Edgar Filing: PetroHunter Energy Corp

f10q-033108_phun.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2008

£	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		(I.R.S. Employer
incorporation or organization)		Identification No.)

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

(303) 572-8900

Registrant’s telephone number, including area code

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 R No £

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

Large accelerated filer £ Accelerated filer £ Non-accelerated filer 0 Smaller reporting company R

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

As of April 30, 2008, the registrant had 318,748,841 shares of common stock outstanding.

Unless otherwise noted in this report, any description of “us” or “we” refers to PetroHunter Energy Corporation and our subsidiaries. All amounts expressed herein are in U.S. dollars unless otherwise indicated.

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. All forward-looking statements herein as well as all subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by cautionary statements set forth in Item 1A “Risk Factors” appearing in our Annual Report on Form 10-K for the fiscal year ended September 30, 2007. We assume no duty to update or revise our forward-looking statements based on changes in internal estimates or expectations or otherwise. We advise you to carefully review the reports and documents we file from time to time with the Securities and Exchange Commission (the “SEC”).

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.

Drilled and Cased. Involves drilling a well and installing casing to a specified depth in the wellbore for future completion.

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

INDEX


PART I — FINANCIAL INFORMATION
Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets at March 31, 2008 (unaudited) and September 30, 2007.
	Condensed Consolidated Statements of Operations for the three and six months ended March 31, 2008 and 2007, and the cumulative period from inception to March 31, 2008 (unaudited).
	Condensed Consolidated Statements of Stockholders’ Equity and Comprehensive Loss for the six months ended March 31, 2008 and the cumulative period from inception to March 31, 2008 (unaudited).
	Condensed Consolidated Statements of Cash Flows for the six months ended March 31, 2008 and 2007 and the cumulative period from inception to March 31, 2008 (unaudited).
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 4T.	Controls and Procedures
PART II — OTHER INFORMATION
Item 1.	Legal Proceedings
Item 1A.	Risk Factors
Item 6.	Exhibits
	Signatures

PART I. FINANCIAL INFORMATION

PETROHUNTER ENERGY CORPORATION

(A Development Stage Company)

CONDENSED CONSOLIDATED BALANCE SHEETS

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

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

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

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

Common Stock Subscribed		—			2,858

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

See accompanying notes to condensed consolidated financial statements.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited; $ in thousands except per share amounts)

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

Revenues
Oil and gas revenues	$	496		$	889		$	783		$	1,338		$	3,639
Other revenues		209			—			209			—			209
Total revenues		705			889			992			1,338			3,848

Costs and expenses
Lease operating expenses		140			224			240			386			1,037
General and administrative		3,796			4,331			5,690			8,002			38,639
Property development — related party		—			—			—			1,815			7,205
Impairment of oil and gas properties		—			3,800			—			8,951			24,053
Consulting fees – related party		—			75			—			75			—
Depreciation, depletion, amortization and accretion		182			827			441			1,213			1,759
Total operating expenses		4,118			9,257			6,371			20,442			72,693

Loss from operations		(3,413	)		(8,368	)		(5,379	)		(19,104	)		(68,845	)
Other income (expense):
Gain on foreign exchange		34			—			11			—			34
Interest income		26			6			27			14			66
Interest expense		(2,390	)		(2,004	)		(7,425	)		(2,231	)		(16,643	)
Trading security losses		(594	)		—			(2,987	)		—			(2,987	)
Total other expense		(2,924	)		(1,998	)		(10,374	)		(2,217	)		(19,530	)
Net loss	$	(6,337	)	$	(10,366	)	$	(15,753	)	$	(21,321	)	$	(88,375	)
Net loss per common share — basic and diluted	$	(0.02	)	$	(0.05	)	$	(0.05	)	$	(0.10	)
Weighted average number of common shares outstanding — basic and diluted		316,978			222,562			312,610			221,245

See accompanying notes to condensed consolidated financial statements

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE LOSS

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

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

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

See accompanying notes to condensed consolidated financial statements.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited, $ in thousands)

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

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

See accompanying notes to condensed consolidated financial statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1 — Organization and Basis of Presentation

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

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

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

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

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

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

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

Note 2 — Summary of Significant Accounting Policies

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

• The cost of properties not being amortized; plus

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

• Income tax effects related to differences between the book and tax basis of the properties.

If unamortized costs capitalized within a cost center, less related deferred income taxes, exceed the cost center ceiling, the excess is charged to expense. During the three and six-month periods ended March 31, 2008, we did not record any impairment charges. During the three and six-month periods ended March 31, 2007, we recorded impairment charges of $3.8 million and $9.0 million.

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

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

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

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

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

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

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

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

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

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

Note 3 — Agreements with MAB Resources LLC

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

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

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

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

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

·	7% of the issued and outstanding shares of any new subsidiary with assets comprised of the subject properties

·	A 5% overriding royalty interest on certain of the properties, to be accrued and deferred for three years, provided these royalties do not render our net revenue interest to be less than 75%, and

·	$25,000 per month for consulting services (which was later rescinded by Amendment 1 to the Consulting Agreement, effective retroactively to January 1, 2007).

