f10k-2009_phun.htm
 
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-K

(Mark One)
  
þ
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended September 30, 2009
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
incorporation or organization)
(I.R.S. Employer
Identification No.)


1600 Stout Street, Suite 450
80202
Denver, Colorado
(Zip Code)
(Address of principal executive offices)
  

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

Securities registered pursuant to Section 12(b) of the Act:
None

Securities registered pursuant to Section 12(g) of the Act:
Common Stock, $0.001 par value
(Title of class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.¨ Yes ý No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.
¨ Yes                      ý No

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 past 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.
ý Yes                      ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
¨ Yes                      ¨ No (not required)

 
 
 


Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨

 
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 definitions of “large accelerated filer,” “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 þ   

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

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter: $3,525,943 as of March 31, 2009.

As of December 31, 2009, the registrant had 380,468,544 shares of common stock outstanding.


FORWARD-LOOKING STATEMENTS

Certain statements contained in this Annual Report constitute “forward-looking statements”. These statements, identified by words such as “plan”, “anticipate”, “believe”, “estimate”, “should”, “expect” and similar expressions include our expectations and objectives regarding our future financial position, operating results and business strategy. These statements reflect the current views of management with respect to future events and are subject to risks, uncertainties and other factors that may cause our actual results, performance or achievements, or industry results, to be materially different from those described in the forward-looking statements. Such risks and uncertainties include those set forth under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operation” and elsewhere in this Annual Report. We do not intend to update the forward-looking information to reflect actual results or changes in the factors affecting such forward-looking information. We advise you to carefully review the reports and documents we file from time to time with the Securities and Exchange Commission (the “SEC”).

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


CURRENCIES

All amounts expressed herein are in U.S. dollars.



 
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GLOSSARY

Certain Definitions

Terms used to describe quantities of oil and natural gas and marketing

·  
Bbl — 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.
 
·  
BOE— One barrel of oil equivalent, converting natural gas to oil at the ratio of 6 Mcf of natural gas to 1 Bbl of oil.
 
·  
MBbl — One thousand barrels.
 
·  
Mcf — One thousand cubic feet of natural gas.
 
   ·  
Mcfe— One thousand cubic feet of natural gas equivalent, converting oil or condensate to natural gas at the ratio of 1 Bbl of oil or condensate to 6 Mcf of natural gas.
 
·  
MMcf — One million cubic feet of natural gas.
 
·  
MBOE — One thousand BOE.
 
Terms used to assign a present value to the Company’s reserves

·  
Standardized measure of discounted future net cash flows, after income taxes — The present value, discounted at 10%, of the after-tax future net cash flows attributable to estimated net proved reserves.  The Company calculates this amount by assuming that it will sell the oil and natural gas production attributable to the proved reserves estimated in its independent engineer’s reserve report for the oil and natural gas spot prices on the last day of the year, adjusted for quality and transportation. The Company also assumes that the cost to produce the reserves will remain constant at the costs prevailing on the date of the report. The assumed costs are subtracted from the assumed revenues resulting in a stream of future net cash flows. Estimated future income taxes, using rates in effect on the date of the report, are deducted from the net cash flow stream. The after-tax cash flows are discounted at 10% to result in the standardized measure of the Company’s proved reserves.
 
·  
Standardized measure of discounted future net cash flows before income taxes — The discounted present value of proved reserves is identical to the standardized measure described above, except that estimated future income taxes are not deducted in calculating future net cash flows. The Company discloses the discounted present value without deducting estimated income taxes to provide what it believes is a better basis for comparison of its reserves to the producers who may have different income tax rates.

   Terms used to classify the Company’s reserve quantities

The Securities and Exchange Commission (“SEC”) definition of proved oil and natural gas reserves, per Regulation S-X, is as follows:

•   
Proved oil and natural gas reserves — Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made as defined in Rule 4-10(a)(2).

Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

3


•    
Proved developed reserves —Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods as defined in Rule 4-10(a)(3).

•    
Proved undeveloped reserves —Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required as defined in Rule 4-10(a)(4).

Terms used to describe the legal ownership of the Company’s oil and natural gas properties

                 •
Working interest — A real property interest entitling the owner to receive a specified percentage of the proceeds of the sale of oil and natural gas production or a percentage of the production, but requiring the owner of the working interest to bear the cost to explore for, develop and produce such oil and natural gas. A working interest owner who owns a portion of the working interest may participate either as operator or by voting its percentage interest to approve or disapprove the appointment of an operator and drilling and other major activities in connection with the development and operation of a property.

 
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PETROHUNTER ENERGY CORPORATION

FORM 10-K

FOR THE FISCAL YEAR ENDED
SEPTEMBER 30, 2009
INDEX

   
Page
PART I
  
Item 1.
Business
6
Item 1A.
Risk Factors
9
Item 1B.
Unresolved Staff Comments
12
Item 2.
Properties
12
Item 3.
Legal Proceedings
14
Item 4.
Submission of Matters to a Vote of Security Holders
14
PART II
  
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
15
Item 6.
Selected Financial Data
15
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operation
15
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
23
Item 8.
Financial Statements and Supplementary Data. 
23
Item 9.
Changes In and Disagreements With Accountants on Accounting and Financial Disclosure
52
Item 9A(T).
Controls and Procedures
53
Item 9B.
Other Information
55
PART III
  
Item 10.
Directors, Executive Officers and Corporate Governance
55
Item 11.
Executive  Compensation
57
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
59
Item 13.
Certain Relationships and Related Transactions, and Director Independence
61
Item 14.
Principal Accounting Fees and Services
63
PART IV
  
Item 15.
Exhibits, Financial Statement Schedules
65


 
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PART I

ITEM 1.  
BUSINESS

General

PetroHunter Energy Corporation (collectively, with its subsidiaries, referred to herein as “PetroHunter”, “Company”, “we”, “us” or “our”), formerly Digital Ecosystems Corp. (“Digital”), is an oil and gas exploration and production company, which currently holds oil and gas interests located in the Piceance Basin of Western Colorado, and in the Beetaloo Basin in the Northern Territory in Australia.  Since our inception in 2005, our business activities have been financed by raising capital through the sale of common stock, and through the issuance of notes and convertible notes. 

Digital was incorporated on February 21, 2002, under the laws of the State of Nevada. On February 10, 2006, Digital entered into a Share Exchange Agreement (the “Agreement”) with GSL Energy Corporation (“GSL”) and certain shareholders of GSL pursuant to which Digital acquired more than 85% of the issued and outstanding shares of common stock of GSL, in exchange for shares of Digital’s common stock. On May 12, 2006, the parties to the Agreement completed the share exchange and Digital changed its business to the business of GSL. Subsequent to the closing of the Agreement, Digital acquired all the remaining outstanding stock of GSL, and effective August 14, 2006, Digital changed its name to PetroHunter Energy Corporation and reincorporated under the laws of the State of Maryland.

As a result of the Agreement, GSL became a wholly-owned subsidiary of PetroHunter. Since this transaction resulted in the former shareholders of GSL acquiring control of PetroHunter, for financial reporting purposes the business combination was accounted for as an additional capitalization of PetroHunter (a reverse acquisition with GSL as the accounting acquirer).

In October 2006, GSL Energy Corporation changed its name to PetroHunter Operating Company. In March 2006, GSL acquired a 50% interest in four exploration permits held by Sweetpea Corporation Pty Ltd. (“Sweetpea”), an Australian corporation; and effective January 1, 2007, we acquired 100% of the common shares of Sweetpea from MAB Resources, LLC (“MAB”), a Delaware limited liability company which is also in the business of oil and gas exploration and development, and is our largest shareholder. Sweetpea is the record owner of four exploration permits issued by the Northern Territory of Australia. On October 20, 2006, PetroHunter formed PetroHunter Energy NT Ltd., also known as PetroHunter Australia Ltd. (“PetroHunter Australia”) for the purpose of holding and developing its assets in Australia, but no assets were assigned into PetroHunter Australia. In May 2007, we approved the dissolution of PetroHunter Australia.

Through September 30, 2009 Sweetpea has sold 75% of its original 100% working interest to Falcon Oil & Gas Australia Pty Ltd (“Falcon Australia”).  PetroHunter currently owns a 25% working interest in the four exploration permits covering 7 million acres in Australia, including one well (known as the Beetaloo Basin Project), and a 100% working interest in leases covering 20,000 acres and ten wells in the Piceance Basin in Western Colorado. These oil and gas wells have not yet commenced oil and gas production.

During fiscal 2010, Sweetpea began the process of selling its remaining 25% working interest in the Beetaloo Basin project in Australia to Falcon Australia in order to consolidate the interest in this property to facilitate its further financing. In consideration, Sweetpea will receive 25% of the shares in Falcon Australia, which currently owns the other 75% working interest and operates the project (See Note 14 - Subsequent Events of the Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data).

Our annual report on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, as well as any amendments to such reports and all other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available free of charge to the public on the Company’s website at www.petrohunter.com. To access the Company’s SEC filings, select “SEC FILINGS” under the INVESTOR RELATIONS tab on the Company’s website. You may also request a copy of these filings at no cost by making written or telephone requests for copies to our principal executive offices at PetroHunter Energy Corporation, Investor Relations, 1600 Stout Street, Suite 450, Denver, CO 80202. The telephone number is (303) 572-8900 and the facsimile number is (303) 893-4838. Our
 
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periodic and current reports filed with the SEC can be found on our website and on the SEC’s website at www.sec.gov.

Business Strategy

During the period ended September 30, 2009, we continued to focus our efforts in two core properties: the Beetaloo Basin in Australia and the Piceance Basin, of Western Colorado.  We also focused on improving our liquidity. We sold additional working interests in the Beetaloo Basin and the Piceance Basin to Falcon Oil & Gas Ltd. (“Falcon”), a related party, as follows. In September 2008, we closed on an agreement with Falcon to sell a 50% working interest in the Beetaloo Basin and sold an additional 25% working interest in the Beetaloo Basin to Falcon in June 2009.  In August 2008, we closed a transaction with Falcon selling a 25% working interest in five wells located within our 20,000-acre Buckskin Mesa Project located in the Piceance Basin, in Western Colorado. As a component of this sale Falcon had an option to purchase an additional 50% interest in these wells.  In February 2009, Falcon decided not to pursue this project or participate in the purchase of an additional 50% interest. As a result of Falcon’s election, in accordance with our agreements, Falcon assigned the 25% working interest back to us. We are in the process of pursuing other potential partners in relation to our Buckskin Mesa Project.

Australia

Beetaloo Basin Project
 
As of September 30, 2009, Sweetpea, our wholly-owned Australian subsidiary, owned a 25% non-operated working interest in four exploration permits in the Northern Territory, comprising the Beetaloo Basin Project, operated by Falcon. Sweetpea participated in the deepening of the Shenandoah #1A during the year ended September 30, 2009. During September 2007, Sweetpea had drilled that well (as 100% working interest owner and operator as the Shenandoah #1) to a total depth of 1,555 meters (4,740 feet). We are very encouraged with the results of the logging program that was conducted after the well was deepened to 2,714 meters (8,904 feet), and we plan further testing/deepening activities for 2010.

We have also applied for two additional exploration permits in the Northern Territory in Australia covering an additional 1.5 million acres that are adjacent to our Beetaloo Basin Project acreage. We continue to await the outcome of the application for these permits.

Northwest Shelf Project
 
In March 2007, Sweetpea acquired Exploration Permit #WA-393-P in the Barrow Sub-Basin of the Carnavon Basin on the Northwest Shelf of Australia.  Sweetpea did not carry out the required work program associated with this permit and this permit was cancelled during the year ended September 30, 2009.

Piceance Basin, Colorado

Buckskin Mesa Project
 
The Buckskin Mesa Project area was purchased on September 17, 2005 from MAB Resources, subject to certain agreements with Daniels Petroleum Company ("DPC").  The property is located in the northern part of the Piceance Basin in Rio Blanco County, Colorado.  The acquisition included 20,000 net acres and five previously drilled that were shut-in. PetroHunter drilled five wells on this acreage during the years ended September 30, 2007 and 2008. We attempted to complete three of these wells in the quarter ending March 31, 2009; however we were not successful in completing these three wells. All ten wells are shut-in.

