Edgar Filing: PetroHunter Energy Corp

Filed by Bowne Pure Compliance

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended December 31, 2007


o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____ to _____

Commission file number: 000-51152

PETROHUNTER ENERGY CORPORATION

(Exact name of registrant as specified in its charter)


Maryland		98-0431245
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)


1600 Stout Street		80202
Suite 2000, Denver, Colorado		(Zip Code)
(Address of principal executive offices)

Registrant’s telephone number, including area code:
(303) 572-8900

Registrant’s former address:
1875 Lawrence Street,
Suite 1400, Denver, Colorado 80202

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o Accelerated filer o Non-accelerated filer þ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

As of January 31, 2008, the registrant had 318,748,841 shares of common stock outstanding.

FORWARD-LOOKING STATEMENTS

Certain statements contained in this Quarterly Report 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. Such risks and uncertainties include those set forth under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Quarterly Report. We do not intend to update the forward-looking information to reflect actual results or changes in the factors affecting such forward-looking information. We advise you to carefully review the reports and documents we file from time to time with the Securities and Exchange Commission (the “SEC”).

All subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements. We assume no duty to update or revise our forward-looking statements based on changes in internal estimates or expectations or otherwise.

CURRENCIES

All amounts expressed herein are in U.S. dollars unless otherwise indicated.

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 the depth of a stratigraphic horizon 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.

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 with the drill bit.

3-D Seismic. The method by which a three-dimensional image of the earth’s subsurface is created through the interpretation of reflection 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.

PETROHUNTER ENERGY CORPORATION

FORM 10-Q

FOR THE THREE-MONTH PERIOD ENDED
DECEMBER 31, 2007

INDEX


		Page
	PART I — FINANCIAL INFORMATION
Item 1.	Financial Statements		6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations		30
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		38
Item 4.	Controls and Procedures		38

	PART II — OTHER INFORMATION
Item 1.	Legal Proceedings		39
Item 1A.	Risk Factors		39
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		40
Item 3.	Defaults Upon Senior Securities		40
Item 4.	Submission of Matters to a Vote of Security Holders		40
Item 5.	Other Information		40
Item 6.	Exhibits		40
	Signatures		40

Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

PART I. FINANCIAL INFORMATION
PETROHUNTER ENERGY CORPORATION
(A Development Stage Company)
CONSOLIDATED BALANCE SHEETS


	December 31,			September 30,
	2007			2007
	(unaudited)
	( $ in thousands)
ASSETS
Current Assets
Cash and cash equivalents	$	462		$	120
Receivables
Oil and gas receivables, net		86			487
Other receivables		7			59
Due from related parties		—			500
Note receivable — related party		—			2,494
Prepaid expenses and other assets		326			187
Marketable securities, trading		6,619			—

Total Current Assets		7,500			3,847

Property and Equipment, at cost
Oil and gas properties under full cost method, net		166,764			162,843
Furniture and equipment, net		538			569

		167,302			163,412

Other Assets
Joint interest billings		1,029			13,637
Restricted cash		599			599
Deposits and other assets		90			—
Deferred financing costs		847			529

Total Assets	$	177,367		$	182,024

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Notes payable — short-term	$	1,440		$	4,667
Convertible notes payable		400			400
Accounts payable and accrued expenses		22,995			26,631
Note payable — related party — current portion		—			3,755
Note payable — current portion of long term liabilities		120			120
Accrued interest payable		3,821			2,399
Accrued interest payable — related party		606			516
Due to shareholder and related parties		1,132			1,474
Contract payable — oil and gas properties		—			1,750

Total Current Liabilities		30,514			41,712


Non-Current Obligations
Notes payable — net of discount and current portion		30,088			27,944
Subordinated notes payable — related parties		3,392			9,050
Convertible notes payable — net of discount		2,954			—
Asset retirement obligation		104			136

Net Non-Current Obligations		36,538			37,130


Total Liabilities		67,052			78,842


Common Stock Subscribed		—			2,858

Commitments and Contingencies (Note 12)
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 issued and outstanding — 318,748,841 and 278,948,841 shares		319			279
Additional paid-in-capital		192,050			172,672
Other comprehensive loss		(16	)		(5	)
Deficit accumulated during the development stage		(82,038	)		(72,622	)

Total Stockholders’ Equity		110,315			100,324

Total Liabilities and Stockholders’ Equity	$	177,367		$	182,024

See accompanying notes to consolidated financial statements.

PETROHUNTER ENERGY CORPORATION
(A Development Stage Company)
CONSOLIDATED STATEMENTS OF OPERATIONS


	Three-Months			Three-Months Ended			Cumulative
	Ended			December 31,			From Inception
	December 31,			2006			(June 20, 2005) to
	2007			(restated)			December 31, 2007
	(unaudited, $ in thousands, except per share amounts)
Revenues
Oil and gas revenues	$	287		$	449		$	3,143

Costs and Expenses
Lease operating expenses		100			162			897
General and administrative		1,894			3,671			34,843
Project development costs — related party		—			1,815			7,205
Impairment of oil and gas properties		—			5,151			24,053
Depreciation, depletion, amortization and accretion		259			386			1,577

Total Operating Expenses		2,253			11,185			68,575


Loss from Operations		(1,966	)		(10,736	)		(65,432	)

Other Income (Expense)
Foreign currency exchange		(23	)		—			—
Interest income		1			8			40
Interest expense		(5,035	)		(227	)		(14,253	)
Unrealized loss on trading securities		(2,393	)		—			(2,393	)

Total Other Expense		(7,450	)		(219	)		(16,606	)


Net Loss	$	(9,416	)	$	(10,955	)	$	(82,038	)


Net loss per common share — basic and diluted	$	(0.03	)	$	(0.05	)

Weighted average number of common shares outstanding — basic and diluted		306,471			219,929

