 31, 2013, unless otherwise indicated, each on a pro forma basis to reflect the Mid-Continent Acquisition and the East Texas Divestiture.

			Identified Drilling Locations  (1)		2013 Budget						Estimated Net Proved Reserves as of December 31, 2012					First Quarter 2013 Average Daily Production
	Net Acreage		Net(5)		Gross Wells		Net Wells		Drilling Capex (in millions)		MMcfe		Developed (%)			(Mcfe/d)		(Boe/d)
Marcellus Shale, West Virginia and Pennsylvania:
Marcellus West		20,900		55		19		9.5	$	52.4		152,909		65	%		28,097		4,683
Marcellus East		49,700		—		—		—		—		265		100	%		509		85
Hilltop area, East Texas(2)		16,300		—		—		—		0.1		27,449		100	%		11,000		1,833
Mid-Continent
Existing		22,200		65		8		4		20.8		286		100	%		902		150
Chesapeake Acquisition(3)(4)		157,000		210		4		2		8.9		15,534		100	%		4,871		812
Pro forma total prior to East Texas Divestiture(2)(3)		266,100		330		31		15.5		82.2		196,443		72	%		45,379		7,563
Pro forma total after East Texas Divestiture(3)		249,800		330		31		15.5		82.1		168,994		68	%		34,379		5,730

⁽¹⁾  Our identified potential drilling locations in the Marcellus Shale area are actual surface locations that have been specifically identified by management for future drilling units based on an evaluation of applicable geological, seismic, engineering, production and reserve data on nearby acreage and geological formations, including successful drilling efforts by other operators in the area. In identifying potential drilling locations in the Marcellus Shale area, we have assumed 400-foot well spacing, which we have recently successfully tested. Potential drilling locations in the Mid-Continent area have been identified along the geological trend believed to be most prospective for middle and lower Hunton Limestone development, which is supported by information from thousands of vertical wells that intersect the Hunton Limestone formation and by recent horizontal drilling along the trend by us, our operating partner and other operators. In identifying potential drilling locations in the Mid-Continent area, the number of locations is based upon 320-acre well spacing and drainage. Under Oklahoma forced pooling rules, we believe that all available net acres identified along the geological trend can be utilized. We have not committed to drill any specific number of our potential drilling locations. Our identified potential drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, which in certain instances could prevent production prior to the expiration date of leases for such locations. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill a substantial portion of our identified potential drilling locations.

⁽²⁾  Includes estimated acreage, drilling locations, reserves and production associated with oil and gas properties to be sold in the East Texas Divestiture.

⁽³⁾  Includes estimated acreage, drilling locations, reserves and production associated with the assets proposed to be purchased in connection with the Mid-Continent Acquisition. The AMIs in our joint venture with our current operator in the Mid-Continent area cover approximately 25,000 net acres to be acquired in the Mid-Continent Acquisition. Our current operator will have the right to participate in the acquisition of 50% of the proved reserves and leasehold within the existing AMIs on the same terms that we will acquire these interests. Proved reserves associated with the acreage acquired in the Mid-Continent Acquisition located within our existing AMIs were approximately 4,928 MMcfe (821 MBoe) as of December 31, 2012, all of which were proved developed reserves.

⁽⁴⁾  As of December 31, 2012, SEC proved reserves associated with the assets proposed to be acquired in the Mid-Continent Acquisition were approximately 15,534 MMcfe (2.6 MMBoe), all of which were proved developed reserves.

⁽⁵⁾  Of the 330 net pro forma total drilling locations, 26 gross (13 net) locations were associated with proved reserves.

        Our capital plan calls for approximately $82.5 million of drilling, completion and infrastructure costs in 2013, which will provide for 19 gross (9.5 net) horizontal wells in the Marcellus Shale and 12 gross (six net) horizontal wells, assuming a 50% joint venture partner, in the Mid-Continent area. We believe these Marcellus Shale wells will be completed by the end of the second quarter of 2013 at an average gross cost of approximately $7.0 million. We plan to drill up to 23 gross horizontal Marcellus Shale wells during 2014. We anticipate we will complete the drilling of our planned wells in the Hunton Limestone play by the end of 2013 at an average gross cost of approximately $5.2 million.

We are scheduled to bring on production an additional 19 gross (9.5 net) Marcellus Shale wells by the second quarter of 2013, bringing our total producing well count in the Marcellus Shale to 57 gross (26.9 net) wells, and have identified approximately 55 net additional potential horizontal drilling opportunities on our liquids-rich Marcellus Share area leasehold. Additionally, we have identified 65 net drilling locations in our property in the Hunton Limestone play, with an additional 210 net drilling locations in the Chesapeake Assets, of which 12 gross (six net) wells, assuming a 50% joint venture partner, are scheduled to be completed in 2013.