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

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

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

·	MAB relinquished portions of its overriding royalty interest effective October 1, 2007 such that the override currently only applies to our Australian properties and Buckskin Mesa property;

·	MAB received 25.0 million additional shares of our common stock;

·	MAB relinquished all rights to the Performance Shares described above;

·	MAB’s consulting services were terminated effective retroactively back to January 1, 2007;

·	MAB waived all past due amounts and all claims against PetroHunter; and

·	the note payable to MAB was reduced in accordance with and in exchange for the following:

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;

o	by $2.9 million in exchange for our release of MAB’s obligation to pay the equivalent amount as guarantor of the performance of Galaxy Energy Corporation under the subordinated unsecured promissory note dated August 31, 2007 (see Note 10);

o	a reduction to the note payable to MAB of $0.5 million for cash payments made during the first quarter of 2008; and

o	by $0.2 million for MAB assuming certain costs that Paleo Technology owed to us.

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

As more fully described in Note 12, during the preparation of our second quarter financial statements, we discovered certain errors that relate to our first quarter financial statements. One of those errors resulted from the retroactive termination of MAB’s consulting services, where we (a) overstated the reversal of our obligation to pay for the consulting services by $0.2 million, and (b) had erroneously recorded the relief of the actual $0.2 million liability we had recorded at September 30, 2007 as a credit to our first quarter net loss. We have subsequently determined that the relief of this obligation by MAB should correctly be reflected as a credit to our paid in capital account, as the transaction relates to the relief of an obligation to a significant shareholder. These errors were corrected in the second quarter.

Note 4 — Oil and Gas Properties

Oil and gas properties consisted of the following:

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

Included in oil and gas properties above is capitalized interest of $0.0 million and $0.4 million for three months ended March 31, 2008 and 2007, respectively. In the six months ended March 31, 2008 and 2007, oil and gas properties included capitalized interest of $0.2 million and $0.4 million, respectively.

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

PICEANCE BASIN

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

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

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

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

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

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

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

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

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

AUSTRALIA

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

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

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

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

POWDER RIVER BASIN

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

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

MONTANA COALBED METHANE

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

HEAVY OIL

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

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

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

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

Note 5 — Asset Retirement Obligation

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

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

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

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

Note 6 — Contract Payable

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

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

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

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

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

Note 7 — Notes Payable

Notes payable are summarized below:

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

Short - Term Notes Payable

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

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

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

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

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

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

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

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

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

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

Note – Payable Related Party – Current Portion

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

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

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

Subordinated Notes Payable-Related Party

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

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

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

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

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

Long-Term Notes Payable

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

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

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

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

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

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

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

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

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

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

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

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

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

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 8 — Stockholders’ Equity

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

• 25.0 million shares issued at $0.31 per share for consideration given to an amendment to a related party contract relinquishing overriding royalty interests (see Note 3)

• 16.0 million shares issued at $0.23 per share for an amendment to a related party contract reducing an outstanding note payable (see Note 3)

• 5.0 million shares issued at $0.25 per share in conjunction with sale of heavy oil assets

• 0.2 million shares issued at $0.28 per share for transaction finance costs

• 1.9 million shares returned at $1.70 per share for property interests

• 0.5 million shares returned at $1.72 per share for property interests

• 0.4 million shares returned at $1.29 per share for property interests

• 0.4 million shares returned at $0.51 per share for property interests

• 3.2 million shares returned at $0.23 per share for property interests

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

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

Warrants

The following stock purchase warrants were outstanding at:

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

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

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

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

Note 9 — Stock Options

Stock Option Plan. On August 10, 2005, we adopted the 2005 Stock Option Plan (the “Plan”), as amended. Stock options under the Plan may be granted to key employees, non-employee directors and other key individuals who are committed to our interests. Options may be granted at an exercise price not less than the fair market value of our common stock at the date of grant. Most options have a five year life but may have a life up to 10 years as designated by the compensation committee of the Board of Directors (the “Compensation Committee”). Typically, options vest 20% on grant date and 20% each year on the anniversary of the grant date but each vesting schedule is also determined by the Compensation Committee. Most initial grants to Directors vest 50% on grant date and 50% on the one-year anniversary of the initial grant date. Subsequent grants (subsequent to the initial grant) to Directors typically vest 100% at the grant date. In special circumstances, the Board may elect to modify vesting schedules upon the termination of selected employees and contractors. We have reserved 40.0 million shares of common stock for the plan. At March 31, 2008 and September 30, 2007, 9.5 and 15.0 million shares, respectively remained available for grant pursuant to the stock option plan. During the three and six months ended March 31, 2008, we granted 5.0 and 8.0 million options under our 2005 stock option plan to directors, employees and consultants performing employee-like services for us. During the three and six months ended March 31, 2007, we granted 1.0 million options under our 2005 stock option plan to directors.

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

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

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

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

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

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

	Number of Shares			Weighted-Average Exercise Price
	(shares in thousands)
Options outstanding — September 30, 2007		9,895		$	0.50
Granted		—			—
Forfeited		(1,260	)		0.50
Options outstanding — March 31, 2008		8,635			0.50
Options exercisable — March 31, 2008		5,181			0.50

Compensation Expense

Under SFAS 123(R), pre-tax stock-based employee compensation expense of $1.0 million and $1.5 million was charged to operations for the three and six months ended March 31, 2008, respectively, and $1.0 million and $1.5 million was charged to operations for the three and six months ended March 31, 2007, respectively. Under EITF 96-18, pre-tax stock-based non-employee compensation expense of $0.0 million and $0.1 million was charged to operations as compensation expense for the three and six months ended March 31, 2008, respectively, and $1.0 and $2.1 million for the three and six months ended March 31, 2008, respectively.

