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PROSPECTUS

Filed pursuant to Rule 424(b)(3)
Registration No. 333-150181

$100,000,000

Gastar Exploration USA, Inc.

Offer to Exchange up to

$100,000,000 of 12 ³/4% Senior Secured Notes due 2012

that have been registered under the Securities Act of 1933

for

$100,000,000 of 12 ³/4% Senior Secured Notes due 2012

that have not been registered under the Securities Act of 1933

The Exchange Offer will expire at 5:00 pm, New York City time,

on July 31, 2008, unless we extend the date

 

 

Terms of the Exchange Offer

 

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We are offering to exchange up to $100.0 million aggregate principal amount of registered 12 3/4% Senior Secured Notes due 2012, which we refer to as the new notes, for any and all of our $100.0 million aggregate principal amount of unregistered 12 3/4% Senior Secured Notes due 2012, which we refer to as the old notes, that were issued on November 29, 2007. The new notes are being issued under the indenture pursuant to which we previously issued the old notes.

 

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We will exchange all outstanding old notes that are validly tendered and not validly withdrawn prior to the expiration of the exchange offer for an equal principal amount of new notes.

 

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The terms of the new notes are substantially identical to those of the outstanding old notes, except that the transfer restrictions and registration rights relating to the old notes do not apply to the new notes.

 

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You may withdraw tenders of old notes at any time prior to the expiration of the exchange offer.

 

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The exchange of new notes for old notes should not be a taxable transaction for U.S. federal income tax purposes.

 

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We will not receive any cash proceeds from the exchange offer.

 

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The old notes are, and the new notes will be, guaranteed by each of our existing domestic subsidiaries, future material domestic subsidiaries and by Gastar Exploration Ltd., our parent company.

This investment involves risks. Please read “ Risk Factors” beginning on page 9 for a discussion of the risks that you should consider prior to tendering your outstanding old notes in the exchange offer.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

 

 

The date of this prospectus is July 1, 2008.

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This prospectus is part of a registration statement we filed with the Securities and Exchange Commission, referred to in this prospectus as the SEC. In making your decision to participate in the exchange offer, you should rely only on the information contained in this prospectus and in the accompanying letter of transmittal. We have not authorized anyone to provide you with any other information. If you received any unauthorized information, you must not rely on it. We are not making an offer to sell these securities in any state or jurisdiction where the offer is not permitted. You should not assume that the information contained in this prospectus, or the documents incorporated by reference into this prospectus, is accurate as of any date other than the date on the front cover of this prospectus or the date of such document incorporated by reference, as the case may be.

Each broker-dealer that receives new notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where such old notes were acquired by such broker-dealer as a result of market-making activities or other trading activities. We have agreed that, for a period of 180 days after the consummation of the exchange offer, we will make this prospectus available to any broker-dealer for use in connection with any such resale. Please read “Plan of Distribution”.

 

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TABLE OF CONTENTS

 

PROSPECTUS SUMMARY		1
RISK FACTORS		9
RATIO OF EARNINGS TO FIXED CHARGES		28
USE OF PROCEEDS		28
THE EXCHANGE OFFER		29
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS		36
SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA		38
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		40
BUSINESS		53
LEGAL PROCEEDINGS		70
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT		75
MANAGEMENT		77
COMPENSATION DISCUSSION AND ANALYSIS		81
EXECUTIVE COMPENSATION		87
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS		97
DESCRIPTION OF THE NOTES		98
CERTAIN U.S. FEDERAL TAX CONSIDERATIONS		146
PLAN OF DISTRIBUTION		147
LEGAL MATTERS		149
EXPERTS		149
INDEPENDENT PETROLEUM ENGINEERS		149
WHERE YOU CAN FIND MORE INFORMATION		149
INDEX TO FINANCIAL STATEMENTS		F-1
LETTER OF TRANSMITTAL		A-1

 

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RISK FACTORS

An investment in the new notes involves a significant degree of risk. You should consider carefully these risks together with all of the other information included in this prospectus and the documents to which we have referred you before deciding whether to invest in the new notes. All of the risks described below could materially and adversely affect our business prospects, financial condition, operating results and cash flows, which in turn could adversely affect our ability to satisfy our obligations under the new notes and the guarantees of the new notes.

Risks Relating to the New Notes and Our Other Indebtedness

We have incurred significant net losses since our inception and may incur additional significant net losses in the future.

We have not been profitable since we started our business. We incurred net losses of $30.5 million, $84.8 million and $25.7 million for the years ended December 31, 2007, 2006 and 2005, respectively. Our capital has been employed in an increasingly expanding natural gas and oil exploration and development program with the focus on finding significant natural gas and oil reserves and producing from them over the long-term rather than focusing on achieving immediate net income. The uncertainties described in this section may impede our ability to ultimately find, develop and exploit natural gas and oil reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows from operating activities in the future.

We have a substantial amount of debt, which may adversely affect our cash flow and our ability to operate our business, to remain in compliance with debt covenants and make payments on our debt.

As March 31, 2008, we had total debt of $133.3 million of which $100.0 million consisted of the 12 ³/4% Senior Secured Notes, $30.0 million consisted of convertible senior debentures due 2009 and $3.3 million consisted of subordinated unsecured notes due 2009. Our level of indebtedness affects our operations in several ways, including the following:

 

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We may have difficulty borrowing money in the future for acquisitions, capital expenditures or to meet our operating expenses or other general corporate obligations;

 

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We will need to use a substantial portion of our cash flows to pay principal and interest on our debt, which will reduce the amount of money we have for operations, working capital, capital expenditures, expansion, acquisitions or general corporate or other business activities;

 

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We have substantial capital requirements, and we may be unable to obtain needed financing on satisfactory terms;

 

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We may be more vulnerable to economic downturns and adverse developments in our industry or the economy in general, especially declines in natural gas and oil prices;

 

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The covenants contained in the agreements governing our outstanding indebtedness limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments; and

 

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Our debt covenants may affect our flexibility in planning for and reacting to changes in the economy or in our industry.

We may incur substantially more debt, which may intensify the risks described above, including our ability to service our indebtedness.

We may need to incur substantially more debt in the future. Although the indenture governing the 12 ³/4% Senior Secured Notes and our revolving credit facility contain restrictions on our incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions, and under certain circumstances, indebtedness incurred in compliance with these restrictions could be substantial. In addition, the indenture governing the new notes and our revolving credit facility will not prevent us from incurring obligations that do not constitute indebtedness. See “Description of the Notes—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock”. To the extent new indebtedness is added to our current indebtedness levels, the risks described above could substantially intensify.

 

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To service our indebtedness, we will require a significant amount of cash. Our ability to generate cash depends on many factors beyond our control, and any failure to meet our debt obligations could harm our business, financial condition and results of operations.

Our ability to make interest payments on and to repay our indebtedness, including the new notes, and to fund planned capital expenditures will depend on our ability to generate cash from operations in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control, including the prices that we receive for natural gas and oil. We cannot assure you that our business will generate sufficient cash flow from operations or that future borrowings will be available to us under our revolving credit facility in an amount sufficient to enable us to make interest payments on and to repay our indebtedness, including the new notes, or to fund our other liquidity needs.

If our cash flow and capital resources are insufficient to fund our debt obligations, we may be forced to sell assets, seek additional equity or debt capital or restructure our debt. Our Australian joint ventures include a contractual priority over production to satisfy joint venture debts as against secured creditors. The indenture governing the old notes, the new notes and our revolving credit facility will restrict our ability to dispose of assets and use the proceeds from any such disposition. We cannot assure you that any of these remedies could, if necessary, be effected on commercially reasonable terms, or at all. In addition, any failure to make scheduled payments of interest and principal on our outstanding indebtedness, including our revolving credit facility, would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms. If we fail to meet our payment obligations under our revolving credit facility, those lenders would be entitled to foreclose on substantially all of our assets and liquidate those assets. Under those circumstances, our cash flow and capital resources would be insufficient for payment of interest on and principal of our debt in the future, including interest payments on the new notes and the old notes, and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations, impair our liquidity, or cause the holders of the new notes to lose a portion of or the entire value of their investment.

A default on our obligations could result in:

 

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Our debt holders declaring all outstanding principal and interest due and payable;

 

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The lenders under our revolving credit facility terminating their commitments to loan us money and foreclosing against the assets securing their loans to us; and

 

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Our bankruptcy or liquidation, which is likely to result in delays in the payment of the new notes and in the exercise of enforcement remedies under the new notes or the subsidiary guarantees.

In addition, provisions under the bankruptcy code or general principles of equity that could result in the impairment of your rights include the automatic stay, avoidance of preferential transfers by a trustee or a debtor-in-possession, limitations of collectibility of unmatured interest or attorneys’ fees and forced restructuring of the new notes.

Restrictive debt covenants in the indenture and our revolving credit facility will restrict our business in many ways.

The indenture governing the new notes will contain a number of significant covenants that, among other things, will restrict our ability to:

 

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Transfer or sell assets;

 

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Make investments;

 

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Pay dividends, redeem subordinated indebtedness or make other restricted payments;

 

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Incur or guarantee additional indebtedness or issue disqualified capital stock;

 

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Create or incur liens;

 

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Incur dividend or other payment restrictions affecting certain subsidiaries;

 

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Consummate a merger, consolidation or sale of all or substantially all of our assets;

 

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Enter into transactions with affiliates; and

 

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Engage in businesses other than the natural gas and oil business.

These covenants could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general or otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants impose on us. A breach of any of these covenants could result in a default under the new notes which, if not cured or waived, could result in acceleration of the new notes. See “Description of the Notes—Events of Default and Remedies”.

In addition, our revolving credit facility contains restrictive covenants and requires us to maintain specified financial ratios and satisfy other financial condition tests. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those tests. A breach of any of these covenants could result in a default under the facility. Upon the occurrence of an event of default, the lenders could elect to declare all amounts outstanding to be immediately due and payable and terminate all commitments to extend further credit. If we were unable to repay those amounts, the lenders could proceed against the collateral granted to them to secure that indebtedness. We have pledged substantially all of our assets as collateral under the revolving credit facility, including our ownership interests in our subsidiaries. If the lenders accelerate our repayment of borrowings, we cannot assure you that we will have sufficient assets to repay our revolving credit facility and our other indebtedness, including the new notes.

Our borrowings under our revolving credit facility expose us to interest rate risk.

Our borrowings under our revolving credit facility are, and are expected to continue to be, at variable rates of interest and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our net loss would increase.

There may not be sufficient collateral to pay all or any of the new notes.

Indebtedness and other obligations under our revolving credit facility, the new notes and certain other senior secured indebtedness that we may incur in the future will be secured by a lien on substantially all of our tangible and intangible assets. Pursuant to the terms of an intercreditor agreement, the security interest in those assets that secure the new notes and guarantees of our current domestic subsidiaries and future material domestic subsidiaries will be contractually subordinated to a lien thereon that secures our revolving credit facility and certain other permitted indebtedness. Therefore, in the event of a bankruptcy, liquidation, dissolution, reorganization or similar proceeding involving us, or an acceleration of our first priority claims, such assets that secure these first priority claims and the new notes must be used first to pay first priority claims in full before any payments are made therewith on the new notes.

No fair market value appraisals of any collateral have been prepared in connection with this offering of the new notes. The value of the collateral at any time will depend on market and other economic conditions, including the availability of suitable buyers for the collateral. By its nature, some or all of the collateral may be illiquid and may have no readily ascertainable market value. The value of the assets pledged as collateral for the new notes could be impaired in the future as a result of changing economic conditions, competition or other future trends. In the event of a foreclosure, liquidation, bankruptcy or similar proceeding, no assurance can be given that the proceeds from any sale or liquidation of the collateral will be sufficient to pay our obligations under the new notes, in full or at all, after first satisfying our obligations in full under first priority claims. See the section entitled “Description of the Notes—Collateral”. Accordingly, there may not be sufficient collateral to pay all or any of the amounts due on the new notes.

 

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To the extent that third parties enjoy prior liens, such third parties may have rights and remedies with respect to the property subject to such liens that, if exercised, could adversely affect the value of the collateral. Additionally, the terms of the indenture allow us to issue additional notes in certain circumstances. The indenture will not require that we maintain the current level of collateral value or maintain a specific ratio of indebtedness to asset values. Any additional notes issued pursuant to the indenture will rank pari passu with the new notes and be entitled to the same rights and priority with respect to the collateral. Thus, the issuance of additional notes pursuant to the indenture may have the effect of significantly diluting your ability to recover payment in full from the then existing pool of collateral. Releases of collateral from the liens securing the new notes will be permitted under some circumstances. See “Description of the Notes—Collateral”.

The collateral is subject to casualty risks.

We will be obligated under the collateral arrangements to maintain adequate insurance or otherwise insure against hazards as is usually done by corporations operating properties of a similar nature in the same or similar localities. The Australian assets insurances are procured by the operator of the relevant joint venture (acting as a reasonable and prudent operator) to cover joint venture loss and include deductibles. There are, however, certain losses that may be either uninsurable or not economically insurable, in whole or in part. As a result, it is possible that the insurance proceeds will not compensate us fully for our losses. If there is a total or partial loss of any of the pledged collateral, we cannot assure you that any insurance proceeds received by us will be sufficient to satisfy all of our secured obligations, including the new notes.

Holders of new notes will not control decisions regarding collateral.

In connection with entering into our revolving credit facility, we entered into an intercreditor agreement with the agent under our revolving credit facility, which provides that, among other things, (1) the holders of the first priority claims and the agent under our revolving credit facility control substantially all matters related to the collateral that secures the first priority claims and the new notes; (2) the holders of first priority claims and the agent under our revolving credit facility may foreclose on or take other actions with respect to such collateral with which holders of the new notes may disagree or that may be contrary to the interests of holders of the new notes; (3) to the extent certain collateral is released from securing first priority claims to satisfy such claims, the liens securing the new notes will also automatically be released without any further action; and (4) the holders of the new notes will agree to waive certain of their rights in connection with a bankruptcy or insolvency proceeding involving us or any guarantor of the new notes. See “Description of the Notes—Collateral—Intercreditor Agreement”.

In the event of a bankruptcy, the ability of the noteholders to realize the collateral will be subject to certain bankruptcy law limitations.

The right of the collateral agent for the new notes to repossess and dispose of the collateral securing the new notes upon acceleration is likely to be significantly impaired by federal bankruptcy law if bankruptcy proceedings are commenced by or against us prior to or possibly even after the collateral agent has repossessed and disposed of the collateral. Under the U.S. Bankruptcy Code, a secured creditor, such as the collateral agent for the new notes, is prohibited from repossessing its security from a debtor in a bankruptcy case, or from disposing of security repossessed from a debtor, without bankruptcy court approval. Moreover, bankruptcy law permits the debtor to continue to retain and to use collateral, and the proceeds, products, rents, or profits of the collateral, even though the debtor is in default under the applicable debt instruments, provided that the secured creditor is given “adequate protection”. The meaning of the term “adequate protection” may vary according to circumstances, but it is intended in general to protect the value of the secured creditor’s interest in the collateral and may include cash payments or the granting of additional security, if and at such time as the court in its discretion determines, for any diminution in the value of the collateral as a result of the stay of repossession or disposition or any use of the collateral by the debtor during the pendency of the bankruptcy case. In view of the broad discretionary powers of a bankruptcy court, it is impossible to predict how long payments under the new notes could be delayed following commencement of a bankruptcy case, whether or when the collateral agent would repossess or dispose of the collateral, or whether or to what extent holders of the new notes would be compensated for any delay in payment of loss of value of the collateral through the requirements of “adequate protection”. Furthermore, in the event the bankruptcy court

 

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determines that the value of the collateral is not sufficient to repay all amounts due on the new notes, the holders of the new notes would have “undersecured claims” as to the difference. Federal bankruptcy laws do not permit the payment or accrual of interest, costs, and attorneys’ fees for “undersecured claims” during the debtor’s bankruptcy case.

Rights of noteholders in the collateral may be adversely affected by the failure to perfect security interests in certain collateral existing or acquired in the future.

The security interest in the collateral securing the new notes includes certain of our domestic assets, both tangible and intangible, whether now owned or acquired or arising in the future. Our Australian properties do not constitute any of the collateral securing the new notes. There can be no assurance that the trustee or the collateral agent will monitor, or that we will inform the trustee or the collateral agent of, the future acquisition of oil and gas property and rights that constitute collateral, and that the necessary action will be taken to properly perfect the security interest in such after acquired collateral. The failure to perfect a security interest in respect of such acquired collateral may result in the loss of the security interest therein or the priority of the security interest in favor of the new notes against third parties, subject to the priority order set out in joint venture agreements. If we or any guarantor were to become subject to a bankruptcy proceeding after the issue date of the new notes, any liens recorded or perfected after the issue date of the new notes would face a greater risk of being invalidated than if they had been recorded or perfected on the issue date. If a lien is recorded or perfected after the issue date, it may be treated under bankruptcy law as if it were delivered to secure previously existing debt. In bankruptcy proceedings commenced within 90 days of lien perfection, a lien given to secure previously existing debt is materially more likely to be avoided as a preference by the bankruptcy court than if delivered and promptly recorded on the issue date of the new notes. Accordingly, if we or a guarantor were to file for bankruptcy after the issue date of the new notes and the liens had been perfected less than 90 days before commencement of such bankruptcy proceeding, the liens securing the new notes may be especially subject to challenge as a result of having been delivered after the issue date of the new notes. To the extent that such challenge succeeded, you would lose the benefit of the security that the collateral was intended to provide.

A court could cancel the new notes or the guarantees of our current domestic subsidiaries and future material domestic subsidiaries, our Parent and security interests under fraudulent conveyance laws or certain other circumstances.

Our issuance of the new notes and the issuance of the guarantees by our current and future subsidiaries and our Parent may be subject to review under federal or state fraudulent transfer or similar laws.

All of our current domestic and future material domestic subsidiaries and our Parent will guarantee the new notes. If we, our Parent or such a subsidiary becomes a debtor in a case under the Bankruptcy Code or encounters other financial difficulty, under federal or state laws governing fraudulent conveyance, renewable transactions or preferential payments, a court in the relevant jurisdiction might avoid or cancel its guarantee and/or the liens created by the security interest. The court might do so if it found that, when the subsidiary or our Parent entered into its guarantee and security arrangement or, in some states, when payments become due thereunder, (a) it received less than reasonably equivalent value or fair consideration for such guarantee and/or security arrangement and (b) either (i) was or was rendered insolvent, (ii) was left with inadequate capital to conduct its business, (iii) or believed or should have believed that it would incur debts beyond its ability to pay. The court might also avoid such guarantee and/or security arrangement, without regard to the above factors, if it found that the subsidiary or our Parent entered into its guarantee and/or security arrangement with actual or deemed intent to hinder, delay, or defraud our creditors.

Similarly, if we become a debtor in a case under the Bankruptcy Code or encounter other financial difficulty, a court might cancel our obligations under the new notes, if it found that when we issued the new notes (or in some jurisdictions, when payments become due under the new notes), factors (a) and (b) above applied to us, or if it found that we issued the new notes with actual intent to hinder, delay or defraud our creditors.

A court would likely find that a subsidiary or our Parent did not receive reasonably equivalent value or fair consideration for its guarantee unless it benefited directly or indirectly from the issuance of the new notes. If a court avoided such guarantee, holders of the new notes would no longer have a claim against such subsidiary or our Parent. In addition, the court might direct holders of the new notes to repay any amounts already received from such subsidiary or our Parent. If the court were to avoid any guarantee, we cannot assure you that funds would be available to pay the new notes from another subsidiary or our Parent or from any other source.

 

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The indenture states that the liability of each subsidiary and our Parent on its guarantee and security arrangement is limited to the maximum amount that the subsidiary or our Parent can incur without risk that the guarantee or security arrangement will be subject to avoidance as a fraudulent conveyance. This limitation may not protect the guarantees and/or security arrangements from a fraudulent conveyance attack or, if it does, the guarantees and/or security arrangements may not be in amounts sufficient, if necessary, to pay obligations under the new notes when due.

The trading price of the new notes may be volatile.

Historically, the market for non-investment grade debt has been subject to disruptions that have caused substantial volatility in the prices of securities similar to the new notes. Any such disruptions could adversely affect the prices at which you may sell the new notes. In addition, the new notes may trade at a discount from the initial offering price of the old notes, depending on prevailing interest rates, the market for similar notes, our performance and other factors, many of which are beyond our control.

We may not have the ability to raise the funds necessary to finance any change of control offer required by the indenture governing the new notes.

Upon the occurrence of a “change of control,” as defined in the indenture governing the new notes, we will be required to offer to repurchase all outstanding new notes at a price equal to 101% of the principal amount of the new notes, together with accrued and unpaid interest, if any, to the date of repurchase.

However, it is possible that we will not have sufficient funds at the time of a change of control to make the required repurchase of the new notes or that restrictions in our revolving credit facility will not allow such repurchases. If the indebtedness under our revolving credit facility is not paid, the lenders thereunder may seek to enforce their security interests in the collateral securing such indebtedness thereby limiting our ability to raise cash to purchase the new notes and reducing the practical benefit of the offer to purchase provisions of the new notes. See “Description of the Notes—Repurchase at the Option of Holders”.

One of the circumstances under which a change of control may occur is upon the sale or disposition of all or substantially all of our capital stock or assets. However, the phrase “all or substantially all” will likely be interpreted under applicable state law and will be dependent upon particular facts and circumstances. As a result, there may be a degree of uncertainty in ascertaining whether a sale or disposition of “all or substantially all” of our capital stock or assets has occurred, in which case, the ability of a holder of the new notes to obtain the benefit of an offer to repurchase all of a portion of the new notes held by such holder may be impaired.

The purchase requirements contained in our debt instruments could also delay or make it harder for others to effect a change of control. However, certain other corporate events, such as a leveraged recapitalization that would increase our level of indebtedness, would not necessarily constitute a change of control under the indenture governing the new notes. Upon the occurrence of a change of control we could seek to refinance the indebtedness under our new revolving credit facility and the new notes, obtain a waiver from the lenders and the holders of the new notes or seek third party financing to repurchase the new notes. We cannot assure you, however, that we would be able to obtain waivers or refinance our indebtedness or secure third party financing on commercially reasonable terms, if at all. See “Description of the Notes—Repurchase at the Option of Holders”.

There may be no public market for the new notes.

The new notes will be new securities for which currently there is no trading market. We do not intend to apply for the new notes to be listed on any securities exchange or to arrange for any quotation system to quote them. The liquidity of any market for the new notes will depend on the number of holders of those new notes, the interest of securities dealers in making a market in those securities and other factors. Accordingly, we cannot assure you as to:

 

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The liquidity of any such market that may develop;

 

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Your ability to sell your new notes; or

 

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The price at which you would be able to sell your new notes.

If such a market were to exist, the new notes could trade at prices that may be lower than the principal amount or purchase price, depending on many factors, including prevailing interest rates, the market for similar new notes and our financial performance. If an active market does not develop or is not maintained, the price and liquidity of the new notes may be adversely affected.

If you fail to exchange your old notes, the existing transfer restrictions will remain in effect and the market value of your old notes may be adversely affected because they may be more difficult to sell.

If you fail to exchange your old notes for new notes under the exchange offer, then you will continue to be subject to the existing transfer restrictions on your old notes. In general, the old notes may not be offered or sold unless they are registered or exempt from registration under the Securities Act and applicable state securities laws. Except in connection with this exchange offer or as required by the registration rights agreement, we do not intend to register resales of the old notes.

The tender of old notes under the exchange offer will reduce the principal amount of the old notes outstanding. Due to the corresponding reduction in liquidity, this may have an adverse effect upon, and increase the volatility of, the market price of any old notes that you continue to hold following completion of the exchange offer.

Risks Related to Our Business

Natural gas and oil prices are volatile and a decline in natural gas and oil prices can significantly affect our financial condition and results of operations.

The success of our business greatly depends on market prices of natural gas and oil. The higher market prices are, the more likely it is that we will be financially successful. On the other hand, declines in natural gas or oil prices may have a material adverse affect our financial condition, profitability and liquidity. Lower prices also may reduce the amount of natural gas or oil that we can produce economically. Natural gas and oil are commodities whose prices are set by broad market forces. Historically, the natural gas and oil markets have been volatile. Natural gas and oil prices will likely continue to be volatile in the future. Prices for natural gas and oil are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for natural gas or oil, market uncertainty and a variety of additional factors that are beyond our control. These factors include:

 

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The domestic and foreign supply of natural gas and oil;

 

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Overall economic conditions;

 

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Weather conditions;

 

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Political conditions in the Middle East and other oil producing regions, such as Venezuela;

 

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Domestic and foreign governmental regulations;

 

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The level of consumer product demand; and

 

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The price and availability of alternative fuels.

Our success is influenced by natural gas prices in the specific areas where we operate, and these prices may be lower than prices at major markets.

Even though overall natural gas prices at major markets, such as Henry Hub in Louisiana, may be high, regional natural gas prices may move independent of broad industry price trends. Because some of our operations are located outside major markets, we are directly impacted by regional natural gas prices regardless of Henry Hub or other major market pricing. As of March 31, 2008, approximately 79% of our production is priced based on the Katy Hub (“Katy”) basis point, and the remainder is priced on the CIG basis point. Recently, natural gas prices on CIG

 

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have been extremely volatile, and spot sales of natural gas in the region traded at prices substantially below historic levels, when compared to prices in other primary natural gas sales points in the country. This has been attributed primarily to limitations in available pipeline capacity for natural gas deliveries out of the Rocky Mountain area. In 2007, spot prices for CIG Rocky Mountains on occasion dipped to less than $1.00 per MMBtu. While this volatility currently has been alleviated by completion of a major pipeline system in January 2008, this relief may be offset over time by the expected increase in supply of natural gas available in the Rocky Mountains. For the three months ended March 31, 2008, the Katy hub basis traded at approximately 3% less than Henry Hub, and CIG hub basis traded at approximately 11% less then Henry Hub. Low natural gas prices in any or all of the areas where we operate would negatively impact our financial condition and results of operations.

In Victoria and New South Wales the wholesale price for gas is determined by contract negotiations and is not related to a “hub” or “spot market” price. Prospective natural gas sales related to our pilot CBM project in New South Wales will be dependent on electricity prices in the area since the natural gas is being dedicated initially as fuel for an electric generation facility.

Natural gas and oil reserves are depleting assets, and the failure to replace our reserves would adversely affect our production and cash flows.

Our future natural gas and oil production depends on our success in finding or acquiring new reserves. If we fail to replace reserves, our level of production and cash flows would be adversely impacted. Production from natural gas and oil properties decline as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves will decline as reserves are produced unless we conduct successful exploration and development activities and/or acquire properties containing proved reserves. Our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves, which could have a material adverse effect on our financial condition, future cash flows and the results of operations.

Exploration is a high risk activity, and our participation in drilling activities may not be successful.

Our future success will largely depend on the success of our exploration drilling program. Participation in exploration drilling activities involves numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will be discovered. The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

 

•

Unexpected drilling conditions;

 

•

Blowouts, fires or explosions with resultant injury, death or environmental damage;

 

•

Pressure or irregularities in formations;

 

•

Equipment failures or accidents;

 

•

Adverse weather conditions;

 

•

Compliance with governmental requirements and laws, present and future; and

 

•

Shortages or delays in the availability of drilling rigs and the delivery of equipment.

We use available seismic data to assist in the location of potential drilling sites. Even when properly used and interpreted, 2-D and 3-D seismic data and other visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. Poor results from our drilling activities would have a material adverse affect our financial condition, future cash flows and results of operations. In addition, using seismic data and other advanced technologies involves substantial upfront costs and is more expensive than traditional drilling strategies, and we could incur losses as a result of these expenditures.

 

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Deficiencies of title to our leased interests could significantly affect our financial condition.

Our practice in acquiring exploration leases or undivided interests in natural gas and oil leases is not to incur the expense of retaining lawyers to examine the title to the mineral interest prior to executing the lease. Instead, we rely upon the judgment of lease brokers and others to perform the field work in examining records in the appropriate governmental or county clerk’s office before leasing a specific mineral interest. This practice is widely followed in the industry. Prior to drilling an exploration well, the operator of the well will typically obtain a preliminary title review of the drillsite lease or spacing unit within which the proposed well is to be drilled to identify any obvious deficiencies in title to the well and, if there are deficiencies, to identify measures necessary to cure those defects to the extent reasonably possible. It does happen, from time to time, that the examination made by the title lawyers reveals that the lease or leases are invalid, having been purchased in error from a person who is not the rightful owner of the mineral interest desired. In these circumstances, we may not be able to proceed with our exploration and development of the lease site or may incur costs to remedy a defect, which could affect our financial condition and results of operations. Information about our legal proceedings is set forth in Note 16 – Commitments and Contingencies – Litigation to our consolidated financial statements, which begin on page F-1.

 

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A dispute between third parties affecting the ownership of undivided interests in certain East Texas oil and gas leases that we sold in 2005 may make it difficult for us, as operator of those leases, to obtain funds for some of our planned joint drilling operations until the dispute is resolved.

In 2005, we sold Chesapeake Energy Corporation a one-third undivided interest in various oil and gas leases, located in Leon and Robertson Counties, Texas together with shares of our common stock. Navasota Resources, L.P. filed a lawsuit against us and Chesapeake asserting a preferential right to purchase the undivided leasehold interest under an operating agreement. While this issue was resolved by the trial court in favor of Chesapeake, an appeals court has recently reversed and rendered judgment favoring Navasota’s right to acquire the undivided interest. Together with Chesapeake, we filed a motion for rehearing and, if unsuccessful, may consider an appeal to the Texas Supreme Court. While ownership of this undivided leasehold interest remains unresolved, Chesapeake and Navasota are disputing responsibility for paying the proportionate share of joint capital and operating costs relating to this interest or approving authorizations for future joint drilling expenditures. Delays in determining ultimate ownership of this interest could lead to our paying a disproportionate share of costs at our own risk or result in a delay in drilling of wells planned on this acreage in East Texas, which could have a material adverse effect on our financial condition, future cash flows and the results of operations.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present values of our reserves.

The process of estimating natural gas and oil reserves is complex. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves.

There are many uncertainties inherent in estimating natural gas and oil reserves and their values, many of which are beyond our control. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas or oil that cannot be measured in an exact manner. Estimates of economically recoverable natural gas or oil reserves and of future net cash flows necessarily depend on many variables and assumptions, such as:

 

•

Historical natural gas or oil production from that area, compared with production from other producing areas;

 

•

The assumed effects of regulations by governmental agencies;

 

•

Assumptions concerning future prices;

 

•

Assumptions concerning future operating costs;

 

•

Assumptions concerning severance and excise taxes; and

 

•

Assumptions concerning development costs and workover and remedial costs.

Any of these assumptions could vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of natural gas or oil attributable to any particular group of properties, classifications of those reserves based on risk recovery and estimates of the future net cash flows expected from them prepared by different engineers, or by the same engineer at different times, may vary substantially. Because of this, our reserve estimates may materially change at any time.

You should not consider the present values of estimated future net cash flows referred to in this prospectus to be the current market value of the estimated reserves attributable to our properties. The estimated discounted future net cash flows from proved reserves are generally based on prices and costs in effect when the estimate is made. However, actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as:

 

•

The amount and timing of actual production;

 

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•

Supply and demand for natural gas or oil;

 

•

Actual prices received for natural gas in the future being different than those used in the estimate;

 

•

Curtailments or increases in consumption of natural gas or oil;

 

•

Changes in governmental regulations or taxation; and

 

•

The timing of both production and expenses in connection with the development and production of natural gas or oil properties.

In this prospectus, the net present value of future net revenues is calculated using a 10% discount rate. This rate is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our reserves or the natural gas and oil industry in general.

The imprecise nature of estimating proved natural gas and oil reserves, future downward revisions of proved reserves and increased drilling expenditures without current additions to proved reserves may lead to write downs in the carrying value of our natural gas and oil properties.

Due to the imprecise nature of estimating natural gas and oil reserves as well as the potential volatility in natural gas and oil prices and their effect on the carrying value of our natural gas and oil properties, write downs in the future may be required as a result of factors that may negatively affect the present value of proved natural gas and oil reserves. These factors can include volatile natural gas and oil prices, downward revisions in estimated proved natural gas and oil reserve quantities, limited classification of proved reserves associated with successful wells and unsuccessful drilling activities.

A majority of our proved reserves are classified as proved developed non-producing and proved undeveloped and may ultimately prove to be less than estimated.

At December 31, 2007, approximately 60% of our total proved reserves were classified as proved developed non-producing and proved undeveloped. It will take substantial capital to recomplete or drill our non-producing and undeveloped locations. Our estimate of proved reserves at December 31, 2007 assumes that we will spend significant development capital expenditures to develop these reserves, including an estimated $39.1 million and $9.5 million in 2008 and 2009, respectively. Further, our drilling efforts may be delayed or unsuccessful, and actual reserves may prove to be less than current reserve estimates, which could have a material adverse effect on our financial condition, future cash flows and the results of operations.

We may experience shortages of equipment and personnel, which could significantly disrupt or delay our operations.

From time to time, there has been a general shortage of drilling rigs, equipment, supplies and oilfield services in North America and Australia, which could intensify with increased industry activity. In addition, the costs and delivery times of rigs, equipment and supplies have risen. Shortages of drilling rigs, equipment, supplies or trained personnel could delay and adversely affect our operations and drilling plans, which could have an adverse effect on our results of operations. While we entered into contracts for the services of drilling rigs in North America and Australia, we may not be successful in doing so in the future. The demand for, and wage rates of, qualified rig crews have begun to rise in the drilling industry due to the increasing number of active rigs in service. Personnel shortages have occurred in the past during times of increasing demand for drilling services. If the number of active drilling rigs increases, we may experience shortages of qualified personnel to operate our drilling rigs, which could delay our drilling operations and have a material adverse effect on our financial condition, future cash flows and the results of operations.

 

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We are subject to complex laws and regulations, including environmental laws and regulations that can adversely affect the cost, manner or feasibility of conducting our business.

Our exploration and production interests and operations are subject to stringent and complex federal, state and local laws and regulations governing the operation and maintenance of our facilities and the handling and discharge of substances into the environment. These existing laws and regulations impose numerous obligations that are applicable to our interests and operations including:

 

•

Air and water discharge permits for drilling and production operations;

 

•

Drilling and abandonment bonds or other financial responsibility assurances;

 

•

Reports concerning operations;

 

•

Spacing of wells;

 

•

Access to properties, particularly in the Powder River Basin;

 

•

Taxation; and

 

•

Other regulatory controls on operating activities.

In addition, regulatory agencies have from time to time imposed price controls and limitations on production by restricting the flow rate of wells below actual production capacity in order to conserve supplies of natural gas and oil.

Failure to comply with environmental and other laws and regulations applicable to our interests and operations could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of orders enjoining or limiting future operations, any of which could have a material adverse affect on our financial condition. Legal requirements are sometimes unclear or subject to reinterpretation and may be frequently changed in response to economic or political conditions. As a result, it is hard to predict the ultimate cost of compliance with these requirements or their affect on our interests and operations. In addition, existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations may have a material adverse effect on our financial condition, future cash flows and the results of operations.

The production, handling, storage, transportation and disposal of natural gas and oil, by-products of natural gas and oil and other substances produced or used in connection with natural gas and oil production operations are regulated by laws and regulations focused on the protection of human health and the environment. Joint and several, strict liability may be incurred without regard to fault or the legality of the original conduct under certain of these laws and regulations for the remediation of contaminated areas. Private parties, including the owners of properties located near our storage facilities or through which our pipeline systems pass, also may have the right to pursue legal actions to enforce compliance, as well as seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. Consequently, the discharge or release of natural gas, oil or other substances into the air, soil or water, even by predecessor operators, could subject us to liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury, property and natural resource damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may not be able to recover some or any of these costs from insurance.

Our Australian operations are subject to unique risks relating to Aboriginal land claims and government licenses.

Native title, which is based on the traditional laws of Aboriginal groups, was recognized in Australia in 1992. Since 1994 there has been a process under the Native Title Act 1993 (Cth) through which indigenous groups claiming to hold native title can have their title formally recognized. Because native title, by definition, has existed uninterrupted since white settlement of Australia, claims with a reasonable prospect of success are “registered” and

 

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registered claimants have certain rights to participate in government land use decisions affecting land to which they may hold native title. Through the claims process, there are some areas in Australia where native title is now formally recognized. However, in New South Wales, where we have our Australian operations, most native title claims are yet to be resolved. There are registered native title claims in the Gunnedah Basin in New South Wales affecting PEL 238 and 433.

Native title can and has been extinguished across much of Australia and cannot be revived. Native title may be wholly extinguished in relation to particular areas of land by a grant of an inconsistent title, such as freehold or a lease conferring exclusive possession. Where this has occurred it is possible to determine that native title has been extinguished irrespective of the formal resolution of a claim. Native title has no effect in relation to land use in such areas. Native title is also extinguished where the traditional Aboriginal owners have lost their traditional links to the land. This can usually only be determined through the claim resolution process.

Native title can impact our Australian operations in two important ways:

 

•

Validity of interests: Where we are seeking to obtain an authority to prospect, develop resources or construct a pipeline over land subject to a registered native title claim or determination, in respect of which prior extinguishment cannot be demonstrated, it is necessary to follow the processes contained in the Commonwealth native title the Native Title Act 1993 (Cth) to ensure validity of the authority insofar as it affects native title.

 

•

Costs and delays associated with procedural rights of registered native title claimants/holders when seeking government authorities: Under the Native Title Act 1993 (Cth), registered native title claimants or holders (native title parties) have certain procedural rights in relation to the grant of authorities by the state government in respect of land to which they may or do hold native title. We may be required to attempt to reach agreement with any native title parties as to the terms on which they will agree to the grant of the authority we seek. Such an agreement may include immediate payments, revenue sharing, or both. Payments are likely to apply even before the claim is formally resolved. An agreement may also restrict the area where prospecting or development can occur in order to ensure that areas of cultural heritage significance are preserved. Reaching agreement with a native title party can be costly and cause delay. Generally, the costs associated with the grant of pipeline licenses are less than those for production approvals. It is possible to request the National Native Title Tribunal to arbitrate a dispute regarding the terms on which a prospecting or production authority can be granted, if there has been no resolution after six months. Other processes are available for resolution of disputes regarding pipeline licensing approvals according to state laws.

The process of drilling for and producing natural gas and oil involves many operating risks that can cause substantial losses, and we may not have enough insurance to cover these risks adequately.

The natural gas and oil business involves many operating hazards, such as:

 

•

Well blowouts, fires and explosions;

 

•

Surface craterings and casing collapses;

 

•

Uncontrollable flows of natural gas, oil or well fluids;

 

•

Pipe and cement failures;

 

•

Formations with abnormal pressures;

 

•

Stuck drilling and service tools;

 

•

Pipeline ruptures or spills;

 

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•

Natural disasters; and

 

•

Releases of toxic natural gas.

Any of these events could cause substantial losses to us as a result of:

 

•

Injury or death;

 

•

Damage to and destruction of property, natural resources and equipment;

 

•

Pollution and other environmental damage;

 

•

Regulatory investigations and penalties;

 

•

Suspension of operations; and

 

•

Repair and remediation costs.

We could also be responsible for environmental damage caused by previous owners of property that we purchase or lease. As a result, we may incur substantial liabilities to third parties or governmental entities. Although we maintain what we believe is appropriate and customary insurance for these risks, the insurance may not be available or sufficient to cover all of these liabilities. If these liabilities are not covered by our insurance, paying them could reduce or eliminate the funds available for exploration, development or acquisitions or result in the loss of our properties.

Approximately 79% of our revenues for the three months ended March 31, 2008 was from the production of wells located in our Hilltop area play in East Texas. Any disruption in production or our ability to process and sell our natural gas production from this area would have a material adverse effect on our results of operations.

Production of the natural gas in East Texas could unexpectedly be disrupted or curtailed due to reservoir or mechanical problems. Our natural gas produced from this area contains levels of carbon dioxide and hydrogen sulfide that are above levels accepted by gas purchasers. This production must be treated by the purchaser. A majority of our East Texas production is processed by the purchaser. If the purchaser’s facilities ceased to operate, were destroyed or otherwise needed replacement, it could require 60 to 90 days to replace or repair these facilities. A 60 to 90 day curtailment of our East Texas production could reduce current revenues by an estimated $9.3 million to $13.9 million, with a corresponding reduction in our cash flow.

The CBM which we produce in the Powder River Basin may be drained by offsetting production wells.

Our drilling locations in the Powder River Basin are spaced primarily using 80-acre spacing. Producing wells located on the 80-acre spacing units contiguous with our drilling locations may drain the acreage underlying our wells. If a substantial number of productive wells are drilled on spacing units adjacent to our properties, they may decrease our revenue and could have an adverse impact on the economically recoverable reserves of our properties that are susceptible to such drainage.

Our Powder River Basin CBM wells typically have a shorter reserve life and lower rates of production than conventional natural gas wells, which may adversely affect our profitability during periods of low natural gas prices.

The shallow coals from which we produce CBM in the Powder River Basin typically have a two to six year reserve life and have lower total reserves and produce at lower rates than most conventional natural gas wells. We depend on drilling a large number of wells each year to replace production and reserves in the Powder River Basin and to distribute operational expenses over a larger number of wells. A decline in natural gas prices could make certain wells uneconomical because production rates are lower on an individual well basis and may be insufficient to cover operational costs.

 

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There are a limited number of natural gas purchasers and transporters in the Hilltop area of our deep Bossier play in East Texas. The loss of our current purchaser and transporter and an inability to locate another purchaser and transporter would have a material adverse effect on our financial condition and results of operations.

There are a limited number of natural gas transporters in the Hilltop area in East Texas. For the year ended December 31, 2007, ETC accounted for substantially all of our revenues from this area. If ETC were to cease purchasing and transporting our natural gas and we were unable to contract with another transporter, it would have a material adverse effect on our financial condition, future cash flows and the results of operations.

Our ability to market our natural gas and oil may be impaired by capacity constraints on the gathering systems and pipelines that transport our natural gas and oil.

The availability of a ready market for our natural gas production depends on the proximity of our reserves to and the capacity of natural gas gathering systems, pipelines and trucking or terminal facilities. We enter into agreements with companies that own pipelines used to transport natural gas from the wellhead to contract destination. Those pipelines are limited in size and volume of natural gas flow. Should production begin, other outstanding contracts with other producers and developers could interfere with our access to a natural gas line to deliver natural gas to the market. We do not own or operate any natural gas lines or distribution facilities. Further, interstate transportation and distribution of natural gas is regulated by the federal government through the FERC. FERC sets rules and carries out administratively the oversight of interstate markets for natural gas and other energy policy. Among FERC’s powers is the ability to dictate sale and delivery of natural gas to any markets it oversees.

Additionally, state regulators have vast powers over sale, supply and delivery of natural gas and oil within their state borders. While we do employ certain companies to represent our interests before state regulatory agencies, our interests may not receive favorable rulings from any state agency, or some future occurrence may drastically alter our ability to enter into contracts or deliver natural gas to the market.

In recent years pipeline capacity for natural gas deliveries out of the Rocky Mountain area has been, at times, significantly constrained resulting in an oversupply and creating substantial discounts on spot natural gas prices received for regional production. This has had a substantial impact on the prices received for natural gas production from Wyoming and Montana, as compared to Gulf Coast natural gas prices. While a recently completed interstate pipeline currently has alleviated the problem by providing access to the Midwest interstate pipelines and markets, the relief may be offset over time by the expected increase in supply of natural gas available in the Rocky Mountains.

Australian natural gas markets and transmission infrastructure exists but they are not as developed or interconnected as the markets and infrastructure in the United States. Specifically, the PEL 238 concession is currently not served by natural gas transmission infrastructure. The initial gas market for PEL 238 natural gas is anticipated to be an electricity generation facility located near the town of Narrabri, New South Wales. A short transmission pipeline is required to be built to serve this initial market. Access to a larger electricity facility will require construction of a pipeline of approximately 300 kilometers to reach PEL 238 with an additional 150 kilometers of pipeline infrastructure required to access the natural gas markets in the Sydney-Newcastle-Wollongong markets. The capital costs for these projects, if deemed feasible, would be substantial in order to realize the value of any identified reserves and construction would require significant amounts of time.

Our exploration rights in Australia are subject to renewal at the discretion of the government.

 

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Coal bed methane exploration in New South Wales is conducted under a Petroleum Exploration License (“PEL”) granted under the Petroleum (Onshore) Act 1991 (NSW), which is granted at the discretion of the Minister. Each PEL requires the expenditure of a set amount of exploration costs and is generally subject to renewal a term of up to six years after the initial term of up to six years. On renewal of a PEL, the Minister may require reduction of the area to which the PEL applies. We cannot assure that our PELs will be renewed. Non-renewal or loss of any PEL could adversely affect our exploration and development plans, results of operations, financial condition or cash flows.

Competition in the natural gas and oil industry is intense. We are smaller and have less operating history than many of our competitors, and increased competitive pressure could adversely affect our results of operations.

We operate in a highly competitive environment. We compete with other natural gas and oil companies in all areas of our operations, including the acquisition of exploratory prospects and proven properties. Our competitors include major integrated natural gas and oil companies, numerous independent natural gas and oil companies, individuals and drilling and income programs. Many of our competitors are large, well-established companies that have substantially larger operating staffs and greater capital resources than we do and that, in many instances, have been engaged in the natural gas and oil business for a much longer time than we have. These companies may be able to pay more for exploratory prospects and productive natural gas and oil properties and may be able to define, evaluate, bid for and purchase more properties and prospects than our financial and human resources permit. In addition, these companies may be able to spend more on the existing and changing technologies that we believe are and will be increasingly important to the current and future success of natural gas and oil companies. Our ability to explore for natural gas and oil prospects and to acquire additional properties in the future will depend on our ability to conduct our operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. Increased competitive pressure could have a material adverse effect on our financial condition, future cash flows and the results of operations.

Acquisition prospects are difficult to assess and may pose additional risks to our operations.

Where appropriate, we may evaluate and pursue acquisition opportunities on terms our management considers favorable. In particular, we expect to pursue acquisitions that have the potential to economically increase our natural gas and oil reserves. The successful acquisition of natural gas and oil properties requires an assessment of:

 

•

Recoverable reserves;

 

•

Exploration potential;

 

•

Future natural gas and oil prices;

 

•

Operating costs;

 

•

Potential environmental and other liabilities; and

 

•

Permitting and other environmental authorizations required for our operations.

In connection with such an assessment, we would expect to perform a review of the subject properties that we believe to be generally consistent with industry practices. Nonetheless, the resulting conclusions are inexact and their accuracy inherently uncertain, and such an assessment may not reveal all existing or potential problems, nor will it necessarily permit a buyer to become sufficiently familiar with the properties to fully assess their merits and deficiencies. Inspections may not always be performed on every platform or well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. Future acquisitions could pose additional risks to our operations and financial results, including:

 

•

Problems integrating the purchased operations, personnel or technologies;

 

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•

Unanticipated costs;

 

•

Diversion of resources and management attention from our exploration business;

 

•

Entry into regions or markets in which we have limited or no prior experience; and

 

•

Potential loss of key employees, particularly those of the acquired organization.

We cannot control the activities on properties we do not operate, which may affect the timing and success of our future operations.

Other companies operate some of the properties in which we have an interest. As a result, we have a limited ability to exercise influence over operations for these properties or their associated costs. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could have a material adverse affect on the realization of our targeted returns on capital in drilling or acquisition activities. The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors that are outside of our control, including:

 

•

Timing and amount of capital expenditures;

 

•

The operator’s expertise and financial resources;

 

•

Approval of other participants in drilling wells; and

 

•

Selection of technology.

Technological changes could affect our operations.

The natural gas and oil industry is characterized by rapid and significant technological advancements and introductions of new products and services utilizing new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement such new technologies at substantial costs. In addition, many other natural gas and oil companies have greater financial, technical and personnel resources that may allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may be unable to respond to such competitive pressures and implement such technologies on a timely basis or at an acceptable cost. If one or more of the technologies that we currently use or may implement in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, it could have a material adverse effect on our financial condition, future cash flows and the results of operations.

Rapid growth could result in a strain on our resources.

Because of our size, our growth, if achieved, will likely place a significant strain on our financial, technical, operational and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the recruitment and retention of experienced managers, geoscientists and engineers, could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.

Our ability to successfully execute and maximize our business plan is dependent on our ability to obtain adequate financing.

Our 2008 capital expenditures under our current business plan are estimated to total approximately $65.4 million, of which $43.4 million is estimated to be spent on unconventional natural gas and oil exploration and development operations in East Texas, $7.4 million is estimated to be spent on CBM projects and additional projects in the United States and $14.6 million is estimated to be spent on CBM projects in Australia. Our business plan, which includes participation in 3-D seismic shoots, the drilling of exploration prospects and development projects and producing property acquisitions, has required and will continue to require substantial capital

 

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expenditures. We will require additional financing to fund our planned growth and scheduled debt maturities beyond the next 12 months. Our ability to raise additional capital will depend on the results of our operations and the status of various capital and industry markets at the time we seek such capital. Accordingly, we cannot be certain that additional financing will be available to us on acceptable terms, if at all. In particular, the terms of our credit agreements limit our ability to incur additional indebtedness. In the event additional capital resources are unavailable, we may be required to curtail our exploration and development activities or be forced to sell some of our assets in an untimely fashion or on less than favorable terms.

Hedging of our production may result in losses or prevent us from benefiting to the fullest extent possible from increases in prices for natural gas and oil.

In September 2007, we commenced hedging our natural gas production utilizing costless collars. Although these hedges may partially protect us from by declines in natural gas prices, the use of these arrangements may limit our ability to benefit from significant increases in the prices of natural gas.

Exchange rate fluctuations subject us to unique risks.

As our Australian activities increase, we will be increasingly exposed to the impact of fluctuations in the exchange rate between the Australian dollar and the U.S. dollar. We have only minimal exposure to Canadian currency fluctuations, as almost all of our current revenues and expenses are in U.S. dollars.

We depend on our key personnel, the loss of which could adversely affect our operations and financial performance.

We depend to a large extent on the services of a limited number of senior management personnel and directors. Particularly, the loss of the services of our chief executive officer, chief financial officer and chief operating officer could negatively impact our future operations. We have employment agreements with these key members of our senior management team; although, we do not maintain key-man life insurance on any of our senior management. We believe that our success is also dependent on our ability to continue to retain the services of skilled technical personnel. Our inability to retain skilled technical personnel could have a material adverse effect on our financial condition, future cash flows and the results of operations.

Our major shareholder may influence the activities and operations of certain jointly owned properties, which also could result in conflicts of interest.

As of March 31, 2008, Chesapeake Energy Corporation owned approximately 16.3% of our outstanding common shares. As a result, Chesapeake is in a position to heavily influence the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of or amendment to provisions in our Amended and Restated Articles of Incorporation, Bylaws and the approval of mergers and other significant corporate transactions. Their high level of ownership may also delay, defer or prevent a change in control of us and may adversely affect the voting and other rights of other shareholders. Chesapeake has the right to have an observer present at our board of directors meetings.

 

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Chesapeake and its subsidiaries are also engaged in the natural gas and oil business. Although we have entered into a joint operating agreement with Chesapeake, it is possible that we may in some circumstances be in direct or indirect competition with Chesapeake, including competition with respect to certain business strategies and transactions that we may propose to undertake. These conflicts of interest may have a material adverse affect our results of operations.

Some of our directors may not be subject to suit in the United States.

Two of our directors reside in Canada. As a result, it may be difficult or impossible to effect service of process within the United States upon those directors, to bring suit against them in the United States or to enforce in the United States courts any judgment obtained there against them predicated upon any civil liability provisions of the United States federal securities laws. Investors should not assume that Canadian courts will enforce judgments of United States courts obtained in actions against those directors predicated upon the civil liability provisions of the United States federal securities laws or the securities or “blue sky” laws of any state within the United States or will enforce, in original actions, liabilities against those directors upon the United States federal securities laws or any such state securities or blue sky laws.

 

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Index to Financial Statements

RATIO OF EARNINGS TO FIXED CHARGES

We have computed our ratio of earnings to fixed charges for the three months ended March 31, 2008 and 2007 and for each of our fiscal years ended December 31, 2007, 2006, 2005, 2004 and 2003. As we reported losses (deficiency with fixed charges )in each of the periods reported, our ratio of earnings to fixed charges was less than zero. The computation of earnings to fixed charges is set forth on Exhibit 12.1 to the registration statement of which this prospectus forms a part.

Ratio of earnings to fixed charges is calculated by dividing earnings by fixed charges from operations for the periods indicated. For purposes of calculating the ratio of earnings to fixed charges, (a) earnings represents pre-tax income from continuing operations plus fixed charges and amortization of capitalized interest, less capitalized interest and (b) fixed charges represents interest expensed and capitalized, amortization of financing costs, early extinguishment of debt and the portion of rent expense deemed to be the equivalent of interest.

You should read the ratio information below in conjunction with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and the notes thereto included elsewhere in this prospectus.

 

		For the Three Months Ended March 31,								For the Years Ended December 31,
		2008				2007				2007				2006				2005				2004				2003
										(in thousands)
Loss (deficiency with fixed charges)		$	(1,277	)		$	(10,955	)		$	(32,392	)		$	(84,839	)		$	(25,692	)		$	(12,776	)		$	(4,947	)
Ratio of earnings to fixed charges			—				—				—				—				—				—				—

USE OF PROCEEDS

The exchange offer is intended to satisfy our obligations under the registration rights agreement we entered into in connection with the issuance of the old notes. We will not receive any cash proceeds from the issuance of the new notes in the exchange offer. In consideration for issuing the new notes as contemplated in this prospectus, we will receive in exchange outstanding old notes in like principal amount. We will cancel all old notes surrendered in exchange for new notes in the exchange offer. As a result, the issuance of the new notes will not result in any increase or decrease in our indebtedness.

 

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THE EXCHANGE OFFER

Purpose and Effect of the Exchange Offer

We sold $100.0 million in aggregate principal amount at maturity of the old notes, which was completed on November 29, 2007. The old notes were sold to investors in a private placement in the United States in reliance on Section 4(2) and/or Regulation D of the Securities Act or to the initial purchasers who in turn resold the outstanding notes to offshore investors pursuant to Regulation S of the Securities Act.

We sold the old notes in transactions that were exempt from or not subject to the registration requirements under the Securities Act. Accordingly, the old notes are subject to transfer restrictions. In general, you may not offer or sell the old notes unless either the offer and sale thereof are registered under the Securities Act or are exempt from or not subject to registration under the Securities Act and applicable state securities laws.

In the registration rights agreement, we agreed to file an exchange offer registration statement no later than 150 days after the closing date following the offering of the old notes. We also agreed to use our commercially reasonable best efforts to cause the exchange offer registration statement for the new notes to become effective within 240 days after the closing date. Now, to satisfy our obligations under the registration rights agreement, we are offering holders of the old notes who are able to make certain representations described below the opportunity to exchange their notes for the new notes in the exchange offer. The exchange offer will be open for a period of at least 30 days. During the exchange offer period, we will issue the new notes in exchange for all old notes properly surrendered and not withdrawn before the expiration date. The new notes will be registered and the transfer restrictions, registration rights and provisions for additional interest relating to the old notes will not apply to the new notes.

 

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Terms of Exchange

Subject to the terms and conditions described in this prospectus and in the letter of transmittal, we will accept for exchange any old notes properly tendered and not withdrawn prior to 5:00 p.m., New York City time, on the expiration date of the exchange offer. We will issue new notes in principal amount equal to the principal amount of old notes surrendered in the exchange offer. Old notes may be tendered only for new notes and only in denominations of $2,000 and integral multiples of $1,000.

The exchange offer is not conditioned upon any minimum aggregate principal amount of old notes being tendered in the exchange offer.

As of the date of this prospectus, $100,000,000 in aggregate principal amount of 12¾% Senior Secured Notes due 2012 are outstanding. This prospectus is being sent to DTC, the sole registered holder of the old notes, and to all persons that we can identify as beneficial owners of the old notes. There will be no fixed record date for determining registered holders of old notes entitled to participate in the exchange offer.

We intend to conduct the exchange offer in accordance with the provisions of the registration rights agreement, the applicable requirements of the Securities Act and the Securities Exchange Act of 1934, as amended, or the “Exchange Act,” and the rules and regulations of the Commission. Old notes the holders of which do not tender for exchange in the exchange offer will remain outstanding and continue to accrue interest. These old notes will be entitled to the rights and benefits such holders have under the indenture relating to the old notes and the registration rights agreement.

 

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We will be deemed to have accepted for exchange properly tendered old notes when we have given oral or written notice of the acceptance to the exchange agent and complied with the applicable provisions of the registration rights agreement. The exchange agent will act as agent for the tendering holders for the purposes of receiving the new notes from us.

If you tender old notes in the exchange offer, you will not be required to pay brokerage commissions or fees or, except to the extent indicated by the instructions to the letter of transmittal, transfer taxes with respect to the exchange of old notes. We will pay all charges and expenses, other than certain applicable taxes described below, in connection with the exchange offer. Please read “— Fees and Expenses” for more details regarding fees and expenses incurred in connection with the exchange offer. We will return any old notes that we do not accept for exchange for any reason without expense to their tendering holders promptly after the expiration or termination of the exchange offer.

Expiration, Extension and Amendment

The exchange offer will expire at 5:00 p.m., New York City time, on July 31, 2008, unless, in our sole discretion, we extend it.

We expressly reserve the right, at any time or various times, to extend the period of time during which the exchange offer is open. We may delay acceptance of any old notes by giving oral or written notice of such extension to their holders at any time until the exchange offer expires or terminates. During any such extensions, all old notes previously tendered will remain subject to the exchange offer, and we may accept them for exchange.

To extend the exchange offer, we will notify the exchange agent orally or in writing of any extension. We will notify the registered holders of old notes of the extension no later than 9:00 a.m. New York City time on the business day after the previously scheduled expiration date.

Procedures for Tendering

To participate in the exchange offer, you must properly tender your old notes to the exchange agent as described below. We will only issue new notes in exchange for old notes that you timely and properly tender. Therefore, you should allow sufficient time to ensure timely delivery of the old notes, and you should follow carefully the instructions on how to tender your old notes. It is your responsibility to properly tender your old notes. We have the right to waive any defects. We are not, however, required to waive defects, and neither we nor the exchange agent is required to notify you of any defects in your tender.

If you have any questions or need help in exchanging your old notes, please call the exchange agent whose address and phone number are described in the letter of transmittal included as Annex A to this prospectus.

All of the old notes were issued in book entry form, and all of the old notes are currently represented by global certificates registered in the name of Cede & Co., the nominee of DTC. We have confirmed with DTC that the old notes may be tendered using ATOP. The exchange agent will establish an account with DTC for purposes of the exchange offer promptly after the commencement of the exchange offer, and DTC participants may electronically transmit their acceptance of the exchange offer by causing DTC to transfer their old notes to the exchange agent using the ATOP procedures. In connection with the transfer, DTC will send an “agent’s message” to the exchange agent. The agent’s message will state that DTC has received instructions from the participant to tender old notes and that the participant agrees to be bound by the terms of the letter of transmittal.

By using the ATOP procedures to exchange old notes, you will not be required to deliver a letter of transmittal to the exchange agent. You will, however, be bound by its terms just as if you had signed it.

There is no procedure for guaranteed late delivery of the old notes.

 

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Determinations Under the Exchange Offer. We will determine in our sole discretion all questions as to the validity, form, eligibility, time of receipt, acceptance of tendered old notes and withdrawal of tendered old notes. Our determination will be final and binding. We reserve the absolute right to reject any old notes not properly tendered or any old notes our acceptance of which would, in the opinion of our counsel, be unlawful. We also reserve the right to waive any defect, irregularities or conditions of tender as to particular old notes. Our interpretation of the terms and conditions of the exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, all defects or irregularities in connection with tenders of old notes must be cured within such time as we shall determine. Although we intend to notify holders of defects or irregularities with respect to tenders of old notes, neither we, the exchange agent nor any other person will incur any liability for failure to give such notification. Tenders of old notes will not be deemed made until such defects or irregularities have been cured or waived. Any old notes received by the exchange agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned to the tendering holder as soon as practicable following the expiration date of the exchange.

When We Will Issue New Notes. In all cases, we will issue new notes for old notes that we have accepted for exchange under the exchange offer only after the exchange agent receives, prior to 5:00 p.m., New York City time, on the expiration date,

 

•

A book-entry confirmation of such old notes into the exchange agent’s account at DTC; and

 

•

A properly transmitted agent’s message.

Return of Old notes Not Accepted or Exchanged. If we do not accept any tendered old notes for exchange or if old notes are submitted for a greater principal amount than the holder desires to exchange, the unaccepted or non exchanged old notes will be returned without expense to their tendering holder. Such non exchanged old notes will be credited to an account maintained with DTC. These actions will occur as promptly as practicable after the expiration or termination of the exchange offer.

Valid Tender. By agreeing to be bound by the letter of transmittal, you will represent to us that, among other things:

 

•

Any new notes that you receive will be acquired in the ordinary course of your business;

 

•

You have no arrangement or understanding with any person or entity to participate in the distribution of the new notes;

 

•

You are not engaged in and do not intend to engage in the distribution of the new notes;

 

•

If you are a broker-dealer that will receive new notes for your own account in exchange for old notes, you acquired those old notes as a result of market-making activities or other trading activities and you will deliver this prospectus, as required by law, in connection with any resale of the new notes; and

 

•

You are not an “affiliate,” as defined in Rule 405 under the Securities Act, of us.

Withdrawal Rights

Except as otherwise provided in this prospectus, you may withdraw your tender at any time prior to 5:00 p.m., New York City time, on the expiration date of the exchange offer. For a withdrawal to be effective you must comply with the appropriate ATOP procedures. Any notice of withdrawal must specify the name and number of the account at DTC to be credited with withdrawn old notes and otherwise comply with the ATOP procedures.

We will determine all questions as to the validity, form, eligibility and time of receipt of a notice of withdrawal. Our determination shall be final and binding on all parties. We will deem any old notes so withdrawn not to have been validly tendered for exchange for purposes of the exchange offer.

 

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Any old notes that have been tendered for exchange but that are not exchanged for any reason will be credited to an account maintained with DTC for the old notes. This return or crediting will take place as soon as practicable after withdrawal, rejection of tender, expiration or termination of the exchange offer. You may retender properly withdrawn old notes by following the procedures described under “— Procedures for Tendering” above at any time on or prior to the expiration date of the exchange offer.

 

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Resales of New Notes

Based on interpretations by the staff of the SEC, as described in no-action letters issued to third parties that are not related to us, we believe that new notes issued in the exchange offer in exchange for old notes may be offered for resale, resold or otherwise transferred by holders of the new notes without compliance with the registration and prospectus delivery provisions of the Securities Act, if:

 

•

The new notes are acquired in the ordinary course of the holder’s business;

 

•

The holders have no arrangement or understanding with any person to participate in the distribution of the new notes;

 

•

The holders are not “affiliates” of ours within the meaning of Rule 405 under the Securities Act; and

 

•

The holders are not a broker-dealer who purchased old notes directly from us for resale pursuant to Rule 144A or any other available exemption under the Securities Act.

However, the SEC has not considered the exchange offer described in this prospectus in the context of a no-action letter. The staff of the SEC may not make a similar determination with respect to the exchange offer as in the other circumstances. Each holder who wishes to exchange old notes for new notes will be required to represent that it meets the above four requirements.

Any holder who is an affiliate of ours or who intends to participate in the exchange offer for the purpose of distributing new notes or any broker-dealer who purchased old notes directly from us for resale pursuant to Rule 144A or any other available exemption under the Securities Act:

 

•

Cannot rely on the applicable interpretations of the staff of the SEC mentioned above;

 

•

Will not be permitted or entitled to tender the old notes in the exchange offer; and

 

•

Must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any secondary resale transaction.

Each broker-dealer that receives new notes for its own account in exchange for old notes must acknowledge that the old notes were acquired by it as a result of market-making activities or other trading activities and agree that it will deliver a prospectus that meets the requirements of the Securities Act in connection with any resale of the new notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. Please read “Plan of Distribution”. A broker-dealer may use this prospectus, as it may be amended or supplemented from time to time, in connection with the resales of new notes received in exchange for old notes that the broker-dealer acquired as a result of market-making or other trading activities. Any holder that is a broker-dealer participating in the exchange offer must notify the exchange agent at the telephone number set forth in the enclosed letter of transmittal and must comply with the procedures for broker-dealers participating in the exchange offer. We have not entered into any arrangement or understanding with any person to distribute the new notes to be received in the exchange offer.

 

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In addition, to comply with state securities laws, the new notes may not be offered or sold in any state unless they have been registered or qualified for sale in such state or an exemption from registration or qualification, with which there has been compliance, is available. The offer and sale of the new notes to “qualified institutional buyers,” as defined under Rule 144A of the Securities Act, is generally exempt from registration or qualification under the state securities laws. We currently do not intend to register or qualify the sale of new notes in any state where an exemption from registration or qualification is required and not available.

Exchange Agent

Wells Fargo Bank, National Association has been appointed as the exchange agent for the exchange offer. Questions and requests for assistance, requests for additional copies of this prospectus or of the letter of transmittal should be directed to the exchange agent addressed as follows:

Wells Fargo Bank, National Association

 

By Facsimile for Eligible Institutions:		By Registered and Certified Mail:		Confirm by Telephone:
(214) 777-4086		Wells Fargo Bank, NA		(214) 740-1573
Attention: Patrick T. Giordano		Corporate Trust Operations
		MAC N9303-121
		PO Box 1517
		Minneapolis, MN 55480
		By Regular Mail or Overnight Courier:
		Wells Fargo Bank, NA
		Corporate Trust Operations
		MAC N9303-121
		Sixth & Marquette Avenue Minneapolis, MN 55479
		In person by hand only:
		Wells Fargo Bank, NA
		12th Floor - Northstar East Building
		Corporate Trust Operations
		608 Second Avenue South Minneapolis, MN

Fees and Expenses

We will bear the expenses of soliciting tenders. The principal solicitation is being made by mail; however, we may make additional solicitation by telegraph, telephone or in person by our officers and regular employees and those of our affiliates.

We have not retained any dealer manager in connection with the exchange offer and will not make any payments to broker dealers or others soliciting acceptances of the exchange offer. We will, however, pay the exchange agent reasonable and customary fees for its services and reimburse it for its related reasonable out of pocket expenses.

We will pay the cash expenses to be incurred in connection with the exchange offer. They include:

 

•

Commission registration fees;

 

•

Fees and expenses of the exchange agent and trustee;

 

•

Accounting and legal fees and printing costs; and

 

•

Related fees and expenses.

Transfer Taxes

We will pay all transfer taxes, if any, applicable to the exchange of old notes under the exchange offer. Each tendering holder, however, will be required to pay any transfer taxes, whether imposed on the registered holder or any other person, if a transfer tax is imposed for any reason other than the exchange of old notes under the exchange offer.

Consequences of Failure to Exchange Outstanding Securities

If you do not exchange your old notes for new notes under the exchange offer, the old notes you hold will continue to be subject to the existing restrictions on transfer. In general, you may not offer or sell the old notes except under an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. We do not intend to register old notes under the Securities Act unless the registration rights agreement requires us to do so.

Accounting Treatment

We will record the new notes in our accounting records at the same carrying value as the old notes. This carrying value is the aggregate principal amount of the old notes, as reflected in our accounting records on the date of exchange. Accordingly, we will not recognize any gain or loss for accounting purposes in connection with the exchange offer, other than the recognition of the fees and expenses of the offering as stated under “— Fees and Expenses.”

Other

Participation in the exchange offer is voluntary, and you should consider carefully whether to accept. You are urged to consult your financial and tax advisors in making your own decision on what action to take.

We may in the future seek to acquire untendered old notes in open market or privately negotiated transactions, through subsequent exchange offers or otherwise. We have no present plans to acquire any old notes that are not tendered in the exchange offer or to file a registration statement to permit resales of any untendered old notes.

 

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CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS

This prospectus and the documents incorporated contain or incorporate by reference “forward-looking statements” within the meaning of Section 27A of the Securities Act, and Section 21E of the Exchange Act. Forward-looking statements give our current expectations or forecasts of future events. These statements can be identified by the use of forward-looking words, including “may”, “expect”, “anticipate”, “plan”, “project”, “believe”, “estimate”, “intend”, “will”, “should” or other similar words. Forward-looking statements may include statements that relate to, among other things, our:

 

•

Financial position;

 

•

Business strategy and budgets;

 

•

Anticipated capital expenditures;

 

•

Drilling of wells;

 

•

Natural gas and oil reserves;

 

•

Timing and amount of future production of natural gas and oil;

 

•

Operating costs and other expenses;

 

•

Cash flow and anticipated liquidity;

 

•

Prospect development; and

 

•

Property acquisitions and sales.

Although we believe the expectations reflected in such forward-looking statements are reasonable, we cannot assure you that such expectations will occur. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from actual future results expressed or implied by the forward-looking statements. These factors include among others:

 

•

Low and/or declining prices for natural gas and oil;

 

•

Demand for natural gas and oil;

 

•

Natural gas and oil price volatility;

 

•

The risks associated with exploration, including cost overruns and the drilling of non-economic wells or dry holes;

 

•

Ability to raise capital to fund capital expenditures;

 

•

The ability to find, acquire, market, develop and produce new natural gas and oil properties;

 

•

Uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of development expenditures;

 

•

Operating hazards inherent to the natural gas and oil business;

 

•

Down hole drilling and completion risks that are generally not recoverable from third parties or insurance;

 

•

Potential mechanical failure or under-performance of significant wells or pipeline mishaps;

 

•

Adverse weather conditions;

 

•

Availability and cost of material and equipment, such as drilling rigs and transportation pipelines;

 

•

The number of well locations to be drilled and the time frame in which they will be drilled;

 

•

Delays in anticipated start-up dates;

 

•

Actions or inactions of third-party operators of our properties;

 

•

Ability to find and retain skilled personnel;

 

•

Strength and financial resources of competitors;

 

•

Potential defects in title to our properties;

 

•

Federal and state regulatory developments and approvals;

 

•

Losses possible from pending or future litigation;

 

•

Environmental risks;

 

•

Worldwide political and economic conditions; and

 

•

Operational and financial risks associated with foreign exploration and production.

For these and other reasons, actual results may differ materially from those projected or implied. We believe it is important to communicate our expectations of future performance to our investors. However, events may occur in the future that we are unable to accurately predict, or over which we have no control. We caution you against putting undue reliance on forward-looking statements or projecting any future results based on such statements.

 

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All subsequent written and oral forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this section and any other cautionary statements that may accompany such forward-looking statements. We do not undertake any obligation to release publicly any revisions to these forward-looking statements to reflect events or circumstances after the date of this prospectus or to reflect the occurrence of unanticipated events, unless the securities laws require us to do so.

 

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SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

The following tables set forth selected historical consolidated financial data for the three month ended March 31, 2008 and 2007 and for the years ended December 31, 2007, 2006, 2005, 2004 and 2003. The historical financial data as of December 31, 2007 and 2006 and for the years ended December 31, 2007, 2006 and 2005 are derived from our audited consolidated financial statements and the notes thereto included in this prospectus. The unaudited condensed consolidated balance sheet data and statement of operations data at March 31, 2007 and 2008 and for the three month periods ended March 31, 2007 and 2008 are derived from our unaudited condensed combined financial statements and the notes thereto included in this prospectus. The historical financial data as of December 31, 2005, 2004 and 2003 and for the years ended December 31, 2004 and 2003 are derived from our audited consolidated financial statements which are not included in this prospectus. The selected financial 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 elsewhere in this prospectus.

 

		For the Three Months Ended March 31,								For the Years Ended December 31,
		2008				2007				2007				2006				2005				2004				2003
		(unaudited)								(in thousands, except per share and share amounts)
Revenues:
Natural gas and oil revenues		$	16,846			$	7,515			$	34,565			$	26,765			$	27,442			$	6,059			$	1,461
Unrealized natural gas hedge loss			(1,413	)			—				—				—				—				—				—
Expenses:			15,433				7,515				34,565				26,765				27,442				6,059				1,461
Lease operating expenses, production taxes and transportation and treating			2,270				2,312				8,690				8,584				6,910				2,000				712
Depreciation, depletion and amortization			6,409				4,341				21,456				16,332				13,914				3,233				572
Impairment of natural gas and oil properties			—				—				28,514				56,280				8,697				6,306				552
Accretion of asset retirement obligation			82				66				281				234				109				52				54
Mineral resource properties			—				13				(133	)			450				65				32				30
General and administrative expenses			4,275				6,792				16,906				13,548				8,710				4,023				1,909
Litigation and settlement expenses			—				1,365				1,365				2,407				—				—				—
Total expenses			13,036				14,889				77,079				97,835				38,405				15,646				3,829
Income (loss) from operations			2,397				(7,374	)			(42,514	)			(71,070	)			(10,963	)			(9,587	)			(2,368	)
Other (expenses) income:
Interest expense			(2,096	)			(3,943	)			(14,079	)			(15,599	)			(13,905	)			(3,248	)			(2,567	)
Early extinguishment of debt			—				—				(15,684	)			—				(1,356	)			—				—
Investment income and other			823				363				3,196				1,836				492				56				18
Gain on sale of assets			—				—				38,536				—				—				—				—
Foreign transaction gain (loss)			(37	)			(1	)			5				(6	)			40				3				91
INCOME (LOSS) BEFORE INCOME TAXES			1,087				(10,955	)			(30,540	)			(84,839	)			(25,692	)			(12,776	)			(4,826	)
Provision for income taxes			—				—				—				—				—				—				—
NET INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE			1,087				(10,955	)			(30,540	)			(84,839	)			(25,692	)			(12,776	)			(4,826	)
Cumulative effect of a change in accounting principle			—				—				—				—				—				—				(121	)
NET INCOME (LOSS)		$	1,087			$	(10,955	)		$	(30,540	)		$	(84,839	)		$	(25,692	)		$	(12,776	)		$	(4,947	)
NET INCOME (LOSS) PER SHARE:
Basic and diluted		$	0.01			$	(0.06	)		$	(0.15	)		$	(0.50	)		$	(0.20	)		$	(0.12	)		$	(0.05	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic and diluted			207,098,570				195,015,561				202,828,792				170,014,733				129,398,548				111,374,446				104,958,180

 

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		As of and for the Three Months  Ended March 31,								As of and for the Years Ended December 31,
		2008				2007				2007				2006				2005				2004				2003
		(unaudited)								(in thousands)
Statements of Cash Flow Data:
Capital expenditures		$	19,957			$	18,389			$	64,841			$	50,215			$	33,287			$	34,221			$	4,763
Net cash provided by (used in):
Operating activities			14,292				281				7,442				(1,281	)			3,380				(1,122	)			(2,447	)
Investing activities			(21,183	)			(18,404	)			(3,467	)			(66,949	)			(77,833	)			(36,062	)			2,585
Financing activities			5				(1	)			41,146				47,819				119,755				52,345				283
Balance Sheet Data:
Cash and cash equivalents		$	78,968			$	22,609			$	85,854			$	40,733			$	61,144			$	15,842			$	681
Property, plant and equipment, net			167,358				180,607				157,120				160,826				165,347				56,564				35,799
Total assets			268,285				226,608				261,750				228,889				240,128				84,442				38,757
Total debt			132,715				94,607				132,685				93,803				90,631				57,878				6,562
Shareholders’ equity			93,160				89,230				95,269				98,342				120,776				21,976				23,669

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL

CONDITION AND RESULTS OF OPERATIONS

You should read this discussion in conjunction with our audited and unaudited consolidated financial statements and the related notes beginning on page F-1 of this prospectus. Management’s discussion and analysis may contain forward looking statements that are provided to assist in the understanding of anticipated future financial performance. However, this performance involves risks and uncertainties that may cause actual results to differ materially from these expressed in the forward looking statements. Some of the important factors that could cause our actual results or outcomes to differ from those discussed are listed under “Cautionary Statements Regarding Forward-Looking Statements”.

Overview

We are an independent energy company engaged in the exploration, development and production of natural gas and oil in the United States and Australia. Our principal business activities include the identification, acquisition, and subsequent exploration and development of natural gas and oil properties. Our emphasis is on prospective deep structures identified through seismic and other analytical techniques as well as unconventional natural gas reserves, such as CBM. We are also pursuing unconventional natural gas exploration in the deep Bossier play in the Hilltop area in East Texas. Our primary CBM properties are in the United States in the Powder River Basin in Wyoming and Montana and in the Gunnedah Basin of Australia. We recently agreed to release our interests in the Gippsland Basin of Australia in connection with our settlement of disputes with GeoStar.

Our major domestic asset is approximately 35,400 gross (16,300 net) acres in the Bossier play in the Hilltop area of East Texas. During the past three years, we spent approximately $196.6 million in acreage, seismic and reserve acquisition and exploratory and development drilling on this acreage. While we have not attained positive net income from operations in the past three years, and there can be no assurance that operating income and net earnings will be achieved in future periods, our recent efforts have resulted in significant growth in production over the past three-year period. As we continue the exploitation and development drilling in the Hilltop area, we expect to show further improvement in our operations.

Our international activities are focused on CBM development in Australia on over 6.0 million gross (2.1 million net) acres in New South Wales. We are in the early stages of development of this potentially significant asset, which could have a material and positive long-term impact on our financial results. Although we currently have no commercial production, we and our joint venture partner have been approached by potential buyers with an interest in potentially contracting for future deliveries of natural gas from PEL 238 for use in the generation of electricity. In September 2007, NSA certified a quantity of proved and probable reserves under guidelines established by the Society of Petroleum Engineers (“SPE”), as a result of the success of one of our pilot production projects on PEL 238. These reserves, however, are not yet established as proved reserves under SEC guidelines nor can we assure that other unevaluated acreage will contain similar reserves.

Our financial results depend upon many factors which significantly affect our results of operations including the following:

 

•

The level and success of exploration and development activity;

 

•

The sales prices of natural gas and crude oil;

 

•

The level of total sales volumes of natural gas and crude oil; and

 

•

The availability of and our ability to raise the capital necessary to meet our cash flow and liquidity needs.

We plan our activities and budget based on conservative sales price assumptions, given the inherent volatility of natural gas and oil prices that are influenced by many factors beyond our control. We focus our efforts on increasing natural gas and oil reserves and production and strive to control costs at an appropriate level. Our future earnings and cash flows are dependent on our ability to manage our overall cost structure to a level that allows for profitable production. Our future earnings will also be impacted by the changes in the fair market value of hedges we executed to mitigate the volatility in the changes of natural gas and oil prices in future periods. These instruments meet the criteria to be accounted for as cash flow hedges, and until settlement, the changes in fair

 

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market value of our hedges will be included as a component of stockholder’s equity to the extent effective in periods of rising prices, these transactions will mitigate future earnings and in periods of declining prices will increase future earnings in the respective period the positions are settled.

Like other natural gas and oil exploration and production companies, we face the fact of natural production declines. As initial reservoir pressures are depleted, natural gas and oil production from a given well will decrease. Thus, a natural gas and oil exploration and production company depletes part of its asset base with each unit of natural gas and oil it produces. We attempt to overcome this natural decline by adding reserves in excess of what we produce through successful drilling or acquisition. Our future growth will depend on our ability to continue to add reserves in excess of our production. We will maintain our focus on adding reserves through drilling and acquisitions, while placing a clear priority on lowering our cost of replacing reserves. Consistent with our stated strategies, we will emphasize maintaining a high-quality inventory of drilling locations, while also focusing on improving our capital and cost efficiency.

