Edgar Filing: ENERNORTH INDUSTRIES INC

As filed with the Securities and Exchange Commission on October 5, 2006

United States

Securities and Exchange Commission

Washington, D.C. 20549

Form 20-F

(Mark One)

o Registration Statement pursuant to Section 12(b) or (g) of The Securities Exchange Act of 1934

x Annual Report pursuant to Section 13 or 15(d) of The Securities Exchange Act of 1934

For the fiscal year ended June 30, 2006

o Transition Report pursuant to Section 13 or 15(d) of The Securities Exchange Act of 1934

o Sell Company Report pursuant to Section 13 or 15(d) of The Securities Exchange Act of 1934

Date of event requiring this shell company report.............................

For the transition period from ________ to _________

Commission file number: 0-29586

EnerNorth Industries Inc.

(Exact name of Registrant as specified in its charter)

Province of Ontario, Canada

(Jurisdiction of incorporation or organization)

1 King Street West, Suite 1502, Toronto, Ontario, M5H 1A1

(Address of principal executive offices)

Securities registered or to be registered pursuant to Section 12(b) of the Act:

Common Shares, no par value The American Stock Exchange

Title of each class Name of each exchange on which registered

Securities registered or to be registered pursuant to Section 12(g) of the Act:

None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:

None

Indicate the number of outstanding shares of each of the issuer's classes of capital or common stock as of the close of the period covered by the Annual Report:

4,272,009 Common Shares as of June 30, 2006

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes o No x

If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.

Yes o No x

Note - Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x No o

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

Large accelerated filer o Accelerated filer o Non-accelerated filer x

Indicate by check mark which financial statement item the registrant has elected to follow:

Item 17 x Item 18 o

If this is an Annual Report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act):

Yes o No x

(Applicable only to Issuers involved in bankruptcy proceedings during the past five years)

- -

ENERNORTH INDUSTRIES INC.

Form 20-F Annual Report

Table of Contents

PART I

ITEM 1	Identity of Directors, Senior Management and Advisers	5
	A. Directors and Senior Management	5
	B. Advisers	5
	C. Auditors	5

ITEM 2	Offer Statistics and Expected Timetable	5
	A. Offer Statistics	5
	B. Method and Expected Timetable	5

ITEM 3	Key Information	5
	A. Selected Financial Data	5
	B. Capitalization and Indebtedness	10
	C. Reasons for the Offer and Use of Proceeds	10
	D. Risks Factors	10

ITEM 4	Information on the Company	22
	A. History and Development of the Company	22
	B. Business Overview	29
	C. Organizational Structure	30
	D. Property, Plants and Equipment	30

ITEM 4A	Unresolved Staff Comments	37

ITEM 5	Operating and Financial Review and Prospects	37
	A. Operating Results	41
	B. Liquidity and Capital Resources	46
	C. Research and Development, Patents and Licenses	47
	D. Trend Information	48
	E. Off-balance Sheet Arrangements	48
	F. Tabular Disclosure of Contractual Obligations	48
	G. Safe Harbor	49

ITEM 6	Directors, Senior Management and Employees	58
	A. Directors and Senior Management	58
	B. Compensation	61
	C. Board Practices	64
	D. Employees	72
	E. Share Ownership	73

ITEM 7	Major Shareholders and Related Party Transactions	74
	A. Major Shareholders	74
	B. Related Party Transactions	74
	C. Interests of Experts and Counsel	75


ITEM 8	Financial Information	76
	A. Consolidated Statements and Other Financial Information	76
	B. Significant Changes	79

ITEM 9	The Offer and Listing	79
	A. Offer and Listing Details	79
	B. Plan of Distribution	81
	C. Markets	81
	D. Selling Shareholders	81
	E. Dilution	81
	F. Expenses of the Issue	81

ITEM 10	Additional Information	81
	A. Share Capital	81
	B. Memorandum and Articles of Association	82
	C. Material Contracts	84
	D. Exchange Controls	85
	E. Taxation	86
	F. Dividends and Paying Agents	89
	G. Statement by Experts	89
	H. Documents on Display	90
	I. Subsidiary Information	90

ITEM 11	Quantitative and Qualitative Information about Market Risk	90

ITEM 12	Description of Securities Other than Equity Securities	92
	A. Debt Securities	92
	B. Warrants and Rights	92
	C. Other Securities	92
	D. American Depositary Shares	92

	PART II

ITEM 13	Defaults, Dividend Arrearages and Delinquencies	92

ITEM 14	Material Modifications to the Rights of
	Security Holders and Use of Proceeds	92
ITEM 15	Controls and Procedures	92
ITEM 16	Reserved	93
ITEM 16A	Audit Committee Financial Expert	93
ITEM 16B	Code of Ethics	93
ITEM 16C	Principal Accountant Fees and Services	93
ITEM 16D	Exemptions From the Listing Standards for Audit Committees	94
ITEM 16E	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	94
ITEM 17	PART III Financial Statements	94
ITEM 18	Financial Statements	94

ITEM 19	Exhibits	94

PART I

Forward-Looking Statements

Certain statements contained in this Annual Report constitute "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995 (the "Reform Act"), which reflect the Company's current expectations regarding the future results of operations, performance and achievements of the Company. The Company has tried, wherever possible, to identify these forward-looking statements by, among other things, using words such as "anticipate," "believe," "estimate," "expect" and similar expressions. These statements reflect the current beliefs of management of the Company, and are based on current available information. Accordingly, these statements are subject to known and unknown risks, uncertainties and other factors which could cause the actual results, performance or achievements of the Company to differ materially from those expressed in, or implied by, these statements. (See, in general, "Item 3D. Key Information — Risk Factors" below.) The Company is not obligated to update or revise these "forward-looking" statements to reflect new events or circumstances unless required by securities law.

ITEM 1 IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS

ITEM 1.A DIRECTORS AND SENIOR MANAGEMENT

Not applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

ITEM 1.B ADVISERS

Not applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

ITEM 1.C AUDITORS

Not applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

ITEM 2 OFFER STATISTICS AND EXPECTED TIMETABLE

ITEM 2.A OFFER STATISTICS

Not applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

ITEM 2.B METHOD AND EXPECTED TIMETABLE

Not applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

ITEM 3 KEY INFORMATION

ITEM 3.A. SELECTED FINANCIAL DATA

The following table sets forth selected consolidated financial data of EnerNorth Industries Inc. ("EnerNorth" or the "Company") for its twelve-month fiscal periods ended June 30, 2002, June 30, 2003 June 30, 2004, June 30, 2005 and June 30, 2006, and are presented pursuant to Canadian Generally Accepted Accounting Principles ("Canadian GAAP").

The selected consolidated statement of operations data set forth below are for the twelve-month fiscal periods ended June 30, 2002, June 30, 2003, June 30, 2004, June 30, 2005 and June 30, 2006, and the selected consolidated balance sheet data set forth below are as of June 30, 2002 through June 30, 2006. The June 30, 2002, June 30, 2003, June 30, 2004, June 30, 2005 and June 30, 2006 statement of operations data and June 30, 2002, June 30, 2003, June 30, 2004, June 30, 2005 and June 30, 2006 balance sheet data are derived from the consolidated financial statements of the Company, which have been audited by BDO Dunwoody LLP, Chartered Accountants. The consolidated balance sheet data set forth below at June 30, 2002, June 30, 2003 and June 30, 2004 and statement of operations data for the years ended June 30, 2003 and June 30, 2002 are derived from audited financial statements not included elsewhere in this Annual Report.

The selected financial data should be read in conjunction with the consolidated financial statements of the Company for the years ended June 30, 2006, June 30, 2005 and June 30, 2004 included elsewhere in this Annual Report and with "Item 5 - Operating and Financial Review and Prospects" below.

EnerNorth Industries Inc.

Presented Pursuant to Canadian Generally Accepted Accounting Principles

(Canadian $000s, Except % Items and Per Share Data)

	(Audited)
	As of and for the Twelve Month Period Ended June 30,
	2002	2003	2004	2005	2006
Statement of Operations Data:

Financial INFORMATION:
Oil and gas revenue	$ 540,735	$ 673,573	$ 765,941	$ 946,655	$ 1,169,988
Less: royalties	92,272	93,824	106,485	201,172	189,720
Net revenue	448,463	579,749	659,456	745,483	980,268

Operating and transportation	260,599	279,189	292,275	399,795	394,863
Depletion and accretion	376,622	416,937	458,230	691,539	729,856
Administrative expenses	1,627,838	2,023,237	1,921,385	2,221,343	2,198,024
Interest	4,925	5,215	4,812	2,020	6,968
Income (loss) from operations...	(1,821,521)	(2,144,829)	(2,017,246)	(2,569,214)	(2,349,443)
Other items	(1,004,509)	5,830,915	1,828,360	(371,468)	1,116,461
Income tax	502,000	490,578	-	-	(457,159)
Net loss from operations before discontinued operations	(1,319,012)	(8,466,322)	(3,845,606)	(2,197,746)	(3,008,745)
Income (loss) and gain (loss) on disposition of discontinued operations (1)	187,642	418,846	1,627,664	2,034,997	-
Net loss for the year	(1,131,370)	(8,047,476)	(2,217,942)	(162,749)	(3,008,745)
Weighted average common shares outstanding(2)	2,212,795	3,806,224	4,059,009	4,059,009	4,099,883
Net loss from continuing operations per share (2)	($0.60)	($2.22)	($0.95)	($0.54)	($0.73)
Net loss per share (2)	($0.51)	($2.11)	($0.55)	($0.04)	($0.73)

- -

	As of and for the Twelve Month Period Ended June 30,
	2002	2003	2004	2005	2006
Other Financial Data:

Cash flows provided by (used in)
Operating activities	(2,020,541)	621,878	(3,052,995)	4,625,926	(789,226)
Investing activities	(2,998,503)	(896,749)	(2,660,646)	3,046,194	(4,787,912)
Financing activities	9,387,044	1,393,533	(415,329)	(2,986,118)	358,138

Purchase of oil and gas properties for cash	2,759,206	354,625	1,740,154	1,001,743	6,535,176

Balance Sheet Information:
Working capital (deficiency)	$7,313,998	$777,076	$814,985	(101,057)	(6,915,974)
Total assets	25,415,063	28,834,961	23,262,596	15,708,656	15,198,471
Due to shareholders, less current portion	-	-	-	-	-
Total long-term debt, less current portion	501,670	528,020	542,109	-	152,924
Non-controlling interest	-	-	75,141	-	-
Shareholders' equity (net assets)	18,058,682	11,253,606	7,089,878	7,076,238	4,542,157

____________________

(1)	During fiscal 2005 the Company sold its interests in M&M Engineering Limited (“M&M”). As a result the Industrial & Offshore Division has been treated as discontinued operations for accounting purposes, and prior years' statements of operations have been restated.

(2) Adjusted for a three-for-one share consolidation effective February 11, 2003.

The following table sets forth selected consolidated financial data of the Company as set forth in the preceding table, as reconciled pursuant to United States Generally Accepted Accounting Principles as allowed by Item 17 of Form 20F:

EnerNorth Industries Inc.

Presented Pursuant to United States Generally Accepted Accounting Principles

(Canadian $000s, Except % Items and Per Share Data)

	(audited)
	As of and for the Twelve Month Period Ended June 30,
	2002	2003	2004	2005	2006

Statement of Operations Data:
Financial INFORMATION:
Oil and gas revenue	$ 540,735	$ 673,573	$ 765,941	$ 946,655	$1,169,988
Less: royalties	92,272	93,824	106,485	201,172	189,720
Net revenue	448,463	579,749	659,456	745,483	980,268

Operating and transportation	260,599	279,189	292,275	399,795	394,863
Depletion and accretion	1,420,622	416,937	1,614,818	1,817,442	5,566,679
Administrative expenses	1,739,009	2,023,237	1,921,385	2,221,343	2,198,024
Interest	160,105	5,215	4,812	2,020	8,071
Income (loss) from operations...	(3,131,872)	(2,144,829)	(3,173,834)	(3,695,117)	(7,187,369)
Other items	(1,004,509)	5,830,915	1,828,360	(371,468)	(1,347,615)
Income tax	502,000	490,578	-	-	(457,159)
Net loss from operations before discontinued operations	(2,629,363)	(8,466,322)	(5,002,194)	(3,323,649)	(5,382,595)
Income (loss) and gain (loss) on disposition of discontinued operations (1)	187,642	418,846	1,627,664	2,034,997	-
Cumulative effect of a change in accounting principle	2,056,832	-	-	-	-
Net loss for the year	(2,441,721)	(8,047,476)	(3,374,530)	(1,288,652)	(5,382,595)
Deemed dividend on preferred shares	-	-	-	-	-
Net loss available for common shareholders	(2,441,721)	(8,047,476)	(3,374,530)	(1,288,652)	(5,382,595)
Weighted average common shares outstanding(2)	2,212,795	3,806,224	4,059,009	4,059,009	4,099,883
Net loss from continuing operations per share	($1.19)	($2.22)	($1.23)	($0.82)	($1.31)
Net loss per share	($1.10)	($2.11)	($0.83)	($0.32)	($1.31)

	As of and for the Twelve Month Period Ended June 30,
	2002	2003	2004	2005	2006

Other Financial Data:

Cash flows provided by (used in)
Operating activities	(2,020,541)	621,878	(3,052,995)	4,625,926	(789,226)
Investing activities	(2,998,503)	(896,749)	(2,660,646)	3,046,194	(4,787,912)
Financing activities	9,387,044	1,393,533	(415,329)	(2,986,118)	358,138

Purchase of oil and gas properties for cash	2,759,206	354,625	1,740,154	1,001,743	6,535,176

Balance Sheet Information:
Working capital (deficiency)	7,313,998	827,688	923,635	105,530	(6,915,974)
Total assets	24,270,103	27,841,573	23,167,056	14,534,538	11,445,019
Due to shareholders, less current portion	-	-	-	-	-
Total long-term debt, less current portion	501,670	528,020	542,109	-	74,267
Non-controlling interest	-	-	75,141	-	-
Shareholders' equity (net assets)	17,014,682	10,260,218	6,994,338	5,902,120	867,362

____________________

(1)	During fiscal 2005 the Company sold its interests in M&M Engineering Limited (“M&M”). As a result the Industrial & Offshore Division has been treated as discontinued operations for accounting purposes, and prior years' statements of operations have been restated.

(2) Adjusted for a three-for-one share consolidation effective February 11, 2003.

Exchange Rate Information

The Company's accounts are maintained in Canadian dollars. In this Annual Report, all dollar amounts are expressed in Canadian dollars except where otherwise indicated.

The exchange rate used for the purpose of this Annual Report (other than financial statement information) for the conversion of Canadian dollars ("CDN $") into United States dollars ("US $") was US $0.8953353 as of September 18, 2006). The following table sets forth the exchange rates for the conversion of one Canadian dollar into one United States dollar at the end of the following periods, the high and low rates of exchange for such periods, and the average exchange rates for the periods (based upon the average of the exchange rates on the last day of each month during the periods). The rates of exchange set forth below are derived from the reciprocals of the noon buying rates in New York City for cable transfers payable in Canadian dollars, as certified for customs purposes by the Federal Reserve Bank of New York. The source of this data is the Federal Reserve Bulletin and Digest.

	2006	2005	2004	2003	2002
Period End	0.82	0.82	0.75	0.75	0.66
Low	0.80	0.74	0.70	0.63	0.62
High	0.91	0.85	0.78	0.75	0.66
Average*	0.86	0.80	0.75	0.67	0.64

*Calculated by using the average of the exchange rates on the last day of each month during the period.


Year 2006	September	August	July	June	May	April	March

High	0.90	0.90	0.89	0.90	0.91	0.89	0.88
Low	0.88	0.88	0.87	0.88	0.89	0.85	0.85

The rate of exchange for the conversion of United States dollars into Canadian dollars at September 18, 2006 was (US $1 = CDN $1.1169).

ITEM 3.B. CAPITALIZATION AND INDEBTEDNESS

Not applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

ITEM 3.C. REASONS FOR THE OFFER AND USE OF PROCEEDS

Not Applicable. This Form 20-F is being filed as an Annual Report under the Exchange Act.

ITEM 3.D. RISK FACTORS

The Company is subject to a number of significant uncertainties and risks, including, without limitation, those described below and those described elsewhere in this Annual Report, any of which may affect the Company in a manner and to a degree which cannot be foreseen at this time.

General Risk Factors

Need for additional capital. Exploration, development and acquisition of oil and gas reserves is a capital-intensive business. The Company makes, and will continue to make, substantial expenditures for exploration and development of oil and gas. Historically, the Company has financed operations primarily with proceeds from the sale of its equity securities in private offerings. The Company expects to satisfy its working capital requirements from cash flow and by raising capital through public or private sales of debt or equity securities, debt financing or short-term loans, or a combination of the foregoing. The Company has no current arrangements for obtaining additional capital, and no assurance can be given that the Company will be able to secure additional capital, or on terms which will not be objectionable to the Company or its then existing shareholders. Under such circumstances, the failure or inability of the Company to obtain additional capital on acceptable terms or at all could have a material adverse effect on the Company. As of the date of this Annual Report the Company also has an unfunded liability in the amount of approximately CDN $6,186,971 in relation to a Judgment against the Company (See “Oakwell Litigation”, “Item 5 - Operating and Financial Review and Prospects - Critical Accounting Estimates” and “Item 8.A.7. - Litigation” below). If the Judgment is enforced in Canada, the Company’s financial condition would be materially and adversely affected.

A history of losses and limited operating history. To date, we have incurred significant losses. The Company has a limited operating history upon which any evaluation of the Company and its long-term prospects might be based. The Company commenced its business plan for the exploitation of oil and gas in February of 2001. The Company is subject to the risks inherent in the oil and gas business. The Company and its prospects must be considered in light of the risks, expenses and difficulties encountered by all companies engaged in the extremely volatile and competitive oil and gas industry. Any future success the Company might achieve will depend upon many factors, including factors which will be beyond its control. These factors may include changes in technologies, price and product competition, developments and changes in the international oil and gas market, changes in the Company's strategy, changes in expenses, fluctuations in foreign currency exchange rates, general economic conditions (both in the United States and Canada), and economic and regulatory conditions specific to the areas in which the Company competes, among others. To address these risks, the Company must, among other things, continue to respond to competitive developments; attract, retain and motivate qualified personnel; implement and successfully execute its business plan; comply with environmental regulations; expand its portfolio of proven and prospective oil and gas properties and /or negotiate additional working interests and prospect participations; and expand and replace depleting oil and gas reserves. There can be no assurance that the Company will be successful in addressing these risks.