1

Certain Historical and Pro Forma Financial Data

The following tables set forth certain historical consolidated financial data for the years ended December 31, 2010, 2011 and 2012, the three months ended March 31, 2012 and 2013 and the twelve months ended March 31, 2013. The annual historical financial data are derived from our audited consolidated financial statements and the notes thereto included in our periodic reports filed with the SEC under the Securities Exchange Act of 1934, as amended (our “Periodic Reports”). The data for the three months ended March 31, 2012 and 2013 are derived from our unaudited condensed consolidated financial statements included in our Periodic Reports. The data for the twelve months ended March 31, 2013 are derived from our audited and unaudited condensed consolidated financial statements included in our Periodic Reports and our accounting records, which are also unaudited. This data should be read in conjunction with, and is qualified in its entirety by reference to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and the notes thereto included in our Periodic Reports.

The pro forma financial data presented for the year ended December 31, 2012 and as of and for the twelve months ended March 31, 2013 are derived from our pro forma condensed consolidated financial statements included herein.

The pro forma balance sheet data at March 31, 2013 has been prepared assuming the transactions listed below occurred as of March 31, 2013. The pro forma statement of operations data for the year ended December 31, 2012 and the twelve months ended March 31, 2013 has been prepared assuming the transactions listed below occurred as of January 1, 2012. The pro forma financial data give pro forma effect to:

• the Mid-Continent Acquisition, litigation settlement with Chesapeake and the repurchase of common shares of our Parent currently held by Chesapeake (the “Chesapeake Transaction”); and

• the East Texas Divestiture and the application of the net proceeds therefrom.

The pro forma financial data have been prepared for illustrative purposes only and do not purport to be indicative of the actual results for the period indicated or that may be realized in the future. Although management believes the assumptions used in preparing these pro forma financial results are reasonable, these assumptions may not be correct. As a result, actual results could differ materially. These pro forma financial statements should be read in conjunction with, and are qualified in their entirety by reference to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and the notes thereto included in our Periodic Reports. The pro forma data below include the pro forma effects of the East Texas Divestiture, the closing of which is not a condition to any debt financing in connection with the closing of the Chesapeake Transaction. See “Unaudited Condensed Combined Pro Forma Financial Statements” for pro forma financial information assuming the East Texas Divestiture is not consummated.

Pro forma adjustments for Adjusted EBITDA and Normalized Adjusted EBITDA give effect to the Chesapeake Transaction and related financing and the East Texas Divestiture as if they had occurred at January 1, 2012. The historical financial statements of revenues and direct operating expenses for the assets acquired in the Mid-Continent Acquisition (the “Chesapeake Assets”) used as the basis for the pro forma adjustments for the Mid-Continent Acquisition do not include revenues and direct operating expenses attributable to certain small interests in the Chesapeake Assets being sold by entities controlled by the former chief executive officer of Chesapeake, which interests Gastar estimates would not represent more than two percent of corresponding revenues and direct operating expenses for such reported period of the Chesapeake Assets being sold by Chesapeake.

Pro forma adjustments for the twelve months ended March 31, 2013 includes pro forma adjustments for the Mid-Continent Acquisition based on the Company’s preliminary estimates of revenues and direct operating expenses for the Chesapeake Assets for the three months ended March 31, 2013, which utilized one month of actual production, revenues and direct operating expense data and two months of estimates by our management based on historical averages.

Actual results for the Chesapeake Assets for such period may differ. When we prepare historical financial information relating to the assets being acquired from Chesapeake and the related pro forma financial information in compliance with Regulation S-X, the presentation of this financial information and the related pro forma financial information may change materially from that presented herein.

2

The following table reconciles net loss in accordance with GAAP to EBITDA, Adjusted EBITDA and Normalized Adjusted EBITDA:

											Pro Forma(1)
	Year Ended December 31,						Three Months Ended March 31,				Twelve Months Ended December 31, 2012		Twelve Months Ended March 31, 2013
	2010		2011		2012		2012		2013
	(audited)						(unaudited)
	(in thousands)
Net loss attributable to common stockholder	$	(11,548)		$(739)	$	(159,399)	$	(5,922)		$(4,361)	$	(160,969)	$	(161,570)
Plus:
Dividends on Preferred Stock		—		1,024		7,077		1,236		2,130		7,077		7,971
Depreciation, depletion and amortization		9,306		15,216		25,424		5,653		5,365		20,498		21,646
Impairment of natural gas and oil properties		—		—		150,787		—		—		150,787		150,787
Interest expense		97		112		271		28		609		11,589		11,858
Income tax benefit		(804)		—		—		—		—		—		—
EBITDA(2)		(2,949)		15,613		24,160		995		3,743		28,982		30,692
Other adjustments:
Accretion of asset retirement obligation		396		534		388		94		102		369		381
Stock option expense		2,765		2,612		3,295		892		823		3,295		3,226
Litigation settlement expense(3)		21,744		—		1,250		1,250		1,000		1,250		1,000
Investment income and other		(1,238)		(95)		4		(2)		(5)		4		1
Foreign transaction gain(4)		(354)		(1)		(2)		(2)		(1)		(2)		(1)
Unrealized hedge (gain) loss		(11,214)		(2,336)		5,566		1,524		9,637		5,566		13,679
Adjusted EBITDA(2)		$9,150		$16,327		$34,661		$4,751		$15,299		$39,464		$48,978
Impact from unscheduled downtime(5)		—		—		7,080		1,738		6,686		7,080		12,027
Normalized Adjusted EBITDA(6)		$9,150		$16,327		$41,741		$6,489		$21,958		$46,544		$61,005