On June 12, 2008, our Parent entered into a settlement agreement with GeoStar to settle all outstanding disputes. The settlement includes an upfront cash payment by our Parent of approximately $25.7 million plus the issuance to GeoStar of a Warrant to purchase 10 million of our Parent’s common shares. Pursuant the settlement, GeoStar will assign to our Parent all of GeoStar’s oil and gas interests in West Virginia and Pennsylvania while our Parent will acknowlede GeoStar’s clear title to an exploration license (EL 4416) and assign its interest to GeoStar’s Australian subsidiary in an exploration license application (EL 4968), both of which are in the Gippsland Basin of Victoria, Australia. As of December 31, 2007, EL 4416 and EL 4968 had no attributable proved reserves or production.

Certain other corrective lease assignments and releases are being made between our Parent and GeoStar and each have mutually agreed to release all claims against each other, their affiliates and current and past officers and directors. For more discussion of the settlement, please see “Business—Recent Developments—Settlement of Arbitration and Litigation with GeoStar and Affiliates”.

Results of Operations

The following is a comparative discussion of the results of operations for the periods indicated. It should be read in conjunction with the consolidated financial statements and the related notes to the consolidated financial statements.

The following table gives information about production volumes and prices of natural gas and oil for the periods indicated:

 

		For the Three Months Ended March 31,						For the Years Ended December 31,
		2008			2007			2007			2006			2005
Production:
Natural gas (MMcf)			2,406			1,253			6,577			4,646			3,810
Oil (MBbl)			1			3			7			12			2
Total (MMcfe)			2,413			1,272			6,621			4,716			3,822
Total (MMcfed)			26.5			14.1			18.1			12.9			10.5
Average sales prices:
Natural gas (per Mcf)		$	6.96		$	5.86		$	5.18		$	5.60		$	7.18
Oil (per Bbl)		$	96.84		$	55.05		$	66.17		$	64.66		$	50.85

Three Months Ended March 31, 2008 compared to the Three Months Ended March 31, 2007

Revenues. Substantially all of our revenues are derived from the production of natural gas in the United States. Natural gas and oil revenues were $16.8 million for the three months ended March 31, 2008, up 124% from $7.5 million for the three months ended March 31, 2007. Of the increase in revenues, 72% was the result of a 88% increase in natural gas production volumes, primarily in East Texas, and 28% was due to a 19% increase in prices. During the three months ended March 31, 2008, approximately 44% of our natural gas production was hedged. The realized effect of hedging on natural gas sales was a decrease of $232,000 in revenues resulting in a decrease in total price received from $7.05 per Mcf to $6.96 per Mcf.

Unrealized natural gas hedge loss of $1.4 million is comprised of $169,000 of ineffectiveness and $1.2 million related to the time value of the costless collars. For the remainder of 2008, we have approximately 50% of our estimated gas production hedged.

Production taxes. We reported production taxes of $269,000 for the three months ended March 31, 2008, compared to $294,000 for the three months ended March 31, 2007. The lower overall production tax level is the result of refunds and abatements of severance taxes due to “tight sands” production on certain of our Hilltop wells.

Lease operating expenses. We reported lease operating expenses of $1.5 million for the three months ended March 31, 2008, down from $1.7 million for the three months ended March 31, 2007. Our lease operating expenses were $0.64 per Mcfe for the three months ended March 31, 2008, compared to $1.33 per Mcfe for the comparable period in 2007. This decrease was due to lower ad valorem taxes, workover expense and the elimination of lease costs associated with natural gas treatment plants in East Texas. This decrease was partially offset by an increased number of producing wells and increased production.

Transportation and treating. We reported transportation expenses of $459,000 for the three months ended March 31, 2008, up from 323,000 for the three months ended March 31, 2007. This increase was primarily due to increased production and prices in Wyoming.

Depreciation, depletion and amortization. We reported depreciation, depletion and amortization (“DD&A”) of $6.4 million for the three months ended March 31, 2008, up from $4.3 million for the three months ended March 31, 2007. The increase in DD&A expense was the result of a 90% increase in production, primarily attributable to new East Texas wells drilled during 2007. The DD&A rate for the three months ended March 31, 2008 was $2.66 per Mcfe, as compared to $3.41 for the comparable period in 2007.

General and administrative. We reported general and administrative expenses of $4.3 million for the three months ended March 31, 2008, down from $6.8 million for the three months ended March 31, 2007. This decrease in general and administrative expenses was primarily due to an allowance for doubtful accounts of $3.6 million recorded in the three months ended March 31, 2007, which was partially offset by an increase in professional service charges, including legal costs and personnel costs. Non-cash stock-based compensation expense pursuant to the SFAS 123R, which is included in general and administrative expenses, was $856,000 and $1.2 million for the three months ended March 31, 2008 and 2007, respectively.

Litigation settlement expense. The $1.4 million litigation settlement expense incurred in the three months ended March 31, 2007 was primarily the result of an accrual related to a proposed settlement with GeoStar on certain matters, which have since been settled. There was no litigation settlement expense for the three months ended March 31, 2008. For more discussion of the settlement, please see “Business—Recent Developments—Settlement of Arbitration and Litigation with GeoStar and Affiliates”.

Interest expense. We reported interest expense of $2.1 million for the three months ended March 31, 2008, compared to $3.9 million for the three months ended March 31, 2007. The decrease in interest expense was primarily the result of $2.4 million of interest being capitalized during the three months ended March 31, 2008, resulting from capital activity expansion in Texas and Australia, which was partially offset by higher interest expense on the new 12¾% senior secured notes. There was no capitalized interest recorded in the 2007 period.

Year Ended December 31, 2007 compared to Year Ended December 31, 2006

Revenues. Substantially all of our revenues are derived from the production of natural gas in the United States. Revenues were $34.6 million for the year ended December 31, 2007, up 29% from $26.8 million for the year ended December 31, 2006. The increase in revenues was the result of a 42% increase in natural gas production primarily in East Texas, which was partially offset by an 8% decrease in natural gas prices.

Production taxes. We reported production taxes of $765,000 for the year ended December 31, 2007, down from $1.5 million for the year ended December 31, 2006. This decrease was the result of tight sand credit refunds on our Texas natural gas sales and lower Wyoming taxes due to gas price declines.

Lease operating expenses. We reported lease operating expenses of $6.3 million for the year ended December 31, 2007, up from $5.5 million for the year ended December 31, 2006. This increase was due to an increased number of producing wells and increased production. Our lease operating expenses were $0.95 per Mcfe for the year ended December 31, 2007, compared to $1.18 per Mcfe for the comparable period in 2006.

Transportation and treating. We reported transportation expenses of $1.6 million for the years ended December 31, 2007 and 2006. Transportation and treating expense was constant as it relates to our Powder River Basin CBM production, which did not change significantly from 2006.

 

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Depreciation, depletion and amortization. Depreciation, depletion and amortization was $21.5 million for the year ended December 31, 2007, up from $16.3 million for the year ended December 31, 2006. The increase in DD&A expense was the result of a 40% increase in production, primarily attributable to new East Texas wells drilled during 2007. The DD&A rate for the year ended December 31, 2007 was $3.22 per Mcfe, as compared to $3.44 for the comparable period in 2006.

Impairment of natural gas and oil properties. Impairment of U.S. natural gas and oil properties was $28.5 million for the year ended December 31, 2007, compared to $56.3 million for the comparable period ended December 31, 2006. The 2007 impairment is the result of net natural gas and oil property costs, as adjusted for related deferred income taxes, if any, and other adjustments, exceeding the sum of estimated future net revenues using weighted average after basis adjustment prices in effect at June 30, 2007, the date of the impairment, held constant at $5.72 per Mcf for natural gas, discounted at 10%, and unproven properties at historical costs of $43.6 million. The 2006 impairment was the result of net natural gas and oil property costs, as adjusted for related deferred income taxes and other adjustments, exceeding the sum of estimated future net revenues using post end of period weighted average after basis adjustment prices held constant of $6.11 per Mcf for natural gas, discounted at 10%, and unproven property at historical cost of $81.5 million, as adjusted for related income taxes and other adjustments.

General and administrative. We reported general and administrative expenses of $16.9 million for the year ended December 31, 2007, up from $13.5 million for the year ended December 31, 2006. This increase in general and administrative expenses was primarily due to an increase in allowance for doubtful accounts and professional service charges, including Sarbanes-Oxley compliance costs, partially offset by a decline in contract personnel costs. The allowance for doubtful accounts was increased by $3.7 million to fully reserve the GeoStar receivable due to current litigation. Non-cash stock-based compensation expense pursuant to the SFAS 123R, which is included in general and administrative expenses, was $3.9 million for both years ended December 31, 2007 and 2006.

Litigation settlement expense. The $1.4 million litigation settlement expense incurred in 2007 was primarily the result of an accrual of a settlement payment related to a proposed settlement with GeoStar on certain matters. That settlement proposal was never finalized (Note 16 – Commitments and Contingencies – Litigation – Arbitration and Litigation with GeoStar Corporation and Affiliates). The $2.4 million litigation settlement expense incurred in 2006 was primarily the result of a settlement payment regarding Western Gas Resources, Inc., et. al. litigation involving a gas gathering agreement and its applicability to properties we exchanged in 2002 and settlement of the Burning Rock Energy LLC, et. al. litigation by assigning our interest in certain disputed properties.

Interest expense. We reported interest expense of $14.1 million for the year ended December 31, 2006, compared to $15.6 million for the year ended December 31, 2006. The decrease in interest expense was primarily the result of $1.9 million of capitalized interest in 2007, resulting from capital activity expansion in Texas and Australia. Interest expense includes deferred cost and debt discount amortization of $4.2 million for 2007, a decrease of $100,000 from the comparable 2006 period. There was no capitalized interest in 2006

Debt extinguishment expense. We reported debt extinguishment expense of $15.7 million for the year ended December 31, 2007. This resulted from the expensing of a prepayment penalty of $3.7 million and deferred financing and debt discount costs of $12.0 million incurred related to $73.0 million of senior secured notes. The senior secured notes were repaid prior to maturity with the proceeds from the sale of $100.0 million of 12  ³/4% Senior Secured Notes in November 2007. There was no debt extinguishment expense in 2006.

Year Ended December 31, 2006 compared to Year Ended December 31, 2005

Revenues. Substantially all of our revenues are derived from the production of natural gas in the United States. Revenues were $26.8 million for the year ended December 31, 2006, down from $27.4 million for the year ended December 31, 2005. The decrease in revenues was the result of a 21% decrease in natural gas prices, which was partially offset by a 23% increase in production.

Production taxes. We reported production taxes of $1.5 million for the year ended December 31, 2006, up from $1.1 million for the year ended December 31, 2005. This increase was the result of increased production from new wells and a $350,000 tight sands gas tax refund in 2005.

 

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Lease operating expenses. We reported lease operating expenses of $5.5 million for the year ended December 31, 2006, up from $3.9 million for the year ended December 31, 2005. This increase was due to an increase in the number of producing wells. Our lease operating expenses were $1.18 per Mcfe for the year ended December 31, 2006, compared to $1.01 per Mcfe for the comparable period in 2005.

Transportation and treating. We reported transportation expenses of $1.6 million for the year ended December 31, 2006, down from $2.0 million for the year ended December 31, 2005. The decrease in expense was primarily the result of lower Powder River Basin transportation costs. This decrease was the result of a decrease in per Mcf cost from $1.43 per Mcf in 2005 to $0.88 per Mcf in 2006.

Depreciation, depletion and amortization. Depreciation, depletion and amortization was $16.3 million for the year ended December 31, 2006, up from $13.9 million for the year ended December 31, 2005. This increase primarily was attributable to new East Texas wells drilled and placed into production during 2006 and additional production from new CBM wells drilled in the Powder River Basin. The increase in DD&A expense was the result of a 23% increase in production, which was partially offset by a 5% decrease in the DD&A rate per unit of production. The DD&A rate for the year ended December 31, 2006 was $3.44 per Mcfe, as compared to $3.63 for the comparable period in 2005.

Impairment of natural gas and oil properties. Impairment of U.S. natural gas and oil properties was $56.3 million for the year ended December 31, 2006, compared to $8.7 million for the comparable period ended 2005. The 2006 impairment was the result of net natural gas and oil property costs, as adjusted for related deferred income taxes and other adjustments, exceeding the sum of estimated future net revenues using post end of period weighted average after basis adjustment prices held constant of $6.11 per Mcf for natural gas, discounted at 10%, and unproven property at historical cost of $81.5 million, which was lower than the estimated fair market value, as adjusted for related income taxes and other adjustments. The 2005 impairment was the result of net natural gas and oil property costs, as adjusted for related deferred income taxes, if any, and other adjustments, exceeding the sum of estimated future net revenues using prices in effect at June 30, 2005, the date of the impairment, held constant at $5.32 per Mcf for natural gas, discounted at 10%, and unproven properties at historical costs of $93.3 million, as adjusted for related deferred income taxes and other adjustments.

General and administrative. We reported general and administrative expenses of $13.5 million for the year ended December 31, 2006, up from $8.7 million for the year ended December 31, 2005. This increase in general and administrative expenses was primarily due to increases in staff, contract personnel and professional service charges, and the recording of non-cash compensation expense due to the granting of stock options. Non-cash stock-based compensation expense for 2006 pursuant to the SFAS 123R, which is included in general and administrative expenses, was $3.9 million, up from $2.3 million in 2005.

Litigation settlement expense. The $2.4 million litigation settlement expense incurred in 2006 was primarily the result of a settlement payment regarding Western Gas Resources, Inc., et. al., of a lawsuit involving a gas gathering agreement and its applicability to properties we exchanged in 2002 and settlement of the Burning Rock Energy LLC, et. al. litigation by assigning our interest in certain disputed properties. There was no litigation settlement expense in 2005.

Interest expense. We reported interest expense of $15.6 million for the year ended December 31, 2006, compared to $13.9 million for the year ended December 31, 2005. The increase in interest expense was the result of higher average debt outstanding and higher interest rates. Interest expense includes deferred financing cost and debt discount amortization of $4.3 million for 2006, a decrease of $500,000 from 2005.

Debt extinguishment expense. In June 2005, in conjunction with the issuance of the senior secured notes, the Company retired certain senior secured notes, resulting in a debt extinguishment expense of $1.4 million, comprised of $662,000 of early prepayment penalty and $694,000 of unamortized deferred financing costs.

Liquidity and Capital Resources

At March 31, 2008, we had cash and cash equivalents of $79.0 million and $16.9 million of borrowing availability under our bank revolving credit facility. For the three months ended March 31, 2008, we reported cash flow from operations of $14.3 million, up from $281,000 of cash flow from operations for the three months ended March 31, 2007. This increase resulted primarily from a 88% increase in production volumes and a 19% increase in prices. Capital expenditures on natural gas and oil properties totaled $20.0 million for the three months ended March 31, 2008.

On June 12, 2008, Gastar and GeoStar Corporation announced that they had settled all outstanding disputes. The settlement resolves significant uncertainty related to Gastar’s common equity and potential dilution of existing shareholders. The settlement includes an upfront cash payment by Gastar of approximately $25.7 million plus the issuance to GeoStar of a Warrant to purchase 10 million Gastar common shares. On a pro forma basis after the cash payment to GeoStar, our cash and cash equivalent balance at March 31, 2008 was approximately $53.3 million.

Covenants in our 12¾% Senior Secured Notes Indenture, our indenture governing our 9.75% convertible senior unsecured subordinated debentures and our Revolving Credit Facility agreement require us to make an offer to repurchase or repay all of the outstanding indebtedness thereunder in the event of a change of control of the Company, as defined in the respective agreements. Each of the indentures provides that if there is a change of control of the Company, as defined in the respective indenture, we are required to make an offer to each holder to repurchase all or any part of the 12¾% Senior Secured Notes or the 9.75% convertible senior unsecured subordinated debentures, as the case may be, at 101% of the aggregate principal amount of the notes or debentures tendered for repurchase, plus accrued and unpaid interest. In the event of a change of control, as defined under the Revolving Credit Facility Agreement, all obligations under the Revolving Credit Facility will become immediately due and payable. If the change of control event occurs in one or more of these agreements, we may not have adequate financing available to meet the resulting payment obligations.

We continually evaluate our capital needs and compare them to our capital resources. To execute our operational plans, particularly our drilling plans in East Texas and Australia, additional funds will be needed for acreage acquisition, seismic and other geologic analysis, drilling, undertaking completion activities and for general corporate purposes. We may have to significantly reduce our drilling and development program if our internally generated cash flow from operations and cash flow from financing activities are not sufficient to pay debt service, corporate overhead and expenditures associated with our projected drilling and development activities. We expect to fund these expenditures from internally generated cash flow, cash on hand, sales of assets and the issuance of additional debt or equity. We may also attempt to balance future capital expenditures through joint venture development of certain properties with industry partners. We cannot be certain that future funds will be available to fully execute our current business plan.

Our 2008 capital expenditures under our business plan are estimated to total approximately $65.4 million, of which $43.4 million is estimated to be spent on unconventional natural gas and oil exploration and development operations in East Texas, $7.4 million is estimated to be spent on CBM projects and additional projects in the United States and $14.6 million is estimated to be spent on CBM projects in Australia. Based on our current budget, we have sufficient capital, together with internally generated cash flow, to fund our exploration and development activities in East Texas and Australia for 2008 and a portion of our 2009 projected capital needs.

Our cash flow and ability to raise capital are highly dependent upon natural gas pricing. A material decrease in current and projected natural gas prices could impact our ability to fund future activities, impair our ability to raise additional capital on acceptable terms and result in a financial covenant default under the 12¾% Senior Secured Notes, resulting in mandatory principal reduction under certain conditions. It may be difficult for us to raise capital through the issuance of common shares due to the pending GeoStar litigation.

In the fourth quarter of 2007 and the first quarter of 2008, we entered into various costless collar transactions with counterparties. The volumes currently hedged represents approximately 50% of 2008 and 15% of 2009 projected production.

Covenants in our 12¾% Senior Secured Notes Indenture and our Revolving Credit Facility Agreement restrict us from hedging more than 75% of the projected production from proved developed producing reserves.

At March 31, 2008, we were in compliance with all debt covenants.

 

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Contractual Obligations

The following table summarizes our future contractual obligations under these arrangements as of December 31, 2007:

 

		Total			Less Than 1 Year			1-3 Years			3-5 Years			More Than 5 Years
		(in thousands)
Maturities on long-term debt, including related current portion (1)		$	133,250		$	—		$	33,250		$	100,000		$	—
Interest on long-term debt			67,934			16,008			28,540			23,386		$	—
Office lease (2)			582			205			377			—		$	—
Drilling contract (3)			12,060			6,300			5,760			—		$	—
Operating leases and other (4)			25			8			17			—		$	—
Total		$	213,851		$	22,521		$	67,944		$	123,386		$	—

 

(1)	These amounts represent the principal balances that will become due on our 12 3/4% Senior Secured Notes, subordinated unsecured notes payable and convertible senior debenture.

(2)	Office lease obligation expires October 31, 2010.

(3)	Represents minimum rates under a three year drilling contract commitment requiring minimum fees per year, net of advance payments.

(4)	Represents operating lease payments for various office equipment.

We maintain a reserve for cost associated with the retirement of tangible long-lived assets. At December 31, 2007, our reserve for these obligations totaled $4.4 million for which no contractual commitment exists. Information about this reserve is set forth in Note 2 – Summary of Significant Accounting Policies – Asset Retirement Obligation to our consolidated financial statements, which begin on page F-1.

We have employment agreements with our Chief Executive Officer, Chief Financial Officer and Chief operating Officer, which obligate us to pay a specified level of salary, target bonus and certain other payments and reimbursements to them during their employment and in the event of termination or change of control. Information about such payments is set forth in “Executive Compensation”.

Commitments

During 2006, we entered into an agreement with a drilling contractor to provide contracted drilling services in the Hilltop area of East Texas for a three-year period at agreed upon day rates. The Company made advance payments totaling $2.0 million prior to drilling rig delivery in November 2006. The advance payments are being amortized over the three-year term of the agreement. The Company is required to pay the drilling contractor a minimum of $6.3 million per year in drilling day rate fees, net of the amortization of the advance payments, during the three-year term of the agreement commencing November 2006.

 

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In March 2008, we entered into formal agreements with ETC Texas Pipeline, Ltd. (“ETC”) for the gathering, treating, purchase and transportation of our natural gas production from Hilltop area of East Texas. These agreements are effective September 1, 2007 and have a term of 10 years. ETC currently provides us 50 MMcfd of treating capacity and 120 MMcfd of gathering capacity. We have the right to request ETC build, at their cost, up to 150 MMcfd of treating and gathering capacity during the term of the agreement, provided that our production equals 85% of the then existing treating and gathering capacity for a 30 day period. We may at any time elect to have our treating and gathering capacity increased subject to cost indemnifications to ETC. Additional treating and gathering capacity requests must be in at least 25 MMcfd and 5 MMcfd increments, respectively. In addition, we must furnish to ETC information that reasonably demonstrates that our projected production for the five years after expansion is sufficient to warrant the costs to create the expanded treating and gathering capacity. The incremental volume increases in treating and gathering capacity shall be subject to marginal increases in treating fees. Pursuant to the agreements, we have access up to 150 MMcfd of firm transportation on ETC’s system or the pipelines of its affiliates or subsidiaries from the tailgate of the treating facility to Katy Hub. We have the option to sell and ETC has the obligation to buy, up to 150 MMcfd of our Hilltop production at delivery points upstream of ETC’s gathering and treating facilities. We do not have an obligation to deliver to ETC volumes in excess of 150 MMcfd, but should ETC elect to purchase such excess volumes, purchases will be subject to the treating and gathering expansion terms set forth in the agreements.

Registration Obligation and Penalties

On November 29, 2007, Gastar USA, a wholly owned subsidiary of Gastar Exploration Ltd., sold $100.0 million aggregate principal amount of 12 ³/4% Senior Secured Notes at an issue price of 99.50%. Gastar USA is obligated to prepare and file with the SEC within 150 days of the issue date of the 12 ³/4% Senior Secured Notes, or April 27, 2008, a registration statement to exchange the 12 ³/4% Senior Secured Notes for registered, publicly tradable notes that have substantially identical terms as the 12 ³/4% Senior Secured Notes. Gastar USA is to use its best efforts to cause the registration statement to be declared effective within 240 day of the issue date of the 12 ³/4% Senior Secured Notes, or July 24, 2008. Gastar USA has agreed to offer new notes in exchange for the 12 ³/4% Senior Secured Notes as soon as is practicable after the registration statement has become effective, unless prohibited by law or SEC policy, and to file a shelf registration statement for the resale of the 12 ³/4% Senior Secured Notes if Gastar USA cannot consummate the exchange offer within 290 days of the date of the issuance of the 12 ³/4% Senior Secured Notes, or September 12, 2008, and in certain other circumstances. In the event Gastar USA fails to meet its registration obligations as set forth above, Gastar USA has agreed to pay liquidated damages to the holders of the 12 ³/4% Senior Secured Notes in the form of additional cash interest payments on the 12 ³/4% Senior Secured Notes equal to 0.25% per annum for the first 90-day period, increasing to a maximum of 0.50% per annum for each subsequent 90-day period.

New Accounting Pronouncements

Fair Value Measurements. In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”), which addresses how companies should measure fair value when companies are required to use a fair value measure for recognition or disclosure purposes under US GAAP. As a result of SFAS No. 157 there is now a common definition of fair value to be used throughout US GAAP. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. The FASB also has issued Staff Position FAS 157-2 (“FSP No. 157-2”), which delays the effective date of SFAS No. 157 for nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until fiscal years beginning after November 15, 2008. Effective January 1, 2008, the Company adopted SFAS 157 and has chosen to defer the implementation of nonfinancial assets and liabilities in accordance with FSP FAS No. 157-2. The effect of adoption in January 1, 2008 was immaterial to the Company’s financial position. The adoption of FSP FAS No. 157-2 is not expected to have a material impact on the Company’s results of operations, cash flows or financial positions. See Note 10, “Fair Value Measurements” for additional information regarding the adoption of SFAS No. 157.

Non-controlling Interests in Consolidated Financial Statements. In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of Accounting Research Bulletin No. 51” (“SFAS No. 160”), which improves the relevance, comparability and transparency of the

 

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financial information that a reporting entity provides in its consolidated financial statements by establishing accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. This statement is effective for fiscal years beginning after December 15, 2008. The Company does not expect the adoption of SFAS No. 160 to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.

Business Combinations. In December 2007, FASB issued SFAS No. 141, “Business Combinations” (“SFAS No. 141R”), which creates greater consistency in the accounting and financial reporting of business combinations. This statement is effective for fiscal years beginning after December 15, 2008. The Company does not expect the adoption of SFAS No. 141R to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.

The Fair Value Option for Financial Assets and Financial Liabilities. In February 2007, FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115” (“SFAS No159”), which permits an entity to choose to measure certain financial assets and liabilities at fair value. SFAS No. 159 also revises provisions of SFAS No. 115 that apply to available-for-sale and trading securities. This statement is effective for fiscal years beginning after November 15, 2007. The Company does not expect the adoption of SFAS No. 159 to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.

Commodity Price Risk

Our major commodity price risk exposure is to the prices received for our natural gas production. Realized commodity prices received for our production are the spot prices applicable to natural gas in the region produced. Prices received for natural gas are volatile and unpredictable and are beyond our control. We have entered into hedge transactions to mitigate our commodity pricing risk. For the three months ended March 31, 2008, a 10% change in the prices received for natural gas production would have had an approximate $1.7 million impact on our revenues before mitigating factors that might result from having hedge transactions in place. See Note 5 to our condensed consolidated financial statements for additional information on our hedging activities.

Interest Rate Risk

The carrying value of our debt approximates fair value. At March 31, 2008, we had approximately $133.3 million in principal amount of long-term debt, all of which was at a fixed interest rate. A 10% fluctuation in interest rates would have no impact on annual interest expense.

Currency Translation Risk

Our revenues and expenses and the majority of our capital expenditures are primarily in U.S. dollars, thus limiting our exposure to currency translation risk. During the three months ended March 31, 2008, we spent approximately $860,000 of capital expenditures on our Australian activities. We have no plans in the foreseeable future to implement hedges or financial instruments to manage international currency changes.

Management’s Report on Internal Control over Financial Reporting

The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of management, including the principal executive officer and principal financial officer, the Company conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting based on the framework in “Internal Control – Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Our internal control over financial reporting includes policies and procedures that (1) pertain to maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of our management and board of directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of assets that could have a material effect on the financial statements.

 

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Due to its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and, even when determined to be effective, can only provide reasonable, not absolute, assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to risk that controls may become inadequate as a result of changes in conditions or deterioration in the degree of compliance.

Based on the assessment, our management has concluded that our internal control over financial reporting was effective as of December 31, 2007 and provides reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes in accordance with generally accepted accounting principles. The results of management’s assessment were reviewed with the Audit Committee of our Board of Directors.

Our internal control over financial reporting has been audited by BDO Seidman, LLP, an independent registered public accounting firm, as stated in their report which is included herein.

 

/s/ J. RUSSELL PORTER				/s/ MICHAEL A. GERLICH
J. Russell Porter				Michael A. Gerlich
Chairman, President and Chief Executive Officer				Vice President and Chief Financial Officer
March 17, 2008				March 17, 2008

 

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Report of Independent Registered Public Accounting Firm

Board of Directors and Shareholders

Gastar Exploration Ltd.

Houston, Texas

We have audited Gastar Exploration Ltd.’s (the “Company”) internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Criteria”). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Item 9A, “Management’s Report on Internal Control over Financial Reporting.” Our responsibility is to express an opinion on the effectiveness of internal control over financial reporting of the Company based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Gastar Exploration Ltd. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the COSO Criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Gastar Exploration Ltd. and subsidiaries as of December 31, 2007 and 2006 and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007 and our report dated March 14, 2008 expressed an unqualified opinion thereon.

 

/s/ BDO Seidman, LLP

Dallas, Texas

March 14, 2008

 

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Off-Balance Sheet Arrangements

As of December 31, 2007, we had no off-balance sheet arrangements. We have no plans to enter into any off-balance sheet arrangements in the foreseeable future.

Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America (“US GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, contingent assets and liabilities and the related disclosures in the accompanying consolidated financial statements. Changes in these estimates and assumptions could materially affect our financial position, results of operations or cash flows. Management considers an accounting estimate to be critical if:

 

•

It requires assumptions to be made that are uncertain at the time the estimate is made; and

 

•

Changes in the estimate or different estimates that could have been selected could have a material impact on our consolidated results of operations or financial condition.

All other significant accounting policies that we employ are presented in the notes to the consolidated financial statements. The following discussion presents information about the nature of our most critical accounting estimates, our assumptions or approach used and the effects of hypothetical changes in the material assumptions used to develop each estimate.

Full Cost Method of Accounting

We follow the full cost method of accounting for natural gas and oil operations, whereby all costs incurred in the acquisition, exploration and development of natural gas and oil reserves are initially capitalized into cost centers on a country-by-country basis. Our current cost centers are located in the United States and Australia. Such costs include land acquisition costs, geological and geophysical expenditures, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition, exploration and development activities.

Costs capitalized, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated net proved reserves, as determined by independent petroleum engineers. The percentage of total reserve volumes produced during the year is multiplied by the net capitalized investment plus future estimated development costs in those reserves.

Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed periodically to ascertain whether impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations.

In applying the full cost method, we perform a quarterly ceiling test on the cost center properties whereby the net cost of natural gas and oil properties, net of related deferred income taxes (“net cost”), is limited to the sum of the estimated future net revenues from proved reserves using prices in effect at the end of the period held constant, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects (“ceiling”). If the net cost exceeds the ceiling, an impairment loss is recognized for the amount by which the net cost exceeds the ceiling and is shown as a reduction in natural gas and oil properties and as additional depletion. Proceeds from a sale of natural gas and oil properties will be applied against capitalized costs, with no gain or loss recognized, unless such a sale would significantly alter the rate of depletion or amortization.

Natural Gas and Oil Reserves

Nature of Critical Estimate Item. Our estimate of proved reserves is based on the quantities of natural gas and oil which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in the future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve

 

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estimate is a function of the quality of available data, engineering and geological interpretation, and judgment. For example, we must estimate the amount and timing of future operating costs, severance taxes, development costs, and workover costs, all of which may in fact vary considerably from actual results. In addition, as prices and cost levels change from year to year, the economics of producing the reserves may change and therefore the estimate of proved reserves also may change. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves. Despite the inherent imprecision in these engineering estimates, our proved reserve volumes and values are used to calculate depletion and impairment provisions.

“Ceiling” Limitation Test – The full cost method of accounting for natural gas and oil properties requires a quarterly calculation of a limitation on capitalized costs, often referred to as a full cost ceiling calculation. The ceiling is the discounted present value of our estimated total proved reserves using a 10% discount rate. To the extent that our capitalized costs (net of accumulated depletion and deferred taxes) exceed the ceiling, the excess must be written off to expense. Once incurred, this impairment of natural gas and oil properties is not reversible at a later date even if natural gas and oil prices increase. Impairments were required at December 31, 2006 and at June 30, 2007. The calculation of our proved reserves could significantly impact our ceiling limitation used in determining whether an impairment of our capitalized costs is necessary. The ceiling calculation dictates that prices and costs in effect as of the last day of the period are generally held constant indefinitely, but subsequent period end prices may be used if such prices would reduce the ceiling impairment. Therefore, the future net revenues associated with the estimated proved reserves are not based on our assessment of future prices or costs, but rather are based on prices and costs in effect at the time of evaluation. The weighted average natural gas after basis adjustments used in the reserve valuations as of December 31, 2006 and June 30,2007 were $6.12 per Mcf and $5.72 per Mcf, respectively.

The most likely factor to contribute to a ceiling test impairment is the price used to calculate the reserve limitation threshold. A significant reduction in the prices at a future measurement date could trigger a full cost ceiling impairment. At December 31, 2007, we had a ceiling impairment cushion of $45.2 million. A 10% decrease in prices would have resulted in a decrease in the cushion of approximately $24.1 million. A 10% increase in prices used would have resulted in an increase in the cushion approximately $20.7 million.

Assumptions/Approach Used. Units-of-production method is used to amortize our natural gas and oil properties. A change in the quantity of reserves could significantly impact our depletion expense. A reduction in proved reserves, without a corresponding reduction in capitalized costs, will increase our depletion rate.

Effect if different assumptions used. A 10% increase in reserves would have decreased our depletion expense for the year ended December 31, 2007 by approximately 2%, while a 10% decrease in reserves would have increased our depletion expense by approximately 3%.

Unproved Property Impairment

Nature of Critical Estimate Item. We have elected to use the full cost method to account for our natural gas and oil activities. Investments in unproved properties are not amortized until proved reserves associated with the properties can be determined or until impairment occurs. Unproved properties are evaluated quarterly for impairment on a field basis. If the results of an assessment indicate that an unproved property is impaired, the amount of impairment is added to the proved natural gas and oil property costs to be amortized.

Assumptions/Approach Used. At December 31, 2007, we had $46.5 million allocated to unproved United States property costs which was comprised primarily of unevaluated acreage costs. The unproven property costs are evaluated by the technical team and management of whether the property has potential attributable reserves. Therefore, the assessment made by our technical team and management of the potential reserves will determine whether costs are moved from the unproved category to the full-cost pool for depletion or whether an impairment is taken.

Effect if different assumptions used. A 10% increase or decrease in the unproved property balance would have decreased or increased our depletion expense by approximately 1% for the year ended December 31, 2007.

 

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Asset Retirement Obligation

Nature of Critical Estimate Item. We have certain obligations to remove tangible equipment and restore land at the end of natural gas and oil production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells. Under Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations”, as discussed in Note 2 to our consolidated financial statements, we estimate asset retirement costs for all of our assets, inflation adjust those costs to the forecast abandonment date, discount that amount using a credit-adjusted-risk-free rate back to the date we acquired the asset or obligation to retire the asset and record an asset retirement obligation, or ARO, liability in that amount with a corresponding addition to our capitalized cost. We then accrete the liability quarterly using the period-end effective credit-adjusted-risk-free rate. As new wells are drilled or purchased, their initial asset retirement cost and liability is calculated and recorded. Should either the estimated life or the estimated abandonment costs of a property change upon our quarterly review, a new calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using our credit-adjusted-risk-free rate. The carrying value of the asset retirement obligation is adjusted to the newly calculated value, with a corresponding offsetting adjustment to the asset retirement cost (included in the full-cost pool); therefore, abandonment costs will almost always approximate the estimate. When wells are sold the related liability and asset costs are removed from the balance sheet.

Assumptions/Approach Used. Estimating the future asset removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Inherent in the estimate of the present value calculation of our AROs are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit-adjusted-risk-free-rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments.

Effect if different assumptions used. Since there are so many variables in estimating AROs, we attempt to limit the impact of management’s judgment on certain of these variables by using input of qualified third parties. We engage independent petroleum engineers, who have consented to the use of their name and reports in this Prospectus, to evaluate our properties annually. We primarily use the remaining estimated useful life from the year end reserve reports by our independent reserve engineer in estimating when abandonment could be expected for each property as an estimate based on field or industry practices. We expect to see our calculations impacted significantly if interest rates move from their current levels, as the credit-adjusted-risk-free rate is one of the variables used on a quarterly basis. Our technical team developed a standard cost estimate based on historical costs, industry quotes and depth of wells. Unless we expect a well’s plugging to be significantly different than a normal abandonment, we use this estimate. The resulting estimate, after application of a discount factor and some significant calculations, could differ from actual results, despite all our efforts to make an accurate estimate.

Capitalized Interest

We capitalize interest for two purposes: (1) capitalized interest on funds borrowed for specific projects, such as our long-term development of our CBM assets in New South Wales and Victoria, Australia and (2) capitalized interest on borrowed funds used to invest in unproven natural gas and oil properties not being amortized. The methodology for capitalizing interest on general funds, consistent with SFAS No. 34, “Capitalization of Interest Cost,” begins with a determination of the borrowings applicable to our qualifying assets. The basis of this approach is the assumption that the portion of the interest costs that are capitalized on expenditures during an asset’s acquisition period could have been avoided if the expenditures had not been made. This methodology takes the view that if funds are not required for construction then they would have been used to pay off other debt. We use our best judgment in determining which borrowings represent the cost of financing the acquisition of the assets. The primary debt instruments included in the rate calculation of interest incurred on the funds is our 12 ³/4% Senior Secured Notes. The interest to be capitalized for any period is derived by multiplying this fixed rate of interest times the average qualifying assets during the period. To qualify for interest capitalization, we must continue to make progress on the development of the assets.

 

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Stock-Based Compensation

Nature of Critical Estimate Item. Effective January 1, 2003, we adopted the provisions of SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”), using the prospective application method of SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure”. This statement required us to record compensation costs for options granted under our stock option plan in accordance with the fair value method prescribed in SFAS No. 123.

Effective January 1, 2006, we adopted the fair value recognition provisions of SFAS 123R, “Share-Based Payment”, using the modified-prospective method. Under that method, compensation cost for 2007 and 2006 includes: (a) compensation cost for all share-based payments granted prior to, but not yet vested as of, January 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123, and (b) compensation cost for all share-based payments granted subsequent to January 1, 2006, based on the grant-date fair value estimated in accordance with the provisions of SFAS 123R.

The Company reports compensation expense for stock options and restricted common shares granted to officers, directors and employees using the fair value method in accordance with SFAS 123R. Stock-based compensation costs are recorded over the requisite service period, which approximates the vesting period.

The fair value of each stock option grant is estimated on the date of grant using the Black-Scholes-Merton valuation pricing model. The fair value of all awards is expensed using the “graded-vesting method”, which recognizes compensation costs over the requisite service period for each separately vesting tranche of an award as though the award were, in substance, multiple awards.

Assumption/Approach Used. The Black-Scholes-Merton model requires various highly judgmental assumptions including volatility, expected option life and forfeiture rate. If any of the assumptions used in the Black-Scholes-Merton model change significantly, stock-based compensation expense may differ materially in the future from that recorded in the current period. The table below summarizes the key assumptions for the stock options granted for the periods indicated:

 

		For the Years Ended December 31,
		2007			2006
Expected volatility		44.4-44.7	%		45.7	%
Expected life (in years)		6.25			6.5
Expected forfeitures		5.0	%		5.0	%

Effect if different assumptions used. A 10% increase or decrease in the volatility rate would increase or decrease our stock based compensation for the year ended December 31, 2007 by approximately 6.4% and 6.6%, respectively. A 10% increase or decrease in expected life would increase or decrease our stock based compensation expense for the year ended December 31, 2007 by approximately 4.6% and 4.9%, respectively. A 10% increase or decrease in forfeiture rate would have a corresponding impact on our stock based compensation expense for the year ended December 31, 2007.

 

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BUSINESS

Our Company

We are a Houston, Texas-based independent natural gas and oil company engaged in the exploration, development and production of natural gas and oil in the United States and Australia. Our domestic drilling activities are focused on exploiting our multi-year inventory of drilling locations in the deep Bossier sands and Knowles Limestone plays of East Texas and in the Powder River Basin of Wyoming. Our operations in Australia are focused on the development of CBM rights in New South Wales and Victoria, Australia. We believe that our dual focus enables us to generate high initial production and long-lived producing wells with strong cash flow dynamics from our East Texas activities while also providing us with significant reserve upside through the development of our Australian resource plays. Gastar USA is a Michigan corporation. Our parent, Gastar Exploration Ltd., a Canadian corporation incorporated in Alberta, is a publicly traded company listed on the American Stock Exchange under the ticker symbol “GST” and on the Toronto Stock Exchange under the ticker symbol “YGA” with an equity market capitalization of $491 million and CDN $493 million, respectively, as of June 17, 2008.

The majority of our domestic portfolio is located on acreage in established geological trends where we utilize our engineering, operating, geologic and geophysical expertise to provide significant proved reserve and production growth with attractive returns on investment. The current focus of these activities is in the Hilltop area of East Texas, where we currently hold a total of approximately 37,500 gross (16,500 net) acres of oil and gas leaseholds. Our production in East Texas is characterized by prolific initial production rates that decline in the first year into a more stable long-term productive profile. Typically wells in the deep Bossier generate approximately 25 to 35% of their production in the first 12 months and have a reserve life ranging from 8 to 12 years. To date, we have drilled and completed 16 of 17 East Texas wells, including the successful completion of all 10 wells drilled since the end of 2005.

Our ability to apply information learned with the drilling of each of our wells to the drilling of subsequent wells has enabled us to significantly improve the drilling and completion costs of our newer East Texas wells. Based on estimates from our independent petroleum engineers, our eight deep Bossier wells completed in 2006 and 2007 have improved average proved reserves over their economic lives to 4.3 Bcf gross (2.3 Bcf net) from 2.0 Bcf gross (1.5 Bcf net) for all of our previous drilling. During these same periods our average per well drilling and completion costs improved to $14.3 million gross from $15.6 million gross. As a result of our early drilling we recognized that the deep Bossier series of sands is productive in high structural positions with favorable porosity and permeability characteristics within the reservoir. We then recognized that the deposition of slightly younger Bossier sands is dependent upon their position relative to faulting within the Bossier section. As a result of these and other derived information, we drilled the Donelson #3 well (our most recent Bossier completion) which generated peak production of 24.0 MMcfc/d and which our engineers estimate will produce approximately 10.9 Bcf gross (5.5 Bcf net) of proved reserves over its economic life. Our cost to drill and complete the Donelson #3 was $12.6 million gross ($8.4 million net). Following the spudding of the Donelson #3, we completed the processing and interpretation of the new 3-D seismic data which covers 100% of our East Texas acreage. We believe that our increased understanding of the depositional geologic model for the Bossier, combined with the new 3-D seismic data and a drilling strategy over the next two years focusing on offset locations to the Donelson #3, will enhance our ability to find optimal drilling locations. We have identified 115 additional drilling locations (64 net) across our acreage for this formation.

Since early 2006, we drilled three wells in the Knowles Limestone, which NSA estimates will average 1.9 Bcf gross (0.7 Bcf net) of proved reserves over their economic life. We believe that production and ultimate recoveries from existing and future Knowles Limestone wells may be enhanced through the use of a relatively inexpensive well stimulation process. We believe we can further improve our well economics by using our recently acquired 3-D seismic survey, covering 100% of our Knowles Limestone acreage. We have identified 20 additional drilling locations (11 net) across our acreage for this formation.

In addition to our exploitation and production activities in East Texas, the exploration and development of our CBM assets in Australia has the potential for significant reserve and production growth. We own a 35% working interest in each of three petroleum exploration licenses, PEL 238, PEL 433 and PEL 434, in the Gunnedah Basin of New South Wales and a 75% working interest in an exploration license, EL 4416, in the Gippsland Basin in Victoria, Australia. These licenses include over 7.0 million gross (2.9 million net) acres. During 2008, we intend to

 

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expand our pilot production drilling program on the PEL 238 concession working with Eastern Star Gas Limited (ASX:ESG), our working interest partner and license operator. Through our planned development program in PEL 238, consisting of additional production pilot projects and core hole drilling, we intend to convert a portion of the significant resource potential into certifiable proved and probable reserves as we move towards commercial production. The certification of proved reserves and the growth of our probable reserves is necessary to support the development of infrastructure to service growing natural gas demand in New South Wales. Contracts for the construction of this infrastructure, as well as gas sales or use contracts, are not expected until late 2008 and will be required before recognition of significant proved reserves in PEL 238 under SEC guidelines. Eastern Star Gas Limited owns a 65% interest in PEL 238.

In the United States, our CBM activities are located in the Powder River Basin in Wyoming where our development and recompletion activities provide us with a stable base of production. At December 31, 2007, we held an approximate 40% average working interest in approximately 55,000 gross (21,900 net) leasehold acres and an ownership interest in 283 gross (125.2 net) productive economic CBM wells.

NSA has estimated our total domestic proved reserves as of December 31, 2007, to be 54.9 Bcfe under SEC definition and guidelines, consisting almost entirely of natural gas.

Recent Developments

Settlement of Arbitration and Litigation with GeoStar and Affiliates

On June 12, 2008, our Parent entered into a settlement agreement with GeoStar to settle all outstanding disputes. The settlement includes an upfront cash payment by our Parent of approximately $25.7 million plus the issuance to GeoStar of a Warrant to purchase 10 million of our Parent’s common shares. Pursuant the settlement, GeoStar will assign to our Parent all of GeoStar’s oil and gas interests in West Virginia and Pennsylvania while our Parent will acknowledge GeoStar’s clear title to an exploration license (EL 4416) and assign its interest to GeoStar’s Australian subsidiary in an exploration license application (EL 4968) in the Gippsland Basin of Victoria, Australia. As of December 31, 2007, EL 4416 and EL 4968 had no attributable proved reserves or production.

GeoStar will also receive a right to farm-in our Parent’s interest in well locations in the East Hilltop area of East Texas that are not included in our Parent’s future Bossier or Knowles drilling plans. In addition, our Parent will surrender or release claims to GeoStar on approximately 340 acres that were in dispute in East Texas. Additional acreage that could have been surrendered to GeoStar under the settlement has been acquired by another property owner, entitling GeoStar to elect to receive additional farm-in locations and/or receive additional cash considerations of up to $2.04 million (net of receipts from the other property owner). Certain other corrective lease assignments and releases are being made between our Parent and GeoStar. Our Parent and GeoStar have mutually agreed to release all claims against each other, their affiliates and current and past officers and directors.

The Warrant is exercisable for $2.75 per share in the event that on or before June 11, 2011, our Parent sells up to all or substantially all of its present oil and gas interests located in Leon and Robertson Counties in East Texas for net proceeds exceeding $500 million. A sale, or a series of sales, of all or substantially all of our present East Texas properties prior to June 11, 2011 for less than $500 million will terminate the warrant. If our Parent does not sell all or substantially all of these properties by June 11, 2011, the Warrant will be exercisable for a six month period commencing on that date at $3.00 per share. Our Parent is not obligated to sell any of its East Texas properties and is not currently pursuing any sale of its East Texas assets.

Natural Gas and Oil Activities

The following provides an overview of our major natural gas and oil projects. While actively pursuing specific exploration and development activities in each of the following areas, we continue to review other opportunities. There is no assurance that new drilling opportunities will be identified or that any new drilling opportunities will be successful if drilled.

Hilltop Area, East Texas

Hilltop Area, East Texas. The majority of our activities has been in the deep Bossier play in the Hilltop area, located in East Texas approximately midway between Dallas and Houston in Leon and Robertson Counties. This exploration play has attracted some of the largest and most active operators in the U.S. Wells in this area target multiple potentially productive natural gas formations and are typically characterized by high initial production, significant decline rates and long-lived reserves.

Our first successful operated well was spudded in 2003 and placed on production in September 2004. As of December 31, 2007, we had successfully completed 14 out of 15 deep Bossier wells and four out of four Knowles Limestone wells. During 2007, we drilled and successfully completed a total of five gross (3.0 net) Bossier wells and three gross (1.5 net) Knowles Limestone wells.

In May 2007, we sold a portion of our undeveloped natural gas and oil acreage in the Hilltop area of East Texas for approximately $66.5 million, net of transaction costs of approximately $1.2 million, resulting in a gain on sale of $38.5 million. We currently have a total of approximately 35,400 gross (16,300 net) acres in the Bossier play. In July 2007, we completed the processing of a 3-D seismic survey purchased earlier in the year. This survey covered all of our retained undeveloped acreage position and is being interpreted and used in the selection of our drilling locations. For 2008, we plan to drill up to three deep Bossier wells and four Knowles Limestone wells.

In early 2008, we drilled the Holmes #1 well to a total depth of 18,700 feet and, based on drilling, core and log analysis, encountered one Bossier sand that will be completed for production. The well is scheduled to be completed and placed on production in mid-May 2008. The Holmes #1 is an immediate offset to the successful F-K #1 well.

We are drilling the Lone Oak Ranch #6 well (LOR #6) to target middle Bossier sands. The LOR #6 is currently drilling at 13,774 feet and is expected to reach total depth in early June. The LOR #6 is being drilled using slim-hole casing design at an estimated cost of $8.0 million to drill and complete the well. We are also side-tracking the LOR #4 well horizontal section in order to re-complete the well using a strata-pack system that will allow for multiple acid fracture stimulations of the Knowles Limestone pay zones. The LOR #4 was originally completed as an open-hole well with no acid fracture stimulation.

We drilled the Brunette #1, a horizontal Knowles Limestone well, to a total measured depth of 15,251 feet (total vertical depth of 13,341 feet). The well encountered approximately 640 feet of reservoir quality formation within the 1,367-foot horizontal section of the wellbore. The Brunette #1 was stimulated and placed on production in mid-April 2008 and is flowing at a gross stabilized rate of 1.0 MMcf per day. Several mechanical issues were encountered in the completion of the Brunette #1 well that appear to be restricting the sales rate. We will monitor well performance for approximately 60 days before implementing any remedial operations to further enhance production.

For the year ended December 31, 2007, net production from the Hilltop area averaged 13.0 MMcf per day, For the three months ended March 31, 2008, net production from the Hilltop area averaged 20.9 MMcf per day, up approximately 40% from 15.0 MMcf per day for the fourth quarter on 2007 and up approximately 121% from 9.5 MMcf per day for the three months ended March 31, 2007.

For the balance of 2008, Gastar anticipates a two-rig drilling program in East Texas with one rig dedicated to drilling deep Bossier wells and the second rig dedicated to drilling horizontal Knowles Limestone wells.

Coalbed Methane – Powder River Basin, Wyoming and Montana

We own an approximate 40% average working interest in approximately 55,000 gross (21,900 net) acres in the Powder River Basin of Wyoming and Montana. The Powder River Basin has been an important natural gas producing area for nearly 100 years. Generally, CBM wells are shallow and less costly than conventional natural gas wells. Our primary areas of activity in the Powder River Basin are the Squaw Creek, Ring of Fire and adjacent fields, all of which are located north of Gillette, Wyoming in an active drilling area.

 

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During 2007, we participated in the drilling of approximately 27 (12.5 net) CBM wells. As of December 31, 2007, we had an interest in 283 gross (125.2 net) productive CBM wells producing in the Basin. For the year ended December 31, 2007, our average net production from our CBM properties in the Powder River Basin was approximately 5.1 MMcf per day. We anticipate continuing our recompletion and drilling program in 2008. Our activity level will be influenced by regional natural gas prices, which remained lower than its historic prices relative to Gulf Coast Henry Hub natural gas prices during late 2007. Regional prices in early 2008 have rebounded to, or above, historic price levels.

For the three months ended March 31, 2008, our average net production form our CBM properties in the Powder River Basin was approximately 5.6 MMcf per day.

Coalbed Methane – PEL 238, Gunnedah Basin, New South Wales, Australia

We have a 35% interest in PEL 238, a CBM exploratory property covering approximately 2.2 million gross (786,000 net) acres, located in the Gunnedah Basin of New South Wales, approximately 250 miles northwest of Sydney, Australia, near the town of Narrabri. We believe that the strategic location of the properties and potential CBM reserves near the large natural gas markets in the Sydney-Newcastle-Wollongong area and the concession’s location relative to other developing gas markets should create a competitive marketing advantage for the natural gas reserves that may be developed on PEL 238.

Extensive coring of the coal on PEL 238 by the Australian government has provided a thorough understanding of the coal resources and potential CBM resource in place on our license. Two primary coal seams are found on the PEL 238 license, the Late Permian aged Hoskisson coal formation and the Early Permian aged Maules Creek coal formation.

During 2006, we participated with our joint venture partner and license operator, Eastern Star Gas Limited, in the drilling of eight new vertical coal seam natural gas wells on approximately 40-acre spacing in close proximity to an existing well within the Bohena Project Area of PEL 238 and one additional monitoring well. The results from the pilot production phase of the program have been positive, with the results confirming the high measured permeability of the coal and the presence of natural gas in the coal.

During 2007, we and our joint venture partner were approached by potential buyers with an interest in potentially contracting for up to 1 Tcf of natural gas from PEL 238. In March 2007, we announced that we and our joint venture partner had executed a Memorandum of Understanding (“MOU”) with Macquarie Generation, a New South Wales government-owned electricity generator, for the potential future supply of natural gas for its Bayswater power station. Macquarie Generation is Australia’s largest electricity producer and owns and operates two coal fired power stations in the Hunter Valley-Bayswater and Liddell. A long-term natural gas supply and purchase agreement with Macquarie Generation could include up to 500 Bcf to be delivered over a 15 to 20 year period commencing in late 2010, though there is no assurance that such an agreement will ultimately be reached or that such volumes will ultimately be produced from PEL 238. In addition, a potential gas supply and purchase agreement with Macquarie Generation would serve to underpin the development of the approximately 300 kilometers of pipeline infrastructure necessary to transport gas from the PEL 238 concession to Bayswater. An additional 150 kilometers of pipeline infrastructure would be required to access the natural gas markets of Sydney-Newcastle-Wollongong area.

In November 2007, we announced that we and our joint venture partner had entered into a second MOU with Babcock & Brown (“Babcock & Brown MOU”) to supply gas from the PEL 238 and PEL 433 concessions for use in the generation of electricity. The Babcock & Brown MOU envisions the supply of up to 30 Bcf per year of natural gas from the Gunnedah Gas Project to be delivered over multiple years for use in a gas fueled power station to be developed by Babcock & Brown in northern New South Wales, Australia commencing in late 2010. Natural gas sales under the anticipated agreements could be expanded to meet requirements for power station developments at other locations, though there is no assurance that such an agreement will ultimately be reached or that such volumes will ultimately be produced from the PEL 238 and PEL 433 concessions.

In September 2007, NSA certified a quantity of proved and probable reserves under guidelines established by the Society of Petroleum Engineers (“SPE”), as a result of the success of one of our pilot production projects on PEL 238. These reserves, however, are not yet established as proved reserves under SEC guidelines nor can we assure that other unevaluated acreage will contain similar reserves.

Petroleum Assessment Lease 2, or PAL 2, was issued by the New South Wales Department of Primary Industries on October 30, 2007. PAL 2, in which Gastar holds a 35% interest, lies within PEL 238 and covers the

 

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existing Bohena Project Area of approximately 65,000 gross acres including the Bibblewindi and Bohena Production Pilots, with umbilical areas connecting to the Wilga Park Power Station. The assessment lease, which is intended for the area to be assessed for an eventual production lease, allows gas production from the two production pilots to ultimately be transported by a dedicated gas gathering system to the power station for electricity production and sale. We and our joint venture partner are in the permitting phase for the construction of the gathering system and pipeline, which is anticipated to be completed by late 2008.

Beginning in 2008, we and our joint venture partner have expanded our pilot production drilling program on the PEL 238 concession and recently successfully completed the drilling of the first test corehole, the Dewhurst #2, in a 20-well exploration and appraisal corehole drilling program on PEL 238. The results of the Dewhurst #2 confirmed the presence of a thick Bohena coal seam developed to the south and east of the Bibblewindi pilot production area. The Dewhurst #2 encountered approximately 39 meters of coal within the Black Jack and Maules Creek coal formations, including approximately 18.2 meters in the targeted Bohena seam of which 14.7 meters was found in a single coal zone. We have commenced drilling the second test corehole of the 2008 gas reserves upgrade program, the Dewhurst #3, which is located approximately 2.2 miles east of the Dewhurst #2.

The area on which PEL 238 is located is subject to a native title claim lodged in March 2007 by the Gomeroi Narrabri People (NSD437/07). See “Governmental Regulation-Australian Governmental Regulation-Native Title”.

Coal Bed Methane—PEL 433-434, Gunnedah Basin, New South Wales, Australia

PEL 433 is located south of PEL 238 where Gastar and our joint venture partner, Eastern Star Gas Limited, are developing the Gunnedah Basin Gas Project (Coal Seam Gas Joint Venture). Coal evaluation core-hole drilling completed during the 1970s and 1980s by the New South Wales government identified the distribution and thickness of the coal measures within a portion of PEL 433. The Hoskissons Coal Seam is believed to be approximately 4 to 6 meters thick and widely distributed within the eastern part of PEL 433. There has been no previous coal seam gas exploration and evaluation work in the area, and there is no information on gas content, gas composition or coal permeability.

In July 2007, we entered into a Farm-In Agreement with Eastern Star Gas Limited under which we have earned a 35% working interest in the PEL 433 and adjoining PEL 434 properties. Under the terms of the Farm-In Agreement, we paid the costs of a two core-hole program and the related costs of the evaluation of the coal reservoirs intersected by the core-holes. The two corehole drilling program commenced during July 2007 and evaluated the coal seam gas potential of the Hoskissons Coal Seam within the Late Permian Black Jack Coal Measures. Additional coring may be undertaken on PEL 433 to provide additional data on coal depth, thickness, permeability, gas contents and composition.

The area believed to be the most prospective for coal seam gas within PEL 433 underlies and is in close proximity to the Central Ranges Natural Gas Pipeline that links Dubbo with Tamworth and joins with the larger Moomba-Sydney Gas Pipeline. This gas pipeline would enable gas sales within the region and potentially in Sydney and surrounding markets.

The area on which PEL 433 is located is subject to a native title claim lodged in June 2002 by the Tubba-Gah People (NSD6010/02). See “Governmental Regulation-Australian Governmental Regulation-Native Title”.

 

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Production, Prices and Operating Expenses

The following table presents information regarding the production volumes, average sales prices received and average production costs associated with our sales of natural gas and oil for the years ended December 31, 2007 and 2006. Oil and condensate are compared with natural gas in terms of cubic feet of natural gas equivalents. One barrel of oil or condensate is the energy equivalent of six Mcf of natural gas.

 

		For the Three Months Ended						For the Years Ended December 31,
		2008			2007			2007			2006
Production:
Natural gas (MMcf)			2,406			1,253			6,576			4,646
Oil (MBbl)			1			3			8			12
Total (MMcfe)			2,413			1,272			6,621			4,716
Total (MMcfed)			26.5			14.1			18.1			12.9
Average sales prices:
Natural gas (per Mcf), including impact of realized hedging activities		$	6.96		$	5.86		$	5.18		$	5.60
Oil (per Bbl)		$	96.84		$	55.05		$	66.17		$	64.66
Selected data per Mcfe:
Lease operating, transportation and selling expenses		$	0.94		$	1.81		$	1.32		$	1.82
General and administrative expenses		$	1.77		$	2.50		$	2.13		$	2.87
Depreciation, depletion and amortization of natural gas and oil properties		$	2.66		$	3.41		$	3.24		$	3.46

Drilling Activity

The following table shows our drilling activity for the periods indicated. In the table, “gross” wells refer to wells in which we have a working interest, and “net” wells refer to gross wells multiplied by our working interest in such wells. “Undecided” wells are CBM wells for which permanent equipment was installed for the production of natural gas or oil but that as of each respective period end were in the process of de-watering.

 

		For the Years Ended December 31,
		2007				2006
		Gross		Net		Gross		Net
Exploratory wells:
Productive		4		2.2		4		2.3
Non-productive		1		0.3		1		0.3
Under evaluation		10		7.5		9		3.2
Total		15		10.0		14		5.8
Development wells:
Productive		31		14.8		43		19.5
Non-productive		—		—		—		—
Total		31		14.8		43		19.5

 

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Exploration and Development Acreage

The following table sets forth our ownership interest in undeveloped and developed acreage in the areas indicated where we own a working interest as of December 31, 2007. Gross represents the total number of acres in which we own a working interest. Net represents our proportionate working interest resulting from our ownership in gross acres.

 

		Undeveloped Acreage				Developed Acreage
		Gross		Net		Gross		Net
Hilltop area, East Texas		28,494		12,144		6,942		4,106
Powder River Basin, Wyoming and Montana		33,917		11,992		21,049		9,862
Other		7,017		5,782		—		—
Total United States		69,428		29,918		27,991		13,968
Gunnedah Basin, New South Wales		6,047,150		2,116,503		2,200		770
Total Australia		7,047,150		2,866,503		2,200		770

Productive Wells

The following table sets forth our working interest ownership in productive economic wells in the areas indicated as of December 31, 2007, based on our third party reservoir engineering report. Gross represents the total number of wells in which we own a working interest. Net represents our proportionate working interest resulting from our ownership in gross wells. Productive wells are wells that are capable of producing natural gas or oil in economic quantities. Wells that are completed in more than one producing horizon are counted as one well.

 

		Productive Wells
		Natural Gas				Oil				Total Wells
		Gross		Net		Gross		Net		Gross		Net
Hilltop area, East Texas		17		12.0		—		—		17		12.0
Powder River Basin, Wyoming and Montana		283		125.2		—		—		283		125.2
Total United States		300		137.2		—		—		300		137.2

As of December 31, 2007, we had no commercially productive wells in Australia.

Natural Gas and Oil Reserves

Our estimated total net proved reserves of natural gas and oil as of December 31, 2007 and the present values of estimated future net revenues attributable to those reserves as of those dates are presented in the following table. These estimates were prepared by NSAI and are part of their reserve reports on our natural gas and oil properties. The estimates of NSAI were based on a review of geologic, economic, ownership and engineering data that we provided.

In accordance with SEC regulations, estimates of our proved reserves and future net revenues are made using sales prices in effect as of the date of the reserve estimates and are held constant throughout the life of the properties, except to the extent a contract specifically provides for escalation. Estimated quantities of proved reserves and future net revenues are affected by natural gas and oil prices, which have fluctuated significantly in recent years. Our estimated proved reserves have not been filed with or included in reports to any U.S. federal agency.

 

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		Total Proved Reserves as of December 31, 2007
		Producing			Non- producing			Undeveloped			Total
Natural gas (MMcf)		$	21,778			12,280			20,764			54,822
Oil (MBbls)			9			—			—			9
Total proved reserves (MMcfe)			21,831			12,280			20,764			54,875
Standardized measure of discounted future net cash flow (000)		$	70,374		$	40,160		$	21,698		$	132,232

Pricing Assumptions

SEC regulations require that the natural gas and oil prices used in the NSA reserve reports are the period-end prices for natural gas and oil at December 31, 2007. These prices are held constant in accordance with SEC guidelines for the life of the wells included in the reserve reports but are adjusted by lease for energy content, quality, transportation, compression and gathering fees, and regional price differentials. The pricing assumptions are listed below:

 

		As of December 31, 2007
		Gas			Oil
		($/MMBtu)			($/Bbl)
Production:
Hilltop Area		$	6.795		$	92.50
Powder River Basin		$	6.040		$	—

The weighted average natural gas and oil prices after basis adjustments used in our reserve valuation as of December 31, 2007 were $6.08 per Mcf and $93.88 per barrel.

The prices used in calculating the estimated future net revenue attributable to proved reserves do not reflect market prices for natural gas and oil production sold subsequent to December 31, 2007. There can be no assurance that all of the estimated proved reserves will be produced and sold at the assumed prices. Accordingly, the foregoing prices should not be interpreted as a prediction of future prices.

For additional information concerning our estimated proved reserves, the standardized measure of discounted future net cash flows of the proved reserves at December 31, 2007, 2006 and 2005 and the changes in quantities and standardized measure of such reserves for each of the three years then ended, see Note 21 – Supplemental Oil & Gas Disclosures – Unaudited to our annual consolidated financial statements, which begin on page F-27.

Markets and Customers

The success of our operations is dependent upon prevailing prices for natural gas and oil. The markets for natural gas and oil have historically been volatile and may continue to be volatile in the future. Natural gas and oil prices are beyond our control. However, rising demand for natural gas to fuel power generation and meet increasing environmental requirements has led some industry observers to indicate that long-term demand for natural gas is increasing.

Our current United States production has access to major intrastate and interstate pipeline systems. We contract to sell natural gas from our properties with spot market contracts that vary with market forces on a monthly basis. While overall natural gas prices at major markets, such as Henry Hub in Louisiana, may have some impact on regional prices, the regional natural gas price at our production facilities may move somewhat independently of broad industry price trends. Because some of our operations are located in specific regions, we are directly impacted by regional natural gas prices in those regions regardless of pricing at major market hubs. The East Texas Basin area has an extensive natural gas pipeline infrastructure in place. Our deep Bossier production is transported to the Katy Hub in Katy, Texas, where numerous parties are available to purchase our natural gas production. Powder River Basin natural gas is sold under spot market contracts to major pipeline and natural gas marketing companies.

 

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Australian natural gas markets and infrastructure exist and are viable markets; however, they are not as developed as the markets and infrastructure in the United States. Specifically, the PEL 238 concession is currently not served by any natural gas infrastructure. The initial gas market for PEL 238 natural gas is anticipated to be an electricity generation facility owned and operated by Eastern Star Gas Ltd. and located near the town of Narrabri, New South Wales, Australia. Although there currently is no pipeline from the existing and planned CBM project areas, we and our joint venture partner are in the permitting phase for the construction of the gathering system and pipeline, which is anticipated to be completed by late 2008.

The longer term market for PEL 238 natural gas is considered to be future gas-fired power generation facilities in New South Wales and the industrial and residential markets in the Sydney-Newcastle-Wollongong areas of New South Wales. Recent announcements of planned LNG facilities in southern Queensland are to be sourced from coalbed methane projects, which could potentially lead to the possibility of a portion of future PEL 238 production being sold to LNG export facilities. In March 2007, we announced that we had executed, along with our joint venture partner, a MOU with Macquarie Generation, a government-owned electricity generator in the state of New South Wales, Australia. The MOU sets the framework for negotiation of a potential long-term agreement to supply natural gas for Macquarie Generation’s Bayswater power station. In November 2007, we announced that we and our joint venture partner had entered into a second MOU with Babcock & Brown (“Babcock & Brown MOU”) to supply gas from the PEL 238 and PEL 433 concessions for use in the generation of electricity. The Babcock & Brown MOU envisions the supply of up to 38 Bcf per year of natural gas from the Gunnedah Gas Project over multiple years for use in a gas fueled power station to be developed by Babcock & Brown in northern New South Wales, Australia commencing in late 2010. Natural gas sales under the anticipated agreements could be expanded to meet requirements for power station developments at other locations, though there is no assurance that such an agreement will ultimately be reached or that such volumes will ultimately be produced from the PEL 238 and PEL 433 concessions. In addition, a potential gas supply and purchase agreement with Macquarie Generation would serve to underpin the development of the approximately 300 kilometers of pipeline infrastructure necessary to transport gas from the PEL 238 concession to Bayswater. An additional 150 kilometers of pipeline infrastructure would be required to access the natural gas markets of Sydney-Newcastle-Wollongong area.

The area on which PEL 433 is located is subject to a native title claim lodged in June 2002 by the Tubba-Gah People (NSD6010/02). See “Governmental Regulation – Australian Governmental Regulation-Native Title”.

Our very limited oil production in Texas and the Appalachian Basin in West Virginia is sold under spot sales transactions at market prices. The availability and price responsiveness of the multiple oil purchasers provides for a highly competitive and liquid market for oil sales.

In March 2008, we entered into formal agreements with ETC Texas Pipeline, Ltd. (“ETC”) for the gathering, treating, purchase and transportation of our natural gas production from the Hilltop area of East Texas. These agreements are effective September 1, 2007 and have a term of 10 years. ETC currently provides us 50 MMcfd of treating capacity and 120 MMcfd of gathering capacity. We have the right to request ETC build, at their cost, up to 150 MMcfd of treating and gathering capacity during the term of the agreement, provided that our production equals 85% of the then existing treating and gathering capacity for a 30 day period. We may at any time elect to have our treating and gathering capacity increased subject to cost indemnifications to ETC. Additional treating and gathering capacity requests must be in at least 25 MMcfd and 5 MMcfd increments, respectively. In addition, we must furnish to ETC information that reasonably demonstrates that our projected production for the five years after expansion is sufficient to warrant the costs to create the expanded treating and gathering capacity. The incremental volume increases in treating and gathering capacity shall be subject to marginal increases in treating fees. Pursuant to the agreements, we have access up to 150 MMcfd of firm transportation on ETC’s system or the pipelines of its affiliates or subsidiaries from the tailgate of the treating facility to Katy Hub. We have the option to sell and ETC has the obligation to buy, up to 150 MMcfd of our Hilltop production at delivery points upstream of ETC’s gathering and treating facilities. We do not have an obligation to deliver to ETC volumes in excess of 150 MMcfd, but should ETC elect to purchase such excess volumes, purchases will be subject to the treating and gathering expansion terms set forth in the agreements.

 

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During 2007, ETC and Enserco Energy, Inc. (“Enserco”) accounted for 78% and 20% of our natural gas and oil revenues, respectively. During 2006, sales to ETC and Enserco accounted for 63% and 25% of our natural gas and oil revenues, respectively. During 2005, ETC and Enserco accounted for 65% and 26%, respectively, of our natural gas and oil revenues. Although ETC is the major natural gas purchaser and transporter in the area of our deep Bossier play and only limited natural gas purchaser and transporter alternatives are currently available in this area, management believes that other natural gas purchasers and transporters could ultimately be located and would minimize any long-term material adverse impact on our financial condition or results of operations. Management believes that the loss of Enserco in the Powder River Basin would not have a long-term material adverse impact on our financial position or results of operations, as there are numerous other purchasers operating in the Powder River Basin.

Competition

The natural gas and oil industry is intensely competitive and speculative in all of its phases. We encounter competition from other natural gas and oil companies in all areas of our operations. In seeking suitable natural gas and oil properties for acquisition, we compete with other companies operating in our areas of interest, including large natural gas and oil companies and other independent operators, many of whom have greater financial resources and in many instances, have been engaged in the exploration and production business for a much longer time than we have. Many of our competitors also have substantially larger operating staffs than we do. Many of these competitors not only explore for and produce natural gas and oil but also market natural gas and oil and other products on a regional, national or worldwide basis. These competitors may be able to pay more for productive natural gas and oil properties and exploratory prospects and define, evaluate, bid for and purchase a greater number of properties and prospects than us. In addition, these competitors may have a greater ability to continue exploration activities during periods of low market prices. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

Prices of our natural gas and oil production are controlled by market forces. However, competition in the natural gas and oil exploration industry also exists in the form of competition to acquire leases and obtain favorable transportation prices. We are smaller and have a more limited operating history than most of our competitors and may have difficulty acquiring additional acreage and/or projects and may have difficulty arranging for the transportation of our production. We also face competition in obtaining natural gas and oil drilling rigs and in providing the manpower to operate them and provide related services.

Governmental Regulation

In addition to the environmental regulations discussed below, our natural gas and oil exploration, production and related operations are subject to extensive rules and regulations promulgated in the United States and Australia. These laws and regulations, all of which are subject to change from time to time, include matters relating to land tenure; drilling and production practices, such as discharge permits and the spacing of wells; the disposal of water resulting from operations and the processing, handling and disposal of hazardous materials, such as hydrocarbons and naturally occurring radioactive materials; bonding requirements; ongoing obligations for licensing; reporting requirements; marketing and pricing policies; royalties; taxation; and foreign trade and investment.

Failure to comply with these rules and regulations can result in substantial penalties. Furthermore, we could be liable for personal injuries, property damage, spills, discharge of hazardous materials, reclamation costs, remediation, clean-up costs and other environmental damages as a consequence of acquiring a natural gas or oil prospect or acreage.

The regulatory burden on the natural gas and oil industry increases our cost of doing business and affects our financial condition. Although we believe we are in substantial compliance with all applicable laws and regulations, we are unable to predict the future cost or impact of complying with such laws because those laws and regulations are frequently amended or reinterpreted. We are unable to predict what additional legislation or amendments may be proposed that will affect our operations or when any such proposals, if enacted, might become effective.

 

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U.S. Governmental Regulation

Transportation and Sale of Natural Gas. Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the regulations promulgated thereunder by the Federal Energy Regulatory Commission, or FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. Deregulation of natural gas sales by producers began with the enactment of the Natural Gas Policy Act of 1978. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining Natural Gas Act of 1938 and Natural Gas Policy Act of 1978 price and non-price controls affecting producer sales of natural gas effective January 1, 1993. Congress could, however, re-enact price controls in the future.

FERC regulates interstate natural gas pipeline transportation rates and service conditions, which affect the marketing of natural gas produced by us and the revenues received by us for sales of such natural gas. FERC requires interstate pipelines to provide open-access transportation on a non-discriminatory basis for all natural gas shippers. FERC frequently reviews and modifies its regulations regarding the transportation of natural gas with the stated goal of fostering competition within all phases of the natural gas industry. In addition, with respect to production onshore or in state waters, the intra-state transportation of natural gas would be subject to state regulatory jurisdiction as well.

Additional proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, FERC, state regulatory bodies and the courts. We cannot predict when or if any such proposals might become effective or their effect, if any, on our operations. The natural gas industry historically has been closely regulated; thus there is no assurance that the less stringent regulatory approach recently pursued by FERC and Congress will continue indefinitely into the future. We do not believe that we will be affected by any action taken in a materially different way than other natural gas producers, gatherers and marketers with which we compete.

Federal Regulation of Sales and Transportation of Crude Oil. Our sales of crude oil and condensate are not currently regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. Certain regulations implemented by FERC in recent years could result in an increase in the cost of pipeline transportation service. We do not believe, however, that these regulations affect us any differently than other producers.

Our operations are subject to extensive and continually changing regulation affecting the natural gas and oil industry. Many departments and agencies, both federal and state are authorized by statute to issue, and have issued, rules and regulations binding on the natural gas and oil industry and its individual participants. The failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the natural gas and oil industry increases our cost of doing business and, consequently, affects our profitability. We do not believe that we are affected in a significantly different manner by these regulations than are our competitors.

Regulation of Production. The production of natural gas and oil is subject to regulation under a wide range of state and federal statutes, rules, orders and regulations. State and federal statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. The states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of the natural gas and oil properties; the establishment of maximum rates of production from natural gas and oil wells; the spacing of wells; and the plugging and abandonment of wells and removal of related production equipment. These regulations can limit the amount of the natural gas and oil we can produce from our wells, limit the number of wells, or limit the locations at which we can conduct drilling operations. Moreover, each state generally imposes a production or severance tax with respect to production and sale of natural gas, natural gas liquids and crude oil within its jurisdiction.

Australian Governmental Regulation

Commonwealth and State Laws and Regulations. The regulation of the activities of participants in the natural gas and oil industry in Australia is similar to that of the United States, in that regulatory controls are imposed at both the state and commonwealth (federal) levels. Specific commonwealth regulations impose environmental, petroleum industry licensing, foreign investment, cultural heritage and native title restrictions on accessing resources in Australia. These regulations are in addition to any state level regulations.

 

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Foreign Investment Regulation. Foreign investment in Australia is regulated by the commonwealth through its foreign investment legislation and policy. In some circumstances, Australian foreign investment regulation and policy requires foreign interests to obtain prior approval from the Treasurer before investing in specific industry sectors. The Foreign Investment Review Board administers the regulation of foreign investment on behalf of the commonwealth. Its functions include analyzing proposals by foreign interests for investment in Australia and making recommendations to the government on the compatibility of those proposals with government policy and the relevant legislation. In some circumstances, the acquisition of, investment in or formation of a new business, or acquisition of urban land will require review and approval under the commonwealth foreign investment policy and regulations.

Native Title. In a landmark Australian High Court decision in 1992, it was recognized that the native title to land of Indigenous Australians survived the acquisition of sovereignty by the British Crown. However native title to any particular area will only survive to the present if it has not been extinguished subsequently. Native title may be extinguished by the action of government, such as the creation of an interest that is inconsistent with native title. In particular, the grant of the right to exclusive possession through freehold title or a lease will wholly extinguish native title. Native title may also be extinguished if the connection between the land and the group of Aboriginal people claiming native title has been lost. The Native Title Act 1993 (Cth) was enacted in 1993 in order to provide a statutory framework for deciding questions such as where native title exists, who holds native title and how dealings affecting native title can be conducted in the future. Native title claims by Aboriginal groups can cover existing and potential natural gas and oil exploration and development areas. If we apply to the relevant state or territory for an onshore exploration permit or production license over Crown land or “Aboriginal” land which has a registered native title claimant or a registered native title holder, we will have to go through a mandatory negotiation process, followed by an arbitration conducted by the National Native Title Tribunal if no agreement can be reached through negotiation. The results of the negotiation may impose significant financial obligations on us. Each application for an exploration permit, production license or a pipeline license must be examined individually in order to determine the existence of native title claims or determinations. To validly affect native title, permits and licenses must be granted in compliance with the Native Title Act 1993 (Cth).

Australian Petroleum Regulation and Gas Markets. All petroleum tenements in which we hold an interest are subject to specific licensing regulation in the relevant states. Each exploration permit or production license will (depending on the nature of the license and the state in which the project is located) be issued subject to various obligations. These may include obligations as to expenditure, payment of rent, consultation with occupiers and rehabilitation. These obligations must be met to maintain the good standing of the tenement. Licenses may be cancelled or revoked for non compliance. In Australia, the ownership of minerals (including petroleum) is vested in the government and ownership only passes to the license holder once the relevant mineral is extracted. We are required to pay Government royalties of 10% of the wellhead value of petroleum extracted. Several statutory mechanisms regulate access rights to a range of infrastructure in Australia including gas transmission pipelines. These involve generic access regulations contained in the Trade Practices Act 1974 (Cth) and industry specific schemes contained in specific legislative instruments, industry codes and schemes. Objectives of this regulatory regime include providing a process for establishing third party access to natural gas pipelines, facilitating the development and operation of a national natural gas market, promoting a competitive market for natural gas in which customers are able to choose their supplier, and providing a right of access to transmission and distribution networks on fair and reasonable terms and conditions. We cannot currently ascertain the impact of the regime objectives on our operations but believe it could benefit us.

Environmental Regulation

Our U.S. natural gas and oil exploration and production operations and similar operations that we do not operate but in which we own a working interest are subject to significant federal, state and local environmental laws and regulations governing environmental protection as well as the discharge of substances into the environment. These laws and regulations may restrict the types, quantities and concentrations of various substances that can be released into the environment as a result of natural gas and oil drilling, production and processing activities; suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands and other protected areas; require remedial measures to mitigate pollution from historical and on-going operations such as the

 

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use of pits and plugging of abandoned wells; and restrict injection of liquids into subsurface strata that may contaminate groundwater. Governmental authorities have the power to enforce compliance with their laws, regulations and permits, and violations may result in the issuance of injunctions limiting or prohibiting operations, as well as administrative, civil and even criminal penalties. The effects of these laws and regulations, as well as the assessment of other laws or regulations that are adopted in the future, could have a material adverse impact on our operations and other operations in which we own an interest. As discussed below, our Australian operations are similarly subject to regulation by Australian authorities.

We believe that we are in substantial compliance with existing applicable environmental laws and regulations. However, it is possible that new environmental laws and regulations or the modification or more stringent enforcement of existing laws and regulations could have a material adverse effect on our operations and other operations in which we own an interest. As a general matter, the recent trend in environmental legislation and regulation is toward stricter standards, and this trend will likely continue. To date, we have not been required to expend significant resources in order to satisfy existing applicable environmental laws and regulations. However, there is no assurance that costs to comply with existing, and any new environmental laws and regulations in the future will not be material. In addition, if substantial liabilities to third parties or governmental entities are incurred, the payment of such claims may reduce or eliminate the funds available for project investment or result in loss of our properties. Moreover, a serious incident of pollution may result in the suspension or cessation of operations in the affected area. Although we maintain insurance coverage against costs of clean-up operations, no assurance can be given that we are fully insured against all such potential risks. The imposition of any of these liabilities or compliance obligations on us may have a material adverse effect on our financial condition and results of operations.

