f10q-phun_063008.htm
 


 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2008

or

[ ]
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[X]     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 [ ]     Smaller reporting company [X]

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

As of July 31, 2008, the registrant had 340,743,469 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 on Form 10-Q 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 the “Risk Factors” section of our Prospectus on Form S-1 filed with the Securities and Exchange Commission (“SEC”) on June 30, 2008 and 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 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 that is 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.


 
2

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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


 
3

 

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

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

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

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

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

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



 
4

 
 


PETROHUNTER ENERGY CORPORATION

FORM 10-Q


INDEX

     
PART I — FINANCIAL INFORMATION
Item 1.
Financial Statements
 
 
Condensed Consolidated Balance Sheets at June 30, 2008 and September 30, 2007 (unaudited).
 
 
Condensed Consolidated Statements of Operations for the three and nine months ended June 30, 2008 and 2007, and the cumulative period from inception to June 30, 2008 (unaudited).
 
 
Condensed Consolidated Statements of Stockholders’ Equity and Comprehensive Loss for the nine months ended June 30, 2008 and the cumulative period from inception to June 30, 2008 (unaudited).
 
 
Condensed Consolidated Statements of Cash Flows for the nine months ended June 30, 2008 and 2007 and the cumulative period from inception to June 30, 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 4.
Submission of Matters to a Vote of Security Holders
 
Item 6.
Exhibits
 
 
Signatures
 




 
5

 
 

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
PETROHUNTER ENERGY CORPORATION
(A Development Stage Company)
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited; $ in thousands, except share and per share amounts)

   
June 30, 2008
   
September 30, 2007
 
ASSETS
Current Assets
           
Cash and cash equivalents
  $ 695     $ 120  
Restricted cash
    531        
Receivables
               
Oil and gas receivables, net
    280       487  
Other receivables
    62       59  
Due from related parties
          500  
GST receivable
    485        
Note receivable — related party
          2,494  
Prepaid expenses and other assets
    406       187  
Total Current Assets
    2,459       3,847  
                 
Property and Equipment, at cost
               
Oil and gas properties under full cost method, net
    146,184       162,843  
Furniture and equipment, net
    422       569  
     Total Property and Equipment
    146,606       163,412  
Other Assets
               
Joint interest billings
          13,637  
Restricted cash
    524       599  
Deposits and other assets
    130        
Deferred financing costs
    1,657       529  
    Intangible asset
    4,142        
Total Assets
  $ 155,518     $ 182,024  
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
               
Notes payable — short-term
  $ 1,055     $ 4,667  
Convertible notes payable
    400       400  
Accounts payable and accrued expenses
    9,873       26,631  
Note payable — related party — current portion
    2,622       3,755  
Note payable — current portion of long-term liabilities
    120       120  
Accrued interest payable
    6,302       2,399  
Accrued interest payable — related party
    18       516  
Due to shareholder and related parties
    440       1,474  
Contract payable — oil and gas properties
          1,750  
Contingent purchase obligation
    4,142        
Total Current Liabilities
    24,972       41,712  
                 
Non-current obligations
               
Notes payable — net of discount
    37,207       27,944  
Subordinated notes payable — related parties
    106       9,050  
Convertible notes payable — net of discount
    684        
Asset retirement obligation
    73       136  
Net Non-current Obligations
    38,070       37,130  
                 
Total Liabilities
    63,042       78,842  
                 
Common Stock Subscribed
          2,858  
Commitments and Contingencies (Note 13)
               
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; 338,065,950 and 278,948,841 shares issued and outstanding at June 30, 2008 and September 30, 2007, respectively
    338       279  
Additional paid-in-capital
    199,968       172,672  
Accumulated other comprehensive gain (loss)
    33       (5 )
Deficit accumulated during the development stage
    (107,863 )     (72,622 )
Total Stockholders’ Equity
    92,476       100,324  
                 
Total Liabilities and Stockholders’ Equity
  $ 155,518     $ 182,024  

See accompanying notes to condensed consolidated financial statements.