(1) Pro forma adjustments give effect to the Chesapeake Transaction and related financing and the East Texas Divestiture, as if they had occurred at January 1, 2012. The historical financial statements of revenues and direct operating expenses for the Chesapeake Assets used as the basis for the pro forma adjustments for the Mid-Continent Acquisition do not include revenues and direct operating expenses attributable to certain small interests in the Chesapeake Assets being sold by entities controlled by the former chief executive officer of Chesapeake, which interests Gastar estimates would not represent more than two percent of corresponding revenues and direct operating expenses for such reported period of the Chesapeake Assets being sold by Chesapeake.

Pro forma adjustments for the twelve months ended March 31, 2013 includes pro forma adjustments for the Mid-Continent Acquisition based on the Company’s preliminary estimates of revenues and direct operating expenses for the Chesapeake Assets for the three months ended March 31, 2013. Actual results for the Chesapeake Assets for such period may differ. When we prepare historical financial information relating to the assets being acquired from Chesapeake and the related pro forma financial information in compliance with Regulation S-X, the presentation of this financial information and the related pro forma financial information may change materially from that presented in herein.

(2) EBITDA and Adjusted EBITDA are not alternative measures of operating results of cash flows from operations, as determined in accordance with GAAP. We have included EBITDA and Adjusted EBITDA because we believe they are indicative measures of operating performance and our ability to meet our debt service requirements and are used by investors and analysts to evaluate companies with our capital structure. As presented by us, EBITDA and Adjusted EBITDA may not be comparable to similarly titled measures reported by other companies. EBITDA and Adjusted EBITDA should be considered in addition to, not as a substitute for, operating income, net income (loss), cash flow and other measures of financial performance and liquidity reported in accordance with GAAP.

(3) Litigation settlement expense for fiscal year 2010 primarily resulted from our settlement with the plaintiffs in the ClassicStar Mare Lease litigation suits in December 2010. Litigation settlement expense for fiscal year 2012 primarily resulted from our settlement with Navasota Resources LP in April 2012. Litigation settlement expense for the three months ended March 31, 2013 resulted from an accrual for settlement of the Chesapeake litigation.

(4) Foreign exchange gain for fiscal year 2010 primarily resulted from Australian denominated cash and accounts receivable balances. The Australian properties were sold in 2009.

(5) Represents an adjustment to reflect the estimated impact of unscheduled downtime from mid-stream assets which service our Marcellus West properties, which includes incremental production for the unscheduled downtime assuming an average daily production rate equal to the average daily production immediately prior to the downtime at our actual average monthly sales prices. Our five day average gross production as of April 30, 2013 was 72.2 MMcf per day, which is 54% higher than our first quarter 2013 average gross production of 47.0 MMcf/d. In addition, we have developed a plan that could be implemented prior to year end whereby a new third party would handle all of our condensate production, resulting in an increase in gross natural gas and condensate production rates and condensate pricing. Normalized Adjusted EBITDA is not an alternative measure of operating result of cash flows from operations, as determined in accordance with GAAP, nor does it represent our actual operating results for the periods presented.

(6) Normalized Adjusted EBITDA further adjusts Adjusted EBITDA to reflect for illustrative purposes only our management estimate of what our operating performance would have been for the applicable periods if there had not been production curtailments related to high line pressures and unscheduled downtime of mid-stream assets owned and operated by Williams which service our Marcellus West properties. We are continuing to work with the gathering system operator to resolve recurring production curtailment issues on our operated Marcellus Shale wells; however, there can be no assurance that such issues can be fully ameliorated quickly, or at all.

3

Summary Historical and Pro Forma Reserve Data

The following tables summarize our historical and pro forma oil and natural gas proved reserves and present values as of the dates indicated. Our historical reserve information has been derived from reserve reports prepared by Wright & Company, Inc. (“Wright”) and Netherland, Sewell & Associates, Inc. (“NSAI”). Wright has made the proved reserve estimates for our Marcellus Shale and other Appalachia area and our Mid-Continent area as of December 31, 2012. NSAI has evaluated the reserve estimates for our Hilltop Area of East Texas as of December 31, 2012, which properties are subject to the pending East Texas Divestiture. Estimated proved reserve data for the Chesapeake Assets as of January 1, 2013 was prepared by Wright, which we expect to acquire in the Mid-Continent Acquisition.