Note 10 — Related Party Transactions

MAB. During the three and six months ended March 31, 2007, we incurred project development costs to MAB under the Development Agreement between us and MAB (see Note 3) in the amount of $0.0 million and $1.8 million, respectively. We did not incur project development costs to MAB during the three and six months ended March 31, 2008. Project development costs to MAB are classified in our consolidated statements of operations as Project development costs — related party. During the three and six months ended March 31, 2008 and 2007, we recorded expenditures paid by MAB on our behalf in the amount of $0.2 million, $0.7 million, $(0.2) million and $0.3 million, respectively. At March 31, 2008 and September 30, 2007, we owed MAB $0.7 million and $1.0 million, respectively, related to project development costs and other expenditures that MAB made on our behalf.

As of March 31, 2008, pursuant to the agreements with MAB and the $13.5 million promissory note issued thereunder (see Note 7), we owed MAB principal and accrued interest of $1.7 million. As of September 30, 2007, we owed MAB principal and accrued interest of $13.0 million under the terms of the promissory note.

At March 31, 2008, we had six separate promissory notes with the Bruner Family Trust (see Note 7) for an aggregate amount of $2.8 million. During the three and six-months ended March 31, 2008, we incurred total interest expense of $0.1 million and $0.1 million, respectively, and paid nothing in principal on these notes.

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

Galaxy. Note receivable- related party on the consolidated balance sheet at September 30, 2007 represents $2.5 million related to a $2.0 million earnest money deposit made by us under the terms of the Galaxy PSA and additional operating costs of $0.5 million that we paid toward the operating costs of the assets we were to acquire plus accrued interest on amounts due to us which were all converted into the Galaxy Note on August 31, 2007. During the six months ended March 31, 2008, the entire $2.5 million has been paid to us by offset against amounts that we owed to MAB. At September 30, 2007, Galaxy owed us $0.3 million and $17,000 related to additional expenses paid by us related to the Galaxy PSA and accrued interest on the Galaxy Note, respectively. During the six months ended March 31, 2008, these amounts have also been paid by offset to amounts we owed to MAB under the MAB Note. Marc A. Bruner is our largest single beneficial shareholder, is a 14.0% beneficial shareholder of Galaxy and is the father of the President and Chief Executive Officer of Galaxy.

Note 11 — Commitments and Contingencies

Contingencies. We may from time to time be involved in various claims, lawsuits, disputes with third parties, actions involving allegations of discrimination, or breach of contract incidental to the operations of its business. We are currently a party to the following legal actions:

As of March 31, 2008, there were 21 parties that had filed liens against our properties. Likewise, we were a party to 10 lawsuits, 9 of which relate to lienholders and one which relates to a lease on the property we intend to sell in connection with the pending property sale to Laramie (see Note 13). In connection with the Laramie transaction described in Note 13, we are required to obtain releases of all of these liens related to the subject property prior to the closing of the transaction. As a result, we have obtained all Release of Lien documents and settlement agreements required from our creditors to resolve these liens and the related disputes. All such documents and agreements will be recorded and become effective upon closing on the sale to Laramie and payment to such creditors. We currently estimate that we will incur costs of approximately $20 million, excluding related legal fees, to resolve these liens and related disputes. See Note 13 for further description of the pending Laramie transaction.

In August 2007, a lawsuit was filed by a law firm in the Supreme Court of Victoria, Australia for the balance of legal fees owed to the law firm in the amount of 0.2 million Australian dollars. The total amount owed was included in accounts payable at September 30, 2007, but has been reduced to less than 0.1 million Australian dollars, as a result of payments made by us.

In December 2007, a lawsuit was filed by a vendor in the Supreme Court of Queensland, Australia for the balance which the vendor claims is owed by us in the amount of 2.4 million Australian dollars. Although we accrued the entire amount of the judgment lien in Accounts payable as of March 31, 2008, this amount is disputed by us on the basis that the vendor breached the contract.

In the event we lose the lawsuit to either or both vendors in the lawsuits filed in Australia and do not pay the amount owed, either of said vendors could obtain a judgment lien and seek to execute on the lien against our assets.

Work Commitments. See Note 4 for commitments related to the drilling of specific wells.

Environmental. While we are not currently subject to environmental-related litigation, the nature of our business is such that we are subject to constantly changing environmental laws and regulations adopted by federal, state and local governmental authorities in both the U.S. and Australia. We would face significant liabilities to the government of other third parties for discharges of oil, natural gas, produced water or other pollutants into the air, oil, or water, and the cost to investigate, litigate and remediate such a discharge could

materially adversely affect our business, results of operations and financial condition. We encourage readers of this filing to review our risk factors disclosed in our Item 1A of our Annual Report on Form 10-K for the year ended September 30, 2007 for further discussion of our environmental risks.