The following is a summary of some of the existing environmental laws, rules and regulations to which our business operations are subject.

U.S. Environmental Regulations

In the United States, environmental laws are implemented principally by the United States Environmental Protection Agency, or EPA, the Department of Transportation and the Department of the Interior, as well as other comparable state agencies.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superfund law, imposes strict, joint and several liability without regard to fault or legality of conduct on persons who are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that transported, disposed or arranged for the disposal of the hazardous substance released at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring land owners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Although CERCLA currently excludes “petroleum” and “natural gas, natural gas liquids, liquefied natural gas or synthetic gas useable for fuel,” from the definition of “hazardous substance”, our operations as well as other operations in which we own an interest may generate materials that are subject to regulation as hazardous substances under CERCLA.

CERCLA may require payment for cleanup of certain abandoned waste disposal sites, even if such waste disposal activities were undertaken in compliance with regulations applicable at the time of disposal. Under CERCLA, one party may, under certain circumstances, be required to bear more than its proportional share of cleanup costs if payment cannot be obtained from other responsible parties. CERCLA authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. The scope of financial liability under these laws involves inherent uncertainties.

Resource Conservation and Recovery Act. The Resource Conservation and Recovery Act, or RCRA, and comparable state programs regulate the management, treatment, storage and disposal of hazardous and non-hazardous solid wastes. Our operations and other operations in which we own an interest generate wastes, including hazardous wastes that are subject to RCRA and comparable state laws. We believe that these operations are

 

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currently complying in all material respects with applicable RCRA requirements. Although RCRA currently exempts certain natural gas and oil exploration and production wastes from the definition of hazardous waste, we cannot assure you that this exemption will be preserved in the future. In the past, proposals have been made to amend RCRA to rescind this exemption. Repeal or modification of the exception or similar exemptions in state law could increase the amount of hazardous waste we are required to manage and dispose of and could cause us to incur increased operating cost, which could have a significant impact on us as well as the natural gas and oil industry in general.

We currently own, lease, own a working interest in, or operate numerous properties that for many years have been used by third parties for the exploration and production of natural gas and oil. Although we abide by standard industry operating and disposal practices, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us or in which we own an interest, or on or under other locations, including off-site locations, where such substances have been taken for disposal or recycling. In addition, many of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes (including substances disposed of or released by prior owners or operators), remediate contaminated property or perform remedial plugging or pit closure operations to prevent future contamination.

Water Discharges. Our operations and other operations in which we own a working interest are subject to the Clean Water Act, or CWA, as well as the Oil Pollution Act, or OPA, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States, including wetlands. Under the CWA and OPA, any unpermitted release of pollutants from operations could cause us to become subject to the costs of remediating a release; administrative, civil or criminal fines or penalties; or OPA specified damages, such as damages for loss of use and natural resource damages. In addition, in the event that spills or releases of produced water from natural gas and oil production operations were to occur, we would be subject to spill notification and response requirements under the CWA or the equivalent state regulatory program. Depending on the nature and location of these operations, spill response plans may also have to be prepared.

Our natural gas and oil exploration and production operations and other operations in which we own an interest generate produced water as a waste material, which is subject to the disposal requirements of the CWA, Safe Drinking Water Act, or SDWA, or an equivalent state regulatory program. Naturally occurring groundwater is also typically produced by CBM production in our operations or in other operations in which we own an interest. This produced water is disposed of by re-injection into the subsurface through disposal wells, discharge to the surface, or in evaporation ponds. Whichever disposal method is used, produced water must be disposed of in compliance with permits issued by regulatory agencies and in compliance with applicable environmental regulations. This water can sometimes be disposed of by discharging it under discharge permits issued pursuant to the CWA or an equivalent state program. Another common method of produced water disposal is subsurface injection in disposal wells. Such disposal wells are permitted under the SDWA or an equivalent state regulatory program. To date, we believe that all necessary surface discharge or disposal well permits have been obtained and that the produced water has been discharged into the produced water disposal wells in substantial compliance with such obtained permits and applicable laws. Nonetheless, in connection with CBM production in the Powder River Basin, a concern common to many operators in the Basin is the potential for opposition by individuals or groups to the issuance of a permit for the discharge or disposal of water generated by production activities. Such opposition could result in delays, limitations or denials with respect to environmental or other approvals necessary to develop our acreage in the Powder River Basin, which could adversely affect our financial condition or results of operations.

Air Emissions. The Clean Air Act, or CAA, and comparable state laws and regulations govern emissions of various air pollutants through the issuance of permits and the imposition of other requirements. Air emissions from some equipment found at our operations or other operations in which we own an interest, such as gas compressors, are potentially subject to regulations under the CAA or equivalent state and local regulatory programs, although many small air emission sources are expressly exempt from such regulations. To the extent that these air emissions are regulated, they are generally regulated by permits issued by state regulatory agencies. To date, we believe that no unusual difficulties have been encountered in obtaining air permits. However, there is no assurance in the future, we will not be required to incur capital expenditures in connection with maintaining or obtaining operating permits and approvals addressing air emission-related issues.

 

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Our CBM production operations involve the use of gas-fired compressors to produce or transport gas that is produced. Emissions of combustible by-products from compressors at one location may be large enough to subject the compressors to CAA and comparable state air quality regulation requirements for pre-construction and operating permits. To date, we believe that such gas-fired compressors that have been operated by us or at other operations in which we own a working interest have been operated in substantial compliance with obtained permits and the applicable federal, state and local laws and regulations without undue cost to or burden on our business activities. Another air emission associated with the CBM operations that may be subject to regulation and permitting requirements is particulate matter resulting from construction activities and vehicle traffic. To date, we do not believe there has been any unusual difficulty in complying with requirements related to particulate matter.

Other Laws and Regulations. Our operations and other operations in which we own a working interest are also impacted by regulations governing the handling, transportation, storage and disposal of naturally occurring radioactive materials. Furthermore, owners, lessees and operators of natural gas and oil properties are also subject to increasing civil liability brought by surface owners and adjoining property owners. Such claims are predicated on the damage to or contamination of land resources occasioned by drilling and production operations and the products derived therefrom and are often based on negligence, trespass, nuisance, strict liability or fraud.

In response to recent studies suggesting that emissions of certain gases including carbon dioxide, may be contributing to warming of the Earth’s atmosphere, many foreign nations have agreed to limit emissions of these gases, generally referred to as “greenhouse gases”, pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol”. Although the United States is not participating in the Kyoto Protocol, the current session of Congress is considering climate change legislation, with multiple bills having already been introduced in the Senate that propose to restrict greenhouse gas emissions. One bill recently approved by the U.S. Senate Environment and Public Works Committee, known as the Lieberman-Warner Climate Security Act or S.2191, would require a 70% reduction in emissions of greenhouse gases from sources within the United States between 2012 and 2050. The Lieberman-Warner bill proposes a “cap and trade” scheme of regulation of greenhouse gas emissions or a ban on emissions above a defined reducing annual cap. Covered parties will be authorized to emit greenhouse emissions through the acquisition and subsequent surrender of emission allowances that may be traded or acquired on the open market. A vote on this bill by the full Senate is expected to occur before mid-year 2008. In addition, at least 17 states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs require either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries or gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year until the overall greenhouse gas emission reduction goal is achieved. Depending on the particular program, we could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from our operations or from combustion of fuels (such as natural gas or oil) we produce. Although we would not be impacted to a greater degree than other similarly situated producers of natural gas and oil, a stringent greenhouse gas control program could have an adverse effect on our cost of doing business and could reduce demand for the natural gas and oil we produce.

Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may be required to regulate carbon dioxide and other greenhouse gas emissions from mobile sources, such as cars and trucks even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The EPA has indicated that it will issue a rulemaking notice to address carbon dioxide and other greenhouse gas emissions from vehicles and automobile fuels, although the date for issuance of this notice has not been finalized. The Supreme Court’s holding in Massachusetts that greenhouse gases including carbon dioxide fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of carbon dioxide and other greenhouse gas emissions from stationary sources under certain Clean Air Act programs. New federal or state restrictions on emissions of carbon dioxide that may be imposed in areas of the United States in which we conduct business could also adversely affect our cost of doing business and demand for the natural gas and oil we produce.

Finally, legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security, or DHS, and other agencies concerning the security of industrial facilities,

 

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including natural gas and oil facilities. Our operations and the operations of the natural gas and oil industry in general may be subject to such laws and regulations. The federal Department of Homeland Security Appropriations Act of 2007 required the DHS to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including natural gas and oil facilities that are deemed to present “high levels of security risk”. The DHS issued an interim final rule, known as the Chemical Facility Anti-Terrorism Standards Interim Final Rule, in April 2007 regarding risk-based performance standards to be attained pursuant to the Act and, on November 20, 2007, further issued an Appendix A to the interim rule that establish chemicals of interest and their respective threshold quantities that trigger compliance with this rule. Facilities that possess the threshold quantities of chemicals of interest must submit to an initial screening process for DHS to determine if they present a high level of security risk. Facilities that are deemed to pose a high level of security risk will be required to prepare and submit Security Vulnerability Assessments and Site Security Plans and comply with other regulatory requirements including those regarding inspections, audits, recordkeeping and protection of Chemical-terrorism Vulnerability Information. We have not yet determined the extent to which our facilities are subject to the interim rules or the associated costs to comply, but it is possible that such costs could be substantial.

Australian Environmental Regulations

Australia has environmental laws and regulations that are similar in scope and impact to United States environmental laws and regulations. Similar approval, licensing and operational impacts apply at a commonwealth, state and local government level. As a result, environmental laws and regulations can result in similar licensing and operational impacts in Australia that are similar to those discussed above with respect to the United States.

Australia ratified the Kyoto Protocol on December 3, 2007, and officially committed to meeting its Kyoto Protocol target. Australia set a target to reduce greenhouse gas emissions by 60% on 2000 levels by 2050 and committed to actively participate in negotiations working towards a post 2012 agreement involving developed and developing countries. Australia has introduced a National Greenhouse and Energy Reporting Act 2007, which establishes a single national system for reporting greenhouse gas emissions, abatement actions and energy consumption and production by corporations from July 1, 2008. Data reported through the system will underpin the Australian Emissions Trading Scheme, or AETS, which is to be introduced by 2010. The consultation stage and detailed design of the AETS is to be finalized by the end of 2008. The government has made it clear that it plans to introduce a “cap and trade scheme” in which total emissions are capped, permits allocated up to the cap and trading allowed to let the market find the cheapest way to meet any necessary emission reductions. As the details of the AETS are not yet finalized, we are unable at this stage to assess the likely impact of the AETS on our operations in Australia.

The legislation regulating environmental assessment at a commonwealth level is the Environmental Protection and Biodiversity Conservation Act 1999 (Cth.). This Commonwealth Act establishes a regime for protecting the environment, flora and fauna biodiversity and Australian national heritage. It requires any person taking an action which could have a significant impact on one of these values to refer it to the commonwealth Minister for the Environment for consideration and potential assessment. The Act only applies to matters of national environmental or heritage significance. These are matters which impact on a world heritage site, Ramsar wetlands, species which are listed as threatened under the Act, migratory species, nuclear actions and commonwealth marine areas or places listed on the commonwealth heritage list. Operators are required to assess their projects to determine whether an action is likely to have a significant impact on matters of national environmental significance and make a decision respecting submission of that assessment to a public referral process. The referral is expected to add time to the existing approval process but its effect on a project will depend on the significance of the impact identified. In addition, see the discussion in “Business-Gunnedah Basin, New South Wales, Australia” for a discussion of the New South Wales government’s bioregion study involving PEL 238.

Environmental protection and planning issues are also regulated in each state and territory by specific legislation enacted by each state or territory. The governments of New South Wales and Victoria both have a suite of legislation regulating environmental matters in their states. Generally speaking, onshore natural gas and oil projects in New South Wales and Victoria require an environmental approval from the state (and sometimes commonwealth) government, land use planning approval from local government and an approval under the relevant petroleum regime (as referred to above). Legislation provides for the integrated assessment of these issues. The environmental regulators in both New South Wales and Victoria have the ability to require a project operator to prepare and implement a plan to improve the environmental performance of a project and may also amend the

 

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conditions on an existing environmental approval. As such, the environmental regulation of a project may not be assumed to remain static following approval and may become more onerous over time. The legislation imposes a licensing approval and contamination management scheme which may impact on our operations and impose a liability which may extend beyond the time period during which properties are operated, occupied or owned. The laws and regulations also restrict emissions to air, land and water and may control or regulate substances which can be released into the environment and the manner in which they are transported and disposed of. Approvals will usually include terms which require remediation and reinstatement obligations for the site during the course of operations and following closure of the project.

Australian laws and regulations protecting archeological relics, cultural, natural and built heritage as well as native flora and fauna can also impact on our operations and impose obligations in respect of restitution or replacement, as well as liability in respect of damage. In particular, indigenous cultural heritage protection laws are becoming increasingly stringent and in many states and the Northern Territory the specialist indigenous heritage protection laws require a proponent to negotiate directly with indigenous groups with respect to a major project.

Industry Segment and Geographic Information

We operate in one industry segment, which is the exploration, development and production of natural gas and oil. Our operational activities are conducted in the United States and Australia with only the United States currently having revenue generating operating results.

Employees

As of June 17, 2008, we had 25 employees, all of whom are full time. We use the services of independent consultants and contractors to perform various professional services, including reservoir engineering, land, legal, regulatory reporting, environmental and tax services. On those properties where we are not the operator, we rely on outside operators to drill, produce and market our natural gas and oil. Our employees do not belong to a union or have a collective bargaining organization. Management considers its relationship with employees to be good.

Corporate Offices

Our parent leases corporate offices at 1331 Lamar Street, Suite 1080, Houston, Texas 77010. Our office space covers 9,332 square feet at a monthly rental of $17,100 through October 2010. We maintained an office in Miami, Florida (our Chief Executive Officer’s city of residence) through April 2007 at a monthly rental of $2,700 per month.

Internet Website Access

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange are made available free of charge on our internet website at www.gastar.com as soon as reasonably practicable after we have electronically filed the material with, or furnished it to, the SEC. The public may read and copy any materials we have filed with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Room 1580, Washington, DC 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet website that contains our reports, proxy and information statements and our other SEC filings. The address of that site is www.sec.gov. Information is also available at www.sedar.com for our filings required by Canadian securities regulators and the Toronto Stock Exchange. None of the information on our internet website or filed by us on www.sedar.com should be considered incorporated into, or considered a part of, this report.

We also make available free of charge on our internet website at www.gastar.com our:

 

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Code of Ethics;

 

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Terms of Reference of our Audit Committee;

 

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Terms of Reference of our Reserves Review Committee;

 

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Terms of Reference of our Governance Committee;

 

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Terms of Reference of our Remuneration Committee;

 

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Terms of Reference of our Nominating Committee; and

 

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Whistleblower Procedure.

 

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LEGAL PROCEEDINGS

The Company is a party to various litigation matters arising out of the normal course of business. The ultimate outcome of the matters discussed below cannot presently be determined, nor can the liability that could potentially result from an adverse outcome be reasonably estimated at this time. The more significant litigation matters are summarized below.

Navasota Resources L.P. (“Navasota”) vs. First Source Texas, Inc. (now Gastar Exploration Texas, Inc.), First Source Gas L.P. (now Gastar Exploration Texas LP) and Gastar Exploration Ltd. (Cause No. 0-05-451) District Court of Leon County, Texas 12th Judicial District. This lawsuit, dated October 31, 2005, contends that the Company breached Navasota’s preferential right to purchase 33.33% of the Company’s interest in certain natural gas and oil leases located in Leon and Robertson Counties and sold to Chesapeake Energy Corporation pursuant to a transaction closed November 4, 2005. The preferential right claimed is under an operating agreement dated July 7, 2000. The Company contends, among other things, that Navasota neither properly nor timely exercised any preferential right election it may have had with respect to the inter-dependent Chesapeake transaction. In July 2006, the District Court of Leon County, Texas issued a summary judgment in favor of the Company and Chesapeake. Navasota filed a Notice of Appeal to the Tenth Court of Appeals in Waco. Oral argument was heard on September 26, 2007 and the Court of Appeals issued its opinion on January 9, 2008 reversing the trial court’s rulings and rendering judgment in favor of Navasota on all counts. The Company and Chesapeake filed a motion for rehearing on February 6, 2008, and if unsuccessful, will consider filing a petition for review to the Texas Supreme Court. Pursuant to an agreement between the Company and Chesapeake, any adverse result in this matter should impact only Chesapeake’s assigned leasehold interests. While this matter is pending, it is possible that expenditures incurred, or authorizations for proposed expenditures, for drilling activities on leases which include the disputed interest may remain unpaid or not be authorized by the non-operators asserting competing ownership rights, which could require the Company to either fund a disproportionate amount of drilling costs at its own risk or postpone its drilling program on affected leases.

Gastar Exploration Texas LP v. John E. McFarlane, et al (Cause No. 0-06-161) 87th Judicial District Court of Leon County, Texas. This suit is to quiet title to an undivided 25% mineral interest under an oil and gas lease dated December 4, 2003, covering approximately 2,598 gross acres (the “Lease”). John E. McFarlane and certain other family members contend that an undivided 25% mineral interest in the lands covered by the Lease are owned in trust by the grandchildren of Fay W. McFarlane and are not covered by the Lease as Gastar claims. McFarlane, et. al., has filed an answer to the Company’s petition and also filed several different motions for summary judgment, which were denied by the District Court. A day long mediation of this lawsuit occurred on August 24, 2007, but the parties were unable to settle this matter at that time. The lawsuit is currently in the discovery phase and is currently set for a non-jury trial in October 2008. The existence of unleased mineral interests in this Lease could adversely impact the future development of the Lease. The Company will continue to vigorously pursue this claim.

Spencer D. Plummer, III v. GeoStar Corporation, Classic Star LLC, Gastar Exploration, Ltd., Thom Robinson, Tony Ferguson, and John W. Parrott; In the United States District Court of Utah, Central Division (Case No. 2:07-CV-00409). This lawsuit was filed on May 24, 2007 initially in Utah state court by Spencer Plummer, or the Plaintiff, in which he asserts breaches of his Employment Agreement and subsequent Termination Agreement (the “Agreements”) with his employer, Classic Star, a subsidiary of GeoStar. The Plaintiff claims that he has not received benefits promised under such Agreements, including 699,249 shares of Company stock. The Company is not a party to the Agreements on which Plaintiff’s claims are expressly based; however, the Company and Plaintiff are parties to a Stock Option Agreement on which Plaintiff claim to Company stock is partially based. The Company filed an Answer and Motion to Dismiss for lack of personal jurisdiction in Utah and for Plaintiff’s failure to state a claim upon which relief can be granted. Plaintiff filed a Motion to Remand to state court, and on September 5, 2007, the Court denied Plaintiff’s Motion to Remand. Thereafter, the Company’s co-defendant, Classic Star LLC, moved to transfer and consolidate the case in a United States Judicial Panel on Multi District Litigation (“MDL Panel”) in Kentucky with other cases in which Classic Star LLC is a named defendant. On October 22, 2007, the MDL Panel granted the motion to transfer. The Company is awaiting the Kentucky court’s ruling on its Motion to Dismiss.

 

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Arbitration and Litigation with GeoStar Corporation and Affiliates

Recent Settlement with GeoStar Corporation. Pursuant to a settlement agreement entered into between our Parent and GeoStar on June 12, 2008, we expect the following legal matters to be dismissed in the near future under the terms of the settlement agreement. For more discussion of the settlement, please see “Business—Recent Developments—Settlement of Arbitration and Litigation with GeoStar and Affiliates”.

Arbitration against GeoStar Corporation and Affiliates. On October 18, 2006, in connection with 10 wells to be drilled in Victoria, Australia on the jointly owned EL 4416 exploration license operated by GeoStar Corporation, the Company sent a letter to GeoStar demanding the arbitration of certain disputed issues and interpretations under a Participation and Operating Agreement (“POA”) with GeoStar and its subsidiaries. Among other items, the claims the Company presented for resolution in arbitration included claims relating to GeoStar’s demands for cash calls under the POA while simultaneously asserting that certain provisions of the POA, including overhead reimbursement rates, need to be renegotiated on terms that the Company believes are not reasonable or within industry standards. The Company had also requested that GeoStar’s Australian subsidiary provide a record title assignment of the Company’s beneficial interests in EL 4416, the exploration license in the Gippsland Basin property in Victoria, Australia. The Company had approximately $9.9 million invested in EL 4416 as of December 31, 2007. GeoStar contended that the Company is not entitled to the record title assignment notwithstanding the Company’s significant investment. The Company’s former Chairman of the Board is a major shareholder and President of GeoStar. Geostar also asserted counterclaims including (a) a request for a declaration that the Company has no rights to participate in brown coal projects in EL 4416, (b) a request for a declaration that the Company did not earn an interest under the POA as to certain wells the Company drilled in East Texas, (c) breach of contract for failure to pay certain bills and expenses and (d) breach of contract to pay for employee expenses and services. With respect to items (b) and (c), GeoStar sought recovery in an unspecified amount of at least $17 million.

Gastar Exploration, Ltd., Gastar Exploration Texas, Inc., f/k/a First Texas Development, Inc., Gastar Exploration Texas LLC, f/k/a Bossier Basin, LLC, and Gastar Exploration Texas LP, f/k/a First Source Gas, LP v. GeoStar Corporation, First Source Texas, Inc., First Source Bossier, LLC, and First Texas Gas, LP. In July 2007, the Company filed a lawsuit in Robertson County, Texas against GeoStar and affiliates seeking relief in connection with the failure by GeoStar and its affiliates to execute formal assignments of certain leases that were omitted from the schedule of leases attached to the assignments executed by GeoStar affiliates in June 2005 pursuant to Purchase and Sale Agreements covering Texas properties of GeoStar and its affiliates. The lawsuit asked the court to decree that in the transaction evidenced by the Purchase and Sale Agreements, affiliates of the Company acquired title to all properties in Texas in which GeoStar and its affiliates owned an interest and that GeoStar and its affiliates are obligated to execute formal assignments with regard to all such leases. GeoStar and certain of its affiliates filed counterclaims in this litigation, which are described below and in the section below entitled “GeoStar Look Back Developments”.

Gastar Exploration Ltd., Gastar Exploration USA, Inc. f/k/a First Sourcenergy Wyoming Inc., Gastar Exploration New South Wales, Inc., f/k/a First Sourcenergy Group, Inc., Gastar Exploration Victoria, Inc. f/k/a First Sourcenergy Victoria, Inc.,, Gastar Exploration Texas, Inc., f/k/a First Texas Development, Inc., Gastar Exploration Texas LLC, f/k/a Bossier Basin, LLC, and Gastar Exploration Texas LP, f/k/a First Source Gas, LP v. GeoStar Corporation. In July 2007, the Company and affiliates filed a lawsuit in the District Court of Harris County, Texas against GeoStar in connection with GeoStar’s failure to deliver to the Company and its affiliates the corporate records of the Company and to its affiliates that have been retained by GeoStar. The lawsuit asked the court to decree that the Company and its affiliates are entitled to possession of the corporate records and order their return to the Company and its affiliates. The lawsuit also sought recovery of actual and punitive damages, costs, and attorney’s fees. GeoStar has now delivered some of the requested records that are the subject of this litigation to the Company, and is cooperating with the Company in delivering additional records.

Gastar Exploration, Ltd., Gastar Exploration Texas, Inc., f/k/a First Texas Development, Inc., Gastar Exploration Texas LLC, f/k/a Bossier Basin, LLC, and Gastar Exploration Texas LP, f/k/a First Source Gas, LP v. GeoStar Corporation, First Source Texas, Inc., First Source Bossier, LLC, and First Texas Gas, LP. In

 

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August 2007, the Company and certain affiliates filed a second lawsuit in Robertson County, Texas, seeking a declaratory judgment that the Company and its affiliates have complied with the Look-Back provisions of the Texas Purchase and Sale Agreements that were the subject of the other Robertson County, Texas lawsuit referenced above, that the Company and its affiliates complied with the provisions of the Texas Purchase and Sale Agreements relating to the drilling of wells, and that GeoStar and its affiliates hold no farm-in interest in properties owned by the Company’s affiliates. GeoStar and one of its affiliates filed a challenge to the Texas court’s jurisdiction. The defendants also generally denied the allegations made in the lawsuit. Additionally, GeoStar and certain of its affiliates also filed counterclaims in this litigation, which are described in the following paragraph and in the section below entitled “GeoStar Look Back Developments”.

Although it previously contested jurisdiction in Texas, GeoStar, together with certain of its affiliates, asserted counterclaims in all three Texas lawsuits similar to claims GeoStar had previously asserted and dismissed in the Michigan lawsuit described below. The counterclaims related to Texas properties that were the subject of Purchase and Sale Agreements entered into in 2005, under which the Company acquired the interests of GeoStar-affiliated entities in properties in Texas. Specifically, GeoStar claims that the Company breached the Purchase and Sale Agreements by failing to provide information in connection with contingent “Look Back” payments under provisions of the Purchase and Sale Agreements, and by failing to make payments allegedly due to GeoStar under the Look-Back provisions, arising out of alleged changes in reserves following the sale of the Texas properties in June 2005. Although requesting only damages in an unspecified amount, GeoStar contended in the counterclaim that it would have been entitled under the Purchase and Sale Agreements to approximately 1.7 billion shares of Gastar stock. GeoStar also claimed that the Company failed to timely comply with provisions of the Purchase and Sale Agreements relating to the drilling of 20 wells on the properties conveyed under the Purchase and Sale Agreements and by failing to drill and test at least two wells in the Travis Peak formation in Texas, allegedly entitling GeoStar to unspecified damages related to a farm-in interest under which it was allegedly entitled to the right to drill, complete, and operate wells in the Travis Peak formation on certain acreage. Certain information that may be relevant to this matter is set forth in the section below entitled “GeoStar Look Back Developments”.

GeoStar Corporation and West Virginia Gas Corporation v. Gastar Exploration Ltd. and J. Russell Porter. On July 27, 2007, the Company was served with a lawsuit filed by GeoStar and one of its affiliates, West Virginia Gas Corporation, in federal court in Saginaw, Michigan. GeoStar asserted a broad range of claims against the Company and its current chief executive officer, J. Russell Porter. GeoStar initially sought in the Michigan suit to enjoin the Company’s arbitration against GeoStar and its affiliates. GeoStar voluntarily dismissed that request with prejudice.

GeoStar also claimed in the Michigan suit that the POA was cancelled effective January 1, 2005, and that the parties had operated under oral contracts since that date. GeoStar asserted that the Company breached the alleged oral contracts by allegedly failing to pay joint interest billings, authorizations for expenditures, and cash calls relating to operations or proposed operations on EL 4416 in Australia and West Virginia properties, in an unspecified amount exceeding $75,000. GeoStar also claimed that the Company breached alleged agreements to reimburse GeoStar for various payments and services allegedly performed by GeoStar and its personnel and paid on behalf of the Company by GeoStar. GeoStar claimed that the amounts of the payments and the value of the services exceed $10.0 million. GeoStar alternatively alleged that if there was no contract covering those payments and services, it allegedly was entitled to reimbursement on equitable principles.

 

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West Virginia Gas Corporation (WVGC), an affiliate of GeoStar, also asserted claims against the Parent’s current chief executive officer, alleging that the Company and its current chief executive officer tortiously interfered with an alleged contract between WVGC and certain West Virginia individuals and entities. According to the lawsuit, these individuals and entities allegedly promised to give their oil, gas, and coalbed methane opportunities in West Virginia and Pennsylvania to WVGC. WVGC alleged that Gastar and its chief executive officer caused those individuals and entities to establish and use new business entities to allegedly conceal opportunities from West Virginia Gas Corporation and to funnel them to the Company, the Company’s chief executive officer and the West Virginia individuals and entities. On June 23, 2008, in accordance with the parties’ settlement agreement, the court dismissed the claims against the Company and our chief executive officer with prejudice.

GeoStar Look Back Developments. The Purchase and Sale Agreements between GeoStar and the Company relating to certain East Texas properties acquired by the Company in 2005 (the “PSAs”) contained a “Look Back” provision that is the subject of claims in three of the previously described lawsuits with GeoStar. Under the 2005 PSAs, GeoStar conveyed interests in certain Texas properties to the Company and was paid an agreed $43.5 million in consideration for the properties (including cash, 8.6 million shares of Company common stock and promissory notes), subject to certain purchase price adjustments relating to the period prior to closing. The interests conveyed by the PSAs comprise a portion of the security for the notes and the Guarantees.

Under the Look Back provision, two Look Back payments were to be calculated based in part on changes in proved and probable reserves attributable to certain of the Company’s leasehold interests over certain periods of time ending June 30, 2006 and 2007. If a Look Back payment was due to GeoStar under the PSAs, the PSAs required the payment to be effected through the issuance of the Company’s stock.

The PSAs provide that the calculation of the Look Back payment shall be based upon reserve estimates reported by Netherland Sewell & Associates, Inc. (“NSA”), or in certain circumstances, based upon an average of the NSA estimates and estimates obtained by GeoStar from an independent, professionally certified reservoir engineering firm utilizing the same regulatory requirements and reserve calculation guidelines as those employed by NSA in its estimates. Based on the NSA reserves estimate and the Look Back calculations set forth in the PSAs, the Company believed that no additional issuance of Company common shares was due GeoStar under the Look Back provision.

On November 1, 2007, GeoStar informed the board of directors of our Parent that it intended to submit a reserve report for purposes of the June 30, 2006 and 2007 Look Back analyses showing that the gross reserves attributable to the Company’s leasehold interests are substantially greater than those reflected in the NSA reserve reports on which the Company’s Look Back analyses were based. On November 7, 2007, GeoStar submitted a reserve report to the Company that reported a substantially greater reserve estimate than the estimates in the NSA reserve report.

On November 14, 2007, the Company received a reserve report of T.J. Smith & Company, Inc. (“T.J. Smith”) as well as a demand letter from GeoStar’s counsel (the “Demand Letter”) in which GeoStar asserted a purported right under the PSAs to receive additional shares of Gastar stock as a Look Back payment. In the Demand Letter, GeoStar asserted that T.J. Smith has estimated that the total proved and probable reserves in the Company’s Texas properties attributable to 100% of the working interest amount to 2.15 trillion cubic feet of gas, a number which is approximately fourteen times more than the proved and probable reserves estimated by NSA, the engineering firm selected by the parties in the PSAs. On the basis of that reserves estimate, GeoStar asserted in the Demand Letter that it was entitled to a Look Back payment of approximately 1.7 billion shares of Gastar common stock, which if issued would constitute approximately 89% of the Company’s common equity and would result in a change in control of the Company under the Company’s debt agreements. In the Demand Letter, GeoStar further asserted that if its demand was not met, it would pursue remedies that may have included reclaiming operatorship over certain of the Company’s Texas properties, rescission of the PSAs resulting in return of the properties covered by the PSAs and consideration paid, and unspecified injunctive relief.

 

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In 2007, the Company recorded a $1.4 million litigation settlement expense accrual related to a proposed settlement with GeoStar regarding the various GeoStar arbitration and litigation matters. That settlement proposal was never finalized. At March 31, 2008, the Company had a receivable from GeoStar of approximately $3.7 million that was fully reserved due to the various litigation matters. The Company may incur additional litigation expense and capitalized charges as a result of the recent settlement with GeoStar, which the Company cannot currently quantify.

 

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth certain information about the beneficial ownership of our Parent’s common shares by:

 

•

Each of our Parent’s directors;

 

•

Named executive officers listed in the Summary Compensation Table set forth under the caption “Compensation of Executive Officers and Directors” below;

 

•

All of our Parent’s named executive officers and directors as a group; and

 

•

Each person known to the Company to be the beneficial owner of more than 5% of our Parent’s outstanding common shares.

Unless otherwise indicated and subject to community property laws where applicable, management believes that all persons named in the following table have sole voting and investment power over all common shares reported as beneficially owned by them.

The following table is based upon information supplied by officers, directors, certain named individuals, principal shareholders and from documents filed with the SEC. Applicable percentages are based on 209,894,913 common shares outstanding on June 17, 2008, subject to adjustment for each beneficial owner as described above. To the knowledge of our Parent’s directors and executive officers, as of June 17, 2008, no person, firm or corporation own, directly or indirectly, or exercise control or direction over voting securities carrying more than 5% of the voting rights attached to any class of our Parent’s voting securities, except as indicated in the below.

 

Name and Address of Beneficial Owner (1)		Amount and Nature of Beneficial Ownership		Percent Common Shares Outstanding
Our greater than 5% shareholders:
Chesapeake Energy Corporation (2)		33,908,836		16.2	%
6100 North Western Avenue, Oklahoma City, OK 73118
Palo Alto Investors, LLC (2)		23,876,100		11.4	%
470 University Avenue, Palo Alto, CA 94301
Ospraie Management, LLC (2)		18,308,100		8.7	%
320 Park Avenue, 27th Floor, New York, NY 10022
GeoStar Corporation (3)		15,767,524		7.5	%
2480 W. Campus Drive, Building C, Mt. Pleasant, MI 48858
Parent Directors, who are not employees: (4)
Abby F. Badwi (5)		633,333		*
Robert D. Penner (6)		50,000		*
John M. Selser Sr. (7)		75,000		*
Parent named executive officers: (4)
J. Russell Porter, Chairman, President, Chief Executive Officer and Chief Operating Officer (8)		2,075,000		1.5	%
Michael A. Gerlich, Vice President and Chief Financial Officer (9)		587,500		*
Jeffery C. Pettit, Vice President, Chief Operating Officer		—		*
Directors and named executive officers, as a group (6 persons)		4,560,833		2.1	%

 

*	Less than 1%.

(1)	Unless otherwise indicated and subject to community property laws where applicable, management believes that all persons named in the following table have sole voting and investment power over all common shares reported as beneficially owned by them.

(2)	Consists of common shares owned directly.

 

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(3)	The number of common shares shown as beneficially owned by GeoStar is based on its most recent Form 13D filing with the SEC dated July 24, 2006. We have reasons to believe that GeoStar beneficially owns significantly less than 5% of our Parent’s outstanding common shares.

(4)	The contact address for our Parent’s directors and named executive officers is 1331 Lamar Street, Suite 1080, Houston, Texas 77010.

(5)	Consists of 633,333 common shares underlying stock options that currently are vested or will vest or be exercisable within 60 days of June 17, 2008 regardless of price.

(6)	Consists of 50,000 common shares underlying stock options that currently are vested or will vest or be exercisable within 60 days of June 17, 2008 regardless of price.

(7)	Consists of 75,000 common shares underlying stock options that currently are vested or will vest or be exercisable within 60 days of June 17, 2008 regardless of price.

(8)	Consists of 1,140,000 common shares owned directly and 2,075,000 common shares underlying stock options that currently are vested or will vest or be exercisable within 60 days of June 17, 2008 regardless of price.

(9)	Consists of 25,000 common shares owned directly and 562,500 common shares underlying stock options that currently are vested or will vest or be exercisable within 60 days of June 17, 2008 regardless of price.

 

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MANAGEMENT

Parent

Our Parent’s directors, executive officers, who are also referred to as “named executive officers,” and certain other significant employees and their ages as of June 17, 2008 are as follows:

 

Name		Age		Position
J. Russell Porter*		46		Chairman, President, Chief Executive Officer and Director
Michael A. Gerlich*		54		Vice President and Chief Financial Officer
Jeffery C. Pettit*		50		Vice President and Chief Operating Officer
Henry J. Hansen		52		Vice President of Land
Frederick E. Beck, PhD		48		Vice President of Drilling
R. David Rhodes		49		Vice President of Completion and Production
Sara-Lane Sirey		40		General Corporate Canadian Counsel and Corporate Secretary
Abby F. Badwi		61		Director
Robert D. Penner		64		Director
John M. Selser Sr.		49		Director

 

*	Named executive officer.

J. Russell Porter has been a member of our Parent’s Board of Directors and has served as our Parent’s President and Chief Executive Officer since February 2004 and was appointed Chairman of the Board in August 2006. From September 2000 to February 2004, he served as Chief Operating Officer and as an officer of GeoStar Corporation. Mr. Porter has an energy focused background, with approximately 17 years of natural gas and oil exploration and production experience and five years of banking and investment experience specializing in the energy sector. From April 1994 to September 2000, Mr. Porter served as an Executive Vice President of Forcenergy, Inc., a publicly traded exploration and production company, where he was responsible for the acquisition and financing of the majority of its assets across the United States and Australia. He currently is a director of Caza Oil & Gas, Inc., a publicly traded exploration and development company listed on the Toronto Stock Exchange and the London AIM exchange. Mr. Porter holds a Bachelor of Science degree in Petroleum Land Management from Louisiana State University and a MBA from the Kenan-Flagler School of Business at the University of North Carolina at Chapel Hill.

Michael A. Gerlich joined our Parent in May 2005, as Vice President and Chief Financial Officer. Mr. Gerlich has over 27 years of natural gas and oil accounting and finance experience. From 1994 until joining our Parent, Mr. Gerlich served as Senior Vice President – Accounting and Finance for Calpine Natural Gas L.P., formerly known as Sheridan Energy, Inc., where he served as Vice President and Chief Financial Officer. Over a 10-year period prior to joining Sheridan Energy, Mr. Gerlich held various accounting and finance positions with Trinity Resources, Ltd., with his last position being Executive Vice President and Chief Financial Officer. Mr. Gerlich was also with a Big Four accounting firm, where the focus of his practice was with energy related clients. Mr. Gerlich is a Certified Public Accountant and graduated with honors from Texas A&M University with a Bachelor of Business Administration degree in Accounting.

Jeffery C. Pettit joined our Parent in August 2007, as Vice President and Chief Operating Officer. Mr. Pettit has over 28 years of natural gas and oil operational experience. Prior to joining our Parent, Mr. Pettit was General Manager-Gulf Coast Operations and Engineering with Dominion E&P. He joined Dominion in 2001 and held positions as Joint Interest Manager and General Manager – Coalbed Methane. Previous to his service at Dominion, Mr. Pettit worked as a private engineering consultant for several independent oil and gas companies. During the twenty year period from 1979 until 1999, his employment included various operations, acquisitions, and reservoir engineering management positions with Burlington Resources, LL&E, Inexco Oil Company and Pennzoil. Mr. Pettit holds a Bachelor of Science degree in Petroleum Engineering from Mississippi State University.

Henry J. Hansen joined our Parent in September 2005, as Vice President of Land. Mr. Hansen has over 28 years of land management experience. Prior to joining our Parent, Mr. Hansen was Rocky Mountain Land Manager with El Paso Corporation from 1999 until January 2003. He returned to El Paso Corporation in June 2004, where he was senior landman until joining Gastar in September 2005. Mr. Hansen graduated from the University of Texas at Austin, Texas with a Bachelor of Business Administration in Petroleum Management.

 

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Frederick E. Beck, PhD joined our Parent in April 2002, as Vice President of Drilling. Dr. Beck has over 25 years of diversified experience in the natural gas and oil business. He has held positions with a major operator as a drilling engineer, drilling supervisor and as an assistant professor of petroleum engineering at the New Mexico School of Mines. From 1996 and prior to joining our Parent as Vice President of Operations, Dr. Beck was Vice President of the turnkey drilling division of Nabors Drilling USA LP. Dr. Beck holds a Bachelor of Science degree in Geology, Master of Science degree in Petroleum Engineering and Doctor of Philosophy Degree in Petroleum Engineering, all from Louisiana State University in Baton Rouge, Louisiana.

R. David Rhodes joined our Parent in March 2006, as Vice President of Completion and Production. Mr. Rhodes has over 25 years of petroleum engineering experience, focused primarily in the supervision and management of completion and production operations. Prior to joining our Parent, he managed Oil & Gas Operations and Consulting, Inc., an independent consulting firm he established in May 2001, where he worked as a petroleum engineering consultant for numerous natural gas and oil operators including our Parent. Mr. Rhodes continues to maintain his relationship with Oil & Gas Operations and Consulting, Inc. From 1981 to 2001, Mr. Rhodes held various engineering and management/supervisory positions at Getty Oil Company and Marathon Oil Company (formerly Texas Oil & Gas Company). His last position was Operations Manager for East Texas and Northern Louisiana. Mr. Rhodes holds a Bachelor of Science degree in Petroleum Engineering from Louisiana Tech University.

Sara-Lane Sirey, LLB is an attorney in private practice, who has served as the Corporate Secretary of our Parent and General Corporate Canadian Counsel since May 2000. From July 1993 to April 2001, she served as an attorney at the law firm of Armstrong Perkins Hudson LLP (formerly Ogilvie and Company) in Calgary, Alberta, Canada, becoming a partner in 1999. Specializing in corporate/securities law, she has acted for issuers, in all industry segments, in Canada, the United States and internationally, focusing on corporate reorganizations, commercial transactions and initial public offerings of junior emerging companies as well as equity and debt financings, mergers and acquisitions and commercial transactions of senior established companies. Ms. Sirey obtained her Bachelor of Laws degree at the University of Saskatchewan.

Abby F. Badwi has been a member of our Parent’s Board of Directors since February 2004. Mr. Badwi is an international energy executive with more than 30 years of experience in the exploration, development and production of natural gas and oil fields in North America, South America, Asia, Europe and the Middle East. He currently is Chief Executive and Director of Bankers Petroleum, a Canadian public exploration and production company listed on the TSX and London AIM Exchange with operations in Europe and the USA. From July 2005 to September 2007, he was President, Chief Executive Officer and director of Rally Energy Corp., a public Canadian natural gas and oil company listed on the TSX and the Frankfurt Stock Exchange with operations in Egypt, Pakistan and Canada. Prior to joining Rally Energy, he was the President of Corrundum Energy Ltd, a private natural gas and oil investment and advisory firm from 2003 until 2005. From 2000 until 2003, he was President and CEO of Geodyne Energy Inc., a natural gas and oil venture publicly traded on Canada’s TSX Venture Exchange. Mr. Badwi has been an officer of several Canadian public and private companies, including President and Chief Operating Officer of Carmanah Resources Ltd., a Calgary, Alberta-based company with oil holdings in Canada, Indonesia and Venezuela, and Vice President International Exploration of Sceptre Resources Limited, an natural gas and oil exploration and production company. He is currently a director of Sustainable Energy Technologies Ltd. and Fairmount Energy Inc., both listed on Canada’s TSX Venture Exchange. Mr. Badwi holds a Bachelor of Science degree in petroleum geology from the University of Alexandria, Egypt.

Robert D. Penner became a member of our Parent’s Board of Directors effective July 16, 2007. Mr. Penner retired from his position as a senior partner with KPMG in 2004, after a career of advising public and private clients on tax and accounting matters for almost 40 years. He currently serves on the Board of Directors for Corridor Resources Ltd, Storm Cat Energy Corporation, Sustainable Energy Technologies Ltd., Terra Energy Corp. and Unbridled Energy Corporation as well as serving on the Board of Directors or as Executor/Trustee for several private companies and family trusts.

John M. Selser Sr. became a member of our Parent’s Board of Directors effective March 30, 2007. He has been a partner at Maple Leaf Partners, a Baton Rouge, Louisiana based hedge fund since 2003. From 1992 to 2003, Mr. Selser was an energy equity analyst for several sell-side firms. From 1984 to 1991, Mr. Selser was a petroleum engineer for major oil companies in various domestic drilling, production and reservoir engineering assignments. Mr. Selser holds a Bachelor of Science in both Civil Engineering and Petroleum Engineering from Louisiana State University, Baton Rouge, Louisiana and a Masters of Business Administration from Tulane University, New Orleans, Louisiana.

 

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Each of our Parent’s directors holds office until the next annual meeting of shareholders or until the director resigns or is removed by actions of the board. Of our Parent’s directors, Messrs. Porter and Selser are citizens of the United States, while Messrs. Badwi and Penner are citizens of Canada. There are no family relationships between any of our Parent’s directors or executive officers.

Code of Ethics

Our Parent adopted a Code of Ethics on December 15, 2005. A copy of our Code of Ethics for all employees was filed as an exhibit to our Registration Statement on Form S-1/A on December 22, 2005 and is available on our website at www.gastar.com. A copy of our Parent’s Code of Ethics will be provided to any person without charge, upon request. Such requests should be directed to J. Russell Porter, President and Chief Executive Officer, 1331 Lamar Street, Suite 1080, Houston, Texas 77010.

Shareholders or other interested parties may send communications to the Board of Directors by writing through the Secretary of the Company at 1331 Lamar Street, Suite 1080, Houston, Texas 77010. The Secretary will forward to the directors all communications that, in his or her judgment, are appropriate for consideration by the directors. Comments or complaints relating to our accounting, internal accounting controls or auditing matters will also be referred to members of the Audit Committee. The Audit Committee has procedures for (a) receipt, retention and treatment of complaints received by us regarding accounting, internal accounting controls, or auditing matters and (b) the confidential, anonymous submission by our employees of concerns regarding questionable accounting or auditing matters. The “Whistleblower” procedure adopted by the Audit Committee is available on our website at www.gastar.com.

Audit Committee

Our Parent has a separately-designated standing Audit Committee, which currently is comprised of Messrs. Badwi, Penner (chairman) and Selser. After reviewing the qualifications of the current members of the Audit Committee, our Parent’s Board of Directors has determined that all current Audit Committee members are “independent”, as that concept is defined in Section 10A of the Exchange Act, and the applicable rules of the American Stock Exchange. Our Parent’s Board of Directors also determined that all current Audit Committee members are financially literate and that Mr. Penner is a “financial expert” under the applicable rules of the Exchange Act. In accordance with its Terms of Reference, the Audit Committee examines and reviews on behalf of the Board of Directors, internal financial controls, financial and accounting policies and practices, related party transactions and the form and content of financial reports and statements. The Audit Committee is responsible for the hiring, overseeing and terminating the independent accountants engaged to prepare any audit or issue any audit report, and the work of the external auditors. The Chief Financial Officer attends the meetings of the Audit Committee by invitation.

On March 15, 2007, our Parent notified the American Stock Exchange that we were not in compliance with the American Stock Exchange Company Guide Rule 121(B)(2)(a), which requires that each listed company must have, and certify that it has and will continue to have, an audit committee of at least three independent members. As a result of an independent member of our Audit Committee not standing for reelection at our 2006 annual meeting of shareholders, the Audit Committee was left with two independent members, one of whom remains designated as its “financial expert”. On July 16, 2007, our Parent announced that Mr. Robert D. Penner had been appointed a director and a member of the Audit Committee, bringing our Parent into compliance with the American Stock Exchange Company Guide Rule.

Notwithstanding our Parent’s temporary non-compliance with the American Stock Exchange rule regarding the number of independent directors serving on the Audit Committee, at all times since January 4, 2006, the date our Parent first became listed and subject to the reporting requirements of the Exchange Act, as amended, our Parent’s Audit Committee has consisted solely of directors meeting the independence requirements of the American Stock Exchange and Section 10A of the Exchange Act.

 

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The Compensation Committee

The compensation committee of our Parent’s Board of Directors, which we refer to as the Remuneration Committee, is currently comprised of Messrs. Badwi (Chairman), Crow, Penner and Selser.

None of our Parent’s executive officers serves as a member of the board of directors or compensation committee (or committee performing similar functions) of any other entity, one or more of whose executive officers serve on our Parent’s Board of Directors or Remuneration Committee.

Issuer

Issuer’s board of directors is comprised of a sole director, J. Russell Porter who is reelected annually. Members of Issuer’s board of directors receive no compensation for their board duties. Issuer’s executive officers are J. Russell Porter (President) and Michael A. Gerlich (Secretary and Treasurer).

 

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COMPENSATION DISCUSSION AND ANALYSIS

The following Compensation Discussion and Analysis explains the compensation objectives, philosophy and practices of our Parent, with respect to its Chief Executive Officer, Chief Financial Officer and Chief Operating Officer, who are referred to as named executive officers. These individuals are our Parent’s only executive officers. For purposes of this discussion, the terms “we,” “us”, “our” and “the Company” refer to our Parent, Gastar Exploration Ltd.

Compensation Philosophy

Our compensation programs for our named executive officers are designed to achieve the following objectives:

 

•

Attract and retain highly talented individuals who will engage in behavior essential to our success;

 

•

Motivate and reward employee performance that is critical to our success;

 

•

Align the interests of our named executive officers and our shareholders by motivating our named executive officers to increase shareholder value and rewarding them based on operational and financial success and when shareholder value increases; and

 

•

Balance annual cash payments and longer term equity compensation.

Our executive compensation is structured to achieve these goals through our mix of short-term cash payments and long-term equity compensation.

Elements of Executive Compensation and Rationale

There are three key elements to our compensation: base salary, annual cash bonus awards and stock-based compensation. We believe that a combination of these three elements balances rewards for current performance and longer term corporate objectives as measured, among other things, by operational successes, common share performance and creation of shareholder value. The terms of the named executive officers’ employment, including their compensation and other benefits, are set forth in employment agreements, described below.

Role of the Remuneration Committee, its Consultant and Management

Executive compensation is the responsibility of the Remuneration Committee (for purposes of this analysis, the “Committee”). The Committee operates under a written charter, or the “Terms of Reference”, adopted by the Board of Directors. Abby F. Badwi, Robert D. Penner and John M. Selser Sr. are members of the Board of Directors and members of the Committee. Mr. Badwi is the Committee Chairman. Each member of the Committee qualifies as an independent director under the American Stock Exchange listing standards and under the Exchange Act.

The aim of the Committee is to award and compensate officers and employees in a manner which provides incentives for the enhancement of shareholder value, for the successful implementation of the Company’s business plan and for continuous improvement in corporate and personal performance. The compensation program is based on a pay-for-performance philosophy.

The Committee reviews and recommends the compensation philosophy and guidelines for the Company, which include reviewing the compensation philosophy and guidelines (a) for executive management, for recommendation to the Board for its consideration and approval, and (b) relating to all employees, including annual salary and incentive policies and programs, and material new benefit programs or material changes to existing benefit programs.

During 2007, the Committee engaged Thomas J. Reno & Associates, Inc. (“TJR”), a consulting firm experienced in executive compensation, which has access to national compensation surveys and our compensation information. TJR’s responsibilities include”

 

•

Providing recommendations on compensation based on review of the compensation of our peer group (as described below);

 

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•

Gathering and analyzing publicly available proxy data from the peer group and other peer group data;

 

•

Analyzing pay survey data and analyses provided by our management;

 

•

Reviewing and advising on the performance measures to be used in bonus formulas and equity awards; and

 

•

Reviewing and advising on target bonus levels, actual year end bonus calculations and the design and size of equity awards.

These peer companies reviewed by TJR included Abraxas Petroleum Corp., Exploration Company of Delaware, Gasco Energy Inc., GMX Resources Inc., Harvest Natural resources Inc., NGAS Resources Inc., Toreador Resources Corp., Transmeridian Exploration Inc. and Warren Resources Inc. TJR reviewed the amount or form of executive and director compensation, as well as periodic detailed analyses of peer group executive salaries, cash bonus awards and other incentive compensation bonus awards and other incentive compensation awards, such as stock options and restricted common stock grants. This information is used by the Committee to insure that base salaries and other benefits are reasonable and competitive with those offered by our peer group to their executives.

Our Chief Executive Officer also plays an important role in the executive compensation process and is closely involved in assessing the performance of our named executive officers and making recommendations regarding base salary, bonus targets, performance measures and weighting and equity compensation for these executive officers. The compensation of our Chief Financial Officer and Chief Operating Officer is determined by the Committee, after receiving the recommendations of the Chief Executive Officer as to what he considers to be fair compensation for our named executive officers. The recommendations are based on an assessment of the Chief Financial Officer’s and Chief Operating Officer’s responsibilities and performance, the Company’s performance and the market in which the Company competes for executive talent. The Chief Executive Officer attends those portions of the meetings of the Committee that are related to the Chief Financial Officer’s and Chief Operating Officer’s compensation. The compensation of our Chief Executive Officer is determined by the Committee. In determining the compensation of the Chief Executive Officer, the Committee takes into account the Chief Executive Officer’s responsibilities and performance, the Company’s performance and the market in which the Company competes for executive talent. The Chief Executive Officer does not attend any meetings related to his compensation.

Our Chief Financial Officer also plays an important role in our executive compensation process. Our Chief Financial Officer makes recommendations to the Committee regarding the structure of the annual cash bonus awards program and the size of such awards. These recommendations are drawn from our Chief Financial Officer’s previous work experience and informal surveys of the annual cash bonus programs of other similar sized companies and other oil and natural gas companies.

Benchmarking of Compensation

When making compensation decisions, we also look to the compensation of our named executive officers relative to the compensation paid to similarly-situated executives at other organizations that are similar in size and operations to us. During 2007, TJR provided us with competitive compensation data from our peer group as well as business and technical considerations. In 2007, we used three primary resources to identify competitive compensation relevant to our named executive officers:

 

•

TJR;

 

•

2007 U.S. Energy Compensation Survey; and

 

•

SEC disclosure data for similarly sized organizations within the natural gas and oil industry.

Third-party survey data, such as that provided by TJR and information from other resources and industry contacts, is considered when evaluating external competitiveness. We use this data to ensure that we are maintaining a level of compensation that is both commensurate with our size and sufficient to retain personnel we consider essential. In reviewing comparative data, we do not engage in benchmarking for the purpose of establishing compensation levels relative to any predetermined point. In the Committee’s view, third-party survey data provides insight into external competitiveness but is not an appropriate single basis for establishing

 

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compensation levels. This is primarily due to the differences in the size of comparable companies and the lack of sufficient appropriate matches to provide statistical relevance. Our preference is that performance, rather than third party survey data, should drive executive compensation. The Committee seeks the input of our Chief Executive Officer in evaluating the performance of all of our executive officers, excluding himself. Our Chief Financial Officer assists in the gathering of information regarding the employment market assessment.

In the processes used by the Committee to establish and adjust executive compensation levels, third party-survey data is considered, along with performance, experience and the potential of the individual to contribute to the Company’s operations and growth. The Committee can exercise both positive and negative discretion in relation to the compensation awards and its allocation between cash and non-cash awards. The Committee has the authority to approve, deny and suggest alternative compensation packages.

Elements of Executive Compensation and Rationale

The Company entered into employment agreements with J. Russell Porter, our President and Chief Executive Officer, and Michael A. Gerlich, our Chief Financial Officer, effective February 24, 2005 and May 17, 2005, respectively. The agreements with Messrs. Porter and Gerlich set forth, among other things, annual compensation, and adjustments thereto, minimum bonus payments, termination provisions, fringe benefits, termination and severance provisions. The agreements automatically renew annually; however, they may be terminated at any time with or without cause. The Company and Jeffery C. Pettit, our Chief Operating Officer, entered into a letter agreement on August 21, 2008. The letter agreement sets forth, among other things, Mr. Pettit’s initial base salary, a guaranteed 2007 bonus, fringe benefits, such as vacation and medical insurance coverage, and severance provisions for his at will employment, which may be terminated at any time by us or Mr. Pettit with or without cause. See “Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table” for additional information on employment agreement to the named executive officers.

Base Salary. Base salary represents the fixed element of the named executive officers’ cash compensation. The base salary reflects economic consideration for each individual’s level of responsibility, expertise, skills, knowledge, experience and performance. Base salaries for our named executive officers are reviewed annually. Each of our named executive officer’s initial annual salary is set for the terms of their respective employment agreement but may be adjusted upward or downward at each anniversary date of each officer’s employment at the discretion of the Committee. The base salary amounts for Messrs. Porter and Gerlich have been set at $450,000 and $275,000 respectively. Mr. Pettit’s letter agreement with us set his initial base salary at $285,000. A description of the material terms of each named executive officer’s employment agreement is provided in “Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table — Employment Agreements”.

In 2007, the Committee made no changes to the base salary amounts for any of our named executive officers, based on the Committee’s determination that the existing base salaries were competitive and appropriate in light of the named executive officers’ tenure with the Company and the overall level of corporate activity.

Annual Cash Bonus Awards. Our cash bonus awards reflect our philosophy to pay for performance. These awards provide our named executive officers, as well as our other employees on the same basis, with an opportunity to earn an annual cash bonus based on an evaluation of individual performance and the Company achieving certain operational and financial performance targets. At the beginning of each year, the Committee approves a target cash bonus pool, which equals the sum of a bonus target percentages of each employee times each employee’s annual salary. The targeted bonus percentages for named executive officers was determined using the experiences of the members of the Committee, the review of cash bonus awards of named executive officers with other companies, many of which have substantially more resources to evaluate such matters, and on informal surveys with other companies. At the end of each year, the Company’s performance is evaluated against certain specific operational and financial target criteria. Each criterion is given a certain weighting, with a majority of the weighting allocated to operational factors. In developing the appropriate target criteria and their respective weightings, the Committee analyses the relative importance of each of the target criteria to our business strategy for the upcoming fiscal year. Criteria and weightings used in 2007 were:

 

•

Achieving a target average annual production per day for the year (20%);

 

•

Achieving a target total Company proved reserves (20%);

 

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•

Achieving specific Texas average (per Mcfe) finding and development costs and controllable lifting costs (20%);

 

•

Achieving specific overall per Mcfe average cash general and administrative expense (5%);

 

•

Achieving specific level of operating cash flow (25%); and

 

•

Accomplishing certain financing goals during the year (10%).

Performance above or below the targeted criteria results in a calculated increase or decrease in the cash bonus pool. Certain minimum targets are also established for the individual criteria which, if not met, results in no bonus being earned for that criterion. At the end of the year, an approved bonus pool is calculated based on the bonus pool criteria accomplishments. The amount of the calculated bonus pool is subject to adjustment and final approval by the Committee. As a result of our 2007 operational and financial performance, we surpassed all of the performance targets except one operational criterion. This would have resulted in a calculated bonus pool of an amount equal to 250% of the target cash bonus pool. In its discretion, the Committee reduced the calculated bonus pool to an amount equal to 150% of the target cash bonus pool.

For 2007, the Committee determined that Mr. Porter’s target cash bonus would be 50% of his annual compensation based on the reasons described above. As a result of our operational and financial performance, he was awarded a cash bonus of $337,500, or 75% of his base salary in 2007, which is equal to 150% of his target bonus. He received an amount based on the same formula applicable to all employees of 1.5 times targeted cash bonus. His 2007 bonus reflected his leadership in raising significant debt and equity capital to finance our expanded exploration activities in East Texas and Australia, as well as the Company meeting and exceeding the operational and financial targets described above.

For 2007, the Committee determined that Mr. Gerlich’s target cash bonus would be 35% of his annual compensation based on the reasons described above. As a result of our operational and financial performance, he was awarded a cash bonus of $145,000, or 53% of his base salary in 2007, which is equal to 150% of his target bonus. He received an amount based on the same formula applicable to all employees of 1.5 times targeted cash bonus. His 2007 bonus recognized his financial skills used to successfully raise significant debt and equity capital to finance our expanded exploration activities in East Texas and Australia, providing the leadership in the successful completion of the Sarbanes Oxley compliance process, including IT compliance, as well as the Company meeting and exceeding the operational and financial targets described above.

For 2007, the Committee determined that Mr. Pettit’s target cash bonus would be 25% of his annual compensation based on the reasons described above. In 2007, he was awarded a cash bonus of $40,000, or 38% of his base salary, pro rated for the period he was employed by us during the year. He received an amount based on the same formula applicable to all employees of 150% of targeted cash bonus. His 2007 bonus recognized his contribution to the overall improvement in operational activities since becoming our Chief Operating Officer, as well as the Company meeting and exceeding the operational and financial targets described above.

In 2007, a significant factor in determining the 150% of multiplier to calculate the level of cash bonus awards was the Company’s substantially improved exploration and operational results, as compared to those of 2006, and the substantial increase in year end proved reserves.

Cash Retention Payment Award. The Company is involved in a number of litigation matters, where an adverse ruling could have a material adverse effect on us. Retention of our named executive officers and all other employees has become a meaningful consideration in our overall compensation package. As a result of the uncertainties created by this situation, the Board of Directors at the Committee’s recommendation approved cash retention payment awards for the named executive officers, as well as all other employees. Each named executive officer and other current employees of the Company who are still employed by the Company on January 31, 2009 will receive a cash retention payment equal to their target bonus. The cash incentive bonus awards for Messrs. Porter, Gerlich and Pettit are calculated to be $225,000, $96,250 and $71,250.

Stock-based Compensation. We believe that equity compensation is the most effective means of linking compensation provided to our named executive officers with long-term operational success and increases in

 

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shareholders’ value. The Board of Directors has discretionary authority to determine granting and vesting periods of stock option and restricted common share grants. We use stock-based compensation as a long-term vehicle because we believe:

 

•

Stock-based compensation align the interests of named executive officers and our other employees with those of the shareholders;

 

•

The vesting period incorporated into stock-based compensation fosters a longer term perspective necessary for staff retention, stability and continuity; and

 

•

Stock-based compensation helps to provide a longer term balance to our overall compensation program.

Historically, we used stock options as the equity compensation vehicle. In mid-2007, we began using grants of restricted common shares to employees as a compensation vehicle, rather than stock options. This change occurred in response to the Committee’s judgment that to retain and attract qualified employees we needed a more definable deferred monetary incentive than was being provided by stock option grants. Currently, restricted common shares are granted to new hires at the time of employment and to all others, including our named executive officers, in the first half of the year, as determined by the Committee. The 2007 grants of restricted common shares vest one-third on the second, third and fourth anniversaries of the grant. This vesting schedule was based on the Chief Executive Officer’s belief that a vesting schedule that delayed the initial vesting of shares until the second anniversary of the grant provides more incentive for retention of employees than might be provided by a shorter initial vesting period.

Although we do not anticipate using stock option grants for employees in the future, we have utilized stock option grants as the equity compensation vehicle for our directors, although this may change in the future.

In July 2007, Messrs. Porter and Gerlich received a restricted common share grant for an aggregate of 225,000 and 137,500 of our restricted common shares, respectively. The restricted common shares granted to Messrs. Porter and Gerlich were part of a larger annual grant of restricted common shares to employees designed to retain and provide additional employee incentives.

The number of restricted common shares is calculated by multiplying 50% times the employee’s base salary. For 2007, TJR recommended that the target bonus percentage be 100% of base salary based on their review of the compensation practices of our peer companies. The Committee determined that the target bonus percentage for 2007 would be 50% of each employee’s base salary. In making this determination, the committee also considered other factors, such as Mr. Porter’s leadership and his success during the year in raising significant debt and equity capital to finance our expanded exploration activities in East Texas and Australia, Mr. Gerlich’s contribution during the year in raising significant equity capital to finance our expanded exploration activities in East Texas and Australia and the Company’s successful completion and compliance with the Sarbanes Oxley Act, and Mr. Pettit’s guidance in the overall improvement in our operational activities.

Mr. Pettit joined us as Chief Operating Officer in August 21, 2007. As a part of his employment package, Mr. Pettit received a restricted common share grant for an aggregate of 112,500 restricted common shares.

Perquisites. The named executive officers are eligible to participate in the same comprehensive benefits as are offered to all full-time employees. Additionally, Mr. Porter’s employment agreement provides that we will pay or reimburse him up to $25,000 for his membership dues in clubs and/or organizations as are reasonable and customary for a senior executive officer and will reimburse him for the cost of a yearly executive physical examination and all required or recommended medical testing in connection with that yearly examination. During 2007, we paid, or reimbursed, Mr. Porter a total of $73,138. See footnote 3 to “Summary Compensation Table” for details of payment of perquisites to Mr. Porter in 2007.

During 2007, other than the comprehensive benefits offered to all full-time employees, neither Mr. Gerlich nor Mr. Pettit received any perquisites having a value over $10,000 in aggregate.

 

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Post Termination or Change of Control Compensation and Benefits

On March 23, 2007, our Board of Directors approved a change of control severance plan, as amended February 15, 2008, covering all employees, including the named executive officers. The purpose of the severance plan is to promote stability and continuity of management and employees in the event a change of control transaction should occur. Pursuant to the terms of their respective employment agreements and the provisions of our change of control severance plan, Messrs. Porter, Gerlich and Pettit are entitled to receive certain post termination compensation and benefits. These benefits were determined in the negotiations with each individual and were based on what the Board of Directors determined were elements of a competitive compensation arrangement at the time or as set forth in the Employee Change of Control Severance Plan. See “Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table” and “Potential Payments upon Termination or Change of Control” below.

 

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EXECUTIVE COMPENSATION

Summary Compensation and Awards

The following table and discussion below sets forth information about the compensation awarded to, earned by or paid to our named executive officers during the years ended December 31, 2007 and 2006.

Summary Compensation Table

 

Name and Principal Position		Year		Salary			Bonus			Option Awards (1)			Restricted Common Shares (2)			All Other Compensation (3)			Total
Russell Porter		2007		$	450,000		$	337,500		$	770,030		$	89,152		$	73,138		$	1,719,820
Chairman, President and Chief Executive Officer		2006		$	450,000		$	225,000		$	944,655		$	—		$	95,892		$	1,715,547
Michael A. Gerlich		2007		$	275,000		$	145,000		$	441,507		$	54,482		$	—		$	915,989
Vice President and Chief Financial Officer		2006		$	275,000		$	96,000		$	583,221		$	—		$	—		$	954,221
Jeffery C. Pettit (4)		2007		$	104,865		$	40,000		$	—		$	22,558		$	—		$	167,423
Vice President and Chief Operating Officer

 

(1)

The fair values of stock option awards are determined by using the Black-Scholes-Merton valuation model as of the date of grant, as set forth in SFAS 123R. See Note 8 – Equity Compensation Plans – Determining Fair Value under SFAS 123R to our consolidated financial statements, which begins on Page F-1, for a discussion of assumptions made in the valuation of option awards. The fair value at the date of grant is amortized using the “graded-vesting method”, which recognizes compensation costs over the requisite service period for each separately vesting tranche of an award as though the award were, in substance, multiple awards. The amounts shown in these column represent the stock-based compensation expense for the years ended December 31, 2007 and 2006, prior to a 5.0% deduction for estimated forfeitures, attributable to stock options and restricted common share grants that was attributable to all stock options and restricted common shares granted to the named executive officer and outstanding during each respective year that is recognized by us in that respective year. During 2007, total fair value attributable to restricted common share grants to Messrs. Porter, Gerlich and Pettit as of the date of grant was $495,000, $203,500 and $187,875, respectively. During 2006, total fair value attributable to stock options granted to Messrs. Porter and Mr. Gerlich as of the date of grant was $1,677,646 and $1,035,262, respectively.

(2)

Grant date fair value of restricted common share awards is equal to the closing price of our common shares on the day prior to the date of grant times the number of common shares granted. This fair value is used to determine the stock-based compensation expense, as shown in our consolidated financial statements. The amounts shown in these column represent the stock-based compensation expense for the year ended December 31, 2007 prior to a 5.0% deduction for estimated forfeitures, attributable to restricted common share grants that was attributable to all restricted common shares granted to the named executive officer and outstanding during each respective year that is recognized by us in that respective year. During 2007, total fair value attributable to restricted common share grants to Messrs. Porter, Gerlich and Pettit as of the date of grant was $281,250, $171,875 and $140,625, respectively.

(3)

Of the $73,138 shown for Mr. Porter in 2007, $16,610 related to the rental and related utility costs for an apartment in Houston, Texas; $10,800 related to the rental of an office in Miami, Florida (our Chief Executive Officer’s city of residence); $13,569 related to the use of a rental car while in Houston; $18,821 related to airfare between Houston and Miami, $9,000 related to the Company’s contribution to Mr. Porter’s 401-K plan and the balance of $4,338 was for club dues. Each of the items was incurred by or on behalf of Mr. Porter in the ordinary course of business or for his convenience and was considered a reasonable perquisite for a senior executive officer.

Of the $95,892 shown for Mr. Porter during 2006, $19,962 related to the rental and related utility costs for an apartment in Houston, Texas; $41,264 related to the rental of an office in Miami, Florida (our Chief Executive Officer’s city of residence); and $13,274 related to the use of a rental car while in Houston. The balance of $21,392 was related to airfare between Houston and Miami, club dues, an executive health physical examination and the Company’s contribution to Mr. Porter’s 401-K plan. Each of the items was incurred by or on behalf of Mr. Porter in the ordinary course of business or for his convenience and was considered reasonable and customary perquisites for a senior executive officer.

As permitted by the rules promulgated by the SEC, no amounts are shown for Messrs. Gerlich and Pettit with respect to all other compensation received in 2007 and 2006, as the total value of all perquisites and personal benefits during the year was less than $10,000 per year.

 

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(4)	Mr. Pettit commenced his employment with us on August 21, 2007.

The following table shows certain information about the number of restricted common shares granted to our named executive officers during the year ended December 31, 2007. There were no stock option grants to named executive officers in 2007.

Grants of Plan-Based Awards Table

For the Year Ended December 31, 2007

 

Name		Grant Date		Number of Restricted Shares of Stock		Number of Securities Underlying Options		Exercise or Base Price of Awards			Grant Date Fair Value of Awards (1)
J. Russell Porter (2)		07/03/07		225,000		—		$	2.20		$	495,000
Michael A. Gerlich (2)		07/03/07		137,500		—		$	2.20		$	302,500
Jeffery C. Pettit (3)		08/27/07		112,500		—		$	1.67		$	187,875

 

(1)

Grant date fair value of restricted common share awards is equal to the closing price of our common shares on the day prior to the date of grant times the number of common shares granted. This fair value is used to determine the compensation expense, as shown in our consolidated financial statements.

(2)	The 07/03/07 grant of restricted common shares to Messrs. Porter and Gerlich vest 33.3% on 07/03/09, 07/03/10 and 07/03/11.

(3)	The 08/27/07 grant of restricted common shares to Mr. Pettit vest 33.3% on 08/27/09, 08/27/10 and 08/27/11.

Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table

The following is a narrative of our various compensation plans and the general terms of each:

2002 Stock Option Plan. The Company’s 2002 Stock Option Plan was approved and ratified by the Company’s shareholders in July 2002. It authorizes the Company’s Board of Directors to issue stock options to directors, officers, employees and consultants of the Company and its subsidiaries to purchase a maximum of 25.0 million common shares. Stock option grant expirations vary between five and 10 years. The vesting schedule has varied from two years to four years but generally has occurred over a four-year period at 25% per year beginning on the first anniversary date of the grant. Stock options issued pursuant to the Company’s 2002 Stock Option Plan have an exercise price determined by the Board of Directors, but that exercise price cannot be less than the market price on the date immediately prior to the date of grant as reported by any stock exchange on which the Company’s common shares are listed. If a stock option granted under the Company’s 2002 Stock Option Plan expires or terminates for any reason in accordance with the terms of the Company’s Stock Option Plan, the unpurchased common shares subject to that stock option become available for other stock option grants.

In April 2004, the Board of Directors amended the provisions of the Company’s 2002 Stock Option Plan to specifically incorporate a provision to provide for stock options to be exercised on a cashless basis, whereby the Company issues to the optionee the number of common shares equal to the stock option exercised, less the number of common shares which when multiplied by the market price at the date of exercise equals the aggregate exercise price for all of the common shares exercised. As of December 31, 2007, stock option grants covering the issuance of 10,173,750 common shares were outstanding under the 2002 Stock Option Plan.

2006 Gastar Long-Term Stock Incentive Plan. On June 1, 2006, the Company’s shareholders approved the 2006 Gastar Long-Term Stock Incentive Plan. The 2006 Gastar Long-Term Stock Incentive Plan authorizes the Company’s Board of Directors to issue stock options, stock appreciation rights, bonus stock awards and any other type of award established by the Committee which is consistent with the Plan’s purposes to directors, officers and employees of the Company and its subsidiaries covering a maximum of 5.0 million common shares. The contractual life and vesting period for a grant will be determined by the Board of Directors at the time grant is awarded. The vesting period for restricted common stock grants during 2007 was over four years, with one-third vesting on the second, third and fourth anniversaries of the date of grant. As of December 31, 2007, only grants covering the issuance of 1,096,000 restricted common shares were outstanding under the 2006 Gastar Long-Term Stock Incentive Plan.

 

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All stock options incorporate the following features:

 

•

Existing grants have a term of five or 10 years;

 

•

Grant price is not less than the closing market price on the date immediately prior to the date of grant;

 

•

Grants do not include “reload” provisions;

 

•

Repricing of options is prohibited, unless approved by the shareholders; and

 

•

Stock options vest over a period of time that is determined by the Board of Directors.

In 2006 and a portion of 2007, stock options were granted to new hires at the time of employment and to all other employees, including our named executive officers, around the time of our annual meeting of shareholders. The Board of Directors has discretionary authority to determine granting and vesting periods of stock options. Typically, vesting periods have been over a four-year period with 25% vesting on the first, second, third and fourth anniversary dates. Certain stock options granted in 2006 to our Chief Executive Officer and certain technical managers vest over two years. Other stock options granted on the same date to the Chief Financial Officer and other employees vest over three years. The stock option awards having shorter vesting periods were granted to provide additional shorter term incentive to our named executive officers, certain technical and other employees.

Pursuant to our incentive plans, the Board of Directors has designated the Remuneration Committee as the entity to administer the granting of stock options, restricted common stock grants and other forms of stock-based compensation. Grants are determined by the Committee, based on the recommendations of our Chief Executive Officer, except in the case of grants awarded to the Chief Executive Officer. In determining a grant to named executive officers, the Committee has taken into account the named executive officer’s position, the scope of his responsibilities, his ability to affect profits and shareholder value and the individual’s past and current individual performance and corporate performance.

Employee Change of Control Severance Plan. A change of control is defined in the severance plan to mean (1) the consummation of a merger, consolidation, reorganization or other transaction whereby our shareholders retain less than 50% control, directly or indirectly, of us or the surviving company, (2) our incumbent directors cease to constitute a majority of the board of directors or (3) a sale or other disposition of all or substantially all of our assets. The change of control severance plan does not change the specific, non-change of control severance payments in place under the existing employment agreements with our named executive officers but does provide change of control severance benefits to the named executive officers only if they are greater than the severance benefits provided under the employment agreement. The change of control severance plan does not allow for any duplication of severance benefits.

For the named executive officers, the change of control severance plan provides that if a named executive officer’s employment is terminated within two years following a change of control for any reason other than (i) death, (ii) disability, (iii) by us for “cause” or (iv) by the named executive officer for other than a “good reason”, the named executive officer will receive a lump-sum payment equal to a multiple that is equal to the applicable severance period, as set forth in the change of control severance plan, times the sum of (1) his annual salary and (2) annual target bonus.

The following summarizes the severance periods and target bonus percentages for the named executive officers set forth in the change of control severance plan:

 

		Severance Period in Years		Target Bonus Percentage
Chief Executive Officer		3.00		50	%
Chief Financial Officer		2.50		35	%
Vice President (Chief Operating Officer)		2.00		25	%

 

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Additionally, during the applicable severance period, named executive officers would receive reimbursement for the cost of COBRA continuation health care coverage, less the amount charged at the time of termination to the employee for their medical coverage.

If the named executive officer receives a payment or benefit that is subject to the “golden parachute” excise tax, the named executive officer will receive an additional payment under the severance plan to make him or her “whole” for that excise tax and any taxes on the additional parachute tax gross-up payment.

If the individual’s employment is terminated within six months prior to a change of control and it is reasonably shown to have been in connection with the change of control, then the change of control will be treated with respect to that employee as having occurred prior to his or her termination.

Employment Agreements. We entered into employment agreements with J. Russell Porter, our President and Chief Executive Officer; and Michael A. Gerlich, our Chief Financial Officer, effective February 24, 2005 and May 17, 2005, respectively. The agreements with Messrs. Porter and Gerlich set forth, among other things, annual compensation, and adjustments thereto, minimum bonus payments, fringe benefits, termination and severance provisions. The agreements renew annually; however, they may be terminated at any time with or without cause. Jeffery C. Pettit, our Chief Operating Officer, entered into an employment letter agreement on August 21, 2008. The letter agreement sets forth, among other things, Mr. Pettit’s initial base salary, a guaranteed 2007 bonus, fringe benefits and severance provisions for Mr. Pettit’s, which may be terminated at any time by us or Mr. Pettit with or without cause.

Mr. Porter’s employment agreement provides that he is entitled to an annual bonus in an amount that may take the form of cash compensation, the award of stock or stock options, royalty rights or otherwise and that he shall receive an annual cash bonus equal to at least 20% of his annual base salary. The employment agreement further provides that the bonuses shall reflect not only the results of the Company’s operations and business, but his contribution as President and Chief Executive Officer.

Mr. Porter’s employment agreement also provides that his employment shall terminate (i) without notice upon his death; (ii) without notice upon his “Disability”, as defined in his employment agreement; (iii) upon six month’s written notice to us by Mr. Porter for any or no reason, with or without cause; (iv) upon one year’s written notice to Mr. Porter by us for any or no reason, with or without cause; or (v) by us without prior notice upon a showing of “Reasonable Cause”, as defined in his employment agreement. If he is terminated by us for any reason other than cause, he will receive severance pay of two years total compensation. The severance payment will consist of the payment of Porter’s W-2 compensation earned in the calendar year coincident with or immediately preceding Porter’s termination of employment, payable over the appropriate number of weeks after termination of employment (the “Severance Pay Period”) and continuation of health insurance for Mr. Porter and his family at our expense during the Severance Pay Period. If Mr. Porter dies during the Severance Pay Period, severance pay and health benefits will continue for the benefit of his eligible beneficiary during the remainder of the Severance Pay Period.

Mr. Gerlich’s employment agreement provides that the Committee may on a yearly basis, or more frequently, award Mr. Gerlich a discretionary bonus or bonuses based not only on the positive results of our operations and business, but Mr. Gerlich’s contribution as Chief Financial Officer. Such bonuses may take the form of cash compensation, the award of stock or stock options, royalty rights or otherwise. Mr. Gerlich’s employment agreement also provides that his employment shall terminate (i) without notice, upon his death; (ii) without notice, upon his “Disability”, as defined in his employment agreement; (iii) upon two month’s written notice to us by Mr. Gerlich for any or no reason, with or without cause; (iv) if there is a “change of control”, as defined in his employment agreement and that “change in control” results in a material change in the scope of Mr. Gerlich’s duties and responsibilities such that he terminates his employment; (v) upon two month’s written notice to Mr. Gerlich by us for any or no reason, with or without cause and (vi) or by us without prior notice, upon a showing of “Reasonable Cause”, as defined in his employment agreement. If he is terminated by us for any reason other than cause, he will receive severance pay of two years annual gross salary, exclusive of bonuses received, stock options granted or exercised, or other non cash compensation. The severance payment will be calculated on the basis of his then current annual salary, to be earned in Mr. Gerlich’s then current employment year coincident with or immediately preceding the notice of termination of employment, payable in equal amounts over 100 weeks (the “Severance Pay Period”). There will be continuation of health insurance for Mr. Gerlich and his family at our expense during the Severance Pay Period. If Mr. Gerlich dies during the Severance Pay Period, severance pay and health benefits will continue for the benefit of his eligible beneficiary during the remainder of the Severance Pay Period.