See accompanying notes to consolidated financial statements

PETROHUNTER ENERGY CORPORATION
(A Development Stage Company)
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE LOSS
(unaudited)


										Deficit
										Accumulated			Accumulated
							Additional			During the			Other			Total			Total
	Common Stock						Paid-in			Development			Comprehensive			Stockholders’			Comprehensive
	Shares			Amount			Capital			Stage			Loss			Equity			Loss
	($ 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	)

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 $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	)

Balance, 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		—			—			3,842			—			—			3,842			—
Discount on notes payable		—			—			64			—			—			64			—
Foreign currency translation adjustment		—			—			—			—			(11	)		(11	)		(11	)
Stock based compensation		—			—			624			—			—			624			—
Net loss		—			—			—			(9,416	)		—			(9,416	)		(9,416	)

Balance, December 31, 2007		318,748,841		$	319		$	192,050		$	(82,038	)	$	(16	)	$	110,315		$	(9,427	)

See accompanying notes to consolidated financial statements.

PETROHUNTER ENERGY CORPORATION
(A Development Stage Company)
CONSOLIDATED STATEMENTS OF CASH FLOWS


				Three-Months			Cumulative From
	Three-Months			Ended			Inception
	Ended			December 31,			(June 20, 2005)
	December 31,			2006			to December 31,
	2007			(restated)			2007
	(unaudited, $ in thousands)
Cash flows used in operating activities
Net loss	$	(9,416	)	$	(10,955	)	$	(82,038	)
Adjustments used to reconcile net loss to net cash used in operating activities:
Stock for expenditures advanced		—			—			100
Stock based compensation		624			1,561			18,808
Detachable warrants recorded as interest expense		3,636			—			3,636
Depreciation, depletion, amortization and accretion		259			386			1,577
Impairment of oil and gas properties		—			5,151			24,053
Stock for financing costs		—			—			1,623
Amortization of discount and deferred financing costs on notes payable		575			—			1,611
Loss on trading securities		2,393			—			2,393
Loss on foreign exchange		23			—			—
Changes in assets and liabilities
Receivables		200			(476	)		(346	)
Due from related party		—			786			(500	)
Prepaids and other		(218	)		(33	)		(263	)
Deferred financing costs		(375	)		—			(375	)
Accounts payable, accrued expenses, and other liabilities		(2,261	)		(51	)		2,593
Due to shareholder and related parties		203			470			1,677

Net cash used in operating activities		(4,357	)		(3,161	)		(25,451	)

Cash flows used in investing activities
Additions to oil and gas properties		(5,720	)		(1,241	)		(71,385	)
Sales of oil and gas properties		7,500			—			7,500
Notes receivable-related party		—			(6,427	)		(2,494	)
Additions to property and equipment		(16	)		(33	)		(703	)
Restricted cash		—			(525	)		(1,077	)

Net cash provided by (used in) investing activities		1,764			(8,226	)		(68,159	)

Cash flows from financing activities
Proceeds from the sale of common stock		—			—			35,742
Proceeds from common stock subscribed		—			1,588			2,858
Proceeds from the issuance of notes payable		1,750			—			33,300
Payments on long-term debt		(40	)		—			(40	)
Borrowing on short-term notes payable		750			—			1,250
Payments on short-term notes		(4,807	)		—			(4,807	)
Payments on contracts payable		(250	)		—			(250	)
Payments on related party borrowing		(469	)		—			(194	)
Proceeds from the exercise of warrants		—			—			1,000
Cash received upon recapitalization and merger		—			—			21
Proceeds from issuance of convertible notes		6,334			1,505			27,166
Offering and financing costs		(339	)		(30	)		(1,977	)

Net cash provided by financing activities		2,929			3,063			94,069

Effect of exchange rate changes on cash		6			—			3

Net increase (decrease) in cash and cash equivalents		342			(8,324	)		462
Cash and cash equivalents, beginning of period		120			10,632			—

Cash and cash equivalents, end of period	$	462		$	2,308		$	462

Supplemental schedule of cash flow information
Cash paid for interest	$	2		$	—		$	1,503

Cash paid for income taxes	$	—		$	—		$	—

See accompanying notes to consolidated financial statements.

PETROHUNTER ENERGY CORPORATION
(A Development Stage Company)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

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” or the “Company”).

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 December 31, 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 loss in the amount of $82.0 million for the period from inception (June 20, 2005) to December 31, 2007, has a working capital deficit of approximately $23.0 million as of December 31, 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 December 31, 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 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 $101.3 million through December 31, 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. In November 2007, we raised an additional $7.0 million in a private placement of convertible debentures and we sold our Heavy Oil assets for up to $30.0 million, of which $7.5 million was cash.

For the three-months ended December 31, 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.

The accompanying financial statements should be read in conjunction with the Company’s Annual Report on Form 10-K for the year-ended September 30, 2007. Significant accounting policies disclosed therein have not changed. The accompanying consolidated financial statements are unaudited; however, in the opinion of management, they include all normal recurring adjustments necessary for a fair presentation of the consolidated financial position of the Company at December 31, 2007 and the consolidated results of its operations and cash flows for the three-months ended December 31, 2007 and 2006. The results of operations for the three-months ended December 31, 2007 are not necessarily indicative of the results that may be expected for the full fiscal year ending September 30, 2008.

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.

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 net loss.

Marketable Securities, Trading. In November 2007, we sold some of our Heavy Oil assets (see Note 4). As partial consideration, we accepted 947,153 shares of common stock of the purchaser, Pearl Exploration and Production Ltd. These shares are held for sale in the short term and as a result we account for them by marking them to market with unrealized gains recognized to income in the period incurred. During the first quarter ended December 31, 2007, we recognized a loss on trading securities in the amount of $2.4 million recorded as Unrealized loss on trading securities in our consolidated statement of operations.