Per the agreement with DPC we were required to drill 5 additional wells by July 31, 2009, or pay DPC $2 million, or return these leases to DPC. We did not drill these additional five wells. Global Project Finance AG (“Global”) holds a first lien on this leasehold interest as described in Note 8 – Notes Payable, in the Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data. We are in the process of negotiating a mutually agreeable alternative to assigning the leases back with Daniels in order to be able to further explore for oil and gas on this leasehold interest. We are not able to determine if these negotiations will be successful. We are in the process of evaluating other alternatives to further explore this leasehold interest in conjunction with these negotiations. 
 
7
 
Financing Strategy

During the year ended September 30, 2009, we completed several asset sale transactions with Falcon that were entered into to reduce cash requirements for capital expenditures, to improve working capital, and to provide available funds to attempt to complete our Buckskin Mesa Project wells.

Marketing and Pricing

We have historically derived our revenues principally from the sale of natural gas and associated condensate production from wells operated by us and others in the Piceance Basin, in Western Colorado. Our revenues have been determined, to a large degree, by prevailing natural gas prices for production situated in the Rocky Mountain Region of the United States, specifically, Colorado.  Energy commodity prices in general, and the Company’s regional prices in particular, have been highly volatile in the past, and such high levels of volatility are expected to continue in the future. We cannot predict or control the market prices for the sale of our natural gas, condensate, or oil production.

Natural Gas Marketing

Historically, we have sold all of our natural gas production to a diverse group of third-party, non-affiliated entities in a portfolio of transactions of various durations and prices (daily, monthly and longer term), under a marketing agreement with EnCana, who was the operator of our 8 producing gas wells that we sold effective December 1, 2008. As of September 30, 2009, we are not producing or selling any natural gas.

Competition

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

Employees

At September 30, 2009, we had 4 full time equivalent employees. In addition, we utilized the services of 1 full time consultant. Our employees are not covered by a collective bargaining agreement.

Environmental Regulation

Our exploration, drilling and production activities from wells and natural gas facilities, including the operation and construction of pipelines, plants and other facilities for transporting, processing, treating or storing oil, natural gas and other products are subject to stringent federal, state and local laws and regulations governing environmental quality, including those relating to oil spills and pollution control, that are constantly changing. Although such laws and regulations can increase the cost of planning, designing, installing and operating such facilities, it is anticipated that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials in the environment or otherwise relating to the protection of the environment, will not have a material effect upon our business operations, capital expenditures, operating results or competitive position.


 
8
 

ITEM 1A.  
RISK FACTORS

Risks Related to Our Business

We have a limited operating history and have generated only very limited revenues. We have incurred significant losses and will continue to incur losses for the foreseeable future.  If we fail to secure significant sources of funding in the short term, we may not be able to continue in existence.

The report of our independent registered public accounting firm on the financial statements for the years ended September 30, 2009 and 2008 includes an explanatory paragraph relating to significant doubt or uncertainty of our ability to continue as a going concern.  We have an accumulated deficit of $279 million as of September 30, 2009 and generated losses of $130 million for the year then ended. For the 2010 fiscal year, we do not expect our operations to generate sufficient cash flows to provide working capital to pay overhead expenses, the funding of our lease acquisitions, and the exploration and development of our properties. Without adequate financing, we may not be able to successfully develop prospects that we have, and we may not achieve profitability from operations in the near future or at all.

As a result of severe cash flow constraints, we have experienced substantial difficulties in meeting our short term cash needs, particularly in relation to our past due financing and vendor commitments. Substantially all of our assets are pledged, and extreme volatility in energy pricing and a deteriorating global economy are creating great difficulties in the capital markets and have greatly hindered our ability to raise debt and/or equity capital. Further, as the result of a series of asset sale transactions, we no longer have proven reserves, which will increase our difficulties in obtaining any financing. During the year ended September 30, 2009 we have obtained minimal debt financing from related parties which we expect will not continue in the near future. We have a $64.9 million working capital deficit as of September 30, 2009, and substantially all of our current assets are concentrated in marketable equity securities we received in conjunction with the sale of a total of 75% of our working interest in  our Australian assets to a related party. Those securities have experienced a dramatic decline in value and the price of these securities remains highly volatile.  

We have completed several significant asset dispositions during the past years, which leaves us with two primary projects that are both undeveloped and subject to substantial risks.

During the years ended September 30, 2009 and 2008, we experienced significant dispositions of assets, both in sale transactions and as a result of our inability to maintain certain financial commitments.  These dispositions of non-core assets have resulted in our development risks being concentrated in two primary projects in Australia and Colorado, which are both undeveloped and at this stage without proved reserves associated with them. 

The value of the securities of Falcon received in the sale of a 50% working interest in four exploration permits in Australia is highly volatile and subject to significant changes in value due to significant changes in market value, and their value has substantial implications on our future liquidity.

The common stock of Falcon represents the substantial majority of current assets and our current liquidity, resulting in a concentration of risk.  The shares are subject to significant market volatility and are subject to significant restrictions on our ability to sell the securities.  Accordingly, our inability to realize sufficient value from these securities and/or our inability to convert the securities into cash to fund our operations and development plans when needed, could present material adverse consequences to us.

Two related parties control a significant percentage of our outstanding common stock, which may enable them to control many significant corporate actions and may prevent a change in control that would otherwise be beneficial to our stockholders.

Entities controlled by Marc A. Bruner and Christian Russenberger beneficially owned approximately 25.3% and 14.5%, respectively, of our common stock as of December 31, 2009.  The control and/or significant influence held by such entities may have a substantial impact on matters requiring the vote of common shareholders, including the election of our directors and most of our corporate actions. Such control could delay, defer or prevent others from
 
9
 
initiating a potential merger, takeover or other change in control that might benefit us and our shareholders. Such control could adversely affect the voting and other rights of our other shareholders and could depress the market price of our common stock.

Marc A. Bruner is the controlling owner of MAB Resources, LLC.  Mr. Bruner serves as chairman of the board, chief executive officer and president of Falcon, a company whose stock is traded on the TSX Venture Exchange, and our partner in our primary exploration and development projects.

Christian Russenberger, a related party and significant shareholder, is President of Global Project Finance AG, our most significant creditor.

Our convertible debentures could significantly dilute the interests of shareholders.

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

In addition, to date we have issued five-year warrants to the holders of the convertible debentures.  The warrant holders are entitled to purchase an aggregate of 52.2 million shares of our common stock at exercise prices ranging from $0.12 to $0.28 per share, inclusive of warrants issued in consideration of certain waivers and amendments during our fiscal year ended September 30, 2009.  Both the number of warrants and the exercise price are subject to potential adjustments which could result in further dilution to our stockholders.

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

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

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

We are obligated to make significant periodic payments of interest on our portfolio of debt.

We are currently obligated to pay annual interest of approximately $5.0 million. Currently, we are not able to make these interest payments and we are in the process of renegotiating these terms. We have pledged or secured our assets in respect to these obligations.

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

As of September 30, 2009, we have issued warrants and options to purchase a total of 172.3 million shares of common stock.  The issuance of shares upon exercise of warrants and options may result in significant dilution to the interests of our existing stockholders.
 
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Our officers, directors and advisors are engaged in other businesses, which may result in conflicts of interest.

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

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

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

Substantially all of our oil and gas properties are located in the Piceance Basin of Western Colorado and in the Northern Territory in Australia, making us vulnerable to specific risks associated with operating in these geographic areas.

We may be exposed to the effect of seasonal weather conditions, lease stipulations, delays or interruptions of production from these areas caused by significant governmental regulation, transportation capacity constraints, the availability and capacity of compression and gas processing facilities, curtailment of production or interruption of transportation of natural gas produced from the wells in these areas, as well as the remoteness and lack of infrastructure in the case of the Australian properties.

We have limited control over activities on our oil and gas properties as we do not operate or do not intend to operate.

As we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of underlying properties.

We have found material weaknesses in our internal controls that require remediation and concluded that our internal controls over financial reporting at September 30, 2009, were not effective.
 
As we discuss in Part II, Item 9A(T), “Controls and Procedures”, of this Form 10-K, we have determined that we continue to have deficiencies, including material weaknesses, in our internal control over financial reporting as of September 30, 2009. 

We are subject to various risks associated with our Australian operations.

A significant portion of our remaining assets are in Australia, which subjects us to various risks associated with doing business in a foreign country. These risks include, among other things:

·    
governmental and regulatory requirements unique to the country;
 
·    
exposure to foreign currency losses;
 
·    
foreign taxation requirements, which can differ significantly from U.S. regulations;
 
·    
local economic and/or political instability; and
 
·    
potential difficulties in our ability to expatriate cash and/or assets to the U.S.
 
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These risks are beyond our control, and could result in material adverse consequences to us.

Risks Relating to the Oil and Gas Industry

We are subject to various risks associated with the oil and gas industry, summarized as follows:

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

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

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

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

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

Risks Related to Our Common Stock

We are subject to various risks in respect to our Common Stock, summarized as follows:

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

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

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

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


ITEM 1B.  
UNRESOLVED STAFF COMMENTS

Not Required by Form 10-K for Smaller Reporting Companies.


ITEM 2.  
PROPERTIES

Location and Characteristics

Our headquarters are located at 1600 Stout Street, Suite 450, Denver, Colorado, 80202. The lease for this office space of approximately 3,800 square feet has a term expiring September 1, 2014. The annual rent is approximately $0.2 million, including adjustments for inflation and expenses, as well as termination fees for additional square footage we had leased through September 1, 2009. We no longer occupy that space.

Currently, we own oil and gas leases in Colorado, where we own ten wells on our Buckskin Mesa property (20,000 gross and net acres), and in the Northern Territory in Australia, where we own a 25% working interest in the Beetaloo Basin project (7,000,000 gross and 1,750,000 net acres), including one well. The wells on these properties have not yet commenced oil and gas production. In fiscal 2008, we owned working interests in eight natural gas wells in Colorado which were operated by EnCana Oil & Gas USA (“EnCana”).  These interests were sold to a third party in December 2008. We also owned other undeveloped acreage in Montana and Western Colorado in fiscal 2008. This acreage has been sold or the underlying leases have expired.
 
12
 
Plan of Operations

In fiscal 2010, we will focus on executing and implementing a financing strategy with Falcon Australia for our Beetaloo Basin project in Australia in order to further explore and develop this acreage, as well as to pursue opportunities to further explore our Buckskin Mesa acreage. We will continue to reduce operating costs and attempt to reduce/renegotiate our debt, accounts payable and other liabilities, and potentially acquire additional properties.

Oil and Gas Reserves

The following table is a summary of our oil and gas reserves. For the year ended September 30, 2008, the reserves are presented as estimated by independent petroleum engineers Gustavson Associates, LLC. For the year ended September 30, 2009, the Company did not engage Gustavson or any other independent petroleum engineers and has presented its internal estimates for that period ($’s in thousands unless volumetric unit or per volumetric unit):

   
Year Ended
September 30,
  
   
2009
    
2008
  
Proved Undeveloped Reserves
            
  Natural gas (MMcf)
    
—
      
16,504
  
  Oil (MBbl)
    
—
      
5
  
Proved Developed Reserves
                
  Natural gas (MMcf)
    
—
      
3,310
  
  Oil (MBbl)
    
—
      
2
  
Total Proved Reserves (MMcfe)
    
—
      
19,856
  
Estimated future net cash flows, before income tax
  
$
—
    
$
33,739
  
Standardized measure of discounted future net cash flows, before income taxes
  
$
—
    
$
8,357
  
Future income tax
    
—
      
—
  
Standardized measure of discounted future net cash flows, after income taxes
  
$
—
    
$
8,357
  
Calculated weighted average prices per unit
                
  Gas ($/Mcf)
  
$
—
    
$
3.36
  
  Oil ($/Bbl)
  
$
—
    
$
79.47
  

Production Volumes, Average Sales Prices and Average Production Costs

The following table sets forth certain information regarding our historical U.S. net production of oil and natural gas, and certain price and cost information.