 
6

 
 

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited; $ in thousands except per share amounts)

   
Three months
ended
June 30,
2008
   
Three months
ended
June 30,
2007
(restated)
   
Nine months
ended
June 30,
2008
   
Nine months
ended
June 30,
2007
(restated)
   
Cumulative
From Inception
(June 20, 2005) to
June 30, 2008
 
Revenues
                             
Oil and gas revenues
 
$
567
   
$
847
   
$
1,349
   
$
2,285
 
 
$
4,206
 
Other revenues
   
13
     
     
222
     
     
222
 
Total revenues
   
580
     
847
     
1,571
     
2,285
     
4,428
 
                                         
Costs and expenses
                                       
Lease operating expenses
   
164
     
211
     
404
     
597
     
1,201
 
General and administrative
   
2,554
     
5,395
     
8,245
     
13,396
     
41,193
 
Property development — related party
   
     
     
     
1,815
     
7,205
 
Impairment of oil and gas properties
   
     
600
     
     
9,551
     
24,053
 
Consulting fees – related party
   
     
75
     
     
150
     
 
Depreciation, depletion, amortization and accretion
   
334
     
805
     
774
     
2,018
     
2,093
 
Total operating expenses
   
3,052
     
7,086
     
9,423
     
27,527
     
75,745
 
                                         
Loss from operations
   
(2,472
)
   
(6,239
)
   
(7,852
)
   
(25,242
)
   
(71,317
)
Other income (expense):
                                       
Loss from conveyance of property
   
(15,220
)
   
     
(15,220
)
   
     
(15,220
)
Gain on foreign exchange
   
     
     
11
     
     
33
 
Interest income
   
6
     
6
     
33
     
20
     
72
 
Interest expense
   
(1,801
)
   
(846
)
   
(9,226
)
   
(2,677
)
   
(18,444
)
Trading security losses
   
     
     
(2,987
)
   
     
(2,987
)
Total other expense
   
(17,015
)
   
(840
)
   
(27,389
)
   
(2,657
)
   
(36,546
)
Net loss
 
$
(19,487
)
 
$
(7,079
)
 
$
(35,241
)
 
$
(27,899
)
 
$
(107,863
)
Net loss per common share — basic and diluted
 
$
(0.06
)
 
$
(0.03
)
 
$
(0.11
)
 
$
(0.12
)
       
Weighted average number of common shares outstanding — basic and diluted
   
324,147
     
256,906
     
317,811
     
221,802
         

See accompanying notes to condensed consolidated financial statements
 
 
7

 
 

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
Compre-
hensive
   
Total
Stockholders’
   
Total
Compre-
hensive
 
   
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
     
 
 
 

 
8

 

 
   
Common Stock
 
Additional
Paid-in
   
Deficit
Accumulated
During the
Development
   
Accumulated
Other
Compre-
hensive
   
Total
Stockholders’
   
Total
Compre-
hensive
 
   
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
     
 
Shares issued for vendor settlements at $0.20 per share
   
16,879,219
     
17
     
3,723
     
     
     
3,740
     
 
Shares issued for finance costs at $0.20 per share
   
2,037,890
     
2
     
     
     
     
2
     
 
Shares issued for option to purchase CCES
   
400,000
     
     
80
     
     
     
80
     
 
Warrant value associated with amendment & waiver on convertible debt
   
     
     
209
     
     
     
209
     
 
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
     
 
Origination fees on Global debt
   
     
     
1,895
     
     
     
1,895
     
 
Discount on notes payable
   
     
     
336
     
     
     
336
     
 
Foreign currency translation adjustment
   
     
     
     
     
38
     
38
     
38
 
Stock-based compensation
   
     
     
2,138
     
     
     
2,138
     
 
Net loss
   
     
     
     
(35,241
)
   
     
(35,241
)
   
(35,241
)
Balances, June 30, 2008
   
338,065,950
   
$
338
   
$
199,968
   
$
   (107,863
)
 
$
33
   
$
92,476
   
$
(85,019
)

See accompanying notes to condensed consolidated financial statements.
 
 
9

 
 

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited, $ in thousands)
   
Nine months
ended
June 30,
2008
   
Nine months
ended
June 30,
2007
(restated)
   
Cumulative From
Inception
(June 20, 2005)
to June 30,
2008
 
Cash flows used in operating activities
                 
Net loss
 
$
(35,241
 
$
(27,899
)
 
$
(107,868
)
Adjustments used to reconcile net loss to net cash used in operating activities:
Stock for expenditures advanced
   
     
     