Note 12 — Correction of Errors

During the quarter ended March 31, 2008 and in relation to the filing of this quarterly report, we discovered various errors in our financial statements, and the correction of these errors has been reflected in our second quarter operating results. The characterization of these errors primarily falls into the following categories (a) classification errors in relation to our balance sheet captions; (b) errors relating to the timing of recording various expenses between our first and second quarters; (c) errors in relation to the timing of the recognition of certain liabilities; and (d) an error in relation to the recording of the proceeds received from the sale of our Heavy Oil Projects during the first quarter.

The discovery of these errors has resulted from our ongoing efforts to strengthen our internal controls and to reconcile our accounts, and is reflective of our significant progress to this end. We have evaluated these errors for qualitative and quantitative materiality, and have concluded that these errors do not materially affect our previously reported results. Consequently, we have corrected these errors in the current period.

The aggregate effect of these errors, if corrected in their proper periods, would be to decrease our reported net loss in the first quarter by $0.0 million, and increase our reported net loss in the second quarter by the same amount. Overall, an error in our accounting for unrealized losses on marketable securities was fully offset by a series of errors affecting other costs, primarily general and administrative expenses. Additionally, one of the more significant errors involved a related party transaction, and is discussed in further detail in Note 3.

Finally, the error in relation to the sale of our Heavy Oil Projects, which affected our accounting for marketable equity securities, is discussed in more detail in Note 4. We have provided additional visibility to these two errors in this report, as although we believe these errors are not individually material, we believe the absence of such disclosures in this second quarter report may render our current financial statements confusing or potentially misleading.

Note 13 — Subsequent Events

Laramie Transaction

On April 25, 2008 we signed a binding purchase and sale agreement with Laramie Energy II, LLC (“Laramie”) an unrelated third party for the sale of substantially all of our working interest in our Southern Piceance properties in Colorado, effective as of April 1, 2008. The original closing date target of May 6, 2008 has been extended by the parties to May 31, 2008. A total of up to 1,059 net acres are expected to be transferred to Laramie at closing. We will retain all of our interest in eight producing wells in Garfield County, which are operated by EnCana Oil & Gas (USA), Inc. The total purchase price, prior to adjustments for transaction fees and certain other adjustments as required by the agreement with Laramie (the “Agreement”), is $21.0 million in cash. In addition to customary terms and conditions, the Agreement also requires us to resolve numerous liens and other legal actions brought against us in relation to these properties, and to distribute the majority of the proceeds from the transaction to our trade creditors and others in satisfaction of outstanding claims. We expect to complete the last remaining pre-closing conditions in the near future.

Additionally, we have entered into numerous settlement and release agreements with many of our trade creditors who have placed liens on our Southern Piceance properties, and we have agreed to pay cash for a portion and issue shares of our stock for a portion of the amounts owed to them, and we have further agreed to use our best efforts to file a registration statement with the Securities and Exchange Commission by June 30, 2008 in order to register these shares for resale on the public market. Such agreements are conditioned upon the closing with Laramie.

Upon closing, we will be required to distribute substantially all of the adjusted proceeds in settlement of existing trade obligations and other claims, resulting in expected net proceeds to us of approximately $2.0 million. A total of $0.5 million of our net proceeds will be held in escrow for 90 days to secure our performance under the agreement.

CCES Transactions

On April 11, 2008 we closed the sale of certain natural gas gathering assets for $0.7 million in cash consideration, and simultaneously entered into a Gas Gathering Agreement with CCES Piceance Partners I, LLC (“CCES”) relating to the initial phase of our gas gathering system project. These agreements formalize and expand upon a Letter of Understanding (“LOU”) between the parties which contemplates a dedicated relationship with CCES in the development of a gas gathering system and the provision of Gas Gathering Services within our Buckskin Mesa Project area (the “CCES Agreements”).

In addition to customary terms and conditions, the CCES Agreements include a guarantee (the “Guarantee”) from us to CCES regarding their increasing financial commitments as they are incurred in relation to the development of the gas gathering system, including our contingent repurchase of the gas gathering assets we sold to CCES. The triggering event for the Guarantee is contingent upon our mutual failure to execute a formal agreement for long-term gas gathering services in the future (the “Second Phase Midstream Services Agreement”). The resolution of this contingency is dependent upon, among other things, gas production levels from the initial phase gas gathering system for our Buckskin Mesa Project over the next 12 to 18 months, and other factors as determined by both parties. Should we fail to execute a mutually agreeable long-term contract, CCES has the right to invoice us for their incurred costs and demand repayment within 20 days of our receipt of the Demand Invoice. To secure our Guarantee, we have executed a Promissory Note for an amount up to $11.5 million, secured by second deeds of trust on our Colorado properties that were recorded in the second quarter. The amount of the Guarantee is variable, based upon the underlying incurred costs by CCES as defined in the CCES Agreements, and aggregated $2.8 million as of March 31, 2008.

We have accounted for our Guarantee under the requirements of FASB Interpretation (“FIN”) 45. As of March 31, 2008, we have recorded a current liability and intangible asset in our financial statements, to reflect our Contingent Purchase Obligation relating to the Guarantee. In the event the triggering event does not occur and our obligation lapses, these obligations will be offset against each other. In the event the Guarantee is triggered, we expect to acquire and obtain title to the gas gathering assets, which will then be included in our full cost pool. Our Contingent Purchase Obligation will be adjusted during future periods to its fair value, so long as the contingent Guarantee remains unresolved.