   
Year ended September 30,
  
   
2009
    
2008
    
2007
  
Production Data:
                  
Natural gas (Mcf)
    
66,527
      
286,474
      
456,740
  
Oil (Bbl)
    
74
      
348
      
137
  
Average Prices:
                        
Natural gas (per Mcf)
  
$
5.43
    
$
6.82
    
$
6.16
  
Oil (per Bbl)
  
$
37.35
    
$
111.80
    
$
52.40
  
Production Costs:
                        
Lease operating expenses (per Mcfe)
  
$
8.82
    
$
2.79
    
$
1.73
  

Productive Wells

As of September 30, 2009 we do not have any producing wells.
 
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Oil and Gas Drilling Activities

During the year ended September 30, 2009, we participated in the deepening of the Shenandoah #1 well (Shenandoah #1A) in the Beetaloo Basin in Australia and conducted completion activities on three wells at our Buckskin Mesa Project.

During the fiscal year ended September 30, 2008, we drilled 2 gross wells and 2 net wells as follows: the Lake 6-22 well in the Buckskin Mesa Project in Colorado, and the Shenandoah #1 well in the Beetaloo Basin in Australia.

Oil and Gas Interests

As of September 30, 2009, we owned interests in the following undeveloped acreage positions. Undeveloped acreage refers to acreage that has not been placed in production.

       
Undeveloped
       
Gross Acres
    
Net Acres
Location
              
        Colorado
        
20,000
      
20,000
Australia
        
7,000,000
      
1,750,000
Total
        
7,020,000
      
1,770,000

Impairment of Oil and Gas Properties

Costs capitalized for properties accounted for under the full cost method of accounting are subjected to a ceiling test limitation to the amount of costs included in the cost pool by geographic cost center. Costs of oil and gas properties may not exceed the ceiling which is an amount equal to the present value, discounted at 10%, of the estimated future net cash flows from proved oil and gas reserves plus the cost, or estimated fair market value, if lower, of unproved properties. Should capitalized costs exceed this ceiling, impairment expense equal to the costs exceeding the ceiling is recognized. As the Company does not have available capital to develop the U.S. properties the entire U.S. Full Cost Pool has been written down to $0.0 million as of September 30, 2009. During the fiscal years ended September 30, 2009 and 2008, we recorded impairment expense of $90.4 million and $30.8 million, respectively.

Depreciation, Depletion, Amortization and Accretion

Depreciation, depletion, amortization and accretion expense was $0.2 million in 2009 and $1.2 million in 2008.

ITEM 3.  
LEGAL PROCEEDINGS

As of September 30, 2009, there are no legal proceedings filed or threatened (to our knowledge) against or involving the Company.

ITEM 4.  
SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.


 
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PART II

ITEM 5.  
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

Our common stock commenced trading on the OTC bulletin board on April 20, 2005, under the symbol “DGEO,” and has been trading under the symbol “PHUN” since August 21, 2006. The following table sets forth the high and low bid prices per share of our common stock, as reported on the OTC bulletin board for the periods indicated.   

Quarter Ended
High
Low
December 31, 2007
$0.31
$0.15
March 31, 2008
$0.25
$0.12
June 30, 2008
$0.30
$0.15
September 30, 2008
$0.24
$0.11
December 31, 2008
$0.13
$0.06
March 31, 2009
$0.15
$0.01
June 30, 2009
$0.04
$0.02
September 30, 2009
$0.04
$0.01

On December 30, 2009, the last sale price for our common stock was $0.02.

Holders and Dividends

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

As of December 31, 2009, there were 220 record holders of our common stock.

Recent Sales of Unregistered Securities

None.

ITEM 6.  
SELECTED FINANCIAL DATA

Not Required by Form 10-K for Smaller Reporting Companies.

ITEM 7.  
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION

The following discussion of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and notes appearing elsewhere in this Form 10-K.

Results of Operations - Year Ended September 30, 2009 versus Year Ended September 30, 2008

Oil and Gas Revenues – Oil and gas revenues were $0.1 million and $2.0 million for the fiscal years ended September 30, 2009 and 2008, respectively, which represents a decline of $1.9 million or 95%.  Oil and gas revenues decreased as we sold our only producing wells effective as of December 1, 2008.
 
15
 
Costs and Expenses

General and Administrative – During 2009, general and administrative expenses were $7.8 million as compared to $10.7 million in fiscal 2008, representing a decrease of $3.0 million or 28%. The following table highlights significant general and administrative expenses for the respective periods ($ in thousands):
 
   
Period Ending September 30,
  
  
  
2009
    
2008
    
Change
  
Payroll
   $ 2,193     $ 2,572     $ (379 )     (15 )%
Consulting fees
     551       1,936       (1,385 )     (72 )%
Stock - based compensation expense
     2,942       3,276       (334 )     (10 )%
Legal
     355       906       (551 )     (61 )%
Travel
     22       224       (202 )     (90 )%
Investor relations
     79       250       (171 )     (68 )%
Insurance
     464       575       (111 )     (19 )%
Office
     320       314       6       2 %
Other
     833       689       144       21 %
 Total
   $ 7,759     $ 10,742     $ (2,983 )        

Payroll Expense – Declined $0.4 million to $2.2 million, from $2.6 million in 2008. This 15% decline was attributable to the termination of a large percentage of our workforce on March 31, 2009. These reductions were offset by additional compensation paid to executive and officers during the year, including one time awards of stock. As of September 30, 2009, the rightsizing of our labor force was essentially complete as we had reduced the workforce from 30 full time equivalents as of March 31, 2009 to four full time equivalents and one full time consultant. We anticipate payroll expense in fiscal 2010 to be nominal in comparison to prior fiscal periods.

Consulting Fees – Declined $1.4 million or 72% due to the Company’s cost reduction efforts and lower activity levels.

Stock-Based Compensation - Decreased to $2.9 million in 2009 from $3.3 million in 2008, a decrease of $0.4 million. This 10% decrease results from fewer grants of options during the period, coupled with grants issued being valued at a lower intrinsic value resultant from significant declines in the value of our common stock.  Additionally,  the Board of Directors approved the extension of the terms of many of the employees of the Company who were terminated in March 31, 2009. Accordingly,  a one-time expense was realized related to this extension during the period. We anticipate stock-based compensation expense in fiscal 2010 to be nominal in comparison to prior fiscal periods.

Legal Fees – Decreased to $0.4 million in 2009 from $0.9 million in 2008, a decrease of $0.5 million. This 61% decrease is primarily attributable to efforts to reduce the use of outside legal services in 2009, coupled with fewer equity and property related transactions. We anticipate legal expense in fiscal 2010 to be less in comparison to prior fiscal periods.

Travel Costs – Decreased to $0.0 million in 2009 from $0.2 million in 2008. This 90% decrease results from our conscious efforts to manage costs.

Investor Relations – Decreased to $0.1 million in 2009 from $0.3 million in 2008. This 68% decrease is due primarily to our focus on expense management.

Insurance, Office, and Other – Remained at $1.6 million per year, for both 2009 and 2008.

Lease Operating Expenses – Lease operating expenses decreased $0.2 million from $0.8 million in 2008 to $0.6 million in 2009. This decrease is primarily attributed to property sales.

Impairment of Oil and Gas Properties – During the year ended September 30, 2009, we recorded impairment expense of $90.4 million, and during the year ended September 30, 2008, we recorded an impairment of $30.8
 
16
 
million, an increase of $59.6 million or 194%. The increase was due to the impairment of the remaining book value of the U.S. full cost pool due to unsuccessful exploration activity and the Company’s inability to fund additional exploration.

Impairment expense recorded in 2008 was primarily attributable to oil and gas properties that were subsequently sold.

Depreciation, Depletion, Amortization and Accretion – Depreciation, depletion, amortization and accretion expense  was $0.2 million in 2009 and $1.2 million in 2008, respectively.  This decrease is attributable to decreases in production volumes related to the sale of our producing properties in December 2008.

Gains (Losses) on Conveyances of Property – During 2009, we completed several significant asset sales, which resulted in our recognizing net gains of $2.5 million in accordance with the full cost accounting rules.  During our first quarter ended December 31, 2008, we sold our eight producing wells and realized net proceeds of $2.3 million. The disposition of these assets was significant in relation to our U.S. full cost pool, and therefore, we were required to evaluate whether the transaction had significantly altered the relationship between our capitalized costs and proved reserves, which could cause us to recognize a loss under the full cost pool accounting rules.  Accordingly, our evaluation resulted in our recognition of a $0.2 million loss on conveyance during the quarter ended December 31, 2008. Similarly, during our third quarter ended June 30, 2009, we sold an additional 25% of our exploration licenses and permits in the Beetaloo Basin. This transaction was considered a recoup of expenses and caused us to write down the remaining balances in the Australian full cost pool to $0 and we recorded a gain on the conveyance of $2.7 million. During fiscal 2008, we sold our Heavy Oil Project and our Southern Piceance property, and we recorded losses on conveyance of $11.9 million and $8.6 million, respectively.

Interest Expense – During 2009, interest expense was $16.2 million in comparison to $11.2 million incurred in 2008. The $5.0 million net increase in interest expense, or 45%, primarily relates to charges of $9.8 million including $1.4 million for the amortization of deferred financing costs, and $8.6 million for the amortization of debt discount and beneficial conversion feature. These charges were increased significantly during the current period as we deemed that the underlying debt instruments would not be held to maturity and or be repaid in cash, and therefore the related amortization and accretion charges were accelerated during the period. (See Note 8 - Notes Payable, of the Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data).

Net Loss – Our net loss of $129.7 million in 2009 compared to the loss of $76.9 million in 2008 represents an increase of $52.8 million or 68.7%, as a result of the factors above, primarily impairment.

Going Concern

The report of our independent registered public accounting firm on the financial statements for the years ended September 30, 2009 and 2008 includes explanatory paragraphs relating to substantial doubt or uncertainty of our ability to continue as a going concern.  We have generated a cumulative net loss of $279.2 million, and we have a working capital deficit of $64.9 million as of September 30, 2009. For our 2010 fiscal year, we expect that we will be able to fund, on a very limited basis, overhead expenses from the proceeds of sales of our Falcon shares. We do not believe we will be investing cash in our properties in the foreseeable future. Our ability to establish ourselves as a going concern is dependent upon our ability to obtain additional funding in order to finance our planned operations.  Further, our outstanding debentures (as further explained in Note 8 - Notes Payable of the Notes to Consolidated Financial Statements included in Item 8. Financial Statements and Supplementary Data) are in technical default.  Management continues to negotiate with the Company's creditors.  However, our ability to establish ourselves as a going concern is dependent upon our ability to either refinance our currently outstanding obligations or obtain additional funding and there are no assurances either of these can occur in the forseeable future.


 
17
 

Schedule of Contractual Commitments

The following table summarizes the Company’s obligations and commitments to make future payments under its notes payable, operating leases, employment contracts, consulting agreements and service contracts for the periods specified as of September 30, 2009 ($ in thousands):

     Payments Due by Period  
 
Contractual Obligations
  
Total
    
Less Than
1 Year
    
1-3
Years
    
3-5
Years
  
   Office lease
  
 $
632
    
 $
176
    
 $
255
    
 $
201
  

Plan of Operation

Colorado

In fiscal year 2010 we will continue to focus on exploring alternative financing and/or working interest partners to further explore on our  Buckskin Mesa prospect.

Australia

During fiscal 2010 we plan to continue to seek ways to finance the exploration and development in the Beetaloo Basin project area located in Australia, through Falcon Australia.

Liquidity and Capital Resources

Our most recent year ended September 30, 2009 continued to be a year of significant transition for us. Our cash flows from operations continued to be insufficient for us to meet our operating commitments.   Given these circumstances, our primary goal during 2009 was to ensure liquidity to continue in existence, and further our exploration activities, on a limited basis, on our remaining properties. We continued to seek financing transactions, and to seek development partners for our Buckskin Mesa Project in Colorado and our Beetaloo Basin Project in Australia.

We completed the sale of the following interests in our properties pursuant to a purchase and sale agreement with Falcon dated August 25, 2008: (a) an undivided 50% working interest in four exploration permits in the Beetaloo Basin, Australia, which closed on September 30, 2008 and yielded net cash proceeds of $5.0 million and securities in the common stock of Falcon valued at $14.1 million as of September 30, 2008; and (b) an undivided 25% working interest in the five wells drilled in Buckskin Mesa, including the 40-acre tract surrounding each well, which closed on November 10, 2008, in exchange for a $7.0 million cash work commitment to complete certain of these wells. In addition, in December 2008, we completed the sale of our working interests in our eight producing wells operated by EnCana Oil & Gas (USA), Inc., for net cash proceeds of $2.3 million.