100
 
Stock-based compensation
   
2,138
     
7,305
     
20,322
 
Detachable warrants recorded as interest expense
   
813
     
     
813
 
Depreciation, depletion, amortization and accretion
   
774
     
2,268
     
2,092
 
Impairment of oil and gas properties
   
     
4,400
     
24,053
 
Stock for financing costs
   
     
1,338
     
1,623
 
Amortization of discount and deferred financing costs on notes payable
   
2,576
     
458
     
3,612
 
Loss on trading securities
   
2,987
     
     
2,987
 
Loss on conveyance of property
   
15,220
     
     
15,220
 
Gain on foreign exchange
   
(11
)
   
     
(34
)
Changes in assets and liabilities
Receivables
   
6
     
(894
)
   
(540
)
Due from related party
   
(61
)
   
848
     
(3,055
)
Prepaids and other
   
(102
)
   
(54
)
   
(147
)
Deferred financing costs
   
(484
)
   
     
(484
)
Accounts payable, accrued expenses, and other liabilities
   
(5,063
)
   
(2,508
)
   
(209
)
Due to shareholder and related parties
   
(525
)
   
1,291
     
949
 
Net cash used in operating activities
   
(16,973
)
   
(13,447
)
   
(60,089
)
Cash flows provided by (used in) investing activities
                       
Proceeds from CD redemption
   
50
     
     
50
 
Additions to oil and gas properties
   
(21,205
)
   
(13,212
)
   
(70,596
)
Proceeds from sale of oil and gas properties
   
28,066
     
     
28,066
 
Sale of trading securities
   
2,541
     
     
2,541
 
Due from joint interest owner
   
     
(16,274
)
   
 
Deposit on oil and gas property acquisition
   
     
(2,244
)
   
 
Additions to property and equipment
   
(22
)
   
(260
)
   
(22
)
Restricted cash
   
     
475
     
(1,077
)
Net cash provided by (used in) investing activities
   
9,430
     
(31,515
)
   
(44,220
)
Cash flows from financing activities
                       
Proceeds from the sale of common stock
   
     
300
     
35,742
 
Proceeds from common stock subscribed
   
     
2,768
     
2,858
 
Proceeds from the issuance of notes payable
   
8,250
     
31,700
     
39,800
 
Payments on long-term debt
   
(101
)
   
     
(101
)
Borrowing on short-term notes payable
   
1,655
     
     
2,155
 
Payments on short-term notes
   
(6,436
)
   
     
(6,436
)
Payments on contracts payable
   
(250
)
   
     
(250
)
Payments on related party borrowing
   
(1,805
)
   
(600
)
   
(1,805
)
Proceeds from related party borrowing
   
420
     
     
695
 
Proceeds from the exercise of warrants
   
     
     
10,000
 
Cash received upon recapitalization and merger
   
     
     
21
 
Proceeds from issuance of convertible notes
   
6,334
     
     
27,166
 
Offering and financing costs
   
     
180
     
(1,638
)
Net cash provided by financing activities
   
8,067
     
34,348
     
99,207
 
Effect of exchange rate changes on cash
   
(35
)
   
     
(38
)
Net increase (decrease) in cash and cash equivalents
   
575
     
(10,614
)
   
695
 
Cash and cash equivalents, beginning of period
   
120
     
10,632
     
 
Cash and cash equivalents, end of period
 
$
695
   
$
18
   
$
695
 
Supplemental schedule of cash flow information
                       
Cash paid for interest
 
$
1,088
   
$
1
   
$
1,483
 
Cash paid for income taxes
 
$
   
$
   
$
 

See accompanying notes to condensed consolidated financial statements.
 
 
10

 
 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited, dollars in thousands except per share amounts)

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 “Heavy Oil” in Note 4) and on May 30, 2008, we sold 625 net acres, 16 wells which had been drilled but not completed or connected to a pipeline and rights to participate in an additional 8 wells in the Southern Piceance Basin in Colorado (see Note 12).

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 $107.9 million for the period from inception (June 20, 2005) to June 30, 2008, have a working capital deficit of approximately $22.5 million as of June 30, 2008, and were not in compliance with the covenants of several loan agreements. As of June 30, 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 $106.4 million through June 30, 2008 through issuances of common stock and convertible and other debt.

For the three and nine month periods ending June 30, 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.

11

The accompanying financial statements should be read in conjunction with our Registration Statement on Form S-1 filed June 30, 2008 and 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 June 30, 2008 and the consolidated results of our operations and cash flows for the three and nine month periods ending June 30, 2008 and 2007. The results of operations for the three and nine-month periods ending June 30, 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.  We recognized a loss on the disposition of our trading securities in the amount of $3.0 million recorded as Trading Security Losses in our consolidated statement of operations during the nine months ended June 30, 2008.