Variability of operating results. The Company's operating results may in the future fluctuate significantly depending upon a number of factors including industry conditions, oil and gas prices, rate of drilling success, rates of production from completed wells and the timing of capital expenditures. Such variability could have a material adverse effect on the Company's business, financial condition and results of operations. In addition, any failure or delay in the realization of expected cash flows from operating activities could limit the Company's future ability to continue exploration and to participate in economically attractive oil and gas projects.

Foreign exchange. Because energy commodity prices are primarily priced in US dollars, a portion of our revenue stream is affected by U.S./Canadian dollar exchange rates. We do not hedge this exposure. While to date this exposure has not been material it may become so in the future. The Oakwell Engineering Limited Claim is priced in US dollars and costs are priced in Singapore dollars. The Company maintains a nominal balance of US currency. These US and Singapore denominated balances are susceptible to changes in the exchange rate between Canada and the US and Canada and Singapore.

Foreign law may hinder our ability to repatriate foreign held investments. There may be restrictions on the withdrawal of capital or repatriation of dividends from a country in which the Company or one of its investment affiliates is operating. There is no assurance that the laws of any jurisdiction in which the Company holds investments or locates its assets may not change in a manner that materially and adversely affects the investments of the Company.

The North American Free Trade Agreement. On January 1, 1994, the North American Free Trade Agreement among the governments of Canada, the United States and Mexico became effective. In the context of energy resources, Canada continues to remain free to determine whether exports to the United States or Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy resource exported relative to domestic use (based upon the proportion prevailing in the most recent 36 month period); (ii) impose an export price higher than the domestic price; or (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum export or import price requirements and, except as permitted in enforcement of countervailing and antidumping orders and undertakings, minimum or maximum import price requirements.

The North American Free Trade Agreement contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions and export taxes. The North American Free Trade Agreement also contemplates clearer disciplines on regulators to ensure fair implementation of any regulatory changes and to minimize disruption of contractual arrangements, which is important for Canadian natural gas exports.

Insurance. The Company’s involvement in the exploration for and development of oil and gas properties may result in the Company becoming subject to liability for pollution, blow-outs, property damage, personal injury or other hazards. Although the Company carries insurance in accordance with industry standards to address such risks, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. In addition, such risks may not, in all circumstances be insurable or, in certain circumstances, the Company may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. The payment of such uninsured liabilities would reduce the funds available to the Company. The occurrence of a significant event that the Company is not fully insured against, or the insolvency of the insurer of such event, could have a material adverse effect on the Company’s financial position, results of operations or prospects.

Failure to Realize Anticipated Benefits of Acquisitions and Dispositions. The Company makes acquisitions and dispositions of businesses and assets in the ordinary course of business. Achieving the benefits of acquisitions depends in part on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner as well as the Company’s ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of EnerNorth. The integration of acquired business may require substantial management effort, time and resources and may divert management’s focus from other strategic opportunities and operational matters. Management continually assesses the value and contribution of services provided and assets required to provide such services. In this regard, non-core assets are periodically disposed of, so that the Company can focus its efforts and resources more efficiently. Depending on the state of the market for such non-core assets, certain non-core assets of the Company, if disposed of, could be expected to realize less than their carrying value on the financial statements of the Company.

Management of Growth. The Company may be subject to growth-related risks including capacity constraints and pressure on its internal systems and controls. The ability of the Company to manage growth effectively will require it to continue to implement and improve its operational and financial systems and to expend, train and manage its employee base. The inability of the Company to deal with this growth could have a material adverse impact on its business, operations and prospects.

Loss of key personnel could harm our business. Our ability to continue our business and to develop a competitive edge in the marketplace depends, in large part, on our ability to attract and maintain qualified management and personnel. Competition for such personnel is intense, and there can be no assurance that we will be able to attract and retain such personnel. Our development to date has depended, and in the future will continue to depend, on the efforts of our key executive officers, management and employees, including James C. Cassina, our Chairman of the Board of Directors, Sandra J. Hall, our President and Secretary and Scott T. Hargreaves, our Chief Financial Officer. The loss of any of these individuals could have a material adverse effect on the Company.

Potential Conflicts of Board and Committees. Some of the directors and officers of the Company are or may serve on the board of directors of other companies from time to time. To avoid the possibility of conflicts of interest which may arise out of their fiduciary responsibilities to each of the boards, all such directors have agreed to abstain from voting with respect to a conflict of interest between the applicable companies. In appropriate cases, the Company will establish a special committee of independent directors to review a matter in which a director, or a member of management, may have a conflict.

Reliance on expertise of certain persons. The Company is dependent on the advice, expertise and project management skills of various consultants including geologists, geophysicists, engineers and joint venture partners contracted by the Company from time to time.

Legal Proceedings. As of the date of this Annual Report, the Company has pending litigation, actions or proceedings as described below which could have a material effect on the Company's financial condition or profitability.

Oakwell Litigation Canada/India

In March 1997, Oakwell Engineering Limited (“Oakwell”) and the Andhra Pradesh State Electricity Board (“APSEB”) executed two identical Power Purchase Agreements (“PPAs”) providing for Oakwell to build, own and operate two identical 100 MW net capacity diesel generator barge mounted power plants, fueled by furnace oil (total 200 MW net capacity) and sell electricity to APSEB on a take-or-pay basis for 15 years (the “Project”). In June 1997, the Company and Oakwell formed an 87.5% - 12.5% joint venture and then incorporated an Indian company, EOPL (now known as KGPL), to implement the provisions of the PPAs. Disputes rose between the Company and Oakwell regarding the time taken to obtain financing for the Project and a Settlement Agreement was reached in December 1998 under which Oakwell sold the Company all of Oakwell's interest in the PPAs and in EOPL.

In July 2002, Oakwell claimed the Company was in breach of the Settlement Agreement over the same issue settled by the Settlement Agreement and in August 2002 the Company was named as a defendant in the High Court of Singapore, in the matter of Oakwell vs. the Company, Suit No. 997 of 2002/V. On October 16, 2003 the High Court of Singapore ordered the Company to pay Oakwell US $5,657,000 plus costs (the “Judgment”). On November 13, 2003 the Company appealed the Judgment to the Court of Appeal of the Republic of Singapore (Civil Appeal No. 129 of 2003/Y). That Court, which is the final Court of Appeal for Singapore, dismissed the appeal from the bench on April 27, 2004.

Canada

On June 21, 2004, Oakwell filed an Application with the Ontario Superior Court of Justice seeking an order recognizing and enforcing the Judgment in Ontario (Court File No.04-CV-271121 CM3). On August 30, 2004, the Company filed an Application with the Ontario Superior Court of Justice for a declaration that the Judgment cannot be recognized and enforced in the Province of Ontario (Court File No.04-CV-274860 CM2) on the basis that Singapore does not adhere to the Rule of Law and that the Singapore litigation did not provide the Company with an independent and impartial judiciary and accordingly could not be given the full faith and credit of the Canadian courts. The Applications were heard on December 6-9, 2004 before the Honourable Mr. Justice Day.

On January 10, 2005, after the Company publicly announced its intention to sell its engineering and offshore subsidiary, M&M Engineering Limited (“M&M”), Oakwell brought a motion in the Ontario proceedings seeking to prevent the Company from disposing of or encumbering assets equal to the Canadian dollar equivalent of the Judgment from the proceeds of the sale of M&M. On January 27, 2005, that motion was withdrawn and the Company agreed to provide Oakwell with 5 days notice before execution of any transaction or series of related transactions exceeding $2.4 million from the proceeds from the sale of M&M.

On June 27, 2005 Justice Day released his decision, in which he granted Oakwell's Application with costs, and dismissed the Company's Application. The formal Order granting recognition and enforcement to the Judgment was issued August 2, 2005.

On July 13, 2005, the Company filed a Notice of Appeal with respect to Justice Day's decision with the Court of Appeal for the Province of Ontario (“Court of Appeal”) (Court of Appeal File Number C43898). The appeal was heard April 10, 2006. On June 9, 2006 the Court of Appeal rendered its decision, dismissing the Company's appeal with costs.

On July 18, 2006 the Company brought a motion before the Court of Appeal (Court of Appeal File Number: M33962) seeking a stay of execution of the decision of the Court of Appeal pending the Company’s application to the Supreme Court of Canada for leave to appeal, and, should leave be granted, the appeal itself. On July 28, 2006 the Court of Appeal granted the Company's motion for a stay of execution on the condition that the Company pay CDN$1,500,000 into Court on or before September 8, 2006. The Company paid this amount into Court on September 7, 2006.

On September 8, 2006 the Company filed its application for leave to appeal to the Supreme Court of Canada (Supreme Court of Canada Court File Number: 31620). The Supreme Court of Canada will only grant leave if it is persuaded that the case raises issues of public importance. The Court's decision on the leave application is not expected until late 2006 or early 2007.

India

On January 12, 2005, Oakwell filed an Execution Petition before the Hon’ble High Court of Delhi, India (“Delhi Court”) which was served on February 14, 2005 against the Company for enforcement of the Singapore Judgment in India against certain assets of the Company alleged located in India (Execution Petition No. 22/2005) and an application for interim relief seeking attachment of certain assets of the Company including its Konaseema Gas Power Limited (“KGPL”) Shares.

On May 23, 2005, the Delhi High Court ordered that if VBC Ferro Alloys Ltd. (“VBC”) purchases the Company’s KGPL shares the sale proceeds shall be kept in India and on September 9, 2005 the Delhi Court further ordered that if the Company receives any payments from VBC from the sale of it’s KGPL Shares, then the proceeds shall be deposited in the Company’s account held in a Public Sector Bank in India or invested only in Government of India securities until the disposal of Oakwell’s Execution Petition. This order became infructuous upon the Company withdrawing its Execution Petition against VBC and not otherwise receiving any payment from VBC by way of sale of KGPL shares.

On August 29, 2006 the Delhi Court dismissed the objections filed by the Company (Execution Application No. 385/2005) as to the maintainability of the Execution Petition and questioning the Jurisdiction of Delhi Court. The Company filed a Review Petition (Execution Application 474/2006) and a Stay Petition (Execution Application 475/2006) against the Order of August 29, 2006 and a hearing is scheduled for October 13, 2006.

On September 7, 2006 Oakwell filed (Execution Application 482/2006) for interim relief, seeking restraint on the disposal of the Company’s KGPL shares and other assets. On September 18, 2006 the Delhi Court ordered that until October 13, 2006 the date of next hearing, the Company shall not deal with, transfer or alienate the KGPL shares or other assets.

The Execution Petition and related applications are ongoing. (See “Item 5 - Operating and Financial Review and Prospects - Critical Accounting Estimates” and “Item 8A7 - Litigation” below).

Investment in Marketable Securities The Company’s investments in Marketable Securities is carried at the lower of cost or market value. The actual market value is determined by external factors that are beyond the control of the Company and may fluctuate materially. Causes of fluctuation include but are not isolated to changes in oil and gas commodities as much of the Company's portfolio is dominated by oil and gas investments. The portfolio is also influenced by the individual performance of each company as well as the performance of the overall market and economy. As a result, the Company could be exposed to a significant decline in the market value of its entire investment in marketable securities. If the market value of its marketable securities decreased significantly it would have a material adverse effect on the income and cash flow of the Company.

Risk Factors Relating to Oil and Gas Exploration, Development and Production

Uncertain discovery of viable commercial prospects. The Company's future success may be dependent upon its ability to economically locate commercially viable oil or gas deposits. The Company can make no representations, warranties or guaranties that it will be able to consistently identify viable prospects, or that such prospects will be commercially exploitable. An inability of the Company to consistently identify and exploit commercially viable hydrocarbon deposits would have a material and adverse effect on the Company's business and financial position.

Risk of exploratory drilling activities. Under the Company's business plan, revenues and cash flow will continue to be principally dependent upon the success of drilling and production from prospects in which the Company participates. The success of such prospects will be determined by the economical location, development and production of commercial quantities of hydrocarbons. Exploratory drilling is subject to numerous risks, including the risk that no commercially productive oil and gas reservoirs will be encountered. The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including unexpected formation and drilling conditions, pressure or other irregularities in formations, blowouts, equipment failures or accidents, as well as weather conditions, compliance with governmental requirements and/or shortages or delays in the delivery of equipment. The inability to successfully locate and drill wells that will economically produce commercial quantities of oil and gas could have a material adverse effect on the Company's business and, financial position.

Drilling and explorations plans subject to change. This Annual Report includes descriptions of the Company’s prospective future drilling and explorations plans with respect to its properties. A prospect is a property which the Company and its partners have identified based on available geological and geophysical information that indicate the potential for hydrocarbons. The Company's properties are in various stages of exploration and development. Whether the Company ultimately drills a property may depend on a number of factors including funding; the receipt of additional seismic data or reprocessing of existing data; material changes in oil or gas prices; the costs and availability of drilling equipment; success or failure of wells drilled in similar formations or which would use the same production facilities; changes in estimates of costs to drill or complete wells; the Company's ability to attract industry partners to acquire a portion of its working interest to reduce exposure to drilling and completion costs; decisions of the Company's joint working interest owners; and/or restrictions under provincial regulators.

Restrictions on development and production as a non-operator. The Company holds minority interests in certain of its properties, and therefore cannot control the pace of an exploration/development program effecting the drilling of wells, or a plan for development and production. If a majority partner decides to accelerate development of a program it may exceed the Company's ability to meet its share of costs at a faster pace than anticipated, and may surpass the Company's ability to further finance its ongoing proportional obligation to fund costs. If the Company were unable to meet its funding obligations with respect to one or more prospect(s), its proportional working interest in such prospect(s) would be diluted.

Volatility of oil and natural gas prices. The ultimate profitability, cash flow and future growth of the Company will be affected by changes in prevailing oil and gas prices. Oil and gas prices have been subject to wide fluctuations in recent years in response to changes in the supply and demand for oil and natural gas, market uncertainty, competition, regulatory developments and other factors which are beyond the control of the Company. It is impossible to predict future oil and natural gas price movements with any certainty. The Company does not engage in hedging activities. As a result, the Company may be more adversely affected by fluctuations in oil and gas prices than other industry participants that do engage in such activities. An extended or substantial decline in oil and gas prices would have a material adverse effect on (i) the Company's access to capital; and (ii) the Company's financial position and results of operations.

Increased operating costs. Higher operating costs for our underlying properties will directly decrease the amount of cash flow received by the Company. Electricity, chemicals, supplies, reclamation and abandonment and labour costs are a few of the operating costs that are susceptible to material fluctuation.

Unforeseen title defects may result in a loss of entitlement to production and reserves. Although the Company conducts title reviews in accordance with industry practice prior to any purchase of resource assets, such reviews do not guarantee that an unforeseen defect in the chain on title will not arise and defeat our title to the purchased assets. If such a defect were to occur, our entitlement to the production from such purchased assets could be jeopardized.

Lower oil and gas prices increase the risk of ceiling limitation write-down. During 2004, the Company adopted the recommendations of the new CICA Handbook guideline AcG-16. As a result of applying the new standards, management determined that a transitional impairment loss of CDN $1,945,786 should be recorded as at July 1, 2003. At June 30, 2006, the Company recorded an additional write down of CDN$2,692,798. There is an ongoing risk that we will be required to write down the carrying value of oil and gas properties when oil and gas prices are low or volatile. We may experience additional ceiling test write-downs in the future (See “Item 5.G - Safe Harbour - Critical Accounting Policies - Oil and gas accounting and reserve estimates” below).

Uncertainty of estimates of reserves and future events. Certain statements included in this Annual Report contain estimates of the Company's oil and gas reserves and the discounted future net revenues from those reserves, as prepared by independent petroleum engineers and/or the Company. There are numerous uncertainties inherent in such estimates including many factors beyond the control of the Company. The estimates are based on a number of assumptions including constant oil and gas prices, and assumptions regarding future production, revenues, taxes, operating expenses, development expenditures and quantities of recoverable oil and gas reserves. Such estimates are inherently imprecise indications of future net revenues, and actual results might vary substantially from the estimates based on these assumptions. Any significant variance in these assumptions could materially affect the estimated quantity and value of reserves. In addition, the Company's reserves might be subject to revisions based on upon future production, results of future exploration and development, prevailing oil and gas prices and other factors. Moreover, estimates of the economically recoverable oil and gas reserves, classifications of such reserves and estimates of future net cash flows prepared by independent engineers at different times may vary substantially. Information about reserves constitutes forward-looking statements.

Ability to replace reserves. The future success of the Company depends upon its ability to find, develop and acquire oil and gas reserves that are economically recoverable. As a result the Company must locate, acquire and develop new oil and gas reserves to replace those being depleted by production. Without successful funding, for acquisitions and exploration and development activities, the Company's reserves will decline. No assurances can be made that the Company will be able to find and develop or acquire additional reserves at an acceptable cost.

Competition. The Company engages in the exploration for and production of oil and gas, industries which are highly competitive. The Company competes directly and indirectly with major and independent oil and gas companies in its exploration for and development of desirable oil and gas properties. Many companies and individuals are engaged in the business of acquiring interests in and developing oil and gas properties in the United States and Canada, and the industry is not dominated by any single competitor or a small number of competitors. Many of such competitors have substantially greater financial, technical, sales, marketing and other resources, as well as greater historical market acceptance than the Company. The Company will compete with numerous industry participants for the acquisition of land and rights to prospects, and for the equipment and labor required to operate and develop such prospects. Competition could materially and adversely affect the Company's business, operating results and financial condition. Such competitive disadvantages could adversely affect the Company's ability to participate in projects with favorable rates of return.