SEC Case Reserves

Definitions and guidelines established by the SEC regarding the present value of future net cash flows were utilized to prepare the estimates in the table below. Estimates of reserves and their value are inherently imprecise and are subject to constant revision and change, and they should not be construed as representing the actual quantities of future production or cash flows to be realized from oil and natural gas properties or the fair market value of such properties.

	Historical Gastar		Pro Forma Gastar for Chesapeake Transaction(1)		Pro Forma Gastar for Chesapeake Transaction and East Texas Divestiture(1)
Proved Reserves—SEC Case(2)
Natural gas (MMcf)		131,010		141,985		114,629
NGLs (MBbls)		4,922		5,226		5,226
Condensate and oil (MBbls)		3,394		3,851		3,835
Total proved reserves (MMcfe)		180,909		196,443		168,994
Proved developed reserves (MMcfe)		126,653		142,187		114,738
SEC PV-10 (in thousands)(3)	$	206,809	$	230,382	$	217,596

(1) Pro forma estimated proved reserve data includes proved reserve data for the Chesapeake Assets as of January 1, 2013 prepared by Wright using an unweighted average of the first-day-of-the-month prices for the year ended December 31, 2012.

(2) Our estimated proved reserves and related future net revenues and PV-10 at December 31, 2012 were determined using benchmark prices that are the 12-month unweighted arithmetic average of the first-day-of-the-month prices for natural gas and oil. Key natural gas prices utilized were the Henry Hub price of $2.76 per MMBtu, the Katy Hub price of $2.77 per MMBtu and the Columbia Gas Appalachia Pool price of $2.77 per MMBtu. NSAI utilized an average West Texas Intermediate (“WTI”) posted oil price of $91.21 per barrel, and Wright utilized a WTI spot oil price of $94.71 per barrel. Our reserve engineers utilized an NGLs per Bbl price of 33.5% of the WTI spot oil price. These prices are held constant in accordance with SEC definitions and guidelines for the life of the wells included in the reserve reports but are adjusted by lease in accordance with sales contracts and for energy content, quality, transportation, compression and gathering fees and regional price differentials. Estimated quantities of proved reserves and future net revenues are affected by natural gas and oil prices, which have fluctuated significantly in recent years. All of our proved reserves are located onshore within the United States.

(3) PV-10 represents the present value, discounted at 10% per annum, of estimated future net revenue to be generated from the production of proved reserves before income tax. PV-10 is a non-GAAP financial measure because it excludes the effect of income taxes, which effect is included in standardized measure of discounted future net cash flows as defined under GAAP, which we refer to as standardized measure. We believe that PV-10 is a useful measure for evaluating the relative monetary significance of oil and natural gas properties. Further, investors may use the measure as a basis for comparison of the relative size and value of our reserves to other companies. PV-10 should not be considered as an alternative to standardized measure. We presently have approximately $254.3 million of net operating loss carryforwards, $50.6 million of foreign tax credit carryforwards and $211.1 million of remaining property tax basis for Federal income tax purposes. Based on those carryforwards and current and future property tax basis, we will not incur future income taxes, and as such, the standardized measure of our proved reserves is equal to its PV-10 value. Assuming that Chesapeake’s tax rates would be the same as ours, the standardized measure of discounted future net cash flows attributable to the Chesapeake Assets would be $23.6 million.

4

NYMEX Case Reserves

The following table illustrates the price sensitivity of our estimated proved natural gas and oil reserves as of December 31, 2012 and related PV-10 changes in product price levels. The reserve quantities and PV-10 shown below were prepared on the same basis as in the table above, except for the use of pricing based on closing monthly futures prices on the NYMEX for oil and natural gas on December 31, 2012 rather than the unweighted average of the first-day-of-the-month prices for the prior 12 months as specified by the SEC. In our NYMEX case, oil prices in effect for December 2021 and thereafter were held constant and natural gas prices in effect for December 2025 and thereafter were held constant. We believe that the use of forward prices provides investors with additional useful information about our reserves, as the forward prices are based on the market’s forward-looking expectations of oil and natural gas prices as of a certain date. NGLs and condensate pricing in this was based on a fixed historical average percentage of the applicable future WTI price. Investors should be careful to consider forward prices in addition to, and not as a substitute for, SEC prices, when considering our oil and natural gas reserves. The assumed lease and well operating costs included in the pricing sensitivity are based on our historical lease and well operating costs and have been held constant throughout the life of the properties. The assumed capital and abandonment costs were held constant to the date of the expenditure. Based on SEC pricing, the pro forma PV-10 of our proved oil and natural gas reserves at December 31, 2012 was approximately $218 million while, based on NYMEX forward pricing at December 31, 2012, as set forth below, the pro forma PV-10 of our proved oil and natural gas reserves at December 31, 2012 was approximately $322 million.