 

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Mr. Pettit’s employment agreement provides that he or us may terminate his employment and any time, with or without cause. If he is terminated by us for cause (as defined in his employment agreement), he will not be eligible for severance or other compensation; except for, accrued annual salary to the date of termination. If he is terminated by us without cause during his first two years, he will receive 1.0 times his annual salary plus stock options or restricted common shares vested prior to the date of termination. If he is terminated by us without cause after his second year of employment, he will receive 1.5 times his annual salary plus stock options or restricted common shares vested prior to the date of termination. Any severance or other compensation shall be paid over the termination period. We may terminate Mr. Pettit’s employment if a disability results in Mr. Pettit being unable to work for more than 90 days; provided, however, this will not apply to injury occurring while performing job duties.

Salary and Cash Bonus in Proportion to Total Compensation

The following table sets forth the percentage of each named officer’s total compensation that we paid in the form of base salary and cash bonus for the year 2007.

 

		Percentage of Total Compensation
J. Russell Porter		46	%
Michael A. Gerlich		46	%
Jeffery C. Pettit		87	%

Outstanding Equity Awards at Fiscal Year-End Table

 

Name		Number of Securities Underlying Unexercised Options Exercisable		Number of Securities Underlying Unexercised Options Unexercisable		Option Exercise Price			Option Expiration Date		Number of Shares of Restricted Stock That Have Not Vested		Market Value of Shares of Restricted Stock That Have Not Vested (1)
J. Russell Porter (2)		750,000		250,000		$	3.48		08/04/09		—			—
		37,500		112,500		$	4.89		04/05/16		—			—
		500,000		500,000		$	2.32		07/14/16		—			—
		—		—			—		—		225,000		$	281,250
Michael A. Gerlich (3)		125,000		125,000		$	3.57		06/24/10		—			—
		62,500		187,500		$	5.11		01/16/16		—			—
		25,000		75,000		$	4.89		04/05/16		—			—
		100,000		200,000		$	2.32		07/14/16		—			—
		—		—			—		—		137,500		$	171,875
Jeffery C. Pettit (4)		—		—			—		—		112,500		$	140,625

 

(1)	The closing price of our common share on December 31, 2007 was $1.25.

(2)

The 250,000 unexercisable stock options granted to Mr. Porter that expire on 08/04/09 (grant date of 08/04/04) vest 100% on 08/04/08. The exercise price was denominated at CDN$3.41. At the exchange rate on 12/31/07, this exercise price equates to $3.48. The 112,500 unexercisable stock options granted to Mr. Porter that expire on 04/05/16 (grant date of 04/05/06) vest 33.3% on 04/05/08, 04/05/09 and 04/05/10. The exercise price was denominated at CDN$4.80. At the exchange rate on 12/31/07, this exercise price equates to $4.89. The 500,000 unexercisable stock options granted to Mr. Porter that expire on 07/14/16 (grant date of 07/14/06) vest 50% on 07/14/08 and 07/14/09. The exercise price was denominated in United States dollars at $2.32. The 225,000 restricted common shares granted to Mr. Porter on 07/03/07 vest 33.3% on 07/03/09, 07/03/10 and 07/03/11.

(3)

The 125,000 unexercisable stock options granted to Mr. Gerlich that expire on 06/24/10 (grant date of 06/24/05) vest 50% on 06/24/08 and 06/24/09. The exercise price was denominated at CDN$3.50. At the exchange rate on 12/31/07, this exercise price equates to $3.57. The 187,500 unexercisable stock options granted to Mr. Gerlich that expire on 01/16/16 (grant date of 01/16/06) vested 33.3% on 01/16/08, 06/16/09 and 06/16/10. The exercise price was denominated at

 

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CDN$5.01. At the exchange rate on 12/31/07, this exercise price equates to $5.11. The 75,000 unexercisable stock options granted to Mr. Gerlich that expire on 04/05/16 (grant date of 04/05/06) vest 33.3% on 04/04/08, 04/04/9 and 04/04/10. The exercise price was denominated at CDN$4.80. At the exchange rate on 12/31/07, this exercise price equates to $4.89. The 200,000 unexercisable stock options granted to Mr. Gerlich that expire on 07/14/16 (grant date of 7/14/06) vest 50% on 07/14/08 and 07/14/09. The exercise price was denominated in United States dollars at $2.32. The 137,500 restricted common shares granted to Mr. Gerlich on 07/03/07 vest 33.3% on 07/03/09, 07/03/10 and 07/03/11.

(4)	Mr. Pettit joined us as our Chief Operating Officer on August 27, 2007. He was granted 112,500 restricted common shares as a condition of his employment that vest 33.3% on 08/27 2009, 08/27/10 and 08/27/11.

Option Exercises and Stock Vested

During the year ended December 31, 2007, no restricted common shares that were granted to the named executive officers vested, and no stock options were exercised by the named executive officers. The named executive officers have no other outstanding stock awards other than those shown above.

Potential Payments Upon Termination or Change of Control

The table below discloses the amount of compensation and/or other benefits due to the named executive officers in the event of their termination of employment, including, but not limited to, in connection with a change in control. The amounts shown assume that such termination was effective as of December 31, 2007, and thus include amounts earned through such date and are estimates of the amounts which would be paid to the named executive officers upon their respective termination. The actual amounts to be paid out can only be determined at the time the executive is terminated.

 

Named Executive Officer and Post Termination Benefits		Termination for other than Reasonable Cause (1)			Constructive Termination and termination in Connection with Change of Control (2)			Termination for Reasonable Cause (3)			Death (4)			Disability (4)
J. Russell Porter
Salary		$	1,350,000		$	2,025,000		$	—		$	1,350,000		$	1,350,000
Accrued vacation			51,924			51,924			51,924			51,924			51,924
Paid health and medical			27,265			27,265			—			22,474			27,265
Parachute tax gross-up payment (5)			—			847,832			—			—			—
Equity compensation (6)			—			281,250			—			—			—
Total		$	1,429,189		$	3,233,271		$	51,924		$	1,424,398		$	1,429,189
Michael A. Gerlich
Salary		$	550,000		$	928,126		$	—		$	550,000		$	550,000
Accrued vacation			15,865			15,865			15,865			15,865			15,865
Paid health and medical			27,265			27,265			—			22,474			27,265
Parachute tax gross-up payment (5)			—			340,861			—			—			—
Equity compensation (6)			—			171,875			—			—			—
Total		$	593,130		$	1,483,992		$	15,865		$	588,339		$	593,130
Jeffery C. Pettit
Salary		$	285,000		$	712,501		$	—		$	—		$	—
Accrued vacation			3,398			3,398			3,398			3,398			3,398
Paid health and medical			—			27,265			—			—			—
Parachute tax gross-up payment (5)			—			—			—			—			—
Equity compensation (6)			—			140,625			—			—			—
Total		$	288,398		$	883,789		$	3,398		$	3,398		$	3,398

 

(1)

Per Mr. Porter’s employment agreement, if he is involuntarily terminated for any reason other than for reasonable cause (as defined in his employment agreement) and if proper notice is received, Mr. Porter will be entitled to a severance payment equal to two years (“Severance Pay Period”) of the most recent annual gross salary (as shown on his W-2 inclusive of cash bonuses paid) to be paid over 104 weeks after termination. For 2007, this amount was $675,000. If Mr. Porter timely elects COBRA continuation coverage, he and his family will be entitled to continuation of health insurance at our expense, subject to the limitations imposed by law and our insurance plan (currently 18 months). As of December 31, 2007, the cost for health and medical coverage for Mr. Porter and his

 

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family was $1,515 per month. If Mr. Porter dies during the Severance Pay Period, his family will be entitled to continuation of health insurance at our expense, subject to the limitations imposed by law and our insurance plan, for the remaining portion of the Severance Pay Period. At December 31, 2007, the maximum cost over the 24 month Severance Pay Period would be $22,464 at $936 per month. Mr. Porter currently is entitled to 20 working days of vacation per year. He would receive a lump-sum cash payment of his unused vacation time of up to 10 days that are not used during each year employed. As of December 31, 2007, Mr. Porter had available 19.25 days of available accrued but unused vacation pay. In addition, effective on Mr. Porter’s termination for any reason, the unvested portion of all stock options held by Mr. Porter will immediately vest. If Mr. Porter elects to terminate his employment without proper notice, all unvested stock options would be forfeited. All other terms and conditions of his stock options will remain unchanged, including provision that all stock option will terminate 90 day after termination. As of December 31, 2007, Mr. Porter had 1,287,500 stock options that were vested and 862,500 stock options were not vested. On December 31, 2007, the exercise prices of all of Mr. Porter’s stock options were greater than the market price of our common shares. Upon termination for any reason, all of Mr. Porter’s unvested stock options shall vest and be exercisable for period of 90 days. Additionally, on December 31, 2007, he had 225,000 restricted common shares that had not vested having a value on that date of $281,250.

Per Mr. Gerlich’s employment agreement, if he is involuntarily terminated for any reason other than for reasonable cause (as defined in their employment agreement), he will be entitled to a severance payment equal to two years (“Severance Pay Period”) of the most recent annual gross salary (as shown on his W-2 exclusive of cash bonuses paid) to be paid over 100 weeks after termination. If Mr. Gerlich timely elects COBRA continuation coverage, he and his family will be entitled to continuation of health insurance at our expense, subject to the limitations imposed by law and our insurance plan (currently 18 months). As of December 31, 2007, the cost for health and medical coverage for Mr. Gerlich and his family was $1,515 per month. If Mr. Gerlich dies during the Severance Pay Period, his family will be entitled to continuation of health insurance at our expense, subject to the limitations imposed by law and our insurance plan, for the remaining portion of the Severance Pay Period. At December 31, 2007, the maximum cost over the 24 month Severance pay Period would be $22,464 at $936 per month. In addition, Mr. Gerlich will receive a lump-sum cash payment of his unused vacation time of up to 10 days per each year employed up to a maximum of 15 days. As of December 31, 2007, Mr. Gerlich had 14.25 days of available accrued but unused vacation pay. Per Mr. Gerlich’s stock option agreements, he will have 90 days after termination to exercise all vested options. As of December 31, 2007, Mr. Gerlich had 312,500 stock options that were vested and 587,500 stock options that were not vested. The exercise prices of all of Mr. Gerlich’s stock options were greater than the market price of our common shares on December 31, 2007. Additionally, on December 31, 2007, he had 137,500 restricted common shares that had not vested having a value on that date of $171,875.

Per Mr. Pettit’s employment agreement, if he is involuntarily terminated for any reason other than for reasonable cause (as defined in their employment agreement), he will be entitled to a severance payment equal to one year of the most recent annual gross salary (as shown on his W-2 exclusive of cash bonuses paid) to be paid over 52 weeks after termination. In addition, Mr. Pettit will receive, unless termination is for cause, a lump-sum cash payment of his unused vacation time. As of December 31, 2007, Mr. Pettit had 3.1 days of available accrued but unused vacation pay. Additionally, as of December 31, 2007, Mr. Pettit has no stock option grants but had 112,500 restricted common shares that had not vested having a value on that date of $140,625.

 

(2)

Our Employee Change of Control Severance Plan provides that if there is a change of control, covered employees, including named executive officers, will receive a lump sum cash payment equal to the applicable severance period times the sum of the covered employees annual pay and target bonus. Mr. Porter’s severance period is 3, and his annual salary and 50% target bonus at December 31, 2007 was $450,000 and $225,000, respectively. Mr. Gerlich’s severance period is 2.5, and his annual salary and 35% target bonus at December 31, 2007 was $275,000 and $96,250, respectively. Mr. Pettit’s severance period is 2, and his annual salary and 25% target bonus at December 31, 2007 was $285,000 and $71,250, respectively. The Employee Severance Change of Control Plan provides that if there is a change of control, covered employees, including named executive officers, will be receive reimbursement of COBRA costs. Other termination or severance compensation is determined by the individual named executive officer’s employment agreement.

(3)

Per their respective employment agreements, we are not obligated to pay any amounts to Messrs. Gerlich or Mr. Porter, other than accrued and unused vacation days and their pro-rata base salary through the date of his termination of employment, as a result of a termination for reasonable cause (as defined in their respective employment agreements). The Company has no obligation to pay Mr. Pettit any amounts if termination is for reasonable cause.

(4)

Per their respective employment agreements, if Mr. Porter’s or Mr. Gerlich’s employment terminates due to death, his eligible beneficiary will be entitled to receive his severance payment over the severance period described in footnote 1 above. If Messrs. Porter’s or Gerlich’s employment terminates due to a disability (as defined in their respective employment agreements), he shall be entitled to receive a severance payment in the form and amount as determined in footnote 1 above. The Company has no obligation to pay Mr. Pettit any amount; except for accrued and unused vacation pay.

 

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(5)

The Company’s Employee Change of Control Severance Plan provides that if the named executive officer receives a payment or benefit that is subject to the “golden parachute” excise tax, the named executive officer will receive an additional payment under the severance plan to make him or her “whole” for that excise tax and any taxes on the additional parachute tax gross-up payment (the “gross-up payment”). To determine Mr. Porter’s amount of the gross-up payment, Mr. Porter’s “base amount” was calculated using the five-year average of his compensation for the years 2002-2006. In the case of Mr. Gerlich, the amount is calculated using the two-year average of his W-2 earnings for 2006 and his annualized salary plus paid bonus for 2005, as his employment with the Company commenced in mid-2005. The payments received in connection with the change of control in excess of a named executive officer’s “base amount” is considered an “excess parachute payment” as provided by Section 280G of the Code. If the total of all “parachute payments” is equal to or greater than three times the base amount, the amount of the excess parachute payment will be subject to the excise tax. In making the calculation, the following assumptions were used: (a) the change of control occurred on December 31, 2007, (b) the closing price of our stock was $1.25 on such date, (c) the excise tax rate under Section 4999 of the Code is 20%, the federal income tax rate is 35%, the Medicare rate is 1.45%, the adjustment to reflect the phase-out of itemized deductions is 1.05%, and there is no state or local income taxes, (d) no amounts will be discounted as attributable to reasonable compensation, (e) all cash severance payments are contingent upon a change of control, (f) the presumption required under applicable regulations that the equity awards granted were contingent upon a change of control could be rebutted.

(6)

The Gastar Employee Change of Control Severance Plan provides that if there is a transaction that results in a change of control and the surviving entity does not assume or convert the awards, then such awards will immediately vest. For the purpose of this disclosure, we have assumed the surviving entity does not assume or convert the awards. The amount shown is the product of the number of restricted shares held by the named executive officer times the closing price of our common shares on December 31, 2007, or $1.25 per common share.

The employment agreements of Messrs. Porter, Gerlich and Pettit generally use the following terms:

“Reasonable Cause” means any of the following (a) an act or omission that amounts to dishonesty, disloyalty, fraud, deceit, gross negligence, willful misconduct or recklessness, including the willful violation of any of our policies or procedures; (b) a felony conviction; (c) a breach of any material term of the employment agreement; (d) the refusal to perform any services that the named executive officer is required to perform under the employment agreement; or (e) with respect to Mr. Porter’s agreement only, an act that is determined by the vote of two-thirds of the shareholders to constitute “Reasonable Cause” or to be detrimental to the best interests of the Company.

“Disability” means the inability to perform the functions essential to the named executive officer’s position with or without accommodation during a continuous 12 month period, due to physical or mental illness of the named executive officer. The date of disability is the last day of the 12 month period. Successive periods of illness or injury that are due to the same or related causes are considered one period of disability unless the named executive officer returns to work full-time for three successive months. Except that Mr. Pettit’s employment agreement defines “disability” as the inability to perform all duties of his job for more than ninety days.

Mr. Gerlich’s employment agreement describes a “change of control” as a “change of control” as a result of a sale of all or substantially all of our assets, purchase of over 50% of our stock, or through merger, consolidation, corporate restructuring or otherwise.

The Employee Change of Control Severance Plan generally uses the following terms:

A “change of control” means (1) the consummation of a merger, consolidation, reorganization or other transaction whereby our shareholders retain less than 50% control, directly or indirectly, of us or the surviving company, (2) our incumbent directors cease to constitute a majority of the board of directors or (3) a sale or other disposition of all or substantially all of our assets.

“Involuntary Termination” means any termination of employment that occurs within two years following a Change of Control and which (1) does not result from a voluntary resignation by the covered employee (except for Good Reason), (2) results from a resignation by the Covered Employee for Good Reason, but (3) does not result from a

 

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termination by the Company for Cause, as a result of the covered employee’s death or Disability, or because the covered employee declined to accept an offer of comparable employment from the successor employer.

“Good Reason” means the occurrence of any of the following after a Change of Control: (1) relocating the covered employee’s place of employment without his consent to a place outside of the 35-mile radius of his previous place of employment, (2) reducing the covered employee’s annual base salary or materially reducing his benefits that were provided immediately prior to the Change of Control, (3) the Company’s material breach of the Employee Change of Control Severance Plan, (4) a purported termination of the covered employee’s employment for Cause by the Company that does not otherwise comply with the terms of the Employee Change of Control Severance Plan, or (5) a substantial reduction in the covered employee’s position or responsibilities. In certain circumstances, the occurrence of one of these events within six months prior to the Change of Control may be “Good Reason”.

Our Employee Change of Control Severance Plan provides that if any payment made, or benefit provided, to or on behalf of a covered employee pursuant to the plan or otherwise (“Payments”) results in a covered employee being subject to the excise tax imposed by Section 409 of the Code (or any successor or similar provision) (“Excise Tax”), we shall, as soon as administratively practicable, pay such covered employee an additional amount in cash (the “Additional Payment”) such that after payment by the covered employee of all taxes, including, without limitation, any taxes imposed on the Additional Payment, such Covered Employee retains an amount of the Additional Payment equal to the Excise Tax imposed on the Payments. Such determinations shall be made by our independent certified public accountants.

Mr. Porter’s employment agreement contains a confidentiality provision applicable both during the term of his employment and following his termination of employment. Pursuant to the confidentiality provision, Mr. Porter agrees to hold in confidence and not disclose any confidential information about our business, except as required in the ordinary course of performing his employment duties with us. A breach of this confidentiality provision could result in a reasonable cause termination. Mr. Porter’s employment agreement further provides that, for a period of two years after his termination of employment with us for a reason other than reasonable cause, (six months if terminated for reasonable cause), Mr. Porter shall not, directly or indirectly, compete with us.

Mr. Gerlich’s employment agreement provides that, unless specifically pre-approved by the Chief Executive Officer in writing, which approval may not be unreasonably withheld, Mr. Gerlich will not directly compete (as defined in the employment agreement) with us for a period of two years following his termination of employment.

Mr. Pettit’s employment agreement contains a confidentiality provision applicable both during the term of his employment and following his termination of employment. Pursuant to the confidentiality provision, he agrees to hold in confidence and not disclose any confidential and proprietary information about our business, except as required in the ordinary course of performing his employment duties with us. A breach of this confidentiality provision could result in a reasonable cause termination.

Compensation of Directors

Since November 2005, directors who are not employees receive the following fees:

 

•

$7,500 for all meetings attended in person;

 

•

$1,500 per meeting attended telephonically; and

 

•

$500 per committee meeting attended in person.

Directors who are not employees are eligible to receive stock option grants under our stock option plans. During the fiscal year ended December 31, 2007, stock options were issued to the Messrs. Badwi, Crow, Penner and Selser to purchase 150,000, 100,000, 200,000 and 100,000 common shares, respectively. Each stock option vests over a four-year period (25% on the first anniversary of the grant and 25% on each of the second, third and

 

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fourth anniversaries of the grant) and expires 10 years from the date of grant. The stock options granted to Messrs. Badwi and Crow have an exercise price of $2.20 per common share. Mr. Penner’s stock option has an exercise price of $2.19. Mr. Selser’s 2007 stock options consist of two grants, one for 200,000 common shares and another for 100,000 common shares, having exercise prices of $2.17 and $2.20 per share, respectively.

The following table shows certain information about directors’ compensation for the year ended December 31, 2007:

Director Compensation Table

 

		Fees Earned or Paid in Cash			Option Awards (1)			Total
Abby F. Badwi		$	45,000		$	327,439		$	372,439
Thomas L. Crow (2)		$	24,000		$	190,790		$	214,790
Richard A. Kapuscinski (3)		$	9,500		$	161,572		$	171,072
Robert D. Penner (4)		$	36,000		$	58,629		$	94,629
John M. Selser Sr. (5)		$	34,000		$	114,323		$	148,323

 

(1)

We have granted to our directors stock options in addition to their specified compensation to be paid as directors. These grants are, in part, to compensate our directors for the stricter regulatory role in which they have to operate and to provide them with incentives to remain as a director by offering them a long-term stake in our potential future value. The fair values of stock option awards were determined in accordance with SFAS 123R by using the Black-Scholes-Merton valuation model as of the date of grant. See Note 8 – Equity Compensation Plans – Determining Fair Value under SFAS 123R to our consolidated financial statements, which begins on Page F-1, for a discussion of assumptions made in the valuation of option awards. The amounts shown in this column represents the stock-based compensation expense, prior to a 5.0% deduction for estimated forfeitures, attributable to stock options grants that is recognized by us for the year ended December 31, 2007 that was attributable to all stock options granted to the Directors and outstanding during the year. During 2007, Messrs. Badwi, Crow, Penner and Selser were awarded stock options to purchase 150,000, 100,000, 200,000 and 100,000 common shares, respectively. As of December 31, 2007, Messrs. Badwi, Crow, Penner and Selser held stock options to purchase an aggregate of 950,000, 500,000, 200,000 and 300,000 common shares. Total fair value attributable to stock options granted to Messrs. Badwi, Crow, Penner and Selser during 2007 as of the date of grant was $168,975, $112,650, $225,700 and $112,650, respectively. Mr. Kapuscinski resigned as a director of the Board effective June 19, 2007 and received no stock based compensation grants in 2007. In determining the number of stock options granted to directors, consideration was given to the number of stock options previously granted to the directors. Additional consideration was given to Mr. Badwi, who served as the chairman of the Audit Committee, as well as other committees of the Board of Directors. Additional consideration also was given to Mr. Penner, who replaced Mr. Badwi as Chairman of the Audit Committee.

(2)	Mr. Crow resigned as a director of the Board of Directors effective January 1, 2008.

(3)	Mr. Kapuscinski resigned as a director of the Board effective June 19, 2007.

(4)	Mr. Penner became a director of the Board effective July 16, 2007.

(5)	Mr. Selser became a director of the Board effective April 4, 2007.

Compensation Committee Interlocks and Insider Participation

During the year ended December 31, 2007, the compensation committee of our Board of Directors, which we refer to as the Remuneration Committee, was comprised of Messrs. Badwi (Chairman), Crow, Kapuscinski and Selser, who replaced Mr. Kapuscinski upon his resignation as a director of the Board of Directors on June 19, 2007. Mr. Crow resigned from the Board of Directors effective January 1, 2008. Currently, our Remuneration Committee is comprised of Messrs. Badwi, Penner and Selser. None of our named executive officers serves as a member of the board of directors or compensation committee (or committee performing similar functions) of any other entity, one or more of whose executive officers serve on our Board of Directors or Remuneration Committee.

 

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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

On November 4, 2005, our Parent completed an integrated transaction with Chesapeake Energy Corporation whereby Chesapeake acquired 27,151,641 million newly issued common shares equal to 19.9% of our Parent’s then outstanding common shares, acquired a 33.3% working interest in our Bossier play in the Hilltop area of East Texas and formed an area of mutual interest to explore jointly in 13 counties in East Texas. As part of this transaction, Chesapeake paid an additional $7.8 million, before fees and expenses, to reimburse us for Chesapeake’s pro rata share of leasehold interests acquired and to pay a disproportionate amount of future drilling costs in exchange for an undivided 33.3% of our leasehold working interests in the deep Bossier Hilltop prospect, less and except 160 acres surrounding each existing well bore. Chesapeake agreed to pay 44.44% of the drilling costs through casing point in the first six wells drilled by the parties in the Hilltop prospect to a depth sufficient to test the deep Bossier formation (an approximate depth of 19,000 feet) in order to earn its 33.33% leasehold working interest.

As a result of its purchase of our Parent’s common shares, Chesapeake has an exclusive right to negotiate with our Parent for a period of 30 days on any proposed sale of assets. Additionally, Chesapeake has the right, with certain exceptions, to maintain its percentage ownership in our Parent, on a fully diluted basis, by participating in future stock issuances and has the right to an observer being present at meetings of our Parent’s Board of Directors.

On November 11, 2006, Chesapeake acquired an additional 5,000,000 common shares in a private placement transaction to institutional investors. On May 23, 2007, Chesapeake elected to exercise its preemptive right to acquire an additional 1,757,195 common shares as a result of our Parent’s issuance of common shares to Navasota Resources, L.P. related to its sale of a portion of its undeveloped East Texas leasehold interest. As of March 10, 2008, Chesapeake owned approximately 16.3% of our Parent’s outstanding common shares.

 

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DESCRIPTION OF THE NOTES

You can find the definitions of certain terms used in this description under the subheading “—Certain Definitions”. In this description, the term “Company,” “us,” “our” or “we” refers only to Gastar Exploration USA, Inc. and not to any of its subsidiaries. References herein to the “Parent” refer to Gastar Exploration Ltd., the Company’s parent, and not to any of its subsidiaries. References herein to the “Guarantors” refer to both the Parent and the Subsidiary Guarantors described below.

The old notes were, and the new notes will be, issued under an indenture among the Company, the Parent, the Subsidiary Guarantors and Wells Fargo Bank, National Association, as trustee and collateral agent. See “Notice to Investors”. We refer to the new notes and the old notes in this description as the “Notes”. The terms of the Notes include those stated in the indenture and those made part of the indenture by reference to the Trust Indenture Act of 1939.

The following description is a summary of the material provisions of the indenture, the Collateral Agreements and the registration rights agreement. It does not restate those agreements in their entirety. We urge you to read the indenture and the registration rights agreement because they, and not this description, define your rights as holders of the new notes. Certain defined terms used in this description but not defined below under “—Certain Definitions” have the meanings assigned to them in the indenture.

The registered Holder of a new note will be treated as the owner of it for all purposes. Only registered Holders will have rights under the indenture.

As described below under “—Registration Rights; Additional Interest,” we are filing a registration statement to enable holders of outstanding notes to exchange their notes for publicly registered notes having substantially identical terms, except for provisions relating to transfer restrictions and additional interest. Any old notes, the new notes issued in the exchange offer and any additional notes subsequently issued under the indenture will constitute a single series of securities under the indenture and therefore will vote together as a single class for purposes of determining whether holders of the requisite percentage in aggregate principal amount thereof have taken actions or exercised rights they are entitled to take or exercise under the Indenture. We are required under specified circumstances to file a shelf registration statement to cover resales of the old notes. If we fail to satisfy specified obligations under the registration rights agreement, we may be required to pay additional interest to holders of the old notes.

Brief Description of the Notes and the Guarantees

The Notes

The Notes:

 

•

Were initially issued in an aggregate principal amount of $100.0 million, subject to the Company’s ability to issue additional notes under certain circumstances;

 

•

Are equal in right of payment to all existing and future senior Indebtedness of the Company;

 

•

Are secured by a second priority lien on the Company’s principal oil and gas properties and other assets that secure the obligations under the Credit Agreement, subject to certain exceptions and subject to Permitted Liens; and

 

•

Are senior in right of payment to any future subordinated Indebtedness of the Company.

The Guarantees

The Notes are fully and unconditionally guaranteed by the Parent and by each of the Parent’s present domestic Restricted Subsidiaries (other than the Company) and its future Material Domestic Subsidiaries.

The Guarantees of the Notes:

 

•

Are equal in right of payment to all existing and future senior Indebtedness of each Guarantor;

 

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•

Are secured by a second priority lien on the Guarantor’s principal oil and gas properties and other assets that secure the obligations under the Credit Agreement, subject to certain exceptions and to Permitted Liens; and

 

•

Are senior in right of payment to any future subordinated Indebtedness of each Guarantor.

Pursuant to the terms of the Intercreditor Agreement and the other Collateral Agreements described herein, the lien on the assets of the Company and the Guarantors that secures the Notes and the Guarantees are contractually subordinated to the liens thereon that secure First Priority Claims. Consequently, the Notes and the Guarantees will be effectively subordinated to the First Priority Claims to the extent of the value of such assets.

As of the date of the indenture, all of the Parent’s domestic subsidiaries (including the Company) will be “Restricted Subsidiaries”. However, under the circumstances described below under the subheading “—Certain Covenants—Designation of Restricted and Unrestricted Subsidiaries,” the Parent will be permitted to designate certain of its subsidiaries as “Unrestricted Subsidiaries”. Unrestricted Subsidiaries will not be subject to many of the restrictive covenants in the indenture. Unrestricted Subsidiaries will not guarantee the new notes.

Principal, Maturity and Interest

The Company has issued Notes with an initial aggregate principal amount of $100.0 million. The Company may issue additional notes from time to time after this offering. Any offering of additional notes is subject to the covenant described below under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock”. Any old notes, the new notes and any additional notes subsequently issued under the indenture will be treated as a single class for all purposes under the indenture, including, without limitation, waivers, amendments, redemptions and offers to purchase, and will share equally and ratably in the Collateral securing the notes. As such, any issuance of additional notes may have the effect of diluting the security afforded by the Collateral for the new notes. The Company will issue Notes in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof. The Notes will mature on December 1, 2012.

Interest on the Notes will accrue at the rate of 12 ³/4% per annum. Interest will be payable semi-annually in arrears on June 1 and December 1, commencing on June 1, 2008. The Company will make each interest payment to the Holders of record on the immediately preceding May 15 and November 15.

Additional interest may accrue on the old notes as liquidated damages in certain circumstances described below under “—Registration Rights; Additional Interest,” and all references to “interest” in this description include any additional interest that may be payable on the Notes. Interest will be computed on the basis of a 360-day year comprised of twelve 30-day months.

Methods of Receiving Payments on the Notes

If a Holder has given wire transfer instructions to the Company, the Company will pay all principal, interest and premium, if any, on that Holder’s Notes in accordance with those instructions. All other payments on Notes will be made at the office or agency of the paying agent and registrar unless the Company elects to make interest payments by check mailed to the Holders at their address set forth in the register of Holders.

Paying Agent and Registrar for the Notes

The trustee will initially act as paying agent and registrar. The Company may change the paying agent or registrar without prior notice to the Holders of the Notes, and the Company or any of its Domestic Subsidiaries may act as paying agent.

Transfer and Exchange

A Holder may transfer or exchange Notes in accordance with the indenture. The Company or the trustee may require a Holder to furnish appropriate endorsements and transfer documents in connection with a transfer of Notes.

 

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No service charge will be imposed for any registration of transfer or exchange of Notes, but the Company may require Holders to pay all taxes due on transfer. The Company is not required to transfer or exchange any Note selected for redemption. Also, the Company is not required to transfer or exchange any Note for a period of 15 days prior to the mailing of a notice of redemption.

Guarantees

Initially, the Parent and all of its domestic Subsidiaries (other than the Company) will fully and unconditionally guarantee the Notes. In the future, the Notes will also be fully and unconditionally guaranteed by each of the Parent’s newly created or acquired Material Domestic Subsidiaries and by any other Restricted Subsidiary of the Parent that guarantees other Indebtedness of the Company or the Parent. See “—Certain Covenants—Additional Guarantees”. These Guarantees will be joint and several obligations of the Guarantors. The obligations of each Guarantor under its Guarantee will be limited as necessary to prevent that Guarantee from constituting a fraudulent conveyance under applicable law. See “Risk Factors—Risks Relating to the Notes and Our Other Indebtedness—A court could cancel the Notes or the Guarantees of our current and future Subsidiaries or Parent and security interests under fraudulent conveyance laws or certain other circumstances”.

A Subsidiary Guarantor may not sell or otherwise dispose of all or substantially all of its properties or assets to, or consolidate with or merge with or into (whether or not such Subsidiary Guarantor is the surviving Person), another Person, other than the Parent, the Company or another Subsidiary Guarantor, unless:

(1) immediately after giving effect to such transaction, no Default or Event of Default exists; and

(2) either:

(a) the Person acquiring the properties or assets in any such sale or other disposition or the Person formed by or surviving any such consolidation or merger (if other than the Subsidiary Guarantor) unconditionally assumes all the obligations of that Subsidiary Guarantor, pursuant to a supplemental indenture substantially in the form specified in the indenture, under the notes, the indenture and its Guarantee on terms set forth therein; or

(b) such sale or other disposition complies with the “Asset Sale” provisions of the indenture.

The Guarantee of a Subsidiary Guarantor will be released:

(1) in connection with any sale or other disposition of all or substantially all of the properties or assets of that Subsidiary Guarantor (including by way of merger or consolidation) to a Person that is not (either before or after giving effect to such transaction) a Subsidiary of the Parent, if the sale or other disposition complies with the “Asset Sale” provisions of the indenture;

(2) in connection with any sale or other disposition of all of the Capital Stock of that Subsidiary Guarantor to a Person that is not (either before or after giving effect to such transaction) a Subsidiary of the Parent, if the sale or other disposition complies with the “Asset Sale” provisions of the indenture;

(3) if the Parent designates any Restricted Subsidiary that is a Subsidiary Guarantor as an Unrestricted Subsidiary in accordance with the applicable provisions of the indenture;

(4) upon Legal Defeasance or Covenant Defeasance with respect to all notes as described below under the caption “—Legal Defeasance and Covenant Defeasance” or upon satisfaction and discharge of the indenture as described below under the caption “—Satisfaction and Discharge;” or

(5) as provided in the Intercreditor Agreement.

Collateral

The Notes and the Guarantees are secured by a lien on the existing and future natural gas and oil properties and other assets of the Company and the Guarantors that, from time to time, secure the obligations of the Company and the Guarantors under the Credit Agreement, except that the Collateral will not include any Capital Stock of Subsidiaries (the “Excluded Collateral”) whether or not such Capital Stock is pledged to secure the First Priority Claims.

 

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The indenture provides that, subject to satisfaction of certain conditions, the Trustee will be authorized and required to release any Collateral that is released by the First Priority Agent, except that the indenture contains a requirement that the Company certify to the trustee semi-annually (and at the time of any such release) that the Collateral includes oil and gas properties representing at least 85% of the PV-10 value of the Parent’s and its Restricted Subsidiaries’ proved reserves located in the United States as reflected in the most recent available semi-annual reserve report (which shall use pricing assumptions consistent with SEC guidelines) and that, to the extent necessary, the Company update the modify or supplement the Collateral Agreements to satisfy this requirement.

Intercreditor Agreement

A summary of certain sections of the Intercreditor Agreement is set forth below.

First Priority Claims; Notes Effectively Subordinated to First Priority Claims. The First Priority Claims are secured by a Lien on the Collateral, which Lien is contractually senior to the Lien thereon that secures the Notes and the Guarantees pursuant to the Intercreditor Agreement. By their acceptance of the old notes, the Holders of the old notes authorized the collateral agent to enter into the Intercreditor Agreement with the First Priority Agent. As a result, the Notes are effectively subordinated to the First Priority Claims to the extent of the value of the Collateral.

Relative Priorities. The Intercreditor Agreement provides that notwithstanding the date, manner or order of grant, attachment or perfection of any Lien securing the Notes or Guarantees (a “Second Priority Lien”) or any Lien securing the First Priority Claims (a “First Priority Lien”), and notwithstanding any provision of the Uniform Commercial Code of any applicable jurisdiction or any other applicable law or the provisions of any Indenture Document or any agreement, instrument or other document evidencing or governing any First Priority Claims (collectively, the “First Priority Debt Documents” and, together with the Indenture Documents, the “Debt Documents”) or any other circumstance whatsoever, each Agent (i.e., the First Priority Agent and the collateral agent), for itself and on behalf of the Secured Parties (i.e., the holders of the First Priority Claims and the First Priority Agent (collectively, the “First Priority Secured Parties”) and the Holders, the Trustee and the collateral agent (collectively, the “Second Priority Secured Parties”)) on whose behalf it acts in such capacity therefor, will agree that, so long as the First Priority Claims have not been paid in full in cash, (a) any First Priority Lien then or thereafter held by or for the benefit of any First Priority Secured Party will be senior in right, priority, operation, effect and all other respects to any and all Second Priority Liens and (b) any Second Priority Lien then or thereafter held by or for the benefit of any Second Priority Secured Party will be junior and subordinate in right, priority, operation, effect and all other respects to any and all First Priority Liens, and the First Priority Liens will be and remain senior in right, priority, operation, effect and all other respects to any Second Priority Liens for all purposes, whether or not any First Priority Liens are subordinated in any respect to any other Lien securing any other obligation of the Company, any Guarantor or any other Person.

Prohibition on Contesting Liens; Additional Collateral. The Intercreditor Agreement provides that (a) each Agent, for itself and on behalf of the other Secured Parties on whose behalf it acts in such capacity therefor, will agree that it will not, and will waive any right to, contest or support any other Person in contesting, in any proceeding (including any insolvency or liquidation proceeding), the priority, validity or enforceability of any Second Priority Lien or any First Priority Lien, as the case may be; provided that nothing in the Intercreditor Agreement will be construed to prevent or impair the rights of any Agent or any other Secured Party to enforce the Intercreditor Agreement to the extent provided thereby and (b) if the Company or any Guarantor creates any additional Liens upon any property to secure (i) any First Priority Claims, it must concurrently grant a Lien upon such property (other than Excluded Collateral) as security for the Notes or the Guarantee of such Guarantor, as the case may be, and (ii) the Notes or Guarantee of such Guarantor, it must concurrently grant a Lien upon such property as security for the First Priority Claims.

Exercise of Rights and Remedies; Standstill. In addition, the Intercreditor Agreement provides that the First Priority Agent and the other holders of First Priority Claims will, at all times prior to the payment in full in cash of the First Priority Claims, have the exclusive right to enforce rights and exercise remedies (including any right of setoff) with respect to the Collateral (including making determinations regarding the release, disposition or restrictions with respect to the Collateral), or to commence or seek to commence any action or proceeding with

 

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respect to such rights or remedies (including any foreclosure action or proceeding or any insolvency or liquidation proceeding), in each case, without any consultation with or the consent of the Second Priority Agent or any other Second Priority Secured Party and no Second Priority Secured Party will have any such right; provided, however, that (i) the Second Priority Secured Parties will be entitled to take certain actions to preserve and protect their claims with respect to the Collateral and actions that unsecured creditors are entitled to take (which in any event cannot be in contravention to the limitations imposed on the Second Priority Secured Parties in the Intercreditor Agreement), in each case, to the extent set forth in the Intercreditor Agreement and (ii) after a period of 90 days has elapsed (which period will be tolled during any period in which the First Priority Agent will not be entitled to enforce or exercise any rights or remedies with respect to any Collateral as a result of (x) any injunction issued by a court of competent jurisdiction or (y) the automatic stay or any other stay in any insolvency or liquidation proceeding) since the date on which the Second Priority Agent has delivered to the First Priority Agent written notice of the acceleration of the Notes (the “Standstill Period”) the Second Priority Secured Parties may enforce or exercise any rights or remedies with respect to any Collateral subject to the following proviso; provided further, however, that notwithstanding the expiration of the Standstill Period or anything in the Intercreditor Agreement to the contrary, in no event may the Second Priority Agent or any other Second Priority Secured Party enforce or exercise any rights or remedies with respect to any Collateral, or commence, join with any Person at any time in commencing, or petition for or vote in favor of any resolution for, any such action or proceeding, if the First Priority Agent or any other First Priority Secured Party shall have commenced, and shall be diligently pursuing (or shall have sought or requested relief from or modification of the automatic stay or any other stay in any insolvency or liquidation proceeding to enable the commencement and pursuit thereof), the enforcement or exercise of any rights or remedies with respect to any material portion of the Collateral or any such action or proceeding (prompt written notice thereof to be given to the Second Priority Agent by the First Priority Agent).

Automatic Release of Second Priority Liens. The Intercreditor Agreement also provides that if, in connection with (i) any disposition of any Collateral permitted under the terms of the First Priority Debt Documents or (ii) the enforcement or exercise of any rights or remedies with respect to the Collateral, including any disposition of Collateral, the First Priority Agent, for itself and on behalf of the other First Priority Secured Parties, (x) releases any of the First Priority Liens, or (y) releases any Subsidiary Guarantor from its obligations under its guarantee of the First Priority Claims (in each case, a “Release”), other than any such Release granted following the payment in full in cash of the First Priority Claims, and termination of commitments under the First Priority Debt Documents, then the Second Priority Liens on such Collateral, and the obligations of such Subsidiary Guarantor under its guarantee of the Notes, will be automatically, unconditionally and simultaneously released, and the Second Priority Agent will, for itself and on behalf of the other Second Priority Secured Parties, promptly execute and deliver to the First Priority Agent, the Company or such Subsidiary Guarantor, as the case may be, such termination statements, releases and other documents as the First Priority Agent, the Company or such Subsidiary Guarantor, as the case may be, may reasonably request to effectively confirm such Release.

Waterfall. The Intercreditor Agreement also provides that any Collateral or proceeds thereof received by any Secured Party in connection with any disposition of, or collection on, such Collateral upon the enforcement or exercise of any right or remedy (including any right of setoff) will be applied as follows:

first, to the payment of costs and expenses of the applicable Secured Party in connection with such enforcement or exercise;

second, after all such costs and expenses have been paid in full in cash, to the payment of the First Priority Claims in accordance with the First Priority Debt Documents; and

third, after all such costs and expenses and First Priority Claims have been paid in full in cash, to the payment of the Notes and Guarantees.

After all such costs and expenses and First Priority Claims and the Notes and Guarantees have been paid in full in cash, any surplus Collateral or proceeds then remaining will be returned to the Company, the applicable Guarantor or to whosoever may be lawfully entitled to receive the same or as a court of competent jurisdiction may direct.

Turnover. The Intercreditor Agreement also provides that so long as the First Priority Claims have not been paid in full in cash, any Collateral or any proceeds thereof received by the Second Priority Agent or any other

 

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Second Priority Secured Party in connection with any disposition of, or collection on, such Collateral upon the enforcement or the exercise of any right or remedy (including any right of setoff) with respect to the Collateral, or in connection with any insurance policy claim or any condemnation award (or deed in lieu of condemnation) with respect to the Collateral, will be segregated and held in trust and forthwith transferred or paid over to the First Priority Agent for the benefit of the First Priority Secured Parties in the same form as received, together with any necessary endorsements, or as a court of competent jurisdiction may otherwise direct.

Insolvency or Liquidation Proceedings. The Intercreditor Agreement also provides that:

(a) Until the First Priority Claims have been paid in full, the Second Priority Agent, for itself and on behalf of the other Second Priority Secured Parties, will agree that, in the event of any insolvency or liquidation proceeding, the Second Priority Secured Parties:

(i) will not oppose or object to the use of any Collateral constituting cash collateral under Section 363 of the Bankruptcy Code, or any comparable provision of any other bankruptcy law, unless the First Priority Secured Parties, or a representative authorized by the First Priority Secured Parties, shall oppose or object to such use of cash collateral;

(ii) will not oppose or object to any post-petition financing, whether provided by the First Priority Secured Parties or any other Person, under Section 364 of the Bankruptcy Code, or any comparable provision of any other bankruptcy law (a “DIP Financing”), or the Liens securing any DIP Financing (“DIP Financing Liens”), unless the First Priority Secured Parties, or a representative authorized by the First Priority Secured Parties, shall then oppose or object to such DIP Financing or such DIP Financing Liens, and, to the extent that such DIP Financing Liens are senior to, or rank pari passu with, the First Priority Liens, the Second Priority Agent will, for itself and on behalf of the other Second Priority Secured Parties, subordinate the Second Priority Liens to the First Priority Liens and the DIP Financing Liens on the terms of the Intercreditor Agreement;

(iii) except to the extent permitted by paragraph (b) below, in connection with the use of cash collateral as described in clause (i) above or a DIP Financing, will not request adequate protection or any other relief in connection with such use of cash collateral, DIP Financing or DIP Financing Liens; and

(iv) will not oppose or object to any disposition of any Collateral free and clear of the Second Priority Liens or other claims under Section 363 of the Bankruptcy Code, or any comparable provision of any other bankruptcy law, if the First Priority Secured Parties, or a representative authorized by the First Priority Secured Parties, shall consent to such disposition free and clear of the First Priority Liens.

(b) The Second Priority Agent, for itself and on behalf of the other Second Priority Secured Parties, will agree that no Second Priority Secured Party may contest, or support any other Person in contesting, (i) any request by the First Priority Agent or any other First Priority Secured Party for adequate protection in respect of any First Priority Claims or (ii) any objection, based on a claim of a lack of adequate protection with respect of any First Priority Claims, by the First Priority Agent or any other First Priority Secured Party to any motion, relief, action or proceeding. Notwithstanding the immediately preceding sentence, if, in connection with any DIP Financing or use of cash collateral, (A) any First Priority Secured Party seeks or requests adequate protection in the form of a Lien on additional collateral, the Second Priority Agent may, for itself and on behalf of the other Second Priority Secured Parties, seek or request adequate protection in the form of a Lien on such additional collateral, which Lien will be subordinated to the First Priority Liens and DIP Financing Liens on the same basis as the other Second Priority Liens are subordinated to the First Priority Liens under the Intercreditor Agreement or (B) any Second Priority Secured Party is granted adequate protection in the form of a Lien on additional collateral, the First Priority Agent will, for itself and on behalf of the other First Priority Secured Parties, be granted adequate protection in the form of a Lien on such additional collateral that is senior to such Second Priority Lien as security for the First Priority Claims.

(c) Notwithstanding the foregoing, the applicable provisions of paragraphs (a) and (b) above will only be binding on the Second Priority Secured Parties with respect to any DIP Financing to the extent the principal amount of such DIP Financing, when taken together with the aggregate principal amount of the First Priority Claims, does not exceed the sum of $5.0 million plus the amount of Indebtedness at the time permitted to be outstanding pursuant to clause (1) of the definition of Permitted Debt.

 

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(d) Notwithstanding anything to the contrary in the Intercreditor Agreement, the holders of the Indenture Documents retain their rights under the Bankruptcy Code to make post-petition financing proposals and such proposals shall not be deemed to be an objection to any other DIP Financing proposals so long as (x) any court order approving such post-petition financing requires that all First Priority Claims be paid in full in cash as a condition to such post-petition financing, and (y) all First Priority Claims are paid in full in cash on the date of such post-petition financing, which date shall be no later than 10 business days after the date on which such post-petition financing is approved by the court in which such insolvency or liquidation proceeding is pending.

Relief from the Automatic Stay. The Second Priority Agent, for itself and on behalf of the other Second Priority Secured Parties, will agree that, so long as the First Priority Claims have not been paid in full, no Second Priority Secured Party may, without the prior written consent of the First Priority Agent, seek or request relief from or modification of the automatic stay or any other stay in any insolvency or liquidation proceeding in respect of any part of the Collateral, any proceeds thereof or any Second Priority Lien.

Reorganization Securities. If, in any insolvency or liquidation proceeding, debt obligations of the reorganized debtor secured by Liens upon any property of the reorganized debtor are distributed, pursuant to a plan of reorganization or similar dispositive restructuring plan, on account of the First Priority Claims and the Notes and Guarantees, then, to the extent the debt obligations distributed on account of the First Priority Claims and on account of the Notes and Guarantees, the provisions of the Intercreditor Agreement will survive the distribution of such debt obligations pursuant to such plan and will apply with like effect to the Liens securing such debt obligations.

Post-Petition Interest. The Second Priority Agent, for itself and on behalf of the other Second Priority Secured Parties, will agree that no Second Priority Secured Party may oppose or seek to challenge any claim by the First Priority Agent or any other First Priority Secured Party for allowance in any insolvency or liquidation proceeding of First Priority Claims consisting of post-petition interest, fees or expenses to the extent of the value of the First Priority Liens (it being understood and agreed that such value will be determined without regard to the existence of the Second Priority Liens on the Collateral). The First Priority Agent, for itself and on behalf of the other First Priority Secured Parties, will agree that the Second Priority Agent or any other Second Priority Secured Party may make a claim for allowance in any insolvency or liquidation proceeding of Second Priority Claims consisting of post-petition interest, fees or expenses to the extent of the value of the Second Priority Liens; provided, however, that if the First Priority Secured Parties shall have made any such claim, such claim (A) shall have also have been approved or (B) will be approved contemporaneous with the approval of any such claim by any Second Priority Secured Party.

Certain Waivers by the Second Priority Secured Parties. Except as provided in the Intercreditor Agreement, the Second Priority Agent, for itself and on behalf of the other Second Priority Secured Parties, will waive any claim any Second Priority Secured Party may have against any First Priority Secured Party arising out of (a) the election by any First Priority Secured Party of the application of Section 1111(b)(2) of the Bankruptcy Code, or any comparable provision of any other bankruptcy law, or (b) any use of cash collateral or financing arrangement, or any grant of a security interest in the Collateral, in any insolvency or liquidation proceeding.

Certain Voting Matters. Each of the First Priority Agent, on behalf of the First Priority Secured Parties and the Second Priority Agent on behalf of the Second Priority Secured Parties, will agree that, without the written consent of the other, it will not seek to vote with the other as a single class in connection with any plan of reorganization in any insolvency or liquidation proceeding. Except as provided in this paragraph, nothing in the Intercreditor Agreement is intended, or may be construed, to limit the ability of the Second Priority Agent or the Second Priority Secured Parties to vote on any plan of reorganization that maintains the Lien subordination provisions of the Intercreditor Agreement or of either the First Priority Secured Parties or Second Priority Secured Parties, to contest any plan of reorganization that does not maintain the Lien subordination provisions of the Intercreditor Agreement.

Postponement of Subrogation. The Intercreditor Agreement also provides that the Second Priority Agent will agree that no payment or distribution to any First Priority Secured Party pursuant to the provisions of the Intercreditor Agreement will entitle any Second Priority Secured Party to exercise any rights of subrogation in respect thereof until the First Priority Claims shall have been paid in full in cash.

 

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Purchase Option. The Intercreditor Agreement also provides that notwithstanding anything in the Intercreditor Agreement to the contrary, following the acceleration of the Indebtedness then outstanding under the First Priority Debt Documents, the Second Priority Secured Parties may, at their sole expense and effort, upon notice to the Company and the First Priority Agent, require the First Priority Secured Parties to transfer and assign to the Second Priority Secured Parties, without warranty or representation or recourse, all (but not less than all) of the First Priority Claims; provided that (x) such assignment may not conflict with any law, rule or regulation or order of any court or other governmental authority having jurisdiction, and (y) the Second Priority Secured Parties shall have paid to the First Priority Agent, for the account of the First Priority Secured Parties, in immediately available funds, an amount equal to 100% of the principal of such Indebtedness plus all accrued and unpaid interest thereon plus all accrued and unpaid fees plus all the other First Priority Claims then outstanding (which will include, with respect to (i) the aggregate face amount of the letters of credit outstanding under the First Priority Debt Documents, posting cash collateral in an amount equal to 105% thereof, and (ii) each interest rate hedging, cap, collar, swap or other similar agreements that evidence any Hedging Obligations included in such First Priority Claims, 100% of the aggregate amount of such First Priority Claims, after giving effect to any netting arrangements, that the Company or the applicable Guarantor as the case may be, would be required to pay if such interest rate hedging, cap, collar, swap or other similar agreements were terminated at such time calculated using the market quotation method). In order to effectuate the foregoing, the First Priority Agent will calculate, upon the written request of the Second Priority Agent from time to time, the amount in cash that would be necessary so to purchase the First Priority Claims. If the right set forth in this paragraph is exercised, the parties shall endeavor to close promptly thereafter but in any event within ten business days of the request set forth in the first sentence of this paragraph. If the Second Priority Secured Parties exercise the right set forth in this paragraph, it will be exercised pursuant to documentation mutually acceptable to each of the First Priority Agent and the Second Priority Agent.

Security Documents

The Company, the Guarantors and the collateral agent have entered into one or more Collateral Agreements granting, in favor of the collateral agent for the benefit of the Second Priority Secured Parties, Liens on the Collateral securing the Notes and Guarantees. Whether prior to or after the First Priority Claims have been paid in full, the Company and the Guarantors will be entitled to releases of assets included in the Collateral from the Liens securing the Notes under any one or more of the following circumstances:

(1) to enable the Company or any Guarantor to consummate asset dispositions permitted or not prohibited under the covenant described below under “—Repurchase at the Option of Holder—Asset Sales;”

(2) if any Subsidiary that is a Subsidiary Guarantor is released from its Guarantee, that Subsidiary’s assets will also be released from the Liens securing the Notes;

(3) as described under “Amendment, Supplement and Waiver” below; or

(4) if required in accordance with the terms of the Intercreditor Agreement.

The Liens on all Collateral that secures the Notes and the Guarantees also will be released:

(1) if the Company exercises its legal defeasance option or covenant defeasance option as described below under “—Legal Defeasance and Covenant Defeasance;”

(2) upon satisfaction and discharge of the Indenture or payment in full of the principal of, and premium, if any, and accrued and unpaid interest on, the notes and all other Obligations that are then due and payable; or

(3) as described under “Amendment, Supplement and Waiver” below.

Certain Bankruptcy and Other Limitations

The ability of the Holders of the Notes to realize upon the Collateral may be subject to certain bankruptcy law limitations in the event of a bankruptcy. See the section entitled “Risk Factors—Risks related to the Notes and Our Other Indebtedness—In the event of a bankruptcy, the ability of the noteholders to realize upon the Collateral will be subject to certain bankruptcy law limitations”. The collateral agent’s ability to foreclose on the Collateral may be subject to lack of perfection, the consent of third parties, prior Liens and practical problems associated with the realization of the collateral agent’s Lien on the Collateral.

 

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Additionally, the collateral agent may need to evaluate the impact of the potential liabilities before determining to foreclose on Collateral consisting of real property (if any) because a secured creditor that holds a Lien on real property may be held liable under environmental laws for the costs of remediating or preventing release or threatened releases of hazardous substances at such real property. Consequently, the collateral agent may decline to foreclose on such Collateral or exercise remedies available if it does not receive indemnification to its satisfaction from the Holders.

No fair market value appraisals of any of the Collateral have been prepared by or on behalf of the Company in connection with the issuance of the Notes. There can be no assurance that the proceeds from the sale of the Collateral remaining after the satisfaction of all Obligations owed to the holders of First Priority Claims or after the satisfaction of all other Obligations in which any Collateral secures such other Obligations owing to the holders of other Liens which have priority over the Lien securing the Notes would be sufficient to satisfy the obligations owed to the Holders of the Notes.

Subject to the restrictions on incurring Indebtedness in the indenture, the Company and the Parent and its Restricted Subsidiaries also have the right to grant Liens securing Capital Lease Obligations and purchase money obligations constituting Permitted Indebtedness and to acquire any such assets subject to such Liens. To the extent third parties hold Permitted Liens, such third parties may have rights and remedies with respect to the property subject to such Liens that, if exercised, could adversely affect the value of the Collateral. By its nature, some or all of the Collateral will be illiquid and may have no readily ascertainable market value and any sale of such Collateral separately from the assets of the Company and the Guarantors as a whole may not be feasible. Accordingly, there can be no assurance that the Collateral can be sold in a short period of time, if salable. See “Risk Factors—Risks Related to the Notes and Our Other Indebtedness—There may not be sufficient Collateral to pay all or any of the Notes”.

Optional Redemption

Optional Redemption after June 1, 2010. On or after June 1, 2010, the Company may redeem all or a part of the Notes at any time or from time to time upon not less than 30 nor more than 60 days’ notice, at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest thereon, if any, to the applicable redemption date (subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date), if redeemed during the twelve month period beginning on June 1 of the years set forth below:

 

For the Period Below		Percentage
2010		106.375	%
2011		103.188	%
2012		100.000	%

Optional Redemption with Equity Proceeds. In addition, at any time prior to June 1, 2010, the Company may on any one or more occasions redeem up to 35% of the aggregate principal amount of the Notes issued under the indenture upon not less than 30 nor more than 60 days’ prior notice at a redemption price of 112.750% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date), with the net cash proceeds of one or more Equity Offerings by the Company or the Parent, provided that:

(1) at least 65% of the aggregate principal amount of Notes issued under the indenture (including additional notes) remains outstanding immediately after the occurrence of such redemption (excluding Notes held by the Parent and its Subsidiaries); and

(2) the redemption occurs within 90 days of the date of the closing of such Equity Offering.

 

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Make-Whole Redemption. In addition, at any time prior to June 1, 2010, the Notes may be redeemed in whole or in part at the option of the Company upon not less than 30 nor more than 60 days’ prior notice at a redemption price equal to 100% of the principal amount thereof plus the Applicable Premium as of, and accrued and unpaid interest, if any, to, the date of redemption (subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date).

“Applicable Premium” means, with respect to a Note at any redemption date, the greater of (x) 1.0% of the principal amount of such Note and (y) the excess of (A) the present value at such time of (1) redemption price of such note as of June 1, 2010 (without regard to accrued and unpaid interest) plus (2) all required interest payments due on such note through June 1, 2010, computed using a discount rate equal to the Treasury Rate plus 50 basis points, over (B) the principal amount of such Note.

“Treasury Rate” means, with respect to a redemption date, the yield to maturity at the time of computation of United States Treasury securities with a constant maturity (as compiled and published in the most recent Federal Reserve Statistical Release H.15 (519) that has become publicly available at least two business days prior to the redemption date (or, if such Statistical Release is no longer published, any publicly available source or similar market data)) most nearly equal to the period from the redemption date to June 1, 2010; provided, however, that if the period from the redemption date to June 1, 2010 is not equal to the constant maturity of a United States Treasury security for which a weekly average yield is given, the Treasury Rate shall be obtained by linear interpolation (calculated to the nearest one-twelfth of a year) from the weekly average yields of United States Treasury securities for which such yields are given, except that if the period from the redemption date to the final maturity of the Notes is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year shall be used.

Optional Redemption Upon a Change of Control. If a Change of Control occurs at any time prior to December 1, 2008, the Company may, at its option, redeem all, but not less than all, of the Notes upon not less than 30 nor more than 60 days’ prior notice, at a redemption price equal to the sum of 112.750% of the principal of the Notes as of the redemption date, and accrued and unpaid interest, if any, to the date of redemption (subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date). If the Company elects to exercise the redemption right set forth in this paragraph (the “Change of Control Redemption Right”), it must do so by mailing a notice to each Holder with a copy to the trustee within 60 days following the Change of Control (or, at the Company’s option, prior to such Change of Control but after the transaction giving rise to such Change of Control is publicly announced). Any such redemption may be conditioned upon the Change of Control occurring if the notice is mailed prior to the Change of Control. If the Company exercises the Change of Control Redemption Right, it may elect not to make a Change of Control Offer as described below under “—Repurchase at the Option of Holders—Change of Control”.

Except as provided above, the notes will not be redeemable at the Company’s option prior to their final maturity.

Selection and Notice

If less than all of the Notes are to be redeemed at any time, the trustee will select notes for redemption as follows:

(1) if the relevant Notes are listed on any national securities exchange, in compliance with the requirements of the principal national securities exchange on which the Notes are listed; or

(2) if the relevant Notes are not listed on any national securities exchange, on a pro rata basis.

No Notes of $2,000 or less can be redeemed in part. Notices of redemption will be mailed by first class mail at least 30 but not more than 60 days before the redemption date to each Holder of Notes to be redeemed at its registered address, except that redemption notices may be mailed more than 60 days prior to a redemption date if the notice is issued in connection with a defeasance of the Notes or a satisfaction and discharge of the indenture.

If any Note is to be redeemed in part only, the notice of redemption that relates to that Note will state the portion of the principal amount of that Note that is to be redeemed. A new note in principal amount equal to the

 

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unredeemed portion of the original note will be issued in the name of the Holder of Notes upon cancellation of the original note. Notes called for redemption become due on the date fixed for redemption. On and after the redemption date, interest ceases to accrue on Notes or portions of them called for redemption.

Mandatory Redemption; Open Market Purchases

Except as set forth below under “—Repurchase at the Option of Holders,” the Company is not required to make mandatory redemption or sinking fund payments with respect to the Notes or to repurchase the Notes at the option of the Holders. The Company may at any time and from time to time purchase Notes in the open market or otherwise.

Repurchase at the Option of Holders

Change of Control

If a Change of Control occurs, each Holder of Notes will have the right to require the Company to repurchase all or any part (equal to $2,000 or an integral multiple of $1,000 in excess thereof) of that Holder’s Notes pursuant to a Change of Control Offer on the terms set forth in the indenture. In the Change of Control Offer, the Company will offer a Change of Control Payment in cash equal to 101% of the aggregate principal amount of Notes repurchased plus accrued and unpaid interest, if any, on the Notes repurchased, to the date of settlement (the “Change of Control Purchase Date”), subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the Change of Control Purchase Date. Within 30 days following any Change of Control, the Company will mail a notice to each Holder and the Trustee describing the transaction or transactions that constitute the Change of Control and offering to repurchase Notes as of the Change of Control Purchase Date specified in the notice, which date will be no earlier than 30 days and no later than 60 days from the date such notice is mailed, pursuant to the procedures required by the indenture and described in such notice.

The Company will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with the repurchase of the Notes as a result of a Change of Control. To the extent that the provisions of any securities laws or regulations conflict with the Change of Control provisions of the indenture, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Change of Control provisions of the indenture by virtue of such conflict.

On the Change of Control Purchase Date, the Company will, to the extent lawful, accept for payment all Notes or portions of Notes properly tendered pursuant to the Change of Control Offer. Promptly thereafter the Company will:

(1) deposit with the paying agent an amount equal to the Change of Control Payment in respect of all Notes or portions of Notes properly tendered; and

(2) deliver or cause to be delivered to the trustee the Notes properly accepted together with an officers’ certificate stating the aggregate principal amount of Notes or portions of Notes being purchased by the Company.

Promptly after the Change of Control Purchase Date, the paying agent will mail to each Holder of Notes properly tendered the Change of Control Payment for such Notes (or, if all the Notes are then in global form, make such payment through the facilities of DTC), and the trustee will authenticate and mail (or cause to be transferred by book entry) to each Holder a new note equal in principal amount to any unpurchased portion of the Notes surrendered, if any; provided that each new note will be in a principal amount of $2,000 or an integral multiple of $1,000 in excess thereof. The Company will publicly announce the results of the Change of Control Offer on or as soon as practicable after the Change of Control Payment Date.

The occurrence of a Change of Control may result in a default under the Credit Agreement and may cause a default under other Indebtedness of the Parent, the Company and their Subsidiaries, and give the lenders thereunder the right to require the repayment of obligations outstanding thereunder. Moreover, the exercise by Holders of their right to require the Company to repurchase the Notes could cause a default under such Indebtedness, even if the Change of Control itself does not, due to the financial effect of such repurchase on the Company. The Company’s

 

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ability to repurchase Notes following a Change of Control also may be limited by the Company’s then existing financial resources. Prior to complying with any of the provisions of this “Change of Control” covenant, but in any event no later than the Change of Control Purchase Date, the Company or the Parent will, to the extent necessary, either repay all outstanding Credit Facilities or obtain any requisite consents under all agreements governing outstanding Credit Facilities to permit the repurchase of Notes required by this covenant.

The provisions described above that require the Company to make a Change of Control Offer following a Change of Control will be applicable whether or not any other provisions of the indenture are applicable. Except as described above with respect to a Change of Control, the indenture does not contain provisions that permit the Holders of the Notes to require that the Company repurchase or redeem the Notes in the event of a takeover, recapitalization or similar transaction.

The Company will not be required to make a Change of Control Offer upon a Change of Control if a third party makes the Change of Control Offer in the manner, at the time and otherwise in compliance with the requirements set forth in the indenture applicable to a Change of Control Offer made by the Company and purchases all Notes properly tendered and not withdrawn under the Change of Control Offer.

The definition of Change of Control includes a phrase relating to the direct or indirect sale, lease, transfer, conveyance or other disposition of “all or substantially all” of the properties or assets of the Parent and its Restricted Subsidiaries taken as a whole. Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a Holder of Notes to require the Company to repurchase its Notes as a result of a sale, lease, transfer, conveyance or other disposition of less than all of the assets of the Parent and its Subsidiaries taken as a whole to another Person or group may be uncertain.

Asset Sales

The Parent will not, and will not permit any of its Restricted Subsidiaries to, consummate an Asset Sale unless:

(1) the Parent (or the Restricted Subsidiary, as the case may be) receives consideration at the time of the Asset Sale at least equal to the fair market value of the assets or Equity Interests issued or sold or otherwise disposed of;

(2) the fair market value is determined by the Parent’s or Company’s Board of Directors and evidenced by a resolution of such Board of Directors set forth in an officers’ certificate delivered to the trustee; and

(3) at least 75% of the consideration received by the Parent or such Restricted Subsidiary from all Asset Sales since the Issue Date, in the aggregate, is in the form of cash. For purposes of this provision, each of the following will be deemed to be cash:

(a) any liabilities, as shown on the Parent’s or such Restricted Subsidiary’s most recent balance sheet, of the Parent or any Restricted Subsidiary (other than contingent liabilities and liabilities that are by their terms subordinated to the Notes or any Guarantee) that are assumed by the transferee of any such assets pursuant to a customary novation agreement that releases the Parent or such Restricted Subsidiary from further liability; and

(b) any securities, notes or other obligations received by the Parent or any such Restricted Subsidiary from such transferee that are converted within 90 days by the Parent or such Restricted Subsidiary into cash, to the extent of the cash received in that conversion.

On the 30th day after a Major Asset Sale (or, at the Company’s option, any earlier date), the Company will make an Asset Sale Offer to all Holders of Notes, and all holders of other Indebtedness that is pari passu with the Notes containing provisions similar to those set forth in the indenture with respect to offers to purchase or redeem with the proceeds of sales of assets, to purchase the maximum principal amount of Notes and such other pari passu Indebtedness that may be purchased out of the Net Proceeds of such Major Asset Sale. The offer price in any such Asset Sale Offer will be equal to 106.375% of principal amount (if such Asset Sale Offer is made prior to June 1, 2011), 103.188% of principal amount (if such Asset Sale Offer is made on or after June 1, 2011 and prior to June 1,

 

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2012), or 100% of principal amount (if such Asset Sale Offer is made on or after June 1, 2012) plus, in each case, accrued and unpaid interest, if any, to the date of settlement, subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the date of settlement, and will be payable in cash. If any Net Proceeds from a Major Asset Sale remain after consummation of such an Asset Sale Offer, the Company may use those Net Proceeds for any purpose not otherwise prohibited by the indenture. If the aggregate principal amount of Notes and other pari passu Indebtedness tendered into such Asset Sale Offer exceeds the amount of Net Proceeds, the trustee will select the Notes and such other pari passu Indebtedness to be purchased on a pro rata basis. Pending the final application of any such Net Proceeds, the Parent or any such Restricted Subsidiary may temporarily reduce revolving credit borrowings or otherwise invest the Net Proceeds in any manner that is not prohibited by the indenture. Prior to making any such Asset Sale Offer, the Parent or any such Restricted Subsidiary may also apply all or any part of such Net Proceeds to repay, redeem or repurchase Senior Debt under Credit Facilities (provided that, if such Senior Debt is revolving credit Indebtedness, the commitments with respect thereto must be correspondingly reduced), and in such event the portion of such Net Proceeds required to be used to make such Asset Sale Offer shall be correspondingly reduced.

During the 360 days after the receipt of any Net Proceeds from an Asset Sale other than a Major Asset Sale, the Parent or any such Restricted Subsidiary may apply those Net Proceeds at its option to any combination of the following:

(i) to repay, redeem or repurchase Senior Debt (other than intercompany Indebtedness) provided that, if such Senior Debt is revolving credit Indebtedness, the commitments with respect thereto must be correspondingly reduced;

(ii) to acquire all or substantially all of the properties or assets of one or more other Persons primarily engaged in the Oil and Gas Business, and, for this purpose, a division or line of business of a Person shall be treated as a separate Person;

(iii) to acquire a majority of the Voting Stock of one or more other Persons primarily engaged in the Oil and Gas Business;

(iv) to make one or more capital expenditures; or

(v) to acquire other long-term assets that are used or useful in the Oil and Gas Business.

Pending the final application of any such Net Proceeds, the Parent or any such Restricted Subsidiary may temporarily reduce revolving credit borrowings or otherwise invest the Net Proceeds in any manner that is not prohibited by the indenture. Any Net Proceeds from Asset Sales (other than Major Asset Sales) that are not applied or invested as provided in the preceding paragraph will constitute “Excess Proceeds”.

On the 361st day after any Asset Sale other than a Major Asset Sale (or, at the Company’s option, any earlier date), if the aggregate amount of Excess Proceeds then exceeds $10.0 million, the Company will make an Asset Sale Offer to all Holders of Notes, and all holders of other Indebtedness that is pari passu with the Notes containing provisions similar to those set forth in the indenture with respect to offers to purchase or redeem with the proceeds of sales of assets, to purchase the maximum principal amount of Notes and such other pari passu Indebtedness that may be purchased out of the Excess Proceeds. The offer price in any such Asset Sale Offer will be equal to 100% of principal amount plus accrued and unpaid interest, if any, to the date of settlement, subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the date of settlement, and will be payable in cash. If any Excess Proceeds remain after consummation of such an Asset Sale Offer, the Company may use those Excess Proceeds for any purpose not otherwise prohibited by the indenture. If the aggregate principal amount of Notes and other pari passu Indebtedness tendered into such Asset Sale Offer exceeds the amount of Excess Proceeds, the trustee will select the Notes and such other pari passu Indebtedness to be purchased on a pro rata basis. Upon completion of each such Asset Sale Offer, the amount of Excess Proceeds will be reset at zero.

The Company will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with each repurchase of Notes pursuant to an Asset Sale Offer. To the extent that the provisions of any securities laws or

 

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regulations conflict with the Asset Sale provisions of the indenture, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Asset Sale provisions of the indenture by virtue of such conflict.

Certain Covenants

Restricted Payments

The Parent will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly:

(1) declare or pay any dividend or make any other payment or distribution on account of the Parent’s or any of its Restricted Subsidiaries’ Equity Interests (including, without limitation, any payment by the Parent in connection with any merger or consolidation involving the Parent or any of its Restricted Subsidiaries) or to the direct or indirect holders of the Parent’s or any of its Restricted Subsidiaries’ Equity Interests in their capacity as such (other than dividends or distributions payable in Equity Interests (other than Disqualified Stock) of the Parent or payable to the Parent or a Restricted Subsidiary of the Parent);

(2) purchase, redeem or otherwise acquire or retire for value (including, without limitation, in connection with any merger or consolidation involving the Parent) any Equity Interests of the Parent or any direct or indirect parent of the Parent;

(3) make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value any Indebtedness that is subordinated to the Notes or the Guarantees, except a payment of interest or principal at the Stated Maturity thereof; or

(4) make any Restricted Investment (all such payments and other actions set forth in these clauses (1) through (4) above being collectively referred to as “Restricted Payments”),

unless, at the time of and after giving effect to such Restricted Payment:

(1) no Default or Event of Default has occurred and is continuing or would occur as a consequence of such Restricted Payment;

(2) the Parent would, at the time of such Restricted Payment and after giving pro forma effect thereto as if such Restricted Payment had been made at the beginning of the applicable four-quarter period, have been permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described below under the caption “—Incurrence of Indebtedness and Issuance of Preferred Stock;” and

(3) such Restricted Payment, together with the aggregate amount of all other Restricted Payments made by the Parent and its Restricted Subsidiaries after the date of the indenture (excluding Restricted Payments permitted by clauses (2) through (9) of the next succeeding paragraph), is less than the sum, without duplication, of:

(a) 50% of the Consolidated Net Income of the Parent for the period (taken as one accounting period) from January 1, 2008 to the end of the Parent’s most recently ended fiscal quarter for which internal financial statements are available at the time of such Restricted Payment (or, if such Consolidated Net Income for such period is a deficit, less 100% of such deficit), plus

(b) 100% of the aggregate net proceeds received by the Parent (including the fair market value of any Additional Assets to the extent acquired in exchange for Equity Interests of the Parent (other than Disqualified Stock)) since the Issue Date as a contribution to its common equity capital or from the issue or sale of Equity Interests of the Parent (other than Disqualified Stock) or from the issue or sale of convertible or exchangeable Disqualified Stock or convertible or exchangeable debt securities of the Parent that have been converted into or exchanged for such Equity Interests (other than Equity Interests (or Disqualified Stock or debt securities) sold to a Subsidiary of the Parent), plus

 

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(c) to the extent that any Restricted Investment that was made after the Issue Date is sold for cash or otherwise liquidated or repaid for cash, the lesser of (i) the cash return of capital with respect to such Restricted Investment (less the cost of disposition, if any) and (ii) the initial amount of such Restricted Investment, plus

(d) to the extent that any Unrestricted Subsidiary of the Parent is redesignated as a Restricted Subsidiary after the Issue Date, the lesser of (i) the fair market value of the Parent’s Investment in such Subsidiary as of the date of such redesignation or (ii) such fair market value as of the date on which such Subsidiary was originally designated as an Unrestricted Subsidiary.

So long as no Default or Event of Default has occurred and is continuing or would be caused thereby, the preceding provisions will not prohibit:

(1) the payment of any dividend within 60 days after the date of declaration of the dividend, if at the date of declaration the dividend payment would have complied with the provisions of the indenture;

(2) the purchase, redemption, defeasance or other acquisition or retirement of any subordinated Indebtedness of the Parent, the Company or any Subsidiary Guarantor or of any Equity Interests of the Parent in exchange for, or out of the net cash proceeds of the substantially concurrent sale (other than to a Subsidiary of the Parent) of, Equity Interests of the Parent (other than Disqualified Stock); provided that the amount of any such net cash proceeds that are utilized for any such redemption, repurchase, retirement, defeasance or other acquisition will be excluded from clause (3)(b) of the preceding paragraph;

(3) the purchase, redemption, defeasance or other acquisition or retirement of subordinated Indebtedness of the Parent, the Company or any Subsidiary Guarantor with the net cash proceeds from an incurrence of, or in exchange for, Permitted Refinancing Indebtedness;

(4) the payment of any dividend by a Restricted Subsidiary of the Parent to the holders of its Equity Interests on a pro rata basis;

(5) the purchase, redemption or other acquisition or retirement for value of any Equity Interests of the Parent or any direct or indirect parent of the Parent held by any current or former director or employee of the Parent or any direct or indirect parent pursuant to any director or employee equity subscription agreement or plan, stock option agreement or similar agreement or plan; provided that the aggregate price paid for all such purchased, redeemed, acquired or retired Equity Interests may not exceed $500,000 in any calendar year, plus the amount of any such allowance not used in any prior calendar year;

(6) the acquisition of Equity Interests by the Parent in connection with the exercise of stock options or stock appreciation rights by way of cashless exercise;

(7) upon the occurrence of a Change of Control or an Asset Sale and within 60 days after the completion of the offer to repurchase the Notes under the covenants described under “—Repurchase at the Option of Holders—Change of Control” or “—Asset Sales” above (including the purchase of all Notes tendered), any purchase, redemption, defeasance or other acquisition or retirement for value of subordinated Indebtedness required under the terms thereof as a result of such Change of Control or Asset Sale at a price not to exceed 101% of the outstanding principal amount thereof, plus accrued and unpaid interest thereon, if any, provided that, in the notice to Holders relating to a Change of Control or Asset Sale hereunder, the Company shall describe this clause (7);

(8) the payment of cash in lieu of fractional shares of Capital Stock in connection with any transaction otherwise permitted under the indenture; and

(9) other Restricted Payments in an aggregate amount since the Issue Date not to exceed $3.0 million.

The amount of all Restricted Payments (other than cash) will be the fair market value on the date of the Restricted Payment of the asset(s) or securities proposed to be transferred or issued by the Parent or such Restricted Subsidiary, as the case may be, pursuant to the Restricted Payment. The fair market value of any assets or securities

 

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that are required to be valued by this covenant will be determined by the Board of Directors of the Parent, whose determination shall be evidenced by a Board Resolution. The Board of Directors’ determination must be based upon an opinion or appraisal issued by an accounting, appraisal or investment banking firm of national standing if the fair market value exceeds $25.0 million. Not later than the date of making any Restricted Payment under the first paragraph of this covenant the Company will deliver to the trustee an officers’ certificate stating that such Restricted Payment is permitted and setting forth the basis upon which the calculations required by this “Restricted Payments” covenant were computed, together with a copy of any fairness opinion or appraisal required by the indenture. For purposes of determining compliance with this “Restricted Payments” covenant, in the event that a Restricted Payment meets the criteria of more than one of the categories of Restricted Payments described in the preceding clauses (1) – (9), the Parent will be permitted to classify (or later classify or reclassify in whole or in part in its sole discretion) such Restricted Payment in any manner that complies with this covenant.

Incurrence of Indebtedness and Issuance of Preferred Stock

The Parent will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur, issue, assume, guarantee or otherwise become directly or indirectly liable, contingently or otherwise, with respect to (collectively, “incur”) any Indebtedness (including Acquired Debt), neither the Parent, the Company nor any Subsidiary Guarantor will issue any Disqualified Stock, and the Parent will not permit any of its other Restricted Subsidiaries to issue any shares of preferred stock; provided, however, that the Parent, the Company and any Subsidiary Guarantor may incur Indebtedness (including Acquired Debt) or issue Disqualified Stock, if the Fixed Charge Coverage Ratio for the Parent’s most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date on which such additional Indebtedness is incurred or such Disqualified Stock is issued would have been at least 2.0 to 1.0, determined on a pro forma basis (including a pro forma application of the net proceeds therefrom), as if the additional Indebtedness had been incurred or Disqualified Stock had been issued, as the case may be, at the beginning of such four-quarter period.