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 2008, we entered into a transaction whereby we increased our interest in 14 of these wells to 100% (see Note 4) and we therefore reclassified $12.6 million of costs related to those wells from Joint interest billings to Oil and gas properties. We are currently in negotiations with our other partner regarding the remaining two wells and the balance of $1.0 million at December 31, 2007.

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. 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 depletion, amortization and accretion expense in the accompanying consolidated statements of operations.

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 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 three-months ended December 31, 2007 there was no impairment charge to expense. During the three-months ended December 31, 2006, we recorded an impairment charge in the amount of $5.2 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 the Company for loans with similar terms and average maturities, the fair value of payable notes, approximates their carrying value.

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.

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. In June 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 was effective for us on October 1, 2007. The cumulative effect of adopting FIN 48 did not have a significant impact on the Company’s financial position or results of operations and accordingly no adjustment was made.

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.

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 44,701,500 for the three-months ended December 31, 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.

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.

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.

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.

Supplemental Cash Flow Information. Supplement cash flow information for the three-months ended December 31, 2007 and 2006, respectively, and cumulative from inception (June 2005) is as follows:


						Cumulative
	Three-Months			Three-Months		From Inception
	Ended			Ended		(June 20, 2005) to
	December 31,			December 31,		December 31,
	2007			2006		2007
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		$	—	$	50
Shares issued for property	$	1,250		$	—	$	82,250
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
Receipt of trading securities related to sale of heavy oil assets	$	9,012		$	—	$	9,012
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
Debt discount related to beneficial conversion feature	$	4,002		$	—	$	4,002
Increase in oil and gas properties related to relief of joint interest billings	$	12,608		$	—	$	12,608

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 53.8% beneficial ownership interest in us at December 31, 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”).

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,

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.

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).

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 8):

•

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 $2.5 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 made during the first quarter of 2008.

Further, in the Second Amendment, MAB waived all past due amounts and all claims against PetroHunter.

The net effect of the reduction of debt and issuance of our common shares in the Second Amendment resulted in a net benefit to us of $3.8 million and has been 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 (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

Oil and gas properties consisted of the following ($ in thousands):


	December 31,			September 30,
	2007			2007
Oil and gas properties, at cost, full cost method
Unproved
United States	$	98,236		$	107,239
Australia		24,213			23,569
Proved		45,604			57,168

Total		168,053			187,976

Less accumulated depreciation, depletion, amortization and impairment		(1,289	)		(25,133	)

Total	$	166,764		$	162,843

Included in oil and gas properties above is capitalized interest of $0.2 million and $1.5 million for three-months ended December 31, 2007 and the year ended September 30, 2007, respectively. No interest was capitalized during the three-months ended December 31, 2006.

The following is a summary of depreciation, depletion, amortization and accretion, as reflected in the consolidated statements of operations (including depletion and amortization of oil and gas properties per thousand cubic feet of natural gas equivalent) for the three-months ended December 31, ($ in thousands, except per thousand cubic feet):


	2007		2006		Cumulative Total
Depletion and amortization of oil and gas properties	$	210	$	300	$	1,250
Depreciation of furniture and equipment		47		37		239
Accretion of asset retirement obligation		2		1		15

Total	$	259	$	338	$	1,504

Depletion and amortization per thousand cubic feet of natural gas equivalent	$	2.43	$	3.27

Using December 31, 2007 oil and gas prices of $95.96 per barrel and $6.07 per thousand cubic feet, our full cost pools did not exceed their ceiling.

Included below is the description of significant oil and gas properties and their current status.

PICEANCE BASIN

Buckskin Mesa Project. As of December 31, 2007, the Company drilled, but did not complete, five wells at a cost of $19.3 million. Plans include completion of these wells during the fiscal year ending September 30, 2008.

By the terms of the amended agreement with a third party assignor, Daniels Petroleum Company (“DPC”), 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. The Company’s estimate to drill and complete each well is $3.7 million; costs to drill and complete the 16 wells aggregate $59.2 million. 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. As of December 31, 2007, the Company drilled, but did not complete, 16 wells at a 100% working interest cost of $18.8 million. Plans include completion of these wells during the fiscal year ending September 30, 2008.

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

Exchange 1 — We 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 reflected as Joint interest billings in the Company’s consolidated balance sheet at September 30, 2007 was 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 $0.2 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 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 the Company’s 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 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 (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 December 31, 2007. 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.

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 7).

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.

Beetaloo Project. 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.

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”).

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 paid the balance off in November 2007 by offsetting it against amount owed by us to MAB under the MAB Note (see Notes 3 and 8).

MONTANA COALBED METHANE

Bear Creek Project. 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. On November 6, 2007 and 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 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.

Note 5 — Furniture and Equipment

Furniture and equipment is reported at cost, net of accumulated depreciation and consisted of the following ($ in thousands):


	December 31,			September 30,
	2007			2007
Furniture and equipment	$	764		$	748
Less accumulated depreciation		(226	)		(179	)

Total	$	538		$	569

Depreciation expense associated with capitalized office furniture and equipment during the three-months ended December 31, 2007 and 2006 was $47,000 and $37,000, respectively. 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, ($ in thousands):


	December 31,			September 30,
	2007			2007
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 7 — 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. 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 amended the terms of the Maralex Agreement on several occasions since the original 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. By the terms of the Maralex Agreement, the Company was required to pay to Maralex an amount equal to 5% of the outstanding payable for each 20 days past due (the “Maralex Penalty”). At September 30, 2007, we recorded an accrued liability in the amount of $0.4 million related to the Maralex Penalty. The entire amount of additional consideration, including the Maralex Penalty, in the amount of $3.5 million was recorded as interest expense in our consolidated statement of operations during the year ended September 30, 2007.

