Edgar Filing: PetroHunter Energy Corp

s-1_phun.htm

As filed June 30, 2008

File No. 333-______

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM S-1

REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933

PetroHunter Energy Corporation

(Exact name of registrant as specified in its charter)

Maryland

(State or jurisdiction of

incorporation or organization)

1311

(Primary Standard Industrial

Classification Code Number)

98-0431245

(I.R.S. Employer Identification No.)

1600 Stout Street, Suite 2000

Denver, Colorado 80202

(303) 572-8900; (720) 889-8371 fax

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

Charles B. Crowell, Chairman and Chief Executive Officer

1600 Stout Street, Suite 2000

Denver, Colorado 80202

(303) 572-8900; (720) 889-8371 fax

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies of all communications to:

Fay M. Matsukage, Esq.

Dill Dill Carr Stonbraker & Hutchings, P.C.

455 Sherman Street, Suite 300

Denver, Colorado 80203

(303) 777-3737; (303) 777-3823 fax

Approximate date of commencement of proposed sale to the public: As soon as practicable after the effective date of the Registration Statement.

If any of the securities registered on this Form are being offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. [X]

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. 9 _________

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. 9 _________

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. 9 ____________

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “small reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer [ ]

Non-accelerated filer [ ]

Accelerated filer [ ]

Smaller reporting company [X]

CALCULATION OF REGISTRATION FEE

Title of each class of securities to be registered	Amount to be registered (1)	Proposed maximum offering price per unit	Proposed maximum aggregate offering price	Amount of registration fee
Common stock, $0.001 par value per share, issuable upon exercise of warrants	34,442,500 shares	$1.00 (2)	$34,442,500 (2)	$1,353.59
Common stock, $0.001 par value per share, issuable upon exercise of warrants	48,230,950 shares	$0.25 - $0.28 (2)	$12,610,716 (2)	$495.60
Common stock, $0.001 par value per share	400,000 shares	$0.20 (3)	$80,000 (3)	$3.14
Common stock, $0.001 par value per share	18,917,109 shares	$0.20 (3)	$3,783,422 (3)	$148.69
	101,990,559 shares		$50,916,638	$2,001.02

___________________

(1)	Pursuant to Rule 416 of the Securities Act of 1933, as amended, this registration statement also covers such additional number of shares of common stock that may become issuable as a result of any stock splits, stock dividends, or other similar transactions.

(2)	Pursuant to Rule 457(g) of the Securities Act of 1933, as amended, the registration fee has been calculated using the price at which the warrants may be exercised.

(3)	Estimated pursuant to Rule 457(c) solely for the purpose of calculating the registration fee, based upon the average of the bid and asked prices for such shares of common stock on June 26, 2008, as reported by the OTC Bulletin Board.

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Subject to Completion, Dated June 30, 2008

PetroHunter Energy Corporation

Up to 101,990,559 Shares of Common Stock

Unless the context otherwise requires, the terms “we”, “our” and “us” refers to PetroHunter Energy Corporation.

This prospectus relates to the resale by selling stockholders of up to 101,990,559 shares of common stock. We will not receive any proceeds from sale of any of the shares offered by the selling stockholders. We will pay the expenses of registering these shares.

Our common stock is traded on the OTC Bulletin Board under the symbol “PHUN.OB.” On June 27, 2008, the closing bid price for our common stock was $0.20 per share.

Investing in these securities involves a high degree of risk. A detailed explanation of these risks is included in the section entitled “Risk Factors” of this prospectus, beginning on page 5.

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.

____________, 2008

TABLE OF CONTENTS

Page

PROSPECTUS SUMMARY	3
RISK FACTORS	7
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS	7
USE OF PROCEEDS	20
MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS	20
SELECTED FINANCIAL DATA	21
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL	22
CONDITION AND RESULTS OF OPERATIONS	22
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	33
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	33
BUSINESS	36
PROPERTIES	42
MANAGEMENT	48
EXECUTIVE COMPENSATION	53
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT	60
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS	62
DESCRIPTION OF SECURITIES	67
SELLING STOCKHOLDERS	69
PLAN OF DISTRIBUTION	74
LEGAL MATTERS	75
EXPERTS	75
ADDITIONAL INFORMATION	75
REPORTS TO STOCKHOLDERS	76
INDEX TO FINANCIAL STATEMENTS	76

PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. You should carefully read this entire prospectus and the financial statements contained in this prospectus before purchasing our securities.

PetroHunter Energy Corporation

PetroHunter Energy Corporation (collectively, with its subsidiaries, referred to herein as “PetroHunter”, “Company”, “we”, “us” or “our”) is a development stage global oil and gas exploration and production company committed to acquiring and developing primarily unconventional natural gas and oil prospects that we believe have a very high probability of economic success. Since our inception in 2005, our principal business activities have been raising capital through the sale of common stock and convertible notes and acquiring oil and gas properties in the western United States and Australia. Currently, we own property in Colorado, where we have drilled five wells on our Buckskin Mesa property, Australia, where we have drilled one well on our property in the Northern Territory, and in Montana, where we hold a land position in the Bear Creek area. The wells on these properties have not yet commenced oil production. We also have working interests in eight additional wells in Colorado which are operated by EnCana Oil & Gas USA (“EnCana”). In November 2007, we sold 66,000 net acres of land and two wells in Montana and 177,445 net acres of land in Utah, and in May 2008, we sold 625 net acres of land and 16 wells in the Southern Piceance in Colorado, allowing us to focus on our Buckskin Mesa property and Australia.

Our principal executive offices are located at 1600 Stout Street, Suite 2000, Denver, CO 80202. The telephone number is (303) 572-8900, the facsimile number is (303) 572-8927, and our web site is www.petrohunter.com. Information contained in our website is not part of this prospectus.

The Offering

Securities offered	101,990,559 shares of common stock.

Use of proceeds	We will not receive any of the proceeds from the selling stockholders of shares of our common stock.

Securities outstanding	338,065,950 shares of common stock as of June 27, 2008.

Plan of distribution	The offering is made by the selling stockholders named in this prospectus, to the extent they sell shares. Sales may be made in the open market or in private negotiated transactions, at fixed or negotiated prices. See “Plan of Distribution.”

Risk Factors

Investing in our securities involves a high degree of risk. You should consider carefully the information under the caption “Risk Factors” in deciding whether to purchase the shares.

Summary Financial Information

The following summary financial data is derived from the interim (unaudited) financial statements for the six months ended March 31, 2008 and 2007 and audited financial statements for the fiscal years ended September 30, 2007 and 2006 and the period from inception (June 20, 2005) through September 30, 2005.

We have prepared the financial statements in accordance with generally accepted accounting principles. You should read this summary financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business,” and our financial statements.

STATEMENT OF OPERATIONS DATA

	Six Months Ended March 31, 2008			Six Months Ended March 31, 2007 (restated)			Year Ended September 30, 2007			Year Ended September 30, 2006			From Inception (June 20, 2005) to September 30, 2005			Cumulative from Inception (June 20, 2005) to March 31, 2008
	($ in thousands, except per share amounts)
Total Revenues	$	992		$	1,338		$	2,820		$	36		$	--		$	3,848
Total Operating Expenses	$	6,371		$	20,442		$	45,981		$	18,245		$	2,096		$	72,693
Loss from Operations	$	(5,379	)	$	(19,104	)	$	(43,161	)	$	(18,209	)	$	(2,096	)	$	(68,845	)
Total Other Expense	$	(10,374	)	$	(2,217	)	$	(6,650	)	$	(2,483	)	$	(23	)	$	(19,530	)
Net Loss	$	(15,753	)	$	(21,321	)	$	(49,811	)	$	(20,692	)	$	(2,119	)	$	(88,375	)
Net Loss per Common Share – Basic and Diluted	$	(0.05	)	$	(0.10	)	$	(0.20	)	$	(0.14	)	$	(0.02	)

BALANCE SHEET DATA

	March 31, 2008			September 30, 2007			September 30, 2006		September 30, 2005
	($ in thousands, except per share amounts)
Working (Deficit) Capital	$	(39,773	)	$	(37,865	)	$	1,275	$	8,438
Oil and Gas Properties, Net	$	173,975		$	162,843		$	45,973		7,231
Total Assets	$	181,537		$	182,024		$	59,242	$	8,500
Non-Current Liabilities	$	34,601		$	37,130		$	522	$	--
Stockholders’ Equity (Deficit)	$	105,143		$	100,324		$	48,353	$	(1,196	)

GLOSSARY

Unless otherwise indicated in this document, oil equivalents are determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids so that six Mcf of natural gas are referred to as one barrel of oil equivalent.

API Gravity. A specific gravity scale developed by the American Petroleum Institute (API) for measuring the relative density of various petroleum liquids, expressed in degrees. API gravity is gradated in degrees on a

hydrometer instrument and was designed so that most values would fall between 10° and 70° API gravity. The arbitrary formula used to obtain this effect is: API gravity = (141.5/SG at 60°F) — 131.5, where SG is the specific gravity of the fluid.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bcf. One billion cubic feet of natural gas at standard atmospheric conditions.

Capital Expenditures. Costs associated with exploratory and development drilling (including exploratory dry holes); leasehold acquisitions; seismic data acquisitions; geological, geophysical and land-related overhead expenditures; delay rentals; producing property acquisitions; other miscellaneous capital expenditures; compression equipment and pipeline costs.

Carried Interest. The owner of this type of interest in the drilling of a well incurs no liability for costs associated with the well until the well is drilled, completed and connected to commercial production/processing facilities.

Completion. The installation of permanent equipment for the production of oil or natural gas.

Developed Acreage. The number of acres that are allocated or assignable to producing wells or wells capable of production.

Development Well. A well drilled within the proved area of an oil or natural gas reservoir to a depth that is known to be productive.

Exploitation. The continuing development of a known producing formation in a previously discovered field. To make complete or maximize the ultimate recovery of oil or natural gas from the field by work including development wells, secondary recovery equipment or other suitable processes and technology.

Exploration. The search for natural accumulations of oil and natural gas by any geological, geophysical or other suitable means.

Exploratory Well. A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir.

Farm-In or Farm-Out. An agreement under which the owner of a working interest in a natural gas and oil lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out”.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Finding and Development Costs. The total capital expenditures, including acquisition costs and exploration and abandonment costs, for oil and gas activities divided by the amount of proved reserves added in the specified period.

Force Pooling. The process by which interests not voluntarily participating in the drilling of a well, may be involuntarily committed to the operator of the well (by a regulatory agency) for the purpose of allocating costs and revenues attributable to such well.

Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which we have a working interest.

Lease. An instrument which grants to another (the lessee) the exclusive right to enter to explore for, drill for, produce, store and remove oil and natural gas on the mineral interest, in consideration for which the lessor is entitled to certain rents and royalties payable under the terms of the lease. Typically, the duration of the lessee’s authorization is for a stated term of years and “for so long thereafter” as minerals are producing.

Mcf. One thousand cubic feet of natural gas at standard atmospheric conditions.

MCFE. One thousand cubic feet of gas equivalent. Gas equivalents are determined using the ratio of six Mcf of gas (including gas liquids) to one Bbl of oil.

Net Acres or Net Wells. A net acre or well is deemed to exist when the sum of our fractional ownership working interests in gross acres or wells, as the case may be, equals one. The number of net acres or wells is the sum of the fractional working interests owned in gross acres or wells, as the case may be, expressed as whole numbers and fractions thereof.

Operator. The individual or company responsible to the working interest owners for the exploration, development and production of an oil or natural gas well or lease.

Overriding Royalty. A revenue interest in oil and gas, created out of a working interest which entitles the owner to a share of the proceeds from gross production, free of any operating or production costs.

Payout. The point at which all costs of leasing, exploring, drilling and operating have been recovered from production of a well or wells, as defined by contractual agreement.

Productive Well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes. Productive wells consist of producing wells and wells capable of productions, but specifically exclude wells drilled and cased during the fiscal year that have yet to be tested for completion.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved Reserves. The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

Reserves. Natural gas and crude oil, condensate and natural gas liquids on a net revenue interest basis, found to be commercially recoverable.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Royalty. An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage, or of the proceeds of the sale thereof, but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Spud. To start the well drilling process by removing rock, dirt and other sedimentary material.

Stratigraphic. Relating to vertical position in a rock column. More generally, relating to relative geological age, since typically, in any given sequence of sedimentary rock, older rock is lower than newer.

3-D Seismic. The method by which a three-dimensional image of the earth’s subsurface is created through the interpretation of a reflection of seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, exploitation and production.

Undeveloped Acreage. Lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether or not such acreage contains proved reserves.

Working Interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of royalties.

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements contained in this prospectus constitute “forward-looking statements.” These statements, identified by words such as “plan,” “anticipate,” “believe,” “estimate,” “should,” “expect” and similar expressions include our expectations and objectives regarding our future financial position, operating results and business strategy. These statements reflect the current views of management with respect to future events and are subject to risks, uncertainties and other factors that may cause our actual results, performance or achievements, or industry results, to be materially different from those described in the forward-looking statements. All forward-looking statements herein as well as all subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by cautionary statements set forth in “Risk Factors” appearing below. We assume no duty to update or revise our forward-looking statements based on changes in internal estimates or expectations or otherwise. We advise you to carefully review the reports and documents we file from time to time with the Securities and Exchange Commission (the “SEC”).

RISK FACTORS

Before deciding to invest in us or to maintain or increase your investment, you should carefully consider the risk factors described below that discuss the material risks related to an investment in us, together with all other information in this prospectus and in our other filings with the SEC, before making an investment decision. If any of the following risks actually occurs, our business, financial conditions or operating results could be materially adversely affected. In such case, the trading price of our common stock could decline, and you may lose all or part of your investment.

Risks Related to Our Business

We have a limited operating history and have generated only very limited revenues. We have incurred significant losses and will continue to incur losses for the foreseeable future.

We are a development stage oil and gas company and have limited operating history and production revenue. Our principal activities have been oil and gas drilling and development activities, raising capital through the sale of our securities and identifying and evaluating potential oil and gas properties.

The report of our independent registered public accounting firm on the financial statements for the year ended September 30, 2007, includes an explanatory paragraph relating to the uncertainty of our ability to continue as a going concern. We have incurred a cumulative net loss of $88.4 million for the period from inception (June 20, 2005) to March 31, 2008. As of March 31, 2008, we had a working capital deficit of approximately $39.8 million, are in default on certain obligations, are not in compliance with the covenants of several loan agreements, and require significant additional funding to sustain our operations and satisfy our contractual obligations for our planned oil and gas exploration and development operations. We have had multiple property liens and foreclosure actions filed by vendors, some of whom have begun foreclosure proceedings, and have significant capital expenditure commitments. For the 2008 fiscal year, we do not expect our operations to generate sufficient cash flows to provide working capital to cover overhead, the funding of our lease acquisitions, and the exploration and development of our properties. Without adequate financing, we may not be able to successfully develop prospects that we have or that we acquire and we may not achieve profitability from operations in the near future or at all.

Our short-term cash commitments require us to sell more debt and/or equity securities and/or sell our assets, which may be detrimental to our stockholders.

As of March 31, 2008, we had drilling commitments for the fiscal year ending September 30, 2008 of $44 million. We will raise additional funds to meet these obligations by selling debt and/or equity securities, by selling assets, or by entering into farm-out agreements or other similar types of arrangements. Financing obtained through the sale of our equity will result in significant dilution to our stockholders. We have granted security interests in our assets to lenders and holders of our debentures which limits our ability to sell debt securities since they will be subordinated to our other security interest holders. The existence of security interests in our assets restricts our ability to sell those assets. We may be forced to sell assets at below market value, and therefore we may not realize the market value or even the carrying value of those assets.

The lack of production and established reserves for our properties impairs our ability to raise capital.

As of September 30, 2007, we have established very limited production of natural gas from a limited number of wells, and have a limited number of properties for which reserves have been established, making it more difficult to raise the amount of capital needed to fully exploit the production potential of our properties. Therefore, we may have to raise capital on terms less favorable than we would desire; this may result in increased dilution to existing stockholders.

Terms of subsequent financings may adversely impact your investment.

We may have to engage in common equity, debt or preferred stock financing in the future. Stockholders’ rights and the value of their investment in the common stock could be reduced by any type of financing we do. Interest on debt securities could increase costs and negatively impact operating results, and investors in debt securities may negotiate for other consideration or terms that could have a negative impact on the investment of existing stockholders. Preferred stock could be issued in series from time to time with such designations, rights, preferences and limitations as needed to raise capital, and the terms of preferred stock could be more advantageous to those investors than to the holders of common stock. If we need to raise more equity capital from the sale of common stock, institutional or other investors may negotiate terms at least as, and possibly more favorable than, the terms of the investment of existing stockholders. In addition, any shares of common stock that we sell could be sold into the market and subsequent sales could adversely affect the market price of our stock.

Marc A. Bruner and his affiliates control a significant percentage of our outstanding common stock, which will enable them to control many significant corporate actions and may prevent a change in control that would otherwise be beneficial to our stockholders.

Marc A. Bruner beneficially owned approximately 43% of our common stock as of June 27, 2008. Such control by Mr. Bruner may have a substantial impact on matters requiring the vote of common stockholders, including the election of our directors and most of our corporate actions. Such control could delay, defer or prevent others from initiating a potential merger, takeover or other change in control that might benefit us and our stockholders. Such control could adversely affect the voting and other rights of our other stockholders and could depress the market price of our common stock.

Marc A. Bruner is the controlling owner of MAB Resources LLC (“MAB”), the entity with which we have an agreement under which MAB is entitled to an overriding royalty interest on certain of our oil and gas properties. Mr. Bruner serves as the chairman of the board of Gasco Energy, Inc., a company whose stock is trading on the American Stock Exchange, and chairman of the board, chief executive officer and president of Falcon Oil & Gas Ltd. (“Falcon”), a company whose stock is traded on the TSX Venture Exchange, and is involved with other natural resource companies. He is a significant stockholder of Galaxy Energy Corporation, a company whose stock is traded on the OTC Bulletin Board. Mr. Bruner is also a significant stockholder of Exxel Energy Corp., a British Columbia corporation, whose stock is traded on the TSX Venture Exchange.

The issuance of the shares upon conversion of convertible debentures and exercise of warrants could significantly dilute the interests of stockholders.

In November 2007, we issued convertible debentures in the aggregate principal amount of approximately $7.0 million. The debentures are convertible into shares of our common stock at any time prior to their maturity dates at a current conversion price of $0.15, subject to adjustments for stock splits, stock dividends, stock combinations and other similar transactions. The conversion prices of the convertible debentures could be further lowered, perhaps significantly, in the event of our issuance of common stock below the convertible debentures’ conversion price, either directly or in connection with the issuance of securities that are convertible into, or exercisable for, shares of our common stock.

In addition, we issued five-year warrants to the holders of the convertible debentures. The warrant holders are entitled to purchase an aggregate of 48.2 million shares of our common stock at an exercise price ranging from $0.24 to $0.28 per share. Both the number of warrants and the exercise price are subject to adjustments that could make them further dilutive to our stockholders.

Neither the convertible debentures nor the warrants establish a “floor” that would limit reductions in the conversion price of the convertible debentures or the exercise price of the warrants that may occur under certain circumstances. Correspondingly, there is no “ceiling” on the number of shares that may be issuable under certain circumstances under the anti-dilution adjustment in the convertible debentures and warrants. Accordingly, our issuance of the convertible debentures and warrants could significantly dilute the interests of our stockholders.

Our failure to satisfy our registration, listing and other obligations with respect to the common stock underlying the warrants could result in adverse consequences, including acceleration of the convertible debentures.

We are required to maintain the effectiveness of the registration statement covering the resale of the common stock underlying the warrants, until the earlier of the date the underlying common stock may be resold pursuant to Rule 144 under the Securities Act of 1933 without any type of restriction or the date on which the sale of all the underlying common stock is completed, subject to certain exceptions. We will be subject to various penalties for failing to meet our registration obligations, which include cash penalties and the forced redemption of the convertible debentures.

The issuance of shares upon exercise of outstanding warrants and options may cause immediate and significant dilution to our existing stockholders.

As of March 31, 2008, we have issued warrants and options to purchase a total of 169.3 million shares of common stock. In November 2007, we sold convertible debentures that are convertible into a total of 46.4 million shares of common stock. The issuance of shares upon exercise of warrants and options and upon conversion of debentures may result in significant dilution to the interests of our existing stockholders.

We are obligated to make significant periodic payments of interest under our credit facilities.

As of March 31, 2008, we have drawn down $32.8 million on our credit facilities. Interest on the credit facility borrowings accrues at 6.75% over the prime rate and is payable quarterly. If the prime rate remains at 7.25% and we take no additional draws, our required interest payment will be $4.4 million during the 2008 fiscal year. As of March 31, 2008, we were in default of payments in the amount of $3.9 million, consisting of interest and fees owed to the lender. The lender has waived and released us from any and all defaults, failures to perform, and any other failures to meet our obligations through July 1, 2009. If we default on our payment obligations in the future, the lender will have all rights available under the instrument, including acceleration, termination and enforcement of its security interest in our Buckskin Mesa project in the Piceance Basin, Colorado.

We are in default in relation to numerous provisions under our convertible debentures and other debt and credit arrangements, which could bring material adverse consequences to our business.

As of March 31, 2008, we were in default in relation to various terms, covenants and conditions, including provisions relating to the payment of principal and interest toward our debt obligations and credit facilities. Although we believe we have obtained sufficient waivers and releases from the holders of these instruments, there can be no assurance that the continuation of such events of default, failures to perform and other failures to meet the terms of these instruments will not result in the holders of these instruments taking any and all actions afforded them under these agreements in collecting amounts owed to them. Such actions could include, and are not limited to, acceleration, termination, and foreclosure actions in relation to any underlying collateral, and could result in the holders pursuing involuntary bankruptcy proceedings against us.

We have been and continue to be delinquent in paying certain trade creditor obligations to our vendors, who have historically filed liens on our properties and taken other legal actions against us in order to collect amounts owed to them by us, which could bring material adverse consequences to our business.

In conjunction with the closing of the Laramie transaction in May 2008, we have settled or otherwise resolved numerous claims, liens and other courses of action brought or potentially brought by our U.S. based trade vendors. Although these settlements, primarily through the payment of cash from the proceeds from the sale of assets to Laramie, have substantially reduced our past due trade obligations, there can be no assurance such conditions could not arise again due to our inability to pay future amounts due to our trade vendors. In addition, we continue to have substantial unpaid and past due obligations with our Australian vendors, and we are in the process of attempting to resolve asserted, pending and potential claims with them. Regardless of our ability to successfully resolve these past due obligations, we may be unable to maintain ongoing business relationships with these vendors, which could have a material adverse effect on our business.

We continue to experience significant cash flow challenges, and absent our ability to continue to secure adequate funding to meet our cash obligations, we will not be able to continue in existence.

As of March 31, 2008, we have earned oil and gas revenue from our initial operating wells, but will require significant additional funding to sustain operations and satisfy contractual obligations for planned oil and gas exploration, development and operations in the future. These factors, among others, may indicate that we may be unable to continue in existence. Management believes that we can be successful in obtaining equity and/or debt financing and/or sell interests in some of our properties, which will enable us to continue in existence and establish ourselves as a going concern. While we have raised approximately $102.4 million through March 31, 2008 through issuances of common stock and convertible and other debt, we cannot assure you that we can continue to raise additional funding.

Our officers, directors and advisors are engaged in other businesses, which may result in conflicts of interest.

Certain of our officers, directors, and advisors also serve as directors of other companies or have significant shareholdings in other companies. To the extent that such other companies participate in ventures in which we may participate, or compete for prospects or financial resources with us, these officers and directors will have a conflict of interest in negotiating and concluding terms relating to the extent of such participation. In the event that such a conflict of interest arises at a meeting of the Board of Directors, a director who has such a conflict must disclose the nature and extent of his interest to the Board of Directors and abstain from voting for or against the approval of such participation or such terms.

We depend on a limited number of key personnel who would be difficult to replace.

We depend on the performance of our executive officers and other key employees. The loss of any member of our senior management or other key employees could negatively impact our ability to execute our strategy. We do not maintain key person life insurance policies on any of our employees.

Reserve estimates depend on many assumptions that may turn out to be inconclusive, subject to varying interpretations or inaccurate.

Estimates of natural gas and oil reserves are based upon various assumptions, including assumptions relating to natural gas and oil prices, drilling and operating expenses, capital expenditures, ownership and title, taxes and the availability of funds. The process of estimating natural gas and oil reserves is complex. It requires interpretations of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise.

Actual natural gas and oil prices, future production, revenues, operating expenses, taxes, development expenditures and quantities of recoverable natural gas will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of future net revenues at any time. A reduction in natural gas and oil prices, for example, would reduce the value of reserves and reduce the amount of natural gas and oil that could be economically produced, thereby reducing the quantity of reserves. At any time, there might be adjustments of estimates of reserves to reflect production history, results of exploration and development, prevailing natural gas prices and other factors, many of which are beyond our control.

Undeveloped reserves, by their nature, are less certain. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. Any reserve data assumes that we will make these capital expenditures necessary to develop our reserves. To the extent that we have prepared estimates of our natural gas and oil reserves and of the costs associated with these reserves in accordance with industry standards, we cannot assure you that the estimated costs are accurate, that development will occur as scheduled or that the actual results will be as estimated.

Our identified drilling location inventories are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, natural gas and oil prices, costs and drilling results. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of natural gas and oil-bearing structures or favorable stratigraphy, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable geoscientists to know whether hydrocarbons are, in fact, present in those structures. We are employing 2-D and 3-D seismic technology for certain of our projects. The use of 2-D and 3-D seismic and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies, and the profitability of our ventures may be adversely affected. Even with the use of advanced seismic applications, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline.

We often gather 2-D and 3-D seismic over large areas. Our interpretation of seismic data delineates those portions of an area that we believe are desirable for drilling. Therefore, we may choose not to acquire option or lease rights prior to acquiring seismic data and, in many cases, we may identify hydrocarbon indicators before seeking option or lease rights in a prospective area. If we are unable to lease those locations on acceptable terms, we will have made substantial expenditures to acquire and analyze 2-D and 3-D data without having an opportunity to attempt to benefit from those expenditures.

Substantially all of our producing properties are located in the Rocky Mountains, making us vulnerable to risks associated with operating in one major geographic area.

Our operations are focused on the Rocky Mountain region and therefore our producing properties are geographically concentrated in that area. In addition, a significant portion of our oil and natural gas resources and operations are located in the Piceance Basin, Colorado and the Northern Territory, Australia. As a result, we may be disproportionately exposed to the effect of delays or interruptions of production from these areas caused by significant governmental regulation, transportation capacity constraints, the availability and capacity of compression and gas processing facilities, curtailment of production or interruption of transportation of natural gas produced from the wells in these areas, as well as the remoteness and lack of infrastructure in the case of the Australian properties.

Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Oil and natural gas operations in the Rocky Mountains and in Australia are adversely affected by seasonal weather conditions and lease stipulations designed to regulate land use, including operating guidelines for designated wildlife habitats and areas with scenic resource value. In certain areas in Australia and on federal lands in the U.S., drilling and other oil and natural gas activities can only be conducted during limited times of the year. This limits our ability to operate in those areas and can intensify competition during those times for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.

Acquisitions are a part of our business strategy and are subject to the risks and uncertainties of evaluating recoverable reserves and potential liabilities. Properties that we buy may not produce as projected and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them.

One of our growth strategies is to capitalize on opportunistic acquisitions of oil and natural gas reserves. The successful acquisition of producing and non-producing properties requires an assessment of a number of factors. These factors include recoverable reserves, future oil and gas prices, operating costs, potential environmental and other liabilities, title issues and other factors. Our reviews of acquired properties are inherently incomplete, because it generally is not feasible to perform an in depth review of every individual property involved in each acquisition. Ordinarily, we focus our review efforts on the higher value properties and sample the remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies or their potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. We sometimes knowingly assume certain environmental and other risks and liabilities in connection with acquired properties. It is possible that our future acquisition activity will result in disappointing results. We could be subject to significant liabilities related to acquisitions

In addition, there is strong competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our strategy of completing acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to pursue our acquisition strategy may be hindered if we are unable to obtain financing or regulatory approvals.

Acquisitions often pose integration risks and difficulties. In connection with future acquisitions, the process of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of existing operations. Possible future acquisitions could result in our incurring additional debt, contingent liabilities and expenses, all of which could have a material adverse effect on our financial condition and operating results.

We have limited control over activities on properties we do not operate, which could reduce our production and revenues.

A portion of our business activities are conducted through joint operating agreements under which we own partial interests in oil and natural gas properties. If we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of underlying properties. The failure of an operator of our wells to adequately perform operations or an operator’s breach of the applicable agreements could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others, therefore, depends upon a number of factors outside of our control, including the operator’s deployment of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology. Because we do not have a majority interest in certain wells we do not operate, we may not be in a position to remove the operator in the event of poor performance.

The inability of one or more of our customers to meet their obligations may adversely affect our financial results.

Substantially all of our accounts receivable result from oil and natural gas sales or joint interest to third parties in the energy industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, potential oil and natural gas hedging arrangements may expose us to credit risk in the event of nonperformance by counterparties.

Market conditions or operation impediments may hinder our access to natural gas and oil markets or delay our production.

The marketability of our production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities. The dependence is heightened where the infrastructure is less developed. Therefore, if drilling results are positive in certain areas, a new gathering system may need to be built to handle the potential volume of gas produced. We might be required to shut in wells, at least temporarily, for lack of a market or because of the inadequacy or unavailability of transportation facilities. If that were to occur, we would be unable to realize revenue from those wells until arrangements were made to deliver production to the market.

Our ability to produce and market natural gas and oil is affected and also may be harmed by:

·	the lack of pipeline transmission facilities or carrying capacity;

·	government regulation of natural gas and oil production;

·	government transportation, tax and energy policies;

·	changes in supply and demand; and

·	general economic conditions.

We might incur additional debt in order to fund our exploration and development activities, which would continue to reduce our financial flexibility and could have a material adverse effect on our business, financial condition or results of operations.

If we incur indebtedness, our ability to meet our debt obligations and reduce our level of indebtedness will depend on future performance. General economic conditions, oil and gas prices and financial, business and other factors affect our operations and future performance; many of these factors are beyond our control. We cannot assure you that we will be able to generate sufficient cash flow to pay the interest on our debt or that future working capital, borrowings or equity financing will be available to pay for or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and performance at the time we need capital. We cannot assure you that we will have sufficient funds to make refund debt payments. Lack of sufficient funds and/or the inability to negotiate new borrowing terms may cause us to sell significant assets which could have a material adverse effect on our business and financial results.

We have found material weaknesses in our internal controls that require remediation and concluded that our internal controls over financial reporting at March 31, 2008, were not effective.

In our filings with the Securities and Exchange Commission, we have reported the existence of continuing material weaknesses related to our control environment which did not sufficiently promote effective internal control over financial reporting through our management structure to prevent a material misstatement from occurring. Specifically, management did not have an adequate process for monitoring accounting and financial reporting and had not conducted a comprehensive review of account balances and transactions that had occurred throughout the year. Our disclosure controls and accounting processes lack adequate staff and procedures in order to be effective. We have not had adequate staffing to provide for an effective segregation of duties, or to adequately identify and resolve accounting issues and provide information to our auditors on a timely basis. These material weaknesses continued to exist as of March 31, 2008; however, we have taken steps to retain additional senior financial consultants to assist us in completing our remediation of these material weaknesses on an accelerated basis.

We are fully committed to remediating the material weaknesses described above and believe that the steps we are taking, including the active involvement of our Audit Committee in the remediation planning and implementation, will properly address these issues. However, while we are taking immediate steps and dedicating substantial resources to correct these material weaknesses, any new controls we implement must operate for a period of time and be tested before a determination can be made as to their effectiveness. Also, our remediation procedures have identified several errors in our previously issued financial statements, which have resulted in an aggregate overstatement of our first quarter net loss by $0.0 million, and an offsetting understatement of our second quarter net loss by the same amount, as more fully described in our consolidated financial statements. As we continue to proceed through our remediation process, we may discover additional past, ongoing or future material weaknesses or significant deficiencies in our financial reporting processes, or additional errors in our financial statements, some of which could be material.

Likewise, our failure to remediate any material weaknesses or significant deficiencies, or a difficulty encountered in their implementation, could result in, among other things: an inability to provide timely and reliable financial information, an inability to meet our reporting obligations with governing bodies such as the Securities and Exchange Commission, loss of investor confidence in our reported financial information leading to a lower trading price for our common shares, additional costs to remediate and implement effective internal controls, or restatements of previously-issued financial statements, any of which could have a material adverse effect on our business, results of operations, or financial condition.

Pending the successful implementation and testing of new controls, we are performing mitigating procedures which we believe are sufficient until such new controls have been implemented.

We have significant future capital requirements. If these obligations are not met, our growth and operations could be limited or suspended indefinitely.

Our future growth depends on our ability to cause the development of the working interests we have acquired, and such development will require the expenditure of large capital either by us or by third parties through farm-out agreements. In addition, we may acquire interests in additional oil and gas leases where we will be required to pay for a specific amount of the initial costs and expenses related to the development of those leases. We intend to finance our foreseeable capital expenditures through sales of non-core assets, farm-out agreements, private placements of debt or equity, and additional funding for which we have no commitments at this time. Future cash flow and the availability of financing will be subject to a number of variables, such as:

·	the success of exploration and development on our leases;

·	success in locating and producing new reserves; and

·	prices of natural gas and oil.

Additional financing sources will be required in the future to fund developmental and exploratory drilling. Issuing equity securities to satisfy our financing requirements could cause substantial dilution to our existing stockholders. Additional debt financing could lead to:

·	a substantial portion of operating cash flow being dedicated to the payment of principal and interest;

·	the Company being more vulnerable to competitive pressures and economic downturns; and

·	restrictions on our operations.

Financing might not be available in the future, or we might not be able to obtain necessary financing on acceptable terms, if at all. If sufficient capital resources are not available, we might be forced to curtail drilling and other activities or be forced to sell assets on an untimely or unfavorable basis, which would have an adverse effect on our business, financial condition and results of operations.

Our leases and/or future properties might not produce as anticipated, and we might not be able to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them, which could cause us to incur losses.

Although we have reviewed and evaluated our leases in a manner consistent with standard industry practices, our review and evaluation may not reveal all existing or potential problems. These same factors apply to future acquisitions to be made by us. We may not perform inspections on every well, and environmental issues may not be observable during an inspection. When problems are identified, a seller may be unwilling or unable to provide effective contractual protection against those problems, and we may assume environmental and other risks and liabilities in connection with the acquired properties.

We do not plan to insure against all potential operating risks. We might incur substantial losses and be subject to substantial liability claims as a result of our natural gas and oil operations.

We do not intend to insure against all risks. We intend to maintain insurance against various losses and liabilities arising from operations in accordance with customary industry practices and in amounts that management believes to be prudent. Losses and liabilities arising from uninsured and underinsured events or in amounts in excess of existing insurance coverage could have a material adverse effect on our business, financial condition or results of operations. Our natural gas and oil exploration and production activities are subject to hazards and risks associated with drilling for, producing and transporting natural gas and oil, and any of these risks can cause substantial losses resulting from:

·	environmental hazards, such as uncontrollable flows of natural gas, oil, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;

·	abnormally pressured formations;

·	mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;

·	fires and explosions;

·	personal injuries and death;

·	regulatory investigations and penalties; and

·	natural disasters.

Any of these hazards could have a material adverse effect on our ability to conduct operations and may result in substantial losses. We may elect not to obtain insurance in the event that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could have a material adverse effect on our business, financial condition and results of operations.

Risks Relating to the Oil and Gas Industry

A substantial or extended decline in natural gas and oil prices may adversely affect our ability to meet our capital expenditure obligations and financial commitments.

Our revenues, operating results and future rate of growth are substantially dependent upon the prevailing prices of, and demand for, natural gas and oil. Declines in the prices of, or demand for, natural gas and oil may adversely affect our financial condition, liquidity, ability to finance planned capital expenditures and results of operations. Lower natural gas and oil prices may also reduce the amount of natural gas and oil that we can produce economically. Historically, natural gas and oil prices and markets have been volatile, and they are likely to continue to be volatile in the future. A decrease in natural gas or oil prices will not only reduce revenues and profits, but will also reduce the quantities of reserves that are commercially recoverable and may result in charges to earnings for impairment in the value of assets. If natural gas or oil prices decline significantly for extended periods of time in the future, we might not be able to generate enough cash flow from operations to meet our obligations and make planned capital expenditures. Natural gas and oil prices are subject to wide fluctuations in response to relatively minor changes in the supply of, and demand for, natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control. Among the factors that could cause this fluctuation are:

·	changes in supply and demand for natural gas and oil;

·	levels of production and other activities of the Organization of Petroleum Exporting Countries, or OPEC, and other natural gas and oil producing nations;

·	market expectations about future prices;

·	the level of global natural gas and oil exploration, production activity and inventories;

·	political conditions, including embargoes, in or affecting other oil producing activity; and

·	the price and availability of alternative fuels.

Lower natural gas and oil prices may not only decrease our revenues on a per unit basis, but also may reduce the amount of natural gas and oil that we are able to produce economically. A substantial or extended decline in oil or natural gas prices may materially and adversely affect our business, financial condition and results of operations.

Drilling for and producing natural gas and oil are high-risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future success depends on the success of our exploration, development and production activities. Such activities are subject to numerous risks beyond our control, including the risk that we will not find commercially productive natural gas or oil reservoirs. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretation. The cost of drilling, completing and operating wells is often uncertain before drilling commences.

Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or prevent drilling operations, including:

·	unexpected drilling conditions;

·	pressure or irregularities in geological formations;

·	equipment failures or accidents;

·	pipeline and processing interruptions or unavailability;

·	title problems;

·	lack of market demand for natural gas and oil;

·	delays imposed by or resulting from compliance with environmental and other regulatory requirements;

·	shortages of or delays in the availability of drilling rigs and the delivery of equipment; and

·	reductions in natural gas and oil prices.

Our future drilling activities might not be successful, and the drilling success rate overall or within a particular area could decline. We could incur losses by drilling unproductive wells. Although we have identified numerous potential drilling locations, we cannot be sure that we will ever drill them or will produce natural gas or oil from them or from any other potential drilling locations. Shut-in wells, curtailed production and other production interruptions may negatively impact our business and result in decreased revenues.

Competition in the oil and gas industry is intense, and many of our competitors have greater financial, technological and other resources than we do, which may adversely affect our ability to compete.

We operate in the highly competitive areas of oil and gas exploration, development and acquisition with a substantial number of other companies. We face intense competition from independent, technology-driven companies as well as from both major and other independent oil and gas companies in each of the following areas:

·	seeking oil and gas exploration licenses and production licenses;

·	acquiring desirable producing properties or new leases for future exploration;

·	marketing natural gas and oil production;

·	integrating new technologies;

·	acquiring the equipment and expertise necessary to develop and operate properties; and

·	hiring and retaining a staff of competent technical and administrative professionals.

Many of our competitors have substantially greater financial, managerial, technological and other resources. These companies might be able to pay more for exploratory prospects and productive oil and gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. To the extent competitors are able to pay more for properties than we are able to afford, we will be at a competitive disadvantage. Further, many competitors may enjoy technological advantages and may be able to implement new technologies more rapidly. Our ability to explore for natural gas and oil prospects and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, implement advanced technologies, evaluate and select suitable properties and consummate transactions in this highly competitive environment.

Shortages of rigs, equipment, supplies and personnel could delay or otherwise adversely affect our cost of operations or our ability to operate according to our business plan.

In periods of increased drilling activity, shortages of drilling and completion rigs, field equipment and qualified personnel could develop. From time to time, these costs have sharply increased in various areas around the

world and could do so again. The demand for and wage rates of qualified drilling rig crews generally rise in response to the increasing number of active rigs in service and could increase sharply in the event of a shortage. Shortages of drilling and completion rigs, field equipment or qualified personnel could delay, restrict or curtail our exploration and development operations, which could in turn harm our operating results.

We are currently experiencing an extreme shortage of well casing, which is becoming an increasing world-wide issue in our industry. Such extreme and potentially prolonged shortages prevent us from completing planned drilling operations, which may have significant implications on our ability to meet fixed drilling commitments in some of our properties, especially in relation to our Buckskin Mesa properties. Our inability to secure critical supplies such as well casing can bring our entire drilling operation to a halt until supply shortages ease.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Because total estimated proved reserves include our proved undeveloped reserves at September 30, 2007, production will decline even if those proved undeveloped reserves are developed and the wells produce as expected. The rate of decline will change if production from our existing wells declines in a different manner than we have estimated. The rate of decline may change under other circumstances as well. As a result, our future oil and natural gas reserves, and our production are highly dependent upon our success in efficiently developing and exploiting our current reserves. In addition, our potential oil and gas revenues and production depend on us finding or acquiring additional recoverable reserves economically. Our cash flow and results of operations are also dependent upon these factors. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs.

Assets may be impaired.

Under full cost accounting rules, capitalized costs of proved oil and gas properties may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10%. Application of the “Ceiling Test” generally requires pricing future revenue at the unescalated prices in effect as of the end of each fiscal quarter and requires an impairment charge for accounting purposes if the ceiling is exceeded. Impairments result in a charge to earnings, but do not impact cash flow from operating activities. Once incurred, an impairment of oil and gas properties is not reversible at a later date.

Our industry is heavily regulated which increases our cost of doing business and decreases our profitability.

U.S. and Australian federal, state and local authorities regulate the oil and gas industry. Legislation and regulations affecting the industry are under constant review for amendment or expansion, raising the possibility of changes that may affect, among other things, the pricing or marketing of oil and gas production. State and local authorities regulate various aspects of oil and gas drilling and production activities, including the drilling of wells (through permit and bonding requirements), the spacing of wells, the unitization or pooling of oil and gas properties, environmental matters, safety standards, the sharing of markets, production limitations, plugging and abandonment and restoration of wells. The overall regulatory burden on the industry increases the cost of doing business, which, in turn, decreases profitability.

Our operations must comply with complex environmental regulations that may have a material adverse effect on our business.

Our operations are subject to complex and constantly changing environmental laws and regulations adopted by federal, state and local governmental authorities, including in the U.S. and in Australia. New laws or regulations, or changes to current requirements, could have a material adverse effect on our business. We will continue to be subject to uncertainty associated with new regulatory interpretations and inconsistent interpretations between state and federal agencies. We would face significant liabilities to the government or other third parties for discharges of oil, natural gas, produced water or other pollutants into the air, soil or water, and we would have to spend substantial amounts on investigations, litigation and remediation if such a spill were to occur. We cannot be sure that existing environmental laws or regulations, as currently interpreted or enforced, or as they may be interpreted, enforced or altered in the future, will not have a material adverse effect on our results of operations and financial condition.

Risks Related to Our Common Stock

Our stock price and trading volume may be volatile, which could result in losses for our stockholders.

The equity trading markets may experience periods of volatility, which could result in highly variable and unpredictable pricing of equity securities. The market price of our common stock could change in ways that may or may not be related to our business, our industry or our operating performance and financial condition. In addition, the trading volume in our common stock may fluctuate and cause significant price fluctuations. Some of the factors that could negatively affect our share price or result in fluctuations in the price or trading volume of our common stock include:

·	actual or anticipated quarterly variations in our operating results;

·	changes in expectations as to our future financial performance or changes in financial estimates, if any, of public market analysts;

·	announcements relating to our business or the business of our competitors;

·	conditions generally affecting the oil and natural gas industry;

·	the success of our operating strategy; and

·	the operating and stock price performance of other comparable companies.

As a result of these factors, it is possible that the market price of our common stock will fluctuate or decline significantly in the future. In addition, many brokerage firms may not effect transactions and may not deal with low priced securities as it may not be economical for them to do so. This could have an adverse effect on developing and sustaining a market for our securities. In addition, an investor may be unable to use our securities as collateral.

Our common stock may not meet the criteria necessary to qualify for listing on one or more particular stock exchanges on which we seek or desire a listing. Even if our common stock does meet the criteria, it is possible that our common stock will not be accepted for listing on any of these exchanges.

Our common stock may be thinly traded, and therefore, an investor may not be able to easily liquidate his or her investment.

Although our common stock is currently traded on the OTC Bulletin Board, at any time, it may be thinly traded. To the extent that is true, an investor may not be able to liquidate his or her investment without a significant decrease in price, or at all.

Raising additional capital would dilute existing stockholders.

In order to pursue our business plans, we will need to continue to raise additional capital. If we obtain additional funding through the sale of common stock, the funding would dilute the equity ownership of existing stockholders.

We have not and do not anticipate paying dividends on our common stock.

We have not paid cash dividends to date with respect to our common stock. We do not anticipate paying dividends on our common stock in the foreseeable future since we will use all of our available cash to finance exploration and development of our properties. We are authorized to issue preferred stock and may pay dividends on our preferred stock issued in the future.

USE OF PROCEEDS

We will not receive any of the proceeds from the selling stockholders of shares of our common stock. However, we may receive the sale price of any common stock we sell to the selling stockholders upon exercise of the warrants. We expect to use the proceeds received from the exercise of warrants, if any, for general working capital purposes including the ongoing development and operations of the Company.

MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Market Information

Our common stock commenced trading on the OTC bulletin board on April 20, 2005, under the symbol “DGEO,” and has been trading under the symbol “PHUN” since August 21, 2006. The following table sets forth the high and low bid prices per share of our common stock, as reported on the OTC bulletin board for the periods indicated. The following prices reflect inter-dealer prices, without retail mark-up, mark-down or commission, and may not represent actual transactions.

Quarter Ended:	High	Low
December 31, 2005	$1.79	$0.05
March 31, 2006	$3.36	$1.10
June 30, 2006	$4.23	$1.45
September 30, 2006	$2.98	$1.31
December 31, 2006	$2.30	$1.50
March 31, 2007	$1.85	$0.96
June 30, 2007	$1.29	$0.46
September 30, 2007	$0.55	$0.16
December 31, 2007	$0.36	$0.14
March 31, 2008	$0.25	$0.10

On June 27, 2008, the closing bid price for the common stock was $0.20.

Holders and Dividends

We have neither declared nor paid cash dividends on our capital stock and do not anticipate paying cash dividends in the foreseeable future. Our current policy is to retain cash to finance the exploration and development of our properties. Our Board of Directors will determine future declaration and payment of dividends, if any, in accordance with applicable corporate law.

As of June 27, 2008, there were 235 record holders of our common stock.

SELECTED FINANCIAL DATA

STATEMENT OF OPERATIONS DATA

	Six Months Ended March 31, 2008			Six Months Ended March 31, 2007 (restated)			Year Ended September 30, 2007			Year Ended September 30, 2006			From Inception (June 20, 2005) to September 30, 2005			Cumulative from Inception (June 20, 2005) to March 31, 2008
	($ in thousands, except per share amounts)
Total Revenues	$	992		$	1,338		$	2,820		$	36		$	--		$	3,848
Total Operating Expenses	$	6,371		$	20,442		$	45,981		$	18,245		$	2,096		$	72,693
Loss from Operations	$	(5,379	)	$	(19,104	)	$	(43,161	)	$	(18,209	)	$	(2,096	)	$	(68,845	)
Total Other Expense	$	(10,374	)	$	(2,217	)	$	(6,650	)	$	(2,483	)	$	(23	)	$	(19,530	)
Net Loss	$	(15,753	)	$	(21,321	)	$	(49,811	)	$	(20,692	)	$	(2,119	)	$	(88,375	)
Net Loss per Common Share – Basic and Diluted	$	(0.05	)	$	(0.10	)	$	(0.20	)	$	(0.14	)	$	(0.02	)

BALANCE SHEET DATA

	March 31, 2008			September 30, 2007			September 30, 2006		September 30, 2005
	($ in thousands, except per share amounts)
Working (Deficit) Capital	$	(39,773	)	$	(37,865	)	$	1,275	$	8,438
Oil and Gas Properties, Net	$	173,975		$	162,843		$	45,973		7,231
Total Assets	$	181,537		$	182,024		$	59,242	$	8,500
Non-Current Liabilities	$	34,601		$	37,130		$	522	$	--
Stockholders’ Equity (Deficit)	$	105,143		$	100,324		$	48,353	$	(1,196	)

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL

CONDITION AND RESULTS OF OPERATIONS

The following discussion of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and notes appearing elsewhere in this prospectus.

Executive Summary

We are a development stage global oil and gas exploration and production company committed to acquiring and developing primarily unconventional natural gas and oil prospects that we believe have a very high probability of economic success. Since our inception in 2005, our principal business activities have been raising capital through the sale of common stock and convertible notes and acquiring oil and gas properties in the western United States and Australia. Currently, we own property in Colorado, where we have drilled five wells on our Buckskin Mesa property; Australia, where we have drilled one well on our property in the Northern Territory; and in Montana, where we hold a land position in the Bear Creek area. The wells on these properties have not yet commenced oil production. We also have working interests in eight additional wells in Colorado which are operated by EnCana Oil & Gas USA (“EnCana”). In November 2007, we sold 66,000 net acres of land and two wells in Montana and 177,445 net acres of land in Utah and on May 30, 2008, we sold 1,059 net acres of land and 16 wells in the Southern Piceance Basin in Colorado.

We are considered to be a development stage company as defined by Statement of Financial Accounting Standards (“SFAS”) 7, Accounting and Reporting by Development Stage Enterprises, as we have not yet commenced our planned principal operations. A development stage enterprise is one in which planned principal operations have not commenced, or if its operations have commenced, there have been no significant revenue therefrom.

Results of Operations

Six Months Ended March 31, 2008 Compared to Six Months Ended March 31, 2007

Revenues. For the six months ended March 31, 2008, revenues declined $0.3 million to $1.0 million. The decrease in revenue was the result of natural production decline in the wells and to ownership interests in fewer producing wells, slightly offset by increases in commodity prices and a $0.2 million increase in other revenues, which represent revenues from certain services we are providing to Pearl Exploration and Production Ltd. Stemming from the sale of our Heavy Oil Projects effective October 1, 2007.

Lease Operating Expenses. Lease operating expenses declined $0.1 million during the six month period ended March 31, 2008 compared to the same period in the prior year. This decline is due to a decrease in activity year over year with respect to drilling and completions, where in the 2007 period, we were actively working on drilling and completions on certain of our Colorado properties and in the 2008 period, we were not.

General and Administrative. During the six months ended March 31, 2008, general and administrative expenses were $2.3 million or 29% lower than in the same period of 2007. The following table highlights the changes:

	Six months ended
	2008		2007		Change
	($ in thousands)
P Personnel and contract services	$	2,138	$	1,755	$	383
L Legal		392		621		(229	)
StStock-based compensation		1,602		3,617		(2,015	)
TrTravel		73		779		(706	)
OOther		1,485		1,230		255
Total	$	5,690	$	8,002	$	(2,312	)

Overall, the decrease in general and administrative expense from the six months ended March 31, 2007 to the six months ended March 31, 2008, is primarily due to a $2.0 million decrease in stock-based compensation expense, a decrease in travel expense of $0.7 million, offset by an increase of $0.4 million in personnel and contract services expense.

Property Developmental Costs — Related Party. Property development costs of $1.8 million incurred during the six months ended March 31, 2007 relate to development costs we paid to MAB under the Development Agreement (described more fully in the Business section included later in this prospectus). We no longer pay project development costs to MAB as a result of the restructuring of our agreements with MAB effective January 1, 2007.

Impairment of Oil and Gas Properties. Costs capitalized for properties accounted for under the full cost method of accounting are subjected to a ceiling test limitation to the amount of costs included in the cost pool by geographic cost center. Costs of oil and gas properties may not exceed the ceiling, which is an amount equal to the present value, discounted at 10%, of the estimated future net cash flows from proved oil and gas reserves plus the cost, or estimated fair market value, if lower, of unproved properties. Should capitalized costs exceed this ceiling, an impairment is recognized. During the six month period ended March 31, 2007, we recognized an impairment of $9.0 million, representing the excess of capitalized costs over the ceiling, as calculated in accordance with these full cost rules. There was no impairment charge in the six months ended March 31, 2008.

Depreciation, Depletion, Amortization and Accretion. During the six months ended March 31, 2008, depreciation, depletion, amortization and accretion declined $0.8 million. This decrease was driven by an adjustment in the previous year to proved reserves. During the fourth quarter of the prior year, our proved reserves were estimated by an independent reservoir engineer. We estimated that, had those reserves been obtained during previous quarters, depreciation, depletion and amortization would have increased by $1.0 million during the six month period ended March 31, 2007. The effect of this adjustment did not impact on our net loss for the year as the adjustment was ultimately reflected in impairment of oil and gas properties in the consolidated statements of operations.