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. In May 2008, we sold the remaining wells for which we had joint billing arrangements as part of the Laramie transaction, as described further in Note 12.

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 or loss 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 (“SFAS 143”). 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
 
 
12

gas gathering assets we sold to CCES.  We have accounted for this guarantee using Financial Accounting Standards Board (“FASB”) Interpretation No. 45 as amended, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (“FIN 45”) , 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 $4.1 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 nine month periods ended June 30, 2007, we recorded impairment charges of $0.6 million and $9.6 million. We did not impair any of our properties in the three and nine months ended June 30, 2008.

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 change frequently, 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 excluding potential common shares from; stock options, warrants and convertible debt of 221,582 and 61,553 respectively for the periods ended June 30, 2008 and 2007.

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

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements (“SFAS 157”), which provides guidance for using fair value to measure assets and liabilities. The standard also responds to investors’ requests for more information about: (1) the extent to which companies measure assets and liabilities at fair value; (2) the information used to measure fair value; and (3) the effect that fair value measurements have on earnings. SFAS 157 will apply whenever another standard requires (or permits) assets or liabilities to be measured at fair value. SFAS 157 does not expand the use of fair value to any new circumstances. SFAS 157
 
 
13

will be effective for us on October 1, 2008. We have not yet 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 nine months ended June 30, 2008 and 2007, respectively, and cumulative from inception (June 2005) is as follows:

   
 Nine Months Ended June 30, 2008
Nine Months Ended June 30, 2007 (restated)
 
Cumulative From Inception (June 20, 2005) to June 30, 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
  $ 3,376     $     $ 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
  $ 2,037     $     $ 9,644  
Non-cash uses of notes payable, accounts payable and accrued liabilities
  $     $     $ 26,313  
Convertible debt issued for property
  $     $     $ 1,200  
Common stock issuable
  $     $ 4,510     $  
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 equity and forgiveness of related party notes payable
  $ 15,959     $     $ 15,959  
Satisfaction of receivable by reduction of related party note payable
  $ 3,202     $     $ 3,202  
Debt discount related to convertible debt
  $ 6,956     $     $ 6,956  
Increase in oil and gas properties related to relief of joint interest billings
  $ 12,608     $     $ 12,608  
Warrants issued recorded as debt discount
  $ 729     $ 3,952     $ 5,220  
Warrants issued recorded as deferred finance costs
  $ 1,898     $     $ 1,898  
Common stock issued for purchase option    80         $ 80  

Note 3 — Agreements with MAB Resources LLC

We were a party to various agreements (the “MAB Agreements”) with MAB Resources LLC (“MAB”), a company that is controlled by our largest beneficial shareholder, Marc A. Bruner.  All the MAB Agreements described below were terminated as of June 30, 2008.  The following is a summary of those prior MAB 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:
 
 
14

 
·   
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:
o   
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.

Effective June 30, 2008, MAB sold all its interest in the above-mentioned overriding royalty (in our Buckskin Mesa and Australian properties) to a third party.

Note 4 — Oil and Gas Properties

Oil and gas properties consisted of the following:
 
June 30,
2008
   
September 30,
2007
 
Oil and gas properties, at cost, full cost method
 
($ in thousands)
 
Unproved
           
United States
 
$
73,738
   
$
107,239
 
Australia
   
25,350
     
23,569
 
Proved – United States
   
48,794
     
57,168
 
Total
   
147,882
     
187,976
 
Less accumulated  depreciation, depletion, amortization and impairment
   
    (1,698
)
   
(25,133
)
Total
 
$
146,184
   
$
162,843
 
 
Included in oil and gas properties above is capitalized interest of $0.0 million and $0.8 million for three months ended June 30, 2008 and 2007, respectively.  In the nine months ended June 30, 2008 and 2007, oil and gas properties included capitalized interest of $0.2 million and $1.1 million, respectively.

Included below is a summary of significant activity related to oil and gas properties during the three and nine month periods ended June 30, 2008.