Enforcement of Operating Agreements. Operations of the wells on properties not operated by the Company are generally governed by operating agreements, which typically require the operator to conduct operations in a good and workmanlike manner. Operating agreements generally provide, however, that the operator will have no liability to the other non-operating working interest owners for losses sustained or liabilities incurred, except such as may result from gross negligence or wilful misconduct.

Shortage of Supplies and Equipment. The Company’s ability to conduct operations in a timely and cost effective manner is subject to the availability of natural gas and crude oil field supplies, rigs, equipment and service crews. Although none are expected currently, any shortage of certain types of supplies and equipment could result in delays in our operations as well as in higher operating and capital costs.

Interruption from Severe Weather. The Company’s operations are conducted principally in the central region of Alberta, and the northeastern region of British Columbia and in Saskatchewan. The weather in these areas can be extreme and can cause interruption or delays in our drilling and construction operations.

Dependence on Third-Party Pipelines. In fiscal 2006, substantially all our sales of natural gas production was effected through deliveries to local third-party gathering systems to processing plants. In addition, the Company relies on access to inter-provincial pipelines for the sale and distribution of substantially all of our gas. As a result, a curtailment of our sale of natural gas by pipelines or by third-party gathering systems, an impairment of our ability to transport natural gas on inter-provincial pipelines or a material increase in the rates charged to us for the transportation of natural gas by reason of a change in federal or provincial regulations or for any other reason, could have a material adverse effect upon us. In such event, we would have to obtain other transportation arrangements. There can be no assurance that we would have economical transportation alternatives or that it would be feasible for us to construct pipelines. In the event such circumstances were to occur, our operating netbacks from the affected wells would be suspended until, and if, such circumstances could be resolved.

Operating Hazards and Uninsured Risks. The oil and gas business involves a variety of operating risks, including fire, explosion, pipe failure, casing collapse, abnormally pressured formations, adverse weather conditions, governmental and political actions, premature reservoir declines, and environmental hazards such as oil spills, gas leaks and discharges of toxic gases. The occurrence of any of these events with respect to any property operated or owned (in whole or in part) by us could have a material adverse impact on us. The Company and the operators of our properties maintain insurance in accordance with customary industry practices and in amounts that we believe to be reasonable. However, insurance coverage is not always economically feasible and is not obtained to cover all types of operational risks. The occurrence of a significant event that is not insured or insured fully could have a material adverse effect on our financial condition.

Restoration, Safety and Environmental Risk. Our operations are primarily in western Canada and, in particular, the western provinces of Alberta, British Columbia and Saskatchewan. Certain laws and regulations exist that require companies engaged in petroleum activities to obtain necessary safety and environmental permits to operate. Such legislation may restrict or delay us from conducting operations in certain geographical areas. Further, such laws and regulations may impose liabilities on us for remedial and clean-up costs, personal injuries related to safety and environmental damages, such liabilities collectively referred to as “asset retirement obligations”.

To ensure that the Company provides for future estimated asset retirement obligations, the Company has estimated the future cost to clean up all its wellsite facilities to be CDN $422,883 and the current cost to be CDN $285,219 using a credit-adjusted risk free discount rate of 5 percent at June 30, 2006. While the Company cannot predict the ultimate cost, the Company’s independent engineering consultants assist us in assessing its total asset retirement obligations related to removal and clean-up costs. While the Company’s safety and environmental activities have been prudent in managing such risks, there can be no assurance that the Company will always be successful in protecting itself from the impact of all such risks.

Expiration of Licenses and Leases. The Company's properties are held in the form of licenses and leases and working interests in licenses and leases. If the Company or the holder of the licence or lease fails to meet the specific requirement of a licence or lease, the licence or lease may terminate or expire. There can be no assurance that any of the obligations required to maintain each licence or lease will be met. The termination or expiration of the Company's licenses or leases or the working interests relating to a licence or lease may have a material adverse effect on the Company's results of operations and business.

Canadian Government Regulation and Industry Conditions

Kyoto Protocol. The Kyoto protocol, ratified by the Canadian federal government in December 2002, came into force on February 16, 2005. The protocol commits Canada to reducing greenhouse gas emissions to six percent below 1990 levels over the period 2008-2012. The Canadian government released a framework outlining its Climate Change action plan on April 13, 2005. The plan contains few technical details regarding the implementation of the government’s greenhouse gas reduction strategy. The Climate Change Working Group of the Canadian Association of Petroleum Producers continues to work with the Canadian and Alberta governments to develop an approach for implementing targets and enabling greenhouse gas control legislation, which protects the industry’s competitiveness, limits the cost and administrative burden of compliance and supports continued investment in the sector. As the Canadian government has yet to release a detailed Kyoto compliance plan, the Company is unable to predict the impact of potential regulations upon its business; however, it is possible that the Company would face increases in operating costs in order to comply with the greenhouse gas emissions legislation.

Compliance with governmental regulations. The oil and natural gas industry is subject to extensive controls and regulations imposed by various levels of the federal and provincial governments in Canada. It is not expected that any of these controls or regulations will affect the operations of the Company in a manner materially different than they would affect other oil and gas companies of similar size. All current legislation is a matter of public record and the Company is unable to accurately predict what additional legislation or amendments may be enacted. All of the governmental regulations noted below may be changed from time to time in response to economic or political conditions. Company management believes that the trend of more expansive and stricter environmental laws and regulations will continue. The implementation of new or modified environmental laws or regulations could have a material adverse impact on the Company.

Canadian Government Regulation and Environmental Matters. The Company is subject to various Canadian federal and provincial laws and regulations relating to the environment. The Company believes that it is currently in compliance with such laws and regulations. However, such laws and regulations may change in the future in a manner which will increase the burden and cost of compliance. In addition, the Company could incur significant liability under such laws for damages, clean-up costs and penalties in the event of certain discharges into the environment. In addition, environmental laws and regulations may impose liability on the Company for personal injuries, clean-up costs, environmental damage and property damage as well as administrative, civil and criminal penalties. The Company maintains limited insurance coverage for accidental environmental damages, but does not maintain insurance for the full potential liability that could be caused by such environmental damage. Accordingly, the Company may be subject to significant liability, or may be required to cease production in the event of the noted liabilities.

Provincial regulation - royalties and incentives. In addition to federal regulation, each province has regulations which govern land tenure, royalties, production rates, extra-provincial export, environmental protection and other matters. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced. From time to time the provincial governments of Canada have established incentive programs which have included royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced planning projects.

Land Tenure. Crude oil and natural gas located in the western provinces is owned predominantly by the respective provincial governments. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences and permits for varying terms from two years and on conditions set forth in provincial legislation including requirements to perform specific work or make payments. Oil and natural gas located in such provinces can also be privately owned and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated.

Risk Factors Relating to Investments in Independent Power Projects in India

Development of Independent Power Projects ("IPPs") cannot be assured. The successful completion of IPPs can be particularly difficult in countries, which have not uniformly embraced privatization, or where politically motivated opposition is routinely mounted to initiatives of the existing leadership. In addition, the development of IPPs sometimes results in litigation or threatened litigation, which may need to be resolved before successful development of IPPs can occur.

Our investment in IPPs may not function properly or may suffer damages. Our investment in IPPs involve many risks, including the failure of equipment or the performance of equipment at levels below those originally projected, whether due to unexpected wear and tear, misuse or unexpected degradation. Any of the foregoing could significantly reduce or eliminate project revenues, thereby reducing any net income from the project. In addition, catastrophic events could result in personal injury, loss of life, destruction of project assets or suspension of project operations. Although the affiliated owner/operators may maintain insurance to protect against certain risks, the insurance proceeds may not be adequate to cover reduced revenues or, other liabilities arising from any of the events described above.

Uncertain political and economic conditions could affect our investments. General political and economic conditions in India could significantly affect the project's prospects. The economies of India differ significantly from the economies of other developed countries in many respects, including levels of capital reinvestment, growth rate, government involvement, resource allocation, rate of inflation and balance of payments position in international trade. The success of the Indian projects may depend upon the existence of a political, and judicial economic environment, which will accommodate project development. In addition, future government actions in India concerning the operation and regulation of power plants have and will have a significant effect on project operations. There can be no assurance that future government actions over which we have no control will not materially adversely affect a project's operations.

Foreign operations entail legal risks. Material agreements to which we are a party relating to contracts for equity participation in power facilities located in India may be governed by the laws of that or another country, and there are no assurances that such agreements can be enforced in Canadian courts or elsewhere. The inability to enforce such agreements in Canada may have a material adverse effect on the Company’s investments. In addition, the administration of laws and regulations by government agencies in India may be subject to considerable discretion. The projects may be adversely affected by new laws and changes to existing laws (or interpretations thereof).

Foreign regulatory risks. Power projects in India are subject to governmental and electric power regulation in virtually all aspects of their operations, including, but not limited to, the amount and timing of electricity generation, the performance of scheduled maintenance, compliance with power grid control and dispatch directives, foreign ownership restrictions, dividend separation restrictions and restrictions on fuel access. There can be no assurance that all necessary approvals will be received and the time and expense of obtaining such approvals cannot be accurately predicted.

Recoverability of Foreign Investment. As of the date of this Annual Report, the Company owns 12,348,200 common shares of KGPL, which is developing a power project in Andhra Pradesh, India. These KGPL Shares are being held as an investment, and the Company estimates that the carrying amount of the investment in KGPL will be fully recovered. However, the actual recoverable amount is dependent upon future events and foreign exchange and could differ materially from the amount estimated by management. (See “Item 5 - Operating and Financial Review and Prospects - Critical Accounting Estimates” and “Item 8A-7 - Litigation” below).

Risks Relating to the Company's Common Stock

Possible volatility of stock price. The market price for the Company's Common Stock may be volatile and is subject to significant fluctuations in response to a variety of factors, including the liquidity of the market for the Common Stock, variations in the Company's quarterly operating results, regulatory or other changes in the oil and gas industry generally, announcements of business developments by the Company or its competitors, litigations and judgments, changes in operating costs and variations in general market conditions. Because the Company has a limited operating history, the market price for the Company's Common Stock may be more volatile than that of a seasoned issuer. Changes in the market price of the Company's securities may have no connection with the Company's operating results. No predictions or projections can be made as to what the prevailing market price for the Company's Common Stock will be at any time.

Litigation costs. To date the Company has incurred significant costs related to defending the Oakwell Claim. The Company's operating results may in the future fluctuate significantly depending upon a number of factors including the timing of litigation expenditures incurred. Such variability could have a material adverse effect on the Company's business, financial condition and results of operations.

Public trading market. There is only a limited public market for the Company's Common Stock, and no assurance can be given that a broad and/or active public trading market will develop or be sustained. The Company's Common Stock trades on the American Stock Exchange (“AMEX”) and the Frankfurt Stock Exchange. However, there can be no assurance that the Company will continue to meet and maintain listing requirements on either stock exchange. In addition, apart from automatic listing exemptions, the Common Stock has not been qualified under any applicable state blue-sky laws, and the Company is under no obligation to so qualify the Common Stock, or otherwise to take action to improve the public market for such securities. The Company's Common Stock could have limited marketability due to any of the following factors, each of which could impair the market for such securities: (i) lack of profits, (ii) need for additional capital, (iii) the limited public market for such securities; (iv) the applicability of certain resale requirements under the US Securities Act of 1933, as amended; (v) applicable blue sky laws, (vi) litigations and judgments and the other factors discussed in this Risk Factors section.

No likelihood of dividends. The Company plans to retain all available funds for use in its business, and therefore does not plan to pay any cash dividends with respect to its securities in the foreseeable future. Hence investors in the Common Stock should not expect to receive any distribution of cash dividends with respect to such securities.

No assurance of liquidation distribution. If the Company were to be liquidated or dissolved, holders of shares of its capital stock would be entitled to share ratably in its assets only after satisfaction of the Company's liabilities. After satisfaction of those liabilities and satisfaction of any liquidation preference with respect to any then outstanding senior securities of the Company, the holders of the Common Stock would share ratably in any remaining assets of the Company. There can be no assurance that there would be any remaining assets or any distribution to shareholders after the payment of third party obligations and any liquidation preferences.

We will incur significant costs as a result of being a public company. As a public company, we incur significant accounting, legal, governance, compliance and other expenses that private companies do not incur. In addition, the Sarbanes-Oxley Act of 2002 and the rules subsequently implemented by the Securities and Exchange Commission have required changes in corporate governance practices of public companies. The Company expects these rules and regulations to increase its legal, audit and financial compliance costs and to make some activities more time-consuming and costly. For example, as a public company, we are required to create additional board committees and adopt policies regarding internal controls and disclosure controls and procedures. In addition, the Company has incurred additional costs associated with our public company reporting requirements. The Company also expects these rules and regulations to make it more difficult and more expensive for the Company to obtain director and officer liability insurance and the Company may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for the Company to attract and retain qualified persons to serve on our board of directors or as executive officers.

If we fail to comply in a timely manner with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 or to remedy any material weaknesses in our internal controls that we may identify, such failure could result in material misstatements in our financial statements, cause investors to lose confidence in our reported financial information and have a negative effect on the trading price of our Common Stock. The Company is in the process of assessing the effectiveness of its internal control over financial reporting in connection with the rules adopted by the Securities and Exchange Commission under Section 404 of the Sarbanes-Oxley Act of 2002. Compliance with Section 404 of the Sarbanes-Oxley Act of 2002 is required in connection with the filing of the Company’s Annual Report on Form 20-F for the fiscal year ending June 30, 2008 assuming the Company does not qualify as an accelerated filer. While management anticipates expending significant resources in an effort to complete this important project, there can be no assurance that the Company will be able to achieve its objective on a timely basis. There also can be no assurance that our auditors will be able to issue an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting.

In addition, in connection with the Company’s on-going assessment of the effectiveness of its internal control over financial reporting, the Company may discover “material weaknesses” in its internal controls as defined in standards established by the Public Company Accounting Oversight Board (“PCAOB”). A material weakness is a significant deficiency, or combination of significant deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. The PCAOB defines “significant deficiency” as a deficiency that results in more than a remote likelihood that a misstatement of the financial statements that is more than inconsequential will not be prevented or detected.

While the Company has not identified any material weaknesses in its internal controls over financial reporting that would cause it to deem such internal controls ineffective, the Company will retain additional resources and will work to obtain the requisite training for others in the Company to remediate any deficiencies. However, the Company cannot provide any assurance that additional testing of its internal controls will not uncover additional deficiencies that, when aggregated with any other unremediated deficiencies, would result in a material weakness in its internal control over financial reporting.

In the event that a material weakness is identified, the Company will employ qualified personnel and adopt and implement policies and procedures to address any material weaknesses that is identified. However, the process of designing and implementing effective internal controls is a continuous effort that requires the Company to anticipate and react to changes in its business and the economic and regulatory environments and to expend significant resources to maintain a system of internal controls that is adequate to satisfy its reporting obligations as a public company. The Company cannot assure you that the measures it will take will remediate any material weaknesses that we may identify or that the Company will implement and maintain adequate controls over our financial process and reporting in the future.

Any failure to complete an assessment of the Company’s internal control over financial reporting, to remediate any material weaknesses that it may identify or to implement new or improved controls, or difficulties encountered in their implementation, could harm its operating results, cause it to fail to meet its reporting obligations or result in material misstatements in its financial statements. Any such failure also could adversely affect the results of the periodic management evaluations of the Company’s internal controls and, in the case of a failure to remediate any material weaknesses that the Company may identify, would adversely affect the annual auditor attestation reports regarding the effectiveness of the Company’s internal control over financial reporting that are required under Section 404 of the Sarbanes-Oxley Act of 2002. Inadequate internal controls could also cause investors to lose confidence in the Company’s reported financial information, which could have a negative effect on the trading price of the Company’s Common Stock.

Potential issuance of additional stock. At the Annual and Special Meeting of Shareholders held on November 14, 2005, shareholders approved a resolution permitting the Company to issue up 4,059,009 shares of Common Stock in one or more private placements to be completed on or before November 13, 2006. At an Annual and Special Meeting of Shareholders scheduled for November 7, 2006, management will seek shareholder approval to issue up to 4,272,009 shares of Common Stock pursuant to one or more private placement, acquisitions or equity credit lines to be completed on or before October 30, 2007.

In December 2002, a majority of the Company’s shareholders approved a resolution authorizing the Company to issue up to 20% of the outstanding shares of Common Stock from time to time (or a total of 705,243 shares) in connection with the Company’s Stock Option Plan (the “Option Plan”). At an Annual and Special Meeting of Shareholders scheduled for November 7, 2006, management will seek shareholder approval for an amendment to the Option Plan to, among other things, increase the maximum aggregate number of shares of Common Stock reserved for issuance under the Option Plan, to an amount equal to 20% of the outstanding shares of Common Stock (or a total of 854,402 shares). The Company currently has reserved 705,243 shares of Common Stock reserved for issuance under the Option Plan.

As of the date of this Annual Report, 600,000 of such options are issued.

On September 6, 2006 Company entered into a Share Purchase Agreement with 1211115 Alberta Ltd. (“1211115”) and the shareholders of 1211115 to acquire all the issued and outstanding shares of 1211115. The Company agreed to issue to the shareholders of 1211115 an aggregate of 1,850,001 units of the Company ("Units"), each Unit comprised of one share of Common Stock with an attributed price of CDN $1.25 and one common share purchase warrant ("Warrant"), each Warrant entitling the holder to purchase one share of Common Stock at a price of CDN $1.40 for a period of three years from the date of issuance (the “Transaction”).

Under the terms of the agreement, 1211115 advanced CDN $650,000 to the Company (the "Advance") upon execution of the agreement, which amount is immediately repayable to 1211115 in the event the Transaction is not completed by October 2, 2006 or such later date as agreed to by the parties. If not repaid as required, the Advance is converted to a demand promissory note, the repayment of which is secured by the unencumbered assets of the Company. Furthermore in the event that the Proposed Transaction terminates at no fault of 1211115 or the shareholders of 1211115 then 650,000 compensation warrants, each compensation warrant entitling the holder to purchase one share of Common Stock at a price of CDN $1.40 for a period of three years from the date of issuance, will be issued to the shareholders of 1211115. (See Item 4.A - “History and Development - Oil and Gas Operations”, Item 7.B - “Related Party Transactions” and Item10.C - “Material Contracts” below).