Waiver and Amendment

In April and May 2008, we entered into a Waiver and Amendment Agreement (the “Waiver”) with all of the holders of our Series A 8.5% convertible debentures (see Note 8). The Waiver provides the following:

·	We agree to pay the interest installments due January 1, 2008 and April 1, 2008 (both currently unpaid) by September 30, 2008, together with late fees of 18% per annum.

·	We agree to issue warrants to purchase common stock, having the same terms as the warrants (see Note 8), equal to 4% of the shares each debenture holder (collectively, the “investors”) is entitled to under the debentures.

·	The investors agree to waive our obligation to file a registration statement by March 4, 2008 to be effective July 2, 2008, and extend these dates to June 30, 2008 and December 31, 2008, respectively.

·	The investors agree to waive certain events of default, including the non-payment of interest.

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

The following discussion of our financial condition and results of operations is provided as a supplement to, and should be read in conjunction with, our audited consolidated financial statements, accompanying notes and Item 7 of our Annual Report on Form 10-K for the fiscal year ended September 30, 2007, as well as our unaudited consolidated financial statements and accompanying notes appearing elsewhere in this Form 10-Q.

Executive Summary

We are a development stage global oil and gas exploration and production company committed to acquiring and developing primarily unconventional natural gas and oil prospects that we believe have a very high probability of economic success. Since our inception in 2005, our principal business activities have been raising capital through the sale of common stock and convertible notes and acquiring oil and gas properties in the western United States and Australia. Currently, we own property in Colorado, where we have drilled five wells on our Buckskin Mesa property, Australia, where we have drilled one well on our property in the Northern Territory, and in Montana, where we hold a land position in the Bear Creek area. The wells on these properties have not yet commenced oil production. We also have working interests in eight additional wells in Colorado which are operated by EnCana Oil & Gas USA (“EnCana”). In November 2007, we sold 66,000 net acres of land and two wells in Montana and 177,445 net acres of land in Utah (See Note 14 in Item 1) and subsequent to March 31, 2008, we entered into a binding purchase and sale agreement to sell up to 1,059 net acres of land and 16 wells in the Southern Piceance Basin in Colorado (see Note 13 of the Notes to the Consolidated Financial Statements in Item 1).

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

During the three month period ended March 31, 2008, we found certain adjustments relating to the previous quarter. We assessed the materiality of these adjustments both quantitatively and qualitatively and determined that the effect of these adjustments did not have a material effect on our results of operations or financial condition such that it would render the financial statements or accompanying notes as previously reported misleading. Consequently, these adjustments were made in our fiscal second quarter. Please see Note 12 of the Notes to the Consolidated Financial Statements in Item 1 for a more thorough discussion of these adjustments.

Results of Operations

The following summarizes our results of operations for the three and six-month periods ended March 31, 2008 and 2007:

	Three months ended March 31, 2008			Three months ended March 31, 2007 (restated)			Six months ended March 31, 2008			Six months ended March 31, 2007 (restated)

Revenues	$	705		$	889		$	992		$	1,338
Costs and Expenses
Lease operating expenses		140			224			240			386
General and administrative		3,795			4,331			5,689			8,002
Property development — related party		—			—			—			1,815
Impairment of oil and gas properties		—			3,800			—			8,951
Consulting fees – related party		—			75			—			75
Depreciation, depletion, amortization and accretion		183			827			442			1,213
Total Operating Expenses		4,118			9,257			6,371			20,442
Operating (loss) income		(3,413	)		(8,368	)		(5,379	)		(19,104	)
Other Income (Expense)
Gain on foreign exchange		34			—			11			—
Interest income		26			6			27			14
Interest expense		(2,390	)		(2,004	)		(7,425	)		(2,231	)
Trading Security Losses		(594	)		—			(2,987	)		—
Total other income (expense)		(2,924	)		(1,998	)		(10,374	)		(2,217	)
Net Loss	$	(6,337	)	$	(10,366	)	$	(15,753	)	$	(21,321	)
Net loss per common share — basic and diluted	$	(0.02	)	$	(0.05	)	$	(0.05	)	$	(0.10	)
Weighted average number of common shares outstanding — basic and diluted		316,978			222,562			312,610			221,245

Revenues. During the quarter ended March 31, 2008, revenues declined $0.2 million to $0.7 million, led by a decline in oil and gas revenues of $0.4 million as a result of natural production decline in the wells and to ownership interests in fewer producing wells. This decline was offset by $0.2 million in other revenues, which represent certain services we have provided to Pearl Exploration and Production Ltd. during the quarter, as well as increases in commodity prices.

For the six months ended March 31, 2008, revenues declined $0.3 million to $1.0 million, led by a decline of $0.6 million in oil and gas revenues, as a result of the same factors discussed above.

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

General and Administrative. During the three months ended March 31, 2008, general and administrative expenses were $0.5 million or 12% lower than in the same period of 2007. The following table highlights the changes:

	Three months ended
	2008		2007		Change
	($ in thousands)
Personnel and contract services	$	1,563	$	1,071	$	492
Legal		256		432		(176	)
Stock-based compensation		977		2,056		(1,079	)
Travel		22		313		(291	)
Other		978		459		519
Total	$	3,796	$	4,331	$	(535	)

Overall, the decrease in general and administrative expense from the three-months ended March 31, 2007 to the three months ended March 31, 2008, is primarily due to a $1.1 million decrease in stock-based compensation expense, and a decrease in travel expense of $0.3 million, offset by an increase of $1.0 million in personnel and contract services and other expenses.