Interest Expense. Interest expense increased $5.2 million during the six months ended March 31, 2008 compared to the same period in the previous fiscal year. This increase is attributable to two primary factors:

i.	higher interest expense associated with warrants on the Series A 8.5% Convertible Debentures we issued in November 2007. Because these warrants are immediately exercisable, we recorded interest expense associated with the warrants of $3.2 million in the six month period ended March 31, 2008; and

ii.	higher rates due to our default on certain of our borrowing agreements.

Trading Security Losses. In connection with the sale of certain of our properties to Pearl Exploration and Production Ltd (“Pearl”), we received a portion of the total purchase price in Pearl common stock. The value of these shares declined significantly from the date of the transaction until we sold the shares in March 2008. As a result, we recognized losses associated with these securities of $3.0 million during the six month period ended March 31, 2008. We did not have trading securities during the comparable period of the previous year.

Net Loss. Net loss for the six months ended March 31, 2008 was $15.8 million compared to a loss of $21.3 million during the last fiscal year. This $5.5 million change was primarily due to lower impairment, general and administrative and depreciation, depletion, amortization and accretion costs in the current year when compared with the same six months of the previous fiscal year, as described above. These factors were partially offset by higher interest expense.

Net loss per common share. For the six months ended March 31, 2008, net loss per common share was ($0.05) per share compared to a net loss of ($0.10) per share in the same period of the previous year. This change was driven by a lower net loss, as described above, and a higher share base primarily due to the issuance of common stock associated with certain of our debt agreements, amendments of certain agreements with MAB, and the issuance of Series A 8.5% convertible debentures.

Year Ended September 30, 2007 Compared to Year Ended September 30, 2006

Revenues. Our initial revenues were generated during 2006 in the amount of $35,656. The 2006 revenues were results of initial testing and production of four natural gas wells in the Piceance Basin of Colorado. Revenues increased to $2.8 million for the 2007 fiscal year. The increase is related to our earning revenue from our interest in 27 operating wells, operated by a third party, in the Piceance Basin of Colorado. In 2007, these 27 producing wells produced and sold approximately 457,000 Mcf of natural gas and 137 Bbls of oil. In 2006, we had four testing wells that sold 5,822 Mcf of natural gas. Average prices received for gas sold has increased to $6.16 per Mcf in 2007 from $6.12 per Mcf in 2006 as a result of market conditions.

Lease Operating Expenses. For 2007, lease operating expenses increased to $0.8 million compared to $3,672 in 2006. This is a result of the fact that we had only performed testing on the four wells that we earned revenue from in 2006 while those same wells were operating for the full year during 2007, plus there were an additional 23 wells operating during 2007.

General and Administrative. During 2007, general and administrative expenses increased by $4.4 million or 33% as compared to 2006. The following table highlights the areas with the most significant increases:

	Year Ended September 30,
	2007		2006		Change
	($ in thousands)
Payroll	$	2,346	$	846	$	1,500
Consulting fees		2,887		1,292		1,595
Stock-based compensation expense		8,172		9,189		(1,017	)
Legal		1,419		550		869
Travel		1,193		759		434
Investor relations		709		553		156
IT maintenance and support		205		13		192
Total	$	16,931	$	13,202	$	3,729

The increase in general and administrative expenses in 2007 is a result of commencing operations and hiring full-time employees in June 2006.

Project Developmental Costs — Related Party. Property costs incurred to MAB were $1.8 million during 2007, as compared to $4.5 million in 2006, a decrease of $2.7 million or 60%. These costs decreased as a result of the restructure of our agreements with MAB, which was effective January 1, 2007.

Impairment of Oil and Gas Properties. Costs capitalized for properties accounted for under the full cost method of accounting are subjected to a ceiling test limitation as described previously. Should capitalized costs in the full cost pool exceed the limitations under the ceiling test, an impairment is recognized. During 2007, we recorded an impairment expense in the amount of $24.1 million, representing the excess of capitalized costs over the ceiling, as calculated in accordance with these full cost rules. The impairment in 2007 was primarily caused by an increase to the cost pool in the amount of $94.5 million, most of which was related to the fair value of the shares given up to MAB to increase our interest in several properties and as a result of the Consulting Agreement and amendments thereto (see the Business section of this prospectus for a more thorough description of the Consulting Agreement and other significant transactions with MAB). In accordance with accounting rules, the shares were valued at market price on the date of issuance, which was $1.62 per share.

Depreciation, Depletion, Amortization and Accretion. Depreciation, depletion, amortization and accretion expense (“DD&A”) was $1.2 million in 2007 compared to $0.1 million in 2006. The increase is primarily a result of a higher amortization base in 2007.

Interest Expense. During 2007, interest expense was $6.7 million compared to $2.5 million during 2006. During 2007, interest expense included $3.4 million of costs paid to extend the Maralex Agreement (described more thoroughly in the Properties section of this prospectus) and $1.0 million of amortization of discount and deferred financing costs on the credit facilities entered into during that year. We expect that interest expense will increase for

the fiscal year ending September 30, 2008 when compared to the fiscal year ended September 30, 2007 due to the borrowings under credit facilities we entered into in January and May 2007 and other borrowings that have or may occur.

Net Loss. During 2007, we incurred a net loss of $49.8 million compared to a net loss of $20.7 million during 2006.

Year Ended September 30, 2006 Compared to Year Ended September 30, 2005

Lease Operating Expenses. During 2006, lease operating expenses were $3,672. During 2005, we had no operating wells and therefore incurred no lease operating expenses.

General and Administrative. During 2006, general and administrative expenses increased by $12.4 million compared to 2005. The following table highlights the areas with the most significant increases:

	Year Ended September 30,
	2006		2005		Change
	($ in thousands)
Payroll	$	846	$	--	$	846
Consulting fees		1,292		287		1,005
Stock-based compensation expense		9,189		822		8,367
Legal		550		29		521
Travel		759		15		744
Investor relations		553		--		553
Total	$	13,189	$	1,153	$	12,036

Increases in all general and administrative costs from 2006 to 2005 were a result of commencing operations in 2006 and hiring employees in June 2006. Also during 2005, we had no employees or operations and our primary focus was to raise capital and acquire property.

Project Development Costs — Related Party. Property costs incurred to MAB were $4.5 million during 2006, as compared to $0.9 million in 2005. These costs increased as a result of the various EDAs entered into during 2006 that committed us to pay monthly project development costs to MAB. (See the Business section of this prospectus for a more thorough description of the MAB agreements and transactions.)

Depreciation, Depletion, Amortization and Accretion. DD&A expense was $0.1 million in 2006. We recorded no DD&A expense during 2005 because we had no oil and gas properties that were subject to amortization.

Interest Expense. During 2006, interest expense was $2.5 million, as compared to $23,029 during 2005. During 2006, interest expense included expense related to the issuance of convertible notes.

Net Loss. During 2006, we incurred a net loss of $20.7 million as compared to a net loss of $2.1 million during 2005.

Going Concern

liens and foreclosure actions filed by vendors, some of whom have begun foreclosure proceedings, and have significant capital expenditure commitments. Our ability to establish ourselves as a going concern is dependent upon our ability to obtain additional funding in order to finance our planned operations.

Schedule of Contractual Commitments

The following table summarizes our obligations and commitments to make future payments under our notes payable, operating leases, employment contracts, consulting agreements and service contracts for the periods specified as of September 30, 2007:

	Payments Due by Period
Contractual Obligations	Total		Less Than 1 Year		1-3 Years		3-5 Years		More than 5 Years
	($ in thousands)
Related party notes	$	12,805	$	11,366	$	1,439	$	--	$	--
Long-term borrowings		31,800		3,870		27,930		--		--
Office leases		1,039		205		634		200		--
Short-term borrowings		4,667		4,667		--		--		--
Drilling commitments		120,450		94,075		20,075		--		6,300
Seismic activity		2,000		2,000		--		--		--
Total	$	172,761	$	116,183	$	50,078	$	200	$	6,300

Plan of Operation

Colorado. We expect that the development of our Colorado properties will include the following activities: (i) the tie-in of two wells drilled, cased and completed to date and the completion and tie-in of three wells drilled and cased to date in our Buckskin Mesa Prospect (four wells drilled and cased during fiscal year 2007; one well drilled and cased during the first quarter ended December 31, 2007; and two of the five drilled wells completed during the second quarter ended March 31, 2008); (ii) the drilling of a minimum of 13 commitment wells in our greater than 20,000 net acre Buckskin Mesa Prospect leasehold block surrounding the discovery wells for the Powell Park Field near Meeker, Colorado in the northern Piceance Basin; and (iii) the recompletion and tie-in of the six shut-in gas wells in the Powell Park Field acquired by us from a third party operator.

We anticipate that the following costs associated with the development of the Colorado assets will be incurred:

$40.0 million to $50.0 million in connection with the Piceance II Project, to include expenditures for seismic data acquisition, lease and asset acquisition, drilling, completion, lease operation, and installation of production facilities subject to the Laramie transaction referenced below in “Business”.

·	$41.0 million to $60.0 million in connection with the Buckskin Mesa Project, to include expenditures for seismic data acquisition, lease and asset acquisition, drilling, completion, lease operation, and installation of production facilities.

We are currently attempting to rationalize the Colorado asset base to raise capital and reduce our working interest and the associated development costs attributable to such retained interest.

Australia. We plan to explore and develop portions of our 7.0 million net acre position in the Beetaloo Basin project area located in northwestern Australia. During calendar year 2008, we plan to drill five wells in the exploration permit blocks. We anticipate that costs related to seismic acquisition, development of operational infrastructure, and the drilling and completion of wells over the next twelve months will range from $22.0 million to $30.0 million. As a means of reducing this exposure, selected portions of the project portfolio will be made available for farm-out to industry for cash and payment of expenses related to drilling and completion of one or more wells in each prospect.

Liquidity and Capital Resources

We have grown rapidly since our inception. At September 30, 2005, we had been operating for only a few months, had no employees, and had acquired an interest in two properties, West Rozel and Buckskin Mesa, aggregating approximately 12,400 net mineral acres. From 2006 to 2008, we added employees and acquired interests in additional properties. At March 2007, we had 16 full time employees and at March 2008 we grew to 15 full-time employees and 11 consultants. We had interests in properties aggregating approximately 21,700 net acres in Colorado and 7.0 million net acres in Australia at March 31, 2007 and grew to an aggregate of approximately 21,700 net acres in Colorado, 16,000 net acres in Montana, and 7.0 million net acres in Australia as of March 31, 2008.

Our initial plan for 2007 was to raise capital to fund the exploration and development of our acquired properties and we were successful at raising $35.5 million through borrowings, common stock issuances and subscriptions. We drilled (or participated in the drilling of) 39 gross wells, and completed (or participated in the completion of) 21 gross wells. During the third and fourth quarters of 2007, we revised our plan to (i) sell non-core assets to allow us to focus our exploration and development efforts in two primary areas: the Piceance Basin in Colorado and Australia, and (ii) to improve the economics of our projects by restructuring the Development Agreement with MAB. Accordingly, during the six months ended March 31, 2008, we sold our heavy oil assets and restructured the Development Agreement with MAB through amendments.

Working Capital. Our working capital is impacted by various business and financial factors, including, but not limited to: changes in the prices of oil and gas, the timing of operating cash receipts and disbursements, borrowings and repayments of debt, additions to oil and gas properties and increases and decreases in other non-current assets, along with other business factors that affect our net income and cash flows.

As of March 31, 2008, we had a working capital deficit of $39.8 million and cash of $1.6 million. As of September 30, 2007, we had a working capital deficit of $37.9 million and cash of $0.1 million. As of September 30, 2006, we had working capital of $1.3 million and cash of $10.6 million. The changes in working capital are primarily attributable to the factors described above. We expect that our future working capital will continue to be affected by these same factors.

In November 2007, we raised approximately $7.0 million through the sale of convertible debentures and $0.8 million through the pledge of our investment in Pearl shares. During the remainder of fiscal year 2008, we have sold working interests in some of our properties and we may complete additional private placements of debt or equity to raise cash to meet our working capital needs. A significant amount of capital is needed to fund our proposed drilling program for 2008. See “Plan of Operation” above.

Cash Flow. Net cash used in or provided by operating, investing and financing activities for the six months ended March 31, 2008 and 2007 and for the years ended September 30, 2007 and 2006 were as follows:

	Six months ended March 31,						Year ended September 30,
	2008			2007			2007			2006
	($ in thousands)
Net cash used in operating activities	$	(6,420	)	$	(6,712	)	$	(10,326	)	$	(10,546	)
Net cash provided by (used in) investing activities	$	4,753		$	(17,291	)	$	(35,666	)	$	(32,692	)
Net cash provided by financing activities	$	3,152		$	15,073		$	35,483		$	52,620

Net Cash Used in Operating Activities. The changes in net cash used in operating activities are attributable to our net income adjusted for non-cash charges as presented in the consolidated statements of cash flows and changes in working capital as discussed above.

Net Cash Provided by (Used in) Investing Activities. Net cash provided by investing activities for the six months ended March 31, 2008 was primarily from cash received for the sale of oil and gas properties of $7.5 million and the sale of trading securities of $2.5 million offset by cash used for additions to oil and gas properties of $5.3 million. Net cash used in investing activities for the six months ended March 31, 2007 was primarily used for joint interest

billings in the amount of $10.6 million, additions to oil and gas properties in the amount of $4.0 million and deposits on oil and gas property acquisitions of $2.2 million.

Net cash used in investing activities for the year ended September 30, 2007 was primarily used for: (1) additions to oil and gas properties of $33.0 million, and (2) a $2.0 million earnest money deposit related to the proposed purchase of the Powder River basin assets that became a note receivable. Net cash used in investing activities for the year ended September 30, 2006 was primarily used for additions to oil and gas properties.

Net Cash Provided by Financing Activities. Net cash provided by financing activities for the six months ended March 31, 2008 was primarily comprised of borrowings of $9.7 million, net of repayments of debt in the amount of $6.1 million, and payment of financing costs in the amount of $0.4 million. Net cash provided by financing activities for the six months ended March 31, 2007 was comprised of proceeds from promissory notes sold under a Credit and Security Agreement of $12.5 million and proceeds from the sale of units in our private placement shares for gross proceeds of $3.1 million. This was partially offset by payments on contracts payable of $0.5 million.

Net cash provided financing activities for the year ended September 30, 2007 was primarily comprised of borrowings of $32.3 million and the issuance of common stock subscriptions and common stock for $3.2 million. Net cash provided by financing activities for the year ended September 30, 2006 was comprised of the issuance of common stock and warrants of $36.4 million and the issuance of convertible notes of $17.8 million, offset by offering and financing costs of $1.6 million.

Capital Requirements. We currently anticipate our capital budget for the year ending September 30, 2008 to be approximately $42 million. Uses of cash for 2008 will be primarily for our drilling program in the Piceance Basin and in Australia. The following table summarizes our drilling commitments for fiscal year 2008:

Activity	Prospect	Aggregate Total Cost		Our Working Interest			Our Share (a)
		($ in thousands)
Drill and complete eight wells	Buckskin Mesa	$	24,000		100	%	$	24,000
Drill five wells	Beetaloo		20,000		100	%		20,000	(b)
Total		$	44,000				$	44,000

______________

(a)	We intend to sell portions of our working interest to third parties and farm-out additional portions for cash and the agreement of the assignee to pay a portion of our development costs.

(b)	Our commitment in Australia is to have five wells drilled on the various permits by December 31, 2008.

Financing. During the six months ended March 31, 2008 and the fiscal year 2007, we entered into different short and long-term financing arrangements as follows:

(1) On November 13, 2007, we completed the sale of Series A 8.5% Convertible Debentures in the aggregate principal amount of $7.0 million. The debentures are due November 2012, are convertible at any time by the holders into shares of our common stock at a price of $0.15 per share and are collateralized by shares in our Australian subsidiary. Interest accrues at an annual rate of 8.5% and is payable in cash or in shares (at our option) quarterly, beginning January 1, 2008.

Debenture holders also received five-year warrants that allow them to purchase a total of 46.4 million shares of common stock at prices ranging from $0.24 to $0.27 per share. In connection with the placement of the debentures, we paid a placement fee of $0.3 million and issued placement agent warrants entitling the holders to purchase an aggregate of 0.2 million shares at $0.35 per share for a period of five years.

We originally agreed to file a registration statement with the SEC in order to register the resale of the shares issuable upon conversion of the debentures and the shares issuable upon exercise of the warrants. According to the Registration Rights Agreement, the registration statement was to be filed by March 4, 2008 and declared effective by July 2, 2008. The following penalties apply if filing deadlines and/or documentation requirements are not met in compliance with the stated rules: (i) we shall pay to each holder of Registrable Securities 1% of the purchase price paid in cash as partial liquidated damages; (ii) the maximum aggregate liquidated damages payable is 18% of the

aggregate subscription amount paid by the holder; (iii) if we fail to pay liquidated damages in full within seven days of the date payable, we will pay interest of 18% per annum, accruing daily from the original due date; (iv) partial liquidated damages apply on a daily prorated basis for any portion of a month prior to the cure of an event; and (v) all fees and expenses associated with compliance to the agreement shall be incurred by us.

A waiver and amendment agreement relating to the above Registration Rights Agreement was signed by all investors on or before May 8, 2008. The agreement is an extension of filing date and effectiveness date to June 30, 2008 and December 31, 2008, respectively. Each purchaser waived i) our obligation to file a registration statement covering the Registrable Securities by March 4, 2008; ii) our obligation to have such registration statement declared effective by July 2, 2008, and iii) any penalties associated with the failure to satisfy such obligations as described above. In addition, each purchaser waived as events of default our failure to pay the January 1, 2008 and April 1, 2008 interest payments. As consideration for this waiver, we agreed to pay the interest installments due January 1, 2008 and April 1, 2008 by September 30, 2008, together with late fees of 18% per annum. In addition, warrants to purchase our common stock will be issued in an amount equal to 4% of the shares each purchaser received with the original agreement. The terms of these warrants mirror the terms given in the original agreement.

Provided that there is an effective registration statement covering the shares underlying the debentures and the volume-weighted-average price of our common stock over 20 consecutive trading days is at least 200% of the per share conversion price, with a minimum average trading volume of 0.3 million shares per day: (i) the debentures are convertible, at our option and (ii) are redeemable at our option at 120% of face value at any time after one year from date of issuance.

The debenture agreement contains anti-dilution protections for the investors to allow a downward adjustment to the conversion price of the debentures in the event that we sell or issue shares at a price less than the conversion price of the debentures.

Proceeds were used to fund working capital needs.

(2) On December 18, 2007, we obtained a loan from a third party in the amount of $0.8 million. The loan is secured by the shares that we received as partial consideration for the sale of our Heavy Oil assets, bears interest at 15% per annum and matures on January 18, 2008. Funds were used to fund working capital needs. This loan was paid in full in March 2008.

(3) During fiscal year 2007, we borrowed $0.5 million from Global. The note was unsecured and bore interest at 7.75% per annum. The funds were used primarily to fund working capital needs. We paid this note in full in November 2007.

(4) We entered into a note with MAB in the amount of $13.5 million as a result of the Consulting Agreement with MAB; however, no cash was actually received. During the six months ended March 31, 2008, the note was reduced by further amendments to the Consulting Agreement (the First, Second and Third Amendments) and as a result, we paid $0.3 million in cash towards repayment of this note. At March 31, 2008, the balance of this note was $1.3 million. The note is unsecured and bears interest at the London InterBank Offered Rate, (“LIBOR”). Although at March 31, 2008, we were in default on this note, MAB has waived and released us from defaults, failures to perform and any other failures to meet our obligations through October 1, 2008.

(5) We entered into six separate loans with the Bruner Family Trust, UTD March 28, 2005 for a total of $3.0 million. The long-term note bears interest at 8% and is due in full at the time when the January and May Credit Facilities have been paid in full (described below). A portion of one of these notes was assigned to a director of the company who then invested in our convertible debenture offering in November 2007. At March 31, 2008, the balance of these notes is $0.1 million. The short-term notes bear interest at LIBOR + 3% and are due 12 months from issue date.

(6) We entered into a $15.0 million credit facility in January 2007, with Global (the “January 2007 Credit Facility”). The January 2007 Credit Facility is secured by certain oil and gas properties and other assets of ours. It bears interest at prime plus 6.75% and is due to be paid in full in July 2009. We pay an advance fee of 2% on all amounts borrowed under the facility. We may prepay the balance without penalty. We are currently in default on interest

payments and not in compliance with the covenants. Global has waived all defaults that have occurred or that might occur in the future until October 2008, at which time all defaults must be cured. We have drawn the total $15.0 million available to us under this facility. The funds were used to fund working capital needs.

(7) We entered into a $60.0 million credit facility with Global in May 2007 (the “May 2007 Credit Facility”). The May 2007 Credit Facility is secured by the same certain oil and gas properties and other assets as the January 2007 Credit Facility. The May 2007 Credit Facility bears interest at prime plus 6.75% and is due to be paid in full in November 2009. We pay an advance fee of 2% on all amounts borrowed under the facility. We may prepay the balance without penalty. We are currently in default on interest payments and not in compliance with the covenants. Global has waived all defaults that have occurred or that might occur in the future until October 2008. At March 31, 2008 we had $42.2 million remaining available to us from the credit facility. The funds borrowed were used to fund our working capital needs.

Pursuant to (4) and (5) above Global received warrants to purchase an aggregate of 4.0 million shares of our common stock for the execution of the January 2007 Credit Facility, the May 2007 Credit Facility and the “most favored nation” letter to Global. In addition, an aggregate of 0.4 million warrants were issued for each $1.0 million advanced under each credit facility, resulting in a total of 17.1 million warrants issued related to advances on the credit facilities through March 31, 2008. The warrants are exercisable until second and third quarters of 2012. The exercise price of the warrants is equal to 120% of the weighted-average price of our common stock for the 30 days immediately prior to each warrant issuance date.

Prior to merger with GSL in May 2006, Digital entered into five separate loan agreements, aggregating $0.4 million, due one year from issuance, commencing October 11, 2006. The loans bear interest at 12% per annum, are unsecured, and are convertible, at the option of the lender, at any time during the term of the loan or upon maturity, at a price per share equal to the closing price of our common stock on the OTC Bulletin Board on the day preceding notice from the lender of its intent to convert the loan. As of January 10, 2007, we were in default on payment of the notes and we are currently in discussions with the holders to convert the notes and accrued interest into our common stock.

Other Cash Sources. On November 6, 2007, we sold our Heavy Oil assets. The cash proceeds of $7.5 million were used to fund working capital needs.

The continuation and future development of our business will require substantial additional capital expenditures. Meeting capital expenditure, operational and administrative needs for the period ending September 30, 2008 will depend on our success in farming out or selling portions of working interests in our properties for cash and/or funding of our share of development expenses, the availability of debt or equity financing, and the results of our activities. To limit capital expenditures, we may form industry alliances and exchange an appropriate portion of our interest for cash and/or a carried interest in our exploration projects using farm-out arrangements. We may need to raise additional funds to cover capital expenditures. These funds may come from cash flow, equity or debt financings, a credit facility, or sales of interests in our properties, although there is no assurance additional funding will be available or that it will be available on satisfactory terms. If we are unable to raise capital through the methods discussed above, our ability to execute our development plans will be greatly impaired. See the Going Concern section above.

Development Stage Company. We had not commenced principal operations or earned significant revenue as of March 31, 2008, and we are considered a development stage entity for financial reporting purposes. During the period from inception to March 31, 2008, we incurred a cumulative net loss of $88.4 million. We have raised approximately $102.4 million through borrowing and the sale of convertible notes and common stock from inception through March 31, 2008. In order to fund our planned exploration and development of oil and gas properties, we will require significant additional funding.

Off-Balance Sheet Arrangements

We do not have off-balance sheet arrangements.

Critical Accounting Policies and Estimates

We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our financial statements.

Oil and Gas Properties. We utilize the full cost method of accounting for oil and gas activities. Under this method, subject to a limitation based on estimated value, all costs associated with property acquisition, exploration and development, including costs of unsuccessful exploration, are capitalized within a cost center on a by-country basis. No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas properties unless the sale represents a significant portion of oil and gas properties and the gain significantly alters the relationship between capitalized costs and proved oil and gas reserves of the cost center. Depreciation, depletion and amortization of oil and gas properties is computed on the units-of-production method based on proved reserves. Amortizable costs include estimates of future development costs of proved undeveloped reserves.

Capitalized costs of oil and gas properties may not exceed an amount equal to the present value, discounted at 10%, of the estimated future net cash flows from proved oil and gas reserves plus the cost, or estimated fair market value, if lower, of unproved properties. Should capitalized costs exceed this ceiling, an impairment is recognized. The present value of estimated future net cash flows is computed by applying year end prices of oil and natural gas to estimated future production of proved oil and gas reserves as of year end, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions.

Asset Retirement Obligation. Asset retirement obligations associated with tangible long-lived assets are accounted for in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations. The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of oil and gas properties is recorded generally upon acquisition or completion of a well. The net estimated costs are discounted to present values using a risk-adjusted rate over the estimated economic life of the oil and gas properties. Such costs are capitalized as part of the related asset. The asset is depleted on the units-of-production method on a field-by-field basis. The liability is periodically adjusted to reflect (1) new liabilities incurred, (2) liabilities settled during the period, (3) accretion expense, and (4) revisions to estimated future cash flow requirements. The accretion expense is recorded as a component of depreciation, depletion, amortization, and accretion expense in the accompanying consolidated statements of operations.

Share Based Compensation. Effective October 1, 2006, we adopted the provisions of SFAS No. 123(R) (As Amended), Share-Based Payment (“SFAS 123(R)”). SFAS No. 123(R) revises SFAS No. 123, Accounting for Stock-Based Compensation (“SFAS 123”), and supersedes Accounting Principles Board (“APB”) Opinion 25, Accounting for Stock Issued to Employees and related interpretations (“APB 25”). SFAS 123(R) establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods and services at fair value, focusing primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. It also addresses transactions in which an entity incurs liabilities in exchange for goods and services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those equity instruments. Prior to October 1, 2006, we accounted for stock-based compensation using the intrinsic value recognition and measurement principles detailed in APB 25. Stock-based compensation awarded to non-employees is accounted for under the provisions of EITF 96-18, Accounting for Equity Instruments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling, Goods or Services.

Under the fair value recognition provisions of SFAS 123(R), stock-based compensation cost is measured at the grant date based on the fair value of the award and is recognized as expense over the service period, which generally represents the vesting period. The following table illustrates the pro-forma effect on net loss per share if compensation cost had been determined based upon the fair value at the grant dates in accordance with SFAS 123(R):

	Year Ended September 30,
	2006			2005
	($ in thousands)
Net loss as reported	$	(20,692	)	$	(2,119	)
Add stock-based compensation included in reported loss		9,189			823
Deduct stock-based compensation expense determined under fair value method		(9,189	)		(1,202	)
Pro-forma net loss	$	(20,692	)	$	(2,498	)
Net loss per share:
As reported	$	(0.14	)	$	(0.02	)
Pro-forma	$	(0.14	)	$	(0.02	)

Impairment. SFAS No. 144, Accounting for the Impairment and Disposal of Long-Lived Assets (“SFAS 144”), requires long-lived assets to be held and used to be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. We use the full cost method of accounting for our oil and gas properties. Properties accounted for using the full cost method of accounting are excluded from the impairment testing requirements under SFAS 144. Properties accounted for under the full cost method of accounting are subject to SEC Regulation S-X Rule 4-10, Financial Accounting and Reporting for Oil and Gas Producing Activities Pursuant to the Federal Securities Laws and the Energy Policy and Conversion Act of 1975 (“Rule 4-10”). Rule 4-10 requires that each regional cost center’s (by country) capitalized costs, less accumulated amortization and related deferred income taxes not exceed a cost center “ceiling”. The ceiling is defined as the sum of:

the present value of estimated future net revenues computed by applying current prices of oil and gas reserves to estimated future production of proved oil and gas reserves as of the balance sheet date less estimated future expenditures to be incurred in developing and producing those proved reserves to be computed using a discount factor of 10%; plus

·	the cost of properties not being amortized; plus

·	the lower of cost or estimated fair value of unproven properties included in the costs being amortized; less

·	income tax effects related to differences between the book and tax basis of the properties.

If unamortized costs capitalized within a cost center, less related deferred income taxes, exceed the cost center ceiling, the excess is charged to expense. During the period ended September 30, 2007, $24.1 million was charged to impairment expense. During the periods ended September 30, 2006 and 2005, there was no impairment charged to expense.

Recently Issued Accounting Pronouncements

In February 2007, the Financial Accounting Standards Board (“FASB”), issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS 159”), which allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value that are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item’s fair value in subsequent reporting periods must be recognized in current earnings. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparison between entities that elect different measurement attributes for similar assets and liabilities. SFAS 159 will be effective for us on October 1, 2008. We have not assessed the impact of SFAS 159 on our consolidated results of operations, cash flows or financial position.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS 157”), which provides guidance for using fair value to measure assets and liabilities. The standard also responds to investors’ requests for more information about: (1) the extent to which companies measure assets and liabilities at fair value; (2) the information used to measure fair value; and (3) the effect that fair value measurements have on earnings. SFAS 157 will apply whenever another standard requires (or permits) assets or liabilities to be measured at fair value. SFAS 157 does not expand the use of fair value to any new circumstances. SFAS 157 will be effective for us on

October 1, 2008. We have not assessed the impact of SFAS 157 on our consolidated results of operations, cash flows or financial position.

In July 2006, the FASB issued Interpretation (“FIN”) No. 48, Accounting for Uncertainty in Income Taxes (“FIN 48”), which clarifies the accounting for uncertainty in income taxes recognized in financial statements in accordance with SFAS No. 109, Accounting for Income Taxes. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 will be effective for us on October 1, 2007. We have not assessed the impact FIN 48 on our consolidated results of operations, cash flows or financial position.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Because of our relatively low level of current oil and gas production, we are not exposed to a great degree of market risk relating to the pricing applicable to our oil and natural gas production. However, our ability to raise additional capital at attractive pricing, our future revenues from oil and gas operations, our future profitability and future rate of growth all depend substantially upon the market prices of oil and natural gas, which fluctuate considerably. We expect commodity price volatility to continue. We do not currently utilize hedging contracts to protect against commodity price risk. As our oil and gas production grows, we may manage our exposure to oil and natural gas price declines by entering into oil and natural gas price hedging arrangements to secure a price for a portion of our expected future oil and natural gas production.

Foreign Currency Exchange Rate Risk

We conduct business in Australia and are subject to exchange rate risk on cash flows related to sales, expenses, financing and investment transactions. We do not currently utilize hedging contracts to protect against exchange rate risk. As our foreign oil and gas production grows, we may utilize currency exchange contracts, commodity forwards, swaps or futures contracts to manage our exposure to foreign currency exchange rate risks.

Interest Rate Risk

Interest rates on future credit facility draws and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. This could limit our ability to raise funds in debt capital markets.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

On August 21, 2006, our Board of Directors approved 1) the termination of Telford Sadovnick, P.L.L.C. (“Telford”) as our independent accountants and 2) the appointment of Hein & Associates LLP (“Hein”) to serve as our independent accountants for the year ending September 30, 2006. The change was effective August 21, 2006.

Telford’s reports on our financial statements for each of the years ended March 31, 2006 and 2005 did not contain, with the exception of a going concern disclaimer in each such report, an adverse opinion or disclaimer of opinion, nor were such reports qualified or modified as to uncertainty, audit scope, or accounting principles.

During the years ended March 31, 2006 and 2005, and the period ended August 21, 2006, there were no disagreements with Telford on any matter of accounting principle or practice, financial statement disclosure, or auditing scope or procedure which, if not resolved to Telford’s satisfaction, would have caused them to make reference to the subject matter of the disagreement in connection with the audit reports on our financial statements for such years; and there were no events as set forth in Item 304(a)(1)(iv) of Regulation S-B.

We provided Telford with a copy of the foregoing disclosures. We filed as an exhibit to a report on Form 8-K a letter from Telford relating to the disclosure included in the Form 8-K.

During the years ended March 31, 2006 and 2005 and through August 21, 2006, we did not consult Hein with respect to the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on our consolidated financial statements, or on any other matters or reportable events as set forth in Items 304(a)(2)(i) and (ii) of Regulation S-B. Hein was the independent accountants for our subsidiary, PetroHunter Operating Company from its inception (June 2005) until we acquired substantially all of its outstanding common stock (May 12, 2006).

On January 29, 2008, Hein informed the Audit Committee of our Board of Directors (“Audit Committee”) that they were resigning as our independent registered public accounting firm. The decision to change accountants was approved by the Audit Committee on January 31, 2008. The reports of Hein on the consolidated financial statements for the two most recent fiscal years ended September 30, 2007 and 2006, did not contain an adverse opinion or disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope, or accounting principles, except that the audit reports for both years contained an explanatory paragraph regarding our ability to continue as a going concern.

The report of Hein to the Audit Committee and our management addressing management’s assessment of the effectiveness of internal control over financial reporting and the effectiveness of internal control over financial reporting as of September 30, 2007 indicates that we did not maintain effective internal control over financial reporting as of September 30, 2007 due to the effect of the following material weaknesses:

1.	We did not have an adequate process for monitoring accounting and financial reporting and had not conducted a comprehensive review of the account balances and transactions that had occurred during the year. However, we did conduct such a review prior to filing of the Form 10-K.

2.	We did not have sufficient controls to ensure that the accounting department would receive or review material documents, or to ensure that the accounting department would receive or review material information on a timely basis.

In connection with the interim review of the June 30, 2007 financial statements, Hein advised us that we did not have effective internal control over financial reporting due to the effect of the following material weaknesses:

We did not have sufficient controls to ensure that our accounting department would receive or review material documents, or to ensure that the accounting department would receive or review material information on a timely basis. There was not an effective system in place to ensure that those responsible for financial reporting received copies of Board minutes which reflected the issuance of common shares of stock. In addition, our accounting department did not have adequate staffing to provide timely financial information

In connection with the audit of the September 30, 2006 financial statements, Hein advised us that we did not have effective internal control over financial reporting due to the effect of the following material weakness:

Our staffing for the period under audit and record keeping was not adequate to ensure an effective internal control structure as evidenced by the lack of recording certain equity transactions on a timely basis and delays in providing necessary information to the auditors.

In connection with the interim review of the June 30, 2006 financial statements, Hein advised us that we did not have effective internal control over financial reporting due to the effect of the following material weakness:

Our current staffing is not adequate to ensure an effective internal control structure as evidenced by the overpayment of certain development fees to a related party and the filing of the Form 10-QSB for the three and nine months periods ended June 30, 2006 prior to the completion of the review by our independent registered public accounting firm.

During the fiscal years ended September 30, 2007 and 2006 and through the subsequent interim period ending January 29, 2008, there were no disagreements with Hein on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of Hein, would have caused Hein to make reference thereto in its report on our financial statements for such years. Further, except as described above, there were no other reportable events as described in Item 304(a)(1)(v) of Regulation S-K occurring within our two most recent fiscal years and the subsequent interim period ending January 29, 2008.

We provided Hein with a copy of the foregoing disclosures. We filed as an exhibit to a report on Form 8-K a letter from Hein relating to the disclosure included in the Form 8-K.

On January 31, 2008, the Audit Committee approved the engagement of Gordon, Hughes & Banks, LLP (“GHB”) to serve as our principal accountant to audit our financial statements for the fiscal year ending September 30, 2008 and to perform procedures related to the financial statements to be included in our quarterly reports on Form 10-Q, beginning with and including the quarter ending December 31, 2007. That decision was approved and ratified by our Board of Directors on January 31, 2008.

During our two most recent fiscal years ended September 30, 2007 and 2006, we consulted GHB on the application of the Financial Accounting Standards Board 109, Accounting for Income Taxes and accrued $2,425 in fees related to that consultation.

BUSINESS

Corporate Background

We are a development stage global oil and gas exploration and production company committed to acquiring and developing primarily unconventional natural gas and oil prospects that we believe have a very high probability of economic success. Since our inception in 2005, our principal business activities have been raising capital through the sale of common stock and convertible notes and acquiring oil and gas properties in the western United States and Australia. Currently, we own property in Colorado, where we have drilled five wells on our Buckskin Mesa property, and Australia, where we have drilled one well on our property in the Northern Territory and in Montana, where we hold a land position in the Bear Creek area. The wells on these properties have not yet commenced oil and gas production. We own working interests in eight additional wells in Colorado which are operated by EnCana Oil & Gas USA (“EnCana”) and are currently producing gas. In November 2007, we sold 66,000 net acres of land and two wells in Montana and 177,445 net acres of land in Utah, and in May 2008, we sold 625 net acres of land and 16 wells in the Southern Piceance in Colorado, allowing us to focus on our Buckskin Mesa property and Australia.

Our predecessor, Digital Ecosystems Corp. (“Digital”), was incorporated on February 21, 2002 under the laws of the state of Nevada. On February 10, 2006, Digital entered into a share Exchange Agreement (the “Exchange Agreement”) with GSL Energy Corporation (“GSL”) and certain shareholders of GSL pursuant to which Digital acquired more than 85% of the issued and outstanding shares of common stock of GSL in exchange for shares of Digital’s common stock. The Exchange Agreement was completed on May 12, 2006. At that time, GSL’s business, which was formed in 2005 for the purpose of acquiring, exploring, developing and operating oil and gas properties, became Digital’s business and GSL became a subsidiary of Digital. Since this transaction resulted in the former shareholders of GSL acquiring control of Digital, for financial reporting purposes, the business combination was accounted for as an additional capitalization of Digital (a reverse acquisition with GSL as the accounting acquirer). In accounting for this transaction:

i.	GSL was deemed to be the purchaser and parent company for financial reporting purposes. Accordingly its net assets were included in the consolidated balance sheet at their historical book value; and

ii.	control of the net assets and business of Digital was effective May 12, 2006 for no consideration.

Subsequent to the closing of the Exchange Agreement, Digital acquired all the remaining outstanding stock of GSL, and effective August 14, 2006, Digital changed its name to PetroHunter Energy Corporation (“PetroHunter”). Likewise, in October 2006, GSL changed its name to PetroHunter Operating Company.

PetroHunter is considered a development stage company as defined by Statement of Financial Accounting Standards (“SFAS”) 7, Accounting and Reporting by Development Stage Enterprises, as we have not yet commenced our planned principal operations. A development stage enterprise is one in which planned principal operations have not commenced, or if its operations have commenced, there have been no significant revenue therefrom.

PaleoTechnology

Effective August 31, 2007, PetroHunter sold its interest in Paleo in consideration for a royalty interest in the net revenues derived from the sale of Paleo ‘petro-environment’ products or services, as defined in the Paleo business plan to include: petroleum related applications for enhanced recovery, reclaimed oils, residuum oil supercritical extraction, cleaning, unplugging, breaking oil-water emulsions, oil-sand separation, de-waxing and de-greasing, which Paleo (and/or its subsidiaries, affiliates and successors) develops over a fifteen-year period from August 31, 2007.

Southern Piceance Properties

On May 30, 2008, PetroHunter completed the sale of its working interest in its Southern Piceance properties in Garfield County, Colorado, to Laramie Energy II, LLC. The purchase price was $21 million before various adjustments for title defects, holdbacks and other matters in accordance with the purchase and sale agreement. The proceeds of the sale will be used to pay PetroHunter’s creditors and for working capital.

The properties covered by the sale consist of approximately 625 net acres, including 16 wells which have been drilled, but not completed or connected to a pipeline. An additional 434 net acres may be included in the sale in a subsequent closing between the parties if PetroHunter and a third party lessor are able to enter into an amended lease. PetroHunter retains all of its interest in eight producing wells in Garfield County, which are operated by EnCana Oil & Gas (USA), Inc.

Heavy Oil Assets

Effective October 1, 2007, we, through our wholly-owned subsidiary, PetroHunter Heavy Oil Ltd., completed the sale of its heavy oil assets located in Montana and Utah to Pearl Exploration and Production Ltd. (“Pearl”), a company whose stock is traded on the TSX Venture Exchange. The assets sold included all of our working interest in certain oil and gas leases and related real and personal property interests comprised of heavy oil development projects we refer to as the Fiddler Creek and Promised Land prospects in Montana, and the West Rozel and Gunnison Wedge prospects in Utah. The closing took place on November 6, 2007.

The purchase price was a maximum of $30.0 million, payable as follows: (a) $7.5 million in cash at closing; (b) the issuance of 2.5 million common shares of Pearl equivalent to $10.0 million (based on a price of $4.00 Canadian per share as stipulated in the purchase and sale contract), excluding value attributable to leases on which title is being reviewed after closing, and value attributable to 4,645 net acres of leasehold which were not assigned at closing, pending Pearl’s attempt to renegotiate the terms of a purchase and development agreement with the third party that sold the acreage to PetroHunter; and (c) a performance payment (the “Pearl Performance Payment”) of $12.5 million in cash at such time as either: (i) production from the assets reaches 5,000 barrels per day; or (ii) proven reserves from the assets are greater than 50.0 million barrels of oil as certified by a third party reserve engineer. In the event that these targets have not been achieved by September 30, 2010, Pearl’s obligation to make the Pearl Performance Payment will expire.

The sale of assets to Pearl also resulted in amendments to existing agreements with third parties, including MAB’s relinquishment of all of its rights and obligations, including reassignment of certain reserved overriding royalty interests, in all PetroHunter properties in Utah and Montana, as set forth in the second amendment to the Acquisition and Development Agreement with MAB (the “Second Amendment”) (discussed below), and termination of PetroHunter’s obligation to pay an overriding royalty and a per barrel production payment to American Oil & Gas, Inc. (“American”) and Savannah Exploration, Inc. (“Savannah”), in consideration for: (a) five million common shares of PetroHunter common stock to be issued to American and Savannah; and (b) a contingent obligation to pay a total of $2.0 million to American and Savannah in the event that PetroHunter receives the Pearl Performance Payment.

MAB Resources LLC

We have entered into various agreements with MAB, a company that is controlled by our largest shareholders, Marc A. Bruner, who had an approximate 43% beneficial ownership interest in us at June 27, 2008. The following is a summary of those agreements.

The Development Agreement. From July 1, 2005 through December 31, 2006, we and MAB operated pursuant to a Development Agreement and a series of individual property agreements (collectively, the “EDAs”). The Development Agreement defined MAB’s and our long-term relationship regarding the ownership and operation of all jointly-owned properties and stipulated that we and MAB would sign a joint operating agreement governing all operations. The Development Agreement specified, among other things, that:

i.	MAB and the Company each owned an undivided 50% working interest in all oil and gas leases, production facilities and related assets (collectively, the “Properties”).

ii.	We were named as Operator, and had appointed a related controlled entity, MAB Operating Company LLC, as sub-operator. We and MAB agreed to sign a joint operating agreement, governing all operations.

iii.	Each party was to pay its proportionate share of costs and receive its proportionate share of revenues, subject to us bearing the following burdens:

a.	Each assignment of Properties from MAB to us reserved an overriding royalty equivalent to 3% of 8/8ths (proportionately reduced to 1.5% of our undivided 50% working interest in the Properties) (the “MAB Override”), payable to MAB out of production and sales.

b.	Each EDA provided that we would pay 100% of the cost of acquisitions and operations (“Project Costs”) up to a specified amount, after which time each party shall pay its proportionate 50% share of such costs. The maximum specified amount of Project Costs of which we were to pay 100%, under the Development Agreement for properties acquired in the future, was $100.0 million per project. There was no “before payout” or “after payout” in the traditional sense of a “carried interest” because our obligation to expend the specified amount of Project Costs and MAB’s receipt of its 50% share of revenues applied without regard to whether or not “payout” had occurred. Therefore, our payment of all Project Costs up to such specified amount may have occurred before actual payout, or may have occurred after actual payout, depending on each project and set of Properties.

c.	Under the Development Agreement, we were to pay to MAB monthly project development costs representing a specified portion of MAB’s “carried” Project Costs. The total amount incurred to MAB by us was to be deducted from MAB’s portion of the Project Costs carried by the Company. During 2007, 2006 and 2005, we paid MAB $1.8 million, $4.5 million and $0.9 million, respectively, for Project costs which are classified on the consolidated statements of operations as Property development— related party in the affected periods.

The Consulting Agreement. Effective January 1, 2007, we and MAB began operating under an Acquisition and Consulting Agreement (the “Consulting Agreement”) which replaced in its entirety the Development Agreement described previously. The Consulting Agreement provides as follows:

MAB conveyed to us its entire remaining undivided 50% working interest in all rights and benefits under each EDA, and we assumed our share of all duties and obligations under each individual EDA (such as drilling and development obligations), with respect to said remaining undivided 50% working interest,

ii.	A consulting agreement was agreed upon, including our obligation to pay fees in the amount of $25,000 per month for services rendered to us for which we paid a total of $0.2 million, during the year ended September 30, 2007,

iii.	As a result of MAB’s conveyance of its remaining undivided 50% working interest to us, our working interest in certain oil and gas properties increased from 50% to 100%,

iv.	Our obligation to pay up to $700.0 million in capital costs for MAB’s 50% interest as well as the monthly project cost advances against such capital costs was eliminated,

v.	We became obligated for monthly payments in the amount of $0.2 million under a $13.5 million promissory note,

vi.

MAB’s overriding royalty interest (the “Override”) was increased from 3% to 5%, half of which accrues but is deferred for three years. The Override does not apply to our Piceance II properties, and did not apply to certain other properties to the extent that the Override would cause our net revenue interest to be less than 75%,

vii.	MAB would receive 7% of the issued and outstanding shares of any new subsidiary with assets comprised of the subject properties,

viii.

MAB received 50.0 million shares of PetroHunter Energy Corporation common stock, and would receive up to an additional 50.0 million shares (the “Performance Shares”) if we met certain thresholds based on proven reserves.

We accounted for the acquisition component of the Consulting Agreement in accordance with the purchase accounting provisions of SFAS No. 141, Business Combinations. Accordingly, at the date of acquisition, we recorded oil and gas properties of $94.5 million, notes payable of $13.5 million, and common stock and additional paid-in-capital totaling $81.0 million (equal to the 50.0 million shares issued to MAB at the trading price of $1.62 per share for our common stock on the trading date immediately preceding the closing date of the transaction).

On October 29, 2007, November 15, 2007 and December 31, 2007 we entered into the first, second and third amendments, respectively, to the Consulting Agreement (the “First Amendment”, the “Second Amendment” and the “Third Amendment”, respectively, and collectively, “the Amendments”). Portions of the First Amendment were effective January 1, 2007, the Second Amendment was effective November 1, 2007 and the Third Amendment was effective December 31, 2007. The Amendments significantly changed several provisions of the Consulting Agreement.

Pursuant to the First Amendment: (a) MAB relinquished its overriding royalty interest in all properties in Montana and Utah effective October 1, 2007, (the Override still applies to our Australian properties and Buckskin Mesa property); (b) MAB received 25.0 million additional shares of our common stock; (c) MAB relinquished all rights to the Performance Shares; and (d) the parties’ rights and obligations related to MAB’s consulting services were terminated effective retroactively back to January 1, 2007.

Under the terms of the Second Amendment, effective November 1, 2007, the note payable to MAB was reduced in accordance with and in exchange for the following:

·	By $8.0 million in exchange for 16.0 million shares of our common stock with a value of $3.7 million based on the closing price of $0.23 per share at November 15, 2007, and warrants to acquire 32.0 million shares of our common stock at $0.50 per share. The warrants expire on November 14, 2009;

·	By $2.9 million in exchange for our release of MAB’s obligation to pay the equivalent amount as guarantor of the performance of Galaxy Energy Corporation under the subordinated unsecured promissory note dated August 31, 2007 and;

·	A reduction to the note payable to MAB of $0.5 million for cash payments to be made by us subsequent to September 30, 2007.

Further, in the Second Amendment, MAB waived all past due amounts and all claims against PetroHunter (including the due date for the balance of $0.3 million owed to MAB out of the above-described $0.5 million payment, which is now due on or before February 1, 2008).

The net effect of the reduction of debt and issuance of our common shares in the Second Amendment will result in a net benefit to us of $3.8 million and will be reflected as additional paid-in-capital during the first fiscal quarter ending December 31, 2007. Monthly payments on the revised promissory note in the amount of $2.0 million commence February 1, 2008, and will be paid in full in two years.

Under the terms of the Third Amendment, effective December 31, 2007, the note payable to MAB was reduced: (a) by $0.4 million for our release of MAB’s obligation to pay the equivalent amount as guarantor of the performance of Galaxy Energy Corporation under the subordinated unsecured promissory note dated August 31, 2007; and (b) by $0.2 million for MAB assuming certain obligations of Paleo, which Paleo owed to us.

Acquisition of Powder River Basin Properties

On December 29, 2006, we entered into a purchase and sale agreement (the “Galaxy PSA”) with Galaxy Energy Corporation (“Galaxy”) and its wholly-owned subsidiary, Dolphin Energy Corporation (“Dolphin”). Pursuant to the Galaxy PSA, we agreed to purchase all of Galaxy’s and Dolphin’s oil and gas interests in the Powder River Basin of Wyoming and Montana (the “Powder River Basin Assets”). The purchase price for Powder River Basin Assets was $45.0 million, with $20.0 million to be paid in cash and $25.0 million to be paid in shares of our common stock. Closing of the transaction was subject to approval by Galaxy’s secured noteholders, approval of all matters by our Board of Directors, including our obtaining outside financing on terms acceptable to our Board of Directors, and

various other terms and conditions. Pursuant to successive monthly amendments to the Galaxy PSA, either party could terminate the agreement if closing had not occurred by August 31, 2007.

We became the contract operator of the Powder River Basin Assets beginning January 1, 2007. In January 2007, we paid a $2.0 million earnest money deposit to Galaxy, which was due under the terms of the agreement. In the event the closing did not occur for any reason other than a material breach by us, the deposit was to convert into a promissory note (the “Galaxy Note”), payable to us, as an unsecured subordinated debt of both Galaxy and Dolphin, which was to be payable only after repayment of Galaxy’s and Dolphin’s senior indebtedness.

On March 21, 2007, we entered into a partial assignment of contract and guarantee (the “Assignment”) with MAB. Pursuant to the Assignment, we assigned MAB our right to purchase an undivided 45% interest in oil and gas interests in the Powder River Basin Assets. As consideration for the Assignment, MAB assumed our obligation under the Galaxy PSA to pay Galaxy $25.0 million in PetroHunter common stock. MAB also agreed to indemnify us against costs relating to or arising out of the termination or breach of the Galaxy PSA by Galaxy or Dolphin, and MAB agreed to guarantee the payment of principal and interest due to us under the Galaxy Note in the event the Galaxy PSA did not close.

The Galaxy PSA expired by its terms on August 31, 2007. We obtained the Galaxy Note in the amount of $2.5 million, which consisted of the $2.0 million earnest deposit plus a portion of operating costs paid by us and which was due upon the later of (i) the date upon which all of Galaxy’s senior indebtedness has been paid in full and (ii) December 29, 2007. As discussed previously, MAB was guarantor of the Galaxy Note. The Galaxy Note was paid by MAB in November 2007 (by the terms of the Second and Third Amendments to the Consulting Agreement) by offsetting it against the MAB Note (see discussion under “MAB Resources LLC”, discussed previously).

Competition

We operate in the highly competitive oil and gas areas of acquisition and exploration, areas in which other competing companies have substantially larger financial resources, operations, staffs and facilities. Such companies may be able to pay more for prospective oil and gas properties or prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit.

Environmental Matters

Operations on properties in which we have an interest are subject to extensive federal, state and local environmental laws that regulate the discharge or disposal of materials or substances into the environment and otherwise are intended to protect the environment. Numerous governmental agencies issue rules and regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial administrative, civil and criminal penalties, and in some cases, injunctive relief for failure to comply.

Some laws, rules and regulations relating to the protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination. These laws render a person or company liable for environmental and natural resource damages, cleanup costs and, in the case of oil spills in certain states, consequential damages without regard to negligence or fault. Other laws, rules and regulations may require the rate of oil and gas production to be below the economically optimal rate or may even prohibit exploration or production activities in environmentally sensitive areas. In addition, state laws often require some form of remedial action, such as closure of inactive pits and plugging of abandoned wells, to prevent pollution from former or suspended operations.