In addition, as part of the Purchase and Sale Agreement with Falcon relating to our Buckskin Mesa property, Falcon obtained an option to acquire up to a 50% interest in our entire Buckskin Mesa Project, for total consideration of $28.5 million in cash or shares of Falcon common stock, and an $18.0 million work commitment ($9.0 million of which would be a carried interest for us). Further, Falcon had the option to elect to become the operator of the Buckskin Mesa Project for an additional payment of $3.5 million. In February 2009, Falcon elected not to exercise its option to acquire additional interests in the Buckskin Mesa. In June 2009, we sold an additional 25% interest in our four exploration permits in the Beetaloo Basin located in the Northern Territory of Australia to Falcon. In consideration, we received relief of a $5.0 million note payable to Falcon, as well as relief of $1.2 million in accounts payable related to the prospect, and the remaining restrictions on our Falcon shares which had secured the note payable were lifted, subject to our escrow agreement with Falcon.


18
 
Working Capital

Working capital is the amount by which current assets exceed current liabilities, and our working capital deficit is the result of having current liabilities in excess of our current assets. Our working capital is impacted by changes in our ongoing operating costs, along with the timing of operating cash receipts and disbursements, borrowings of and payments toward debt, expenditures for and sales of oil and gas properties, and increases and decreases in other assets involving cash. We are in default of the underlying debt instruments included in current liabilities, and penalty interest is accruing on this debt.
 
As of September 30, 2009, we had a working capital deficit of $64.9 million and a cash balance of $0.2 million. As of September 30, 2008, we had working capital deficit of $3.9 million and cash of $1.0 million; accordingly our working capital deficit increased by $61 million during 2009.

Cash Flow – Year Ended September 30, 2009 versus Year Ended September 30, 2008

Net cash used in or provided by operating, investing and financing activities for the years ended September 30, 2009 and 2008 were as follows ($ in thousands):

   
Year Ended
September 30,
  
   
2009
    
2008
  
Net cash used in operating activities
   $ (8,900 )   $ (21,737 )
Net cash provided by investing activities
   $ 3,361     $ 14,145  
Net cash provided by financing activities
   $ 4,807     $ 8,439  

Net Cash Used in Operating Activities.  Net cash used in operating activities decreased approximately $12.8 million in 2009 as compared to 2008. The improvement is attributed to the use of cash for paying off accounts payable, shareholders and related parties of approximately $9 million in 2008, while in 2009 we received $2.5 million in receivable related payments and our accounts payable balance increased by $0.2 million.

Net Cash Provided in Investing Activities.   Net cash provided by investing activities decreased by approximately $11 million in 2009 as compared to 2008. The decrease in cash provided is primarily attributed to one time property sales in 2008, netted against oil and gas property additions, which provided approximately $12 million in 2008, and in 2009 property sale proceeds net of oil and gas property additions resulted in $1 million of cash provided.

Net Cash Provided by Financing Activities.  Net cash provided by financing activities decreased by approximately $3.6 million in 2009 as compared to 2008 primarily due to our declining financial position.

2009 Financing Transactions

During 2009, we completed financing transactions as follows:

(1)    
We issued an 18% subordinated debenture in the amount of $0.03 million to a shareholder of the Company in exchange for the relief of amounts due the shareholder. The subordinated debenture is collateralized by an interest in .01 million shares of Falcon common stock held by us as restricted marketable securities. In connection with the issuance of the debenture we issued 0.07 million warrants to purchase our common stock at $0.15 per share, which expire in January 2010.  The debenture was due on April 15, 2009. We made partial payments on the note and are currently in default under the terms of the debenture agreement for the remaining outstanding balance.

(2)    
We issued three subordinated convertible debentures totaling $0.2 million to two related parties in December 2008. These debentures bore interest at 15% per annum and were due in May 2009. We issued 0.5 million warrants to purchase our common stock at $0.15 per share in connection with these debentures.  As of September 30, 2009 these debentures along with all related accrued interest have been repaid.
 
19

 
(3)    
We issued a promissory note in the amount of $0.1 million to a related party. This note bore interest at 15% per annum. As of September 30, 2009 we have repaid this note and all accrued interest.

(4)    
We entered into a 10% secured loan agreement with Falcon. Under the terms of the loan agreement, Falcon agreed to advance us $5.0 million.  This loan was secured by 14.5 million shares of Falcon common stock we had received as consideration in relation to the sale of a 50% working interest in our four exploration permits in Australia to Falcon in October 2008.   In addition the loan was also secured by a first position security interest in the five wells we drilled in our Buckskin Mesa project. In June 2009, we sold an additional 25% interest in our Australian exploration permits to Falcon, for relief of debt in respect to this loan of $5.0 million, which released the shares as collateral.

2008 Financing Transactions

During 2008, we completed financing transactions as follows:

      (1)
We borrowed $8.3 million on our credit facility with Global, for a total of $39.8 million drawn as of September 30, 2008.   The credit facility bears interest at prime plus 6.75%, which ranged from 14.0% at the beginning of the year to 11.8% at the end of the year.  Accrued interest of $6.5 million at September 30, 2008 was converted to into 32.6 million shares of our common stock.  We pay an advance fee of 2% on all amounts borrowed under the facility, totaling $0.2 million during the year. 

      (2)
In November 2007, we completed the sale of 8.5% convertible debentures to several accredited investors for an aggregate principal amount of $7.0 million, for which we received $6.3 million in cash proceeds.  The remaining $0.7 million resulted from a transfer of $0.5 million or the $2.9 million common stock subscription outstanding at September 30, 2007 and $0.2 million of amounts converted from other accrued expenses.  The debenture holders also received five-year warrants to purchase 46.4 million shares of our common stock.  We paid a placement fee of $0.3 million.  

      (3)
We borrowed $1.4 million from Global under short term promissory notes, which were unsecured and bore interest at 15% per annum.  

      (4)
We borrowed $0.9 million from vendors which was subsequently repaid during the year.

      (5)
We entered into four separate promissory notes with Bruner Family Trust, UTD March 28, 2005 for a total borrowing of $0.4 million in the current year.  Each note bears interest at 8.0%.  The funds were used to fund working capital needs.  The remaining $2.3 million of the $2.7 million balance due to the Bruner Family Trust was converted from the $2.9 million common stock subscription outstanding as of September 30, 2007.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Critical Accounting Policies and Estimates

We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our Financial Statements.
 
Reserve Estimates

Our estimates of oil and natural gas reserves, by necessity, are projections based on an interpretation of geological and engineering data.  There are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures.  Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that are difficult to measure.  The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment.  Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily
 
20
 
depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, and the assumed effects of regulations by governmental agencies.  Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves which could affect the carrying value of our oil and gas properties and/or the rate of depletion of the oil and gas properties.
 
Oil and Gas Properties

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

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

 Asset Retirement Obligation

Asset retirement obligations associated with tangible long-lived assets are accounted for in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 410, “Accounting for Asset Retirement Obligations”. The estimated fair value of the future costs associated with dismantlement, abandonment and restoration of oil and gas properties is recorded generally upon acquisition or completion of a well. The net estimated costs are discounted to present values using a risk adjusted rate over the estimated economic life of the oil and gas properties. Such costs are capitalized as part of the related asset. The asset is depleted on the units-of-production method on a field-by-field basis. The liability is periodically adjusted to reflect (1) new liabilities incurred, (2) liabilities settled during the period, (3) accretion expense, and (4) revisions to estimated future cash flow requirements. The accretion expense is recorded as a component of depreciation, depletion, amortization and accretion expense in the accompanying consolidated statements of operations.

Share - Based Compensation

We use the Black-Scholes option-pricing model and the straight-line attribution approach to determine the fair-value of stock-based awards in accordance with FASB ASC 718, “Compensation”.   The option-pricing model requires the input of highly subjective assumptions, including the option’s expected life and the price volatility of the underlying stock. The Company’s expected term represents the period that stock-based awards are expected to be outstanding and is determined based on historical experience of similar awards, giving consideration to the contractual terms of the stock-based awards, vesting schedules and expectations of future employee behavior as influenced by changes to the terms of its stock-based awards. The expected stock price volatility is based on the Company’s historical stock prices.

Impairment

We apply the provisions of FASB ASC 360, “Property Plant and Equipment,” which addresses financial accounting and reporting for the impairment or disposal of long-lived assets.  FASB ASC 360 requires a long-lived asset to be sold to be classified as “held for sale” in the period in which certain criteria are met, including that the sale of the asset within one year is probable.  FASB ASC 360 also requires that the results of operations of a component of an entity that either has been disposed of or is classified as held for sale be reported in discontinued operations if the
 
21
 
operations and cash flows of the component have been or will be eliminated from the Company’s ongoing operations.

The Company periodically reviews the carrying value of its long-term assets in relation to historical results, current business conditions and trends to identify potential situations in which the carrying value of assets may not be recoverable.  If such reviews indicate that the carrying value of such assets may not be recoverable, the Company would estimate the undiscounted sum of the expected cash flows of such assets to determine if such sum is less than the carrying value of such assets to ascertain if an impairment exists. If an impairment exists, the Company would determine the fair value by using quoted market prices, if available for such assets, or if quoted market prices are not available, the Company would discount the expected future cash flows of such assets.

Marketable Securities

We received marketable equity securities as consideration from the sale of certain of our oil and gas properties, and account for them in accordance with FASB ASC 320, “Accounting for Certain Investments in Debt and Equity Securities.”  As the shares we have received will be made available for sale in the short term through the terms in an underlying escrow agreement, we account for them by marking them to market with unrealized gains and losses reflected as a component of Other Comprehensive Income, until such gains or losses become realized, at which time they are then recognized in our statement of operations. In addition, in circumstances where significant price declines are experienced subsequent to the balance sheet date, we consider whether such declines are other than temporary, after considering our expected holding period, we may record a provision for impairment in the event we do not expect the value of the securities to recover from such a decline in market value. We consider our accounting for marketable securities to involve significant management judgment that is subject to estimation.
 
Recently Issued Accounting Pronouncements
 
 In May 2009, the FASB issued FASB ASC 855, “Subsequent Events”. FASB ASC 855 incorporates accounting and disclosure requirements related to subsequent events into U.S. GAAP. The requirements of FASB ASC 855 for subsequent-events accounting and disclosure are not significantly different from those in existing auditing standards, which we have historically followed for financial reporting purposes, as a result, we do not believe this standard had any material impact on our financial statements. We have evaluated subsequent events through the date of issuance of these consolidated financial statements, which is January 13, 2010.

In July 2009, the FASB issued new guidance relating to the “FASB Accounting Standards Codification” at FASB ASC 105, as the single source of authoritative nongovernmental U.S. generally accepted accounting principles (GAAP). The codification is effective for interim periods ending after September 15, 2009. All existing accounting standards are superseded as described in ASC 105. All other accounting literature not included in the Codification is non-authoritative. The adoption of ASC 105 did not impact our results of operations, financial position or cash flows.

In October 2009, we adopted certain accounting principles within FASB ASC 470 “Debt with Conversion and Other Options” that requires the proceeds from the issuance of certain convertible debt instruments to be allocated between a liability component (issued at a discount) and an equity component. The resulting debt discount is amortized over the period the convertible debt is expected to be outstanding as additional non-cash interest expense. The change in accounting treatment is effective for us in fiscal 2010, and it is required to be applied retrospectively to prior periods.  Management is currently assessing the potential impact that the adoption of this new guidance could have on our financial statements in fiscal 2010.