15

PICEANCE BASIN

Buckskin Mesa Project. As of June 30, 2008, we had drilled five wells, with two wells having been completed and shut-in, awaiting installation 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. Prior to June 30, 2008 (the due date for commencing the next four wells), we determined that we could not obtain the materials necessary to commence such operations by June 30, and we provided written notice of such force majeure condition to DPC.  We were otherwise prepared to comply with all obligations regarding the referenced commitment.  DPC objected to the notice. On June 30, 2008, we filed an action in Denver District Court requesting the court to issue a declaratory judgment concerning this dispute. See Note 11 for further discussion of this case. As of June 30, 2008, we had not recorded a loss with respect to this case as we believe we are in full compliance with our contractual obligations.

Piceance II Project. On May 30, 2008, we completed the sale of 625 net acres of land, 16 wells which had been drilled but not completed or connected to a pipeline and rights to participate in an additional 8 wells to Laramie Energy II, LLC, as described more fully in Note 12.  Additionally, as of June 30, 2008, as part of this transaction, we held $0.8 million in escrow relating to a dispute between us and the lessor of 435 acres of land in the Southern Piceance in which the lessor of this land claims that the lease will be terminated in conjunction with the Laramie transaction, as described more fully in Notes 11 and 12.  On August 1, 2008, we transferred the $0.8 million in escrow back to Laramie and retained the 435 acres of land relating to the escrowed amount.  We still retain all of our interest in eight producing wells in Garfield County, which are operated by EnCana Oil & Gas (USA) Inc.

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

Beetaloo 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.

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 received an extension on our drilling commitments related to this property and are currently committed to drill 8 wells in 2009 at a total estimated cost of $36 million. We are not currently committed to drilling any wells on this property in 2008.

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).
 
 
16

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 all of our interest in our Heavy Oil Projects, including the West Rozel, Fiddler Creek and Promised Land Projects in Utah and Montana, 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 June 30, 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 nine months ended June 30, 2008.  

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.
 
 
17

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

   
June 30,
2008
   
September 30,
2007
 
   
($ in thousands)
 
Beginning asset retirement obligation
 
$
136
   
$
522
 
    Liabilities incurred
   
1
     
30
 
    Liabilities settled
   
(35
)
   
 
    Revisions to estimates
   
(27
   
(429
)
    Accretion expense
   
(2
   
13
 
Ending asset retirement obligation
 
$
73
   
$
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.

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 nine months ended June 30, 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:

   
June 30, 2008
   
September 30, 2007
 
   
($ in thousands)
 
Notes payable – short-term:
           
Shareholder note
 
850
   
 
Vendor
   
     
4,050
 
Global Project Finance AG
   
     
500
 
Flatiron Capital Corp.
   
205
     
117
 
Notes payable – short-term
 
$
1,055
   
$
4,667
 
Convertible notes payable
 
$
400
   
$
400
 
Notes payable – related party – current portion:
               
Bruner Family Trust
 
$
2,622
   
$
 
MAB- current portion
   
     
3,755
 
Notes payable – related party – current portion
 
$
2,622
   
$
3,755
 
Subordinated notes payable — related party:
               
Bruner Family Trust
 
$
106
   
$
275
 
MAB
   
     
8,775
 
 
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Subordinated notes payable — related party
 
$
106
   
$
9,050
 
Long-term notes payable — net of discount:
               
Global Project Finance AG
 
$
39,800
   
$
31,550
 
Vendor
   
149
     
250
 
Less current portion
   
(120
)
   
(120
)
Discount on notes payable
   
(2,622
)
   
(3,736
)
Long-term notes payable — net of discount
 
$
37,207
   
$
27,944
 
Convertible debt
 
$
6,956
   
$
 
Discount on convertible debt
   
(6,272
)
   
 
Convertible debt — net of discount
 
$
684
   
$
 

RECENT DEBT ACTIVITY

Laramie Transaction.  On May 30, 2008, we sold substantially all of our working interest in our Southern Piceance properties in Colorado (see Notes 4, 11 and 12).  In conjunction with this sale, we entered into numerous settlement and release agreements with many of our trade creditors, some of whom had previously entered into promissory notes with us.  Specifically, with respect to settlements on notes previously outstanding:

(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 bore interest at 14% per annum if paid current. Upon our default on the note, the interest rate increased to 21% per annum.  In conjunction with the Laramie transaction, we paid $6.3 million in cash and issued 10 million shares of our common stock to this vendor in full satisfaction of all amounts owed by us to this vendor including the note as well as other amounts owed.