The first paragraph of this covenant will not prohibit the incurrence of any of the following items of Indebtedness (collectively, “Permitted Debt”):

(1) the incurrence by the Parent or any Restricted Subsidiary of Indebtedness under one or more Credit Facilities in an aggregate principal amount at any one time outstanding under this clause (1) not to exceed an amount equal to the greater of (a) $25.0 million and (b) 15.0% of ACNTA as of the date of such incurrence;

(2) the incurrence by the Parent or any of its Restricted Subsidiaries of the Existing Indebtedness;

(3) the incurrence by the Parent, the Company and the Subsidiary Guarantors of Indebtedness represented by the Notes issued and sold in this offering and the related Guarantees to be issued on the date of the indenture and the Exchange Notes and the related Guarantees issued pursuant to any registration rights agreement;

(4) the incurrence by the Parent or any of its Restricted Subsidiaries of Indebtedness represented by Capital Lease Obligations, Attributable Debt, mortgage financings or purchase money obligations, in each case, incurred for the purpose of financing all or any part of the purchase price or cost of construction or improvement of property, plant or equipment used in the business of the Parent or such Restricted Subsidiary, in an aggregate principal amount, including all Permitted Refinancing Indebtedness incurred to extend, refinance, renew, replace, defease or refund Indebtedness incurred pursuant to this clause (4), not to exceed $5.0 million at any time outstanding;

(5) the incurrence by the Parent or any of its Restricted Subsidiaries of Permitted Refinancing Indebtedness in exchange for, or the net proceeds of which are used to extend, refinance, renew, replace, defease or refund Indebtedness (other than intercompany Indebtedness) that was permitted by the indenture to be incurred under the first paragraph of this covenant or clause (2), (3) or (11) of this paragraph or this clause (5);

(6) the incurrence by the Parent or any of its Restricted Subsidiaries of intercompany Indebtedness between or among the Parent and any of its Restricted Subsidiaries; provided, however, that:

(a) if the Company is the obligor on such Indebtedness and the Parent or a Subsidiary Guarantor is not the obligee, such Indebtedness must be expressly subordinated to the prior payment in full in cash of all

 

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Obligations with respect to the Notes, or if the Parent or a Subsidiary Guarantor is the obligor on such Indebtedness and neither the Parent, the Company nor another Subsidiary Guarantor is the obligee, such Indebtedness must be expressly subordinated to the prior payment in full in cash of all Obligations with respect to the Guarantee of the Parent or such Subsidiary Guarantor, as the case may be; and

(b) (i) any subsequent issuance or transfer of Equity Interests that results in any such Indebtedness being held by a Person other than the Parent or a Restricted Subsidiary of the Parent and (ii) any sale or other transfer of any such Indebtedness to a Person that is neither the Parent nor a Restricted Subsidiary of the Parent will be deemed, in each case, to constitute an incurrence of such Indebtedness by the Parent or such Restricted Subsidiary, as the case may be, that was not permitted by this clause (6);

(7) the incurrence by the Parent or any of its Restricted Subsidiaries of Hedging Obligations;

(8) the guarantee by the Parent, the Company or any of the Subsidiary Guarantors of Indebtedness of the Parent, the Company or any Subsidiary Guarantor that was permitted to be incurred by another provision of this covenant;

(9) the incurrence by the Parent or any of its Restricted Subsidiaries of obligations relating to net gas balancing positions arising in the ordinary course of business and consistent with past practice;

(10) the incurrence by the Parent or any of its Restricted Subsidiaries of Indebtedness in respect of bid, performance, surety and similar bonds issued for the account of the Parent and any of its Restricted Subsidiaries in the ordinary course of business, including guarantees and obligations of the Parent and any of its Restricted Subsidiaries with respect to letters of credit supporting such obligations (in each instance other than an obligation for money borrowed);

(11) Indebtedness of a Restricted Subsidiary (other than the Company) incurred and outstanding on the date on which such Restricted Subsidiary was acquired by, or merged into, the Parent or any Restricted Subsidiary (other than Indebtedness Incurred (a) to provide all or any portion of the funds utilized to consummate the transaction or series of related transactions pursuant to which such Restricted Subsidiary became a Restricted Subsidiary or was otherwise acquired by the Parent or (b) otherwise in connection with, or in contemplation of, such acquisition); provided, however, that at the time such Restricted Subsidiary is acquired by the Parent, the Parent would have been able to incur $1.00 of additional Indebtedness pursuant to the first paragraph of this covenant after giving effect to the incurrence of such Indebtedness pursuant to this clause (11);

(12) the incurrence by the Parent or any of its Restricted Subsidiaries of Indebtedness arising from agreements of the Parent or any of its Restricted Subsidiaries providing for indemnification, adjustment of purchase price or similar obligations, in each case, incurred or assumed in connection with the disposition of any business, assets or Capital Stock of a Subsidiary, provided that the maximum aggregate liability in respect of all such Indebtedness shall at no time exceed the gross proceeds actually received by the Parent and its Restricted Subsidiaries in connection with such disposition; and

(13) the incurrence by the Parent or any of its Restricted Subsidiaries of additional Indebtedness in an aggregate principal amount (or accreted value, as applicable) at any time outstanding, not to exceed $5.0 million.

For purposes of determining compliance with this “Incurrence of Indebtedness and Issuance of Preferred Stock” covenant, in the event that an item of Indebtedness (including Acquired Debt) meets the criteria of more than one of the categories of Permitted Debt described in clauses (1) through (13) above, or is entitled to be incurred pursuant to the first paragraph of this covenant, the Parent will be permitted to classify (or later classify or reclassify in whole or in part in its sole discretion) such item of Indebtedness in any manner that complies with this covenant.

The amount of Indebtedness issued at a price that is less than the principal amount thereof will be equal to the amount of the liability in respect thereof determined in accordance with GAAP. Indebtedness of any Person existing at the time such Person becomes a Restricted Subsidiary shall be deemed to have been incurred by the Parent and the Restricted Subsidiary at the time such Person becomes a Restricted Subsidiary. The accrual of interest, the accretion or amortization of original issue discount, the payment of interest on any Indebtedness in the form of

 

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additional Indebtedness with the same terms, and the payment of dividends on Disqualified Stock in the form of additional shares of the same class of Disqualified Stock will not be deemed to be an incurrence of Indebtedness or an issuance of Disqualified Stock for purposes of this covenant; provided, in each such case, that the amount thereof is included in Fixed Charges of the Parent as accrued.

Liens

The Parent will not and will not permit any of its Restricted Subsidiaries to, create, incur, assume or otherwise cause or suffer to exist or become effective any Lien of any kind (other than Permitted Liens) securing Indebtedness or Attributable Debt upon any of their property or assets, now owned or hereafter acquired.

Dividend and Other Payment Restrictions Affecting Subsidiaries

The Parent will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create or permit to exist or become effective any consensual encumbrance or restriction on the ability of any Restricted Subsidiary to:

(1) pay dividends or make any other distributions on its Capital Stock to the Parent or any of its Restricted Subsidiaries, or pay any Indebtedness or other obligations owed to the Parent or any of its Restricted Subsidiaries;

(2) make loans or advances to the Parent or any of its Restricted Subsidiaries; or

(3) transfer any of its properties or assets to the Parent or any of its Restricted Subsidiaries.

However, the preceding restrictions will not apply to encumbrances or restrictions existing under or by reason of:

(1) agreements governing Existing Indebtedness and Credit Facilities as in effect on the Issue Date and any amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings of those agreements, provided that the amendments, modifications, restatements, renewals, increases, supplements, refundings, replacement or refinancings are not materially more restrictive, taken as a whole, with respect to such dividend and other payment restrictions than those contained in those agreements on the date of the indenture;

(2) the indenture, the Notes, the Collateral Agreements and the Guarantees;

(3) applicable law;

(4) any instrument governing Indebtedness or Capital Stock of a Person acquired by the Parent or any of its Restricted Subsidiaries as in effect at the time of such acquisition, which encumbrance or restriction is not applicable to any Person, or the properties or assets of any Person, other than the Person, or the property or assets of the Person, so acquired, provided that, in the case of Indebtedness, such Indebtedness was permitted by the terms of the indenture to be incurred;

(5) customary non-assignment provisions in leases entered into in the ordinary course of business and consistent with past practices;

(6) purchase money obligations for property acquired in the ordinary course of business that impose restrictions on that property of the nature described in clause (3) of the preceding paragraph;

(7) any agreement for the sale or other disposition of a Restricted Subsidiary of the Parent that restricts distributions by that Restricted Subsidiary pending its sale or other disposition;

(8) Permitted Refinancing Indebtedness, provided that the restrictions contained in the agreements governing such Permitted Refinancing Indebtedness are not materially more restrictive, taken as a whole, than those contained in the agreements governing the Indebtedness being refinanced;

 

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(9) agreements governing other Indebtedness of the Parent and one or more Restricted Subsidiaries permitted under the indenture, provided that the restrictions in the agreements governing such Indebtedness are not materially more restrictive, taken as a whole, than those in the indenture;

(10) Liens permitted to be incurred under the provisions of the covenant described above under the caption “—Liens” that limit the right of the debtor to dispose of the assets subject to such Liens;

(11) provisions with respect to the disposition or distribution of assets or property in joint venture agreements, asset sale agreements, stock sale agreements, agreements respecting Permitted Business Investments and other similar agreements entered into in the ordinary course of business; and

(12) restrictions on cash or other deposits or net worth imposed by customers under contracts entered into in the ordinary course of business.

Merger, Consolidation or Sale of Assets

Neither the Company nor the Parent may, directly or indirectly: (1) consolidate or merge with or into another Person; or (2) sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of the properties or assets of the Parent and its Restricted Subsidiaries taken as a whole, in one or more related transactions, to another Person, unless:

(1) either: (a) the Parent or the Company, as applicable, is the surviving corporation; or (b) the Person formed by or surviving any such consolidation or merger (if other than the Company) or to which such sale, assignment, transfer, lease, conveyance or other disposition has been made is a corporation organized or existing under the laws of Canada, any province thereof, the United States, any state of the United States or the District of Columbia;

(2) the Person formed by or surviving any such consolidation or merger (if other than the Company or the Parent, as applicable) or the Person to which such sale, assignment, transfer, lease, conveyance or other disposition has been made assumes all the obligations of the Company or the Parent, as applicable, under the Notes, the indenture, the registration rights agreement, the Parent’s Guarantee and the Collateral Agreements, as applicable, pursuant to agreements reasonably satisfactory to the trustee and the collateral agent, as applicable (it being agreed that if the Company is merged into the Parent, the Parent must assume all such obligations of the Company);

(3) immediately after such transaction no Default or Event of Default exists;

(4) except with respect to a transaction solely between the Parent, the Company and/or any Subsidiary Guarantor, either (a) the Parent or the Person formed by or surviving any such consolidation or merger (if other than the Parent), or to which such sale, assignment, transfer, lease, conveyance or other disposition has been made will, on the date of such transaction after giving pro forma effect thereto and any related financing transactions as if the same had occurred at the beginning of the applicable four-quarter period, be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described above under the caption “—Incurrence of Indebtedness and Issuance of Preferred Stock”; or (b) the Fixed Charge Coverage Ratio of the Parent or the surviving or transferee entity, as applicable, after giving pro forma effect to such transaction, is greater than or equal to the Parent’s Fixed Charge Coverage Ratio immediately prior to such transaction; and

(5) the Company or the Parent shall have delivered to the trustee an officers’ certificate and an opinion of counsel, each stating that such consolidation, merger or disposition and such supplemental indenture (if any) comply with the indenture.

Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve “all or substantially all” of the properties or assets of a Person.

 

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Transactions with Affiliates

The Parent will not, and will not permit any of its Restricted Subsidiaries to, make any payment to, or sell, lease, transfer or otherwise dispose of any of its properties or assets to, or purchase any property or assets from, or enter into or make or amend any transaction, contract, agreement, understanding, loan, advance or guarantee with, or for the benefit of, any Affiliate (each, an “Affiliate Transaction”), unless:

(1) the Affiliate Transaction is on terms that are no less favorable to the Parent or the relevant Restricted Subsidiary than those that would have been obtained in a comparable transaction by the Parent or such Restricted Subsidiary with an unrelated Person; and

(2) the Parent delivers to the trustee:

(a) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $5.0 million, a resolution of the Board of Directors set forth in an officers’ certificate certifying that such Affiliate Transaction complies with this covenant and that such Affiliate Transaction has been approved by a majority of the disinterested members of the Board of Directors; and

(b) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $20.0 million, the Parent delivers to the Trustee a written opinion that such Affiliate Transaction(s) is fair, from a financial point of view, to the Parent and its Restricted Subsidiaries, taken as a whole, or that such Affiliate Transaction(s) is not less favorable to the Parent and its Restricted Subsidiaries than could reasonably be expected to be obtained at the time in an arm’s-length transaction with a person who is not an Affiliate, in either such case issued by an independent accounting, appraisal or investment banking firm of national standing.

The following items will not be deemed to be Affiliate Transactions and, therefore, will not be subject to the provisions of the prior paragraph:

(1) any employment or severance agreement or other employee compensation agreement, arrangement or plan, or any amendment thereto, entered into by the Parent or any of its Restricted Subsidiaries in the ordinary course of business;

(2) transactions between or among any of the Parent and its Restricted Subsidiaries;

(3) transactions with a Person that is an Affiliate of the Parent solely because the Parent directly or indirectly owns an Equity Interest in such Person;

(4) payment of reasonable directors’ fees and other benefits to persons who are not otherwise Affiliates of the Parent;

(5) provision of officers’ and directors’ indemnification and insurance in the ordinary course of business to the extent permitted by law;

(6) sales of Equity Interests (other than Disqualified Stock) in the Parent to Affiliates of the Parent; and

(7) Permitted Investments or Restricted Payments that are permitted by the provisions of the indenture described above under the caption “—Restricted Payments”.

Designation of Restricted and Unrestricted Subsidiaries

The Board of Directors of the Parent may designate any Restricted Subsidiary of the Parent (other than the Company) to be an Unrestricted Subsidiary if that designation would not cause a Default. If a Restricted Subsidiary of the Parent is designated as an Unrestricted Subsidiary, the aggregate fair market value of all outstanding Investments owned by the Parent and its Restricted Subsidiaries in the Subsidiary properly designated will be deemed to be an Investment made as of the time of the designation and will reduce the amount available for Restricted Payments under the first paragraph of the covenant described above under the caption “—Restricted

 

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Payments” or represent Permitted Investments, as determined by the Parent. That designation will only be permitted if the Investment would be permitted at that time and if the Subsidiary so designated otherwise meets the definition of an Unrestricted Subsidiary.

The Board of Directors of the Parent may at any time designate any Unrestricted Subsidiary to be a Restricted Subsidiary of the Parent; provided that such designation will be deemed to be an incurrence of Indebtedness by a Restricted Subsidiary of the Parent of any outstanding Indebtedness of such Unrestricted Subsidiary and such designation will only be permitted if (1) such Indebtedness is permitted under the covenant described above under the caption “—Incurrence of Indebtedness and Issuance of Preferred Stock,” calculated on a pro forma basis as if such designation had occurred at the beginning of the four-quarter reference period, and (2) no Default or Event of Default would be in existence following such designation.

Additional Guarantees

If the Parent or any of its Restricted Subsidiaries acquires or creates another Material Domestic Subsidiary after the Issue Date, or if any Restricted Subsidiary, other than the Company, that is not already a Subsidiary Guarantor guarantees any other Indebtedness of the Parent or the Company after such date, then in either case that Subsidiary will become a Subsidiary Guarantor by executing a supplemental indenture, and, to the extent it holds assets required to be Collateral, one or more Collateral Agreements or supplements or amendments thereto needed to grant to the collateral agent the Liens required to be granted pursuant to the indenture, and delivering them to the trustee within 20 Business Days of the date on which it was acquired or created or guaranteed Indebtedness of the Parent, as the case may be; provided, however, that the foregoing shall not apply to Subsidiaries of the Parent that have properly been designated as Unrestricted Subsidiaries in accordance with the indenture for so long as they continue to constitute Unrestricted Subsidiaries. In addition to the foregoing, if, after the Issue Date, any of the interests in the PEL 238, PEL 433, PEL 434, or EL 4416 licenses that are owned by the Parent or its Restricted Subsidiaries as of the Issue Date (or any production licences issued in respect thereof) are transferred to a Restricted Subsidiary of Parent that is not a Subsidiary Guarantor, then such Restricted Subsidiary shall within 20 Business Days of such transfer execute a supplemental indenture under which it shall become a Subsidiary Guarantor. The Parent or Company or Subsidiary Guarantor, as applicable, will provide opinions of counsel and officers’ certificates specified in the indenture with respect to the foregoing.

Impairment of Security Interest

Subject to the Intercreditor Agreement, neither the Parent nor any of its Restricted Subsidiaries will take or omit to take any action which would adversely affect or impair in any material respect the Liens in favor of the collateral agent with respect to the Collateral, except as otherwise permitted or required by the Collateral Agreements or the indenture. Neither the Parent nor any of its Restricted Subsidiaries will enter into any agreement that requires the proceeds received from any sale of Collateral to be applied to repay, redeem, defease or otherwise acquire or retire any Indebtedness of any Person, other than the First Priority Claims and the Notes. The Parent shall, and shall cause the Company and each Subsidiary Guarantor to, at their sole cost and expense, execute and deliver all such agreements and instruments as the collateral agent or the trustee shall reasonably request to more fully or accurately describe the property intended to be Collateral or the obligations intended to be secured by the Collateral Agreements. The Parent shall, and shall cause the Company and each Subsidiary Guarantor to, at their sole cost and expense, file any such notice filings or other agreements or instruments as may be reasonably necessary or desirable under applicable law to perfect the Liens created by the Collateral Agreements at such times and at such places as the collateral agent or the trustee may reasonably request.

Business Activities

The Parent will not, and will not permit any Restricted Subsidiary to, engage in any business other than the Oil and Gas Business, except to such extent as would not be material to the Parent and its Restricted Subsidiaries taken as a whole.

 

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Reports

So long as any Notes are outstanding, the Parent will furnish to the trustee and, upon its request, to any of the Holders of Notes, within fifteen days after the deadline specified in the SEC’s rules for registrants that are not accelerated filers:

(1) all quarterly and annual financial information with respect to the Parent and its Subsidiaries that would be required to be contained in a filing with the SEC on Forms 10-Q and 10-K if the Parent were required to file such Forms, including a “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and, with respect to the annual information only, a report on the annual financial statements by the Parent’s certified independent accountants; and

(2) all current reports that would be required to be filed with the SEC on Form 8-K if the Parent were required to file such reports, except to the extent the Parent in good faith determines that any such report is not material to holders of Notes.

If the Parent has designated any of its Subsidiaries as Unrestricted Subsidiaries, then the quarterly and annual financial information required by the preceding paragraph will include a reasonably detailed presentation, either on the face of the financial statements or in the footnotes thereto, of the financial condition and results of operations of the Parent and its Restricted Subsidiaries separate from the financial condition and results of operations of the Unrestricted Subsidiaries of the Parent.

In addition, the Parent, the Company and the Subsidiary Guarantors have agreed that, for so long as any Notes remain outstanding, they will furnish to the Holders and to securities analysts and prospective investors in the Notes, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act.

Events of Default and Remedies

Each of the following is an Event of Default:

(1) default for 30 days in the payment when due of interest on the Notes;

(2) default in payment when due of the principal of, or premium, if any, on the Notes;

(3) failure by the Parent or the Company, as applicable, to comply with the provisions described under the captions “—Certain Covenants—Merger, Consolidation or Sale of Assets,” “—Repurchase at the Option of Holders—Asset Sales” or “—Repurchase at the Option of Holders—Change of Control;”

(4) failure by the Parent or any of its Restricted Subsidiaries to comply for 30 days after receipt of written notice from the trustee or the Holders of 25% in principal amount of the Notes with the provisions described under the captions “—Certain Covenants—Restricted Payments,” “—Incurrence of Indebtedness and Issuance of Preferred Stock,” “—Liens,” “—Dividends and Other Payment Restrictions Affecting Subsidiaries,” “—Transactions with Affiliates,” “—Additional Guarantees,” “—Impairment of Security Interest” and “—Business Activities;”

(5) failure by the Parent or the Company for 60 days after notice from the trustee or the Holders of 25% of the principal amount of the Notes outstanding to comply with any of the other agreements in the indenture or the Collateral Agreements (or 120 days with respect to the covenant described above under “–Certain Covenants—Reports”; provided, however, that beginning on the 61^st day after such notice that the Parent is not in compliance with the covenant described above under “–Certain Covenants—Reports”, additional interest at the rate of 0.25% per annum shall accrue on the Notes until such covenant is complied with);

(6) default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness for money borrowed by the Parent or any of its Restricted Subsidiaries (or the payment of which is guaranteed by the Parent or any of its Restricted Subsidiaries), whether such Indebtedness or guarantee now exists, or is created after the Issue Date, if that default:

(a) is caused by a failure to pay principal of, or interest or premium, if any, on such Indebtedness prior to the expiration of the grace period provided in such Indebtedness (a “Payment Default”); or

 

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(b) results in the acceleration of such Indebtedness prior to its Stated Maturity,

and, in each case, the principal amount of any such Indebtedness, together with the principal amount of any other such Indebtedness under which there has been a Payment Default or the maturity of which has been so accelerated, aggregates $5.0 million or more;

(7) failure by the Parent or any of its Restricted Subsidiaries to pay final judgments aggregating in excess of $5.0 million, which judgments are not paid, discharged or stayed (including a stay pending appeal) for a period of 60 days after the date of such final judgment (or, if later, the date when payment is due pursuant to such judgment);

(8) except as permitted by the indenture, any Guarantee shall be held in any judicial proceeding to be unenforceable or invalid or shall cease for any reason to be in full force and effect or any Guarantor, or any Person acting on behalf of any Guarantor, shall deny or disaffirm its obligations under its Guarantee;

(9) certain events of bankruptcy, insolvency or reorganization described in the indenture with respect to the Parent or any of its Significant Subsidiaries or any group of Subsidiaries of the Parent that, taken as a whole, would constitute a Significant Subsidiary; or

(10) except as provided in the indenture or any Collateral Agreement, any Collateral Agreement ceases to be in full force and effect in all material respects, or ceases to give the collateral agent the Liens, rights, powers and privileges purported to be created thereby in all material respects.

In the case of an Event of Default arising from certain events of bankruptcy, insolvency or reorganization, with respect to the Parent, any Subsidiary of the Parent that is a Significant Subsidiary or any group of Subsidiaries of the Parent that, taken together, would constitute a Significant Subsidiary, all outstanding Notes will become due and payable immediately without further action or notice. If any other Event of Default occurs and is continuing, the trustee or the Holders of at least 25% in principal amount of the then outstanding Notes may declare all the Notes to be due and payable immediately.

Holders of the Notes may not enforce the indenture or the Notes except as provided in the indenture. Subject to certain limitations, Holders of a majority in principal amount of the then outstanding Notes may direct the trustee in its exercise of any trust or power. The trustee may withhold notice of any continuing Default or Event of Default from Holders of the Notes if it determines that withholding notice is in their interest, except a Default or Event of Default relating to the payment of principal of, or interest or premium, if any, on, the Notes.

The Holders of a majority in principal amount of the Notes then outstanding by notice to the trustee may on behalf of the Holders of all of the Notes waive any past Default or Event of Default and its consequences under the indenture except a continuing Default or Event of Default in the payment of principal of, or interest or premium, if any, on the Notes or in respect of a covenant that cannot be amended without the consent of each Holder.

The Company is required to deliver to the trustee annually a statement regarding compliance with the indenture. Upon becoming aware of any Default or Event of Default, the Company is required to deliver to the trustee a statement specifying such Default or Event of Default.

No Personal Liability of Directors, Officers, Employees and Stockholders

No director, officer, employee, incorporator or stockholder or other owner of Capital Stock of the Company or any Guarantor, as such, will have any liability for any obligations of the Company or any Guarantor under the Notes, the indenture or the Guarantees, or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. The waiver may not be effective to waive liabilities under the federal securities laws.

 

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Legal Defeasance and Covenant Defeasance

The Company may, at its option and at any time, elect to have all of its obligations discharged with respect to the Notes and all obligations of the Guarantors discharged with respect to their Guarantees (“Legal Defeasance”) except for:

(1) the rights of Holders of outstanding Notes to receive payments in respect of the principal of, and interest or premium, if any, on such Notes when such payments are due from the trust referred to below;

(2) the Company’s obligations with respect to the Notes concerning issuing temporary notes, registration of Notes, mutilated, destroyed, lost or stolen notes and the maintenance of an office or agency for payment and money for security payments held in trust;

(3) the rights, powers, trusts, duties and immunities of the trustee, and the Company’s obligations in connection therewith; and

(4) the Legal Defeasance provisions of the indenture.

In addition, the Company may, at its option and at any time, elect to have its and the Parent’s obligations released with respect to certain covenants that are described in the indenture (“Covenant Defeasance”) and thereafter any omission to comply with those covenants will not constitute a Default or Event of Default with respect to the Notes. In the event Covenant Defeasance occurs, certain events (not including non-payment, bankruptcy, insolvency or reorganization events) described under “—Events of Default and Remedies” will no longer constitute an Event of Default with respect to the Notes. If the Company exercises either its Legal Defeasance or Covenant Defeasance option, each Guarantor will be released and relieved of any obligations under its Guarantee and the Collateral for the Notes (other than the trust) will be released.

In order to exercise either Legal Defeasance or Covenant Defeasance:

(1) the Company must irrevocably deposit with the trustee, in trust, for the benefit of the Holders of the Notes, cash in U.S. dollars, Government Securities, or a combination of cash in U.S. dollars and Government Securities, in amounts as will be sufficient, in the opinion of a nationally recognized firm of independent public accountants, to pay the principal of, and interest and premium, if any, on the outstanding Notes on the date of fixed maturity or on the applicable redemption date, as the case may be, and the Company must specify whether the Notes are being defeased to the date of fixed maturity or to a particular redemption date;

(2) in the case of Legal Defeasance, the Company has delivered to the trustee an opinion of counsel reasonably acceptable to the trustee confirming that:

(a) the Company has received from, or there has been published by, the Internal Revenue Service a ruling; or

(b) since the date of the indenture, there has been a change in the applicable federal income tax law,

in either case to the effect that, and based thereon such opinion of counsel will confirm that, the Holders of the outstanding Notes will not recognize income, gain or loss for federal income tax purposes as a result of such Legal Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Legal Defeasance had not occurred;

(3) in the case of Covenant Defeasance, the Company has delivered to the trustee an opinion of counsel reasonably acceptable to the trustee confirming that the Holders of the outstanding Notes will not recognize income, gain or loss for federal income tax purposes as a result of such Covenant Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Covenant Defeasance had not occurred;

(4) no Default or Event of Default has occurred and is continuing on the date of such deposit (other than a Default or Event of Default resulting from the borrowing of funds to be applied to such deposit);

 

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(5) such Legal Defeasance or Covenant Defeasance will not result in a breach or violation of, or constitute a default under, any material agreement or instrument (other than the indenture) to which the Company or any of the Guarantors is a party or by which the Company or any of the Guarantors is bound;

(6) the Company must have delivered to the trustee an opinion of counsel to the effect that after the 91st day following the deposit (or, if any Holder or Beneficial Owner of Notes is an insider of the Company, such later date as counsel may specify in such opinion), the trust funds will not be subject to the effect of Section 547 of the Federal Bankruptcy Code;

(7) the Company must deliver to the trustee an officers’ certificate stating that the deposit was not made by the Company with the intent of preferring the Holders of Notes over the other creditors of the Company with the intent of defeating, hindering, delaying or defrauding creditors of the Company or others; and

(8) the Company must deliver to the trustee an officers’ certificate and an opinion of counsel, each stating that all conditions precedent relating to the Legal Defeasance or the Covenant Defeasance have been complied with.

Amendment, Supplement and Waiver

Except as provided in the next three succeeding paragraphs, the indenture, the Notes, the Collateral Agreements or the Guarantees may be amended or supplemented with the consent of the Holders of at least a majority in principal amount of the Notes then outstanding (including, without limitation, consents obtained in connection with a purchase of or tender offer for Notes), and any existing default or compliance with any provision of the indenture, the Notes, the Collateral Agreements or the Guarantees may be waived with the consent of the Holders of a majority in principal amount of the then outstanding Notes (including, without limitation, consents obtained in connection with a purchase of or tender offer for Notes).

Without the consent of each Holder affected, an amendment, supplement or waiver may not (with respect to any Notes held by a non-consenting Holder):

(1) reduce the principal amount of Notes whose Holders must consent to an amendment, supplement or waiver;

(2) reduce the principal of or change the fixed maturity of any Note or alter the provisions with respect to the redemption or repurchase of the Notes (other than provisions relating to the covenants described above under the caption “—Repurchase at the Option of Holders”);

(3) reduce the rate of or change the time for payment of interest on any Note;

(4) waive a Default or Event of Default in the payment of principal of, or interest or premium, if any, on the Notes (except, in connection with a rescission of acceleration of the Notes by the Holders of at least a majority in principal amount of the Notes, a waiver of any payment default that resulted from such acceleration);

(5) make any Note payable in currency other than that stated in the Notes;

(6) make any change in the provisions of the indenture relating to waivers of past Defaults or the rights of Holders of Notes to receive payments of principal of, or interest or premium, if any, on the Notes (other than as permitted in clause (7) below);

(7) waive a redemption or repurchase payment with respect to any Note (other than a payment required by one of the covenants described above under the caption “—Repurchase at the Option of Holders”);

(8) release any Guarantor from any of its obligations under its Guarantee, except in accordance with the terms of the indenture;

(9) release all or substantially all of the Collateral from the Liens created pursuant to the Collateral Agreements otherwise than in accordance with the indenture or the Collateral Agreements; or

 

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(10) make any change in the preceding amendment, supplement and waiver provisions.

Notwithstanding the preceding, without the consent of any Holder of Notes, the Company, the Guarantors and the trustee may amend or supplement the indenture, the Notes, the Collateral Agreements or the Guarantees:

(1) to cure any ambiguity, defect or inconsistency;

(2) to provide for uncertificated Notes in addition to or in place of certificated Notes;

(3) to provide for the assumption of the Company’s or the Parent’s obligations to Holders of Notes in the case of a merger or consolidation or sale of all or substantially all of the Parent’s properties or assets;

(4) to make any change that would provide any additional rights or benefits to the Holders of Notes or that does not adversely affect the legal rights of any Holder under the indenture, the Notes, the Guarantees or any Collateral Agreement, provided that any change to conform the indenture to this offering memorandum will not be deemed to adversely affect the legal rights under the indenture of any holder;

(5) in connection with any addition or release of Collateral permitted under the terms of the indenture or the Collateral Agreements;

(6) to provide for the issuance of additional Notes in accordance with the limitations set forth in the indenture;

(7) to add any additional Subsidiary Guarantor or to evidence the release of any Subsidiary Guarantor from its Guarantee, in each case as provided in the indenture;

(8) to comply with requirements of the Commission in order to effect or maintain the qualification of the indenture under the Trust Indenture Act; or

(9) to evidence or provide for the acceptance of appointment under the indenture of a successor trustee.

Neither the Parent nor any of its Subsidiaries shall, directly or indirectly, pay or cause to be paid any consideration, whether by way of interest, fee or otherwise, to any Beneficial Owner or Holder of any Notes for or as an inducement to any consent to any waiver, supplement or amendment of any terms or provisions of the indenture, the Notes, the Collateral Agreement or the Guarantees unless such consideration is offered to be paid or agreed to be paid to all Beneficial Owners and Holders of the Notes which so consent in the time frame set forth in solicitation documents relating to such consent.

Satisfaction and Discharge

The indenture will be discharged and will cease to be of further effect as to all Notes issued thereunder (except as to surviving rights of registration of transfer or exchange of the Notes and as otherwise specified in the indenture), and all Guarantees and Liens created pursuant to the Collateral Agreements will be released, when:

(1) either:

(a) all Notes that have been authenticated, except lost, stolen or destroyed Notes that have been replaced or paid and Notes for whose payment money has been deposited in trust and thereafter repaid to the Company, have been delivered to the trustee for cancellation; or

(b) all Notes that have not been delivered to the trustee for cancellation have become due and payable or will become due and payable within one year by reason of the mailing of a notice of redemption or otherwise and the Company or any Guarantor has irrevocably deposited or caused to be deposited with the trustee as trust funds in trust solely for the benefit of the Holders, cash in U.S. dollars, Government Securities, or a combination of cash in U.S. dollars and Government Securities, in amounts as will be sufficient without consideration of any reinvestment of interest, to pay and discharge the entire indebtedness on the Notes not delivered to the trustee for cancellation for principal, premium, if any, and accrued interest to the date of fixed maturity or redemption;

 

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(2) no Default or Event of Default has occurred and is continuing on the date of the deposit or will occur as a result of the deposit and the deposit will not result in a breach or violation of, or constitute a default under, any material agreement or instrument (other than the indenture) to which the Parent or any of its Subsidiaries is a party or by which the Parent or any of its Subsidiaries is bound;

(3) the Company or any Guarantor has paid or caused to be paid all sums payable by it under the indenture; and

(4) the Company has delivered irrevocable instructions to the trustee under the indenture to apply the deposited money toward the payment of the Notes at fixed maturity or the redemption date, as the case may be.

In addition, the Company must deliver an officers’ certificate and an opinion of counsel to the trustee stating that all conditions precedent to satisfaction and discharge have been satisfied.

Concerning the Trustee

If the trustee becomes a creditor of the Company or any Guarantor, the indenture limits its right to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The trustee will be permitted to engage in other transactions; however, if it acquires any conflicting interest (as defined in the Trust Indenture Act) after a Default has occurred and is continuing, it must eliminate such conflict within 90 days, apply to the Commission for permission to continue or resign.

The Holders of a majority in principal amount of the then outstanding Notes will have the right to direct the time, method and place of conducting any proceeding for exercising any remedy available to the trustee, subject to certain exceptions. The indenture provides that in case an Event of Default occurs and is continuing, the trustee will be required, in the exercise of its power, to use the degree of care of a prudent man in the conduct of his own affairs. Subject to such provisions, the trustee will be under no obligation to exercise any of its rights or powers under the indenture at the request of any Holder of Notes, unless such Holder has offered to the trustee security or indemnity satisfactory to it against any loss, liability or expense.

Governing Law

The indenture, the Notes and the Guarantees are governed by, and construed in accordance with, the laws of the State of New York.

Additional Information

Anyone who receives this offering memorandum may obtain a copy of the indenture and registration rights agreement without charge by writing to the Company at 1331 Lamar Street, Suite 1080, Houston, Texas 77010, Attn: Chief Financial Officer.

Registration Rights; Additional Interest

The Company, the Guarantors and the initial purchasers entered into a registration rights agreement on the original issuance date of the old notes. The following description is a summary of the material provisions of the registration rights agreement. It does not restate that agreement in its entirety. We urge you to read the registration rights agreement in its entirety because it, and not this description, defines your registration rights as Holders of the Notes. See “—Additional Information”.

Pursuant to the registration rights agreement, the Company and the Guarantors agreed that they will, subject to certain exceptions,

(1) within 150 days after the date of original issue of the old notes (the “Issue Date”), file a registration statement (the “Exchange Offer Registration Statement”) with the SEC with respect to a Registered Exchange Offer to exchange the old notes for new notes of the Company, which we call “Exchange Notes,” having terms substantially identical in all material respects to the old notes (except that the Exchange Notes will not contain terms relating to transfer restrictions);

 

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(2) use their reasonable best efforts to cause the Exchange Offer Registration Statement to be declared effective under the Securities Act within 240 days after the Issue Date;

(3) as soon as practicable after the effectiveness of the Exchange Offer Registration Statement (the “Effectiveness Date”), offer the Exchange Notes in exchange for the old notes; and

(4) keep the Registered Exchange Offer open for not less than 30 days (or longer if required by applicable law) after the date notice of the Registered Exchange Offer is mailed to the holders of the old notes.

For each old note tendered to us pursuant to the Registered Exchange Offer, we will issue to the Holder of such old note an Exchange Note having a principal amount equal to that of the surrendered note. Interest on each Exchange Note will accrue from the last interest payment date on which interest was paid on the note surrendered in exchange therefor, or, if no interest has been paid on such note, from the date of its original issue.

Under existing SEC interpretations, the Exchange Notes will be freely transferable by Holders other than our affiliates after the Registered Exchange Offer without further registration under the Securities Act if the Holder of the Exchange Notes makes the representations to us set forth in the second succeeding paragraph; provided, however, that broker-dealers (“Participating Broker-Dealers”) receiving Exchange Notes in the Registered Exchange Offer will have a prospectus delivery requirement for resales of such Exchange Notes. The SEC has taken the position that Participating Broker-Dealers may fulfill their prospectus delivery requirements with respect to Exchange Notes (other than a resale of an unsold allotment from the original sale of the notes) with the prospectus contained in the Exchange Offer Registration Statement.

The registration rights agreement requires the Company and the Guarantors to allow Participating Broker-Dealers and other Persons, if any, with similar prospectus delivery requirements to use the prospectus contained in the Exchange Offer Registration Statement in connection with the resale of such Exchange Notes for 180 days following the Effectiveness Date (or such shorter period during which Participating Broker-Dealers are required by law to deliver such prospectus).

A Holder of old notes (other than certain specified Holders) who wishes to exchange such notes for Exchange Notes in the Registered Exchange Offer will be required to represent that any Exchange Notes to be received by it will be acquired in the ordinary course of its business and that at the time of the commencement of the Registered Exchange Offer it has no arrangement or understanding with any Person to participate in the distribution (within the meaning of the Securities Act) of the Exchange Notes and that it is not an “affiliate” of the Company, as defined in Rule 405 of the Securities Act, or if it is an affiliate, that it will comply with the registration and prospectus delivery requirements of the Securities Act to the extent applicable.

In the event that:

(1) any change in law or in applicable interpretations thereof by the staff of the SEC does not permit us to effect the Registered Exchange Offer;

(2) for any other reason we do not consummate the Registered Exchange Offer within 290 days after the Issue Date;

(3) an initial purchaser notifies us following consummation of the Registered Exchange Offer that old notes held by it are not eligible to be exchanged for Exchange Notes in the Registered Exchange Offer; or

(4) certain Holders are prohibited by law or SEC policy from participating in the Registered Exchange Offer or may not resell the Exchange Notes acquired by them in the Registered Exchange Offer to the public without delivering a prospectus,

then, the Company and the Guarantors will, subject to certain exceptions,

(1) promptly file a shelf registration statement (the “Shelf Registration Statement”) with the SEC covering resales of the notes or the Exchange Notes, as the case may be;

 

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(2) (A) in the case of clause (1) above, use their reasonable best efforts to cause the Shelf Registration Statement to be declared effective under the Securities Act on or prior to the 240th day after the Issue Date and (B) in the case of clause (2), (3) or (4) above, use their reasonable best efforts to cause the Shelf Registration Statement to be declared effective under the Securities Act on or prior to the 90th day after the date on which the Shelf Registration Statement is required to be filed; and

(3) use their reasonable best efforts to keep the Shelf Registration Statement effective until the earliest of (A) the time when the notes covered by the Shelf Registration Statement can be sold pursuant to Rule 144 without any limitations under clause (c), (e), (f) and (h) of Rule 144, (B) two years from the Issue Date and (C) the date on which all notes registered thereunder are disposed of in accordance therewith.

We will, in the event a Shelf Registration Statement is filed, among other things, provide to each Person for whom such Shelf Registration Statement was filed copies of the prospectus which is part of the Shelf Registration Statement, notify each such Person when the Shelf Registration Statement has become effective and take certain other actions as are required to permit unrestricted resales of the old notes or the Exchange Notes, as the case may be. A Person selling such old notes or Exchange Notes pursuant to the Shelf Registration Statement generally would be required to be named as a selling security holder in the related prospectus and to deliver a prospectus to purchasers, will be subject to certain of the civil liability provisions under the Securities Act in connection with such sales and will be bound by the provisions of the registration rights agreement that are applicable to such holder (including certain indemnification obligations).

We may require each Person requesting to be named as a selling security holder to furnish to us such information regarding the Person and the distribution of the old notes or Exchange Notes by the Person as we may from time to time reasonably require for the inclusion of the Person in the Shelf Registration Statement, including requiring the Person to properly complete and execute such selling security holder notice and questionnaires, and any amendments or supplements thereto, as we may reasonably deem necessary or appropriate. We may refuse to name any Person as a selling security holder that fails to provide us with such information.

We will pay, as liquidated damages, additional cash interest on the applicable notes and Exchange Notes, subject to certain exceptions,

(1) if the Company and the Guarantors fail to file an Exchange Offer Registration Statement with the SEC on or prior to the 150th day after the Issue Date,

(2) if the Exchange Offer Registration Statement is not declared effective by the SEC on or prior to the 210th day after the Issue Date or, if the Company and the Guarantors are obligated to file a Shelf Registration Statement pursuant to clause 2(A) above, a Shelf Registration Statement is not declared effective by the SEC on or prior to the 240th day after the Issue Date,

(3) if the Registered Exchange Offer is not consummated on or before the 50th day after the Effectiveness Date,

(4) if they are obligated to file the Shelf Registration Statement pursuant to clause 2(B) above, the Company and the Guarantors fail to file the Shelf Registration Statement with the SEC on or prior to the 90th day (the “Shelf Filing Date”) after the date on which the obligation to file a Shelf Registration Statement arises,

(5) if the Company and the Guarantors are obligated to file a Shelf Registration Statement pursuant to clause 2(B) above, the Shelf Registration Statement is not declared effective on or prior to the 90th day after the Shelf Filing Date, or

(6) after the Exchange Offer Registration Statement or the Shelf Registration Statement, as the case may be, is declared effective, such Registration Statement thereafter ceases to be effective or usable (subject to certain exceptions) (each such event referred to in this clause (6) and the preceding clauses (1) through (5) being called a “Registration Default”),

 

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from and including the date on which any such Registration Default shall occur to but excluding the earlier of the date on which all Registration Defaults have been cured or the date on which old notes may be sold without restriction by non- affiliates under Rule 144(k) under the Securities Act.

The rate of the additional interest will be 0.25% per annum for the first 90-day period immediately following the occurrence of a Registration Default, and such rate will increase by an additional 0.25% per annum with respect to each subsequent 90-day period until all Registration Defaults have been cured, up to a maximum additional interest rate of 0.50% per annum. We will pay such additional interest on regular interest payment dates. Such additional interest will be in addition to any other interest payable from time to time with respect to the old notes and the Exchange Notes.

We will be entitled to close the Registered Exchange Offer 30 days after it commences, provided that we have accepted all old notes theretofore validly tendered in accordance with the terms of the Registered Exchange Offer.

Subject only to limited exceptions applicable to persons to whom the exchange offer is not available, if you do not exchange your outstanding old notes in the exchange offer, you will no longer be entitled to registration rights. You will not be able to offer or sell the outstanding old notes unless they are later registered, sold pursuant to an exemption from registration or sold in a transaction not subject to the Securities Act or state securities laws. Other than in connection with the exchange offer or as specified in the registration rights agreement, we are not obligated to, nor do we currently anticipate that we will, register the outstanding old notes under the Securities Act.

Certain Definitions

Set forth below are certain defined terms used in the indenture. Reference is made to the indenture for a full disclosure of all such terms, as well as any other capitalized terms used herein for which no definition is provided.

“ACNTA” (Adjusted Consolidated Net Tangible Assets) means (without duplication), as of the date of determination:

(1) the sum of:

(a) discounted future net revenue from proved crude oil and natural gas reserves of the Parent and its Restricted Subsidiaries calculated in accordance with SEC guidelines before any state or federal income taxes, as estimated in a reserve report prepared as of the end of the Parent’s most recently completed fiscal year, which reserve report is prepared or reviewed or audited by an independent petroleum engineer as to reserves accounting for at least 80% of all such discounted future net revenue and by the Parent’s petroleum engineers with respect to any other such reserves covered by such report, as increased by, as of the date of determination, the discounted future net revenue from:

(i) estimated proved crude oil and natural gas reserves of the Parent and its Restricted Subsidiaries attributable to acquisitions consummated since the date of such year-end reserve report, and

(ii) estimated crude oil and natural gas reserves of the Parent and its Restricted Subsidiaries attributable to extensions, discoveries and other additions and upward determinations of estimates of proved crude oil and natural gas reserves (including previously estimated development costs incurred during the period and the accretion of discount since the prior year end) due to exploration, development or exploitation, production or other activities which reserves were not reflected in such year-end reserve report,

in each case calculated in accordance with SEC guidelines (utilizing the prices utilized in such year-end reserve report), and decreased by, as of the date of determination, the discounted future net revenue attributable to

(iii) estimated proved crude oil and natural gas reserves of the Parent and its Restricted Subsidiaries reflected in such year-end reserve report produced or disposed of since the date of such year-end reserve report and

 

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(iv) reductions in the estimated proved crude oil and natural gas reserves of the Parent and its Restricted Subsidiaries reflected in such year-end reserve report since the date of such year-end reserve report attributable to downward determinations of estimates of proved crude oil and natural gas reserves due to exploration, development or exploitation, production or other activities conducted or otherwise occurring since the date of such year-end reserve report,

in each case calculated in accordance with SEC guidelines (utilizing the prices utilized in such year-end reserve report); provided, however, that, in the case of each of the determinations made pursuant to clauses (i) through (iv), such increases and decreases shall be as estimated by the Parent’s engineers, except that if as a result of such acquisitions, dispositions, discoveries, extensions or revisions, there is a Material Change, then such increases and decreases in the discounted future net revenue shall be confirmed in writing by an independent petroleum engineer;

(b) the capitalized costs that are attributable to crude oil and natural gas properties of the Parent and its Restricted Subsidiaries to which no proved crude oil and natural gas reserves are attributed, based on the Parent’s books and records as of a date no earlier than the date of the Parent’s latest annual or quarterly financial statements;

(c) the Net Working Capital on a date no earlier than the date of the Parent’s latest annual or quarterly financial statements; and

(d) the greater of (I) the net book value on a date no earlier than the date of the Parent’s latest annual or quarterly financial statements and (II) the appraised value, as estimated by independent appraisers, of other tangible assets of the Parent and its Restricted Subsidiaries as of a date no earlier than the date of the Parent’s latest audited financial statements;

(2) minus, to the extent not otherwise taken into account in the immediately preceding clause (1), the sum of:

(a) minority interests;

(b) any net gas balancing liabilities of the Parent and its Restricted Subsidiaries reflected in the Parent’s latest audited financial statements;

(c) the discounted future net revenue, calculated in accordance with SEC guidelines (utilizing the same prices utilized in the Parent’s year-end reserve report), attributable to reserves subject to participation interests, overriding royalty interests or other interests of third parties, pursuant to participation, partnership, vendor financing or other agreements then in effect, or which otherwise are required to be delivered to third parties;

(d) the discounted future net revenue, calculated in accordance with SEC guidelines (utilizing the same prices utilized in the Parent’s year-end reserve report), attributable to reserves that are required to be delivered to third parties to fully satisfy the obligations of the Parent and its Restricted Subsidiaries with respect to Volumetric Production Payments on the schedules specified with respect thereto; and

(e) the discounted future net revenue, calculated in accordance with SEC guidelines, attributable to reserves subject to Dollar-Denominated Production Payments that, based on the estimates of production included in determining the discounted future net revenue specified in the immediately preceding clause (1)(a) (utilizing the same prices utilized in the Parent’s year-end reserve report), would be necessary to satisfy fully the obligations of the Parent and its Restricted Subsidiaries with respect to Dollar-Denominated Production Payments on the schedules specified with respect thereto.

For purposes of the covenant described under “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock,” the Parent shall be entitled to rely on the calculation of ACNTA as of the date of its most recent semi-annual reserve report prepared for purposes of its financial statements. If the Parent changes its method of accounting for its oil and gas properties from the full cost method to the successful efforts method or a similar method of accounting, ACNTA will continue to be calculated as if the Parent were still using the full cost method of accounting.

 

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“Acquired Debt” means, with respect to any specified Person:

(1) Indebtedness of any other Person existing at the time such other Person was merged with or into or became a Subsidiary of such specified Person, whether or not such Indebtedness is incurred in connection with, or in contemplation of, such other Person merging with or into, or becoming a Subsidiary of, such specified Person; and

(2) Indebtedness secured by a Lien encumbering any asset acquired by such specified Person.

“Additional Assets” means:

(1) any assets used or useful in the Oil and Gas Business;

(2) the Capital Stock of a Person that becomes a Restricted Subsidiary as a result of the acquisition of such Capital Stock by the Parent or another Restricted Subsidiary; or

(3) Capital Stock constituting a minority interest in any Person that at such time is a Restricted Subsidiary;

provided, however, that any such Restricted Subsidiary described in clause (2) or (3) is primarily engaged in the Oil and Gas Business.

“Administrative Agent” has the meaning set forth in the definition of the term “Credit Agreement”.

“Affiliate” of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For purposes of this definition, “control,” as used with respect to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by agreement or otherwise; provided that beneficial ownership of 10% or more of the Voting Stock of a Person will be deemed to be control. For purposes of this definition, the terms “controlling,” “controlled by” and “under common control with” have correlative meanings.

“Asset Sale” means:

(1) the sale, lease, conveyance or other disposition of any properties or assets (including by way of a Production Payment or sale and leaseback transaction); provided that the disposition of all or substantially all of the properties or assets of the Parent and its Restricted Subsidiaries taken as a whole will be governed by the provisions of the indenture described above under the caption “—Repurchase at the Option of Holders—Change of Control” and/or the provisions described above under the caption “—Certain Covenants—Merger, Consolidation or Sale of Assets” and not by the provisions of the Asset Sale covenant; and

(2) the issuance of Equity Interests in any of the Parent’s Restricted Subsidiaries or the sale of Equity Interests in any of its Restricted Subsidiaries.

Notwithstanding the preceding, the following items will not be deemed to be Asset Sales:

(1) any single transaction or series of related transactions that involves properties or assets having a fair market value of less than $3.0 million;

(2) a transfer of assets between or among any of the Parent and its Restricted Subsidiaries;

(3) an issuance or sale of Equity Interests by a Restricted Subsidiary to the Parent or to another Restricted Subsidiary;

(4) the sale, lease or other disposition of hydrocarbons, equipment, inventory, accounts receivable or other properties or assets in the ordinary course of business, including, without limitation, any abandonment, farm-in,

 

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farm-out, lease or sublease of any oil and gas properties or the forfeiture or other disposition of such properties pursuant to standard form operating agreements, in each case in the ordinary course of business in a manner customary in the Oil and Gas Business;

(5) the sale or other disposition of cash or Cash Equivalents;

(6) a Restricted Payment that is permitted by the covenant described above under the caption “—Certain Covenants—Restricted Payments” or a Permitted Investment;

(7) any trade or exchange by the Parent or any Restricted Subsidiary of oil and gas properties or other properties or assets for oil and gas properties or other properties or assets owned or held by another Person, provided that the fair market value of the properties or assets traded or exchanged by the Parent or such Restricted Subsidiary (together with any cash) is reasonably equivalent to the fair market value of the properties or assets (together with any cash) to be received by the Parent or such Restricted Subsidiary, and provided further that any net cash received must be applied in accordance with the provisions described above under the caption “—Repurchase at the Option of Holders—Asset Sales;”

(8) the creation or perfection of a Lien (but not the sale or other disposition of the properties or assets subject to such Lien); and

(9) disposition, surrender or waiver of contract rights or property in connection with the settlement, release or surrender of contract, tort or other claims of any kind.

“Asset Sale Offer” means an offer to purchase Notes and certain other pari passu Indebtedness in accordance with the covenant above “—Repurchase at the Option of Holders—Asset Sales”.

“Attributable Debt” in respect of a sale and leaseback transaction means, at the time of determination, the present value of the obligation of the lessee for net rental payments during the remaining term of the lease included in such sale and leaseback transaction including any period for which such lease has been extended or may, at the option of the lessor, be extended. Such present value shall be calculated using a discount rate equal to the rate of interest implicit in such transaction, determined in accordance with GAAP.

“Beneficial Owner” has the meaning assigned to such term in Rule 13d-3 and Rule 13d-5 under the Exchange Act, except that in calculating the beneficial ownership of any particular “person” (as that term is used in Section 13(d)(3) of the Exchange Act), such “person” will be deemed to have beneficial ownership of all securities that such “person” has the right to acquire by conversion or exercise of other securities, whether such right is currently exercisable or is exercisable only upon the occurrence of a subsequent condition. The terms “Beneficially Owns” and “Beneficially Owned” have correlative meanings.

“Board of Directors” means:

(1) with respect to a corporation, the board of directors of the corporation;

(2) with respect to a partnership, the Board of Directors of the general partner of the partnership; and

(3) with respect to any other Person, the board or committee of such Person serving a similar function.

“Board Resolution” means a copy of a resolution certified by the Secretary or an Assistant Secretary of the applicable Person to have been duly adopted by the Board of Directors of such Person and to be in full force and effect on the date of such certification, and delivered to the trustee.

“Business Day” means each day that is not a Saturday, Sunday or other day on which banking institutions in Houston, Texas or in New York, New York are authorized or required by law to close.

“Capital Lease Obligation” means, at the time any determination is to be made, the amount of the liability in respect of a capital lease that would at that time be required to be capitalized on a balance sheet in accordance with GAAP.

 

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“Capital Stock” means:

(1) in the case of a corporation, corporate stock;

(2) in the case of an association or business entity, any and all shares, interests, participations, rights or other equivalents (however designated) of corporate stock;

(3) in the case of a partnership or limited liability company, partnership or membership interests (whether general or limited); and

(4) any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, the issuing Person.

“Cash Equivalents” means:

(1) United States dollars or other foreign currencies used in the ordinary course of the Parent’s or a Restricted Subsidiary’s business;

(2) securities issued or directly and fully guaranteed or insured by the United States government or any agency or instrumentality of the United States government (provided that the full faith and credit of the United States is pledged in support of those securities) having maturities of not more than six months from the date of acquisition;

(3) certificates of deposit and eurodollar time deposits with maturities of six months or less from the date of acquisition, bankers’ acceptances with maturities not exceeding six months and overnight bank deposits, in each case, with any lender party to the Credit Agreement or with any domestic commercial bank having capital and surplus in excess of $250.0 million and a Thomson Bank Watch Rating of “B” or better;

(4) repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (2) and (3) above entered into with any financial institution meeting the qualifications specified in clause (3) above;

(5) commercial paper having the highest rating obtainable from Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and in each case maturing within six months after the date of acquisition; and

(6) money market funds at least 95% of the assets of which constitute Cash Equivalents of the kinds described in clauses (1) through (5) of this definition.

“Change of Control” means the occurrence of any of the following:

(1) the direct or indirect sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the properties or assets (including Capital Stock of the Restricted Subsidiaries) of the Parent and its Restricted Subsidiaries taken as a whole, to any “person” (as that term is used in Section 13(d)(3) of the Exchange Act);

(2) the adoption of a plan relating to the liquidation or dissolution of the Parent;

(3) the consummation of any transaction (excluding any merger or consolidation of the Parent with or into another Person) the result of which is that any “person” (as that term is used in Section 13(d)(3) of the Exchange Act) (other than a person who acquires Voting Stock under the terms of any agreement existing on the Issue Date, including in respect of any settlement or other resolution of a dispute with respect thereto) becomes the Beneficial Owner, directly or indirectly, of more than 50% of the Voting Stock of the Parent, measured by voting power rather than number of shares;

(4) the first day on which a majority of the members of the Board of Directors of the Parent are not Continuing Directors; or

 

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(5) the Parent consolidates with, or merges with or into, any Person pursuant to a transaction in which any of the outstanding Voting Stock of the Parent is converted into or exchanged for cash, securities or other property, other than any such transaction where the Voting Stock of the Parent outstanding immediately prior to such transaction is converted into or exchanged for Voting Stock (other than Disqualified Stock) of the surviving or transferee Person constituting a majority of the outstanding shares of such Voting Stock of such surviving or transferee Person (or any parent thereof) immediately after giving effect to such issuance.

“Collateral” shall mean all property mortgaged under the Mortgages and any other property, whether now owned or hereafter acquired, upon which a Lien securing the Obligations under the indenture, the Notes or the Guarantees is granted or purported to be granted under any Collateral Agreement; provided, however, that “Collateral” shall not include any Excluded Collateral.

“collateral agent” means the party named as such in the indenture until a successor replaces it in accordance with the provisions of the indenture and thereafter means such successor.

“Collateral Agreements” means, collectively, the Intercreditor Agreement, each Mortgage and each other instrument creating Liens in favor of the trustee or the collateral agent as required by the Indenture, in each case, as the same may be in force from time to time.

“Commission” or “SEC” means the Securities and Exchange Commission.

“Consolidated Cash Flow” means, with respect to any specified Person for any period, the Consolidated Net Income of such Person for such period plus:

(1) provision for taxes based on income or profits of such Person and its Restricted Subsidiaries for such period, to the extent that such provision for taxes was deducted in computing such Consolidated Net Income; plus

(2) consolidated interest expense of such Person and its Restricted Subsidiaries for such period, whether paid or accrued and whether or not capitalized (excluding any interest attributable to Dollar-Denominated Production Payments but including, without limitation, amortization of debt issuance costs and original issue discount, non-cash interest payments, the interest component of any deferred payment obligations, the interest component of all payments associated with Capital Lease Obligations, imputed interest with respect to Attributable Debt, commissions, discounts and other fees and charges incurred in respect of letter of credit or bankers’ acceptance financings), and net of the effect of all payments made or received pursuant to interest rate Hedging Obligations, to the extent that any such expense was deducted in computing such Consolidated Net Income; plus

(3) depreciation, depletion and amortization expenses (including amortization of intangibles but excluding amortization of prepaid cash expenses that were paid in a prior period), exploration expenses and impairment and other non-cash expenses (excluding any such non-cash expense to the extent that it represents an accrual of or reserve for cash expenses in any future period or amortization of a prepaid cash expense that was paid in a prior period) of such Person and its Restricted Subsidiaries for such period to the extent that such depreciation, depletion and amortization expenses, exploration expenses and impairment and other non-cash expenses were deducted in computing such Consolidated Net Income; plus

(4) unrealized non-cash losses resulting from foreign currency balance sheet adjustments required by GAAP to the extent such losses were deducted in computing such Consolidated Net Income; minus

(5) non-cash items increasing such Consolidated Net Income for such period, other than items that were accrued in the ordinary course of business; minus (to the extent included in determining Consolidated Net Income):

(6) the sum of (x) the amount of deferred revenues that are amortized during such period and are attributable to reserves that are subject to Volumetric Production Payments and (y) amounts recorded in accordance with GAAP as repayments of principal and interest pursuant to Dollar-Denominated Production Payments, in each case, on a consolidated basis and determined in accordance with GAAP.

 

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“Consolidated Net Income” means, with respect to any specified Person for any period, the aggregate of the Net Income of such Person and its Restricted Subsidiaries for such period, on a consolidated basis, determined in accordance with GAAP; provided that:

(1) the Net Income (but not loss) of any Person that is not a Restricted Subsidiary or that is accounted for by the equity method of accounting will be excluded, except to the extent of the amount of dividends or distributions paid in cash to the specified Person or a Restricted Subsidiary of the Person;

(2) the Net Income of any Restricted Subsidiary will be excluded to the extent that the declaration or payment of dividends or similar distributions by that Restricted Subsidiary of that Net Income is not at the date of determination permitted without any prior governmental approval (that has not been obtained) or, directly or indirectly, by operation of the terms of its charter or any agreement, instrument, judgment, decree, order, statute, rule or governmental regulation applicable to that Restricted Subsidiary or its stockholders, partners or members;

(3) the cumulative effect of a change in accounting principles will be excluded;

(4) income resulting from transfers of assets (other than cash) between the Parent or any of its Restricted Subsidiaries, on the one hand, and an Unrestricted Subsidiary, on the other hand, will be excluded;

(5) any write-downs of non-current assets will be excluded; provided that any ceiling limitation write-downs under Commission guidelines shall be treated as capitalized costs, as if such write-downs had not occurred;

(6) any unrealized non-cash gains or losses or charges in respect of hedge or non-hedge derivatives (including those resulting from the application of FAS 133) will be excluded;

(7) any non-cash compensation charge arising from any grant of stock, stock options or other equity-based awards will be excluded;

(8) any item classified as an extraordinary, unusual or nonrecurring gain, loss or charge will be excluded; and

(9) all deferred financing costs written off and premiums paid in connection with any early extinguishment of Indebtedness will be excluded.

In addition, notwithstanding the preceding, for the purposes of the covenant described under “—Certain Covenants—Restricted Payments” only, there shall be excluded from Consolidated Net Income any nonrecurring charges relating to any premium or penalty paid, write off of deferred finance costs or other charges in connection with redeeming or retiring any Indebtedness prior to its Stated Maturity.

“Continuing Directors” means, as of any date of determination, any member of the Board of Directors of the Parent who:

(1) was a member of such Board of Directors on the Issue Date; or

(2) was nominated for election or elected to such Board of Directors with the approval of a majority of the Continuing Directors who were members of such Board at the time of such nomination or election.

“Credit Agreement” means the revolving credit facility, to be in effect on the Issue Date, among the Parent, the Company, certain subsidiaries, Amegy Bank National Association, as Administrative Agent (together with all successors thereto, the “Administrative Agent”), and the other financial institutions party thereto, providing for revolving credit borrowings, including any related Notes, guarantees, collateral documents, instruments and agreements executed in connection therewith, and in each case as amended, restated, modified, renewed, refunded, replaced or refinanced from time to time.

 

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“Credit Facilities” means one or more debt facilities (including, without limitation, the Credit Agreement), commercial paper facilities or secured capital markets financings, in each case with banks or other institutional lenders or institutional investors providing for revolving credit loans, term loans, receivables financing (including through the sale of receivables to such lenders or to special purpose entities formed to borrow from (or sell receivables to) such lenders against such receivables), letters of credit or secured capital markets financings, in each case, as amended, restated, modified, renewed, refunded, replaced or refinanced (including refinancing with any capital markets transaction) in whole or in part from time to time.

“Default” means any event that is, or with the passage of time or the giving of notice or both would be, an Event of Default.

“Disqualified Stock” means any Capital Stock that, by its terms (or by the terms of any security into which it is convertible, or for which it is exchangeable, in each case at the option of the holder of the Capital Stock), or upon the happening of any event, matures or is mandatorily redeemable, pursuant to a sinking fund obligation or otherwise, or redeemable at the option of the holder of the Capital Stock, in whole or in part, on or prior to the date that is 91 days after the date on which the Notes mature. Notwithstanding the preceding sentence, any Capital Stock that would constitute Disqualified Stock solely because the holders of the Capital Stock have the right to require the Parent to repurchase or redeem such Capital Stock upon the occurrence of a change of control or an asset sale will not constitute Disqualified Stock if the terms of such Capital Stock provide that the Parent may not repurchase or redeem any such Capital Stock pursuant to such provisions unless such repurchase or redemption complies with the covenant described above under the caption “—Certain Covenants—Restricted Payments”.

“Dollar-Denominated Production Payments” means production payment obligations recorded as liabilities in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“Domestic Subsidiary” means any Restricted Subsidiary of the Parent other than a Foreign Subsidiary.

“Equity Interests” means Capital Stock and all warrants, options or other rights to acquire Capital Stock (but excluding any debt security that is convertible into, or exchangeable for, Capital Stock).

“Equity Offering” means any public or private sale of Capital Stock (other than Disqualified Stock) made for cash on a primary basis by the Parent or the Company after the Issue Date.

“Exchange Notes” means the notes issued in a Registered Exchange Offer pursuant to the indenture.

“Existing Indebtedness” means the aggregate principal amount of Indebtedness of the Parent and its Restricted Subsidiaries in existence on the Issue Date, until such amounts are repaid.

“First Priority Agent” means the Administrative Agent and any successor designated as such by the holders of First Priority Claims.

“First Priority Claims” means (1) all Indebtedness under the Credit Agreement permitted pursuant to clause (1) of the definition of the term “Permitted Debt,” and all other Obligations (other than principal) related to such Indebtedness and owing under the documents relating to such Indebtedness and (2) all Hedging Obligations permitted under such Credit Agreement.

“Fixed Charge Coverage Ratio” means with respect to any specified Person for any four-quarter reference period, the ratio of the Consolidated Cash Flow of such Person for such period to the Fixed Charges of such Person for such period. In the event that the specified Person or any of its Restricted Subsidiaries incurs, assumes, guarantees, repays, repurchases or redeems any Indebtedness (other than ordinary working capital borrowings) or issues, repurchases or redeems preferred stock subsequent to the commencement of the applicable four-quarter reference period and on or prior to the date on which the event for which the calculation of the Fixed Charge Coverage Ratio is made (the “Calculation Date”), then the Fixed Charge Coverage Ratio will be calculated giving pro forma effect to such incurrence, assumption, guarantee, repayment, repurchase or redemption of Indebtedness, or such issuance, repurchase or redemption of preferred stock, and the use of the proceeds therefrom as if the same had occurred at the beginning of such period.

 

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In addition, for purposes of calculating the Fixed Charge Coverage Ratio:

(1) acquisitions that have been made by the specified Person or any of its Restricted Subsidiaries, including through mergers or consolidations and including any related financing transactions, subsequent to the commencement of the applicable four-quarter reference period and on or prior to the Calculation Date will be given pro forma effect as if they had occurred on the first day of such period, including any Consolidated Cash Flow and any pro forma expense and cost reductions that have occurred or are reasonably expected to occur, in the reasonable judgment of the chief financial or accounting officer of the Parent (regardless of whether those cost savings or operating improvements could then be reflected in pro forma financial statements in accordance with Regulation S-X promulgated under the Securities Act or any other regulation or policy of the Commission related thereto);

(2) the Consolidated Cash Flow attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses disposed of prior to the Calculation Date, will be excluded; and

(3) the Fixed Charges attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses disposed of prior to the Calculation Date, will be excluded, but only to the extent that the obligations giving rise to such Fixed Charges will not be obligations of the specified Person or any of its Restricted Subsidiaries following the Calculation Date.

“Fixed Charges” means, with respect to any specified Person for any period, the sum, without duplication, of:

(1) the consolidated interest expense of such Person and its Restricted Subsidiaries for such period, whether paid or accrued including, without limitation, amortization of debt issuance costs (excluding prepayment penalties associated with the repayment of debt from the proceeds of this offering) and original issue discount, non-cash interest payments, the interest component of any deferred payment obligations, the interest component of all payments associated with Capital Lease Obligations, imputed interest with respect to Attributable Debt, commissions, discounts and other fees and charges incurred in respect of letter of credit or bankers’ acceptance financings), and net of the effect of all payments made or received pursuant to interest rate Hedging Obligations; plus

(2) the consolidated interest expense of such Person and its Restricted Subsidiaries that was capitalized during such period; plus

(3) any interest expense on Indebtedness of another Person that is guaranteed by such Person or one of its Restricted Subsidiaries or secured by a Lien on assets of such Person or one of its Restricted Subsidiaries, whether or not such guarantee or Lien is called upon; plus

(4) the product of (a) all dividends, whether paid or accrued and whether or not in cash, on any series of preferred stock of such Person or any of its Restricted Subsidiaries, other than dividends on Equity Interests payable solely in Equity Interests of the Parent (other than Disqualified Stock) or to the Parent or a Restricted Subsidiary of the Parent, times (b) a fraction, the numerator of which is one and the denominator of which is one minus the then current combined federal, state and local statutory tax rate of such Person, expressed as a decimal,

in each case, on a consolidated basis and in accordance with GAAP.

“Foreign Subsidiary” means any Restricted Subsidiary of the Parent that was not formed under the laws of the United States or any state of the United States or the District of Columbia.

“GAAP” means generally accepted accounting principles in the United States, which are in effect, from time to time.

“Government Securities” means securities that are:

 

•

direct obligations of the United States of America for the timely payment of which its full faith credit is pledged; or

 

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•

obligations of a Person controlled or supervised by and acting as an agency or instrumentality of the United States of America, the timely payment of which is unconditionally guaranteed as a full faith and credit obligation by the United States of America

that, in either case, are not callable or redeemable at the option of the issuer thereof, and shall also include a depository receipt issued by a bank (as defined in Section 3(a) of the Securities Act), as custodian, with respect to any such Government Security or a specific payment of principal of or interest on any such Government Security held by such custodian for the account of the holder of such depository receipt; provided, however, that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depository receipt from any amount received by the custodian in respect of the Government Security or the specific payment of principal of or interest on the Government Security evidenced by such depository receipt.

The term “guarantee” means a guarantee other than by endorsement of negotiable instruments for collection in the ordinary course of business, direct or indirect, in any manner including, without limitation, by way of a pledge of assets or through letters of credit or reimbursement agreements in respect thereof, of all or any part of any Indebtedness. When used as a verb, “guarantee” has a correlative meaning.

“Guarantee” means any guarantee by a Guarantor of the Company’s payment Obligations under the indenture and on the Notes.

“Guarantors” means the Parent and the Subsidiary Guarantors.

“Hedging Obligations” means, with respect to any specified Person, the obligations of such Person incurred in the normal course of business and consistent with past practices and not for speculative purposes under:

(1) interest rate swap agreements, interest rate cap agreements and interest rate collar agreements entered into with one of more financial institutions and designed to protect the Person or any of its Restricted Subsidiaries entering into the agreement against fluctuations in interest rates with respect to Indebtedness incurred and not for purposes of speculation;

(2) foreign exchange contracts and currency protection agreements entered into with one of more financial institutions and designed to protect the Person or any of its Restricted Subsidiaries entering into the agreement against fluctuations in currency exchanges rates with respect to Indebtedness incurred and not for purposes of speculation;

(3) any commodity or basis swap, floor, collar or futures contract, commodity or basis option or other similar agreement or arrangement designed to protect against fluctuations in the prices of oil, natural gas or other commodities used, produced, processed or sold by that Person or any of its Restricted Subsidiaries at the time; and

(4) other agreements or arrangements designed to protect such Person or any of its Restricted Subsidiaries against fluctuations in interest rates, commodity prices or currency exchange rates.

“Holder” means a Person in whose name a Note is registered.

“Indebtedness” means, with respect to any specified Person, without duplication,

(1) all obligations of such Person, whether or not contingent, in respect of:

(a) the principal of and premium, if any, in respect of outstanding (A) indebtedness of such Person for money borrowed and (B) indebtedness evidenced by Notes, debentures, bonds or other similar instruments for the payment of which such Person is responsible or liable;

(b) all Capital Lease Obligations of such Person and all Attributable Debt in respect of sale and leaseback transactions entered into by such Person;

(c) the deferred purchase price of property, which purchase price is due more than six months after the date of taking delivery of title to such property, including all obligations of such Person for the deferred purchase price of property under any title retention agreement, but excluding accrued expenses and trade accounts payable arising in the ordinary course of business; and

 

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(d) the reimbursement obligation of any obligor for the principal amount of any letter of credit, banker’s acceptance or similar transaction (excluding obligations with respect to letters of credit securing obligations (other than obligations described in clauses (a) through (c) above) entered into in the ordinary course of business of such Person to the extent such letters of credit are not drawn upon or, if and to the extent drawn upon, such drawing is reimbursed no later than the tenth Business Day following receipt by such Person of a demand for reimbursement following payment on the letter of credit);

(2) all net obligations in respect of Hedging Obligations;

(3) all liabilities of others of the kind described in the preceding clause (1) or (2) that such Person has Guaranteed or that are otherwise its legal liability;

(4) with respect to any Production Payment, any warranties or guarantees of production or payment by such Person with respect to such Production Payment but excluding other contractual obligations of such Person with respect to such Production Payment;

(5) Indebtedness (as otherwise defined in this definition) of another Person secured by a Lien on any asset of such Person, whether or not such Indebtedness is assumed by such Person, the amount of such obligations being deemed to be the lesser of

(a) the full amount of such obligations so secured, and

(b) the fair market value of such asset as determined in good faith by such specified Person;

(6) Disqualified Stock of such Person in an amount equal to the greater of the maximum mandatory redemption or repurchase price (not including, in either case, any redemption or repurchase premium) or the liquidation preference thereof;

(7) the aggregate preference in respect of amounts payable on the issued and outstanding shares of preferred stock of any of such Person’s Restricted Subsidiaries other than the Company or a Subsidiary Guarantor in the event of any voluntary or involuntary liquidation, dissolution or winding up (excluding any such preference attributable to such shares of preferred stock that are owned by such Person or any of its Restricted Subsidiaries); and

(8) any and all deferrals, renewals, extensions, refinancings and refundings (whether direct or indirect) of, or amendments, modifications or supplements to, any liability of the kind described in any of the preceding clauses (1), (2), (3), (4), (5), (6) or (7) or this clause (8), whether or not between or among the same parties.

Subject to clause (4) of the preceding sentence, Production Payments shall not be deemed to be Indebtedness.

“Indenture Documents” means, collectively, the indenture, the Notes, the Guarantees and the Collateral Agreements.

“Investments” means, with respect to any Person, all direct or indirect investments by such Person in other Persons (including Affiliates) in the forms of loans (including guarantees or other obligations), advances or capital contributions (excluding commission, travel and similar advances to officers and employees made in the ordinary course of business), purchases or other acquisitions for consideration of Indebtedness, Equity Interests or other securities, together with all items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP. If the Parent or any Restricted Subsidiary of the Parent sells or otherwise disposes of any Equity Interests of any direct or indirect Restricted Subsidiary of the Parent such that, after giving effect to any such sale or disposition, such Person is no longer a Restricted Subsidiary of the Parent, the Parent will be deemed to have made an Investment on the date of any such sale or disposition in an amount equal to the fair market value of the Equity Interests of such Restricted Subsidiary not sold or disposed of in an amount determined as provided in the final paragraph of the covenant described above under the caption “—Certain Covenants—Restricted Payments”.

 

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“Issue Date” means the date on which Notes are first issued under the indenture.

“Lien” means, with respect to any asset, any mortgage, lien, pledge, charge, security interest or encumbrance of any kind in respect of such asset, whether or not filed, recorded or otherwise perfected under applicable law, including any conditional sale or other title retention agreement, any lease in the nature thereof, any option or other agreement to sell or give a security interest in and any filing of or agreement to give any financing statement under the Uniform Commercial Code (or equivalent statutes) of any jurisdiction other than a precautionary financing statement not intended as a security agreement.

“Major Asset Sale” means an Asset Sale of oil and gas properties (excluding oil and gas properties located in Wyoming) that have a fair market value of $10,000,000 or more.

“Material Change” means an increase or decrease (excluding changes that result solely from changes in prices and changes resulting from the incurrence of previously estimated future development costs) of more than 25% during a fiscal quarter in the discounted future net revenues from proved crude oil and natural gas reserves of the Parent and its Restricted Subsidiaries, calculated in accordance with clause (1)(a) of the definition of ACNTA; provided, however, that the following will be excluded from the calculation of Material Change:

(1) any acquisitions during the fiscal quarter of oil and gas reserves that have been estimated by independent petroleum engineers and with respect to which a report or reports of such engineers exist; and

(2) any disposition of properties existing at the beginning of such fiscal quarter that have been disposed of in compliance with the covenant described under “ —Repurchase of the Option of Holders—Assets Sales”.

“Material Domestic Subsidiary” means any Domestic Subsidiary, when taken together with all other Domestic Subsidiaries that are not Subsidiary Guarantors at the time of determination, at such time has either assets or quarterly revenues in excess of 3.0% of the consolidated assets or quarterly revenues of the Parent and its Restricted Subsidiaries, in each case based upon the most recent quarterly financial statements available to the Parent.

“Mortgages” means the mortgages, deeds of trust, deeds to secure Indebtedness, assignments of as extracted collateral, fixture filings or other similar documents granting Liens on the Parent and its Restricted Subsidiaries’ properties and interests, to secure the Notes.

“Net Income” means, with respect to any specified Person, the net income (loss) of such Person, determined in accordance with GAAP and before any reduction in respect of preferred stock dividends, excluding, however:

(1) any gain or loss, together with any related provision for taxes on such gain or loss, realized in connection with: (a) any Asset Sale; or (b) the disposition of any securities by such Person or any of its Subsidiaries or the extinguishment of any Indebtedness of such Person or any of its Subsidiaries; and

(2) any extraordinary gain or loss, together with any related provision for taxes on such extraordinary gain or loss.

“Net Proceeds” means the aggregate cash proceeds received by the Parent or any of its Restricted Subsidiaries in respect of any Asset Sale (including, without limitation, any cash received upon the sale or other disposition of any non-cash consideration received in any Asset Sale), net of, without duplication:

(1) the direct costs relating to such Asset Sale, including, without limitation, legal, accounting and investment banking fees, and sales commissions, and any relocation expenses incurred as a result of the Asset Sale,

(2) taxes paid or payable as a result of the Asset Sale, in each case, after taking into account any available tax credits or deductions and any tax sharing arrangements,

(3) amounts required to be applied to the repayment of Indebtedness, other than under the Credit Facilities, secured by a Lien on the properties or assets that were the subject of such Asset Sale, and

 

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(4) any reserve for adjustment in respect of the sale price of such properties or assets established in accordance with GAAP.

“Net Working Capital” means:

(1) all current assets of the Parent and its Restricted Subsidiaries, minus

(2) all current liabilities of the Parent and its Restricted Subsidiaries, except current liabilities included in Indebtedness;

in each case, on a consolidated basis and determined in accordance with GAAP.

“Non-Recourse Debt” means Indebtedness:

(1) as to which neither the Parent nor any of its Restricted Subsidiaries (a) provides credit support of any kind (including any undertaking, agreement or instrument that would constitute Indebtedness), (b) is directly or indirectly liable as a borrower, guarantor or otherwise, or (c) is the lender;

(2) no default with respect to which (including any rights that the holders of the Indebtedness may have to take enforcement action against an Unrestricted Subsidiary) would permit upon notice, lapse of time or both any holder of any other Indebtedness (other than the Notes) of the Parent or any of its Restricted Subsidiaries to declare a default on such other Indebtedness or cause the payment of the Indebtedness to be accelerated or payable prior to its Stated Maturity; and

(3) as to which the lenders have been notified in writing that they will not have any recourse to the stock or assets of the Parent or any of its Restricted Subsidiaries.

“Obligations” means any principal, premium, if any, interest (including interest accruing on or after the filing of any petition in bankruptcy or for reorganization, whether or not a claim for post-filing interest is allowed in such proceeding), penalties, fees, charges, expenses, indemnifications, reimbursement obligations, damages, guarantees, and other liabilities or amounts payable under the documentation governing any Indebtedness or in respect thereto.

“Oil and Gas Business” means:

(1) the acquisition, exploration, development, operation and disposition of interests in oil, natural gas and other hydrocarbon properties, including coal bed methane;

(2) the gathering, marketing, treating, processing (but not refining), storage, selling and transporting of any production from those interests, including the conversion of natural gas to electricity to facilitate the sale of natural gas; and

(3) any activity necessary, appropriate or incidental or reasonably related to the activities described above.

“Permitted Business Investments” means Investments made in the ordinary course of, and of a nature that is or shall have become customary in, the Oil and Gas Business, including through agreements, transactions, interests or arrangements that permit one to share risk or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of the Oil and Gas Business jointly with third parties, including without limitation:

(1) direct or indirect ownership of crude oil, natural gas, other related hydrocarbon and mineral properties or any interest therein or gathering, transportation, processing, storage or related systems; and

(2) the entry into operating agreements, joint ventures, processing agreements, working interests, royalty interests, mineral leases, farm-in agreements, farm-out agreements, development agreements, production sharing agreements, area of mutual interest agreements, contracts for the sale, transportation or exchange of crude oil and natural gas and related hydrocarbons and minerals, unitization agreements, pooling arrangements, joint bidding agreements, service contracts, partnership agreements (whether general or limited), or other similar or customary agreements, transactions, properties, interests or arrangements and Investments and

 

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expenditures in connection therewith or pursuant thereto, in each case made or entered into in the ordinary course of the Oil and Gas Business, excluding, however, Investments in corporations and publicly-traded limited partnerships.