	Historical Gastar		Pro Forma Gastar for Chesapeake Transaction(1)		Pro Forma Gastar for Chesapeake Transaction and East Texas Divestiture(1)
Proved Reserves—NYMEX Case(2)
Natural gas (MMcf)		140,166		153,185		118,022
NGLs (MBbls)		4,967		5,277		5,277
Condensate and oil (MBbls)		3,401		3,905		3,889
Total proved reserves (MMcfe)		190,376		208,275		173,020
Proved developed reserves (MMcfe)		136,120		154,019		118,764
NYMEX PV-10 (in thousands)(3)	$	333,242	$	367,418	$	321,795

(1) Pro forma estimated proved reserve data includes reserve data for the Chesapeake Assets as of January 1, 2013 prepared by Wright using NYMEX strip pricing described above as of December 31, 2012.

(2) Our NYMEX case estimated proved reserves and related future net revenues and PV-10 at December 31, 2012 were determined using index prices for oil and natural gas, without giving effect to derivative transactions. At December 31, 2012, the futures prices for benchmark commodities used in our NYMEX case reserve estimates were $3.54/MMBtu for natural gas and $92.88/Bbl for oil for the production year ended December 31, 2013, and $5.42/MMBtu for natural gas and $86.81/Bbl for oil for the production years thereafter. These prices were adjusted by lease for quality, transportation fees, historical geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. NGLs and condensate pricing on our NYMEX case was based on a fixed historical average percentage of the applicable future WTI price.

(3) For additional information about our SEC PV-10 and standardized measure, please read footnote 3 to the table above under “Summary Historical and Pro Forma
Reserve Data—SEC Case Reserves.”

5

Summary Historical and Pro Forma Production Data

The following table summarizes our historical and pro forma net production volumes, natural gas and oil sales, and average sales prices for the periods indicated:

	Year Ended December 31, 2012						Three Months Ended March 31, 2013
	Historical Gastar		Pro Forma Gastar for Chesapeake Transaction		Pro Forma Gastar for Chesapeake Transaction and East Texas Divestiture		Historical Gastar		Pro Forma Gastar for Chesapeake Transaction		Pro Forma Gastar for Chesapeake Transaction and East Texas Divestiture
Production:
Natural gas (MMcf)		10,564		12,038		7,124		2,699		3,016		2,047
Condensate and oil (MBbls)		177		262		247		78		93		90
NGLs (MBbls)		270		293		293		80		85		85
Total production (MMcfe)		13,247		15,367		10,362		3,646		4,084		3,094
Daily production:
Natural gas (MMcf/d)		28.9		32.9		19.5		30.0		33.5		22.7
Condensate and oil (MBbls/d)		0.5		0.7		0.7		0.9		1.0		1.0
NGLs (MBbls/d)		0.7		0.8		0.8		0.9		0.9		0.9
Total production (MMcfe/d)		36.2		42.0		28.3		40.5		45.4		34.4
Revenues (in thousands):
Natural gas		$33,829		$38,686		$28,585		$11,233		$12,423		$9,802
Condensate and oil		12,377		20,102		18,650		6,126		7,497		7,159
NGLs		9,300		10,001		10,001		3,542		3,700		3,700
Unrealized hedge loss		(5,566)		(5,566)		(5,566)		(9,637)		(9,637)		(9,637)
Total revenues		$49,940		$63,223		$51,670		$11,264		$13,983		$11,024
Average sales prices:
Natural gas ($/Mcf)		$3.20		$3.21		$4.01		$4.16		$4.12		$4.79
Condensate and oil ($/Bbl)		70.01		76.70		75.53		78.66		80.61		79.92
NGLs ($/Bbl)		34.40		34.16		34.16		44.32		43.51		43.51
Average sales price ($/Mcfe)		4.19		4.48		5.52		5.73		5.78		6.68

6

UNAUDITED CONDENSED COMBINED PRO FORMA FINANCIAL STATEMENTS

We expect to acquire certain oil and gas properties and related assets and liabilities from Chesapeake, repurchase shares of our Parent’s common stock from Chesapeake and settle certain litigation with Chesapeake in connection with the pending Chesapeake Transaction. We expect to use the proceeds of a debt financing to fund the Chesapeake Transaction, repay indebtedness under our existing revolving credit facility and for general corporate purposes. We also expect to sell our East Texas oil and gas properties and related assets and liabilities in the East Texas Divestiture and will use the net proceeds from that sale to repay any borrowings under our existing revolving credit facility.