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

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

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

Property Development Costs — Related Party. Project development costs of $1.8 million incurred during the six months ended March 31, 2007 relate to development costs we paid to MAB under the Development Agreement (described more fully in Note 3 to the financial statements in Item 1). We no longer pay project development costs to MAB as a result of the restructuring of our agreements with MAB effective January 1, 2007.

Impairment of Oil and Gas Properties. Costs capitalized for properties accounted for under the full cost method of accounting are subjected to a ceiling test limitation to the amount of costs included in the cost pool by geographic cost center. Costs of oil and gas properties may not exceed the ceiling, which is an amount equal to the present value, discounted at 10%, of the estimated future net cash flows from proved oil and gas reserves plus the cost, or estimated fair market value, if lower, of unproved properties. Should capitalized costs exceed this ceiling, an impairment is recognized. During the three and six-month periods ended March 31, 2007, we recognized impairments of $3.8 million and $9.0 million, respectively, representing the excess of capitalized costs over the ceiling, as calculated in accordance with these full cost rules. There were no impairment charges in the quarter and six months ended March 31, 2008.

Depreciation, Depletion, Amortization and Accretion. During the quarter and six months ended March 31, 2008, depreciation, depletion, amortization and accretion declined $0.6 million and $0.8 million, respectively. These decreases were due to adjustments in the previous year to proved reserves. During the fourth quarter of the prior year, our proved reserves were estimated by an independent reservoir engineer. We estimated that, had those reserves been obtained during previous quarters, depreciation, depletion and amortization would have increased by $0.7 million and $1.0 million during the three and six-month periods ended March 31, 2007. The effect of this adjustment did not impact on our net loss for the year as such adjustments were ultimate reflected in impairment of oil and gas properties in the consolidated statements of operations.

Interest Expense. Interest expense increased $0.4 million and $5.2 million during the second fiscal quarter and six-months ended March 31, 2008 compared to the same periods in the previous fiscal year. This increase is attributable to two primary factors as follows:

(i)

higher interest expense associated with warrants on the Series A 8.5% Convertible Debentures we issued in November. Because these warrants are immediately exercisable, we recorded interest expense associated with the warrants of $0.2 million and $3.2 million in the three and six-month periods ended March 31, 2008; and

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

Trading Security Losses. In connection with the sale of certain of our properties to Pearl Exploration and Production Ltd (“Pearl”), we received a portion of the total purchase price in Pearl common stock. The value of these shares declined significantly from the date of the transaction until we sold the shares in March 2008. As a result, we recognized losses associated with these securities of $3.0 million during the six month period ended March 31, 2008. The loss of $0.6 million for the quarter ended March 31, 2008 is net of an adjustment of $0.9 million relating to the correction of an error, as described more fully in Notes 4 and 12 to the Condensed Consolidated Financial Statements in Item 1. We did not have trading securities during the comparable period of the previous year.

Net Loss. Net loss for the quarter ended March 31, 2008 was $6.3 million compared to a loss of $10.4 million during the same period in the previous fiscal year. This $4.1 million change was primarily the result of a $3.8 million impairment charge recorded in the previous year quarter versus no impairment in the current year quarter. Excluding this impairment, net loss changed $0.3 million, primarily as a result of lower general and administrative expenses and depreciation, depletion, amortization and accretion costs in the three months ended March 31, 2008 compared to the same period in the previous year, as described above, partially offset by higher interest expense.

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

Net loss per common share. Net loss per common share was ($0.02) per share in the quarter ended March 31, 2008 compared to ($0.05) per share in the same period in the prior year. This change was driven by a lower net loss and a higher share base primarily due to the issuance of common stock associated with certain of our debt agreements, amendments of certain agreements with MAB, and the issuance of Series A 8.5% convertible debentures.

For the six months ended March 31, 2008, net loss per common share was ($0.05) per share compared to a net loss of ($0.10) per share in the same period of the previous year. This change was driven by a lower net loss and a higher share base, as described above.

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 $88.4 million for the period from inception (June 20, 2005) to March 31, 2008. Likewise, as of March 31, 2008, we had a working capital deficit of approximately $39.8 million, are in default on certain obligations, are not in compliance with the covenants of several loan agreements, and require significant additional funding to sustain our operations and satisfy our contractual obligations for our planned oil and gas exploration and development operations. We have also had multiple property liens and foreclosure actions filed by vendors, some of whom have begun foreclosure proceedings, and have significant capital expenditure commitments. Our ability to establish ourselves as a going concern is dependent upon our ability to obtain additional funding in order to finance our planned operations.

Plan of Operation

Colorado. We expect that the development of our Colorado properties will include the following activities: (i) the tie-in of two wells drilled, cased and completed to date, and the completion and tie-in of three wells drilled and cased to date in the Buckskin Mesa Prospect (four wells drilled and cased during fiscal year 2007; one well drilled and cased during the first quarter ended December 31, 2007; and two of the five drilled wells completed during the current quarter); (ii) the drilling, of a minimum of 13 commitment wells in our greater than 20,000 net acre Buckskin Mesa Prospect leasehold block surrounding the discovery wells for the Powell Park Field

near Meeker, Colorado in the northern Piceance Basin; and (iii) the recompletion and tie-in of the six shut-in gas wells in the Powell Park Field acquired by us from a third party operator.