“Permitted Investments” means:

(1) any Investment in the Parent or in a Restricted Subsidiary of the Parent;

(2) any Investment in Cash Equivalents;

(3) any Investment by the Parent or any Restricted Subsidiary of the Parent in a Person, if as a result of such Investment:

(a) such Person becomes a Restricted Subsidiary of the Parent; or

(b) such Person is merged, consolidated or amalgamated with or into, or transfers or conveys substantially all of its properties or assets to, or is liquidated into, the Parent or a Restricted Subsidiary of the Parent;

(4) any Investment made as a result of the receipt of non-cash consideration from an Asset Sale that was made pursuant to and in compliance with the covenant described above under the caption “—Repurchase at the Option of Holders—Asset Sales;”

(5) any Investment in any Person solely in exchange for the issuance of Equity Interests (other than Disqualified Stock) of the Parent;

(6) any Investments received in compromise of obligations of trade creditors or customers that were incurred in the ordinary course of business, including pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of any trade creditor or customer;

(7) Hedging Obligations permitted to be incurred under the “Incurrence of Indebtedness and Issuance of Preferred Stock” covenant;

(8) Permitted Business Investments; and

(9) other Investments in any Person having an aggregate fair market value (measured on the date each such Investment was made and without giving effect to subsequent changes in value), when taken together with all other Investments made pursuant to this clause (9) that are at the time outstanding, not to exceed $3.0 million.

“Permitted Liens” means:

(1) Liens on any property or assets of the Parent, the Company or any Subsidiary Guarantor securing First Priority Claims;

(2) Liens in favor of the Company or any Guarantor;

(3) Liens on any property or assets of a Person existing at the time such Person is merged with or into or consolidated with the Parent or any Restricted Subsidiary of the Parent, provided that such Liens were in existence prior to the contemplation of such merger or consolidation and do not extend to any property or assets other than those of the Person merged into or consolidated with the Parent or the Restricted Subsidiary;

(4) Liens on any property or assets existing at the time of acquisition thereof by the Parent or any Restricted Subsidiary of the Parent, provided that such Liens were not incurred in connection with the contemplation of such acquisition;

(5) Liens to secure the performance of statutory obligations, surety or appeal bonds, performance bonds or other obligations of a like nature incurred in the ordinary course of business;

 

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(6) Liens existing on the Issue Date;

(7) Liens arising from Uniform Commercial Code financing statement filings regarding operating leases entered into by the Parent and its Restricted Subsidiaries in the ordinary course of business;

(8) Liens securing Permitted Refinancing Indebtedness incurred to refinance Indebtedness that was previously so secured, provided that any such Lien is limited to all or part of the same property or assets (plus improvements, accessions, proceeds or dividends or distributions in respect thereof) that secured (or, under the written arrangements under which the original Lien arose, could secure) the Indebtedness being refinanced or is in respect of property that is the security for a Permitted Lien hereunder;

(9) Liens securing Hedging Obligations of the Parent or any of its Restricted Subsidiaries;

(10) Liens securing Indebtedness incurred in connection with the acquisition by the Parent or any Restricted Subsidiary of assets used in the Oil and Gas Business (including the office buildings and other real property used by the Parent or such Restricted Subsidiary in conducting its operations); provided that (i) such Liens attach only to the assets acquired with the proceeds of such Indebtedness; and (ii) such Indebtedness is not in excess of the purchase price of such fixed assets;

(11) any Lien incurred in the ordinary course of business incidental to the conduct of the business of the Parent or the Restricted Subsidiaries or the ownership of their property (including (a) easements, rights of way and similar encumbrances, (b) rights or title of lessors under leases (other than Capital Lease Obligations), (c) rights of collecting banks having rights of setoff, revocation, refund or chargeback with respect to money or instruments of the Parent or the Restricted Subsidiaries on deposit with or in the possession of such banks, (d) Liens imposed by law, including Liens under workers’ compensation or similar legislation and mechanics’, carriers’, warehousemen’s, materialmen’s, suppliers’ and vendors’ Liens, (e) Liens incurred to secure performance of obligations with respect to statutory or regulatory requirements, performance or return-of-money bonds, surety bonds or other obligations of a like nature and incurred in a manner consistent with industry practice, or (f) operators Liens under joint operating agreements or similar customary agreements in the Oil and Gas Business);

(12) Liens for taxes, assessments and governmental charges not yet due or the validity of which are being contested in good faith by appropriate proceedings, promptly instituted and diligently conducted, and for which adequate reserves have been established to the extent required by GAAP as in effect at such time;

(13) Liens securing the Notes or obligations under the indenture or Collateral Agreements; or

(14) Liens incurred in the ordinary course of business of the Parent or any Restricted Subsidiary of the Parent with respect to obligations that do not exceed $3.0 million at any one time outstanding.

“Permitted Refinancing Indebtedness” means any Indebtedness of the Parent or any of its Restricted Subsidiaries issued in exchange for, or the net proceeds of which are used to extend, refinance, renew, replace, defease or refund other Indebtedness of the Parent or any of its Restricted Subsidiaries (other than intercompany Indebtedness); provided that:

(1) the principal amount (or accreted value, if applicable) of such Permitted Refinancing Indebtedness does not exceed the principal amount (or accreted value, if applicable) of the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded (plus all accrued interest on the Indebtedness and the amount of all expenses and premiums incurred in connection therewith);

(2) such Permitted Refinancing Indebtedness has a final maturity date later than the final maturity date of, and has a Weighted Average Life to Maturity equal to or greater than the Weighted Average Life to Maturity of, the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded;

(3) if the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded is subordinated in right of payment to the Notes or the Guarantees, such Permitted Refinancing Indebtedness is subordinated in right of payment to the Notes or the Guarantees on terms at least as favorable to the Holders of Notes as those contained in the documentation governing the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded; and

 

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(4) such Indebtedness is not incurred by a Restricted Subsidiary of the Parent if the Parent is the obligor on the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded; provided, however, that the Company or a Restricted Subsidiary that is also a Subsidiary Guarantor may guarantee Permitted Refinancing Indebtedness incurred by the Parent, whether or not such Restricted Subsidiary was an obligor on or guarantor of the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded.

“Person” means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company or government or other entity.

“Production Payments” means, collectively, Dollar-Denominated Production Payments and Volumetric Production Payments.

“Registered Exchange Offer” has the meaning set forth for such term in the applicable registration rights agreement.

“Restricted Investment” means an Investment other than a Permitted Investment.

“Restricted Subsidiary” of a Person means any Subsidiary of the referent Person that is not an Unrestricted Subsidiary.

“Senior Debt” means all Indebtedness of the Parent or any of its Restricted Subsidiaries permitted to be incurred under the terms of the indenture, unless the instrument under which such Indebtedness is incurred expressly provides that it is subordinated in right of payment to the Notes or any Guarantee, and all Obligations with respect to the foregoing.

“Significant Subsidiary” means any Subsidiary that would be a “significant subsidiary” as defined in Article 1, Rule 1-02 of Regulation S-X, promulgated pursuant to the Securities Act, as such rule is in effect on the date of the indenture.

“Stated Maturity” means, with respect to any installment of interest or principal on any series of Indebtedness, the date on which the payment of interest or principal was scheduled to be paid in the original documentation governing such Indebtedness, and will not include any contingent obligations to repay, redeem or repurchase any such interest or principal prior to the date originally scheduled for the payment thereof.

“Subsidiary” means, with respect to any specified Person:

(1) any corporation, association or other business entity (other than a partnership) of which more than 50% of the total voting power of Voting Stock is at the time owned or controlled, directly or through another Subsidiary, by that Person or one or more of the other Subsidiaries of that Person (or a combination thereof); and

(2) any partnership (a) the sole general partner or the managing general partner of which is such Person or a Subsidiary of such Person, (b) the only general partners of which are that Person or one or more Subsidiaries of that Person (or any combination thereof), or (c) as to which such Person and its Subsidiaries are entitled to receive more than 50% of the assets of such partnership upon its dissolution.

“Subsidiary Guarantors” means each Restricted Subsidiary of the Parent (other than the Company) that executes the indenture as an initial Subsidiary Guarantor or that becomes a Subsidiary Guarantor in accordance with the provisions of the indenture, and its successors and assigns.

“Unrestricted Subsidiary” means any Subsidiary of the Parent (other than the Company) that is designated by the Board of Directors as an Unrestricted Subsidiary pursuant to a Board Resolution, but only to the extent that such Subsidiary:

(1) has no Indebtedness other than Non-Recourse Debt;

 

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(2) is not party to any agreement, contract, arrangement or understanding with the Parent or any Restricted Subsidiary of the Parent unless the terms of any such agreement, contract, arrangement or understanding are no less favorable to the Parent or such Restricted Subsidiary than those that might be obtained at the time from Persons who are not Affiliates of the Parent;

(3) is a Person with respect to which neither the Parent nor any of its Restricted Subsidiaries has any direct or indirect obligation (a) to subscribe for additional Equity Interests or (b) to maintain or preserve such Person’s financial condition or to cause such Person to achieve any specified levels of operating results; and

(4) has not guaranteed or otherwise directly or indirectly provided credit support for any Indebtedness of the Parent or any of its Restricted Subsidiaries.

Any designation of a Subsidiary of the Parent as an Unrestricted Subsidiary will be evidenced to the trustee by filing with the trustee the Board Resolution giving effect to such designation and an officers’ certificate certifying that such designation complied with the preceding conditions and was permitted by the covenant described above under the caption “—Certain Covenants—Restricted Payments”. If, at any time, any Unrestricted Subsidiary would fail to meet the preceding requirements as an Unrestricted Subsidiary, it will thereafter cease to be an Unrestricted Subsidiary for purposes of the indenture and any Indebtedness of such Subsidiary will be deemed to be incurred by a Restricted Subsidiary of the Parent as of such date and, if such Indebtedness is not permitted to be incurred as of such date under the covenant described under the caption “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock,” the Parent will be in default of such covenant.

“Volumetric Production Payments” means production payment obligations recorded as deferred revenue in accordance with GAAP, together with all related undertakings and obligations.

“Voting Stock” of any Person as of any date means the Capital Stock of such Person that is at the time entitled (without regard to the occurrence of any contingency) to vote in the election of the Board of Directors of such Person.

“Weighted Average Life to Maturity” means, when applied to any Indebtedness at any date, the number of years obtained by dividing:

(1) the sum of the products obtained by multiplying (a) the amount of each then remaining installment, sinking fund, serial maturity or other required payments of principal, including payment at final maturity, in respect of the Indebtedness, by (b) the number of years (calculated to the nearest one-twelfth) that will elapse between such date and the making of such payment; by

(2) the then outstanding principal amount of such Indebtedness.

Book-Entry, Delivery and Form of Securities

The Global Notes

The new notes will be issued in the form of one or more registered notes in global form, without interest coupons (collectively, the “Global notes”). Upon issuance, each of the Global notes will be deposited with the trustee as custodian for DTC and registered in the name of Cede & Co., as nominee of DTC. Beneficial interests in the Global notes may be held through the Euroclear System (“Euroclear”) and Clearstream Banking, S.A. (“Clearstream”) (as indirect participants in DTC).

Ownership of beneficial interests in each Global note will be limited to persons who have accounts with DTC (“DTC participants”) or persons who hold interests through DTC participants. The Company expects that under procedures established by DTC:

 

•

Upon deposit of each Global note with DTC’s custodian, DTC will credit portions of the principal amount of the Global note to the accounts of the DTC participants designated by the initial purchasers; and

 

•

Ownership of beneficial interests in each Global note will be shown on, and transfer of ownership of those interests will be effected only through, records maintained by DTC (with respect to interests of DTC participants) and the records of DTC participants (with respect to other owners of beneficial interests in the Global note).

 

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Beneficial interests in the Global notes may not be exchanged for notes in physical, certificated form except in the limited circumstances described below.

Book-Entry Procedures for the Global Notes

All interests in the Global notes will be subject to the operations and procedures of DTC, Euroclear and Clearstream. The Company provides the following summaries of those operations and procedures solely for the convenience of investors. The operations and procedures of each settlement system are controlled by that settlement system and may be changed at any time. Neither the Company nor the initial purchasers are responsible for those operations or procedures.

DTC has advised the Company that it is:

 

•

A limited purpose trust company organized under the laws of the State of New York;

 

•

A “banking organization” within the meaning of the New York State Banking Law;

 

•

A member of the Federal Reserve System;

 

•

A “clearing corporation” within the meaning of the Uniform Commercial Code; and

 

•

A “clearing agency” registered under Section 17A of the Securities Exchange Act of 1934.

DTC was created to hold securities for its participants and to facilitate the clearance and settlement of securities transactions between its participants through electronic book-entry changes to the accounts of its participants. DTC’s participants include securities brokers and dealers, including the initial purchasers, banks and trust companies, clearing corporations and other organizations. Indirect access to DTC’s system is also available to others such as banks, brokers, dealers and trust companies; these indirect participants clear through or maintain a custodial relationship with a DTC participant, either directly or indirectly. Investors who are not DTC participants may beneficially own securities held by or on behalf of DTC only through DTC participants or indirect participants in DTC.

So long as DTC’s nominee is the registered owner of a Global note, that nominee will be considered the sole owner or holder of the notes represented by that Global note for all purposes under the Indenture. Except as provided below, owners of beneficial interests in a Global note:

 

•

Will not be entitled to have notes represented by the Global note registered in their names;

 

•

Will not receive or be entitled to receive physical, certificated notes; and

 

•

Will not be considered the owners or holders of the notes under the Indenture for any purpose, including with respect to the giving of any direction, instruction or approval to the trustee under the Indenture.

As a result, each investor who owns a beneficial interest in a Global note must rely on the procedures of DTC to exercise any rights of a holder of the notes under the Indenture (and, if the investor is not a participant or an indirect participant in DTC, on the procedures of the DTC participant through which the investor owns its interest).

Payments of principal, premium (if any) and interest with respect to the notes represented by a Global note will be made by the trustee to DTC’s nominee as the registered holder of the Global note. Neither the Company nor the trustee will have any responsibility or liability for the payment of amounts to owners of beneficial interests in a Global note, for any aspect of the records relating to or payments made on account of those interests by DTC, or for maintaining, supervising or reviewing any records of DTC relating to those interests.

 

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Payments by participants and indirect participants in DTC to the owners of beneficial interests in a Global note will be governed by standing instructions and customary industry practice and will be the responsibility of those participants or indirect participants and DTC.

Transfers between participants in DTC will be effected under DTC’s procedures and will be settled in same-day funds. Transfers between participants in Euroclear or Clearstream will be effected in the ordinary way under the rules and operating procedures of those systems.

Cross-market transfers between DTC participants, on the one hand, and Euroclear or Clearstream participants, on the other hand, will be effected within DTC through the DTC participants that are acting as depositaries for Euroclear and Clearstream. To deliver or receive an interest in a Global note held in a Euroclear or Clearstream account, an investor must send transfer instructions to Euroclear or Clearstream, as the case may be, under the rules and procedures of that system and within the established deadlines of that system. If the transaction meets its settlement requirements, Euroclear or Clearstream, as the case may be, will send instructions to its DTC depositary to take action to effect final settlement by delivering or receiving interests in the relevant Global notes in DTC, and making or receiving payment under normal procedures for same-day funds settlement applicable to DTC. Euroclear and Clearstream participants may not deliver instructions directly to the DTC depositaries that are acting for Euroclear or Clearstream.

Because of time zone differences, the securities account of a Euroclear or Clearstream participant that purchases an interest in a Global note from a DTC participant will be credited on the business day for Euroclear or Clearstream immediately following the DTC settlement date. Cash received in Euroclear or Clearstream from the sale of an interest in a Global note to a DTC participant will be received with value on the DTC settlement date but will be available in the relevant Euroclear or Clearstream cash account as of the business day for Euroclear or Clearstream following the DTC settlement date.

DTC, Euroclear and Clearstream have agreed to the above procedures to facilitate transfers of interests in the Global notes among participants in those settlement systems. However, the settlement systems are not obligated to perform these procedures and may discontinue or change these procedures at any time. Neither the Company nor the trustee will have any responsibility for the performance by DTC, Euroclear or Clearstream or their participants or indirect participants of their obligations under the rules and procedures governing their operations.

Exchange of Global Notes for Certificated Notes

A Global Note is exchangeable for certificated notes, if:

(1) DTC (a) notifies us that it is unwilling or unable to continue as depositary for the Global Notes or (b) has ceased to be a clearing agency registered under the Exchange Act and in either event the Company fails to appoint a successor depositary within 90 days; or

(2) there has occurred and is continuing an Event of Default and DTC notifies the trustee of its decision to exchange the Global Note for certificated notes.

Beneficial interests in a Global Note also may be exchanged for certificated notes upon prior written notice given to the trustee by or on behalf of DTC in the limited other circumstances permitted by the indenture. In all cases, certificated notes delivered in exchange for any Global Note or beneficial interests in Global Notes will be registered in the names, and issued in any approved denominations, requested by or on behalf of the depositary (in accordance with its customary procedures) and will bear the restrictive legend referred to in “Notice to Investors,” unless that legend is not required by applicable law.

Exchange of Certificated Notes for Global Notes

Certificated notes may not be exchanged for beneficial interests in any Global Note unless the transferor first delivers to the trustee a written certificate (in the form provided in the indenture) to the effect that such transfer will comply with the appropriate transfer restrictions applicable to such notes. See “Notice to Investors”.

 

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CERTAIN U.S. FEDERAL TAX CONSIDERATIONS

Exchange Offer

We believe that the receipt of new notes in exchange for old notes in the exchange offer will not be treated as a taxable exchange for United States federal income tax purposes. The new notes will not differ materially in kind or extent from the old notes and, as a result, your exchange of old notes for new notes will not constitute a taxable disposition of the old notes for U.S. federal income tax purposes. As a result, you will not recognize taxable income, gain or loss on such exchange, your holding period for the new notes will generally include the holding period for the old notes so exchanged, and your adjusted tax basis in the new notes will generally be the same as your adjusted tax basis in the old notes so exchanged.

 

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PLAN OF DISTRIBUTION

Based on interpretations by the staff of the SEC in no action letters issued to third parties, we believe that you may transfer new notes issued under the exchange offer in exchange for the old notes if:

 

•

You acquire the new notes in the ordinary course of your business; and

 

•

You are not engaged in, and do not intend to engage in, and have no arrangement or understanding with any person to participate in, a distribution of such new notes.

You may not participate in the exchange offer if you are:

 

•

A broker-dealer that acquired old notes directly from us.

Each broker-dealer that receives new notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. To date, the staff of the SEC has taken the position that broker-dealers may fulfill their prospectus delivery requirements with respect to transactions involving an exchange of securities such as this exchange offer, other than a resale of an unsold allotment from the original sale of the old notes, with the prospectus contained in this registration statement. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where such old notes were acquired as a result of market-making activities or other trading activities. We have agreed that, for a period of up to 180 days after the consummation of the exchange offer, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale. In addition, until such date, all dealers effecting transactions in new notes may be required to deliver a prospectus.

If you are an “affiliate,” as defined in Rule 405 of the Securities Act, of ours, you must comply with any applicable registration and prospectus delivery requirements of the Securities Act in connection with any resale of the notes.

If you wish to exchange your old notes for new notes in the exchange offer, you will be required to make representations to us as described in “Exchange Offer—Purpose and Effect of the Exchange Offer” and “—Procedures for Tendering—Valid Tender” in this prospectus. As indicated in the letter of transmittal, you will be deemed to have made these representations by tendering your old notes in the exchange offer. In addition, if you are a broker-dealer who receives new notes for your own account in exchange for old notes that were acquired by you as a result of market-making activities or other trading activities, you will be required to acknowledge, in the same manner, that you will deliver a prospectus in connection with any resale by you of such new notes.

We will not receive any proceeds from any sale of new notes by broker-dealers. New notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the new notes or a combination of such methods of resale, at market prices prevailing at the time of resale, and at prices related to such prevailing market prices or negotiated prices.

Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such new notes. Any broker-dealer that resells new notes that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such new notes may be deemed to be an “underwriter” within the meaning of the Securities Act and any profit on any such resale of new notes and any commission or concession received by any such persons may be deemed to be underwriting compensation under the Securities Act. The letter of transmittal states that, by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.

For a period of up to 180 days after the consummation of the exchange offer, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents in the letter of transmittal. We have agreed to pay all expenses incident to the exchange offer other than commissions or concessions of any broker-dealers and will indemnify the holders of the old notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

 

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DTC was created to hold securities for its participants and to facilitate the clearance and settlement of securities transactions between its participants through electronic book-entry changes to the accounts of its participants. DTC’s participants include securities brokers and dealers, including the initial purchasers, banks and trust companies, clearing corporations and other organizations. Indirect access to DTC’s system is also available to others such as banks, brokers, dealers and trust companies; these indirect participants clear through or maintain a custodial relationship with a DTC participant, either directly or indirectly. Investors who are not DTC participants may beneficially own securities held by or on behalf of DTC only through DTC participants or indirect participants in DTC.

So long as DTC’s nominee is the registered owner of a Global note, that nominee will be considered the sole owner or holder of the notes represented by that Global note for all purposes under the Indenture. Except as provided below, owners of beneficial interests in a Global note:

 

•

Will not be entitled to have notes represented by the Global note registered in their names;

 

•

Will not receive or be entitled to receive physical, certificated notes; and

 

•

Will not be considered the owners or holders of the notes under the Indenture for any purpose, including with respect to the giving of any direction, instruction or approval to the trustee under the Indenture.

As a result, each investor who owns a beneficial interest in a Global note must rely on the procedures of DTC to exercise any rights of a holder of the notes under the Indenture (and, if the investor is not a participant or an indirect participant in DTC, on the procedures of the DTC participant through which the investor owns its interest).

Payments of principal, premium (if any) and interest with respect to the notes represented by a Global note will be made by the trustee to DTC’s nominee as the registered holder of the Global note. Neither the Company nor the trustee will have any responsibility or liability for the payment of amounts to owners of beneficial interests in a Global note, for any aspect of the records relating to or payments made on account of those interests by DTC, or for maintaining, supervising or reviewing any records of DTC relating to those interests.

Payments by participants and indirect participants in DTC to the owners of beneficial interests in a Global note will be governed by standing instructions and customary industry practice and will be the responsibility of those participants or indirect participants and DTC.

Transfers between participants in DTC will be effected under DTC’s procedures and will be settled in same-day funds. Transfers between participants in Euroclear or Clearstream will be effected in the ordinary way under the rules and operating procedures of those systems.

Cross-market transfers between DTC participants, on the one hand, and Euroclear or Clearstream participants, on the other hand, will be effected within DTC through the DTC participants that are acting as depositaries for Euroclear and Clearstream. To deliver or receive an interest in a Global note held in a Euroclear or Clearstream account, an investor must send transfer instructions to Euroclear or Clearstream, as the case may be, under the rules and procedures of that system and within the established deadlines of that system. If the transaction meets its settlement requirements, Euroclear or Clearstream, as the case may be, will send instructions to its DTC depositary to take action to effect final settlement by delivering or receiving interests in the relevant Global notes in DTC, and making or receiving payment under normal procedures for same-day funds settlement applicable to DTC. Euroclear and Clearstream participants may not deliver instructions directly to the DTC depositaries that are acting for Euroclear or Clearstream.

Because of time zone differences, the securities account of a Euroclear or Clearstream participant that purchases an interest in a Global note from a DTC participant will be credited on the business day for Euroclear or Clearstream immediately following the DTC settlement date. Cash received in Euroclear or Clearstream from the sale of an interest in a Global note to a DTC participant will be received with value on the DTC settlement date but will be available in the relevant Euroclear or Clearstream cash account as of the business day for Euroclear or Clearstream following the DTC settlement date.

 

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DTC, Euroclear and Clearstream have agreed to the above procedures to facilitate transfers of interests in the Global notes among participants in those settlement systems. However, the settlement systems are not obligated to perform these procedures and may discontinue or change these procedures at any time. Neither the Company nor the trustee will have any responsibility for the performance by DTC, Euroclear or Clearstream or their participants or indirect participants of their obligations under the rules and procedures governing their operations.

LEGAL MATTERS

The validity of the new notes being offered hereby and certain other legal matters are being passed upon for us by Vinson & Elkins L.L.P., Houston, Texas.

EXPERTS

The consolidated financial statements and schedule as of December 31, 2007 and 2006 and for each of the three years in the period ended December 31, 2007 and management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2007 included in this Prospectus have been so included in reliance on the reports of BDO Seidman, LLP, an independent registered public accounting firm, appearing elsewhere herein given on the authority of said firm as experts in auditing and accounting.

INDEPENDENT PETROLEUM ENGINEERS

The information included in this prospectus regarding estimated quantities of proved reserves applicable to our domestic oil and gas properties as of December 31, 2004, 2005, 2006, and 2007, were prepared or derived from estimates prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers based on guidelines established by the Securities and Exchange Commission.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-4 with respect to the notes being offered by this prospectus. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the notes offered by this prospectus, please review the full registration statement, including its exhibits. The registration statement, including the exhibits, may be inspected and copied at the public reference facilities maintained by the SEC at 100 F Street, N.E., Washington D.C. 20549. Copies of this material can also be obtained from the public reference section of the SEC at prescribed rates, or accessed at the SEC’s website at www.sec.gov. Please call the SEC at 1-800-SEC-0330 for further information on its public reference room. In addition, our Parent files with or furnishes to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC’s website as provided above.

 

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INDEX TO FINANCIAL STATEMENTS

 

Contents		Page
Unaudited Condensed Consolidated Balance Sheets as of March 31, 2008 and December 31, 2007		F-2
Unaudited Condensed Consolidated Statements of operations for the Three Months Ended March 31, 2008 and 2007		F-3
Unaudited Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2008 and 2007		F-4
Notes to the Unaudited Condensed Consolidated Financial Statements		F-5
Report of Independent Registered Public Accounting Firm		F-27
Consolidated Balance Sheets as of December 31, 2007 and 2006		F-28
Consolidated Statements of Operations for the Years Ended December 31, 2007, 2006 and 2005		F-29
Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2007, 2006 and 2005		F-30
Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005		F-31
Notes to Consolidated Financial Statements		F-32
Schedule II, Valuation and Qualifying Accounts		F-76

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

 

		March 31, 2008				December 31, 2007
		(Unaudited)
		(in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	78,968			$	85,854
Accounts receivable, net of allowance for doubtful accounts of $4.3 million for both periods			8,769				4,828
Due from related parties			1,611				904
Prepaid expenses			1,117				1,235
Total current assets			90,465				92,821
PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, full cost method of accounting:
Unproved properties, not being amortized			84,279				69,844
Proved properties			249,490				247,372
Total natural gas and oil properties			333,769				317,216
Furniture and equipment			763				669
Total property, plant and equipment			334,532				317,885
Accumulated depreciation, depletion and amortization			(167,174	)			(160,765	)
Total property, plant and equipment, net			167,358				157,120
OTHER ASSETS:
Restricted cash			76				1,074
Deferred charges, net			7,916				8,334
Drilling advances			2,320				2,251
Other assets			150				150
Total other assets			10,462				11,809
TOTAL ASSETS		$	268,285			$	261,750
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable		$	11,233			$	12,001
Revenue payable			7,728				6,770
Accrued interest			4,790				1,534
Accrued drilling and operating costs			2,048				2,810
Commodity derivative contracts			5,422				480
Other accrued liabilities			4,306				4,831
Due to related parties			1,865				979
Total current liabilities			37,392				29,405
LONG-TERM LIABILITIES:
Long-term debt			132,715				132,685
Asset retirement obligation			4,473				4,391
Commodity derivative contracts			545				—
Total long-term liabilities			137,733				137,076
COMMITMENTS AND CONTINGENCIES (Footnote 12)
SHAREHOLDERS’ EQUITY:
Common stock, no par value, unlimited shares authorized, 208,204,570 and 208,194,570 common shares issued and outstanding at March 31, 2008 and December 31, 2007, respectively			249,980				249,980
Additional paid-in capital			15,222				14,366
Accumulated other comprehensive loss – fair value of commodity hedging			(4,554	)			(480	)
Accumulated other comprehensive loss – foreign exchange			(7	)			(29	)
Accumulated deficit			(167,481	)			(168,568	)
Total shareholders’ equity			93,160				95,269
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY		$	268,285			$	261,750

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

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

		For the Three Months Ended March 31,
		2008				2007
		(in thousands, except shares and per share data)
REVENUES:
Natural gas and oil revenues		$	16,846			$	7,515
Unrealized natural gas hedge loss			(1,413	)			—
Total revenues			15,433				7,515
EXPENSES:
Production taxes			269				294
Lease operating expenses			1,542				1,695
Transportation and treating			459				323
Depreciation, depletion and amortization			6,409				4,341
Accretion of asset retirement obligation			82				66
Mineral resource properties			—				13
General and administrative expenses			4,275				6,792
Litigation settlement expense			—				1,365
Total expenses			13,036				14,889
INCOME (LOSS) FROM OPERATIONS			2,397				(7,374	)
OTHER (EXPENSES) INCOME:
Interest expense			(2,096	)			(3,943	)
Investment income and other			823				363
Foreign transaction loss			(37	)			(1	)
INCOME (LOSS) BEFORE INCOME TAXES			1,087				(10,955	)
Provision for income taxes			—				—
NET INCOME (LOSS)		$	1,087			$	(10,955	)
NET INCOME (LOSS) PER SHARE:
Basic and diluted		$	0.01			$	(0.06	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic and diluted			207,098,570				195,015,561

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

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

		For the Three Months Ended March 31,
		2008				2007
		(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)		$	1,087			$	(10,955	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization			6,409				4,341
Stock based compensation			856				1,236
Unrealized natural gas hedge loss			1,413				—
Amortization of deferred financing costs and debt discount			463				1,077
Accretion of asset retirement obligation			82				66
Changes in operating assets and liabilities:
Restricted cash for hedging program			1,000				—
Accounts receivable			(4,648	)			2,298
Prepaid expenses			118				321
Accounts payable and accrued liabilities			7,512				1,897
Net cash provided by operating activities			14,292				281
CASH FLOWS FROM INVESTING ACTIVITIES:
Development and purchases of natural gas and oil properties			(19,957	)			(18,389	)
Drilling advances			(1,132	)			—
Purchase of furniture and equipment			(94	)			(15	)
Net cash used in investing activities			(21,183	)			(18,404	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Increase in restricted cash			(2	)			(1	)
Deferred financing charges and other			7				—
Net cash provided (used in) by financing activities			5				(1	)
NET DECREASE IN CASH AND CASH EQUIVALENTS			(6,886	)			(18,124	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD			85,854				40,733
CASH AND CASH EQUIVALENTS, END OF PERIOD		$	78,968			$	22,609

The accompanying notes are an integral part of these condensed financial statements.

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Summary of Significant Accounting Policies

The accounting policies followed by Gastar Exploration Ltd. (the “Company”) are set forth in the notes to the Company’s audited condensed consolidated financial statements in its Annual Report on Form 10-K for the year ended December 31, 2007. Additionally, refer to the notes to those financial statements for additional details of the Company’s financial condition, results of operations and cash flows. All material items included in those notes have not changed except as a result of normal transactions in the interim or as disclosed within this report. The accompanying interim condensed consolidated financial statements have not been audited by independent registered public accountants but, in the opinion of management, reflect all normal and recurring adjustments considered necessary for a fair presentation of the financial position and results of operations. The results of operations for the three months ended March 31, 2008 are not necessarily indicative of results to be expected for the full year.

The condensed consolidated financial statements of the Company are presented in United States (“U.S.”) dollars unless otherwise noted and have been prepared by management in accordance with accounting principles generally accepted in the United States of America (“US GAAP”). The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved natural gas and oil reserve quantities and the related present value of estimated future net cash flows.

The condensed consolidated financial statements include the accounts of the Company and the consolidated accounts of all its subsidiaries. The entities included in these consolidated accounts are all wholly owned. All significant intercompany accounts and transactions have been eliminated in consolidation.

Certain information provided for the prior period has been reclassified to conform to the presentation adopted in 2008.

New Accounting Pronouncements

Fair Value Measurements. In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS 157, Fair Value Measurements (“SFAS 157”), which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. SFAS 157 applies to other accounting pronouncements that require or permit fair value measurements; however, it does not require any new fair value measurements. The provisions of SFAS 157 are effective for the years beginning after November 15, 2007 and interim periods within those years. The FASB has also issued Staff Position FSP FAS No. 157-2 (“FSP FAS No. 157-2”), which delays the effective date of SFAS 157 for nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until fiscal years beginning after November 15, 2008. Effective January 1, 2008, the Company adopted SFAS 157 and has chosen to defer the implementation of nonfinancial assets and liabilities in accordance with FSP FAS No. 157-2. The effect of adoption in January 1, 2008 was immaterial to the Company’s financial position. The adoption of FSP FAS No. 157-2 is not expected to have a material impact on the Company’s results of operations, cash flows or financial positions. See Note 10, “Fair Value Measurements” for additional information regarding the adoption of SFAS No. 157.

FASB Statement of Accounting Standard No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”): SFAS No. 159, issued in February 2007, allows entities the option to measure eligible financial instruments at fair value as of specified dates. Such election, which may be applied on an instrument by instrument basis, is typically irrevocable once elected. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007, and early application is allowed under certain circumstances. The Company adopted SFAS 159 on January 1, 2008, which allows an entity the

 

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Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

irrevocable option to elect fair value for the initial and subsequent measurement for certain financial assets and liabilities on a contract-by-contract basis. The Company did not elect fair value as an alternative, as provided under SFAS 159 for any of its financial assets and liabilities that are not currently measured at fair value.

Non-controlling Interests in Consolidated Financial Statements. In December 2007, the FASB Issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of Accounting Research Bulletin No. 51” (“SFAS No. 160”), which improves the relevance, comparability and transparency of the financial information that a reporting entity provides in its consolidated financial statements by establishing accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. This statement is effective for fiscal years beginning after December 15, 2008. The Company does not expect the adoption of SFAS No. 160 to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.

Business Combinations. In December 2007, FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS No. 141R”), which replaces SFAS No. 141 (“SFAS No. 141”). This statement retains the fundamental requirements in SFAS No. 141 that the acquisition method of accounting (which SFAS No. 141 called the purchase method) be used for all business combinations. SFAS No. 141R also establishes principles and requirements for how the acquirer: (a) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (b) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and (c) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141R is effective as of the beginning of an entity’s fiscal year that begins after December 15, 2008. Early adoption is prohibited. The Company is currently evaluating the impact of adopting SFAS No. 141R, which also requires acquisition transaction costs to be expensed as incurred rather than capitalized as a direct cost of the acquisition, as transaction costs are not considered an element of the fair value of the company acquired. Depending upon the size, nature and complexity of a future acquisition transaction, such transaction costs could be material to the Company’s results of operations.

2. Property, Plant and Equipment

The amount capitalized as natural gas and oil properties was incurred for the purchase and development of various properties in the states of California, Montana, Texas, West Virginia and Wyoming in the United States and in New South Wales and Victoria in Australia. The following schedule represents natural gas and oil property costs by country:

 

		United States				Australia				Total
		(in thousands)
From inception to March 31, 2008:
Natural gas and oil properties, full cost method of accounting:
Unproved properties		$	59,562			$	24,717			$	84,279
Proved properties			248,886				604				249,490
Total natural gas and oil properties			308,448				25,321				333,769
Furniture and equipment			666				97				763
Total property and equipment			309,114				25,418				334,532
Impairment of proved natural gas and oil properties			(104,205	)			(604	)			(104,809	)
Accumulated depreciation, depletion and amortization			(62,350	)			(15	)			(62,365	)
Total accumulated depreciation, depletion and amortization			(166,555	)			(619	)			(167,174	)
Total property and equipment, net		$	142,559			$	24,799			$	167,358

At March 31, 2008, unproved properties not being amortized consisted of U.S. drilling in progress costs of $9.9 million, U.S. acreage acquisition costs of $49.7 million and Australian unevaluated property costs of $24.7 million.

 

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Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

There was no impairment of United States or Australian properties during the three months ended March 31, 2008 or 2007.

3. Long-Term-Debt

The following shows the Company’s long-term debt as of the dates indicated:

 

		March 31, 2008			December 31, 2007
		(in thousands)
Revolving credit facility		$	—		$	—
12 3/4% senior secured notes			99,524			99,506
Convertible senior debenture			30,000			30,000
Subordinated unsecured notes payable			3,191			3,179
Total net carrying value of long-term debt			132,715			132,685
Debt discount costs to be accreted			535			565
Total long-term debt at maturity		$	133,250		$	133,250

12 ³/4% Senior Secured Notes due 2012

On November 29, 2007, Gastar Exploration USA, Inc. (“Gastar USA”), a wholly owned subsidiary of Gastar Exploration Ltd., (“Parent”) sold $100.0 million aggregate principal amount of 12 ³/4% Senior Secured Notes due December 1, 2012 (“12 ³/4% Senior Secured Notes”) at an issue price of 99.50%. Approximately $76.7 million of the $92.5 million net proceeds from the offering were used to repay the then outstanding senior secured notes, with the remaining net proceeds to be used for general corporate purposes. Interest is payable, semi-annually on June 1 and December 1, in cash on the principal amount at an annual rate of 12 ³/4%. The annual effective interest rate, after amortization of the debt discount and fees paid to establish the 12 ³/4% Senior Secured Notes, is 14.89%. The 12 ³/4% Senior Secured Notes are fully and unconditionally guaranteed jointly and severally by Gastar USA, the Parent and all of the Parent’s existing and future material domestic subsidiaries. The 12 ³/4% Senior Secured Notes and the guarantees are secured by a lien on Gastar USA’s principal domestic oil and gas properties and other assets that secure Gastar USA’s revolving credit facility (“Revolving Credit Facility”), subject to certain exceptions. The 12 ³/4% Senior Secured Notes mature on December 1, 2012.

As of March 31, 2008, the Company was in compliance with all debt covenants under the 12 ³/4% Senior Secured Notes.

Revolving Credit Facility

On November 29, 2007, concurrent with the closing of the 12 ³/4% Senior Secured Notes, Gastar USA entered into a revolving credit facility currently providing for a first priority lien maximum borrowing base of $19.4 million. At March 31, 2008, $2.5 million of the available borrowing base was utilized as collateral for a $2.5 million letter of credit to support the Company’s hedging activities. The balance of the borrowing base, or $16.9 million, remained available to the Company. The borrowing base is to be redetermined at least semiannually, using the lender’s usual and customary criteria for natural gas and oil reserve valuation. The applicable interest rate margin varies from -0.75% to 0.0% in the case of borrowings based on the prime rate and from 1.5% to 2.25% in the case of borrowings based on the Eurodollar rate, depending on the utilization level in relation to the borrowing base. At March 31, 2008, the prime rate and the Eurodollar rate were 5.25% and 2.7%, respectively. The Revolving Credit Facility is guaranteed by the Parent and all its current domestic subsidiaries and all future domestic subsidiaries formed during the term of the Revolving Credit Facility. Borrowings and related guarantees under the Revolving Credit Facility are secured by a first priority lien on all domestic natural gas and oil properties currently owned by or later acquired by Gastar USA, excluding de minimus value properties as determined by the lender. The revolving credit facility matures on October 15, 2009.

 

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Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

As of March 31, 2008, the Company was in compliance with all debt covenants under the revolving credit facility.

Convertible Senior Debentures

In November 2004, the Company issued $30.0 million aggregate principal amount of convertible senior unsecured debentures. The convertible senior debentures have a term of five years and will be due November 20, 2009 and bear interest at 9.75% per annum, payable quarterly. The convertible senior debentures are convertible by the holders into 6,849,315 common shares at a conversion price of $4.38 per share

Subordinated Unsecured Notes Payable

The Company’s subordinated unsecured notes mature between April 2009 and September 2009, bear interest at 10% per annum and are callable by the Company at 105% after three years and 101% after four years.

4. Equity Compensation Plans

Share-Based Compensation Plans

2002 Stock Option Plan. The Company’s 2002 Stock Option Plan was approved and ratified by the Company’s shareholders in July 2002. It authorizes the Company’s Board of Directors to issue stock options to directors, officers, employees and consultants of the Company and its subsidiaries to purchase a maximum of 25.0 million common shares. Stock option grant expirations vary between five and ten years. The vesting schedule has varied from two years to four years but generally has occurred over a four-year period at 25% per year beginning on the first anniversary date of the grant. Stock options issued pursuant to the Company’s 2002 Stock Option Plan have an exercise price determined by the Board of Directors, but that exercise price cannot be less than the market price on the date immediately prior to the date of grant as reported by any stock exchange on which the Company’s common shares are listed. If a stock option granted under the Company’s 2002 Stock Option Plan expires or terminates for any reason in accordance with the terms of the Company’s Stock Option Plan, the unpurchased common shares subject to that stock option become available for other stock option grants.

In April 2004, the Board of Directors amended the provisions of the Company’s 2002 Stock Option Plan to specifically incorporate a provision to provide for stock options to be exercised on a cashless basis, whereby the Company issues to the optionee the number of common shares equal to the stock option exercised, less the number of common shares which when multiplied by the market price at the date of exercise equals the aggregate exercise price for all of the common shares exercised. As of March 31, 2008, stock option grants covering the issuance of 9,648,750 common shares were outstanding under the 2002 Stock Option Plan.

2006 Gastar Long-Term Stock Incentive Plan. On June 1, 2006, the Company’s shareholders approved the 2006 Gastar Long-Term Stock Incentive Plan. The 2006 Gastar Long-Term Stock Incentive Plan authorizes the Company’s Board of Directors to issue stock options, stock appreciation rights, bonus stock awards and any other type of award established by the Remuneration Committee which is consistent with the Plan’s purposes to directors, officers and employees of the Company and its subsidiaries covering a maximum of 5.0 million common shares. The contractual life and vesting period for a grant is determined by the Board of Directors at the time the grant is awarded. The vesting period for restricted common stock grants during 2007 and 2008 was over four years, with one-third vesting on the second, third and fourth anniversaries of the date of grant. As of March 31, 2008, grants covering the issuance of 1,106,000 restricted common shares were outstanding under the 2006 Gastar Long-Term Stock Incentive Plan.

 

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Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Determining Fair Value under SFAS No. 123R

In determining fair value for stock option grants pursuant to SFAS No. 123R, the Company utilized the following assumptions:

Valuation and Amortization Method. The Company estimates the fair value of share-based awards granted using the Black-Scholes-Merton valuation model. The fair value of all awards is expensed using the “graded-vesting method”.

Expected Life. The expected life of awards granted represents the period of time that stock options are expected to be outstanding. Prior to 2008, the Company determined the expected life using the “simplified method” resulting in a 6.25-year expected life in accordance with Staff Accounting Bulletin No. 107 for all stock options issued with a four-year vesting period and a ten-year grant expiration. Using the simplified method, stock options that have been issued with two and three-year vesting periods and having a ten-year expiration have an expected life of 5.75 and 6.0 years, respectively. Beginning in 2008, management determined the expected life of stock option grants to be 6.25 years, based on historical records.

Expected Volatility. Using the Black-Scholes-Merton valuation model, the Company estimates the volatility of its common shares at the beginning of the quarter in which the stock option is granted. The volatility is based on historical movements of our common share price on the American Stock Exchange and the Toronto Stock Exchange over a period that approximates the expected life.

Risk-Free Interest Rate. The Company utilizes a risk-free interest rate equal to the rate of U.S. Treasury zero-coupon issues as of the date of grant with a term equivalent to the stock option’s expected life.

Expected Dividend Yield. The Company has not paid any cash dividends on its common shares and does not anticipate paying any cash dividends in the foreseeable future. Consequently, a dividend yield of zero is utilized in the Black-Scholes-Merton valuation model.

Expected Forfeitures. Beginning March 1, 2008, the Company increased the forfeiture rate to 6% from 5% previously used. The forfeiture rate is used in calculating compensation expense and is based on the number of forfeitures of all unvested stock option since January 1, 2004 as a percentage of all stock option grants since January 1, 2004 calculated at the beginning of the year.

The fair value of each stock option grant is estimated on the date of grant using the Black-Scholes-Merton valuation pricing model. There were no stock options granted during the three months ended March 31, 2008. The table below summarizes the number of stock options granted and the assumptions for the stock options granted for the period indicated.

 

		For the Three Months Ended March 31, 2007
Stock options granted		227,000
Expected life (years)		6.25
Expected volatility		44.4	%
Risk-free interest rate		4.6%-4.8	%

 

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Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

The weighted average grant date fair value of stock options granted and the intrinsic value of stock options exercised are shown below for the periods indicated. Intrinsic value of stock options is calculated using the difference between the common share price on the date of exercise and the exercise price times the number of stock options exercised. There were no stock options granted or exercised during the three months ended March 31, 2008.

 

		For the Three Months Ended March 31, 2007
Weighted average fair value per share of stock options granted		$	1.08
Intrinsic value of stock options exercised		$	—

Stock Option Activity

The following table summarizes the annual changes and option exercise prices for stock options under the Company’s Stock Option Plan for the three months ended March 31, 2008:

 

		Number of Shares Under Stock Options		Weighted Average Exercise Price
Stock options outstanding as of December 31, 2007		10,173,750		$	3.19
Stock options granted		—		$	—
Stock options exercised		—		$	—
Stock options cancelled/expired		525,000		$	4.27
Stock options outstanding as of March 31, 2008		9,648,750		$	3.14
Stock options exercisable:
March 31, 2008		5,643,866		$	3.21

The table below summarizes certain information about the stock options for the three months ended March 31, 2008. Fair value calculations are as of the date of grant.

 

		Number of Shares Under Stock Options		Weighted Average Fair Value
Unvested stock options at the beginning of the quarter		5,045,834		$	1.22
Unvested stock options at the end of the quarter		4,578,334		$	1.21
Stock options granted during the quarter		—		$	—
Stock options vested during the quarter		117,500		$	1.68
Stock options forfeited/canceled during the quarter		525,000		$	1.09

As of March 31, 2008, there was no aggregate intrinsic value for outstanding stock options, and the remaining weighted average contractual life of outstanding stock options was 5.0 years. As of March 31, 2008, there was no aggregate intrinsic value for exercisable stock options, and the remaining weighted average contractual life of exercisable stock options was 3.5 years. As of March 31, 2008, the total fair value of exercisable stock options was $5.6 million.

 

F-10

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Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Restricted Share Activities

The following table summarizes the changes and grant date prices for restricted common share grants for the three months ended March 31, 2008:

 

		Number of Shares Under Stock Options		Weighted Average Grant Date Fair Value
Restricted common shares outstanding as of December 31, 2007		1,096,000		$	2.15
Restricted common shares granted		10,000		$	1.09
Restricted common shares vested		—		$	—
Restricted common shares cancelled/expired		—		$	—
Restricted common shares outstanding as of March 31, 2008		1,106,000		$	2.14

The following table summarizes the range of grant dates (expiration dates) and grant date prices for restricted common shares outstanding and unvested as of March 31, 2008:

 

		Restricted Common Shares Outstanding		Grant Date Fair Value
July 3, 2007 (July 3, 2011)		983,500		$	2.20
August 27, 2007 (August 27, 2011)		112,500		$	1.67
January 16, 2008 (January 16, 2012)		10,000		$	1.09
Total		1,106,000		$	2.14

Stock-Based Compensation Expense

For the three months ended March 31, 2008 and 2007, the Company recorded stock-based compensation expense for stock options and restricted common shares granted using the fair-value method of $856,000 million and $1.2 million, respectively. All stock based compensation costs were expensed and not tax effected, as the Company currently records no income tax expense. All common shares issued upon exercise or vesting are reserved and non-assessable.

5. Commodity Hedging Contracts

The following costless collar transactions were outstanding with associated notional volumes and contracted floor and ceiling prices that represent hedge prices for the index specified as of March 31, 2008:

 

Date		Period		Derivative Instrument (1)		Hedge Strategy		Notional Daily Volume		Total of Notional Volume		Floor Price			Ceiling Price			Index			Production Area Hedged
								(MMBtu)		(MMBtu)		(MMBtu)			(MMBtu)
09/21/07		Cal 08		CC		Cash flow		2,000		732,000		$	5.50		$	7.50		CIG	(3)		WY
12/12/07		Cal 08		CC		Cash flow		5,000		1,830,000		$	6.75		$	8.00		HSC	(2)		TX
01/03/08		02-12/08		CC		Cash flow		5,000		1,675,000		$	7.00		$	8.88		HSC	(2)		TX
01/18/08		02-12/08		CC		Cash flow		800		268,000		$	6.00		$	7.90		CIG	(3)		WY
02/19/08		Cal 09		CC		Cash flow		5,000		1,825,000		$	8.00		$	9.30		HSC	(2)		TX

 

(1)	Costless collars.

(2)	East-Houston-Katy—Houston Ship Channel.

(3)	Inside FERC Colorado Interstate Gas, Rocky Mountains.

As of March 31, 2008, the Company’s current cash flow hedge positions were with counterparties that are major United States financial institutions. The credit support for certain of the Company’s hedges is a $2.5 million letter of credit, with the remaining credit support under the Revolving Credit Facility through intercreditor agreements. Based on the Company’s December 31, 2007 third party engineering report, the Company had approximately 50% of its 2008 estimated proved developed production hedged and 30% of its 2009 estimated proved developed production hedged.

 

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Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

The Company recorded a short term and a long term derivative liability of $5.4 million and $545,000, respectively, related to the difference between hedged commodity prices and market prices on hedged volumes as of March 31, 2008, after application of FAS157 Fair Value Measurement. All of the Company’s derivative instruments have been designated cash flow as hedging instruments and are deemed to be highly effective. The Company recognized unrealized losses in the statement of operations on the cash flow hedges due to ineffectiveness of $169,000 and $1.2 million related to the time value of the costless collars. The Company records time value on the costless collars designated as cash flow hedges currently in earnings, as it has elected to exclude time value from its assessment of hedge effectiveness.

6. Common Shares

Authorized

The Company’s articles of incorporation allow the Company to issue an unlimited number of common shares without par value.

Other Share Issuances

During three months ended March 31, 2008, pursuant to the Company’s 2006 Gastar Long-Term Stock Incentive Plan, the Company issued 10,000 restricted common shares to an employee, subject to vesting.

Shares Reserved

At March 31, 2008, the Company has reserved 16,730,586 common shares to be issued pursuant to the conversion of convertible debt (6,849,315 common shares), exercise of options (9,648,750 common shares) and the exercise of warrants (232,521 common shares).

7. Warrants

The following table summarizes warrant information to purchase common shares as of March 31, 2008:

 

		Number of Warrants		Fair Value of Warrants (in thousands)			Weighted Average Warrant Price			Weighted Average Remaining Life in Years		Weighted Average Exercise Price
Warrants issued in connection with $3.25 million subordinated unsecured notes payable		232,521		$	235		$	2.80		1.1		$	2.80

8. Interest Expense

The following tables summarize the components of interest expense:

 

		For the Three Months Ended March 31.
		2008				2007
		(in thousands)
Interest expense:
Cash and accrued		$	4,004			$	2,866
Amortization of deferred financing costs and debt discount			463				1,077
Capitalized interest			(2,371	)			—
Total interest expense		$	2,096			$	3,943

 

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Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

9. Income Taxes

Due to the Company’s significant net operating loss carryforwards, the Company did not record any income tax expense for the three months ended March 31, 2008 and 2007. The Company fully reserves its deferred tax asset through a valuation allowance.

10. Fair Value Measurements

Fair Value Measurements. In September 2006, the FASB issued SFAS 157, which defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. SFAS 157 applies to other accounting pronouncements that require or permit fair value measurements; however, it does not require any new fair value measurements.

SFAS 157 establishes a valuation hierarchy for disclosure of the inputs to valuation used to measure fair value. This hierarchy prioritizes the inputs into three broad levels as follows.

 

•

Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities.

 

•

Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration, for substantially the full term of the financial instrument.

 

•

Level 3 inputs are measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources. The Company’s valuation models consider various inputs including: (a) quoted forward prices for commodities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the underlying instruments. Level 3 instruments are natural gas zero cost collars. Although the Company utilizes third party broker quotes to assess the reasonableness of prices and valuation techniques, the Company does not have sufficient corroborating market evidence to support classifying these assets and liabilities as Level 2.

A financial asset or liability’s classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement. The determination of the fair values below incorporates various factors required under SFAS 157, including the impact of our nonperformance risk on our liabilities. The following table provides the assets and liabilities carried at fair value measured on a recurring basis as of March 31, 2008:

 

		As of March 31, 2008
Recurring Fair Value Measures		Level 1			Level 2			Level 3				Total
		(in thousands)
Assets:
Derivative assets		$	—		$	—		$	—			$	—
Liabilities:
Derivative liabilities		$	—		$	—		$	(5,967	)		$	(5,967	)

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as level 3 in the fair value hierarchy:

 

		Derivatives
		(in thousands)
Balance as of January 1, 2008		$	(391	)
Total gains or losses (realized or unrealized)			—
Included in earnings (1)			(1,413	)
Included in other comprehensive loss			(4,395	)
Purchases, issuances and settlements			232
Transfers in and out of Level 3			—
Balance as of March 31, 2008		$	(5,967	)
Changes in unrealized losses relating to derivatives still held as of March 31, 2008		$	(1,413	)

 

(1)	This amount is included in revenues on the statement of operations as unrealized gas hedge loss.

 

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Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

11. Earnings or Loss per Share

In accordance with the provisions of Statement of Financial Standards No. 128 ‘Earnings per Share’, basic earnings or loss per share is computed on the basis of the weighted average number of common shares outstanding during the periods. Diluted earnings or loss per share is computed based upon the weighted average number of common shares plus the assumed issuance of common shares for all potentially dilutive securities. Diluted amounts are not included in the computation of diluted loss per share, as such would be anti-dilutive.

 

				For the Three Months Ended March 31,
				2008			2007
				(in thousands, except per share and share data)
Basic and diluted income (loss) and shares outstanding:
Net income (loss)				$	1,087		$	(10,955	)
Weighted average common shares outstanding:
Basic and diluted					207,098,570			195,015,561
Basic and diluted income (loss) per common share:
Basic and diluted				$	0.01		$	(0.06	)
Common shares excluded from denominator as anti-dilutive:
Stock options (1)					9,648,750			10,699,750
Unvested restricted common shares (2)					1,106,000			—
Warrants (1)					232,521			2,732,521
Convertible senior debentures (1)					6,849,315			6,849,315
(a)		Total			17,836,586			20,281,586

 

(1)	Common shares for the 2008 period have been excluded as the strike price of each was greater than the market price as of March 31, 2008.

(2)	Unvested common shares are included in the total outstanding number of common shares but are excluded from the calculation of weighted average common shares when calculating income per share.

12. Commitments and Contingencies

Litigation

The Company is party to various litigation matters. The ultimate outcome of the matters discussed below cannot presently be determined, nor can the liability that could potentially result from an adverse outcome be reasonably estimated at this time. The more significant litigation matters are summarized below.

Arbitration against GeoStar Corporation and Affiliates. On October 18, 2006, in connection with 10 wells to be drilled in Victoria, Australia on the jointly owned EL 4416 exploration license operated by GeoStar Corporation, the Company sent a letter to GeoStar demanding the arbitration of certain disputed issues and interpretations under a Participation and Operating Agreement (“POA”) with GeoStar and its subsidiaries. Among other items, the claims the Company presented for resolution in arbitration include claims relating to GeoStar’s demands for cash calls under the POA while simultaneously asserting that certain provisions of the POA, including overhead reimbursement rates, need to be renegotiated on terms that the Company believes are not reasonable or within industry standards. The Company has also requested that GeoStar’s Australian subsidiary provide a record title assignment of the Company’s beneficial interests in EL 4416, the exploration license in the Gippsland Basin property in Victoria, Australia. The Company has approximately $9.9 million invested in EL 4416 as of March 31, 2008. GeoStar contends that the Company is not entitled to the record title assignment notwithstanding the Company’s significant investment. The Company’s former Chairman of the Board is a major shareholder

 

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and President of GeoStar. GeoStar has voluntarily dismissed its efforts to enjoin the arbitration from proceeding and has answered and asserted counterclaims. Those counterclaims include (a) a request for a declaration that the Company has no rights to participate in brown coal projects in EL 4416, (b) a request for a declaration that the Company did not earn an interest under the POA as to certain wells the Company drilled in East Texas, (c) breach of contract for failure to pay certain bills and expenses and (d) breach of contract to pay for employee expenses and services. The Company, which denies and intends to vigorously defend each of these counterclaims, contends that it has participation rights to the full scope of EL 4416 under the terms of the POA and that the Texas wells were drilled on lands to which the Company obtained rights under separate 2005 Purchase and Sale Agreements. The three-member arbitration panel has been appointed. The date of the arbitration has been postponed and a new date has not been determined.

Gastar Exploration, Ltd., Gastar Exploration Texas, Inc., f/k/a First Texas Development, Inc., Gastar Exploration Texas LLC, f/k/a Bossier Basin, LLC, and Gastar Exploration Texas LP, f/k/a First Source Gas, LP v. GeoStar Corporation, First Source Texas, Inc., First Source Bossier, LLC, and First Texas Gas, LP. In July 2007, the Company filed a lawsuit in Robertson County, Texas against GeoStar and affiliates seeking relief in connection with the failure by GeoStar and its affiliates to execute formal assignments of certain leases that were omitted from the schedule of leases attached to the assignments executed by GeoStar affiliates in June 2005 pursuant to Purchase and Sale Agreements covering Texas properties of GeoStar and its affiliates. The lawsuit asks the court to decree that in the transaction evidenced by the Purchase and Sale Agreements, affiliates of the Company acquired title to all properties in Texas in which GeoStar and its affiliates owned an interest and that GeoStar and its affiliates are obligated to execute formal assignments with regard to all such leases. GeoStar and one of its affiliates have filed a challenge to the Texas court’s jurisdiction. Additionally, GeoStar and certain of its affiliates have also filed counterclaims in this litigation, which are described below and in the section below entitled “GeoStar Look Back Developments”.

Gastar Exploration Ltd., Gastar Exploration USA, Inc. f/k/a First Sourcenergy Wyoming Inc., Gastar Exploration New South Wales, Inc., f/k/a First Sourcenergy Group, Inc., Gastar Exploration Victoria, Inc. f/k/a First Sourcenergy Victoria, Inc.,, Gastar Exploration Texas, Inc., f/k/a First Texas Development, Inc., Gastar Exploration Texas LLC, f/k/a Bossier Basin, LLC, and Gastar Exploration Texas LP, f/k/a First Source Gas, LP v. GeoStar Corporation. In July 2007, the Company and affiliates filed a lawsuit in the District Court of Harris County, Texas against GeoStar in connection with GeoStar’s failure to deliver to the Company and its affiliates the corporate records of the Company and to its affiliates that have been retained by GeoStar. Representatives of the Company and its affiliates previously demanded return of the corporate records retained by GeoStar, but GeoStar failed to return the records. The lawsuit asks the court to decree that the Company and its affiliates are entitled to possession of the corporate records and order their return to the Company and its affiliates. The lawsuit also seeks recovery of actual and punitive damages, costs, and attorney’s fees. GeoStar has now delivered some of the requested records that are the subject of this litigation to the Company, and the Company has requested that GeoStar deliver additional records. Additionally, GeoStar and certain of its affiliates have also filed counterclaims in this litigation, which are described below and in the section below entitled “GeoStar Look Back Developments”.

Gastar Exploration, Ltd., Gastar Exploration Texas, Inc., f/k/a First Texas Development, Inc., Gastar Exploration Texas LLC, f/k/a Bossier Basin, LLC, and Gastar Exploration Texas LP, f/k/a First Source Gas, LP v. GeoStar Corporation, First Source Texas, Inc., First Source Bossier, LLC, and First Texas Gas, LP. In August 2007, the Company and certain affiliates filed a second lawsuit in Robertson County, Texas, seeking a declaratory judgment that the Company and its affiliates have complied with the Look-Back provisions of the Texas Purchase and Sale Agreements that are the subject of the other Robertson County, Texas lawsuit referenced above, that the Company and its affiliates have complied with the provisions of the Texas Purchase and Sale Agreements relating to the drilling of wells, and that GeoStar and its affiliates hold no farm-in interest in properties owned by the Company’s affiliates. GeoStar and one of its affiliates have filed a challenge to the Texas court’s jurisdiction. The defendants also have generally denied the allegations made in the lawsuit. Additionally, GeoStar and certain of its affiliates have also filed counterclaims in this litigation, which are described in the following paragraph and in the section below entitled “GeoStar Look Back Developments”.

 

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Although it previously contested jurisdiction in Texas, GeoStar (together with certain of its affiliates) has as of January and February 2008 asserted counterclaims in all three Texas lawsuits similar to claims GeoStar had previously asserted and dismissed in the Michigan lawsuit described below. The counterclaims relate to Texas properties that were the subject of Purchase and Sale Agreements entered into in 2005, under which the Company acquired the interests of GeoStar-affiliated entities in properties in Texas. Specifically, GeoStar claims that the Company breached the Purchase and Sale Agreements by failing to provide information in connection with contingent “Look Back” payments under provisions of the Purchase and Sale Agreements, and by failing to make payments allegedly due to GeoStar under the Look-Back provisions, arising out of alleged changes in reserves following the sale of the Texas properties in June 2005. Although requesting only damages in an unspecified amount, GeoStar contends in the counterclaim that it would have been entitled under the Purchase and Sale Agreements to approximately 1.7 billion shares of Gastar stock. GeoStar also claims that the Company failed to timely comply with provisions of the Purchase and Sale Agreements relating to the drilling of 20 wells on the properties conveyed under the Purchase and Sale Agreements and by failing to drill and test at least two wells in the Travis Peak formation in Texas, allegedly entitling GeoStar to unspecified damages related to a farm-in interest under which it was allegedly entitled to the right to drill, complete, and operate wells in the Travis Peak formation on certain acreage. The Company intends to vigorously defend the counterclaims. The Company has moved to abate the Harris County proceedings with respect the counterclaims in favor of the earlier-filed Robertson County proceedings. Certain information that may be relevant to this matter is set forth below in the section below entitled “GeoStar Look Back Developments”.

GeoStar Corporation and West Virginia Gas Corporation v. Gastar Exploration Ltd. and J. Russell Porter. On July 27, 2007, the Company was served with a lawsuit filed by GeoStar and one of its affiliates, West Virginia Gas Corporation, in federal court in Saginaw, Michigan. GeoStar asserted a broad range of claims against the Company and its current chief executive officer, J. Russell Porter.

GeoStar initially sought in the Michigan suit to enjoin the Company’s arbitration against GeoStar and its affiliates. GeoStar has now voluntarily dismissed that request with prejudice.

GeoStar also claims in the Michigan suit that the POA was cancelled effective January 1, 2005, and that the parties have operated under oral contracts since that date. GeoStar asserts that the Company has breached the alleged oral contracts by allegedly failing to pay joint interest billings, authorizations for expenditures, and cash calls relating to operations or proposed operations on EL 4416 in Australia and West Virginia properties, in an unspecified amount exceeding $75,000. GeoStar also claims that the Company has breached alleged agreements to reimburse GeoStar for various payments and services allegedly performed by GeoStar and its personnel and paid on behalf of the Company by GeoStar. GeoStar claims that the amounts of the payments and the value of the services exceed $10.0 million. GeoStar alternatively alleges that if there was no contract covering those payments and services, it allegedly is entitled to reimbursement on equitable principles. On January 15, 2008, the federal court granted the Company’s motion to dismiss these claims for failure to state a claim on which relief could be granted. GeoStar filed a motion asking that the Court reconsider that ruling or permit it to replead the claims. On February 8, 2008, the federal court denied the motion to reconsider but granted GeoStar permission to replead those claims, which it did on February 22, 2008. In repleading those claims, GeoStar has restated the prior claims for oral agreement to reimburse certain expenses or equitable entitlement to reimbursement of certain expenses, and it specifies a number of items for which GeoStar is allegedly entitled to reimbursement from the Company. Pursuant to these claims, which are substantially duplicated by certain of the counterclaims GeoStar pursues in the arbitration, GeoStar seeks approximately $17.0 million. The Company filed a response to these claims on March 7, 2008.

GeoStar also asserted claims in the Michigan lawsuit relating to Texas properties that were the subject of Purchase and Sale Agreements entered into in 2005. GeoStar has voluntarily dismissed those claims without prejudice from the Michigan lawsuit and re-asserted similar claims in pending litigation in Harris and Robertson Counties, Texas, as discussed above and below under “GeoStar Look Back Developments”.

 

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West Virginia Gas Corporation (WVGC), an affiliate of GeoStar, also asserts claims against the Company’s current chief executive officer, alleging that the Company and its current chief executive officer tortiously interfered with an alleged contract between WVGC and certain West Virginia individuals and entities. According to the lawsuit, these individuals and entities allegedly promised to give their oil, gas, and coalbed methane opportunities in West Virginia and Pennsylvania to WVGC. WVGC alleged that Gastar and its chief executive officer caused those individuals and entities to establish and use new business entities to allegedly conceal opportunities from West Virginia Gas Corporation and to funnel them to the Company, the Company’s chief executive officer and the West Virginia individuals and entities. On January 15, 2008, the federal court dismissed these claims to the extent they were brought by GeoStar and to the extent they were brought against the Company. The court denied our chief executive’s motions to dismiss WVGC’s claim and a motion to reconsider that denial. Our chief executive intends to vigorously defend the claim.

GeoStar Look Back Developments. The Purchase and Sale Agreements between GeoStar and the Company relating to certain East Texas properties acquired by the Company in 2005 (the “PSAs”) contain a “Look Back” provision that is the subject of claims in three of the previously described lawsuits with GeoStar. Under the 2005 PSAs, GeoStar conveyed interests in certain Texas properties to the Company and was paid an agreed $43.5 million in consideration for the properties (including cash, 8.6 million shares of Company common stock and promissory notes), subject to certain purchase price adjustments relating to the period prior to closing. The interests conveyed by the PSAs comprise a portion of the security for the notes and the Guarantees.

Under the Look Back provision, two Look Back payments are to be calculated based in part on changes in proved and probable reserves attributable to certain of the Company’s leasehold interests over certain periods of time ending June 30, 2006 and 2007. If a Look Back payment is due to GeoStar under the PSAs, the PSAs require the payment to be effected through the issuance of the Company’s stock.

The PSAs provide that the calculation of the Look Back payment shall be based upon reserve estimates reported by Netherland Sewell & Associates, Inc. (“NSA”), or in certain circumstances, based upon an average of the NSA estimates and estimates obtained by GeoStar from an independent, professionally certified reservoir engineering firm utilizing the same regulatory requirements and reserve calculation guidelines as those employed by NSA in its estimates. Based on the NSA reserves estimate and the Look Back calculations set forth in the PSAs, the Company believes that no additional issuance of Company common shares is due GeoStar under the Look Back provision.

On November 1, 2007, GeoStar informed the board of directors of our Parent that it intended to submit a reserve report for purposes of the June 30, 2006 and 2007 Look Back analyses showing that the gross reserves attributable to the Company’s leasehold interests are substantially greater than those reflected in the NSA reserve reports on which the Company’s Look Back analyses were based. On November 7, 2007, GeoStar submitted a reserve report to the Company that reported a substantially greater reserve estimate than the estimates in the NSA reserve report.

On November 14, 2007, the Company received a reserve report of T.J. Smith & Company, Inc. (“T.J. Smith”) as well as a demand letter from GeoStar’s counsel (the “Demand Letter”) in which GeoStar asserted a purported right under the PSAs to receive additional shares of Gastar stock as a Look Back payment. In the Demand Letter, GeoStar asserts that T.J. Smith has estimated that the total proved and probable reserves in the Company’s Texas properties attributable to 100% of the working interest amount to 2.15 trillion cubic feet of gas, a number which is approximately fourteen times more than the proved and probable reserves estimated by NSA, the engineering firm selected by the parties in the PSAs. On the basis of that reserves estimate, GeoStar asserts in the Demand Letter that it is entitled to a Look Back payment of approximately 1.7 billion shares of Gastar stock, which if issued would constitute approximately 89% of the Company’s common equity and would result in a change in control of the Company under the

 

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Company’s debt agreements. In the Demand Letter, GeoStar further asserts that if its demand is not met, it will pursue remedies that may include reclaiming operatorship over certain of the Company’s Texas properties, rescission of the PSAs resulting in return of the properties covered by the PSAs and consideration paid, and unspecified injunctive relief. The Company does not believe that GeoStar is entitled to these remedies.

The Company believes that GeoStar’s assertions are without merit. The Company believes that the T.J. Smith reserve report was submitted in bad faith and does not meet the requirements of the PSAs because, among other things, it does not follow the same regulatory requirements and reserve calculation guidelines as those employed by NSA, as required by the terms of the PSAs. In addition, GeoStar has asserted that the Look Back analysis should be based on changes in reserves attributable to the entirety, or 8/8ths, of the Company’s leasehold interests with respect to its Texas properties, rather than on changes in reserves attributable to GeoStar’s net revenue interest in those properties as of the effectiveness of the PSAs, as the Company believes. The Company is pursuing discovery of data pertinent to the T.J. Smith report and GeoStar’s contentions relating thereto and will continue to evaluate the Company’s legal positions and options based on such discovery.

The Company intends to vigorously defend itself against GeoStar’s assertions. However, an unfavorable outcome in litigation relating to the Look Back could have a material adverse effect on the Company were GeoStar to obtain issuance of the requested shares and obtain control of the Company, rescission of the PSAs, or other relief to which it asserted it was entitled in the November demand letter. A change in control of the Company as a result of an issuance of shares to GeoStar may require the Company to refinance substantially all of its indebtedness under its existing debt agreements, which refinancing may not be obtainable or may not be on terms as favorable as under current debt agreements. Although the Company does not currently anticipate the need to access the equity capital markets through 2008 or early 2009 to continue its business plan, until these issues are resolved in whole or in significant part, it will be difficult for the Company to raise capital through the sale of equity.

In 2007, the Company recorded a $1.4 million litigation settlement expense accrual related to a proposed settlement with GeoStar regarding the various GeoStar arbitration and litigation matters. The settlement proposal was never finalized. At March 31, 2008, the Company had a receivable from GeoStar of approximately $3.7 million that was fully reserved due to the various litigation matters.

Other Litigation

The Company does not expect that the outcome of these proceedings will have a material adverse effect on its financial position, results of operations or cash flow.

Navasota Resources L.P. (“Navasota”) vs. First Source Texas, Inc., First Source Gas L.P. (now Gastar Exploration Texas LP) and Gastar Exploration Ltd. (Cause No. 0-05-451) District Court of Leon County, Texas 12th Judicial District. This lawsuit, dated October 31, 2005, contends that the Company breached Navasota’s preferential right to purchase 33.33% of the Company’s interest in certain natural gas and oil leases located in Leon and Robertson Counties and sold to Chesapeake Energy Corporation pursuant to a transaction closed November 4, 2005. The preferential right claimed is under an operating agreement dated July 7, 2000. The Company contends, among other things, that Navasota neither properly nor timely exercised any preferential right election it may have had with respect to the inter-dependent Chesapeake transaction. In July 2006, the District Court of Leon County, Texas issued a summary judgment in favor of the Company and Chesapeake. Navasota filed a Notice of Appeal to the Tenth Court of Appeals in Waco. Oral argument was heard on September 26, 2007 and the Court of Appeals issued its opinion on January 9, 2008 reversing the trial court’s rulings and rendering judgment in favor of Navasota on all counts. The Company and Chesapeake filed a motion for rehearing on February 6, 2008, and if unsuccessful, will consider filing a petition for review to the Texas Supreme Court. Pursuant to an agreement between the Company and Chesapeake, any adverse result in this matter should impact only Chesapeake’s assigned leasehold interests. While this matter is pending, it is possible that expenditures incurred, or authorizations for proposed expenditures, for drilling activities on leases which include the

 

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disputed interest may remain unpaid or not be authorized by the non-operators asserting competing ownership rights, which could require the Company to either fund a disproportionate amount of drilling costs at its own risk or postpone its drilling program on affected leases.

Gastar Exploration Texas LP v. John E. McFarlane, et al (Cause No. 0-06-161) 87th Judicial District Court of Leon County, Texas. This suit is to quiet title to an undivided 25% mineral interest under an oil and gas lease dated December 4, 2003, covering approximately 2,598 gross acres (the “Lease”). John E. McFarlane and certain other family members contend that an undivided 25% mineral interest in the lands covered by the Lease are owned in trust by the grandchildren of Fay W. McFarlane and are not covered by the Lease as Gastar claims. McFarlane, et. al., filed an answer to the Company’s petition and also filed several different motions for summary judgment which were denied by the District Court. A day long mediation of this lawsuit occurred on August 24, 2007, but the parties were unable to settle this matter at that time. The lawsuit is in the discovery phase, and is currently set for a non-jury trial in October 2008. The existence of unleased mineral interests in this Lease could adversely impact the future development of the Lease. The Company will continue to vigorously pursue this claim.

Spencer D. Plummer, III v. GeoStar Corporation, Classic Star LLC, Gastar Exploration, Ltd., Thom Robinson, Tony Ferguson, and John W. Parrott; In the United States District Court of Utah, Central Division (Case No. 2:07-CV-00409). This lawsuit was filed on May 24, 2007 initially in Utah state court by Spencer Plummer, or the Plaintiff, in which he asserts breaches of his Employment Agreement and subsequent Termination Agreement (the “Agreements”) with his employer, Classic Star, a subsidiary of GeoStar. The Plaintiff claims that he has not received benefits promised under such Agreements, including 699,249 shares of Company stock. The Company is not a party to the Agreements on which Plaintiff’s claims are expressly based; however, the Company and Plaintiff are parties to a Stock Option Agreement on which Plaintiff claim to Company stock is partially based. The Company filed an Answer and Motion to Dismiss for lack of personal jurisdiction in Utah and for Plaintiff’s failure to state a claim upon which relief can be granted. Plaintiff filed a Motion to Remand to state court, and on September 5, 2007, the Court denied Plaintiff’s Motion to Remand. Thereafter, the Company’s co-defendant, Classic Star LLC, moved to transfer and consolidate the case in a United States Judicial Panel on Multi District Litigation (“MDL Panel”) in Kentucky with other cases in which Classic Star LLC is a named defendant. On October 22, 2007, the MDL Panel granted the motion to transfer. The Company is awaiting the Kentucky court’s ruling on its Motion to Dismiss.

Commitments

In March 2008, the Company entered into formal agreements with ETC Texas Pipeline, Ltd. (“ETC”) for the gathering, treating, purchase and transportation of the Company’s natural gas production from Hilltop area of East Texas. These agreements are effective September 1, 2007 and have a term of 10 years. ETC currently provides us 50 MMcfd of treating capacity and 120 MMcfd of gathering capacity. The Company has the right to request ETC build, at their cost, up to 150 MMcfd of treating and gathering capacity during the term of the agreement, provided that the Company’s production equals 85% of the then existing treating and gathering capacity for a 30 day period. The Company may at any time elect to have its treating and gathering capacity increased subject to cost indemnifications to ETC. Additional treating and gathering capacity requests must be in at least 25 MMcfd and 5 MMcfd increments, respectively. In addition, the Company must furnish to ETC information that reasonably demonstrates that its projected production for the five years after expansion is sufficient to warrant the costs to create the expanded treating and gathering capacity. The incremental volume increases in treating and gathering capacity shall be subject to marginal increases in treating fees. Pursuant to the agreements, the Company has access up to 150 MMcfd of firm transportation on ETC’s system or the pipelines of its affiliates or subsidiaries from the tailgate of the treating facility to Katy Hub. The Company has the option to sell and ETC has the obligation to buy, up to 150 MMcfd of the Company’s Hilltop production at delivery points upstream of ETC’s gathering and treating facilities. The Company does not have an obligation to deliver to ETC volumes in excess of 150 MMcfd, but should ETC elect to purchase such excess volumes, purchases will be subject to the treating and gathering expansion terms set forth in the agreements.

 

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Registration Obligation

On November 29, 2007, Gastar USA sold $100.0 million aggregate principal amount of 12 ³/4% Senior Secured Notes at an issue price of 99.50% in a private placement to qualified institutional. In connection with the sale Gastar Exploration USA, Inc., other Guarantors and the Company entered into a registration rights agreement. Pursuant to the registration rights agreement, the Company and the Guarantors agreed that they would (1) within 150 days after the date of original issue of the 12 ³/4% Senior Secured Notes file a registration statement with the SEC to exchange the 12 ³/4% Senior Secured Notes for new notes of the Company having terms substantially identical in all material respects to the notes (except that the new notes will not contain terms relating to transfer restrictions); (2) use their reasonable best efforts to cause the registration statement to be declared effective within 240 days after the issue date; (3) as soon as practicable after the effectiveness of the registration statement, offer the new notes to the holders of the notes in exchange for the notes; and (4) keep the exchange offer open for not less than 30 days (or longer if required by applicable law) after the date notice of the exchange offer is mailed to the holders of the notes. Under existing SEC interpretations, the new notes will be freely transferable by holders other than Company affiliates after the exchange offer without further registration. In the event Gastar USA fails to meet its registration obligations as set forth above, Gastar USA has agreed to pay liquidated damages to the holders of the 12 ³/4% Senior Secured Notes in the form of additional cash interest payments on the 12 ³/4% Senior Secured Notes equal to 0.25% per annum for the first 90-day period, increasing to a maximum of 0.50% per annum for each subsequent 90-day period. The Company filed a Registration Statement on Form S-4 on April 10, 2008, which has not yet become effective.

13. Statement of Cash Flows – Supplemental Information

The following is a summary of supplemental cash paid and non-cash transactions disclosed in the notes to the condensed consolidated financial statements:

 

		For the Three Months Ended March 31,
		2008				2007
		(in thousands)
Cash paid for interest		$	748			$	2,871
Non-cash transactions:
Non-cash capital expenditures excluded from accounts payable and accrued drilling costs		$	(4,467	)		$	4,248
Asset retirement obligation included in oil and gas properties		$	—			$	422
Drilling advances application		$	1,063			$	1,048
Common shares issued under senior secured notes		$	—			$	606

14. Issuer Subsidiaries Condensed Consolidating Financial Statements

The following tables present condensed consolidating balance sheets as of March 31, 2008 and December 31, 2007 and the related condensed consolidating statements of operations and condensed consolidating statements of cash flows for the three months ended March 31, 2008 and 2007 of Gastar Exploration Ltd. (“Parent”), Gastar Exploration USA, Inc. (“Issuer”) and Gastar Exploration Texas, Inc., Gastar Exploration Texas LP, Gastar Exploration Texas LLC, Gastar Exploration New South Wales, Inc., Gastar Exploration Victoria, Inc. and Gastar Power Pty Ltd., a minor non-guarantor subsidiary included in issuer subsidiaries, (collectively referred to as “Issuer Subsidiaries”). Each of the Parent and the Issuer Subsidiaries, except for Gastar Power Pty Ltd., have fully and unconditionally guaranteed, on a joint and severally basis, the $100.0 million 12 ³/4% Senior Secured Notes and the Revolving Credit Facility. During 2007, Parent intercompany receivables were reclassified to investment in subsidiary with Issuer and Issuer Subsidiaries. Prior to January 1, 2008, interest was not charged on intercompany receivables or payables. Total intercompany interest charged by Parent to Issuer during the three months ended March 31, 2008 was $12,000, which was eliminated in consolidation.