(ii) In October 2007, we entered into another promissory note with a vendor for outstanding account payable balances. The note bore interest at 8.25% per annum, which increased to 10.25% upon default and was due to mature February 29, 2008.  In conjunction with the Laramie transaction, we paid $0.2 million to this vendor in full satisfaction of all amounts owed by us to this vendor.

Both of the notes described above were classified as Vendor notes in the table above as of September 30, 2007.

Vendor.  On January 29, 2008 an unsecured promissory note with a vendor was entered into for past due invoices aggregating $0.1 million. The note bore interest at an annual rate of 8%. On April 8, 2008, we satisfied this note with full payment of principal and interest.

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.

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 bore interest at a rate of 7.25% per annum. Payments were due in 10 equal installments of $17,000, commencing on July 1, 2007 and maturing on April 1, 2008. The note was unsecured and the note was paid in full in April 2008.

On June 6, 2008, we entered into another 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 4.15% per annum.  We made a down payment of $0.1 million at the inception of the loan.  Monthly payments are due in 11 equal installments commencing in July 2008. The note is unsecured and we are current in our payments

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 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 bore interest at an annual rate equal to LIBOR and was due to mature on January 1, 2010.  At June 30, 2008, we had repaid the note in full and applied a $0.1 million overpayment towards the balance of notes outstanding with the Bruner Family Trust, discussed below.

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.
 
Wealth Preservation. On January 25, 2008, we borrowed $0.1 million under a promissory note. The note bore interest at 15% per annum, provided the note was not in default, in which case the interest rate increased to 24% per annum, and was due on February 29, 2008. This principal balance and accrued interest of $4,000 was paid in full in April 2008.
 
 
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OTHER OUTSTANDING DEBT

Short - Term Notes Payable

Shareholder Note. During the second fiscal quarter of 2008, we entered into an agreement to borrow $0.9 million from a shareholder with interest to accrue at a rate of 15% per annum.  All principal and accrued interest amounts are due in full on August 31, 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 bore interest at 12% per annum, were unsecured, and were 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. Subsequent to June 30, 2008 we received notice from the lender of its intent to convert the loans into common stock, as described in Note 15.

Notes Payable – Related Party

Bruner Family Trust. As of September 30, 2007, we had entered into two promissory notes with the Bruner Family Trust in the amount of $0.3 million which each accrue interest at 8% per annum and are 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.  At June 30, 2008, total principal and accrued interest related to these notes was $0.1 million and was classified as long term on our consolidated balance sheets.

During the 2008 fiscal year, we entered into four more promissory notes with the Bruner Family Trust with principal amounts aggregating $2.7 million.  Each of these notes accrues interest at the LIBOR plus 3% per annum and are due 12 months from each note’s respective issue date.  The largest of these notes, aggregating $2.3 million in principal and interest as of June 30, 2008, is due November 13, 2008, with the remaining three notes, aggregating $0.3 million in principal and accrued interest as of June 30, 2008, due in February and March 2009.  As of June 30, 2008, all principal and accrued interest related to these notes were classified as current on our consolidated balance sheets.

Long-Term Notes Payable

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 June 30, 2008, the balance of this note was $0.2 million.

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 June 30, 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 4.7%; and (v) an expected life of 5 years. The fair value of the warrants 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
 
20

 
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 June 30, 2008, $24.8 million has been advanced to us under this facility. The advance fee in the amount of $0.6 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 76.0%; (iv) risk free interest rate of 2.2% to 4.9%; and (v) expected life of 2.0 to 2.5 years. The fair value of the warrants issuable as of June 30, 2008 was recorded as a discount to the note and is being amortized over the life of the note.

On May 12, 2007, we issued a “most favored nation” letter to Global which indicated that 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 June 30, 2008, we would have been in default of payments to Global in the amount of $6.1 million, which consists of unpaid interest and fees under the Global Credit Facilities, and we would have been out of compliance with various financial and debt covenants under these Facilities.  However, prior to any such default and non-compliance event or condition occurring, Global waived and released PetroHunter from any and all defaults, failures to perform, and any other failures to meet its obligations through July 1, 2009.

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 $0.28 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. 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. We defaulted on interest payments due January 1, 2008 and April 1, 2008 and as a result, we obtained a waiver and amendment from Debenture holders under which the defaults were waived in consideration for the issuance of warrants and an agreement to pay the interest and related late fees in September 2008.  This waiver and amendment is described more fully below. As of the date of filing, we were in default on our July 1, 2008 scheduled interest payment.