Legislation has been proposed in the past and continues to be evaluated in Congress from time to time that would reclassify certain oil and gas exploration and production wastes as “hazardous wastes”. This reclassification would make these wastes subject to much more stringent storage, treatment, disposal and clean-up requirements, which could have a significant adverse impact on our operating costs. Initiatives to further regulate the disposal of oil and gas wastes are also proposed in certain states from time to time and may include initiatives at the county, municipal and local government levels. These various initiatives could have a similar adverse impact on our operating costs.

The regulatory burden of environmental laws and regulations increases our cost and risk of doing business and consequently affects our profitability. The federal Comprehensive Environmental Response, Compensation and

Liability Act, or CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault, on certain classes of persons with respect to the release of a “hazardous substance” into the environment. These persons include the current or prior owner or operator of the disposal site or sites where the release occurred and companies that transported, disposed or arranged for the transport or disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for the federal or state governments to pursue such claims.

It is also not uncommon for neighboring landowners and other third parties to file claims for personal injury or property or natural resource damages allegedly caused by the hazardous substances released into the environment. Under CERCLA, certain oil and gas materials and products are, by definition, excluded from the term “hazardous substances”. At least two federal courts have held that certain wastes associated with the production of crude oil may be classified as hazardous substances under CERCLA. Similarly, under the federal Resource, Conservation and Recovery Act, or RCRA, which governs the generation, treatment, storage and disposal of “solid wastes” and “hazardous wastes,” certain oil and gas materials and wastes are exempt from the definition of “hazardous wastes”. This exemption continues to be subject to judicial interpretation and increasingly stringent state interpretation. During the normal course of operations on properties in which we have an interest, exempt and non-exempt wastes, including hazardous wastes, that are subject to RCRA and comparable state statutes and implementing regulations are generated or have been generated in the past. The federal Environmental Protection Agency and various state agencies continue to promulgate regulations that limit the disposal and permitting options for certain hazardous and non-hazardous wastes.

We believe that the operator of the properties in which we have an interest is in substantial compliance with applicable laws, rules and regulations relating to the control of air emissions at all facilities on those properties. Although we maintain insurance against some, but not all, of the risks described above, including insuring the costs of clean-up operations, public liability and physical damage, there is no assurance that our insurance will be adequate to cover all such costs, that the insurance will continue to be available in the future or that the insurance will be available at premium levels that justify our purchase. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our financial condition and operations. Compliance with environmental requirements, including financial assurance requirements and the costs associated with the cleanup of any spill, could have a material adverse effect on our capital expenditures, earnings or competitive position. We do believe, however, that our operators are in substantial compliance with current applicable environmental laws and regulations. Nevertheless, changes in environmental laws have the potential to adversely affect our operations. At this time, we have no plans to make any material capital expenditures for environmental control facilities.

Employees

As of May 31, 2008, we employed a total of 14 persons, all of which were full-time. None of our employees is covered by a collective bargaining agreement. In addition, we utilized the services of 20 full and part-time consultants.

Facilities

Our principal offices are located at 1600 Stout Street, Suite 2000, Denver, Colorado. We entered into two leases for these offices that run through April 2011 and June 2013, respectively, with an option to renew the 2011 lease for one additional lease term of 36 months. The leases requires monthly rent of $0.3 million, adjusting annually as provided in the lease agreements.

Legal Proceedings

As of March 31, 2008, we were a party to various legal proceedings and liens, including the following:

1.	21 vendors had filed liens applicable to our properties

2.	9 lawsuits had been filed related to these liens

3.	A lawsuit was filed by the lessor of certain properties in the Piceance Basic for breach of our lease contract.

All of these legal proceedings and liens were subsequently resolved in conjunction with the Laramie transaction, as described more fully previously. As of the date of this filing, we are a party to the following legal proceedings and liens:

1.	1 lien applicable to our property in Rio Blanco in the amount of $0.1 million. We are currently negotiating a settlement for this lien.

A lawsuit was filed in August 2007 by a law firm in Australia in the Supreme Court of Victoria for the balance of legal fees owed (0.2 million Australian dollars). Subsequent to filing our March 31, 2008 10-Q, we paid nearly all amounts due under this lawsuit and the issue has been substantially resolved.

3.	A lawsuit was filed in December 2007 by a vendor in the Supreme Court of Queensland for the balance which the vendor claims is owed (2.4 million Australian dollars). We are disputing this claim on the basis that the vendor breached the contract.

We may, from time to time, be involved in various claims, lawsuits, disputes with third parties, actions involving allegations of discrimination, or breach of contract incidental to the operations of our business.

PROPERTIES

Piceance Basin, Colorado Properties

Buckskin Mesa Project. As of March 31, 2008, we had drilled, but did not complete, five wells. We are required to drill 16 wells during the calendar year ending December 31, 2008, three during the first quarter and four during each of the second and third calendar quarters of 2008 and five during the fourth calendar quarter of 2008, under the terms of an agreement between us and a third party assignor, Daniels Petroleum Company (“DPC”). If we do not satisfy these quarterly drilling requirements, our agreement with DPC requires that we pay DPC $0.5 million for each undrilled well on the last day of the applicable quarter. At the end of the first calendar quarter of 2008, we extended and subsequently exercised our right to pay $0.5 million in penalties for three wells that were required to be drilled that quarter by agreeing to pay the $1.5 million fee, plus a $1.0 million additional penalty. These amounts were paid on April 28, 2008, thereby bringing the total number of wells we are committed to drill for the remainder of calendar year 2008 to 13. We currently estimate our cost to drill and complete each well at $3.0 million, aggregating $39.0 million for the remaining 13 wells.

Piceance II Project. As disclosed previously, this property was sold to Laramie Energy II, LLC in May 2008. The following discussion applies to the period prior to the sale.

As of March 31, 2008, we had drilled, but did not complete, 16 wells in the Piceance Basin in Colorado.

On December 10, 2007, we entered into two agreements with EnCana Oil & Gas (USA) Inc. (“EnCana”) to exchange interests in certain Piceance Basin properties, which resulted in an increase in our working interest in 14 of the 16 wells mentioned above as follows:

Exchange 1 — We received from EnCana an interest in 40 net acres, including two wells, and conveyed to EnCana interests in 19 wells. We and EnCana relieved each other of existing obligations related to all past costs and operations of the respective properties exchanged. EnCana’s share of the costs to drill the two wells of $3.2 million reflected as Joint interest billings in our consolidated balance sheet at September 30, 2007 was reclassified to Oil and gas properties during the first quarter ended December 31, 2007. In addition, our accounts receivable from EnCana for oil and gas sales and accounts payable to EnCana for lease operating expenses from the 19 wells, of $0.2

million and $0.1 million respectively, as of December 31, 2007, was also reclassified to Oil and gas properties during the first quarter ended December 31, 2007.

Exchange 2 — We received from EnCana an interest in 198 net acres, including 10 wells with a total present value of net cash flows discounted at 10% as of September 30, 2007 of $6.5 million. EnCana’s share of the costs to drill the 10 wells of $9.4 million reflected as Joint interest billings in our consolidated balance sheet at September 30, 2007 was reclassified to Oil and gas properties during the first quarter ended December 31, 2007. In addition, we paid EnCana $1.0 million at closing that is also reflected in Oil and gas properties during the first quarter ended December 31, 2007.

By the terms of a Lease Acquisition and Development Agreement between MAB, Apollo Energy LLC and ATEC Energy Ventures and a third oil and gas lease pertaining to the Piceance II properties, we were required to drill 10 wells by December 31, 2008. Of the 10 wells, we drilled two during the fiscal year ended September 30, 2007 and we paid 100% of the costs to drill those two wells (two of the 16 wells mentioned above). Our joint interest partner’s share in the amount of $1.0 million is reflected as Joint interest billings on our consolidated balance sheet at March 31, 2008. We have estimated total estimated costs to drill and complete these wells at approximately $16.8 million ($10.5 million to our 62.5% interest). We are currently conducting negotiations with the owners of the remaining 37.5% working interest owners to trade their interest in this lease for other oil and gas interests owned by us.

By the terms of a Lease Acquisition and Development Agreement between MAB, Apollo Energy LLC and ATEC Energy Ventures and of a certain oil and gas lease, we were to have commenced drilling on two wells by August 31, 2007 and an additional two wells by August 31, 2008. Subject to certain spacing orders being issued by the Colorado Oil and Gas Conservation Commission, that requirement has been deferred in its entirety by one year, thus requiring the drilling of two wells by August 31, 2008 and two wells by August 31, 2009. We have estimated total costs to drill and complete these wells at approximately $4.2 million ($1.6 million to our 37.5% interest in the dedicated spacing unit) to be incurred by August 31, 2008 and 2009, respectively.

By the terms of a Lease Acquisition and Development Agreement between MAB, Apollo Energy LLC and ATEC Energy Ventures and of a second oil and gas lease, pertaining to the Piceance II properties, we were to have commenced the drilling of four wells by June 30, 2007, an additional two wells by June 30, 2008 and an additional two wells by June 30, 2009. Subject to certain spacing orders being issued by the Colorado Oil and Gas Conservation Commission, that requirement has been deferred indefinitely. We have estimated total costs to drill and complete these wells at approximately $16.8 million ($8.4 million to our 50% interest).

Sugarloaf Project. On November 28, 2006, we entered into a purchase and sale agreement with Maralex Resources, Inc. and Adelante Oil & Gas, LLC (the “Maralex Agreement”) (collectively “Maralex”) for the acquisition and development of 2,000 net acres in the Jack’s Pocket Prospect in Garfield County, Colorado, including a commitment to drill four wells in the prospect before the end of fiscal year 2008. An initial payment of $0.1 million was made upon execution of the Maralex Agreement. The remaining cash in the amount of $2.9 million and transfer of 2.4 million shares of our common stock was due on January 15, 2007. We amended the Maralex Agreement on several occasions, amending payment dates, issuing an additional 5.6 million shares of our common stock to Maralex and increasing the cash to be paid by $0.3 million. On June 29, 2007, Maralex notified us we were in default under the terms of the Maralex Agreement, as amended. Consequently, by the terms of the Maralex Agreement, we were required to pay Maralex an amount equal to 5% of the outstanding payable for each 20 days past due. As of September 30, 2007, we had reflected an accrued liability of $0.4 million with a corresponding amount in interest expense. If we failed to make payment of the remaining balance by August 28, 2007, Maralex, at its option, could return up to 80% of the previously issued shares of our common stock, and we would reassign to Maralex all leases acquired under the Maralex Agreement.

As of September 30, 2007, the balance due to Maralex is $1.8 million and is reflected as Contract payable — oil and gas properties in our year end consolidated balance sheet. On December 1, 2007, we paid Maralex $0.3 million related to payments on this agreement.

On December 4, 2007, Maralex terminated the Maralex Agreement and notified us that they would return 6.4 million shares of common stock and consequently, we were relieved of our drilling commitments. In addition,

costs incurred in excess of the carrying value of the common stock to be returned, have been included in costs to be amortized, and have been included in the ceiling test at the lower of cost or estimated fair value.

Gibson Gulch Project. In August and November 2006, we entered into two agreements with a third party owner (the “Farmor”) to farm-in and participate in the drilling and completion of six wells located in the Mamm Creek Field, Garfield County, Colorado, due east of our Piceance II wells and assets. On February 27, 2007, we received a notice of default from the party designated as operator under the joint operating agreement (the “Operator”) covering the subject lands for failure to make timely payment of the amounts due for the completion of the four wells for which we had paid our share of drilling costs, and for drilling or completion of the remaining two wells. On March 29, 2007, the Farmor notified us that it was exercising its right to terminate our agreement and resume ownership of the working interests in the six wells drilled on the farmout acreage. The Farmor refunded all amounts paid by us to drill the wells less interest incurred on the past due joint interest billings, and credited us for the remaining balance due to the Operator.

Plan of Operations. We expect that the development of our Colorado properties will include the following activities: (i) the completion and tie-in of five wells drilled and cased to date in the Buckskin Mesa Prospect (four wells drilled and cased during fiscal year 2007 and one well drilled and cased during the first quarter ended December 31, 2007); (ii) the drilling, of a minimum of 13 commitment wells in our greater than 20,000 net acre Buckskin Mesa Prospect leasehold block surrounding the discovery wells for the Powell Park Field near Meeker, Colorado in the northern Piceance Basin; and (iii) the recompletion and tie-in of the six shut-in gas wells in the Powell Park Field acquired by us from a third party operator.

We anticipate that the following costs associated with the development of the Colorado assets will be incurred:

• $40.0 million to $50.0 million in connection with the Piceance II Project, to include expenditures for seismic data acquisition, lease and asset acquisition, drilling, completion, lease operation, and installation of production facilities

• $41.0 million to $60.0 million in connection with the Buckskin Mesa Project, to include expenditures for seismic data acquisition, lease and asset acquisition, drilling, completion, lease operation, and installation of production facilities

We are currently attempting to rationalize the Colorado asset base to raise capital and reduce our working interest and the associated development costs attributable to such retained interest.

Australia Properties

Beetaloo Project. The Beetaloo Basin property in the Northern Territory of Australia currently consists of approximately 7.0 million net contiguous acres. Sweetpea owns the existing four permits that cover this acreage. We have applied to the Department of Primary Industry, Fisheries and Mines for additional permits covering an additional 1.5 million net acres that is contiguous to our currently-owned permits.

Located about 600 kilometers south of Darwin, the Beetaloo Basin is a large basin, comparable in size to the Williston Basin in the U.S. or the entire southern North Sea basin. The basin has many thousands of meters of sediments, but the reservoirs of interest to us are within 4,000 meters of the surface, most less than 3,000 meters. The sedimentary rocks include thick (hundreds of meters), rich source rocks, namely the Velkerri Shale. There are also a number of sandstone reservoirs interbedded with the rich source rocks. These formations, from stratigraphically youngest to oldest, include the Cambrian Bukalara Sandstone, and the Neoproterozoic Jamison, Moroak, and Bessie Creek sandstones. A number of even deeper sandstones are expected to be very tight and were not prospective in the single well where they were tested east of the Basin.

Three primary plays have been recognized within the basin. The first is a conventional structural, shallow sweet oil play of 35° API gravity. The Bukalara, Jamison, and Moroak sands (and perhaps the Bessie Creek sand along the western margin) have potential for oil and gas accumulations in trapped and sealed geometries. Most of the eleven previous wells drilled within the basin had oil and gas shows, and the Jamison No. 1 well tested oil on a Drill Stem

Test. Detailed petrophysical analyses have been performed on all wells and have identified significant potential in some of these tests.

The second play is an unconventional fractured shale play within the Kyalla and Velkerri formations, not unlike the Barnett Shale play in Texas. It is unknown whether the hydrocarbons will be gas or oil (or possibly both) for this exploration target; however, the Barnett Shale model and algorithms in our petrophysical analyses of these shales suggest they are viable targets.

Finally, the Moroak and Bessie Creek sandstones offer a Basin Centered Gas Accumulation (BCGA) play at the center of the basin. It is an unconventional resource play characterized by a lack of a gas/water contact. Petrophysical analyses of several wells previously drilled in the basin demonstrate the presence of a BCGA in the basin.

We spudded the Sweetpea Shenandoah No. 1 well on July 31, 2007 and drilled to 4,724 feet. Intermediate casing was run on September 15, 2007 and the well was then suspended with an intention to deepen the well to a depth of 9,580 feet.

Because of its proximity and geological similarity to the Balmain No. 1 well, we regard this well as a twin to the Balmain No. 1 well that was drilled by an unrelated third party in 1992. Based on our initial drilling, geologically, the Shenandoah No. 1 well has matched its prognosis and the drilling results correlate with the Balmain No. 1 well.

To date, seven drilling locations have been identified based on extensive geological and geophysical analysis. These locations have been cleared through the Northern Land Council, responsible for consulting with and representing traditional landowners and other Aborigines with an interest in land. Final drilling approval was received in May 2007, and these locations have been staked and will be formally surveyed. The preparation of drilling pads and access lines commenced the last week of May 2007 and continued into June 2007. We are attempting to obtain drilling locations beyond the initial seven locations.

From July through November of 2006, 686 kilometers of new 2-D seismic data were acquired throughout the Beetaloo Basin. Additionally, 1,000 kilometers of previously acquired 2-D seismic data were reprocessed. Along, with the other existing 1,500 kilometers of 2-D seismic data that have not been reprocessed, geologic structure maps were generated for the basin.

The exploration drilling program for 2008 will test several play concepts within the basin. Hydrocarbon potential exists in shallow, conventional structures (in the form of oil), and in deeper unconventional reservoirs, including fractured shales and basin centered gas accumulations. The unconventional plays may be gas and/or oil. All of the exploration wells are planned to reach a total depth in the Bessie Creek Sandstone formation. The deepest penetration is expected to be 3,000 meters.

Gippsland and Otway Project. On November 14, 2006, we and Lakes Oil N.L. (“Lakes Oil”) entered into an agreement (the “Lakes Agreement”) under which they would jointly develop Lakes Oil’s onshore petroleum prospects (focusing on unconventional gas resources) in the Gippsland and Otway Basins in Victoria, Australia. The arrangement was subject to various conditions precedent, including completion of satisfactory due diligence, and the satisfactory processing and retention of certain lease applications.

The Lakes Agreement expired pursuant to its terms, and we and Lakes Oil are conducting discussions to formally terminate the Lakes Agreement wherein we would receive $0.1 million in escrowed funds and both parties will fully waive and release each other from all further obligations and liabilities.

Northwest Shelf Project. Effective February 19, 2007, the Commonwealth of Australia granted to Sweetpea an exploration permit in the shallow, offshore waters of Western Australia. The permit, WA-393-P, has a six year term and encompasses almost 20,000 acres. Geophysical data across the permit from public sources has been acquired and is being analyzed. We have committed to an exploration program with geological and geophysical data acquisition in the first two years with a third year drilling commitment and additional wells to be drilled in the subsequent three year period depending upon the results of the initial well.

Plan of Operations. We plan to explore and develop portions of our 7.0 million net acre position in the Beetaloo Basin project area located in northwestern Australia. During calendar year 2008, we plan to drill five wells in the exploration permit blocks. We anticipate that costs related to seismic acquisition, development of operational infrastructure, and the drilling and completion of wells over the next twelve months will range from $22.0 million to $30.0 million. As a means of reducing this exposure, selected portions of the project portfolio will be made available for farm-out to industry for cash and payment of expenses related to drilling and completion of one or more wells in each prospect.

Heavy Oil Properties

As described above, these properties were sold to Pearl effective October 1, 2007. The following discussion applies to the period prior to the sale to Pearl.

Great Salt Lake, Utah. We owned 173,738 net mineral acres under lease (covered by approximately 78 leases) on two principal properties, the West Rozel Field and the Gunnison Wedge prospect, each located in the Great Salt Lake of Utah. Permitting was required to be completed on this project during 2007. One well was required to be drilled prior to the expiration date of the primary term under each lease. We negotiated an extension to the dates of the work commitments under the acquisition agreement between us and American under an amendment executed on July 31, 2007.

Fiddler Creek, Montana. We owned 23,324 net acres situated on three anticlines located in the northern portion of the Big Horn Basin, which extends from north central Wyoming into southern Montana. Our interests encompassed shut-in wells and leasehold interests in the Roscoe Dome, Dean Dome and Fiddler Creek project areas. These anticlines are large asymmetric anticlines with proven production from several Cretaceous horizons; i.e. the Upper Greybull Sandstone, the Lower Greybull Sandstone and the Pryor Conglomerate.

Promised Land, Montana. We owned 48,793 net acres in a resource play evaluating heavy oil reservoirs in the Jurassic Swift Formation and the Lower Cretaceous Bow Island and Sunburst sandstone reservoirs in north central Montana. The Swift reservoirs were deposited in a shallow marine to estuarine depositional setting. The Swift sandstones are commonly oil saturated in the area, and most well tests report oil shows in the Swift. The reservoirs are up to 60 feet thick and composed of high quality sandstone, averaging about 20 percent porosity and permeabilities range up to one darcy. The oil gravities range from 10° to 22°API with viscosities of 1,500 centipoise to greater than 50,000 centipoise at 125°F.

Other Assets

Bear Creek, Montana. As of March 31, 2008, we owned 13,905 net acres of leasehold in a combination deeper conventional gas/coalbed methane project area located in southern Montana, east of the Fiddler Creek heavy oil assets. The primary deep objectives are incised Greybull valley-fill sequences along the Nye-Bowler lineament, and the Frontier sandstone, while the shallow Ft. Union provides an opportunity to produce methane from multiple thin coal lenses at intervals from 500 to 3,000 feet. No activity was conducted in this project area during the fiscal year, nor are any funds budgeted to evaluation of this asset in the coming year.

Production and Prices

The following table sets forth information regarding net production of oil and natural gas, and certain price and cost information for fiscal years ended September 30, 2007 and 2006. We did not have any production during the fiscal year ended September 30, 2005.

	For the Fiscal Year
	Ended September 30,
	2007		2006

Production Data:
Natural gas (Mcf)		456,740		5,822
Oil (Bbl)		137		—
Average Prices:
Natural gas (per Mcf)	$	6.16	$	6.12
Oil (per Bbl)	$	52.40	$	—
Production Costs:
Lease operating expenses (per MCFE)	$	1.73	$	0.63

Productive Wells

The following table summarizes information at September 30, 2007, relating to the productive wells in which we owned a working interest as of that date. Productive wells consist of producing wells and wells capable of production, but specifically exclude wells drilled and cased during the fiscal year that have yet to be tested for completion (for example, all of the operated wells we drilled during 2007 have been cased in preparation for completion, but operations have not been initiated to allow these wells to be productive). Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests in the gross wells.


	Gross						Net
	Oil		Gas		Total		Oil		Gas		Total

Location
Colorado (1)		—		33.0		33.0		—		10.4		10.4
Utah(1)		—		—		—		—		—		—
Montana(1)		2.0		—		2.0		2.0		—		2.0
Australia		—		—		—		—		—		—
Total		2.0		33.0		35.0		2.0		10.4		12.4


(1)		As of May 31, 2008, we sold most of our interests in Utah and Montana, as wells as a portion of our interests in Colorado.

Oil and Gas Drilling Activities

During the fiscal year ended September 30, 2007, our drilling activities were limited to Colorado and Australia. We drilled, or participated in the drilling of a total of 39 gross wells and 14.46 net wells categorized as follows: (i) 2.21 net wells under 21 gross wells drilled, completed and turned down-line to production; and (ii) 12.25 net wells under 18 gross wells drilled and cased, but not completed for production. In addition, we acquired during the year six gross producing wells in Colorado that are shut-in awaiting a tie-in to the market, and drilled one net under one gross exploratory well in Australia that is currently suspended. During 2007, we drilled no dry exploratory wells and no development wells.

During the fiscal year ended September 30, 2006, our drilling activities were limited to Colorado; we drilled, or participated in the drilling of six gross exploratory wells and 2.14 net exploratory wells with no dry exploratory wells, and we acquired two gross and net oil wells. We did not drill development wells during 2006.

During the fiscal year ended September 30, 2005 we did not drill any wells.

Oil and Gas Interests

As of September 30, 2007, we owned interests in the following developed and undeveloped acreage positions. Undeveloped acreage refers to acreage that has not been placed in producing units.


	Developed				Undeveloped
	Gross Acres		Net Acres		Gross Acres		Net Acres

Location
Colorado		598.40		341.42		27,888.86		21,317.50
Utah		—		—		173,738.00		173,738.00
Montana		80.00		80.00		100,118.00		86,748.00
Australia		—		—		7,000,000.00		7,000,000.00

Total		678.40		421.42		7,301,744.86		7,281,803.50

Effective as of October 1, 2007, we sold most of our interests in Utah and Montana.

MANAGEMENT

Officers, Directors and Key Employees

Our executive officers, directors, and key employees are:

Name	Age	Position

Charles B. Crowell	65	Chairman of the Board of Directors and Chief Executive Officer

Carmen J. Lotito	64	Executive Vice President – Business Development

Charles A. Josenhans	46	Interim Chief Financial Officer

David E. Brody	59	Vice President, General Counsel and Secretary

Thomas S. Ahlbrandt	60	Vice President of Exploration and Chief Geologist

Lyle R. Nelson	60	Vice President of Operations and Production

Jim Bob Byrd	48	Vice President of Land and Business Development

Kyle L. WhiteJohnson	50	Vice President of Administration and Assistant Secretary

Robert Perlman	45	Controller

Martin B. Oring	63	Director

Name	Age	Position

Matthew R. Silverman	54	Director

Dr. Anthony K. Yeats	61	Director

Our stockholders elect our directors annually and our board of directors appoints our officers annually. Vacancies in our board are filled by the board itself. Set forth below are brief descriptions of the recent employment and business experience of our executive officers and directors.

Charles B. Crowell was appointed to serve as our Chairman of the Board and Chief Executive Officer in July 2007. Mr. Crowell has served as a director of the Company since February 2007 and was a member and chairman of the Audit and Compensation Committees. In addition to his service to the Company, Mr. Crowell has been a practicing attorney and an officer and consultant to oil and gas companies for 38 years. Mr. Crowell has held executive positions at several public and private companies, including manager and principal of Enigma Energy Company, LLC, Dallas, Texas, and Executive Vice President of Administration of Triton Energy Corporation. In addition to his services as a director of the Company, Mr. Crowell has also served and continues to serve as a director in several other public companies, including PetroHunter Energy, Inc., Denver Colorado (2002-present) and Vice Chairman of the Board (2003-present); Comanche Energy, Inc., Tulsa, Oklahoma (1999-2000); Arakis Energy Corporation, Calgary, Alberta, Canada (1997-1998); Aero Services International, Inc., Newtown, Pennsylvania (1989-1993) (Chairman of the Board 8/90-12/92); and Triton Europe, plc., The Hague, The Netherlands (1989-1993). Mr. Crowell holds a BA degree from John Hopkins and a JD from University of Arkansas. He was admitted to the practice of law in Texas in 1974.

Carmen J. Lotito has been a director of the Company since May 2006 and the Executive Vice President – Business Development since October 2007. He previously served as the Executive Vice President, Chief Financial Officer, Treasurer, and Secretary of the Company at various times from May 2006 to October 2007. Mr. Lotito is also the Executive Vice President – Business Development of PetroHunter Operating Company. Mr. Lotito has been a director and chairman of the audit and compensation committees of Gasco Energy, Inc. since April 2001, and was a director of Galaxy Energy Corporation from November 2002 to August 2006. He served as chief financial officer and treasurer of Galaxy Energy Corporation from November 2002 to July 2005, and as executive vice president from August 2004 to July 2005. Both PetroHunter Energy and Galaxy Energy are subject to the reporting requirements of the Securities Exchange Act of 1934. Mr. Lotito served as vice president, chief financial officer, and director of Coriko Corporation, a private business development company, from November 2000 to August 2002. Prior to joining Coriko, Mr. Lotito was self-employed as a financial consultant. Mr. Lotito holds a B.S. degree in accounting from the University of Southern California.

Charles A. Josenhans was elected to serve as interim chief financial officer in May 2008. Mr. Josenhans is the founder and managing partner of New Vector Partners, LLC, a consulting and interim management services business serving clients on a national basis. Since forming New Vector in 2004, he has been involved with a number of interim CFO engagements, providing guidance with transition management, SEC reporting, business design and planning, organization development, due diligence assistance and financing activities, Sarbanes-Oxley 404 internal control evaluation and improvement, and numerous other project management efforts. Prior to forming New Vector, Mr. Josenhans held a variety of senior roles in finance with several publicly-held and privately-held companies, dating back to 1991. Mr. Josenhans began his career in 1985 with Arthur Young & Company in Seattle, Washington, after receiving his bachelor’s degree in accounting from Western Washington University, and became a licensed CPA in Washington in 1987 (currently inactive).

David E. Brody became our Vice President, General Counsel and Secretary in September 2006. Mr. Brody is also a partner in the law firm of Patton Boggs LLP, where he has represented the Company since its inception, and where his practice since 1999 focused on complex transactions and litigation involving oil and gas matters domestically and internationally. Mr. Brody has extensive experience representing oil and gas clients which operate in Europe, Australia, and other countries throughout the world. This work includes all aspects of oil and natural gas production, operations, gas gathering, transportation and sales. Prior to joining Patton Boggs, Mr. Brody worked for Amoco Corporation (now BP), where he focused on acquisitions and divestments and other transactions,

and managed extensive major litigation. He also served as general counsel for an Amoco subsidiary, and was a member of various management teams with Amoco. Mr. Brody received his B.S. from University of Colorado and is a graduate of the American University Washington College of Law. He has presented numerous papers and written articles on various oil industry subjects, and has written three books. He was recognized on the inaugural list of Colorado Super Lawyers, 2006, and Colorado Super Lawyers, 2007. Mr. Brody is a member of several professional associations, including: Association of International Petroleum Negotiators, Independent Petroleum Association of Mountain States, Rocky Mountain Mineral Law Foundation, Colorado Oil and Gas Association, Colorado Bar Association and American Bar Association.

Thomas S. Ahlbrandt has been our Vice President of Exploration and Chief Geologist since June 2006. He briefly assumed the role of Chairman of the Board and Chief Executive Officer from February 7, 2007 to July 2, 2007. From August 1988 to June 2006, he served in various capacities with the U.S. Geological Survey, including serving as project chief for the World Energy Project, which produced the USGS World Petroleum Assessment 2000. He currently serves as the Vice Chairman for the United Nations Committee (UNECE), Ad Hoc Group of Experts on the Supply of Fossil Fuels. He has had many years of industry experience, dating back to 1966. Dr. Ahlbrandt also served on the Executive Committee of the American Association of Petroleum Geologists (AAPG) as Chairman of the House of Delegates from 1995 to 1996. He has received numerous awards including distinguished Lecturer of the AAPG, the Distinguished Service Award from AAPG, Outstanding Scientist from the Rocky Mountain Association of Geologists, Distinguished Alumnus of the University of Wyoming and Meritorious Service Award from the Department of the Interior. He received his B.A. and Ph.D. in geology from the University of Wyoming.

Lyle R. Nelson became our Vice President of Operations and Production in July 2006. Prior to joining the company in July 2006, Mr. Nelson served as Senior Project Manager for Integrated Solutions Group of Halliburton where he worked since September 1998. He was Vice President and Operations Manager of Nescor Energy and Vice President of Petroleum Engineering for Micro-Bac International, Inc. Mr. Nelson has been Manager and Owner of Williston Basin Consulting, Inc and has worked with Amerado Hess Corporation and Texaco, Inc. Mr. Nelson has more than 30 years of experience drilling wells throughout the United States and abroad, including Hungary, Canada, Iraq, Russia, Mexico and Mongolia. He holds a B.S. in civil engineering from South Dakota State University and a B.S. in mathematics from Dakota State College. He has been a registered Professional Petroleum Engineer since 1983.

Jim Bob Byrd became our Vice President of Land and Business Development in February 2007. Mr. Byrd has more than twenty years experience in acquiring, managing and developing oil and gas assets as a land professional. Prior to joining the company in August 2006, Mr. Byrd was the Manager of Business Development and Senior Landman for Black Hills Exploration and Production, Inc. where he was the primary liaison for business development and responsible for significant corporate growth through numerous acquisitions in the Piceance and San Juan Basins. Mr. Byrd began his corporate career at Meridian Oil Inc. in 1985 working major basins in the Rocky Mountains, and later major assets in the Gulf Coast and Mid-Continent regions. From 1995 to 2005, he was a land and business development consultant to various oil and gas companies, including Burlington Resources Oil & Gas Co., Alberta Energy Co./Encana Oil & Gas (USA) Inc., KCS Mountain Resources, Inc., Vessels Oil & Gas Co., and Coronado Oil Co. Mr. Byrd is an active member of several professional land organizations and an alumnus of Baylor University.

Kyle L. WhiteJohnson became our Vice President of Administration and Assistant Secretary in September 2006. Mrs. Johnson brings nearly thirty years of corporate and legal experience to her role. Before joining the company in September 2006, Mrs. Johnson served as Director of Legal & Shareholder Services for a Nasdaq-listed company and as Director of Legal Compliance for a private holding company that incubated publicly traded Real Estate Investment Trusts (REITs) through syndication and conversion to the NYSE. Mrs. Johnson has executed initial and secondary public offerings, conversions, equity, debt, mergers and acquisitions, securitization, and other financing transactions in various industries. She has worked closely with Boards of Directors and has assisted the related Audit and Compensation Committees with complex corporate governance and regulatory compliance matters. Mrs. Johnson has coordinated with corporate human resources and accounting teams to design, implement, and remediate internal controls and procedures in response to newly imposed Sarbanes Oxley legislation. Mrs. Johnson is an alumnus of the University of Florida has been an active member of several professional associations since 2001, including: National Association of Stock Plan Professionals, Society of Corporate Secretaries and Governance

Professionals, National Center for Employee Ownership, and is an associate member of the American Bar Association.

Robert Perlman was elected to serve as controller and principal accounting officer in May 2008. Prior to joining us in April 2008, Mr. Perlman was the controller for Westwood College Online from November 2005 to April 2008. He served as the senior manager, accounting and finance special projects, for Qwest Communications from 2001 to 2005. Prior to Qwest, Mr. Perlman worked with other companies in accounting and finance, dating back to 1998. He began his accounting career in 1993 with KPMG Peat Marwick, in New York, NY and then in Denver, Colorado. Mr. Perlman received a master’s degree in professional accounting from Rutgers University Graduate School of Management and his bachelor’s degree in communications from C.W. Post College.

Martin B. Oring became a director in July 2007. Mr. Oring is an executive in the financial services and energy industries. Prior to forming his current business in 2001, Wealth Preservation, LLC, he had extensive experience as a member of management in several companies, including Prudential Securities (Managing Director of Executive Services), Chase Manhattan Corporation (Manager of Capital Planning), and Mobil Corporation (Manager, Capital Markets & Investment Banking). He has served and will continue to serve as a director of Parallel Petroleum Corporation, located in Midland, Texas. Mr. Oring received a B.S. degree in mechanical engineering from the Carnegie Institute of Technology in 1966 and an M.B.A. degree from in production management, finance and marketing from Columbia University in 1968. Mr. Oring chairs the audit, compensation and nominating committees of our board of directors and is a qualified financial expert.

Matthew R. Silverman became a director in February 2007. Mr. Silverman is Exploration Manager with Robert L. Bayless, Producer LLC, an oil and gas company that is active in the central and southern Rocky Mountain regions. Such projects have included exploration for conventional oil and natural gas, tight gas, and coalbed methane development in several basins. Mr. Silverman directs Bayless's geology and land departments in its Denver offices. From 1989 to 2000, he was employed by Gustavson Associates, Inc., an international oil and gas consulting group, where he was responsible for technical evaluation and capital formation for exploration and production opportunities around the world. His work included appraising oil and gas assets (producing and exploratory), preparing on-site oil and gas field feasibility studies, and business development. Mr. Silverman was previously employed by TOTAL Minatome and its predecessors, CSX Oil & Gas and Texas Gas Exploration, from 1982 to 1989 in Denver, Colorado, and by Evans Energy from 1976 to 1982. He received an A.B. degree from Brown University in 1975 and an M.S. degree in Geological Sciences from the University of Colorado in 1983. Mr. Silverman is a Certified Petroleum Geologist.

Dr. Anthony K. Yeats became a director in February 2006. Dr. Yeats has participated in the development of numerous exploration ventures in oil and gas opportunities around the world. His career has included the role of Chief Geologist, Geophysicist and Team Leader for Royal Dutch Shell in the Middle East, Africa and the Far East, Exploration Coordinator for BP’s Global Basin Group, and Chief Geologist for a number of regional acquisitions undertaken by British Petroleum at a variety of locations throughout the Middle East, Africa, Canada and Europe. Before joining the Company, in 1999 Dr. Yeats started Cambridge Earth Sciences Limited, which provides private research and consulting services for companies engaging in geology and exploration management, which Dr. Yeats continues to run. Prior to 1999, Dr. Yeats was Co-coordinator for World Wide New Ventures for Total in Paris and finally Exploration Manager for Total in the Former Soviet Union where he managed teams undertaking hydrocarbon exploration in Kazakhstan, Azerbaijan, and Russia. In this post he was responsible for the generation of new ventures, including the acquisition of already existing discoveries. Over the years he has developed extensive contacts with the financial community in Edinburgh and London, which specialize in the raising of capital for oil and gas ventures particularly from UK, French, Canadian and Middle East sources.

Director Independence Determinations

The Board has evaluated the independence of the members of the Board under the independence standards promulgated in the Nasdaq listing standards. In conducting this evaluation, the Board considered transactions and relationships between each director nominee or his immediate family and the Company to determine whether any such transactions or relationships were material and, therefore, inconsistent with a determination that each such director nominee is independent. Based upon that evaluation, the Board determined that Dr. Yeats and Messrs. Oring and Silverman have no material relationship with the Company and, thus, are independent.

Board Committees

The Board has an Audit Committee, Nominating Committee, and Compensation Committee. All of the members of these committees are non-employee, independent directors in accordance with the Nasdaq listing standards.

Audit Committee. The current members of the Audit Committee are Martin B. Oring (Chairman), Matthew R. Silverman and Dr. Anthony K. Yeats. The Board has determined that Mr. Oring is the audit committee financial expert, as defined by the Securities and Exchange Commission (“SEC”) rules and has accounting or related financial management expertise under the Nasdaq rules. All of the members of the Audit Committee are independent under the SEC rules pertaining to audit committee members. The Audit Committee adopted an Audit Committee Charter. The Audit Committee is responsible for (i) making recommendations to the Board concerning the engagement of the Company’s independent public accountants, (ii) consulting with the independent public accountants with regard to the audit plan, (iii) consulting with the Company’s principal financial and accounting officers on any matter the Audit Committee or the principal financial and accounting officers deem appropriate in connection with carrying out the audit, (iv) reviewing the results of audits of the Company by its independent public accountants, (v) reviewing all material related party transactions and all other potential conflict of interest situations, (vi) discussing audit recommendations with management and reporting the results of its reviews to the Board and (vii) performing such other functions as may be prescribed by the Board. The Audit Committee Charter may be found on our website, at www.PetroHunter.com.

Nominating Committee. The Nominating Committee was formed in December 2007. The current members of the Nominating Committee are Martin B. Oring (Chairman), Matthew R. Silverman and Dr. Anthony K. Yeats. The Nominating Committee is responsible for (i) making recommendations to the Board about appropriate composition of the Board and its committees, (ii) evaluating potential director nominees and making recommendations to the Board regarding those director nominees that may be considered for election to the Board at the Annual Meeting, (iii) advising the Board on corporate governance practices and policies, (iv) overseeing the evaluation of the Board and management of the Company, (v) making recommendations to the Board regarding succession planning, and (vi) performing such other functions as may be prescribed by the Board. The Nominating Committee Charter may be found on our website, at www.PetroHunter.com.

The Board’s current criteria for selecting new directors do not include specific minimum qualifications, but include criteria relating to a candidate’s business experience and accomplishments, lack of conflicts of interest, ability to commit the time to serve effectively, personal characteristics, the Board’s needs for diversity of backgrounds and skills, and other pertinent considerations. The Nominating Committee periodically reviews the appropriate skills, experience, perspectives and characteristics required of Board members or candidates in the context of the perceived needs of the Board at the time.

Compensation Committee. The current members of the Compensation Committee are Martin B. Oring (Chairman), Matthew R. Silverman and Dr. Anthony K. Yeats. The Compensation Committee administers the Company’s stock option plans, makes decisions concerning salaries and incentive compensation for the Company’s executive officers, and performs such other functions as may be prescribed by the Board. The Compensation Committee Charter may be found on our website, at www.PetroHunter.com

None of members of the Compensation Committee is or was an officer of the company or any of its subsidiaries at any time now or in the past.

Code of Ethics

We have adopted a Code of Conduct and Standard of Ethics that applies to our principal executive officer, principal financial officer, principal accounting officer, and persons performing similar functions. The text of this code is posted on our Internet website at www.PetroHunter.com. In the event that an amendment to, or a waiver from, a provision of this code is necessary, we intend to post such information on our website.

EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

We believe that the skill and dedication of our executive officers and other management personnel are critical factors affecting our long-term success in meeting our objectives and fostering growth and profitability. In support of this, compensation programs have been designed to attract and retain a high level of talented leadership, to reward performance in accordance with results, to provide an incentive for future performance and to align PetroHunter executives’ long-term interests with those of the stockholders.

Our executive and key management compensation is comprised of three major components: (i) base salary adjusted annually by the Compensation Committee, (ii) cash incentive bonuses awarded based on individual performance and the performance of PetroHunter, and (iii) stock option grants awarded based on individual performance and the performance of PetroHunter. The compensation mix of cash and stock options grants for the CEO is similar to that of other executive officers of PetroHunter.

The Compensation Committee was established by the Board of Directors of PetroHunter for the following purposes:

·	to assist the Board in its responsibility relating to fair and competitive compensation of key employees of PetroHunter;

·	to assure that key employees, which includes all officers, are compensated in a manner consistent with the compensation philosophy and strategy of the Board and in compliance with the requirements of appropriated regulatory bodies and any exchange rules to which we may be subject;

·	to review and approve our compensation philosophy and our compensation programs, plans and awards;

·	to administer our long and short term incentive plans and stock option plans;

·	to review the compensation of our Chief Executive Officer and recommendations of the Chief Executive Officer as to appropriate compensation for the other executive officers and key personnel; and

·	to review and approve our general employee benefit plans as needed.

The Compensation Committee was formed in February 2007, when two independent directors were added to the Board of Directors. The Compensation Committee is composed of three members, Mr. Oring, Mr. Silverman and Dr. Yeats, all of whom are “independent” under the rules and regulations of Nasdaq. To be “independent” under the rules and regulations of Nasdaq, a director may not, other than in his or her capacity as a member of the audit committee, board of directors, or other board committee: (i) accept directly or indirectly, any consulting, advisory, or other compensatory fee from PetroHunter or any of its subsidiaries, provided that compensatory fees do not include the receipt of fixed amounts of compensation under a retirement plan (including deferred compensation) for prior service with PetroHunter (provided that such compensation is not contingent in any way on continued service), or (ii) be an affiliated person of PetroHunter or any of its subsidiaries.

The Compensation Committee compares all compensation components for executive officers, at least annually, with data on similar positions at other organizations that are similar in number of employees, level of operations, gross revenue and total assets with which we compete for talent. When evaluating external competitiveness, third party survey data, as well as information from other resources and industry contacts, are considered. 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 compensation levels. This is primarily due to 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, drive executive compensation. The Compensation Committee seeks the input of our Chief Executive Officer in evaluating the performance of all of our executive officers, excluding himself.

In the processes used by the Compensation Committee to establish and adjust executive compensation levels, third party survey data is considered, along with performance, experience, potential and internal equity. The Compensation 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 or suggest alternative compensation packages.

The Compensation Committee used the analysis set forth below in its determination of the level of compensation for each of the following components of our 2007 compensation program. Since the Compensation Committee was not formed until the middle of the 2007 fiscal year, much of the compensation program was already in place and the Committee was not in a position to introduce many changes. The 2008 compensation program may change in light of the Company’s cash resources and other factors.

Base Salary – The base salaries of the named executive officers are reviewed annually by the Committee and future salary adjustments are reviewed by the Committee on an annual basis and recommended to the Board for final approval. The Committee and the Board consider various factors, including, the position of the named executive officer, the compensation of executive officers of comparable companies within the oil and natural gas industry, the performance of each executive officer, increases in responsibilities of each executive officer and recommendations of the Chief Executive Officer with respect to base salaries of other named executive officers. Salaries for the named executive officers in fiscal 2007 are set forth in the “Summary Annual Compensation Table” below and were determined by the Board based on the considerations described above.

During the fiscal year ended September 30, 2007, we had both a Chief Executive Officer and a President/Chief Operating Officer. For the 2008 fiscal year, the position of President/Chief Operating Officer was eliminated and effective January 1, 2008, the Compensation Committee established an annual base salary of $480,000 for the Chief Executive Officer.

Annual Cash Bonus Awards – We propose to establish a bonus plan for executive officers in the near future. The plan will be designed to compensate, and thus incentivize, individuals for exceptional effort and job performance, facilitating our continued growth and success by providing rewards that are commensurate with individual achievement. It is anticipated that the proposed bonus plan will allow the Compensation Committee to give consideration to the following: the achievements of PetroHunter, and the employee’s relationship thereto, in order to determine the level of the cash bonus, if any, to be awarded; the earnings of PetroHunter; the return on stockholders’ equity; the growth in proved oil and gas reserves; and the successful completion of specific projects of PetroHunter to determine the level of bonus awards, if any.

During the fiscal year ended September 30, 2007, bonuses were awarded to Thomas Ahlbrandt in recognition of his increased responsibilities during the time that he served as the Company’s Chief Executive Officer, to Jim Bob Byrd and Garry Lavold as incentive to join the Company, and to Lyle Nelson for serving in an overseas assignment.

Stock Option Awards - Stock option awards are utilized for aligning the executives’ interests with those of the stockholders by giving each individual direct ownership in PetroHunter. We also believe that these awards serve as a retention incentive since unvested stock grants and options may be forfeited if the executive leaves us. In some cases, the Company has elected to allow the options to continue to vest even though the employment relationship has ended. The Compensation Committee focuses on the earnings of PetroHunter, the return on stockholders’ equity, the growth in proved oil and gas reserves and the successful completion of specific projects of PetroHunter to determine the level of stock option awards, if any. Decisions to grant stock options are normally made when industry conditions cause concern that personnel may be lost.

During the fiscal year ended September 30, 2007, stock options were granted only in the following circumstances: (i) on February 7, 2007 and September 21, 2007 for new directors; (ii) on May 2, 2007 and July 2, 2007 for the new Chief Executive Officer, and (iii) on May 21, 2007 to fulfill previous commitments made to employees. The Committee considered the grants made to new directors and the new Chief Executive Officer to be appropriate in order to compensate such individuals for the responsibility and risk exposure assumed when serving in such positions, especially in light of the current financial condition of the Company. The May 21, 2007 option grants were made to meet commitments that had been made to employees of the Company in 2006 when the market value of the stock was $0.50 per share. Accordingly, the exercise price of those options is $0.50 even though the market

price of the stock on May 21, 2007 was $0.70 per share. The Committee considered the grants made to be necessary in order to retain existing employees.

Summary Compensation

The following table sets forth the compensation paid to our Chief Executive Officer and Chief Financial Officer and each of our next highly compensated executive officers and other employees for services rendered during the year ended September 30, 2007:

SUMMARY COMPENSATION TABLE
Name and principal position	Year	Salary ($)	Bonus ($)	Option Awards ($)	All Other Compensation ($)	Total ($)
Kelly H. Nelson Chief Executive Officer(1)	2007	$220,000	--	$208,154 (3)	(2)	$428,154
Thomas S. Ahlbrandt Chief Executive Officer and Vice President of Exploration (4)	2007	$160,000	$80,000	$404,584 (3)( 5)	(2)	$644,584
Charles B. Crowell Chief Executive Officer (6)	2007	$177,750 (7)	--	$600,298 (8)	(2)	$755,548
Carmen J. Lotito Chief Financial Officer	2007	$240,000	--	$208,154 (3)	$37,193 (9)	$485,347
Garry Lavold President and Chief Operating Officer (10)	2007	$270,000	$29,856	$208,154 (3)	$18,575 (11)	$526,585
David E. Brody Vice President & General Counsel	2007	$200,000	--	$416,308 (3)	(2)	$616,308
Lyle R. Nelson Vice President of Operations and Production	2007	$186,800	$9,469	$104,077 (3)	$36,950 (12)	$337,296
Jim Bob Byrd Vice President of Land and Business Development	2007	$150,000	$30,000	$104,077 (3)	(2)	$284,077
Thomas Schandle President and Managing Director of Sweetpea (13)	2007	$170,000	--	$104,077 (3)	(2)	$274,077

_________________

(1)	Mr. Nelson served as the Chief Executive Officer through February 7, 2007. He continued to serve as the Chairman of the Board and Chief Executive Officer of one of the Company’s subsidiaries, Paleo Technology Inc. until August 31, 2007 when Paleo Technology was sold.

(2)	Pursuant to the requirements of Item 402 of Regulation S-K, disclosure of perquisites and personal benefits has been excluded for a named officer if that officer’s total is less than $10,000.

(3)

The Company granted non-qualified stock options on May 21, 2007 that were valued at $0.42 per share which represents the FAS 123(R) value of the option on that date. Under FAS 123(R), the grant date fair value of each stock option award is calculated on the date of grant using the Black-Scholes option valuation model. The Black-Scholes model was used with the following assumptions: volatility rate of 69.66%; risk-free interest rate of 4.5% based on a U.S. Treasury rate of five years; and a 3.25-year expected option life. The options vest 60% at grant date and 20% at the one-and two-year anniversaries of the grant date. The options are exercisable at $0.50 per share and expire on May 21, 2012.

(4)	Mr. Ahlbrandt served as the Chairman of the Board and Chief Executive Officer from February 7, 2007 to July 2, 2007. He served as Vice President of Exploration throughout the 2007 fiscal year.

(5)

The Company granted options to purchase 500,000 shares under its 2005 Stock Option Plan on May 2, 2007. The FAS 123(R) value of the option on that date was $0.60 per share, using the Black-Scholes option valuation model and the following assumptions: volatility rate of 69.66%; risk-free interest rate of 4.5% based on a U.S. Treasury rate of five years; and a 3.75-year expected option life. The options vest 20% at grant date and 20% on each anniversary of the grant date. The options are exercisable at $1.11 per share and expire on May 2, 2012.

(6)	Mr. Crowell became the Chairman of the Board and Chief Executive Officer on July 2, 2007.

(7)	Includes $22,500 in director fees earned before Mr. Crowell became an officer.

(8)

The Company granted options to purchase 500,000 shares under its 2005 Stock Option Plan on February 7, 2007 upon Mr. Crowell becoming a director of the Company and 1,000,000 shares on July 2, 2007 upon Mr. Crowell assuming the office of Chairman of the Board and Chief Executive Officer. The FAS 123(R) value of the option on for the February 7, 2007 grant date was $0.66 per share, using the Black-Scholes option valuation model and the following assumptions: volatility rate of 70.35%; risk-free interest rate of 4.75% based on a U.S. Treasury rate of five years; and a 2.75-year expected option life. The options vest 50% at grant date and 50% on the one-year anniversary of the grant date. The options are exercisable at $1.38 per share and expire on February 7, 2012. The FAS 123(R) value of the option on for the July 2, 2007 grant date was $0.27 per share, using the Black-Scholes option valuation model and the following assumptions: volatility rate of 71.32%; risk-free interest rate of 4.89% based on a U.S. Treasury rate of five years; and a 3.75-year expected option life. The options vest 20% at grant date and 20% on each anniversary of the grant date. The options are exercisable at $0.49 per share and expire on July 2, 2012.

(9)	All other compensation consists of: $13,276 for commuting expenses and $23,917 for meals.

(10)	Mr. Lavold resigned his position effective September 30, 2007.

(11)	All other compensation consists of: $15,247 for personal travel, $2,575 for meals and $753 for the purchase of a cell phone.

(12)	All other compensation consists of: $16,512 for commuting expenses, $19,000 for housing expenses and $1,438 for moving expenses.

(13)	Mr. Schandle resigned his position effective December 3, 2007.

Grants of Plan Based Awards

The following table sets forth information with respect to all stock options granted during the year ended September 30, 2007 to the named Executive Officers and other highly compensated employees. Options granted on May 21, 2007 were outside of the 2005 Stock Option Plan.

GRANTS OF PLAN-BASED AWARDS
Name	Grant Date	All Other Option Awards: Number of Securities Underlying Options (#)	Exercise or Base Price of Option Awards ($/Sh)	Closing Market Price on Grant Date (1)	Grant Date Fair Value of Stock and Option Awards (2)
Kelly H. Nelson	5/21/07	500,000	$0.50	$0.70	$208,154
Thomas S. Ahlbrandt	5/02/07 5/21/07	500,000 250,000	$1.11 $0.50	$1.11 $0.70	$300,507 $104,077
Charles B. Crowell	2/07/07 7/02/07	500,000 1,000,000	$1.38 $0.49	$1.38 $0.49	$328,760 $271,538
Carmen J. Lotito	5/21/07	500,000	$0.50	$0.70	$208,154
Garry Lavold	5/21/07	500,000	$0.50	$0.70	$208,154
David E. Brody	5/21/07	1,000,000	$0.50	$0.70	$416,308
Lyle R. Nelson	5/21/07	250,000	$0.50	$0.70	$104,077
Jim Bob Byrd	5/21/07	250,000	$0.50	$0.70	$104,077
Thomas Schandle	5/21/07	250,000	$0.50	$0.70	$104,077

_______________

(1)	The May 21, 2007 option grants were made to meet commitments that had been made to employees of the Company in 2006 when the market value of the stock was $0.50 per share.