The following pro forma condensed combined statements of operations for the three months ended March 31, 2013 and the year ended December 31, 2012 and the related explanatory notes have been prepared to reflect the Chesapeake Transaction and related debt financing and application of the net proceeds therefrom and the East Texas Divestiture as if they had closed on January 1, 2012. The following pro forma condensed combined balance sheet at March 31, 2013 and related explanatory notes have been prepared to reflect the Chesapeake Transaction and related debt financing and the East Texas Divestiture occurred on March 31, 2013.

The historical financial data within the unaudited pro forma condensed combined financial statements have been derived from and should be read in conjunction with the historical consolidated financial statements and accompanying notes contained in the Company’s Periodic Reports and the historical statements of revenues and direct operating expenses of the Chesapeake Assets. The historical financial statements of revenues and direct operating expenses for the Chesapeake Assets for the year ended December 31, 2012 and unaudited statements of revenues and direct operating expenses for the period ended March 31, 2013 do not include all items of expense that would be included in full financial statements such as general and administrative expenses and depreciation, depletion and amortization expenses. Gastar estimates that initial incremental annual general and administrative expenses associated with the Chesapeake Assets would be in the range of $2.0 to $2.5 million. The historical financial statements for the Chesapeake Assets do not include the revenues and direct operating expenses attributable to certain small interests in the Chesapeake Assets being sold by entities controlled by the former chief executive officer of Chesapeake, which interests Gastar estimates would not represent more than two percent of corresponding revenues and direct operating expenses for such reported period of the Chesapeake Assets being sold by Chesapeake.

Pro forma adjustments for the three and twelve months ended March 31, 2013 include pro forma adjustments for the Mid-Continent Acquisition based on the Company’s preliminary estimates of revenues and direct operating expenses for the Chesapeake Assets for the three months ended March 31, 2013, which utilized one month of actual production, revenues and direct operating expense data and two months of estimates by our management based on historical averages. When we prepare historical financial information relating to the assets being acquired from Chesapeake and the related pro forma financial information in compliance with Regulation S-X, the presentation of this financial information and the related pro forma financial information may change materially from that presented herein.

These unaudited pro forma financial results have been prepared for illustrative purposes only and are not intended to represent or be indicative of the consolidated results of operations or financial position of Gastar that would have been recorded had the pro forma transactions been completed as of the dates presented and should not be taken as representative of future results of operations or financial position of Gastar. Although management believes the assumptions used in preparing these unaudited pro forma financial statements are reasonable and accurate, these assumptions may not be correct. As a result, actual results could differ materially. In addition, it is not a condition of the debt financing related to the Mid-Continent Acquisition that the East Texas Divestiture is completed. These unaudited pro forma financial statements should be read in conjunction with, and are qualified in their entirety by reference to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and the notes thereto included in our Periodic Reports.

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Unaudited Pro Forma Condensed Combined Statement of Operations

for the Three Months Ended March 31, 2013

	Historical Gastar		Chesapeake Transaction and Debt Financing Adjustments(1)			Pro Forma Gastar for Chesapeake Transaction and Debt Financing		East Texas Divestiture Adjustments			Pro Forma Gastar for Chesapeake Transaction, Debt Financing and East Texas Divestiture
Statements of Operations Data:
Revenues
Natural gas		$11,233		$1,190	(a)		$12,423	$	(2,621)	(f)		$9,802
Condensate and oil		6,126		1,371	(a)		7,497		(338)	(f)		7,159
NGLs		3,542		158	(a)		3,700		—			3,700
Unrealized hedge loss		(9,637)		—			(9,637)		—			(9,637)
Total revenues		11,264		2,719			13,983		(2,959)			11,024
Expenses
Production taxes		643		151	(b)		794		(20)	(g)		774
Lease operating expenses		1,837		885	(b)		2,722		(934)	(g)		1,788
Transportation, treating and gathering		1,164		38	(b)		1,202		(927)	(g)		275
Depreciation, depletion and amortization		5,365		797	(c)		6,162		(1,500)	(h)		4,662
Impairment of natural gas and oil properties		—		—			—		—			—
Accretion of asset retirement obligation		102		52	(d)		154		(53)	(i)		101
General and administrative expense		2,781		—			2,781		—			2,781
Litigation settlement expense		1,000		—			1,000		—			1,000
Total expense		12,892		1,923			14,815		(3,434)			11,381
(Loss) income from operations		(1,628)		796			(832)		475			(357)
Other income (expense)
Interest expense		(609)		(2,792)	(e)		(3,401)		60	(j)		(3,341)
Investment and other income		5		—			5		—			5
Foreign transaction gain		1		—			1		—			1
Net (loss) income		(2,231)		(1,996)			(4,227)		535			(3,692)
Dividend on Preferred Stock		(2,130)		—			(2,130)		—			(2,130)
Net loss (income) attributable to common stockholder		$(4,361)		$(1,996)			$(6,357)		$535			$(5,822)

(1) Three months ended March 31, 2013 Chesapeake Transaction pro forma adjustments utilized one month of actual production, revenues and direct operating expense data and two months of estimates by our management based on historical averages.