 

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(Unaudited)

 

Condensed Consolidating Parent and Issuer Subsidiaries Balance Sheets

As of March 31, 2008

(Unaudited)

 

		Parent				Issuer				Issuer Subsidiaries				Reclassifications and Eliminations				Gastar Exploration Ltd. and Subsidiaries
		(in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	34			$	—			$	78,934			$	—			$	78,968
Accounts receivable, net			7				265				9,132				(635	)			8,769
Due from related parties			—				—				1,611				—				1,611
Prepaid expenses			252				—				865				—				1,117
Total current assets			293				265				90,542				(635	)			90,465
PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, full cost method of accounting:
Unproved properties, not being amortized			—				4,036				80,243				—				84,279
Proved properties			8				43,925				205,557				—				249,490
Total natural gas and oil properties			8				47,961				285,800				—				333,769
Furniture and equipment			—				—				763				—				763
Total property, plant and equipment			8				47,961				286,563				—				334,532
Accumulated depreciation, depletion and amortization			(7	)			(42,828	)			(124,339	)			—				(167,174	)
Total property, plant and equipment, net			1				5,133				162,224				—				167,358
OTHER ASSETS:
Restricted cash			30				—				46				—				76
Deferred charges, net			802				7,114				—				—				7,916
Drilling advances			—				—				2,320				—				2,320
Intercompany receivable and investment in subsidiaries			130,350				220,315				—				(350,665	)			—
Other assets			—				100				50				—				150
Total other assets			131,182				227,529				2,416				(350,665	)			10,462
TOTAL ASSETS		$	131,476			$	232,927			$	255,182			$	(351,300	)		$	268,285
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable		$	39			$	—			$	11,194			$	—			$	11,233
Revenue payable			—				—				7,728				—				7,728
Accrued interest			469				4,321				—				—				4,790
Accrued drilling and operating costs			—				350				1,698				—				2,048
Commodity derivative contracts			—				5,422				—				—				5,422
Other accrued liabilities			138				635				4,168				(635	)			4,306
Due to related parties			—				—				1,865				—				1,865
Total current liabilities			646				10,728				26,653				(635	)			37,392
LONG-TERM LIABILITIES:
Long-term debt			33,191				99,524				—				—				132,715
Asset retirement obligation			5				2,331				2,137				—				4,473
Commodity derivative contracts			—				545				—				—				545
Intercompany payable			—				2,379				34,458				(36,837	)			—
Total long-term liabilities			33,196				104,779				36,595				(36,837	)			137,733
TOTAL SHAREHOLDERS’ EQUITY			97,634				117,420				191,934				(313,828	)			93,160
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY.		$	131,476			$	232,927			$	255,182			$	(351,300	)		$	268,285

 

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(Unaudited)

 

Condensed Consolidating Parent and Issuer Subsidiaries Balance Sheets

As of December 31, 2007

 

		Parent				Issuer				Issuer Subsidiaries				Reclassifications and Eliminations				Gastar Exploration Ltd. and Subsidiaries
		(in thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	73			$	—			$	85,781			$	—			$	85,854
Accounts receivable, net			10				265				5,188				(635	)			4,828
Due from related parties			—				—				904				—				904
Prepaid expenses			291				—				944				—				1,235
Total current assets			374				265				92,817				(635	)			92,821
PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, full cost method of accounting:
Unproved properties, not being amortized			—				2,988				66,856				—				69,844
Proved properties			8				43,611				203,753				—				247,372
Total natural gas and oil properties			8				46,599				270,609				—				317,216
Furniture and equipment			—				—				669				—				669
Total property, plant and equipment			8				46,599				271,278				—				317,885
Accumulated depreciation, depletion and amortization			(7	)			(42,828	)			(117,930	)			—				(160,765	)
Total property, plant and equipment, net			1				3,771				153,348				—				157,120
OTHER ASSETS:
Restricted cash			1,029				—				45				—				1,074
Deferred charges, net			924				7,410				—				—				8,334
Drilling advances			—				—				2,251				—				2,251
Intercompany receivable and investment in subsidiaries			128,677				209,494				—				(338,171	)			—
Other assets			—				100				50				—				150
Total other assets			130,630				217,004				2,346				(338,171	)			11,809
TOTAL ASSETS		$	131,005			$	221,040			$	248,511			$	(338,806	)		$	261,750
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable		$	47			$	—			$	11,954			$	—			$	12,001
Revenue payable			—				—				6,770				—				6,770
Accrued interest			401				1,133				—				—				1,534
Accrued drilling and operating costs			—				350				2,460				—				2,810
Commodity derivative contracts			—				480				—				—				480
Other accrued liabilities			244				586				4,636				(635	)			4,831
Due to related parties			—				—				979				—				979
Total current liabilities			692				2,549				26,799				(635	)			29,405
LONG-TERM LIABILITIES:
Long-term debt			33,179				99,506				—				—				132,685
Asset retirement obligation			5				2,289				2,097				—				4,391
Intercompany payable			589				1,615				26,668				(28,872	)			—
Total long-term liabilities			33,773				103,410				28,765				(28,872	)			137,076
TOTAL SHAREHOLDERS’ EQUITY			96,540				115,081				192,947				(309,299	)			95,269
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY.		$	131,005			$	221,040			$	248,511			$	(338,806	)		$	261,750

 

F-22

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Table of Contents

Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Condensed Consolidating Parent and Issuer Subsidiaries Statements of Operations

For the Three Months Ended March 31, 2008

(Unaudited)

 

		Parent				Issuer				Issuer Subsidiaries				Reclassifications and Eliminations				Gastar Exploration Ltd. and Subsidiaries
		(in thousands)
REVENUES:
Natural gas and oil revenues		$	1			$	3,134			$	13,711			$	—			$	16,846
Unrealized natural gas hedge loss			—				(216	)			(1,197	)			—				(1,413	)
Total revenues			1				2,918				12,514				—				15,433
EXPENSES:
Production taxes			—				348				(79	)			—				269
Lease operating expenses			—				704				838				—				1,542
Transportation and treating			—				459				—				—				459
Depreciation, depletion and amortization			—				—				6,409				—				6,409
Accretion of asset retirement obligation			—				40				42				—				82
General and administrative expenses			297				42				3,936				—				4,275
Total expenses			297				1,593				11,146				—				13,036
INCOME (LOSS) FROM OPERATIONS			(296	)			1,325				1,368				—				2,397
OTHER (EXPENSES) INCOME:
Interest expense			(944	)			(1,146	)			(6	)			—				(2,096	)
Investment income and other			21				(10	)			812				—				823
Equity earnings in subsidiaries			2,349				2,180				—				(4,529	)			—
Foreign transaction (loss) gain			(43	)			—				6				—				(37	)
INCOME BEFORE INCOME TAXES			1,087				2,349				2,180				(4,529	)			1,087
Provision for income taxes			—				—				—				—				—
NET INCOME		$	1,087			$	2,349			$	2,180			$	(4,529	)		$	1,087

 

F-23

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Table of Contents

Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Condensed Consolidating Parent and Issuer Subsidiaries Statements of Operations

For the Three Months Ended March 31, 2007

(Unaudited)

 

		Parent				Issuer				Issuer Subsidiaries				Reclassifications and Eliminations			Gastar Exploration Ltd. and Subsidiaries
		(in thousands)
REVENUES:
Natural gas and oil revenues		$	1			$	2,153			$	5,361			$	—		$	7,515
Unrealized natural gas hedge loss			—				—				—				—			—
Total revenues			1				2,153				5,361				—			7,515
EXPENSES:
Production taxes			—				234				60				—			294
Lease operating expenses			1				727				967				—			1,695
Transportation and treating			—				323				—				—			323
Depreciation, depletion and amortization			—				1,529				2,812				—			4,341
Accretion of asset retirement obligation			—				40				26				—			66
Mineral resource properties			—				—				13				—			13
General and administrative expenses			364				—				6,428				—			6,792
Litigation settlement expense			—				—				1,365				—			1,365
Total expenses			365				2,853				11,671				—			14,889
LOSS FROM OPERATIONS			(364	)			(700	)			(6,310	)			—			(7,374	)
OTHER (EXPENSES) INCOME:
Interest expense			(3,926	)			—				(17	)			—			(3,943	)
Investment income and other			—				—				363				—			363
Equity loss in subsidiaries			(6,663	)			(5,963	)			—				12,626			—
Foreign transaction (loss) gain			(2	)			—				1				—			(1	)
LOSS BEFORE INCOME TAXES			(10,955	)			(6,663	)			(5,963	)			12,626			(10,955	)
Provision for income taxes			—				—				—				—			—
NET LOSS		$	(10,955	)		$	(6,663	)		$	(5,963	)		$	12,626		$	(10,955	)

 

F-24

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Table of Contents

Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Condensed Consolidating Parent and Issuer Subsidiaries Statements of Cash Flows

For the Three Months Ended March 31, 2008

(Unaudited)

 

		Parent				Issuer				Issuer Subsidiaries				Reclassifications and Eliminations				Gastar Exploration Ltd. and Subsidiaries
		(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	1,087			$	2,349			$	2,180			$	(4,529	)		$	1,087
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization			—				—				6,409				—				6,409
Stock based compensation			—				—				856				—				856
Unrealized natural gas hedge loss			—				216				1,197				—				1,413
Amortization of deferred financing costs and debt discount			134				329				—				—				463
Accretion of asset retirement obligation			—				40				42				—				82
Equity in loss of issuer subsidiaries			(2,349	)			(2,180	)			—				4,529				—
Changes in operating assets and liabilities, exclusive of effects of acquisition:
Restricted cash for hedging program			1,000				—				—				—				1,000
Accounts receivable			3				—				(4,651	)			—				(4,648	)
Prepaid expenses			39				—				79				—				118
Accounts payable and accrued liabilities			(46	)			3,237				4,321				—				7,512
Net cash provided by (used in) operating activities			(132	)			3,991				10,433				—				14,292
CASH FLOWS FROM INVESTING ACTIVITIES:
Development and purchases of natural gas and oil properties			—				(1,362	)			(18,595	)			—				(19,957	)
Drilling advances			—				—				(1,132	)			—				(1,132	)
Purchase of furniture and equipment			—				—				(94	)			—				(94	)
Subsidiary equity investment repayments			—				(2,614	)			—				2,614				—
Net cash used in investing activities			—				(3,976	)			(19,821	)			2,614				(21,183	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Subsidiary equity investment repayments			87				—				2,527				(2,614	)			—
Increase in restricted cash			(1	)			—				(1	)			—				(2	)
Deferred financing charges and other			7				(15	)			15				—				7
Net cash provided by (used in) financing activities			93				(15	)			2,541				(2,614	)			5
NET DECREASE IN CASH AND CASH EQUIVALENTS			(39	)			—				(6,847	)			—				(6,886	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD			73				—				85,781				—				85,854
CASH AND CASH EQUIVALENTS, END OF PERIOD		$	34			$	—			$	78,934			$	—			$	78,968

 

F-25

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Table of Contents

Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

 

Condensed Consolidating Parent and Issuer Subsidiaries Statements of Cash Flows

For the Three Months Ended March 31, 2007

(Unaudited)

 

		Parent				Issuer				Issuer Subsidiaries				Reclassifications and Eliminations				Gastar Exploration Ltd. and Subsidiaries
		(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss		$	(10,955	)		$	(6,663	)		$	(5,963	)		$	12,626			$	(10,955	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization			—				1,529				2,812				—				4,341
Stock based compensation			—				—				1,236				—				1,236
Amortization of deferred financing costs and debt discount			1,077				—				—				—				1,077
Accretion of asset retirement obligation			—				40				26				—				66
Equity in loss of issuer subsidiaries			6,663				5,963				—				(12,626	)			—
Changes in operating assets and liabilities, exclusive of effects of acquisition:
Accounts receivable			(3	)			100				2,201				—				2,298
Prepaid expenses			90				135				96				—				321
Accounts payable and accrued liabilities			(79	)			—				1,976				—				1,897
Net cash provided by (used in) operating activities			(3,207	)			1,104				2,384				—				281
CASH FLOWS FROM INVESTING ACTIVITIES:
Development and purchases of natural gas and oil properties			(1	)			(2,464	)			(15,924	)			—				(18,389	)
Purchase of furniture and equipment			—				—				(15	)			—				(15	)
Subsidiary equity investment repayments			—				—				(4,637	)			4,637				—
Net cash used in investing activities			(1	)			(2,464	)			(20,576	)			4,637				(18,404	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Subsidiary equity investment repayments			3,277				1,360				—				(4,637	)			—
Increase in restricted cash			—				—				(1	)			—				(1	)
Net cash provided by (used in) financing activities			3,277				1,360				(1	)			(4,637	)			(1	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS			69				—				(18,193	)			—				(18,124	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD			46				—				40,687				—				40,733
CASH AND CASH EQUIVALENTS, END OF PERIOD		$	115			$	—			$	22,494			$	—			$	22,609

 

F-26

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Table of Contents

Index to Financial Statements

Report of Independent Registered Public Accounting Firm

Board of Directors and Shareholders

Gastar Exploration Ltd.

Houston, Texas

We have audited the accompanying consolidated balance sheets of Gastar Exploration Ltd. (the “Company”) and subsidiaries as of December 31, 2007 and 2006, and the related consolidated statements of operations, shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2007. In connection with our audits of the financial statements, we have also audited the financial statement schedule listed in the accompanying index. These financial statements and the schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and the schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatements. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements and schedule. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Gastar Exploration Ltd. and subsidiaries at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.

Also, in our opinion, the schedule when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth herein.

As more fully described in Note 2 to the consolidated financial statements, effective January 1, 2006, the Company adopted the provisions of SFAS No. 123(R), “Share-Based Payment”.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Gastar Exploration Ltd.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) and our report dated March 14, 2008 expressed an unqualified opinion thereon.

 

/s/ BDO Seidman, LLP

Dallas, Texas

March 14, 2008

 

F-27

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Table of Contents

Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

 

ASSETS
		As of December 31,
		2007				2006
		(in thousands)
CURRENT ASSETS:
Cash and cash equivalents		$	85,854			$	40,733
Accounts receivable, net of allowance for doubtful accounts of $4.3 million and $626,000 respectively			4,828				8,733
Due from related parties			904				4,394
Prepaid expenses			1,235				1,369
Total current assets			92,821				55,229
PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, full cost method of accounting:
Unproved properties, not being amortized			69,844				89,658
Proved properties			247,372				181,362
Total natural gas and oil properties			317,216				271,020
Furniture and equipment			669				600
Total property, plant and equipment			317,885				271,620
Accumulated depreciation, depletion and amortization			(160,765	)			(110,794	)
Total property, plant and equipment, net			157,120				160,826
OTHER ASSETS:
Restricted cash			1,074				45
Deferred charges, net			8,334				3,502
Drilling advances			2,251				9,137
Other assets			150				150
Total other assets			11,809				12,834
TOTAL ASSETS		$	261,750			$	228,889
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable		$	12,001			$	15,471
Revenue payable			6,770				3,464
Accrued interest			1,534				2,515
Accrued drilling and operating costs			2,810				5,680
Other accrued liabilities			5,311				3,120
Due to related parties			979				1,670
Total current liabilities			29,405				31,920
LONG-TERM LIABILITIES:
Long-term debt			132,685				93,803
Asset retirement obligation			4,391				4,218
Liability to be settled by issuance of common shares			—				606
Total long-term liabilities			137,076				98,627
COMMITMENTS AND CONTINGENCIES (Note 16)
SHAREHOLDERS’ EQUITY:
Common stock, no par value, unlimited shares authorized, 208,194,570 and 194,965,436 shares issued and outstanding at December 31, 2007 and 2006, respectively			249,980				225,986
Additional paid-in capital			14,366				10,418
Accumulated other comprehensive loss – fair value of commodity hedging			(480	)			—
Accumulated other comprehensive loss – foreign exchange			(29	)			(34	)
Accumulated deficit			(168,568	)			(138,028	)
Total shareholders’ equity			95,269				98,342
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY		$	261,750			$	228,889

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

 

F-28

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Table of Contents

Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

 

		For the Years Ended December 31,
		2007				2006				2005
		(in thousands, except share and per share data)
REVENUES		$	34,565			$	26,765			$	27,442
EXPENSES:
Production taxes			765				1,478				1,062
Lease operating expenses			6,284				5,549				3,853
Transportation and treating			1,641				1,557				1,995
Depreciation, depletion and amortization			21,456				16,332				13,914
Impairment of natural gas and oil properties			28,514				56,280				8,697
Accretion of asset retirement obligation			281				234				109
Mineral resource properties			(133	)			450				65
General and administrative expenses			16,906				13,548				8,710
Litigation settlement expense			1,365				2,407				—
Total expenses			77,079				97,835				38,405
LOSS FROM OPERATIONS			(42,514	)			(71,070	)			(10,963	)
OTHER (EXPENSES) INCOME:
Interest expense			(14,079	)			(15,599	)			(13,905	)
Early extinguishment of debt			(15,684	)			—				(1,356	)
Investment income and other			3,196				1,836				492
Gain on sale of assets			38,536				—				—
Foreign transaction gain (loss)			5				(6	)			40
LOSS BEFORE INCOME TAXES			(30,540	)			(84,839	)			(25,692	)
Provision for income taxes			—				—				—
NET LOSS		$	(30,540	)		$	(84,839	)		$	(25,692	)
NET LOSS PER SHARE:
Basic and diluted		$	(0.15	)		$	(0.50	)		$	(0.20	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic and diluted			202,828,792				170,014,733				129,398,548

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

 

F-29

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Table of Contents

Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS EQUITY

 

		Common Stock					Additional Paid-in Capital			Accumulated Other Comprehensive Loss				Total Accumulated Shareholders’ Comprehensive
		Shares		Amount										Deficit				Equity				Loss
		(in thousands, except share data)
Balance at December 31, 2004		113,390,108		$	45,347		$	4,221		$	(95	)		$	(27,497	)		$	21,976			$	—
Exercise of stock options – cash		3,721,300			707			—			—				—				707				—
Exercise of stock options – cashless		2,214,888			—			—			—				—				—				—
Issuance of shares – cash, net of offering costs of $3,312		33,769,377			90,096			—			—				—				90,096				—
Issuance of shares – acquisition		8,023,827			23,000			—			—				—				23,000				—
Issuance of shares – senior secured debt		2,505,728			7,893			—			—				—				7,893				—
Exercise of stock purchase warrants – cash		207,814			413			—			—				—				413				—
Exercise of stock purchase warrants – cashless		841,224			—			—			—				—				—				—
Stock based compensation		—			—			2,288			—				—				2,288				—
Foreign currency translation gain		—			—			—			95				—				95				95
Net loss		—			—			—			—				(25,692	)			(25,692	)			(25,692	)
Total comprehensive loss																						$	(25,597	)
Balance at December 31, 2005		164,674,266			167,456			6,509			—				(53,189	)			120,776				—
Issuance of shares – cash, net of offering costs of $2,169		25,000,000			47,831			—			—				—				47,831				—
Issuance of shares – acquisition		548,128			2,116			—			—				—				2,116				—
Issuance of shares – senior secured debt		3,815,458			8,499			—			—				—				8,499				—
Exercise of stock options – cashless		905,636			—			—			—				—				—				—
Exercise of stock purchase warrants – cash		21,948			84			—			—				—				84				—
Stock based compensation		—			—			3,909			—				—				3,909				—
Foreign currency translation loss		—			—			—			(34	)			—				(34	)			(34	)
Net loss		—			—			—			—				(84,839	)			(84,839	)			(84,839	)
Total comprehensive loss																						$	(84,873	)
Balance at December 31, 2006		194,965,436			225,986			10,418			(34	)			(138,028	)			98,342				—
Issuance of shares – senior secured debt		375,939			606			—			—				—				606				—
Issuance of shares – cash, net of offering costs of $126		11,757,195			23,388			—			—				—				23,388				—
Stock based compensation		1,096,000			—			3,948			—				—				3,948				—
Change in fair value of commodity hedging contract		—			—			—			(480	)			—				(480	)			(480	)
Foreign currency translation gain		—			—			—			5				—				5				5
Net loss		—			—			—			—				(30,540	)			(30,540	)			(30,540	)
Total comprehensive loss																						$	(31,015	)
Balance at December 31, 2007		208,194,570		$	249,980		$	14,366		$	(509	)		$	(168,568	)		$	95,269

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

 

F-30

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Table of Contents

Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

		For the Years Ended December 31,
		2007				2006				2005
		(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss		$	(30,540	)		$	(84,839	)		$	(25,692	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization			21,456				16,332				13,914
Impairment of natural gas and oil properties			28,514				56,280				8,697
Amortization of deferred lease costs			—				345				416
Stock based compensation			3,948				3,909				2,288
Amortization of deferred financing costs and debt discount			4,235				4,260				4,111
Accretion of asset retirement obligation			281				234				109
Gain on sale of assets			(38,536	)			—				—
Loss on early extinguishment of debt			12,034				—				694
Changes in operating assets and liabilities:
Restricted cash for hedging program			(1,000	)			—				—
Accounts receivable			7,395				(6,354	)			(5,042	)
Prepaid expenses			134				182				(1,244	)
Accounts payable and accrued liabilities			(479	)			8,370				5,129
Net cash provided by (used in) operating activities			7,442				(1,281	)			3,380
CASH FLOWS FROM INVESTING ACTIVITIES:
Development and purchases of natural gas and oil properties			(64,841	)			(50,215	)			(33,287	)
Proceeds from sale of natural gas and oil properties			66,513				—				2
Purchase of natural gas and oil properties from related parties			—				(2,116	)			(28,784	)
Drilling advances			(5,070	)			(14,228	)			(15,269	)
Purchase of furniture and equipment			(69	)			(240	)			(352	)
Other			—				(150	)			(143	)
Net cash used in investing activities			(3,467	)			(66,949	)			(77,833	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of 12 3/4% senior secured notes			99,500				—				—
Proceeds from issuance of senior secured notes			—				—				73,000
Repayment of senior secured notes			(73,000	)			—				—
Repayment of Senior Secured Notes			—				—				(26,483	)
Repayment of related note payable			—				—				(15,000	)
Proceeds from the issuance of common shares, net of share issue costs			23,388				47,915				91,216
Increase in restricted cash			(29	)			(45	)			—
Deferred financing charges and other			(8,713	)			(51	)			(2,978	)
Net cash provided by financing activities			41,146				47,819				119,755
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS			45,121				(20,411	)			45,302
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR			40,733				61,144				15,842
CASH AND CASH EQUIVALENTS, END OF YEAR		$	85,854			$	40,733			$	61,144

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

 

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Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

1.	Description of Business

Gastar Exploration Ltd. (the “Company”) is an independent energy company engaged in the exploration, development and production of natural gas and oil in the United States and Australia. Our principal business activities include the identification, acquisition, and subsequent exploration and development of natural gas and oil properties. Our emphasis is on prospective deep structures identified through seismic and other analytical techniques as well as unconventional natural gas reserves, such as coal bed methane (“CBM”). The Company is pursuing unconventional natural gas exploration in the deep Bossier play in the Hilltop area in East Texas. The Company’s primary CBM properties are in the United States in the Powder River Basin in Wyoming and in the Gunnedah and Gippsland Basins of Australia.

 

2.	Summary of Significant Accounting Policies

The consolidated financial statements of the Company are stated in United States (“U.S.”) dollars unless otherwise noted and have been prepared by management in accordance with accounting principles generally accepted in the United States of America (“US GAAP”). The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates with regard to these financial statements include the estimate of proved natural gas and oil reserve quantities and the related present value of estimated future net cash flows (see “Supplemental Oil and Gas Disclosures”).

Principles of Consolidation

The consolidated financial statements include the accounts of the Company and the consolidated accounts of all its subsidiaries. The entities included in these consolidated accounts are all wholly owned and are Gastar Exploration USA, Inc. (“Gastar USA”), Gastar Exploration Texas, Inc., Gastar Exploration Texas LP, Gastar Exploration Texas LLC, Gastar Exploration New South Wales, Inc., Gastar Exploration Victoria, Inc. (collectively, “Guarantors”) and Gastar Power Pty Ltd. (“Gastar Power”). All significant intercompany accounts and transactions have been eliminated in consolidation.

Foreign Currency Translation and Exchange

The majority of the Company’s operations are conducted by its U.S. subsidiaries in U.S. dollars. The operations outside of the U.S. are primarily natural gas and oil property development in Australia, which are conducted in Australian dollars (“AUD$”). Our Australian properties represent CBM wells that are in the exploration or pre-production stage. Although we have exploration and development operations in Australia, we currently have no commercial production operations there. Limited operations are conducted in Canadian dollars (“CDN$”). Foreign operations are translated using rates in effect at the period end for the balance sheet, while the income statement is translated at the average rates prevailing during the period. Adjustments resulting from financial statement translations are included in cumulative translation adjustments in Accumulated Other Comprehensive Loss and as a component of consolidated statement of shareholders’ equity.

Foreign currency balances and non-monetary assets and liabilities are translated at the rates of exchange on the particular transaction date. Monetary assets and liabilities denominated in foreign currencies that remain outstanding at the balance sheet date are translated at period end exchange rates with resulting gains (losses) being recognized in the period. The accounts of all active U.S. subsidiaries are maintained in U.S. dollars. The accounts of Gastar Power are maintained in Australian dollars. Translation gains and losses recorded on investments in subsidiaries that are of a permanent nature are not tax effected.

Cash and Cash Equivalents

Cash and cash equivalents, which includes short-term investments such as money market deposits or highly liquid debt instruments with a maturity of three months or less when purchased, amounted to $85.9 million and $40.7 million as of December 31, 2007 and 2006, respectively. The Company maintains its cash in bank deposit accounts, which, at times, may exceed federally insured limits. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant risk of loss.

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Accounts Receivable

Accounts receivable are reported net of the allowance for doubtful accounts. The allowance for doubtful accounts is determined based on a review of the Company’s receivables. Receivable accounts are charged off when collection efforts have failed and the account is deemed uncollectible.

Deferred Financing Costs and Debt Discount

Deferred financing costs include costs of debt financings undertaken by the Company including commissions, legal fees, value attributed to warrants issued in conjunction with a financing and other direct costs of the financing. Using the effective interest method, the deferred financing costs are amortized over the term of the related debt instrument.

Debt discount is amortized over the term of the related debt utilizing the effective interest method.

The following table indicates deferred charges and related accumulated amortization as of the dates indicated:

 

		As of December 31,
		2007				2006
		(in thousands)
Deferred charges		$	14,164			$	5,447
Accumulated amortization			(5,830	)			(1,945	)
Deferred charges, net		$	8,334			$	3,502

Natural Gas and Oil Properties

The Company follows the full cost method of accounting for natural gas and oil operations, whereby all costs incurred in the acquisition, exploration and development of natural gas and oil reserves are initially capitalized into cost centers on a country-by-country basis. The Company’s current cost centers are located in the United States and Australia. Such costs include land acquisition costs, geological and geophysical expenditures, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition, exploration and development activities.

Costs capitalized, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated net proved reserves, as determined by independent petroleum engineers.

Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed periodically to ascertain whether impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property is added to costs subject to depletion calculations.

In applying the full cost method, the Company performs a quarterly ceiling test on the cost center properties whereby the net cost of natural gas and oil properties, net of related deferred income taxes (“net cost”), is limited to the sum of the estimated future net revenues from proved reserves using prices in effect at the end of the period held constant, discounted at 10%, and the lower of cost or fair value of unproved properties, adjusted for related income tax effects (“ceiling”). If the net cost exceeds the ceiling, an impairment loss is recognized for the amount by which the net cost exceeds the ceiling and is shown as a reduction in natural gas and oil properties and as additional depletion. Proceeds from a sale of natural gas and oil properties will be applied against capitalized costs, with no gain or loss recognized, unless such a sale would significantly alter the rate of depletion or amortization.

 

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Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Capitalized Interest

The Company capitalizes interest based on the cost of major development projects, which are excluded from current depreciation, depletion and amortization calculation. Capitalized interest costs were approximately $1.9 million for 2007. The Company reported no capitalized interest for 2006 or 2005.

Furniture and Equipment

Furniture and equipment are recorded at historical cost and are depreciated over their estimated useful lives, which ranges from three to seven years on a straight-line basis.

Fair Value of Financial Instruments

The carrying amounts of the Company’s short-term financial instruments, including cash equivalents, trade accounts receivable and trade accounts payable, approximate their fair values based on the short maturities of those instruments. The 12 ³/4 % Senior Secured Notes, the convertible senior debentures and the subordinated unsecured notes payable are fixed rate debt, but the interest rates are not materially different than current prevailing market rates based on relative maturities, and as such, their carrying value approximates fair value for such instruments.

Revenue Recognition

The Company records revenues from the sale of natural gas and oil when delivery to the customer has occurred and title has transferred. This recording of revenues occurs when natural gas or oil has been delivered to a pipeline or a tank lifting has occurred. Revenues from natural gas and oil production are recorded using the sales method. Under this method, revenues are recorded based on the Company’s net revenue interest, as delivered. The Company had no material gas imbalances at December 31, 2007 and 2006.

Asset Retirement Obligation

The Company accounts for its asset retirement obligations in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”). Asset retirement costs and liabilities associated with future site restoration and abandonment of tangible long-lived assets are initially measured at fair value which approximates the cost a third party would incur in performing the tasks necessary to retire such assets. The fair value is recognized in the financial statements as the present value of expected future cash expenditures for site restoration and abandonment. Subsequent to the initial measurement, the effect of the passage of time on the liability for the asset retirement obligation (accretion expense) and the amortization of the asset retirement cost are recognized in the results of operations.

Mineral Resource Properties

Mineral resource properties are properties that may hold mineral deposits of rutile (titanium dioxide), zircon (zirconium silicate) and other resource minerals. All exploration and related direct and indirect overhead expenditures for mineral resources are expensed. Capitalized acquisition costs, if any, are written off when the decision to abandon the mineral resource property is made.

Deferred Income Taxes

Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as income in the period that includes the enactment date. The Company has established a valuation reserve to offset its net deferred tax asset since, on a more likely than not basis, such benefits are not considered recoverable at this time.

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Earnings or Loss per Share

In accordance with the provisions of SFAS No. 128, “Earnings per Share” (“SFAS No. 128”), basic earnings or loss per share is computed on the basis of the weighted average number of common shares outstanding, excluding unvested restricted common shares, during the periods. Diluted earnings or loss per share is computed based upon the weighted average number of common shares outstanding, excluding unvested restricted common shares, plus the incremental effect of the assumed issuance of common shares for all potentially dilutive securities. Diluted per share amounts reflect the potential dilution that could occur if securities or other contracts to issue common shares were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options, restricted common shares and warrants and the “as if converted” method for the convertible senior debentures.

Stock-Based Compensation

The Company reports compensation expense for stock options and restricted common shares granted to officers, directors and employees using the fair value method. Stock-based compensation costs are recorded over the requisite service period, which approximates the vesting period.

Effective January 1, 2003, the Company adopted the provisions of SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”), using the prospective application method of SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure”. This statement requires the Company to record stock-based compensation costs for options granted under the Company’s stock option plan in accordance with the fair value method prescribed in SFAS No. 123.

Effective January 1, 2006, the Company adopted the fair value recognition provisions of the SFAS No. 123R, “Share-Based Payment” (“SFAS No. 123R”), using the modified-prospective method. Under that method, stock-based compensation cost for 2006 included: (a) compensation cost for all share-based payments granted prior to, but not yet vested as of, January 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123, and (b) compensation cost for all share-based payments granted subsequent to January 1, 2006, based on the grant-date fair value estimated in accordance with the provisions of SFAS No. 123(R). Compensation expense is recognized using the “graded-vesting method”, which recognizes compensation costs over the requisite service period for each separately vesting tranche of an award as though the award were, in substance, multiple awards. The adoption of SFAS No. 123R had an immaterial effect on 2006 financial results.

The table below reflects the pro-forma impact of stock-based compensation on the Company’s net loss and loss per share had the Company applied SFAS No. 123 to stock options granted prior to January 1, 2003 that vested in 2005:

 

		For the Year Ended December 31, 2005
		(in thousands, except per share data)
Net loss, as reported		$	(25,692	)
Cost of compensation expense using fair value (not tax effected)			(569	)
Net loss, pro forma		$	(26,261	)
Net loss per share, as reported		$	(0.20	)
Net loss per share, pro forma		$	(0.20	)

Joint Venture Operation

The majority of the Company’s natural gas and oil exploration activities are conducted jointly with others. These consolidated financial statements reflect only the Company’s proportionate interest in such activities.

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Industry Segment and Geographic Information

The Company operates in one industry segment, which is the exploration, development and production of natural gas and oil. The Company’s operational activities are conducted in the United States and Australia with only the United States currently having revenue generating operating results.

Treasury Stock

The Company’s common shares are without par value. Treasury stock purchases are recorded at cost as a reduction to common stock. Common shares are cancelled upon repurchase.

Hedging Program

The Company accounts for derivatives and hedging activities in accordance with SFAS Statement No. 133, Accounting for Derivative Instruments and Certain Hedging Activities, as amended, which requires entities to recognize all derivative instruments as either assets or liabilities in the balance sheet at their respective fair values. For derivatives designated as hedges, changes in the fair value are either offset against the change in fair value of the assets and liabilities through earnings, or recognized in accumulated other comprehensive income until the hedged item is recognized in earnings.

The Company utilizes derivative instruments in the form of natural gas costless collar price arrangements in order to manage price risk associated with future natural gas production. Such agreements are accounted for as hedges using the deferral method of accounting. Gains and losses resulting from these transactions, recorded at market value, are deferred and recorded in accumulated other comprehensive income as appropriate, until recognized as operating income in the Company’s consolidated statements of operations as the physical production hedged by the contracts is delivered.

The Company is required to assess the effectiveness of all our derivative contracts at inception and at every quarter-end. If open contracts cease to qualify for hedge accounting, mark-to-market accounting is utilized and changes in the fair value of open contracts are recognized in the consolidated statements of operations. Not qualifying for hedge accounting may cause volatility in net income. Fair value is assessed, measured and estimated by obtaining forward commodity pricing, credit adjusted risk-free interest rates and estimated volatility factors. In addition, forward price curves and estimates of future volatility factors are used to assess and measure the effectiveness of our open contracts at the end of each period. The fair values we report in our consolidated financial statements change as estimates are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.

The net cash flows related to any recognized gains or losses associated with these hedges are reported as oil and gas revenues and presented in cash flows from operations. If the hedge is terminated prior to expected maturity, gains or losses are deferred and included in income in the same period as the physical production hedged by the contracts is delivered.

The conditions to be met for a derivative instrument to qualify as a cash flow hedge are the following: (i) the item to be hedged exposes the Company to price risk; (ii) the derivative reduces the risk exposure and is designated as a hedge at the time the derivative contract is entered into; and (iii) at the inception of the hedge and throughout the hedge period there is a high correlation of changes in the market value of the derivative instrument and the fair value of the underlying item being hedged.

When the designated item associated with a derivative instrument matures, is sold, extinguished or terminated, derivative gains or losses are recognized as part of the gain or loss on sale or settlement of the underlying item. When a derivative instrument is associated with an anticipated transaction that is no longer expected to occur or if correlation no longer exists, the gain or loss on the derivative is recognized in income to the extent the future results have not been offset by the effects of price changes on the hedged item since the inception of the hedge.

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Restricted Cash

The Company is required to maintain cash balances that are restricted by provisions of certain banking agreements to support commodity hedging transactions. Restricted cash is invested in short term instruments at market rates; therefore, the carrying value approximates fair value. Such cash is included as Other Assets and is excluded from cash and cash equivalents in the consolidated balance sheets.

Reclassifications

Certain information provided for the prior years have been reclassified to conform to the current year presentation.

Recent Accounting Pronouncements

Fair Value Measurements. In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”), which addresses how companies should measure fair value when companies are required to use a fair value measure for recognition or disclosure purposes under US GAAP. As a result of SFAS No. 157, there is now a common definition of fair value to be used throughout US GAAP. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those years. The FASB has also issued Staff Position FAS 157-2 (“FSP No. 157-2”), which delays the effective date of SFAS No. 157 for nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually), until fiscal years beginning after November 15, 2008. The Company does not expect the adoption of SFAS No. 157 or FSP No. 157-2 to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.

Non-controlling Interests in Consolidated Financial Statements. In December 2007, the FASB Issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of Accounting Research Bulletin No. 51” (“SFAS No. 160”), which improves the relevance, comparability and transparency of the financial information that a reporting entity provides in its consolidated financial statements by establishing accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. This statement is effective for fiscal years beginning after December 15, 2008. The Company does not expect the adoption of SFAS No. 160 to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.

Business Combinations. In December 2007, FASB issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS No. 141R”), which replaces SFAS No. 141 (“SFAS No. 141”). This statement retains the fundamental requirements in SFAS No. 141 that the acquisition method of accounting (which SFAS No. 141 called the purchase method) be used for all business combinations. SFAS No. 141R also establishes principles and requirements for how the acquirer: (a) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; (b) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and (c) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141R is effective as of the beginning of an entity’s fiscal year that begins after December 15, 2008. Early adoption is prohibited. The Company is currently evaluating the impact of adopting SFAS No. 141R, which also requires acquisition transaction costs to be expensed as incurred rather than capitalized as a direct cost of the acquisition, as transaction costs are not considered an element of the fair value of the company acquired. Depending upon the size, nature and complexity of a future acquisition transaction, such transaction costs could be material to the Company’s results of operations.

 

3.	Drilling Advances

Drilling advances represents the Company’s proportionate share of planned authorized expenditures payable to the operator upon execution of the final drilling authorization of expenditures and an advance payment to a drilling contractor. The Company made advance payments totaling $2.0 million to a drilling contractor prior to the delivery of a drilling rig in November 2006. The advance payments are being amortized over the three-year term of the drilling contract agreement on a straight line basis as an increase to capitalized natural gas and oil property costs.

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

		Total
		(in thousands)
Balance as of December 31, 2005		$	391
Advances			14,228
Amounts applied			(5,482	)
Balance as of December 31, 2006			9,137
Advances			5,070
Amounts applied			(11,956	)
Balance as of December 31, 2007		$	2,251

 

4.	Property, Plant and Equipment

The amount capitalized as natural gas and oil properties was incurred for the purchase and development of various properties in the states of California, Montana, Texas, West Virginia and Wyoming in the United States and in New South Wales and Victoria in Australia. The following schedule represents natural gas and oil property costs by country:

 

		United States				Australia				Total
		(in thousands)
From inception to December 31, 2007:
Natural gas and oil properties, full cost method of accounting:
Unproved properties		$	46,527			$	23,317			$	69,844
Proved properties			246,768				604				247,372
Total natural gas and oil properties			293,295				23,921				317,216
Furniture and equipment			654				15				669
Total property and equipment			293,949				23,936				317,885
Impairment of proved natural gas and oil properties			(104,205	)			(604	)			(104,809	)
Accumulated depreciation, depletion and amortization			(55,941	)			(15	)			(55,956	)
Total accumulated depreciation, depletion and amortization			(160,146	)			(619	)			(160,765	)
Total property and equipment, net		$	133,803			$	23,317			$	157,120
From inception to December 31, 2006:
Natural gas and oil properties, full cost method of accounting:
Unproved properties		$	81,540			$	8,118			$	89,658
Proved properties			180,758				604				181,362
Total natural gas and oil properties			262,298				8,722				271,020
Furniture and equipment			585				15				600
Total property and equipment			262,883				8,737				271,620
Impairment of proved natural gas and oil properties			(75,691	)			(604	)			(76,295	)
Accumulated depreciation, depletion and amortization			(34,484	)			(15	)			(34,499	)
Total accumulated depreciation, depletion and amortization			(110,175	)			(619	)			(110,794	)
Total property and equipment, net		$	152,708			$	8,118			$	160,826

At December 31, 2007, unproved properties not being amortized consisted of drilling in progress costs and acreage acquisition costs of $21.1 million and $48.7 million, respectively. As of December 31, 2006, unproved properties not being amortized consisted of drilling in progress costs and acreage acquisition costs of $13.0 million and $76.6 million, respectively.

For the years ended December 31, 2007, 2006 and 2005, the results of management’s ceiling test evaluation resulted in an impairment of the U.S. proved properties of $28.5 million, $56.3 million and $8.7 million,

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

respectively. The December 31, 2007 U.S. proved property impairment was reported in the second quarter of 2007 utilizing a weighted average natural gas price of $5.72 per Mcf. Management determined that impairment was not required on the Australian properties at December 31, 2007, 2006 or 2005.

In May 2007, the Company sold a portion of its undeveloped natural gas and oil acreage in the Hilltop area of East Texas for approximately $66.5 million in cash, net of transaction costs of approximately $1.2 million, resulting in a gain on sale of $38.5 million. The Company follows the full cost method of accounting, which typically does not allow for gain on sale recognition involving less than 25% of the reserves in a given cost center. Reducing the U.S. full cost pool by the $66.5 million in net sales proceeds would have resulted in an approximate 39% reduction in capitalized cost with no change in proved reserves, thus “significantly altering” the relationship of capitalized costs to proved reserves. The significant reduction in the full cost pool was deemed to be an “out-of-the-ordinary situation”, and the Company determined that gain recognition on the sale of unproven property was the proper accounting treatment.

 

5.	GeoStar Acquisition

On June 17, 2005, the Company completed the acquisition of additional leasehold and working interests from GeoStar in the deep Bossier Hilltop prospect of East Texas and in the Powder River Basin of Wyoming and Montana (the “GeoStar Acquisition” and the “GeoStar Acquisition Properties”). The Company paid a total of $73.1 million, after acquisition costs of $400,000 and purchase price adjustments of $4.2 million for the interest acquired from January 1, 2005 (“Effective Date”) to June 17, 2005 (“Acquisition Date”). This amount consisted of $30.9 million in cash, 1,650,133 common shares valued at $6.0 million based on a per share price of CDN$4.50 and $32.0 million in unsecured subordinated notes scheduled to mature on January 31, 2006 and bearing interest at the rate of 3.42% (“GeoStar Subordinated Notes”). The acquisition was accounted for using the purchase method in which the cost of the acquisition was allocated first to identifiable net assets acquired based on estimated fair values. The results of operations are included in the accompanying consolidated financial statements only from the Acquisition Date. On March 31, 2006, the purchase price adjustment of $4.2 million was settled for $2.1 million in cash and the issuance of 548,128 common shares of the Company valued at CDN$4.50 per share.

The initial carrying values of the GeoStar Acquisition Properties as of June 17, 2005 was entirely allocated to natural gas and oil properties, of which $14.5 million was for proved developed properties, $8.7 million was for proved undeveloped properties and $49.9 million was for unproved properties.

In addition, GeoStar may receive additional common shares at prevailing market prices based on look-backs at June 30, 2006 and June 30, 2007 on the East Texas assets, based on a required number of drilled wells, and net reserve additions valued at $1.50 per Mcf less attributable development expenditures to GeoStar’s acquired interest. For additional information, see Footnote 16, “Commitments and Contingencies – Litigation”.

On August 11, 2005, the Company executed an agreement with GeoStar whereby the GeoStar Subordinated Notes were cancelled. In conjunction with the cancellation of the GeoStar Subordinated Notes, the Company issued to GeoStar 6,373,694 common shares of the Company valued at $17.0 million based on a per share price of CDN $3.25 and a new unsecured subordinated note (“New GeoStar Subordinated Note”) for $15.0 million. The New GeoStar Subordinated Note bore interest, payable monthly commencing February 15, 2006, at three-month LIBOR plus 4.5%. On November 28, 2005, concurrent with the transaction with Chesapeake Energy Corporation (“Chesapeake”), the New GeoStar Subordinated Note was paid in full, as required by the agreement.

The following unaudited pro forma results for the year ended December 31, 2005 show the effect on the Company’s consolidated results of operations as if the GeoStar Acquisition had occurred at the beginning of the period presented. The pro forma results are the result of combining the statement of operations of the Company with the statement of revenues and direct operating expenses for the properties acquired from GeoStar adjusted for (1) the financing and share issuance directly attributable to the acquisition, (2) assumption of ARO liabilities and accretion expense for the properties acquired and (3) additional depreciation, depletion and amortization expense as a result of the Company’s increased ownership in the acquired properties. The statement of revenues and direct operating expenses for the GeoStar assets exclude all other historical expenses of GeoStar. As a result, certain estimates and judgments were made in preparing the pro forma adjustments. Further, the pro forma information includes numerous assumptions and is not necessarily indicative of future results of operations.

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

		For the Year Ended December 31, 2005
		(in thousands, except per share data) (Unaudited)
Revenues		$	31,370
Net loss		$	(27,862	)
Loss per share:
Basic and diluted		$	(0.21	)

The pro forma information above is presented for illustrative purposes only and may not be indicative of the results of operations that would have actually occurred had the GeoStar Acquisition occurred as presented. Further, the above pro forma amounts do not consider any potential synergies or integration costs that may result from the transaction. In addition, future results may vary significantly from the results reflected in such pro forma information.

Various disputes have arisen primarily over the past year, in connection with joint activities and general operating and administrative activity between GeoStar and the Company. See Footnote 16, Commitments and Contingencies—Litigation for the current status of such disputes and pending litigation.

 

6.	Long-Term-Debt

The following shows the Company’s long-term debt as of the dates indicated:

 

		As of December 31,
		2007			2006
		(in thousands)
12 3/4% senior secured notes		$	99,506		$	—
Revolving credit facility			—			—
Senior secured notes			—			60,671
Convertible senior debenture			30,000			30,000
Subordinated unsecured notes payable			3,179			3,132
Total net carrying value of long-term debt			132,685			93,803
Debt discount costs to be accreted			565			12,447
Total long-term debt at maturity		$	133,250		$	106,250

12 ³ /4% Senior Secured Notes due 2012

On November 29, 2007, Gastar USA, a wholly owned subsidiary of Gastar Exploration Ltd., (“Parent”) sold $100.0 million aggregate principal amount of 12 ³/4% Senior Secured Notes due December 1, 2012 (“12 ³/4% Senior Secured Notes”) at an issue price of 99.50%. Approximately $76.7 million of the $92.5 million net proceeds from the offering were used to repay the then outstanding senior secured notes, with the remaining net proceeds to be used for general corporate purposes. The 12 ³/4 % Senior Secured Notes mature on December 1, 2012.

Interest is payable, semi-annually on June 1 and December 1, in cash on the principal amount at an annual rate of 12 ³/4%. The annual effective interest rate, after amortization of the debt discount and fees paid to establish the 12 ³/4% Senior Secured Notes, is 14.89%. The 12 ³/4% Senior Secured Notes are fully and unconditionally guaranteed jointly and severally by Gastar USA, the Parent and all of the Parent’s existing and future material domestic subsidiaries. The 12 ³/4% Senior Secured Notes and the guarantees rank equal in right of payment with all existing and future senior indebtedness of Gastar USA and the Guarantors and senior in right of payment to any future subordinated indebtedness of Gastar USA and the Guarantors, as applicable. The 12 ³/4% Senior Secured Notes and the guarantees are secured by a lien on Gastar USA’s principal domestic oil and gas properties and other assets that secure Gastar USA’s revolving credit facility (“Revolving Credit Facility”), subject to certain exceptions. Pursuant

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

to the terms of an intercreditor agreement, the lien securing the 12 ³/4% Senior Secured Notes is contractually subordinated to (i) the lien that secures the Revolving Credit Facility and (ii) certain hedging obligations of Gastar USA. Consequently, the 12 ³/4% Senior Secured Notes and the guarantees are effectively subordinated to Gastar USA’s and the Guarantors’ secured obligations, including the Revolving Credit Facility, to the extent of the value of the assets securing such obligations.

At any time prior to June 1, 2010, Gastar USA may redeem the 12 ³/4% Senior Secured Notes in whole or in part at a redemption price equal to 100% of the principal amount plus the applicable premium. The applicable premium is the greater of (i) 1.0% of the 12 ³/4% Senior Secured Notes being redeemed and (ii) the excess of (A) the present value at such time of (1) redemption price of 12 ³/4% Senior Secured Notes as of June 1, 2010 (without regard to accrued and unpaid interest) plus (2) all required interest payments due on 12 ³/4% Senior Secured Notes through June 1, 2010, computed using a discount rate equal to the Treasury Rate plus 50 basis points, over (B) the principal amount of 12 ³/4% Senior Secured Notes. At any time and from time to time prior to June 1, 2010, Gastar USA may redeem up to 35% of the aggregate principal amount of the 12 ³/ 4% Senior Secured Notes with the net cash proceeds of one or more equity offerings at 112.750% of the aggregate principal amount, plus accrued and unpaid interest. On or after June 1, 2010, Gastar USA may redeem the 12 ³/4% Senior Secured Notes during the 12-month periods beginning on June 1 of the years and at a premium as set forth below:

 

Twelve-Month Period Beginning June 1,		Percentage
2010		106.375	%
2011		103.188	%
2012		100.000	%

If a change of control of Parent and the Guarantors, taken as a whole, occurs prior to December 1, 2008, Gastar USA may elect to redeem all, but not less than all, of the 12 ³/4% Senior Secured Notes at the price of 112.750%, plus accrued and unpaid interest. If Parent and the Guarantors, taken as a whole, experience a change in control, but elects not to redeem all 12 ³/4% Senior Secured Notes, the holders of the 12 ³/4% Senior Secured Notes have the right to require Gastar USA to repurchase the 12 ³/4% Senior Secured Notes at 101% of principal amount, plus accrued and unpaid interest.

Within 30 days of an asset sale greater than $10.0 million, excluding Wyoming property sales, Gastar USA will offer to use the net proceeds to repurchase that portion of the 12 ³/4% Senior Secured Notes at a premium as set forth below:

 

Period		Percentage
Prior to June 1, 2011		106.375	%
June 2, 2011 to June 1, 2012		103.188	%
After June 1, 2012		100.000	%

Gastar USA is obligated to prepare and file with the Securities and Exchange Commission (“SEC”) within 150 days of the issue date of the 12 ³/4% Senior Secured Notes, or April 27, 2008, a registration statement to exchange the 12 ³/4% Senior Secured Notes for registered, publicly tradable notes that have substantially identical terms as the 12 ³/4% Senior Secured Notes. Gastar USA is to use its best efforts to cause the registration statement to be declared effective within 240 day of the issue date of the 12 ³/4% Senior Secured Notes, or July 24, 2008. Gastar USA has agreed to offer new notes in exchange for the 12 ³/4% Senior Secured Notes as soon as is practicable after the registration statement has become effective, unless prohibited by law or SEC policy, and to file a shelf registration statement for the resale of the 12 ³/4% Senior Secured Notes if Gastar USA cannot consummate the exchange offer within 290 days of the date of the issuance of the 12 ³/4% Senior Secured Notes, or September 12, 2008, and in certain other circumstances. In the event Gastar USA fails to meet its registration obligations as set forth above, Gastar USA has agreed to pay liquidated damages to the holders of the 12 ³/4% Senior Secured Notes in the form of additional cash interest payments on the 12 ³/4% Senior Secured Notes equal to 0.25% per annum for the first 90-day period, increasing to a maximum of 0.50% per annum for each subsequent 90-day period. The Company intends to file a registration statement with the SEC on or before April 27, 2008 and to use its best efforts to have such statement effective on or before September 12, 1008.

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

The 12 ³/4% Senior Secured Notes contain certain covenants, that among other things, limit Gastar USA’s and the Guarantors’ ability to: (i) incur additional indebtedness; (ii) pay distributions on, or repurchase or redeem Company equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into certain transactions with affiliates; and (vi) sell assets or consolidate or merge into other companies. Notwithstanding the above, Gastar USA may incur up to $25.0 million of indebtedness under the Revolving Credit Facility (see below) and such additional amounts of 12 ³/4% Senior Secured Notes or indebtedness subordinate to the 12 ³/4% Senior Secured Notes; provided that Gastar USA’s consolidated cash flow to fixed charges for the most recent four quarters giving the effect of the incurrence at the beginning of such four-quarter-period is at least 2.0 to 1.0. As of December 31, 2007, the Company was in compliance with all debt covenants.

Covenants in the 12 ³/4 % Senior Secured Notes Indenture provide that if there is a change of control the Company will make an offer to each note holder to repurchase all or any part of the 12 ³ /4% Senior Secured Notes at 101% of the aggregate principal amount of the 12 ³/4% Senior Secured Notes to be repurchased.

Revolving Credit Facility

On November 29, 2007, concurrent with the closing of the 12 ³/4% Senior Secured Notes, Gastar USA entered into a Revolving Credit Facility providing for an initial first priority lien maximum borrowing base of $19.4 million at December 31, 2007, of which no amounts were outstanding. The borrowing base is to be redetermined at least semiannually, using the lender’s usual and customary criteria for natural gas and oil reserve valuation. If at any time the outstanding credit extended under the Revolving Credit Facility exceeds the lesser of the aggregate commitments or the applicable borrowing base, the deficiency will be required to be amortized in three monthly installments, and until the deficiency is eliminated, increases in some applicable interest rate margins apply.

The lender’s commitment under the Revolving Credit Facility will be limited to a maximum of $250 million outstanding at any one time, subject to applicable borrowing base limitations. Borrowings under the Revolving Credit Facility bears interest, at Gastar USA’s election, at a prime rate or Eurodollar rate, plus in each case an applicable margin. The applicable interest rate margin varies from -0.75% to 0.0% in the case of borrowings based on the prime rate and from 1.5% to 2.25% in the case of borrowings based on the Eurodollar rate, depending on the utilization level in relation to the borrowing base. At December 31, 2007, the prime rate and the Eurodollar rate were 7.25% and 4.70%, respectively. At closing, Gastar USA paid a commitment fee of $73,000. In addition, an annual commitment fee, ranging from 0.375% to 0.50% depending on borrowing base utilization, is payable on the unused portion of each lender’s commitment; provided, however, such rate as to the portion of the available commitment allocable to the lender on the basis of its percentage share as a lender shall be reduced if certain cash deposit investments are maintained with the lender.

All outstanding amounts owed under the Revolving Credit Facility become due and payable no later than October 15, 2009, unless extended by the lender, and will be subject to acceleration upon the occurrence of certain usual and customary events of default, including among others:

 

•

Failure to make payments under the Revolving Credit Facility;

 

•

Non-performance of covenants and obligations continuing beyond any applicable grace period; and

 

•

The occurrence of a “change in control” of our Parent.

The Revolving Credit Facility is guaranteed by the Parent and all its current domestic subsidiaries and all future domestic subsidiaries formed during the term of the Revolving Credit Facility. Borrowings and related guarantees under the Revolving Credit Facility are secured by a first priority lien on all domestic natural gas and oil properties currently owned by or later acquired by Gastar USA, excluding de minimus value properties as determined by the lender. The facility is secured by a first priority pledge of the stock of each domestic subsidiary, a first priority interest on all accounts receivable, notes receivable, inventory, contract rights, general intangibles and material property of the Issuer and 65% of the stock of each foreign subsidiary of the Issuer.

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

The Revolving Credit Facility contains various covenants, including among others:

 

•

Restrictions on liens;

 

•

Restrictions on incurring other indebtedness without lender’s consent;

 

•

Restrictions on Company dividends and other restricted payments;

 

•

Maintenance of a minimum consolidated current ratio, as adjusted, of not less than 1.0 to 1.0;

 

•

Maintenance of a maximum total net debt to earnings before interest, taxes, depreciation and amortization (“EBITDA”), on a rolling four quarters basis as adjusted, of not more than 5.0 to 1.0 through June 30, 2008, 4.25 to 1.0 for the quarters ended September 30, 2008 and December 31, 2008 and 4.0 to 1.0 for all quarters thereafter;

 

•

Limitation on general and administrative expense, excluding any stock based compensation costs, not to exceed 25% of consolidated revenue less lease operating and production tax expenses, as adjusted, for any quarter; and

 

•

Maintenance of cash liquidity equal to the semi-annual interest payment under 12 3/4% Senior Secured Notes, so long as the borrowing based under the Revolving Credit Facility is less than $40.0 million, unless borrowing base utilization is zero or less then 90%.

As of December 31, 2007, the Company was in compliance with all debt covenants.

Should there occur a change of control of the Parent, then, five days after such occurrence, immediately and without notice, (i) all amounts outstanding under the Revolving Credit Facility shall automatically become immediately due and payable and (ii) the commitments shall immediately cease and terminate unless and until reinstated by the lender in writing. If amounts outstanding under the Revolving Credit Facility become immediately due and payable in accordance with the immediately preceding sentence, the obligation of the Gastar USA with respect to any commodity hedge exposure shall be to provide cash as collateral to be held and administered by the lender as collateral agent.

Senior Secured Notes

On June 17, 2005, the Company issued $63.0 million in principal amount of senior secured notes. On September 19, 2005, the Company issued to the holders of these notes an additional $10.0 million of senior secured notes on substantially the same terms as the original June 2005 private placement. The senior secured notes were secured by substantially all of the Company’s assets, bear interest payable quarterly equal to the sum of the three-month LIBOR rate at the beginning of the current quarter plus 6.0%, and mature five years and one day from the date of issuance. The senior secured notes were redeemable in whole or in part prior to maturity at the Company’s option at any time upon payment of the principal and accrued and unpaid interest plus a premium of 5% until the third anniversary of issuance, 4% from the third anniversary to the fourth anniversary and 3% from the fourth anniversary until the day before maturity. Redemption at the Company’s option was not permitted following the public announcement of certain pending, proposed or intended change of control transactions.

In connection with the senior secured notes issuances, the Company agreed to issue to the note holders, for no additional consideration, common shares in increments valued at CDN$4.5 million with respect to the $63.0 million of senior secured notes and additional common shares in increments valued at CDN$714,286 with respect to the $10.0 million of senior secured notes at closing and on each of the six, twelve and eighteen-month anniversaries of the closing date, valued on a five-day weighted average trading price immediately prior to the date of issuance. The Company initially recorded a liability of $17.0 million related to common shares to be issued and a corresponding amount recorded as a debt discount to be accreted to interest expense using the effective interest method. The Company also incurred an estimated $3.0 million of direct financing costs for legal fees and fees paid to an agent as deferred charges and are amortizing these costs over the term of the senior secured notes. Subsequent to the March 19, 2007 issuance of common shares to the note holders, the Company had no further obligation to issue additional common shares under the senior secured notes.

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

On November 29, 2007, in connection with the sale of $100.0 million aggregate principal amount of 12 ³/4% Senior Secured Notes, the Company repaid in full the $73.0 million of senior secured notes. The Company paid a prepayment penalty of $3.65 million, or 5% of the aggregate principal amount repaid.

Convertible Senior Debentures

In November 2004, the Company issued $30.0 million aggregate principal amount of convertible senior unsecured debentures. The convertible senior debentures have a term of five years and will be due November 20, 2009 and bear interest at 9.75% per annum, payable quarterly. The convertible senior debentures are convertible by the holders into 6,849,315 common shares at a conversion price of $4.38 per share. The convertible senior debentures may be redeemed at any time by the Company at a redemption price equal to par plus accrued and unpaid interest; provided that, the volume weighted average trading price of the common shares of the Company, for at least 20 trading days in any consecutive 30-day period, equals or exceeds $4.38.

The Company incurred an estimated $1.9 million of direct financing costs for legal fees and other expenses as deferred charges, which are being amortized over the term of convertible senior debentures. The Company also issued 259,740 broker warrants with an exercise price of $3.87 and a fair value of $359,000. Interest expense relating to the amortization of the warrants for each of the years ended December 31, 2007, 2006 and 2005 was $72,000. There was no beneficial conversion feature associated with the convertible senior debentures.

On February 3, 2006, the Company issued 21,948 common shares upon exercise of 21,948 broker warrants at $3.87 per share issued in connection with the sale of the convertible senior debentures. The remaining 237,792 broker warrants expired in May 2006.

Upon the occurrence of a change of control, as defined in the debenture indenture, the Company is required to make an offer to purchase all of the convertible senior debentures at a price equal to 101% of the offer price set forth in the debenture indenture plus accrued and unpaid interest. If 90% or more of the principal amount of all convertible senior debentures outstanding on the date the Company provides notice of a change of control to the convertible senior debentures trustee have been tendered for purchase pursuant to the change of control offer, the Company has the right to redeem the remaining outstanding convertible senior debentures on the same date and at the same price.

Subordinated Unsecured Notes Payable

The Company’s subordinated unsecured notes mature between April 2009 and September 2009, bear interest at 10% per annum and are callable by the Company at 105% after three years and 101% after four years. The subscribers were issued 232,521 warrants exercisable at prices ranging from $2.76 to $3.03 expiring at varying dates between April 2009 and September 2009. A value of $235,000 was ascribed to the warrants and recorded as a debt discount to be accreted to interest expense using the effective interest method. Cash commissions of $196,000 were incurred, which have been capitalized and are being amortized over the term of the subordinated unsecured notes.

Long-term Debt Maturities

The following table represents the maturities of the Company’s long-term debt agreements:

 

		Amount
		(in thousands)
2008		$	—
2009			33,250
2010			—
2011			—
2012			100,000
Total		$	133,250

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Loss on Early Extinguishment of Debt

On November 29, 2007, as a result of the prepayment prior to maturity of the $73.0 million of senior secured notes, the Company expensed all unamortized deferred financing costs of $2.7 million, $9.3 million debt discount costs being accreted and $3.7 million of early prepayment penalty, resulting in a loss on early debt extinguishment of $15.7 million. In June 2005, in conjunction with the issuance of the senior secured notes, the Company retired certain Senior Secured Notes, resulting in a debt extinguishment expense of $1.4 million, comprised of $662,000 of early prepayment penalty and $694,000 of unamortized deferred financing costs.

 

7.	Asset Retirement Obligation

The Company accounts for its liabilities associated with site restoration and abandonment of its natural gas and oil properties pursuant to the provisions of SFAS No. 143. A summary of the activity related to the asset retirement obligation is as follows:

 

		December 31,
		2007				2006			2005
		(in thousands)
Asset retirement obligation, beginning of year		$	4,218			$	3,558		$	1,711
Liabilities incurred			642				426			816
Accretion expense			281				234			109
Increase due to acquisition			—				—			922
Revision in previous estimates			(750	)			—			—
Asset retirement obligation, end of year		$	4,391			$	4,218		$	3,558

 

8.	Equity Compensation Plans

Share-Based Compensation Plans

2002 Stock Option Plan. The Company’s 2002 Stock Option Plan was approved and ratified by the Company’s shareholders in July 2002. It authorizes the Company’s Board of Directors to issue stock options to directors, officers, employees and consultants of the Company and its subsidiaries to purchase a maximum of 25.0 million common shares. Stock option grant expirations vary between five and ten years. The vesting schedule has varied from two years to four years but generally has occurred over a four-year period at 25% per year beginning on the first anniversary date of the grant. Stock options issued pursuant to the Company’s 2002 Stock Option Plan have an exercise price determined by the Board of Directors, but that exercise price cannot be less than the market price on the date immediately prior to the date of grant as reported by any stock exchange on which the Company’s common shares are listed. If a stock option granted under the Company’s 2002 Stock Option Plan expires or terminates for any reason in accordance with the terms of the Company’s Stock Option Plan, the unpurchased common shares subject to that stock option become available for other stock option grants.

In April 2004, the Board of Directors amended the provisions of the Company’s 2002 Stock Option Plan to specifically incorporate a provision to provide for stock options to be exercised on a cashless basis, whereby the Company issues to the optionee the number of common shares equal to the stock option exercised, less the number of common shares which when multiplied by the market price at the date of exercise equals the aggregate exercise price for all of the common shares exercised. As of December 31, 2007, stock option grants covering the issuance of 10,173,750 common shares were outstanding under the 2002 Stock Option Plan.

2006 Gastar Long-Term Stock Incentive Plan. On June 1, 2006, the Company’s shareholders approved the 2006 Gastar Long-Term Stock Incentive Plan. The 2006 Gastar Long-Term Stock Incentive Plan authorizes the Company’s Board of Directors to issue stock options, stock appreciation rights, bonus stock awards and any other type of award established by the Committee which is consistent with the Plan’s purposes to directors, officers and employees of the Company and its subsidiaries covering a maximum of 5.0 million common shares. The contractual life and vesting period for a grant will be determined by the Board of Directors at the time grant is awarded. The vesting period for restricted common stock grants during 2007 was over four years, with one-third vesting on the second, third and fourth anniversaries of the date of grant. As of December 31, 2007, only grants covering the issuance of 1,096,000 restricted common shares were outstanding under the 2006 Gastar Long-Term Stock Incentive Plan.

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Determining Fair Value under SFAS No. 123R

In determining fair value for stock option grants pursuant to SFAS No. 123R, the Company utilized the following assumptions:

Valuation and Amortization Method. The Company estimates the fair value of share-based awards granted using the Black-Scholes-Merton valuation model. The fair value of all awards is expensed using the “graded-vesting method”.

Expected Life. The expected life of awards granted represents the period of time that stock options are expected to be outstanding. The Company determined the expected life using the “simplified method” resulting in a 6.25-year expected life in accordance with Staff Accounting Bulletin No. 107 for all stock options issued with a four-year vesting period and a ten-year grant expiration. Using the simplified method, stock options that have been issued with two and three-year vesting periods and having a ten-year expiration have an expected life of 5.75 and 6.0 years, respectively. Beginning in 2008, management will determine expected life of stock option grants based on historical records.

Expected Volatility. Using the Black-Scholes-Merton valuation model, the Company estimates the volatility of its common shares at the beginning of the quarter in which the stock option is granted. The volatility is based on historical movements of our common share price on the American Stock Exchange and the Toronto Stock Exchange over a period that approximates the expected life.

Risk-Free Interest Rate. The Company utilizes a risk-free interest rate equal to the rate of U.S. Treasury zero-coupon issues as of the date of grant with a term equivalent to the stock option’s expected life.

Expected Dividend Yield. The Company has not paid any cash dividends on its common shares and does not anticipate paying any cash dividends in the foreseeable future. Consequently, a dividend yield of zero is utilized in the Black-Scholes-Merton valuation model.

Expected Forfeitures. The Company utilized a forfeiture rate of 5% for 2007 and 2006 in determining initial compensation expense, based on forfeitures of all unvested stock option as a percentage of all stock option grants calculated at the beginning of the year.

The fair value of each stock option grant is estimated on the date of grant using the Black-Scholes-Merton valuation pricing model. The table below summarizes the number of stock options granted and the assumptions for the stock options granted for the periods indicated:

 

		For the Years Ended December 31,
		2007			2006			2005
Stock options granted		828,000			4,790,000			711,000
Expected life (in years)		6.25			6.5			5.0
Expected volatility		44.4-44.7	%		45.7	%		41.5	%
Risk-free interest rate		4.3%-5.1	%		5.0	%		5.0	%

The weighted average grant date fair value of stock options granted and the intrinsic value of stock options exercised are shown below for the periods indicated. Intrinsic value of stock options is calculated using the difference between the common share price on the date of exercise and the exercise price times the number of stock options exercised. There were no stock options exercised in 2007.

 

		For the Years Ended December 31,
		2007			2006			2005
Weighted average grant date fair value		$	1.11		$	1.28		$	1.19
Intrinsic value of stock options exercised (000)		$	—		$	2,922		$	17,491
Fair value of shares vested during year		$	2,912		$	2,516		$	18,674

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Stock Option Activity

The following table summarizes the annual changes and option exercise prices for stock options under the Company’s Stock Option Plan for the year ended December 31, 2007:

 

		Number of Shares Under Stock Options			Average Exercise Price
Stock options outstanding as of December 31, 2006		10,472,750			$	2.86
Stock options granted		828,000			$	2.18
Stock options exercised (1)		—				—
Stock options cancelled/expired		(1,127,000	)		$	2.90
Stock options outstanding as of December 31, 2007		10,173,750			$	3.19
Stock options exercisable:
December 31, 2007		5,127,916			$	3.29

 

(1)	There were no stock options forfeited during 2007.

The table below summarizes certain information about the stock options for the year ended December 31, 2007. Fair value calculations are as of the date of grant.

 

		Number of Shares Under Stock Options		Weighted Average Fair Value
Unvested stock options at the beginning of year		7,541,250		$	1.26
Unvested stock options at the end of the year		5,045,834		$	1.22
Stock options granted during the year		828,000		$	1.11
Stock options vested during the year		2,497,550		$	1.17
Stock options forfeited during the year		—		$	—

As of December 31, 2007, there was no aggregate intrinsic value for outstanding stock options, and the remaining weighted average contractual life of outstanding stock options was 5.3 years. As of December 31, 2007, there was no aggregate intrinsic value for exercisable stock options, and the remaining weighted average contractual life of exercisable stock options was 3.8 years. As of December 31, 2007, the total fair value of exercisable stock options was $5.6 million.

The following table summarizes the range of exercise prices for stock options outstanding and exercisable as of December 31, 2007:

 

Expiration Date		Number of Shares Under Stock Options				Exercise Prices (1)
		Outstanding		Exercisable
April 20, 2009		625,000		468,750		$	3.77
August 4, 2009		3,653,750		2,726,250		$	3.48
April 4, 2010		21,000		10,500		$	4.38
June 24, 2010		345,000		148,750		$	3.57
June 28, 2010		50,000		25,000		$	3.47
September 7, 2010		150,000		75,000		$	3.31
September 20, 2010		40,000		20,000		$	4.08
October 17, 2015		75,000		37,500		$	4.59
January 16, 2016		270,000		67,500		$	5.11
April 5, 2016		838,000		209,500		$	4.89
May 24, 2016		50,000		12,500		$	3.31
July 14, 2016		3,230,000		1,326,666		$	2.32
January 12, 2017		25,000		—		$	1.95
March 30, 2017		200,000		—		$	2.17
July 3, 2017		400,000		—		$	2.20
July 7, 2017		200,000		—		$	2.19
August 30, 2017		1,000		—		$	1.67
		10,173,750		5,127,916

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

 

(1)	Stock options granted with strike prices denominated in CDN$ were converted to US$ by multiplying the CDN$ strike price by the exchange rate at December 31, 2007.

Restricted Share Activities

The following table summarizes the changes and grant date prices for restricted common share grants for the year ended December 31, 2007:

 

		Number of Shares Under Stock Options			Weighted Average Grant Date Fair Value
Restricted common shares outstanding as of December 31, 2006		—			$	—
Restricted common shares granted		1,105,000				2.15
Restricted common shares vested		—				—
Restricted common shares cancelled/expired		(9,000	)			2.20
Restricted common shares outstanding as of December 31, 2007		1,096,000			$	2.15

The following table summarizes the range of grant dates (expiration dates) and grant date prices for restricted common shares outstanding and unvested as of December 31, 2007:

 

		Restricted Common Shares Outstanding		Grant Date Fair Value
July 3, 2007 (July 3, 2011)		983,500		$	2.20
August 27, 2007 (August 27, 2011)		112,500		$	1.67
Total		1,096,000		$	2.15

As of December 31, 2007, the remaining weighted average contractual life of unvested restricted common shares was 3.5 years. The following table shows the total value and weighted average fair value per share of restricted common shares outstanding for the periods indicated:

 

		As of December 31,
		2007			2006
		(in thousands, except per share data)
Total value of restricted common shares outstanding		$	1,370		$	—
Weighted average grant date fair value per share of restricted common share outstanding		$	2.15		$	—

Stock-Based Compensation Expense

For the years ended December 31, 2007, 2006 and 2005, the Company recorded stock-based compensation expense for stock options and restricted common shares granted using the fair-value method of $3.9 million, $3.9 million and $2.3 million, respectively. All stock based compensation costs were expensed and not tax effected, as the Company currently records no income tax expense. All common shares issued upon exercise or vesting are reserved and non-assessable.

At December 31, 2007, the Company had unvested stock options to purchase 5,045,834 common shares with a weighted average grant date fair value of $1.22 per common share and 1,096,000 restricted common shares outstanding having a weighted average grant date value of $2.15 per common share. As of December 31, 2007, the Company had approximately $4.3 million of total unrecognized compensation cost related to unvested stock options and restricted common shares, which is expected to be amortized over the following periods:

 

		Amount
		(in thousands)
2008		$	2,536
2009			1,161
2010			434
2011			120
2012			—
Total		$	4,251

 

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9.	Commodity Hedging Contracts

In the third and fourth quarters of 2007, the Company entered into costless collar transactions with counterparties for the purpose of mitigating revenue volatility. The following transactions were outstanding with associated notional volumes and contracted floor and ceiling prices that represent hedge prices for the index specified as of December 31, 2007:

 

Date		Period		Derivative Instrument		Hedge Strategy		Notional Daily Volume		Total of Notional Volume		Floor Price			Ceiling Price			Index			Production Area Hedged		Total of Proved Natural Gas Production Hedged (1)
								(MMBtu)		(MMBtu)		(MMBtu)			(MMBtu)
09/24/07		Year 2008		Costless Collar		Cash Flow		2,000		732,000		$	5.50		$	7.50		CIG	(2)		WY		53	%
12/12/07		Year 2008		Costless Collar		Cash Flow		5,000		1,830,000		$	6.75		$	8.00		HSC	(3)		E. TX		40	%

 

(1)	Estimated based on respective year net natural gas production as projected in the reserve report by Netherland, Sewell & Associates, Inc. as of December 31, 2007.

(2)	East-Houston-Katy - Houston Ship Channel.

(3)	Inside FERC Colorado Interstate Gas, Rocky Mountains.

As of December 31, 2007, the Company’s current cash flow hedge positions were with counterparties that are major United States financial institutions. The credit support for the CIG hedge is a $1.0 million collateral position with the counterparty secured by a cash collateralized letter of credit. As of December 31, 2007, the Company has 43% of its total 2008 estimated production hedged, based on its year end third party engineering report. At December 31, 2007, the Company recorded a short term derivative liability of $480,000 related to the difference between hedged commodity prices and market prices on hedged volumes as of December 31, 2007. All of the Company’s derivative instruments have been designated cash flow as hedging instruments and are deemed to be highly effective.

 

10.	Common Shares

Authorized

The Company’s articles of incorporation allow the Company to issue an unlimited number of common shares without par value.

Other Share Issuances

On June 17, 2005, the Company issued 1,217,269 common shares valued at $3.6 million (CDN$4.5 million) based upon a five-day weighted average trading price of CDN$3.69 per share pursuant to the private placement of $63.0 million senior secured notes.

On June 17, 2005, concurrent with private placement of $63.0 million senior secured notes, the Company issued 1,650,133 common shares valued at $6.0 million (CDN$7.4 million at CDN$4.50 per share) pursuant to the acquisition of additional leasehold and working interest properties in East Texas and the Powder River Basin from GeoStar.

 

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On June 30, 2005, the Company completed a private placement of 6,617,736 common shares valued at $16.4 million (CDN$20.5 million at CDN$3.31 per share) after deducting placement fees and expenses.

On August 11, 2005, the Company issued to GeoStar 6,373,694 common shares at CDN$3.25 per share in conjunction with partial payment of $17.0 million of the $32.0 million GeoStar subordinated notes.

On September 19, 2005, the Company issued 206,354 common shares representing and aggregate value of $606,000 (CDN$714,286) based upon a five-day weighted average trading price of CDN$3.46 per share pursuant to the private placement of $10.0 million of senior secured notes.

During the month of September 2005, the 2,005,027 Bossier warrants were exercised and converted into common shares of the Company. Of the Bossier warrants exercised, 207,814 were exercised for cash proceeds of $413,000 (CDN$485,000) and 1,797,214 were exercised on a cashless basis. The Bossier warrants exercised on a cashless basis resulted in the issuance of 841,224 net Company common shares.

On November 4, 2005, the Company completed a private placement of 27,151,641 common shares to Chesapeake valued at $73.8 million (CDN$89.9 million at CDN$3.31 per share) after deducting placement fees and expenses.

On December 19, 2005, the Company issued 1,082,105 common shares valued at $3.6 million (CDN$4.5 million) based upon a five-day weighted average trading price of CDN$4.16 per share upon the six month anniversary of the private placement of $63.0 million senior secured notes.

During 2005, pursuant to the Company’s Stock Option Plan, the Company issued 3,721,300 common shares for cash exercises of $707,000 and 2,214,888 common shares on a cashless exercise basis.

On February 3, 2006, the Company issued 21,948 common shares upon exercise of warrants at CDN$4.65 per share issued in connection with the sale of the convertible senior debentures.

On March 20, 2006, the six-month anniversary of the September 19, 2005 $10.0 million senior secured notes issuance, the Company issued to the note holders an additional 152,299 common shares valued at CDN$714,286.

On March 31, 2006, the Company issued 548,128 common shares in a private placement in settlement of a purchase price adjustment on the acquisition of natural gas and oil properties.

On June 19, 2006, the twelve-month anniversary of the June 17, 2005 $63.0 million senior secured notes issuance, the Company issued to the note holders an additional 1,607,143 common shares valued at CDN$4.5 million.

On September 19, 2006, the twelve-month anniversary of the September 19, 2005 $10.0 million senior secured notes issuance, the Company issued to the note holders an additional 256,016 common shares valued at CDN$714,286.

On November 17, 2006, the Company issued 25,000,000 common shares at $2.00 in a private transaction to institutional investors.

On December 19, 2006, the eighteen-month anniversary of the June 17, 2005 $63.0 million senior secured notes issuance, the Company issued to the note holders an additional 1,800,000 common shares valued at CDN$4.5 million.

During the year ended December 31, 2006, pursuant to the Company’s Stock Option Plan, the Company issued 905,636 common shares net of forfeitures in connection with the cashless exercise of stock options.

 

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On March 19, 2007, the eighteen-month anniversary of the September 19, 2005 $10.0 million senior secured notes issuance, the Company issued to the note holders an additional 375,939 common shares valued at CDN$714,286.

On May 9, 2007, in conjunction with the sale of a portion of the Company’s East Texas undeveloped natural gas and oil acreage to a third party, the Company issued 10,000,000 common shares at a price of $2.00 per share, or $20.0 million.

On May 23, 2007 in conjunction with the May 9, 2007 sale of 10.0 million newly issued common shares, Chesapeake acquired an additional 1,757,195 of the Company’s common shares at $2.00 per share pursuant to its preemptive rights under a Common Stock Purchase Agreement dated November 4, 2005.

During the year ended December 31, 2007, pursuant to the Company’s 2006 Gastar Long-Term Stock Incentive Plan, the Company issued 1,095,500 restricted common shares (net of 9,000 common shares which were cancelled) to employees, subject to vesting.

Shares Reserved

At December 31, 2007, the Company has reserved 17,255,586 common shares to be issued pursuant to the conversion of convertible debt (6,849,315 common shares), exercise of options (10,173,750 common shares) and the exercise of warrants (232,521).

 

11.

Warrants

The following table summarizes warrant information to purchase common shares as of December 31, 2007:

 

		Number of Warrants		Fair Value of Warrant (in thousands)			Warrant Price per Share Range			WA (1) Remaining Life in Years		WA (1) Exercise Price in US$
Warrants issued in connection with $3.25 million subordinated unsecured notes payable		232,521		$	235		$	2.76-3.03		1.7		$	2.80

 

(1)	WA – weighted average as of the respective period end dates.