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

• $40.0 million to $50.0 million in connection with the Piceance II Project, to include expenditures for seismic data acquisition, lease and asset acquisition, drilling, completion, lease operation, and installation of production facilities subject to the Laramie transaction referenced in Note 13 of Item 1.

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

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

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

Liquidity and Capital Resources

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

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

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

As of March 31, 2008, we had a working capital deficit of $39.8 million and cash of $1.6 million. As of September 30, 2007, we had a working capital deficit of $37.9 million and cash of $0.1 million. 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 have sold working interests in some of our properties and we may complete additional private placements of debt or equity to raise cash to meet our working capital needs. A significant amount of additional capital is needed to fund our proposed drilling program for 2008. See "Plan of Operation" above.

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

	Six months ended March 31,
	2008			2007
	($ in thousands)
Net cash used in operating activities	$	(6,420	)	$	(6,712	)
Net cash provided by (used in) investing activities	$	4,753		$	(17,291	)
Net cash provided by financing activities	$	3,152		$	15,073

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

Net Cash Provided by (Used in) Investing Activities. Net cash provided by investing activities for the six months ended March 31, 2008 was primarily from cash received for the sale of oil and gas properties of $7.5 million and the sale of trading securities of $2.5 million offset by cash used for additions to oil and gas properties of $5.3 million. Net cash used in investing activities for the six months ended March 31, 2007 was primarily used for joint interest billings in the amount of $10.6 million, additions to oil and gas properties in the amount of $4.0 million and deposits on oil and gas property acquisitions of $2.2 million.

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

Capital Requirements. We currently anticipate our capital budget for the year ending September 30, 2008 to be approximately $42 million. Uses of cash for 2008 will be primarily for our drilling program in the Piceance Basin and in Australia. Properties in the Piceance II area are expected to be sold in the third quarter 2008. Pursuant to the terms and conditions of the Laramie deal, drilling commitments for Piceance II will be terminated effective the closing date. Capital allocated to the Piceance II area are to be redeployed to the Buckskin Mesa project. The following table summarizes our drilling commitments for fiscal year 2008 ($ in thousands):

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

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

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

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

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

Debenture holders also received five-year warrants that allow them to purchase a total of 46.4 million shares of common stock at prices ranging from $0.24 to $0.27 per share. In connection with the placement of the debentures, we paid a placement fee of $0.3

million and issued placement agent warrants entitling the holders to purchase an aggregate of 0.2 million shares at $0.35 per share for a period of five years.

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. This loan was paid in full in March, 2008.

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

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

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

(6) We entered into a $15.0 million credit facility in January 2007, with Global (the “January 2007 Credit Facility”). The January 2007 Credit Facility is secured by certain oil and gas properties and other assets of ours. It bears interest at prime plus 6.75% and is due to be paid in full in July 2009. We 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 2007 Credit Facility”). The May 2007 Credit Facility is secured by the same certain oil and gas properties and other assets as the January 2007 Credit Facility. The May 2007 Credit Facility bears interest at prime plus 6.75% and is due to be paid in full in November, 2009. We pay an advance fee of 2% on all amounts borrowed under the facility. We may prepay the balance without penalty. We are currently in default on interest payments and not in compliance with the covenants. Global has waived all defaults that have occurred or that might occur in the future until October 2008. At March 31, 2008 we had $42.2 million remaining available to us from the credit facility. The funds borrowed were used to fund our working capital needs.

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

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

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

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

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.

Critical Accounting Estimates

In preparing our condensed consolidated financial statements in conformity with U.S. generally accepted accounting principles, management must undertake decisions that impact the reported amounts and related disclosures. Such decisions include the selection of the appropriate accounting principles to be applied and assumptions upon which accounting estimates are based. Management applies its best judgment based on its understanding and analysis of the relevant circumstances to reach these decisions. By their

nature, these judgments are subject to an inherent degree of uncertainty. Accordingly, actual results may vary significantly from the estimates we have applied.

Our critical accounting estimates are consistent with those disclosed in our Annual Report on Form 10-K for the year ended September 30, 2007. Please refer to Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, in our Annual Report on Form 10-K for the year ended September 30, 2007, for a complete description of our Critical Accounting Estimates.

ITEM 4T. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

During the quarter ended March 31, 2008, we performed an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and our former Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in the Securities Exchange Act of 1934 [the “Exchange Act”]). Based on that evaluation, our management, including our Chief Executive Officer and our former Chief Financial Officer, concluded that our disclosure controls and procedures were not effective to ensure that information required to be disclosed by us in reports we file or submit 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 management, including our Chief Executive Officer and former Chief Financial Officer, to allow timely decisions regarding required disclosure as evidenced by the material weaknesses described below.

As reported in Item 9A of our 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 our management structure to prevent a material misstatement from occurring. Specifically, management did not have an adequate process for monitoring accounting and financial reporting and had not conducted a comprehensive review of account balances and transactions that had occurred throughout the year. Our disclosure controls and accounting processes lack adequate staff and procedures in order to be effective. We have not had adequate staffing to provide for an effective segregation of duties, or to adequately identify and resolve accounting issues and provide information to our auditors on a timely basis. These material weaknesses continued to exist as of March 31, 2008, however, we have taken steps to retain additional senior financial consultants to assist us in completing our remediation of these material weaknesses on an accelerated basis.