In October 2009, we adopted certain accounting principles within FASB ASC 805 “Business Combinations” which requires an acquirer to recognize the assets acquired, the liabilities assumed, including those arising from contractual contingencies, any contingent consideration, and any non-controlling interest in the acquiree at the acquisition date, measured at their fair values as of that date, with limited exceptions specified in the statement.  It also requires the acquirer in a business combination achieved in stages (sometimes referred to as a step acquisition) to recognize the identifiable assets and liabilities, as well as the non-controlling interest in the acquiree, at the full amounts of their fair values (or other amounts determined in accordance with this accounting principle).  In addition, the accounting principles requirement to measure the non-controlling interest in the acquiree at fair value will result in recognizing
 
22
 
the goodwill attributable to the non-controlling interest in addition to that attributable to the acquirer. ASC 805 also requires the acquirer to recognize changes in the amount of its deferred tax benefits that are recognizable because of a business combination either in income from continuing operations in the period of the combination or directly in contributed capital, depending on the circumstances. It also provides guidance on the impairment testing of acquired research and development intangible assets and assets that the acquirer intends not to use. ASC 805 applies prospectively to business combinations for which the acquisition date is on or after October 1, 2009, therefore, the adoption of ASC 805 did not have any impact on our historical financial statements.

In October 2009, we adopted certain accounting principles within FASB ASC 810 “Consolidation” which establishes accounting and reporting standards for the non-controlling interest in a subsidiary and for the deconsolidation of a subsidiary. It also clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements.  ASC 810 also changes the way the consolidated income statement is presented by requiring consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the non-controlling interest. It also requires disclosure, on the face of the consolidated statement of income, of the amounts of consolidated net income attributable to the parent and to the non-controlling interest. ASC 810 requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated and requires expanded disclosures in the consolidated financial statements that clearly identify and distinguish between the interests of the parent owners and the interests of the non-controlling owners of a subsidiary.  The adoption of ASC 810 did not have any impact on our historical financial statements.
 
In January 2010, the FASB issued Accounting Standards Update (ASU) No. 2010-03 “Oil and Gas Reserve Estimation and Disclosures.” The ASU aligns the current oil and gas reserve estimation and disclosure requirements of FASB Accounting Standards Codification Topic 932, Extractive Activities — Oil and Gas, with those in SEC Final Rule Release No. 33-8995, Modernization of Oil and Gas Reporting. The ASU will be effective for reporting periods ending on or after December 31, 2009. We are currently assessing the impact that adoption of this rule will have on our financial statements.
 
In December 2008, the SEC issued revised reporting requirements for oil and natural gas reserves that a company holds. Included in the new rule entitled “Modernization of Oil and Gas Reporting Requirements”, are the following changes: 1) permitting use of new technologies to determine proved reserves, if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes; 2) enabling companies to additionally disclose their probable and possible reserves to investors, in addition to their proved reserves; 3) allowing previously excluded resources, such as oil sands, to be classified as oil and natural gas reserves rather than mining reserves; 4) requiring companies to report the independence and qualifications of a preparer or auditor, based on current Society of Petroleum Engineers criteria; 5) requiring the filing of reports for companies that rely on a third party to prepare reserve estimates or conduct a reserve audit; and 6) requiring companies to report oil and natural gas reserves using an average price based upon the prior 12-month period, rather than year-end prices. The new requirements are effective for registration statements filed on or after January 1, 2010, and for annual reports on Form 10K for fiscal years ending on or after December 31, 2009. Early adoption is not permitted. We are currently assessing the impact that adoption of this rule will have on our financial disclosures.

ITEM 7A.  
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
 
Not required by Form 10-K for Smaller Reporting Companies.

ITEM 8.  
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA



 
23
 

 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
 

 
To the Board of Directors of
PetroHunter Energy Corporation
Denver, Colorado
 
We have audited the accompanying consolidated balance sheets of PetroHunter Energy Corporation (the “Company”) as of September 30, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss), and cash flows for the years then ended. The Company’s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audits.
 
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
 
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of PetroHunter Energy Corporation as of September 30, 2009 and 2008 and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.
 
The accompanying financial statements have been prepared assuming that PetroHunter Energy Corporation will continue as a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of operations. As discussed in Note 2, certain factors indicate substantial doubt that the Company will be able to continue as a going concern. The financial statements do not include any adjustments to reflect the possible future effect on the recoverability and classification of assets or the amounts and classification of liabilities that might result from the outcome of these uncertainties.

As discussed in Notes 3, 4, 8, 9, 10 11, 12 and 14, the Company had numerous significant transactions with related parties.
 

 
/s/ Eide Bailly LLP
 
Eide Bailly LLP

Greenwood Village, Colorado
January 8, 2010

 




 
24
 

PETROHUNTER ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
   
September 30,
  
                     ASSETS
  
2009
    
2008
  
   
($ in thousands)
  
Current Assets
            
  Cash and cash equivalents
  
$
235
    
$
967
  
  Receivables
                
  Oil and gas receivables, net
    
—
      
193
  
  GST receivables
    
1
      
504
  
  Other receivables
    
16
      
12
  
  Due from related parties
    
—
      
1,840
  
  Restricted marketable securities
    
2,925
      
7,495
  
  Unrestricted marketable securities
    
455
      
6,638
  
  Prepaid expenses and other assets
    
205
      
273
  
      TOTAL CURRENT ASSETS
    
3,837
      
17,922
  
                 
Property and Equipment, at cost
                
  Oil and gas properties under full cost method, net
    
1,427
      
97,352
  
  Furniture and equipment, net
    
122
      
737
  
     
1,549
      
98,089
  
Other Assets
                
  Restricted cash
    
101
      
524
  
  Deposits and other assets
    
50
      
130
  
  Deferred financing costs
    
—
      
1,388
  
  Contingent asset
    
—
      
4,832
  
TOTAL ASSETS
  
$
5,537
    
$
122,885
  
                 
LIABILITIES AND STOCKHOLDERS’ EQUITY
                
                 
Current Liabilities
                
  Accounts payable and accrued expenses
  
$
4,104
    
$
11,981
  
  Notes payable – short term
    
81
      
329
  
  Convertible notes payable – net
    
6,956
      
—
  
  Note payable –related party –net
    
43,479
      
3,572
  
  Accrued interest payable
    
457
      
166
  
  Accrued interest and fees payable  – related party
    
5,409
      
969
  
  Other accrued liabilities
    
7,273
      
4,832
  
  Asset retirement obligation
    
1,012
      
—
  
      TOTAL CURRENT LIABILITIES
    
68,771
      
21,849
  
                 
  Notes payable  –  related party – net
    
—
      
38,035
  
  Convertible notes payable – net
    
—
      
325
  
  Asset retirement obligation
    
—
      
114
  
  Other long-term liabilities
    
29
      
—
  
TOTAL LIABILITIES
    
68,800
      
60,323
  
                 
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; 380,468,544 and
  373,343,544 issued and outstanding at September 30, 2009 and 2008, respectively
    
380
      
374
  
  Additional paid-in-capital
    
215,576
      
212,308
  
  Accumulated other comprehensive loss
    
—
      
(632
)
  Accumulated deficit
    
(279,219
)
    
(149,488
)
      TOTAL STOCKHOLDERS’ EQUITY
    
(63,263)
      
62,562
  
      TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
  
$
5,537
    
$
122,885
  
See accompanying notes to consolidated financial statements.

25
PETROHUNTER ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS

 
Year Ended
September 30,
2009
    
Year Ended
September 30,
2008
  
                 
 
($ in thousands except per share and share data)
  
Revenues
          
Oil and gas revenues
$
127
    
$
1,993
  
Other revenues
  
1
      
187
  
 Total Revenues
  
128
      
2,180
  
               
Costs and Expenses
              
Lease operating expense
  
587
      
805
  
General and administrative
  
7,759
      
10,742
  
Impairment of contingent asset
  
6,805
      
—
  
Impairment of oil and gas properties
  
90,404
      
30,847
  
Depreciation, depletion, amortization and accretion
  
244
      
1,230
  
Total operating expenses
  
105,799
      
43,624
  
Loss from Operations
  
(105,671
)
    
(41,444
)
               
Other Income (Expense)
              
Gain (Loss) on property conveyances – net
  
2,492
      
(20,469
)
Foreign currency exchange gain
  
—
      
11
  
Interest income
  
14
      
65
  
Interest expense
  
(16,241
)
    
(11,242
)
Loss on sale of securities
  
(1,156
)
    
(2,987
)
Impairment of marketable securities
  
(8,537
)
    
(800
)
Other
  
(303
)
    
—
  
Loss on abandonment
  
(329
)
    
—
  
Total other expense
  
(24,060
)
    
(35,422
)
Net Loss
$
(129,731
)
  
$
(76,866
)
Net loss per common share — basic and diluted
$
     (0.35)
    
$
(0.24
)
Weighted average number of common
    shares outstanding — basic and diluted
  
375,850,141
      
322,902,152
  

See accompanying notes to consolidated financial statements

26
PETROHUNTER ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE LOSS
 
   
Common Stock
                                
   
Shares
    
Amount
    
Additional Paid-In Capital
    
 
Accumulated Deficit
    
Accumulated Other comprehensive Loss
    
Total Stockholders’ Equity
    
Total Comprehensive Loss
  
    ($ in thousands)  
 (Balance, October 1, 2007
     278,948,841     $ 279     $ 172,672     $ (72,622 )   $ (5 )   $ 100,324     $ (49,816 )
    Shares returned  for property conveyance at  $0.22 per share
     (6,400,000 )     (6 )     (1,402 )     —       —       (1,408 )     —  
    Shares issued for property interests at $0.31 per share - related party
     25,000,000       25       7,725       —       —       7,750       —  
    Shares issued in connection with debt conversion  at $0.23 per share – related party
     16,000,000       16       3,664       —       —       3,680       —  
    Shares issued for property conveyance at $0.25  per share
     5,000,000       5       1,245       —       —       1,250       —  
    Shares issued for finance costs at $0.28 per share
     200,000       —       56       —       —       56       —  
    Shares issued for conversion of convertible debt at $0.20 per share
     2,677,519       3       533       —       —       536       —  
    Common shares issued for conversion of accrued   interest – related party at $0.20 per share
     32,600,075       33       6,487       —       —       6,520       —  
    Shares issued for vendor settlements at $0.20 per share
     16,879,219       17       3,359       —       —       3,376       —  
    Shares issued for finance costs at $0.18 per share
     2,037,890       2       365       —       —       367       —  
    Shares issued for purchase option at $0.20 per  share
     400,000       —       80       —       —       80       —  
    Discount 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 debt conversion – related party
     —       —       1,841       —               1,841          
    Debt conversion - related party
     —       —       2,704       —       —       2,704       —  
    Recognition of warrant value associated with amendment & waiver on convertible debt
     —       —       495       —       —       495       —  
    Discount on notes payable
     —       —       336       —       —       336       —  
    Stock - based compensation
     —       —       3,276       —       —       3,276       —  
 
 
27
 
   
Origination fees associated with debt issuance
     —       —       1,895        —        —        1,895       —  
    Foreign currency translation adjustment
     —       —       —       —       (627 )     (627 )     (627 )
Net loss
     —       —       —       (76,866 )     —       (76,866 )     (76,866 )
Balance, September 30, 2008
     373,343,544     $ 374     $ 212,308     $ (149,488 )   $ (632 )   $ 62,562     $ (77,493 )
Common Stock issued in connection with property option agreement
     1,875,000       1       148       —       —       149       —  
Additional paid in capital associated with the issuance of RenCap Penalty warrants
     —       —       51       —       —       51       —  
Additional paid in capital associated with the issuance of warrants in connection with debenture agreements
     —       —       9       —       —       9       —  
Common Stock issued in connection with investor relations
     250,000       —       23       —       —       23       —  
Common Stock issued to officer
     5,000,000       5       95       —       —       100       —  
Foreign currency translation adjustment
     —       —               —       632       632       632  
Stock - based
compensation
     —       —       2,942       —       —       2,942       —  
Net loss
                             (129,731 )             (129,731 )     (129,731 )
Balance, September 30, 2009
     380,468,544     $ 380     $ 215,576     $ (279,219 )   $ —     $ (63,263 )   $ (76,861 )


See accompanying notes to consolidated financial statements.