(2)

Non-qualified stock option awards made on May 21, 2007 were valued at $0.42 per share which represents the FAS 123(R) value of the option on that date. Under FAS 123(R), the grant date fair value of each stock option award is calculated on the date of grant using the Black-Scholes option valuation model. The Black-Scholes model was used

with the following assumptions: volatility rate of 69.66%; risk-free interest rate of 4.5% based on a U.S. Treasury rate of five years; and a 3.25-year expected option life. The options vest 60% at grant date and 20% at the one-and two-year anniversaries of the grant date.

The FAS 123(R) value of the stock options granted on February 7, 2007 was $0.66 per share, using the Black-Scholes option valuation model and the following assumptions: volatility rate of 70.35%; risk-free interest rate of 4.75% based on a U.S. Treasury rate of five years; and a 2.75-year expected option life. The options vest 50% at grant date and 50% on the one-year anniversary of the grant date.

The FAS 123(R) value of the stock options granted on May 2, 2007 was $0.60 per share, using the Black-Scholes option valuation model and the following assumptions: volatility rate of 69.66%; risk-free interest rate of 4.5% based on a U.S. Treasury rate of five years; and a 3.75-year expected option life. The options vest 20% at grant date and 20% on each anniversary of the grant date.

The FAS 123(R) value of the stock options granted on July 2, 2007 was $0.27 per share, using the Black-Scholes option valuation model and the following assumptions: volatility rate of 71.32%; risk-free interest rate of 4.89% based on a U.S. Treasury rate of five years; and a 3.75-year expected option life. The options vest 20% at grant date and 20% on each anniversary of the grant date.

Outstanding Equity Awards at Fiscal Year-End

OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END
Name	OPTION AWARDS
Name	Number of Securities Underlying Unexercised Options (#) Exercisable	Number of Securities Underlying Unexercised Options (#) Unexercisable (1)	Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#)	Option Exercise Price ($)	Option Expiration Date
Kelly H. Nelson	1,200,000 300,000 300,000	800,000 450,000 200,000	-- -- --	$0.50 $2.10 $0.50	8/11/2010 8/11/2011 5/21/2012
Thomas S. Ahlbrandt	300,000 100,000 150,000	450,000 400,000 100,000	-- -- --	$2.10 $1.11 $0.50	8/11/2011 5/02/2012 5/21/2012
Charles B. Crowell	250,000 200,000	250,000 800,000	-- --	$1.38 $0.49	2/07/2012 7/02/2012
Carmen J. Lotito	1,200,000 300,000 300,000	800,000 450,000 200,000	-- -- --	$0.50 $2.10 $0.50	8/11/2010 8/11/2011 5/21/2012
Garry Lavold (2)	750,000 500,000	0 0	-- --	$2.10 $0.50	8/11/2011 5/21/2012
David E. Brody	300,000 600,000	450,000 400,000	-- --	$2.10 $0.50	8/11/2011 5/21/2012
Lyle R. Nelson	300,000 150,000	450,000 100,000	-- --	$2.10 $0.50	8/11/2011 5/21/2012
Jim Bob Byrd	200,000 150,000	300,000 100,000	-- --	$2.10 $0.50	8/11/2011 5/21/2012
Thomas Schandle	200,000 150,000	300,000 100,000	-- --	$2.10 $0.50	8/11/2011 5/21/2012

_____________

(1)

The unexercisable stock options with a strike price of $2.10 vest 20% on 8/11/06 and 20% on each anniversary of that date. The unexercisable stock options with a strike price of $0.50 vest 60% on 5/21/07 and 20% on the one- and two-year anniversaries of that date. The unexercisable stock options with a strike price of $1.11 vest 20% on 5/2/07 and 20% on each anniversary of that date. The unexercisable stock options with a strike price of $1.38 vest 50% on 2/7/07 and 50% on 2/7/08. The unexercisable stock options with a strike price of $.49 vest 20% on 7/2/07 and 20% on each anniversary of that date.

(2)	Effective September 30, 2007, the vesting of all stock options granted to Garry Lavold was accelerated.

Option Exercises

The following table sets forth certain information regarding options exercised during the fiscal year ended September 30, 2007 for the persons named in the Summary Compensation Table above.

OPTION EXERCISES AND STOCK VESTED
Name	OPTION AWARDS
Name	Number of Shares Acquired on Exercise (#)	Value Realized on Exercise ($)
Kelly H. Nelson	-0-	--
Thomas S. Ahlbrandt	-0-	--
Charles B. Crowell	-0-	--
Carmen J. Lotito	-0-	--
Garry Lavold	-0-	--
David E. Brody	-0-	--
Lyle R. Nelson	-0-	--
Jim Bob Byrd	-0-	--
Thomas Schandle	-0-	--

We have no pension benefits for any of our officers or employees.

Employment Agreements

Charles B. Crowell Employment Agreement. We entered into an employment agreement with Mr. Crowell effective January 1, 2008, that currently expires on December 31, 2012. Either we or Mr. Crowell may terminate the employment relationship at any time, subject to other provisions of the agreement. Mr. Crowell serves as the Chairman and Chief Executive Officer of PetroHunter. Mr. Crowell’s employment agreement entitles him to an annual salary of $480,000, subject to increase at the discretion of the Board of Directors, as well as the issuance of options to purchase a total of 5,000,000 shares of common stock under our 2005 Stock Option Plan. The stock options were priced at $0.22 per share, which was the last reported sale price of the common stock as quoted on the OTC Bulletin Board on December 31, 2007, and are exercisable as follows: (i) 20% of the options were exercisable on January 1, 2008, and (ii) 20% of the options shall become exercisable on January 1, of each 2009, 2010, 2011, and 2012. In addition, during the first year of employment, we have agreed to pay Mr. Crowell a living allowance of $60,000 and provide twelve round-trip airline tickets from Dallas, Texas, to Denver, as well as a one-time relocation allowance of $10,000. Mr. Crowell’s employment agreement provides for the payment of salary for six months if he is terminated by us for any reason other than for cause. All grants made under the 2005 Stock Option Plan or other equity incentive plans shall vest in full immediately prior to the occurrence of a change of control. See additional information in “Potential Payments Under Termination or Change in Control.”

Potential Payments Under Termination or Change in Control

We have entered into an employment agreement with Mr. Crowell (the “Employment Agreement”), which contains provisions regarding payments to be made to Mr. Crowell upon termination of his employment. This Employment Agreement is described in greater detail above. Pursuant to the Employment Agreement, the employment of Mr. Crowell is not for any specified period of time. Either Mr. Crowell or the Company may terminate the employment relationship at any time. However, if Mr. Crowell is terminated without “cause” by PetroHunter, he will receive salary and benefits as severance in an amount equal to six months of salary. In the event Mr. Crowell is terminated as a result of a “change of control,” any unvested stock options held by him will immediately vest.

For purposes of the Employment Agreement, “for cause” means (i) his material breach of the Employment Agreement, (ii) his material failure to adhere to any written PetroHunter policy, (iii) the appropriation (or attempted appropriation) of a material business opportunity of PetroHunter, including attempting to secure or securing any personal profit in connection with any transaction entered into on behalf of PetroHunter, (iv) the misappropriation (or attempted misappropriation) of any of PetroHunter’s funds or property, or (v) the conviction of, or the entering of a guilty plea or plea of no contest with respect to, a felony.

For purposes of the Employment Agreement, a “change of control” shall be deemed to have occurred if: (i) there shall be consummated any consolidation or merger of PetroHunter with another corporation or entity and as a result of such consolidation or merger less than 50% of the outstanding voting securities of the surviving or resulting corporation or entity shall be owned beneficially, directly or indirectly, in the aggregate by the beneficial stockholders of PetroHunter; (ii) the stockholders of PetroHunter shall have approved any plan or proposal for the liquidation or dissolution of PetroHunter; or (iii) any “person” (as such term is used in the Section 13(d) and 14(d) of the Securities Exchange Act of 1934) shall have become the beneficial owner of 50% or more of our outstanding common stock.

Compensation of Directors

During 2007, each director of PetroHunter who was not a full-time employee or consultant earned a monthly director’s fee of $2,500 plus an additional monthly fee of $1,000 for each committee on which the director serves. Each director was entitled to reimbursement for reasonable travel expenses incurred in connection with such director’s attendance at Board of Directors and Committee meetings. We grant directors options under our 2005 Stock Option Plan. Vesting schedules are determined by the Board; however, most initial grants to directors vest 50% on grant date and 50% on the one-year anniversary of the initial grant date. Subsequent grants (subsequent to the initial grant) to directors typically vest 100% at the grant date. The following table sets forth the compensation paid to our non employee Directors for services rendered during the year ended September 30, 2007.

DIRECTOR COMPENSATION
Name	Fees Earned or Paid in Cash ($)	Option Awards ($)	All Other Compensation ($)	Total ($)
Martin B. Oring	$13,500 (1)	$61,256 (2)	(3)	$74,756
Matthew R. Silverman	$36,000 (4)	$328,760 (5)	(3)	$364,760
Anthony K. Yeats	$51,000 (6)	$41,631 (7)	(3)	$92,631

_______________

(1)	At September 30, 2007, we owed $13,500 in director’s fees to Mr. Oring.

(2)

Mr. Oring’s options to purchase 750,000 shares granted on September 21, 2007 was valued at $.08 per share which represents the FAS 123(R) value of the option on that date. Under FAS 123(R), the grant date fair value of each stock option award is calculated on the date of grant using the Black-Scholes option valuation model. The Black-Scholes model was used with the following assumptions: volatility rate of 62.46%; risk-free interest rate of 4.16% based on a U.S. Treasury rate of five years; and a 2.75-year expected option life. The options vest 50% upon grant date and 50% on the one-year anniversary of the grant date. The options are exercisable at $0.19 per share and expire September 21, 2012.

(3)	Pursuant to the requirements of Item 402 of Regulation S-K, disclosure of perquisites and personal benefits has been excluded for a named director if that director’s total is less than $10,000.

(4)	At September 30, 2007, we owed $4,500 in director’s fees to Mr. Silverman.

(5)

Mr. Silverman’s options to purchase 500,000 shares granted on February 7, 2007 was valued at $0.66 per share which represents the FAS 123(R) value of the option on that date. Under FAS 123(R), the grant date fair value of each stock option award is calculated on the date of grant using the Black-Scholes option valuation model. The Black-Scholes model was used with the following assumptions: volatility rate of 70.35%; risk-free interest rate of 4.75% based on a U.S. Treasury rate of five years; and a 2.75-year expected option life. The options vest 50% upon grant date and 50% on the one-year anniversary of the grant date. The options are exercisable at $1.38 per share and expire February 7, 2012.

(6)	At September 30, 2007, we owed $27,000 in director’s fees to Dr. Yeats.

(7)

Dr. Yeats options to purchase 100,000 shares granted on May 21, 2007 was valued at $0.42 per share which represents the FAS 123(R) value of the option on that date. Under FAS 123(R), the grant date fair value of each stock option award is calculated on the date of grant using the Black-Scholes option valuation model. The Black-Scholes model was used with the following assumptions: volatility rate of 69.66%; risk-free interest rate of 4.5% based on a U.S. Treasury rate of five years; and a 3.25-year expected option life. The options vest 60% upon grant date and 20% on the one- and two-year anniversaries of the grant date. The options are exercisable at $0.50 per share and expire May 21, 2012.

Stock Option Plan

On August 11, 2006, our stockholders approved the terms of the 2005 Stock Option Plan of PetroHunter Operating Company (the “Plan”). Under the Plan, we may grant certain employees both incentive and non-qualified options to purchase shares of common stock. The Plan is authorized to grant options covering up to 40,000,000 shares. When we acquired more than 85% of the outstanding stock of PetroHunter Operating Company in May 2006, we agreed to replace all existing stock options of PetroHunter Operating Company with stock options to purchase shares of our common stock having the same terms as the original grant. Accordingly in August 2006, we granted options to purchase an aggregate of 19,000,000 shares of common stock to replace those that had been granted by PetroHunter Operating Company in August 2005, including options to purchase 13,000,000 shares to MAB Operating Company. In May 2007, MAB Operating Company relinquished options to purchase 10,000,000 shares. Twenty percent of each of the options granted is exercisable immediately, and twenty percent of each option becomes exercisable on August 10th of 2006, 2007, 2008 and 2009. Each option has an exercise price of $0.50 per share, and each option expires and terminates, if not exercised sooner, on August 10, 2010.

We granted options to purchase a total of 13,295,000 shares under the Plan in August 2006 to employees and consultants. Twenty percent of each of the options granted is exercisable immediately and twenty percent of each option becomes exercisable on August 10th of 2007, 2008, 2009, and 2010. Each option has an exercise price of $2.10 per share, and each option expires and terminates, if not exercised sooner, on August 11, 2011.

During the fiscal year ended September 30, 2007, we granted options to purchase a total of 4,020,000 shares under the Plan to employees and consultants. Twenty percent of each of the options granted is exercisable upon date of grant and twenty percent of each option becomes exercisable on each anniversary of the grant date.

At March 31, 2008, options to purchase a total of 30,465,000 shares under the Plan were outstanding.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table indicates the beneficial ownership, as of June 27, 2008, of the Company’s Common Stock by (i) each director and director nominee, (ii) each Named Officer disclosed under the “Summary Compensation Table,” (iii) each person known by the Company to own more than 5% of the outstanding shares of the Company’s Common Stock, and (iv) all directors and executive officers of the Company as a group. Except as otherwise indicated below, all shares indicated as beneficially owned are held with sole voting and investment power.

Name and Address of Beneficial Owner (1)	Amount and Nature of Beneficial Ownership	Percent of Class (2)
Marc A. Bruner 29 Blauenweg Metzerlen, Switzerland 4116	160,400,000 (3)	43.1%
MAB Resources LLC 1875 Lawrence Street, Suite 1400 Denver, CO 80202	158,400,000 (4)	42.6%
Nobu Ventures, Inc. Austrasse 15 Vaduz 9490, Switzerland	30,000,000	8.9%
Global Project Finance AG Sunnaerai 1 Sachsein 6072, Switzerland	20,140,000 (5)	5.7%
Charles B. Crowell	4,540,000 (6)	1.3%

Name and Address of Beneficial Owner (1)	Amount and Nature of Beneficial Ownership	Percent of Class (2)
Martin B. Oring	3,875,001 (7)	1.1%
David E. Brody	2,880,001 (8)	0.8%
Carmen J. Lotito	2,700,000 (9)	0.8%
Jim Bob Byrd	1,230,000 (10)	0.4%
Thomas S. Ahlbrandt	850,000 (11)	0.3%
Matthew R. Silverman	800,000 (12)	0.2%
Lyle R. Nelson	743,000 (13)	0.2%
Anthony K. Yeats	480,000 (14)	0.1%
Kyle WhiteJohnson	210,000 (15)	0.1%
Robert Perlman	120,000 (16)	(17)
Charles A. Josenhans	0	--
All officers and directors as a group (11 persons)	18,428,002 (18)	5.2%

_______________

(1)	To our knowledge, except as set forth in the footnotes to this table and subject to applicable community property laws, each person named in the table has sole voting and investment power with respect to the shares set forth opposite such person’s name.

(2)

This table is based on 338,065,950 shares of Common Stock outstanding as of June 27, 2008. If a person listed on this table has the right to obtain additional shares of Common Stock within sixty (60) days from June 27, 2008, the additional shares are deemed to be outstanding for the purpose of computing the percentage of class owned by such person, but are not deemed to be outstanding for the purpose of computing the percentage of any other person.

(3)

Included in Mr. Bruner’s share ownership are 124,000,000 shares owned of record by MAB Resources LLC and 2,000,000 shares owned of record by BioFibre Technology International, Inc. Mr. Bruner is a control person of both these entities. Also included in Mr. Bruner’s share ownership are 34,400,000 shares issuable upon exercise of vested stock options and warrants held by MAB Resources LLC.

(4)	Includes 2,400,000 shares issuable upon exercise of vested stock options and 32,000,000 shares issuable upon exercise of warrants.

(5)	Includes 16,600,000 shares issuable upon exercise of warrants held by Global Project Finance AG.

(6)	Includes 2,500,000 shares issuable upon exercise of vested stock options, 1,000,000 shares issuable upon conversion of debentures and 1,040,000 shares issuable upon exercise of warrants.

(7)	Includes 475,000 shares issuable upon exercise of vested stock options, 1,666,667 shares issuable upon conversion of debentures and 1,733,334 shares issuable upon exercise of warrants.

(8)	Includes 1,320,000 shares issuable upon exercise of vested stock options, 666,667 shares issuable upon conversion of debentures and 693,334 shares issuable upon exercise of warrants.

(9)	Includes 200,000 shares held of record by Mr. Lotito’s wife and 2,500,000 shares issuable upon exercise of vested stock options.

(10)	Includes 175,000 shares held jointly with Mr. Byrd’s wife and 555,000 shares issuable upon exercise of vested stock options.

(11)	Includes 850,000 shares issuable upon exercise of vested stock options.

(12)	Includes 600,000 shares issuable upon exercise of vested stock options.

(13)	Includes 703,000 shares issuable upon exercise of vested stock options.

(14)	Includes 480,000 shares issuable upon exercise of vested stock options.

(15)	Includes 210,000 shares issuable upon exercise of vested stock options.

(16)	Includes 120,000 shares issuable upon exercise of vested stock options.

(17) Less than 0.1%

(18)	Includes 12,708,000 shares issuable upon exercise vested stock options, 3,333,334 shares issuable upon conversion of debentures, and 3,466,668 shares issuable upon exercise of warrants.

Changes in Control

There are no agreements known to management that may result in a change of control of our company.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Our “Code of Conduct and Standard of Ethics” addresses our policy for dealing with transactions with affiliates and as a matter of procedure, we obtain Board of Director approval for any transaction with a director, executive officer or other affiliate of PetroHunter. A complete description of the transaction including the services or products to be provided, the financial components related to the services or products, the nature of the relationship of the entity involved in the transaction, and any other contractual obligations related to the transaction is presented to the Board of Directors for their review. The Board of Directors indicates their approval of the transaction with a written resolution.

Other than the transactions described below, none of our present directors, officers or principal stockholders, nor any family member of the foregoing, nor, to the best of our information and belief, any of our former directors, officers or principal stockholders, nor any family member of such former directors, officers or principal stockholders, has or had any material interest, direct or indirect, in any transaction, or in any proposed transaction which has materially affected or will materially affect us.

MAB Resources LLC/Marc A. Bruner

The Company and MAB Resources LLC (“MAB”) have entered into various agreements described below. MAB is a Delaware limited liability company controlled by the largest stockholder of the Company, who had an approximate 43.4% beneficial ownership interest in us at September 30, 2007. MAB is in the business of oil and gas exploration and development.

i.	MAB and the Company each owned an undivided 50% working interest in all oil and gas leases, production facilities and related assets (collectively, the “Properties”).

ii.	We were named as Operator, and had appointed a related controlled entity, MAB Operating Company LLC, as sub-operator. We and MAB agreed to sign a joint operating agreement, governing all operations.

iii.	Each party was to pay its proportionate share of costs and receive its proportionate share of revenues, subject to us bearing the following burdens:

a.	Each assignment of Properties from MAB to us reserved an overriding royalty equivalent to 3% of 8/8ths (proportionately reduced to 1.5% of our undivided 50% working interest in the Properties) (the “MAB Override”), payable to MAB out of production and sales.

b.	Each EDA provided that we would pay 100% of the cost of acquisitions and operations (“Project Costs”) up to a specified amount, after which time each party shall pay its proportionate 50% share of such costs. The maximum specified amount of Project Costs of which we were to pay 100%, under the Development Agreement for properties acquired in the future, was $100.0 million per project. There was no “before payout” or “after payout” in the traditional sense of a “carried interest” because our obligation to expend the specified amount of Project Costs and MAB’s receipt of its 50% share of revenues applied without regard to whether or not “payout” had occurred. Therefore, our payment of all Project Costs up to such specified amount may have occurred before actual payout, or may have occurred after actual payout, depending on each project and set of Properties.

c.	Under the Development Agreement, we were to pay to MAB monthly project development costs representing a specified portion of MAB’s “carried” Project Costs. The total amount incurred to MAB by us was to be deducted from MAB’s portion of the Project Costs carried by the Company. During 2007, 2006 and 2005, we paid MAB $1.8 million, $4.5 million and $0.9 million, respectively, for Project costs which are classified on the consolidated statements of operations as Property development— related party in the affected periods.

ii.	A consulting agreement was agreed upon, including our obligation to pay fees in the amount of $25,000 per month for services rendered to us for which we paid a total of $0.2 million, during the year ended September 30, 2007,

iii.	As a result of MAB’s conveyance of its remaining undivided 50% working interest to us, our working interest in certain oil and gas properties increased from 50% to 100%,

iv.	Our obligation to pay up to $700.0 million in capital costs for MAB’s 50% interest as well as the monthly project cost advances against such capital costs was eliminated,

v.	We became obligated for monthly payments in the amount of $0.2 million under a $13.5 million promissory note,

vi.

vii.	MAB would receive 7% of the issued and outstanding shares of any new subsidiary with assets comprised of the subject properties,

viii.

Under the terms of the Second Amendment, effective November 1, 2007, the note payable to MAB was reduced in accordance with and in exchange for the following:

·	By $8.0 million in exchange for 16.0 million shares of our common stock with a value of $3.7 million based on the closing price of $0.23 per share at November 15, 2007, and warrants to acquire 32.0 million shares of our common stock at $0.50 per share. The warrants expire on November 14, 2009;

·	By $2.9 million in exchange for our release of MAB’s obligation to pay the equivalent amount as guarantor of the performance of Galaxy Energy Corporation under the subordinated unsecured promissory note dated August 31, 2007 and;

·	A reduction to the note payable to MAB of $0.5 million for cash payments to be made by us subsequent to September 30, 2007.

Officers

During the years ended September 30, 2007 and 2006, we incurred consulting fees related to services provided by our officers in the aggregate amounts of $0.3 million and $0.5 million, respectively, as follows: David E. Brody ($200,000 – 2007), Charles B. Crowell ($155,250 – 2007), Kelly H. Nelson ($155,000 - 2006), Carmen J. Lotito ($125,000 - 2006), and Garry Lavold ($211,650 - 2006). Amounts paid to Messrs Brody and Crowell are reflected as “Salary” in the Summary Compensation Table previously disclosed in this prospectus.

Falcon Oil & Gas Ltd.

Falcon Oil & Gas Ltd. (“Falcon”) is the lessee of approximately 13,595 square feet of office space at 1875 Lawrence Street, Suite 1400, Denver, Colorado, pursuant to the terms of a lease that expires June 30, 2011. From June 1, 2006 through January 31, 2008, we shared the offices with Falcon, and shared the costs of the office space, cost of equipment, furniture, office operating costs, administrative staff, and related expenses on a 50/50 basis. Several of the consultants and employees of Falcon’s and ours who work in the shared space perform services for both

companies pursuant to separate agreements - that is, each consultant or employee who performs work for both companies does so pursuant to separate agreements which define the scope of work for each company and which do not combine such work under one agreement. At September 30, 2007, we owed Falcon $0.5 million and at September 30, 2006, Falcon owed us $0.2 million for Falcon’s share of cost incurred pursuant to the sharing arrangement.

Marc A. Bruner is the President, Chief Executive Officer, and Chairman of the Board of Falcon. Our Vice President, General Counsel and Secretary, David E. Brody, is the Corporate Secretary and General Counsel of Falcon.

Galaxy Energy Corporation

In July 2006, Galaxy Energy Corporation (“Galaxy”) used a drilling rig under contract to us. At September 30, 2006, Galaxy owed us $712,830 for reimbursement for charges paid to a drilling company for Galaxy’s use of the rig. Galaxy paid us $703,970 during the quarter ended December 31, 2006 and the remaining $8,860 in January 2007.

The purchase price for Powder River Basin Assets was $45.0 million, with $20.0 million to be paid in cash and $25.0 million to be paid in shares of our common stock. Closing of the transaction was subject to approval by Galaxy’s secured noteholders, approval of all matters by our Board of Directors, including the Company obtaining outside financing on terms acceptable to our Board of Directors, and various other terms and conditions. Pursuant to successive monthly amendments to the Galaxy PSA, either party could terminate the agreement if closing had not occurred by August 31, 2007.

The Galaxy PSA expired by its terms on August 31, 2007. We obtained the Galaxy Note in the amount of $2.5 million, which consisted of the $2.0 million earnest deposit plus a portion of operating costs paid by us and which was due upon the later of (i) the date upon which all of Galaxy’s senior indebtedness has been paid in full and (ii) December 29, 2007. As discussed previously, MAB was guarantor of the Galaxy Note. The Galaxy Note was paid by MAB in November 2007 (by the terms of the Second and Third Amendments to the Consulting Agreement) by offsetting it against the MAB Note (see previous discussion under “MAB Resources LLC”).

Global Project Finance AG

On January 9, 2007, we entered into a Credit and Security Agreement (the “January 2007 Credit Facility”) with Global Project Finance, AG (“Global”) for mezzanine financing in the amount of $15.0 million. The January 2007 Credit Facility is collateralized by a first perfected lien on certain oil and gas properties and other assets of the Company and interest accrues at an annual rate of 6.75% over the prime rate. Interest is payable in arrears on the last day of each quarter beginning March 31, 2007. Principal payments commence at the end of the first quarter,

18 months following the date of the agreement or September 30, 2008. Principal payments shall be made in such amounts as may be agreed upon by us and Global on the then outstanding principal balance in order to repay the balance by the maturity date, July 9, 2009. We may prepay the balance in whole or in part without penalty or notice and we may terminate the facility with 30 days written notice. In the event that we sell any interest in the oil and gas properties that compromise the collateral, a mandatory prepayment is due in the amount equal to such sales proceeds, not to exceed the balance due under the January 2007 Credit Facility.

The terms of the January 2007 Credit Facility provide for the issuance of 1.0 million warrants to purchase 1.0 million shares of our common stock upon execution of the January 2007 Credit Facility, and an additional 200,000 warrants, for each $1.0 million draw of funds from the credit facility up to the total amount available under the facility, $15.0 million. The warrants are exercisable until January 9, 2012. The exercise price of the warrants is equal to 120% of the weighted-average price of our stock for the 30 days immediately prior to each warrant issuance date. Prices range from $1.30 to $2.10 per warrant. The fair value of the warrants was estimated as of each respective issue date under the Black-Scholes pricing model with the following assumptions: (i) the common stock price at market price on the date of issue; (ii) zero dividends; (iii) expected volatility of 69.2% to 71.4%; (iv) a risk-free interest rate ranging from 4.5% to 4.75%; and (v) an expected life of 2.5 years. The fair value of the warrants of $2.2 million was recorded as a discount to the credit facility and is being amortized over the life of the note. The unamortized portion of the discount is offset against the long-term notes payable on the consolidated balance sheet. We pay an advance fee (the “Advance Fee”) of 1% of all amounts drawn against the facility. In 2007, the advance fee related to the original January 2007 Credit Facility was recorded as deferred financing fees, totaled $0.2 million and is being amortized to interest expense over the life of the January 2007 Credit Facility.

Global and its controlling shareholder were stockholders of ours prior to entering into the January 2007 Credit Facility. The initial draw from the January 2007 Credit Facility of $1.5 million was converted from the convertible note offering discussed below. As of March 31, 2008, we had drawn the total $15.0 million available under the January 2007 Credit Facility.

On May 21, 2007, we entered into a second Credit and Security Agreement with Global (the “May 2007 Credit Facility”). Under the May 2007 Credit Facility, Global agreed to use its best efforts to advance up to $60.0 million to us over the following 18 months. Interest on advances under the May 2007 Credit Facility accrues at 6.75% over the prime rate and is payable quarterly beginning June 30, 2007. We pay an advance fee of 2% on all amounts drawn under the May 2007 Credit Facility. We are to begin making principal payments on the loan beginning at the end of the first quarter following the end of the 18 month funding period, December 31, 2008. Payments shall be made in such amounts as may be agreed upon by us and Global on the then outstanding principal balance in order to repay the principal balance by the maturity date, November 21, 2009. The loan is collateralized by a first perfected security interest on the same properties and assets that are collateral for the January 2007 Credit Facility. We may prepay the balance in whole or in part without penalty or notice and we may terminate the facility with 30 days written notice. In the event that we sell any interest in the oil and gas properties that comprise the collateral, a mandatory prepayment is due in the amount equal to such sales proceeds, not to exceed the balance due under the May 2007 Credit Facility. As of March 31, 2008, $17.8 million has been advanced to us under this facility. The advance fee in the amount of $0.5 million was recorded as deferred financing costs, and is being amortized over the life of the May 2007 Credit Facility.

Global received warrants to purchase 2.0 million of our shares upon execution of the May 2007 Credit Facility and 0.4 million warrants for each $1.0 million advanced under the credit facility. The warrants are exercisable until May 21, 2012, at prices equal to 120% of the volume-weighted-average price of our common stock for the 30 days immediately preceding each warrant issuance date. Prices range from $0.22 to $1.01 per warrant. The fair value of the warrants was estimated as of each respective issue date under the Black-Scholes pricing model, with the following assumptions: (i) common stock based on the market price on the issue date; (ii) zero dividends; (iii) expected volatility of 69.8% to 71.8%; (iv) risk-free interest rate of 3.1% to 4.9%; and (v) expected life of 2.3 to 2.5 years. The fair value of the warrants issuable as of March 31, 2008, in the amount of $2.5 million for advances through March 31, 2008, was recorded as a discount to the note and is being amortized over the life of the note.

On May 12, 2007, we issued a “most favored nation” letter to Global which indicated that it would extend all the economic terms from the May 2007 Credit Facility retroactively to the January 2007 Credit Facility. On May 21, 2007, when the May 2007 Credit Facility was signed, we issued an additional 1.0 million warrants for the execution

of the January 2007 Credit Facility and an additional 3.0 million warrants for the January 2007 Credit Facility based on the $15.0 million advanced under the January 2007 Credit Facility. The fair value of the warrants relating to this amendment totaled $0.6 million. We also recorded an additional $0.2 million in deferred financing costs which are being amortized over the life of the January 2007 Credit Facility. The most favored nation agreement did not extend the dates identified in the January 2007 Credit Facility; as a result, the additional deferred financing costs and loan discount are being amortized over the term of the January 2007 Credit Facility.

As of March 31, 2008, we were in default of payments in the amount of $3.9 million, which consists of unpaid interest and fees under the Credit Facilities, and we were out of compliance with various financial and debt covenants under the Global Credit Facilities as of March 31, 2008. Global has waived and released PetroHunter from any and all defaults, failures to perform, and any other failures to meet its obligations through January 15, 2009.

Global and its controlling shareholder, Christian Russenberger, were stockholders of the Company prior to entering into this Credit and Security Agreement

David E. Brody

Our Vice President, General Counsel and Secretary, David E. Brody, is a partner in the law firm of Patton Boggs LLP, where he has represented us since our inception. Mr. Brody joined us in September 2006. During the years ended September 30, 2007 and 2006, we incurred legal fees with Patton Boggs of $803,034 and $259,356, respectively. Mr. Brody does not receive any part of the fees we pay to Patton Boggs.

Future Transactions

All future affiliated transactions will be made or entered into on terms that are no less favorable to us than those that can be obtained from any unaffiliated third party. A majority of the independent, disinterested members of our board of directors will approve future affiliated transactions.

DESCRIPTION OF SECURITIES

Our authorized capital stock consists of 1,000,000,000 shares of common stock, $0.001 par value, and 100,000,000 shares of preferred stock, $0.001 par value. As of June 27, 2008, we had 338,065,950 shares of common stock and no shares of preferred stock outstanding.

The following is a summary of the rights of our capital stock as provided in our Articles of Incorporation and Bylaws. For more detailed information, please see our Articles of Incorporation and Bylaws, which have been filed as exhibits to documents filed with the SEC.

Preferred Stock

Our Board of Directors is authorized by our Articles of Incorporation to establish classes or series of preferred stock and fix the designation, powers, preferences and rights of the shares of each such class or series and the qualification, limitation or restrictions thereof without any further vote or action by our stockholders. Any shares of preferred stock so issued would have priority over our common stock with respect to dividend or liquidation rights. Any future issuance of preferred stock may have the effect of delaying, deferring or preventing a change in our control without further action by our stockholders and may adversely affect the voting and other rights of the holders of our common stock. At present we have no plans to issue any shares of preferred stock.

The issuances of shares of preferred stock, or the issuance of rights to purchase such shares, could be used to discourage an unsolicited acquisition proposal. For instance, the issuance of a series of preferred stock might impede a business combination by including class voting rights that would enable a holder to block such a transaction. In addition, under certain circumstances, the issuance of preferred stock could adversely affect the voting power of holders of our common stock. Although our Board of Directors is required to make any determination to issue preferred stock based on its judgment as to the best interests of our stockholders, our Board

could act in a manner that would discourage an acquisition attempt or other transaction that some, or a majority, of our stockholders might believe to be in their best interests or in which such stockholders might receive a premium for their stock over the then market price of such stock. Our Board presently does not intend to seek stockholder approval prior to the issuance of currently authorized stock, unless otherwise required by law or applicable stock exchange rules.

Common Stock

The holders of the common stock are entitled to one vote for each share held of record on all matters submitted to a vote of the stockholders. We do not have cumulative voting rights in the election of directors. Subject to preferences that may be granted to any then outstanding preferred stock, holders of common stock are entitled to receive ratably such dividends as may be declared by the board of directors out of funds legally available therefor as well as any distributions to the stockholders. In the event of our liquidation, dissolution or winding up, holders of common stock are entitled to share ratably in all of our assets remaining after payment of liabilities and the liquidation preference of any then outstanding preferred stock. Holders of common stock have no preemptive or other subscription of conversion rights. There are no redemption or sinking fund provisions applicable to the common stock.

Convertible Debenture Financing Warrants

In November 2007, we completed the sale of Series A 8.5% Convertible Debentures in the principal amount of $7.0 million. Investors received five-year warrants to purchase up to 46.4 million shares of common stock at prices ranging from $0.24 to $0.28 per share. A holder of a Warrant is not permitted to exercise the warrant for a number of shares of common stock greater than the number that would cause the aggregate beneficial ownership of common stock of such holder and all persons affiliated with such holder to exceed 4.99% of our then outstanding common stock. Both the number of warrants and the exercise price of the warrants are subject to anti-dilution adjustments in the event of stock dividends, stock splits, stock combinations and any other similar transactions. The warrants also give the holders the right to any additional rights, including those obtained through the consolidation, merger or sale of assets of the company or a similar transaction, that are granted, issued or sold to our stockholders as if the holders had held the number of shares of common stock acquirable upon the complete exercise of the warrants at the time such rights become available to the stockholders.

2006 Financing Warrants

In May 2006, we sold 35,442,500 shares of common stock and warrants to purchase a total of 35,442,500 shares in a private placement. The warrants are exercisable at $1.00 per share and expire in May 2011. Both the number of warrants and the exercise price of the warrants are subject to anti-dilution adjustments in the event of stock dividends, stock splits, stock combinations and any other similar transactions. The warrants also give the holders the right to any additional rights, including those obtained through the consolidation, merger or sale of assets of the company or a similar transaction, that are granted, issued or sold to our stockholders as if the holders had held the number of shares of common stock acquirable upon the complete exercise of the warrants at the time such rights become available to the stockholders.

Anti-Takeover Effects of Certain Provisions of Nevada Law and Our Articles of Incorporation and Bylaws

Our Articles of Incorporation and Bylaws contain a number of provisions that could make our acquisition by means of a tender or exchange offer, a proxy contest or otherwise more difficult. These provisions are summarized below.

Special Meetings. Our Bylaws provide that special meetings of stockholders can be called by the Chairman of the Board, the Chief Executive Officer, a majority of the Board, or the Secretary at the written request of stockholders entitled to cast at least a majority of all the votes entitled to be cast at the meeting.

Undesignated Preferred Stock. The ability to authorize undesignated preferred stock makes it possible for our Board of Directors to issue preferred stock with voting or other rights or preferences that could impede the success of any attempt to acquire us. The ability to issue preferred stock may have the effect of deterring hostile takeovers or delaying changes in control or management of our company.

Advance Notice Procedure for Director Nominations and Stockholder Proposals. Our Bylaws provide that adequate notice must be given to nominate candidates for election as directors or to make proposals for consideration at annual meetings of stockholders. Notice of a stockholder’s intent to nominate a director must be delivered to or mailed and received at our principal executive offices as follows:

·	for an election to be held at the annual meeting of stockholders, not earlier than 120 days or later than 90 calendar days prior to the anniversary date of the immediately preceding annual meeting of stockholders; and

·	for an election to be held at a special meeting of stockholders, not later than the later of (1) 90 calendar days prior to the special meeting or (2) 10 calendar days following the public announcement of the special meeting.

Notice of a stockholder’s intent to raise business at an annual meeting must be received at our principal executive offices not later than 90 calendar days prior to the anniversary date of the preceding annual meeting of stockholders.

These procedures may operate to limit the ability of stockholders to bring business before a stockholders’ meeting, including the nomination of directors and the consideration of any transaction that could result in a change in control and that may result in a premium to our stockholders.

Transfer Agent and Registrar

The transfer agent and registrar for our common stock is Empire Stock Transfer Inc. Its address is 2470 Saint Rose Parkway, Suite 304, Henderson, Nevada 89074, and its telephone number is (702) 818-5898.

SELLING STOCKHOLDERS

This prospectus covers the offer and sale by the selling stockholders of up to 101,990,559 shares of common stock owned or to be owned on exercise of warrants. All shares issued or to be issued are and will be restricted securities as that term is defined in Rule 144 under the Securities Act of 1933, and will remain restricted unless and until such shares are sold pursuant to this prospectus, or otherwise are sold in compliance with Rule 144.

No stockholder may offer or sell shares of our common stock under this prospectus unless such stockholder has notified us of his or her intention to sell shares of our common stock and the registration statement of which this prospectus is a part has been declared effective by the SEC, and remains effective at the time such selling stockholder offers or sells such shares. We are required to amend the registration statement of which this prospectus is a part to reflect material developments in our business and current financial information. Each time we file a post-effective amendment to our registration statement with the SEC, it must first become effective prior to the offer or sale of shares of our common stock by the selling stockholders.

The table below lists the selling stockholders and other information regarding the beneficial ownership of the common stock by the selling stockholders. The second column lists the number of shares of common stock held, plus the number of shares of common stock, based on its ownership of the convertible debentures and the warrants, that would have been issuable to the selling stockholders, assuming conversion of all convertible debentures and exercise of the warrants held by the selling stockholders on that date, without regard to any limitations on conversions or exercise. The third column lists the shares of common stock being offered by this prospectus by the selling stockholders.

The common stock covered by this prospectus is to be offered for the account of the following selling stockholders listed below. All material relationships that any security holder has had with us or any of our predecessors or affiliates in the past three years are disclosed in footnotes to the table.

The following selling stockholders purchased shares of common stock and warrants in January 2006. We are registering for resale the shares issuable upon exercise of the warrants.

			Ownership After Offering
Name of Selling Stockholder	Number of Shares Beneficially Owned (1)	Shares Registered for Resale	Number of Shares	Percent (2)
2S Vermogensverwaltung GmbH	200,000	100,000	100,000	*
AK Asset Management GIMBH	25,000	25,000	0	--
Artemis Alpha Trust	3,300,000	3,300,000	0	--
Bank Sal. Oppenheim Jr. & Cie (Switzerland) Ltd.	100,000	50,000	50,000	*
Andreas Beyer	200,000	100,000	100,000	*
Amar Bhalla	220,000	75,000	145,000	*
Suresh & Nutan Bhalla	75,000	75,000	0	--
Blumont Hirsch Performance Fund	300,000	300,000	0	--
BMO Nesbitt Burns	1,200,000	1,200,000	0	--
Tobias Bosler	100,000	100,000	0	--
Brunner & Lanni Asset Management AG	555,000	375,000	180,000	0.1%
Robert Burschik	250,000	125,000	125,000	*
Coppertree Mustang Fund Limited	1,000,000	1,000,000	0	--
Cornhill Asset Management Ltd.	5,700,000	5,700,000	0	--
Delta One Northern Rivers Fund LP	24,000	24,000	0	--
Delta One Northern Rivers RSP Fund	13,200	13,200	0	--
Euro America (Perinvest)	1,200,000	1,200,000	0	--
Forest Nominees Limited	1,100,000	1,100,000	0	--
Fortis HK via Huet (Firestone)	500,000	500,000	0	--
GLG European Long-Short Fund	4,550,713	1,300,000	3,250,713	1.0%
GLG Global Utilities Fund	6,700,000	1,700,000	5,000,000	1.5%
Global Equity Trading & Finance Ltd.	250,000	125,000	125,000	*
Jeff Green	100,000	100,000	0	--
Richard Hamm	150,000	75,000	75,000	*
Huet & Cie on behalf of 0240/779268	230,000	230,000	0	--
Huet & Cie on behalf of 0240/779270	230,000	230,000	0	--
Jeffrey J. Shier Holdings, Inc.	50,000	50,000	0	--
Christian Jueptner	50,000	50,000	0	--
Julius Baer via Huet	1,040,000	1,040,000	0	--
L-R Global Fund, Ltd.	1,680,000	1,680,000	0	--
L-R Global Partners	1,820,000	1,820,000	0	--
M.F. Van Til	60,000	60,000	0	--
Stuart MacGreagor	50,000	25,000	25,000	*
Kevin T. McKnight	1,120,000	30,000	1,090,000	0.3%
Millennium Partners LP	1,000,000	1,000,000	0	--
Nesbitt Burns in Trust	600,000	600,000	0	--
Northern Rivers Innovation Fund LP	362,800	362,800	0	--
Steven Palmer	200,000	200,000	0	--
Tony Pampena	50,000	50,000	0	--
Rosalind Saper	120,000	120,000	0	--
Robert Sarcher	100,000	100,000	0	--
Sceptre Canadian Equity Fund	30,000	30,000	0	--
Sceptre Investment Counsel Ltd.	3,970,000	3,970,000	0	--
Jorg Schwarz	50,000	25,000	25,000	*

			Ownership After Offering
Name of Selling Stockholder	Number of Shares Beneficially Owned (1)	Shares Registered for Resale	Number of Shares	Percent (2)

Rick Shobin	500,000	500,000	0	--
Smith & Williamson	500,000	500,000	0	--
SNT Solar Nano Tech AG	75,000	37,500	37,500	*
Patrick D. Soares	100,000	50,000	50,000	*
Ravi Sood	100,000	100,000	0	--
Richard David Straker-Smith	200,000	100,000	100,000	*
Markus Straub	200,000	100,000	100,000	*
Tectonic Fund	500,000	500,000	0	--
TFB Capital GmbH	3,030,000	1,515,000	1,515,000	0.5%
Daniel Thung	10,000	10,000	0	--
WAV Wertpapieranalysen Verlagsgesellschaft mbH	200,000	100,000	100,000	*
Gerd Weger	350,000	175,000	175,000	*
WH Ireland	120,000	120,000	0	--
Winton Capital Holdings Ltd.	250,000	250,000	0	--
Verena Witzelberger	100,000	50,000	50,000	*
TOTAL	46,860,713	34,442,500	12,418,213

_____________

* Less than 0.1%

(1)

The shares of common stock considered beneficially owned by each selling stockholder equal that number of shares of our common stock that such selling stockholder could acquire by converting its convertible debentures at the initial conversion price of $0.15 per share and by exercising the warrants.

(2)	Based on 338,065,950 shares outstanding as of June 27, 2008.

The following selling stockholders purchased convertible debentures and warrants in November 2007. We are registering for resale the shares issuable upon exercise of the warrants.

			Ownership After Offering
Name of Selling Stockholder	Number of Shares Beneficially Owned (1)	Shares Registered for Resale	Number of Shares	Percent (2)
David E. Brody (3)	2,880,001	693,334	2,186,667	0.6%
Charles B. Crowell (4)	4,540,000	1,040,000	3,500,000	1.0%
J.R. Darne as Trustee of the Montac Trust (5)	2,963,078	1,510,589	1,452,489	0.4%
Desmodio Management, Inc. (6)	3,040,000	1,040,000	2,000,000	0.6%
Equity Trust Co., Custodian FBO Raymond John Pfenning IRA	257,776	111,023	146,753	*
David E. Fisher	779,999	346,666	433,333	0.1%
HSBC Marking Name Nominee (UK) Limited A/C ExPco	3,498,009	1,681,338	1,816,671	0.5%
Hapi Handels und Beteiligungs GmbH (7)	14,280,000	7,280,000	7,000,000	2.0%
Bruce E. Lazier	679,999	346,666	333,333	0.1%
Bruce E. Lazier DBP	340,001	173,334	166,667	0.1%
Danielle H. Lazier	340,001	173,334	166,667	0.1%
Martin Oring (8)	3,875,001	1,733,334	2,141,667	0.6%
Premier RENN US Emerging Growth Fund Limited (9)	6,799,999	3,466,666	3,333,333	1.0%

			Ownership After Offering
Name of Selling Stockholder	Number of Shares Beneficially Owned (1)	Shares Registered for Resale	Number of Shares	Percent (2)

Renaissance US Growth & Investment Trust PLC (9)	27,199,999	13,866,666	13,333,333	3.8%
Renaissance Capital Growth & Income Fund III, Inc. (9)	13,600,001	6,933,334	6,666,667	1.9%
Elsbeth Russenberger	608,000	208,000	400,000	0.1%
U.S. Special Opportunities Trust PLC (9)	6,799,999	3,466,666	3,333,333	1.0%
WES-TEX Drilling Company, L.P. (10)	4,080,000	2,080,000	2,000,000	0.6%
West Indies Enterprises Ltd. (11)	4,490,000	2,080,000	2,410,000	0.7%
TOTAL	101,051,863	48,230,950	52,820,913

_____________

*	Less than 0.1%

(1)

(2)	Based on 338,065,950 shares outstanding as of June 27, 2008.

(3)	Mr. Brody is the Vice President, General Counsel and Secretary of the Company. Shares owned after the offering include 1,320,000 shares issuable upon exercise of vested stock options.

(4)	Mr. Crowell is the Chairman of the Board and Chief Executive Officer of the Company. Shares owned after the offering include 2,500,000 shares issuable upon exercise of vested stock options.

(5)	J.R. Darne exercises voting and/or dispositive power over these securities.

(6)	Karl-Heinz Hemmerle exercises voting and/or dispositive power over these securities.

(7)	M. Hirschmann exercises voting and/or dispositive power over these securities.

(8)	Mr. Oring is a director of the Company. Shares owned after the offering include 475,000 shares issuable upon exercise of vested stock options.

(9)	Russell Cleveland exercises voting and/or dispositive power over these securities.

(10)	Carmen Reimann exercises voting and/or dispositive power over these securities.

(11)	Robert W. Richards exercises voting and/or dispositive power over these securities.

The following selling stockholder received shares of common stock in May 2008 as payment of financing costs of gas production facilities. We are registering these shares for resale.

			Ownership After Offering
Name of Selling Stockholder	Number of Shares Beneficially Owned	Shares Registered for Resale	Number of Shares	Percent (1)
CCES Piceance Partners II, LLC (2)	400,000	400,000	0	--

________________

(1)	Based on 338,065,950 shares outstanding as of June 27, 2008.

The following selling stockholders received shares of common stock in June 2008 as payment of amounts that we owed them. We are registering those shares for resale.

			Ownership After Offering
Name of Selling Stockholder	Number of Shares Beneficially Owned	Shares Registered for Resale	Number of Shares	Percent (1)
BJ Services Company, U.S.A.	169,745	169,745	0	--
Black Hills Trucking, Inc.	190,755	190,755	0	--
Bronco Drilling Company, Inc.	10,000,000	10,000,000	0	--
Colorado Tubulars	792,589	792,589	0	--
Frank’s Westates Services, Inc.	250,000	250,000	0	--
Halliburton Energy Services, Inc.	2,110,345	2,110,345	0	--
Henderson Equipment Sales & Rental, Inc.	144,329	144,329	0	--
KLA Consulting	1,018,945	1,018,945	0	--
MI Swaco	183,971	183,971	0	--
Brad L. Mollman	27,575	27,575	0	--
Mud Control Equipment Corp.	383,850	383,850	0	--
Nevis Energy Services Inc.	782,786	782,786	0	--
Plexus Capital, LLC	1,018,945	1,018,945	0	--
Premier Pipe	271,772	271,772	0	--
Scientific Drilling International, Inc.	1,188,019	1,188,019	0	--
Simons Petroleum, Inc.	82,874	82,874	0	--
Smith International Inc.	60,170	60,170	0	--
Wood Group Pressure Control	240,439	240,439	0	--
TOTAL	18,917,109	18,917,109	0	--

_________________

(1)	Based on 338,065,950 shares outstanding as of June 27, 2008.

PLAN OF DISTRIBUTION

Each Selling Stockholder of the common stock and any of their pledgees, assignees and successors-in-interest may, from time to time, sell any or all of their shares of common stock on the OTC Bulletin Board or any other stock exchange, market or trading facility on which the shares are traded or in private transactions. These sales may be at fixed or negotiated prices. A Selling Stockholder may use any one or more of the following methods when selling shares:

·	ordinary brokerage transactions and transactions in which the broker-dealer solicits purchasers;

·	block trades in which the broker-dealer will attempt to sell the shares as agent but may position and resell a portion of the block as principal to facilitate the transaction;

·	purchases by a broker-dealer as principal and resale by the broker-dealer for its account;

·	an exchange distribution in accordance with the rules of the applicable exchange;

·	privately negotiated transactions;

·	settlement of short sales entered into after the effective date of the registration statement of which this prospectus is a part;

·	broker-dealers may agree with the Selling Stockholders to sell a specified number of such shares at a stipulated price per share;

·	through the writing or settlement of options or other hedging transactions, whether through an options exchange or otherwise;

·	a combination of any such methods of sale; or

·	any other method permitted pursuant to applicable law.

The Selling Stockholders may also sell shares under Rule 144 under the Securities Act of 1933, as amended (the “Securities Act”), if available, rather than under this prospectus.

Broker-dealers engaged by the Selling Stockholders may arrange for other brokers-dealers to participate in sales. Broker-dealers may receive commissions or discounts from the Selling Stockholders (or, if any broker-dealer acts as agent for the purchaser of shares, from the purchaser) in amounts to be negotiated, but, except as set forth in a supplement to this Prospectus, in the case of an agency transaction not in excess of a customary brokerage commission in compliance with FINRA Rule 2440; and in the case of a principal transaction a markup or markdown in compliance with FINRA IM-2440.

In connection with the sale of the common stock or interests therein, the Selling Stockholders may enter into hedging transactions with broker-dealers or other financial institutions, which may in turn engage in short sales of the common stock in the course of hedging the positions they assume. The Selling Stockholders may also sell shares of the common stock short and deliver these securities to close out their short positions, or loan or pledge the common stock to broker-dealers that in turn may sell these securities. The Selling Stockholders may also enter into option or other transactions with broker-dealers or other financial institutions or the creation of one or more derivative securities which require the delivery to such broker-dealer or other financial institution of shares offered by this prospectus, which shares such broker-dealer or other financial institution may resell pursuant to this prospectus (as supplemented or amended to reflect such transaction).

The Selling Stockholders and any broker-dealers or agents that are involved in selling the shares may be deemed to be “underwriters” within the meaning of the Securities Act in connection with such sales. In such event, any commissions received by such broker-dealers or agents and any profit on the resale of the shares purchased by them may be deemed to be underwriting commissions or discounts under the Securities Act. Each Selling Stockholder has informed us that it does not have any written or oral agreement or understanding, directly or indirectly, with any person to distribute the Common Stock. In no event shall any broker-dealer receive fees, commissions and markups which, in the aggregate, would exceed eight percent (8%).