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 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 first quarter ended December 31, 2007, 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 8 — Notes Payable

Notes payable are summarized below ($ in thousands):


	December 31,			September 30,
	2007			2007
Short-term notes payable:
Wes-Tex	$	750		$	—
Global Project Finance AG		—			500
Vendor		622			4,050
Flatiron Capital Corp.		68			117

Short-term notes payable	$	1,440		$	4,667

Convertible notes payable	$	400		$	400

Subordinated notes payable — related party:
Bruner Family Trust	$	2,347		$	275
MAB		1,045			12,530
Less current portion		—			(3,755	)

Subordinated notes payable — related party	$	3,392		$	9,050

Long-term notes payable — net of discount:
Global Project Finance AG	$	33,300		$	31,550
Vendor		210			250
Less current portion		(120	)		(120	)
Discount on notes payable		(3,302	)		(3,736	)

Long-term notes payable — net of discount	$	30,088		$	27,944

Convertible debt	$	6,956		$	—
Discount on convertible debt		(4,002	)		—

Convertible debt — net of discount	$	2,954		$	—

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 is collateralized by 947,153 of the Pearl shares, accrues interest at the rate of 15%. Principal and accrued interest was originally due on January 18, 2008. On January 17, 2008, the Wes-Tex Note was extended to March 4, 2008.

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 Heavy Oil assets. 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. The company has entered into promissory notes for outstanding unpaid account payable balances as follows: (i) 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 December 31, 2007, we were in default on this note due to non-payment; the balance was $248,000 and we had accrued interest on the note in the amount of $0.3 million. The vendor filed a judgment lien against us (see Note 12) related to non-payment of this note and the Company and the vendor are continuing to negotiate a settlement on this matter; (ii) During the first quarter ended December 31, 2007, we entered into one other promissory note with a vendor for outstanding account payable balances. The note bears interest at 8.25% per annum and is due to mature February 29, 2008. At December 31, 2007, we had accrued interest related to this in the amount of $2,000 and we were in default on the payment terms. 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.

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 December 31, 2007 was $68,000. At December 31, 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 December 31, 2007, accrued interest amounted to $0.1 million. The Company is in default on payment of the notes.

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 December 31, 2007, we had accrued interest on these notes in the 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. 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.

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, 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 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 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. At December 31, 2007, 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 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.

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. As of December 31, 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 under the May 2007 Credit Facility. As of December 31, 2007, $18.3 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 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 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 69.2% 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 December 31, 2007, in the amount of $4.7 million for advances through December 31, 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 December 31, 2007, the Company was in default of payments to Global in the amount of $3.9 million, which consists of unpaid interest and 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 December 31, 2007. 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, 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. As of December 31, the balance of this note is $0.2 million and we are not in default on this note.

Convertible Notes. 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. 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, the Company recorded $3.0 million of interest expense during the first quarter of 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 were due quarterly beginning January 1, 2008. As of January 2, 2008 we were in default on interest payments on this note. All overdue, accrued, unpaid interest incurs a late fee of 18% to be charged on the unpaid interest balance. Interest accrued on these notes as of December 31, 2007 was $0.1 million.

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 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. 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, 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. 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.

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.

Note 9 — Stockholders’ Equity

Common Stock. During the three-months ended December 31, 2007, the Company issued 46.2 million shares of its common stock and had 6.4 million shares of its 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 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 were offered the opportunity to rescind their subscriptions or to participate on the same terms as ultimately defined for the restructured offering. As of December 31, 2007, the Company reclassed $2.4 million of subscriptions which included $0.1 million of accrued interest to Notes Payable- Related Party.

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 8). 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 at December 31, 2007 totaling $0.5 million was reclassed from Common Stock Subscribed to Convertible notes payable — net of discount on 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 December 31, 2007 and September 30, 2007, 14.0 and 15.0 million shares, respectively remained available for grant pursuant to the stock option plan. During the three-months ended December 31, 2007, the Company granted 3.0 million options under its 2005 stock option plan to directors, employees and consultants performing employee-like services to the Company. There were no options granted, forfeited or vested during the three-months ended December 31, 2006.

A summary of the activity under the Plan for the three-months ended December 31, 2007 is presented below (shares in thousands):


				Weighted-
	Number of			Average
	Shares			Exercise Price
Options outstanding — September 30, 2007		24,965		$	1.31
Granted		2,950			0.20
Forfeited		(1,920	)		1.68

Options outstanding — December 31, 2007		25,995			1.15

There have been no options exercised under the terms of the Plan.

A summary of the activity and status of non-vested awards for the three-months ended and as of December 31, 2007, is presented below (shares in thousands):


				Weighted-
	Number of			Average
	Shares			Fair Value
Non-vested — September 30, 2007		10,208		$	0.62
Granted		2,950			0.11
Vested		(590	)		0.11
Forfeited		(1,920	)		0.10
Expired		—			—

Non-vested — December 31, 2007		10,648			0.41

As of December 31, 2007 there was $4.4 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 3.56 years. The total fair value of shares vested during the three-months ended December 31, 2007 and 2006 was $0.1 million and $0.0 million, respectively.

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-months ended December 31, 2007.


		2007
Expected option term — years		5
Weighted-average risk-free interest rate		3.75%
Expected dividend yield		0
Weighted-average volatility		71%

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 3.81 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.