 
28
 

PETROHUNTER ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS

   
Year Ended
September 30,
2009
    
Year Ended
September 30,
2008
  
   
($ in thousands)
Cash flows used in operating activities
            
Net loss
  
$
(129,731
)
  
$
(76,866
)
Adjustments used to reconcile net loss to net cash used in operating activities:
                
Stock based compensation
    
2,942
      
3,276
  
Depreciation, depletion, amortization and accretion
    
244
      
1,230
  
Impairment of oil and gas properties
    
90,404
      
30,847
  
Warrants issued to settle interest costs
    
60
      
495
  
Loss on abandonment
    
329
      
—
  
Impairment of contingent asset
    
6,805
      
—
  
Amortization of deferred financing costs
    
1,388
      
1,575
  
Amortization of debt discount and beneficial conversion feature
    
8,648
      
2,419
  
(Gain) Loss on conveyance of properties
    
(2,492)
      
20,469
  
Losses on sale of marketable securities
    
1,156
      
2,987
  
    Impairment of marketable securities
 
  
8,537
      
800
  
Other, net
    
—
      
45
  
    Changes in operating assets and liabilities:
                
    Receivables
    
680
      
(163
)
    Due from related party
    
1,840
      
—
  
    Prepaid expenses and other assets
    
68
      
(216
)
    Accounts payable and accrued expenses
    
222
      
(7,161
) 
    Due to shareholder and related parties
    
—
      
(1,474
)
Net cash used in operating activities
    
(8,900)
      
(21,737
)
Cash flows provided by investing activities
                
Additions to oil and gas properties
    
(1,495
)
    
(20,040
)
Proceeds from sale of oil and gas properties
    
2,565
      
31,922
  
Proceeds from sale of marketable securities
    
1,878
      
2,541
  
Additions to furniture and equipment
    
(10)
      
(353
)
Change in restricted cash
    
423
      
75
  
Net cash provided by investing activities
    
3,361
      
14,145
  
Cash flows from financing activities
                
Proceeds from the Global credit facility
    
—
      
8,250
  
Borrowing on short-term notes payable
    
—
      
850
  
Proceeds from related party borrowings
    
5,210
      
1,770
  
Proceeds from issuance of convertible notes
    
—
      
6,330
  
Payments on short-term notes payable
    
(93
)
    
(6,163
)
Payments on related party borrowings
    
(310
)
    
(2,598
)
Net cash provided by financing activities
    
4,807
      
8,439
  
Effect of exchange rate changes on cash
    
—
      
—
  
Net (decrease) increase in cash and cash equivalents
    
(732)
      
847
  
                 
Cash and cash equivalents, beginning of period
    
967
      
120
  
Cash and cash equivalents, end of period
  
$
235
    
$
967
  

 
29
 

PETROHUNTER ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS

   
Year Ended
September 30,
2009
  
  
Year Ended
September 30,
2008
  
   
($ in thousands)
  
Supplemental schedule of cash flow information
                
Cash paid for interest
  
$
315
    
$
2,698
  
Cash paid for income taxes
  
$
—
    
$
—
  
                 
Supplemental disclosures of non-cash investing and
financing activities
                
Contracts for oil and gas properties
  
$
—
    
$
(1,500)
  
Shares issued for debt conversion
  
$
—
    
$
6,920
  
Shares issued for commissions on offerings
  
$
—
    
$
56
  
Shares issued for property
  
$
149
    
$
9,000
  
Shares returned on property conveyances
  
$
—
    
$
(1,408)
  
Shares issued for payment of accrued interest
  
$
—
    
$
6,520
  
Shares issued for property and finder’s fee on property
  
$
—
    
$
367
  
Shares issued for vendor settlements
  
$
—
    
$
3,376
  
Warrants issued for debt
  
$
—
    
$
4,588
  
Discount associated with beneficial conversion feature
    and detachable warrants
  
$
—
    
$
6,956
  
Common stock subscriptions converted to notes and convertible debentures
  
$
—
    
$
2,858
  
Marketable securities received from sale of oil and gas properties
  
$
14,133
    
$
20,461
  
Acquisition of oil and gas properties by exchange of joint interest
    billings, oil and gas receivables and accounts payable
  
$
—
    
$
12,707
  
Accounts payable relieved in connection with property conveyance
  
$
1,455
    
$
—
  
Note payable relieved in connection with property conveyance
  
$
5,000
    
$
—
  



See accompanying notes to consolidated financial statements.

 
30
 

PETROHUNTER ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Organization and Basis of Presentation

We are an oil and gas exploration and production company, and we currently own oil and gas leasehold interests located in Australia (Beetaloo Basin) and in Western Colorado (Piceance Basin).  We are incorporated in the State of Maryland.

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).  

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”) and reincorporated under the laws of the state of Maryland.  Likewise, in October 2006, GSL changed its name to PetroHunter Operating Company.

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. The report of our independent registered public accounting firm on the financial statements for the years ended September 30, 2009 and 2008 includes an explanatory paragraph relating to substantial doubt or uncertainty of our ability to continue as a going concern.  As shown in the accompanying statements of operations, we have an accumulated deficit of $279.2 million and net loss of $129.7 million for the year ending September 30, 2009, and as of that date we have a working capital deficit of $64.9 million.
 
Cash and Cash Equivalents – We consider investments in highly liquid financial instruments with an original stated maturity of three months or less to be cash equivalents.

Comprehensive Loss – FASB ASC 220, “Comprehensive Income”, establishes standards for reporting and display of comprehensive income and its components in financial statements. It requires that all items that are required to be recognized under accounting standards as components of comprehensive income be reported in the financial statement that is displayed with the same prominence as other financial statements.  The Company’s comprehensive loss consists of both net loss and foreign currency translation adjustments and it is presented in the accompanying consolidated statements of shareholders' equity and comprehensive loss.

Concentration of Credit Risk – Financial instruments which potentially subject us to concentrations of credit risk consist of cash and marketable securities. We periodically evaluate the credit worthiness of financial institutions, and maintain cash accounts only with major financial institutions, thereby minimizing exposure for deposits in excess of federally insured amounts. On occasion, the Company may have cash in banks in excess of federally insured amounts. We believe that credit risk associated with cash is remote.  Marketable securities credit risk is discussed later in Note 3 - Restricted Cash and Marketable Securities.

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Debt Issuance Costs – Debt issuance costs represent direct costs incurred for the issuance of long-term debt. These costs are amortized to interest expense over the lives of the respective debt issues using the effective interest method. When debt is repaid early or when it becomes apparent that underlying debt will not be held to maturity, the portion of unamortized debt issue costs related to the principal repayment is written off and included in interest expense.

Fair Value – We apply the provisions of FASB ASC 820,”Fair Value Measurements”. The carrying amounts reported in the consolidated balance sheets for cash, receivables, marketable securities, prepaid assets, accounts payable and accrued liabilities approximate fair value because of the immediate or short-term maturity of these financial instruments. Fair values of assets and liabilities measured on a recurring basis as of September 30, 2009 included restricted and unrestricted marketable securities, recorded at fair values of $ $2.9 million and $0.5 million, respectively, which had quoted prices in active markets for identical assets (level 1) of $2.9 million and $0.5 million respectively.

Impairment – We apply the provisions of FASB ASC 360, “Property Plant and Equipment”, which addresses financial accounting and reporting for the impairment or disposal of long-lived assets.  FASB ASC 360 requires a long-lived asset to be sold to be classified as “held for sale” in the period in which certain criteria are met, including that the sale of the asset within one year is probable.  FASB ASC 360 also requires that the results of operations of a component of an entity that either has been disposed of or is classified as held for sale be reported in discontinued operations if the operations and cash flows of the component have been or will be eliminated from the Company’s ongoing operations.

The Company periodically reviews the carrying value of its long-term assets in relation to historical results, current business conditions and trends to identify potential situations in which the carrying value of assets may not be recoverable.  If such reviews indicate that the carrying value of such assets may not be recoverable, the Company would estimate the undiscounted sum of the expected cash flows of such assets to determine if such sum is less than the carrying value of such assets to ascertain if an impairment exists. If an impairment exists, the Company would determine the fair value by using quoted market prices, if available for such assets, or if quoted market prices are not available, the Company would discount the expected future cash flows of such assets.

Income Taxes – We record income taxes under the asset and liability method prescribed by FASB ASC 740, “Income Taxes”. Under this method, deferred tax assets and liabilities are recognized for temporary differences between the financial statement amounts and the tax basis of certain assets and liabilities by applying statutory rates in effect when the temporary differences are expected to reverse.

Loss Per Common Share – We do not report fully diluted loss per common share as the effect would be anti-dilutive.

Marketable Securities – We account for marketable securities with FASB ASC 320, “Accounting for Certain Investments in Debt and Equity Securities”. We account for marketable securities by marking to market with unrealized gains and losses reflected as a component of Other Comprehensive Income, until such gains or losses become realized, at which time they are then recognized in our statement of operations. In addition, in circumstances where significant price declines are experienced subsequent to the balance sheet date, we consider whether such declines are other than temporary. After considering our expected holding period, we may record a provision for impairment in the event we do not expect the value of the securities to recover from such a decline in market value. We consider our accounting for marketable securities to involve significant management judgment that is subject to estimation.

Oil and Gas Properties – The Company applies the full cost method of accounting for its oil and gas properties. Under this method, subject to a limitation based on estimated value, all costs associated with property acquisition, exploration and development, including costs of unsuccessful exploration, are capitalized within a cost center on a by country basis. No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas properties unless the sale represents a significant portion of oil and gas properties and the gain significantly alters the relationship between capitalized costs and proved oil and gas reserves of the cost center. Depletion of oil
 
32
 
and gas properties is computed on the units-of-production method based on proved reserves. This includes estimates of future development costs of proved undeveloped reserves.

Capitalized costs of oil and gas properties may not exceed an amount equal to the present value, discounted at 10%, of the estimated future net cash flows from proved oil and gas reserves plus the cost, or estimated fair market value, if lower, of unproved properties. Should capitalized costs exceed this ceiling, an impairment is recognized. The present value of estimated future net cash flows is computed by applying year-end prices of oil and natural gas to estimated future production of proved oil and gas reserves as of year-end, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions.
 
Operating Leases – We lease our offices under operating leases, and our lease agreements generally include rent escalation clauses. Most of the Company’s lease agreements include renewal periods at the Company’s option. We recognize scheduled rent increases on a straight-line basis over the lease term beginning with the date the Company takes possession of the leased space. Deferred rent relates to certain of our operating leases containing predetermined fixed increases of the base rental rate during the lease term being recognized as rental expense on a straight-line basis over the lease term. We have recorded the difference between the amounts charged to operations and amounts payable under the leases as other liabilities in the accompanying consolidated balance sheets.

Property and Equipment – Property and equipment are stated at cost and depreciated using the straight-line method over the estimated useful lives of the related assets approximating seven years. Leasehold improvements are amortized over the shorter of the lease term or the estimated useful lives of the related assets using the straight-line method. We have capitalized costs associated with various equipment leases in accordance with FASB ASC 840, “Accounting for Leases.” These amounts have been presented as components of our property and equipment in our consolidated balance sheets.

Reclassifications – Certain prior period amounts have been reclassified in the consolidated financial statements to conform to the current period presentation.

Restricted Cash – Restricted cash consists of certificates of deposit, underlying letters of credit for exploration permits, state and local bonds and guarantees to vendors.

 Revenue Recognition – We recognize revenues from the sale 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.  Revenue is presented on a gross basis, prior to deductions for taxes and gathering expenses.

Share-Based Compensation – We use the Black-Scholes option-pricing model and the straight-line attribution approach to determine the fair-value of stock-based awards in accordance with FASB ASC 718, “Stock Compensation”.   The option-pricing model requires the input of highly subjective assumptions, including the option’s expected life and the price volatility of the underlying stock. The Company’s expected term represents the period that stock-based awards are expected to be outstanding and is determined based on historical experience of similar awards, giving consideration to the contractual terms of the stock-based awards, vesting schedules and expectations of future employee behavior as influenced by changes to the terms of its stock-based awards. The expected stock price volatility is based on the Company’s historical stock prices.

Use of Estimates – The preparation of our consolidated 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 and disclosures of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ materially from those estimates.  Our significant estimates include the estimated life of long-lived assets, use of reserves in the estimation of depletion of oil and gas properties, impairment of oil and gas properties, asset retirement obligation liabilities and the market value of securities.

Asset Retirement Obligation – Asset retirement obligations associated with tangible long-lived assets are accounted for in accordance with FASB ASC 410,” Accounting for Asset Retirement Obligations”. The estimated
 
33
 
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 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. Accretion expense is recorded as a component of depreciation, depletion, amortization and accretion expense.
 