We are required to pay certain fees and expenses incurred by us incident to the registration of the shares. We have agreed to indemnify the Selling Stockholders against certain losses, claims, damages and liabilities, including liabilities under the Securities Act.

Because Selling Stockholders may be deemed to be “underwriters” within the meaning of the Securities Act, they will be subject to the prospectus delivery requirements of the Securities Act including Rule 172 thereunder. In addition, any securities covered by this prospectus which qualify for sale pursuant to Rule 144 under the Securities Act may be sold under Rule 144 rather than under this prospectus. There is no underwriter or coordinating broker acting in connection with the proposed sale of the resale shares by the Selling Stockholders.

We agreed to keep this prospectus effective until the earlier of (i) the date on which the shares may be resold by the Selling Stockholders without registration and without regard to any volume limitations by reason of Rule 144 under the Securities Act or any other rule of similar effect or (ii) all of the shares have been sold pursuant to this prospectus or Rule 144 under the Securities Act or any other rule of similar effect. The resale shares will be sold only through registered or licensed brokers or dealers if required under applicable state securities laws. In addition, in certain states, the resale shares may not be sold unless they have been registered or qualified for sale in the applicable state or an exemption from the registration or qualification requirement is available and is complied with.

Under applicable rules and regulations under the Exchange Act, any person engaged in the distribution of the resale shares may not simultaneously engage in market making activities with respect to the common stock for the applicable restricted period, as defined in Regulation M, prior to the commencement of the distribution. In addition, the Selling Stockholders will be subject to applicable provisions of the Exchange Act and the rules and regulations thereunder, including Regulation M, which may limit the timing of purchases and sales of shares of the common stock by the Selling Stockholders or any other person. We will make copies of this prospectus available to the Selling Stockholders and have informed them of the need to deliver a copy of this prospectus to each purchaser at or prior to the time of the sale (including by compliance with Rule 172 under the Securities Act).

LEGAL MATTERS

Dill Dill Carr Stonbraker & Hutchings, P.C., Denver, Colorado, has given an opinion on the validity of the securities.

EXPERTS

We have included the financial statements of the company as of September 30, 2007 and 2006, and for the years ended September 30, 2007 and 2006 and the period from inception (June 20, 2005) to September 30, 2005, in reliance upon the report of Hein & Associates LLP, an independent registered public accounting firm, to the extent and for the periods indicated in their report also incorporated by reference, and are included in reliance upon such report and upon the authority of such firm as experts in accounting and auditing.

ADDITIONAL INFORMATION

We are subject to the reporting and other requirements of the Securities Exchange Act of 1934, as amended, and in accordance therewith file or furnish reports, proxy statements and other information with the SEC. These reports, proxy statements and other information may be read and copied at the Public Reference Room of the SEC at 100 F Street, N.E., Washington, D.C. 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. Reports, proxy and information statements and other information about us that we file or furnish electronically with the SEC are available at the SEC’s website at www.sec.gov or at our website at www.petrohunter.com.

The information in this prospectus itself may not contain all the information that may be important to your decision whether to invest in the common stock. You should read the entire prospectus, including the documents

incorporated by reference into the prospectus (as well as the exhibits to those documents), before making an investment decision.

Any statement contained in any document included herein shall be deemed to be modified or superseded, for purposes of this prospectus, to the extent that a statement contained in or omitted from this prospectus, or in any other subsequently filed document which also is or is deemed to be incorporated by reference herein, modifies or supersedes such statement. Any such statement so modified or superseded shall not be deemed, except as so modified or superseded, to constitute a part of this prospectus.

REPORTS TO STOCKHOLDERS

We are subject to the reporting requirements of the federal securities laws, and are required to file periodic reports and other information with the SEC. We will furnish our stockholders with annual reports containing audited financial statements certified by independent public accountants following the end of each fiscal year and quarterly reports containing unaudited financial information for the first three quarters of each fiscal year following the end of such fiscal quarter.

INDEX TO FINANCIAL STATEMENTS

Financial Statements

	Condensed Consolidated Balance Sheet
		March 31, 2008 (unaudited)	F-1

	Condensed Consolidated Statements of Operations
		Six Months Ended March 31, 2008 and 2007 and the Cumulative Period from Inception (June 20, 2005) to March 31, 2008 (unaudited)	F-2

	Condensed Consolidated Statements of Stockholders’ Equity and Comprehensive Loss for the Six
		Months Ended March 31, 2008 (unaudited)	F-3

	Condensed Consolidated Statements of Cash Flows
		Six Months Ended March 31, 2008 and 2007 and the Cumulative Period from Inception (June 20, 2005) to March 31, 2008 (unaudited)	F-4

	Notes to Consolidated Financial Statements (unaudited)		F-6

	Report of Independent Registered Public Accounting Firm		FF-1

	Consolidated Balance Sheets
		September 30, 2007 and 2006	FF-2

	Consolidated Statements of Operations
		Years Ended September 30, 2007 and 2006, Period from Inception (June 20, 2005) to September 30, 2005 and the Cumulative Period from Inception (June 20, 2005) to September 30, 2005	FF-3

	Consolidated Statements of Stockholders’ Equity and Comprehensive Loss
		Period from Inception (June 20, 2005) to September 30, 2007	FF-4

	Consolidated Statements of Cash Flows
		Years Ended September 30, 2007 and 2006, Period from Inception (June 20, 2005) to September 30, 2005 and Cumulative from Inception (June 20, 2005) to September 30, 2005	FF-5

	Notes to Consolidated Financial Statements		FF-6

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited, $ in thousands, except share and per share amounts)

	March 31, 2008			September 30, 2007
ASSETS
Current Assets
Cash and cash equivalents	$	1,592		$	120
Receivables
Oil and gas receivables, net		184			487
Other receivables		15			59
Due from related parties		160			500
Note receivable - related party		-			2,494
Prepaid expenses and other assets		69			187
Marketable securities, trading		-			-
Total Current Assets		2,020			3,847

Property and Equipment, at cost
Oil and gas properties under full cost method, net		173,975			162,843
Furniture and equipment, net		447			569
		174,422			163,412
Other Assets
Joint interest billings		1,029			13,637
Restricted cash		549			599
Deposits and other assets		48			-
Deferred financing costs		713			529
Intangible asset		2,756			-
Total Assets	$	181,537		$	182,024
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Notes payable - short-term	$	2,109		$	4,667
Convertible notes payable		400			400
Accounts payable and accrued expenses		26,695			26,631
Note payable - related party - current portion		2,805			3,755
Note payable - current portion of long-term liabilities		120			120
Accrued interest payable		5,130			2,399
Accrued interest payable - related party		720			516
Due to shareholder and related parties		1,058			1,474
Contract payable - oil and gas properties		-			1,750
Contingent purchase obligation		2,756			-
Total Current Liabilities		41,793			41,712

Notes payable - net of discount		30,099			27,944
Subordinated notes payable - related parties		1,401			9,050
Convertible notes payable - net of discount		2,997			-
Asset retirement obligation		104			136
Total Liabilities		76,394			78,842

Common Stock Subscribed		-			2,858

Commitments and Contingencies
Stockholders' Equity
Preferred stock, $0.001 par value; authorized 100,000,000 shares; none issued		-			-
Common stock, $0.001 par value; authorized 1,000,000,000 shares; 318,748,841 and 278,948,841 shares issued and outstanding at March 31, 2008 and September 30, 2007, respectively		319			279
Additional paid-in-capital		193,240			172,672
Accumulated other comprehensive loss		(41	)		(5	)
Deficit accumulated during the development stage		(88,375	)		(72,622	)
Total Stockholders' Equity		105,143			100,324
Total Liabilities and Stockholders' Equity	$	181,537		$	182,024

See accompanying notes to condensed consolidated financial statements.

F-1

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited; $ in thousands except per share amounts)

	Six months ended March 31, 2008			Six months ended March 31, 2007 (restated)			Cumulative From Inception (June 20, 2005) to March 31, 2008

Revenues
Oil and gas revenues	$	783		$	1,338		$	3,639
Other revenues		209			-			209
Total revenues		992			1,338			3,848

Costs and expenses
Lease operating expenses		240			386			1,037
General and administrative		5,690			8,002			38,639
Property development - related party		-			1,815			7,205
Impairment of oil and gas properties		-			8,951			24,053
Consulting fees - related party		-			75			-
Depreciation, depletion, amortization and accretion		441			1,213			1,759
Total operating expenses		6,371			20,442			72,693

Loss from operations		(5,379	)		(19,104	)		(68,845	)
Other income (expense):
Gain on foreign exchange		11			-			34
Interest income		27			14			66
Interest expense		(7,425	)		(2,231	)		(16,643	)
Trading security losses		(2,987	)		-			(2,987	)
Total other expense		(10,374	)		(2,217	)		(19,530	)
Net loss	$	(15,753	)	$	(21,321	)	$	(88,375	)
Net loss per common share - basic and diluted	$	(0.05	)	$	(0.10	)
Weighted average number of common shares outstanding - basic and diluted		312,610			221,245

See accompanying notes to condensed consolidated financial statements

F-2

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE LOSS

(unaudited, $ in thousands except share and per share amounts)

	Common Stock				Additional Paid-in			Deficit Accumulated During the Development			Accumulated Other Comprehensive		Total Stockholders'			Total Comprehensive
	Shares		Amount		Capital			Stage			Loss		Equity			Loss
Balances, June 20, 2005 (inception)		-	$	-	$	-		$	-		$	-	$	-		$	-
Shares issued to founder at $0.001 per share		100,000,000		100		-			-			-		100			-
Stock-based compensation costs for options granted to non- employees		-		-		823			-			-		823			-
Net loss		-		-		-			(2,119	)		-		(2,119	)		(2,119	)
Balances, September 30, 2005		100,000,000		100		823			(2,119	)		-		(1,196	)		(2,119	)
Shares issued for property interests at $0.50 per share		3,000,000		3		1,497			-			-		1,500			-
Shares issued for finder's fee on property at $0.50 per share		3,400,000		3		1,697			-			-		1,700			-
Shares issued upon conversion of debt, at $0.50 per share		44,063,334		44		21,988			-			-		22,032			-
Shares issued for commission on convertible debt at $0.50 per share		2,845,400		3		1,420			-			-		1,423			-
Sale of shares and warrants at $1.00 per unit		35,442,500		35		35,407			-			-		35,442			-
Shares issued for commission on sale of units		1,477,500		1		1,476			-			-		1,477			-
Costs of stock offering:
Cash		-		-		(1,638	)		-			-		(1,638	)		-
Shares issued for commission at $1.00 per share		-		-		(1,478	)		-			-		(1,478	)		-
Exercise of warrants		1,000,000		1		999			-			-		1,000			-
Recapitalization of shares issued upon merger		28,700,000		30		(436	)		-			-		(406	)		-
Stock-based compensation		-		-		9,189			-			-		9,189			-
Net loss		-		-		-			(20,692	)		-		(20,692	)		(20,692	)
Balances, September 30, 2006		219,928,734		220		70,944			(22,811	)		-		48,353			(20,692	)
Shares issued for property interests at $1.62 per share		50,000,000		50		80,950			-			-		81,000			-
Shares issued for property interests at $1.49 per share		256,000		-		382			-			-		382			-

F-3

	Common Stock					Additional Paid-in			Deficit Accumulated During the Development			Accumulated Other Comprehensive			Total Stockholders'			Total Comprehensive
	Shares		Amount			Capital			Stage			Loss			Equity			Loss
Shares issued for commission costs on property at $1.65 per share	121,250			-			200			-			-			200			-
Shares issued for finance costs on property at $0.70 per share	642,857			1			449			-			-			450			-
Shares issued for property and finance interests at various costs per share	8,000,000			8			6,905			-			-			6,913			-
Foreign currency translation adjustment	-			-			-			-			(5	)		(5	)		(5	)
Discount on notes payable	-			-			4,670			-			-			4,670			-
Stock-based compensation	-			-			8,172			-			-			8,172			-
Net loss	-			-			-			(49,811	)		-			(49,811	)		(49,811	)
Balances, September 30, 2007	278,948,841			279			172,672			(72,622	)		(5	)		100,324			(49,816	)
Shares issued for property interests at $0.31 per share	25,000,000			25			7,725			-			-			7,750			-
Shares issued for finance costs at $0.23 per share	16,000,000			16			3,664			-			-			3,680			-
Shares issued in conjunction with asset sale at $0.25 per share	5,000,000			5			1,245			-			-			1,250			-
Shares returned for property and retired at prices ranging from $0.23 per share to $1.72 per share	(6,400,000	)		(6	)		(5,524	)		-			-			(5,530	)		-
Shares issued for finance costs at $0.28 per share	200,000			-			56			-			-			56			-
Discounts associated with beneficial conversion feature and detachable warrants on convertible debenture issuance	-			-			6,956			-			-			6,956			-
Warrant value associated with convertible debenture issuance	-			-			21			-			-			21			-
Warrant value associated with related party amendment	-			-			705			-			-			705			-
Forgiveness of amounts due to shareholder and related party debt	-			-			4,067			-			-			4,067			-
Discount on notes payable	-			-			52			-			-			52			-
Foreign currency translation adjustment	-			-			-			-			(36	)		(36	)		(36	)
Stock-based compensation	-			-			1,601			-			-			1,601			-
Net loss	-			-			-			(15,753	)		-			(15,753	)		(15,753	)
Balances, March 31, 2008	318,748,841		$	319		$	193,240		$	(88,375	)	$	(41	)	$	105,143		$	(15,789	)

See accompanying notes to condensed consolidated financial statements.

F-4

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited, $ in thousands)

	Six months ended March 31, 2008			Six months ended March 31, 2007 (restated)			Cumulative From Inception (June 20, 2005) to December 31, 2007

Cash flows used in operating activities
Net loss	$	(15,753	)	$	( 21,321	)	$	(88,375	)
Adjustments used to reconcile net loss to net cash used in operating activities: Stock for expenditures advanced		-			-			100
Stock-based compensation		1,601			3,617			19,785
Detachable warrants recorded as interest expense		4,097			-			4,097
Depreciation, depletion, amortization and accretion		442			1,763			1,760
Impairment of oil and gas properties		-			8,400			24,053
Stock for financing costs		-			1,441			1,623
Amortization of discount and deferred financing costs on notes payable		1,205			148			2,241
Loss on trading securities		2,987			-			2,987
Gain on foreign exchange		(11	)		-			(34	)
Changes in assets and liabilities Receivables		102			(1,469	)		(444	)
Due from related party		(160	)		921			(660	)
Prepaids and other		74			24			29
Deferred financing costs		(344	)		-			(344	)
Accounts payable, accrued expenses, and other liabilities		(667	)		(854	)		4,187
Due to shareholder and related parties		7			618			1,481
Net cash used in operating activities		(6,420	)		(6,712	)		(27,514	)
Cash flows provided by (used in) investing activities
Proceeds from CD redemption		50			-			50
Additions to oil and gas properties		(5,322	)		(3,808	)		(70,987	)
Proceeds from sale of oil and gas properties		7,500			-			7,500
Sale of trading securities		2,541			-			2,541
Deposit on oil and gas property acquisition		-			(12,863	)		(2,494	)
Additions to property and equipment		(16	)		(95	)		(703	)
Restricted cash		-			(525	)		(1,077	)
Net cash provided by (used in) investing activities		4,753			(17,291	)		(65,170	)
Cash flows from financing activities
Proceeds from the sale of common stock		-			-			35,742
Proceeds from common stock subscribed		-			3,067			2,858
Proceeds from the issuance of notes payable		1,150			12,500			32,700
Payments on long-term debt		(40	)		-			(40	)
Borrowing on short-term notes payable		1,755			-			2,255
Payments on short-term notes		(5,648	)		-			(5,648	)
Payments on contracts payable		(250	)		-			(250	)
Payments on related party borrowing		(219	)		(450	)		(219	)
Proceeds from related party borrowing		420			-			695
Proceeds from the exercise of warrants		-			-			1,000
Cash received upon recapitalization and merger		-			-			21
Proceeds from issuance of convertible notes		6,334			-			27,166
Offering and financing costs		(350	)		(44	)		(1,988	)
Net cash provided by financing activities		3,152			15,073			94,292
Effect of exchange rate changes on cash		(13	)		-			(16	)
Net increase (decrease) in cash and cash equivalents		1,472			(8,930	)		1,592
Cash and cash equivalents, beginning of period		120			10,632			-
Cash and cash equivalents, end of period	$	1,592		$	1,702		$	1,592
Supplemental schedule of cash flow information
Cash paid for interest	$	21		$	-		$	1,522
Cash paid for income taxes	$	-		$	-		$	-

See accompanying notes to condensed consolidated financial statements.

F-5

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1 - Organization and Basis of Presentation

We are a development stage global oil and gas exploration and production company committed to acquiring and developing primarily unconventional natural gas and oil prospects that we believe have a very high probability of economic success. Since our inception in 2005, our principal business activities have been raising capital through the sale of common stock and convertible notes and acquiring oil and gas properties in the western United States and Australia. Currently, we own property in Colorado, where we have drilled five wells on our Buckskin Mesa property, and Australia, where we have drilled one well on our property in the Northern Territory, and in Montana, where we hold a land position in the Bear Creek area. The wells on these properties have not yet commenced oil and gas production. We own working interests in eight additional wells in Colorado which are operated by EnCana Oil & Gas USA ("EnCana") and are currently producing gas. In November 2007, we sold 66,000 net acres of land and two wells in Montana and 177,445 acres of land in Utah (see Note 4) and subsequent to March 31, 2008, we entered into a binding purchase and sale agreement to sell up to 1,059 net acres and 16 wells in the Southern Piceance Basin in Colorado (see Note 13).

Our predecessor, Digital Ecosystems Corp. ("Digital"), was incorporated on February 21, 2002 under the laws of the state of Nevada. On February 10, 2006, Digital entered into a Share Exchange Agreement (the "Exchange Agreement") with GSL Energy Corporation ("GSL") and certain shareholders of GSL pursuant to which Digital acquired more than 85% of the issued and outstanding shares of common stock of GSL in exchange for shares of Digital's common stock. The Exchange Agreement was completed on May 12, 2006. At that time, GSL's business, which was formed in 2005 for the purpose of acquiring, exploring, developing and operating oil and gas properties, became Digital's business and GSL became a subsidiary of Digital. Since this transaction resulted in the former shareholders of GSL acquiring control of Digital, for financial reporting purposes, the business combination was accounted for as an additional capitalization of Digital (a reverse acquisition with GSL as the accounting acquirer). In accounting for this transaction:

i.	GSL was deemed to be the purchaser and parent company for financial reporting purposes. Accordingly its net assets were included in the consolidated balance sheet at their historical book value; and

ii.	control of the net assets and business of Digital was effective May 12, 2006 for no consideration.

Subsequent to the closing of the Exchange Agreement, Digital acquired all the remaining outstanding stock of GSL, and effective August 14, 2006, Digital changed its name to PetroHunter Energy Corporation ("PetroHunter"). Likewise, in October 2006, GSL changed its name to PetroHunter Operating Company.

PetroHunter is considered a development stage company as defined by Statement of Financial Accounting Standards ("SFAS") 7, Accounting and Reporting by Development Stage Enterprises, as we have not yet commenced our planned principal operations. A development stage enterprise is one in which planned principal operations have not commenced, or if its operations have commenced, there have been no significant revenue therefrom.

Unless otherwise noted in this report, any description of "us" or "we" refers to PetroHunter Energy Corporation and our subsidiaries. Financial information in this report is presented in U.S. dollars.

Note 2 - Summary of Significant Accounting Policies

Basis of Accounting. The accompanying financial statements have been prepared on the basis of accounting principles applicable to a going concern, which contemplates the realization of assets and extinguishment of liabilities in the normal course of business. As shown in the accompanying statements of operations, we have incurred a cumulative loss in the amount of $88.4 million for the period from inception (June 20, 2005) to March 31, 2008, have a working capital deficit of approximately $39.8 million as of March 31, 2008, were not in compliance with the covenants of several loan agreements, have had multiple property liens and foreclosure actions filed by vendors and have significant capital expenditure commitments. As of March 31, 2008, we have earned oil and gas revenue from our initial operating wells, but will require significant additional funding to sustain operations and satisfy contractual obligations for planned oil and gas exploration, development and operations in the future. These factors, among others, may indicate that we may be unable to continue in existence. Our financial statements do not include adjustments related to the realization of the carrying value of assets or the amounts and classification of liabilities that might be necessary should we be unable to continue in existence. Our ability to establish ourselves as a going concern is dependent upon our ability to obtain additional financing to fund planned operations

F-6

and to ultimately achieve profitable operations. Management believes that we can be successful in obtaining equity and/or debt financing and/or sell interests in some of our properties, which will enable us to continue in existence and establish ourselves as a going concern. We have raised approximately $102.4 million through March 31, 2008 through issuances of common stock and convertible and other debt.

For the six-month period ending March 31, 2008 and 2007, the condensed consolidated financial statements include the accounts of PetroHunter and our wholly-owned subsidiaries. For the period from June 20, 2005 through September 30, 2005, the consolidated financial statements include only the accounts of GSL. All significant intercompany transactions have been eliminated upon consolidation.

The accompanying financial statements should be read in conjunction with our Annual Report on Form 10-K for the year ended September 30, 2007. The accompanying condensed consolidated financial statements are unaudited; however, in the opinion of management, they include all normal recurring adjustments necessary for a fair presentation of our consolidated financial position at March 31, 2008 and the consolidated results of our operations and cash flows for the six-month period ending March 31, 2008 and 2007. The results of operations for the six-month period ending March 31, 2008 are not necessarily indicative of the results that may be expected for the full fiscal year ending September 30, 2008 or for any other interim period in the September 2008 fiscal year. Further, the accompanying balance sheet as of September 30, 2007 was derived from audited financial statements.

Use of Estimates. Preparation of our financial statements in accordance with Generally Accepted Accounting Principles ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses for the reporting period. Actual results could differ from those estimates.

In the course of preparing the consolidated financial statements, management makes various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenue and expenses, and to disclose commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established.

The more significant areas requiring the use of assumptions, judgments and estimates relate to volumes of natural gas and oil reserves used in calculating depletion, the amount of expected future cash flows used in determining possible impairments of oil and gas properties and the amount of future capital costs estimated for such calculations. Assumptions, judgments and estimates are also required to determine future abandonment obligations, the value of undeveloped properties for impairment analysis and the value of deferred tax assets.

Reclassifications. Certain prior period amounts have been reclassified in the consolidated financial statements to conform to the current period presentation. Such reclassifications had no effect on our net loss.

Marketable Securities, Trading. In November 2007, we sold our Heavy Oil assets (see Note 4, Oil and Gas Properties). As partial consideration, we accepted a total of 1,539,975 shares of common stock of the purchaser, Pearl Exploration and Production Ltd. These shares were sold subsequent to a holding period, and were classified as held for sale in the short term at December 31, 2007. During the intervening period from closing through the date of sale in March 2008, we accounted for them by marking them to market with unrealized losses recognized in our operating results in the period incurred. During the second quarter ended March 31, 2008, and as more fully described in Notes 4 and 12, we recorded certain adjustments in relation to these marketable securities due to the correction of an error. In addition to the reversal of $0.9 million of unrealized losses on these securities that was initially recorded during the first quarter, we recognized a loss on the disposition of our trading securities in the amount of $1.5 million recorded as Trading Security Losses in our consolidated statement of operations during the second quarter.

Joint Interest Billings. Joint interest billings represents our working interest partners' share of costs that we paid, on their behalf, to drill certain wells. During the first quarter of 2008, we entered into a transaction whereby we increased our interest in 14 wells to 100% (see Note 4, Oil and Gas Properties) and we therefore reclassified $12.6 million of costs related to those wells from Joint interest billings to Oil and gas properties.

F-7

Oil and Gas Properties. We utilize the full cost method of accounting for our oil and gas activities. Under this method, subject to a limitation based on estimated value, all costs associated with property acquisition, exploration and development, including costs of unsuccessful exploration, are capitalized within a cost center on a by-country basis. No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas properties unless the sale represents a significant portion of oil and gas properties and the gain significantly alters the relationship between capitalized costs and proved oil and gas reserves of the cost center. Depletion and amortization of oil and gas properties is computed on the units-of-production method based on proved reserves. Amortizable costs include estimates of future development costs of proved undeveloped reserves.

Asset Retirement Obligation. Asset retirement obligations associated with tangible long-lived assets are accounted for in accordance with SFAS 143, Accounting for Asset Retirement Obligations. The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of oil and gas properties is recorded generally upon acquisition or completion of a well. The net estimated costs are discounted to present values using a risk adjusted rate over the estimated economic life of the oil and gas properties. Such costs are capitalized as part of the related asset. The asset is depleted on the units-of-production method on a field-by-field basis. The liability is periodically adjusted to reflect (1) new liabilities incurred, (2) liabilities settled during the period, (3) accretion expense, and (4) revisions to estimated future cash flow requirements. The accretion expense is recorded as a component of depletion, amortization and accretion expense in the accompanying consolidated statements of operations.

Guarantees. As part of a Gas Gathering Agreement we have with CCES Piceance Partners1, LLC ("CCES"), we have guaranteed that, should there be a mutual failure to execute a formal agreement for long-term gas gathering services in the future, we will repay CCES for certain costs they have incurred in relation to the development of a gas gathering system and repurchase certain gas gathering assets we sold to CCES. We have accounted for this guarantee using FASB Interpretation No. 45 as amended, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, which requires us to recognize a liability for the obligations undertaken upon issuing the guarantee in order to have a more representationally faithful depiction of the guarantor's assets and liabilities. Accordingly, we have recognized a $2.7 million contingent purchase obligation on our balance sheet. See further explanation at Note 13.

Impairment. We use the full cost method of accounting for our oil and gas properties and as such, these properties are subject to SEC Regulation S-X Rule 4-10, Financial Accounting and Reporting for Oil and Gas Producing Activities Pursuant to the Federal Securities Laws and the Energy Policy and Conversion Act of 1975 ("Rule 4-10"). Rule 4-10 requires that each regional cost center's (by country) capitalized cost, less accumulated amortization and related deferred income taxes not exceed a cost center "ceiling." The ceiling is defined as the sum of:

The present value of estimated future net revenues computed by applying current prices of oil and gas reserves to estimated future production of proved oil and gas reserves as of the balance sheet date less estimated future expenditures to be incurred in developing and producing those proved reserves to be computed using a discount factor of 10%; plus
The cost of properties not being amortized; plus
The lower of cost or estimated fair value of unproven properties included in the costs being amortized; less
Income tax effects related to differences between the book and tax basis of the properties.

If unamortized costs capitalized within a cost center, less related deferred income taxes, exceed the cost center ceiling, the excess is charged to expense. During the six-month period ended March 31, 2008, we did not record any impairment charges. During the six-month period ended March 31, 2007, we recorded an impairment charge of $9.0 million.

Fair Value. The carrying amount reported in the consolidated balance sheets for cash, receivables, prepaids, accounts payable and accrued liabilities approximates fair value because of the immediate or short-term maturity of these financial instruments. Based upon the borrowing rates currently available to us for loans with similar terms and average maturities, the fair value of payable notes, approximates their carrying value.

Environmental Contingencies. Oil and gas producing activities are subject to extensive environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require us to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental

F-8

expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.

Revenue Recognition. We recognize revenues from the sales of natural gas and crude oil related to our interests in producing wells when delivery to the customer has occurred and title has transferred. We currently have no gas balancing arrangements in place.

Loss per Common Share. Basic loss per share is based on the weighted average number of common shares outstanding during the period. Diluted loss per share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Convertible equity instruments such as stock options and convertible debentures are excluded from the computation of diluted loss per share, as the effect of the assumed exercises would be anti-dilutive. The dilutive weighted-average number of common shares outstanding excluded potential common shares from stock options and warrants of approximately 114,169,114 and 48,701,500 for the periods ended March 31, 2008 and 2007, respectively.

Recently Issued Accounting Pronouncements. In February 2007, the Financial Accounting Standards Board ("FASB") issued SFAS 159, The Fair Value Option for Financial Assets and Financial Liabilities, which allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value that are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item's fair value in subsequent reporting periods must be recognized in current earnings. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparison between entities that elect different measurement attributes for similar assets and liabilities. SFAS 159 will be effective for us on October 1, 2008. We have not assessed the impact of SFAS 159 on our consolidated results of operations, cash flows or financial position.

In September 2006, the FASB issued SFAS 157, Fair Value Measurements, which provides guidance for using fair value to measure assets and liabilities. The standard also responds to investors' requests for more information about: (1) the extent to which companies measure assets and liabilities at fair value; (2) the information used to measure fair value; and (3) the effect that fair value measurements have on earnings. SFAS 157 will apply whenever another standard requires (or permits) assets or liabilities to be measured at fair value. SFAS 157 does not expand the use of fair value to any new circumstances. SFAS 157 will be effective for us on October 1, 2008. We have not assessed the impact of SFAS 157 on our consolidated results of operations, cash flows or financial position.

Supplemental Cash Flow Information. Supplement cash flow information for the six months ended March 31, 2008 and 2007, respectively, and cumulative from inception (June 2005) is as follows:

	Six Months Ended March 31, 2008			Six Months Ended March 31, 2007(restated)		Cumulative From Inception (June 20, 2005) to March 31, 2008
	($ in thousands)
Supplemental disclosures of non-cash investing and financing activities
Shares issued for expenditures advanced	$	-		$	-	$	100
Contracts for oil and gas properties	$	(7,030	)	$	2,900	$	6,494
Shares issued for debt conversion	$	-		$	-	$	22,032
Shares issued for commissions on offerings	$	50		$	200	$	250
Shares issued for property	$	1,250		$	81,275	$	82,525
Shares issued for property and finder's fee on property	$	-		$	-	$	9,644
Warrants issued for debt	$	2,954		$	-	$	7,624
Non-cash uses of notes payable, accounts payable and accrued liabilities	$	-		$	-	$	26,313
Convertible debt issued for property	$	-		$	-	$	1,200
Common stock issuable	$	-		$	4,128	$	-
Shares issued for common stock offerings	$	-		$	-	$	2,900
Debt issued for common stock previously subscribed	$	2,858		$	-	$	2,858
Assignment of rights in properties in exchange for stock and forgiveness of related party notes payable	$	15,959		$	-	$	15,959
Satisfaction of receivable by reduction of related party note payable	$	2,992		$	-	$	2,992

F-9

Debt discount related to beneficial conversion feature		$	3,959			$	-			$	3,959
Increase in oil and gas properties related to relief of joint interest billings		$	12,608			$	-			$	12,608

Note 3 - Agreements with MAB Resources LLC

We have entered into various agreements with MAB Resources LLC ("MAB"), a company that is controlled by our largest shareholder, Marc A. Bruner. The following is a summary of those agreements.

The Development Agreement. From July 1, 2005 through December 31, 2006, we and MAB operated pursuant to a Development Agreement and a series of individual property agreements (collectively, the "EDAs"). The Development Agreement defined MAB's and our long-term relationship regarding the ownership and operation of all jointly-owned properties and stipulated that we and MAB would sign a joint operating agreement governing all operations. The Development Agreement specified, among other things, that:

MAB assign to us a 50% undivided interest in any and all oil and gas leases, production facilities and related assets (collectively, the "Properties") that MAB was to acquire from third parties in the future, we would be operator of the jointly owned properties, with MAB Operating Company LLC as sub-operator, and each party would pay its proportionate share of costs and receive its proportionate share of revenues, subject to certain adjustments, including our burden to carry MAB for specified costs, pay advances, and to make an overriding royalty payment of 3% (gross, or 1.5% net) to MAB out of production and sales.

A more thorough description of the Development Agreement is included in Item 8 of our Annual Report on Form 10-K, Financial Statements and Supplementary Data - Note 3.

The Consulting Agreement. Effective January 1, 2007, we and MAB began operating under an Acquisition and Consulting Agreement (the "Consulting Agreement") which replaced in its entirety the Development Agreement described above. Upon execution of the Consulting Agreement, MAB conveyed its entire remaining working interest in the Properties to us in consideration for a $13.5 million promissory note, 50 million shares of PetroHunter Energy Corporation and an additional 50 million shares (the "Performance Shares") provided we met certain thresholds based on proven reserves. Furthermore, MAB would receive:

7% of the issued and outstanding shares of any new subsidiary with assets comprised of the subject properties
A 5% overriding royalty interest on certain of the properties, to be accrued and deferred for three years, provided these royalties do not render our net revenue interest to be less than 75%, and
$25,000 per month for consulting services (which was later rescinded by Amendment 1 to the Consulting Agreement, effective retroactively to January 1, 2007).

Our obligation to pay up to $700.0 million in capital costs for MAB's 50% interest as well as the monthly project cost advances against such capital costs was also eliminated.

We accounted for the acquisition component of the Consulting Agreement in accordance with the purchase accounting provisions of SFAS 141 Business Combinations. Accordingly, at the date of acquisition, we recorded oil and gas properties of $94.5 million, notes payable of $13.5 million, and common stock and additional-paid-in capital totaling $81.0 million (equal to the 50.0 million shares issued to MAB at the trading price of $1.62 per share for our common stock on the trading date immediately preceding the closing date of the transaction).

In the first quarter of the current fiscal year ending September 30, 2008, the Consulting Agreement was amended three times, resulting in the following changes:

MAB relinquished portions of its overriding royalty interest effective October 1, 2007 such that the override currently only applies to our Australian properties and Buckskin Mesa property;
MAB received 25.0 million additional shares of our common stock;
MAB relinquished all rights to the Performance Shares described above;
MAB's consulting services were terminated effective retroactively back to January 1, 2007;
MAB waived all past due amounts and all claims against PetroHunter; and
the note payable to MAB was reduced in accordance with and in exchange for the following:

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by $8.0 million in exchange for 16.0 million shares of our common stock with a value of $3.7 million based on the closing price of $0.23 per share at November 15, 2007 and warrants to acquire 32.0 million shares of our common stock at $0.50 per share. The warrants expire on November 14, 2009 and were valued at $0.7 million;
by $2.9 million in exchange for our release of MAB's obligation to pay the equivalent amount as guarantor of the performance of Galaxy Energy Corporation under the subordinated unsecured promissory note dated August 31, 2007 (see Note 10);
a reduction to the note payable to MAB of $0.5 million for cash payments made during the first quarter of 2008; and
by $0.2 million for MAB assuming certain costs that Paleo Technology owed to us.

The net effect of the reduction of debt and issuance of our common shares resulted in a net benefit to us of $3.8 million and has been reflected as additional paid-in-capital during the six months ended March 31, 2008. Monthly payments on the revised promissory note in the amount of $2.0 million commenced February 1, 2008 and are due in full in two years.

Note 4 - Oil and Gas Properties

Oil and gas properties consisted of the following:

	March 31, 2008			September 30, 2007
Oil and gas properties, at cost, full cost method	($ in thousands)
Unproved
United States	$	107,135		$	107,239
Australia		24,099			23,569
Proved - United States		44,172			57,168
Total		175,406			187,976
Less accumulated depreciation, depletion, amortization and impairment		(1,431	)		(25,133	)
Total	$	173,975		$	162,843

In the six months ended March 31, 2008 and 2007, oil and gas properties included capitalized interest of $0.2 million and $0.4 million, respectively.

Included below is a summary of significant activity related to oil and gas properties during the six-month period ended March 31, 2008.

PICEANCE BASIN

Buckskin Mesa Project. As of March 31, 2008, we had drilled five wells, with two wells having been completed and shut-in, awaiting completion of the gathering system, and the remaining 3 wells awaiting completion. We are required to drill 16 wells during the calendar year ending December 31, 2008, three during the first quarter and four during each of the second and third calendar quarters of 2008 and five during the fourth calendar quarter of 2008, under the terms of an agreement between us and a third party assignor, Daniels Petroleum Company ("DPC"). If we do not satisfy these quarterly drilling requirements, our agreement with DPC requires that we pay DPC $0.5 million for each undrilled well on the last day of the applicable quarter. At the end of the first calendar quarter of 2008, we extended and subsequently exercised our right to pay $0.5 million in penalties for three wells that were required to be drilled that quarter by agreeing to pay the $1.5 million fee, plus a $1.0 million additional penalty. These amounts were paid on April 28, 2008, thereby reducing the total number of wells we are committed to drill for the remainder of calendar year 2008 to 13. We currently estimate our cost to drill and complete each well at $3.0 million, aggregating $39.0 million for the remaining 13 wells.

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Piceance II Project. As of March 31, 2008, we had drilled, but did not complete, 16 wells.

On December 10, 2007, we entered into two agreements with EnCana Oil & Gas (USA) Inc. ("EnCana") to exchange and augment interests in certain Piceance Basin properties, which resulted in an increase in our working interest in 12 of the 16 wells mentioned above as follows:

Exchange 1 -- We received from EnCana an interest in 40 net acres, including two net and gross wells, and conveyed to EnCana interests in 19 gross wells and 0.4 net wells. We and EnCana relieved each other of existing obligations related to all past costs and operations of the respective properties exchanged. EnCana's share of the costs to drill the two wells of $3.2 million reflected as Joint interest billings in our consolidated balance sheet at September 30, 2007 was reclassified to Oil and gas properties during the first quarter ended December 31, 2007. In addition, our accounts receivable from EnCana for oil and gas sales and accounts payable to EnCana for lease operating expenses from the 19 wells, of $0.2 million and $0.1 million respectively, as of December 31, 2007, was also reclassified to Oil and gas properties during the first quarter ended December 31, 2007.

Exchange 2 -- We received from EnCana an interest in 99 net acres, including 10 gross wells (5 net). EnCana's share of the costs to drill the 10 wells of $9.4 million reflected as Joint interest billings in our consolidated balance sheet at September 30, 2007 was reclassified to Oil and gas properties during the first quarter ended December 31, 2007. In addition, we paid EnCana $1.0 million at closing that is also reflected in Oil and gas properties during the first quarter ended December 31, 2007.

By the terms of a Lease Acquisition and Development Agreement between MAB, Apollo Energy LLC and ATEC Energy Ventures and a third oil and gas lease pertaining to the Piceance II properties, we were required to drill 10 wells by December 31, 2008. Of the 10 wells, we drilled two during the fiscal year ended September 30, 2007 and we paid 100% of the costs to drill those two wells (two of the 16 wells mentioned above). Our joint interest partner's share in the amount of $1.0 million is reflected as Joint interest billings on our consolidated balance sheet at March 31, 2008. We have estimated total estimated costs to drill and complete the 8 additional wells at approximately $16.8 million ($10.5 million to our 62.5% interest). We are currently conducting negotiations with the owners of the remaining 37.5% working interest owners to trade their interest in this lease for other oil and gas interests owned by us.

Sugarloaf Project. We failed to make payments in accordance with the agreement related to this prospect and as a result, on December 4, 2007, the agreement was terminated and we instructed the escrow agent to return all assignments which were being held in escrow to the seller (See Note 6).

AUSTRALIA

Australia Project. We own four exploration licenses comprising 7.0 million net acres in the Beetaloo Basin (owned by our wholly-owned subsidiary, Sweetpea Petroleum Pty Ltd., ["Sweetpea"]). In July 2007, we drilled and cased one well to a depth of 4,724 feet, with the intention to deepen the well at a later date.

Beetaloo Project. We have a 100% working interest in this project with a royalty interest of 10% to the government of the Northern Territory and an overriding royalty interest of 1% to 2%, 8% and 5% to the Northern Land Council, the original assignor of the

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licenses, and to MAB, respectively, leaving a net revenue interest of 75% to 76% to us. We have committed to drill five wells at a total estimated cost of $20.0 million related to this property.

Northwest Shelf Project. Effective February 19, 2007, the Commonwealth of Australia granted an exploration permit in the shallow, offshore waters of Western Australia to Sweetpea. The permit has a six year term and encompasses almost 20,000 net acres. We have committed to an exploration program with geological and geophysical data acquisition in the first two years with a third year drilling commitment and additional wells to be drilled in the subsequent three year period depending upon the results of the initial well.

POWDER RIVER BASIN

On December 29, 2006, we entered into a purchase and sale agreement (the "Galaxy PSA") with Galaxy Energy Corporation ("Galaxy") and its wholly-owned subsidiary, Dolphin Energy Corporation ("Dolphin"), both of which are related parties to us. Pursuant to the Galaxy PSA, we agreed to purchase all of Galaxy's and Dolphin's oil and gas interests in the Powder River Basin of Wyoming and Montana (the "Powder River Basin Assets"), and to assume operations as contract operator, pending the purchase.

In January 2007, we paid a $2.0 million earnest money deposit to Galaxy, which was due under the terms of the Galaxy PSA. As contract operator of the Powder River Basin Assets, we incurred $0.8 million in expenses. The Galaxy PSA expired by its terms on August 31, 2007. Upon expiration and under the terms of the Galaxy PSA, we obtained a note receivable in the amount of $2.5 million (the "Galaxy Note") which consisted of the $2.0 million earnest deposit plus a portion of operating costs paid by us. As guarantor of the Galaxy Note, MAB repaid the balance in November 2007 by offsetting it against amounts owed by us to MAB under the MAB Note (see Notes 3 and 7).

MONTANA COALBED METHANE

Bear Creek Project. We have retained 13,905 acres of the original 25,278 acres of leasehold acquired through an assignment from MAB. The remaining 11,373 acres of leasehold have expired. The acres retained have been reflected in unproved oil and gas properties and are subject to further evaluation. The acres released have been reflected in unproved properties but included in evaluated costs subject to amortization and in the full cost ceiling test at the lower of cost or market value.

HEAVY OIL

Sale of Heavy Oil Projects. On November 6, 2007 and effective October 1, 2007, we sold a majority of our interest in certain of our Heavy Oil Projects, including the West Rozel, Fiddler Creek and Promised Land Projects, to Pearl Exploration and Production Ltd. ("Pearl"). The purchase price was a maximum of $30.0 million, payable as follows: (a) $7.5 million in cash at closing; (b) the issuance of up to 2.5 million shares of Pearl equivalent to $10 million (based on a price of $4.00 Canadian dollars per share, as stipulated in the purchase and sale contract), and (c) a performance payment (the "Pearl Performance Payment") of $12.5 million in cash at such time as either: (i) production from the assets reaches 5,000 barrels per day or (ii) proven reserves from the assets is greater than 50.0 million barrels of oil as certified by a third party reserve engineer. In the event that these targets have not been achieved by September 30, 2010, the Pearl Performance Payment obligation will expire. As of March 31, 2008, no amounts have been accrued in relation to the Pearl Performance Payment as the triggering events have not yet occurred. In addition, the number of shares included in (b) above may be reduced by 960,025 shares (valued in the contract at $3.8 million based on a price of $4.00 per share, as above) if a satisfactory agreement is not made between Pearl and the lessor ("ECA") of certain of the properties within 6 months of the date of closing (that being May 6, 2008). No such satisfactory agreement was reached between Pearl and ECA and therefore, the total amount conveyed in (b) above was 1,539,975 shares.

We originally accounted for the sale of the Heavy Oil Project assets to Pearl to include the sale of the ECA properties, as we believed at that time it was probable Pearl and ECA would reach agreement and the ECA assets would be conveyed to Pearl within the six month period contemplated in our agreement with Pearl. During the second quarter, we were informed that agreement between Pearl and ECA would not be reached, and that the ECA assets would not transfer to Pearl. As a result, we reviewed the original accounting for the transaction and determined that we had inappropriately included the 960,025 shares of Pearl stock relating to the ECA assets in our marketable securities as of December 31, 2007, and further, we had recorded unrealized losses on those shares during the first quarter in error. During the second quarter, we recorded correcting entries in our financial statements which resulted in (a) the reversal of $0.9 million of unrealized losses on the shares of Pearl stock we did not ultimately receive, and (b) the reversal into our full cost pool of $3.5 million of marketable securities we originally recorded in anticipation of closing the sale of the ECA assets. During March 2008, we sold all of the 1,539,975 shares of Pearl stock we did receive, which resulted in net proceeds of $2.5 million. The

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difference between the value of these shares at closing of $5.5 million and the net proceeds received upon sale, was recorded as Trading Security Losses in our consolidated results of operations for the six months ended March 31, 2008. See Note 12 for further discussion.

The sale of assets to Pearl also resulted in amendments to existing agreements with third parties, including MAB's relinquishment of its rights and obligations in all PetroHunter properties in Utah and Montana, and termination of PetroHunter's obligation to pay an overriding royalty and a per barrel production payment to American Oil & Gas, Inc. ("American") and Savannah Exploration, Inc. ("Savannah"), in consideration for: (a) 5 million common shares of PetroHunter common stock to be issued to American and Savannah; and (b) a contingent obligation to pay a total of $2.0 million to American and Savannah in the event PetroHunter receives the Pearl Performance Payment.

Note 5 - Asset Retirement Obligation

We recognize an estimated liability for future costs associated with the abandonment of our oil and gas properties. A liability for the fair value of an asset retirement obligation and a corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is completed or acquired. The increase in carrying value is included in proved oil and gas properties in the consolidated balance sheets. We deplete the amount added to proved oil and gas property costs and recognize accretion expense in connection with the discounted liability over the remaining estimated economic lives of the respective oil and gas properties.

Our estimated asset retirement obligation liability is based on estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. The credit-adjusted risk-free rates used to discount our abandonment liabilities range from 8% to 15%. Revisions to the liability are due to increases in estimated abandonment costs and changes in well economic lives, or in changes to federal or state regulations regarding the abandonment of wells.

A reconciliation of our asset retirement obligation liability is as follows:

	March 31, 2008			September 30, 2007
	($ in thousands)
Beginning asset retirement obligation	$	136		$	522
Liabilities incurred		1			30
Liabilities settled		(35	)		-
Revisions to estimates		-			(429	)
Accretion expense		2			13
Ending asset retirement obligation	$	104		$	136

Note 6 - Contract Payable

On November 28, 2006, MAB entered into a Lease Acquisition and Development Agreement (the "Maralex Agreement") with Maralex Resources, Inc. and Adelante Oil & Gas LLC (collectively, "Maralex") for the acquisition and development of the Sugarloaf Prospect in Garfield County, Colorado. MAB subsequently assigned the Maralex Agreement to us in January 2007 (the "Assignment"). By the terms of the Maralex Agreement and subsequent Assignment, we paid $0.1 million at closing, with the remaining cash of $2.9 million and the issuance of 2.4 million shares of our common stock due on January 15, 2007. We recorded the $2.9 million obligation as Contract payable - oil and gas properties, and $4.1 million as stockholders' equity (equal to 2.4 million shares at the $1.70 closing price of our common stock on the date of the closing).

The terms of the Maralex Agreement and Assignment were amended on several occasions since the original Agreement was executed, amending the payment dates, issuing 5.6 million additional shares of our common stock and agreeing to increase the amount of cash due under the agreement by a total of $0.3 million. By the terms of the Maralex Agreement, we were required to pay to Maralex an amount equal to 5% of the outstanding payable for each 20 days past due (the "Maralex Penalty").

We failed to make payments in accordance with the Maralex Agreement and as a result, on December 4, 2007, Maralex terminated the Maralex Agreement and notified us that, in accordance with the terms of the Maralex Agreement, they returned 6.4 million shares of

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common stock and we instructed the escrow agent to reassign to Maralex all leases which were being held in escrow pursuant to the Maralex Agreement.

During the six months ended March 31, 2008, in accordance with the termination of this agreement, we (i) reclassified the balance of Contract payable - Oil and gas properties in the amount of $1.5 million to Oil and gas properties; (ii) recorded the return of 80% of the additional equity consideration as a reduction of Oil and gas properties and equity and (iii) reversed the remaining accrued liabilities to Oil and gas properties.

Note 7 - Notes Payable

Notes payable are summarized below:

	March 31, 2008			September 30, 2007
	($ in thousands)
Notes payable - short-term:
Wes-Tex	$	-		$	-
Global Project Finance AG		-			500
Shareholder note		850			-
Vendor		1,224			4,050
Flatiron Capital Corp.		35			117
Notes payable - short-term	$	2,109		$	4,667
Convertible notes payable	$	400		$	400
Notes payable - related party - current portion:
Bruner Family Trust	$	2,705		$	-
Wealth Preservation		100			-
MAB- current portion		-			3,755
Notes payable - related party - current portion	$	2,805		$	3,755
Subordinated notes payable - related party:
Bruner Family Trust	$	106		$	275
MAB		1,295			8,775
Subordinated notes payable - related party	$	1,401		$	9,050
Long-term notes payable - net of discount:
Global Project Finance AG	$	32,800		$	31,550
Vendor		200			250
Less current portion		(120	)		(120	)
Discount on notes payable		(2,781	)		(3,736	)
Long-term notes payable - net of discount	$	30,099		$	27,944
Convertible debt	$	6,956		$	-
Discount on convertible debt		(3,959	)		-
Convertible debt - net of discount	$	2,997		$	-

Short - Term Notes Payable

Wes-Tex. On December 18, 2007, we obtained a loan and signed a promissory note (the "Wes-Tex Note") in the amount of $0.8 million from a third party oil and gas company. The loan was collateralized by 947,153 of the Pearl shares, and accrued interest at the rate of 15%. The note and accrued interest was paid in full in March 2008.

Global Project Finance AG. On September 25, 2007, we borrowed $0.5 million from Global Project Finance, AG ("Global") under an unsecured note bearing interest at a rate of 7.75% per annum. We repaid this note in full on November 9, 2007 before it became due.

Shareholder Note. During the six months ended March 31, 2008, we entered into an agreement with a shareholder for short-term borrowings. Principal and accrued interest at 15% per annum are due in full in July 2008.

Vendor. (i) On June 19, 2007, we entered into a promissory note with a vendor for an outstanding unpaid balance due to the vendor, in the amount of $6.5 million. The note was to be paid in full by July 31, 2007 and bears interest at 14% per annum if paid current. The

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interest rate increases to 21% per annum if the note is in default. At March 31, 2008, we were in default on this note due to non-payment; the balance was $1.0 million and we had accrued interest on the note in the amount of $0.4 million. The vendor filed a judgment lien against us and garnished $0.3 million in cash. This matter has subsequently been settled. (See Note 11).

(ii) During the six months ended March 31, 2008, we entered into another promissory note with a vendor for outstanding account payable balances. The note bears interest at 8.25% per annum, increases to 10.25% if the note is in default and was due to mature February 29, 2008. At March 31, 2008, we were in default on the payment terms; the balance was $0.2 million and we had accrued interest related to this in the amount of $6,000. The payee on this note has deferred any formal claim or legal action for the payment of interest and principal for the time being, and the parties are discussing a deferred payment schedule;

(iii) On January 29, 2008 an unsecured promissory note with a vendor was entered into for past due invoices aggregating $0.1 million. The note bears interest at an annual rate of 8%. Principal plus interest was due on March 15, 2008. At March 31, 2008 we were in default on this note; however on April 8, 2008, we satisfied this note with full payment of principal and interest.

As more fully described in Note 13, subsequent to March 31, 2008 and as part of a sale of substantially all of our working interest in our Southern Piceance properties, we have entered into numerous settlements and reached agreements with many of our trade creditors, in relation to balances recorded as of March 31, 2008.

Flatiron Capital Corp. On June 6, 2007, we entered into a promissory note with Flatiron Capital for the financing of certain insurance policies in the amount of $0.2 million. The note bears interest at a rate of 7.25% per annum. Payments are due in 10 equal installments of $17,000, commencing on July 1, 2007 and maturing on April 1, 2008. The note is unsecured and the balance at March 31, 2008 was $35,000. This note was paid in full in April 2008.

Convertible Notes Payable. Prior to the merger with GSL on May 12, 2006, Digital entered into five separate loan agreements, aggregating $0.4 million, due one year from issuance, commencing October 11, 2006. The loans bear interest at 12% per annum, are unsecured, and are convertible, at the option of the lender, at any time during the term of the loan or upon maturity, at a price per share equal to the closing price of our common shares on the Over the Counter Bulletin Board market on the day preceding notice from the lender of its intent to convert the loan. As of March 31, 2008, accrued interest amounted to $0.1 million. We are in default on payment of the notes.

Note - Payable Related Party - Current Portion

Wealth Preservation. On January 25, 2008, we borrowed $0.1 million under a promissory note. The note bears interest at 15% and was due on February 29, 2008. At March 31, 2008 we were in default of this note and the interest increased to 24%. This principal balance and accrued interest of $4,000 was paid in full in April 2008.