 

12.	Interest and Debt Extinguishment Expense

The following tables summarize the components of interest and debt extinguishment expense:

 

		For the Years Ended December 31.
		2007				2006			2005
		(in thousands)
Interest expense:
Cash and accrued		$	11,702			$	11,339		$	9,834
Amortization of deferred financing costs and debt discount			4,235				4,260			4,071
Capitalized interest			(1,858	)			—			—
Total interest expense		$	14,079			$	15,599		$	13,905
Early extinguishment of debt:
Call premium		$	3,650				—		$	662
Unamortized deferred financing costs and debt discount			12,034				—			694
Total debt extinguishment expense		$	15,684			$	—		$	1,356

 

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13.	Related Party Transactions

Chesapeake Energy Corporation

On November 4, 2005, the Company completed an integrated transaction with Chesapeake whereby Chesapeake acquired 27,151,641 newly issued Company common shares equal to 19.9% of the then outstanding common shares, acquired a 33.3% working interest in the Company’s Bossier play in the Hilltop area of East Texas and formed an area of mutual interest to explore jointly in 13 counties in East Texas. As part of this transaction, Chesapeake paid an additional $7.8 million, before fees and expenses, to reimburse the Company for Chesapeake’s pro rata share of leasehold interests acquired and to pay a disproportionate amount of future drilling costs in exchange for an undivided 33.3% of the Company’s leasehold working interests in the deep Bossier Hilltop prospect, less and except 160 acres surrounding each existing well bore. Chesapeake agreed to pay 44.44% of the drilling costs through casing point in the first six wells drilled by the parties in the Hilltop prospect to a depth sufficient to test the deep Bossier formation (an approximate depth of 19,000 feet) in order to earn its 33.33% leasehold working interest. The leasehold reimbursement was recorded as a reduction to natural gas and oil property cost. The Company utilized a portion of the proceeds of the Chesapeake transaction to pay the New GeoStar Subordinated Note in full.

As a result of its purchase of common shares, Chesapeake has the right to negotiate exclusively with the Company for a period of 30 days on any proposed sale of assets. Additionally, Chesapeake has the right, with certain exceptions, to maintain its percentage ownership of the Company, on a fully diluted basis, by participating in future stock issuances and has the right to an observer being present at meetings of the Board of Directors.

On November 11, 2006 and May 23, 2007, Chesapeake acquired an additional 5,000,000 common shares and 1,757,195 common shares, respectively, in private placement transactions. As of December 31, 2007, Chesapeake owned 33,908,836 common shares, or 16.3% of the Company’s outstanding common shares.

All related balances are the result of well operations activity governed by an existing standard form joint operating agreement. All balances are typically due and payable within 30 days.

 

14.	Income Taxes

Loss before income taxes for the three years ended December 31, 2007 is as follows:

 

		For the Years Ended December 31,
		2007				2006				2005
		(in thousands)
United States		$	336			$	(67,852	)		$	(11,477	)
Foreign			(30,876	)			(16,987	)			(14,215	)
Net loss		$	(30,540	)		$	(84,839	)		$	(25,692	)

The reconciliation of the Company’s effective tax rates from the statutory rate for the three years ended December 31, 2007 are as follows:

 

		For the Years Ended December 31,
		2007				2006				2005
		(in thousands)
Expected income tax provision at statutory U.S. rates of 35%		$	(10,689	)		$	(29,694	)		$	(8,992	)
State tax, tax effected			72				(1,222	)			(166	)
Non-deductible stock-based compensation expense			1,270				1,252				767
Deferred tax effect of change in Canadian tax rates			1,576				—				—
Impact of Canadian capital gain tax rate on extinguishment income			1,197				—				—
Impact of Canadian capital gain tax rate on foreign exchange gains			2,390				—				—
Other			37				1,141				773
Change in valuation allowance			4,147				28,523				7,618
Actual income tax provision		$	—			$	—			$	—

 

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The components of the Company’s U.S. deferred taxes are comprised of the following:

 

		As of December 31,
		2007			2006
		(in thousands)
Deferred tax asset (liability):
Capital assets		(11,251	)		$	(9,354	)
Net operating loss carryforwards		45,081				44,818
Valuation allowance		(33,830	)			(35,464	)
Net deferred tax asset		—			$	—

For U.S. federal income tax purposes, the Company has net operating loss carryforwards of approximately $122.1 million, which if not utilized will begin to expire in 2020.

The Company has the following approximate undeducted Canadian tax pools:

 

		As of December 31,
		2007			2006
		(in thousands)
Cumulative Canadian exploration expense		$	987		$	938
Cumulative Canadian development expense		$	192		$	183
Foreign exploration and development expense		$	684		$	660
Undeducted undepreciated capital costs		$	24		$	40
Undeducted share issue costs		$	2,826		$	3,873
Undeducted non-capital loss carryforwards		$	53,681		$	32,567
Undeducted senior secured note issue costs		$	2,352		$	—

For Canadian income tax purposes, the Company has net operating loss carryforwards, which if not utilized will begin to expire in 2008 through 2015.

The components of the Company’s Canadian deferred tax assets are comprised of the following:

 

		As of December 31,
		2007				2006
		(in thousands)
Deferred tax assets:
Capital assets		$	551			$	585
Senior and senior secured note issue costs			1,664				1,244
Net operating loss carryforwards			15,836				10,461
Valuation allowance			(18,051	)			(12,289	)
Net deferred tax asset		$	—			$	—

The components of the Company’s Australian deferred taxes are comprised of the following:

 

		As of December 31,
		2007				2006
		(in thousands)
Deferred tax asset (liability):
Capital assets		$	(5,946	)		$	(3,241	)
Net operating loss carryforwards			6,534				3,810
Valuation allowance			(588	)			(569	)
Net deferred tax asset		$	—			$	—

For Australian income tax purposes, the Company has net operating loss carry forwards of approximately $21.8 million. There is currently no time limit on the utilization of tax losses in Australia. Ability to use Australian tax losses is based on statutory tests.

 

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In June 2006, the FASB issued FIN 48. FIN 48 requires that the Company recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For a tax position meeting the more likely than not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. The Company did not have any unrecognized tax benefits and there was no effect on our financial condition or results of operations as a result of implementing FIN 48.

It is expected that the amount of unrecognized tax benefits may change in the next twelve months; however, the Company does not expect the change to have a significant impact on financial condition or results of operations. As of December 31, 2007, the Company has no unrecognized tax benefits that if recognized would affect the effective tax rate.

The Company is subject to examination of income tax filings in the U. S., various state jurisdictions and the foreign jurisdictions of Canada and Australia for the tax periods 2000 and forward due to the Company’s continued loss position in such jurisdictions.

Estimated interest and penalties related to potential underpayment on any unrecognized tax benefits are classified as a component of general and administrative expense in the consolidated statement of operations. The Company has not recorded any interest or penalties associated with unrecognized tax benefits.

 

15.	Earnings or Loss per share

In accordance with the provisions of SFAS No. 128, basic earnings or loss per share is computed on the basis of the weighted average number of common shares outstanding during the periods. Diluted earnings or loss per share is computed based upon the weighted average number of common shares plus the assumed issuance of common shares for all potentially dilutive securities. Diluted amounts are not included in the computation of diluted loss per share, as such would be anti-dilutive.

 

		For the Years Ended December 31.
		2007				2006				2005
		(in thousands, except per share and share data)
Basic and diluted loss and shares outstanding:
Net loss		$	(30,540	)		$	(84,839	)		$	(25,692	)
Weighted average common shares outstanding			202,828,792				170,014,733				129,398,548
Basic and diluted loss per common share:
Net loss per share applicable to all common shares		$	(0.15	)		$	(0.50	)		$	(0.20	)
Common shares excluded from denominator as anti-dilutive:
Stock options			10,173,750				10,472,750				17,500,600
Unvested restricted common shares			1,096,000				—				—
Warrants			232,521				2,732,521				2,992,261
Convertible senior debentures			6,849,315				6,849,315				6,849,315
Liability to be settled by issuance of common shares (1)			—				288,018				3,042,484
Total			18,351,586				20,342,604				30,384,660

 

(1)

December 31, 2006 assumes conversion of the liability to be settled by issuance of common shares for the senior secured notes at a year end closing price of CDN$2.48 per common share. December 31, 2005 assumes conversion of the liability to be settled by issuance of common shares for the senior secured notes of 2,494,356 common shares at a year end closing price of CDN$4.25 per common share and 548,128 common shares for the GeoStar Acquisition Properties settlement statement at CDN$4.50 per common share.

 

16.	Commitments and Contingencies

Operating Leases

The Company leases its office facilities, certain gas treatment facilities and certain office equipment under non-cancelable operating lease agreements. For the years ended December 31, 2007, 2006 and 2005, office lease

 

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expense totaled approximately $205,000, $184,000 and $53,000, respectively. The Company had no office lease expense prior to August 1, 2005. For the years ended December 31, 2007, 2006 and 2005, gas treatment lease payments were approximately $565,000, $777,000 and $759,000, respectively.

As of December 31, 2007, the Company’s operating leases for the indicated periods were as follows:

 

		For the Year Ending December 31,
		Total			2008			2009			2010			2011			Thereafter
		(in thousands)
Office lease		$	582		$	205		$	205		$	172		$	—		$	—
Operating leases and other			25			9			9			7			—			—
Total		$	607		$	214		$	214		$	179		$	—		$	—

Litigation

The Company is party to various litigation matters arising out of the normal course of business. The ultimate outcome of the matters discussed below cannot presently be determined, nor can the liability that could potentially result from an adverse outcome be reasonably estimated at this time. The Company does not expect that the outcome of these proceedings will have a material adverse effect on its financial position, results of operations or cash flow. The more significant litigation matters are summarized below.

Arbitration and Litigation with GeoStar Corporation and Affiliates

Arbitration against GeoStar and Affiliates. On October 18, 2006, in connection with 10 wells to be drilled in Victoria, Australia on the jointly owned EL 4416 exploration license operated by GeoStar Corporation, the Company sent a letter to GeoStar demanding the arbitration of certain disputed issues and interpretations under a Participation and Operating Agreement (“POA”) with GeoStar and its subsidiaries. Among other items, the claims the Company presented for resolution in arbitration include claims relating to GeoStar’s demands for cash calls under the POA while simultaneously asserting that certain provisions of the POA, including overhead reimbursement rates, need to be renegotiated on terms that the Company believes are not reasonable or within industry standards. The Company has also requested that GeoStar’s Australian subsidiary provide a record title assignment of the Company’s beneficial interests in EL 4416, the exploration license in the Gippsland Basin property in Victoria, Australia. The Company has approximately $9.9 million invested in EL 4416 as of December 31, 2007. GeoStar contends that the Company is not entitled to the record title assignment notwithstanding the Company’s significant investment. The Company’s former Chairman of the Board is a major shareholder and President of GeoStar. GeoStar has voluntarily dismissed its efforts to enjoin the arbitration from proceeding and has answered and asserted counterclaims. Those counterclaims include (a) a request for a declaration that the Company has no rights to participate in brown coal projects in EL 4416, (b) a request for a declaration that the Company did not earn an interest under the POA as to certain wells the Company drilled in East Texas, (c) breach of contract for failure to pay certain bills and expenses related to West Virginia properties, and (d) breach of contract to pay for employee expenses and services. The Company, which denies and intends to vigorously defend each of these counterclaims, contends that it has participation rights to the full scope of EL 4416 under the terms of the POA and that the Texas wells were drilled on lands to which the Company obtained rights under separate 2005 Purchase and Sale Agreements. The three-member arbitration panel has been appointed and an arbitration hearing is currently scheduled for June 2008.

Gastar Exploration, Ltd., Gastar Exploration Texas, Inc., f/k/a First Texas Development, Inc., Gastar Exploration Texas LLC, f/k/a Bossier Basin, LLC, and Gastar Exploration Texas LP, f/k/a First Source Gas, LP v. GeoStar Corporation, First Source Texas, Inc., First Source Bossier, LLC, and First Texas Gas, LP. In July 2007, the Company filed a lawsuit in Robertson County, Texas against GeoStar and affiliates seeking relief in connection with the failure by GeoStar and its affiliates to execute formal assignments of certain leases that were omitted from the schedule of leases attached to the assignments executed by GeoStar affiliates in June 2005 pursuant to Purchase and Sale Agreements covering Texas properties of GeoStar and its affiliates. The lawsuit asks the court to decree that in the transaction evidenced by the Purchase and Sale Agreements, affiliates of the Company acquired title to all properties in Texas in which GeoStar and its affiliates owned an interest and that GeoStar and its affiliates are obligated to execute formal assignments with regard to all such leases. GeoStar and one of its affiliates have filed a

 

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challenge to the Texas court’s jurisdiction. Additionally, GeoStar and certain of its affiliates have also filed counterclaims in this litigation substantively identical to the counterclaims filed in the Harris County lawsuit described in the next paragraph and in the section below entitled “GeoStar Look Back Developments”.

Gastar Exploration Ltd., Gastar Exploration USA, Inc. f/k/a First Sourcenergy Wyoming Inc., Gastar Exploration New South Wales, Inc., f/k/a First Sourcenergy Group, Inc., Gastar Exploration Victoria, Inc. f/k/a First Sourcenergy Victoria, Inc.,, Gastar Exploration Texas, Inc., f/k/a First Texas Development, Inc., Gastar Exploration Texas LLC, f/k/a Bossier Basin, LLC, and Gastar Exploration Texas LP, f/k/a First Source Gas, LP v. GeoStar Corporation. In July 2007, the Company and affiliates filed a lawsuit in the District Court of Harris County, Texas against GeoStar in connection with GeoStar’s failure to deliver to the Company and its affiliates the corporate records of the Company and to its affiliates that have been retained by GeoStar. Representatives of the Company and its affiliates previously demanded return of the corporate records retained by GeoStar, but GeoStar failed to return the records. The lawsuit asks the court to decree that the Company and its affiliates are entitled to possession of the corporate records and order their return to the Company and its affiliates. The lawsuit also seeks recovery of actual and punitive damages, costs, and attorney’s fees. GeoStar has now delivered some of the requested records that are the subject of this litigation to the Company, and the Company has requested that GeoStar deliver additional records.

Gastar Exploration, Ltd., Gastar Exploration Texas, Inc., f/k/a First Texas Development, Inc., Gastar Exploration Texas LLC, f/k/a Bossier Basin, LLC, and Gastar Exploration Texas LP, f/k/a First Source Gas, LP v. GeoStar Corporation, First Source Texas, Inc., First Source Bossier, LLC, and First Texas Gas, LP. In August 2007, the Company and certain affiliates filed a second lawsuit in Robertson County, Texas, seeking a declaratory judgment that the Company and its affiliates have complied with the Look-Back provisions of the Texas Purchase and Sale Agreements that are the subject of the other Robertson County, Texas lawsuit referenced above, that the Company and its affiliates have complied with the provisions of the Texas Purchase and Sale Agreements relating to the drilling of wells, and that GeoStar and its affiliates hold no farm-in interest in properties owned by the Company’s affiliates. GeoStar and one of its affiliates have filed a challenge to the Texas court’s jurisdiction. The defendants also have generally denied the allegations made in the lawsuit. Additionally, GeoStar and certain of its affiliates have also filed counterclaims in this litigation substantively identical to the counterclaims filed in the Harris County litigation described above in the discussion of that litigation and below in the section entitled “GeoStar Look Back Developments”.

Although it previously contested jurisdiction in Texas, GeoStar (together with certain of its affiliates) has as of January 2008 asserted counterclaims in all three Texas lawsuits similar to claims GeoStar had previously asserted and dismissed in the Michigan lawsuit described below. The counterclaims relate to Texas properties that were the subject of Purchase and Sale Agreements entered into in 2005, under which the Company acquired the interests of GeoStar-affiliated entities in properties in Texas. Specifically, GeoStar claims that the Company breached the Purchase and Sale Agreements by failing to provide information in connection with contingent “Look Back” payments under provisions of the Purchase and Sale Agreements, and by failing to make payments allegedly due to GeoStar under the Look-Back provisions, arising out of alleged changes in reserves following the sale of the Texas properties in June 2005. Although requesting only damages in an unspecified amount, GeoStar contends in the counterclaim that it would have been entitled under the Purchase and Sale Agreements to approximately 1.7 billion shares of Gastar stock. GeoStar also claims that the Company failed to timely comply with provisions of the Purchase and Sale Agreements relating to the drilling of 20 wells on the properties conveyed under the Purchase and Sale Agreements and by failing to drill and test at least two wells in the Travis Peak formation in Texas, allegedly entitling GeoStar to unspecified damages related to a farm-in interest under which it was allegedly entitled to the right to drill, complete, and operate wells in the Travis Peak formation on certain acreage. The Company intends to vigorously defend the counterclaims. The Company has moved to abate the Harris County proceedings with respect the counterclaims in favor of the earlier-filed Robertson County proceedings. Certain information that may be relevant to this matter is set forth below in the section below entitled “GeoStar Look Back Developments”.

GeoStar Corporation and West Virginia Gas Corporation v. Gastar Exploration Ltd. and J. Russell Porter. On July 27, 2007, the Company was served with a lawsuit filed by GeoStar and one of its affiliates, West Virginia Gas Corporation, in federal court in Saginaw, Michigan. GeoStar asserted a broad range of claims against the Company and its current chief executive officer, J. Russell Porter.

 

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GeoStar initially sought in the Michigan suit to enjoin the Company’s arbitration against GeoStar and its affiliates. GeoStar has now voluntarily dismissed that request with prejudice.

GeoStar also claims in the Michigan suit that the POA was cancelled effective January 1, 2005, and that the parties have operated under oral contracts since that date. GeoStar asserts that the Company has breached the alleged oral contracts by allegedly failing to pay joint interest billings, authorizations for expenditures, and cash calls relating to operations or proposed operations on EL 4416 in Australia and West Virginia properties, in an unspecified amount exceeding $75,000. GeoStar also claims that the Company has breached alleged agreements to reimburse GeoStar for various payments and services allegedly performed by GeoStar and its personnel and paid on behalf of the Company by GeoStar. GeoStar claims that the amounts of the payments and the value of the services exceed $10.0 million. GeoStar alternatively alleges that if there was no contract covering those payments and services, it allegedly is entitled to reimbursement on equitable principles. On January 15, 2008, the federal court granted the Company’s motion to dismiss these claims for failure to state a claim on which relief could be granted. GeoStar filed a motion asking that the Court reconsider that ruling or permit it to replead the claims. On February 8, 2008, the federal court denied the motion to reconsider but granted GeoStar permission to replead those claims, which it did on February 22, 2008. In repleading those claims, GeoStar has restated the prior claims for oral agreement to reimburse certain expenses or equitable entitlement to reimbursement of certain expenses, and it specifies a number of items for which GeoStar is allegedly entitled to reimbursement from the Company. GeoStar seeks approximately $17.0 million. The Company filed a response to these claims on March 7, 2008.

GeoStar also asserted claims in the Michigan lawsuit relating to Texas properties that were the subject of Purchase and Sale Agreements entered into in 2005. GeoStar has voluntarily dismissed those claims without prejudice from the Michigan lawsuit and re-asserted similar claims in pending litigation in Harris and Robertson Counties, Texas as discussed below under “GeoStar Look Back Developments”.

West Virginia Gas Corporation (WVGC), an affiliate of GeoStar, also asserts claims against the Company’s current chief executive officer, alleging that the Company and its current chief executive officer tortiously interfered with an alleged contract between WVGC and certain West Virginia individuals and entities. According to the lawsuit, these individuals and entities allegedly promised to give their oil, gas, and coalbed methane opportunities in West Virginia and Pennsylvania to WVGC. WVGC alleged that Gastar and its chief executive officer caused those individuals and entities to establish and use new business entities to allegedly conceal opportunities from West Virginia Gas Corporation and to funnel them to the Company, the Company’s chief executive officer and the West Virginia individuals and entities. On January 15, 2008, the federal court dismissed these claims to the extent they were brought by GeoStar and to the extent they were brought against the Company. The court denied our chief executive’s motions to dismiss WVGC’s claim and a motion to reconsider that denial. Our chief executive intends to vigorously defend the claim.

GeoStar Look Back Developments. The Purchase and Sale Agreements between GeoStar and the Company relating to certain East Texas properties acquired by the Company in 2005 (the “PSAs”) contain a “Look Back” provision that is the subject of claims in three of the previously described lawsuits with GeoStar. Under the 2005 PSAs, GeoStar conveyed interests in certain Texas properties to the Company and was paid an agreed $43.5 million in consideration for the properties (including cash, 8.6 million shares of Company common stock, and promissory notes), subject to certain purchase price adjustments relating to the period prior to closing. The interests conveyed by the PSAs comprise a portion of the security for the notes and the Guarantees.

Under the Look Back provision, two Look Back payments are to be calculated based in part on changes in proved and probable reserves attributable to certain of the Company’s leasehold interests over certain periods of time ending June 30, 2006 and 2007. If a Look Back payment is due to GeoStar under the PSAs, the PSAs require the payment to be effected through the issuance of the Company’s stock.

The PSAs provide that the calculation of the Look Back payment shall be based upon reserve estimates reported by Netherland Sewell & Associates, Inc. (“NSAI”), or in certain circumstances, based upon an average of the NSAI estimates and estimates obtained by GeoStar from an independent, professionally certified reservoir engineering firm utilizing the same regulatory requirements and reserve calculation guidelines as those employed by NSAI in its estimates. Based on the NSAI reserves estimate and the Look Back calculations set forth in the PSAs, the Company believes that no additional issuance of Company common shares is due GeoStar under the Look Back provision.

 

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On November 1, 2007, GeoStar informed the board of directors of our Parent that it intended to submit a reserve report for purposes of the June 30, 2006 and 2007 Look Back analyses showing that the gross reserves attributable to the Company’s leasehold interests are substantially greater than those reflected in the NSAI reserve reports on which the Company’s Look Back analyses were based. On November 7, 2007, GeoStar submitted a reserve report to the Company that reported a substantially greater reserve estimate than the estimates in the NSAI reserve report.

On November 14, 2007, the Company received a reserve report of T.J. Smith & Company, Inc. (“T.J. Smith”) as well as a demand letter from GeoStar’s counsel (the “Demand Letter”) in which GeoStar asserted a purported right under the PSAs to receive additional shares of Gastar stock as a Look Back payment. In the Demand Letter, GeoStar asserts that T.J. Smith has estimated that the total proved and probable reserves in the Company’s Texas properties attributable to 100% of the working interest amount to 2.15 trillion cubic feet of gas, a number which is approximately fourteen times more than the proved and probable reserves estimated by NSAI, the engineering firm selected by the parties in the PSAs. On the basis of that reserves estimate, GeoStar asserts in the Demand Letter that it is entitled to a Look Back payment of approximately 1.7 billion shares of Gastar stock, which if issued would constitute approximately 89% of the Company’s common equity and would result in a change in control of the Company under the Company’s debt agreements. In the Demand Letter, GeoStar further asserts that if its demand is not met, it will pursue remedies that may include reclaiming operatorship over certain of the Company’s Texas properties, rescission of the PSAs resulting in return of the properties covered by the PSAs and consideration paid, and unspecified injunctive relief. The Company does not believe that GeoStar is entitled to these remedies.

The Company believes that GeoStar’s assertions are without merit. The Company believes that the T.J. Smith reserve report was submitted in bad faith and does not meet the requirements of the PSAs because, among other things, it does not follow the same regulatory requirements and reserve calculation guidelines as those employed by NSAI, as required by the terms of the PSAs. In addition, GeoStar has asserted that the Look Back analysis should be based on changes in reserves attributable to the entirety, or 8/8ths, of the Company’s leasehold interests with respect to its Texas properties, rather than on changes in reserves attributable to GeoStar’s net revenue interest in those properties as of the effectiveness of the PSAs, as the Company believes. The Company is pursuing discovery of data pertinent to the T.J. Smith report and GeoStar’s contentions relating thereto and will continue to evaluate the Company’s legal positions and options based on such discovery.

The Company intends to vigorously defend itself against GeoStar’s assertions. However, an unfavorable outcome in litigation relating to the Look Back could have a material adverse effect on the Company were GeoStar to obtain issuance of the requested shares and obtain control of the Company, rescission of the PSAs, or other relief to which it asserted it was entitled in the November demand letter. A change in control of the Company as a result of an issuance of shares to GeoStar may require the Company to refinance substantially all of its indebtedness under its existing debt agreements, which refinancing may not be obtainable or may not be on terms as favorable as under current debt agreements. Although the Company does not currently anticipate the need to access the equity capital markets through 2008 to continue its business plan, until these issues are resolved in whole or in significant part, it will be difficult for the Company to raise capital through the sale of equity.

In 2007, the Company recorded a $1.4 million litigation settlement expense accrual related to a proposed settlement with GeoStar regarding the various GeoStar arbitration and litigation matters. The settlement proposal was never finalized. At December 31, 2007, the Company had a receivable from GeoStar of approximately $3.7 million that was fully reserved due to the various litigation matters.

Other Litigation

Navasota Resources L.P. (“Navasota”) vs. First Source Texas, Inc. (now Gastar Exploration Texas, Inc.), First Source Gas L.P. (now Gastar Exploration Texas LP) and Gastar Exploration Ltd. (Cause No. 0-05-451) District Court of Leon County, Texas 12th Judicial District. This lawsuit, dated October 31, 2005, contends that the Company breached Navasota’s preferential right to purchase 33.33% of the Company’s interest in certain natural gas and oil leases located in Leon and Robertson Counties and sold to Chesapeake Energy Corporation pursuant to a transaction closed November 4, 2005. The preferential right claimed is under an operating agreement dated July 7, 2000. The Company contends, among other things, that Navasota neither properly nor timely exercised any preferential right election it may have had with respect to the inter-dependent Chesapeake transaction. In July 2006,

 

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the District Court of Leon County, Texas issued a summary judgment in favor of the Company and Chesapeake. Navasota filed a Notice of Appeal to the Tenth Court of Appeals in Waco. Oral argument was heard on September 26, 2007 and the Court of Appeals issued its opinion on January 9, 2008 reversing the trial court’s rulings and rendering judgment in favor of Navasota on all counts. The Company and Chesapeake filed a motion for rehearing on February 6, 2008, and if unsuccessful, will consider filing a petition for review to the Texas Supreme Court. Pursuant to an agreement between the Company and Chesapeake, any adverse result in this matter should impact only Chesapeake’s assigned leasehold interests. While this matter is pending, it is possible that expenditures incurred, or authorizations for proposed expenditures, for drilling activities on leases which include the disputed interest may remain unpaid or not be authorized by the non-operators asserting competing ownership rights, which could require the Company to either fund a disproportionate amount of drilling costs at its own risk or postpone its drilling program on affected leases.

Gastar Exploration Texas LP v. John E. McFarlane, et al (Cause No. 0-06-161) 87th Judicial District Court of Leon County, Texas. This suit is to quiet title to an undivided 25% mineral interest under an oil and gas lease dated December 4, 2003, covering approximately 2,598 gross acres (the “Lease”). John E. McFarlane and certain other family members contend that an undivided 25% mineral interest in the lands covered by the Lease are owned in trust by the grandchildren of Fay W. McFarlane and are not covered by the Lease as Gastar claims. McFarlane, et. al., has filed an answer to the Company’s petition and also filed several different motions for summary judgment, which have been denied by the District Court. A day long mediation of this lawsuit occurred on August 24, 2007, but the parties were unable to settle this matter. The lawsuit is currently in the discovery phase. The existence of unleased mineral interests in this Lease could adversely impact the future development of the Lease. The Company will continue to vigorously pursue this claim.

Spencer D. Plummer, III v. GeoStar Corporation, Classic Star LLC, Gastar Exploration, Ltd., Thom Robinson, Tony Ferguson, and John W. Parrott; In the United States District Court of Utah, Central Division (Case No. 2:07-CV-00409). This lawsuit was filed on May 24, 2007 initially in Utah state court by Spencer Plummer, or the Plaintiff, in which he asserts breaches of his Employment Agreement and subsequent Termination Agreement (the “Agreements”) with his employer, Classic Star, a subsidiary of GeoStar. The Plaintiff claims that he has not received benefits promised under such Agreements, including 699,249 shares of Company stock. The Company is not a party to the Agreements on which Plaintiff’s claims are expressly based; however, the Company and Plaintiff are parties to a Stock Option Agreement on which Plaintiff claim to Company stock is partially based. The Company filed an Answer and Motion to Dismiss for lack of personal jurisdiction in Utah and for Plaintiff’s failure to state a claim upon which relief can be granted. Plaintiff filed a Motion to Remand to state court, and on September 5, 2007, the Court denied Plaintiff’s Motion to Remand. Thereafter, the Company’s co-defendant, Classic Star LLC, moved to transfer and consolidate the case in a United States Judicial Panel on Multi District Litigation (“MDL Panel”) in Kentucky with other cases in which Classic Star LLC is a named defendant. On October 22, 2007, the MDL Panel granted the motion to transfer. The Company is awaiting the Kentucky court’s ruling on its Motion to Dismiss.

Commitments

In March 2008, the Company entered into formal agreements with ETC Texas Pipeline, Ltd. (“ETC”) for the gathering, treating, purchase and transportation of the Company’s natural gas production from Hilltop area of East Texas. These agreements are effective September 1, 2007 and have a term of 10 years. ETC currently provides us 50 MMcfd of treating capacity and 120 MMcfd of gathering capacity. The Company has the right to request ETC build, at their cost, up to 150 MMcfd of treating and gathering capacity during the term of the agreement, provided that the Company’s production equals 85% of the then existing treating and gathering capacity for a 30 day period. The Company may at any time elect to have its treating and gathering capacity increased subject to cost indemnifications to ETC. Additional treating and gathering capacity requests must be in at least 25 MMcfd and 5 MMcfd increments, respectively. In addition, the Company must furnish to ETC information that reasonably demonstrates that its projected production for the five years after expansion is sufficient to warrant the costs to create the expanded treating and gathering capacity. The incremental volume increases in treating and gathering capacity shall be subject to marginal increases in treating fees. Pursuant to the agreements, the Company has access up to 150 MMcfd of firm transportation on ETC’s system or the pipelines of its affiliates or subsidiaries from the tailgate of the treating facility to Katy Hub. The Company have the option to sell and ETC has the obligation to

 

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buy, up to 150 MMcfd of the Company’s Hilltop production at delivery points upstream of ETC’s gathering and treating facilities. The Company does not have an obligation to deliver to ETC volumes in excess of 150 MMcfd, but should ETC elect to purchase such excess volumes, purchases will be subject to the treating and gathering expansion terms set forth in the agreements.

Registration Obligation

On November 29, 2007, Gastar USA sold $100.0 million aggregate principal amount of 12 ³/4% Senior Secured Notes at an issue price of 99.50% in a private placement to qualified institutional. In connection with the sale Gastar Exploration USA, Inc., other Guarantors and the Company entered into a registration rights agreement. Pursuant to the registration rights agreement, the Company and the Guarantors agreed that they would (1) within 150 days after the date of original issue of the 12 ³/4% Senior Secured Notes file a registration statement with the SEC to exchange the 12 ³/4% Senior Secured Notes for new notes of the Company having terms substantially identical in all material respects to the notes (except that the new notes will not contain terms relating to transfer restrictions); (2) use their reasonable best efforts to cause the registration statement to be declared effective within 240 days after the issue date; (3) as soon as practicable after the effectiveness of the registration statement, offer the new notes to the holders of the notes in exchange for the notes; and (4) keep the exchange offer open for not less than 30 days (or longer if required by applicable law) after the date notice of the exchange offer is mailed to the holders of the notes. Under existing SEC interpretations, the new notes will be freely transferable by holders other than Company affiliates after the exchange offer without further registration. In the event Gastar USA fails to meet its registration obligations as set forth above, Gastar USA has agreed to pay liquidated damages to the holders of the 12 ³/4% Senior Secured Notes in the form of additional cash interest payments on the 12 ³/4% Senior Secured Notes equal to 0.25% per annum for the first 90-day period, increasing to a maximum of 0.50% per annum for each subsequent 90-day period.

Restoration, Removal and Environmental Liabilities

The Company is subject to various regulatory and statutory requirements relating to the protection of the environment. These requirements, in addition to contractual agreements and management decisions, result in the accrual of estimated future removal and site restoration costs. These costs are initially measured at a fair value and are recognized in the consolidated financial statements as the recent value of expected future cash flows. Subsequent to the initial measurement, the effect of the passage of time on the liability for the asset retirement obligation (accretion expense) and the amortization of the asset retirement obligation cost are recognized in the results of operations. Costs attributable to these commitments and contingencies are expected to be incurred over an extended period of time and are to be funded mainly from the Company’s cash provided by operating activities. Although the ultimate impact of these matters on net earnings cannot be determined at this time, it could be material for any quarter or year.

Indemnifications

Indemnifications in the ordinary course of business have been provided pursuant to provisions of purchase and sale contracts, service agreements, joint venture agreements, operating agreements and leasing agreements. In these agreements, the Company may indemnify counterparties if certain events occur. These indemnification provisions vary on an agreement by agreement basis. In some cases, there are no pre-determined amounts or limits included in the indemnification provisions and the occurrence of contingent events that will trigger payment, if any, is difficult to predict.

Employment Agreements

We entered into employment agreements with our President and Chief Executive Officer and our Chief Financial Officer, effective February 24, 2005 and May 17, 2005, respectively. The agreements set forth, among other things, annual compensation, and adjustments thereto, minimum bonus payments, termination provisions, fringe benefits, termination and severance provisions. The agreements renew annually; however, they may be terminated at any time with or without cause. We entered into a letter agreement with our Chief Operating Officer on August 21, 2008. The letter agreement sets forth, among other things, his initial base salary, a guaranteed 2007 bonus, fringe benefits such as vacation and medical insurance coverage, and severance provisions for his at will employment, which may be terminated at any time by us or him with or without cause.

 

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We also have entered into agreements with these executives, who are acting at the Company’s request to be officers of the Company, to indemnify them the fullest extent permitted by law, against any and all damages, liabilities, costs, charges or expenses suffered by or incurred by the individuals as a result of their service. The nature of the indemnification agreements prevents the Company from making a reasonable estimate of the maximum potential amount it could be required to pay to beneficiary of such indemnification agreement.

 

17.	Concentration of Risk and Significant Customers

Approximately 80%, 66% and 65% of the Company’s revenues for the years ended December 31, 2007, 2006 and 2005, respectively, were from production from producing wells in the Hilltop area East Texas.

During 2007, ETC and Enserco Energy, Inc. (“Enserco”) accounted for 78% and 20% of the Company’s natural gas and oil revenues, respectively. During 2006, ETC and Enserco accounted for 63% and 25% of the Company’s natural gas and oil revenues, respectively. During 2005, ETC and Enserco accounted for 65% and 26%, respectively, of the Company’s natural gas and oil revenues. Although ETC is the major natural gas purchaser and transporter in the area of Gastar’s deep Bossier play and limited natural gas purchaser and transporter alternatives are currently available in this area, management believes that other natural gas purchasers and transporters could ultimately be located thus minimizing a long-term material adverse impact on the Company’s financial condition or results of operations. Management believes that the loss of Enserco in the Powder River Basin would not have a long-term material adverse impact on the financial position or results of operations of the Company, as there are numerous other purchasers operating in the Powder River Basin.

 

18.	Statement of Cash Flows - Supplemental Information

The following is a summary of supplemental cash paid and non-cash transactions disclosed in the notes to the consolidated financial statements:

 

		For the Years Ended December 31,
		2007				2006				2005
		(in thousands)
Cash paid for interest, net of capitalized interest		$	10,825			$	11,242			$	8,027
Cash paid for debt extinguishment		$	3,650			$	—			$	662
		For the Years Ended December 31,
		2007				2006				2005
		(in thousands)
Non-cash transactions:
Non-cash capital expenditures excluded from accounts payable and accrued drilling costs		$	(2,516	)		$	11,724			$	4,822
Asset retirement obligation included in oil and gas properties		$	108			$	(427	)		$	(1,738	)
Drilling advances application		$	11,956			$	5,482			$	21,196
Note payable issued in conjunction with GeoStar Acquisition		$	—			$	—			$	(15,000	)
Common shares issued in conjunction with GeoStar Acquisition		$	—			$	—			$	(25,116	)
Common shares issued under senior secured notes		$	606			$	(8,499	)		$	(7,893	)

 

19.	Quarterly Consolidated Financial Data – unaudited

 

		For the Three Months Ended
		March 31, 2007				June 30, 2007				September 30, 2007				December 31, 2007
		(in thousands, except share and per share data)
Revenues		$	7,515			$	7,956			$	9,775			$	9,319
Loss from operations		$	(7,374	)		$	(31,529	)		$	(2,517	)		$	(1,094	)
Income (loss) before income taxes (1)		$	(10,955	)		$	4,380			$	(5,526	)		$	(18,439	)
Net income (loss) (1)		$	(10,955	)		$	4,380			$	(5,526	)		$	(18,439	)
Income (loss) per share, basic and diluted		$	(0.06	)		$	0.02			$	(0.03	)		$	(0.09	)
Weighted average number of shares, basic and diluted			195,015,561				201,918,634				207,098,570				207,098,570

 

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		For the Three Months Ended,
		March 31, 2006				June 30, 2006				September 30, 2006				December 31, 2006
		(in thousands, except share and per share data)
Revenues		$	6,623			$	6,684			$	6,680			$	6,778
Loss from operations		$	(39,680	)		$	(3,406	)		$	(4,069	)		$	(23,915	)
Loss before income taxes		$	(42,910	)		$	(6,727	)		$	(7,706	)		$	(27,496	)
Net loss		$	(42,910	)		$	(6,727	)		$	(7,706	)		$	(27,496	)
Loss per share, basic and diluted		$	(0.26	)		$	(0.04	)		$	(0.05	)		$	(0.15	)
Weighted average number of shares, basic and diluted			164,796,868				166,513,762				167,942,813				180,648,045

 

(1)	The three months ended June 30, 2007 includes a gain on sale of assets of $38.5 million. The three months ended December 31, 2007 includes a loss on early debt extinguishment of $15.7 million and capitalized interest of $1.9 million.

 

20.	Issuer Subsidiaries Condensed Consolidating Financial Statements

The following table presents condensed consolidating balance sheets as of December 31, 2007 and 2006 and the related condensed consolidating statements of operations and condensed consolidating statements of cash flows for the three years ended December 31, 2007 of Gastar Exploration Ltd. (“Parent”), Gastar Exploration USA, Inc. (“Issuer”) and Gastar Exploration Texas, Inc., Gastar Exploration Texas LP, Gastar Exploration Texas LLC, Gastar Exploration New South Wales, Inc., Gastar Exploration Victoria, Inc. and Gastar Power Pty Ltd., a minor non-guarantor subsidiary included in issuer subsidiaries, (collectively referred to as “Issuer Subsidiaries”). Each of the Parent and the Issuer Subsidiaries, except for Gastar Power Pty Ltd., have fully and unconditionally guaranteed, on a joint and severally basis, the $100.0 million 12 ³/4% Senior Secured Notes sold in November 2007 and the Revolving Credit Facility, established at the same time. During 2007, Parent intercompany receivables were reclassifieded to investment in subsidiary with Issuer and Issuer Subsidiaries. Interest is not charged on intercompany receivable or payables.

Condensed Consolidating Parent and Issuer Subsidiaries Balance Sheets

As of December 31, 2007

 

ASSETS
		Parent				Issuer				Issuer Subsidiaries				Reclassifications and Eliminations				Gastar Exploration Ltd. and Subsidiaries
		(in thousands)
CURRENT ASSETS:
Cash and cash equivalents		$	73			$	—			$	85,781			$	—			$	85,854
Accounts receivable, net			10				265				5,188				(635	)			4,828
Due from related parties			—				—				904				—				904
Prepaid expenses			291				—				944				—				1,235
Total current assets			374				265				92,817				(635	)			92,821
PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, full cost method of accounting:
Unproved properties, not being amortized			—				2,988				66,856				—				69,844
Proved properties			8				43,611				203,753				—				247,372
Total natural gas and oil properties			8				46,599				270,609				—				317,216
Furniture and equipment			—				—				669				—				669
Total property, plant and equipment			8				46,599				271,278				—				317,885
Accumulated depreciation, depletion and amortization			(7	)			(42,828	)			(117,930	)			—				(160,765	)
Total property, plant and equipment, net			1				3,771				153,348				—				157,120
OTHER ASSETS:
Restricted cash			1,029				—				45				—				1,074
Deferred charges, net			924				7,410				—				—				8,334
Drilling advances			—				—				2,251				—				2,251
Intercompany receivable and investment in subsidiaries			127,991				208,808				—				(336,799	)			—
Other assets			—				100				50				—				150
Total other assets			129,944				216,318				2,346				(336,799	)			11,809
TOTAL ASSETS		$	130,319			$	220,354			$	248,511			$	(337,434	)		$	261,750

 

F-62

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Table of Contents

Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable		$	47		$	—		$	11,954		$	—			$	12,001
Revenue payable			—			—			6,770			—				6,770
Accrued interest			401			1,133			—			—				1,534
Accrued drilling and operating costs			—			350			2,460			—				2,810
Other accrued liabilities			244			1,066			4,636			(635	)			5,311
Due to related parties			—			—			979			—				979
Total current liabilities			692			2,549			26,799			(635	)			29,405
LONG-TERM LIABILITIES:
Long-term debt			33,179			99,506			—			—				132,685
Asset retirement obligation			5			2,289			2,097			—				4,391
Intercompany payable			667			1,615			26,590			(28,872	)			—
Total long-term liabilities			33,851			103,410			28,687			(28,872	)			137,076
TOTAL SHAREHOLDERS’ EQUITY			95,776			114,395			193,025			(307,927	)			95,269
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY		$	130,319		$	220,354		$	248,511		$	(337,434	)		$	261,750

 

F-63

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Table of Contents

Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Condensed Consolidating Parent and Issuer Subsidiaries Balance Sheets

As of December 31, 2006

 

ASSETS
		Parent				Issuer				Issuer Subsidiaries				Reclassifications and Eliminations				Gastar Exploration Ltd. and Subsidiaries
		(in thousands)
CURRENT ASSETS:
Cash and cash equivalents		$	46			$	—			$	40,687			$	—			$	40,733
Accounts receivable, net			6				488				8,913				(674	)			8,733
Due from related parties			—				—				4,394				—				4,394
Prepaid expenses			300				135				934				—				1,369
Total current assets (liability)			352				623				54,928				(674	)			55,229
PROPERTY, PLANT AND EQUIPMENT:
Natural gas and oil properties, full cost method of accounting:
Unproved properties, not being amortized			3				6,208				83,447				—				89,658
Proved properties			4				35,959				145,399				—				181,362
Total natural gas and oil properties			7				42,167				228,846				—				271,020
Furniture and equipment			—				—				600				—				600
Total property, plant and equipment			7				42,167				229,446				—				271,620
Accumulated depreciation, depletion and amortization			(6	)			(34,900	)			(75,888	)			—				(110,794	)
Total property, plant and equipment, net			1				7,267				153,558				—				160,826
OTHER ASSETS:
Restricted cash			—				—				45				—				45
Deferred charges, net			3,502				—				—				—				3,502
Drilling advances			—				—				9,137				—				9,137
Intercompany receivable and investment in subsidiaries			189,236				20,018				—				(209,254	)			—
Other assets			—				100				50				—				150
Total other assets			192,738				20,118				9,232				(209,524	)			12,834
TOTAL ASSETS		$	193,091			$	28,008			$	217,718			$	(209,928	)		$	228,889
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable		$	15			$	—			$	15,456			$	—			$	15,471
Revenue payable			—				—				3,464								3,464
Accrued interest			—				—				2,515				—				2,515
Accrued drilling and operating costs			—				1,265				4,415				—				5,680
Other accrued liabilities			286				1,377				2,131				(674	)			3,120
Due to related parties			—				—				1,670				—				1,670
Total current liabilities			301				2,642				29,651				(674	)			31,920
LONG-TERM LIABILITIES:
Long-term debt			93,803				—				—				—				93,803
Asset retirement obligation			4				2,622				1,592				—				4,218
Intercompany payable			—				121,102				251,724				(372,826	)			—
Liability to be settled by issuance of common shares			606				—				—				—				606
Total long-term liabilities			94,413				123,724				253,316				(372,826	)			98,627
TOTAL SHAREHOLDERS’ EQUITY (DEFICIT)			98,377				(98,358	)			(65,249	)			163,572				98,342
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY		$	193,091			$	28,008			$	217,718			$	(209,928	)		$	228,889

 

F-64

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Table of Contents

Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Condensed Consolidating Parent and Issuer Subsidiaries Statements of Operations

For the Year Ended December 31, 2007

 

		Parent				Issuer				Issuer Subsidiaries				Reclassifications and Eliminations				Gastar Exploration Ltd. and Subsidiaries
		(in thousands)
REVENUES		$	1			$	7,076			$	27,488			$	—			$	34,565
EXPENSES:
Production taxes			—				752				13				—				765
Lease operating expenses			2				2,870				3,412				—				6,284
Transportation and treating			—				1,641				—				—				1,641
Depreciation, depletion and amortization			—				6,101				15,355				—				21,456
Impairment of natural gas and oil properties			—				1,141				27,373				—				28,514
Accretion of asset retirement obligation			—				155				126				—				281
Mineral resource properties			—				—				(133	)			—				(133	)
General and administrative expenses			1,395				24				15,487				—				16,906
Litigation settlement expense			—				—				1,365				—				1,365
Total expenses			1,397				12,684				62,998				—				77,079
LOSS FROM OPERATIONS			(1,396	)			(5,608	)			(35,510	)			—				(42,514	)
OTHER (EXPENSES) INCOME:
Interest expense			(13,817	)			(492	)			230				—				(14,079	)
Early extinguishment of debt			(15,684	)			—				—				—				(15,684	)
Investment income and other			20				—				3,176				—				3,196
Equity earnings in subsidiaries			336				6,436				—				(6,772	)			—
Gain on sale of assets			—				—				38,536				—				38,536
Foreign transaction gain			1				—				4				—				5
INCOME (LOSS) BEFORE INCOME TAXES			(30,540	)			336				6,436				(6,772	)			(30,540	)
Provision for income taxes			—				—				—				—				—
NET INCOME (LOSS)		$	(30,540	)		$	336			$	6,436			$	(6,772	)		$	(30,540	)

 

F-65

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Table of Contents

Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Condensed Consolidating Parent and Issuer Subsidiaries Statements of Operations

For the Year Ended December 31, 2006

 

		Parent				Issuer				Issuer Subsidiaries				Reclassifications and Eliminations			Gastar Exploration Ltd. and Subsidiaries
		(in thousands)
REVENUES		$	5			$	9,107			$	17,653			$	—		$	26,765
EXPENSES:
Production taxes			—				1,096				382				—			1,478
Lease operating expenses			7				2,581				2,961				—			5,549
Transportation and treating			—				1,557				—				—			1,557
Depreciation, depletion and amortization			—				5,776				10,556				—			16,332
Impairment of natural gas and oil properties			—				15,718				40,562				—			56,280
Accretion of asset retirement obligation			—				151				83				—			234
Mineral resource properties			—								450				—			450
General and administrative expenses			1,354				(416	)			12,610				—			13,548
Litigation settlement expense			—				2,388				19				—			2,407
Total expenses			1,361				28,851				67,623				—			97,835
LOSS FROM OPERATIONS			(1,356	)			(19,744	)			(49,970	)			—			(71,070	)
OTHER (EXPENSES) INCOME:
Interest expense			(15,627	)			—				28				—			(15,599	)
Investment income and other			1				83				1,752				—			1,836
Equity loss in subsidiaries			(67,852	)			(48,191	)			—				116,043			—
Foreign transaction loss			(5	)							(1	)			—			(6	)
LOSS BEFORE INCOME TAXES			(84,839	)			(67,852	)			(48,191	)			116,043			(84,839	)
Provision for income taxes			—				—				—				—			—
NET LOSS		$	(84,839	)		$	(67,852	)		$	(48,191	)		$	116,043		$	(84,839	)

 

F-66

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Table of Contents

Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Condensed Consolidating Parent and Issuer Subsidiaries Statements of Operations

For the Year Ended December 31, 2005

 

		Parent				Issuer				Issuer Subsidiaries				Reclassifications and Eliminations			Gastar Exploration Ltd. and Subsidiaries
		(in thousands)
REVENUES		$	5			$	9,696			$	17,741			$	—		$	27,442
EXPENSES:
Production taxes			—				1,209				(147	)			—			1,062
Lease operating expenses			10				945				2,898				—			3,853
Transportation and treating			—				1,995				—				—			1,995
Depreciation, depletion and amortization			6				3,755				10,153				—			13,914
Impairment of natural gas and oil properties			—				1,988				6,709				—			8,697
Accretion of asset retirement obligation			1				81				27				—			109
Mineral resource properties			4				—				61				—			65
General and administrative expenses			1,929				3,080				3,701				—			8,710
Total expenses			1,950				13,053				23,402				—			38,405
LOSS FROM OPERATIONS			(1,945	)			(3,357	)			(5,661	)			—			(10,963	)
OTHER (EXPENSES) INCOME:
Interest expense			(12,314	)			—				(1,591	)			—			(13,905	)
Early extinguishment of debt			—				—				(1,356	)			—			(1,356	)
Investment income and other			2				126				364				—			492
Equity loss in subsidiaries			(11,477	)			(8,246	)			—				19,723			—
Foreign transaction gain (loss)			42				—				(2	)			—			40
LOSS BEFORE INCOME TAXES			(25,692	)			(11,477	)			(8,246	)			19,723			(25,692	)
Provision for income taxes			—				—				—				—			—
NET LOSS		$	(25,692	)		$	(11,477	)		$	(8,246	)		$	19,723		$	(25,692	)

 

F-67

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Table of Contents

Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Condensed Consolidating Parent and Issuer Subsidiaries Statements of Cash Flows

For the Year Ended December 31, 2007

 

		Parent				Issuer				Issuer Subsidiaries				Reclassifications and Eliminations				Gastar Exploration Ltd. and Subsidiaries
		(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)		$	(30,540	)		$	336			$	6,436			$	(6,772	)		$	(30,540	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization			—				6,101				15,355				—				21,456
Impairment of natural gas and oil properties			—				1,141				27,373				—				28,514
Stock based compensation			—				—				3,948				—				3,948
Amortization of deferred financing costs and debt discount			4,128				107				—				—				4,235
Accretion of asset retirement obligation			—				155				126				—				281
Gain on sale of assets			—				—				(38,536	)			—				(38,536	)
Loss on early extinguishment of debt			12,034				—				—				—				12,034
Equity in earnings of issuer subsidiaries			(336	)			(6,436	)			—				6,772				—
Changes in operating assets and liabilities, exclusive of effects of acquisition:
Restricted cash for hedging program			(1,000	)			—				—				—				(1,000	)
Accounts receivable (payable)			(4	)			223				7,215				(39	)			7,395
Prepaid expenses			9				135				(10	)			—				134
Accounts payable and accrued liabilities			391				(573	)			(336	)			39				(479	)
Net cash provided by (used in) operating activities			(15,318	)			1,189				21,571				—				7,442
CASH FLOWS FROM INVESTING ACTIVITIES:
Development and purchases of natural gas and oil properties			(1	)			(4,432	)			(60,408	)			—				(64,841	)
Proceeds from sale of natural gas and oil properties			—				—				66,513				—				66,513
Drilling advances			—				—				(5,070	)			—				(5,070	)
Purchase of furniture and equipment			—				—				(69	)			—				(69	)
Subsidiary equity (investment) payments			66,197				(88,754	)			—				22,557				—
Net cash provided by (used in) investing activities			66,196				(93,186	)			966				22,557				(3,467	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from the issuance of 12 3/4% Senior Secured Notes			—				99,500				—				—				99,500
Repayment of senior secured notes			(73,000	)			—				—				—				(73,000	)
Proceeds of issuance of common shares, net of share issue costs			23,388				—				—				—				23,388
Subsidiary advances			—				—				22,557				(22,557	)			—
Increase in restricted cash			(29	)			—				—				—				(29	)
Deferred financing charges and other			(1,210	)			(7,503	)			—				—				(8,713	)
Net cash provided by financing activities			(50,851	)			91,997				22,557				(22,557	)			41,146
NET INCREASE IN CASH AND CASH EQUIVALENTS			27				—				45,094				—				45,121
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR			46				—				40,687				—				40,733
CASH AND CASH EQUIVALENTS, END OF YEAR		$	73			$	—			$	85,781			$	—			$	85,854

 

F-68

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Table of Contents

Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Condensed Consolidating Parent and Issuer Subsidiaries Statements of Cash Flows

For the Year Ended December 31, 2006

 

		Parent				Issuer				Issuer Subsidiaries			Reclassifications and Eliminations				Gastar Exploration Ltd. and Subsidiaries
		(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss		$	(84,839	)		$	(67,852	)$		(48,191	)		$	116,043			$	(84,839	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization			—				5,776			10,556				—				16,332
Impairment of natural gas and oil properties			—				15,718			40,562				—				56,280
Amortization of deferred lease costs			—				—			345				—				345
Stock based compensation			11				—			3,898				—				3,909
Amortization of deferred financing costs and debt discount			4,260				—			—				—				4,260
Accretion of asset retirement obligation			—				151			83				—				234
Equity in loss of issuer subsidiaries			67,852				48,191			—				(116,043	)			—
Changes in operating assets and liabilities, exclusive of effects of acquisition:
Accounts receivable			(25	)			4,124			(11,127	)			674				(6,354	)
Prepaid expenses			(129	)			(5	)		316				—				182
Accounts payable and accrued liabilities			(2,482	)			1,414			10,112				(674	)			8,370
Net cash provided by (used in) operating activities			(15,352	)			7,517			6,554				—				(1,281	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Development and purchases of natural gas and oil properties			1				(7,105	)		(43,111	)			—				(50,215	)
Purchase of natural gas and oil properties from related parties							—			(2,116	)			—				(2,116	)
Drilling advances			—				—			(14,228	)			—				(14,228	)
Purchase of furniture and equipment			—				—			(240	)			—				(240	)
Subsidiary equity investment and payments			(32,527	)			(551	)		—				33,078				—
Other			—				(100	)		(50	)			—				(150	)
Net cash used in investing activities			(32,526	)			(7,756	)		(59,745	)			33,078				(66,949	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds of issuance of common shares, net of share issue costs			47,915				—			—				—				47,915
Subsidiary advances			—				—			33,078				(33,078	)			—
Increase in restricted cash			—				—			(45	)			—				(45	)
Deferred financing charges and other			(16	)			—			(35	)			—				(51	)
Net cash provided by financing activities			47,899				—			32,998				(33,078	)			47,819
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS			21				(239	)		(20,193	)			—				(20,411	)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR			25				239			60,880				—				61,144
CASH AND CASH EQUIVALENTS, END OF YEAR		$	46			$	—  $			40,687			$	—			$	40,733

 

F-69

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Table of Contents

Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Condensed Consolidating Parent and Issuer Subsidiaries Statements of Cash Flows

For the Year Ended December 31, 2005

 

		Parent				Issuer				Issuer Subsidiaries				Reclassifications and Eliminations				Gastar Exploration Ltd. and Subsidiaries
		(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss		$	(25,692	)		$	(11,477	)		$	(8,246	)		$	19,723			$	(25,692	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization			6				3,755				10,153				—				13,914
Impairment of natural gas and oil properties			—				1,988				6,709				—				8,697
Amortization of deferred lease costs			—				—				416				—				416
Stock based compensation			7				—				2,281				—				2,288
Amortization of deferred financing costs and debt discount			2,388				—				1,723				—				4,111
Accretion of asset retirement obligation			1				81				27				—				109
Loss on early extinguishment of debt			—				—				694				—				694
Equity in loss of issuer subsidiaries			11,477				8,246				—				(19,723	)			—
Changes in operating assets and liabilities, exclusive of effects of acquisition:
Accounts receivable			24				(3,614	)			(1,452	)			—				(5,042	)
Prepaid expenses			(11	)			(71	)			(1,162	)			—				(1,244	)
Accounts payable and accrued liabilities			2,307				266				2,556				—				5,129
Net cash provided by (used in) operating activities			(9,493	)			(826	)			13,699				—				3,380
CASH FLOWS FROM INVESTING ACTIVITIES:
Development and purchases of natural gas and oil properties			(9	)			(4,194	)			(29,084	)			—				(33,287	)
Proceeds from sale of natural gas and oil properties			—				2				—				—				2
Purchase of natural gas and oil properties from related parties			—				(4,893	)			(23,891	)			—				(28,784	)
Drilling advances			—				—				(15,269	)			—				(15,269	)
Purchase of furniture and equipment			—				—				(352	)			—				(352	)
Subsidiary equity investment and payments			(152,398	)			—				—				152,398				—
Other			—				(143	)			—				—				(143	)
Net cash used in investing activities			(152,407	)			(9,228	)			(68,596	)			152,398				(77,833	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of senior secured notes			73,000				—				—				—				73,000
Repayment of Senior Secured Notes			—				—				(26,483	)			—				(26,483	)
Repayment of related note payable			(15,000	)			—				—				—				(15,000	)
Proceeds of issuance of common shares, net of share issue costs			91,216				—				—				—				91,216
Subsidiary advances			—				10,291				142,107				(152,398	)			—
Deferred financing charges and other			(2,978	)			—				—				—				(2,978	)
Net cash provided by financing activities			146,238				10,291				115,624				(152,398	)			119,755
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS			(15,662	)			237				60,727				—				45,302
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR			15,687				2				153				—				15,842
CASH AND CASH EQUIVALENTS, END OF YEAR		$	25			$	239			$	60,880			$	—			$	61,144

 

F-70

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Table of Contents

Index to Financial Statements

GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Supplemental Oil and Gas Disclosures – Unaudited

The following disclosures for the Company are made in accordance with SFAS No. 69, “Disclosures About Oil and Gas Producing Activities”.

Capitalized Costs Relating Oil and Producing Activities

The following table presents the Company’s aggregate capitalized costs relating to oil producing activities and the related depreciation, depletion and amortization:

 

		United States				Australia				Total
		(in thousands)
At December 31, 2007:
Unproved properties		$	46,527			$	23,317			$	69,844
Proved properties			246,768				604				247,372
			293,295				23,921				317,216
LESS
Impairment of proved natural gas and oil properties			(104,205	)			(604	)			(104,809	)
Accumulated depreciation, depletion and amortization			(55,675	)			—				(55,675	)
Total		$	133,415			$	23,317			$	156,732
At December 31, 2006:
Unproved properties		$	81,540			$	8,118			$	89,658
Proved properties			180,758				604				181,362
			262,298				8,722				271,020
LESS:
Impairment of proved natural gas and oil properties			(75,691	)			(604	)			(76,295	)
Accumulated depreciation, depletion and amortization			(34,348	)			—				(34,348	)
Total		$	152,259			$	8,118			$	160,377
At December 31, 2005:
Unproved properties		$	70,519			$	3,500			$	74,019
Proved properties			128,549				604				129,153
			199,068				4,104				203,172
LESS
Impairment of proved natural gas and oil properties			(19,410	)			(604	)			(20,014	)
Accumulated depreciation, depletion and amortization			(18,127	)			—				(18,127	)
Total		$	161,531			$	3,500			$	165,031

Pursuant to SFAS No. 143, net capitalized cost includes related asset retirement cost of approximately $3.6 million and $3.7 million at December 31, 2007 and 2006, respectively.

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

The following table sets forth costs incurred related to the Company’s natural gas and oil activities for the years ended December 31, 2007, 2006 and 2005:

 

		United States				Australia			Total
		(in thousands)
For the year ended December 31, 2007:
Unproved property acquisition		$	(7,036	)		$	15,199		$	8,163
Unproved property divestment			(27,977	)			—			(27,977	)
Exploration			29,768				—			29,768
Development			36,242				—			36,242
Total		$	30,997			$	15,199		$	46,196

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

For the year ended December 31, 2006:
Unproved property acquisition		$	11,021		$	4,618		$	15,639
Exploration			45,281			—			45,281
Development			6,928			—			6,928
Total		$	63,230		$	4,618		$	67,848
For the year ended December 31, 2005:
Unproved property acquisition		$	42,853		$	968		$	43,821
Proved property acquisition			23,208			—			23,208
Exploration			28,239			428			28,667
Development			35,354			—			35,354
Total		$	129,654		$	1,396		$	131,050

The United States proved properties are expected to be developed over the next 10 years, while the Australian properties are anticipated to be developed over the next 10 years.

Results of Operations for Oil and Gas Producing Activities

The following table sets forth results of operations for oil and gas producing activities for the years ended December 31, 2007, 2006 and 2005:

 

		United States
		(in thousands, except per Mcf data)
For the year ended December 2007:
Natural gas and oil sales		$	34,565
Production expenses			(8,690	)
Impairment of natural gas and oil properties			(28,514	)
Depreciation, depletion, and amortization			(21,327	)
Results of producing activities		$	(23,966	)
Depreciation, depletion, and amortization rate per Mcfe		$	3.22
For the year ended December 2006:
Natural gas and oil sales		$	26,765
Production expenses			(8,584	)
Impairment of natural gas and oil properties			(56,280	)
Depreciation, depletion and amortization			(16,225	)
Results of producing activities		$	(54,324	)
Depreciation, depletion, and amortization rate per Mcfe		$	3.44
For the year ended December 2005:
Natural gas and oil sales		$	27,442
Production expenses			(6,910	)
Impairment of natural gas and oil properties			(8,697	)
Depreciation, depletion, and amortization			(13,877	)
Results of producing activities		$	(2,042	)
Depreciation, depletion, and amortization rate per Mcfe		$	3.63

The results of producing activities exclude interest charges and general corporate expenses and represent United States activities only due to no producing operations activities in Australia to date.

Net Proved and Proved Developed Reserve Summary

The Company’s proved developed and proved undeveloped reserves are located only in the United States. The Company cautions that there are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. In addition, estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are expected to change as future information becomes available. Material revisions of reserve estimates may occur in the future; development and production of the oil and gas reserves may not occur in the periods assumed and actual

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

prices realized and actual costs incurred may vary significantly from those used. Proved reserves represent estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods being utilized at the time the estimates were made.

The following table sets forth changes in estimated net proved and proved developed and undeveloped reserves for the years ended December 31, 2005, 2006 and 2007:

Change in proved reserves

 

		Gas (MMcf)			Oil (MBbl)
Proved reserves as of December 31, 2004		21,400			6
2005 Activity:
Extensions and discoveries		12,936			—
Purchase of minerals in place		13,048			—
Revisions of previous estimates		(10,551	)		(3	)
Production		(3,810	)		(2	)
Proved reserves as of December 31, 2005		33,023			1
2006 Activity:
Extensions and discoveries		11,120			—
Revisions of previous estimates		(8,340	)		41
Production		(4,646	)		(12	)
Proved reserves as of December 31, 2006		31,157			30
2007 Activity:
Extensions and discoveries		24,064			—
Revisions of previous estimates		6,178			(14	)
Production		(6,577	)		(7	)
Proved reserves as of December 31, 2007		54,822			9
Proved Developed and Undeveloped Reserves as of
		Gas (MMcf)			Oil (MBbl)
December 31, 2005
Proved developed reserves		14,640			1
Proved undeveloped reserves		18,383			—
Total		33,023			1
December 31, 2006
Proved developed reserves		20,098			30
Proved undeveloped reserves		11,059			—
Total		31,157			30
December 31, 2007
Proved developed reserves		34,058			9
Proved undeveloped reserves		20,764			—
Total		54,822			9

The 2007 upward revision of previous estimates is primarily attributed to an increase in natural gas prices and performance revisions. An increase in natural gas prices of approximately 28% from 2006 resulted in an increase in 2007 proved reserves of approximately 3,815 MMcf, with the remaining portion of the increase attributable to upward performance revisions primarily in the Hilltop area of East Texas. The 2006 downward revision of previous estimates is primarily attributed to a decrease in natural gas prices and performance revisions in our Powder River Basin reserves in Wyoming. A decline in natural gas prices of approximately 36% from 2005 resulted in a decrease

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

in proved reserves of approximately 4,836 MMcf. The remaining proved reserve revision of previous estimates is attributed to downward revisions in the Powder River Basin based on updated well performance and reservoir pressure data, which was partially offset by upward performance revisions in the Hilltop area of East Texas.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following information has been developed utilizing procedures prescribed by SFAS No. 69 and based on natural gas and crude oil reserve and production volumes estimated by the independent petroleum reservoir engineers. This information may be useful for certain comparison purposes but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of the Company’s oil and gas assets.

The future cash flows presented below are based on sales prices, cost rates and statutory income tax rates in existence at year end. It is expected that material revisions to some estimates of natural gas and crude oil reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used. Income tax expense has been computed using expected future tax rates and giving effect to tax deductions and credits available, under current laws, and which relate to oil and gas producing activities. Operating loss carryforwards to the extent estimated to be available in the future were also considered, thereby reducing expected tax expense.

Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

The Standardized Measure of Discounted Future Net Cash Flows relating to proved oil and gas reserves is presented below:

 

		United States
		(in thousands)
December 31, 2005:
Future cash inflows		$	244,104
Future production costs			(82,908	)
Future development costs			(43,493	)
Future income taxes			—
Future net cash flows			117,703
10% annual discount for estimated timing of cash flows			(26,408	)
Standardized measure of discounted future cash flows		$	91,295
December 31, 2006:
Future cash inflows		$	150,062
Future production costs			(57,726	)
Future development costs			(36,629	)
Future income taxes			—
Future net cash flows			55,707
10% annual discount for estimated timing of cash flows			(15,369	)
Standardized measure of discounted future cash flows		$	40,338
December 31, 2007:
Future cash inflows		$	334,071
Future production costs			(82,466	)
Future development costs			(58,857	)
Future income taxes			—
Future net cash flows			192,748
10% annual discount for estimated timing of cash flows			(60,516	)
Standardized measure of discounted future cash flows		$	132,232

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

Changes in Standardized Measure of Discounted Future Net Cash Flows

The principal sources of changes in the Standardized Measure of Future Net Cash Flows are as follows:

 

		United States
		(in thousands)
December 31, 2004		$	25,609
Extensions and discoveries, less related costs			43,029
Sale of natural gas and oil, net of production costs			(20,532	)
Purchase of minerals in place			31,746
Revisions of previous quantity estimates			(38,448	)
Net change in income tax			—
Net change in prices and production costs			40,506
Accretion of discount			2,561
Development costs incurred			20,340
Net change in estimated future development costs			(7,238	)
Change in production rates (timing) and other			(6,278	)
December 31, 2005			91,295
Extensions and discoveries, less related costs			22,403
Sale of natural gas and oil, net of production costs			(18,193	)
Revisions of previous quantity estimates			(17,797	)
Net change in income tax			—
Net change in prices and production costs			(63,106	)
Accretion of discount			9,130
Development costs incurred			4,734
Net change in estimated future development costs			10,840
Change in production rates (timing) and other			1,032
December 31, 2006			40,338
Extensions and discoveries, less related costs			65,520
Sale of natural gas and oil, net of production costs			(25,875	)
Revisions of previous quantity estimates			19,800
Net change in income tax			—
Net change in prices and production costs			29,576
Accretion of discount			4,034
Development costs incurred			10,075
Net change in estimated future development costs			(7,870	)
Change in production rates (timing) and other			(3,366	)
December 31, 2007		$	132,232

 

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GASTAR EXPLORATION LTD. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

 

SCHEDULE II

VALUATION AND QUALIFYING ACCOUNTS

 

		Balance at Beginning of Year			Expense			Reduction				Balance at End of Year
		(in thousands)
Year ended December 31, 2007:
Allowance for doubtful accounts		$	626		$	3,697		$	(8	)		$	4,315
Deferred tax valuation allowance		$	48,322		$	4,147		$	—			$	52,469
Year ended December 31, 2006:
Allowance for doubtful accounts		$	721		$	—		$	(95	)		$	626
Deferred tax valuation allowance		$	19,799		$	28,523		$	—			$	48,322
Year ended December 31, 2005:
Allowance for doubtful accounts		$	721		$	—		$	—			$	721
Deferred tax valuation allowance		$	12,181		$	7,618		$	—			$	19,799

 

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ANNEX A

LETTER OF TRANSMITTAL

To Tender

12 ³/4% Senior Secured Notes due 2012

of

GASTAR EXPLORATION USA, INC.

Pursuant to the Exchange Offer and Prospectus dated July 1, 2008

 

 

THE EXCHANGE OFFER AND WITHDRAWAL RIGHTS WILL EXPIRE AT 5:00 P.M., NEW YORK CITY TIME, ON JULY 31, 2008 (THE “EXPIRATION DATE”), UNLESS THE EXCHANGE OFFER IS EXTENDED BY THE COMPANY.

 

 

The Exchange Agent for the Exchange Offer is:

WELLS FARGO. BANK NATIONAL ASSOCIATION

 

Delivery by Registered or Certified Mail:		Facsimile Transmissions: (Eligible Institutions Only)		Overnight Delivery or Regular Mail:
Wells Fargo Bank, NA Corporate Trust Operations MAC N9303-121 PO Box 1517 Minneapolis, MN 55480		(214) 777-4086 Attention: Patrick T. Giordano, Corporate Trust Services		Wells Fargo Bank, NA Corporate Trust Operations MAC N9303-121 Sixth & Marquette Avenue Minneapolis, MN 55479
		To Confirm by Telephone or for Information Call:
		(214) 740-1573

IF YOU WISH TO EXCHANGE ISSUED AND OUTSTANDING 12 ³/4% SENIOR SECURED NOTES DUE 2012 (THE “OLD NOTES”) FOR AN EQUAL AGGREGATE PRINCIPAL AMOUNT OF NEW 12 ³/4% SENIOR SECURED NOTES DUE 2012 PURSUANT TO THE EXCHANGE OFFER, YOU MUST VALIDLY TENDER (AND NOT WITHDRAW) OLD NOTES TO THE EXCHANGE AGENT PRIOR TO 5:00 P.M., NEW YORK CITY TIME, ON THE EXPIRATION DATE BY CAUSING AN AGENT’S MESSAGE TO BE RECEIVED BY THE EXCHANGE AGENT PRIOR TO SUCH TIME.

 

 

The undersigned hereby acknowledges receipt of the Prospectus, dated July 1, 2008 (the “Prospectus”), of Gastar Exploration USA, Inc., a Michigan corporation (the “Company”), and this Letter of Transmittal (the “Letter of Transmittal”), which together describe the Company’s offer (the “Exchange Offer”) to exchange its 12 ³/4% Senior Secured Notes Due 2012 (the “New Notes”) that have been registered under the Securities Act of 1933, as amended (the “Securities Act”), for a like principal amount of its issued and outstanding its 12 ³/4% Senior Secured Notes Due 2012 (the “Old Notes”). Capitalized terms used but not defined herein have the respective meaning given to them in the Prospectus.

The Company reserves the right, at any time or from time to time, to extend the Exchange Offer at its discretion, in which event the term “Expiration Date” shall mean the latest date to which the Exchange Offer is extended. The

 

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Company shall notify the Exchange Agent by oral or written notice and each registered holder of the Old Notes of any extension by press release prior to 9:00 a.m., New York City time, on the next business day after the previously scheduled Expiration Date.

This Letter of Transmittal is to be used by holders of the Old Notes. Tender of Old Notes is to be made according to the Automated Tender Offer Program (“ATOP”) of the Depository Trust Company (“DTC”) pursuant to the procedures set forth in the prospectus under the caption “The Exchange Offer—Procedures for Tendering.” DTC participants that are accepting the Exchange Offer must transmit their acceptance to DTC, which will verify the acceptance and execute a book-entry delivery to the Exchange Agent’s DTC account. DTC will then send a computer generated message known as an “agent’s message” to the exchange agent for its acceptance. For you to validly tender your Old Notes in the Exchange Offer, the Exchange Agent must receive, prior to the Expiration Date, an agent’s message under the ATOP procedures that confirms that:

 

•

DTC has received your instructions to tender your Old Notes; and

 

•

You agree to be bound by the terms of this Letter of Transmittal.

By using the ATOP procedures to tender outstanding notes, you will not be required to deliver this Letter of Transmittal to the Exchange Agent. However, you will be bound by its terms, and you will be deemed to have made the acknowledgments and the representations and warranties it contains, just as if you had signed it.

 

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PLEASE READ THE ACCOMPANYING INSTRUCTIONS CAREFULLY.

Ladies and Gentlemen:

1. By tendering Old Notes in the Exchange Offer, you acknowledge receipt of the Prospectus and this Letter of Transmittal.

2. By tendering Old Notes in the Exchange Offer, you represent and warrant that you have full authority to tender the Old Notes described above and will, upon request, execute and deliver any additional documents deemed by the Company to be necessary or desirable to complete the tender of Old Notes.

3. You understand that the tender of the Old Notes pursuant to all of the procedures set forth in the Prospectus will constitute an agreement between and the Company as to the terms and conditions set forth in the Prospectus.

4. By tendering Old Notes in the Exchange Offer, you acknowledge that the Exchange Offer is being made in reliance upon interpretations contained in no-action letters issued to third parties by the staff of the Securities and Exchange Commission (the “SEC”), including Exxon Capital Holdings Corp., SEC No-Action Letter (available April 13, 1989), Morgan Stanley & Co., Inc., SEC No-Action Letter (available June 5, 1991) and Shearman & Sterling, SEC No-Action Letter (available July 2, 1993), that the New Notes issued in exchange for the Old Notes pursuant to the Exchange Offer may be offered for resale, resold and otherwise transferred by holders thereof (other than a broker-dealer who purchased Old Notes exchanged for such New Notes directly from the Company to resell pursuant to Rule 144A or any other available exemption under the Securities Act of 1933, as amended (the “Securities Act”) and any such holder that is an “affiliate” of the Company within the meaning of Rule 405 under the Securities Act), without compliance with the registration and prospectus delivery provisions of the Securities Act, provided that such New Notes are acquired in the ordinary course of such holders’ business and such holders are not participating in, and have no arrangement with any person to participate in, the distribution of such New Notes.

5. By tendering Old Notes in the Exchange Offer, you represent and warrant that:

a. the New Notes acquired pursuant to the Exchange Offer are being obtained in the ordinary course of your business, whether or not you are the holder;

b. neither you nor any such other person is engaging in or intends to engage in a distribution of such New Notes;

c. neither you nor any such other person has an arrangement or understanding with any person to participate in the distribution of such New Notes; and

d. neither the holder nor any such other person is an “affiliate,” as such term is defined under Rule 405 promulgated under the Securities Act, of the Company.

6. You may, if you are unable to make all of the representations and warranties contained in Item 5 above and as otherwise permitted in the Registration Rights Agreement (as defined below), elect to have your Old Notes registered in the shelf registration statement described in the Registration Rights Agreement, dated as of November 29, 2007 (the “Registration Rights Agreement”), by and among the Company, the Guarantors (as defined therein) and the Initial Purchasers (as defined therein). Such election may be made only by notifying the Company in writing at 1331 Lamar Street, Suite 1080, Houston, Texas 77010, Attention: Chief Financial Officer. By making such election, you agree, as a holder of Old Notes participating in a shelf registration, to indemnify and hold harmless the Company, each of the directors of the Company, each of the officers of the Company who signs such shelf registration statement, each person who controls the Company within the meaning of either the Securities Act or the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and each other holder of Old Notes, from and against any and all losses, claims, damages or liabilities caused by any untrue statement or alleged untrue statement of a material fact contained in any shelf registration statement or prospectus, or in any supplement thereto or amendment thereof, or caused by the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading; but only with respect to information relating to the undersigned furnished in writing by or on

 

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behalf of the undersigned expressly for use in a shelf registration statement, a prospectus or any amendments or supplements thereto. Any such indemnification shall be governed by the terms and subject to the conditions set forth in the Registration Rights Agreement, including, without limitation, the provisions regarding notice, retention of counsel, contribution and payment of expenses set forth therein. The above summary of the indemnification provision of the Registration Rights Agreement is not intended to be exhaustive and is qualified in its entirety by the Registration Rights Agreement.

7. If you are a broker-dealer that will receive New Notes for its own account in exchange for Old Notes that were acquired as a result of market-making activities or other trading activities, you acknowledge, by tendering Old Notes in the Exchange Offer, that you will deliver a prospectus in connection with any resale of such New Notes; however, by so acknowledging and by delivering a prospectus, you will not be deemed to admit that you are an “underwriter” within the meaning of the Securities Act. If you are a broker-dealer and Old Notes held for your own account were not acquired as a result of market-making or other trading activities, such Old Notes cannot be exchanged pursuant to the Exchange Offer.

8. Any of your obligations hereunder shall be binding upon your successors, assigns, executors, administrators, trustees in bankruptcy and legal and personal representatives of the undersigned.

INSTRUCTIONS

FORMING PART OF THE TERMS AND CONDITIONS OF THE EXCHANGE OFFER

1. Book-Entry Confirmations.

Any confirmation of a book-entry transfer to the Exchange Agent’s account at DTC of Old Notes tendered by book-entry transfer (a “Book-Entry Confirmation”), as well as an agent’s message, and any other documents required by this Letter of Transmittal, must be received by the Exchange Agent at its address set forth herein prior to 5:00 P.M., New York City time, on the Expiration Date.

2. Partial Tenders.

Tenders of Old Notes will be accepted only in integral multiples of $1,000. The entire principal amount of Old Notes delivered to the Exchange Agent will be deemed to have been tendered unless otherwise communicated to the Exchange Agent. If the entire principal amount of all Old Notes is not tendered, then Old Notes for the principal amount of Old Notes not tendered and Notes issued in exchange for any Old Notes accepted will be delivered to the holder via the facilities of DTC promptly after the Old Notes are accepted for exchange.

3. Validity of Tenders.

All questions as to the validity, form, eligibility (including time of receipt), acceptance, and withdrawal of tendered Old Notes will be determined by the Company, in its sole discretion, which determination will be final and binding. The Company reserves the absolute right to reject any or all tenders not in proper form or the acceptance for exchange of which may, in the opinion of counsel for the Company, be unlawful. The Company also reserves the absolute right to waive any of the conditions of the Exchange Offer or any defect or irregularity in the tender of any Old Notes. The Company’s interpretation of the terms and conditions of the Exchange Offer (including the instructions on this Letter of Transmittal) will be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of Old Notes must be cured within such time as the Company shall determine. Although the Company intends to notify holders of defects or irregularities with respect to tenders of Old Notes, neither the Company, the Exchange Agent, nor any other person shall be under any duty to give notification of any defects or irregularities in tenders or incur any liability for failure to give such notification. Tenders of Old Notes will not be deemed to have been made until such defects or irregularities have been cured or waived. Any Old Notes received by the Exchange Agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned by the Exchange Agent to the tendering holders via the facilities of DTC, as soon as practicable following the Expiration Date.

 

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4. Waiver of Conditions.

The Company reserves the absolute right to waive, in whole or part, any of the conditions to the Exchange Offer set forth in the Prospectus or in this Letter of Transmittal.

5. No Conditional Tender.

No alternative, conditional, irregular or contingent tender of Old Notes will be accepted.

6. Request for Assistance or Additional Copies.

Requests for assistance or for additional copies of the Prospectus or this Letter of Transmittal may be directed to the Exchange Agent at the address or telephone number set forth on the cover page of this Letter of Transmittal. Holders may also contact their broker, dealer, commercial bank, trust company or other nominee for assistance concerning the Exchange Offer.

7. Withdrawal.

Tenders may be withdrawn only pursuant to the limited withdrawal rights set forth in the Prospectus under the caption “Exchange Offer—Withdrawal Rights.”

8. No Guarantee of Late Delivery.

There is no procedure for guarantee of late delivery in the Exchange Offer.

IMPORTANT: By using the ATOP procedures to tender outstanding notes, you will not be required to deliver this Letter of Transmittal to the Exchange Agent. However, you will be bound by its terms, and you will be deemed to have made the acknowledgments and the representations and warranties it contains, just as if you had signed it.

Until September 29, 2008, all dealers that effect transactions in the new notes, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

 

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Until September 29, 2008, all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to the unsold allotments or descriptions.