The following table summarizes additional information regarding options outstanding as of December 31, 2007 (shares in thousands):


Stock Options Outstanding
			Weighted-Average
			Remaining		Weighted-Average
	Number of		Contractual Life		Exercise Price per		Aggregate
Range of Exercise Price	Options Outstanding		(In Years)		Share		Intrinsic Value
$0.19 - 0.49		4,800		4.4	$	0.26	$	—
0.50 - 0.99		9,100		1.8		0.50		—
1.0 - 1.99		1,500		4.2		1.29		—
> 2.00		10,595		3.5		2.10		—

		25,995		3.1		1.15		—


Stock Options Exercisable
			Weighted-Average
			Remaining		Weighted-Average
	Number of		Contractual Life		Exercise Price per		Aggregate
Range of Exercise Price	Options Exercisable		(In Years)		Share		Intrinsic Value
$0.19 - 0.49		1,185		4.4	$	0.24	$	—
0.50 - 0.99		8,334		1.6		0.50		—
1.0 - 1.99		600		4.2		1.34		—
> 2.00		5,228		3.0		2.10		—

		15,347		2.4		1.05		—

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 the three-months ended December 31, 2007 for these options is presented below (shares in thousands):


	Number of			Weighted-Average
	Shares			Exercise Price
Options outstanding — September 30, 2007		9,895		$	0.50
Granted		—			—
Forfeited		(1,000	)		0.50

Options outstanding — December 31, 2007		8,895			0.50

Options exercisable — December 31, 2007		5,337			0.50

A summary of the status and activity of non-vested awards not under the Plan for the three-months ended December 31, 2007 is presented below (shares in thousands):


	Number of			Weighted-Average
	Shares			Fair Value
Non-vested — September 30, 2007		3,958		$	0.21
Granted		—			—
Vested		—			—
Forfeited		(400	)		0.01
Expired					—

Non-vested — December 31, 2007		3,558		$	0.28

For the three-months ended December 31, 2007 and 2006, there was no unrecognized compensation cost related to non-vested share-based compensation arrangements granted not under the Plan.

Compensation Expense

Under SFAS 123(R), pre-tax stock-based employee compensation expense of $0.5 million and $0.5 million was charged to operations for the three-months ended December 31, 2007 and 2006, respectively. Under EITF 96-18, pre-tax stock-based non-employee compensation expense of $0.1 million and $1.1 million was charged to operations as compensation expense for the three-months ended December 31, 2007 and 2006, respectively.

Warrants

The following stock purchase warrants were outstanding at, (warrants in thousands):


	December 31,	September 30,
	2007	2007
Number of warrants	130,372	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 8). As of December 31, 2007, 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 quarter we issued warrants in connection with amounts borrowed against our credit facility. We issued 0.7 million warrants valued at $0.1 million using the Black-Scholes method.

Note 11 — Related Party Transactions

MAB. During the three-months ended December 31, 2006, 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 three-months ended December 31, 2007. During the three-months ended December 31, 2007 and 2006, we recorded expenditures paid by MAB on behalf of us in the amount of $0.5 million and $0.5 million. Project development costs to MAB are classified in our consolidated statements of operations as Project development costs — related party. At December 31, 2007 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.

During the three-months ended December 31, 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 $85,713 and made principal payments of $0.5 million. As of December 31, 2007, the Company owed MAB principal and accrued interest of $1.6 million under the terms of the promissory note.

At December 31, 2007, the Company also has two separate promissory notes with the Bruner Family Trust (see Note 8) in the amounts of $0.1 million and $25,000, respectively. During the three-months ended December 31, 2007, we incurred total interest expense of $3,765 and paid nothing in principal payments on these notes. As of December 31, 2007, the Company owed the Bruner Family Trust principal and accrued interest of $0.1 million under the terms of these promissory notes.

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 first quarter ended December 31, 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. During the three-months ended December 31, 2007, 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

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. This Office Agreement terminated on January 31, 2008 when the Company moved to new office space. The largest single beneficial shareholder of the Company is also the Chief Executive Officer and a Director of Falcon. At December 31, 2007 and September 31, 2007, we owed Falcon $0.6 million and $0.5 million, respectively, for costs incurred pursuant to the Office Agreement.

Officers. During the three-months ended December 31, 2007 and 2006, the Company incurred consulting fees related to services provided by its officers in the aggregate amount of $0.1 million and $0.2 million, respectively. These fees are reflected in our statements of operations as General and administrative.

Note 12 — 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) Approximately 20 vendors have filed multiple liens applicable to our properties, with two primary foreclosure actions pending at various stages of the pleadings, in connection with the liens. The Company has entered into settlement agreements including payment plans, with five vendors; (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 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; (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 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 either or both vendors referenced in (ii) or (iii), above, and does not pay the amount owed, either of said vendors could obtain a judgment lien and seek to execute on the lien against the Company’s assets. In the event the Company and the vendor referenced in (iv), above do not reach agreement on the amendment to the settlement agreement, this 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, 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 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.

Rent expense for the three-months ended December 31, 2007 and 2006 was $0.1 million and $0.1 million 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 13 — Subsequent Events

Director Note. On January 25, 2008, we obtained a loan and signed a promissory note (the “Director Note”) in the amount of $100,000 from member of the Board of Directors of the Company. The loan is collateralized, in a second priority position, by the same 947,153 of the Pearl shares which secure the Wes-Tex Note. The note accrues interest at the rate of 15% and matures on February 29, 2008.

Bruner Family Trust. On February 12, 2008, we entered into a promissory note with the Bruner Family Trust in the amount of $0.1 million. Interest accrues at three-month LIBOR plus 3%. Principal and interest are due five days after receipt of the holder’s written demand but not before February 11, 2009.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION

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 Form 10-Q.

Background

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.

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

The Company entered into a Securities Purchase Agreement in November 2007 for the issuance of Series A 8.5% Convertible Debentures (“Convertible Debentures”) in the aggregate principal amount of $7.0 million to several accredited investors. Attached to the Convertible Debentures were warrants to purchase 46.4 million shares of the Company’s common stock. The Convertible Debentures accrue interest on the aggregate unconverted and outstanding principal amount at 8.5% per annum, payable quarterly beginning on the first date after the Original Issue Date and are due five years from the date of the note. The decision whether to pay interest in cash, shares of common stock, or a combination thereof is at the discretion of the Company. The note holders have the option to convert any unpaid note principal and interest to the Company’s common stock at a price of $0.15 per share until the Convertible Debenture is no longer outstanding. The conversion price of the Convertible Debentures may be adjusted in certain circumstances such as if the Company pays a stock dividend, subdivides, combines outstanding shares of common stock into a smaller number of shares, or issues any shares of capital stock.