Bruner Family Trust. During the six months ended March 31, 2008 three additional promissory notes aggregating $0.3 million were entered into with the Bruner Family Trust UTD (the "Bruner Family Trust"). Each note accrues interest at the London InterBank Offered Rate ("LIBOR") plus 3% per annum and principal and interest are due in full 12 months from issue date.

During November 2007, we entered into a promissory note with the Bruner Family Trust in the amount of $2.4 million for amounts related to a prior stock subscription that did not occur. Interest accrues at LIBOR plus 3% and principal and interest are due in November 2008.

Subordinated Notes Payable-Related Party

MAB Note. Effective January 1, 2007, in conjunction with the Consulting Agreement, we issued a $13.5 million promissory note (the "MAB Note") as partial consideration for MAB's assignment of its undivided 50% working interest in certain oil and gas properties (see Note 3). The MAB Note bore interest at a rate equal to LIBOR. Monthly payments of principal of $225,000 plus accrued interest were scheduled to begin on January 31, 2007 and were scheduled to end in December 2011. On November 15, 2007, we entered into the Second Amendment under the terms of which the MAB Note was replaced with a new promissory note in the amount of $2.0 million. The note bears interest at LIBOR per annum and is due to mature on January 1, 2010. In the event of default, the interest rate increases to 10%. At March 31, 2008, we had accrued interest on these notes in the

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amount of $0.6 million and were in default on the remaining note. MAB has waived and released PetroHunter from any and all defaults, failures to perform, and any other failures to meet its obligations through October 1, 2008.

Bruner Family Trust. On July 11, 2007, we executed a subordinated unsecured promissory note with the Bruner Family Trust in the amount of $250,000. Interest accrues at an annual rate of 8% and the note plus accrued interest is due in full on the later of October 29, 2007 or the time when the Global Project Finance AG Credit Facility and all other senior indebtedness has been paid in full. In November 2007, Charles Crowell, our Chairman and CEO, was assigned the right to receive from us approximately $0.2 million of the $0.3 million owed by us under this promissory note to the Bruner Family Trust. Mr. Crowell received this right from the Bruner Family Trust in exchange for a promissory note in the same amount which had been issued to Mr. Crowell by Galaxy for services rendered to Galaxy prior to Mr. Crowell becoming an officer of PetroHunter.

Subsequently, Mr. Crowell participated in our private placement in November 2007 to the extent of $0.2 million and in exchange for cancellation of $0.2 million of the total amount we owed to him. The balance of the amount owed to him under the note, $18,000, was then paid in cash. At March 31, 2008, the balance due to the Bruner Family Trust under this arrangement was $81,000.

On September 21, 2007, we executed a subordinated unsecured promissory note in the amount of $25,000 with the Bruner Family Trust. Interest accrues at the rate of 8% per annum and the note plus accrued interest is due in full on the later of December 20, 2007 or the time when the Global Project Finance AG Credit Facility and all other senior indebtedness has been paid in full.

Long-Term Notes Payable

Credit Facility - Global. On January 9, 2007, we entered into a Credit and Security Agreement (the "January 2007 Credit Facility") with Global for mezzanine financing in the amount of $15.0 million. The January 2007 Credit Facility is collateralized by a first perfected lien on certain oil and gas properties and other of our assets and interest accrues at an annual rate of 6.75% over the prime rate. Global and its controlling shareholder were shareholders of ours prior to entering into the January 2007 Credit Facility. As of March 31, 2008, we have drawn the total $15.0 million available under the January 2007 Credit Facility.

The terms of the January 2007 Credit Facility provide for the issuance of 1.0 million warrants to purchase 1.0 million shares of our common stock upon execution of the January 2007 Credit Facility, and an additional 0.2 warrants, for each $1.0 million draw of funds from the credit facility up to the total amount available under the facility, $15.0 million. The warrants are exercisable until January 9, 2012. The exercise price of the warrants is equal to 120% of the weighted-average price of our stock for the 30 days immediately prior to each warrant issuance date. Prices range from $1.30 to $2.10 per warrant. The fair value of the warrants was estimated as of each respective issue date under the Black-Scholes pricing model with the following assumptions: (i) the common stock price at market price on the date of issue; (ii) zero dividends; (iii) expected volatility of 69.2% to 71.4%; (iv) a risk-free interest rate ranging from 4.5% to 4.8%; and (v) an expected life of 2.5 years. The fair value of the warrants of $2.2 million was recorded as a discount to the credit facility and is being amortized over the life of the note. The unamortized portion of the discount is offset against the long-term notes payable on the consolidated balance sheet. We pay an advance fee (the "Advance Fee") of 1% of all amounts drawn against the facility. In 2007, the advance fee related to the original January 2007 Credit Facility was recorded as deferred financing fees, totaled $0.2 million and is being amortized to interest expense over the life of the January 2007 Credit Facility.

On May 21, 2007, we entered into a second Credit and Security Agreement with Global (the "May 2007 Credit Facility"). Under the May 2007 Credit Facility, Global agreed to use its best efforts to advance up to $60.0 million to us over the following 18 months. Interest on advances under the May 2007 Credit Facility accrues at an annual rate of 6.75% over the prime rate and is payable in arrears quarterly beginning June 30, 2007. We pay an advance fee of 2% on all amounts drawn under the May 2007 Credit Facility. We are to begin making principal payments on the loan beginning at the end of the first quarter following the end of the 18 month funding period: December 31, 2008. Payments shall be made in such amounts as may be agreed upon by us and Global on the then outstanding principal balance in order to repay the principal balance by the maturity date, November 21, 2009. The loan is collateralized by a first perfected security interest on the same properties and assets that are collateral for the January 2007 Credit Facility. We may prepay the balance in whole or in part without penalty or notice and we may terminate the facility with 30 days written notice. In the event that we sell any interest in the oil and gas properties that comprise the collateral, a mandatory prepayment is due in the amount equal to such sales proceeds, not to exceed the balance due under the May 2007 Credit Facility. As of March 31, 2008, $17.8 million has been advanced to us under this facility. The advance fee in the amount of $0.5 million was recorded as deferred financing costs, and is being amortized over the life of the May 2007 Credit Facility.

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Global received warrants to purchase 2.0 million of our shares upon execution of the May 2007 Credit Facility and 0.4 million warrants for each $1.0 million advanced under the credit facility. The warrants are exercisable until May 21, 2012 at prices equal to 120% of the volume-weighted-average price of our common stock for the 30 days immediately preceding each warrant issuance date. Prices range from $0.22 to $1.01 per warrant. The fair value of the warrants were estimated as of each respective issue date under the Black-Scholes pricing model, with the following assumptions: (i) common stock based on the market price on the issue date; (ii) zero dividends; (iii) expected volatility of 69.8% to 71.8%; (iv) risk free interest rate of 3.1% to 4.9%; and (v) expected life of 2.3 to 2.5 years. The fair value of the warrants issuable as of March 31, 2008, in the amount of $2.5 million for advances through March 31, 2008 under this facility, was recorded as a discount to the note and is being amortized over the life of the note.

On May 12, 2007, we issued a "most favored nation" letter to Global which indicated that we would extend all the economic terms from the May 2007 Credit Facility retroactively to the January 2007 Credit Facility. On May 21, 2007, when the May 2007 Credit Facility was signed, we issued an additional 1.0 million warrants for the execution of the January 2007 Credit Facility and an additional 3.0 million warrants for the January 2007 Credit Facility based on the $15.0 million advanced under the January 2007 Credit Facility. The fair value of the warrants relating to this amendment totaled $0.6 million. We also recorded an additional $0.2 million in deferred financing costs which are being amortized over the life of the January 2007 Credit Facility. The most favored nation agreement did not extend the dates identified in the January 2007 Credit Facility and as a result, the additional deferred financing costs and loan discount are being amortized over the term of the January 2007 Credit Facility.

As of March 31, 2008, we were in default of payments to Global in the amount of $3.9 million, which consists of unpaid interest and fees under the Credit Facilities. We were also not in compliance with various financial and debt covenants under the Global Credit Facilities as of March 31, 2008. Global has waived and released PetroHunter from any and all defaults, failures to perform, and any other failures to meet its obligations through January 15, 2009.

Vendor Long-term Notes Payable. On August 10, 2007, we entered into an unsecured promissory note with a vendor for past due invoices aggregating $0.3 million. The note bears interest at an annual rate of 8%. Payments are due in 24 equal installments of $11,000, commencing on October 1, 2007 and maturing on September 1, 2009. As of March 31, 2008, the balance of this note is $0.2 million; however on April 8, 2008 we satisfied the note with full payment of principal and interest.

Convertible Notes. On November 13, 2007, we completed the sale of Series A 8.5% Convertible Debentures (the "Debentures") in the aggregate principal amount of $7.0 million to several accredited investors. The debentures are due November 2012 and are collateralized by shares in our Australian subsidiary. Debenture holders also received five-year warrants that allow them to purchase a total of 46.4 million shares of common stock at prices ranging from $0.24 to $0.27 per share. The warrants are immediately exercisable and as a result, we recorded $3.2 million of interest expense during the six-months ended March 31, 2008. In connection with the placement of the debentures, we paid a placement fee of $0.3 million and issued placement agent warrants entitling the holders to purchase an aggregate of 0.2 million shares at $0.35 per share for a period of five years. Interest payments related to the Debentures accrues at an annual rate of 8.5% and is payable in cash or in shares (at our option) quarterly, beginning January 1, 2008. All overdue unpaid interest incurs a late fee of 18% per annum, calculated based on the entire unpaid interest balance. At March 31, 2008 we were in default on the January interest payment of $0.1 million. Accrued late fees of $4,000 were accrued related to this unpaid interest balance. The Company is also currently in default on the April 1, 2008 interest payment of $0.1 million.

We originally agreed to file a registration statement with the Securities and Exchange Commission in order to register the resale of the shares issuable upon conversion of the debentures and the shares issuable upon exercise of the warrants.

According to the Registration Rights Agreement, the registration statement was to be filed by March 4, 2008 and declared effective by July 2, 2008. The following penalties apply if filing deadlines and/or documentation requirements are not met in compliance with the stated rules: (i) the Company shall pay to each holder of Registrable Securities 1% of the purchase price paid in cash as partial liquidated damages; (ii) the maximum aggregate liquidated damages payable is 18% of the aggregate subscription amount paid by the holder; (iii) if the Company fails to pay liquidated damages in full within seven days of the date payable, the Company will pay interest of 18% per annum, accruing daily from the original due date; (iv) partial liquidated damages apply on a daily prorated basis for any portion of a month prior to the cure of an event; and (v) all fees and expenses associated with compliance to the agreement shall be incurred by the Company.

F-18

A waiver and amendment agreement relating to the above Registration Rights Agreement was signed by all investors in April and May 2008. The agreement is an extension of filing date and effectiveness date to June 30, 2008 and December 31, 2008, respectively. Each purchaser waived i) our obligation to file a registration statement covering the Registrable Securities by March 4, 2008; ii) our obligation to have such registration statement declared effective by July 2, 2008, and iii) any penalties associated with the failure to satisfy such obligations as described above. In addition, each purchaser waived as events of default, our failure to pay the January 1, 2008 and April 1, 2008 interest payments. As consideration for this waiver, we agreed to pay the interest installments due January 1, 2008 and April 1, 2008 by September 30, 2008, together with late fees of 18% per annum. In addition warrants to purchase our common stock will be issued in an amount equal to 4% of the shares each purchaser received with the original agreement. The terms of these warrants mirror the terms given in the original agreement.

The debentures have a maturity date of five years and are convertible at any time by the holders into shares of our common stock at a price of $0.15 per share, which was determined to be beneficial to the holders on the date of issuance. In accordance with EITF 00-27, we recorded a discount to the debt in the amount of $4.0 million which will be accreted to interest expense over the term of the notes.

Provided that there is an effective registration statement covering the shares underlying the debentures and the volume-weighted-average price of our common stock over 20 consecutive trading days is at least 200% of the per share conversion price, with a minimum average trading volume of 0.3 million shares per day: (i) The debentures are convertible, at our option and (ii) are redeemable at our option at 120% of face value at any time after one year from date of issuance.

Note 8 -Stockholders' Equity

Common Stock. During the six months ended March 31, 2008, we issued 46.2 million shares of our common stock and had 6.4 million shares of our common stock returned as follows:

25.0 million shares issued at $0.31 per share for consideration given to an amendment to a related party contract relinquishing overriding royalty interests (see Note 3)
16.0 million shares issued at $0.23 per share for an amendment to a related party contract reducing an outstanding note payable (see Note 3)
5.0 million shares issued at $0.25 per share in conjunction with sale of heavy oil assets
0.2 million shares issued at $0.28 per share for transaction finance costs
1.9 million shares returned at $1.70 per share for property interests
0.5 million shares returned at $1.72 per share for property interests
0.4 million shares returned at $1.29 per share for property interests
0.4 million shares returned at $0.51 per share for property interests
3.2 million shares returned at $0.23 per share for property interests

Common Stock Subscribed. On November 6, 2006, we commenced the sale of a maximum $125.0 million pursuant to a private placement of units at $1.50 per unit (the "Private Placement"). Each unit consisted of one share of our common stock and one-half common stock purchase warrant. A whole common stock purchase warrant entitled the purchaser to acquire one share of our common stock at an exercise price of $1.88 per share through December 31, 2007. In February 2007, the Board of Directors determined that the composition of the units being offered would be restructured, and those investors who had subscribed in the offering were offered the opportunity to rescind their subscriptions or to participate on the same terms as ultimately defined for the restructured offering. During the six months ended March 31, 2008, we reclassified $2.4 million of subscriptions which included $0.1 million of accrued interest to Notes Payable- Related Party.

F-19

In November, 2007, the Board of Directors again agreed to restructure the offering of the Private Placement and to pay interest at 8.5% from the date the original funds were received to the date of the issuance (see Note 7). Investors who had subscribed in the offering were again offered the opportunity to rescind their subscriptions or to participate in the restructured offering. Three of the original investors opted to participate in the above restructured offering. As a result the balance of outstanding subscriptions plus accrued interest totaling $0.5 million was reclassified from Common Stock Subscribed to Convertible notes payable - net of discount on the consolidated balance sheet.

Warrants

The following stock purchase warrants were outstanding at:

	March 31, 2008		September 30, 2007
	(warrants in thousands)
Number of warrants		130,172		51,063
Exercise price	$	0.22 - $2.10	$	0.31 - $2.10
Expiration date		2009 - 2012		2011 - 2012

In November 2007, we completed the sale of Series A 8.5% convertible debentures. Debenture holders received five-year warrants that allow them to purchase a total of 46.4 million shares of common stock at prices ranging from $0.24 to $0.27 per share (see Note 7). As of March 31, 2008, none of these warrants had been exercised and the total value of these warrants, based on valuation under the Black-Scholes method was $5.1 million. In connection with the placement of the debentures, we paid a placement fee of $0.3 million and issued placement agent warrants entitling the holders to purchase an aggregate of 0.2 million shares at $0.35 per share for a period of five years. These warrants had a total valuation under the Black-Scholes method of $20,000.

In November 2007, the Second Amendment was entered into and warrants to acquire 32.0 million shares of our common stock at $0.50 per share were issued (see Note 3). These warrants expire on November 14, 2009 and have a total value, based on valuation under the Black-Scholes method of $0.6 million.

During the six months ended March 31, 2008 we issued warrants in connection with amounts borrowed against our credit facility. We issued 0.5 million warrants valued at $0.1 million using the Black-Scholes method.

Note 9 -Stock Options

Stock Option Plan. On August 10, 2005, we adopted the 2005 Stock Option Plan (the "Plan"), as amended. Stock options under the Plan may be granted to key employees, non-employee directors and other key individuals who are committed to our interests. Options may be granted at an exercise price not less than the fair market value of our common stock at the date of grant. Most options have a five year life but may have a life up to 10 years as designated by the compensation committee of the Board of Directors (the "Compensation Committee"). Typically, options vest 20% on grant date and 20% each year on the anniversary of the grant date but each vesting schedule is also determined by the Compensation Committee. Most initial grants to Directors vest 50% on grant date and 50% on the one-year anniversary of the initial grant date. Subsequent grants (subsequent to the initial grant) to Directors typically vest 100% at the grant date. In special circumstances, the Board may elect to modify vesting schedules upon the termination of selected employees and contractors. We have reserved 40.0 million shares of common stock for the plan. At March 31, 2008 and September 30, 2007, 9.5 and 15.0 million shares, respectively remained available for grant pursuant to the stock option plan. During the six months ended March 31, 2008, we granted 8.0 million options under our 2005 stock option plan to directors, employees and consultants performing employee-like services for us. During the six months ended March 31, 2007, we granted 1.0 million options under our 2005 stock option plan to directors.

A summary of the activity under the Plan for the six months ended March 31, 2008 is presented below:

F-20

	Number of Shares			Weighted- Average Exercise Price
	(shares in thousands)
Options outstanding - September 30, 2007		24,965		$	1.31
Granted		7,950			0.21
Forfeited		(2,450	)		1.76
Options outstanding - March 31, 2008		30,465			0.99

Effective October 1, 2006, we adopted the provisions of SFAS 123(R). In accordance with SFAS 123(R) the fair value of each share-based award under all plans is estimated on the date of grant using a Black-Scholes pricing model that incorporates the assumptions noted in the following table for the three and six months ended March 31, 2008.

	2008
Expected option term - years	3.75
Weighted-average risk-free interest rate	3.62%
Expected dividend yield	0
Weighted-average volatility	71%

Deferred Stock-Based Compensation. We authorized and issued 10.1 million of non-qualified stock options not under the Plan, to employees and non-employee consultants on May 21, 2007. The options were granted at an exercise price of $0.50 per share and vest 60% at grant date and 20% per year at the one and two-year anniversaries of the grant date. These options expire on May 21, 2012.

A summary of the activity for the six months ended March 31, 2008 for these options is presented below:

	Number of Shares			Weighted-Average Exercise Price
	(shares in thousands)
Options outstanding - September 30, 2007		9,895		$	0.50
Granted		-			-
Forfeited		(1,260	)		0.50
Options outstanding - March 31, 2008		8,635			0.50
Options exercisable - March 31, 2008		5,181			0.50

Compensation Expense

Under SFAS 123(R), pre-tax stock-based employee compensation expense of $1.5 million was charged to operations for the six months ended March 31, 2008 and $1.5 million was charged to operations for the six months ended March 31, 2007, respectively. Under EITF 96-18, pre-tax stock-based non-employee compensation expense of $0.1 million was charged to operations as compensation expense for the six months ended March 31, 2008, and $2.1 million for the six months ended March 31, 2008.

Note 10 -Related Party Transactions

MAB. During the six months ended March 31, 2007, we incurred project development costs to MAB under the Development Agreement between us and MAB (see Note 3) in the amount of $1.8 million. We did not incur project development costs to MAB during the six months ended March 31, 2008. Project development costs to MAB are classified in our consolidated statements of operations as Project development costs - related party. During the six months ended March 31, 2008 and 2007, we recorded expenditures paid by MAB on our behalf in the amount of $0.7 million and $0.3 million, respectively. At March 31, 2008 and September 30, 2007, we owed MAB $0.7 million and $1.0 million, respectively, related to project development costs and other expenditures that MAB made on our behalf.

F-21

As of March 31, 2008, pursuant to the agreements with MAB and the $13.5 million promissory note issued thereunder (see Note 7), we owed MAB principal and accrued interest of $1.7 million. As of September 30, 2007, we owed MAB principal and accrued interest of $13.0 million under the terms of the promissory note.

At March 31, 2008, we had six separate promissory notes with the Bruner Family Trust (see Note 7) for an aggregate amount of $2.8 million. During the six-months ended March 31, 2008, we incurred total interest expense of $0.1 million, and paid nothing in principal on these notes.

Wealth Preservation. On January 25, 2008, we borrowed $0.1 million under a promissory note with a member of the board of directors. The note bears interest at 15% and was due on February 29, 2008. At March 31, 2008 we were in default of this note and the interest increased to 24%. This principal balance and accrued interest of $4,000 was paid in full in April 2008.

Galaxy. Note receivable- related party on the consolidated balance sheet at September 30, 2007 represents $2.5 million related to a $2.0 million earnest money deposit made by us under the terms of the Galaxy PSA and additional operating costs of $0.5 million that we paid toward the operating costs of the assets we were to acquire plus accrued interest on amounts due to us which were all converted into the Galaxy Note on August 31, 2007. During the six months ended March 31, 2008, the entire $2.5 million has been paid to us by offset against amounts that we owed to MAB. At September 30, 2007, Galaxy owed us $0.3 million and $17,000 related to additional expenses paid by us related to the Galaxy PSA and accrued interest on the Galaxy Note, respectively. During the six months ended March 31, 2008, these amounts have also been paid by offset to amounts we owed to MAB under the MAB Note. Marc A. Bruner is our largest single beneficial shareholder, is a 14.0% beneficial shareholder of Galaxy and is the father of the President and Chief Executive Officer of Galaxy.

Note 11 -Commitments and Contingencies

Contingencies. We may from time to time be involved in various claims, lawsuits, disputes with third parties, actions involving allegations of discrimination, or breach of contract incidental to the operations of its business. We are currently a party to the following legal actions:

As of March 31, 2008, there were 21 parties that had filed liens against our properties. Likewise, we were a party to 10 lawsuits, 9 of which relate to lienholders and one which relates to a lease on the property we intend to sell in connection with the pending property sale to Laramie (see Note 13). In connection with the Laramie transaction described in Note 13, we are required to obtain releases of all of these liens related to the subject property prior to the closing of the transaction. As a result, we have obtained all Release of Lien documents and settlement agreements required from our creditors to resolve these liens and the related disputes. All such documents and agreements will be recorded and become effective upon closing on the sale to Laramie and payment to such creditors. We currently estimate that we will incur costs of approximately $20 million, excluding related legal fees, to resolve these liens and related disputes. See Note 13 for further description of the pending Laramie transaction.
In August 2007, a lawsuit was filed by a law firm in the Supreme Court of Victoria, Australia for the balance of legal fees owed to the law firm in the amount of 0.2 million Australian dollars. The total amount owed was included in accounts payable at September 30, 2007, but has been reduced to less than 0.1 million Australian dollars, as a result of payments made by us.
In December 2007, a lawsuit was filed by a vendor in the Supreme Court of Queensland, Australia for the balance which the vendor claims is owed by us in the amount of 2.4 million Australian dollars. Although we accrued the entire amount of the judgment lien in Accounts payable as of March 31, 2008, this amount is disputed by us on the basis that the vendor breached the contract.

In the event we lose the lawsuit to either or both vendors in the lawsuits filed in Australia and do not pay the amount owed, either of said vendors could obtain a judgment lien and seek to execute on the lien against our assets.

Work Commitments. See Note 4 for commitments related to the drilling of specific wells.

Environmental. While we are not currently subject to environmental-related litigation, the nature of our business is such that we are subject to constantly changing environmental laws and regulations adopted by federal, state and local governmental authorities in both the U.S. and Australia. We would face significant liabilities to the government of other third parties for discharges of oil, natural gas, produced water or other pollutants into the air, oil, or water, and the cost to investigate, litigate and remediate such a discharge could

F-22

materially adversely affect our business, results of operations and financial condition. We encourage readers of this filing to review our risk factors disclosed in our Item 1A of our Annual Report on Form 10-K for the year ended September 30, 2007 for further discussion of our environmental risks.

Note 12 -Subsequent Events

Laramie Transaction

On April 25, 2008 we signed a binding purchase and sale agreement with Laramie Energy II, LLC ("Laramie") an unrelated third party for the sale of substantially all of our working interest in our Southern Piceance properties in Colorado, effective as of April 1, 2008. The original closing date target of May 6, 2008 has been extended by the parties to May 31, 2008. A total of up to 1,059 net acres are expected to be transferred to Laramie at closing. We will retain all of our interest in eight producing wells in Garfield County, which are operated by EnCana Oil & Gas (USA), Inc. The total purchase price, prior to adjustments for transaction fees and certain other adjustments as required by the agreement with Laramie (the "Agreement"), is $21.0 million in cash. In addition to customary terms and conditions, the Agreement also requires us to resolve numerous liens and other legal actions brought against us in relation to these properties, and to distribute the majority of the proceeds from the transaction to our trade creditors and others in satisfaction of outstanding claims. We expect to complete the last remaining pre-closing conditions in the near future.

Additionally, we have entered into numerous settlement and release agreements with many of our trade creditors who have placed liens on our Southern Piceance properties, and we have agreed to pay cash for a portion and issue shares of our stock for a portion of the amounts owed to them, and we have further agreed to use our best efforts to file a registration statement with the Securities and Exchange Commission by June 30, 2008 in order to register these shares for resale on the public market. Such agreements are conditioned upon the closing with Laramie.

Upon closing, we will be required to distribute substantially all of the adjusted proceeds in settlement of existing trade obligations and other claims, resulting in expected net proceeds to us of approximately $2.0 million. A total of $0.5 million of our net proceeds will be held in escrow for 90 days to secure our performance under the agreement.

CCES Transactions

On April 11, 2008 we closed the sale of certain natural gas gathering assets for $0.7 million in cash consideration, and simultaneously entered into a Gas Gathering Agreement with CCES Piceance Partners I, LLC ("CCES") relating to the initial phase of our gas gathering system project. These agreements formalize and expand upon a Letter of Understanding ("LOU") between the parties which contemplates a dedicated relationship with CCES in the development of a gas gathering system and the provision of Gas Gathering Services within our Buckskin Mesa Project area (the "CCES Agreements").

In addition to customary terms and conditions, the CCES Agreements include a guarantee (the "Guarantee") from us to CCES regarding their increasing financial commitments as they are incurred in relation to the development of the gas gathering system, including our contingent repurchase of the gas gathering assets we sold to CCES. The triggering event for the Guarantee is contingent upon our mutual failure to execute a formal agreement for long-term gas gathering services in the future (the "Second Phase Midstream Services Agreement"). The resolution of this contingency is dependent upon, among other things, gas production levels from the initial phase gas gathering system for our Buckskin Mesa Project over the next 12 to 18 months, and other factors as determined by both parties. Should we fail to execute a mutually agreeable long-term contract, CCES has the right to invoice us for their incurred costs and demand repayment within 20 days of our receipt of the Demand Invoice. To secure our Guarantee, we have executed a Promissory Note for an amount up to $11.5 million, secured by second deeds of trust on our Colorado properties that were recorded in the second quarter. The amount of the Guarantee is variable, based upon the underlying incurred costs by CCES as defined in the CCES Agreements, and aggregated $2.8 million as of March 31, 2008.

F-23

We have accounted for our Guarantee under the requirements of FASB Interpretation ("FIN") 45. As of March 31, 2008, we have recorded a current liability and intangible asset in our financial statements, to reflect our Contingent Purchase Obligation relating to the Guarantee. In the event the triggering event does not occur and our obligation lapses, these obligations will be offset against each other. In the event the Guarantee is triggered, we expect to acquire and obtain title to the gas gathering assets, which will then be included in our full cost pool. Our Contingent Purchase Obligation will be adjusted during future periods to its fair value, so long as the contingent Guarantee remains unresolved.

Waiver and Amendment

In April and May 2008, we entered into a Waiver and Amendment Agreement (the "Waiver") with all of the holders of our Series A 8.5% convertible debentures (see Note 8). The Waiver provides the following:

We agree to pay the interest installments due January 1, 2008 and April 1, 2008 (both currently unpaid) by September 30, 2008, together with late fees of 18% per annum.
We agree to issue warrants to purchase common stock, having the same terms as the warrants (see Note 8), equal to 4% of the shares each debenture holder (collectively, the "investors") is entitled to under the debentures.
The investors agree to waive our obligation to file a registration statement by March 4, 2008 to be effective July 2, 2008, and extend these dates to June 30, 2008 and December 31, 2008, respectively.
The investors agree to waive certain events of default, including the non-payment of interest.

F-24

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

PetroHunter Energy Corporation

Denver, Colorado

We have audited the accompanying consolidated balance sheets of PetroHunter Energy Corporation and subsidiaries (the “Company”), a development stage company, as of September 30, 2007 and 2006, and the related consolidated statements of operations, comprehensive loss, stockholders’ equity and cash flows for the years ended September 30, 2007 and 2006 and for the period from inception (June 20, 2005) to September 30, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements 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 misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provided 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 PetroHunter Energy Corporation and subsidiaries as of September 30, 2007 and 2006, and the results of their operations and their cash flows for each of the years ended September 30, 2007, 2006 and for the period from inception (June 20, 2005) to September 30, 2007 in conformity with U.S. generally accepted accounting principles.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the financial statements, the Company has incurred recurring losses from operations, has a working capital deficit of approximately $37.9 million, was not in compliance with the covenants of several loan agreements, has had multiple property liens and foreclosure actions filed by vendors and has significant capital expenditure commitments. These factors raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

As discussed in Note 2, effective October 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123(R), Share Based Payments.

We were not engaged to audit the Company’s internal control over financial reporting as of September 30, 2007 and, accordingly, we do not express and opinion, thereon.

As discussed in Notes 3, 4, 8 and 11, the Company has had numerous significant transactions with related parties.

HEIN & ASSOCIATES LLP

Denver, Colorado

January 11, 2008

FF-1

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

CONSOLIDATED BALANCE SHEETS

	September 30,
	2007			2006
	($ in thousands)
ASSETS
Current Assets
Cash and cash equivalents	$	120		$	10,632
Receivables
Oil and gas receivables, net		487			—
Other receivables		59			22
Due from related parties		500			957
Note receivable — related party		2,494			—
Prepaid expenses and other assets		187			31
TOTAL CURRENT ASSETS		3,847			11,642
Property and Equipment, at cost
Oil and gas properties under full cost method, net		162,843			45,973
Furniture and equipment, net		569			550
		163,412			46,523
Other Assets
Joint interest billings		13,637			—
Restricted cash		599			1,077
Deferred financing costs		529			—
TOTAL ASSETS	$	182,024		$	59,242

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Notes payable — short-term	$	4,667		$	—
Convertible notes payable		400			400
Accounts payable and accrued expenses		26,631			9,644
Note payable — related party — current portion		3,755			—
Note payable — long-term — current portion		120			—
Accrued interest payable		2,399			125
Accrued interest payable — related party		516			—
Due to shareholder and related parties		1,474			198
Contract payable — oil and gas properties		1,750			—
TOTAL CURRENT LIABILITIES		41,712			10,367
Notes payable — net of discount		27,944			—
Subordinated notes payable — related party		9,050			—
Asset retirement obligation		136			522
TOTAL LIABILITIES		78,842			10,889
Commitments and Contingencies (Note 13)
Common Stock Subscribed		2,858			—
Stockholders’ Equity
Preferred stock, $0.001 par value; authorized 100,000,000 shares; none issued		—			—
Common stock, $0.001 par value; authorized 1,000,000,000 shares; 278,948,841 and 219,928,734 issued and outstanding at September 30, 2007 and 2006, respectively		279			220
Additional paid-in-capital		172,672			70,944
Accumulated other comprehensive loss		(5	)		—
Deficit accumulated during the development stage		(72,622	)		(22,811	)
TOTAL STOCKHOLDERS’ EQUITY		100,324			48,353
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	182,024		$	59,242

See accompanying notes to consolidated financial statements.

FF-2

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

CONSOLIDATED STATEMENTS OF OPERATIONS

										Cumulative
										from
							From Inception			Inception
							(June 20,			(June 20,
	Year Ended			Year Ended			2005) to			2005) to
	September 30,			September 30,			September 30,			September 30,
	2007			2006			2005			2007
	($ in thousands, except per share amounts)

Revenues
Oil and gas revenues	$	2,820		$	36		$	—		$	2,856

Costs and Expenses
Lease operating expenses		793			4			—			797
General and administrative		18,075			13,638			1,236			32,949
Project development costs — related party		1,815			4,530			860			7,205
Impairment of oil and gas properties		24,053			—			—			24,053
Depreciation, depletion, amortization and accretion		1,245			73			—			1,318

Total operating expenses		45,981			18,245			2,096			66,322

Loss from Operations		(43,161	)		(18,209	)		(2,096	)		(63,466	)
Other Income (Expense)
Foreign currency exchange gain		23			—			—			23
Interest income		36			3			—			39
Interest expense		(6,709	)		(2,486	)		(23	)		(9,218	)

Total other expense		(6,650	)		(2,483	)		(23	)		(9,156	)

Net Loss	$	(49,811	)	$	(20,692	)	$	(2,119	)	$	(72,622	)

Net loss per common share — basic and diluted	$	(0.20	)	$	(0.14	)	$	(0.02	)

Weighted average number of common shares outstanding — basic and diluted		243,816,957			147,309,096			100,000,000

See accompanying notes to consolidated financial statements

FF-3

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE LOSS

								Deficit
								Accumulated			Accumulated
					Additional			During the			Other			Total			Total			Common
	Common Stock				Paid-in			Development			Comprehensive			Stockholders’			Comprehensive			Stock
	Shares		Amount		Capital			Stage			Loss			Equity			Loss			Subscribed
	($ in thousands)

Balance, June 20, 2005 (inception)		—	$	—	$	—		$	—		$	—		$	—		$	—		$	—
Shares issued to founder at $0.001 per share		100,000,000		100		—			—			—			100			—			—
Stock based compensation costs for options granted to non- employees		—		—		823			—			—			823			—			—
Net loss		—		—		—			(2,119	)					(2,119	)		(2,119	)		—

Balance, September 30, 2005		100,000,000		100		823			(2,119	)		—			(1,196	)		(2,119	)		—

Shares issued for property interests at $0.50 per share		3,000,000		3		1,497			—			—			1,500			—			—
Shares issued for finder’s fee on property at $0.50 per share		3,400,000		3		1,697			—			—			1,700			—			—
Shares issued upon conversion of debt, at $0.50 per share		44,063,334		44		21,988			—			—			22,032			—			—
Shares issued for commission on convertible debt at $0.50 per share		2,845,400		3		1,420			—			—			1,423			—			—
Sale of shares and warrants at $1.00 per unit		35,442,500		35		35,407			—			—			35,442			—			—
Shares issued for commission on sale of units		1,477,500		1		1,476			—			—			1,477			—			—
Costs of stock offering:
Cash		—		—		(1,638	)		—			—			(1,638	)		—			—
Shares issued for commission at $1.00 per share		—		—		(1,478	)		—			—			(1,478	)		—			—
Exercise of warrants		1,000,000		1		999			—			—			1,000			—			—
Recapitalization of shares issued upon merger		28,700,000		30		(436	)		—			—			(406	)		—			—
Stock based compensation		—		—		9,189			—			—			9,189			—			—
Net loss		—		—		—			(20,692	)		—			(20,692	)		(20,692	)		—

Balance, September 30, 2006		219,928,734		220		70,944			(22,811	)		—			48,353			(20,692	)		—

Common stock subscribed		—		—		—			—			—			—			—			2,858
Shares issued for property interests at $1.70 per share		2,428,100		2		4,125			—			—			4,127			—			—
Shares issued for property interests at $1.62 per share		50,000,000		50		80,950			—			—			81,000			—			—
Shares issued for property interests at $1.49 per share		256,000		—		382			—			—			382			—			—
Shares issued for commission costs on property at $1.65 per share		121,250		—		200			—			—			200			—			—
Shares issued for finance costs on property at $1.72 per share		571,900		1		984			—			—			985			—			—
Shares issued for finance costs on property at $1.29 per share		475,000		—		612			—			—			612			—			—
Shares issued for finance costs on property at $0.70 per share		642,857		1		449			—			—			450			—			—
Shares issued for finance costs on property at $0.51 per share		525,000		1		268			—			—			269			—			—
Shares issued for finance costs on property at $0.23 per share		4,000,000		4		916			—			—			920			—			—
Foreign currency translation adjustment		—		—		—			—			(5	)		(5	)		(5	)		—
Discount on notes payable		—		—		4,670			—			—			4,670			—			—
Stock based compensation		—		—		8,172			—			—			8,172			—			—
Net loss		—		—		—			(49,811	)		—			(49,811	)		(49,811	)		—

Balance, September 30, 2007		278,948,841	$	279	$	172,672		$	(72,622	)	$	(5	)	$	100,324		$	(49,816	)	$	2,858

See accompanying notes to consolidated financial statements.

FF-4

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

CONSOLIDATED STATEMENTS OF CASH FLOWS

										Cumulative
							From			from
							Inception			Inception
							(June 20,			(June 20,
	Year Ended			Year Ended			2005) to			2005) to
	September 30,			September 30,			September 30,			September 30,
	2007			2006			2005			2007
	($ in thousands)

Cash flows used in operating activities
Net loss	$	(49,811	)	$	(20,692	)	$	(2,119	)	$	(72,622	)
Adjustments used to reconcile net loss to net cash used in operating activities:
Stock for expenditures advanced		—			—			100			100
Stock based compensation		8,172			9,189			823			18,184
Depreciation, depletion, amortization and accretion		1,245			73			—			1,318
Impairment of oil and gas properties		24,053			—			—			24,053
Stock for financing costs		200			1,423			—			1,623
Amortization of discount and deferred financing costs on notes payable		1,036			—			—			1,036
Foreign currency exchange gain		(23	)		—			—			(23	)
Changes in assets and liabilities
Receivables		(488	)		(58	)		—			(546	)
Due from related party		421			(921	)		—			(500	)
Prepaid expenses and other assets		(36	)		9			(18	)		(45	)
Accounts payable and accrued expenses		3,628			882			344			4,854
Due to shareholder and related parties		1,277			(451	)		648			1,474
Net cash used in operating activities		(10,326	)		(10,546	)		(222	)		(21,094	)
Cash flows used in investing activities
Additions to oil and gas properties		(33,038	)		(31,062	)		(1,565	)		(65,665	)
Note receivable — related party		(2,494	)		—			—			(2,494	)
Additions to furniture and equipment		(134	)		(553	)		—			(687	)
Restricted cash		—			(1,077	)		—			(1,077	)
Net cash used in investing activities		(35,666	)		(32,692	)		(1,565	)		(69,923	)
Cash flows from financing activities
Proceeds from the sale of common stock		300			35,442			—			35,742
Proceeds from common stock subscribed		2,858			—			—			2,858
Proceeds from the issuance of notes payable		31,550			—			—			31,550
Borrowing on short-term notes payable		500			—			—			500
Proceeds from related party borrowings		275			—			—			275
Proceeds from the exercise of warrants		—			1,000			—			1,000
Cash received upon recapitalization and merger		—			21			—			21
Proceeds from issuance of convertible notes		—			17,795			3,037			20,832
Offering and financing costs		—			(1,638	)		—			(1,638	)
Net cash provided by financing activities		35,483			52,620			3,037			91,140
Effect of exchange rate changes on cash		(3	)		—			—			(3	)
Net (decrease) increase in cash and cash equivalents		(10,512	)		9,382			1,250			120
Cash and cash equivalents, beginning of period		10,632			1,250			—			—
Cash and cash equivalents, end of period	$	120		$	10,632		$	1,250		$	120
Supplemental schedule of cash flow information
Cash paid for interest	$	473		$	1,028		$	—		$	1,501
Cash paid for income taxes	$	—		$	—		$	—		$	—
Supplemental disclosures of non-cash investing and financing activities
Shares issued for expenditures advanced	$	—		$	—		$	100		$	100
Contracts for oil and gas properties	$	1,750		$	6,261		$	5,513		$	13,524
Shares issued for debt conversion	$	—		$	22,032		$	—		$	22,032
Shares issued for commissions on offerings	$	—		$	2,900		$	—		$	2,900
Shares issued for property	$	81,000		$	—		$	—		$	81,000
Shares issued for property and finder’s fee on property	$	7,444		$	2,200		$	—		$	9,644
Warrants issued for debt	$	4,670		$	—		$	—		$	4,670
Non-cash uses of notes payable and accounts payable and accrued liabilities	$	26,313		$	—		$	—		$	26,313
Convertible debt issued for property	$	—		$	1,200		$	—		$	1,200

See accompanying notes to consolidated financial statements.

FF-5

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 —

Organization and Basis of Presentation

PetroHunter Energy Corporation, formerly known as Digital Ecosystems Corporation (“Digital”), was incorporated on February 21, 2002 under the laws of the State of Nevada. On February 10, 2006, Digital entered into a Share Exchange Agreement (the “Agreement”) with GSL Energy Corporation (“GSL”) and certain shareholders of GSL pursuant to which Digital acquired more than 85% of the issued and outstanding shares of common stock of GSL, in exchange for shares of Digital’s common stock. On May 12, 2006, the parties to the Agreement completed the share exchange and Digital changed its business to the business of GSL. Subsequent to the closing of the Agreement, Digital acquired all the remaining outstanding stock of GSL, and effective August 14, 2006, Digital changed its name to PetroHunter Energy Corporation (“PetroHunter”).

GSL was incorporated under the laws of the State of Maryland on June 20, 2005 for the purpose of acquiring, exploring, developing and operating oil and gas properties. PetroHunter is considered a development stage company as defined by Statement of Financial Accounting Standards (“SFAS”) 7, Accounting and Reporting by Development Stage Enterprises. A development stage enterprise is one in which planned principal operations have not commenced, or if its operations have commenced, there have been no significant revenues therefrom. As of September 30, 2007, our principal activities since inception have been raising capital through the sale of common stock and convertible notes and the acquisition of oil and gas properties in the western United States and Australia and we have not commenced our planned principal operations. In October 2006, GSL changed its name to PetroHunter Operating Company.

As a result of the Agreement, GSL became a wholly-owned subsidiary of PetroHunter. Since this transaction resulted in the former shareholders of GSL acquiring control of PetroHunter, for financial reporting purposes the business combination was accounted for as an additional capitalization of PetroHunter (a reverse acquisition with GSL as the accounting acquirer). In accounting for this transaction:

i. GSL was deemed to be the purchaser and parent company for financial reporting purposes. Accordingly, its net assets were included in the consolidated balance sheet at their historical book value; and

ii. Control of the net assets and business of PetroHunter was effective May 12, 2006 for no consideration.

The fair value of the Digital assets acquired and liabilities assumed pursuant to the transaction with GSL are as follows ($ in thousands):

Net cash acquired	$	21
Other current assets		22
Liabilities assumed		(449	)
Value of 28,700,000 Digital Shares	$	(406	)

Note 2 —

Summary of Significant Accounting Policies

Basis of Accounting. The accompanying financial statements have been prepared on the basis of accounting principles applicable to a going concern, which contemplates the realization of assets and extinguishment of liabilities in the normal course of business. As shown in the accompanying statements of operations, PetroHunter, together with its wholly-owned subsidiaries (the “Company”, “we” or “us”) has incurred a cumulative net loss of $72.6 million for the period from inception (June 20, 2005) to September 30, 2007 has a working capital deficit of approximately $37.9 as of September 30, 2007 was not in compliance with the covenants of several loan agreements, has had multiple property liens and foreclosure actions filed by vendors and has significant capital expenditure commitments. As of September 30, 2007, the Company has earned oil and gas revenue from its initial operating wells, but will require significant additional funding to sustain operations and satisfy contractual obligations for planned oil and gas exploration, development and operations in the future. These factors, among

FF-6

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

others, may indicate that the Company may be unable to continue in existence. The Company’s financial statements do not include adjustments related to the realization of the carrying value of assets or the amounts and classification of liabilities that might be necessary should the Company be unable to continue in existence. The Company’s ability to establish itself as a going concern is dependent upon its ability to obtain additional financing to fund planned operations and to ultimately achieve profitable operations. Management believes that they can be successful in obtaining equity and/or debt financing and/or sell interests in some of its properties, which will enable the Company to continue in existence and establish itself as a going concern. The Company has raised approximately $91.1 million through September 30, 2007 through issuances of common stock and convertible and other debt. Management believes they will be successful at raising necessary funds to meet obligations for planned operations. Subsequent to September 30, 2007, we raised an additional $7.0 million in a private placement of convertible debentures and we have sold our Heavy Oil assets for up to $30 million, of which $7.5 million was cash.

For the 12 months ended September 30, 2007 and 2006, the consolidated financial statements include the accounts of PetroHunter and its wholly-owned subsidiaries. For the period from June 20, 2005 through September 30, 2005, the consolidated financial statements include only the accounts of GSL. All significant intercompany transactions have been eliminated upon consolidation.

Use of Estimates. Preparation of the Company’s financial statements in accordance with Generally Accepted Accounting Principles (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses for the reporting period. Actual results could differ from those estimates.

Cash and Cash Equivalents. We consider investments in highly liquid financial instruments with an original stated maturity of three months or less to be cash equivalents.

Accounts Receivable. Accounts receivable at September 30, 2007 consists primarily of Oil and gas receivables. Oil and gas receivables represent revenue earned on our operating wells that had not yet been collected. The balance at September 30, 2007 was $0.5 million and based on our history of collections with this operator, no allowance is necessary on this balance.

Joint Interest Billings. Joint interest billings in the amount of $13.6 million represents our working interest partners’ share of costs that we paid, on their behalf, to drill 16 wells. During December, 2007, we entered into a trade which provided us a 100% working interest in 12 of these wells, representing approximately $12.6 million of the Joint interest billing balance and as a result, $12.6 million was reclassified to oil and gas properties in the first quarter of 2008 (see Notes 4 and 14). We are currently in negotiations with our other partner regarding the remaining two wells.

FF-7

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Restricted Cash. Restricted cash consists of certificates of deposit underlying letters of credit for exploration permits, state and local bonds and guarantees to vendors.

Concentration of Credit Risk. Financial instruments which potentially subject us to concentrations of credit risk consist of cash. We periodically evaluate the credit worthiness of financial institutions, and maintain cash accounts only with major financial institutions, thereby minimizing exposure for deposits in excess of federally insured amounts. On occasion, the Company may have cash in banks in excess of federally insured amounts. We believe that credit risk associated with cash is remote.

Oil and Gas Properties. The Company utilizes the full cost method of accounting for oil and gas activities. Under this method, subject to a limitation based on estimated value, all costs associated with property acquisition, exploration and development, including costs of unsuccessful exploration, are capitalized within a cost center on a country basis. No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas properties unless the sale represents a significant portion of oil and gas properties and the gain significantly alters the relationship between capitalized costs and proved oil and gas reserves of the cost center. Depreciation, depletion and amortization of oil and gas properties is computed on the units-of-production method based on proved reserves. Amortizable costs include estimates of future development costs of proved undeveloped reserves.

Capitalized costs of oil and gas properties may not exceed an amount equal to the present value, discounted at 10%, of the estimated future net cash flows from proved oil and gas reserves plus the cost, or estimated fair market value, if lower, of unproved properties. Should capitalized costs exceed this ceiling, an impairment is recognized. The present value of estimated future net cash flows is computed by applying year-end prices of oil and natural gas to estimated future production of proved oil and gas reserves as of year-end, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions.

Asset Retirement Obligation. Asset retirement obligations associated with tangible long-lived assets are accounted for in accordance with SFAS 143, Accounting for Asset Retirement Obligations. The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of oil and gas properties is recorded generally upon acquisition or completion of a well. The net estimated costs are discounted to present values using a risk adjusted rate over the estimated economic life of the oil and gas properties. Such costs are capitalized as part of the related asset. The asset is depleted on the units-of-production method on a field-by-field basis. The liability is periodically adjusted to reflect (1) new liabilities incurred, (2) liabilities settled during the period, (3) accretion expense, and (4) revisions to estimated future cash flow requirements. The accretion expense is recorded as a component of depreciation, depletion, amortization and accretion expense in the accompanying consolidated statements of operations.

Property and Equipment. Furniture, equipment and computer software are recorded at historical cost. Depreciation is computed using the straight-line method over the estimated useful lives of the related assets (see Note 5). The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred. Expenditures to extend the useful lives of the assets are capitalized.

Impairment. SFAS 144, Accounting for the Impairment and Disposal of Long-Lived Assets, requires long-lived assets to be held and used to be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. We use the full cost method of accounting for our oil and gas properties. Properties accounted for using the full cost method of accounting are excluded from the impairment testing requirements under SFAS 144. Properties accounted for under the full cost method of accounting are subject to SEC Regulation S-X Rule 4-10, Financial Accounting and Reporting for Oil and Gas Producing Activities Pursuant to the Federal Securities Laws and the Energy Policy and Conversion Act of 1975 (“Rule 4-10”). Rule 4-10 requires that each regional cost center’s (by country) capitalized cost, less

FF-8

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

accumulated amortization and related deferred income taxes not exceed a cost center “ceiling”. The ceiling is defined as the sum of:


	•	The present value of estimated future net revenues computed by applying current prices of oil and gas reserves to estimated future production of proved oil and gas reserves as of the balance sheet date less estimated future expenditures to be incurred in developing and producing those proved reserves to be computed using a discount factor of 10%; plus

	•	The cost of properties not being amortized; plus

	•	The lower of cost or estimated fair value of unproven properties included in the costs being amortized; less

	•	Income tax effects related to differences between the book and tax basis of the properties.

Based upon the borrowing rates currently available to the Company for loans with similar terms and average maturities, the fair value of payable notes, approximates their carrying value.

Off Balance Sheet Arrangements. As part of its ongoing business, the Company has not participated in transactions that generate relationships with unconsolidated entities or financial partnerships. These entities are often referred to as structured finance or special purpose entities (“SPEs”), and are usually established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. As of and up to September 30, 2007, the Company has not been involved in unconsolidated SPE transactions.

Comprehensive Loss. Comprehensive loss consists of net loss and foreign currency translation adjustments. Comprehensive loss is presented net of income taxes in the consolidated statements of stockholders’ equity and comprehensive loss.

Income Taxes. The Company has adopted the provisions of SFAS 109, Accounting for Income Taxes. SFAS 109 requires recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse.

Temporary differences between the time of reporting certain items for financial and tax reporting purposes consist primarily of exploration and development costs on oil and gas properties, and stock based compensation of options granted.

FF-9

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

common shares outstanding excluded potential common shares from stock options and warrants of approximately 85,923,000 and 25,309,000 for the years ending September 30, 2007 and 2006, respectively.

Share Based Compensation. Effective October 1, 2006, we adopted the provisions of SFAS 123(R) (as amended), Share-Based Payment, using the modified prospective method, which results in the provisions of SFAS 123(R) being applied to the consolidated financial statements on a going-forward basis. SFAS 123(R) revises SFAS 123, Accounting for Stock-Based Compensation, and supersedes Accounting Principles Board (“APB”) Opinion 25, Accounting for Stock Issued to Employees. SFAS 123(R) establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods and services at fair value, focusing primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. It also addresses transactions in which an entity incurs liabilities in exchange for goods and services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those equity instruments.

Prior to October 1, 2006, we accounted for stock-based compensation using the intrinsic value recognition and measurement principles detailed in APB Opinion 25, Accounting for Stock Issued to Employees and related interpretations.

Stock-based compensation awarded to non-employees is accounted for under the provisions of EITF 96-18, Accounting for Equity Instruments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling, Goods or Services.

	Year Ended September 30,
	2006			2005

Net loss as reported	$	(20,692	)	$	(2,119	)
Add stock based compensation included in reported loss		9,189			823
Deduct stock based compensation expense determined under fair value method		(9,189	)		(1,202	)
Pro-forma net loss	$	(20,692	)	$	(2,498	)
Net loss per share, as reported	$	(0.14	)	$	(0.02	)
Net loss per share, Pro-forma	$	(0.14	)	$	(0.02	)

Recently Issued Accounting Pronouncements. In December 2007, the FASB issued SFAS 160, Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51. SFAS 160 establishes accounting and reporting standards that require noncontrolling interests to be reported as a component of equity, changes in a parent’s ownership interest while the parent retains its controlling interest be accounted for as equity transactions, and any retained noncontrolling equity investment upon the deconsolidation of a subsidiary be initially measured at fair value. SFAS 160 is effective for fiscal years and interim periods within those fiscal years, beginning on or after December 15, 2008 and is to be applied prospectively as of the beginning of the fiscal year in which the statement is applied. The Company is required to adopt SFAS 160 in the first quarter of 2009. Management believes that the adoption of SFAS 160 will have no impact on our consolidated results of operations, cash flows or financial position.