Pursuant to the acquisition of 100% of the issued and outstanding shares of Great Northern Oil & Gas Inc., a private Alberta corporation (“Great Northern Oil”) on May 31, 2006 the Company issued to the shareholders of Great Northern Oil (the “Holders”) a CDN$200,000 convertible secured debenture due November 30, 2011 with interest at a rate of 5% per annum. Principal and interest payments are payable quarterly on the first day of January, April, July and October (the “Debenture”). (See Item 4.A. - “History and Development - Oil and Gas Operations”, Item 5.G. - Critical Accounting Estimates - Valuation of Convertible Debenture and Item 10.C. - “Material Contracts” below).

The issuance of additional shares of Common Stock could adversely reduce the proportionate ownership and voting rights and powers of the present holders of the Common Stock, and could also result in dilution in the net tangible book value per share of Common Stock. There can be no assurance that the Company will not issue additional shares of its Common Stock.

ITEM 4. INFORMATION ON THE COMPANY

EnerNorth Industries Inc. is a company amalgamated under the laws of the Province of Ontario, and registered as an extra-provincial company in Alberta, British Columbia and Newfoundland and Labrador, Canada. The Company’s primary activities are investment in, exploration and development and production of oil and gas.

The Company holds oil and gas interests located in the Canadian Provinces of Alberta, Saskatchewan, British Columbia and Ontario, directly and indirectly through its wholly owned Alberta subsidiary Great Northern Oil & Gas Inc. (“Great Northern”) or through other joint venture partners.

Through its wholly owned subsidiary EPS Karnataka Power Corp., a company incorporated in Ontario (“EPS Karnataka”), the Company owns a 97% interest in Euro India Power Canara Limited (45% at the date of this Annual Report) a company incorporated in India (“EIPCL”), which has a Power Purchase Agreement with the Karnataka Power Transmission Corporation Limited (formerly the Karnataka Electricity Board) of the State of Karnataka, India.

Effective February 1, 2005 the Company divested of its interest in M&M Engineering Limited (“M&M”) and its Industrial & Offshore Division. (See “Item 10.C - “Material Contracts” below).

The Company owns directly and through its wholly owned subsidiary CanPower Development Corp., (“CanPower”) a company incorporated under the Companies Act, Cap 308 of the Laws of Barbados, effective June 1, 2006, 12,348,200 issued common shares (approximately 3.27% as of August 23, 2006), at a stated value of INR 10 per share, of Konaseema Gas Power Limited (“KGPL”), a company incorporated in India.

The registered office and management office of the Company is 1 King Street West, Suite 1502, Toronto, Ontario, M5H 1A1, Telephone (416) 861-1484, Facsimile (416) 861-9623. The books and financial records of the Company are located in the registered and management offices. The Company's public filings can be accessed and viewed through the Company's website www.enernorth.com under the heading "Investor Relations" and by clicking on "Corporate Filings". A link to the Company's Canadian Securities Commissions filings can be viewed via the System for Electronic Data Analysis and Retrieval (SEDAR) at www.sedar.com and the Company's United States Securities and Exchange Commission filings can be viewed through the Electronic Data Gathering Analysis and Retrieval System (EDGAR) at www.sec.gov. Readers can also access and view the public insider trading reports via the System for Electronic Disclosure by Insiders at www.sedi.ca. The Company’s Registrar and Transfer Agent is Equity Transfer & Trust Company located at Suite 420, 120 Adelaide Street West, Toronto, Ontario, M5H 4C3. The Company's Common Stock trades on the American Stock Exchange ("AMEX") under the symbol "ENY" and on the Frankfurt Stock Exchange under the symbol "EPW1" and “WKN 919384”.

ITEM 4.A. HISTORY AND DEVELOPMENT OF THE COMPANY

The Company was incorporated on October 5, 1988, under the Business Corporations Act (Ontario), under the name Van Ollie Explorations Limited ("Van Ollie"). Van Ollie originated as a mining exploration company and was inactive from the time its initial exploration program was completed in 1990 until May 8, 1996, when Van Ollie acquired an interest in 1169402 Ontario Inc. ("1169402"), whose principal asset was a 51% ownership interest in M&M. Through a share for share exchange, the shareholders of 1169402 acquired approximately 97% of the Common Stock of the Company and effectuated a change in control of the Company. On July 1, 1996, 1169402 merged into the Company and, as a result of the merger, the Company acquired a direct 51% ownership interest in M&M. The Company acquired the remaining 49% interest in M&M on March 9, 1999. Effective January 29, 1999, the Company changed its name to "Engineering Power Systems Limited" from "Engineering Power Systems Group Inc.", and consolidated its share capital on a one for four basis. Effective February 2, 2001 the Company changed its name to "Energy Power Systems Limited" from "Engineering Power Systems Limited" and consolidated its share capital on a one for four basis. Effective February 11, 2003, the Company changed its name to “EnerNorth Industries Inc.” from “Energy Power Systems Limited” and consolidated its share capital on a one-for-three basis.

In fiscal year 2001, as part of an initiative to increase corporate cash flow, the Company commenced oil and gas operations. The Company’s first acquisition was comprised of properties in two strategic areas of oil and gas development, the proven historic region of Western Canada and the new frontier of Atlantic Canada.

The Company’s oil and natural gas production is located in the Canadian provinces of Alberta, Saskatchewan, British Columbia and Ontario.

On May 22, 2002 the Company commenced trading on the American Stock Exchange under the symbol "EGY" and on February 12, 2003 commenced trading under the new symbol “ENY”.

Oil and Gas Operations

During the last three fiscal years ended June 30, 2006; June 30, 2005, and June 30, 2004 the Company incurred a total of CDN $9,277,073 on exploration, development and acquisition expenditures.

Fiscal 2004

During the fiscal year ended June 30, 2004, the Company incurred exploration, development and acquisition expenditures of CDN $1,740,154. The Company acquired through Crown land sales, a 100% interest in 3 sections (1,920 net acres) in the Sibbald Area of Alberta and acquired approximately 35 kilometers (approximately 22 miles) of seismic data, and a 15% working interest in (1,280 gross acres-192 net) in the Doe Area of Alberta. The Company exercised a right of first refusal and acquired a 68.5% interest in a shut in oil well and acquired 219 net acres of land and purchased a 33.33% interest in 640 gross acres (213 net acres) of land in the Farrow Area of Alberta. The Company participated in drilling one exploration gas well, one development gas well and re-completed two gas wells. The Company also participated in the tie in of a Viking gas well in the Olds-Innisfail Area of Alberta that commenced production on October 1, 2003.

Fiscal 2005

During the fiscal year ended June 30, 2005, the Company incurred exploration, development and acquisition expenditures of CDN $1,001,743. In the Farrow Area of Alberta, the Company participated for its 33.33% working interest and drilled a horizontal exploratory well in the Foremost formation to an approximate depth of 990 meters and repaired a seized bottom hole pump and placed a 100% working interest oil well back on production.

The Company entered into a Farmout and Participation Agreement effective May 16, 2005 to acquire a working interest in a British Columbia Crown Drilling License (the “License”). The License is located in 094-A-15/E and F consisting of 28 spacing units (approximately 4,895 gross acres). As consideration the Company paid $250,000 and subsequent to fiscal year end, drilled a natural gas development well (C-011-E/94-A-15) to the Doig formation and paid 75% of the costs to earn a 75% working interest in the well and 16 spacing units from base Baldonnel to base Artex-Halfway-Doig. The Company, as operator, drilled a natural gas exploratory well (B-064-E/94-A-15) to the Baldonnel formation and paid 75% of the costs to earn a 75% working interest in the well and 12 spacing units from surface to base Baldonnel.

On this License, the Company participated in drilling two more 25% working interest exploratory gas wells (D-019-F/94-A-15 and B-046-E/94-A-15) and may earn a 25% working interest in 16 spacing units from surface to base Baldonnel. All of the four wells have been drilled and cased and are pending completion, production testing and potential tie in. These multi formation lands are prospective for natural gas in the Notikewan, Bluesky and Gething formations and for oil in the Halfway formation. The Company anticipates further exploration and development on these lands pending results from the first four wells.

Subsequent to the fiscal year ended June 30, 2005 the Company entered into a 50/50 Joint Exploration Agreement with an area of mutual interest encompassing nine townships of lands in the Sibbald Area (excluding the Company’s working interest lands) to further acquire, develop and explore this area.

Fiscal 2006

During the fiscal year ended June 30, 2006, the Company incurred exploration, development and land acquisition costs of CDN $6,535,176. These expenditures were funded through cash held by the Company, cash flow from the Company’s oil and gas operations and gains from the sale of marketable securities.

On March 31, 2006 the Company acquired from two (2) arm’s length parties 100% of the issued and outstanding shares of Sawn Lake Resources Ltd., a private Alberta corporation (“Sawn Lake”) with producing oil and natural gas assets located in the Canadian provinces of Saskatchewan and Alberta, for consideration of CDN$2,351,608. The purchase price was satisfied by a cash payment of $2,126,608 and the delivery of 103,212 common shares of the Company issued at a price of CDN $2.18 per share.

The primary assets of Sawn Lake include a 10% interest in a Viking Sand natural gas unit located at Brock, Saskatchewan; a-10% interest in the Cactus Lake area of Saskatchewan; and, a 12.5% interest in the Coutts area of Alberta and approximately 24,960 gross acres (2,520 net acres) of land (See Item10.C - “Material Contracts”).

On May 31, 2006 the Company acquired from two (2) arm’s length parties 100% of the issued and outstanding shares of Great Northern Oil & Gas Inc. (“Great Northern Oil”), a private Alberta corporation with producing oil and natural gas assets located in the Canadian provinces of Saskatchewan and Alberta, for consideration of CDN $2,150,212. The purchase price was satisfied by a cash payment of $1,750,210; the delivery of 94,788 common shares of the Company issued at a price of CDN $2.11 per share; and a CDN $200,000, 5% secured convertible debenture.

The CDN$200,000 convertible secured debenture is due on November 30, 2011 and bears interest at a rate of 5% per annum. Principal and interest payments are payable quarterly on the first day of January, April, July and October (the “Debenture”).

The primary assets of Great Northern Oil include a 10% interest in a Viking Sand natural gas unit located at Brock, Saskatchewan; a 12.5% interest in the Westerose area of Alberta; and, a 12.5% interest in the Coutts area of Alberta and approximately 25,280 gross acres (2,632 net acres) of land See Item 4.A. - “History and Development - Oil and Gas Operations”, Item 5.G. - Critical Accounting Estimates - Valuation of Convertible Debenture and Item 10.C. - “Material Contracts” below).

EnerNorth believes there is potential from identified drilling locations on the lands held by Sawn Lake and Great Northern Oil.

On June 30, 2006 Sawn Lake and Great Northern Oil amalgamated under the Alberta Business Corporations Act to form a new entity named Great Northern Oil & Gas Inc., (“Great Northern”).

Effective July 3, 2006 the Company entered into Purchase and Sale Agreement, for the sale of a portion of its interest in the Buick Creek Area of British Columbia for proceeds of CDN$825,000. The Company sold a 50% working interest in two standing wells and 16 spacing units from base Baldonnel to base Artex-Halfway-Doig and 12 spacing units from surface to base Baldonnel and a 10% working interest in two standing wells and 16 spacing units from surface to base Baldonnel.

Under an Area of Mutual Interest Agreement dated August 1, 2006, the Company participated for a 7.5% working interest in a natural gas test well in this area and earned a 7.5% working interest in the well. The Company also participated in the tie in B-046-E/94-A-15 for its 15% working interest and the well was placed on production in August 2006.

On September 6, 2006 the Company entered into an agreement with 1211115 and the shareholders of 1211115 to acquire all the issued and outstanding shares of 1211115. The Company agreed to issue to the shareholders of 1211115 an aggregate of 1,850,001 units of EnerNorth ("Units"), each Unit comprised of one share of Common Stock with an attributed price of CDN $1.25 and one common share purchase warrant ("Warrant"), each Warrant entitling the holder to purchase one share of Common Stock at a price of CDN $1.40 for a period of three years from the date of issuance. The Company also agreed to issue a secured debenture to the debt holders of 1211115 in satisfaction of CDN $237,500 of debt in 1211115 (the “Transaction”).

Under the terms of the agreement, 1211115 advanced CDN $650,000 to the Company (the "Advance") upon execution of the agreement, which amount is immediately repayable to 1211115 in the event the Transaction is not completed by October 2, 2006 or such later date as agreed to by the parties. If not repaid as required, the Advance is converted to a demand promissory note, the repayment of which is secured by the unencumbered assets of EnerNorth. Furthermore, in the event that the Proposed Transaction terminates at no fault of 1211115 or the shareholders of 1211115, then 650,000 compensation warrants, each compensation warrant entitling the holder to purchase one share of Common Stock at a price of CDN $1.40 for a period of three years from the date of issuance, will be issued to the shareholders of 1211115.

The primary assets of 1211115 consist of cash and oil and gas interests located in the Chinchaga Area of Alberta and in the Lloydminster area of Saskatchewan.

The Proposed Transaction is subject to regulatory approval, including approval from the American Stock Exchange (See Item 7.B - “Related Party Transactions” and Item10.C - “Material Contracts” below).

The Company expects to expend further capital through cash on hand or cash flow from operations to develop its existing properties and acquire additional oil and gas properties to increase cash flow and to enhance oil and gas reserves.

Industrial & Offshore Division

Effective February 1, 2005 the Company divested of its wholly-owned subsidiary M&M to Spectrum Sciences & Software Holdings Corp. for cash proceeds of $7,361,999. The transaction was a sale of 100% of the common shares and 100% of the preferred shares of M&M held by the Company. Prior to closing, the Company retracted preferred shares of M&M for CDN $1,000,000 cash and M&M assigned to the Company 100% of 10915 Newfoundland Limited, a Newfoundland and Labrador company (“10915 Newfoundland”), and 100% of 11123 Newfoundland Limited, a Newfoundland and Labrador company (“11123 Newfoundland”). Each of 10915 Newfoundland and 11123 Newfoundland owned a portion of the facilities located in Port aux Basques, Newfoundland and Labrador. The facilities consisted of two parcels of land. The larger of the two parcels has a 52 foot high and 104 foot high steel frame building, containing 44,000 square feet, designed for utilization as a fabrication and assembly shop. The second parcel of land has a large building containing a total of 96,000 square feet including an attached two-story office section (with full basement) and a one-story office section . The Company received shareholder approval for the transaction at a special meeting of shareholders held on January 26, 2005. As a result of the sale of M&M, the Industrial & Offshore Division has been treated as discontinued operations for accounting purposes. (See “Item 10.C Material Contracts” below).

Effective June 29, 2005, the Company sold its 100% interest in 10915 Newfoundland and 11123 Newfoundland for cash proceeds of $175,000.

During 2003, the Company was awarded a CDN $24 million gross fabrication contract for Husky Energy’s White Rose Offshore Oil Project through North Eastern Contractors Limited (“NECL”). NECL was formed as an equal joint venture partnership of M&M and G. J. Cahill and Company Limited. NECL utilized the Bull Arm Topsides Facilities, located at Trinity Bay Newfoundland and Labrador, to fabricate the M12- Main Electrical Room Module and the LER-Local Electrical Room Module. The Bull Arm Facility is a massive fabrication complex formerly housing the floating production storage and offloading platform for the Terra Nova Offshore Project as well as the gravity based offshore platform for the Hibernia Offshore Project. In a letter dated June 29, 2004, M&M announced its intention to withdraw from the NECL joint venture once all business issues related to the $24 million contract were complete.

During 2004 and 2005, through its 49% interest in Liannu Limited Partnership (“Liannu”), the Company had been awarded contracts for (i) the fabrication, engineering and testing of a fuel unloading and load dispensing system; (ii) the fabrication, engineering and testing of a fire/freshwater pump house; (iii) the fabrication of concentrate storage tanks; (iv) installation of cladding of the infrastructure site for Inco’s Voisey’s Bay Nickel Project in Newfoundland and Labrador; (v) the fabrication of a package of 49 different tanks for Voisey’s Bay; (vi) the fabrication, engineering and testing of a potable water pump house; and, (vii) the fabrication, engineering and testing of the mill site fuel unloading and load dispensing system.

Investments in Marketable Securities

During the fiscal year ended June 30, 2006 the Company invested in CDN $2,812,063 (June 30, 2005 - CDN $2,394,138; and June 30, 2004 - CDN $521,039) in marketable securities and also during the year the Company had proceeds on disposition of marketable securities of CDN $4,929,687. Some of the Company investments for the year ended June 30, 2006, have monthly distributions of approximately 10%.

Oakwell Litigation Canada/India

In March 1997, Oakwell, and the APSEB executed two identical PPAs providing for Oakwell to build, own and operate two identical 100 MW net capacity diesel generator barge mounted power plants, fueled by furnace oil (total 200 MW net capacity) and sell electricity to APSEB on a take-or-pay basis for 15 years (the Project). In June 1997, the Company and Oakwell formed an 87.5% - 12.5% joint venture and then incorporated an Indian company, EOPL (now known as KGPL), to implement the provisions of the PPAs. Disputes rose between the Company and Oakwell regarding the time taken to obtain financing for the Project and a Settlement Agreement was reached in December 1998 under which Oakwell sold the Company all of Oakwell's interest in the PPAs and in EOPL.

In July 2002, Oakwell claimed the Company was in breach of the Settlement Agreement over the same issue settled by the Settlement Agreement and in August 2002 the Company was named as a defendant in the High Court of Singapore, in the matter of Oakwell vs. the Company, Suit No. 997 of 2002/V. On October 16, 2003 the High Court of Singapore ordered the Company to pay Oakwell US $5,657,000 (approximately CDN $6,933,219 at June 30, 2005) plus costs (the “Judgment”). On November 13, 2003 the Company appealed the Judgment to the Court of Appeal of the Republic of Singapore (Civil Appeal No. 129 of 2003/Y). That Court, which is the final Court of Appeal for Singapore, dismissed the appeal from the bench on April 27, 2004.