Recently Issued Accounting Pronouncements

In May 2009, the Financial Accounting Standards Board (“FASB”) issued FASB ASC 855 “Subsequent Events”. FASB ASC 855 incorporates accounting and disclosure requirements related to subsequent events into U.S. GAAP. The requirements of ASC 855 for subsequent-events accounting and disclosure are not significantly different from those in existing auditing standards, which we have historically followed for financial reporting purposes. As of June 30, 2009 we have adopted ASC 855 and we do not believe this standard had any material impact on our financial statements. We have evaluated subsequent events through the date of issuance of these consolidated financial statements, which is January 13, 2010.

In July 2009, the FASB issued new guidance relating to the “FASB Accounting Standards Codification” at FASB ASC 105, as the single source of authoritative nongovernmental U.S. generally accepted accounting principles (GAAP). The codification is effective for interim periods ending after September 15, 2009. All existing accounting standards are superseded as described in ASC 105. All other accounting literature not included in the Codification is non-authoritative. As of September 30, 2009 we have adopted ASC 105 and believe this did not impact our results of operations, financial position or cash flows.

In October 2009, we adopted certain accounting principles within FASB ASC 470, “Debt with Conversion and Other Options” that requires the proceeds from the issuance of certain convertible debt instruments to be allocated between a liability component (issued at a discount) and an equity component. The resulting debt discount is amortized over the period the convertible debt is expected to be outstanding as additional non-cash interest expense. The change in accounting treatment is effective for us in fiscal 2010, and it is required to be applied retrospectively to prior periods.  Management is currently assessing the potential impact that the adoption of this new guidance could have on our financial statements in fiscal 2010.

In October 2009, we adopted certain accounting principles within FASB ASC 805, “Business Combinations,” which requires an acquirer to recognize the assets acquired, the liabilities assumed, including those arising from contractual contingencies, any contingent consideration, and any noncontrolling interest in the acquiree at the acquisition date, measured at their fair values as of that date, with limited exceptions specified in the statement.  It also requires the acquirer in a business combination achieved in stages (sometimes referred to as a step acquisition) to recognize the identifiable assets and liabilities, as well as the noncontrolling interest in the acquiree, at the full amounts of their fair values (or other amounts determined in accordance with this accounting principle).  In addition, the accounting principle’s requirement to measure the noncontrolling interest in the acquiree at fair value will result in recognizing the goodwill attributable to the noncontrolling interest in addition to that attributable to the acquirer. ASC 805 also requires the acquirer to recognize changes in the amount of its deferred tax benefits that are recognizable because of a business combination either in income from continuing operations in the period of the combination or directly in contributed capital, depending on the circumstances. It also provides guidance on the impairment testing of acquired research and development intangible assets and assets that the acquirer intends not to use.  ASC 805 applies prospectively to business combinations for which the acquisition date on or after October 1, 2009, therefore, the adoption of ASC 805 did not have any impact on our historical financial statements.

In October 2009, we adopted certain accounting principles within FASB ASC 810, “Consolidation,” which establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It also clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements.  ASC 810 also changes the way the consolidated income statement is presented by requiring consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the noncontrolling interest. It also requires disclosure, on the face of the consolidated statement of income, of the amounts of consolidated net income
 
34
 
attributable to the parent and to the noncontrolling interest. ASC 810 requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated and requires expanded disclosures in the consolidated financial statements that clearly identify and distinguish between the interests of the parent owners and the interests of the noncontrolling owners of a subsidiary.  The adoption of ASC 810 did not have any impact on our historical financial statements.
 
In January 2010, the FASB issued Accounting Standards Update (ASU) No. 2010-03 “Oil and Gas Reserve Estimation and Disclosures.” The ASU aligns the current oil and gas reserve estimation and disclosure requirements of FASB Accounting Standards Codification Topic 932, Extractive Activities — Oil and Gas, with those in SEC Final Rule Release No. 33-8995, Modernization of Oil and Gas Reporting. The ASU will be effective for reporting periods ending on or after December 31, 2009. We are currently assessing the impact that adoption of this rule will have on our financial statements.
 
In December 2008, the SEC issued revised reporting requirements for oil and natural gas reserves that a company holds. Included in the new rule entitled “Modernization of Oil and Gas Reporting Requirements”, are the following changes: 1) permitting use of new technologies to determine proved reserves, if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes; 2) enabling companies to additionally disclose their probable and possible reserves to investors, in addition to their proved reserves; 3) allowing previously excluded resources, such as oil sands, to be classified as oil and natural gas reserves rather than mining reserves; 4) requiring companies to report the independence and qualifications of a preparer or auditor, based on current Society of Petroleum Engineers criteria; 5) requiring the filing of reports for companies that rely on a third party to prepare reserve estimates or conduct a reserve audit; and 6) requiring companies to report oil and natural gas reserves using an average price based upon the prior 12-month period, rather than year-end prices. The new requirements are effective for registration statements filed on or after January 1, 2010, and for annual reports on Form 10K for fiscal years ending on or after December 31, 2009. Early adoption is not permitted. We are currently assessing the impact that adoption of this rule will have on our financial disclosures.
 
Other recent accounting pronouncements issued by the FASB (including its Emerging Issues Task Force), the AICPA, and the SEC did not, or are not believed by management to, have a material impact on our present or future consolidated financial statements.

Note 3 - Restricted Cash and Marketable Securities

As of September 30, 2009, long term restricted cash consists of $0.1 million in certificates of deposit underlying letters of credit for exploration permits, state and local bonds and guarantees to vendors.

As of September 30, 2009, we have recorded $3.4 million in restricted marketable securities on our Consolidated Balance Sheet, representing the 23.1 million shares of Falcon common stock that we held on this date. The Falcon shares are restricted through an escrow agreement that restricts the timing of and quantity of the sale of the common stock. As described in Note 2, we have accounted for these securities in accordance with FASB ASC 320, “Accounting for Certain Investments in Debt and Equity Securities”. Subsequent to September 30, 2009, the Falcon shares experienced a significant decline in value which we deemed to be an “other than temporary” decline. We determined that the decline in the value of the Falcon shares to be other than temporary based on various factors, including Falcon’s financial condition as well as our ability to hold these securities. Accordingly, we have recorded impairment expense of $8.5 million for the year ended September 30, 2009. We recorded impairment expense related to these securities in the amount of $0.8 million for the year ended September 30, 2008.

Note 4 — Oil and Gas Properties

Summary – Oil and gas properties at September 30, 2009 and 2008 consisted of the following ($ in thousands):

   
2009
    
2008
  
Oil and gas properties, at cost, full cost method
            
Unproved
            
United States
  
$
—
    
$
82,040
  
Australia
    
1,427
      
2,536
  
Proved
    
—
      
69,704
  
Total
    
1,427
      
154,280
  
Less accumulated depreciation, depletion, amortization and impairment
    
—
      
(56,928
)
Total
  
$
1,427
    
$
97,352
  

Included in oil and gas properties above is capitalized interest of $0.0 million and $0.3 million for the years ended September 30, 2009 and 2008, respectively.

The following is a summary of oil and gas property costs not subject to amortization by prospect at September 30, 2009 and 2008 ($ in thousands):

   
2009
    
2008
  
United States
  
$
—
    
$
82,040
  
Australia
    
1,427
      
(2,536
)
Total
  
 $
1,427 
    
 $
84,576 
  

The $1.4 million in oil and gas properties relates to a well in progress in our Beetaloo Basin project in the Northern Territory of Australia as discussed below.
 
35
 
Included below is the description of significant oil and gas properties and their current status.

Australia

During fiscal 2007 we drilled the Shenandoah #1 well located in the Beetaloo Basin in the Northern Territory of Australia. At this time we owned 100% of the working interest in this well and related leasehold interest. This well is located on oil and gas leasehold interest we held through four exploration permits that included 7,000,000 acres. In periods subsequent, we sold 75% of our 100% working interest in this well and the related acreage to Falcon Australia, who now operates the project. During fiscal 2009, we participated in the deepening of this well, the Shenandoah #1A, which is shut-in awaiting additional expenditure that was deferred primarily due to seasonal weather conditions.

US Projects – Piceance Basin

Buckskin Mesa Project – The Buckskin Mesa Project area was purchased on September 17, 2005 from MAB Resources, subject to certain agreements with Daniels Petroleum Company ("DPC").  The property is located in the northern part of the Piceance Basin in Rio Blanco County, Colorado.  The acquisition included 20,000 net acres and five previously drilled that were shut-in. PetroHunter has drilled five wells on this acreage and attempted to complete three of these wells in the first quarter of 2009. All ten wells are shut-in.

Per the agreement with DPC we were required to drill 5 additional wells by July 31, 2009, or pay DPC $2.0 million, or return these leases to DPC. We did not drill these additional five wells. Global holds a first lien on this leasehold interest as described in Note 8- Notes Payable. We are in the process of negotiating a mutually agreeable alternative with Daniels in order to be able to further explore for oil and gas on this leasehold interest.

During the year ended September 30, 2009 we impaired the remaining value of our U.S. full cost pool as we did not have the financial capacity to continue exploring for oil and gas on this acreage.

US Projects – Discontinued

Piceance II Project – The Piceance II Project was acquired December 29, 2005 from MAB Resources.  The property is located in the Piceance Basin, Garfield County, Colorado, and included eight producing wells operated by Encana.  

We sold these eight wells in December 2008 for $2.3 million in cash, and we recorded a loss on conveyance of approximately $0.2 million. The remaining Piceance II Project undeveloped leasehold interest will be reassigned to the lessor as we have failed to meet the contract terms for drilling wells. In addition, we have accrued liquidating damages of $0.5 million associated this contract.

The following is a summary of depreciation, depletion, amortization and accretion, as reflected in the consolidated statements of operations (including depreciation, depletion and amortization of oil and gas properties per thousand cubic feet of natural gas equivalent) for the years ended September 30 ($ in thousands, except per thousand cubic feet):

   
2009
    
2008
    
2007
  
Depletion of oil and gas properties
   $ 8     $ 949     $ 1,040  
Depreciation of furniture and equipment
     215       273       192  
Accretion of asset retirement obligation
     21       8       13  
Total
     244       1,230       1,245  
Depletion per thousand cubic feet of natural gas equivalent
   $ 2.50     $ 2.45     $ 2.27  



 
36
 

Note 5 — Furniture and Equipment

Furniture and equipment at September 30, 2009 and September 30, 2008 is reported at cost, net of accumulated depreciation and consisted of the following:

   
2009
    
2008
  
Furniture and equipment
  
$
157
    
$
1,073
  
Less accumulated depreciation
    
      (35
)
    
(336
)
Total
  
$
122
    
$
737
  

Depreciation expense associated with office furniture and equipment was $0.2 million and $0.3 million for the years ended September 30, 2009, and 2008, respectively. In August 2009, we moved our office in Denver, Colorado.  As a component of this move we abandoned furniture, fixtures, as well as tenant improvements. We have recorded losses on abandonment of approximately $0.3 million in connection with this office move.

Note 6 — Other Accrued Liabilities

Other accrued liabilities as of September 30, 2009 and 2008 are summarized and described below:

   
2009
    
2008
  
Other accrued liabilities
   $ 7,273     $ 4,832  

On April 11, 2008, we closed the sale of certain natural gas gathering assets in our Buckskin Mesa project, for $0.7 million in cash consideration, and simultaneously entered into a gas gathering agreement with Clear Creek Energy Services (“CCES”) relating to the initial phase of a gas gathering system at Buckskin Mesa.  These agreements formalized and expanded upon a letter of understanding between the parties which contemplated a dedicated relationship with CCES in the development of a gas gathering system and the provision of gas gathering services within our Buckskin Mesa Project area (the “CCES Agreements”). In addition to customary terms and conditions, the CCES Agreements included a guarantee (the “Guarantee”) from us to CCES regarding their increasing financial commitments as they were incurred in relation to the development of the gas gathering system, including our contingent repurchase of the gas gathering assets we sold to CCES.  The triggering event for the Guarantee was contingent upon our mutual failure to execute a formal agreement for long-term gas gathering services in the future.  The resolution of this contingency was dependent upon, among other things, gas production levels from the initial phase gas gathering system for our Buckskin Mesa Project. Per the agreement, should we fail to execute a mutually agreeable long-term contract, CCES had the right to invoice us for their incurred costs and demand repayment within 20 days of our receipt of the demand invoice.  To secure our Guarantee, we executed a promissory note for an amount up to $11.5 million, secured by second deeds of trust on our Colorado properties.  The amount of the Guarantee is variable, based upon the underlying incurred costs by CCES as defined in the CCES Agreements. As of September 30, 2008, the Company has incurred a liability of $4.8 million in respect to this agreement.