FF-10

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

In December 2007, the FASB issued SFAS 141(R), Business Combinations. SFAS 141(R) replaces SFAS 141 and provides greater consistency in the accounting and financial reporting of business combinations. SFAS 141(R) requires the acquiring entity in a business combination to recognize all assets acquired and liabilities assumed in the transaction and any non-controlling interest in the acquiree at the acquisition date, measured at the fair value as of that date. This includes the measurement of the acquirer’s shares issued in consideration for a business combination, the recognition of contingent consideration, the accounting for pre-acquisition gain and loss contingencies, the recognition of capitalized in-process research and development, the accounting for acquisition-related restructuring cost accruals, the treatment of acquisition related transaction costs and the recognition of changes in the acquirer’s income tax valuation allowance and deferred taxes. SFAS 141(R) is effective for fiscal years and interim periods within those fiscal years, beginning on or after December 15, 2008 and is to be applied prospectively as of the beginning of the fiscal year in which the statement is applied. Early adoption is not permitted. The Company is required to adopt SFAS 141(R) in the first quarter of 2009. Management believes that the adoption of SFAS 141(R) will have no impact on our consolidated results of operations, cash flows or financial position

In February 2007, the Financial Accounting Standards Board, or “FASB”, issued SFAS 159, The Fair Value Option for Financial Assets and Financial Liabilities, which allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value that are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item’s fair value in subsequent reporting periods must be recognized in current earnings. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparison between entities that elect different measurement attributes for similar assets and liabilities. SFAS 159 is effective for us on October 1, 2008. We have not assessed the impact of SFAS 159 on our consolidated results of operations, cash flows or financial position.

In September 2006, the FASB issued SFAS 157, Fair Value Measurements, which provides guidance for using fair value to measure assets and liabilities. The standard also responds to investors’ requests for more information about: (1) the extent to which companies measure assets and liabilities at fair value; (2) the information used to measure fair value; and (3) the effect that fair value measurements have on earnings. SFAS 157 will apply whenever another standard requires (or permits) assets or liabilities to be measured at fair value. SFAS 157 does not expand the use of fair value to any new circumstances. SFAS 157 is effective for us on October 1, 2008. We have not assessed the impact of SFAS 157 on our consolidated results of operations, cash flows or financial position.

In July 2006, the FASB issued Interpretation (“FIN”) 48, Accounting for Uncertainty in Income Taxes, which clarifies the accounting for uncertainty in income taxes recognized in financial statements in accordance with FASB Statement 109, Accounting for Income Taxes. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for us on October 1, 2007. We have not assessed the impact of FIN 48 on our consolidated results of operations, cash flows or financial position.

Note 3 —

Agreements with MAB Resources LLC

The Company and MAB Resources LLC (“MAB”) have entered into various agreements described below. MAB is a Delaware limited liability company controlled by the largest shareholder of the Company, who had an approximate 43.4% beneficial ownership interest in us at September 30, 2007. MAB is in the business of oil and gas exploration and development.

The Development Agreement. Commencing July 1, 2005 and continuing through December 31, 2006, the Company and MAB operated pursuant to the Development Agreement, and a series of individual property agreements (collectively, the “EDAs”).

FF-11

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Development Agreement set forth: (i) MAB’s obligation to assign to the Company a minimum 50% undivided interest in any and all oil and gas assets that MAB was to acquire from third parties in the future; and (ii) MAB’s and the Company’s long-term relationship regarding the ownership and operation of all jointly-owned properties. Each of the Properties acquired was covered by a property-specific EDA that was consistent with the terms of the Development Agreement.

The material terms of the Development Agreement and the EDAs were as follows:

i. MAB and the Company each owned an undivided 50% working interest in all oil and gas leases, production facilities, and related assets (collectively, the “Properties”).

ii. The Company was named as Operator, and had appointed a related controlled entity, MAB Operating Company LLC, as sub-operator. The Company and MAB agreed to sign a joint operating agreement, governing all operations.

iii. Each party was to pay its proportionate share of costs and receive its proportionate share of revenues, subject to the Company bearing the following burdens:

a. Each assignment of Properties from MAB to the Company reserved an overriding royalty equivalent to 3% of 8/8ths (proportionately reduced to 1.5% of the Company’s undivided 50% working interest in the Properties) (the “MAB Override”), payable to MAB out of production and sales.

b. Each EDA provided that the Company would pay 100% of the cost of acquisitions and operations (“Project Costs”) up to a specified amount, after which time each party shall pay its proportionate 50% share of such costs. The maximum specified amount of Project Costs of which the Company was to pay 100%, under the Development Agreement for properties acquired in the future, was $100.0 million per project. There was no “before payout” or “after payout” in the traditional sense of a “carried interest” because the Company’s obligation to expend the specified amount of Project Costs and MAB’s receipt of its 50% share of revenues applied without regard to whether or not “payout” had occurred. Therefore, the Company’s payment of all Project Costs up to such specified amount may have occurred before actual payout, or may have occurred after actual payout, depending on each project and set of Properties.

c. Under the Development Agreement, the Company was to pay to MAB monthly project development costs representing a specified portion of MAB’s “carried” Project Costs. The total amount incurred to MAB by the Company was to be deducted from MAB’s portion of the Project Costs carried by the Company. During 2007, 2006 and 2005, we paid MAB $1.8 million, $4.5 million and $0.9 million, respectively, for Project Costs which are classified on the consolidated statements of operations as Project development costs — related party.

The Consulting Agreement. Effective January 1, 2007, the Company and MAB entered into an Acquisition and Consulting Agreement (the “Consulting Agreement”) which replaced in its entirety the Development Agreement entered into July 1, 2005, and materially revised the relationship between MAB and the Company. The material terms of the Consulting Agreement provide as follows:

i. MAB conveyed to the Company its entire remaining undivided 50% working interest in all rights and benefits under each EDA, and the Company assumed its share of all duties and obligations under each individual EDA (such as drilling and development obligations), with respect to said remaining undivided 50% working interest,

ii. A consulting agreement was agreed upon, including the Company’s obligation to pay fees in the amount of $25,000 per month for services rendered to us for which we paid a total of $0.2 million, during the year ended September 30, 2007,

FF-12

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

iii. As a result of MAB’s above-referenced conveyance of its remaining undivided 50% working interest to us, the Company’s working interest in certain oil and gas properties increased from 50% to 100%,

iv. The Company’s obligation to pay up to $700.0 million in capital costs for MAB’s 50% interest as well as the monthly project cost advances against such capital costs was eliminated,

v. The Company became obligated for monthly payments in the amount of $0.2 million under a $13.5 million promissory note,

vi. MAB’s overriding royalty interest (the “Override”) was increased from 3% to 5%, half of which accrues but is deferred for three years. The Override does not apply to the Company’s Piceance II properties, and did not apply to certain other properties to the extent that the Override would cause the Company’s net revenue interest to be less than 75%,

vii. MAB would receive 7% of the issued and outstanding shares of any new subsidiary with assets comprised of the subject properties,

viii. MAB received 50.0 million shares of PetroHunter Energy Corporation, and would receive up to an additional 50.0 million shares (the “Performance Shares”) if the Company met certain thresholds based on proven reserves.

On October 29, 2007, November 15, 2007, and December 31, 2007, we entered into the first, second, and third amendments, respectively, to the Consulting Agreement (the “First Amendment”, the “Second Amendment”, and the “Third Amendment”, respectively, and collectively, “the Amendments”). Portions of the First Amendment were effective January 1, 2007, the Second Amendment was effective November 1, 2007, and the Third Amendment was effective December 31, 2007. The Amendments significantly changed several provisions of the Consulting Agreement.

Pursuant to the First Amendment: (a) MAB relinquished its overriding royalty interest in all properties in Montana and Utah effective October 1, 2007 (the Override still applies to the Company’s Australian properties and Buckskin Mesa property); (b) MAB received 25.0 million additional shares of our common stock; (c) MAB relinquished all rights to the Performance Shares; and (d) the parties’ rights and obligations related to MAB’s consulting services were terminated effective retroactively back to January 1, 2007.

Under the terms of the Second Amendment, effective November 1, 2007, the note payable to MAB was reduced in accordance with and in exchange for the following (see Note 14):


	•	By $8.0 million in exchange for 16.0 million shares of our common stock with a value of $3.7 million based on the closing price of $0.23 per share at November 15, 2007 and warrants to acquire 32.0 million shares of our common stock at $0.50 per share. The warrants expire on November 14, 2009;

	•	By $2.9 million in exchange for our release of MAB’s obligation to pay the equivalent amount as guarantor of the performance of Galaxy Energy Corporation under the subordinated unsecured promissory note dated August 31, 2007 (see Note 11);

	•	A reduction to the note payable to MAB of $0.5 million for cash payments to be made by us subsequent to September 30, 2007.

FF-13

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Under the terms of the Third Amendment, effective December 31, 2007, the note payable to MAB was reduced: (a) by $0.4 million for our release of MAB’s obligation to pay the equivalent amount as guarantor of the performance of Galaxy Energy Corporation under the subordinated unsecured promissory note dated August 31, 2007 (see Note 11); and (b) by $0.2 million for MAB assuming certain obligations of PaleoTechnology, Inc. (“Paleo”), which Paleo owed to the Company.

Note 4 —

Oil and Gas Properties

Commencing effective July 1, 2005 and continuing through December 31, 2006, the Company operated under the Development Agreement and the series of property-specific EDAs with MAB. Effective January 1, 2007, the Development Agreement and the EDAs were replaced in their entirety by the Consulting Agreement with MAB (see Note 3).

The following description of the Company’s oil and gas property acquisitions for the period from inception to September 30, 2007 is pursuant to the original Development Agreement and related EDAs. All references to the Company’s obligations to pay “project development costs” pertaining to the following properties relate to the specified amount of capital expenditures (for each such property), which were credited against the Company’s obligation to carry MAB for MAB’s 50% portion of such expenditures. Effective January 1, 2007, for properties that both MAB and the Company owned working interest, MAB assigned its remaining undivided working interests in those properties to the Company, and the commitment to pay up to a certain portion of project costs was terminated (see Note 3).

FF-14

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following is a summary of oil and gas property costs not subject to amortization at September 30, 2007 ($ in thousands):

	2007		2006		2005		Previous		Total
United States:
Acquisition costs	$	64,688	$	10,722	$	5,363	$	—	$	80,773
Exploration costs		15,807		172		3		—		15,982
Development costs		—		—		—		—		—
Capitalized interest		955		—		—		—		955
Total		81,450		10,894		5,366		—		97,710
Australia:
Acquisition costs		6,450		5,542		—		—		11,992
Exploration costs		10,913		612		—		—		11,525
Development costs		—		—		—		—		—
Capitalized interest		52		—		—		—		52
Total		17,415		6,154		—		—		23,569
Acquisition costs		71,138		16,264		5,363		—		92,765
Exploration costs		26,720		784		3		—		27,507
Development costs		—		—		—		—		—
Capitalized interest		1,007		—		—		—		1,007
Total	$	98,865	$	17,048	$	5,366	$	—	$	121,279

The following is a summary of oil and gas property costs not subject to amortization by prospect at September 30, 2007 ($ in thousands):

	2007		2006		2005		Previous		Total
United States:
Buckskin Mesa	$	34,569	$	4,793	$	5,366	$	—	$	44,728
Piceance II		39,232		5,126		—		—		44,358
Sugarloaf		7,029		—		—		—		7,029
Total Piceance Basin		80,830		9,919		5,366		—		96,115
Bear Creek		620		975		—		—		1,595
Total United States		81,450		10,894		5,366		—		97,710
Australia:
Beetaloo		17,415		6,154		—		—		23,569
Total	$	98,865	$	17,048	$	5,366	$	—	$	121,279

Included below is the description of significant oil and gas properties and their current status.

PICEANCE BASIN

Buckskin Mesa Project. Effective September 17, 2005, the Company entered into an EDA with MAB for the Buckskin Mesa Project, under which the Company has paid $5.4 million to the third party assignor, Daniels Petroleum Company, (“DPC”) and, $2.0 million in federal lease payments for federal leases acquired by DPC on

FF-15

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

November 10, 2005 and under which the Company assumed all of MAB’s obligations to DPC (the “DPC Agreement”). As consideration for extending the final payment due on closing and under the DPC Agreement, the Company agreed to pay a monthly extension fee of $0.2 million to DPC for each 30-day period commencing January 6, 2006, of which all were paid as of June 30, 2006. The Company was obligated to pay MAB monthly project development costs of $20,000, commencing July 1, 2005, and the first $50.0 million of project costs. The Company charged to operations all project development costs incurred to MAB under the related EDA’s. Effective January 1, 2007, MAB assigned its remaining undivided 50% working interest in these properties to the Company, and our commitment to pay the remainder of the first $50.0 million of project costs was terminated.

Effective July 18, 2006, the Company entered into an EDA with MAB related to additional properties within the original Buckskin Mesa Project in the Piceance Basin, Colorado, which also became subject to the DPC Agreement and under which the Company received an undivided 50% working interest in the properties for $0.8 million. If the Company elected to accept certain leases which were subject to additional title curative work, it would pay up to a maximum of an additional $1.1 million payable to DPC for bonus payments related to such properties. The Company was also obligated to pay MAB monthly project development costs of $20,000, commencing August 1, 2006, and to pay the first $50.0 million of project costs. Effective January 1, 2007, MAB assigned its remaining undivided 50% working interest in these properties to the Company, and our commitment to pay the remainder of the first $50.0 million of project costs was terminated. During the fiscal year ended September 30, 2007, the Company drilled, but did not complete, four wells at a cost of $13.2 million. The Company is in the process of drilling a fifth well; costs incurred for this fifth well through September 30, 2007 aggregated $2.8 million. Plans include completion of those wells during the fiscal year ending September 30, 2008.

By the terms of the DPC Agreement, as amended, the Company is required to drill 16 wells during the calendar year ending December 31, 2008. With respect to the 16 wells, the Company must commence the drilling of a minimum of three wells on certain subject properties by March 31, 2008, four additional wells during the second calendar quarter of 2008, four additional wells during the third calendar quarter of 2008, and five additional wells during the fourth calendar quarter of 2008. The fifth amendment to the DPC Agreement, dated October 16, 2007, also required a payment of $0.7 million on October 31, 2007, or to pay such amount plus interest up to November 30, 2007. That payment, including interest, was made on November 8, 2007. In addition, the Company was required to commence drilling of the fifth commitment well, as required by the terms of the second amendment to the DPC Agreement, by November 30, 2007, and has complied with that provision. The Company’s estimate to drill and complete each well is $3.7 million; costs to drill and complete the 16 wells and the fifth commitment well aggregate $62.9 million. As of September 30, 2007, the Company had incurred drilling costs of $2.8 million related to the fifth commitment well, with an approximate $0.9 million estimate to complete. If the Company fails to commence the drilling of (or receive credit for) the number of additional wells required by the fifth amendment to the DPC Agreement during each respective quarter, the DPC Agreement, as amended, requires the payment of $0.5 million for each undrilled well on the last day of the applicable quarter.

Piceance II Project. Effective December 29, 2005, the Company entered into an EDA with MAB for the Piceance II Project, under which the Company would pay up to $4.0 million to the assignor (of which $3.9 million was paid) and issue $1.0 million (2.0 million shares at $0.50 per share) of the Company’s common stock. The Company was obligated to pay MAB monthly project development costs of $20,000 per month, commencing November 1, 2005, and the first $50.0 million of project costs. Effective January 1, 2007, MAB assigned its remaining undivided 50% working interest in these properties to the Company, and our commitment to pay the remainder of the first $50.0 million of project costs was terminated.

During the fiscal year ended September 30, 2007, the Company drilled, but did not complete, 16 wells at a 50% working interest cost of $9.4 million. The total 100% working interest cost of drilling these wells was $18.8 million. Plans include completion of those wells during the fiscal year ending September 30, 2008. The costs incurred represent the Company’s 50% share of the costs to drill 10 of those wells. The arrangement with respect to costs paid

FF-16

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

for the remaining working interest share is currently classified in the consolidated balance sheet as Joint interest billings and is discussed below in this section. The Company drilled two additional wells and 100% of the costs to drill those wells are also reflected as Joint interest billings in the consolidated balance sheet. The arrangement, with respect to the working interest share, is also discussed below in this section.

By the terms of a Lease Acquisition and Development Agreement between MAB, Apollo Energy LLC and ATEC Energy Ventures and of a certain oil and gas lease, the Company was to have commenced the drilling of two wells by August 31, 2007 and an additional two wells by August 31, 2008. Subject to certain spacing orders being issued by the Colorado Oil and Gas Conservation Commission, that requirement has been deferred in its entirety by one year, thus requiring the drilling of two wells by August 31, 2008 and two wells by August 31, 2009. The Company has estimated costs to drill and complete each well at $2.1 million per well ($0.8 million to the Company’s 37.5% interest in the dedicated spacing unit), or $4.2 million ($1.6 million to the Company’s 37.5% interest in the dedicated spacing unit), and $4.2 million ($1.6 million to the Company’s 37.5% interest in the dedicated spacing unit) to be incurred by August 31, 2008 and 2009, respectively.

By the terms of a Lease Acquisition and Development Agreement between MAB, Apollo Energy LLC and ATEC Energy Ventures and of a second oil and gas lease, pertaining to the Piceance II properties, the Company was to have commenced the drilling of four wells by June 30, 2007, an additional two wells by June 30, 2008 and an additional two wells by June 30, 2009. Subject to certain spacing orders being issued by the Colorado Oil and Gas Conservation Commission, that requirement has been deferred indefinitely. The Company has estimated costs to drill and complete each well at $2.1 million ($1.0 million to the Company’s 50% interest) per well; total estimated costs to drill and complete is approximately $16.8 million ($8.4 million to the Company’s 50% interest).

By the terms of a Lease Acquisition and Development Agreement between MAB, Apollo Energy LLC and ATEC Energy Ventures and a third oil and gas lease pertaining to the Piceance II properties, the Company was required to drill 10 wells by December 31, 2008. Of the 10 wells, the Company drilled two during the fiscal year ended September 30, 2007 and we paid 100% of the costs to drill those two wells. Our joint interest partner’s share in the amount of $1.0 million is reflected as Joint interest billings on our consolidated balance sheet. The Company has estimated costs to drill and complete each well at $2.1 million ($1.3 million to the Company’s 62.5% interest) per well; total estimated costs to drill and complete is approximately $16.8 million ($10.5 million to the Company’s 62.5% interest). The Company is currently conducting negotiations with the owner of the remaining 37.5% working interest owner to trade their interest in this lease for other oil and gas interests owned by the Company.

On December 10, 2007, the Company entered into two agreements with EnCana Oil & Gas (USA) Inc. (“EnCana”) to exchange interests in certain Piceance Basin wells as follows:

Exchange 1 — The Company received an interest in 40 net acres, including two wells with a total present value of net cash flows discounted at 10% as of September 30, 2007 of $2.6 million, and conveyed interests in 19 wells with a total present value of net cash flows discounted at 10% as of September 30, 2007 of $0.9 million. The Company and EnCana relieved each other of existing obligations related to all past costs and operations. Therefore, EnCana’s share of the costs to drill the two wells of $3.2 million currently reflected as Joint interest billings in the Company’s consolidated balance sheet will be reclassified to oil and gas properties during the first quarter ended December 31, 2007. In addition, the Company’s accounts receivable from EnCana for oil and gas sales and accounts payable to EnCana for lease operating expenses from the 19 wells, of $0.5 million and $0.1 million respectively, as of September 30, 2007, will also be reclassified to oil and gas properties during the first quarter ended December 31, 2007.

Exchange 2 — The Company received an interest in 198 net acres, including 10 wells with a total present value of net cash flows discounted at 10% as of September 30, 2007 of $6.5 million. EnCana’s share of the costs to drill the 10 wells of $9.4 million currently reflected as Joint interest billings in the Company’s consolidated balance sheet will be reclassified to oil and gas properties during the first quarter ended December 31, 2007. In addition, the

FF-17

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Company paid EnCana $1.0 million at closing that will also be reflected in oil and gas properties during the first quarter ended December 31, 2007.

South Bronco Project. Effective July 17, 2006, the Company entered into an EDA with MAB related to the South Bronco properties in the Piceance Basin located in western Colorado, under which the Company received an undivided 50% working interest in the properties in exchange for commitments to drill four exploration wells. The Company was also obligated to pay MAB monthly project development costs of $20,000, commencing May 1, 2006, and to pay the first $50.0 million of project costs. Effective January 1, 2007, MAB assigned its remaining undivided 50% working interest in these properties to the Company, and our commitment to pay the remainder of the first $50.0 million of project costs was terminated. In January 2007, the Company and the seller of the South Bronco properties mutually terminated the Company’s drilling obligations and other rights related to these properties, and the Company relinquished and reassigned its entire interest in the properties to the seller.

Sugarloaf Project. The following is a summary of the costs of acquiring the Sugarloaf Project:

	Shares		Price		Consideration
					($ in thousands)
Closing:
Cash		—		—	$	100
Contract payable		—		—		2,900
Common shares		2,428	$	1.70		4,127
Total		2,428				7,127

Amendments:
Common shares		572		1.72		984
Common shares		475		1.29		613
Common shares		525		0.51		268
Common shares		4,000		0.23		920
Additional common shares		5,572		—		2,785

Cash		—		—		288
Accrued liabilities		—		—		427
Total additional consideration		—		—		3,500
Total Maralex acquisition costs		8,000		—	$	10,627

On November 28, 2006, MAB entered into a Lease Acquisition and Development Agreement (the “Maralex Agreement”) with Maralex Resources, Inc. and Adelante Oil & Gas LLC (collectively, “Maralex”) for the acquisition and development of the Sugarloaf Prospect in Garfield County, Colorado. By the terms of the Maralex Agreement, the Company paid $0.1 million at closing, with the remaining cash of $2.9 million and the issuance of 2.4 million shares of the Company’s common stock due on January 15, 2007. The Company recorded the $2.9 million obligation as Contract payable — oil and gas properties, and $4.1 million as stockholders’ equity (equal to 2.4 million shares at the $1.70 closing price of the Company’s common stock on the date of the Maralex Agreement).

The Company and Maralex have amended the terms of the Maralex Agreement on several occasions since the original Maralex Agreement was executed, amending the payment dates, issuing 5.6 million additional shares of the Company’s common stock and agreeing to increase the amount of cash due under the agreement by a total of $0.3 million (all reflected in the table above). On June 29, 2007, Maralex notified the Company it was in default under the terms of the Maralex Agreement, as amended. Consequently, by the terms of the Maralex Agreement, the

FF-18

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Company was required to pay Maralex an amount equal to 5% of the outstanding payable for each 20 days past due. As of September 30, 2007, the Company has reflected an accrued liability of $0.4 million with a corresponding amount in interest expense and all of which have been recorded as interest expense in our consolidated statement of operations. If the Company failed to make payment of the remaining balance by August 28, 2007, Maralex, at its option, could return up to 80% of the previously issued shares of the Company’s common stock, and the Company would reassign to Maralex all leases acquired under the Maralex Agreement.

By the terms of the third amendment to the Maralex Agreement, the Company was to commence the drilling of four wells on the subject leases by September 30, 2008. The Company has estimated costs to drill and complete each well at $2.4 million per well or total costs of $9.6 million. The Maralex Agreement requires the payment of liquidated damages equal to $0.3 million, $0.2 million, $0.2 million and $0.1 million for failure to commence the first, second, third or fourth well, respectively.

As of September 30, 2007, the balance due to Maralex is $1.8 million and is reflected as Contract payable — oil and gas properties in the consolidated balance sheet. On December 1, 2007, the Company paid Maralex $0.3 million related to payments on this agreement (see Note 7).

On December 4, 2007, Maralex terminated the Maralex Agreement and notified the Company that they would return 6.4 million shares of common stock and consequently, the Company was relieved of its drilling commitment. In addition, costs incurred in excess of the carrying value of the common stock to be returned have been included in costs to be amortized, and have been included in the ceiling test at the lower of cost or estimated fair value.

Gibson Gulch Project. Effective August 4, 2006, the Company entered into an EDA with MAB for the Gibson Gulch Project under which the Company acquired an interest and the right to participate in the proposed drilling of four wells. Effective November 2, 2006, the Company entered into an EDA with MAB related to drilling two additional wells in the Gibson Gulch Project (with the underlying agreements jointly referred to herein as the “Well Participation and Farm-out Agreements”). The Company was also obligated to pay MAB monthly project development costs of $5,000, commencing August 1, 2006, and to pay the first $5.0 million of project costs. Effective January 1, 2007, MAB assigned its remaining undivided 50% working interest in these properties to the Company, and our commitment to pay the remainder of the first $5.0 million of project costs was terminated.

The Company participated in the drilling and completion of six wells under Well Participation and Farm-out Agreements (the “Farm-outs”) with an unrelated third party (the “Farmor”). In February and March 2007, the Farmor notified the Company that it was in default of the terms of the joint operating agreement for failure to timely pay the operator amounts due for drilling and completion costs.

On March 29, 2007, the Farmor notified the Company it was exercising its right to terminate the farm-outs and resume ownership of the working interests in the six wells. The Farmor reimbursed the $1.6 million paid by the Company as partial payments to drill the wells, and credited the Company for the remaining balance payable to the operator. Through March 31, 2007, the Company had reflected $2.5 million of oil and gas sales, $0.4 million of lease operating expenses and production taxes, and $0.4 million of depreciation, depletion and amortization from the six wells in which it had held a contractual interest. Upon the termination of the farm-outs, all amounts were eliminated from the Company’s consolidated financial statements.

AUSTRALIA

Australia Project. The Company owns four exploration licenses comprising 7.0 million net acres in the Beetaloo Basin (owned by the Company’s wholly-owned subsidiary, Sweetpea Petroleum Pty Ltd., [ “Sweetpea”]).

On July 31, 2007, Sweetpea commenced drilling the Sweetpea Shenandoah No. 1 well in the central portion of the Beetaloo Basin. The well was drilled to a depth of 4,724 feet, intermediate casing was run on September 15, 2007 and the well was then suspended with an intention to deepen the well to a depth of 9,580 feet.

FF-19

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Beetaloo Project. Effective March 17, 2006, the Company entered into an EDA with MAB for the acquisition of an undivided 50% working interest in the Beetaloo Project through ownership of shares in Sweetpea, which consists of four exploration permits in the Northern Territory, Australia. By the terms of the EDA, the Company paid $1.0 million to the assignor and has funded the $3.0 million seismic commitment. The Company was obligated to pay monthly project development costs of $0.1 million per month, commencing March 1, 2006, and the first $100.0 million of project costs. Effective January 1, 2007, MAB assigned its remaining undivided 50% working interest in these properties to the Company (by assigning all remaining shares in Sweetpea), and our commitment to pay the remainder of the first $100.0 million of project costs was terminated.

The Company has a 100% working interest in this project with a royalty interest of 10% to the government of the Northern Territory and an overriding royalty interest of 1% to 2%, 8% and 5% to the Northern Land Council, the assignor and to MAB, respectively, leaving a net revenue interest of 75% to 76% to us.

Pursuant to the terms of the exploration permits for the calendar year ended December 31, 2008, the Company is committed to drill two wells on Exploration Permit 76 at an estimated cost of $4.0 million per well, or $8.0 million, and to shoot 100 kilometers (approximately 62 miles) of seismic.

Gippsland and Otway Project. On November 14, 2006, the Company and Lakes Oil N.L. (“Lakes Oil”) entered into an agreement (the “Lakes Agreement”) under which they would jointly develop Lakes Oil’s onshore petroleum prospects (focusing on unconventional gas resources) in the Gippsland and Otway Basins in Victoria, Australia. The arrangement was subject to various conditions precedent, including completion of satisfactory due diligence, and the satisfactory processing and retention of certain lease applications.

The Lakes Agreement expired pursuant to its terms, and the Company and Lakes are conducting discussions to formally terminate the Agreement wherein we would receive $0.1 million in escrowed funds and both parties will fully waive and release each other from all further obligations and liabilities.

Northwest Shelf Project. Effective February 19, 2007, the Commonwealth of Australia granted an exploration permit in the shallow, offshore waters of Western Australia to Sweetpea. The permit, WA-393-P, has a six-year term and encompasses almost 20,000 net acres. We have committed to an exploration program with geological and geophysical data acquisition in the first two years with a third year drilling commitment and additional wells to be drilled in the subsequent three year period depending upon the results of the initial well.

POWDER RIVER BASIN

On December 29, 2006, the Company entered into a purchase and sale agreement (the “Galaxy PSA”) with Galaxy Energy Corporation (“Galaxy”) and its wholly-owned subsidiary, Dolphin Energy Corporation (“Dolphin”). Pursuant to the Galaxy PSA, the Company agreed to purchase all of Galaxy’s and Dolphin’s oil and gas interests in the Powder River Basin of Wyoming and Montana (the “Powder River Basin Assets”).

The purchase price for Powder River Basin Assets was $45.0 million, with $20.0 million to be paid in cash and $25.0 million to be paid in shares of the Company’s common stock. Closing of the transaction was subject to approval by Galaxy’s secured noteholders, approval of all matters by our Board of Directors, including the Company obtaining outside financing on terms acceptable to our Board of Directors, and various other terms and conditions. Pursuant to successive monthly amendments to the Galaxy PSA, either party could terminate the agreement if closing had not occurred by August 31, 2007.

In January 2007, we paid a $2.0 million earnest money deposit to Galaxy, which was due under the terms of the agreement. In the event the closing did not occur for any reason other than a material breach by us, the deposit was to convert into a promissory note (the “Galaxy Note”), payable to us, as an unsecured subordinated debt of both Galaxy and Dolphin, which was to be payable only after repayment of Galaxy’s and Dolphin’s senior indebtedness.

FF-20

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

We became the contract operator of the Powder River Basin Assets beginning January 1, 2007. At closing, the operating expenses incurred by us as the contract operator were to be credited toward the purchase price, or if closing did not occur, would be added to the principal amount of the Galaxy Note.

The Galaxy PSA expired by its terms on August 31, 2007. We obtained the Galaxy Note in the amount of $2.5 million, which consisted of the $2.0 million earnest deposit plus a portion of operating costs paid by us and which was due upon the later of (i) the date upon which all of Galaxy’s senior indebtedness has been paid in full and (ii) December 29, 2007. As discussed above, MAB was guarantor of the Galaxy Note. The Galaxy Note was paid by MAB in November 2007 (by the terms of the Second Amendment to the Consulting Agreement and in December 2007 by the terms of the Third Amendment to the Consulting Agreement) by offsetting it against the MAB Note (see Note 14).

MONTANA COALBED METHANE

Bear Creek Project. Effective May 15, 2006, the Company entered into an EDA with MAB related to the Bear Creek prospect in Montana, under which the Company received an undivided 50% working interest in the properties. By the terms of the agreement, and as the purchase price, the Company issued a convertible note in the amount of $1.2 million, convertible to 2.4 million shares of the Company’s common stock at $0.50 per share to an unrelated third party. The Company was also obligated to pay MAB monthly project development costs of $50,000 commencing May 1, 2006, and to pay the first $50.0 million of project costs. Effective January 1, 2007, MAB assigned its remaining undivided 50% working interest in these properties to the Company, and our commitment to pay the remainder of the first $50.0 million of project costs was terminated.

Of the original 25,278 acres acquired, the Company has retained 13,905 of those acres. The remaining 11,373 acres have been released. The acres retained have been reflected in unproved oil and gas properties subject to further evaluation by the Company. The acres released have been reflected in unproved properties but included in evaluated costs subject to amortization; those costs have also been included in the full cost ceiling test at the lower of cost or market value.

HEAVY OIL

Sale of Heavy Oil Projects. Effective October 1, 2007, the Company sold a majority of its interest in certain Heavy Oil Projects, including the West Rozel, Fiddler Creek and Promised Land Projects to Pearl Exploration and Production Ltd. (“Pearl”). The purchase price was a maximum of $30.0 million, payable as follows: (a) $7.5 million in cash; (b) the issuance of the number of shares of Pearl equivalent to $10.0 million (based on a price of $4.00 Canadian dollars per share or such other higher price as is dictated by the regulations of the TSX Venture Exchange), excluding value attributable to leases on which title is being reviewed after closing, and value attributable to 4,645 net acres of leasehold which were not assigned at closing, pending Pearl’s attempt to renegotiate the terms of the Company’s agreement with the third party that sold acreage to PetroHunter; and (c) a performance payment (the “Pearl Performance Payment”) of $12.5 million in cash at such time as either: (i) production from the assets reaches 5,000 barrels per day; or (ii) proven reserves from the assets is greater than 50.0 million barrels of oil as certified by a third party reserve engineer. In the event that these targets have not been achieved by September 30, 2010, the Pearl Performance Payment obligation will expire. Further, the Company could receive up to approximately 1.0 million additional Pearl shares if the Buyer

FF-21

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

enters into a binding agreement (within six months from the closing) with the above-mentioned third party assignor to acquire certain leases.

The sale of assets to Pearl also resulted in amendments to existing agreements with third parties, including MAB’s relinquishment of its rights and obligations in all PetroHunter properties in Utah and Montana, as set forth in the Second Amendment, and termination of PetroHunter’s obligation to pay an overriding royalty and a per barrel production payment to American Oil & Gas, Inc. (“American”) and Savannah Exploration (“Savannah”), in consideration for: (a) five million common shares of PetroHunter common stock to be issued to American and Savannah; and (b) a contingent obligation to pay a total of $2.0 million to American and Savannah in the event PetroHunter receives the Pearl Performance Payment.

West Rozel Project. Effective November 21, 2005, the Company entered into an EDA with MAB for the West Rozel Project, under which the Company paid $1.3 million to the assignor and reimbursed costs incurred by the assignor of approximately $0.2 million. The Company was obligated to pay MAB monthly project development costs in the amount of $0.2 million, commencing June 1, 2005, and the first $50.0 million of project costs. Effective January 1, 2007, MAB assigned its remaining undivided 50% working interest in these properties to the Company, and our commitment to pay the remainder of the first $50.0 million of project costs was terminated.

Fiddler Creek Project. Effective July 16, 2006, the Company entered into an EDA with MAB for the Fiddler Creek Project located in Montana, under which the Company paid a $2.0 million finder’s fee to an unrelated third party, consisting of $0.3 million cash and the $1.7 million in the Company’s common stock (3.4 million shares at $0.50 per share). The Company was obligated to pay MAB monthly project development costs of $20,000 per month, commencing April 1, 2006, and the first $100.0 million of project costs. Effective January 1, 2007, MAB assigned its remaining undivided 50% working interest in these properties to the Company, and our commitment to pay the remainder of the first $100.0 million of project costs was terminated.

On September 15, 2006 the Company acquired additional acreage in the Fiddler Creek Project area for a purchase price of $11.3 million (of which $6.0 million has been paid). The Company was also obligated to pay MAB monthly project development costs of $0.1 million, commencing August 1, 2006, and to pay the first $50.0 million of project costs on these additional properties. Effective January 1, 2007, MAB assigned its remaining undivided 50% working interest in these properties to the Company, and our commitment to pay the remainder of the first $50.0 million of project costs was terminated.

Promised Land Project. Effective May 15, 2006, the Company entered into an EDA with MAB for the Promised Land Project, under which the Company paid lease acquisition costs of $0.2 million. The Company was also obligated to pay MAB monthly project development costs of $50,000, commencing May 1, 2006, and to pay the first $50.0 million of project costs. Effective January 1, 2007, MAB assigned its remaining undivided 50% working interest in these properties to the Company, and our commitment to pay the remainder of the first $50.0 million of project costs was terminated.

FF-22

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Summary. Oil and gas properties at September 30, 2007 and 2006 consisted of the following ($ in thousands):

	2007			2006
Oil and gas properties, at cost, full cost method
Unproved
United States	$	107,239		$	39,906
Australia		23,569			6,106
Proved		57,168			—
Total		187,976			46,012
Less accumulated depreciation, depletion, amortization and impairment		(25,133	)		(39	)
Total	$	162,843		$	45,973

Included in oil and gas properties above is capitalized interest of $1.5 million for the year ended September 30, 2007. No interest was capitalized during the year ended September 30, 2006 or 2005.

The following is a summary of depreciation, depletion, amortization and accretion, as reflected in the consolidated statements of operations (including depreciation, depletion and amortization of oil and gas properties per thousand cubic feet of natural gas equivalent) for the years ended September 30 ($ in thousands, except per thousand cubic feet):

	2007		2006		2005

Depreciation, depletion and amortization of oil and gas properties	$	1,040	$	39	$	—
Depreciation of furniture and equipment		192		32		—
Accretion of asset retirement obligation		13		2		—
Total		1,245		73		—
Depreciation, depletion and amortization per thousand cubic feet of natural gas equivalent	$	2.27	$	6.71	$	—

For the year ended September 30, 2007, capitalized costs, less accumulated depreciation, depletion and amortization, less related deferred income taxes, exceeded the ceiling limitation. Consequently, the Company reflected a charge of $24.1 million for impairment of oil and gas properties that is reflected in the consolidated statement of operations. Of the total impairment, $23.5 million, $0.1 million and $0.5 million related to the United States, China and Africa, respectively. Impairment in China and Africa represents all costs incurred through September 30, 2007 as the Company has no plans to pursue projects in those countries.

Using September 30, 2007 oil and gas prices of $62.61 per barrel and $4.80 per thousand cubic feet, the United States full cost pool exceeded the ceiling by $29.3 million. Subsequent to year end, prices increased. Using oil and gas prices on December 10, 2007 of $63.00 per barrel and $5.68 per thousand cubic feet, United States impairment expense was reduced by $5.3 million.

FF-23

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 5 —

Furniture and Equipment

Furniture and equipment at September 30, 2007 and 2006 is reported at cost, net of accumulated depreciation and consisted of the following ($ in thousands):

	2007			2006
Furniture and equipment	$	748		$	582
Less accumulated depreciation		(179	)		(32	)
Total	$	569		$	550

Depreciation expense associated with capitalized office furniture and equipment during 2007 and 2006 was $192,000 and $32,000, respectively. There was no depreciation expense during 2005. The estimated useful life of furniture and fixtures is seven years.

Note 6 —

Asset Retirement Obligation

The Company recognizes an estimated liability for future costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and a corresponding increase to the carrying value of the related long-lived asset are recorded at the time a well is completed or acquired. The increase in carrying value is included in proved oil and gas properties in the consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs and recognizes accretion expense in connection with the discounted liability over the remaining estimated economic lives of the respective oil and gas properties.

The Company’s estimated asset retirement obligation liability is based on estimated economic lives, estimates as to the cost to abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using a credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. The credit-adjusted risk-free rates used to discount the Company’s abandonment liabilities range from 8% to 15%. Revisions to the liability are due to increases in estimated abandonment costs and changes in well economic lives, or in changes to federal or state regulations regarding the abandonment of wells.

A reconciliation of the Company’s asset retirement obligation liability is as follows as of September 30, ($ in thousands):

	2007			2006
Beginning asset retirement obligation	$	522		$	—
Liabilities incurred		30			520
Liabilities settled		—			—
Revisions to estimates		(429	)		—
Accretion expense		13			2
Ending asset retirement obligation	$	136		$	522

Note 7 —

Contract Payable

On November 28, 2006, MAB entered into the Maralex Agreement with Maralex for the acquisition and development of the Sugarloaf Prospect (see Note 4). Under the terms of the Maralex Agreement, an initial payment of $0.1 million was made upon execution and the balance of $2.9 million in cash along with the issuance of 2.4 million shares of the Company’s common stock was due on January 15, 2007. The Company recorded the $2.9 million obligation on the consolidated balance sheet as Contract payable — oil and gas properties. The Company and Maralex have amended the terms of the Maralex Agreement on three occasions. The Contract is non-

FF-24

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

interest bearing, but we have agreed to pay a penalty of 5% of the outstanding balance for each 20 day period after the due date of the payments for all unpaid balances.

The balance was scheduled to be paid on September 21, 2007. A payment of $0.3 million was made in November, 2007, but the liability is still in default based on the terms of the extension agreement. If Maralex pursues the default, Maralex may, at its option, return up to 80% of the shares of Company stock previously issued to Maralex and the Company will reassign all leases acquired under the Maralex Agreement to Maralex. We are currently in negotiations with Maralex to renew and extend the Maralex Agreement. As of September 30, 2007, we owe Maralex $1.8 million for principal and accrued penalties under the Maralex Agreement.

On December 4, 2007, Maralex terminated the Maralex Agreement and notified the Company that they would return 6.4 million shares of common stock. Consequently, the Company was relieved of its drilling commitment.

Note 8 —

Notes Payable

Notes payable as of September 30, 2007 and 2006 are summarized below ($ in thousands):

	2007			2006
Short-term notes payable:
Global Project Finance AG	$	500		$	—
Vendor		4,050			—
Flatiron Capital Corp.		117			—
Short-term notes payable	$	4,667		$	—
Convertible notes payable	$	400		$	400
Subordinated notes payable — related party:
Bruner Family Trust	$	275		$	—
MAB		12,530			—
Less current portion		(3,755	)		—
Subordinated notes payable — related party	$	9,050		$	—
Long-term notes payable — net of discount:
Global Project Finance AG	$	31,550		$	—
Vendor		250			—
Less current portion		(120	)		—
Discount on notes payable		(3,736	)		—
Long-term notes payable — net of discount	$	27,944		$	—

Short — Term Notes Payable

Global Project Finance AG. On September 25, 2007, the Company borrowed $0.5 million from Global Project Finance, AG (“Global”) under a note dated September 1, 2007. The note was due on the earlier of November 30, 2007 or five business days after the close of the sale of the PetroHunter Heavy Oil, Ltd. The note is unsecured and bears interest at a rate of 7.75% per annum. This note was paid in full on November 9, 2007.

Vendor. On June 19, 2007, the Company entered into a promissory note with a vendor for an outstanding unpaid balance due to the vendor, in the amount of $6.5 million. The note was to be paid in full by July 31, 2007 and bears interest at 14% if paid current. The interest rate increases to 21% if the note is in default. At September 30,

FF-25

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

2007, we were in default on this note due to non-payment; the balance was $4.1 million and we had accrued interest on the note in the amount of $0.2 million. Subsequent to September 30, 2007, we paid $3.8 million towards the note balance but in October 2007, the vendor filed a judgment lien against us (see Note 13).

Flatiron Capital Corp. On June 6, 2007, the Company entered into a promissory note with Flatiron Capital for the financing of certain insurance policies in the amount of $0.2 million. The note bears interest at a rate of 7.25% per annum. Payments are due in 10 equal installments of $17,000, commencing on July 1, 2007 and maturing on April 1, 2008. The note is unsecured and the balance at September 30, 2007 was $0.1 million. At September 30, 2007, we are not in default on this note.

Convertible Notes Payable

Prior to the merger with GSL on May 12, 2006, Digital entered into five separate loan agreements, aggregating $0.4 million, due one year from issuance, commencing October 11, 2006. The loans bear interest at 12% per annum, are unsecured, and are convertible, at the option of the lender, at any time during the term of the loan or upon maturity, at a price per share equal to the closing price of the Company’s common shares on the Over the Counter Bulletin Board market on the day preceding notice from the lender of its intent to convert the loan. As of September 30, 2007, the Company was in default on payment of the notes and is in discussions with the holders to convert the notes and accrued interest into stock of the Company.

In December 2006, PetroHunter Australia, commenced the sale of up to $50.0 million of convertible notes, pursuant to a private placement. As of January 8, 2007, the Company had received proceeds of $1.5 million from the offering. In February 2007, the Company terminated the offering, and refunded a total of $30,000 to four investors, and converted $1.5 million from one investor as the initial funding under a January 2007 Credit Facility (see Long-Term Notes Payable below).

Notes Payable-Related Party

MAB Consulting. Effective January 1, 2007, in conjunction with the Consulting Agreement, we issued a $13.5 million promissory note (the “MAB Note”) as partial consideration for MAB’s assignment of its undivided 50% working interest in certain oil and gas properties (see Note 3). The MAB Note bore interest at a rate equal to LIBOR. Monthly payments of principal of $225,000 plus accrued interest were scheduled to begin on January 31, 2007 and were scheduled to end in December 2011. As of September 30, 2007, the outstanding balance of the MAB Note was $12.5 million of which $1.6 million of principal and accrued interest was currently due. This amount includes $1.3 million of principal and accrued interest that was past due. The Company was not in compliance with various covenants under the MAB Note as of September 30, 2007. MAB has waived and released PetroHunter from any and all defaults, failures to perform, and any other failures to meet its obligations through October 1, 2008.

On November 15, 2007, we entered into the Second Amendment under the terms of which the MAB Note was replaced with a new promissory note in the amount of $2.0 million (see Note 14).

Bruner Family Trust. On July 11, 2007, we executed a subordinated unsecured promissory note in the amount of $250,000 in favor of Bruner Family Trust, UTD March 28, 2005 (the “Bruner Family Trust”). Interest accrues at an annual rate of 8% and the note plus accrued interest is due in full on the later of October 29, 2007 or the time when the Global Project Finance AG Credit Facility and all other senior indebtedness has been paid in full. In November 2007, this note was partially assigned to an Officer and Director of the Company (see Note 14).

On September 21, 2007, we executed a subordinated unsecured promissory note in the amount of $25,000 in favor of Bruner Family Trust. Interest accrues at the rate of 8% per annum and the note plus accrued interest is due in full on the later of December 20, 2007 or the time when the Global Project Finance AG Credit Facility and all other senior indebtedness has been paid in full.

FF-26

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

At September 30, 2007, we had accrued interest related to the Bruner Family Trust notes in the amount of $3,000.

Long-Term Notes Payable

Credit Facility — Global. On January 9, 2007, we entered into a Credit and Security Agreement (the “January 2007 Credit Facility”) with Global for mezzanine financing in the amount of $15.0 million. The January 2007 Credit Facility is collateralized by a first perfected lien on certain oil and gas properties and other assets of the company and interest accrues at an annual rate of 6.75% over the prime rate. Interest is payable in arrears on the last day of each quarter beginning March 31, 2007. Principal payments commence at the end of the first quarter, 18 months following the date of the agreement or September 30, 2008. Principal payments shall be made in such amounts as may be agreed upon by us and Global on the then outstanding principal balance in order to repay the balance by the maturity date, July 9, 2009. We may prepay the balance in whole or in part without penalty or notice and we may terminate the facility with 30 days written notice. In the event that we sell any interest in the oil and gas properties that compromise the collateral, a mandatory prepayment is due in the amount equal to such sales proceeds, not to exceed the balance due under the January 2007 Credit Facility.

The terms of the January 2007 Credit Facility provide for the issuance of 1.0 million warrants to purchase 1.0 million shares of the Company’s common stock upon execution of the January 2007 Credit Facility, and an additional 0.2 warrants, for each $1.0 million draw of funds from the credit facility up to the total amount available under the facility, $15.0 million. The warrants are exercisable until January 9, 2012. The exercise price of the warrants is equal to 120% of the weighted-average price of the Company’s stock for the 30 days immediately prior to each warrant issuance date. Prices range from $1.30 to $2.10 per warrant. The fair value of the warrants was estimated as of each respective issue date under the Black-Scholes pricing model with the following assumptions: (i) the common stock price at market price on the date of issue; (ii) zero dividends; (iii) expected volatility of 69.2% to 71.4%; (iv) a risk-free interest rate ranging from 4.5% to 4.75%; and (v) an expected life of 2.5 years. The fair value of the warrants of $2.2 million was recorded as a discount to the credit facility and is being amortized over the life of the note. The unamortized portion of the discount is offset against the long-term notes payable on the consolidated balance sheet. We pay an advance fee (the “Advance Fee”) of 1% of all amounts drawn against the facility. In 2007, the advance fee related to the original January 2007 Credit Facility was recorded as deferred financing fees, totaled $0.2 million and is being amortized to interest expense over the life of the January 2007 Credit Facility.

Global and its controlling shareholder were shareholders of the Company prior to entering into the January 2007 Credit Facility. The initial draw from the January 2007 Credit Facility of $1.5 million was converted from the convertible note offering discussed above. As of September 30, 2007, the Company has drawn the total $15.0 million available under the January 2007 Credit Facility.

On May 21, 2007, the Company entered into a second Credit and Security Agreement with Global (the “May 2007 Credit Facility”). Under the May 2007 Credit Facility, Global agreed to use its best efforts to advance up to $60.0 million to us over the following 18 months. Interest on advances under the May 2007 Credit Facility accrues at 6.75% over the prime rate and is payable quarterly beginning June 30, 2007. We pay an advance fee of 2% on all amounts drawn under the May 2007 Credit Facility. The Company is to begin making principal payments on the loan beginning at the end of the first quarter following the end of the 18 month funding period, December 31, 2008. Payments shall be made in such amounts as may be agreed upon by us and Global on the then outstanding principal balance in order to repay the principal balance by the maturity date, November 21, 2009. The loan is collateralized by a first perfected security interest on the same properties and assets that are collateral for the January 2007 Credit Facility. We may prepay the balance in whole or in part without penalty or notice and we may terminate the facility with 30 days written notice. In the event that we sell any interest in the oil and gas properties that comprise the collateral, a mandatory prepayment is due in the amount equal to such sales proceeds, not to exceed the balance due

FF-27

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

under the May 2007 Credit Facility. As of September 30, 2007, $16.6 million has been advanced to us under this facility. The advance fee in the amount of $0.3 million was recorded as deferred financing costs, and is being amortized over the life of the May 2007 Credit Facility.

Global received warrants to purchase 2.0 million of the Company’s shares upon execution of the May 2007 Credit Facility and 0.4 million warrants for each $1.0 million advanced under the credit facility. The warrants are exercisable until May 21, 2012 at prices equal to 120% of the volume-weighted-average price of the Company’s common stock for the 30 days immediately preceding each warrant issuance date. Prices range from $0.31 to $1.39 per warrant. The fair value of the warrants was estimated as of each respective issue date under the Black-Scholes pricing model, with the following assumptions: (i) common stock based on the market price on the issue date; (ii) zero dividends; (iii) expected volatility of 69.2% to 71.8%; (iv) risk free interest rate of 4.5% to 4.875%; and (v) expected life of 2.5 years. The fair value of the warrants issuable as of September 30, 2007, in the amount of $1.9 million for advances through September 30, 2007, was recorded as a discount to the note and is being amortized over the life of the note.

On May 12, 2007, the Company issued a “most favored nation” letter to Global which indicated that it would extend all the economic terms from the May 2007 Credit Facility retroactively to the January 2007 Credit Facility. On May 21, 2007, when the May 2007 Credit Facility was signed, the Company issued an additional 1.0 million warrants for the execution of the January 2007 Credit Facility and an additional 3.0 million warrants for the January 2007 Credit Facility based on the $15.0 million advanced under the January 2007 Credit Facility. The fair value of the warrants relating to this amendment totaled $0.6 million. The Company also recorded an additional $0.2 million in deferred financing costs which are being amortized over the life of the January 2007 Credit Facility. The most favored nation agreement did not extend the dates identified in the January 2007 Credit Facility; as a result, the additional deferred financing costs and loan discount are being amortized over the term of the January 2007 Credit Facility.

As of September 30, 2007, the Company was in default of payments in the amount of $1.6 million, which consists of unpaid interest fees under the Credit Facilities. The Company was also not in compliance with various financial and debt covenants under the Global Credit Facilities as of September 30, 2007. Global has waived and released PetroHunter from any and all defaults, failures to perform, and any other failures to meet its obligations through October 1, 2008.

Vendor Long-term Notes Payable

On August 10, 2007, the Company entered into an unsecured promissory note with a vendor for past due invoices aggregating $0.3 million. The note bears interest at an annual rate of 8%. Payments are due in 24 equal installments of $11,000, commencing on October 1, 2007 and maturing on September 1, 2009.

Principal Payments

The aggregate amount of minimum principal payments required on long-term notes payable in each of the years indicated are as follows as of September 30, ($ in thousands):

September 30,	Principal
2008	$	3,875
2009		17,830
2010		19,525
2011		2,700
2012		675
Total	$	44,605

FF-28

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 9 —

Stockholders’ Equity

Common Stock. During the twelve months ended September 30, 2007, the Company issued 59.0 million shares of its common stock as follows:


	•	2.4 million shares at $1.70 per share for purchases of oil and gas properties

	•	50.0 million shares at $1.62 per share for the acquisition of oil and gas properties to related party

	•	0.3 million shares at $1.49 per share for the acquisition of oil and gas properties and transaction finance costs

	•	0.1 million shares at $1.65 per share for commission on convertible debt issue

	•	0.6 million shares at $1.72 per share for purchases of oil and gas properties

	•	0.5 million shares at $1.29 per share for transaction finance costs

	•	0.6 million shares at $0.70 per share for cash and transaction finance costs

	•	0.5 million shares at $0.51 per share for transaction finance costs

	•	4.0 million shares at $0.23 per share for transaction finance costs.