On January 10, 2005, after the Company publicly announced its intention to sell its engineering and offshore subsidiary, M&M, Oakwell brought a motion in the Ontario proceedings seeking to prevent the Company from disposing of or encumbering assets equal to the Canadian dollar equivalent of the Judgment from the proceeds of the sale of M&M. On January 27, 2005, that motion was withdrawn and the Company agreed to provide Oakwell with 5 days notice before execution of any transaction or series of related transactions exceeding $2.4 million from the proceeds from the sale of M&M.

On May 23, 2005, the Delhi High Court ordered that if VBC purchases the Company’s KGPL shares the sale proceeds shall be kept in India and on September 9, 2005 the Delhi Court further ordered that if the Company receives any payments from VBC from the sale of it’s KGPL shares, then the proceeds shall be deposited in the Company’s account held in a Public Sector Bank in India or invested only in Government of India securities until the disposal of Oakwell’s Execution Petition. This order became infructuous upon the Company withdrawing its Execution Petition against VBC and not otherwise receiving any payment from VBC by way of sale of KGPL shares.

On September 07, 2006 Oakwell filed (Execution Application 482/2006) for interim relief, seeking restraint on the disposal of the Company’s KGPL shares and other assets. On September 18, 2006 the Delhi Court ordered that until October 13, 2006 the date of next hearing, the Company shall not deal with, transfer or alienate the KGPL shares or other assets.

The Execution Petition and related applications are ongoing. (See “Item 5 - Operating and Financial Review and Prospects - Critical Accounting Estimates” and “Item 8A7 - Litigation” below).

KGPL Investment

Pursuant to an Arbitration Agreement between the Company and VBC, the parent company of KGPL, an Arbitration Award was passed on October 11, 2003 by Hon’ble Arbitral Tribunal, India (the “Award”) requiring as follows (i) VBC transfer an additional 500,000 shares in KGPL to the Company, at no cost and (ii) VBC to buy the original KGPL Shares for INR 113,482,000 on or before the earlier of: (a) 60 days after the first disbursal of funds on financial closure for the KGPL Project, and, (b) in any event no later than March 31, 2004. Further, the Company may, upon written notice to VBC, require that VBC purchase, and VBC is then required to buy, an additional 500,000 shares of KGPL at a par value of INR 5,000,000 on or before the same dates. If VBC does not buy the 11,348,200 KGPL Shares before March 31, 2004 then VBC is liable to pay the Company interest at 12% per annum on the value of the unredeemed shares from March 31, 2004 to the date of actual payment thereof.

On February 28, 2004 the Company provided written notice to VBC to 11,348,200 KGPL shares held by the Company. VBC raised a dispute regarding the purchase of the KGPL Shares and the Company commenced legal proceedings against VBC.

Execution Petition

On June 24, 2004 the Company filed an Execution Petition against VBC in the Court of the Chief Judge, City Civil Court, Hyderabad, India (“City Civil Court”) to enforce the Award (Execution Petition No. 46/2004).

In February, 2006, the Company advanced INR 5,000,000 (approximately CDN $134,850) to VBC as consideration for the Company acquiring the additional 500,000 shares of KGPL described in the Award.

The Company filed an application to withdraw its Petition against VBC and on June 9^th, 2006 the City Civil Court, ordered that the Execution Petition be dismissed as withdrawn.

On August 6, 2006 the Company and VBC executed a Joint Memo for full satisfaction of the Award passed on October 11, 2003 stipulating as follows; (i) the Company waive the obligation that VBC purchase 11,348,200 KGPL shares and that the Company will retain its 11,348,200 KGPL shares; (ii) the Company and VBC comply with an order of Reserve Bank of India, such that the Company acquires the allotment of 500,000 KGPL shares rather than having such shares allotted at no cost, (iii) VBC acknowledge the right of the Company to purchase, on payment KGPL shares from VBC and/or its group companies at INR 10 per share free and clear of all claims, demand and encumbrances of any nature and kind; (iv) the Company waive payment of all unpaid interest by VBC under the Award,; (v) the Company, VBC and KGPL mutually undertake and agree to release each other against all and any claims, demand, assertions, petitions, decrees and litigation whatsoever that arose or may hereinafter arise in connection with any agreements, arrangements and understandings and agree that neither party will make any claims or demands against each other.

Pursuant to the Joint Memo, the Company acquired the 500,000 equity shares in KGPL previously allotted for no consideration under the Award by paying INR 5,000,000 (approximately CDN $134,850 in February 2006) and the Company subscribed for a further 500,000 additional equity shares in KGPL at par value INR 5,000,000 (approximately CDN $121,750 in August 2006). As of the date of this Annual Report, the Company owns 12,348,200 KGPL Shares.

As a result of the Joint Memo, the Company filed a fresh Execution Petition in the City Civil Court for such court to record and accept the Joint Memo as full satisfaction of the Award as agreed to by the Company and VBC. The fresh Execution Petition has been listed for disposal by the City Civil Court on October 24, 2006.

Company Petition

On November 30, 2004 the Company filed a Company Petition against VBC in the High Court of Judicature of Andhra Pradesh, India (Company Petition No. 199/2004) to pass an order for the winding up of VBC under the provisions of the Companies Act, 1956 (India). Subsequently the Company withdrew the Company Petition on 16th February 2006, which ended these proceedings. (See “Item 5 - Operating and Financial Review and Prospects - Critical Accounting Estimates” below).

The Karnataka Project

Through its wholly owned subsidiary EPS Karnataka a company incorporated in Ontario the Company owns a 97% interest at June 30, 2006 (45% at the date of this Annual Report) in EIPCL a company incorporated in India.

On April 22, 1999, the Karnataka Power Transmission Corporation Limited (formerly the Karnataka Electricity Board) of the State of Karnataka, India ("KPTCL") executed a power purchase agreement with EIPCL. Under the Power Purchase Agreement (“PPA”), EIPCL would develop, procure, finance, construct, own, operate and maintain a power generation facility and sell electric energy generated therefrom to KPTCL, and KPTCL would purchase 85% of such electric energy from the project for the entire term of the power purchase agreement (the “Karnataka Project”).

Under an agreement dated October 12, 1999 and finally amended February 2, 2002 with a Court (Germany) Appointed Receiver of EuroKapital A.G. (the “Receiver”) (the “EuroKapital Agreement”) EPS Karnataka acquired 67 shares in EIPCL, at that time representing 67% equity ownership in EIPCL, for consideration of US $2.0 million, to be paid after financial closure in principle of the Karnataka Project. The EuroKapital Agreement provides that if the EPS Karnataka 'exits' from the Karnataka Project prior to financial closure, the 67 EIPCL shares transferred under the agreement will be forfeited, as liquidated damages, if the consideration remains unpaid.

Effective May 10, 2001 the Karnataka Project was given the approval by the Karnataka State Government to be converted to a coal fueled land based power project. The power purchase agreement has yet to be amended and there are deficiencies in the State Government's performance, including among other requirements, the provision of payment guarantees for the Karnataka project. Accordingly, the Company invoked the provisions within the PPA and commenced Arbitration proceedings. On August 11, 2003 the Company, through EIPCL, filed a Statement of Claim against KPTCL for repudiatory breach of the power purchase agreement and claimed damages in the amount of US$3,835,232. On August 5, 2004 the Company suspended arbitration in favour of a mutually acceptable resolution being negotiated between EIPCL and KPTCL and the Government of Karnataka (“GOK”), to renew the power purchase agreement and revive the power project. Such resolution is still outstanding.

ITEM 4.B. BUSINESS OVERVIEW

The Company’s producing properties and properties to which the Company has an interest are located in Alberta, Saskatchewan, British Columbia and Ontario, Canada. For the three fiscal years ended June 30, 2006, June 30, 2005 and June 30, 2004, the total gross revenue derived from the sale of oil, natural gas and natural gas liquids before deduction of royalties was as follows:


Fiscal Year	Total (CDN $)
2006	$1,169,988
2005	$946,665
2004	$765,941

The level of activity in the Canadian oil and gas industry is influenced by seasonal weather patterns. Wet weather and spring thaw make the ground unstable and municipalities and provincial transportation departments enforce road bans that may restrict the level of activity. Seasonal factors and unexpected weather patterns may lead to declines in production activity and increased consumer demand or changes in supply during certain months of the year may influence the commodity prices (See “Item 5.D - Trend Information” below).

There is an existing and available market for the oil and gas produced from the Company’s properties. The Company sells its oil and natural gas production to integrated oil and gas companies and marketing agencies. Sales prices are generally set at market prices available in Canada and/or the United States. The Company has no delivery commitments for its oil or gas production. However, the prices obtained for production are subject to market fluctuations, which are affected by many factors, including supply and demand. Numerous factors beyond our control, which could affect pricing include:

·	the level of consumer product demand;

·	weather conditions;

·	domestic and foreign governmental regulations;

·	the price and availability of alternative fuels;

·	political conditions;

·	the foreign supply of oil and gas;

·	the price of foreign imports; and

·	overall economic conditions.

The Company does not have a reliance on raw materials, as it operates in an extractive industry.

The Company does not have a reliance on any significant patents or licenses.

The oil and gas business is highly competitive in every phase. Many of the Company’s competitors have greater financial and technical resources, established multi-national operations, secured land rights and licenses, which the Company may not have. As a result, the Company may be prevented from participating in drilling and acquisition programs (See “Item 3.D. - Key Information - Risk Factors” above).

Governmental Regulation/Environmental Issues

The Company’s oil and gas operations are subject to various Canadian governmental regulations. Matters subject to regulation include discharge permits for drilling operations, drilling and abandonment bonds, reports concerning operations, the spacing of wells, and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and gas wells below actual production capacity in order to conserve supplies of oil and gas. The production, handling, storage, transportation and disposal of oil and gas, by-products thereof, and other substances and materials produced or used in connection with oil and gas operations are also subject to regulation under federal, state, provincial and local laws and regulations relating primarily to the protection of human health and the environment. To date, expenditures related to complying with these laws, and for remediation of existing environmental contamination, have not been significant in relation to the results of operations of our company. The requirements imposed by such laws and regulations are frequently changed and subject to interpretation, and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. These regulations may adversely affect our operations and cost of doing business. It is likely that these laws and regulations will become more stringent in the future (See “Item 3 - Key Information - Risk Factors” above).

Effective February 1, 2005 the Company disposed of its interest in M&M and discontinued the operations of its Industrial & Offshore Division. As a result of the disposition, the Company’s continuing operations presented are exploration and development, production and investment in oil and gas. (See “Item 10.C - “Material Contracts” below).

ITEM 4.C. ORGANIZATIONAL STRUCTURE

The Company’s oil and gas interests are held directly and indirectly through its wholly owned Alberta subsidiary Great Northern and are located in the Provinces of Alberta, British Columbia, Saskatchewan and Ontario, Canada.

The Company, through its wholly owned subsidiary EPS Karnataka Power Corp., a company incorporated in the province of Ontario, owns 96,997 issued common shares (approximately 97% at June 30, 2006 and 45% at the date of this Annual Report) at a stated value of INR 10 per share, of EIPCL, a company incorporated in India. The Company also holds a 100% interest in CanPower Development Corp., (“CanPower”) a company incorporated under the Companies Act, Cap 308 of the Laws of Barbados, effective June 1, 2006.

The Company owns directly and through CanPower 12,348,200 issued common shares at a stated value of INR 10 per share, of KGPL, a company incorporated in India.

ITEM 4.D. PROPERTY, PLANT AND EQUIPMENT

The Company's executive offices are rented and as of the date of this Annual Report are located at 1 King Street West, Suite 1502, Toronto, Ontario, Canada.

The discussion under this Item is in accordance with the Securities and Exchange Commission rules for extractive enterprises, and may contain “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995 (the "Reform Act") (See “Part I - Forward Looking Statements” above). The table below is a glossary of terms and abbreviations that may be used in this Item.

GLOSSARY OF TERMS

Natural Gas
	Mcf	1,000 cubic feet
	MMcf	1,000,000 cubic feet
	Mcf/d	1,000 cubic feet per day
	Bcf	1,000,000,000 cubic feet
Oil and Natural Gas Liquids
	Bbl	Barrel
	Mbbls	1,000 barrels
	Boe(1)	Barrels of oil equivalent (using a conversion ratio of 6 Mcf to 1 bbl of oil)
	Mboe	1,000 boe
	Mmboe	1,000,000 boe
	Bpd	Barrels per day
	Boepd	Barrels of oil equivalent per day
	Bopd	Barrels of oil per day
	NGLs	Natural gas liquids

(1) Disclosure provided herein in respect of Boes may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

The following table sets forth certain standard conversions between Standard Imperial Units and the International System of Units (or metric units).

TO CONVERT
From	To	Multiply By
Mcf	cubic meters	28.317
Meters	cubic feet	35.494
Bbls	cubic meters	0.159
Cubic meters	Bbls	6.292
Feet	Meters	0.305
Meters	Feet	3.281
Miles	Kilometers	1.609
Kilometers	Miles	0.621
Acres	Hectares	0.405
Hectares	Acres	2.471

Estimated Reserves of Crude Oil, Natural Gas and Natural Gas Liquids

The process of evaluating reserves is inherently complex. It requires significant judgments and decisions based on available geological, geophysical, engineering and economics data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs changes. The reserve estimates contained herein are based on current production forecasts, prices and economic conditions. These factors and assumptions include among others (i) historical production in the area compared with production rates from analogous producing areas; (ii) initial production rates, (iii) production decline rates, (iv) ultimate recovery of reserves; (v) success of future development activities; (vi) marketability of production, (vii) effects of government regulation; and (viii) other government levies imposed over the life of the reserves.

As circumstances change and additional data becomes available, reserves estimates also change. Estimates are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required for changes in well performance, prices, economic conditions and governmental restrictions. Revisions to reserve estimates can arise from changes in year-end prices, reservoir performance and geological conditions or production. These revisions can be either positive or negative (See “Item 3.D. - Key Information - Risk Factors” above).

As a Canadian issuer, we are required under Canadian law to comply with National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” (NI 51-101) issued by the Canadian Securities Administrators, in all of our reserves related disclosures. NI 51-101 was effective September 30, 2003 and applies to financial years ended on or after December 31, 2003. NI 51-101 mandates significant changes in the way reporting issuers are required to determine and publicly disclose information relating to oil and gas reserves. Under NI 51-101, proved reserves is an estimate, the premise of which means there must be at least a ninety percent probability that actual quantities of crude oil and natural gas proved reserves recovered will equal or exceed the estimated proved reserves.

The purpose of NI 51-101 is to enhance the quality, consistency, timeliness and comparability of crude oil and natural gas activities by reporting issuers and elevate reserves reporting to a higher level of confidence and accountability. In the United States, registrants, including foreign private issuers like us, are required to disclose proved reserves using the standards contained in the United States Securities and Exchange Commission (“SEC”) Regulation S-X. However, under certain circumstances, applicable U.S. law permits us to comply with our own country’s law if the requirements vary. We believe that the standards for determining proved reserves under NI 51-101 meet those set forth under U.S. law and thus we have presented our proved reserves under NI 51-101 only.

The crude oil and natural gas industry commonly applies a conversion factor to production and estimated proved reserve volumes of natural gas in order to determine an “all commodity equivalency” referred to as barrels of oil equivalent (“boe”). The conversion factor we have applied in this Report is the current convention used by many oil and gas companies, where six thousand cubic feet (“mcf”) is equal to one barrel (“bbl”). A boe is based on an energy equivalency conversion method primarily applicable at the burner tip. It may not represent equivalency at the wellhead and may be misleading if used in isolation.

The estimate of our proved reserves on a constant-pricing basis, and their associated net present values, have been based on the June 30, 2006 actual posted commodity prices on as determined by our independent engineering evaluators, Sproule Associates Limited (“Sproule”), a member of the Association of Professional Engineers Geologists and Geophysicists of Alberta, Canada. Appropriate adjustments have been made to account for quality and transportation, to the constant natural gas prices, and to the constant natural gas by-products prices to reflect historical prices received for each area. The table below sets out in CDN dollars the constant prices and the exchange rate used.

Oil:	Edmonton Par	84.49$/stb
	Cromer Medium	78.16$/stb
Natural Gas:	Alberta AECO-C	5.05$/Mcf
	British Columbia Average Wellhead	4.05$/Mcf
Natural Gas by-Products:	Propane	47.22$/bbl
	Butanes	63.92$/bbl
	Pentanes Plus	83.32$/bbl
	Sulphur	40.00$/lt
Exchange Rate:		0.896$US/$CDN

Proved Reserves: The following table reflects estimates of the Company's proved reserves as at June 30, 2006, 2005 and 2004 as reported by Sproule stated in CDN dollars. All of the Company's oil and gas reserves are located in Canada. The following table represents the Company's net interest in its reserves (after crown royalties, freehold royalties and overriding royalties and interests owned by others). Estimated cash flow figures before income tax are net of all royalties, operating and capital costs and discounted at 10% to the Net Present Value ("NPV"). NPV figures are based on constant prices.

Gas Reserves (Mmcf)		2006 NPV @10% (CDN $)		2005 NPV @ 10% (CDN $)		2004 NPV @ 10% (CDN $)
Proved Developed Producing	886	$2,367,000	440	$1,520,000	937	$2,175,000
Proved Developed Non-producing	24	78,000	-	-	-	-
Proved Undeveloped	22	73,000	-	-	215	660,000
Total Gas Reserves (Mmcf)	932	2,518,000	440	1,520,000	1,151	2,835,000
Natural Gas Liquids (Mbbl)
Proved Developed Producing	16.8	N/A (2)	7.9	N/A (2)	5.5	N/A (2)
Proved Undeveloped	-	N/A (2)	-	N/A (2)	0.8	N/A (2)
Total Natural Gas Liquids (Mbbl)	16.8	N/A (2)	7.9	N/A (2)	6.3	N/A (2)
Oil Reserves (Mbbl)
Proved Developed Producing	13.4	496,000	14.9	481,000	1.6	32,000
Proved Developed	-	-	-	-	16.1	295,000
Total Oil Reserves (Mbbl)	13.4	496,000	14.9	481,000	17.7	327,000
Alberta Royalty Tax Credit
Proved Developed	-	136,000	-	94,000	-	134,000
Proved Undeveloped	-	-	-	-	-	54,000
Total Alberta Royalty Tax Credit	-	136,000	-	94,000	-	188,000
Mbbl Equivalent in Mboe (4)
Proved Developed	181.8	3,078,000	96.1	2,095,000	163.2	2,341,000
Proved Undeveloped	3.6	73,000	-	-	52.6	1,008,000
TOTAL PROVED Mboe	185.5	$3,151,000	96.1	$2,095,000	215.8	$3,349,000

(1) Cash flows from the estimated proved reserves are discounted at 10% to the Net Present Value ("NPV").