As of December 31, 2007, no investor has opted to convert principal or interest. As of December 31, 2007, the Company had accrued interest of $0.1 million and recorded $3.0 million to interest expense related to its valuation of the detachable stock purchase warrants. As of January 2, 2008, we were in default in quarterly interest payments which were due beginning January 1, 2008.

Results of Operations

Three-Months Ended December 31, 2007 vs. Three-Months Ended December 31, 2006

Oil and Gas Revenues. For the three-months ended December 31, 2007, oil and gas revenues were $0.3 million as compared to $0.4 million for the corresponding period in 2006. The 2006 revenues were results of production from 12 natural gas wells in the Piceance Basin of Colorado. The decrease in revenue is related to (a) the natural production decline in the wells, and (b) to ownership interests in fewer producing wells, offset slightly by increases in commodity prices. In 2007, eight producing wells produced and sold approximately 93,824 Mcf of natural gas and 20 Bbls of oil. In 2006, we had 12 operating wells that sold 85,922 Mcf of natural gas. Average prices received for gas sold has increased to $5.36 per Mcf in 2007 from $5.17 per Mcf in 2006 as a result of market conditions.

Costs and Expenses

Lease Operating Expenses. For the three-months ended December 31, 2007, lease operating expenses decreased to $0.1 million compared to $0.2 million for the corresponding period in 2006. This is a result of lower maintenance costs for the non-operated wells in which the Company owns an interest, and a reduction in the Company’s ownership interests in producing wells.

General and Administrative. During the three-months ended December 31, 2007, general and administrative expenses decreased by $1.8 million or 48% as compared to the corresponding period in 2006. The following table highlights the areas with the most significant changes ($ in thousands):


	Three-Months Ended
	December 31,
	2007		2006		Change
Accounting and audit fees	$	0.2	$	0.1	$	0.1
Stock based compensation expense		0.6		1.6		(1.0	)
Travel		0.1		0.5		(0.4	)
Investor relations		—		0.3		(0.3	)

Total	$	0.9	$	2.5	$	(1.6	)

The decrease in general and administrative expenses in 2007 is a result of decreased stock based compensation and decreases in travel and investor relation type expenses.

Project Developmental Costs — Related Party. Property costs incurred to MAB were $1.8 million during 2006. We no longer pay project development costs to MAB as a result of the restructuring of our agreements with MAB, which were 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 2006, we recorded an impairment expense in the amount of $5.2 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 2007.

Depreciation, Depletion, Amortization and Accretion. Depreciation, depletion, amortization and accretion expense (“DD&A”) was $0.3 million in 2007 as compared to $0.4 million in 2006.

Interest Expense. During 2007, interest expense was $5.0 million, as compared to $0.2 million during 2006. During the first quarter ended December 31, 2007, interest expense consisted of the following: ($ in thousands)


Interest expense related to detachable stock purchase warrants on convertible notes	$	2,954
Interest on notes and convertible debt		1,388
Interest on related party note		89
Amortization of deferred financing costs		568
Commission expense on the credit facility		108
Other		98
Capitalized interest		(170	)

Total	$	5,035

We expect that interest expense will increase during the remainder of the fiscal year ending September 30, 2008, due to the borrowings under the convertible debentures and our credit facilities and other borrowings that may occur.

Net Loss. During 2007, we incurred a net loss of $9.4 million as compared to a net loss of $11.0 million during 2006.

Going Concern

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 $82.0 million for the period from inception (June 20, 2005) to December 31, 2007 have a working capital deficit of approximately $23.0 million as of December 31, 2007, are 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. We require significant additional funding to sustain our operations and satisfy our contractual obligations for our planned oil and gas exploration and development operations. Liens have been filed against some of the properties and foreclosure proceedings have begun. In addition, we are in default on certain obligations. Our ability to establish the Company as a going concern is dependent upon our ability to obtain additional funding in order to finance our planned operations.

Plan of Operation

Colorado. We expect that the development of our Colorado properties will include the following activities: (i) the completion and tie-in of 16 wells drilled and cased to date in the Piceance II Prospect and 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, completion and tie-in of a minimum of 10 commitment wells within the Williams Fork development area in which the Piceance II Prospect is located in the southern Piceance Basin; (iii) the drilling, completion and tie-in of a minimum of 12 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 (iv) the recompletion and tie-in of the six shut-in gas wells in the Powell Park Field acquired by the Company 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. 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

The Company has grown rapidly since its 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. During 2006 and 2007, we added employees and acquired an interest in additional properties. At December 2007 we had 13 full time employees and 15 consultants, and at December 2006, we had 16 full time employees. We had interests in properties aggregating approximately 21,757 net acres in Colorado, 20,827 net acres in Montana, and 7.0 million net acres in Australia at December 31, 2007 and 19,839 acres in Colorado and 7.0 million net acres in Australia at December 31, 2006.

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, Colorado and Australia; and (ii) to improve the economics of our projects by restructuring the Development Agreement with MAB. Accordingly, during the three-months ended December 31, 2007 we sold our heavy oil assets and restructured the Development Agreement with MAB through amendments.

Working Capital. Working capital is the amount by which current assets exceed current liabilities. Our working capital is impacted by changes in prices of oil and gas along with other business factors that affect our net income and cash flows. Our working capital is also affected by the timing of operating cash receipts and disbursements, borrowings of and payments of debt, additions to oil and gas properties and increases and decreases in other non-current assets.

As of December 31, 2007, we had a working capital deficit of $23.0 million and cash of $0.5 million. As of September 30, 2007, we had a working capital deficit of $37.9 million and cash of $0.1 million. The changes in working capital are primarily attributable to the factors described above. We expect that our future working capital will 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 may sell 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.