See accompanying Notes to Unaudited Pro Forma Condensed Combined Financial Statements.

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Unaudited Pro Forma Condensed Combined Statement of Operations

for the Year Ended December 31, 2012

	Historical Gastar		Chesapeake Transaction and Debt Financing Adjustments			Pro Forma Gastar for Chesapeake Transaction and Debt Financing		East Texas Divestiture Adjustments			Pro Forma Gastar for Chesapeake Transaction, Debt Financing and East Texas Divestiture
Revenues
Natural gas		$33,829		$4,857	(a)		$38,686	$	(10,101)	(f)		$28,585
Condensate and oil		12,377		7,725	(a)		20,102		(1,452)	(f)		18,650
NGLs		9,300		701	(a)		10,001		—			10,001
Unrealized hedge loss		(5,566)		—			(5,566)		—			(5,566)
Total revenues		49,940		13,283			63,223		(11,553)			51,670
Expenses
Production taxes		2,269		651	(b)		2,920		(84)	(g)		2,836
Lease operating expenses		6,174		3,594	(b)		9,768		(3,624)	(g)		6,144
Transportation, treating and gathering		4,965		136	(b)		5,101		(3,746)	(g)		1,355
Depreciation, depletion and amortization		25,424		4,321	(c)		29,745		(9,247)	(h)		20,498
Impairment of natural gas and oil properties		150,787		—			150,787		—			150,787
Accretion of asset retirement obligation		388		196	(d)		584		(215)	(i)		369
General and administrative expense		10,732		—			10,732		—			10,732
Litigation settlement expense		1,250		—			1,250		—			1,250
Total expense		201,989		8,898			210,887		(16,916)			193,971
(Loss) income from operations		(152,049)		4,385			(147,664)		5,363			(142,301)
Other income (expense)
Interest expense		(271)		(9,906)	(e)		(10,177)		(1,412)	(j)		(11,589)
Investment and other expense		(4)		—			(4)		—			(4)
Foreign transaction gain		2		—			2		—			2
Net (loss) income		(152,322)		(5,521)			(157,843)		3,951			(153,892)
Dividend on Preferred Stock		(7,077)		—			(7,077)		—			(7,077)
Net loss (income) attributable to common stockholder		$(159,399)		$(5,521)			$(164,920)		$3,951			$(160,969)

See accompanying Notes to Unaudited Pro Forma Condensed Combined Financial Statements.

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Unaudited Pro Forma Condensed Combined Balance Sheet

as of March 31, 2013

	Historical Gastar		Chesapeake Transaction and Debt Financing Adjustments			Pro Forma Gastar for Chesapeake Transaction and Debt Financing			East Texas Divestiture Adjustments			Pro Forma Gastar for Chesapeake Transaction, Debt Financing and East Texas Divestiture
Balance sheet data:
Assets
Current Assets:
Cash and cash equivalents		$7,089		$3,209	(k)		$10,298			$44,003	(s)		$54,301
Accounts receivable, net of allowance for doubtful accounts		8,288		—			8,288			—			8,288
Commodity derivative contract		1,217		—			1,217			—			1,217
Prepaid expenses		837		—			837			—			837
Total current assets		17,431		3,209			20,640			44,003			64,643
Property, plant and equipment, net (full cost method)		286,092		72,555	(l)		358,647			(48,029)	(t)		310,618
Other Assets		11,257		(4,925)	(m)		6,332			—			6,332
Total Assets		$314,780		$70,839			$385,619			$(4,026)			$381,593
Liabilities and stockholders’ equity
Current liabilities
Accounts payable		$18,214		$—			$18,214			$—			$18,214
Revenue payable		7,563		—			7,563			—			7,563
Accrued interest		172		—			172			—			172
Accrued drilling and operating costs		2,888		—			2,888			—			2,888
Advances from non-operators		33,630		—			33,630			—			33,630
Commodity derivative contracts		3,491		—			3,491			—			3,491
Accrued litigation settlement liability		1,000		(1,000)	(n)		—			—			—
Asset retirement obligations		358		—			358			—			358
Other accrued liabilities		1,611		—			1,611			—			1,611
Total current liabilities		68,927		(1,000)			67,927			—			67,927
Long-term liabilities
Long-term debt		115,000		79,500	(o)		194,500	(r)		—			194,500
Commodity derivative contracts		1,725		—			1,725			—			1,725
Asset retirement obligation		6,438		2,092	(p)		8,530			(4,026)	(u)		4,504
Due to parent		31,362		(9,753)	(q)		21,609			—			21,609
Other long-term liabilities		228		—			228			—			228
Total long-term liabilities		154,753		71,839			226,592			(4,026)			222,566
Total stockholders’ equity		91,100		—			91,100			—			91,100
Total liabilities and stockholders’ equity		$314,780		$70,839			$385,619			$(4,026)			$381,593

See accompanying Notes to Unaudited Pro Forma Condensed Combined Financial Statements.