(2) Discounted cash flows from natural gas liquids were included in natural gas discounted cash flows.

(3) Discounted cash flows from solutions gas were included with oil discounted cash flows.

(4) Gas was converted to bbls is at ratio of six mcf equals one bbl.

(5) Discounted cash flows from natural gas liquids are included with natural gas discounted cash flows.

(6) NPV figures are based on Constant Price forecasts of Proved Reserves.

Production: The following table sets forth the net quantities of oil, natural gas and natural gas liquids produced for during the fiscal periods ending June 30, 2006, 2005 and 2004.

	2006	2005	2004
Natural Gas (Mmcf)	78,963	87,127	78,266
Natural Gas Liquids (Mbbl)	3,464	3,470	2,727
Oil (Mbbl)	4,273	3,835	1,708
Total (BOE)	20,897	21,826	17,479

Producing Wells: The following table sets forth the number of gross wells producing hydrocarbons during the fiscal periods ending June 30, 2006, 2005 and 2004. A gross well is a well in which the Company owns an interest. The net wells represents the fractional interest the Company owns gross wells.

	2006		2005		2004
	Gross	Net	Gross	Net	Gross	Net
Gas	23	4.46	8	1.53	10	3.92
Oil	5	2.38	3	1.93	4	1.46

The following table sets out the Company’s net share of production, average sales prices, average royalties and average net back per unit of production for the fiscal periods ending June 30, 2006, 2005 and 2004.

	for the Twelve Month Period Ended June 30,
	2006	2005	2004

Average Daily Production
Natural gas (mcf per day)	216	239	214
Natural gas liquids (bbls per day)	9	10	7
Crude oil (bbls per day)	12	11	5
Total (boe per day)	57	60	48
Average Commodity Prices
Natural gas ($/mcf)	$ 9.08	$ 6.86	$ 6.65
Natural gas liquids ($/bbl)	$ 48.05	$ 39.34	$ 29.16
Crude oil ($/bbl)	$ 67.01	$ 55.46	$ 37.61
Total ($/boe)	$ 55.99	$ 43.37	$ 38.16
Royalties
Natural gas ($/mcf)	$ 1.38	$ 1.52	$ 1.04
Natural gas liquids ($/bbl)	$ 11.27	$ 11.39	$ 6.24
Crude oil ($/bbl)	$ 9.68	$ 7.68	$ 4.61
Total royalties ($/boe)	$ 9.08	$ 9.22	$ 6.09
Production costs
Natural gas ($/mcf)	$ 3.28	$ 2.94	$ 2.93
Natural gas liquids ($/bbl)	$ 8.22	$ 6.84	$ 15.24
Crude oil ($/bbl)	$ 25.19	$ 31.20	$ 12.31
Total production costs ($/boe)	$ 18.90	$ 18.32	$ 16.72
Netback by Product
Natural gas ($/mcf)	$ 4.42	$ 2.40	$ 2.68
Natural gas liquids ($/bbl)	$ 28.56	$ 21.11	$ 7.68
Crude oil ($/bbl)	$ 32.14	$ 16.58	$ 20.69
Netback ($/boe)	$ 28.01	$ 15.83	$ 15.35

Acreage. The following table sets forth the developed and undeveloped acreage of the projects in which the Company holds an interest, on a gross and a net basis as of June 30, 2006, 2005 and 2004. The developed acreage is stated on the basis of spacing units designated by provincial authorities and typically on the basis of 160 acre spacing unit for oil production and 640 acre spacing unit for gas production in Alberta and Saskatchewan, 50 acre spacing unit for deep Ordovician and Cambridge-age targets in Ontario, an average 699 acre spacing unit for gas production and 350 acre spacing unit for oil production in British Columbia and based on the technical aspects of any discovery. As of the date of this Annual Report, the Company’s acreage is located in Alberta, British Columbia, Saskatchewan and Ontario.

Leasehold Acreage
	2006	2005	2004
Total Leasehold Acreage Gross Acres Net Acres	62,966 17,991	21,040 7,229	24,880 7,921
Developed Acreage Gross Acres Net Acres	34,775 9,438	12,720 3,688	12,080 3,638
Undeveloped Acreage Gross Acres Net Acres	28,192 8,554	8,320 3,541	12,800 4,283

Drilling Activity. As of June 30, 2006, 2005 and 2004 the Company completed the following drilling. A gross well is a well in which an interest is owned. The number of net wells represents the sum of a fractional interest the Company owns in gross wells.

Number of wells drilled	2006		2005		2004
*Development wells*	Gross	Net (%)	Gross	Net (%)	Gross	Net (%)
Producing
Standing*	1	0.75	1	0.33	-	-
Abandoned	1	0.50	-		-	-
*Exploratory wells*
Producing	1	0.125	-		-	-
Abandoned	-	-	-		1	0.24
Standing *	3	1.25	-		1	0.24
* Standing wells are pending further evaluation or tie in and pipeline facilities.

The following table sets out the number of gross and net producing oil and natural gas wells and the number of gross and net non-producing oil and natural gas wells that the Company has an interest in by location.

Location	Gross Producing Gas Wells	Net Producing Gas Wells	Gross Non- Producing Gas Wells	Net Non- Producing Gas Wells	Gross Producing Oil Wells	Net Producing Oil Wells	Gross Non- Producing Oil Wells	Net Non- Producing Oil Wells
Alberta	9	1.65	10	3.88	3	1.45	1	.50
Ontario	1	.1125	-	-	2	.93	-	-
British Columbia	-	-	4	2.00	-	-	-	-
Saskatchewan	15	2.70	11	2.20	-	-	-	-

Present Activities

Farrow Area, Alberta: The Company has a 100% working interest in 320 net acres located in Township 19 Range 24 W4M and an oil well 8-26-29-24 W4M producing from the Glauconite formation. For the fiscal year ended June 30, 2006 this well accounted for approximately 15% of the Company’s overall production. In addition, the Company has a 33.33% interest in 640 gross acres (213 net acres) and a natural gas well at 10-35-19-24 W4M. The well is currently standing pending economic tie in.

Buick Creek Area, North East British Columbia: During the fiscal year ended June 30, 2006 the Company drilled a natural gas development well (C-011-E/94-A-15) to the Doig formation and earned a 75% working interest in the well and 16 spacing units from base Baldonnel to base Artex-Halfway-Doig. The Company also drilled a natural gas exploratory well (B-064-E/94-A-15) to the Baldonnel formation and earned a 75% working interest in the well and 12 spacing units from surface to base Baldonnel.

The Company participated in drilling two more 25% working interest exploratory gas wells (D-019-F/94-A-15 and B-046-E/94-A-15) and earned a 25% working interest in 16 spacing units from surface to base Baldonnel.

Effective July 3, 2006 the Company entered into Purchase and Sale Agreement, for the sale of a portion of its interest in the Buick Creek Area of British Columbia for proceeds of $825,000. The Company sold a 50% working interest in two standing wells and 16 spacing units from base Baldonnel to base Artex-Halfway-Doig and 12 spacing units from surface to base Baldonnel and a 10% working interest in two standing wells and 16 spacing units from surface to base Baldonnel.

Under an Area of Mutual Interest Agreement dated August 1, 2006 the Company participated in drilling a 7.5% working interest in the well (B-13-E/94-A-15) and earned a 7.5% working interest in the well and 12 spacing units.

The Company also participated in the tie in B-046-E/94-A-15 for its 15% working interest and the well was placed on production in August 2006.

These multi formation lands are prospective for natural gas in the Notikewan, Bluesky and Gething formations and for oil in the Halfway formation.

Sibbald Area, Alberta: The Company has a working interest in 7,040 gross acres (5,032 net acres) located in Townships 28 and 29, Range 2 W4M. During the fiscal year ended June 30, 2006 the Company entered into a 50/50 Joint Exploration Agreement including an area of mutual interest encompassing nine townships of lands in the Sibbald Area (excluding the Company’s working interest lands) to further acquire, develop and explore this area. The Company and its partners acquired 1,280 gross acres (896 net acres) of land and drilled a Belly River formation natural gas test well (50% net working interest to the Company) that was dry and abandoned during the fiscal year ended June 30, 2006. For the fiscal year ended June 30, 2006 this area accounted for 7% of the Company’s overall production. Effective February 1, 2006, the Company farmed out its 50% working interest in 640 gross acres (320 net acres) of land to a third party who drilled a natural gas test well to the Belly River formation. The Company has a 7.5% gross overriding royalty in this well that is currently pending tie in.

Cherhill Area, Alberta: Effective June 1, 2006 the Company exercised its Right of First refusal and acquired a 30% before payout interest and an 18% after payout interest in a producing gas well 13-10-57-5 W5M and 115.2 net acres of land in the Cherhill area of Alberta for gross proceeds of CDN $6,750.

Brock Area, Saskatchewan: During the fiscal year ended June 30, 2006, the Company acquired Sawn Lake and Great Northern Oil, and as a result, holds a 20% working interest 19,549 gross acres (3,910 net acres) of land and a producing Viking Sand natural gas unit located in Townships 27 and 28 Range 20 and 21 W3M in Brock, Saskatchewan. The natural gas unit has a compressor station, a dehydrator unit and a water disposal well. The unit also generates revenue from third party gas processing and water disposal. For the fiscal year ended June 30, 2006 this unit, from the date of acquisition, accounted for 16% of the Company’s overall production.

Olds Davey Area, Alberta: The Company has a working interest in 1,760 gross acres (320 net acres) located in Township 33 Range 28, W4M and Township 34 Range 1 W5M. For the fiscal year ended June 30, 2006 this area accounted for approximately 15% of the Company’s overall production from three wells. During the fiscal year ended June 30, 2006 the Company participated in drilling a 12.5% working interest Viking formation gas well. The well commenced production in May 2006. For the fiscal year ended June 30, 2006 this area accounted for 11% of the Company’s overall production.

Bigstone & Kaybob Area, Alberta: The Company has an interest in 2,560 gross acres (435 net acres) located in Township 61, Range 19 and 22 W5M in Alberta. For the fiscal year ended June 30, 2006 this area accounted for approximately 36% of the Company’s overall production from three wells.

Edson Property, Alberta: The Company has a 10% working interest in three sections of land, 1,920 gross acres (192 net acres) and a well 10-13-52-16W5M in the Edson area of Alberta. At June 30, 2006 the Company’s reserve report had attributed probable reserves to this property. This non-operated well is currently standing, pending pipeline tie in, water disposal facilities and compression. The Company expects that the 10-13-52-16W5M well will be tied in during fiscal 2007.

ITEM 4A. UNRESOLVED STAFF COMMENTS

Not Applicable.

ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS

The following discussion and analysis of EnerNorth Industries Inc. ("EnerNorth" or the "Company") should be read in conjunction with the Company’s Audited Consolidated Financial Statements for the fiscal years ended June 30, 2006, 2005 and 2004 and notes thereto. Unless otherwise indicated, the following discussion is based on Canadian dollars and presented in accordance with Canadian Generally Accepted Accounting Principles ("GAAP").

Certain measures in this discussion and analysis do not have any standardized meaning as prescribed by Canadian generally accepted accounting principles such as netback and other production figures and therefore are considered non-GAAP measures. Therefore these measures may not be comparable to similar measures presented by other issuers. These measures have been described and presented in order to provide shareholders and potential investors with additional information regarding the Company’s liquidity and its ability to generate funds to finance its operations.

Disclosure Controls and Procedures. The Chief Executive Officer and the Chief Financial Officer have evaluated the effectiveness of EnerNorth’s disclosure controls and procedures as of June 30, 2006 and have concluded that such disclosure controls and procedures were effective.

OVERVIEW

The Company is a corporation amalgamated under the laws of the Province of Ontario and is provincially registered in the Provinces of Alberta, British Columbia and Newfoundland. The Company’s primary activities are investment in, exploration and development and production of oil and gas.

On March 31, 2006 the Company acquired from two arm’s length parties 100% of the issued and outstanding shares of Sawn Lake Resources Ltd., a private Alberta corporation (“Sawn Lake”) with producing oil and natural gas assets located in the Canadian provinces of Saskatchewan and Alberta, for consideration of CDN$2,351,608. The purchase price was satisfied by a cash payment of $2,126,608 and the delivery of 103,212 common shares of the Company issued at a price of CDN $2.18 per share. The allocation of the purchase price was as follows:


Current assets	23,673
Oil and gas assets	3,235,319
Payables	(21,167)
Future income tax	(859,798)
Site restoration liabilities	(26,419)
Net assets acquired	2,351,608

On May 31, 2006 the Company acquired from two arm’s length parties 100% of the issued and outstanding shares of Great Northern Oil & Gas Inc., a private Alberta corporation (“Great Northern Oil”) with producing oil and natural gas assets located in the Canadian provinces of Saskatchewan and Alberta, for consideration of CDN $2,150,212. The purchase price was satisfied by a cash payment of $1,750,210; the delivery of 94,788 common shares of the Company issued at a price of CDN $2.11 per share; and a CDN$200,000, 5% secured convertible debenture. The allocation of the purchase price was as follows:


Current assets	54,493
Oil and gas assets	2,850,301
Payables	(71,785)
Future income tax	(656,683)
Site restoration liabilities	(26,114)
Net assets acquired	2,150,212

On June 30, 2006 Sawn Lake and Great Northern Oil, amalgamated under the Alberta Business Corporations Act to form a new entity named Great Northern Oil & Gas Inc. (“Great Northern”).

Through its wholly owned subsidiary EPS Karnataka Power Corp. (“EPS Karnataka”) a company incorporated in Ontario the Company owns a 97% interest at June 30, 2006 (45% at the date of this Operating and Financial Review and Prospects) in Euro India Power Canara Limited (“EIPCL”) a company incorporated in India. Effective June 1, 2006 the Company incorporated CanPower Development Corp., (“CanPower”) a wholly owned subsidiary incorporated under the Companies Act, Cap 308 of the Laws of Barbados to develop power projects globally.

Effective February 1, 2005 the Company divested of its interest in M&M Engineering Limited (“M&M”) for cash proceeds of CDN$7,361,999. The transaction was a sale of 100% of the common shares and 100% of the preferred shares of M&M held by the Company. Prior to closing, the Company retracted preferred shares of M&M for Cdn $1,000,000 cash and M&M assigned to the Company 100% of 10915 Newfoundland Limited, a Newfoundland and Labrador company (“10915 Newfoundland”), and 100% of 11123 Newfoundland Limited, a Newfoundland and Labrador company (“11123 Newfoundland”). Each of 10915 Newfoundland and 11123 Newfoundland owned a portion of the facilities located in Port aux Basques, Newfoundland and Labrador. For the purpose of financial presentation, the operations of M&M and its subsidiaries have been accounted for as discontinued operations.

Effective June 29, 2005 the Company sold its 100% interest in 10915 Newfoundland and 11123 Newfoundland for cash proceeds of CDN$175,000.

The audited consolidated financial results for the twelve month periods ending June 30, 2006, June 30, 2005 and June 30, 2004 include the accounts of the Company as well as an investment in Konaseema Gas Power Limited (“KGPL”) a company incorporated in India that is developing a power project in Andhra Pradesh, India, and investments in marketable securities, EPS Karnataka, CanPower and EIPCL.

The Company’s oil and gas operations are located in Alberta, British Columbia, Saskatchewan and Ontario, Canada. The Company’s financial results are influenced by its business environment. Risks include, but are not limited to: crude oil and natural gas prices; cost to find, develop, produce and deliver crude oil and natural gas; demand for and ability to deliver natural gas; government regulations and cost of capital The Company’s producing wells are subject to normal levels of decline and unavoidable changes in operating conditions in facilities operated by third parties. The Company’s production revenue is subject to commodity price fluctuations over which the Company has no control. Some of the business risks could include:

volatility in market prices for oil and natural gas;

reliance on third party operators;

ability to find or produce commercial quantities of oil and natural gas;

liabilities inherent in oil and natural gas operations;

dilution of interests in oil and natural gas properties;

uncertainties associated with estimating oil and natural gas reserves;

·	new prospects and exploration activities may have inherent risks;

competition for, among other things, financings, acquisitions of reserves, undeveloped lands and skilled personnel;

· governmental regulation and environmental legislation; and

·	weather conditions (See“Item 3.D Rick Factors - Risk Factors Relating to Oil and Gas Exploration, Development and Production” above).

The consolidated financial statements have been prepared on the basis of a “going concern”, which contemplates that the Company will be able to realize assets and discharge liabilities in the normal course of business.

The Company’s ability to continue as a “going concern” is dependent upon the enforceability of the Oakwell Claim (See Note 7 of the Company’s Audited Consolidated Financial Statements) and the Company’s ability to fund its operations and legal costs from internal or external sources. If the application of the Judgment becomes enforceable in Canada, then there would be a material and adverse impact on the Company’s financial condition and the Company may be required to sell certain assets to satisfy the judgment. The Company’s consolidated financial statements do not include any adjustments to the amounts and classification of assets and liabilities that might be necessary should the Company not be able to continue in the normal course of operations. If the “going concern” assumption is not appropriate for the consolidated financial statements then adjustments may be necessary to the carrying value of assets and liabilities, the reported revenues and expenses, and the balance sheet classifications used.

OVERALL PERFORMANCE

The Company’s overall performance for the twelve months ended June 30, 2006 can be highlighted by the following: The Company's gross oil and gas revenue of $1,169,988 for the twelve month period ending June 30, 2006 increased by 24% from $946,655 for the comparative twelve month period ending June 30, 2005. During the twelve month period ending June 30, 2006, commodity prices increased by 29% to an average of $55.99 per boe compared to $43.37 per boe for the twelve month period in 2005. Average production volumes decreased 5% to 57 boe/d compared to 60 boe/d for the same twelve month period in 2005. For the twelve month period revenue growth was driven by increases in commodity prices partially offset by lower production volumes.