Cash Flow. Net cash used in or provided by operating, investing and financing activities for the three-months ended December 31, 2007 and 2006 were as follows ($ in thousands):


	Three-Months Ended December 31,
	2007			2006
Net cash used in operating activities	$	(4,357	)	$	(3,161	)
Net cash provided by (used in) investing activities	$	1,764		$	(13,125	)
Net cash provided by financing activities	$	2,929		$	3,063

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 three-months ended December 31, 2007 was primarily from cash received for the sale of oil and gas properties of $7.5 million offset by cash used for additions to oil and gas properties of $5.7 million. Net cash used in investing activities for the three-months ended December 31, 2006 was primarily used for joint interest billings in the amount of $6.4 million and additions to oil and gas properties in the amount of $1.2 million.

Net Cash Provided by Financing Activities. Net cash provided by financing activities for the three-months ended December 31, 2007 was primarily comprised of borrowings of $8.8 million net of repayments of debt in the amount of $5.6 million and payment of financing costs in the amount of $0.4 million. Net cash provided by financing activities for the three-months ended December 31, 2006 was comprised of: (1) the subscription of common stock of $1.6 million and (2) the issuance of convertible notes of $1.5 million.

Capital Requirements. We currently anticipate our capital budget for the year ending September 30, 2008 to be approximately between $103.0 and $140.0 million. Uses of cash for 2008 will be primarily for our drilling program in the Piceance Basin and in Australia. The following table summarizes our drilling commitments for fiscal year 2008 ($ in thousands):


		Aggregate		Our Working
Activity	Prospect	Total Cost		Interest			Our Share^(a)
Drill and complete 12 wells	Buckskin Mesa	$	44,400		100	%	$	44,400
Drill and complete two wells	Piceance II		4,200		37.5	%		1,575
Drill and complete eight wells	Piceance II		16,800		62.5	%		10,500
Complete 16 wells ^(b)	Piceance II		17,600		100	% ^(e)		17,600
Drill five wells	Beetaloo		20,000		100	%		20,000	^(d)

Total		$	103,000				$	94,075

(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 farmor to pay a portion of our development costs.

(b)		These wells have all been drilled.

(c)		During December 2007, our working interest in these wells increased to 100% with the payment by us of $1.0 million in cash.

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

Financing. During the first quarter ended December 31, 2007 and 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 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 seven 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 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.

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.

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.

(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 first quarter ended December 31, 2007, 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 December 31, 2007, the balance of this note was $1.0 million. The note is unsecured and bears interest at LIBOR. Although at December 31, 2007, 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 two separate loans with the Bruner Family Trust, UTD March 28, 2005 for a total of $0.3 million. Each 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 December 31, 2007, the balance of these notes is $0.1 million.

(6) We entered into a $15.0 million credit facility in January 2007, with Global (the “January Credit Facility”). The January 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 paid 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 Credit Facility”). The May Credit Facility is secured by the same certain oil and gas properties and other assets as the January Credit Facility. The May 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 December 31, 2007 we had $41.7 million remaining available to us from the credit facility. The funds borrowed were used to fund working capital needs of the Company.

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 below.

Development Stage Company. We had not commenced principal operations or earned significant revenue as of December 31, 2007, and we are considered a development stage entity for financial reporting purposes. During the period from inception to December 31, 2007, we incurred a cumulative net loss of $82.0 million. We have raised approximately $101.3 million through borrowing and the sale of convertible notes and common stock from inception through December 31, 2007. 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. 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.

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.

Share Based Compensation. Effective October 1, 2006, we adopted the provisions of SFAS 123(R) (As Amended), Share-Based Payment. 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, 2005, we accounted for stock-based compensation using the intrinsic value recognition and measurement principles detailed in Accounting Principles Board 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.

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 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. There was no impairment charge during the three-months ended December 31, 2007. During the three-months ended December 31, 2006, we recorded an impairment charge in the amount of $5.2 million.

Recently Issued Accounting Pronouncements

Recently Issued Accounting Pronouncements. In December 2007, the FASB issued SFAS 160, Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB 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.

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 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. SFAS 141(R) will have no impact on our consolidated results of operations, cash flows or financial position. 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 June 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. The cumulative effect of adopting FIN 48 did not have a significant impact on the Company’s financial position or results of operations and accordingly no adjustment was made.

ITEM 3. 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.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of December 31, 2007, an evaluation was performed under the supervision and with the participation of the Company’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Partnership’s “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 [the “Exchange Act”]). Based on that evaluation, the Company’s management, including the Chief Executive Officer and Chief Financial Officer, concluded the Company’s disclosure controls and procedures were not effective to ensure that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is (a) recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms and (b) accumulated and communicated to the Company’s management, including the Chief Executive Officer and the Chief Financial Officer, to allow timely decisions regarding required disclosure as evidenced by the material weakness described below.

As reported in Item 9A of the Company’s 2007 Form 10-K filed on January 15, 2008 management reported the existence of a continuing material weakness related to our control environment which did not sufficiently promote effective internal control over financial reporting through the management structure to prevent a material misstatement. 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. The Company did not have adequate staffing to provide for an effective segregation of duties to adequately resolve accounting issues and provide information to the auditors on a timely basis. These material weaknesses continue to exist as of December 31, 2007.

We are fully committed to remediating the material weakness described above, and we believe that we are taking the steps that will properly address these issues. Further, our Audit Committee has been and expects to remain actively involved in the remediation planning and implementation. However, the remediation of the design of the deficient controls and the associated testing efforts are not complete, and further remediation may be required.

While we are taking immediate steps and dedicating substantial resources to correct these material weaknesses, they will not be considered remediated until the new and improved internal controls operate for a period of time, are tested and are found to be operating effectively. During the first quarter ended December 31, 2007, we hired a Chief Financial Officer and are utilizing several full-time accounting contractors serving in senior and staff level accounting positions. We are actively recruiting high-level, competent accounting personnel.