During the year ended September 30, 2009, we deemed that the completion of this gathering system was economically unfeasible for us we and ceased pursing its completion.  As per our initial agreement with CCES, all amounts payable came due within 20 days of demand. In May 2009, we received a demand notice from CCES. We are currently in discussions with CCES management to develop a mutually agreeable settlement in conjunction with our discussions with DPC regarding the underlying leasehold interest, as well with Global who holds the first lien on this property. CCES has a second lien on the Buckskin Mesa acreage and wells.  As of September 30, 2009, the Company has incurred a liability of $7.3 million in respect to this agreement.


 
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Note 7 — 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 Company recognizes 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. Revisions to the liability are due to increases in estimated abandonment, changes in well economic lives, and changes to federal or state regulations regarding the abandonment of wells.  We have recorded our asset retirement obligation as a current liability in 2009, and in 2008 we classified it as long term.

Our asset retirement obligation liability as of September 30, 2009 and 2008 is summarized below ($ in thousands):

   
2009
    
2008
  
Beginning asset retirement obligation
  
$
114
    
$
136
  
Liabilities incurred
    
—
      
—
  
Liabilities settled
    
—
      
(16
)
Revisions to estimates
    
877
      
(14
)
Accretion expense
    
21
      
8
  
Ending asset retirement obligation
  
$
1,012
    
$
114
  

Note 8 — Notes Payable

Notes payable as of September 30, 2009 and 2008 are summarized below ($ in thousands):

   
2009
    
2008
  
Short-term notes payable
            
Installment loan                                                                                   
  
$
—
    
$
199
  
Vendor                                                                                   
    
81
      
              130
  
Notes payable – short-term
  
$
81
    
$
              329
  
                 
Convertible notes payable
  
$
6,956
    
$
6,956
  
Discount on convertible notes payable
  
 
     —
    
 
             (6,631)
  
Convertible notes payable  — net
  
$
                   6,956
    
$
              325
  
                 
Notes payable – related party – short-term
                
Bruner Family Trust                                                                                   
  
$
2,829
    
$
2,722
  
Global Project Finance AG                                                                                   
    
40,650
      
850
  
Notes payable – related party, short-term
  
$
43,479
    
$
              3,572
  
                 
Long-term notes payable – related party — net
                
Global Project Finance AG                                                                                   
  
$
—
    
$
39,800
  
Bruner Family TrustTrustTrust                                                                                   
    
—
      
107
  
Discount on notes payable payable                                                                                   
    
            —
      
          (2,017
)
Long-term notes payable – related party — net
  
$
—
    
$
            38,035
  
                 
Other long – term liabilities, including capital lease obligations 
  
$
29
    
$
            —
  


 
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Short-Term Notes Payable

Installment loan – On June 6, 2008, we entered into a promissory note with Flatiron Capital for the financing of certain insurance policies in the amount of $0.2 million. The note bears interest at a rate of 4.15% per annum. Payments are due in 11 equal installments commencing on July 6, 2008 and maturing on May 6, 2009. The note is secured by unearned premiums and the balance at September 30, 2008 was $0.2 million.  

Vendor – In August 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 were originally due in 24 equal installments commencing on October 1, 2007 and maturing on September 1, 2009.  At September 30, 2009, we owed $0.1 million related to this note.  We defaulted on our obligations under the terms of this note prior to the maturity date and remained in default as of September 30, 2009. 
 
Notes Payable – Related Party Short-Term

Bruner Family Trust – At various times during 2008, we entered into five promissory notes with the Bruner Family Trust.  Each note accrues interest at LIBOR plus 3% per annum and was originally due 12 months from each note’s respective date of issuance.  A note for $2.4 million was originally due on November 13, 2008, but was extended by the lender.  The remaining four notes were originally due in February, March (2) and August 2009.  We continue to receive waivers from the lender on a quarterly basis related to our covenant violations and in relation to our default and failure to make scheduled principal and interest payments. The possibility exists that lender will call all amounts due at the end of each ninety day reporting period. As of September 30, 2009, accrued interest relating to these notes was $ 0.3 million, and the total note balance was $2.8 million.
 
Global Project Finance AG – On October 10, 2007, we entered into a promissory note with Global Project Finance, AG (“Global”).  The entire balance on the notes was due and payable, on December 31, 2008, along with the accrued interest. We received a waiver that extended the due date on these notes through July, 2009, subsequent to that date we are considered to be in default, and the notes may be called at any time. The note is unsecured and the note balance at September 30, 2009 was $0.8 million. Accrued interest is $0.2 million on this note.

In December 2008, we issued a promissory note in the amount of $0.1 million to Global. This note bore interest at 15% per annum.  As of September 30, 2009 we have repaid this note and all accrued interest.

On January 9, 2007, we entered into a Credit and Security Agreement (the “January 2007 Credit Facility”) with Global in the amount of $15.0 million.  As of September 30, 2009, and September 30, 2008, amounts drawn against this facility were $15.0 million.

On May 21, 2007, we entered into a second Credit and Security Agreement with Global (the “May 2007 Credit Facility”) and we extended all the economic terms from the May 2007 Credit Facility retroactively to the January 2007 Credit Facility. Under the May 2007 Credit Facility, Global agreed to use its best efforts to advance up to $60 million to us over the following 18 months. As of September 30, 2009 and 2008 amounts drawn against this facility were $24.8 million.

In connection with the May 2007 Credit Facility, Global received warrants to purchase 2.0 million of our common shares at the date of execution and was to receive 0.4 million warrants for each $1.0 million advanced under the Facility.  We agreed to pay an advance fee of 2% on all amounts drawn under the May 2007 Credit Facility.  Payments were to have been 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 loans are collateralized by a first perfected security interest on certain oil and gas properties and other of our assets. In the event that we sell any interest in the oil and gas properties that comprise the collateral, a mandatory payment is due in the amount equal to such sales proceeds.
 
As of September 30, 2009 and 2008 the cash portion of the advance fees payable in the amount of $0.8 million, incurred proportionately at 2% of each respective draw, had been recorded as a deferred financing cost and these amounts have been amortized to interest expense over the life of the Facilities.  The fair value of the 4 million warrants issued in conjunction with the advances was $1.9 million, valued using the Black-Scholes method, and was
 
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initially being amortized over the same time frame.  The fair value of the 28.5 million warrants issued in connection with the debt was $4.9 million valued using the Black- Scholes Method.

In September 30, 2008, the Company entered into a conversion and release agreement wherein $6.5 million in accrued interest owed to Global related to these Credit Facilities was converted into 32.6 million shares of our common stock at $0.20 per share, which was above the fair value of the shares at that time.  The $2.6 million value of the interest obligation converted to our common stock in excess of the fair value of the shares, and was recorded as additional paid in capital.  Global agreed to accept the shares as complete and total payment for the accrued interest. We deemed that as of the date of this transaction and for all periods subsequent we would consider Global to be a related party. The character of this relationship changed effective in the fourth quarter of the year ended September 30, 2008.

As of September 30, 2009, we were in default of payments in the amount of $0.8 million, which consisted of unpaid advance fees on the Global Facilities, but we obtained a comprehensive waiver from the lender that on October 1, 2009.  As of September 30, 2009, we were in default in respect to the $0.9 million promissory note as well as the associated accrued interest of $0.2 million. As of September 30, 2009, we had received waivers related to our failure to pay principal and interest and various covenant violations related to the $39.8 million drawn on the two credit facilities. These waivers expired on December 31, 2009.  We have accrued $4.1 million in interest related to this debt as of September 30, 2009.

As of September 30, 2009, as we were in default with Global in respect to the promissory notes of $0.9 million and credit facilities of $39.8, we have accelerated the accretion and amortization of the debt discount, and deferred financing costs related to these instruments and recognized $0.2 million in interest expense related to this acceleration.

Falcon Loan – In October 2008, we entered into a 10% secured loan agreement with Falcon (“Falcon Loan”). Under the terms of the loan agreement, Falcon agreed to advance to us $5.0 million.  This loan was secured by 14.5 million shares of Falcon common stock we had received as consideration in relation to the sale of a 50% working interest in our four exploration permits in Australia to Falcon in October 2008.   In addition the loan was also secured by a first position security interest in our five well bores in our Buckskin Mesa project. In June 2009, we sold an additional 25% interest in our exploration permits in the Beetaloo Basin to Falcon. As a component of our consideration, the $5.0 million note was forgiven by Falcon.

Convertible Debentures – In December 2008, we issued three subordinated convertible debentures totaling $0.2 million to two related parties. These debentures bore interest at 15% per annum and were due in May 2009. We issued 0.5 million warrants to purchase our common stock at $0.15 per share in connection with these debentures.  As of September 30, 2009 these debentures along with all related accrued interest have been repaid.

Shareholder Loans – We issued an 18% subordinated debenture in the amount of $0.03 million to a shareholder of the Company in exchange for the relief of amounts due the shareholder. The subordinated debenture is collateralized by an interest in .01 million shares of Falcon common stock held by us as unrestricted marketable securities. In connection with the issuance of the debenture we issued 0.07 million warrants to purchase our common stock at $0.15 per share, which expire in January 2010.  The debenture was due on April 15, 2009. As of September 30, 2009 we have paid the balance on this loan down to $0.015 million and we reclassified this loan to accounts payable as of September 30, 2009.


 
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Convertible Debt

Convertible notes payable as of September 30, 2009 and 2008 are summarized below ($ in thousands):

   
September 30,
2009
     September 30, 2008  
       
Convertible debentures – face value at issuance
   $ 6,956     $ 6,956  
Relative fair value assigned to warrants
     (3,532 )     (3,532 )
Relative fair value of beneficial conversion feature
     (3,424 )     (3,424 )
  Net book value of convertible debentures at issuance
     —       —  
Accumulated accretion
     6,956       325  
  Net book value
   $ 6,956     $ 325  

In November 2007, we issued $7.0 million in convertible debentures (the “Debentures”) 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 allowing them to purchase a total of 46.4 million shares of common stock at prices ranging from $0.24 to $0.28 per share.  We determined that the relative fair value of the warrants was approximately $3.5 million at issuance, under the Black-Scholes model. 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 $0.25 to $0.28 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 of our common stock (at our option) quarterly, beginning upon our successful registration of the warrant shares, as noted below.  All overdue unpaid interest accrues a late fee of 18% per annum, calculated based on the entire unpaid interest balance.

We originally agreed to file a registration statement with the Securities and Exchange Commission in order to register the shares issuable upon conversion of the debentures and the shares issuable upon exercise of the warrants. According to the Registration Rights Agreement, the registration statement was to be filed by March 4, 2008 and declared effective by July 2, 2008. The following penalties were to apply if filing deadlines were not met in compliance with the stated rules: (i) we agreed to pay  1% of the purchase price in cash as partial liquidated damages, subject to maximum aggregate liquidated damages of 18% of the aggregate subscription amount paid by the holder; (ii) if we were to fail to pay liquidated damages in full within seven days of the date payable, we agreed to pay interest of 18% per annum, accruing daily from the original due date subject to proration related to any portion of a month prior to the cure event; and (iii) all fees and expenses associated with compliance to the agreement would be borne by the Company.

Similarly, we have entered into various waiver agreements with respect to the interest installments due.  As consideration for these waivers, we have been able to delay and/or forego scheduled interest payments.

A waiver was executed in relation to the payment of a scheduled interest installment due July 1, 2008 by September 30, 2008, together with late fees of 18% per annum.  In addition, warrants to purchase our common stock were issued in an amount equal to 2% of the shares each purchaser received with the original agreement.  On September 30, 2008, we paid all past due interest in accordance with these waiver agreements.