Net loss from continuing operations increased 37% to $3,008,745 for the twelve month period ended June 30, 2006 compared to a net loss of $2,197,746 for the twelve month period ending June 30, 2005. The increase in net loss from continuing operations was primarily caused by the write down of oil and gas interests, write down of securities and costs related to the Oakwell Claim. These costs were partially offset by the gain on sale of marketable securities (See “Critical Accounting Estimates - Oakwell Claim” below).

Select Financial Information

EnerNorth Industries Inc.

Presented Pursuant to Canadian Generally Accepted Accounting Principles

(Canadian $, Except Per Share Data) (Audited)

	As of and for the Twelve Month Period Ended June 30,
	2006⁽¹⁾⁽²⁾	2005⁽¹⁾⁽²⁾	2004⁽¹⁾⁽²⁾
financial INFORMATION:
Oil and gas revenue	$ 1,169,988	$ 946,655	$ 765,941
Less: royalties	189,720	201,172	106,485
Net revenue	980,268	745,483	659,456

Net loss from operations before discontinued operations	(3,008,745)	(2,197,746)	(3,845,606)
Income and gain on disposition of discontinued operations (2)	-	2,034,997	1,627,664
Net loss for the year	(3,008,745)	(162,749)	(2,217,942)
Net loss from continuing operations per share	$(0.73)	$(0.54)	$(0.95)
Net loss per share	$(0.73)	$(0.04)	$(0.55)
Total assets	15,198,471	15,708,656	23,262,596
Total financial liabilities	10,656,314	8,632,418	16,097,577
OPERATIONS:
Average Daily Production
Natural gas (mcf per day)	216	239	214
Natural gas liquids (bbls per day)	9	10	7
Crude oil (bbls per day)	12	11	5
Total (boe per day)	57	60	48
Average Commodity Prices
Natural gas ($/mcf)	$9.08	$ 6.86	$ 6.65
Natural gas liquids ($/bbl)	$48.05	$ 39.34	$ 29.16
Crude oil ($/bbl)	$67.01	$ 55.46	$ 37.61
Total ($/boe)	$55.99	$ 43.37	$ 38.16

Royalties
Natural gas ($/mcf)	$1.38	$ 1.52	$ 1.04
Natural gas liquids ($/bbl)	$11.27	$ 11.39	$ 6.24
Crude oil ($/bbl)	$9.68	$ 7.68	$ 4.61
Total royalties ($/boe)	$9.08	$ 9.22	$ 6.09
Production costs
Natural gas ($/mcf)	$3.28	$ 2.94	$ 2.93
Natural gas liquids ($/bbl)	$8.22	$ 6.84	$ 15.24
Crude oil ($/bbl)	$25.19	$ 31.20	$ 12.31
Total production costs ($/boe)	$18.90	$ 18.32	$ 16.72
Netback by Product
Natural gas ($/mcf)	$4.42	$ 2.40	$ 2.68
Natural gas liquids ($/bbl)	$28.56	$ 21.11	$ 7.68
Crude oil ($/bbl)	$32.14	$ 16.58	$ 20.69
Netback ($/boe)	$28.01	$ 15.83	$ 15.35

____________________

(1)	Selected Financial Data should be read in conjunction with the discussion below and “Critical Accounting Principles and Critical Accounting Estimates” below.

(2)During fiscal 2005 the Company sold its interests in M&M Engineering Limited (“M&M”). As a result the Industrial & Offshore Division has been treated as discontinued operations for accounting purposes, and prior years' statements of operations have been restated.

ITEM 5.A OPERATING RESULTS

Fiscal 2006 versus Fiscal 2005 and Fiscal 2005 versus Fiscal 2004

Production Volumes. For the twelve month period ending June 30, 2006 average production volumes decreased 5% to 57 boe/d compared to 60 boe/d for the same twelve month period in 2005. Decreases were primarily related declining production from the Company’s Sibbald property, Alberta and the shutin of a well in the Kaybob area of Alberta pending rerouting of production and the shut in of a well in the Bigstone area of Alberta. Offsetting these production decreases were three months of production from the Company’s Sawn acquisition and one months operating results from the Company’s Great Northern Oil acquisition.

For the twelve month period ending June 30, 2006 average gas production decreased 10% to 216 mcf/d compared to 239 mcf/d for the same twelve month period in 2005. Decreased gas production was primarily a result of production declines from Sibbald, Alberta and the temporary shut in of a well in the Kaybob area of Alberta pending rerouting of production and the shut in of a well in the Bigstone area of Alberta.

For the twelve month period ending June 30, 2006 average natural gas liquids production decreased 10% to 9 bbls/d compared to 10 bbls/d for the same twelve month period in 2005. Decreases in natural gas liquids for the twelve month period ending June 30, 2006 was primarily attributed to the shut in of a well pending production rerouting, both of which are located in the Kaybob area of Alberta.

For the twelve month period ending June 30, 2006 average oil production increased 9% to 12 bbls/d compared to 11 bbls/d for the same twelve month period in 2005. Increased oil production was due to production increases from the Company’s Farrow property, Alberta.

For the twelve month period ending June 30, 2005 average production volumes increased 25% to 60 boe/d compared to 48 boe/d for the same twelve month period in 2004. Overall increases were due to new production sources from the Company’s Farrow, Sibbald and Olds-Davey properties located in Alberta Canada.

For the twelve month period ending June 30, 2005 average gas production increased 12% to 239 mcf/d compared to 214 mcf/d for the same twelve month period in 2004. Increased gas production was due to additions from the Company’s Sibbald and Olds-Davey properties, Alberta.

For the twelve month period ending June 30, 2005 average natural gas liquids production increased 43% to 10 bbls/d compared to 7 bbls/d for the same twelve month period in 2004.

For the twelve month period ending June 30, 2005 average oil production increased 120% to 11 bbls/d compared to 5 bbls/d for the same twelve month period in 2004. Increased oil production was due to additions from the Company’s Farrow and Sibbald properties, Alberta.

Commodity Prices. During the twelve month period ending June 30, 2006, commodity prices increased by 29% to an average of $55.99 per boe compared to $43.37 per boe for the twelve month period in 2005. These price increases reflect general price increases in the respective commodities.

Average gas prices per mcf increased by 32% to $9.08 during the twelve month period ending June 30, 2006 compared to $6.86 per mcf for the twelve month period ending June 30, 2005.

Average natural gas liquids prices per barrel increased by 22% to $48.05 during the twelve month period ending June 30, 2006 compared to $39.34 per barrel for the twelve month period ending June 30, 2005.

Average oil prices per barrel increased by 21% to $67.01 during the twelve month period ending June 30, 2006 compared to $55.46 per barrel for the twelve month period ending June 30, 2005.

During the twelve month period ending June 30, 2005, commodity prices increased by 14% to an average of $43.37 per boe compared to $38.16 per boe for the twelve month period in 2004. These price increases reflect the general price increase in the respective commodities in the market.

Average gas prices per mcf increased by 3% to $6.86 during the twelve month period ending June 30, 2005 compared to $6.65 per mcf for the twelve month period ending June 30, 2004.

Average natural gas liquids prices per barrel increased by 35% to $39.34 during the twelve month period ending June 30, 2005 compared to $29.16 per barrel for the twelve month period ending June 30, 2004.

Average oil prices per barrel increased by 47% to $55.46 during the twelve month period ending June 30, 2005 compared to $37.61 per barrel for the twelve month period ending June 30, 2004.

Gross oil and gas revenue. The Company's gross oil and gas revenue of $1,169,988 for the twelve month period ending June 30, 2006 increased by 24% from $946,655 for the comparative twelve month period ending June 30, 2005. For the twelve month period revenue growth was driven by increases in commodity prices partially offset by lower production volumes.

The Company's gross oil and gas revenue of $946,655 for the twelve month period ending June 30, 2005 increased by 24% from $765,941 for the comparative twelve month period ending June 30, 2004. Revenue growth was driven by both production increases and increases in commodity prices. Production increases stemmed primarily from re-completed wells in the Sibbald area, commencement of production from previously drilled gas wells in the Olds-Davey area and the remedial work completed on an oil well in the Farrow area.

Royalties. Royalties decreased by 6% to $189,720 for the twelve month period ending June 30, 2006 compared to $201,172 for the twelve month period ended June 30, 2005. For the twelve month period royalties decreased by 2% to $9.08 per boe compared to $9.22 per boe in 2005.

Royalties increased by 89% to $201,172 for the twelve month period ending June 30, 2005 compared to $106,485 for the twelve month period ended June 30, 2004. Increased royalties were a result of increased production volumes primarily from the Company’s Farrow, Olds-Davey and Sibbald properties along with increased commodity prices. Royalties increased by 51% to $9.22 per boe for the twelve month period ending June 30, 2005 compared to $6.09 per boe in 2004.

Net Revenue. The Company’s net revenues for the twelve month period ending June 30, 2006 increased by 31% to $980,268 compared to $745,483 for the comparative twelve month period ending June 30, 2005.

The Company’s net revenues for the twelve month period ending June 30, 2005 increased by 13% to $745,483 compared to $659,456 for the comparative twelve month period ending June 30, 2004.

Operating and transportation. Operating and transportation costs were $394,863 for the twelve month period ending June 30, 2006, 1% lower than operating and transportation costs of $399,795 during the comparable twelve month period in 2005. Lower costs were a result of decreased production volumes. During the twelve month period ended June 30, 2006 production costs per boe were 3% higher at $18.90 per boe compared to $18.32 per boe during the same period in 2005.

Operating and transportation costs were $399,795 for the twelve month period ending June 30, 2005, 37% higher than operating and transportation costs of $292,275 during the comparable twelve month period in 2004. Higher production expenses were a result of increased production volumes and increased operations primarily on the Company’s Sibbald, Olds/Davey and Farrow, Alberta properties. During the year ended June 30, 2005 production cost per boe increased by 10% to $18.32 per boe compared to $16.72 per boe during 2004.

Depletion and Accretion. For the twelve month period ending June 30, 2006, depletion and accretion expense was $729,856, 6% higher compared to $691,539 for the twelve month period in 2005. The increased depletion and accretion was a result of a higher value of properties in the depletion pool.

For the twelve month period ending June 30, 2005, depletion and accretion expense was $691,539, 51% higher compared to $458,230 for the twelve month period in 2004. The increased depletion and accretion was a result of higher production volumes and a higher value of properties in the depletion pool.

Administrative Expenses. Administrative expenses of $2,198,024 for the twelve month period ending June 30, 2006 were 1% lower than administrative expenses of $2,221,343 the previous year. The primary component of administrative expenses for the twelve month period ending June 30, 2006 was related to litigation expenses of $924,635 versus $982,912 for the previous 12 month period ending June 30, 2005. The Company also accrued an expense of $3,736 for stock option expense during the fiscal 2006.

Administrative expenses of $2,221,343 for the twelve month period ending June 30, 2005 were 16% higher than administrative expenses of $1,921,385 the previous year. The primary component of administrative expenses for the twelve month period ending June 30, 2005 was related to litigation expenses of $982,912 versus $889,614 for the previous 12 month period ending June 30, 2004. The Company also accrued an expense of $149,109 for stock option expense during the current fiscal year.

Foreign Exchange. For the twelve month period ending June 30, 2006 the gain on foreign exchange was $330,816 compared to a foreign exchange gain of $539,836 for the twelve month period in 2005. The foreign exchange gain during the periods in fiscal 2006 and fiscal 2005 was partially attributed to the appreciation in the Canadian dollar relating to the Oakwell Claim. This gain was partially offset by a foreign exchange loss relating to Company’s investment in KGPL.

For the twelve month period ending June 30, 2005 the gain on foreign exchange was $539,836 compared to a foreign exchange loss of $24,070 for the twelve month period in 2004. The foreign exchange gain during fiscal 2005 related to appreciation in the Canadian dollar relating to the Oakwell Claim. This gain was partially offset by a foreign exchange loss relating to Company’s investment in KGPL.

Oakwell Claim. For the twelve month period ending June 30, 2006 the provision on the Oakwell Claim increased by $403,051 versus $712,349 for the twelve month period ending June 30, 2005. The increase related to accrued interest and court awarded costs on the Singapore Judgment.

For the twelve month period ending June 30, 2005 the provision on the Oakwell Claim increased by $712,349 versus $2,015,681 for the twelve month period ending June 30, 2004. The increase related to accrued interest and court awarded costs on the Singapore Judgment (See “Critical Accounting Estimates - Oakwell Claim” below).

Interest income. For the fiscal year ending June 30, 2006 interest income was $69,765, 77% lower compared to $305,836 for the comparable twelve month period in 2005. Interest income was related to interest earned on cash held in short term investments however in 2005 the Company also accrued interest on the Company’s KGPL investment.

For the twelve months ending June 30, 2005 interest income was $305,836, 63% higher compared to $187,440 for the comparable twelve month period in 2004. The increase in interest income was related to interest payments received on the Company’s KGPL investment as well as interest on cash held in short maturity investments.

Gain on sale of inactive subsidiaries. Gain on sale of inactive subsidiaries represents the net proceeds on the properties located in Port aux Basques Newfoundland. Effective June 29, 2005, the Company sold these properties to a third party for cash proceeds of $175,000.

Income from marketable securities. At June 30, 2006 the Company held a portfolio of marketable securities, which contains a portion of oil and gas related trust units. These trust units have a fixed yield distribution to owners of the units. For the twelve month period ending June 30, 2006 the Company earned $234,072 in cash distributions from trust units versus $49,916 for the previous twelve month period in 2005. During 2004 the Company earned Nil in cash distributions from trust units.

Gain on sale of marketable securities. For the twelve month period ending June 30, 2006 the Company sold a portion of its portfolio of marketable securities resulting in a gain on disposition of $1,538,146 compared to $9,775 for the same twelve month period in 2005.

For the twelve month period ending June 30, 2005 the Company sold a portion of its portfolio of marketable securities resulting in a gain on disposition of $9,775 compared to $16,470 for the same twelve month period in 2004.

Write down of marketable securities. Marketable securities are valued at the lower of cost or market on a portfolio basis. At June 30, 2006 the cost of the Company’s marketable securities was greater than market value and as a result a provision of $193,461 was applied compared to Nil for the twelve month period ended June 30, 2005.

Write down of oil and gas interests. In applying the full cost method, the Company performs an annual impairment test (“ceiling test”) which restricts the capitalized costs less accumulated depletion and amortization from exceeding an amount equal to the estimated fair market value of future net revenues from proved and probable oil and gas reserves, as determined by independent engineers, based on sales prices achievable under forecast prices and posted average reference prices in effect at the end of the year and forecast costs, and after deducting estimated future production related expenses, future site restoration costs and income taxes. As a result of applying the aforementioned test at June 30, 2006 the Company recorded a provision of $2,692,748. No provision was applied for the same fiscal periods ending 2005 or 2004.

Current and Future Income Taxes. During the twelve month period ended June 30, 2006 a net future income tax benefit of $457,159 was recognized compared to a net future income tax charge of Nil for the twelve month period ended June 30, 2005. As a result of the write down of oil and gas interests, the Company recorded an income tax benefit. During the twelve month period ended June 30, 2005 a net future income tax charge of Nil was recognized compared to a net future income tax charge of Nil for the twelve month period ended June 30, 2004. During the current and previous year a future tax recovery was absorbed by an increase in the valuation allowance. During fiscal 2006 the statutory tax rate was 34.24% versus 36.12% in 2005.

Net loss from continuing operations. Net loss from continuing operations increased 37% to $3,008,745 for the twelve month period ended June 30, 2006 compared to a net loss of $2,197,746 for the twelve month period ending June 30, 2005. The net loss from continuing operations was primarily caused by the write down of oil and gas interests, write down of marketable securities and costs related to the Oakwell Claim. These costs were partially offset by the gain on sale of marketable securities.

Net loss from continuing operations decreased 43% to $2,197,746 for the twelve month period ended June 30, 2005 compared to a net loss of $3,845,606 for the twelve month period ending June 30, 2004. Net loss from continuing operations was significantly higher in the previous year due to a $2,015,681 provision for the Oakwell Claim (See Critical Accounting Estimates - Oakwell Claim, below).

Net income from discontinued operations. Net income from discontinued operations resulted from the Company’s disposition of its Industrial & Offshore Division, which was sold February 1, 2005. Net income from discontinued operations was Nil for the twelve month period ended June 30, 2006 compared to $317,351 for the twelve month period ended June 30, 2005. On disposition of the operations of the Industrial & Offshore Division the Company recorded a gain of $1,717,646.

Net income from discontinued operations decreased 81% to $317,351 for the twelve month period ended June 30, 2005 compared to $1,627,664 for the twelve month period ended June 30, 2004.

Net loss. As a result of the above factors the net loss was $3,008,745 for the twelve month period ending June 30, 2006 compared to a loss of $162,749 for the comparable twelve month period ending June 30, 2005.

As a result of the above factors the net loss was $162,749 for the twelve month period ending June 30, 2005 compared to a loss of $2,217,942 for the comparable twelve month period ending June 30, 2004.

Net loss from continuing operations per share and net loss per share. Net loss from continuing operations per share for the twelve month period ending June 30, 2006 increased to $0.73 per share from $0.54 per share for the same twelve month period 2005. Net loss per share for the twelve month period ending June 30, 2006 increased to $0.73 per share compared to a net loss of $0.04 per share for the same twelve month period 2005. Fully diluted loss per share and fully diluted loss per share from continuing operations are not presented as they are antidilutive.

Net loss from continuing operations per share for the twelve month period ending June 30, 2005 decreased by 43% to $0.54 per share from $0.95 per share for the same twelve month period 2004. Net loss per share for the twelve month period ending June 30, 2005 decreased 93% to $0.04 per share compared to a net loss of $0.55 per share for the same twelve month period 2004.