Our remediation efforts may not be sufficient to maintain effective internal controls in the future. We may not be able to implement and maintain adequate controls over our financial processes and reporting, which may require us to restate our financial statements in the future. In addition, we may discover additional past, ongoing or future material weaknesses or significant deficiencies in our financial reporting system in the future. Any failure to implement new controls, or difficulty encountered in their implementation, could cause us to fail to meet our reporting obligations or result in material misstatements in our financial statements. Inferior internal controls could also cause investors to lose confidence in our reported financial information, which could result in a lower trading price of our common shares.

Pending the successful implementation and testing of new controls and the hiring of additional personnel, we will perform mitigating procedures. If we fail to remediate any material weaknesses, we could be unable to provide timely and reliable financial information, which could have a material adverse effect on our business, results of operations or financial condition.

Changes in Internal Controls Over Financial Reporting

There have been changes in our internal controls over financial reporting that occurred during the first fiscal quarter of 2008 and additional controls will be implemented during the second and third fiscal quarters that have materially affected or are reasonably likely to materially affect our internal controls over accounting and financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The Company is a party to the following legal proceedings:

1. 21 vendors have filed multiple liens applicable to our properties.

2. Two primary foreclosure actions are pending at various stages of the pleadings, in connection with the liens (plus cross claims and counter claims within each of these actions).

3. A law suit was filed in August 2007 by the law firm of Minter Ellison in the Supreme Court of Victoria for the balance of legal fees owed (0.2 million Australian dollars).

4. A law suit 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). This amount is disputed by the Company on the basis that the vendor breached the contract.

5. A judgment lien was filed in October 2007 by another vendor for PetroHunter’s default under a settlement agreement related to the drilling contract between us and the vendor. The parties are currently negotiating an amendment to the settlement agreement, which would defer any further action by the vendor as long as PetroHunter makes further payments in accordance with the amended settlement.

In the event the Company does not remove the liens referenced in (1) 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 (1) above, the Company could be in jeopardy of losing assets. In the event the Company loses the lawsuits to the vendors referenced in 3 and/or 4 above, and does not pay the amounts owed, the 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 vendor referenced in (5) above do not reach agreement on the amendment to the settlement agreement, the vendor could enforce its existing judgment lien against the Company’s assets in Colorado.

ITEM 1A. RISK FACTORS

There were no material changes from the risk factors disclosed in our Form 10-K for the fiscal year ended September 30, 2007.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

On November 6, 2007, the Company issued 5.0 million shares of common stock to American Oil & Gas, Inc. and Savannah Exploration, Inc. in consideration for the termination of the Company’s obligation to pay an overriding royalty and a per barrel production payment on properties sold to Pearl Exploration and Production Ltd. The Company relied upon the exemption from registration contained in Section 4(2) of the Securities Act of 1933.

These issuances and sales are in addition to the following transactions involving unregistered securities reported in current reports on Form 8-K:

	—		Issuance of 25,000,000 shares of common stock to MAB Resources LLC in an 8-K filed October 23, 2007

	—		Issuance of 16,000,000 shares of common stock and warrants to purchase 32,000,000 shares of common stock in an 8-K filed November 16, 2007

	—		Sales of convertible debentures and warrants in an 8-K filed November 15, 2007 and amended on November 16, 2007 and the sales of convertible debentures and warrants in a current report on Form 8-K filed on November 16, 2007.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.

ITEM 5. OTHER INFORMATION
None.

ITEM 6. EXHIBITS
See Exhibit Index.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


		PETROHUNTER ENERGY CORPORATION

		By:		/s/ Charles B. Crowell

				Charles B. Crowell Chief Executive Officer

		Date: February 19, 2008

		By:		/s/ Lori Rappucci

				Lori Rappucci Vice President and Chief Financial Officer

		Date: February 19, 2008

EXHIBIT INDEX


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 Company’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 Company’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 Company’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 Company’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 Company’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 Company’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 Company’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 Company’s amended current report on Form 8-K dated December 29, 2006, filed May 1, 2007)

	2.9	Fifth Amendment to Purchase and Sale Agreement dated May 31, 2007 (incorporated by reference to Exhibit 2.5 to the Company’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 Company’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 Company’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)

	10.1	Business Consultant Agreement dated October 1, 2005 (incorporated by reference to Exhibit 10.1 to the Company’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 Company’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 Company’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 Company’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 Company’s quarterly report on Form 10-QSB for the quarter ended December 31, 2005, filed February 16, 2006)


Regulation
S-K Number		Exhibit

	10.6	2005 Stock Option Plan (incorporated by reference from Exhibit 4.1 to the Company’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 Company’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 Company’s amended current report on Form 8-K dated January 9, 2007, filed May 4, 2007)

	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 Company’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 Company’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 Company’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 Company’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 Company’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 Company’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 Company’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 Company’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 Company’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 Company’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 Company’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 Company’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 Company’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 Company’s current report on Form 8-K dated January 4, 2008, filed January 10, 2008)

	10.23	Third Amendment to Acquisition and Consulting Agreement between MAB Resources LLC and PetroHunter Energy Corporation dated (incorporated by reference to Exhibit 10.23 to the Company’s annual report on Form 10-K for the fiscal year ended September 30, 2007, filed January 15, 2008)


Regulation
S-K Number		Exhibit

	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 Company’s current report on Form 8-K dated February 12, 2008, filed February 19, 2008)

	31.1	Rule 13a-14(a) Certification of Charles B. Crowell

	31.2	Rule 13a-14(a) Certification of Lori Rappucci

	32.1	Certification of Charles B. Crowell Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act Of 2002

	32.2	Certification of Lori Rappucci Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act Of 2002