During the twelve months ended September 30, 2006, the Company issued 119.9 million shares of its common stock as follows:


	•	3.0 million shares, valued at $0.50 per share, as partial consideration for the acquisition of oil and gas properties

	•	3.4 million shares, valued at $0.50 per share, as consideration for a finder’s fee on an oil and gas prospect

	•	2.8 million shares valued at $0.50 per share, as partial consideration for finder’s fees on the sale of convertible debt

	•	44.1 million shares at $0.50 per share, for conversion of convertible debt (see Note 8)

	•	28.7 million shares pursuant to the share exchange agreement with GSL (see Note 1)

	•	35.4 million shares pursuant to the sale of units at $1.00 per unit to accredited investors pursuant to a private placement memorandum. Each unit consists of one share of common stock and a warrant to purchase one share of common share for a period of five years at $1.00 per share.

	•	1.5 million shares valued at $1.00 per share, as partial consideration for finder’s fees on the sale of $1.00 units in the private placement.

	•	1.0 million shares for exercise of warrants at $1.00 per share.

Common Stock Subscribed. On November 6, 2006, we commenced the sale of a maximum $125.0 million pursuant to a private placement of units at $1.50 per unit (the “Private Placement”). Each unit consisted of one share of our common stock and one-half common stock purchase warrant. A whole common stock purchase warrant entitled the purchaser to acquire one share of the Company’s common stock at an exercise price of $1.88 per share through December 31, 2007. In February 2007, the Board of Directors determined that the composition of the units being offered would be restructured, and those investors who had subscribed in the offering would be offered the opportunity to rescind their subscriptions or to participate on the same terms as ultimately defined for the restructured offering. As of September 30, 2007, the Company has received subscriptions for $2.7 million for the sale of units pursuant to the Private Placement, of which $2.3 million was from a related party.

FF-29

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

of accrued interest through September 30, 2007 was calculated and added to the subscription amount. Investors who had subscribed in the offering were again offered the opportunity to rescind their subscriptions or to participate in the restructured offering. Investors, who had subscribed a total of $75,000, elected to rescind their subscription when the November offer was distributed. That amount plus the related accrued interest was reclassified to a liability as of September 30, 2007. The balance of outstanding subscriptions plus accrued interest at September 30, 2007 totaling $2.9 million was recorded as Common Stock Subscribed in the consolidated balance sheet.

Note 10 —

Compensation Plan

Stock Option Plan. On August 10, 2005, the Company adopted the 2005 Stock Option Plan (the “Plan”), as amended. Stock options under the Plan may be granted to key employees, non-employee directors and other key individuals who are committed to the interests of the Company. Options may be granted at an exercise price not less than the fair market value of the Company’s common stock at the date of grant. Most options have a five year life but may have a life up to 10 years as designated by the compensation committee of the Board of Directors (the “Compensation Committee”). Typically, options vest 20% on grant date and 20% each year on the anniversary of the grant date but each vesting schedule is also determined by the Compensation Committee. Most initial grants to Directors vest 50% on grant date and 50% on the one-year anniversary of the initial grant date. Subsequent grants (subsequent to the initial grant) to Directors typically vest 100% at the grant date. In special circumstances, the Board may elect to modify vesting schedules upon the termination of selected employees and contractors. The Company has reserved 40.0 million shares of common stock for the plan. At September 30, 2007, 15.0 million shares remained available for grant pursuant to the stock option plan.

A summary of the activity under the Plan for the years ended September 30, 2007 and 2006 and period ended September 30, 2005 is presented below (shares in thousands):

				Weighted-
	Number of			Average
	Shares			Exercise Price

Options outstanding — June 20, 2005		—		$	—
Granted		19,000		$	0.50
Options outstanding — September 30, 2005		19,000		$	0.50
Granted		13,295		$	2.10
Forfeited		—		$	—
Expired		—		$	—
Options outstanding — September 30, 2006		32,295		$	1.16
Granted		4,020		$	0.76
Forfeited		(11,350	)	$	0.69
Expired		—		$	—
Options outstanding — September 30, 2007		24,965		$	1.31

There have been no options exercised under the terms of the Plan.

FF-30

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

A summary of the activity and status of non-vested awards for the periods ended and as of September 30, 2007, 2006 and 2005 is presented below (shares in thousands):

				Weighted-
	Number of			Average
	Shares			Fair Value

Non-vested — June 20, 2005		—		$	—
Granted		19,000		$	0.32
Vested		(3,800	)	$	0.32
Forfeited		—		$	—
Expired		—		$	—
Non-vested — September 30, 2005		15,200		$	0.32
Granted		13,295		$	1.23
Vested		(6,459	)	$	1.28
Forfeited		—		$	—
Expired		—		$	—
Non-vested — September 30, 2006		22,036		$	1.27
Granted		4,020		$	0.39
Vested		(7,138	)	$	0.55
Forfeited		(8,710	)	$	1.20
Expired		—		$	—
Non-vested — September 30, 2007		10,208		$	0.62

As of September 30, 2007, there was $6.3 million of total unrecognized compensation cost related to non-vested share-based compensation arrangements granted under the Plan. That cost is expected to be recognized over a weighted-average period of 2.93 years. The total fair value of shares vested during the years ended September 30, 2007, 2006 and 2005 was $3.9 million, $8.3 million and $1.2 million, respectively.

	2007			2006			2005

Expected option term — years		1-5			5			5
Weighted-average risk-free interest rate		4.2%-4.9	%		4.2%-4.9	%		4.2	%
Expected dividend yield		0			0			0
Weighted-average volatility		62%-74	%		74	%		74	%

Because our common stock has only recently become publicly traded, we have estimated expected volatilities based on an average of volatilities of similar sized Rocky Mountain oil and gas companies whose common stock is or has been publicly traded for a minimum of three years and other similar sized oil and gas companies who recently became publicly traded. The expected term ranges from one year to four years based on the above described vesting schedules, with a weighted-average of 3.86 years. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect on the date of grant. We did not include an estimated forfeiture rate due to a lack of history of employee and contractor turnover.

FF-31

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table summarizes additional information regarding options outstanding as of September 30, 2007 (shares in thousands):

Stock Options Outstanding
Range of Exercise Price	Number of Options Outstanding		Weighted-Average Remaining Contractual Life (In Years)		Weighted-Average Exercise Price per Share		Aggregate Intrinsic Value

0.19 - 0.49		1,850		4.9	$	0.34	$	—
0.50 - 0.99		9,670		3.0		0.51		—
1.0 - 1.99		1,500		4.4		1.29		—
³2.00		11,945		3.9		2.10		—

		24,965		3.6	$	1.31	$	—

Stock Options Exercisable
Range of Exercise Price	Number of Options Exercisable		Weighted-Average Remaining Contractual Life (In Years)		Weighted-Average Exercise Price per Share		Aggregate Intrinsic Value

0.19 - 0.49		595		4.9	$	0.28	$	—
0.50 - 0.99		8,334		2.9		0.50		—
1.0 - 1.99		600		4.4		1.34		—
³2.00		5,228		3.9		2.10		—

		14,757		3.4	$	1.09	$	—

Deferred Stock-Based Compensation. The Company authorized and issued 10.1 million of non-qualified stock options not under the Plan, to employees and non-employee consultants on May 21, 2007. The options were granted at an exercise price of $0.50 per share and vest 60% at grant date and 20% per year at the one- and two-year anniversaries of the grant date. These options expire on May 21, 2012.

A summary of the activity for these options is presented below (shares in thousands):

				Weighted-
	Number of			Average
	Shares			Exercise Price

Options outstanding — September 30, 2006		—		$	—
Granted		10,145		$	0.50
Forfeited		(250	)	$	0.50
Options outstanding — September 30, 2007		9,895		$	0.50
Options exercisable — September 30, 2007		5,937		$	0.50

FF-32

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

A summary of the status and activity of non-vested awards not under the Plan for the year ended September 30, 2007 is presented below (shares in thousands):

				Weighted-
	Number of			Average
	Shares			Fair Value

Non-vested, September 30, 2006		—			—
Granted		10,145		$	0.45
Vested		(6,087	)	$	0.45
Forfeited		(100	)	$	0.01
Expired		—			—
Non-vested — September 30, 2007		3,958		$	0.21

As of September 30, 2007, there was $0.8 million of total unrecognized compensation cost related to non-vested share-based compensation arrangements granted not under the Plan. That cost is expected to be recognized over a weighted-average period of two years. The total fair value of shares vested during the year ended September 30, 2007 was $2.7 million.

Compensation Expense

Under SFAS 123(R) in 2007 and APB 25 in 2006 and 2005, pre-tax stock-based employee compensation expense of $6.7 million, $2.8 million and $0.3 million was charged to operations for the years ended September 30, 2007 and 2006 and for the period ended September 30, 2005, respectively. Under EITF 96-18, pre-tax stock-based non-employee compensation expense of $1.5 million, $6.4 million, and $0.5 million was charged to operations as compensation expense for the years ended September 30, 2007 and 2006 and for the period ended September 30, 2005, respectively.

Warrants. The following stock purchase warrants were outstanding at September 30, (warrants in thousands):

	2007		2006

Number of warrants		51,063		34,443
Exercise price	$	0.31 - $2.10	$	1.00
Expiration date		2011-2012		2011

The Company entered into financing agreements whereby the lender would receive 0.4 million warrants for each $1.0 million borrowed in addition to 4.0 million warrants for executing the agreements (see Note 8). The exercise prices of these warrants are 120% of the weighted-average share price of the traded stock for the 30 days previous to the issue date. During 2007, a total of 16.6 million warrants were issued under these arrangements with a total value based on valuation under the Black-Scholes method of $4.7 million. As of September 30, 2007, none of these warrants had been exercised.

During 2006, the Company issued 35.4 million stock purchase warrants to purchase 35.4 million shares of common stock in conjunction with the unit sale of common stock. The warrants are exercisable for a period of five years from date of issuance at an exercise price of $1.00 per share. As of September 30, 2006, 1.0 million warrants were exercised.

Note 11 —

Related Party Transactions

MAB. During the years ended September 30, 2007 and 2006 and the period ended September 30, 2005, we incurred project development costs to MAB under the Development Agreement between us and MAB (see Note 3) in the amount of $1.8 million, $4.5 million and $0.9 million, respectively, and we recorded expenditures paid by MAB

FF-33

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

on behalf of us in the amount of $2.4 million, $2.8 million and $0.2 million for the same periods. Project development costs to MAB are classified in our consolidated statements of operations as Project development costs — related party. At September 30, 2007 and 2006, we owed MAB $1.0 million and $0.2 million, respectively, related to project development costs and other expenditures that MAB made on our behalf.

During the year ended September 30, 2007, pursuant to the agreements with MAB and the $13.5 million promissory note issued thereunder (see Note 8), the Company incurred interest expense of $0.5 million and made principal payments of $1.0 million. As of September 30, 2007, the Company owed MAB principal and accrued interest of $13.0 million under the terms of the promissory note.

During the year ended September 30, 2007, the Company also entered into two separate promissory notes with the Bruner Family Trust (see Note 8) in the amounts of $0.3 million and $25,000, respectively. During 2007, we incurred total interest expense of $3,000 and paid nothing in principal payments on these notes. As of September 30, 2007, the Company owed the Bruner Family Trust principal and accrued interest of $0.3 million under the terms of these promissory notes.

On March 21, 2007, the Company entered into a partial assignment of contract and guarantee (the “Assignment”) with MAB. Pursuant to the Assignment, the Company assigned to MAB its right to purchase an undivided 45% interest in oil and gas interests in the Powder River Basin of Wyoming and Montana, which right the Company obtained in the Galaxy PSA (see Note 4). As consideration for the Assignment, MAB assumed the Company’s obligation under the Galaxy PSA to pay Galaxy $25.0 million in PetroHunter common stock. MAB also agreed to indemnify the Company against costs relating to or arising out of the termination or breach of the Galaxy PSA by Galaxy or Dolphin, and MAB agreed to guarantee the payment of principal and interest due to the Company in the event the transaction did not close.

At September 30, 2006, MAB owed us $36,000 for oil and gas revenues for our share of initial production earned through September 30, 2006 pursuant to the Development and EDA agreements with MAB. At September 30, 2007, MAB owed us nothing related to these agreements.

Galaxy. Note receivable- related party on the consolidated balance sheet at September 30, 2007 represents $2.5 million related to a $2.0 million earnest money deposit made by us under the terms of the Galaxy PSA (see Note 4) and additional operating costs of $0.5 million that we paid toward the operating costs of the assets we were to acquire plus accrued interest on amounts due to us which were all converted into the Galaxy Note on August 31, 2007. Subsequent to September 30, 2007, the entire $2.5 million has been paid to us by offset against amounts that we owed to MAB. At September 30, 2007, Galaxy owed us $0.3 million and $17,000 related to additional expenses paid by us related to the Galaxy PSA and accrued interest on the Galaxy Note, respectively. Subsequent to year-end, these amounts have also been paid by offset to amounts we owed to MAB under the MAB Note. Marc A. Bruner is the largest single beneficial shareholder of the Company, is a 14.0% beneficial shareholder of Galaxy and is the father of the President and Chief Executive Officer of Galaxy.

Due from related parties. September 30, 2006 includes $0.7 million due to the Company from Galaxy for reimbursement for charges paid to a drilling company for Galaxy’s use of a drilling rig under contract to the Company. This amount was paid to the Company subsequent to September 30, 2006.

Falcon Oil and Gas. In June 2006, the Company entered into an office sharing agreement with Falcon Oil & Gas Ltd. (“Falcon”) for office space in Denver, Colorado (the “Office Agreement”), of which Falcon is the lessee. Under the terms of the Office Agreement, Falcon and the Company share all costs related to the office space, including rent, office operating costs, furniture and equipment and any other expenses related to the operations of the corporate offices on a pro rata basis based on percentage of office space used. The largest single beneficial shareholder of the Company is also the Chief Executive Officer and a Director of Falcon. At September 30, 2007, we owed Falcon $0.5 million and at September 30, 2006, Falcon owed us $0.2 million, for costs incurred pursuant to the Office Agreement.

FF-34

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Officers. During the years ended September 30, 2007 and 2006 and the period ended September 30, 2005, the Company incurred consulting fees related to services provided by its officers in the aggregate amount of $0.3 million, $0.5 million, and $0.2 million, respectively. These fees are reflected in our statements of operations as General and administrative.

Note 12 —

Income Taxes

Income tax expense (benefit) consists of the following ($ in thousands):

	Year Ended September 30,
	2007			2006			2005

Current taxes	$	—		$	—		$	—
Deferred taxes		(17,938	)		(6,850	)		(835	)
Less: valuation allowance		17,938			6,850			835
Net income tax provision (benefit)	$	—		$	—		$	—

The effective income tax rate for the years ended September 30, 2007, 2006 and 2005 differs from the U.S. Federal statutory income tax rate due to the following:

	Year Ended September 30,
	2007			2006			2005

Federal statutory income tax rate		(35.0	)%		(35.0	)%		(35.0	)%
State income taxes, net of federal benefit		(2.97	)%		(3.25	)%		(3.25	)%
Permanent differences — disallowed interest on convertible debt		0.81	%		5.20	%		0.07	%
Increase in valuation allowance		37.16	%		33.05	%		38.18	%
Net income tax provision (benefit)		—			—			—

The components of the deferred tax assets and liabilities as of September 30, 2007 and 2006 are as follows ($ in thousands):

	September 30,
	2007			2006
Deferred tax assets:
Federal and state net operating loss carryovers	$	20,964		$	6,640
Asset retirement obligations		51			200
Stock compensation		6,769			3,830
Accrued vacation		9			—
Transfer fees		3			—
Accrued interest		2,053			—
Deferred tax asset	$	29,849		$	10,670
Deferred tax liabilities:
Oil and gas properties and property and equipment		(4,226	)		(2,985	)
Net deferred tax asset		25,623			7,685
Less: valuation allowance		(25,623	)		(7,685	)
Deferred tax liability	$	—		$	—

FF-35

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company has a $56.3 million net operating loss carryover as of September 30, 2007. The net operating losses may offset against taxable income through the year ended September 2027. A portion of the net operating loss carryovers begin expiring in 2025 and may be subject to U.S. Internal Revenue Code Section 382 limitations.

The Company has provided a valuation allowance for the deferred tax asset at September 30, 2007, as the likelihood of the realization of the tax benefit of the net operating loss carry forward cannot be determined. The valuation allowance increased by approximately $17.9 million, $6.9 million and $0.8 million for the years ended September 30, 2007 and 2006 and for the period ended 2005, respectively.

Note 13 —

Commitments and Contingencies

Environmental. Oil and gas producing activities are subject to extensive environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.

Contingencies. The Company may from time to time be involved in various claims, lawsuits, and disputes with third parties, actions involving allegations of discrimination, or breach of contract incidental to the operations of its business. We are currently a party to the following legal actions: (i) 21 vendors have filed multiple liens applicable to our properties, with 10 foreclosure actions pending at various stages of the pleadings, in connection with the liens; (ii) a law suit was filed in August 2007 by a law firm in the Supreme Court of Victoria, Australia for the balance of legal fees owed to them in the amount of 0.2 million Australian dollars, this entire amount is included in accounts payable at September 30, 2007; (iii) a law suit was filed in December 2007 by a vendor in the Supreme Court of Queensland, Australia for the balance which the vendor claims is owed by us in the amount of 2.4 million Australian dollars. Although we have accrued the entire amount of the judgment lien in Accounts payable as of September 30, 2007, this amount is disputed by us on the basis that the vendor breached the contract; and (iv) a judgment lien was filed in October 2007 by another vendor in the U.S. for the Company’s default under a settlement agreement related to the contract between the two companies. The parties are currently negotiating an amendment to the settlement agreement, which would defer any further action by the vendor as long as the Company makes further payments in accordance with the amended settlement. The total amount of the judgment lien was recorded as Notes payable — short term and Accrued interest payable at September 30, 2007.

In the event the Company does not remove the liens referenced in (i), above, by paying the lienors or otherwise settling with them, the encumbrances could have a material adverse effect on the Company’s ability to secure other vendors to perform services and/or provide goods related to the Company’s operations. In the event one or more vendors pursue the foreclosure actions referenced in (ii), above, the Company could be in jeopardy of losing assets. In the event the Company loses the lawsuit to the vendor, and does not pay the amount owed, the other vendor could obtain a judgment lien and seek to execute on the lien against the Company’s assets. In the event the Company and the other vendor do not reach agreement on the amendment to the settlement agreement, the other vendor could enforce its existing judgment lien against the Company’s assets in Colorado.

Commitments

Operating Leases. In 2006, the Company entered into lease agreements for office space in Denver, Colorado and Salt Lake City, Utah. The Salt Lake City office space was for our subsidiary, Paleo Technology which was sold to a related party effective August 31, 2007. The rental payments related to the Salt Lake City office space are included below since we have been unable to obtain consent from the landlord to allow the purchaser to assume all rights and obligations under the lease. In any event, the purchaser has agreed to indemnify us and has guaranteed performance

FF-36

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

for all of our obligations under the lease. On November 26, 2007, we entered into a lease agreement for new office space in Denver, Colorado. This lease expires in 2011.

Minimum rental payments under our various operating leases in the year indicated are as follows at September 30, 2007 ($ in thousands):

	Year Ended
	September 30,
2008	$	205
2009		312
2010		322
2011		200
2012		—

Rent expense for the years ended September 30, 2007, 2006 and 2005 was $0.2 million, $0.1 million and $2,000 respectively.

Delay Rentals. In conjunction with the Company’s working interests in undeveloped oil and gas prospects, the Company must pay approximately $0.1 million in delay rentals during the fiscal year ending September 30, 2008 to maintain the right to explore these prospects. The Company continually evaluates its leasehold interests, therefore certain leases may be abandoned by the Company in the normal course of business.

Work Commitments. See Note 4 for commitments related to the drilling of specific wells.

Note 14 —

Subsequent Events

(a) On November 6, 2007 (effective October 1, 2007), we closed the sale of our heavy oil assets to Pearl Exploration and Production Ltd. (“Pearl”). Pearl’s stock is traded on the TSX Venture Exchange. The assets sold, located in Montana and Utah, included our working interests in oil and gas leases related to our heavy oil development projects that we referred to as Fiddler Creek and Promised Land (in Montana), and West Rozel and Gunnison Wedge (in Utah) (the “Pearl Transaction”) (see Note 4).

(b) On November 13, 2007, we completed the sale of Series A 8.5% Convertible Debentures in the aggregate principal amount of $7.0 million to several accredited investors.

Debenture holders also received five-year warrants that allow them to purchase a total of 46.4 million shares of common stock at prices ranging from $0.24 to $0.27 per share. Repayment of the debentures is collateralized by shares in our Australian subsidiary. In connection with the placement of the debentures, we paid a placement fee of $0.3 million and issued placement agent warrants entitling the holders to purchase an aggregate of 0.2 million shares at $0.35 per share for a period of five years.

We have agreed to file a registration statement with the Securities and Exchange Commission in order to register the resale of the shares issuable upon conversion of the debentures and the shares issuable upon exercise of the warrants.

According to the Registration Rights Agreement, the registration statement must be filed by March 4, 2008 and it must be declared effective by July 2, 2008. The following penalties apply if filing deadlines and/or documentation requirements are not met in compliance with the stated rules: (i) the Company shall pay to each holder of Registrable Securities 1% of the purchase price paid in cash as partial liquidated damages; (ii) the maximum aggregate liquidated damages payable is 18% of the aggregate subscription amount paid by the holder; (iii) if the Company fails to pay liquidated damages in full within 7 days of the date payable, the Company will pay interest of 18% per annum, accruing daily from the original due date; (iv) partial liquated damages apply on a daily prorated basis for any portion of a month prior to the cure of an event; and (v) all fees and expenses associated with

FF-37

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

compliance to the agreement shall be incurred by the Company. We believe that these requirements will be met and therefore have accrued no liabilities related to such penalties.

The debentures have a maturity date of five years and are convertible at any time by the holders into shares of our common stock at a price of $0.15 per share. Interest accrues at an annual rate of 8.5% and is payable in cash or in shares (at our option) quarterly, beginning January 1, 2008.

Provided that there is an effective registration statement covering the shares underlying the debentures and the volume-weighted-average price of our common stock over 20 consecutive trading days is at least 200% of the per share conversion price, with a minimum average trading volume of 0.3 million shares per day: (i) The debentures are convertible, at our option and (ii) are redeemable at our option at 120% of face value at any time after one year from date of issuance.

(c) On November 15, 2007 and December 31, 2007 we entered into the Second Amendment and Third Amendment with MAB (see Note 3).

(d) In November of 2007, Charles Crowell, Chairman and CEO of the Company, was assigned the right to receive from the Company approximately $0.2 million of the $0.3 million owed by the Company under a promissory note to the Bruner Family Trust. Mr. Crowell received this right from the Bruner Family Trust in exchange for a promissory note in the same amount which had been issued to Mr. Crowell by Galaxy for services rendered to Galaxy prior to Mr. Crowell becoming an officer of the Company.

Subsequently, Mr. Crowell participated in the Company’s private placement in November 2007 to the extent of $0.2 million and in exchange for cancellation of $0.2 million of the total amount owed to him by the Company. The balance of the amount owed to him under the note, $18,000, was then paid in cash.

(e) On December 10, 2007 and effective October 1, 2007, we completed the transaction to acquire the following interests from a third party (the “Seller”): (i) an oil and gas lease covering 99 net acres of lands comprised of the Section under which we own a lease covering the remaining 50% of the mineral interest in the section; (ii) an oil and gas lease covering 20 net acres of lands; (iii) an assignment of an oil and gas lease covering the remaining 20 net acres under the same parcel; and (iv) assignment of any and all interests which the assignor may have had in certain wells already drilled and completed by us (50% of 10 wells and 100% of two wells).

In consideration for execution and assignment of the leases, we paid to the assignor: (i) our interests in leases covering 40 net acres; (ii) our working interests in the 19 wells operated by the assignor (ranging from 1% to 11% working interest); and (c) a cash payment in the amount of $1.0 million dollars.

We paid 100% of the costs to drill and complete 12 wells when our working interest in them ranged from zero to 50%. At September 30, 2007, the costs we paid for the 12 wells on behalf of the other 50% joint interest owner, who is also the Seller, were classified on our consolidated balance sheet as Joint interest billings in the amount of $12.6 million. These costs were reclassified to oil and gas properties in the first quarter of 2008.

(f) On December 18, 2007, the Company obtained a loan in the amount of $0.8 million from a third party oil and gas company which had previously participated in the financing discussed in Note 8 above. The loan is collateralized by 947,153 Pearl shares, accrues interest at the rate of 15% and matures on January 18, 2008.

(g) On December 31, 2007, we entered into the Third Amendment with MAB, which reduced the $2.0 million note to MAB (the “Note”) to a balance of $1.5 million, in satisfaction of MAB’s obligation to pay us, as guarantor under a separate promissory note of Galaxy (see Note 11), and in connection with MAB’s assumption of certain obligations owed to us by Paleo. All other terms of the Note remain as described in Note 8 above.

FF-38

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(h) Subsequent to September 30, 2007, the Company granted 2.4 million options under its 2005 stock option plan to directors, employees and consultants performing employee-like services to the Company.

Note 15 —

Disclosures about Oil and Gas Producing Activities

Costs Incurred in Oil and Gas Producing Activities. Costs incurred in oil and gas property acquisition, exploration and development activities are summarized as follows ($ in thousands):

	Year Ended September 30,
	2007		2006		2005

Development	$	9,654	$	—	$	—
Exploration		28,952		13,184		165
Acquisitions:
Proved		3,948		—		—
Unproved		99,409		25,076		7,066
Total	$	141,963	$	38,260	$	7,231
Capitalized costs associated with asset retirement obligation	$	30	$	520	$	—

Oil and Gas Reserve Quantities (Unaudited). For all years presented, Gustavson Associates (“Gustavson”) prepared the reserve information for the Company’s properties located in the Piceance Basin of western Colorado, and for the properties located in the Fiddler Creek Heavy Oil Project located in Montana. The Fiddler Creek Heavy Oil Project was sold effective October 1, 2007 (see Notes 4 and 14).

The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as additional information becomes available.

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. All of the Company’s proved reserves are located in the continental United States.

FF-39

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Presented below is a summary of the changes in estimated reserves of the Company:

	Year Ended September 30,
	2007						2006					2005
	Oil or						Oil or					Oil or
	Condensate			Gas			Condensate		Gas			Condensate		Gas
	(Bbl)			(Mcf)			(Bbl)		(Mcf)			(Bbl)		(Mcf)

Developed and undeveloped:
Beginning of year		—			—			—		—			—		—
Extensions and discoveries		131,174			10,820,228			—		—			—		—
Purchases of minerals in place		—			3,335,933			—		—			—		—
Production		(137	)		(456,740	)		—		(5,822	)		—		—
Revisions to previous estimates		—			—			—		5,822			—		—
End of year		131,037			13,699,421			—		—			—		—
Proved developed reserves:
Beginning of year		—			—			—		—			—		—
End of year		8,873			13,699,421			—		—			—		—

Standardized Measure of Discounted Future Net Cash Flows (Unaudited). SFAS 69, Disclosures about Oil and Gas Producing Activities (“SFAS 69”) prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Company has followed these guidelines, which are briefly described below.

Future cash inflows and future production and development costs are determined by applying benchmark prices and costs, including transportation, quality, and basis differentials, in effect at year-end to the year-end estimated quantities of oil and gas to be produced in the future. Each property we operate is also charged with field-level overhead in the estimated reserve calculation. Estimated future income taxes are computed using current statutory income tax rates, including consideration for estimated future statutory depletion. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor.

Future operating costs are determined based on estimates of expenditures to be incurred in developing and producing the proved oil and gas reserves in place at the end of the period, using year-end costs and assuming continuation of existing economic conditions.

The assumptions used to compute the standardized measure are those prescribed by the FASB and the Securities and Exchange Commission. These assumptions do not necessarily reflect our expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates are the basis for the valuation process. The following prices, as adjusted for transportation, quality, and basis differentials, were used in the calculation of the standardized measure:

	As of September 30,
	2007		2006		2005

Gas (per Mcf)	$	4.80	$	—	$	—
Oil (per Bbl)	$	62.61	$	—	$	—

FF-40

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following summary sets forth the Company’s future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed by SFAS 69 ($ in thousands):

	As of September 30,
	2007			2006		2005

Future cash inflows	$	73,998		$	—	$	—
Future production costs		(18,394	)		—		—
Future development costs		(10,648	)		—		—
Future net cash flows		44,956			—		—
10% annual discount		(25,091	)		—		—
Standardized measure of discounted future net cash flows	$	19,865		$	—	$	—

The primary sources of change in the standardized measure of discounted future net cash flows are ($ in thousands):

	Year Ended September 30,
	2007			2006		2005

Standardized measure, beginning of year	$	—		$	—	$	—
Sales of oil and gas produced, net of production costs		(2,027	)		—		—
Extensions and discoveries, net of production costs		17,266			—		—
Purchases of minerals in place		4,626			—		—
Standardized measure, end of year	$	19,865		$	—	$	—

Note 16 —

Quarterly Financial Information (Unaudited)

Our consolidated results of operations, by quarter, for the years ended September 30, 2007 and 2006 were as follows ($ in thousands, except per share amounts):

	Restated			Restated			Restated
2007	First			Second			Third			Fourth

Total operating revenues	$	449		$	989		$	847		$	535
Operating loss		(10,736	)		(8,267	)		(6,239	)		(17,919	)
Net loss		(10,555	)		(10,265	)		(7,079	)		(21,912	)
Basic and diluted net loss per common share	$	(0.05	)	$	(0.05	)	$	(0.03	)	$	(0.11	)

2006	First			Second			Third			Fourth

Total operating revenues	$	—		$	—		$	—		$	36
Operating loss	$	(1,411	)	$	(1,978	)	$	(3,180	)	$	(11,640	)
Net loss	$	(1,599	)	$	(2,477	)	$	(4,475	)	$	(12,141	)
Basic and diluted net loss per common share	$	(0.02	)	$	(0.02	)	$	(0.03	)	$	(0.07	)

During our year-end procedures, we found certain adjustments relating to previous quarters; as a result, the first, second and third quarter 2007 figures have been restated in the table above from what was previously issued in our Quarterly Reports on Forms 10Q filed with the SEC.

FF-41

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

	As Reported			As Reported			As Reported
As Reported 2007	First			Second			Third

Total operating revenues	$	449		$	889		$	847
Operating loss	$	(5,836	)	$	(3,867	)	$	(5,139	)
Net loss	$	(5,855	)	$	(5,865	)	$	(6,679	)
Basic and diluted net loss per common share	$	(0.03	)	$	(0.03	)	$	(0.03	)

Statements of Operations Restatements. During the fourth quarter ended September 30, 2007, the Company’s proved reserves were estimated by an independent reservoir engineer. The Company estimated that, had those reserves been obtained during previous quarters, depreciation, depletion and amortization would have increased by approximately $0.3, $0.7 and $0.5 million during the first, second and third quarters ended December 31, 2006, March 31, 2007 and June 30, 2007, respectively. The effect of the above did not have an impact on the Company’s net loss for the year ended September 30, 2007 as such adjustments would ultimately be reflected in impairment of oil and gas properties in the consolidated statements of operations.

During the fourth quarter ended September 30, 2007, the Company reflected $24.1 million of impairment of oil and gas properties. Impairment by country was $23.5 in the United States, $0.1 in China and $0.5 in Africa, and resulted from the full cost pool exceeding the limitation as prescribed by Regulation S-X, Article 4-10. The Company estimated that, should they have obtained estimates of proved reserves during previous quarters, impairment of oil and gas properties would have increased by approximately $4.6, $3.7 and $0.6 million during the first, second and third quarters ended December 31, 2006, March 31, 2007 and June 30, 2007, respectively. The effect of the above did not have an impact on the Company’s net loss for the year ended September 30, 2007 as such adjustments would have ultimately reduced, by a corresponding amount, impairment of oil and gas properties recorded during the fourth quarter ended September 30, 2007.

The Company determined that it did not properly calculate and record capitalized interest in its previously filed Quarterly Reports on Form 10-Q. The Company estimated that, if such amount had been properly calculated, capitalized interest amounts recorded in oil and gas properties would have increased by $0.2 during the first quarter ended December 31, 2006, not changed during the second quarter ended March 31, 2007, and decreased by $0.7 million during the third quarter ended June 30, 2007, with a corresponding change to interest expense reflected in the consolidated statements of operations. The effect of the above did not have an impact on the Company’s net loss for the year ended September 30, 2007 as such adjustments would have ultimately changed, by a corresponding amount, capitalized interest and interest expense recorded during the fourth quarter ended September 30, 2007.

The Company determined that it did not properly accrued revenue associated with certain operating wells. As a result, for the second quarter ended June 30, 2007, revenue was understated by approximately $0.1 million. The effect of the above did not have an impact on the Company’s net loss for the year ended September 30, 2007 as such amounts were recorded in the fourth quarter 2007.

Balance Sheet Restatements. The Company determined that it did not properly accrue accounts payable related to its drilling operations in Australia and Colorado. As a result, Accounts payable and accrued expenses and Oil and gas properties were understated by $3.8 million at June 30, 2007. The other quarters in 2007 were not impacted.

The Company determined that it did not properly classify a note payable to a vendor in the second quarter of 2007. The note, in the amount of $6.5 million was entered into during June 2007 as a result of unpaid vendor invoices, all of which were included in Accounts payable and accrued expenses at June 30, 2007. As a result, Accounts payable and accrued expenses were overstated and Notes payable — short-term were understated by $6.5 million at June 30, 2007. Interest on the loan was not accrued but was negligible for the period.

FF-42

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company determined that it did not properly account for an amendment to a credit facility agreement whereby the Company failed to record the value of additional warrants issued and deferred financing fees related to the borrowings under the facility. As a result, Notes payable — net of discount was overstated, Additional paid-in-capital was understated by $0.6 million, and Deferred financing costs and Accounts payable and accrued expenses were understated by $0.2 million as of June 30, 2007.

The Company determined that it did not properly classify a note payable in its consolidated balance sheet in the second quarter of 2007. The total amount of the note was included in Accounts payable and accrued expenses. As a result, Accounts payable and accrued expenses were overstated and Notes payable — short-term were understated by $0.2 million as of June 30, 2007.

As a result of not properly accruing revenue as discussed under Statements of Operations Restatements above, Oil and gas receivables — net is also understated by $0.1 million as of June 30, 2007.

FF-43

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution

The expenses to be paid by the registrant in connection with the securities being registered are as follows (stated in US dollars):

Securities and Exchange Commission filing fee $ 2,001

Accounting fees and expenses

Blue sky fees and expenses

Legal fees and expenses

Transfer agent fees and expenses

Printing expenses

Miscellaneous expenses

Total $

All amounts are estimates except the SEC filing fee. The Selling Stockholders will be bearing the cost of its own brokerage fees and commissions and its own legal and accounting fees.

Item 14. Indemnification of Directors and Officers

Our Articles of Incorporation provide for the indemnification of all directors, officers, employees and agents of the Company to the fullest extent permitted by Section 2-418 of the Maryland Code, as the same may be amended and supplemented, unless it is established that (i) the act or omission was material to the matter giving rise to the liability and was omitted in bad faith or was the result of active and deliberate dishonesty, (ii) the person actually received an improper personal benefit in money, property or services, or (iii) in the case of a criminal proceeding, the person had reasonable cause to believe the act or omission was unlawful. The rights to indemnification and advancement of expenses provided by our Articles are not exclusive of any other rights to which those indemnified may be entitled under the Articles, any bylaw, agreement, vote of stockholders or disinterested directors or otherwise, both as to action in such persons’ official capacity and as to action in another capacity while holding such directorship, office, employment or agency, and continue as to a person who has ceased to be a director, officer, employee or agent and shall inure to the benefit of the heirs, executors and administrators of such a person.

Section 2-418 of the Maryland General Corporation Law requires that the determination that indemnification is proper in a specific case must be made by (a) the stockholders, (b) the board of directors by majority vote of a quorum consisting of directors who were not parties to the action, suit or proceeding or (c) independent legal counsel in a written opinion (i) if a majority vote of a quorum consisting of disinterested directors is not possible or (ii) if such an opinion is requested by a quorum consisting of disinterested directors.

Insofar as indemnification for liabilities arising under the Securities Act of 1933, as amended (the “Securities Act”) may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, we have been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable.

Item 15. Recent Sales of Unregistered Securities.

Within the past three years, the registrant has issued and sold the unregistered securities set forth in the tables below.

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Date	Persons or Class of Persons	Securities	Consideration	Underwriters	Exemption Claimed
May 2006	Shareholders of GSL Energy Corporation	185,176,650 shares of common stock	Shares of GSL Energy Corporation	Not used	Section 4(2) and Rule 506
May 2006	60 Shareholders of GSL Energy Corporation	35,442,500 warrants to purchase common stock	35,442,500 warrants to purchase common stock of GSL Energy Corporation	Not used	Rule 506 and Regulation S
September 2006	22 accredited investors and non-US persons	5,173,334 shares of common stock	$2,586,667 cash		Rule 506 and Regulation S
September 2006	1 non-US person	1,000,000 shares of common stock	$1,000,000 cash (exercise of warrant)	Not used	Regulation S
January 2007	MAB Resources LLC	50,000,000 shares of common stock	Working interest in oil and gas properties valued at $81,000,000	Not used	Section 4(2)
January 2007 through December 2007	Maralex Resources, Inc., Adelante Oil & Gas, LLC and James B. Fullerton	9,856,000 shares of common stock, which includes 8,000,000 shares later returned for cancellation	Oil and gas properties	Not used	Section 492)
January 2007 through December 2007	Global Project Finance	Warrants to purchase 17,120,000 shares of common stock	Advances on credit facility	Not used	Regulation S
May 2007	Robert L. Bayless Producer LLC	642,857 shares of common stock	Finance costs on property valued at $450,000	Not used	Section 4(2)

II-2

Date

Persons or Class of Persons

Securities

Consideration

Underwriters

Exemption Claimed

October 2007	MAB Resources LLC	25,000,000 shares of common stock	Relinquishment of overriding royalty interest in Utah and Montana properties and relinquishment of rights to Performance Shares valued at $7,750,000	Not used	Section 4(2)
October 2007	Savannah Exploration, Inc. and American Oil & Gas, Inc. and their 8 designees	5,000,000 shares of common stock	Termination of registrant’s obligation to pay overriding royalty and production payment on Heavy Oil properties valued at $1,250,000	Not used	Section 4(2)
October 2007	CCES Piceance Partners I, LLC	200,000 shares of common stock	Financing costs of gas production facilities valued at $56,000	Not used	Section 4(2)
November 2007	19 accredited investors and non-US persons	Convertible debentures and warrants to purchase 46,375,913 shares of common stock	$6,956,387 cash	Cash commissions of $258,000 were paid	Rule 506 and Regulation S
November 2007	MAB Resources LLC	16,000,000 shares of common stock and warrants to purchase 32,000,000 shares of common stock	$8,000,000 reduction in principal amount of note payable	Not used	Section 4(2)
May 2008	CCES Piceance Partners II, LLC	400,000 shares of common stock	Financing costs of gas production facilities valued at $96,000	Not used	Section 4(2)

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Date

Persons or Class of Persons

Securities

Consideration

Underwriters

Exemption Claimed

May 2008	19 accredited investors and non-US persons	Warrants to purchase 1,855,037 shares of common stock	Late fee pertaining to interest payments on convertible debentures	Not used	Rule 506 and Regulation S
June 2008	18 accredited investors – creditors	18,917,109 shares of common stock	$3,742,662 debt reduction	Not used	Rule 506

Item 16. Exhibits and Financial Statement Schedules

Regulation S-K Number	Exhibit
2.1	Stock Exchange Agreement dated February 10, 2006 by and among Digital Ecosystems Corp., GSL Energy Corporation, MABio Materials Corporation and MAB Resources LLC (incorporated by reference to Exhibit 10.8 to the registrant’s quarterly report on Form 10-QSB for the quarter ended December 31, 2005, filed February 16, 2006)
2.2	Amendment No. 1 to Stock Exchange Agreement dated March 31, 2006 (incorporated by reference from Exhibit 10.1 to the registrant’s current report on Form 8-K dated March 31, 2006, filed April 7, 2006)
2.3	Amendment No. 5 to Stock Exchange Agreement dated May 12, 2006 (incorporated by reference from Exhibit 10.1 to the registrant’s current report on Form 8-K dated May 12, 2006, filed May 15, 2006)
2.4	Purchase and Sale Agreement dated December 29, 2006 between Dolphin Energy Corporation and Galaxy Energy Corporation and PetroHunter Operating Company and PetroHunter Energy Corporation (incorporated by reference to Exhibit 2.1 to the registrant’s current report on Form 8-K dated December 29, 2006, filed January 4, 2007)
2.5	Second Amendment to Purchase and Sale Agreement dated February 28, 2007 (incorporated by reference to Exhibit 2.2 to the Registrant’s amended current report on Form 8-K dated December 29, 2006, filed March 2, 2007)
2.6	Partial Assignment of Contract and Guarantee between PetroHunter Energy Corporation, PetroHunter Operating Company and MAB Resources LLC, dated March 21, 2007 (incorporated by reference to Exhibit 2.1 to the Registrant’s current report on Form 8-K dated March 21, 2007, filed March 22, 2007)
2.7	Third Amendment to Purchase and Sale Agreement dated March 30, 2007 (incorporated by reference to Exhibit 2.3 to the Registrant’s amended current report on Form 8-K dated December 29, 2006, filed April 2, 2007)
2.8	Fourth Amendment to Purchase and Sale Agreement dated April 30, 2007 (incorporated by reference to Exhibit 2.4 to the Registrant’s amended current report on Form 8-K dated December 29, 2006, filed May 1, 2007)

II-4

Regulation

S-K Number

Exhibit

2.9	Fifth Amendment to Purchase and Sale Agreement dated May 31, 2007 (incorporated by reference to Exhibit 2.5 to the Registrant’s amended current report on Form 8-K dated December 29, 2006, filed June 1, 2007)
2.10	Sixth Amendment to Purchase and Sale Agreement dated June 30, 2007 (incorporated by reference to Exhibit 2.6 to the Registrant’s amended current report on Form 8-K dated December 29, 2006, filed July 2, 2007)
2.11	Seventh Amendment to Purchase and Sale Agreement dated July 31, 2007 (incorporated by reference to Exhibit 2.7 to the Registrant’s amended current report on Form 8-K dated December 29, 2006, filed August 2, 2007)
3.1	Articles of Incorporation (incorporated by reference to Exhibit A to the Information Statement filed July 17, 2006)
3.2	Bylaws (incorporated by reference to Exhibit B to the Information Statement filed July 17, 2006)
5.1	Opinion of Dill Dill Carr Stonbraker & Hutchings, P.C. (to be filed by amendment)
10.1	Business Consultant Agreement dated October 1, 2005 (incorporated by reference to Exhibit 10.1 to the Registrant’s current report on Form 8-K dated October 1, 2005, filed October 28, 2005)
10.2	Marketing Management Contract dated October 15, 2005 (incorporated by reference to Exhibit 10.1 to the Registrant’s current report on Form 8-K dated October 1, 2005, filed October 28, 2005)
10.3	Loan Agreement with Carnavon Trust Reg. Dated for reference October 11, 2005 (incorporated by reference to Exhibit 10.3 to the Registrant’s quarterly report on Form 10-QSB for the quarter ended September 30, 2005, filed November 21, 2005)
10.4	Loan Agreement with Carnavon Trust Reg. Dated for reference December 5, 2005 (incorporated by reference to Exhibit 10.6 to the Registrant’s quarterly report on Form 10-QSB for the quarter ended December 31, 2005, filed February 16, 2006)
10.5	Loan Agreement with Carnavon Trust Reg. Dated for reference February 2, 2006 (incorporated by reference to Exhibit 10.7 to the Registrant’s quarterly report on Form 10-QSB for the quarter ended December 31, 2005, filed February 16, 2006)
10.6	2005 Stock Option Plan (incorporated by reference from Exhibit 4.1 to the Registrant’s annual report Form 10-KSB for the fiscal year ending March 31, 2006, filed on July 14, 2006)
10.7	Management and Development Agreement Between MAB Resources LLC and GSL Energy Corporation (Amended and Restated) Effective July 1, 2005 (incorporated by reference from Exhibit 10.4 to the Registrant’s annual report Form 10-KSB for the fiscal year ending March 31, 2006, filed on July 14, 2006)
10.8	Acquisition and Consulting Agreement between MAB Resources LLC and PetroHunter Energy Corporation Effective January 1, 2007 (incorporated by reference to Exhibit 10.1 to the Registrant’s amended current report on Form 8-K dated January 9, 2007, filed May 4, 2007)

II-5

Regulation

S-K Number

Exhibit

10.9	Credit and Security Agreement dated as of January 9, 2007 between PetroHunter Energy Corporation and PetroHunter Operating Company and Global Project Finance AG (incorporated by reference to Exhibit 10.2 to the Registrant’s current report on Form 8-K dated January 9, 2007, filed January 11, 2007)
10.10	Credit and Security Agreement dated as of May 21, 2007 between PetroHunter Energy Corporation and PetroHunter Operating Company and Global Project Finance AG (incorporated by reference to Exhibit 10.1 to the Registrant’s current report on Form 8-K dated May 21, 2007, filed May 22, 2007)
10.11	Subordinated Unsecured Promissory Note dated July 31, 2007 to Bruner Family Trust UTD March 28, 2005 (incorporated by reference to Exhibit 10.1 to the Registrant’s current report on Form 8-K dated July 31, 2007, filed August 1, 2007)
10.12	Subordinated Unsecured Promissory Note dated September 21, 2007 to Bruner Family Trust UTD March 28, 2005 (incorporated by reference to Exhibit 10.1 to the Registrant’s current report on Form 8-K dated September 21, 2007, filed September 27, 2007)
10.13	First Amendment to Acquisition and Consulting Agreement between MAB Resources LLC and PetroHunter Energy Corporation dated October 18, 2007 (incorporated by reference to Exhibit 10.1 to the Registrant’s current report on Form 8-K dated October 17, 2007, filed October 23, 2007)
10.14	Lori Rappucci Employment Agreement (incorporated by reference to Exhibit 10.2 to the Registrant’s current report on Form 8-K dated October 17, 2007, filed October 23, 2007)
10.15	Purchase and Sale Agreement between PetroHunter Heavy Oil Ltd. and Pearl Exploration and Production Ltd. Effective October 1, 2007 (incorporated by reference to Exhibit 10.1 to the Registrant’s current report on Form 8-K dated November 6, 2007, filed November 7, 2007)
10.16	Securities Purchase Agreement (incorporated by reference to Exhibit 10.1 to the Registrant’s current report on Form 8-K dated November 13, 2007, filed November 15, 2007)
10.17	Form of Debenture (incorporated by reference to Exhibit 10.2 to the Registrant’s current report on Form 8-K dated November 13, 2007, filed November 15, 2007)
10.18	Registration Rights Agreement (incorporated by reference to Exhibit 10.3 to the Registrant’s current report on Form 8-K dated November 13, 2007, filed November 15, 2007)
10.19	Form of Warrant (incorporated by reference to Exhibit 10.4 to the Registrant’s current report on Form 8-K dated November 13, 2007, filed November 15, 2007)
10.20	Collateral Pledge and Security Agreement (incorporated by reference to Exhibit 10.5 to the Registrant’s current report on Form 8-K dated November 13, 2007, filed November 15, 2007)
10.21	Second Amendment to Acquisition and Consulting Agreement between MAB Resources LLC and PetroHunter Energy Corporation dated November 15, 2007 (incorporated by reference to Exhibit 10.1 to the Registrant’s current report on Form 8-K dated November 15, 2007, filed November 16, 2007)
10.22	Charles B. Crowell Employment Agreement (incorporated by reference to Exhibit 10.1 to the Registrant’s current report on Form 8-K dated December 31, 2007, filed January 10, 2008
10.23	Third Amendment to Acquisition and Consulting Agreement between MAB Resources LLC and PetroHunter Energy Corporation (incorporated by reference to Exhibit 10.23 to the Registrant’s annual report on Form 10-K for the fiscal year ended September 30, 2007, filed January 15, 2008)
10.24	Promissory Note dated February 12, 2008 to Bruner Family Trust UTD March 28, 2005 (incorporated by reference to Exhibit 10.1 to the Registrant’s current report on Form 8-K dated February 12, 2008, filed February 19, 2008)

II-6

Regulation

S-K Number

Exhibit

10.25	Promissory Note dated March 14, 2008 to Bruner Family Trust UTD March 28, 2005 (incorporated by reference to Exhibit 10.1 to the Registrant’s current report on Form 8-K dated March 14, 2008, filed March 17, 2008)
10.26	Promissory Note dated March 18, 2008 to Bruner Family Trust UTD March 28, 2005 (incorporated by reference to Exhibit 10.1 to the Registrant’s current report on Form 8-K dated March 18, 2008, filed March 24, 2008)
10.27	Purchase and Sale Agreement between PetroHunter Energy Corporation and PetroHunter Operating Company as Seller and Laramie Energy II, LLC as Buyer Dated Effective April 1, 2008 (incorporated by reference to Exhibit 10.1 to the Registrant’s current report on Form 8-K dated May 30, 2008, filed June 5, 2008)
10.28	Amendment to Purchase and Sale Agreement between PetroHunter Energy Corporation and PetroHunter Operating Company as Seller and Laramie Energy II, LLC as Buyer Dated May 23, 2008 (incorporated by reference to Exhibit 10.2 to the Registrant’s current report on Form 8-K dated May 30, 2008, filed June 5, 2008)
16.1	Letter from Telford Sadovnick, P.L.L.C. (incorporated by reference to Exhibit 16.1 to the Registrant’s amended current report on Form 8-K dated August 21, 2006, filed September 8, 2006)
16.2	Letter from Hein & Associates LLP (incorporated by reference to Exhibit 16.1 to the registrant’s current report on Form 8-K dated January 29, 2008, filed February 4, 2008)
21	Subsidiaries of the registrant (incorporated by reference to Exhibit 10.23 to the Registrant’s annual report on Form 10-K for the fiscal year ended September 30, 2007, filed January 15, 2008)
23.1	Consent of Dill Dill Carr Stonbraker & Hutchings, P.C. (incorporated in Exhibit 5.1)
23.2	Consent of Hein & Associates, LLP
24	Power of Attorney. Reference is made to the signature page of this registration statement

Item 28. Undertakings

Insofar as indemnification for liabilities arising under the Securities Act of 1933, as amended (the “Act”) may be permitted to directors, officers and controlling persons of the issuer pursuant to the foregoing provisions, or otherwise, the issuer has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable.

In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer or controlling person of the issuer in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the issuer will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes:

1. To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

II-7

i. To include any prospectus required by section 10(a)(3) of the Securities Act of 1933;

ii. To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than 20% change in the maximum aggregate offering price set forth in the "Calculation of Registration Fee" table in the effective registration statement.

iii. To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement;

2. That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

3. To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

4. That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser, if the registrant is subject to Rule 430C, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

II-8

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Denver, State of Colorado, on June 30, 2008.

	PETROHUNTER ENERGY CORPORATION

	By:	/s/ Charles B. Crowell
		Charles B. Crowell, Chief Executive Officer

KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Charles B. Crowell his true and lawful attorney-in-fact and agent, with full power of substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Form S-1 registration statement, and to file the same with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorney-in-fact and agent full power and authority to do and perform each and every act and thing requisite and ratifying and confirming all that said attorney-in-fact and agent or his substitute or substitutes may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, this registration statement was signed by the following persons in the capacities and on the dates indicated:

Signature	Title	Date

/s/ Charles B. Crowell	Chariman and Chief Executive Officer (Principal Executive Officer)	June 30, 2008
Charles B. Crowell

/s/ Charles A. Josenhans	Interim Chief Financial Officer (Principal Financial Officer)	June 30, 2008
Charles A. Josenhans

/s/ Robert Perlman	Controller (Principal Accounting Officer)	June 30, 2008
Robert Perlman

/s/ Carmen J. Lotito	Director	June 30, 2008
Carmen J. Lotito

/s/ Martin B. Oring	Director	June 30, 2008
Martin B. Oring

/s/ Matthew R. Silverman	Director	June 30, 2008
Matthew R. Silverman


/s/ Anthony K. Yeats	Director	June 30, 2008
Anthony K. Yeats

II-9