We are fully committed to remediating the material weaknesses described above and believe that the steps we are taking, including the active involvement of our Audit Committee in the remediation planning and implementation, will properly address these issues. However, while we are taking immediate steps and dedicating substantial resources to correct these material weaknesses, any new controls we implement must operate for a period of time and be tested before a determination can be made as to their effectiveness. Also, our remediation procedures have identified several errors in our previously issued financial statements, which have resulted in an aggregate overstatement of our first quarter net loss by $0.0 million, and an offsetting understatement of our second quarter net loss by the same amount, as more fully described in Note 12 to our Consolidated Financial Statements. As we continue to proceed through our remediation process, we may discover additional past, ongoing or future material weaknesses or significant deficiencies in our financial reporting processes, or additional errors in our financial statements, some of which could be material.

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

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

Changes in Internal Controls Over Financial Reporting

There have been changes in our internal controls over financial reporting that occurred during the first half of the 2008 fiscal year that have materially affected or are reasonably likely to materially affect our internal controls over accounting and financial reporting in the future. Given our remediation efforts discussed above, we expect further significant changes to our internal controls will occur during the second half of the 2008 fiscal year as we continue to strengthen our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

As of March 31, 2008, we were a party to the following legal proceedings, which are described more fully in Part I - Item 1 - Note 11 Commitments and Contingencies in this Form 10-Q:

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

2. 9 lawsuits have been filed related to these liens.

3. A lawsuit was filed by the lessor of certain of our properties in the Piceance Basin for breach of our lease contract. We are contesting this claim.

4. A lawsuit was filed in August 2007 by a law firm in Australia in the Supreme Court of Victoria for the balance of legal fees owed (0.2 million Australian dollars).

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

Pursuant to the terms of a pending sale of property to Laramie Energy, II, LLC, items 1 and 3 above must be resolved in order to consummate the sale. We currently estimate it will cost approximately $20 million, excluding related legal fees, to resolve those items. The terms of the pending property sale are more fully described in Part I – Item 1 – Note 13 Subsequent Events in this Form 10-Q.

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

ITEM 1A. RISK FACTORS

During the quarter, there were no material changes from the risk factors disclosed in Item 1A our Form 10-K for the fiscal year ended September 30, 2007.

ITEM 6. EXHIBITS


10.25	Charles B. Crowell Employment Agreement (incorporated by reference to Form 8-K filed with the U.S. Securities and Exchange Commission on January 10, 2008)

10.26	$120,000 unsecured promissory note in favor of Bruner Family Trust UTD March 28, 2005 dated February 12, 2008 (incorporated by reference to Form 8-K filed with the U.S. Securities and Exchange Commission on February 19, 2008)

10.27	$100,000 unsecured promissory note in favor of Bruner Family Trust UTD March 28, 2005 dated March 14, 2008 (incorporated by reference to Form 8-K filed with the U.S. Securities and Exchange Commission on March 17, 2008)

10.28	$100,000 unsecured promissory note in favor of Bruner Family Trust UTD March 28, 2005 dated March 18, 2008 (incorporated by reference to Form 8-K filed with the U.S. Securities and Exchange Commission on March 24, 2008)

16.1	Letter from Hein and Associates, LLP regarding change in certifying accountant (incorporated by reference to Form 8-K filed with the U.S. Securities and Exchange Commission on February 4, 2008)

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

31.2	Rule 13a-14(a) Certification of Carmen J. Lotito

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 Carmen J. Lotito Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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

Date: May 15, 2008	By:	/s/ Charles B. Crowell
		Charles B. Crowell
		Chief Executive Officer
		(Principal Executive Officer)



Date: May 15, 2008	By:	/s/ Carmen J. Lotito
		Carmen J. Lotito
		Executive Vice President - Business Development and Director
		(Principal Financial and Accounting Officer)

EXHIBIT INDEX



10.25	Charles B. Crowell Employment Agreement (incorporated by reference to Form 8-K filed with the U.S. Securities and Exchange Commission on January 10, 2008)

10.26	$120,000 unsecured promissory note in favor of Bruner Family Trust UTD March 28, 2005 dated February 12, 2008 (incorporated by reference to Form 8-K filed with the U.S. Securities and Exchange Commission on February 19, 2008)

10.27	$100,000 unsecured promissory note in favor of Bruner Family Trust UTD March 28, 2005 dated March 14, 2008 (incorporated by reference to Form 8-K filed with the U.S. Securities and Exchange Commission on March 17, 2008)

10.28	$100,000 unsecured promissory note in favor of Bruner Family Trust UTD March 28, 2005 dated March 18, 2008 (incorporated by reference to Form 8-K filed with the U.S. Securities and Exchange Commission on March 24, 2008)

16.1	Letter from Hein and Associates, LLP regarding change in certifying accountant (incorporated by reference to Form 8-K filed with the U.S. Securities and Exchange Commission on February 4, 2008)

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

31.2	Rule 13a-14(a) Certification of Carmen J. Lotito

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 Carmen J. Lotito Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002