Capital Expenditures. Capital expenditures totaled $7,160,176 for the twelve months of fiscal 2006 compared to $1,001,743 for the twelve months of fiscal 2005. During the twelve month period ending June 30, 2006 the Company’s primary expenditures related to drilling and completion costs of $2,410,430 for the Buick Creek lands, British Columbia, and cash acquisition costs related to the Sawn Lake and Great Northern Oil acquisition of $2,351,608 and $2,150,212 respectively.

Capital expenditures totaled $1,001,743 for the twelve months of fiscal 2005 compared to $1,740,154 for the twelve months of fiscal 2004. During the twelve month period ending June 30, 2005 the Company’s primary expenditures related to acquisition costs of $279,765 for the Buick Creek lands, British Columbia, drilling and completion costs of approximately $85,242 for the Doe Property, Alberta, $273,969 in tie-ins at Olds/Davey, Alberta, and $73,360 in re-completions in the Sibbald area of Alberta.

SUMMARY OF QUARTERLY RESULTS

	Fiscal 2006-Unaudited				Fiscal 2005 - Unaudited
	June 30,2006	Mar. 31/06	Dec. 31/05	Sept. 30/05	June 30/05	Mar. 31/05	Dec. 31/04	Sept. 30/04

*Financial Information:*
Net oil and gas revenue	$ 200,131	$ 166,941	$ 326,114	$ 287,082	$ 149,274	$ 206,044	$ 226,755	$ 163,410

Income (loss) from continuing
operations	$ (3,213,485)	$ 368,323	$ (158,974)	$ (4,609)	$ (741,216)	$ (771,886)	$ (470,909)	$ (213,735)
Net income (loss)	$ (3,213,485)	$ 368,323	$ (158,974)	$ (4,609)	$ (891,216)	$ 1,188,123	$ (548,854)	$ 89,198

Income (loss) from continuing
operations per share	$ (0.76)	$ 0.09	$ (0.04)	$ (0.001)	$ (0.18)	$ (0.19)	$ (0.12)	$ (0.05)
Net income (loss) per share	$ (0.76)	$ 0.09	$ (0.04)	$ (0.001)	$ (0.22)	$ 0.29	$ (0.14)	$ 0.02
Fully diluted net income
(loss) per share	$ (0.76)	$ 0.08	$ (0.04)	$ (0.001)	$ (0.22)	$ 0.26	$ (0.14)	$ 0.02

Operating Information:
Average Daily Production
Natural gas (mcf per day)	323	123	212	231	270	233	342	171
Natural gas liquids (bbls per day)	3	4	16	13	10	14	8	5
Crude oil (bbls per day)	10	15	11	11	13	14	16	1
Total (boe per day)	66	39	62	62	69	66	81	34

Average Commodity Prices
Natural gas ($/mcf)	$ 9.08	$ 8.71	$ 12.95	$ 9.73	$ 7.41	$ 7.97	$ 5.98	$ 6.07
Natural gas liquids ($/bbl)	$ 48.05	$ 48.17	$ 45.52	$ 47.01	$ 41.81	$ 32.67	$ 32.14	$ 37.95
Crude oil ($/bbl)	$ 67.01	$ 66.51	$ 67.28	$ 68.30	$ 65.76	$ 52.71	$ 42.19	$ 55.91
Total ($/boe)	$ 55.99	$ 57.30	$ 66.32	$ 57.67	$ 48.15	$ 45.68	$ 36.77	$ 37.29

Royalties
Natural gas ($/mcf)	$ 1.38	$ 1.74	$ 1.42	$ 0.98	$ 1.69	$ 1.18	$ 1.48	$ 1.77
Natural gas liquids ($/bbl)	$ 11.27	$ 12.88	$ 11.39	$ 10.84	$ 9.48	$ 10.03	$ 11.23	$ 19.83
Crude oil ($/bbl)	$ 9.68	$ 9.33	$ 8.61	$ 4.95	$ 8.55	$ 9.07	$ 6.07	$ 4.92
Total royalties ($/boe)	$ 9.08	$ 10.27	$ 9.38	$ 6.77	$ 9.75	$ 8.07	$ 8.58	$ 11.72

Production costs
Natural gas ($/mcf)	$ 3.28	$ 3.89	$ 3.15	$ 3.36	$ 2.80	$ 1.60	$ 4.27	$ 2.77
Natural gas liquids ($/bbl)	$ 8.22	$ 16.69	$ 7.34	$ 5.71	$ 7.28	$ 5.86	$ 5.71	$ 10.94
Crude oil ($/bbl)	$ 25.19	$ 26.35	$ 26.49	$ 24.07	$ 37.00	$ 21.12	$ 34.03	$ 35.82
Total production costs ($/boe)	$ 18.90	$ 23.84	$ 16.98	$ 17.81	$ 19.24	$ 10.99	$ 24.93	$ 16.52

Netback by Product
Natural gas ($/mcf)	$ 4.42	$ 3.08	$ 8.38	$ 5.39	$ 2.92	$ 5.19	$ 0.23	$ 1.53
Natural gas liquids ($/bbl)	$ 28.56	$ 18.60	$ 26.79	$ 30.46	$ 25.05	$ 16.78	$ 15.20	$ 7.18
Crude oil ($/bbl)	$ 32.14	$ 30.83	$ 32.18	$ 39.28	$ 20.21	$ 22.52	$ 2.09	$ 15.17
Netback ($/boe)	$ 28.01	$ 23.19	$ 39.96	$ 33.09	$ 19.16	$ 26.62	$ 3.26	$ 9.05

Net revenues from the Company’s oil and gas operations have generally increased over the past eight quarters due to general increases in production rates and commodity prices (See “Item 5.D - Trend Information” below). Earnings have tended to recede during the fourth quarter of both fiscal 2006 and 2005 and during the third quarter of fiscal 2005 due to increased litigation expenditures related to the Oakwell Claim, the accrual of the Singapore Judgment and in the fourth quarter of 2006, a write down in the Company’s oil and gas properties. The expenditures and accruals related to the Oakwell Claim were tied to the timing of court hearings and decisions and do not represent a normal business trend.

Fourth Quarter FISCAL 2006

During the fourth quarter ended June 30, 2006 the Company’s net revenue was $200,131 versus $149,274 recorded in the fourth quarter ending June 30, 2005. This was primarily due to increased production from the Company’s acquisition of Sawn Lake and Great Northern Oil and commodity price increases.

During the fourth quarter ended June 30, 2006 the Company recorded a write down on its oil and gas properties of $2,568,030 and a write down of $193,461 on its portfolio of marketable securities.

During the fourth quarter ended June 30, 2005 the Company disposed of its interests in 10915 Newfoundland Limited and 11123 Newfoundland Limited for cash proceeds of $175,000. Both of 10915 Newfoundland Limited and 11123 Newfoundland Limited were inactive and their only assets were holdings in two properties located in Newfoundland and Labrador, Canada.

ITEM 5.B. LIQUIDITY AND CAPITAL RESOURCES

Cash and cash equivalents as of June 30, 2006 was $67,315 compared to $5,286,315 at June 30, 2005. During the twelve month period ending June 30, 2006 the Company’s cash flows used from operating activities from continuing operations was $789,226 versus funds used from operating from continuing operating activities of $1,342,888 during the previous year.

Cash and cash equivalents as of June 30, 2005 was $5,286,315 compared 600,313 at June 30, 2004. During the twelve month period ending June 30, 2005 the Company’s cash flows used from operating activities from continuing operations was $1,342,888 versus cash flows used from operating activities from continuing operating activities of 1,871,961 during the previous year.

The Company expended $6,535,176 related to oil and gas assets during the twelve month period ended June 30, 2006 versus $1,001,743 during the previous twelve month period ending June 30, 2005. During the twelve month period ending June 30, 2006 the Company’s primary expenditures related to drilling and completion costs of $2,410,430 for the Buick Creek lands, British Columbia, and acquisition costs related to the Sawn Lake and Great Northern Oil of $2,351,608 and $2,150,212 respectively.

The Company also had net proceeds on disposition of marketable securities of $2,117,624 during the twelve month period ending June 30, 2006 versus purchases of $1,863,324 in the previous period.

Many of the changes in balance sheet accounts during fiscal 2005 are represented by the disposal of the Company’s Industrial & Offshore Division. These items have been reclassified as cash provided by discontinued operations. During the twelve month period ending June 30, 2005 the Company had net cash provided by discontinued operations of $5,968,814 versus cash used of $1,181,034 by the discontinued operations during the previous fiscal year. During the twelve month period ending June 30, 2005 the Company had proceeds of $8,111,989 on the disposal of M&M Engineering and used $2,375,728 from investing activities of discontinued operations. During the previous year the Company used $592,727 on discontinued operations. During the twelve month period ending June 30, 2005 the Company used $2,981,618 on financing activities of discontinued operations versus $54,910 for the previous year.

The Company has the resources to meet its present working capital requirements with the exception of the Oakwell Claim (See “Item 8.A.7 - Litigation - Oakwell” below).

The Company's primary sources of liquidity and capital resources historically have been cash flows from the operations of oil and gas operations, the issuance of share capital, advances from shareholders and cash flows from discontinued operations. During fiscal 2006, it is expected that primary sources of liquidity and capital resources will be derived from the oil and gas operations. The Company also anticipates that it will eventually dispose of its interest in KGPL. (See “Item 5.G - Safe Harbour - Critical Accounting Estimates - Valuation of the Company’s Investment in KGPL” below).

With respect to specific estimates that could have a material affect on future operations and cash flows (See ”Item 5.G - Safe Harbour - Critical Accounting Estimates - Oakwell Claim and the Valuation of the Company's Investment in KGPL” below).

Outlook and Prospective Capital Requirements.

The Company’s oil and gas operations have steadily increased since its inception in 2001. At present, the Company intends to apply cash to further develop its oil and gas properties. As part of the Company's oil and gas exploration and development program, management of the Company anticipates further expenditures to expand its existing portfolio of proved and probable oil and gas reserves. Amounts expended on future oil and gas exploration and development is dependent on the nature of future opportunities evaluated by the Company. These expenditures could be funded through cash held by the Company or through cash flow from operations. Any expenditure which exceeds available cash will be required to be funded by additional share capital or debt issued by the Company, or by other means. With respect to other potential expenditures of the Company see “Critical Accounting Estimates - Oakwell Claim” below.

Effective February 1, 2005 the Company divested of its interest in M&M for cash proceeds of $7,361,999. The Company retracted preferred shares of M&M for Cdn $1,000,000 cash. The Company also sold its interest in 10915 Newfoundland Limited and 11123 Newfoundland Limited for cash proceeds of $175,000.

The Company's long-term profitability will depend upon its ability to successfully implement its business plan. Also, if the Company is not successful in defending the enforceability of the Oakwell Claim in Canada, there will be a material and adverse impact on the Company’s financial position and operations may be curtailed.

ITEM 5.C. RESEARCH AND DEVELOPMENT, PATENTS AND LICENSES

Not applicable.

ITEM 5.D. TREND INFORMATION

Seasonality

The Company's oil and gas operations is not a seasonal business, but increased consumer demand or changes in supply in certain months of the year can influence the price of produced hydrocarbons, depending on the circumstances. Production from the Company's oil and gas properties is the primary determinant for the volume of sales during the year.

There are a number of trends that have been developing in the oil and gas industry during the past several years that appear to be shaping the near future of the business. The first trend is the volatility of commodity prices. Natural gas is a commodity influenced by factors within North America. The continued tight supply demand balance for natural gas is causing significant elasticity in pricing. Despite record drilling activity, a strong economy, weather, fuel switching and demand for electrical generation there still exists a tight supply causing prices to remain high.

Crude oil is influenced by the world economy and OPEC's ability to adjust supply to world demand. Recently crude oil prices have been kept high by political events causing disruptions in the supply of oil, and concern over potential supply disruptions triggered by unrest in the Middle East.

Political events trigger large fluctuations in price levels. The impact on the oil and gas industry from commodity price volatility is significant. During periods of high prices, producers generate sufficient cash flows to conduct active exploration programs without external capital. Increased commodity prices frequently translate into very busy periods for service suppliers triggering premium costs for their services. Purchasing land and properties similarly increase in price during these periods. During low commodity price periods, acquisition costs drop, as do internally generated funds to spend on exploration and development activities. With decreased demand, the prices charged by the various service suppliers also decline.

A second trend within the Canadian oil and gas industry is recent growth in the number of private and small junior oil and gas companies starting up business. These companies often have experienced management teams from previous industry organizations that have disappeared as a part of the ongoing industry consolidation. Many are able to raise capital and recruit well qualified personnel.

A third trend currently affecting the oil and gas industry is the impact on capital markets caused by investor uncertainty in the North American economy. The capital market volatility in Canada has also been affected by uncertainties surrounding the economic impact that the Kyoto Protocol will have on the sector. Generally during the past year, the economic recovery combined with increased commodity prices has caused an increase in new equity financings in the oil and gas industry. The Company must compete with the numerous new companies and their new management teams and development plans in its access to capital. The competitive nature of the oil and gas industry will cause opportunities for equity financings to be selective. Some companies will have to rely on internally generated funds to conduct their exploration and developmental programs.

ITEM 5.E. OFF-BALANCE SHEET ARRANGEMENTS

Not Applicable.

ITEM 5.F. TABABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

Below is a listing of contractual commitments for future payments for the Company by fiscal year to 2011:

Schedule of Contractual Obligations (CDN $)

June 30, 2006
	Less than 1 year	1-3 years	3-5 years	more than 5 years
	Less than 1 year	1-3 years	3-5 years	more than 5 years

Operating leases	$7,404	$8,100	$ -	$ -
Debt interest and principal repayments	$38,182	$127,045	$63,523	$ -
	$45,586	$135,145	$63,523	$ -

ITEM 5.G. SAFE HARBOR

Certain statements in this Annual Report, including those appearing under this Item 5, constitute "forward looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995, Section 21E of the United States Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended. Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future, by us or on our behalf. Such statements are generally identifiable by the terminology used such as "plans", "expects", "estimates", "budgets", "intends", "anticipates", "believes", "projects", "indicates", "targets", "objective", "could", "may", or other similar words.

The forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: market prices for natural gas, natural gas liquids and oil products; the ability to produce and transport natural gas, natural gas liquids and oil; the results of exploration and development drilling and related activities; economic conditions in the countries and provinces in which we carry on business, especially economic slowdown; actions by governmental authorities including increases in taxes, changes in environmental and other regulations, and renegotiations of contracts; political uncertainty, including actions by insurgent groups or other conflict; the negotiation and closing of material contracts; and the other factors discussed in "Item 3. Key Information - Risk Factors", and in other documents that we file with the SEC. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors; our course of action would depend upon our assessment of the future considering all information then available. In that regard, any statements as to future natural gas, natural gas liquids or oil production levels; capital expenditures; the allocation of capital expenditures to exploration and development activities; sources of funding of our capital program; drilling of new wells; demand for natural gas, natural gas liquids and oil products; expenditures and allowances relating to environmental matters; dates by which certain areas will be developed or will come on-stream; expected finding and development costs; future production rates; ultimate recoverability of reserves; dates by which transactions are expected to close; cash flows; uses of cash flows; collectability of receivables; availability of trade credit; expected operating costs; expenditures and allowances relating to environmental matters; debt levels; and changes in any of the foregoing are forward-looking statements, and there can be no assurances that the expectations conveyed by such forward-looking statements will, in fact, be realized. Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity, achievements or financial condition.

Readers should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The foregoing statements are not exclusive and further information concerning us, including factors that could materially affect our financial results, may emerge from time to time. We do not intend to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements

Critical Accounting Policies and Estimates and Newly Adopted Accounting Policies

The Company's significant accounting policies, estimates and changes to accounting policies are also described in the Notes to the audited Consolidated Financial Statements for the fiscal years ended June 30, 2006, 2005, 2004(See Item 19 - Exhibits below). It is increasingly important to understand that the application of generally accepted accounting principles involves certain assumptions, judgments and estimates that affect reported amounts of assets, liabilities, revenues and expenses. The application of principles can cause varying results from company to company.

The most significant accounting policies that impact the Company relate to oil and gas accounting and reserve estimates, future income tax assets and liabilities, and stock based compensation.

The most significant accounting estimates that impact the Company and its subsidiaries relate to the Oakwell Claim, the valuation of the Company's investment in KGPL and the valuation of the convertible debenture of face value CDN $200,00.

During fiscal 2005 the Company adopted the recommendations of the new CICA Handbook Section 3870, stock-based compensation and other stock-based payments. The only new accounting policy that was adopted by the Company during the 2004 fiscal year was a new accounting policy guideline for oil and gas accounting according to the new Canadian Institute of Chartered Accountants (“CICA”) Handbook guideline ACG-16.

Critical Accounting Policies

Oil and gas accounting and reserve estimates. The Company follows the full cost method of accounting for oil and gas operations under which all costs of exploring for and developing oil and gas reserves are initially capitalized. Such costs include land acquisition costs, geological and geophysical costs, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition and exploration activities.

Under the full cost method all of the costs noted above are capitalized, together with the costs of production equipment, and are depleted on the unit-of-production method based on the estimated gross proved reserves. Petroleum products and reserves are converted to equivalent units of natural gas at 6,000 cubic feet to 1 barrel of oil.

Under the full cost method costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed periodically to ascertain whether impairment in value has occurred. When reserves are identified as “proven” by independent engineers, or the property is considered to be impaired, then the cost of the property or the amount of the impairment is added to costs subject to depletion calculations. Impaired assets that are added to the depletion pool are not written down, instead they are amortized over the life of the other oil and gas properties.

Proceeds from the sale of petroleum and natural gas properties are applied against capitalized costs, with no gain or loss recognized, unless such a sale would significantly alter the rate of depletion. Alberta Royalty Tax Credits are net against royalty costs.

In applying the full cost method, under Canadian GAAP, the Company performs a ceiling test which restricts the capitalized costs less accumulated depletion and amortization from exceeding an amount equal to the estimated fair market value undiscounted value of future net revenues from proved and probable oil and gas reserves, as determined by independent engineers, based on sales prices achievable under forecast prices existing contracts and posted average reference prices in effect at the end of the year and forecast current costs, and after deducting estimated future general and administrative expenses, production related expenses, financing costs, future site restoration costs and income taxes. For calculating the fair value the company utilizes a 10% discount factor.