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

A waiver and amendment agreement relating to the above Registration Rights Agreement was signed by all investors 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
 
21

 
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 warrants each purchaser received with the original agreement. The terms of these warrants mirror the terms given in the original agreement.  Pursuant to this waiver and amendment, we filed a registration statement on June 30, 2008, which is expected to become effective in August 2008.  Further, we recorded $0.2 million in costs related to the warrants issued under the waiver and amendment, which is reflected as a discount to debt and is being amortized over the life of the warrants.

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 an additional discount to the debt in the amount of $3.5 million which will be accreted to interest expense over the term of the notes.

During the preparation of our financial statements for the third quarter ended June 30, 2008, we noted that as of July 1, 2008, we were still in default of various provisions as set forth in the November 2007 Debenture agreement. In April, May, and August 2008 the investors granted waivers for certain provisions for which we were in default. Although the waiver granted to us does not cure all of the defaults as of July 1, 2008 we do not believe that the investors will enforce the terms of the Debentures,  as the enforcement of the terms is of no economic benefit to either the investors or to us. Accordingly, no adjustments or reclassifications have been recorded by us in our condensed consolidated financial statements as of June 30, 2008 to reflect the defaults, as we feel that the investors will continue to work with us.

Provided that there is an effective registration statement covering the shares underlying the Debentures, or the shares are otherwise eligible for resale without restriction under Rule 144, 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.

During the preparation of our financial statements for the third quarter ended June 30, 2008, we discovered a significant error that affected our accounting for the Debentures, as more fully described in Note 14.  During our first quarter, when the convertible Debentures were funded, we had erroneously concluded that the relative fair value of the detachable warrants of $2.9 million needed to be immediately expensed to interest expense in full. We subsequently determined that the immediate expensing of the full value of the warrants should have been capitalized as a discount against the face value of the Debentures, and amortized over their five year lives using the effective interest method.

We recorded a correcting entry during the third quarter to correct the accounting for the value associated with the warrants, including those adjustments to appropriately state the cumulative amortization of the discount. The effect of the correction was to reduce interest expense, and reduce the reported book value of the Debentures by $2.8 million during the third quarter, representing the correction of a $2.9 million overstatement of interest expense during the first quarter, and an understatement of interest expense of $0.1 million during the second quarter. The aggregate effect of all errors we have discovered in the preparation of our quarterly filings on Form 10-Q for fiscal 2008 are shown in detail in Note 14.

Note 8 — Stockholders’ Equity

Common Stock. During the nine months ended June 30, 2008, we issued 65.5 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 (see Note 4)
·   
0.2 million shares issued at $0.28 per share for transaction finance costs
·   
16.9 million shares issued at $0.20 per share for settlements with various vendors and lienholders (see Note 12)
·   
2.0 million shares issued at $0.20 per share for transaction finance costs (see Note 12)
·   
0.4 million shares issued at $0.20 per share for the option to purchase shares of CCES (see Note 13)
·   
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

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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 nine months ended June 30, 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 offer those investors the opportunity to rescind their subscriptions or to participate on the same terms as the Debenture offering, with interest to be paid at 8.5% from the date the original funds were received to the date of the subscription of Debentures (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:

   
June 30,
2008
   
September 30,
2007
 
   
(warrants in thousands)
 
                 
Number of warrants
   
134,827
     
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 $0.28 per share. In April 2008, the Debenture holders also received warrants to purchase a total of 1.9 million shares at prices ranging from $0.24 to $0.28 per share in consideration for their agreement to a waiver and amendment (see Note 7). As of June 30, 2008, none of these warrants had been exercised and the total value of these warrants, based on valuation under the Black-Scholes method was $7.4 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 $0.0 million.

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 $1.4 million.

During the nine months ended June 30, 2008 we issued 3.3 million warrants valued at $0.5 million using the Black-Scholes method in connection with amounts borrowed against our credit facility.