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Notes to Unaudited Pro Forma Condensed Combined Financial Statements

(a) To record natural gas, condensate and oil and NGLs sales revenues for the Chesapeake Assets for the three months ended March 31, 2013 and for the year ended December 31, 2012. Adjustments for the results of operations of the Chesapeake Assets for the three months ended March 31, 2013 are based on preliminary estimates made by Gastar. Does not include adjustments for the acquisition of a small portion of the Chesapeake Assets to be purchased from entities controlled by the former chief executive officer of Chesapeake.

(b) To record direct operating expenses for the Chesapeake Assets for the three months ended March 31, 2013 and for the year ended December 31, 2012. Adjustments for the results of operations for the Chesapeake Assets for the three months ended March 31, 2013 are based on preliminary estimates made by Gastar. Does not include adjustments for the acquisition of a small portion of the Chesapeake Assets to be purchased from entities controlled by the former chief executive officer of Chesapeake.

(c) To record additional depreciation, depletion and amortization (“DD&A”) expense for the Chesapeake Transaction for the three months ended March 31, 2013 and for the year ended December 31, 2012 under the full cost method of accounting.

(d) To record additional accretion expense on the asset retirement obligation for the Chesapeake Transaction for the three months ended March 31, 2013 and for the year ended December 31, 2012.

(e) To record interest expense based on borrowings to fund the Chesapeake Transaction and related existing revolving credit facility retirement resulting in a net increase in interest expense for the three months ended March 31, 2013 and for the year ended December 31, 2012. The increase in interest expense assumed the issuance of $200.0 million of long-term debt at an assumed interest rate of 9.5% and the retirement of the existing revolving credit facility with an outstanding balance of $30.0 million at January 1, 2012.

(f) To record the reduction in natural gas, condensate and oil and NGLs sales revenues for the East Texas Divestiture for the three months ended March 31, 2013 and for the year ended December 31, 2012.

(g) To record the reduction in direct operating expenses for the East Texas Divestiture for the three months ended March 31, 2013 and for the year ended December 31, 2012.

(h) To record the reduction in DD&A expense for the East Texas Divestiture for the three months ended March 31, 2013 and for the year ended December 31, 2012.

(i) To record the reduction in accretion expense on the asset retirement obligation for the East Texas Divestiture for the three months ended March 31, 2013 and for the year ended December 31, 2012.

(j) To record interest expense or benefit resulting from the East Texas Divestiture for the three months ended March 31, 2013 and for the year ended December 31, 2012. The interest benefit for the three months ended March 31, 2013 assumes the retirement of the remaining existing revolving credit facility debt. The increased interest expense for the year ended December 31, 2012 is the result of a reduction in capitalized interest due to lower unproved costs as a result of the East Texas Divestiture.

(k) To record the net cash proceeds received from the long-term debt financing, net of discount and expenses less net Chesapeake acquisition costs.

(l) To record additional property, plant and equipment acquired and additional asset retirement obligation (full cost method) as of March 31, 2013 for the Chesapeake Assets, net of purchase price adjustments of $3.8 million to reflect effective date of October 1, 2012.

(m) To record the additional deferred financing costs of $2.5 million and the application of the $7.4 million deposit previously paid at March 31, 2013 for the Chesapeake Transaction.

(n) To record the payment of the litigation liability at March 31, 2013 as a result of the Chesapeake Transaction.

(o) To record the issuance of $200.0 million of long-term debt at an assumed interest rate of 9.5%, net of an assumed $5.5 million of discount, and the retirement of the existing revolving credit facility outstanding balance at March 31, 2013 for the Chesapeake Transaction.

(p) To record additional asset retirement obligation liability for the properties acquired at March 31, 2013 for the Chesapeake Assets.

(q) To record the reduction in the amount due to the Parent for the repurchase of the Parent’s common stock per agreement at March 31, 2013 for the Chesapeake Transaction.

(r) Pro forma long-term debt is net of $5.5 million discount.

(s) To record the net cash proceeds received for the East Texas Divestiture, net of purchase price adjustments of $1.1 million to reflect effective date of January 1, 2013.

(t) To record the reduction in property, plant and equipment for the net sales proceeds and to reduce the property, plant and equipment balance for the related asset retirement obligation costs at March 31, 2013 for the East Texas Divestiture.

(u) To record the reduction in the asset retirement obligation liability at March 31, 2013 for the East Texas Divestiture.

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