During the preparation of our financial statements for the third quarter ended June 30, 2008, we discovered an error in our calculations of the determination of the relative fair value of our detachable warrants associated with our Global Credit Facilities, and an error in recording deferred financing costs for warrants that were not issued directly in relation to making advances on the Facility, and instead were issued in connection with securing the Facilities. In applying the Black-Scholes method to calculate their estimated fair value, we erroneously used warrant term assumptions that were less than the contractual life of the warrants, which understated the initial value of the warrants, in addition to failing to record deferred financing costs as a deferred charge. The effect of the correction of this error was to increase the recorded discount against the Global Credit Facility by $0.0 million, and record $1.8 million in deferred financing costs to account for the difference in the relative fair value of the warrants. The correction of this error resulted in our recording an additional $0.4 million in interest expense in the third quarter, with a corresponding understatement of recorded interest expense during our first and second quarters. The aggregate effect of all errors we have discovered in the preparation of our quarterly filings on Form 10-Q for fiscal 2008 are shown in detail in Note 14.

 

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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 and each vesting schedule is also approved 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 June 30, 2008 and September 30, 2007, 9.25 and 15.0 million shares, respectively, remained available for grant pursuant to the stock option plan. During the three and nine months ended June 30, 2008, we granted .3 and 8.3 million options under our 2005 stock option plan to directors, employees and consultants performing employee-like services for us. During the three and nine months ended June 30, 2007, we granted 1.2 and 2.2 million options, respectively, under our 2005 stock option plan to directors, employees and consultants.

A summary of the activity under the Plan for the nine months ended June 30, 2008 is presented below:

   
Number of
Shares
   
Weighted-
Average
Exercise Price
 
   
(shares in thousands)
 
                 
Options outstanding — September 30, 2007
   
24,965
   
$
1.31
 
Granted
   
8,235
     
0.21
 
Forfeited
   
(2,465
)
   
1.76
 
Options outstanding — June 30, 2008
   
30,735
     
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 nine months ended June 30, 2008.

 
2008
Expected option term — years
3.75 - 4.0
Risk-free interest rate
   1.62% - 4.20%
Expected dividend yield
   0
Weighted-average volatility
    71% - 79%
 
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 nine months ended June 30, 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
   
(2,300
)
   
0.50
 
Options outstanding — June 30, 2008
   
7,595
     
0.50
 
Options exercisable — June 30, 2008
   
5,666
     
0.50
 
 
Compensation Expense

Non-cash stock-based compensation expense of $0.5 million and $2.1 million was recognized during the three and nine months ended June 30, 2008. Stock-based compensation expense of $3.4 million and $7.3 million was recognized during the three and nine months ended June 30, 2007. Stock-based compensation expense is included in general and administrative expenses in the consolidated statements of operations.

24

Note 10 — Related Party Transactions

MAB. During the three and nine months ended June 30, 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 nine months ended June 30, 2008. Project development costs to MAB are classified in our consolidated statements of operations as Project development costs — related party. During the three and nine months ended June 30, 2007, we recorded expenditures paid by MAB on our behalf in the amount of $0.4 million and $0.6 million, respectively. At June 30, 2008 and September 30, 2007, we owed MAB $0.0 million and $1.0 million, respectively, related to project development costs and other expenditures that MAB made on our behalf.
 
As of June 30, 2008, we had paid off the $13.5 million promissory note issued pursuant to the agreements with MAB (see Note 7). As of September 30, 2007, we owed MAB principal and accrued interest of $13.0 million under the terms of the promissory note.

At June 30, 2008, we had six separate promissory notes with the Bruner Family Trust (see Note 7) for an aggregate principal amount of $2.7 million. During the three and nine months ended June 30, 2008, we incurred total interest expense of $0.0 million and $0.1 million, respectively. In June 2008 we offset $0.2 million in receivables from entities controlled by our single largest beneficial shareholder against the balance of these loans pursuant to an agreement between the entities.

Wealth Preservation. On January 25, 2008, we borrowed $0.1 million under a promissory note with an entity controlled by 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 nine months ended June 30, 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 nine months ended June 30, 2008, these amounts have also been paid by offset to amounts we owed to MAB under the MAB Note. Marc A. Bruner, 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 our business. We are currently a party to the following legal actions:

·   
One vendor has filed a lien applicable to our properties in Rio Blanco County, Colorado, for $0.2 million.
·   
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). As of June 30, 2008, we had made payments such that we have no liability left pursuant to the claims in this lawsuit and the lawsuit was pending dismissal.
·   
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 (3.8 million Australian dollars). We disputed the claim on the basis that the vendor breached the contract.  As of June 30, 2008, we were in the final stages of negotiating a written settlement agreement which provides that we will pay 3.5 million Australian dollars as part of the settlement.  This